Well Completion Maintenance Abandonment Guideline May Release 2014

8/9/2019 Well Completion Maintenance Abandonment Guideline May Release 2014

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WELL COMPLETION,MAINTENANCE AND

ABANDONMENT

GUIDELINE

May | 2014

Version 1.14


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Well Completion, Maintenance and Abandonment Guideline, Version 1.14

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 .................................................................................... 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 ............................................. 23

4.1 BLOWOUT PREVENTION ..................................................................................... 23 4.1.1 Well Servicing Blowout Prevention .................................................... 23 4.1.2 BOP Equipment Classes ...................................................................... 23 4.1.3 General .............................................................................................. 24

4.1.4 Accumulator systems ......................................................................... 24 4.1.5 Requirements Specific to Class A Systems .......................................... 25 4.1.5 Requirements Specific to Class B and C Systems ................................ 25 4.1.6 Line Requirements ............................................................................. 25 4.1.7 Stabbing Valve ................................................................................... 26 4.1.8 Blowout Prevention Manifold ............................................................ 26 4.1.9 Testing of Blowout Prevention Equipment......................................... 26 4.1.10 Special Sour Wells ......................................................................... 27


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4.1.11 Slickline, Snubbing and Coil Tubing Operations ............................ 27 4.1.12 Hammer Unions ............................................................................ 27 4.1.13 Diagrams of Blowout Prevention Systems for Well Servicing ....... 28

4.2 PERSONNEL ..................................................................................................... 33 4.3 FIRE PRECAUTIONS AND EQUIPMENT SPACING ....................................................... 34

4.3.1 Engines ............................................................................................... 34 4.3.2

Fuel .................................................................................................... 34

4.3.3 Smoking ............................................................................................. 34 4.3.4 Recommended Spacing Distances...................................................... 36 4.3.5 Flare Stacks ........................................................................................ 37 4.3.6 Explosives ........................................................................................... 37

4.4 INCIDENT REPORTING ........................................................................................ 37 4.5 CONCURRENT OPERATIONS ................................................................................ 37

5 ENVIRONMENTAL CONSIDERATIONS ................................................................ 38

5.1 SURFACE CASING VENT FLOWS ........................................................................... 38 5.1.1 Definitions .......................................................................................... 38 5.1.2 Checking for Surface Casing Vent Flows ............................................ 38 5.1.3 Testing and Reporting Surface Casing Vent Flows ............................. 39 5.1.4 Surface Casing Vent Flow Repairs ...................................................... 41

5.2 GAS MIGRATION .............................................................................................. 42 5.2.1 Definitions .......................................................................................... 42

5.3 CASING LEAKS AND FAILURES .............................................................................. 45 5.4 NOISE ............................................................................................................ 45 5.5 FLARING AND VENTING ...................................................................................... 45 5.6 FLUID STORAGE ............................................................................................... 45

6 DATA SUBMISSION ............................................................................................ 46

6.1 COMPLETION/WORKOVER/ABANDONMENT REPORTS ............................................. 46 6.2 WELL DELIVERABILITY TEST REPORTS ................................................................... 49

6.2.1 Well Deliverability Test Report Instructions ....................................... 49

7 COMPLIANCE ..................................................................................................... 53

OGAA ................................................................................................................ 53 Drilling and Production Regulation .................................................................. 53

APPENDIX A: COMPLETION/WORKOVER REPORT GUIDELINES ............................ 54

APPENDIX B: WELL SUSPENSION/INSPECTION FORM INSTRUCTIONS .................. 56

Well Classification ............................................................................................ 56 Formations Open To The Wellbore ................................................................... 57 Pressure Monitoring and Pressure Tests .......................................................... 57 Visual Inspection .............................................................................................. 57 General ............................................................................................................. 58

APPENDIX C: NOTICE OF OPERATION / FLARE USER MANUAL .............................. 59

1 USING THE APPLICATION ............................................................................ 61

1.1 DRILLING RESULTS APPLICATION MAIN MENU ........................................................... 61

2 NOTICE OF OPERATION ............................................................................... 63

2.1 NOTICE OF OPERATION – WELL SELECTION ............................................................... 63


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2.2 SELECT A WELL RECORD ........................................................................................ 64 2.3 Q UERY FOR A SPECIFIC RECORD .............................................................................. 64 2.4 ENTER NOTICE OF OPERATION ................................................................................ 65 2.5 COMPLETION REPORT REQUIRED ............................................................................ 69 2.6 COMPLETION REPORT OVERDUE ............................................................................. 70

3 NOTICE OF FLARE ........................................................................................ 71

3.1 NOTICE OF FLARE - WELL SELECTION ....................................................................... 71 3.2 SELECT A WELL RECORD ........................................................................................ 72 3.3 Q UERY FOR A SPECIFIC RECORD .............................................................................. 72 3.4 ENTER NOTICE OF FLARE ....................................................................................... 73 3.5 SUBMIT FLARE VOLUMES ....................................................................................... 75 3.6 FLARE VOLUME OVERDUE...................................................................................... 76


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Manual Revisions

Summary of Revisions

The Well Completion, Maintenance and Abandonment Manualhas been revised based upon feedback to provide clarity interms of requirements and process. Structural changes bysection are highlighted below.

Applications received on or after the effective date will berequired to meet the revised application standards.

Effective Date Section Description/Rationale

1-Jan-2012 4 Updated Table 4.1: Recommended Spacing Distances

1-Feb-2012 6 Added Section 6.4: Data Submission

1-Jun-2012 Appendix B Updated Appendix B screen shots, p.52.

1-Jul-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. Added Section 6.5: Production Logs, p.48.

1-Dec-2012 6Updated Section 6.1, p. 42: Two signed copies to A signed copy.Removed: in duplicate, from the Completion/Workover Report Form.

1-March-2013 Appendix A Updated Appendix A information (p.51, 52).

1-June-2013 Section 6.1Updated section to include changes to the Completion / WorkoverReport Form for the purpose of electronic submission of hydraulicFracture data (INDB 2013-03).

1-May-2014 Section 5.1Updated reference to the Drilling and Production Regulation sectionfrom 18(8)(a) to 18(9)(a).

1-June-2014Section 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 6Updated the submissions section to reflect the new Well Data

Requirements Submission Guideline (p. 46)


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1 Preface1.1 Purpose

This manual has been created to guide users through the BCOil and Gas Commission (the Commission) processes andprocedures. It also serves to highlight changes in process,procedure, requirements and terminology resulting from the Oiland Gas Activities Act (OGAA).

For users already familiar with the Commission applicationprocess, this manual provides a quick reference highlighting thesteps required to complete specific tasks. For users lessfamiliar, this manual presents a complete overview of

Commission requirements and provides links to more detailedmaterial.

This manual is not intended to take the place of the applicablelegislation. The user is encouraged to read the full text oflegislation and each applicable regulation and seek directionfrom Commission staff, if and when necessary, for clarification.

1.2 Scope

This manual focuses exclusively on requirements and

processes associated with the Commission’s legislativeauthorities and does not provide information on legalresponsibilities that the Commission does not regulate. It is theresponsibility of the applicant or permit holder to know anduphold its other legal responsibilities. Examples of legalresponsibilities outside of this manual include obligations underthe 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 regulatoryrequirements related to well servicing activities, includingcompletions, workovers, maintenance and abandonments.

Section 2.0 Well Equipment explains regulatory requirements for wellequipment in the Drilling and Production Regulation.

Section 3.0 Well Servicing Operations outlines and explains therequirements for well completions, workovers, maintenance,suspension and abandonments.

Section 4.0 Well Servicing Equipment and Procedures outlines andexplains blowout prevention standards, personnel requirementsand fire precautions that permit holders must follow to complywith the Drilling and Production Regulation.

Section 5.0 Environmental Considerations outlines and explains theregulatory requirements for flaring, noise, fluid storage, casingleaks, surface casing vent flows and gas migration.

Section 6.0 Data Submission outlines and explains the regulatoryrequirements the operator must include in reports for thecompletion, workover and abandonment of wells. Regulatoryrequirements 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 wastemanagement for wells within the jurisdiction of the Commissionis located in the Well Drilling and Waste Management manualsThe glossary page on the Commission website provides acomprehensive list of terms.

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Other navigational and illustrative elements used in the manualinclude:

Hyperlinks:Hyperlinked items appear as blue, underlined text. Clicking on ahyperlink takes the user directly to a document or location on a

webpage.

Sidebars:Sidebars highlight important information such as a change fromthe old procedure, new information, or reminders and tips.

Figures:Figures illustrate a function or process to give the user a visualrepresentation of a large or complex item.

Tables:Tables organize information into columns and rows for quickcomparison.

1.4.1 FeedbackThe Commission is committed to continuous improvement bycollecting information on the effectiveness of guidelines andmanuals. Clients and stakeholders wishing to comment onCommission guidelines and manuals may send constructivecomments to [email protected].

1.4.2 Frequently Asked Questions A Frequently Asked Questions (FAQ) link is available on theCommission OGAA website. The information provided iscategorized into topics which reflect the manuals for easyreference.

mailto:[email protected]:[email protected]:[email protected]://www.bcogc.ca/OGAA/faq.aspxhttp://www.bcogc.ca/OGAA/faq.aspxhttp://www.bcogc.ca/OGAA/faq.aspxhttp://www.bcogc.ca/OGAA/faq.aspxmailto:[email protected]


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2 Well EquipmentThe 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 conditionsanticipated during the life of the well and the wellhead is not tobe 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 disposalexcept 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 numberedhighway or populated area is located within the emergencyplanning 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 whereinstallation of a production packer is required. If a packer testfails, 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 packertesting procedures.

The permit holder is required to maintain a record of all packerisolation tests and repairs. This information must be submittedto the Commission on request.

2.4 Subsurface Safety Valves


Subsurface safety valves are required for wells containing gaswith > 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 8km 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 bemeasured from the corporate limits. In cases where thecorporate limits do not reasonably correspond with theboundaries of the community, the permit holder may take afunctional approach such as delineation of the extent ofdeveloped areas.

2.5 Oil Wells


Oil wells completed after September 13, 2010 equipped with anartificial 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 orpolish rod failure and

An automatic vibration shutdown system

1 In general, all repairs should be completed within 90 days. Reasonabledelays are acceptable in cases where access is seasonal and the delay doesnot result in a risk to safety or the environment. Delays that extend past thenext seasonal access window are not reasonable (greater than one year).

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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 tothe well must be installed in these circumstances.

Fencing or other forms of access control must be proportional tothe potential for unauthorized access to the wellsite. Accesscontrol may include fencing of the wellsite, or gating the accessroad. If the well is located in an access-controlled area, noadditional measures may be required. For wells that are located

on private land, the method of access control should bedeveloped in consultation with the landowner.

2.7 Leak Detection


All completed wells must be equipped with a system to detectand 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 shutdownsystems to periodic inspections.

If an uncontrolled flow from a completed well could produce ahydrogen sulphide concentration in atmosphere greater than100 ppm at a distance of 50 metres from the well, the permitholder must install and maintain: An automated shutdown system and

A hydrogen sulphide detection, alarm and automatedshutdown system if the well is located within 1600 metres

of a populated areaFor wells completed prior to October 4, 2010, H2S detection andautomated shutdown systems are not required until

January 1, 2012 and the permit holder may apply for anexemption to the requirement.


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The following formula may be used to calculate the absoluteopen flow rate of a well that will result in an H2S concentration inatmosphere 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 OperationsThe well servicing operations section outlines and explains therequirements for the reporting of servicing, suspension,

reactivation or abandonment of wells. It also outlines thenotification requirements for completions, workovers andmaintenance of wells.

3.1 Well Servicing Operations


A permit holder must ensure that an adequate EmergencyResponse Plan is in place before conducting well servicingoperations. 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 atleast 24 hours prior to the start of all completion, workover orabandonment operations. An approved Application to Alter is nolonger required for completion or workover operations.

All notifications must be submitted using the Online ReportingSystem. Refer to Appendix B for the instruction manual.

See Section 6.1 for Completion/Workover Report submissionrequirements.

3.2.1 Shallow Fracturing


Fracturing operations conducted at a depth of 600 metres orless must be approved in the well permit. Applications forshallow fracturing operations should include: The fracture program design including proposed pumping

rates, volumes, pressures, and fracturing fluids


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Estimation of the maximum fracture propagation

Assessment of groundwater resources in the area

Identification and depth of all wells within 200 metres of theproposed shallow fracturing operations

Verification of cement integrity through available publicdata of all wells under the Commission’s jurisdiction withina 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 theproposed fracturing operations including casing andcement 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 permissionhas been granted for commingled production. Permission maybe granted in an individual well permit or by a special project forcommingling under section 75 of OGAA. The Commission hasdesignated 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 withinthe Commission’s Resource Conservation Forms andGuidelines page.

The Notification of Commingled Well Production form must besubmitted to the Commission within 30 days of thecommencement of commingled production.

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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 oflast activity is defined as the first day of the month following thelast month for which production, injection and disposal volumeswere reported.

Observation wells are deemed to be active (see ObservationWells section).

For drilling activity, including new wells and re-entries, the dateof last activity is defined as the rig release date.

For completion and workover activity, the date of last activity isdefined as the completion date.

A permit holder may apply to the Commission to declassify aspecial sour well.

3.3.2 Observation Wells

Inactive wells offer good opportunities to monitor reservoirbehaviour, specifically, pool pressures over time. Tests of thesewells 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 testedand a Reservoir Pressure Survey Test Report must besubmitted to the Commission Resource ConservationDepartment at least once every two years.

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A well may be classified as Observation by submission of aBC-11 form (Notice of Commencement or Suspension ofOperations) to the Ministry of Finance. A brief statementindicating what the well will be used to monitor should beincluded in the comments section.

Observation wells are treated as active and do not requiresuspension unless declassified.

Observation wells will be declassified if pressure data isnot submitted within 12 months of its due date.

Upon declassification, observation wells will be reclassifiedaccording to the well operation status (i.e. Gas Production)that existed prior to their classification as observation wellsand will require suspension.

For observation wells that have been declassified, the dateof 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 inactivestatus in a manner that ensures the ongoing integrity of the well.

Any well may be suspended to a higher standard than theminimum requirements described in Tables 1 to 4. Reportingrequirements are outlined in the Information and ReportingRequirements section.

If all zones in a non-special sour well are abandoned and thewell has not yet been surface abandoned, the well shall becategorized as “Low Risk - All cased wells (no perforations oropen hole)”.

Permit holders may apply to the Commission Drilling andProduction Department for an extension of a deadline.

The following tables describe the Commission’s minimumrequirements for each category.


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Table 3.1: General Requirements for All Inactive Wells

WellheadsUnperforated wells may use a welded steel plate atop the production casing stub.The plate must provide access to the wellbore for pressure measurement. All otherwells 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 exceptthe surface casing vent.

The surface casing vent valve must be open and the surface casing ventunobstructed 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 polishrod remains connected to the pump jack.

Pressure testing of the wellhead sealing elements refers to the primary andsecondary seals only, as applicable. For wellheads that do not have adequate testports, 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 withCommission requirements.

Lease

Maintenance

A sign stating the well’s surface location, current permit holder, the currentpermit holder’s emergency contact number and appropriate warning symbolsas defined in Section 17 of the Drilling and Production Regulation must be inplace.

An area of 10 metres radius around the wellhead must be maintained toprevent 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 toobserve for wellhead integrity, noxious weeds and other hazards.

For wells with helicopter access, the visual inspection frequency is the pressuretesting / 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 ofthe completion of suspension operations.

Records of inspections must be maintained on file and if requested, be madeavailable 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 andtubing plug.

Bridge plug capped with 8 mlineal of cement.

Pressure Testing /

Monitoring / Servicing

Requirements

Pressure test both tubing andannulus to 7 MPa for 10minutes.

Service and pressure testwellhead sealing elements.

Pressure test the casing to 7MPa for 10 minutes.

Service and pressure testwellhead sealing elements(if applicable).

Pressure Testing /

Monitoring / ServicingFrequency

At the time of suspension andthen annually. At the time of suspension andthen every 5 years.

Wellbore Fluid

Wellbore must be filled withnon-saline water or corrosioninhibited water. The upperportion of the wellbore mustbe protected from freezing.Freeze protection may beaccomplished by theplacement of at least 2 m of asuitable, non-freezing fluid at

surface.

Wellbore must be filled with non-saline water or corrosioninhibited water. The upperportion of the wellbore must beprotected from freezing. Freezeprotection may be accomplishedby the placement of at least 2 mof 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 isa 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 gasdisposal wells.

Type 6: Completed low risk wells that have been inactive orsuspended for at least 10 consecutive years.

Suspension

OptionsOption 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 thetubing and annulus to 7MPa for 10 minutes.

Service and pressuretest wellhead sealing

elements.

Pressure test thecasing to 7 MPa for 10minutes.

Service and pressuretest wellhead sealing

elements.

Read and record shut-intubing pressure (ifapplicable) and shut-in

casing pressure.

Service and pressure testwellhead sealingelements.

Pressure Testing /

Monitoring /

Servicing

Frequency

At the time of

suspension and thenevery 3 years.

At the time of

suspension and thenevery 5 years.

At the time of suspensionand then annually.

Wellbore Fluid

Wellbore must be filledwith non-saline water orcorrosion inhibited

water. The upperportion of the wellboremust be protected fromfreezing. Freeze

protection may beaccomplished by the

placement of at least 2

Wellbore must be filledwith non-saline water orcorrosion inhibited

water. The upperportion of the wellboremust be protected fromfreezing. Freeze

protection may beaccomplished 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 flowingproduct is a fluid. Removal of polish rods is not required to suspend low-riskoil 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 openhole 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

RequirementsNone. None.

Pressure Testing

/ Monitoring /

Servicing

Requirements

Read and record shut-in tubingpressure (if applicable) and shut-incasing pressure.

Service and pressure testwellhead sealing elements.

Pressure test casing to 7 MPa for 10minutes.

Service and pressure test wellheadsealing elements (if applicable).

Pressure Testing

/ Monitoring /

Servicing

Frequency

At the time of suspension andthen every 5 years.

At the time of suspension and then every 5years.

Wellbore Fluid None.

Wellbore must be filled with non-salinewater or corrosion inhibited water. Theupper portion of the wellbore must beprotected from freezing. Freeze protectionmay be accomplished by the placement ofat 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 productionpacker are exempt from the testing requirements if the well issuspended in accordance with the Drilling and Production

Regulation.

3.3.5 Long Term Inactive Wells

All completed low-risk wells must meet medium risk suspensionrequirements after being suspended for 10 consecutive years.

For example, a completed low-risk well that last reportsproduction in December 2008 would be classed as inactive onDecember 31, 2009 and the Operator would have 60 days tosuspend the well in accordance with low-risk suspensionrequirements. If the well was still suspended on December 31,

2019, the Operator would have 60 days to suspend the well inaccordance with medium risk suspension requirements.

3.3.6 Reactivating Suspended Wells

The following are the procedures for the reactivation of asuspended 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 FinanceMedium and High-Risk Wells: Pressure test the casing to 7 MPa for 10 minutes

(if applicable). If the test fails, investigate and repair theproblem

Pressure test the tubing (if present) to 7 MPa for 10minutes. If the test fails, investigate and repair the problem

3.3.7 Information / Reporting Requirements

3.3.7.1 Oil and Gas Commis sion

Suspensions

A Well Suspension/Inspection Form must be submitted to theCommission, Drilling and Production Department within 30 daysof suspension of a well.


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The suspension report may be submitted as a paper copy or inspreadsheet 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 onrequest.

Inspection results may be recorded by filling out the applicablesections of the Well Suspension/Inspection Form or through thepermit holder’s internal database. If an internal inspectionsdatabase is used, it is the permit holder’s responsibility toensure that the required information is recorded.

3.3.7.2 Ministry of Finance

The form Notice of Commencement or Suspension ofOperations: BC-11 must be submitted to the Ministry of Financeon or before the 20th day of the calendar month following thecalendar month in which the following operations occurred at awell: 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 zonewithin 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 thestatus changes more than once in a production month (forexample testing and producing)

http://www.sbr.gov.bc.ca/documents_library/forms/BC11guidelines.pdfhttp://www.sbr.gov.bc.ca/documents_library/forms/BC11guidelines.pdfhttp://www.sbr.gov.bc.ca/documents_library/forms/BC11guidelines.pdfhttp://www.sbr.gov.bc.ca/documents_library/forms/BC11guidelines.pdfhttp://www.sbr.gov.bc.ca/documents_library/forms/BC11guidelines.pdfhttp://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 asspecial sour or are acid gas disposal wells.

3.4.2 Medium Risk gas wells are gas wells where themaximum stabilized wellhead AOF exceeds the Maximum

Allowable Flowrate5 or 28 x 103 m3/day6 and are not classifiedas high risk gas wells.

Maximum Allowable Flowrate (103m3/day) = 15 x 103 / H2SConcentration (ppm)

3.4.3 Low Risk gas wells are gas wells that are not classifiedas Medium or High Risk.

5 This calculation (adopted from the ERCB Directive 13) determines the

maximum flowrate for a given H2S concentration that will result in amaximum concentration of H2S at the lease boundary of 10 ppm. The leaseboundary 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 p m )

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

3 /day

535 ppm

LOW

RISK

MEDIUM

RISK


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Figure 3.1: Classi f ication of Low and Medium Risk Gas Wells (Ado pted

from ERCB Directive 13).

3.5 Well Abandonment


For drilling wells, notification is not required prior to conductingopen hole plugbacks or abandonments.

Drilling wells that are downhole, but not surface abandoned atthe time of rig release, are not considered abandoned. Anabandonment notification and abandonment report must besubmitted to the Commission at the time of surfaceabandonment as outlined below for the well status to bechanged to abandoned.

Notification is required 7 days prior to conducting all other wellabandonments; however the notification requirement may bewaived on a case by case basis. An abandonment programmust 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 thewell

The long-term integrity of the wellbore is maintained

Permit holders are expected to conduct abandonments andplugbacks in accordance with the ERCB Directive 20. If there isany doubt about the adequacy of a plugging or abandonmentprogram, the permit holder should discuss their plans with theCommission. Failure to adequately plug or abandon a well mayresult in an order for remedial work.

Abandonment reports may be submitted using aCompletion/Workover Report Form.

http://www.ercb.ca/docs/documents/directives/directive020.pdfhttp://www.ercb.ca/docs/documents/directives/directive020.pdfhttp://www.ercb.ca/docs/documents/directives/directive020.pdfhttp://www.bcogc.ca/document.aspx?documentID=668&type=.dochttp://www.bcogc.ca/document.aspx?documentID=668&type=.dochttp://www.bcogc.ca/document.aspx?documentID=668&type=.dochttp://www.ercb.ca/docs/documents/directives/directive020.pdf


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4 Well Servicing Equipment and ProceduresThe well servicing equipment and procedures section outlinesand explains blowout prevention standards, personnel

requirements and fire precautions that permit holders mustfollow 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 thata permit should follow to comply with the requirements of Part 4,Division 2 of the Drilling and Production Regulation. It is theresponsibility of the permit holder to ensure that blowoutprevention equipment and procedures are adequate.

A permit holder may use alternate blowout preventionequipment and techniques if they can demonstrate by means ofa detailed engineering analysis that the alternate equipment ortechniques are adequate as required by section 16(1) of theDrilling 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 minimumpressure rating of the production casing flange is less than orequal to 21 000 kilopascals (kPa) and the hydrogen sulphidecontent in a representative sample of the gas is less than 1 mol%;

Class B equipment is required for a well where the minimumpressure 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 hydrogensulphide content in a representative sample of the gas is1 mol % or greater

Class C equipment is required for a special sour well.


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4.1.3 General

At all times during well servicing, the well must be under control,adequate blowout prevention equipment must be installed andmust be able to shut off flow from the well regardless of the typeor diameter of tools or equipment in the well.

The blowout prevention equipment must have a pressure ratingequal to or greater than the pressure rating of the productioncasing flange or the formation pressure, whichever is the lesser.

Hydraulic ram type blowout preventers which are not equippedwith an automatic ram locking device must have hand wheelsavailable.

An accurate pressure gauge to determine the well annuluspressure during a well shut-in must be either installed or readilyaccessible for installation.

A service rig used at the well site must have an operable hornon the drilling control panel for sounding alerts.

A sour service separator and flare system, including appropriatemanifolding, 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 andconnected to an accumulator system.

The accumulator system must be installed and operated inaccordance with the manufacturer's specifications. The systemmust be:

a) Connected to the blowout preventers with lines ofworking pressure equal to the working pressure of thesystem, and within 7 metres of the well, the lines must beof steel construction unless completely sheathed withadequate fire resistant sleeving

b) Capable of providing, without recharging, fluid ofsufficient volume and pressure to effect full closure of allpreventers, and to retain a pressure of 8 400 kPa on theaccumulator system

c) Recharged by a pressure controlled pump capable ofrecovering the accumulator pressure drop resulting fromfull closure of all preventers within 5 minutes

d) Capable of closing any ram type preventer within 30seconds


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e) Capable of closing the annular preventer within 60seconds

f) Equipped with readily accessible fittings and gauges todetermine the pre-charge pressure

g) Equipped with a check valve between the accumulator

recharge pump and the accumulator andh) 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 minimumpressure of 8 400 kPa, and

b) Have a gauge installed, or readily available forinstallation, to determine the pressure of each nitrogencontainer

4.1.5 Requirements Specific to Class A SystemsClass A blowout prevention system

a) May utilize the rig hydraulic system to recharge theaccumulator and

b) Must have operating controls for each preventer in areadily accessible location near the operator's positionand an additional set of controls located a minimum of7 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 metresfrom the well, shielded or housed to protect the operatorfrom flow from the well

b) An additional set of controls in a readily accessiblelocation 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 andservice rigs completing rod jobs.

A blowout prevention system must have two lines, one forbleeding off pressure and one for killing the well, which must:

a) Be either steel or flexible sheathed hose to provideadequate fire resistant rating


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b) Be valved and have a working pressure equal to orgreater than that required for the blowout preventionequipment

c) Have one line connected to the rig pump and one lineconnected to the tank

d) Have one line connected to an outlet below the blowoutpreventers and the necessary equipment to readilyconnect the second line to the tubing

e) Be at least 50 mm nominal diameter andf) Be securely tied down

4.1.7 Stabbing Valve

A full opening ball valve (stabbing valve) which can be attachedto the tubing or other pipe in the well must:

a) Be ready for use and located in a readily accessiblelocation on the service rig

b) Be maintained in the open positionc) Have an internal diameter equal to or greater than the

smallest restriction inside the tubing or casing andd) 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 ofthe blowout prevention system installed on the well

b) Contains a check valve to prevent flow from well to rigpumpc) Contains a pressure relief valve upstream of the check

valved) 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-minutepressure 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 tothe wellhead pressure rating or the formation pressure,whichever is less


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c) Each annular preventer to 7000 kilopascals or theformation pressure, whichever is less

Note: For an annular type blowout preventer, all mechanical andpressure tests required under subsection (c) must be conductedwith pipe in the blowout preventer.

All blowout prevention equipment, except for shear rams onspecial sour wells, must be mechanically tested daily, ifoperationally safe to do so; any equipment found defective mustbe made serviceable before operations are resumed.

All tests must be reported in the servicing log book and in thecase of a pressure test, the report must state the blowoutpreventer tested, the test duration and the test pressureobserved at the start and finish of each test.

At least once every three years, all blowout preventers must beshop serviced and shop tested to their working pressure and thetest data and the maintenance performed must be recorded andmade 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 fordetailed information.

4.1.11 Slickline, Snubbing and Coil Tubing OperationsRefer 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 orunder the rig substructure

http://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=16&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=16&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=16&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=23&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=23&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=23&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=25&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=25&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=25&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=27&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=27&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=27&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=27&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=25&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=23&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=16&type=irp


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4.1.13 Diagrams of Blowout Prevention Systems for WellServicing

Figure 4.A Equipment Symbols


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Figure 4.B BOP Class A Pressure Rating and Component PlacementNotes: 1. Pressure rating of preventers is equal to or

greater than the production casing flange rating orthe formation pressure, whichever is the lesser.2. 50 mm lines throughout3. The positioning of the tubing and blind rams maybe interchanged.

4. Spool may have threaded side outlet (and valve) ifwellhead has threaded fittings.5. A flanged BOP port (and valve) below the lowestset of rams may replace spool (valve may bethreaded if wellhead has threaded fittings).


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Rating of production casing flange is greater than 21 000 kPa orrating of production casing flange is less than or equal to 21 000kPa and the H2S content of the gas is equal to or greater than10 MOLES per KILOMOLE.

Figure 4.C BOP Class B Pressure Rating and Component PlacementNotes: 1. Pressure rating of preventers is equal to or greater

than the production casing flange rating or theformation pressure, whichever is the lesser.

2. 50 mm lines throughout3. The positioning of the tubing and blind rams maybe interchanged.4. Spool may have threaded side outlet (and valve) ifwellhead 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 threadedfittings.)


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Figure 4.D BOP Class C Wellhead Configuration


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Figure 4.E BOP Class C Optional Wellhead Configuration


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4.2 Personnel


The permit holder must ensure that there are a sufficientnumber of trained and competent individuals to carry out all welloperations safely and without causing pollution.

The following people must possess a valid Well Service BlowoutPrevention 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 betrained in H2S safety.

Blowout prevention drills should be performed by each rig crewevery 7 days or once per well, whichever is more frequent.

Blowout prevention drills should be recorded in the servicing logbook.

Evidence of the qualifications of any person referred to in thissection 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, whenrequested by an official and if it is safe to do so, the contractoror rig crew must: Test the operation and effectiveness of the blowout

prevention equipment and

Perform a blowout prevention drill in accordance with theWell Control Procedure placard issued by the Canadian

Association of Oilwell Drilling Contractors or as outlined bythe Enform Blowout Prevention Manual

Refer to Enform IRP#7 Standards for Wellsite Supervision ofDrilling, Completions and Workovers for more information.

http://ww2.enform.ca/http://ww2.enform.ca/http://ww2.enform.ca/http://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=21&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=21&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=21&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=21&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=21&type=irphttp://www.enform.ca/safety_resources/publications/PublicationDetails.aspx?a=21&type=irphttp://ww2.enform.ca/


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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 awellsite, suitable safeguards are installed and tested to preventa fire or explosion in the event of a release of flammable liquidsor ignitable vapours.

For engines located within 25 metres of a well, petroleumstorage 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 theexhaust pipe

The exhaust pipe is directed away from the well or sourceof ignitable vapours and

The exhaust manifold is sufficiently shielded to preventcontact with flammable materials

For diesel engines located within 25 metres of a well, theCommission recommends that one of the following devices beinstalled:

A positive air shutoff valve, equipped with a readilyaccessible 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 least25 metres from the well

Permit holders must also ensure compliance with therequirements in Section 23.8 of the Occupational Health andSafety Regulation.

4.3.2 Fuel

Gasoline or liquid fuel, except for fuel in tanks that areconnected to operating equipment, must not be stored within 25metres of a well and drainage must be away from the wellhead.

4.3.3 Smoking

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


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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 ismaintained between potential sources of flammable liquids orignitable vapours and ignition sources. All fires must be

sufficiently safeguarded and all vessels and equipment fromwhich ignitable vapours may issue must be safely vented.

It is the responsibility of the permit holder to maintain sufficientequipment spacing.

W E L L H E A D

F L A R E O R I N

C I N E R A T O R

B O I L E R , S T E A M

G E N E R A T I N G

E Q U I P M E

N T , T E G *

P R O D U C E D W

A T E R T A N K

O T H E R S O U R C E S O F I G N I T A B L E

V A P O

U R S

S E P A R

A T O R

F L A M E T Y P E E Q U I P M E N T

P R O D U C E D F L A M

M A B L E L I Q U I D S

C R U D E O I L & C O N

D E N S A T E T A N K 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 VAPOURSNS 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.


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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 fromany public road, utility, building, installation, works, place ofpublic concourse or reservation for national defence.

4.3.5 Flare Stacks

A sufficient area beneath and around flare stacks must becleared of flammable materials and vegetation.

The recommended blackened area beneath a flare stack is 1.5times the stack height.

The Commission recognizes that a lesser area may be justifieddepending on the circumstances. It is the responsibility of thepermit holder to maintain a sufficient area, given the locationand the conditions under which flaring will or may occur.

4.3.6 Explosives

Explosives must be stored in properly constructed magazinesand be located a minimum of 150 metres from any wellservicing operation.

4.4 Incident ReportingSpills and well control incidents must be reported to theProvincial Emergency Program (PEP) at 1-800-663-3456, andthe Commission at (250) 794-5200

Spills must be reported in accordance with the Spill ReportingRegulation.

4.5 Concurrent Operations

A concurrent operations plan is required for completions

operations on any well that is located within 25 metres ofanother well.

http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/46_263_90http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/46_263_90http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/46_263_90http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/46_263_90http://www.bclaws.ca/EPLibraries/bclaws_new/document/ID/freeside/46_263_90


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5 Environmental ConsiderationsThe environmental considerations section outlines and explainsthe regulatory requirements for testing, repairing and reporting

environmental impacts: surface case venting flows, gasmigration, 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 orgreater than 300 cubic metres per day (m3/d)

A vent flow with a surface casing vent stabilized shut-inpressure 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 thatcould cause soil or groundwater contamination

A vent flow where any usable water zone in not covered bycemented casing or

Any other vent flow that constitutes a fire, public safety, orenvironmental hazard

5.1.2 Checking for Surface Casing Vent Flows

Testing for evidence of a surface casing vent flow must beconducted: 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 surfacecasing shoe or

o 11 kPa/m times the surface casing setting depth


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The Commission expects routine tests for surface casing ventflows to be conducted at the time of well suspension, during wellservicing operations (that is, recompletions) and annually for aperiod 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 asurface casing vent flow. The recommended procedure is asfollows:

Bubble Test Equipment:1) A container of water (from 500 ml to 1L)

2) Pipe fittings, small hose (minimum 6mm), or otherequipment 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 flowcan 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 orenvironmental hazard and must be reported to the Commissionas soon as possible.

The Commission recommends that permit holders reportsurface casing vent flows that are non-serious -those that do notpresent an immediate safety or environmental hazard. This maybe accomplished by submitting via email [email protected] a Surface Casing Flow – Gas Migration Information Form or an industry report form . Test

mailto:[email protected]?subject=Surface%20Casing%20Vent%20Flow%20reportmailto:[email protected]?subject=Surface%20Casing%20Vent%20Flow%20reporthttp://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdfhttp://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdfhttp://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdfhttp://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdfhttp://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdfhttp://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdfhttp://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdfhttp://www.bcogc.ca/documents/informationletters/08-20%20Multi%20Well%20Pads%20Spacing%20IL.pdfmailto:[email protected]?subject=Surface%20Casing%20Vent%20Flow%20report


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results for non-serious surface casing vent flows must bemaintained on file and provided to the Commission on request.

A permit holder should perform annual surface casing vent flowtests on all non-serious surface casing vent flow for a minimumof five years. The permit holder may select appropriate yearly

testing measures, however, the Commission may order specifictest measures for surface casing vent flows of particularconcern. If there is no change in the flow rate or shut inpressure after five years of testing, or if the vent dies out, nofurther testing is expected. If a non-serious vent flow becomesserious, the permit holder must notify the Commission as soonas possible.

Recommended surface casing vent flow test procedures are asfollows:

5.1.3.1 Measuring Flowr ate

Once a positive vent flow is detected, the flow rate andstabilized shut in pressures must be recorded. To measureventing gas volumes, a positive displacement gas meter, turbinemeter or an orifice well tester may be used. Equipment selectionshould be based on previous observations indicating what flowrate and pressure range can be expected. A positivedisplacement meter will be necessary to measure low volumesaccurately. An orifice well tester, with proper orifice plate, mayprovide 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 and1) Do not exceed the pressure/volume range of the

equipment

2) Ensure that there are no leaks

5.1.3.2 Measuring Build up Pressu re

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


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A pressure relief valve, calibrated to release the pressure if ithas built to its maximum allowable surface pressure, should beinstalled on the surface casing vent while measuring the buildup pressure. If it is anticipated that the maximum allowable shut

in pressure will be exceeded, a suitable recording device mustbe 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. Ifpressure has not stabilized, it may be necessary to changethe chart in order to cover a longer time period in order toachieve a maximum shut-in pressure.

4) Monitor the readings to determine when a stabilizedmaximum 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 fornon-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 considerthe 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 installationof a burst plate or pressure safety valve.

Non-serious surface casing vent flows must be repaired at thetime of well abandonment.

5.1.4.2 Seriou s Repair

The permit holder of a well determined to have a serious

surface casing vent flow should contact the Commission assoon as possible to discuss repair or managementrequirements.

5.1.4.3 Surface Casing Vent Flow Produ ctio n


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If the permit holder wishes to explore the option of producing thesurface casing vent flow, an application must be made to theDrilling and Production Department to obtain an exemption tosection 18(9)(a) of the Drilling and Production Regulation.Requests will be considered if: The source depth and formation of origin has been clearlyidentified

The permit holder owns the mineral rights to produce thesource formation

The cemented portion of the surface casing or the nextcasing string covers the deepest known usablegroundwater and

The flow has been analyzed and determined to be sweet (0percent H2S)

The Commission may rescind the approval to produce from the

surface casing vent and may require the surface casing ventflow to be repaired at any time if the Commission determines asafety or environmental hazard exists.

5.2 Gas Migration


5.2.1 Definitions

“Gas Migration” (GM) means a flow of gas that is detectable atthe surface outside of the outermost casing string (often referred

to as external migration or seepage).

“Serious Gas Migration” means gas migration that1) 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 [email protected], all occurrences of gasmigration to the Commission as soon as possible.

The permit holder is not required to test for gas migration unlessthere is visible evidence that it is occurring. Upon initialdiscovery of gas migration, a gas sample should be collected toidentify the source of the gas. Recommended gas migrationtesting procedures are as follows:

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

Documents

Well Completion Maintenance Abandonment Guideline May Release 2014