Well Completion, Maintenance and Abandonment Guideline

WELL COMPLETION, MAINTENANCE AND ABANDONMENT GUIDELINE January | 2012 Version 1.7

Well Completion, Maintenance and Abandonment Guideline 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 2.2 2.3 2.4 2.5 2.6 2.7

WELLHEADS ............ ......................... .......................... .......................... .......................... .......................... .......................... ......................... ............5 TUBING ............. .......................... .......................... .......................... .......................... .......................... .......................... .......................... ................. ....5 PACKERS ............ ......................... .......................... .......................... .......................... .......................... .......................... .......................... ................. ....5 SUBSURFACE SAFETY VALVES ............. .......................... .......................... .......................... .......................... .......................... ............... ..6 OIL WELLS .............. ........................... .......................... .......................... .......................... .......................... .......................... ......................... ............6 FENCING ............ ......................... .......................... .......................... .......................... .......................... .......................... .......................... ................. ....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 Fracturing Fluids Records................................... ................................................. ........................... .................. .....10 3.2.3 Commingling ............. .......................... .......................... .......................... .......................... .......................... ..................... ........10 3.3 WELL SUSPENSION ............ ......................... .......................... .......................... .......................... .......................... .......................... ............... 11 3.3.1 Definitions ............. .......................... .......................... ........................... ........................... .......................... ........................ ...........11 3.3.2 Observation Wells ............ ......................... .......................... .......................... ........................... ........................... .............11 3.3.3 Suspension Requirements ............ .......................... ............................ ........................... .......................... .............12 3.3.4 Packer Testing ............. ........................... ........................... .......................... ........................... ........................... ................. ....17 3.3.5 Long Term Inactive Wells ............................. ........................................... ........................... ........................ ...........17 3.3.6 Reactivating Suspended Wells ............ .......................... ............................ ........................... ................... ...... 17 3.3.7 Information / Reporting Requirements ..................... ................................... ......................... ...........17 3.4 CLASSIFICATION OF LOW AND MEDIUM RISK GAS WELLS ............. .......................... ........................... ................19 3.5 WELL ABANDONMENT ............ ......................... .......................... .......................... .......................... .......................... ...................... .........20

4 WELL SERVICING EQUIPMENT AND PROCEDURES .............................. .......................................... ............... ... 21 4.1 BLOWOUT PREVENTION............. .......................... .......................... .......................... .......................... .......................... .................... .......21 4.1.1 Well Servicing Blowout Prevention ....................................... .................................................... .............21 4.1.2 BOP Equipment Classes.......................... ........................................ ........................... .......................... ................. ....21 4.1.3 General ............ .......................... ........................... .......................... .......................... ........................... ........................... ............... ..22 4.1.4 A ccumulator systems ............ .......................... ........................... ........................... ............................ .................... ......22 4.1.5 Requirements Specific to Class A Systems............. .......................... ........................... ................ ..23 4.1.5 Requirements Spe cific to Class B and C Systems ............. ........................... ................... .....23 4.1.6 Line Requirements ............ ......................... ........................... ........................... ........................... ......................... ...........23 4.1.7 Stabbing Valve .............. ........................... .......................... .......................... ........................... ........................... ................ ...24 4.1.8 Blowout Prevention Manifold .............. ........................... .......................... ........................... .................... ...... 24 4.1.9 Testing of Blowout Prevention Equipment.............. Equipment........................... ........................... ..............24

BC Oil & Gas Commission

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Well Completion, Maintenance and Abandonment Guideline 4.1.10 Special Sour Wells ............. .......................... ........................... ........................... ........................... .................... ...... 25 4.1.11 Slickline, Snubbing and Coil Tubing Operations .............. ............................ ..............25 4.1.12 Hammer Unions ............. ........................... ........................... ........................... ........................... ...................... .........25 4.1.13 Diagrams of Blowout Prevention Systems for Well Servicing .......26 4.2 PERSONNEL ............. .......................... .......................... .......................... .......................... .......................... .......................... ....................... ..........31 4.3 FIRE PRECAUTIONS AND EQUIPMENT SPACING ............. ........................... ........................... .......................... ............... ..32 4.3.1 Engines ............ .......................... ........................... .......................... ........................... ........................... .......................... ................ ...32 4.3.2 Fuel ............ ......................... .......................... .......................... .......................... .......................... .......................... ....................... ..........32 4.3.3 Smoking ............. .......................... .......................... .......................... ........................... ........................... .......................... ...............32 4.3.4 Recommended Spacing Distances.......... Distances........................ ............................ ............................ ................ .. 33 4.3.5 Flare Stacks ............. .......................... .......................... .......................... ........................... ........................... ...................... .........34 4.3.6 Explosives ............. ........................... ........................... .......................... ........................... ........................... ........................ ...........34 4.4 INCIDENT REPORTING .............. ........................... .......................... .......................... .......................... .......................... ...................... .........34 4.5 CONCURRENT OPERATIONS ............. .......................... .......................... .......................... .......................... .......................... ............... ..34 5 ENVIRONMENTAL CONSIDERATIONS ........... ...................... ....................... ....................... ...................... ................... ........ 35 5.1 SURFACE CASING VENT FLOWS ............. .......................... .......................... .......................... .......................... ....................... ..........35 5.1.1 Definitions ............. .......................... .......................... ........................... ........................... .......................... ........................ ...........35 5.1.2 Checking for Surface Casing Vent Flows ................................. ............................................ ...........35 5.1.3 Testing and Reporting Surface S urface Casing Vent Flows .......................... ............................. ...36 5.1.4 Surface Casing Vent Flow Repairs ....................... .................................... .......................... .................. .....38 5.2 GAS MIGRATION ............. .......................... .......................... .......................... .......................... .......................... .......................... ................ ...39 5.2.1 Definitions ............. .......................... .......................... ........................... ........................... .......................... ........................ ...........39 5.3 CASING LEAKS AND FAILURES............. .......................... .......................... .......................... .......................... .......................... .............41 5.4 NOISE ............. .......................... .......................... .......................... .......................... .......................... .......................... .......................... ................. ....41 5.5 FLARING AND VENTING............ ......................... .......................... .......................... .......................... .......................... ...................... .........41 5.6 FLUID STORAGE .............. ........................... .......................... .......................... .......................... .......................... .......................... ................ ...41

6 DATA SUBMISSION ............................................................................................ 42 6.1 COMPLETION/WORKOVER/ABANDONMENT REPORTS ............. .......................... .......................... ................... ......42 6.1.1 Instructions for Completion of the Report .............. ............................ ........................... .............42 6.2 WELL DELIVERABILITY TEST REPORTS ............ ......................... .......................... .......................... .......................... ................ ...45 6.2.1 Well Deliverability Test Report Instructions ................... ................................. .................... ......45 6.3 OIL, GAS AND WATER ANALYSIS ............. .......................... .......................... .......................... .......................... ..................... ........48 6.4 HYDRAULIC FRACTURING FLUID REPORTS ............. ........................... ........................... .......................... ...................... .........48

7 COMPLIANCE ..................................................................................................... 49

OGAA ............. .......................... .......................... .......................... .......................... ......................... ......................... .......................... ...................... .........49 Drilling and Production Regulation ....................................... ..................................................... ........................... .............49 APPENDIX A ......................................................................................................... 50 APPENDIX B ......................................................................................................... 52


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Well Completion, Maintenance and Abandonment Guideline

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 1-Dec-2010 1-Jan -2011 1-Feb-2011 1-March-2011

1-May-2011

Section General 3 1 General

3&6

1-August-2011 1-Sept-2011

General 7

1- Nov-2011

General

1-Jan-2012 1-Feb-2012

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Description/Rationale Updated Links Changed the requirements for Wellbore Fluid in tables 3.2, 3.3 and 3.4 Updated links and Feedback email address. Updated formatting. No process changes. Completion/Workover Reports. Included information provided in IL 2011 05 and the Completion/Workover Report Submission Guide. Updated page numbers Added Compliance section. Updated links to BCOGC. Added Notice of Operation/Notice of Flare User Manual to Appendix B. Updated Table 4.1: Recommended Spacing Distances Added Section 6.4: Data Submission


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1 Preface 1.1

Purpose This manual has been created to guide users through the BC Oil and Gas Commission (the Commission) processes and procedures. It also serves to highlight changes in process, procedure, requirements and terminology resulting from the Oil and Gas Activities Act (OGAA). For users already familiar with the Commission application process, this manual provides a quick reference highlighting the steps required to complete specific tasks. For users less familiar, this manual presents a complete overview of Commission requirements and provides links to more detailed material. This manual is not intended to take the place of the applicable legislation. The user is encouraged to read the full text of legislation and each applicable regulation and seek direction from Commission staff, if and when necessary, for clarification.

1.2

Scope This manual focuses exclusively on requirements and processes associated with the Commission’s legislative authorities and does not provide information on legal responsibilities that the Commission does not regulate. It is the responsibility of the applicant or permit holder to know and uphold its other legal responsibilities. Examples of legal responsibilities outside of this manual include obligations under the Federal Fisheries Act, the Transportation Act, the Highway Act, the Workers Compensation Act, and the Wildlife Act.


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1.3

How to Use This Manual This manual is divided into sections which will take the user through the various operational steps and regulatory requirements related to well servicing activities, including completions, workovers, maintenance and abandonments. Section 2.0 Well Equipment explains regulatory requirements for well equipment in the Drilling and Production Regulation. Section 3.0 Well Servicing Operations outlines and explains the requirements for well completions, workovers, maintenance, suspension and abandonments. Section 4.0 Well Servicing Equipment and Procedures outlines and explains blowout prevention standards, personnel requirements and fire precautions that permit holders must follow to comply with the Drilling and Production Regulation. Section 5.0 Environmental Considerations outlines and explains the regulatory requirements for flaring, noise, fluid storage, casing leaks, surface casing vent flows and gas migration. Section 6.0 Data Submission outlines and explains the regulatory requirements the operator must include in reports for the completion, workover and abandonment of wells. Regulatory requirements for reporting on well deliverability tests are also included within this section. Section 7.0 Compliance describes contravention of legislation and regulation and administrative penalties.

1.4

Additional Guidance Guidance for submitting applications for wells within the jurisdiction of the Commission is located in the Well Permit Application Manual. Guidance for well construction, drilling, reclamation and waste management for wells within the jurisdiction of the Commission is located in the Well Drilling and Waste Management manuals The glossary page on the Commission website provides a comprehensive list of terms.


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Well Completion, Maintenance and Abandonment Guideline Other navigational and illustrative elements used in the manual include: Hyperlinks:

Sidebars: Figures: Tables:

Hyperlinked items appear as blue, underlined text. Clicking on a hyperlink takes the user directly to a document or location on a webpage. Sidebars highlight important information such as a change from the old procedure, new information, or reminders and tips. Figures illustrate a function or process to give the user a visual representation of a large or complex item. 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.


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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 [Section 16, Drilling and Production Regulation] Tubing is required for the production of gas containing ≥ 5% hydrogen sulphide (H2S) and for all injection and disposal except for the injection of fresh water.

2.3

Packers [Sections 16 and 39, Drilling and Production Regulation] A production packer must be used for: All injection and disposal except for the injection of fresh  water and  Wells containing gas with > 5% H2S, or if a numbered highway or populated area is located within the emergency planning zone for the well. “Populated area” means a dwelling, school, picnic ground or other place of public concourse.

Annual packer isolation testing is required for all wells where installation of a production packer is required. If a packer test fails, the permit holder must complete repairs without


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Well Completion, Maintenance and Abandonment Guideline unreasonable1 delay. Refer to the Alberta Energy and Resources Conservation Board (ERCB) Interim Directive ID 2003-01 for recommended packer testing procedures. The permit holder is required to maintain a record of all packer isolation tests and repairs. This information must be submitted to the Commission on request.

2.4

Subsurface Safety Valves [Section 39, Drilling and Production Regulation] Subsurface safety valves are required for wells containing gas with > 5% H2S if:  A major highway or populated area is located within the emergency planning zone for the well  The well is located within 800 m of a populated area or 8 km of a town, city or village and  The well could produce > 30 000 m 3 of gas per day In general, the distance from a city, town or village should be measured from the corporate limits. In cases where the corporate limits do not reasonably correspond with the boundaries of the community, the permit holder may take a functional approach such as delineation of the extent of developed areas.

2.5

Oil Wells [Section 39, Drilling and Production Regulation] Oil wells completed after September 13, 2010 equipped with an artificial lift, if the H 2S 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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In general, all repairs should be completed within 90 days. Reasonable delays are acceptable in cases where access is seasonal and the delay does not result in a risk to safety or the environment. Delays that extend past the next seasonal access window are not reasonable (greater than one year).


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2.6

Fencing [Section 39, Drilling and Production Regulation] Permit holders of completed wells that: Are located within 800 m of a populated area or  Have a populated area within the emergency planning  zone for the well Fencing or other measures to prevent unauthorized access to the well must be installed in these circumstances. Fencing or other forms of access control must be proportional to the potential for unauthorized access to the wellsite. Access control may include fencing of the wellsite, or gating the access road. If the well is located in an access-controlled area, no additional measures may be required. For wells that are located on private land, the method of access control should be developed in consultation with the landowner.

2.7

Leak Detection [Section 39, Drilling and Production Regulation] All completed wells must be equipped with a system to detect and control leaks as quickly as practicable. The Commission expects that leak detection systems will be proportional to the consequences that may result from a leak. Leak detection may range from fully automated shutdown systems to periodic inspections. If an uncontrolled flow from a completed well could produce a hydrogen sulphide concentration in atmosphere greater than 100 ppm at a distance of 50 metres from the well, the permit holder must install and maintain:  An automated shutdown system and  A hydrogen sulphide detection, alarm and automated shutdown system if the well is located within 1600 metres of a populated area For wells completed prior to October 4, 2010, H2S detection and automated shutdown systems are not required until January 1, 2012 and the permit holder may apply for an exemption to the requirement.


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Well Completion, Maintenance and Abandonment Guideline The following formula may be used to calculate the absolute open flow rate of a well that will result in an H 2S concentration in atmosphere of 100 ppm at a point 50 metres from the well: Wellhead AOF (103m3 /day) = 147 000 / H2S (ppm) or Wellhead AOF (103m3 /day) = 14.7 / H2S (mol %)


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3 Well Servicing Operations The well servicing operations section outlines and explains the requirements for the reporting of servicing, suspension, reactivation or abandonment of wells. It also outlines the notification requirements for completions, workovers and maintenance of wells.

3.1

Well Servicing Operations [Section 39, Drilling and Production Regulation] A permit holder must ensure that an adequate Emergency Response Plan is in place before conducting well servicing operations. Refer to the Emergency Response Plan Requirements document or contact the Commission Emergency Response and Safety Department for more information.

3.2

Completions / Workovers / Maintenance [Section 24, Drilling and Production Regulation] A Notice of Operations must be submitted to the Commission at least 24 hours prior to the start of all completion, workover or abandonment operations. An approved Application to Alter is no longer required for completion or workover operations. All notifications must be submitted using the Online Reporting System. Refer to Appendix B for the instruction manual. See Section 6.1 for Completion/Workover Report submission requirements.

3.2.1 Shallow Fracturing

[Section 21, Drilling and Production Regulation] Fracturing operations conducted at a depth of 600 metres or less must be approved in the well permit. Applications for shallow fracturing operations should include:  The fracture program design including proposed pumping rates, volumes, pressures, and fracturing fluids  Estimation of the maximum fracture propagation BC Oil & Gas Commission

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Well Completion, Maintenance and Abandonment Guideline  





 

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 Fracturing Fluids Records

[Section 37, Drilling and Production Regulation] Permit holders must maintain a record of the components of all fracturing fluids that are used in a well. The record must provide a “list of ingredients”, but does not need to include the quantities of each ingredient that is used. The Commission may require submission of this data, on a case by case basis, under Section 38 of OGAA. 3.2.3 Commingling

[Section 23, Drilling and Production Regulation] All zones in a well must remain segregated unless permission has been granted for commingled production. Permission may be granted in an individual well permit or by a special project for commingling under section 75 of OGAA. The Commission has designated certain areas where commingling is authorized, subject to certain conditions, including:  Deep basin  Plains and Northern Foothills  Outer Foothills For more information, refer to the Commingling section within the Commission’s Resource Conservation Forms and Guidelines page. The Notification of Commingled Well Production form must be submitted to the Commission within 30 days of the commencement of commingled production. BC Oil & Gas Commission

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3.3

Well Suspension [Section 25, Drilling and Production Regulation] 3.3.1 Definitions “Activity” means (a) production, injection, or disposal of fluids, (b) drilling, completion or workover operations and (c) reservoir pressure observation. “Inactive Well” means a well that has not been abandoned but

(a) has not been active for 12 consecutive months or (b) if the well is classified as a special sour well or an acid gas disposal well and has not been active for 6 consecutive months. For active production, injection and disposal wells, the date of last activity is defined as the first day of the month following the last month for which production, injection and disposal volumes were reported. Observation wells are deemed to be active (see Observation Wells section). For drilling activity, including new wells and re-entries, the date of last activity is defined as the rig release date. For completion and workover activity, the date of last activity is defined as the completion date. A permit holder may apply to the Commission to declassify a special sour well.

3.3.2 Observation Wells

Inactive wells offer good opportunities to monitor reservoir behaviour, specifically, pool pressures over time. Tests of these wells do not require shutting in producing wells to obtain pressure information and can provide accurate sampling points. Wells with an operational status of Observation must be tested and a Reservoir Pressure Survey Test Report must be submitted to the Commission Resource Conservation Department at least once every two years.


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Well Completion, Maintenance and Abandonment Guideline 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). 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.

Wellhead Maintenance

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 poli sh 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 m anaged and reported in accordance with Commission requirements. 

Lease Maintenance

as defined in Section 17 of the Drilling and Production Regulation must be in place. 



Visual Inspection

A sign stating the well’s surface location, current permit holder, the current permit holder’s emergency contact number and appropriate warning symbols

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.

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. 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.

Reporting


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Well Completion, Maintenance and Abandonment Guideline Table 3.2: Requirements Specific to Inactive High Risk Wells 

Well Types



Suspension Options

Type 1: Special sour wells2. Type 2: Acid gas disposal wells. Option A

Downhole Requirements

Pressure Testing / Monitoring / Servicing Requirements Pressure Testing / Monitoring / Servicing Frequency

Wellbore Fluid

Option B

Bridge plug or packer and tubing plug.

Bridge plug capped with 8 m lineal of cement.

Pressure test both tubing and annulus to 7 MPa for 10 minutes.

Pressure test the casing to 7 MPa for 10 minutes.

Service and pressure test wellhead sealing elements.

Service and pressure test wellhead sealing elements (if applicable).

At the time of suspension and then annually.

At the time of suspension and then every 5 years.

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 nonsaline 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.

2

If applicable, install a bridge plug or packer and tubing plug within 100 metres of the liner top on uncompleted special sour wells.


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Well Completion, Maintenance and Abandonment Guideline Table 3.3: Requirements Specific to Inactive Medium Risk Wells

Type 1: Medium risk gas wells (see Section 3.4). Type 2: Non-flowing oil wells ≥ 50 mol/kmol H 2S. 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.

  

Well Types





Suspension Options Downhole / Wellhead Requirements

Option A (All types)

Option B (All types)

Option C (Type 6 Only)

Packer and tubing plug.

Bridge plug.

Dual master valves.

Pressure test both the tubing and annulus to 7 MPa for 10 minutes.

Pressure test the casing to 7 MPa for 10 minutes.

Read and record shut-in tubing pressure (if applicable) and shut-in casing pressure.



Pressure Testing / Monitoring / Servicing Frequency



At the time of suspension and then annually.

Wellbore Fluid

Wellbore must be filled with non-saline water or corrosion inhibited water. The upper portion of the wellbore must be protected from freezing. Freeze protection may be accomplished by the placement of at least 2 m of a suitable, nonfreezing 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, nonfreezing fluid at surface.

None.

Pressure Testing / Monitoring / Servicing Requirements


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.


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Well Completion, Maintenance and Abandonment Guideline Table 3.4: Requirements Specific to Inactive Low Risk Wells



Type 1: All non-special sour cased wells (no perforations or open hole sections). Type 2: Low risk gas wells (see Section 3.4). Type 3: Water source wells.



Type 5: Non-flowing oil wells < 50 mol/kmol H2S.



Well Types



4

Suspension Options

Option A

Option B

(Types 2,3 and 5 only)

(Type 1 only)

Downhole Requirements

None.

Pressure Testing / Monitoring / Servicing Requirements

Read and record shut-in tubing Pressure test casing to 7 MPa for 10 pressure (if applicable) and shut-in minutes. casing pressure. Service and pressure test wellhead Service and pressure test sealing elements (if applicable). wellhead sealing elements.

Pressure Testing / Monitoring / Servicing Frequency



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.

Wellbore Fluid

None.

4

Non-flowing oil wells are oil wells without sufficient reservoir pressure to sustain flow against atmospheric pressure without artificial lift. T he 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.


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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 Suspension Report must be submitted to the Commission, Drilling and Production Department within 30 days of suspension of a well.


17

Well Completion, Maintenance and Abandonment Guideline The suspension report may be submitted as a paper copy or in spreadsheet form. Reactivations Submission of a reactivation report is not required. Reactivations are identified by alternate means (i.e. spud date, production reporting). Inspections Records of inspections must be provided to the Commission on request. Inspection results may be recorded by filling out the applicable sections of the Well Suspension/Inspection Form or through the permit holder’s in ternal 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)


18


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 (10 3m3 /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.

100000 MEDIUM RISK

10000

) 1000 m p p ( S 2 100 H

535 ppm

LOW O RISK

10

1 1

10 Flowrate (x 1000

3

m3 /day)

28,000 m /day

100

Figure 3.1: Classification of Low and Medium Risk Gas Wells (Adopted from ERCB Directive 13). 5

This calculation (adopted from the ERCB Directive 13) determines the maximum flowrate for a given H 2S concentration that will result in a maximum concentration of H 2S at the lease boundary of 10 ppm. The lease boundary is assumed to be 50 metres from the wellhead. 6 Maximum flowrate is adopted from the ERCB Directive 13 and is considered to be surface killable based on fluid momentum theory.


19


3.5

Well Abandonment [Section 26, Drilling and Production Regulation] For drilling wells, notification is not required prior to conducting open hole plugbacks or abandonments. Drilling wells that are downhole, but not surface abandoned at the time of rig release, are not considered abandoned. An abandonment notification and abandonment report must be submitted to the Commission at the time of surface abandonment as outlined below for the well status to be changed to abandoned. Notification is required 7 days prior to conducting all other well abandonments; however the notification requirement may be waived on a case by case basis. An abandonment program must be included with the notification. Wells must be abandoned in a manner that ensures:  Adequate hydraulic isolation between porous zones  Fluids will not leak from the well  Excessive pressure will not build up in any portion of the well  The long-term integrity of the wellbore is maintained Permit holders are expected to conduct abandonments and plugbacks in accordance with the ERCB Directive 20. If there is any doubt about the adequacy of a plugging or abandonment program, the permit holder should discuss their plans with the Commission. Failure to adequately plug or abandon a well may result in an order for remedial work. Abandonment reports may be submitted using a Completion/Workover Report Form.


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4 Well Servicing Equipment and Procedures The well servicing equipment and procedures section outlines and explains blowout prevention standards, personnel requirements and fire precautions that permit holders must follow to comply with the Drilling and Production Regulation.

4.1

Blowout Prevention [Part 4, Division 2, Drilling and Production Regulation] 4.1.1 Well Servicing Blowout Prevention

The following section outlines blowout prevention standards that a permit should follow to comply with the requirements of Part 4, Division 2 of the Drilling and Production Regulation. It is the responsibility of the permit holder to ensure that blowout prevention equipment and procedures are adequate. A permit holder may use alternate blowout prevention equipment and techniques if they can demonstrate by means of a detailed engineering analysis that the alternate equipment or techniques are adequate as required by section 16(1) of the Drilling and Production Regulation. 4.1.2 BOP Equipment Classes

For the purposes of well servicing, blowout prevention equipment classes are as follows: Class A equipment is required for a well where the minimum pressure rating of the production casing flange is less than or equal to 21 000 kilopascals (kPa) and the hydrogen sulphide content in a representative sample of the gas is less than 10 mol %; Class B equipment is required for a well where the minimum pressure rating of the production casing flange is: a) greater than 21 000 kPa, or b) less than or equal to 21 000 kPa and the hydrogen sulphide content in a representative sample of the gas is 10 mol % or greater Class C equipment is required for a special sour well.


21

Well Completion, Maintenance and Abandonment Guideline 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


22

Well Completion, Maintenance and Abandonment Guideline e) Capable of closing the annular preventer within 60 seconds f) Equipped with readily accessible fittings fittings and gauges to determine the pre-charge pressure g) Equipped with a check valve 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 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 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 steel or flexible sheathed hose to provide adequate fire resistant rating


23

Well Completion, Maintenance and Abandonment Guideline b) Be valved and have a working 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 located in a readily accessible location on the service rig b) Be maintained in the the open position c) Have an internal diameter equal to or greater 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 prevent flow from well to rig pump c) Contains a pressure relief valve upstream of the check valve d) Is equipped with 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 preventer to 1400 kPa, prior to the tests described in (b) and (c) b) Each ram preventer, the full opening safety valve valve and the connection between the stack and the wellhead, tested to the wellhead pressure rating or the formation pressure, whichever is less c) Each annular preventer to 7000 kilopascals or the formation pressure, whichever is less


24

Well Completion, Maintenance and Abandonment Guideline 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


25


4.1.13 Diagrams of Blowout Prevention Systems for Well Servicing

Figure 4.A Equipment Symbols


26


Figure 4.B


BOP Class A Pressure Rating and Component Placement Notes: 1. Pressure rating of preventers is equal to or greater than the production casing flange rating or the formation pressure, whichever is the lesser. 2. 50 mm lines throughout 3. The positioning of the tubing and blind rams may be interchanged. 4. Spool may have threaded side outlet (and valve) if wellhead has threaded fittings. 5. A flanged BOP port (and valve) below the lowest set of rams may replace spool (valve may be threaded if wellhead has threaded fittings).

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Figure 4.C


BOP Class B Pressure Rating and Component Placement Notes: 1. Pressure rating of preventers is equal to or greater than the production casing flange rating or the formation pressure, whichever is the lesser. 2. 50 mm lines throughout 3. The positioning of the tubing and blind rams may be interchanged. 4. Spool may have threaded side outlet (and valve) if wellhead has threaded fittings. 5. A flanged blowout preventer port (and valve) below the lowest set of rams may replace spool (valve may be threaded if wellhead has threaded fittings.)

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Figure 4.D


BOP Class C Wellhead Configuration

29


Figure 4.E


BOP Class C Optional Wellhead Configuration

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4.2

Personnel [Section 13, Drilling and Production Regulation] The permit holder must ensure that there are a sufficient number of trained and competent individuals to carry out all well operations safely and without causing pollution. The following people must possess a valid Well Service Blowout Prevention Certificate, issued by Enform:  The driller on tour  The rig manager (tool push) and  The permit holder’s representative If gas containing H2S is expected, every crew member must be trained in H2S safety. Blowout prevention drills should be performed by each rig crew every 7 days or once per well, whichever is more frequent. Blowout prevention drills should be recorded in the servicing log book. Evidence of the qualifications of any person referred to in this section must be made available to an official on request. The rig crew must have an adequate understanding of, and be able to operate, the blowout prevention equipment and, when requested by an official and if it is safe to do so, the contractor or rig crew must:  Test the operation and effectiveness of the blowout prevention equipment and  Perform a blowout prevention drill in accordance with the Well Control Procedure placard issued by the Canadian Association of Oilwell Drilling Contractors or as outlined by the Enform Blowout Prevention Manual Refer to Enform IRP#7 Standards for Wellsite Supervision of Drilling, Completions and Workovers for more information.


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4.3

Fire Precautions and Equipment Spacing [Sections 45 and 47, Drilling and Production Regulation] 4.3.1 Engines

Permit holders must ensure that, if engines are located at a wellsite, suitable safeguards are installed and tested to prevent a fire or explosion in the event of a release of flammable liquids or ignitable vapours. For engines located within 25 metres of a well, petroleum storage tank or other unprotected source of ignitable vapours, the Commission recommends that: The engine exhaust pipe is insulated or cooled to prevent  ignition in the event that flammable material contacts the exhaust pipe  The exhaust pipe is directed away from the well or source of ignitable vapours and  The exhaust manifold is sufficiently shielded to prevent contact with flammable materials For diesel engines located within 25 metres of a well, the Commission recommends that one of the following devices be installed: A positive air shutoff valve, equipped with a readily  accessible control  A system for injecting inert gas into the engine’s cylinders, equipped with a readily accessible control or  A suitable duct so that air for the engine is obtained at least 25 metres from the well Permit holders must also ensure compliance with the requirements in Section 23.8 of the Occupational Health and Safety Regulation. 4.3.2 Fuel

Gasoline or liquid fuel, except for fuel in tanks that are connected to operating equipment, must not be stored within 25 metres of a well and drainage must be away from the wellhead. 4.3.3 Smoking Smoking is prohibited within 25 metres of a well.


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4.3.4 Recommended Spacing Distances

Permit holders must ensure that appropriate spacing is maintained between potential sources of flammable liquids or ignitable vapours and ignition sources. All fires must be sufficiently safeguarded and all vessels and equipment from which ignitable vapours may issue must be safely vented. It is the responsibility of the permit holder to maintain sufficient equipment spacing.

D A E H L L E W

WELLHEAD FLARE OR INCINERATOR BOILER, STEAM GENERATING EQUIPMENT, TEG* PRODUCED WATER TANK

R O T A R E N I C N I R O E R A L F

50 50

G N I T A * R G E E N T , E T G N M E A M E P T I S U , R Q E E L I O B

K N A T R E T A W D E C U D O R P

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

R O T A R A P E S

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

S S D K I N U A T Q I L E T E L A B S A N E M D M N O A L C F D & E L I C O U E D D O U R R P C

25

NS

NS

NS

25*

50

NS

25

25

25

25

50

25

25

25

25

25

NS

NS

25*

NS

NS

25*

NS

25*

NS** 25*

25

NS

NS

25

25

OTHER SOURCES OF IGNITABLE VAPOURS

NS

25

25

NS

SEPARATOR

NS

25

25

NS

NS

FLAME TYPE EQUIPMENT

25*

25

25

25*

25*

25*

T

PRODUCED FLAMMABLE LIQUIDS CRUDE OIL & CONDENSATE TANKS

50

50

25

NS

NS

NS**

25*

All distances are in metres (m). *

25 m without flame arrestors, not specified with flame arrestors.

**

Separator cannot be in the same dyke.

T

Treaters should be at least 5 m (shell to shell) from other treaters.

Note: a) Boilers etc. Includes steam generating equipment, electric generators and TEG units. b) Other sources of ignitable vapours include compressors.


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Well Completion, Maintenance and Abandonment Guideline c) Flame type equipment includes: treaters, reboilers and line heaters. d) All electrical installations must conform to the Canadian Electrical Code. Table 4.1 Recommended Spacing Distances

Flares and incinerators must be located at least 80 metres from any public road, utility, building, installation, works, place of public concourse or reservation for national defence. 4.3.5 Flare Stacks

A sufficient area beneath and around flare stacks must be cleared of flammable materials and vegetation. The recommended blackened area beneath a flare stack is 1.5 times the stack height. The Commission recognizes that a lesser area may be justified depending on the circumstances. It is the responsibility of the permit holder to maintain a sufficient area, given the location and the conditions under which flaring will or may occur. 4.3.6 Explosives

Explosives must be stored in properly constructed magazines and be located a minimum of 150 metres from any well servicing operation.

4.4

Incident Reporting Spills and well control incidents must be reported to the Provincial Emergency Program (PEP) at 1-800-663-3456, and the Commission at (250) 794-5200 Spills must be reported in accordance with the Spill Reporting Regulation.

4.5

Concurrent Operations A concurrent operations plan is required for completions operations on any well that is located within 25 metres of another well. Refer to Commission Information Letter OGC IL 08-20 for more information.


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5 Environmental Considerations The environmental considerations section outlines and explains the regulatory requirements for testing, repairing and reporting environmental impacts: surface case venting flows, gas migration, casing leaks and failures, noise, flaring and venting, fluid storage and spills.

5.1

Surface Casing Vent Flows [Section 41, Drilling and Production Regulation] 5.1.1 Definitions “Surface Casing Vent Flow” (SCVF) means the flow of gas and/or liquid from the surface casing/casing annulus. “Serious Surface Casing Vent Flow” means  



A vent flows with hydrogen sulphide (H2S) present A vent flow with a stabilized gas flow rate equal to or greater than 300 cubic metres per day (m3 /d) A vent flow with a surface casing vent stabilized shut-in pressure greater than one half the formation leak-off pressure at the surface casing shoe or o 11 kPa/m times the surface casing setting depth 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 o

  





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


35

Well Completion, Maintenance and Abandonment Guideline 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 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 BC Oil & Gas Commission

36

Well Completion, Maintenance and Abandonment Guideline of five years. The permit holder may select appropriate yearly testing measures, however, the Commission may order specific test measures for surface casing vent flows of particular concern. If there is no change in the flow rate or shut in pressure after five years of testing, or if the vent dies out, no further testing is expected. If a non-serious vent flow becomes serious, the permit holder must notify the Commission as soon as possible. Recommended surface casing vent flow test procedures are as follows: 5.1.3.1 Measuring Flowrate

Once a positive vent flow is detected, the flow rate and stabilized shut in pressures must be recorded. To measure venting gas volumes, a positive displacement gas meter, turbine meter or an orifice well tester may be used. Equipment selection should be based on previous observations indicating what flow rate and pressure range can be expected. A positive displacement meter will be necessary to measure low volumes accurately. An orifice well tester, with proper orifice plate, may provide satisfactory measurements if the 24 hour shut in pressure is 200 kPa or greater and builds quickly. Install and use the equipment according to manufacturer’s instructions and 1) Do not exceed the pressure/volume range of the equipment

2) Ensure that there are no leaks 5.1.3.2 Measuring Buildup Pressure

To determine the maximum shut-in surface casing pressure the following method can be used. Pressure Buildup Required Equipment:  Pressure gauge or single pen static pressure recorder with 24 hour chart or  Dead weight pressure gauge or  Electronic pressure recorder A pressure relief valve, calibrated to release the pressure if it has built to its maximum allowable surface pressure, should be installed on the surface casing vent while measuring the build up pressure. If it is anticipated that the maximum allowable shut BC Oil & Gas Commission

37

Well Completion, Maintenance and Abandonment Guideline 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 nonserious surface casing vent flow, the permit holder may consider the installation of a burst plate or pressure safety valve (PSV). The permit holder must obtain an exemption to section 18(8)(a) of the Drilling and Production Regulation to allow the installation of a burst plate or pressure safety valve. Non-serious surface casing vent flows must be repaired at the time of well abandonment. 5.1.4.2 Serious Repair

The permit holder of a well determined to have a serious surface casing vent flow should contact the Commission as soon as possible to discuss repair or management requirements. 5.1.4.3 Surface Casing Vent Flow Production

If the permit holder wishes to explore the option of producing the surface casing vent flow, an application must be made to the Drilling and Production Department to obtain an exemption to section 18(8)(a) of the Drilling and Production Regulation. Requests will be considered if:  The source depth and formation of origin has been clearly identified


38

Well Completion, Maintenance and Abandonment Guideline 





The permit holder owns the mineral rights to produce the source formation The cemented portion of the surface casing or the next casing string covers the deepest known usable groundwater and The flow has been analyzed and determined to be sweet (0 percent H2S)

The Commission may rescind the approval to produce from the surface casing vent and may require the surface casing vent flow to be repaired at any time if the Commission determines a safety or environmental hazard exists.

5.2

Gas Migration [Section 41, Drilling and Production Regulation] 5.2.1 Definitions “Gas Migration” (GM) means a flow of gas that is detectable at

the surface outside of the outermost casing string (often referred to as external migration or seepage). “Serious Gas Migration” means gas migration that

1) Contains hydrogen sulphide 2) Creates a fire or public safety hazard or 3) May cause off-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: 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 BC Oil & Gas Commission

39

Well Completion, Maintenance and Abandonment Guideline of diesel fuel, solvents, oil, etc. If contaminated soils are suspected, the soil must be excavated and removed. Retesting is then required. Instrumentation must be calibrated regularly and checked daily when in use. Select sample testing points as follows: Two within 30 cm of wellbore on opposite sides  At two metre intervals outward from the wellbore every 90  (a cross with the wellbore at centre) to a distance of six metres and  At any points within 75 metres of the wellbore where there is apparent vegetation stress Required Equipment: Bar or auger (64 mm or less in diameter) capable of  penetrating a minimum of 50 cm  Calibrated monitor or other instrument capable of detecting hydrocarbon at one percent lower explosive limit (LEL)  Equipment or material to seal the hole at surface while soil gases are being evacuated from the soil through the instrument Test Procedure: 1) Perform instrument check (for example,calibration, voltage, zero) 2) Insert auger or make a bar hole a minimum of 50 cm deep 3) Isolate the hole from atmospheric contaminations 4) Insert hose, wand, or other equipment a minimum of 30 cm into hole, maintaining a seal at surface to prevent atmospheric gas and soil gas mixing 5) Withdraw soil gas sample. The volume, rate, etc., will depend on the instrumentation being used. Ensure that a sufficient sample is removed to purge lines and instrumentation 6) Record observations 7) Purge instrument and lines


40


5.3

Casing Leaks and Failures [Section 18, Drilling and Production Regulation] A permit holder must notify the Commission of any casing leak or casing failure as soon as possible. The leak or failure must be repaired within a reasonable time frame, giving consideration to the accessibility of the site and the seriousness of the leak or failure.

5.4

Noise [Section 40, Drilling and Production Regulation] A permit holder must ensure that well operations do not cause excessive noise. Permit holders should work with area residents to minimize noise impacts when undertaking completions activities near populated areas. The B.C. Noise Control Guideline (OGC IL 09-09) contains information regarding acceptable noise levels and noise assessment techniques.

5.5

Flaring and Venting Refer to the Flaring and Venting Reduction Guideline for detailed guidance.

5.6

Fluid Storage [Section 50, Drilling and Production Regulation] Secondary containment of tanks associated with completions operations is generally not required. For extended, unmanned flowback operations that require a facility permit, secondary containment in accordance with the National Fire Protection Agency’s Flammable and Com bustible 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).


41


6 Data Submission This section describes the regulatory requirements for reporting on the completion, workover and abandonment of wells, as well as regulatory requirements for reporting on well deliverability tests and hydraulic fracturing fluid. All data referred to in this section, with the exception of hydraulic fracturing fluid reports, must be submitted to the Commission’s Victoria office: Well Data Management BC Oil and Gas Commission 300-398 Harbour Road Victoria, B.C. V9A 0B7 Hydraulic fracturing fluid reports are only accepted electronically and can be uploaded to KERMIT.

6.1

Completion/Workover/Abandonment Reports [Sections 26 and 36, Drilling and Production Regulation] Two signed copies of the Completion/Workover Report and required attachments must be submitted to the Commission office in Victoria within 30 days of completing the operation. Incomplete reports will not be accepted and will be returned to sender. If a well has been abandoned, a summary of the surface abandonment must be included for the well status to be changed to abandoned and the location to be a candidate for a Certificate of Restoration. Appendix A specifies which operations require a Completion/Workover Report and which operations do not. Refer to Information Bulletin 2011-05 for more information. 6.1.1 Instructions for Completion of the Report Statements such as “see attached daily reports” are unacceptable and deemed incomplete. Incomplete reports will not be accepted and will be returned.


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6.1.1.1 Reason for work

State the purpose of the operation (For example, initial completion; to increase productivity; to shut-off water flow, etc.) 6.1.1.2 Chronological summary of work done

Including date, state the highlights of the operation such as perforation intervals, zone(s), stimulation operations, final flow rates, pressure tests, fluid recovery, plugs, type of completion string installed. 6.1.1.3 Example Summary:

2006/11/10 Perf Bluesky 971.2 –973.4 mKB 2006/11/13 Frac: Pump 1.5 m3 15% HCL acid. Pump 10 m3 Fracsol, 10 tonnes of 20/40 mesh sand. Formation breakdown @ 21,000 kPa. 2006/11/16 Flowed gas 3.720 103m3 /d @ 2200 kPa. Water production 2.1 m3 /hr. 2006/11/21 Bluesky uneconomic. Abandoned perfs w/bridge plug at 969 mKB w/ 8 lineal m cement on top. Pressure tested BP. 2006/11/28 Cut off casing 1 m below ground, welded vented plate on casing. Wellsite requires surface restoration. A Downhole Schematic Diagram and a copy of the Detailed Daily Report of the completion, workover or abandonment operations must be attached to each copy of the Completion/Workover Report. In cases where a service rig is not used, a copy of the service company’s report to the operator may be submitted instead of the detailed daily reports. 6.1.1.4 Completion Type

Indicate what kind of completion was done (for example, completion of two zones [dual], multiple zones perforated [three or more], openhole well).


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6.1.1.5 Completion Activity

Indicate the main purpose or type of the completion or workover (for example, openhole, perforate, fracture, acidize, cement squeeze or remedial). 6.1.1.6 Stimulation Type

State which stimulation type achieved breakdown or well flow. 6.1.1.7 Stimulation Volume

State the total fluids pumped in the stimulation in cubic metres (m3). 6.1.1.8 Stimulation Pressure

State the maximum pressure used in the stimulation in kilopascals (kPa). 6.1.1.9 Flow Summary

If applicable, indicate the hydrogen sulphide percent, oil rate, water rate, choke size or API gravity. 6.1.1.10 Flow Rate

State the final gas flow rate in 103m3 /day. 6.1.1.11 Flow Pressure

State the final flow pressure in kPa. 6.1.1.12 Flow Date

State the final flow date. 6.1.1.13 Radioactive material

Indicate whether 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. BC Oil & Gas Commission

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Well Completion, Maintenance and Abandonment Guideline 6.1.1.14 Result of work done

State the outcome of the operation (for example, well on production, productivity increased from 24 m3 per day to 31 m3 per day, water flow successfully shut-off) For the above example, the result would be “well abandoned”.

6.2

Well Deliverability Test Reports [Section 63, Drilling and Production Regulation] 6.2.1 Well Deliverability Test Report Instructions 6.2.1.1 Report Filing

A report is required for all: Deliverability type flow tests  Clean-up flows  Under-balanced drilling operations that result in burnable  gas to surface.  Reports are due within 60 days of the completion of the test. Absolute open flow (AOF) tests are required for all:  Wells producing form pools with suspected water drive  Wells that are classified as exploratory wildcat or exploratory outpost 6.2.1.2 Test Type

Indicate the appropriate test type by selecting the corresponding check box. Where the sole purpose of the test is a well cleanup, select “CU” as the test type and enter t he applicable rate and volume data. However, if a clean-up period is carried out in conjunction with a subsequent deliverability test, select the test type corresponding to the deliverability test and include the clean-up flow rate and production volumes on the same form with the AOF data. 6.2.1.3 Under-Balanced Drilling

This form is to be submitted for under-balanced drilling (UBD) operations that result in burnable gas to surface. Reported test type should be “UBD”. Flared gas volumes reported are to be the net volume produced by the target formation (gas produced


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Well Completion, Maintenance and Abandonment Guideline minus gas injected). Net gas rates should be representative of the burnable gas produced near the end of under-balanced drilling operations with the duration being the cumulative time that flaring occurs. A copy of the field notes recorded during drilling must be provided with this report. 6.2.1.4 Test Date

The test date is the final date the well was flowing during the testing period. 6.2.1.5 Absolute Open Flow and n Value

The sandface and wellhead absolute open flow values should be calculated at both extended and stabilized conditions. For low productivity wells with test rates less than 20 10 3m3 /d, the calculation of only the wellhead absolute open flow value is permitted. Complete details of all absolute open flow calculations must be included with the test submission. The Commission records the reciprocal slope “n” value as derived from the Simplified Analysis technique. Where the value of “n” is derived from the test data, the assumed flag should be checked as “no”. Single point test is normally checked as “yes”, unless the “n” is derived from an earlier test on the well under similar wellbore and reservoir conditions. 6.2.1.6 Pressures

Pressure data is reported for all test types other than CU or UBD. Shut-in pressure is defined as the bottomhole pressure as measured prior to each flow rate. Final flow pressure is the bottomhole pressure as measured at the end of that flow period. Stabilized reservoir pressure is entered on the form under “Reservoir Pressure”.

Pressure is to be reported in absolute, to the nearest kPa. The Commission’s accepted correction factor for gauge to absolute is 101 kPa. All tests, other than stand-alone clean up flows and underbalanced drilling operations, also require the submission of a corresponding Reservoir Pressure Survey Test (PST) report form with the pressure data. If a valid stabilized reservoir


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Well Completion, Maintenance and Abandonment Guideline pressure recording is made both prior to and following the flow test, then a separate PST form must be submitted for each point. 6.2.1.7 Test Remarks

Please use the comments section to make remarks pertinent to the well or specific test, indicate any information that would help in interpreting the test data or in designing future tests on the well. Examples:  Following frac and acid squeeze  Slugging water throughout test  No bottom-hole gauges run  Predict stabilized conditions in three months  Well suspended past 12 years 6.2.1.8 Abbreviations and Acronyms AOF Absolute open flow potential CF Casing flange elevation CU Clean up EXT Extended rate FAF Flow after flow FPMI Four point modified isocronal kPaa KiloPascals absolute m Metres MP Multi-point MPP Mid-point of perforations/completion n Reciprocal slope of gas rate versus pressure Squared plot (Simplified Analysis) SP Single point UBD Underbalanced drilling WA# Well authorization number


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6.3

Oil, Gas and Water Analysis [Sections 62, 67 and 71 Drilling and Production Regulation] A well permit holder must take a representative crude oil and/or gas sample (as appropriate) from each producing formation in a well within six months of initial production. If a well has produced sufficient water to allow representative sampling, the permit holder must collect a water sample and analyze the sample for mineral and ion content. All sample results must be submitted to the Commission within 60 days of analysis.

6.4

Hydraulic Fracturing Fluid Reports In accordance with Section 37 of the Drilling and Production Regulation, a well permit holder must maintain a record of the composition of fracturing fluids and submit a hydraulic fracturing fluid report to the Commission within 30 days of completing the hydraulic fracturing operation. The hydraulic fracturing fluid report must include, but is not limited to: Well Authorization number   Fracture date  Ingredients and purpose  Ingredient concentration in additive and fracture fluid  Chemical Abstract Service Number (CAS #)  Total volume of water with ingredients injected  Trade name and supplier of ingredients Hydraulic fracturing fluid reports are only accepted electronically and can be uploaded to KERMIT. For more information, please refer to the Fracture Fluid Report Upload Manual.


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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.


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Appendix A A Completion/Workover Report is required for all COMPLETIONS, WORKOVERS and ABANDONMENTS including, but not limited to the following operations:  Abandonment (permanent plugging of a well or zone). Acid job for stimulation of production   Casing repair, casing patch  Cement plugs, cement squeeze Drilling out cement plugs (unless part of a drilling  operation)   Fracture treatment Injectivity testing  Installation of artificial lift, includes all forms of pumping   methods, plunger lift  Installation of bridge plugs, cement retainers & packers.  Installation of downhole choke  Installation or removal of subsurface safety valves  (except for inspection and repair purposes)  Installation of tubing, e.g.: velocity strings, endless tubing  Installation or removal of tubing plugs (non temporary/   well suspension) Logging for re-entry  Open hole completions (including those conducted by a   drilling rig)  Perforating, milling, abrasion Pulling or replacing casing  Re-perforate an existing zone   Shifting sliding sleeves for commingling of producing zones  Surface casing vent flow repair  Well suspension with permanent bridge plug  Re-entry of an abandoned well (unless part of a drilling operation)


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Well Completion, Maintenance and Abandonment Guideline A Completion/Workover Report is NOT REQUIRED for the following well MAINTENANCE operations:   

    

    


Acid used to clean tubing of scale Back pressure valves Chemical injection for wellbore integrity, methanol injection, wax removal, sulphur removal Chemical cutters, fishing Nitrogen or CO2 blow-downs, well cleanup Packer isolation testing, pressure test casing Packer removal, repair and reinstallation in the wellbore Removal or repair of artificial lift, includes all forms of pumping methods, plunger lift Slickline work; running recorders, gradients Surface casing vent flow rate and build-up pressure testing Tubing repair Wellhead changes, which includes wellhead repairs; installation of master valves

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Appendix B

Online Drilling Reporting System Notice of Operation / Notice of Flare User Manual

September 2011 Version 1.3


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1

USING THE APPLICATION ............................................................................ 54 1.1 1.2

2

NOTICE OF OPERATION ............................................................................... 56 2.1 2.2 2.3 2.4 2.5 2.6

3

DRILLING RESULTS APPLICATION MAIN MENU ..................................................................................... 54 SIGN ON ....................................................................................................................................... 54

NOTICE OF OPERATION – WELL SELECTION ......................................................................................... 56 SELECT A WELL RECORD .................................................................................................................. 57 Q UERY FOR A SPECIFIC RECORD......................................................................................................... 57 ENTER NOTICE OF OPERATION .......................................................................................................... 58 COMPLETION REPORT REQUIRED ....................................................................................................... 62 COMPLETION REPORT OVERDUE ....................................................................................................... 63

NOTICE OF FLARE ........................................................................................ 64 3.1 3.2 3.3 3.4 3.5 3.6

NOTICE OF FLARE - WELL SELECTION ................................................................................................. 64 SELECT A WELL RECORD .................................................................................................................. 65 Q UERY FOR A SPECIFIC RECORD......................................................................................................... 65 ENTER NOTICE OF FLARE .................................................................................................................. 66 SUBMIT FLARE VOLUMES ................................................................................................................. 68 FLARE VOLUME OVERDUE ................................................................................................................ 69


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1 USING THE APPLICATION

1.1 Drilling Results Application Main Menu The BC Oil and Gas Commission has enabled the electronic submission of Notice of Operation and Notice of Flare related information via the Online Drilling Reporting System. The Online Drilling Reporting System is comprised of the following menu system. Drilling Activity This menu item is used by Industry for the weekly submission of drilling activity information. Directional Survey e-Submission of Directional Well Survey Files. Notice of Operation Select well for which Notice of Operation information is to be submitted. Completion Report Required List Notices of Operation for which the submission of a Completion Report is required. Completion Report Overdue List Notices of Operation for which Completion Report has not been received 60 days after end of operation. Notice of Flare Select well for which Notice of Flare information is to be submitted Submit Flare Volumes Enter actual flare volumes for Notices of Flare. Flare Volume Overdue List Notices of Flare for which no flare volume has been received 60 days after end date of Flare.


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1.2 Sign On You can access the Online Drilling Results Application by selecting ‘Web Applications’ from the OGC’s main web page at www.bcogc.ca.

From the Web Application section of the OGC website you will be directed to the logon page depicted below.

Enter your username and password and navigate to the Rich Client Applications Menu. From there select the link for Notice of Operation or Notice of Flare. These links will direct you to the Online Drilling Reporting System’s Main Menu.


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2 NOTICE OF OPERATION

2.1 Notice of Operation

–

Well Selection

Selecting the Notice of Operation button from the Online Drilling Reporting System Main Menu will direct the user to the Notice of Operation Well Selection screen.

By Default the Notice of Operation Well Selection screen displays all wells for which you are able to enter a Notice of Operation. The list of wells presented is ordered by descending WA #. In order to enter Notice of Operation information the user must first select a well record. This can be accomplished in one of two ways:


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2.2 Select a Well Record Select a Record Highlight the well record for which you want to submit a Notice of Operation.

Notice of Operation Click the Notice of Operation button to navigate to the Notice of Operation entry

screen.

2.3 Query for a Specific Record The user can choose to query for a specific well based on any combination of fields displayed on the screen.

Switch to Query Mode Click on the Enter Query button.


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Enter Specific Query Parameters User can query on any field displayed on the screen. In the example at left the user has

entered a value to the WA NUM field to query by WA#.

Find Records based on Query Parameters Click on the Execute Query button.

Click on the Notice of Operation button to navigate to the Notice of Operation screen.

2.4 Enter Notice of Operation


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Well Completion, Maintenance and Abandonment Guideline Mandatory data items to be entered to the Notice of Operation main canvas depicted above include: complete NTS or DLS Bottom Hole Location , Site Supervisor #1 Name and Phone, Work to be Performed , Expected Start Date and Expected End Date. The Completion Report Required indicator is a display only field which has its value set automatically based on the value entered to the Work to be Performed field. Completion Reports are required for all values of Work to be Performed except MTCE – Maintenance. Completion Reports are due 30 days after the Expected End Date of the Operation. The Completion Report Received field is entered by OGC staff and indicates the date on which the Com pletion Report was received by the OGC. The OGC Review Complete field indicates whether or not OGC staff have completed their review of the Notice of Operation. Notice of Operation information can not be edited once the OGC Review is complete.

The Notice of Operation screen Formation H2S canvas depicted above enables the entry of geological formations and H2S concentrations. The Expected H2S % field will accept values between 0 and 99.99. Users can select the Formation from a List of Values by double clicking the Formation field as shown below.


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The Notice of Operation screen Document canvas depicted above allows users to upload supporting Notice of Operation documentation to the OGC. Users can load a document from their local or network file system by clicking the Browse button and navigating to the appropriate file.


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After selecting the appropriate document to load the user then simply clicks the Load button and the file will be submitted to the OGC. Only pdf and MS Word document formats may be uploaded. Users can view previously uploaded files for a Notice of Operation by selecting the desired file and clicking on the Show Document button.


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Well Completion, Maintenance and Abandonment Guideline The Notice of Operation screen Cancel Operation canvas depicted below allows users to cancel a Notice of Operation that was entered in error or is no longer applicable. Please enter both the Cancel Date and a Comment indicating why the Notice of Operation has been cancelled. Double click the Cancel Date field to automatically enter the current date. Please press the Save button after entering or updating a Notice of Operation.

2.5 Completion Report Required The Completion Report Required screen depicted below identifies Notice of Operation records for which a completion report is required, but has not yet been received by the OGC. Completion Reports must be submitted 30 days after the expected end date of a Notice of Operation.


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2.6 Completion Report Overdue The Completion Report Overdue report allows users t o identify Notice of Operation entries for which a completion report is required, the expected end date of the operation is more than 30 days ago, and no completion report has been received by the OGC.

To generate the Completion Report Overdue report simply select the Operator you are interested in from the pull down list and then press the Run Report button. The report will open in a new browser window.


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3 NOTICE OF FLARE

3.1 Notice of Flare - Well Selection Selecting the Notice of Flare button from the Online Drilling Reporting System Main Menu will direct the user to the Notice of Flare Well Selection screen depicted below.


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3.2 Select a Well Record In order to enter Notice of Flare information the user must first select a well record. This can be accomplished in one of two ways:

Select a Record Highlight the well record for which you want to submit a Notice of Flare.

Notice of Flare Click the Notice of Flare button to navigate to the Notice of Flare entry screen.

3.3 Query for a Specific Record The user can choose to query for a specific well based on any combination of fields displayed on the screen.

Switch to Query Mode Click on the ENTER QUERY button.


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Enter Specific Query Parameters User can query on any field displayed on the screen. In the example at left the user has

entered a value to the WA NUM field to query by WA#.

Find Records based on Query Parameters Click on the EXECUTE QUERY button.

Click on the Notice of Flare button to navigate to the Notice of Flare screen.

3.4 Enter Notice of Flare

Mandatory data items to be entered to the Notice of Flare main canvas depicted above include: Site Supervisor #1 Name and Phone, Purpose of Flaring, Expected Start Date , Expected End Date and In Line Testing indicator. The Flare Stack Height should be entered if applicable. The OGC Review Complete indicator, Flare Volume MM3 and Test Facility data


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Well Completion, Maintenance and Abandonment Guideline items on this screen area display only fields. Users will enter actual flare volumes ( Flare Vol MM3) values on the Submit Flare Volumes screen of the Online Drilling Results application. The Test Facility field is entered by OGC staff if applicable. The OGC Review Complete field indicates whether or not OGC staff have completed their review of the Notice of Flare. Notice of Flare information can not be edited once the OGC Review is complete.

The Formation H2S canvas of the Notice of Flare screen enables the entry of geological formations, H2S concentrations and maximum flare volumes. The Expected H2S % Field will accept values between 0 and 99.99 and should be entered with two decimal places. The Max Flare Vol MM3 field will accept values between 0 and 99999 and should be entered with no decimal. Users can select the Formation from a List of Values by double clicking the Formation field as depicted below.


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The Notice of Flare screen Cancel Flare canvas depicted below allows users to cancel a Notice of Flare that was entered in error or is no longer applicable. Please enter both the Cancel Date and a Comment indicating why the Notice of Flare has been cancelled. . Please press the Save button after entering or updating a Notice of Operation.

3.5 Submit Flare Volumes The Submit Flare Volumes screen depicted below enables the entry of actual flare volumes for completed flares. Flare volumes must submitted no later than 60 days after the expected end date of the Flare. The Flare Vol MM3 field will accept values between 0 and 99999. No decimal should be entered.


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3.6 Flare Volume Overdue The Flare Volume Overdue report allows users to identify Notice of Flare entries for which the expected end date of the flare is more than 60 days ago, and no flare volume has been submitted to the OGC.


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Well Completion, Maintenance and Abandonment Guideline

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