well drilling guideline april release v.1.9 2015

8/19/2019 Well Drilling Guideline April Release v.1.9 2015

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WELL DRILLINGGUIDELINEApril | 2015

Version 1.9


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Wells Drilling Guideline, Version 1.9

BC Oil & Gas Commission i

CONTENTS

1.0 PREFACE ........................................................................................................... 2

1.1 PURPOSE ........................................................................................................... 2 1.2 SCOPE ............................................................................................................... 2 1.3

HOW TO USE THIS GUIDELINE ........................................................................... 2

1.4 ADDITIONAL GUIDANCE ................................................................................... 3 1.4.1 Frequently Asked Questions ................................................................. 3 1.4.2 Feedback .............................................................................................. 4

2.0 DRILLING REPORTING ....................................................................................... 5

2.1 UPDATES ........................................................................................................... 5 2.1.1 Status Updates ..................................................................................... 5

2.2 WELL PERMIT AMENDMENTS ............................................................................ 6 2.3 RE-ENTRIES ........................................................................................................ 6 2.4 INCIDENT REPORTING ..................................................................................... 7

2.4.1 Emergency ManagementBC Provincial Emergency Program .............. 7 2.4.2 Kicks ..................................................................................................... 7 2.4.3 Hole problems ...................................................................................... 8

2.5 SUMMARY REPORT OF DRILLING OPERATIONS ..................................................... 8 2.6 OTHER DATA SUBMISSION .............................................................................. 9

General ............................................................................................................. 10 2.7 OTHER REQUIREMENTS ................................................................................ 10

2.7.1 Variances and Exemptions ................................................................. 10 2.7.2 Logging and Sample Waivers ............................................................. 10 2.7.3 Commission Emergency Response Plan Meetings and Requirements

and Safety Notifications ................................................................................... 10 2.7.4 Flaring ................................................................................................ 10 2.7.5 Drillstem Testing ................................................................................ 11 2.7.6 Directional Survey Submission ........................................................... 11

2.7.7 Drilling Suspended Information Confidentiality ................................. 12 2.7.8 Junked or Lost Hole Policy .................................................................. 12 2.7.9 Waste Management .......................................................................... 12

3.0 DRILLING PRACTICES AND PROCEDURES ........................................................ 13

3.1 BLOWOUT PREVENTION, INDUSTRY RECOMMENDED PRACTICES AND BLOWOUT

PREVENTION SCHEMATICS ........................................................................................... 13 3.1.1 Blowout Prevention............................................................................ 13 3.1.1.1 Blowout Prevention Classifications ...................................................... 13 3.1.1.2 Blowout Prevention Pressure Ratings .................................................. 14 3.1.1.3 Other BOP Stipulations ......................................................................... 14 3.1.1.4 BOP Controls ........................................................................................ 15

3.1.2 Ancillary Equipment Requirements .................................................... 15 3.1.2.1 Bleed Off Lines ...................................................................................... 15 3.1.2.2 Choke Manifold .................................................................................... 15 3.1.2.3 Accumulator ......................................................................................... 16 3.1.2.4 Trip Tank and Volume Indicator ........................................................... 17 3.1.2.6 Kelly Cock and Stabbing Valve.............................................................. 18 3.1.2.7 Flare Tanks ........................................................................................... 18 3.1.2.8 Flare Pits ............................................................................................... 19 3.1.3 Testing of Blowout Prevention Equipment......................................... 19


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BC Oil & Gas Commission ii

3.1.4 Personnel Certification ....................................................................... 20 3.1.5 Blowout Prevention Procedures ......................................................... 21 3.1.6 Special Sour Wells .............................................................................. 21

3.2 CASING CEMENTING ...................................................................................... 22 3.3 PLUG BACKS AND ABANDONMENTS .................................................................. 23 3.4 WELDING OF CASING BOWLS .......................................................................... 23 3.5 SURVEYS .......................................................................................................... 23

3.6 DRILL CUTTING SAMPLES ................................................................................ 24 3.7 LOGGING ......................................................................................................... 24

4.0 SCHEDULE A: DRILLING BLOWOUT PREVENTION SYSTEMS ............................. 25

4.1 CLASS A ................................................................................................... 25 4.2 CLASS B ................................................................................................... 26 4.3 CLASS C ................................................................................................... 27 4.4 CLASS D ................................................................................................... 28 4.5 Special Sour: All Depths .......................................................................... 29 Drilling Prevention Systems for Special Sour Wells .......................................... 29 4.6 Special Sour Manifold ............................................................................. 30 4.7 Bleed off lines – All Classes ..................................................................... 31

4.8 Equipment Symbols ................................................................................ 32

5 COMPLIANCE ..................................................................................................... 33

OGAA ................................................................................................................ 33 Drilling and Production Regulation .................................................................. 33


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BC Oil & Gas Commission 1

Summary of Revisions

The Well Drilling Guideline has been revised based uponfeedback 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 berequired to meet the revised application standards.

Effective Date Section Description/Rationale

1-June-2014

2.6 and2.7

Removed content now captured in the Well Data SubmissionRequirements Manual. Replaced submission-specific content with

reference to Well Data Submission Requirements Manual.For more information regarding this document and the associatedprocesses, refer to Industry Bulletin – INDB 2014-06, on the

Commission’s website.

Various

Replaced all references to End of Well Report and End of Well Drillingreport with Summary Report of Drilling Operations. For moreinformation regarding this change, please refer to Industry Bulletin – INDB 2014-06, on the Commission’s website.

13-February-2015 Various

Updated to reflect the change in the water source approval process

and requirements for hydrogeological assessment and data

collection, monitoring, and data reporting.

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

20-April-2015 Various

This document has been updated to reflect the implementation of the

Commission’s eSubmission Portal. Readers are encouraged to

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

Commission’s BTS webpage for more information.


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1.0 Preface

1.1 PurposeThis guideline has been created to guide users through BC Oiland Gas Commission (Commission) processes and procedures.It also serves to highlight changes in processes, procedures,requirements and terminology resulting from implementation ofthe Oil and Gas Activities Act (OGAA).For users already familiar with the Commission’s reportingprocess, this guideline provides a quick reference highlightingrequired reporting submissions and appropriate drilling practicesand procedures. For users less familiar, this guideline presentsa complete overview of Commission requirements and provideslinks to more detailed material.This guideline is not intended to take the place of the applicablelegislation. The user is encouraged to read the full text oflegislation and each applicable regulation and seek directionfrom Commission staff, if and when necessary, for clarification.

1.2 Scope

This guideline focuses exclusively on requirements andprocesses associated with the Commission’s legislativeauthorities, and does not provide information on legalresponsibilities that may be specified as conditions on permits,or responsibilities that the Commission does not regulate. It isthe responsibility of the applicant or permit holder to know anduphold its other legal responsibilities.

1.3 How to Use This Guideline

This guideline is divided into sections which are organizedchronologically, and match the order of the steps applicants andpermit holders will follow when engaging in oil and gas activities.

This guideline outlines the procedures and requirements fordrilling operations at new and existing wells. The guideline takesthe user through drilling reporting requirements, drillingpractices and procedures and blowout prevention system.

Section 2.0 Drilling Reporting outlines and explains reporting requirementsincluding: permit requirements for amendments and re-entries;


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drilling activity reporting; spills, incidents and kick reporting;variances and exemptions and data submission flaring.

Section 3.0 Drilling Practices and Procedures outlines and explainsclassifications and pressure ratings for blowout prevention;requirements for ancillary equipment; procedures for testing

blowout prevention equipment; requirements for casing cementingand welding of casing bowls and survey, sample and logrequirements.

Section 4.0 Drilling Blowout Prevention Systems details and illustrates thedifferent classes of BOP systems.

Section 5.0 Compliance describes contravention of legislation and regulationand administrative penalties.

1.4 Additional Guidance

The glossary page on the Commission website provides acomprehensive list of terms.

The Supplementary Information for Water Source Wells document provides additional information pertaining to drilling ofwater source wells.

The appendices contain documents to be used as referenceswhen compiling information required by the Commission.Other navigational and illustrative elements used in theguideline include:

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

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

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

Tables: Tables organize information into columns and rows for quick

comparison.

1.4.1 Frequently Asked Questions A Frequently Asked Questions (FAQ) link is available on theCommission OGAA page. The information provided iscategorized into topics which reflect the manuals for easyreference. Please consult the FAQ page before contacting theCommission to help keep response times short.

http://www.bcogc.ca/documents/publications/Fact%20Sheets/Glossary_FINAL.pdfhttp://www.bcogc.ca/documents/publications/Fact%20Sheets/Glossary_FINAL.pdfhttp://www.bcogc.ca/documents/publications/Fact%20Sheets/Glossary_FINAL.pdfhttp://www.bcogc.ca/node/12337/downloadhttp://www.bcogc.ca/node/12337/downloadhttp://www.bcogc.ca/node/12337/downloadhttp://www.bcogc.ca/OGAA/faq.aspxhttp://www.bcogc.ca/OGAA/faq.aspxhttp://www.bcogc.ca/OGAA/faq.aspxhttp://www.bcogc.ca/OGAA/faq.aspxhttp://www.bcogc.ca/node/12337/downloadhttp://www.bcogc.ca/documents/publications/Fact%20Sheets/Glossary_FINAL.pdf


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1.4.2 FeedbackThe Commission is committed to continuous improvement bycollecting information on the effectiveness of guidelines andmanuals. Clients and stakeholders wishing to comment onCommission guidelines and manuals may send constructive

comments to [email protected].

mailto:[email protected]?subject=Well%20Drilling%20Guidelinemailto:[email protected]?subject=Well%20Drilling%20Guidelinemailto:[email protected]?subject=Well%20Drilling%20Guidelinemailto:[email protected]?subject=Well%20Drilling%20Guideline


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2.0 Drilling Reporting

Drilling activities must be reported to the Commission inaccordance with Section 8 of the Drilling and ProductionRegulation and any well permit conditions.

The eSubmission Portal is accessible through the Commission’ssecure website and provides specific reporting functions forwells currently being drilled.

Any questions or problems should be directed to the Drilling andProduction Department, Engineering Operations Technician.

2.1 Updates

2.1.1 Status UpdatesThe status update informs the Commission of the drilling statusof a well (spud, drilling suspended, drilling resumed and rigrelease). The information required on the website will depend onthe drilling status change. Status updates must be providedwithin one business day of a change in drilling status.

For drilling re-entry wells, the supplemental Engineering DataForm accompanying the well permit or well permit amendmentwill specify what will be deemed as the spud date. Refer to there-entries section for additional information.

Drilling suspended means a drilling rig has been released, butthe drilling of the well is not complete and the permit holderintends to resume drilling within one year of rig release.Examples of this situation include:

Surface hole rig.

Switch out rigs for horizontal underbalanced drill.

Release drilling rig, switch to service rig to penetrate play

with air (also considered a drilling operation). Drilling ceases due to breakup and will resume when

access is restored.

For a short suspension of drilling operations (for instance,Christmas shutdowns), do not report as drillingsuspended. On the Summary Report of DrillingOperations explain the reason for the short suspension(for example: shutdown for Christmas for five days).

The wellauthorizationnumber must beon allcorrespondence

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Drilling resumed means drilling has resumed after a drillingsuspension. The drilling resumed date is usually when the bitcommences making new hole.

Rig released means the drilling of the well is complete.

2.2 Well Permit Amendments

A well permit amendment is required when:

The lease footprint (surface disturbance) is changed.

Objective formation(s) or the formation at total depth haschanged.

Expected hydrogen sulphide (H2S) release rate ischanged, resulting in a change of the emergencyplanning zone (EPZ).

A change in surface wellhead coordinates results in achange in the well name(For example the pad is locatedin a boundary and the change causes the well name tochange from 1-3 to 3-3).

A change in BHL with attendant change in well profilesuch that the well name adds or deletes “HZ”.

A re-entry is performed (refer to the Re-entries Section).

Minor changes in surface wellsite co-ordinates are collected inthe eSubmission portal using the Summary Report of DrillingOperations.

Permit amendments are not required for minor changes inproposed final total depth (FTD) resulting from geologicalprognosis change, simple changes to hole size or casing size,addition of a core or a drillstem test (DST) or minor changes inwell centre coordinates.

Refer to Section 6 of the Well Permit Application Manual formore information regarding the well permit amendment process.

2.3 Re-entries A drilling re-entry is defined as additional drilling on a well thathad previously been drilled and rig released. A well permitamendment is required to re-enter a well that has not beenissued a Certificate of Restoration (CoR). A new well permit isrequired to re-enter a well that has been issued a CoR. Refer tothe Well Permit Application Manual for the permit applicationand amendment processes.

http://www.bcogc.ca/document.aspx?documentID=874&type=.pdfhttp://www.bcogc.ca/document.aspx?documentID=874&type=.pdfhttp://www.bcogc.ca/document.aspx?documentID=874&type=.pdfhttp://www.bcogc.ca/node/5854/downloadhttp://www.bcogc.ca/node/5854/downloadhttp://www.bcogc.ca/node/5854/downloadhttp://www.bcogc.ca/node/5854/downloadhttp://www.bcogc.ca/document.aspx?documentID=874&type=.pdf


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The new or amended permit will specify how to determine thespud date.

Drilling re-entries are reported in the same manner as thedrilling of a new well.

Completions/workover re-entries that involve no new drilling arereported the same as a completion/workover on a non-abandoned well. Details of the process for completion/workoverre-entries are located in the Well Servicing Operations sectionof the Well Completions, Maintenance and AbandonmentManual.

A spud and rig release status update are required for bothdrilling and completion re-entries. The new or amended permitwill specify how to determine the spud date.

Table 2.1: Permitting requirements for re-entries

Well Status Drilling Re-entry Completion/Workover Re-entry

Not Abandoned Well Permit Amendment Not a re-entry (Notice of Operations only) Abandoned (includingsurface cut and cap) Well Permit Amendment Well Permit AmendmentCertificate of RestorationIssued (or PermitCancelled or Spent) New Well Permit New Well Permit

2.4 Incident Reporting

2.4.1 Emergency ManagementBCIncidents such as spills, gas release, fire/explosion, kicks,vandalism or threats and major structural failures must bereported to the Emergency ManagementBC at1-800-663-3456.

2.4.2 Kicks All kicks must be reported as soon as possible in the followingmanner:

To the Emergency ManagementBC by calling 1-800-663-3456.

Submit a kick report to the Commission using theeSubmission Portal within one business day.

If the well control situation is deteriorating, contact aCommission Drilling Engineer or if a Drilling Engineer is

http://bandicoot/OGC/OGAA%20Implementation/3.00%20Wells/Guidelines/Operations/OGAA_Well_Completion_Maintenance_Abandonment_Manual_PV_August5.docx%23re_entryhttp://www.bcogc.ca/document.aspx?documentID=920&type=.pdfhttp://www.bcogc.ca/document.aspx?documentID=920&type=.pdfhttp://www.bcogc.ca/document.aspx?documentID=920&type=.pdfhttp://www.bcogc.ca/document.aspx?documentID=920&type=.pdfhttp://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://www.bcogc.ca/document.aspx?documentID=920&type=.pdfhttp://www.bcogc.ca/document.aspx?documentID=920&type=.pdfhttp://bandicoot/OGC/OGAA%20Implementation/3.00%20Wells/Guidelines/Operations/OGAA_Well_Completion_Maintenance_Abandonment_Manual_PV_August5.docx%23re_entry


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unavailable, call the On Duty Incident Commander at 1-800-663-3456.

2.4.3 Hole problemsFor fish in hole, sloughing hole, well control issues or other hole

problems where the Commission’s assistance is required,contact a Commission Drilling Engineer during business hoursor outside of business hours call 1-800-663-3456.

2.5 Summary Report of Drilling Operations

Designate a person and a back up individual for submission ofthis report.Within four business days of rig release or drilling suspended(that is, when rig is to move or shutdown for a period of time,excluding short shutdowns for Christmas or rig repairs), the

report must be submitted to the Drilling and ProductionDepartment via the eSubmission Portal. The Summary Reportof Drilling Operations must be completely and accurately filledout.

A summary of formation tops and logs run must accompany theonline submission of the Summary Report. This summary mustinclude the following:• A list of formation tops as picked from the logs. If no open holelogs are run, formation tops may be selected from themeasurement while drilling –gamma ray (MWD-Gr) log. If there

is no MWD-Gr log, formation tops may be selected based ondrill suttings samples.Measured depth (MD) and true vertical depth (TVD) must beprovided if the well is directional or horizontal.

• A list of logs run (including MWD-Gr) with the followinginformation:

Log type run (include MWD – Gr if run). The log typemust be written out in full – for instance, boreholecompensated sonic, not BHC.

Run number.

Last date run for each run number (finished date).

Intervals logged (that is, top depth and bottom depth) foreach log including measured depth and true verticaldepth, as applicable.

Bottom hole temperature (BHT) must be included withthe written list of logs run.

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Table 2.2 Formatting for Summary Report of Drilling Operations

Log Type

(Name)

Run

#

Run End

Date

Top Depth

(MD)

Bottom

Depth

(MD)

Top

Depth

(TVD)

Bottom

Depth

(TVD)

Bottom

Hole Temp

(BHT)

Note: Submit the full name of the log, no abbreviations.

For each log, one line of information must be entered.The naming convention for the pdf document containing theformation tops/logs run information is:

WANUM_FTLR_YYYYMMMDD_OPTIONAL

For wells that have experienced drilling problems not evidentfrom the Summary Report of Drilling Operations, provide a briefpoint summary in the comments section to explain the

problems. For example: Drilled to 800 metres.

Lost fish in hole.

Fish bottom at 750 metres.

Fish top at 600 metres.

Brief description of fish.

Address issue of potential interzonal communication (ifapplicable).

Set plug #1.

Kicked off plug at depth of 1,215 metres to drill aroundfish.

For drilling re-entries, provide a brief point summary (in thecomments section) of the operations performed if not evidentfrom the Summary Report of Drilling Operations.For example: for a basic squeeze of existing perforations, bridgeplug set and mill of window in casing to drill horizontally out ofcased vertical well;

Started drilling on surface three metre abandonment plug

at 0800 hr 2007-06-15. Cement squeezed existing perfs and pressure tested

same.

Set bridge plug at 1,800 metres and whipstock andcommenced cutting window

2.6 Other Data Submission


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GeneralFor information relating to samples and core submission, as wellas complete submission requirements for all other datasubmissions, please refer to the Well Data SubmissionRequirements Manual.

2.7 Other Requirements

2.7.1 Variances and ExemptionsRefer to Section 4 of the Drilling and Production Regulation for alist of sections to which an official can grant an exemption.For drilling operations, exemption requests should be submitted

to a drilling engineer.

2.7.2 Logging and Sample WaiversRequests should be made during business hours to theCommission’s Petroleum Geology, Resource Stewardship &Major Projects.The request should be submitted to a geologist by email, clearlystating the request and the reason for the request ( for example,hole conditions). Refer to the Commission phone list, PetroleumGeology, Resource Stewardship & Major Projects for Contactinformation.

After business hours, the Commission’s 24-hour phone line inFort St. John is 250-794-5200.

2.7.3 Commission Emergency Response Plan Meetingsand Requirements and Safety NotificationsNotification for the Commission to attend/witness emergencyresponse plan meetings should be made via email or fax at 250-794-5381 within 48 hours prior to drilling.

The Commission requires an Emergency Response Plan to bein place and on site prior to spudding a well. For more details,refer to Section 11 in the BC Oil and Gas Handbook and

Appendix D of the Well Permit Application Manual.

2.7.4 FlaringIf flaring during drilling operations is necessary, please note thefollowing:

A Notice of Flare must be submitted using theCommission eSubmission Portal for underbalanced

http://www.bcogc.ca/node/11219/downloadhttp://www.bcogc.ca/node/11219/downloadhttp://www.bcogc.ca/node/11219/downloadhttp://www.bcogc.ca/node/11219/downloadhttp://www.bcogc.ca/phoneList.aspxhttp://www.bcogc.ca/phoneList.aspxhttp://www.bcogc.ca/phoneList.aspxhttp://www.bcogc.ca/phoneList.aspxmailto:[email protected]:[email protected]:[email protected]://www.bcogc.ca/documents/handbook/Handbook%20s11%20Guideline%20for%20Emergency%20Planning%2020031104.pdfhttp://www.bcogc.ca/documents/handbook/Handbook%20s11%20Guideline%20for%20Emergency%20Planning%2020031104.pdfhttp://www.bcogc.ca/documents/handbook/Handbook%20s11%20Guideline%20for%20Emergency%20Planning%2020031104.pdfhttp://www.bcogc.ca/document.aspx?documentID=874&type=.pdfhttp://www.bcogc.ca/document.aspx?documentID=874&type=.pdfhttp://www.bcogc.ca/document.aspx?documentID=874&type=.pdfhttp://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://www.bcogc.ca/document.aspx?documentID=874&type=.pdfhttp://www.bcogc.ca/documents/handbook/Handbook%20s11%20Guideline%20for%20Emergency%20Planning%2020031104.pdfmailto:[email protected]://www.bcogc.ca/phoneList.aspxhttp://www.bcogc.ca/phoneList.aspxhttp://www.bcogc.ca/node/11219/downloadhttp://www.bcogc.ca/node/11219/download


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drilling. The total flared volume must be reported within60 days of completion of flaring.

For other operations (drillstem testing, managed pressuredrilling, kick flaring) advance notification is not requiredand flared volumes must be reported on the Summary

Report of Drilling Operations. Estimation is permitted for operations such as kick flaring

where accurate measurement of flared volumes is notpossible.

For underbalanced drilling, submit a Well DeliverabilityTest Report to the Commission through the eSubmissionPortal within 60 days.

2.7.5 Drillstem Testing A pressure chart and a report containing complete details onfluid recoveries and other pertinent facts for each drillstem test

or wire line test taken on a well must be submitted to theCommission within 30 days of the date on which the test wasmade.

Useful references include:

Drillstem Testing Safety Guidelines, covers safe workguidelines, minimum health and operating standards andpersonnel qualifications.

Industry Recommended Practices for Well Testing andFluid Handling-IRP Volume 4.

2.7.6 Directional Survey Submission

Directional survey data must be uploaded into the Commission’s online system via the eSubmission Portal after the rig release isreported.

Directional surveys must be submitted in both TXT and PDFformat. Directional surveys must include the actual surfacecoordinates of the wellhead.

The last point on the directional survey must be the total

measured depth (TMD) of the well bore. This allows theCommission to link the directional survey with the correct drillingevent.

Deviation surveys must be made during drilling at intervals notexceeding 150 metres in depth, unless there are wellborestability problems.

http://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://www2.worksafebc.com/Publications/OHSRegulation/GuidelinePart23.asp?reportID=19118http://www2.worksafebc.com/Publications/OHSRegulation/GuidelinePart23.asp?reportID=19118http://enform.ca/media/3672/irp4_final_2009.pdfhttp://enform.ca/media/3672/irp4_final_2009.pdfhttp://enform.ca/media/3672/irp4_final_2009.pdfhttp://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://esubmission.bcogc.ca/http://enform.ca/media/3672/irp4_final_2009.pdfhttp://www2.worksafebc.com/Publications/OHSRegulation/GuidelinePart23.asp?reportID=19118http://esubmission.bcogc.ca/http://esubmission.bcogc.ca/


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See the Well Data Submission Requirements Manual and theDirectional Survey File Format Guide for detailed informationregarding the submission of directional survey data.

2.7.7 Drilling Suspended Information ConfidentialityIf an operator reports a drilling well as drilling suspended, therelease of confidential information is treated as if the cessationof drilling was reported as rig released, provided the same wellhas reached its permitted objective.

If drilling is suspended and is not resumed within one year of thedrilling suspended date, the drilling suspended date will betreated as the rig release date for the purposes of the release ofconfidential information.

2.7.8 Junked or Lost Hole PolicyIf surface casing has been set on a drilling well and the holebelow the shoe is junked or lost due to drilling problems, a newwell permit will be required to skid the rig and drill a new hole. Inthese situations the permit processing may be expedited by theCommission provided no changes to the existing location arerequired.

2.7.9 Waste ManagementThe following must be submitted to the Waste Management andReclamation Department:

A Wellsite Cleanup Form within 60 days of rig release.Include a record of sump condition and topsoil storage.

The Drilling Waste Disposal Summary form and anyrequired attachments within 90 days of the closing of anyearthen pit used to store drilling waste

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3.0 Drilling Practices and Procedures

3.1 Blowout Prevention, Industry Recommended Practicesand Blowout Prevention Schematics

The following section outlines blowout prevention standards thata permit holder should follow to comply with the requirements ofPart 4, Division 2 of the Drilling and Production Regulation. It isthe responsibility of the permit holder to ensure that blowoutprevention equipment and procedures are adequate.

A permit holder may use alternate blowout prevention

equipment and techniques if they can demonstrate by means ofa detailed engineering analysis that the alternate equipment ortechniques are adequate as required by section 16(1) of theDrilling and Production Regulation. This engineering analysisshould be submitted as part of the well permit application.Recommended and industry accepted blowout prevention(BOP) guidelines are included in this section. BOP stackschematics are in Schedule A.

If an operation is not covered in these guidelines, refer to theapplicable Industry Recommended Practices. Exercise caution

when drilling surface holes. It is prudent to utilize divertors inareas where shallow gas has been encountered or in wildcatareas (areas where little is known with certainty about thesubsurface geology). Refer to OGC IL 05-12 for moreinformation.

3.1.1 Blowout Prevention

3.1.1.1 Blowout Prevention Classif icatio ns

Blowout prevention equipment is classified as follows:

Class A equipment is equipment to be used from thedepth of the surface casing to 1,800 metres true verticaldepth.

Class B equipment is equipment to be used from a depthof 1,800 metres to 3,000 metres true vertical depth.

Class C equipment is equipment to be used from a depthof 3,000 metres to 5,500 metres true vertical depth.

A concurrentoperations planmust be on sitewhen conductingoperations on any

well that is lessthan 25 metresfrom another well.

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Class D equipment is equipment to be used from a depthof 5,500 metres true vertical depth and greater.

3.1.1.2 Blowo ut Prevention Press ure Ratings

The minimum pressure rating of blowout prevention equipment

must be: 14,000 kPa for Class A equipment.

21,000 kPa for Class B equipment.

34,000 kPa for Class C equipment.

70,000 kPa for Class D equipment.

3.1.1.3 Other BOP Stip ulation s

When a well is being drilled, blowout prevention equipmentmust, at all times:

Consist of a minimum of one annular preventer and two

or more ram preventers; the ram preventers are to becomprised of a blank ram and one or more rams to closeoff around drill pipe, tubing or casing being used in thewell

Be connected to a casing bowl that is equipped with:

o An upper flange that is an integral part of thecasing bowl

o For blowout prevention Class A and B, at leastone threaded, flanged or studded side outlet withone valve and

o For blowout prevention Class C and D, twoflanged or studded side outlets with two valves

Include steel lines or adequate high pressure hosesconnected to the blowout preventer assembly, one ormore for bleeding off pressure and one or more for killingthe well

Consist of components having a working pressure equalto that of the blowout preventers, except that part of thebleed-off line or lines located downstream from the lastcontrol valve on the choke manifold

Have the valve hand wheel assembly in place andsecurely attached to the valve stem on all valves in theblowout prevention system

Be maintained so that its operation will not be impairedby adverse weather conditions

Hammer unions should not be used in the manifold shackor under the substructure and

Conform to the specifications set out in Schedule A.


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3.1.1.4 BOP Con trols

If hydraulically operated blowout preventers are installed, aclearly marked operating control indicating direction of closurefor the annular blowout preventer must be located at least15 metres from the well.

The control valve regulating the closure of the annular preventer must be free of any valve locking device.

All manual controls for the locking of manual ram type blowoutpreventers must be installed or readily accessible.

If ram type blowout preventers are used at a cased well, thecontrols must be attached and be at least five metres from thewell.

All blowout preventers must be hydraulically operated andconnected to an accumulator system.

3.1.2 Ancillary Equipment Requirements

3.1.2.1 Bleed Off Lin es

The bleed off lines referred to above must be:

A minimum nominal 76 millimetre diameter of uniformbore

Connected only by welded neck flanges that areperpendicular to the line to which they are attached

Equipped with a gauge connection where well pressuresmay be measured

Connected to a choke manifold and a mud tank through amud gas separator and

Securely held down and terminated in a slightlydownward direction into an earthen pit or flare tank, if thelines are downstream of the choke manifold.

3.1.2.2 Choke Manifold

The choke manifold referred to above must be located:

A minimum distance of 15 metres from the well bore or

A satisfactory distance from the substructure and themud tanks such that during well control operationspersonnel are not exposed to hazardous gases whichmay be present in those locations.


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The choke manifold referred to above must be designed:

To conform with Class A, B, C or D equipment and

To permit the flow to be directed through a full openingline or through either of the two lines, each containing an

adjustable choke

Equipped with accurate metric pressure gauges toprovide drill pipe and casing pressures at the chokemanifold once the surface casing is cemented in place

Enclosed by a suitable housing, with adequate heat toprevent freezing

Securely tied down and containing only pipe that isstraight or with 1.57 radian bends (90º) and which isconstructed of flanged, studded or welded tees, blankflanged or ball plugged on fluid turns in addition to having

bleed off lines Hammer unions must not be used on main flow lines in

the enclosure that houses the choke manifold.

3.1.2.3 Acc um ulator

The accumulator system must be:

Installed and operated in accordance with themanufacturer's specifications

Connected to the blowout preventers, with lines ofequivalent working pressure to the system, and within 5

metres of the well - the lines must be of steel constructionunless completely sheathed with adequate fire resistantsleeving

Capable of providing, without recharging, fluid ofsufficient volume and pressure to close the annularpreventer, close a ram preventer, open the hydraulicallyoperated valve and retain a pressure of 8,400 kPa on theaccumulator system

Recharged, within five minutes, by a pressure controlledpump capable of recovering the accumulator pressuredrop resulting from closing the annular preventer, closinga ram preventer or opening the hydraulically operatedvalve

Capable of closing any ram type preventer within 30seconds

Capable of closing the annular preventer within 60seconds and


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Equipped with readily accessible fittings and gauges todetermine the precharge pressure of each nitrogencontainer.

If nitrogen cylinders are used as an emergency pressuresource, sufficient usable nitrogen must be available at a

minimum pressure of 8,400 kPa to fully close the annularpreventer and pipe rams and open the hydraulically operatedvalve.

3.1.2.4 Trip Tank and Volum e Indicator

If a mud tank is in use, a device must be installed and visiblefrom the driller’s position to warn of a change in the mud tank’s fluid levels or of an imbalance in the fluids entering andreturning from the well. The device must be either electrically,pneumatically, hydraulically or mechanically operated and

maintained in working order at all times.

The drilling mud system must be equipped with a trip tank withthe capacity of 5 cubic metres to accurately measure the fluidrequired to fill the hole while pulling pipe from the well and thetrip tank must:

Be constructed so that the cumulative volume can bereliably and repeatedly read to an accuracy of 0.15 m 3 (150 litres) from the driller's position.

Be tied into the mud return line.

Be equipped so that drilling fluid can be transferred intoand out of the trip tank.

Be located in or within 10 metres of the shale shaker endof the mud tank and be readily accessible to afford visualobservance of the fluid level.

A diagram of the trip tank and the trip tank volume indicatormust be prominently displayed in the control centre (also knownas the dog house).

The trip tank volume indicator must specify the trip tank volumeand each volume graduation on the scale.


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3.1.2.5 Mud-Gas SeparatorMud gas separators must:

Be designed to ensure personnel safety and adequatemud gas separation and

Be connected to a securely fastened inlet line and outlet

line and the outlet line must

o Be at least one size larger than the inlet line and

o Terminate preferably in a flare tank, but also mayterminate in an earthen flare pit, at least 50 metresfrom the well.

3.1.2.6 Kelly Coc k and Stabbin g Valve

At all times when a well is being drilled:

A valve must be installed in the kelly assembly and

A full opening stabbing valve that can be connected to

the drill pipe, drill collars or tubing in the well and adevice capable of stopping any backflow up the drillstring must be provided and must:

o Be equipped with removable handles to facilitatehandling by two persons

o Be stored in the control centre (dog house) oranother satisfactory location where it is readilyavailable for use with the valve in the openposition and

o Have the valve closing handle attached to the

valve holding stand.

3.1.2.7 Flare Tank s

Flare tanks must:

Be constructed of steel with walls of sufficient height toensure liquid containment during prolonged exposure tofluid flow and extreme heat

Have structural integrity

Have an impingement plate to resist erosion from high-velocity gas, liquids and solids positioned on the flare

tank wall directly opposite all flare lines and diverter linesconnected to the flare tank

Have a minimum capacity of 8 cubic metres and beappropriately sized for the flow to avoid creatingbackpressure

Not be covered

Be positioned a minimum distance of 50 metres from thewell


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Be equipped with a minimum 50.8 mm liquid loadingsteel line that is connected at all times for the purpose ofdrawing fluids from the tank, with the connection point ofthe loading line a minimum of 9 metres from the flaretank

Have degasser vent lines kept separated from the liquidin the flare tank. The vent lines may be laid on the groundnext to the flare tank, provided no fire hazard exists

Have a minimum 10 metre setback from vegetation orother potential fire hazards.

3.1.2.8 Flare Pits

The earthen pit referred to in this document must:

Be excavated to a minimum depth of 2 metres

Have side and back walls rising not less than 2 metres

above ground level Be constructed to resist the erosion of a high pressure

flow of gas or liquid

Be constructed to contain any liquid and

Be used for emergency purposes only.

3.1.3 Testing of Blowout Prevention EquipmentBlowout equipment must be shop serviced and shop tested toits working pressure at least once every three years and testdata and maintenance performed must be recorded and madeavailable on request from a Commission official.

Following assembly, all flow line connections that form a part ofthe blowout prevention system must be inspected by the rigmanager and recorded in the daily report.

Prior to drilling out cement from any string of casing, each unitof the blowout prevention equipment must be pressure tested,first to a pressure of 1,000 kPa and then to at least 7,000 kPa,each for a period of 10 minutes. Until the equipment passesthese tests, further drilling must not proceed.

Casing exposed to drill pipe wear must be tested every 30 daysto determine its adequacy for pressure control by either:

Running a casing inspection log to determine casingwear or

Pressure testing to a pressure not greater than 50 percent of the burst pressure of the weakest section of the


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casing, or to the working pressure of the blowoutpreventers, whichever is less.

Each rig crew must perform a blowout prevention drill everyseven days, or as conditions permit in accordance with aCanadian Association of Oilwell Drilling Contractors (CAODC)

Well Control Procedure placard (available through the CAODCcatalogue) or as outlined by the Enform Blowout PreventionManual.

While pulling pipe from a well, the well permit holder mustensure that:

The hole is filled with drilling fluid at a frequency thatensures the fluid level in the well bore does not fall belowa depth of 30 metres and

A permanent record of the drilling fluid volumes requiredto fill the hole is retained and submitted as part of thedaily drilling reports

The blowout prevention stack and choke manifold ispressure tested every 30 days.

While a well is being drilled or tested during drilling operations,the appropriate blowout prevention equipment must be operateddaily and, if found to be defective, it must be made serviceablebefore operations are resumed.

Full particulars of all tests must be reported in the daily report,and for a pressure test, the pressure applied and the duration of

the test must be recorded.

3.1.4 Personnel CertificationThe rig manager (tool push) and the well permit holder’srepresentative at the well site must:

Be trained in blowout prevention and

Possess a second line supervisor certificate issued withinthe past two years by Enform and a copy of theirqualifications must be made available to an official onrequest.

The driller must: Be trained in blowout prevention and

Possess a first line supervisor’s blowout preventioncertificate or a second line supervisors’ blowout

prevention certificate issued within the past two years byEnform.

http://www.caodc.ca/pdf/Catalogue-2011.pdfhttp://www.caodc.ca/pdf/Catalogue-2011.pdfhttp://www.caodc.ca/pdf/Catalogue-2011.pdfhttp://www.caodc.ca/pdf/Catalogue-2011.pdfhttp://www2.enform.ca/1244http://www2.enform.ca/1244http://www2.enform.ca/1244http://www2.enform.ca/1244http://enform.ca/courses/courselist.aspx#/courses/SafetyTraining.aspxhttp://enform.ca/courses/courselist.aspx#/courses/SafetyTraining.aspxhttp://enform.ca/courses/courselist.aspx#/courses/SafetyTraining.aspxhttp://www2.enform.ca/1244http://www2.enform.ca/1244http://www.caodc.ca/pdf/Catalogue-2011.pdfhttp://www.caodc.ca/pdf/Catalogue-2011.pdf


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The CAODC placard or the well permit holder's Well ControlProcedures placard must be prominently displayed in the controlcentre (dog house) and must be legible at all times.

3.1.5 Blowout Prevention ProceduresThe rig crew must have an adequate understanding of and becapable of operating the blowout prevention equipment and thecontractor or rig crew must:

When requested by a Commission official, test theoperation and effectiveness of the blowout preventionequipment in accordance with the CAODC issued WellControl Procedure placard or the Enform BlowoutPrevention Manual and

Record drills performed in the daily drilling reports.

3.1.6 Special Sour Wells

The criteria for a special sour well in B.C. are: Any well from which the maximum potential H2S release

rate is 0.01 m³/s or greater and less than 0.1 m³/s andwhich is located within 500 metres of an urban center or

Any well from which the maximum potential H2S releaserate is 0.1 m³/s or greater and less than 0.3 m³/s andwhich located within 1.5 kilometres of an urban center or

Any well from which the maximum H2S release rate is 0.3m³/s or greater and less than 2.0 m³/s and which islocated within five kilometres of an urban center or

Any well from which the maximum potential H2S releaserate is 2.0 m³/s or greater or

Any other well which the Commission classifies as aspecial sour well having regard to the maximum potentialH2S release rate, the population density, theenvironment, the sensitivity of the area where the wellwould be located, and the expected complexities duringthe drilling phase.

The minimum pressure rating of blowout prevention equipmentis the same as defined for an equivalent non-special sour well.

Shear blind rams must be used where the calculatedemergency planning zone:

Intersects the boundaries of an urban centre

Encompasses more than 50 occupied dwellings or

Encompasses a portion of a major highway.

The permitee must notify all residents within the EmergencyPlanning Zone prior to penetration of the first sour zone and atrig release.


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The Commission has fully sanctioned the IndustryRecommended Practice for Critical Sour Drilling (IRP Volume1). Refer to IRP 1 for additional information regarding the drillingof special sour wells.

The Commission will evaluate any proposal to drill special sourwells underbalanced on an individual basis. For this type ofoperation refer to Critical Sour Underbalanced Drilling IRPVolume 6 or the Energy Resources Conservation BranchInterim Directive: Underbalanced Drilling (ID 94-3).

3.2 Casing Cementing

Casings must be designed to withstand the maximum load andservice condition that can reasonably be expected during the

service life of the well.

For protection of potable groundwater aquifers, non-toxic drillingfluids must be used until, in the opinion of a professionalengineer or geoscientist, all porous strata that:

Is less than 600 metres deep; and

Contains non-saline groundwater that is usable fordomestic or agricultural purposes

Has been isolated from the drilling fluid.

Isolation may be achieved by setting and cementing casing.

Usable groundwater is defined as groundwater that: Meets Canadian Guidelines for drinking or agricultural

water use or

Could be treated to meet the applicable water useguidelines without excessive cost.

Surface casings must also be set minimum of 25 metres into acompetent formation and must be deep enough to support theblowout prevention equipment and to ensure control of expectedwell pressure.

Surface casings and casings where underbalanced drilling is tooccur below the shoe should be cemented full length.Intermediate and production casing strings must be cemented tosurface or a minimum of 200 metres into the previous string.

Exemptions to specific requirements of Section 18 may berequested and issued in writing by the Commission underSection 4 of the DPR, and may be necessary for shallow watersource wells.

http://ww2.enform.ca/safety_resources/irps/criticalsourdrilling.aspxhttp://ww2.enform.ca/safety_resources/irps/criticalsourdrilling.aspxhttp://ww2.enform.ca/safety_resources/irps/criticalsourdrilling.aspxhttp://ww2.enform.ca/safety_resources/irps/criticalsourdrilling.aspxhttp://enform.ca/media/3586/irp6_final_2005.pdfhttp://enform.ca/media/3586/irp6_final_2005.pdfhttp://enform.ca/media/3586/irp6_final_2005.pdfhttp://enform.ca/media/3586/irp6_final_2005.pdfhttp://www.ercb.ca/docs/ils/ids/pdf/id94-03.pdfhttp://www.ercb.ca/docs/ils/ids/pdf/id94-03.pdfhttp://www.ercb.ca/docs/ils/ids/pdf/id94-03.pdfhttp://www.ercb.ca/docs/ils/ids/pdf/id94-03.pdfhttp://enform.ca/media/3586/irp6_final_2005.pdfhttp://enform.ca/media/3586/irp6_final_2005.pdfhttp://ww2.enform.ca/safety_resources/irps/criticalsourdrilling.aspxhttp://ww2.enform.ca/safety_resources/irps/criticalsourdrilling.aspx


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3.3 Plug backs and Abandonments

Notification or approval is not required prior to conducting open-hole plug backs or abandonments. Permit holders must ensurethat cementing is conducted in a manner that ensures hydraulicisolation between porous zones and the tops of all cement plugsmust be verified. If there is any uncertainty regarding theadequacy of a plugging program, contact the Commission’s Drilling and Production Department to discuss the program.

3.4 Welding of Casing Bowls

Ensure proper welding procedures are followed for the welding

of casing bowls. Proper preheating, the maintenance oftemperature throughout the welding process, proper cool downtechniques and proper rod selection are critical, particularly forspecial sour wells. Refer to Information Letter 09-24: Welding ofCasing Bowls (OGC IL 09-24).

Information on casing bowl welding such as welding procedure,start time, stop time and pressure test results must be recordedon the tour sheet.

3.5 Surveys

Deviation surveys are required at minimum intervals of 150metres.

A wellbore directional survey is required if:

Well is horizontal or directional.

Surface location of well is outside target area.

Surface location of well is within the target area butcloser to the target boundary than true vertical depthmultiplied by two per cent.

Example:Gas well total depth = 2,200.0 metres2200.0 metres X 2% = 44.0 metres44.0 metres + 250.0 gas target setback = 294.0 metres.

Therefore, if the well surface location is closer than 294 metresto the spacing border, a directional survey must be run.Deviation surveys may be omitted if there are wellbore stabilityproblems.

http://www.bcogc.ca/documents/informationletters/OGC%2009-04%20WA%20Drilling%20Period%20Extensions.pdfhttp://www.bcogc.ca/documents/informationletters/OGC%2009-04%20WA%20Drilling%20Period%20Extensions.pdfhttp://www.bcogc.ca/documents/informationletters/OGC%2009-04%20WA%20Drilling%20Period%20Extensions.pdfhttp://www.bcogc.ca/documents/informationletters/OGC%2009-04%20WA%20Drilling%20Period%20Extensions.pdf


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3.6 Drill Cutting Samples

Drill cuttings samples are required at intervals of 5 metres,beginning at 50 metres measured depth above the shallowestpotential reservoir zone and continuing to the total depth of thewell.

3.7 Logging

A gamma ray log is required from the ground surface to the totaldepth of the well.

A neutron log is required from 25 metres below ground level to

the base of the surface casing.

Resistivity and porosity logs are required from the base of thesurface casing to the total depth of the well.

Wellbores may penetrate below the lowest objective formationin order to fully log deepest rights, but overhole should belimited to 20 metres.


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4.0 Schedule A: Drilling BlowoutPrevention Systems

4.1 CLASS ASurface Casing Depth -1,800 metres (14,000-21,000 kPa)Drilling Blowout Prevention System for Wells not exceeding aTrue Vertical Depth of 1,800 m.Minimum pressure rating: 14,000 kPa (2,000 psi).

Accumulator System

Blow-Out Prevention Stack

Choke Manifold

Notes:

1) Bleed-off line, centreline through choke manifold,and flare line must be a minimum nominaldiameter of 76.2mm throughout.

2) Lines through chokes must be a minimumnominal diameter of 50.8mm throughout.

3) Kill line must be a minimum nominal diameter of50.8mm throughout.

4) Flanged pipe connections must be used from thedrilling spool down to and including the connection

to the choke manifold. The remainder of the choke

manifold may contain threaded fittings.5) Minimum pressure rating for flares and degasser

inlet lines is 14MPa.6) Hydraulic and manual valve positions in the

bleed-off line may be interchangeable

7) Ram type BOPs manufactured with integraloutlets may be used in place of drilling spool, butmust be inspected and re-certified if significantflow occurs through the body.


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4.2 CLASS B1,800-3,000 metres (21,000 kPa)Drilling Blowout Prevention System for Wells not exceeding a

True Vertical Depth of 3,000 m.Minimum pressure rating 21,000 kPa (3,000 psi)

Accumulator System

Manifold System

Blow-out Prevention Stack

Notes:

1) Bleed-off line, centreline through choke manifold, andflare line must be a minimum nominal diameter of76.2mm throughout.

2) Lines through chokes must be minimum nominaldiameter of 50.8mm throughout.

3) Kill line must be a minimum nominal diameter of50.8mm throughout.

4) Flanged pipe connections must be used from the

drilling spool to the last valve on the choke manifold,inclusive

5) Welded flanges required to connect primary andemergency bleed-off lines.

6) Minimum pressure rating for flare and degasser linesis 14MPa.

7) Hydraulic and manual valve positions in the bleed-off

line may be interchangeable8) Ram type BOPs manufactured with integral outlets

may be used in place of the drilling spools, but must bere-certified if significant flow has occurred through thebod .


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4.3 CLASS C3,000-5,500 metres (34,000 kPa)Drilling Blowout Prevention System for Wells not exceeding a

True Vertical Depth of 5,500 metres.Minimum pressure rating 34,000 kPa (5,000 psi).

Accumulator System


Manifold System

Notes:

1) Kill lines, bleed-off lines, choke manifold, and flare lines mustbe a minimum nominal diameter of 76.2mm throughout.

2) Flanged pipe connections must be used from the drillingspool to the last valve on the choke manifold, inclusive.3) Minimum pressure rating for flare and degasser lines is

14MPa.4) Hydraulic and manual valve positions in the bleed-off line

may be interchangeable.

5) Ram type BOPs manufactured with integral outlets may beused in place of the drilling spools, but must be re-certified if

significant flow has occurred through the body.6) Other BOP stack configurations are acceptable, including

the use of double gate rams. Stack must contain a minimumof two pipe rams and one blind ram.


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4.4 CLASS D5,500 metres and deeper (70,000 kPa)Drilling Blowout Prevention System for Wells exceeding a True

Vertical Depth of 5,500 metres.Minimum pressure rating 70,000 kPa (10,000 psi)


Accumulator System

Manifold System

Notes:

1) Kill lines, bleed-off lines, choke manifold, and flare linesmust be a minimum nominal diameter of 76.2mm

throughout.2) Flanged pipe connections must be used from the

drilling spool to the last valve on the choke manifold,

inclusive.3) Minimum pressure rating for flare and degasser lines is

14MPa.

4) Hydraulic and manual valve positions in the bleed-offline may be interchangeable

5) Ram type BOPs manufactured with integral outlets maybe used in place of the drilling spools, but must be re-certified if significant flow has occurred through thebody.

6) Other BOP stack configurations are acceptable,including the use of double gate rams. Stack mustcontain a minimum of 2 pipe rams and one blind ram.


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4.5 Special Sour: All Depths

Drilling Prevention Systems for Special Sour WellsMinimum pressure rating 14,000 kPa (2,000 psi).

Note:

1) Hydraulic and manual valve positions in bleed-off line are interchangeable2) If BOP Configuration 2 or BOP Configuration 3 is used, an appropriately sized ram blanking

tool that fits into the top pipe ram must be on location and readily available.3) If BOP Configuration 3 is used, there must be sufficient surface or intermediate casing to

contain the maximum anticipated reservoir pressure.4) Shear blind rams may be required in place of the blind rams.5) Rams type BOPs manufactured with integral outlet may be used in place of the drilling spools,

but must be re-certified if significant flow has occurred through the bodies.


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4.6 Special Sour ManifoldMinimum pressure rating 14,000 kPa (2,000 psi).


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4.7 Bleed off lines – All Classes


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For all classes:Class A, B, C and D diagrams indicate single ram preventer.The single blind ram preventer may be replaced with a doublegate preventer.

4.8 Equipment Symbols

Note:1) R – Single ram type preventer with one set of blind or pipe ram.2) A – annular-type blowout preventer.3) S – drilling spool with flanged side outlet connections for bleed-off and kill lines.4) Flanged means weld necked flanges.5) A double gate blowout preventer may replace a single gate preventer but the lowest ram in any

stack shall be a pipe ram.


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5 Compliance

OGAA A person found by the Courts, to have contravened the Oiland Gas Activities Act may be subject to a fine notexceeding the amount specified in Section 86 of the act. Aperson found by the Commission, to have contravenedOGAA may be liable to an administrative penalty notexceeding the amount specified in the AdministrativePenalties Regulation.

Drilling and Production Regulation

A person who contravenes the Drilling and ProductionRegulation (as specified in the Administrative PenaltiesRegulation, Section 5) may be liable to an administrativepenalty ranging from $2,000 to $500,000.

well drilling guideline april release v.1.9 2015

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