Canada–Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations: SOR/2024-25

Canada Gazette, Part II, Volume 158, Number 5

Registration
SOR/2024-25 February 19, 2024

CANADA–NEWFOUNDLAND AND LABRADOR ATLANTIC ACCORD IMPLEMENTATION ACT

P.C. 2024-143 February 19, 2024

Whereas, under subsection 150(1) of the Canada–Newfoundland and Labrador Atlantic Accord Implementation Act footnote a, a copy of the proposed Canada–Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations, substantially in the annexed form, was published in the Canada Gazette, Part I, on June 18, 2022 and a reasonable opportunity was afforded to interested persons to make representations to the Minister of Natural Resources with respect to the proposed Regulations;

And whereas, under subsection 7(1)footnote b of that Act, the Minister of Natural Resources consulted the Provincial Minister for Newfoundland and Labrador with respect to the proposed Regulations and that minister approved the making of those Regulations;

Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of Natural Resources and the Minister of the Environment, makes the annexed Canada–Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations under section 149footnote c of the Canada–Newfoundland and Labrador Atlantic Accord Implementation Act footnote a.

TABLE OF PROVISIONS

Canada–Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations

PART 1

General

PART 2

Experience, Training, Qualifications and Competence

3 Requirements

PART 3

Management System

PART 4

Authorization

Application

Requirements for Authorization

16 Definitions — paragraph 138(4)(c) of Act

Well Approvals

Development Plan

PART 5

Certificate of Fitness

Application

Requirements for Certification

Certifying Authority

PART 6

General Requirements for Authorized Works and Activities

General

Document Availability

Plans

50 Implementation

PART 7

Geoscientific Programs, Geotechnical Programs and Environmental Programs

Equipment, Materials and Property

Energy Sources

Primary Vessel

56 Classification

Destruction, Discard or Removal from Canada

57 Prohibited without approval

PART 8

Drilling and Production

General

Evaluation of Wells, Pools and Fields

Location of Wells

Well Integrity

Measurements

Production Conservation

Spill-treating Agent

Well Abandonment, Suspension or Completion

PART 9

Diving Projects

PART 10

Installations, Wells and Pipelines

Definitions

97 Definitions

Installations

General
Quality Assurance

100 Quality assurance program

Work Permits
Requirements
Systems and Equipment: Design, Installation, Commission and Other Requirements
Additional Requirements for Platforms
Asset Integrity
Operation and Maintenance

Wells

Pipelines

168 Pipeline integrity — standard

Monitoring of Installations, Wells and Pipelines

PART 11

Support Operations

PART 12

Notice, Records, Reports and Other Information for Authorized Works and Activities

General

Geoscientific, Geotechnical and Environmental Programs

Drilling and Production

Diving Projects or Construction Activities

207 Weekly status reports

PART 13

Repeals and Coming into Force

208 Repeals

Coming into Force

209 Six months after publication

SCHEDULE 1

PART 1

Provisions of these Regulations

PART 2

Provisions of the Canada–Newfoundland and Labrador Offshore Area Occupational Health and Safety Regulations

SCHEDULE 2

Canada–Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations

PART 1
General

Definitions

1 The following definitions apply in these Regulations.

accidental event
means an unexpected or unplanned event or circumstance or series of unexpected or unplanned events or circumstances that may lead to the loss of life or damage to the environment, including pollution. (événement accidentel)
accommodations area
means the area of an installation or vessel that contains the sleeping quarters, dining areas, food preparation areas, general recreation areas, offices and medical rooms and includes all washrooms in that area. (aire d’habitation)
accommodations installation
means an installation that is used to accommodate persons at a production site, drill site or dive site and that functions independently of a production installation, drilling installation or diving installation. (installation d’habitation)
Act
means the Canada–Newfoundland and Labrador Atlantic Accord Implementation Act. (Loi)
authorization
means an authorization issued by the Board under paragraph 138(1)(b) of the Act. (autorisation)
authorized inspector
means a person who is recognized under the laws of Canada or of a province as qualified to inspect boilers and pressure systems or a representative of a certifying authority who is qualified to carry out that function. (inspecteur autorisé)
barrier element
means a physical element that on its own does not prevent the flow of fluids but that in combination with other physical elements forms a well barrier. (élément de barrière)
barrier envelope
means an envelope consisting of a set of barrier elements that prevents any unintended flow of fluids from the formation into the well-bore, another formation or the environment. (enveloppe de barrière)
certificate of fitness
means a certificate referred to in section 139.2 of the Act. (certificat d’aptitude)
certifying authority
means the American Bureau of Shipping, Bureau Veritas, Det norske Veritas or Lloyd’s Register. (autorité)
classification society
means a member of the International Association of Classification Societies that has recognized and relevant competence and experience in, and established rules and procedures for, the classification of fixed and floating structures, including vessels, that are used in oil or gas activities in locations with physical and environmental conditions similar to those of the offshore area. (société de classification)
commingled production
means the production of petroleum from more than one pool or zone through a common well where the production from each pool or zone is not measured separately. (production mélangée)
completion interval
means a section within a well that is prepared to permit
  • (a) the production of fluids from the well;
  • (b) the observation of the performance of the reservoir; or
  • (c) the injection of fluids into the well. (intervalle de complétion)
control centre
means a continuously staffed work area in which a control system that is critical to the operation of an installation or a pipeline, to safety or to the prevention of waste and pollution is located. (centre de commande)
control system
means any system, station or panel used to monitor the status and control the operation of equipment used for or in support of the drilling for, or the production, processing or transportation of, petroleum or any system, station or panel used to monitor and control the operation of an installation. (système de commande)
decommissioning and abandonment
means the carrying out of the following processes in accordance with any applicable Act of Parliament, any applicable regulation made under an Act of Parliament, the applicable authorization and any approved development plans:
  • (a) the cessation of operations;
  • (b) the controlled abandonment of all wells;
  • (c) the retirement from service and abandonment or removal of all installations, including their systems and equipment; and
  • (d) the retirement from service and abandonment or removal of all pipelines and materials. (désaffectation et abandon)
delineation well
has the same meaning as in subsection 119(1) of the Act. (puits de délimitation)
development well
has the same meaning as in subsection 119(1) of the Act. (puits d’exploitation)
diving installation
means an installation or vessel on which a diving system is installed. (installation de plongée)
diving project
means any work or activity that is related to the exploration or drilling for, or the production, conservation, processing or transportation of, petroleum and that involves diving. (projet de plongée)
diving system
means the equipment that is required to execute a dive, including that required for compression, decompression, rescue and recovery. (système de plongée)
drilling installation
means a drilling unit or a drilling rig, and the stable foundation on which it is installed — including an artificial island, an ice platform, a floating platform, a platform fixed to the seabed and any other foundation specifically used for drilling — and any associated accommodations area. (installation de forage)
drilling program
means a program for the drilling of one or more wells within a specified time and within specified areas through the use of one or more drilling installations and includes any work or activity related to the program. (programme de forage)
drilling rig
means the equipment used to conduct well operations and associated systems, including power systems, control systems and monitoring systems. (appareil de forage)
drilling riser
means the connection between a subsea blowout preventer and a mobile offshore platform. (tube prolongateur de forage)
drilling unit
means a fixed or mobile offshore platform, or a vessel used in any well operation, that is fitted with a drilling rig, including all systems and equipment installed on the platform or vessel that are related to well operations and marine activities. (unité de forage)
drill site
means a location where a drilling rig is or is proposed to be installed. (emplacement de forage)
environmental load
means a load imposed by meteorological or oceanographic conditions, such as winds, waves, tides, currents or snow, ice conditions, regional ice features, such as sea ice or icebergs, a seismic event or any other naturally occurring phenomenon. (charge environnementale)
environmental program
means a program pertaining to an environmental study as defined in subsection 119(1) of the Act. (programme environnemental)
exploratory well
has the same meaning as in subsection 119(1) of the Act. (puits d’exploration)
floating platform
means a column-stabilized mobile offshore platform, a surface mobile offshore platform or a fixed floating offshore platform, including a tension leg platform or a spar platform. (plate-forme flottante)
flow allocation procedure
means the procedure
  • (a) to allocate total measured quantities of petroleum and water produced from or injected into a pool or zone back to individual wells in a pool or zone where individual well production or injection is not measured separately; and
  • (b) to allocate production among fields whose petroleum is combined for the purpose of storage or processing. (méthode de répartition du débit)
flow calculation procedure
means the procedure to convert raw meter output to a measured quantity of petroleum or water. (méthode de calcul du débit)
flowline
means any line, other than a pipeline, that is used to transport fluids between a well and equipment used for the production of petroleum that is located at a production site or to transport fluids between a well and any systems or equipment that are used in support of that production and between those systems or equipment and the production equipment. (conduite d’écoulement)
flow system
means the flow meters, auxiliary equipment attached to the flow meters, fluid sampling devices, production test equipment, master meter and meter prover used to measure and record the rate and volumes at which fluids are
  • (a) produced from or injected into a pool;
  • (b) used as a fuel;
  • (c) used for artificial lift; or
  • (d) flared, vented or transferred from a production installation. (système d’écoulement)
formation flow test
means an operation
  • (a) to induce the flow of formation fluids to procure reservoir fluid samples and determine reservoir flow characteristics; or
  • (b) to inject fluids into a formation to evaluate injectivity. (essai d’écoulement de formation)
functional load
means any construction load or operating load other than an environmental load or accidental load. (charge fonctionnelle)
geoscientific program
means any program that involves geological work or geophysical work, as those terms are defined in subsection 119(1) of the Act. (programme géoscientifique)
geotechnical program
means any program that involves geotechnical work, as defined in subsection 119(1) of the Act, that is undertaken to assess whether the seabed or shallow subsurface, as the case may be, is suitable to support installations or any other structures. (programme géotechnique)
installation
means, except in Part 5, a drilling installation, production installation or accommodations installation. (installation)
life-saving appliances
includes lifebuoys, survival craft, launching and embarkation appliances, marine evacuation systems and visual signals. (engins de sauvetage)
load
includes a functional load, environmental load, accidental load and abnormal load. (charge)
LSA Code
means the annex to International Maritime Organization Resolution MSC.48(66), International Life-Saving Appliance (LSA) Code. (recueil LSA)
major accidental event
means an unexpected or unplanned event or circumstance or series of unexpected or unplanned events or circumstances that may lead to the loss of more than one life or uncontrolled pollution. (événement accidentel majeur)
marine activities
means activities related to the stability, station-keeping and collision avoidance of floating platforms and includes mooring, dynamic positioning and ballasting. (activités maritimes)
mobile offshore platform
means a platform that is designed to operate in a floating or buoyant mode or that can be moved from place to place without major dismantling or modification, whether or not it has its own motive power. (plate-forme mobile extracôtière)
operations site
means a site where an authorized work or activity is carried out. (emplacement des opérations)
operator
means a person that holds an operating licence issued by the Board under paragraph 138(1)(a) of the Act and applies for or has been granted an authorization. (exploitant)
physical and environmental conditions
means the physical, geotechnical, seismic, oceanographic, meteorological or ice conditions that might affect an authorized work or activity. (conditions physiques et environnementales)
pipeline
has the same meaning as in CSA Group standard Z662, Oil and gas pipeline systems, as it relates to offshore pipelines. (pipeline)
pollution
means the introduction into the environment of any substance or form of energy outside the limits applicable to an authorized work or activity. (pollution)
pressure system
means piping, pressure vessels, safety components and pressure components, including elements attached to pressurized parts, such as flanges, nozzles, couplings, supports, lifting lugs, safety valves and gauges. (système sous pression)
production installation
means
  • (a) the systems and equipment used for or in support of the production of petroleum, including those that are used for separation, treatment and processing;
  • (b) the systems and equipment used to conduct well operations;
  • (c) any systems and equipment related to marine activities;
  • (d) any associated aircraft landing areas, storage areas or tanks and accommodations areas; and
  • (e) any associated platforms, artificial islands, subsea production systems and offshore loading systems. (ouvrage de production)
production project
means a project for the purpose of developing a production site on, or producing petroleum from, a pool or field, including any work or activity related to the project. (projet de production)
production riser
means the connection between subsea production equipment and a production platform. (tube prolongateur de production)
production site
means a site where a production installation is or is proposed to be installed. (emplacement de production)
recovery of petroleum
means the recovery of petroleum under foreseeable economic and operational conditions. (récupération des hydrocarbures)
relief well
means a well that is drilled to assist in controlling a blowout in an existing well. (puits de secours)
reportable incident
means an event that resulted in any of the following occurrences or in which an occurrence referred to in any of paragraphs (a) to (f) was narrowly avoided:
  • (a) loss of life;
  • (b) fire or explosion;
  • (c) collision;
  • (d) pollution;
  • (e) leak of a hazardous substance;
  • (f) loss of well control;
  • (g) impairment of a support craft or of any of the structural elements of an installation — or any system or equipment — that is critical to safety;
  • (h) impairment of any of the structural elements of an installation — or any system or equipment — critical to environmental protection;
  • (i) implementation of emergency response procedures. (incident à signaler)
safety-critical element
means any system or equipment, including software and temporary or portable equipment, that is critical to the safety or integrity of an installation or to preventing the installation from polluting, including
  • (a) any system or equipment
    • (i) that is intended to prevent or limit the effects of a hazard that could cause a major accidental event, or
    • (ii) whose failure could
      • (A) cause a hazard that could cause a major accidental event, or
      • (B) worsen the effects on the installation of a major accidental event; and
  • (b) any software or temporary or portable equipment that affects any system or equipment referred to in paragraph (a). (élément essentiel à la sécurité)
subsea production system
means equipment and structures that are located on or below the seabed for the production of petroleum from, or for the injection of fluids into, a field under a production site and includes production risers, flowlines and associated control systems that are located upstream of the isolation valve. (système de production sous-marin)
support craft
means a vessel, vehicle, aircraft or other craft used to provide transportation or assistance to persons at an operations site. (véhicule de service)
waste material
means any garbage, refuse, sewage or waste fluids or any other useless material that is generated during the carrying out of any work or activity, including used or surplus drill cuttings and drilling fluid as well as produced water. (déchets)
watertight
means designed and constructed to withstand a static head of water without any leakage. (étanche)
well control
means the control of the movement of fluids into or from a well. (maîtrise du puits)
well operation
means an operation related to the drilling, completion, recompletion, re-entry, intervention, workover, suspension or abandonment of a well. (travaux relatifs au puits)
workover
means an operation on a completed well that requires removal of the tree or the tubing. (reconditionnement)
zone
means any stratum or any sequence of strata, including a zone that has been designated as such by the Board under paragraph 60(a). (couche)

Incorporation by reference

2 (1) In these Regulations, any incorporation by reference of a document is an incorporation of that document as amended from time to time.

Bilingual documents

(2) Despite subsection (1), if a document that is incorporated by reference is available in both official languages, any amendment to it is incorporated only when the amended version is available in both official languages.

PART 2
Experience, Training, Qualifications and Competence

Requirements

3 (1) An operator must ensure that any person to whom a duty is assigned or who carries out a work or activity under these Regulations has the necessary experience, training, qualifications and competence to carry out that duty, work or activity safely, in a manner that protects the environment and in compliance with these Regulations.

Sufficient number and supervision

(2) The operator must ensure that the persons referred to in subsection (1) are sufficient in number and receive the necessary supervision to ensure safety and the protection of the environment.

PART 3
Management System

Requirements

4 (1) An operator must, for the purposes of reducing safety and environmental risks, preventing pollution and ensuring the conservation of petroleum resources, develop a management system that meets the following requirements:

Documentation

(2) The operator must ensure that the processes and policies included in the management system and the standards referred to in it are readily accessible for consultation and examination.

Organization

(3) The documentation associated with the management system must be organized and set out in a logical fashion to allow for ease of understanding and efficient implementation.

Processes and procedures

(4) In this section, a reference to a process includes any procedures that are necessary to implement the process.

Human resources

5 (1) An operator must put in place an organizational structure that includes sufficient human resources to implement and continually improve the management system.

Accountable person

(2) The operator must designate an employee as the accountable person for the management system and must ensure that the accountable person has the necessary authority over the human and financial resources that are required to implement and continually improve the system.

Name, position and contact information

(3) The operator must ensure that the name, position and contact information of the accountable person is submitted to the Board at the time the application for an authorization is made, when a new designation is made under subsection (2) and any time a change is made to the name, position or contact information of the accountable person.

Implementation

6 (1) An operator must ensure that the management system is implemented before the commencement of any authorized work or activity.

Compliance

(2) The operator must ensure that all employees, employers, suppliers, service providers and other persons that are subject to the management system comply with the requirements of the management system.

Continual improvement

7 The accountable person referred to in subsection 5(2) must ensure that the management system is continually improved.

PART 4
Authorization

Application

Documents and information

8 The application for an authorization must be accompanied by the following documents and information:

Safety plan

9 (1) An operator must develop a safety plan that sets out the procedures, practices, resources, sequence of key safety-related activities and monitoring measures that are necessary to safely carry out a proposed work or activity, as well as the target levels of safety in respect of the work or activity and measures for hazard management.

Documents and information

(2) The safety plan must include the following documents and information:

Environmental protection plan

10 (1) An operator must develop an environmental protection plan that sets out the procedures, practices, resources and monitoring measures that are necessary to protect the environment from the effects of a proposed work or activity, the target levels of safety in respect of the work or activity and measures for hazard management.

Documents and information

(2) The environmental protection plan must include the following documents and information:

Contingency plan

11 (1) An operator must develop a contingency plan that sets out the procedures, including emergency response procedures, and the practices, resources and monitoring measures that are necessary to effectively prepare for and mitigate the effects of any accidental event.

Documents and information

(2) The contingency plan must include the following documents and information:

Uncontrolled flow

(3) In the case of a drilling program or a production project, the contingency plan must also include a description of the source control and containment measures to be taken to stop uncontrolled flow from a well and to minimize the duration and environmental effects of any resulting spill, as well as the following documents and information:

Spill-treating agent

(4) If a spill-treating agent is being considered for use as a spill response measure, the contingency plan must include the following additional documents and information:

Assessment of efficacy

(5) The assessment of efficacy under paragraph (4)(a) must be carried out using oil obtained directly from the operations site where the spill-treating agent is being considered for use or, if oil is not available from that operations site, it must be carried out using an oil that most closely resembles the oil that is expected to be obtained from the operations site and must be repeated when oil becomes available from that operations site.

International standard or alternative

(6) The assessment, analysis, methods and protocols referred to in paragraphs (4)(a), (b) and (d) must be based, taking the local environment into account, on an international standard or an alternative recognized by the Board and the contingency plan must identify each of those standards or alternatives.

Methods and protocols

(7) The methods and protocols referred to in paragraph (4)(d) and the monitoring plan referred to in paragraph (4)(f) must conform to industry standards and best practices for spill-treating agent use, taking the local environment into account.

Definition of source control and containment equipment

(8) In this section, source control and containment equipment means the capping stack, containment dome, any subsea and surface equipment, devices or vessels and any relief well drilling installations that are used to contain and control a spill source and to minimize the duration of a spill and its environmental effects until well control is regained.

Spill-treating agent — section 138.21 of Act

12 In determining for the purpose of section 138.21 of the Act whether the use of a spill-treating agent is likely to achieve a net environmental benefit, the Board must take into account

Field data acquisition program

13 In the case of a production project, an operator must develop a field data acquisition program that

Flow system, calculation and allocation

14 (1) If the application for an authorization is in respect of a production project, the operator must submit to the Board for its approval the flow system, the flow calculation procedure and the flow allocation procedure that will be used to conduct the measurements referred to in sections 74 to 78, as well as any alternate measurements referred to in subsection 74(2) that the operator proposes to conduct.

Board approval

(2) The Board must approve the flow system, the flow calculation procedure and the flow allocation procedure if the applicant demonstrates that the system and procedures facilitate accurate measurements and the allocation, on a pool or zone basis, of the production from and injection into individual wells.

Decommissioning and abandonment plan

15 (1) An operator must, in the case of a drilling program or production project, develop a decommissioning and abandonment plan that includes the following information:

Costs and financing or payment

(2) The operator must submit to the Board an update on the forecasted costs of decommissioning and abandonment and the manner in which the operator will finance or pay for those costs

Requirements for Authorization

Definitions — paragraph 138(4)(c) of Act

16 The following definitions apply for the purposes of paragraph 138(4)(c) of the Act.

production facility
means the systems and equipment referred to in paragraph (a) of the definition production installation, other than a diving system, as well as any associated aircraft landing areas, storage areas or tanks and accommodations areas. (installation de production)
production platform
means a production installation. (plate-forme de production)

Well Approvals

Well operation

17 (1) Subject to subsection (2), an operator that intends to conduct a well operation must obtain a well approval.

Approval not necessary

(2) A well approval is not necessary to conduct a wire line operation, slick line operation, coiled tubing operation or other similar operation through a tree located above sea level if

Definitions

(3) The following definitions apply in subsection (2).

slick line
means a single steel cable that is used to run tools in a well. (câble lisse)
wire line
means a line that contains a conductor wire and that is used to run survey instruments or other tools in a well. (câble)

Approval application contents

(4) The application for a well approval must include the estimated cost breakdown of the well operation and the following information:

Well approval granted by the Board

(5) The Board must grant the well approval if the operator demonstrates that the well operation will be conducted safely, without waste or pollution and in compliance with these Regulations.

Well data acquisition program

18 In the case of a drilling program, an operator must develop a well data acquisition program that

Well verification scheme

19 (1) An operator must establish a well verification scheme based on criteria that the operator establishes to ensure that the design of any well is in accordance with industry standards and best practices so that the well’s integrity is maintained throughout its life cycle.

Well ranking

(2) For the purposes of subsection (1), the operator must rank a well according to its level of risk and ensure that the well ranking is confirmed by an independent person.

Verification requirements

(3) The verification scheme must set out the verification requirements that are applicable to the design of a well according to the well’s ranking and to any changes made to the design during the well’s construction or operation that would affect any previously undertaken verification.

Verification by independent person

(4) The operator must ensure that the required verifications are carried out by an independent person that was not involved in the original design.

Suspension of well approval

20 (1) The Board may suspend a well approval if

Factors for suspension

(2) In deciding whether to suspend a well approval, the Board must consider

Revocation of well approval

21 The Board must revoke a well approval if

Suspension or abandonment of well

22 If a well approval is revoked, the operator must ensure that the well is suspended or abandoned in accordance with Part 8.

Development Plan

Well approval — subsection 139(1) of Act

23 For the purposes of subsection 139(1) of the Act, a well approval relating to a production project is prescribed.

Concept safety analysis

24 (1) The approvals referred to in subsection 139(4) of the Act are subject to the operator’s submission of a concept safety analysis to the Chief Safety Officer at the time the operator submits the application and proposed development plan to the Board under subsection 139(2) of the Act.

Content

(2) The concept safety analysis must

Quantitative and qualitative risk assessments

(3) The target levels of safety must be based on risk assessments that are

Contents of risk assessment

(4) The operator must include in the risk assessment a description of the circumstances that will necessitate an update of the risk assessment, including changes in

Review of risk assessment

(5) The operator must update the risk assessment as often as necessary and at least once every five years throughout the life cycle of the development to

Resource management plan — paragraph 139(3)(b) of Act

25 (1) For the purposes of paragraph 139(3)(b) of the Act, Part II of the development plan must contain a resource management plan.

Contents of resource management plan

(2) The resource management plan must include a description and analysis of the following:

Organizational structure

(3) The resource management plan must also contain a description of the operator’s organizational structure as it relates to the implementation of the plan.

PART 5
Certificate of Fitness

Application

Prescribed installations — section 139.2 of Act

26 For the purpose of section 139.2 of the Act, a production installation, drilling installation, accommodations installation and diving installation are prescribed installations.

Definition of installation

27 In this Part, installation means an installation referred to in section 26.

Requirements for Certification

Issuance of certificate — requirements and conditions

28 (1) Before a certifying authority issues a certificate of fitness in respect of an installation,

Substitution — section 151 and subsection 205.069(1) of Act

(2) For the purposes of subparagraphs (1)(b)(ii) and (iii), the certifying authority may substitute, for any equipment, methods, measures, standards or other things required under any regulation referred to in those subparagraphs, any other equipment, methods, measures, standards or other things the use of which is authorized by the Chief Safety Officer or the Chief Conservation Officer, as the case may be, under section 151 of the Act or subsection 205.069(1) of the Act.

Limitations

(3) The certifying authority must set out in any certificate of fitness that it issues the details of any limitation on the operation of the installation that is necessary to ensure that the installation, including its systems and equipment, meets the requirements set out in paragraph (1)(b).

Conflict of interest — paragraph 139.2(4)(b) of Act

29 (1) For the purposes of paragraph 139.2(4)(b) of the Act, the extent to which a certifying authority may participate in the design, construction or installation of an installation in respect of which a certificate of fitness is issued is as follows:

Notice of non-compliance

(2) The certifying authority must monitor for any participation beyond that described in subsection (1) and must, without delay, inform the person that applied for the certificate and the Board of any such participation.

Certification plan

30 (1) A person that applies for a certificate of fitness must submit a certification plan to the Chief Safety Officer and to the certifying authority for the purposes of the approval of the scope of work under section 31.

Contents

(2) The certification plan must include the following documents and information:

Scope of work

31 (1) A certifying authority must submit to the Chief Safety Officer for approval a scope of work that takes into account the certification plan.

Contents of scope of work

(2) The scope of work must include

Approval of scope of work

(3) The Chief Safety Officer must approve the scope of work if the Chief Safety Officer determines that

Period of validity

32 (1) A certificate of fitness is valid for five years from the day on which it is issued if the certifying authority determines that the requirements referred to in paragraph 28(1)(b) will be met for a period of at least five years from that day.

Less than five years

(2) If the certifying authority determines that the requirements referred to in paragraph 28(1)(b) can be met only for a period that is less than five years, the certificate of fitness is valid for the corresponding lesser period.

Expiry date

(3) The certifying authority must indicate on the certificate of fitness its expiry date.

Extension of period of validity

(4) The certifying authority may, on request of the holder of a certificate of fitness, extend the period of validity of the certificate of fitness for a period of up to three months, subject to the approval of the Chief Safety Officer.

Approval by Chief Safety Officer

(5) The Chief Safety Officer must approve the extension of the period of validity of the certificate of fitness if the extension does not compromise safety or the protection of the environment.

Applicable site or region

33 (1) A certifying authority must indicate on a certificate of fitness the site or region where the installation is to be operated.

Validity

(2) A certificate of fitness is valid for the operation of the installation at the site or in the region that is indicated on the certificate of fitness.

Revalidation — scope of work

34 (1) The certifying authority must revalidate the scope of work against the criteria referred to in subsection 31(3) and make any modifications that are necessary

Revalidation approval

(2) The revalidated scope of work must be submitted to the Chief Safety Officer for approval under subsection 31(3).

Renewal of certificate

35 The certifying authority must renew the certificate of fitness in relation to an installation before or on its expiry date if

Invalidity

36 (1) Subject to subsections (2) and (3), a certificate of fitness ceases to be valid if

Notice in writing

(2) At least 30 days before a determination referred to in subsection (1) is made, notice of the impending determination must be given in writing

Consideration of information

(3) Before making a determination referred to in subsection (1), the certifying authority or the Chief Safety Officer, as the case may be, must consider any information in relation to that determination that is submitted by any person notified under subsection (2).

Change of certifying authority

37 (1) If the person that applies for a certificate of fitness decides to change the certifying authority in relation to an installation before the initial certificate of fitness is issued, the new certifying authority must undertake its own independent verification activities for the purpose of issuing the certificate of fitness.

After issuance of certificate

(2) If the holder of a certificate of fitness decides to change the certifying authority in relation to an installation, the holder must

Transition plan implementation

(3) The holder of a certificate of fitness must ensure that the transition plan referred to in paragraph (2)(b) is implemented.

One certificate — one authority

(4) There must be no more than one certificate of fitness and certifying authority in relation to an installation at any given time.

Certifying Authority

Organizational structure

38 A certifying authority must, without delay, notify the Board, the Federal Minister and the Provincial Minister of any changes to its organizational structure, including amalgamations and legal name changes.

Reports and information

39 (1) A certifying authority must submit to the Board, the Federal Minister and the Provincial Minister, not later than March 31 of each year, an annual report that contains

Monthly reports

(2) The certifying authority must submit a monthly report to the Board that describes the certification activities it carried out during the previous month as a certifying authority under the Act.

Information and documents to Board

(3) On the Board’s request, the certifying authority must submit to the Board any information obtained or documents generated in the course of carrying out its certification and verification activities.

Record retention

(4) The certifying authority must retain records, including technical drawings, for any activity carried out during its certification or verification activities in respect of an installation until the day that is seven years after the day on which the last certificate of fitness issued for that installation expires.

PART 6
General Requirements for Authorized Works and Activities

General

Installation manager

40 For the purposes of section 193.2 of the Act, every installation is a prescribed installation.

Safety and protection of environment

41 An operator must take all measures necessary to ensure safety and the protection of the environment during any authorized work or activity, including measures to ensure that

Physical and environmental conditions

42 An operator must ensure that

Location of infrastructure or equipment

43 An operator must keep data or information that accurately describes the location of any infrastructure or equipment at an operations site that is on or attached to the seabed, including any abandoned installation or part of it.

Accessibility, storage and handling of consumables

44 An operator must ensure that explosives, fuel, spill-treating agents, spill containment products, drilling, completion and well stimulation fluids and cement, as well as chemicals and other consumables that are necessary for safe operations, are

Storage and handling of chemical substances

45 An operator must ensure that all chemical substances present at an operations site, including process fluids, fuel, lubricants, waste material, drilling fluids and drill cuttings, are stored and handled in a manner that does not create a hazard to safety or the environment.

Misuse of equipment

46 It is prohibited for any person to tamper with, activate without cause or otherwise misuse equipment that is necessary for safety or the protection of the environment.

Cessation of work or activity

47 (1) An operator must ensure that any work or activity ceases without delay if it

Condition for resumption

(2) The operator must ensure that the work or activity does not resume until it can be done safely and without causing pollution.

Document Availability

Copy of authorization and approvals

48 (1) The operator must ensure that a copy of the authorization and all related approvals that are required under these Regulations or Part III of the Act is displayed in a conspicuous location at every operations site.

Additional copy and plans

(2) An operator must keep an additional copy of the authorization and approvals, as well as all plans that are required under these Regulations or Part III of the Act, at every operations site and must ensure that they are readily accessible for consultation or examination.

Emergency response procedures and other documentation

49 An operator must ensure that a copy of the most current version of the emergency response procedures and any documentation that is necessary to carry out an authorized work or activity and to operate and maintain an installation or pipeline is

Plans

Implementation

50 (1) An operator must ensure that the safety plan referred to in section 9, the environmental protection plan referred to in section 10 and the resource management plan referred to in section 25 are implemented at the commencement of any work or activity and that the contingency plan referred to in section 11 is implemented as soon as an accidental event occurs or appears imminent.

Periodic updates

(2) The operator must ensure that the safety plan, environmental protection plan, resource management plan and contingency plan are periodically updated; however, the descriptions of installations, vessels, systems and equipment that are included in the safety plan and the environmental protection plan as required by paragraphs 9(2)(c) and 10(2)(c), respectively, must be updated as soon as the circumstances permit after the modification, replacement or addition of any major component.

PART 7
Geoscientific Programs, Geotechnical Programs and Environmental Programs

Equipment, Materials and Property

Measures

51 An operator must ensure that

Certification

52 An operator must ensure that a competent third party has certified that all equipment that is installed temporarily on a vessel to conduct a geoscientific program, geotechnical program or environmental program is fit for the purposes for which it is to be used.

Damage to property

53 An operator must take all necessary measures to ensure that no property is damaged as a result of a geoscientific program, geotechnical program or environmental program.

Energy Sources

General requirements

54 (1) An operator must ensure that any energy source that is used in a geoscientific program, geotechnical program or environmental program is

Electrical or electromagnetic energy source

(2) The operator must ensure that any electrical or electromagnetic energy source is equipped with circuit breakers on the charging and discharging circuits and with wiring that is adequately insulated and grounded to prevent current leakage and electrical shock.

Elimination of risk to divers

(3) The operator must ensure that the program is conducted in a manner that eliminates all safety risks to divers from any energy source used, including by determining the minimum distances that are required to be maintained between the divers and the energy source and ensuring compliance with those distances.

Testing of energy sources

55 (1) An operator must minimize energy source testing on the deck of an operations site while a geoscientific program, geotechnical program or environmental program is being conducted.

Energy source activation

(2) Before an energy source is activated for testing purposes, the operator must ensure that measures are taken to protect persons at the operations site where the test will be conducted from exposure to any hazard associated with the energy source, including

Primary Vessel

Classification

56 An operator must ensure that the primary vessel used in a geoscientific program, geotechnical program or environmental program holds a valid certificate of class issued by a classification society.

Destruction, Discard or Removal from Canada

Prohibited without approval

57 (1) It is prohibited for any person to destroy, discard or, subject to subsection (2), remove from Canada the following materials and information that are obtained in the context of a geoscientific program, geotechnical program or environmental program unless the destruction, discard or removal is approved by the Board under subsection (3):

Exception

(2) The materials and information may be removed from Canada without the approval of the Board for the purpose of being processed in a foreign country if they are returned to Canada as soon as the processing is complete.

Approval of application

(3) Within 60 days after the day on which the Board receives an application for approval to destroy, discard or remove from Canada materials or information, the Board must approve the application if the Board is satisfied that the materials or information are not of much use or value.

Provision of materials or information

(4) The Board may, after receiving an application referred to in subsection (3), require that the materials or information, or a copy of the information, be provided to the Board within the period that it specifies.

PART 8
Drilling and Production

General

Allocation of areas

58 The Board may make orders respecting the allocation of areas, including respecting the determination of the size of spacing units and the determination of well production rates, for the purpose of drilling for or producing petroleum.

Name, classification or status of well

59 The Board may give a name, classification or status to any well and may change that name, classification or status.

Pool, zone or field

60 The Board may

Evaluation of Wells, Pools and Fields

Data acquisition programs

61 (1) An operator must ensure that the field data acquisition program referred to in section 13 and the well data acquisition program referred to in section 18 are implemented in accordance with good oilfield practices.

Partial implementation

(2) If part of the field or well data acquisition program cannot be implemented, the operator must ensure that

Board approval of alternate measures

(3) The Board must approve the measures submitted under paragraph (2)(b) if the operator demonstrates that the measures can achieve the goals of the field data acquisition program or the well data acquisition program, as the case may be, or are the only ones that can be taken in the circumstances.

Periodic updates

(4) The operator must ensure that the field data acquisition program is periodically updated.

Formation evaluation, testing and sampling

62 If the Board determines that data or samples from a formation in a well would contribute substantially to the geological and reservoir evaluation, the operator must ensure that the formation is evaluated, tested and sampled as necessary to obtain the data or samples.

Formation flow test

63 (1) An operator must ensure that no development well is put into production unless a formation flow test that has been approved by the Board under subsection (5) is conducted.

Well operation

(2) If a development well is subjected to a well operation that might change its deliverability, productivity or injectivity, the operator must, for the purpose of determining the effects of the operation on the well’s deliverability, productivity or injectivity, ensure that a formation flow test that has been approved by the Board under subsection (5) is conducted as soon as the circumstances permit after the well operation has ended and the flow or injection conditions have stabilized.

Conditions

(3) Before conducting a formation flow test on a well drilled on a geological feature, the operator must

Contribution to geological and reservoir evaluation

(4) The Board may require that the operator conduct a formation flow test on a well drilled on a geological feature, other than the first well, if the Board determines that the test would contribute to the geological and reservoir evaluation.

Approval of formation flow test

(5) The Board must approve a formation flow test if the operator demonstrates that the test will be conducted in a manner that ensures safety and the protection of the environment and in accordance with good oilfield practices and that the test will enable the operator to

Samples and cores

64 (1) An operator must ensure that all drill cutting and fluid samples and cores collected as part of the field data acquisition program referred to in section 13 and the well data acquisition program referred to in section 18 are

Remaining conventional core

(2) An operator must ensure that, after any samples necessary for analysis or for research or academic studies have been removed from a conventional core, the remaining core, or a longitudinal slab that is not less than one half of the cross-sectional area of that core, is delivered to the Board.

Remaining sidewall core

(3) The operator must ensure that, after any samples necessary for analysis or for research or academic studies have been removed from a sidewall core, the remaining core is delivered to the Board.

Notice before disposal

65 Before disposing of any drill cutting or fluid samples, cores or evaluation data, an operator must ensure that the Board is notified in writing and given an opportunity to request delivery of the samples, cores or data.

Location of Wells

Depth measurements

66 An operator must ensure that no record is made of any depth in a well unless the depth is measured from the rotary table of the drilling rig.

Directional and deviation surveys

67 An operator must ensure that

Well Integrity

Well control

68 (1) An operator must ensure that adequate procedures, materials and equipment are in place and used throughout the life cycle of the well to prevent the loss of well control.

Reliable well control equipment

(2) The equipment referred to in subsection (1) must include reliable well control equipment to detect and control kicks, prevent blowouts and safely conduct all well operations.

Shallow hazards

(3) During well operations conducted without a riser, the operator must ensure that measures are implemented to reduce the risk of shallow hazards while drilling.

Surface casing

(4) The operator must ensure that the surface casing of the well is installed to a sufficient depth, and in a competent formation, to establish well control for the continuation of the drilling operations.

Blowout preventer and barrier envelopes

(5) After the surface casing has been installed and cemented, the operator must ensure that

Barrier envelope failure

(6) If there is a failure in a barrier envelope, the operator must ensure that no well operation, other than one that is intended to replace or restore the barrier envelope, takes place until the barrier envelope is replaced or restored.

Replacement or restoration of barrier envelope

(7) The operator must ensure that

Drilling fluid column

(8) The operator must ensure that, during well operations, one of the two barrier envelopes is the drilling fluid column, except when drilling under-balanced or if, when a completion or test string is run, the other barrier envelope has already been installed downhole and tested.

Pressure control equipment

(9) The operator must ensure that all pressure control equipment associated with well operations is pressure-tested on installation and as often as necessary to ensure its continued safe operation.

Corrective measures

(10) If well control is lost or if safety, the protection of the environment or resource conservation is at risk, the operator must ensure that any necessary corrective measures are taken without delay.

Casing and wellhead system

69 (1) An operator must ensure that a casing and wellhead system is designed, taking into account the wellhead’s fatigue life, so that, throughout the life cycle of the well,

Barrier analysis

(2) The operator must ensure that, during the design of the casing and wellhead system, if the annulus is to be used for fluid production or injection, a barrier analysis is conducted to confirm that two barrier envelopes can be maintained in place throughout the life cycle of the well.

Casing depth

(3) The operator must ensure that each casing is installed at a depth that provides for adequate kick tolerance and safe well control.

Wellhead fatigue life

(4) The operator must ensure that well operations do not continue beyond the wellhead’s fatigue life.

Cement slurry

(5) The operator must ensure that the cement slurry is designed and installed so that, throughout the life cycle of the well,

Cement integrity and placement

(6) The operator must ensure that the cement integrity and placement are verified, subject to subsection (7), through pressure-testing and, if the cement is a common barrier element of the two barrier envelopes or if confirmation of zonal isolation is required, also through logging.

Other methods of verification

(7) The cement integrity and placement may be verified using other methods if the operator demonstrates that those methods provide a level of verification that is equivalent to those referred to in subsection (6).

Cement design and slurry analysis

(8) The operator must ensure that the cement design is subjected to comprehensive laboratory testing and pre-cementing quality control, under all foreseeable conditions that could have an impact on cementing, so that the cement provides the expected isolation and can be efficiently installed.

Waiting on cement time

(9) The operator must ensure that, after cementing any casing or casing liner and before drilling out the casing shoe, the cement reaches the minimum compressive strength sufficient to support the casing and provide zonal isolation.

Casing pressure testing

(10) The operator must ensure that, after any casing is installed and cemented and before the casing shoe is drilled out, the casing is pressure-tested to the value required to confirm its integrity for maximum anticipated operating pressure throughout the life cycle of the well.

Formation leak-off or integrity test

70 (1) An operator must ensure that a formation leak-off test or a formation integrity test is conducted

Pressure

(2) The formation leak-off test or formation integrity test must be conducted at a pressure that allows for safe drilling to the next casing depth and for the adequacy of the cement at the level of the shoe to be verified before drilling ahead.

Completion, testing and operation of development wells

71 (1) The operator of a development well must ensure that

Segregated multi-pool well

(2) If the development well is a segregated multi-pool well, the operator must also ensure that

Definition of multi-pool well

(3) In this section, multi-pool well means a well that is completed in more than one pool.

Production tubing

72 An operator must ensure that the production tubing used in a well is designed and maintained to be compatible with the fluids to which it will be exposed, to withstand the maximum conditions, forces and stresses to which it may be subjected and to maximize recovery of petroleum from the pool.

Safe operations and production

73 An operator must ensure that equipment and procedures are in place to recognize and control normal and abnormal operating conditions, for the purposes of allowing for safe and controlled well operations and production and of preventing pollution.

Measurements

Flow and volume

74 (1) Subject to subsection (2), an operator must ensure that the following are measured:

Alternate measurements

(2) Alternate measurements may be conducted if approved by the Board under section 14.

Method

(3) The operator must ensure that all measurements are conducted using the flow system, flow calculation procedure and flow allocation procedure approved under subsection 14(2).

Allocation of group production

75 An operator must ensure that group production of oil, gas and water from wells and the volume of fluids injected into those wells are allocated on a pro rata basis using the flow system, flow calculation procedure and flow allocation procedure approved under subsection 14(2).

Allocation over multiple pools or zones

76 (1) If a well is completed over multiple pools or zones, the operator must ensure that the production of oil, gas and water from the well and the volume of fluids injected into the well are allocated on a pro rata basis to the pools or zones using the flow allocation procedure approved under subsection 14(2).

Proration tests

(2) The operator must ensure that sufficient proration tests are conducted to measure the rates at which fluids are produced from the well to ensure that the allocation of oil, gas and water production to the pools and zones as a result of the flow allocation procedure is accurate.

Testing and maintenance

77 (1) An operator must ensure that

Notice

(2) The operator must ensure that a conservation officer is notified, as soon as the circumstances permit, of any modification to or malfunction or failure of any flow system component that may have an impact on the accuracy of the flow system and of the corrective measures taken.

Calibration

78 An operator must ensure that

Production Conservation

Resource management

79 An operator must, in respect of the recovery of petroleum, ensure that

Commingled production

80 (1) It is prohibited for an operator to engage in commingled production unless approved by the Board.

Approval by the Board

(2) The Board must approve commingled production if the operator demonstrates that it will maximize the recovery of petroleum.

Measurement and allocation

(3) If the operator engages in commingled production, it must ensure that the total volume and the rate of production of each fluid produced is measured and the volume from each pool or zone is allocated in accordance with the requirements set out in sections 74 to 78.

Pilot scheme

81 (1) An operator may develop and implement a pilot scheme that applies technology in relation to the commercial production of petroleum from a pool, field or zone that is accessible from a production installation and in relation to which there is an approved development plan for the purpose of obtaining information on reservoir, production or technology performance in order to optimize production performance under the development plan or to determine whether the development plan requires an amendment for production performance to be optimized.

Duration and interim evaluations

(2) The Board must establish

Completion of pilot scheme

(3) On completion of the pilot scheme, the operator must ensure that any production activities undertaken for the purpose of the scheme are discontinued.

Prohibition against flaring or venting

82 It is prohibited for an operator to flare or vent gas unless

Venting limit

83 (1) An operator must ensure that the volume of gas vented under paragraph 82(a) per installation during a year is not greater than 15 000 standard m3.

Definition of vented

(2) For the purpose of subsection (1), vented means emitted in a controlled manner, other than as a result of combustion, from an installation due to

Gas emissions

84 (1) The operator must ensure that the emissions of gas from the seals of a centrifugal compressor or reciprocating compressor at an installation are

Flow rate measurement device

(2) The operator must ensure that the flow rate of emissions of gas released from vents referred to in paragraph (1)(b) is measured by means of a continuous monitoring device that is

Flow rate limit — centrifugal compressor

(3) The operator must ensure that the flow rate limit of emissions from the vents of a centrifugal compressor on an installation is

Flow rate limit — reciprocating compressor

(4) The operator must ensure that the flow rate limit of emissions that are from the rod packings and distance pieces of a reciprocating compressor on an installation is

Corrective measures

(5) If the alarm referred to in paragraph (2)(c) is triggered, the operator must ensure that corrective measures are taken as soon as the circumstances permit to reduce the flow rate to below or equal to the applicable flow rate limit.

Prohibition against oil burning

85 It is prohibited for an operator to burn oil unless

Spill-treating Agent

Determination of net environmental benefit

86 In determining for the purpose of subsection 161.1(3) of the Act whether the use of a spill-treating agent is likely to achieve a net environmental benefit, the Chief Conservation Officer must take into account

Small-scale test

87 (1) An operator must, in respect of any small-scale test of a spill-treating agent referred to in section 161.1 of the Act, ensure that

Conditions

(2) The following conditions must be met before a small-scale test is approved:

Net environmental benefit already determined

(3) No small-scale test is to be approved if the Chief Conservation Officer has made a determination for the purpose of section 161.1 of the Act regarding the net environmental benefit of the use of the spill-treating agent whose efficacy the test is intended to evaluate.

Oral or written approval

(4) Approval of a small-scale test may be provided orally or in writing but, if approval is provided orally, the Chief Conservation Officer must, as soon as the circumstances permit, provide to the operator written confirmation of the approval.

Variation of approval

88 (1) The Chief Conservation Officer must vary the approval to use a spill-treating agent if new information indicates that a modification to the requirements set out in the approval is necessary to ensure that the approved use is likely to achieve a net environmental benefit.

Revocation of approval

(2) The Chief Conservation Officer must revoke the approval if new information indicates that, despite any modification, use of the agent will not likely achieve a net environmental benefit.

Use of spill-treating agent

89 (1) An operator must ensure that any spill-treating agent is used in accordance with industry standards and best practices for spill-treating agent use, taking into account the local environment.

Equipment and materials

(2) The operator must ensure that all equipment and materials that are listed in the contingency plan as required by paragraph 11(4)(e) are available and maintained in accordance with the manufacturers’ specifications and ready for use at all times.

Monitoring plan implementation

(3) The operator must implement the monitoring plan that is included in the contingency plan as required by paragraph 11(4)(f) at the commencement of the use of a spill-treating agent in the case of a spill.

Information to Chief Conservation Officer

(4) The operator must inform the Chief Conservation Officer of the spill-treating agent’s efficacy, the effects of its use on the environment and any changes that may require a modification to its use.

Well Abandonment, Suspension or Completion

Conditions for suspension or abandonment

90 (1) An operator that suspends or abandons a well must ensure that the well

Verification of isolation

(2) Before suspending or abandoning the well, the operator must verify the effectiveness of the isolations referred to in subparagraph (1)(b)(i) in accordance with the methods set out in its well approval application under paragraph 17(4)(e).

Additional condition for suspension

91 An operator that suspends a well must ensure that it is inspected and monitored to maintain its integrity and prevent pollution.

Additional condition for abandonment

92 The operator of a well must ensure that, on the abandonment of the well, the seabed is cleared of any material or equipment that might have an adverse effect on the marine environment or interfere with fishing activities or other uses of the sea.

Conditions for drilling installation removal

93 It is prohibited for the operator of a drilling installation to remove the drilling installation from a well or cause it to be removed unless

PART 9
Diving Projects

Vessel used in diving project

94 An operator that conducts a diving project must, in respect of a vessel used in the diving project, ensure that

Dynamic positioning system

95 (1) An operator must ensure that the dynamic positioning system on a vessel that is used in a diving project

Verification

(2) After the design of the dynamic positioning system is completed, the operator must ensure that a failure modes and effects analysis is conducted to verify that the dynamic positioning system meets the requirements set out in subsection (1).

Maintenance

(3) The operator must ensure that the dynamic positioning system is maintained so that it continues to perform in accordance with its design specifications.

Light dive craft

96 (1) The operator must ensure that any light dive craft that is used for a diving project is

Dive support vessel

(2) The operator must ensure, during all dives from a light dive craft, the availability of a dive support vessel that

Definition of light dive craft

(3) In this section, light dive craft means a small vessel or secondary craft that is equipped to deploy divers from a primary vessel.

PART 10
Installations, Wells and Pipelines

Definitions

Definitions

97 The following definitions apply in this Part.

air gap
means the clearance between the highest water or ice surface that occurs during extreme environmental conditions and the lowest exposed part of an installation not designed to withstand wave or ice impingement. (tirant d’air)
control station
means a work area that is not continuously staffed that provides an alternative location to a control centre and the minimum necessary control equipment to enable essential management of the installation or of specific key systems. (poste de contrôle)
damaged condition
means, with respect to a floating platform, the condition of the platform after it has suffered damage up to the extent determined in accordance with the applicable provisions of the MODU Code or, in the case of a platform that is not a mobile offshore drilling unit, the applicable rules of a classification society. (état d’avarie)
design service life
means the anticipated period during which any installation, including its systems or equipment, is to be used for its intended purpose, with anticipated maintenance but without substantial repair. (vie utile)
hazardous area
means an area on an installation where flammable, explosive or combustible mixtures are or are likely to be present in sufficient quantities and for sufficient periods of time to require special precautions to be taken in the selection, installation or use of machinery and electrical equipment to prevent a fire or explosion. (aire dangereuse)
IS Code
means the annex to International Maritime Organization Resolution MSC.267(85), International Code on Intact Stability, 2008. (recueil IS)
MODU Code
means the annex to International Maritime Organization Resolution A.1023(26), Code for the Construction and Equipment of Mobile Offshore Drilling Units, 2009. (Code MODU)
process vessel
means a heater, dehydrator, separator, treater or any other pressurized vessel used in the processing or treatment of produced petroleum. (cuve de traitement)
unattended installation
means an installation on which persons are not normally present and in respect of which, when persons are present, it is for the purpose of performing operational duties, maintenance or inspections that will not require an overnight stay. (installation non fréquentée)

Installations

General

Safety and environmental protection

98 An operator must ensure that an installation, including its systems and equipment, is designed, constructed, installed, arranged and commissioned so that it is fit for the purposes for which it is to be used and can be operated safely without posing a threat to persons or the environment.

Design of installation

99 For the purpose of meeting the requirement under section 98 in respect of design, an operator must ensure that an installation, including its systems and equipment, is designed in accordance with the measures referred to in clauses 9(2)(b)(v)(A) and 10(2)(b)(v)(A) that are described in the operator’s safety plan and environmental protection plan, respectively.

Quality Assurance

Quality assurance program

100 (1) An operator must, for the purpose of ensuring that an installation, including its systems and equipment, is fit for the purposes for which it is to be used, develop a quality assurance program that meets the following requirements:

Implementation

(2) The operator must ensure that each phase of the life cycle of the installation, from its design up to and including its decommissioning and abandonment, is carried out in accordance with the program and that any activity relating to the installation that is carried out under the control of a third party is also carried out in accordance with a quality assurance program.

Accessibility

(3) The operator must ensure that the processes and policies that are included in the program referred to in subsection (1) are readily accessible for consultation and examination.

Organization

(4) The operator must ensure that the documentation relating to the program referred to in subsection (1) is organized and set out in a logical fashion to allow for ease of understanding and efficient implementation.

Processes and procedures

(5) In this section, a reference to a process includes any procedures that are necessary to implement the process.

Work Permits

Requirements

101 (1) An operator must ensure that a work permit that is required under this Part is issued in either paper or electronic form, is approved by a person other than the one who issued it and sets out the following information:

Signatures

(2) The work permit must bear the signatures of the person who issued it, the person who approved it and every person involved in the work or activity to which it relates, certifying that they have read and understood its contents.

Operator obligations

102 (1) An operator must ensure that

Retention of copy

(2) The operator must retain a copy of each work permit for at least three years after the day on which the work or activity to which it relates is completed.

Requirements

Innovations

103 (1) An operator must ensure that any technology, including any technology that is used in relation to materials, design methods, joining techniques or construction techniques, that has not been previously used in comparable situations is not used in relation to an installation unless

Technology qualification program

(2) The operator must develop a technology qualification program that sets out the performance monitoring and inspection measures that are necessary to determine the effectiveness of any technology referred to in subsection (1) that it intends to use.

Program implementation and update

(3) The operator must ensure that the program is implemented and periodically updated.

Physical and environmental conditions

104 (1) An operator must ensure that an installation is designed to withstand or avoid all foreseeable site-specific physical and environmental conditions, or any foreseeable combination of those conditions, without compromising its structural integrity or that of any of its systems or equipment that are critical to safety or to the protection of the environment.

Criteria

(2) The operator must ensure that the design of an installation is based on criteria that are determined using evidence-based regional and site-specific data, statistical analysis and modelling of physical and environmental conditions, including

Ice conditions

(3) The operator must ensure that an installation that is to be operated where ice conditions may exist is designed and operated to

Redundancy

(4) The operator must ensure that there is redundancy included in any measures implemented for the purpose of paragraph (3)(a) in relation to ice and snow accumulation and removal.

Cold climate — safety plan and environmental protection plan

(5) The operator must ensure that an installation that is to be operated in a cold climate is designed, winterized and operated in accordance with the measures referred to in clauses 9(2)(b)(v)(B) and 10(2)(b)(v)(B) that are described in the operator’s safety plan and environmental protection plan, respectively.

Cold climate — design

(6) An installation that is to be operated in a cold climate must be designed to

Design for intended use and location

105 (1) An operator must ensure that the structural components of an installation and any of its ancillary structures, including skids and modules, are designed for their intended use and location, taking into account

Analyses, tests, modelling and investigations

(2) The design of the structural components of an installation and any of its ancillary structures, including skids and modules, must be based on any analyses, model tests, numerical modelling and site investigations that are necessary to determine the behaviour of the installation and of the soils that support it or its mooring systems under all foreseeable operating, construction, transportation and installation conditions — including those involving geohazards — and under all foreseeable loads during the design service life of the installation.

Design criteria

(3) The structural components of an installation and any of its ancillary structures, including skids and modules, must be designed to

Accidental loads

(4) For the purposes of paragraphs (3)(d) to (f) and (h), the design must take into account all credible accidental load scenarios, including collisions between the installation and a vessel or aircraft.

Conditions for safe operation and survival

106 Based on the results of any analyses, tests, modelling or investigations undertaken under subsection 105(2), the operator must ensure that

Risk assessment — fire, explosion and hazardous gas

107 (1) An operator must ensure that an assessment of fire and explosion risks and of risks associated with hazardous gas and its containment is conducted in respect of an installation and that the assessment identifies

Elements for consideration

(2) For the purposes of paragraphs (1)(b) and (c), the assessment must take into account the following elements:

Reliability and availability

108 (1) An operator must demonstrate, through a risk and reliability analysis conducted using internationally recognized techniques, the reliability and availability of any system in an installation whose failure could cause or contribute to a major accidental event or whose purpose is to prevent or mitigate the effects of a major accidental event.

Redundancies and measures

(2) The risk and reliability analysis must determine the redundancies and measures that are required to protect a system referred to in subsection (1) from failure, including any redundancies and measures required under this Part for that system.

Results of analysis

(3) The operator must ensure that the results of the risk and reliability analysis are reflected in the design of the installation, its systems and equipment and in any associated operating and maintenance manuals, including the operations manual referred to in section 157.

Monitoring program for physical and environmental conditions

109 (1) An operator must develop a monitoring program that involves the collection of data on physical and environmental conditions in sufficient quantities and at sufficient frequencies, and the retention of that data for sufficient periods, to

Equipment

(2) For the purposes of subsection (1), the operator must ensure that the installation is equipped to observe, measure and forecast physical and environmental conditions, to record data on those conditions and to obtain from external sources any additional data on those conditions.

Program implementation and update

(3) The operator must ensure that the monitoring program is implemented and periodically updated.

Availability of data

(4) The operator must ensure that the data referred to in subsection (1) that may have an impact on safety and the protection of the environment is documented and provided to all persons that request it.

Inspection, monitoring, testing and maintenance

110 An operator must, for the purpose of facilitating the inspection, monitoring, testing and maintenance of an installation, ensure that

Materials for installations

111 (1) An operator must ensure that the materials used in an installation are

Definition of non-combustible

(2) In this section, non-combustible means, in respect of material, material that does not burn or give off flammable gases or vapours in sufficient quantity for self-ignition when heated to 750°C.

Passive fire and blast protection

112 (1) An operator must ensure that an installation is designed and constructed with passive fire and blast protection.

Design of passive fire protection

(2) The design of the passive fire protection must

Divisions

(3) The operator must ensure that the installation is divided such that spacing and barriers protect against accidental events and loads identified in the risk assessment conducted under subsection 107(1) or mitigate their effects.

Barriers — safety plan and environmental protection plan

(4) The operator must ensure that barriers are designed, arranged, installed and maintained in accordance with the measures referred to in clauses 9(2)(b)(v)(C) and 10(2)(b)(v)(C) that are described in the operator’s safety plan and environmental protection plan, respectively.

Barriers — requirements

(5) Barriers must be designed, arranged, installed and maintained to

Barriers — level of protection

(6) The level of fire and blast protection that each barrier must provide is to be based on the results of the risk assessment conducted under subsection 107(1).

Barriers — penetrations and openings

(7) A barrier must not have any penetrations or openings unless

Barrier components

(8) The operator must ensure that barrier components are certified by a competent third party.

Bulkheads — production installation

(9) Unless the other combined features of a production installation can be demonstrated to provide at least the same level of protection, the operator must ensure that the following bulkheads are capable of preventing the passage of smoke and flame and of limiting the temperature rise on the unexposed face of the bulkhead to an average increase of 139°C and a maximum increase of 180°C above the initial temperature following 120 minutes of exposure to a hydrocarbon fire:

Classification society rules

(10) The operator must ensure that the passive fire and blast protection for an installation that does not hold a valid certificate of class issued by a classification society is at least equivalent to the protection required under the rules of a classification society for a mobile offshore drilling unit.

Hazardous and non-hazardous areas

113 (1) An operator must ensure that the boundaries between all hazardous areas and non-hazardous areas on an installation are delineated.

Classification of hazardous areas

(2) The operator must ensure that, following the conduct of the risk assessment under subsection 107(1), each hazardous area is classified according to an internationally recognized, comprehensive and documented classification system.

Separation of areas

(3) The operator must ensure that hazardous areas of different classifications are separated from one another and from non-hazardous areas.

Direct access and openings

(4) The operator must ensure, if practicable, that there is no direct access or other opening between hazardous areas and non-hazardous areas and between hazardous areas of different classifications or, if that is not practicable, that any direct access or opening between those areas is minimized and is designed to prevent uncontrolled air flow between them.

Piping systems

(5) The operator must ensure that piping systems are designed to ensure that there is no direct conduit between hazardous and non-hazardous areas and between hazardous areas of different classifications.

Ventilation of enclosed hazardous areas

114 (1) An operator must ensure that any enclosed hazardous area on an installation is ventilated such that

Mechanical ventilation system

(2) If a mechanical ventilation system is used for the purposes of subsection (1), the operator must ensure that the air in the enclosed hazardous area is maintained at a pressure that is lower than the pressure of any adjacent non-hazardous area or any adjacent hazardous area that is classified as less hazardous.

Air exhaustion from enclosed hazardous area

(3) The operator must ensure that all air exhausted from an enclosed hazardous area is vented to an outdoor area that, were it not for the vented air, would be a non-hazardous area or a hazardous area that would be classified as no more hazardous than the enclosed hazardous area.

Ventilation pressure differential and functionality

(4) The operator must ensure that measuring devices are installed that will monitor any loss of ventilation pressure differential and any loss of functionality of each ventilation system for a hazardous area and that will, no more than 30 seconds after such a loss occurs, activate audible and visual alarms at the control points from which the system is monitored.

Positive overpressure relative to atmospheric pressure

(5) The operator must, in respect of the main control centre and all accommodations areas on an installation, ensure that

Power shut-off for mechanical ventilation system

(6) The operator must ensure that the power source for a mechanical ventilation system that serves a hazardous area, a work area in a non-hazardous area or an accommodations area is capable of being shut off from the control station and from a position that is outside the area being ventilated and that will remain accessible during any fire that may occur within that area.

Inlets and outlets of ventilation systems

(7) The operator must ensure that the main inlets and outlets of all ventilation systems are capable of being closed from a position that is outside the area being ventilated and that will remain accessible during any fire that may occur within that area.

Ventilation system in non-hazardous area

(8) The operator must ensure that any ventilation system that serves a non-hazardous area is equipped with emergency devices in the event of a mechanical ventilation failure or the detection of hazardous gas, including

Ignition prevention

115 (1) In order to prevent the ignition of flammable, combustible or explosive substances on an installation, an operator must ensure that measures are implemented to prevent the uncontrolled release or accumulation of those substances, including by ensuring that materials and equipment are properly arranged.

Design — systems and equipment

(2) The operator must ensure that any system or equipment that is to be used in a hazardous area is designed to control ignition sources and to prevent fire and explosions in that area, taking into account the area’s classification under subsection 113(2).

Risk assessment

(3) For the purposes of meeting the requirements under subsections (1) and (2), the operator must ensure that any control measures identified in the risk assessment conducted under subsection 107(1) are implemented.

Other requirements — equipment

(4) The operator must ensure that any equipment located in a hazardous area is rated for use in that area and is installed, ventilated and maintained to ensure safe operation.

Safe distance operation

(5) The operator must ensure that any equipment that is operated in a non-hazardous area is operated at a safe distance from any flammable, combustible or explosive substances and is, unless it is rated for use in a hazardous area, equipped with an automatic and manual means of deactivation in the event of fire or hazardous gas detection.

Equipment in event of emergency

(6) The operator must ensure that any equipment that is located in a non-hazardous area and that is to remain in service in the event of an emergency associated with a gas release is rated for use in a hazardous area and is installed, ventilated and maintained to ensure safe operation.

Cargo tank

(7) The operator must ensure that

Work permit

(8) A work permit is required for all hot work carried out on an installation.

Safe distances

(9) The work permit for hot work must set out safe distances to be maintained between the hot work and any well or any flammable, combustible or explosive substance.

Means of escape, evacuation and rescue

116 An operator must ensure that an installation is equipped with a safe means of escape, evacuation and rescue, taking into account the results of the risk assessment conducted under subsection 107(1) and comprehensive and documented safety studies.

Temporary safe refuge

117 (1) The operator must ensure that the installation is equipped with a temporary safe refuge that will, in the case of an emergency, including an accidental event,

Areas required to remain safe

(2) The operator must ensure that the accommodations area, main control centre and any other area of an installation that is required to remain safe for persons to occupy during an emergency, including the temporary safe refuge, are

Periodic verification

(3) The operator must verify on a periodic basis that the temporary safe refuge meets the requirements set out in subsections (1) and (2) and must record the findings resulting from the verification.

Exits, access and escape routes

118 (1) An operator must ensure that

Exception

(2) Despite paragraph (1)(a), if an area referred to in that paragraph has an area less than 20 m2 or is a passage less than 5 m in length, the operator must ensure that there is at least one exit as described in that paragraph in that area.

Distancing — exits

(3) The operator must ensure that the exits referred to in paragraph (1)(a) are separated as far apart from each other as possible to increase the likelihood that at least one exit and its connected escape route will be passable during an accidental event.

Location of escape routes

(4) The operator must ensure that the installation has escape routes on two of its sides.

Safe evacuation

(5) The operator must ensure that all escape routes from an accommodations area or a temporary safe refuge to a muster area, embarkation station or evacuation point are clearly marked and illuminated and provided with fire protection to allow for the safe evacuation of persons in a time frame determined in the safety studies referred to in section 116.

Size of escape routes

(6) The operator must ensure that each escape route is of sufficient size to enable the efficient movement of the maximum number of persons who may need to use it, as well as unrestricted manoeuvring of firefighting equipment and stretchers, taking into account the maximum number of persons who can be accommodated on the installation.

Life-saving appliances for installation

119 (1) An operator must ensure that an installation is equipped with life-saving appliances that

Loads

(2) The operator must ensure that life-saving appliances can withstand all loads to which they may be subjected when they are in use.

Space requirements and weight

(3) The operator must ensure that, in determining the number of persons any lifeboat, life raft or marine evacuation system can accommodate, the persons’ space requirements and weight while wearing immersion suits are taken into account.

Arrangement and selection

(4) The operator must ensure that the arrangement and selection of life-saving appliances are based on

Position

(5) The operator must ensure that copies of a plan showing the position of all life-saving appliances are posted at the installation, including in the main control centre and in every accommodations area and work area.

Lifeboats — availability

(6) For the purpose of subsections (1) and (2), the operator must ensure, with respect to the lifeboats on an installation, that

Lifeboats — specifications

(7) The operator must ensure that the lifeboats are totally enclosed and are fire-protected.

Lifeboats — continuous communication

(8) The operator must ensure that each lifeboat is capable of being in continuous communication with each other lifeboat and with other vessels in the area.

Lifeboats — towing devices

(9) The operator must ensure that each lifeboat is equipped with towing devices.

Life rafts

(10) For the purpose of subsections (1) and (2), the operator must ensure that the life rafts on an installation have a combined capacity to accommodate the total number of persons on board the installation.

Continuous verification

(11) The operator must verify on a continual basis that the lifeboats, life rafts and other life-saving appliances are available and in a condition to perform as intended and must record the findings resulting from each verification.

Installation designed for removal

120 (1) An operator must ensure that an installation is designed to facilitate its removal from the offshore area at the end of its design service life and to reduce any risks to safety, adverse effects on the marine environment and interference with navigation and other uses of the sea that may occur during and after its removal.

Exception

(2) Subsection (1) does not apply if the Board has approved, in the development plan, the abandonment or an alternative use of the installation.

Transportation and positioning

121 (1) An operator must ensure that an installation, or any part of it, is transported and positioned

Risk assessment

(2) Before an installation, or any part of it, is transported and positioned, the operator must ensure that the following requirements are met:

Systems and Equipment: Design, Installation, Commission and Other Requirements

Electrical system

122 (1) An operator must ensure that any electrical system on an installation is designed to avoid any abnormal conditions and faults that may endanger the installation or, if it is not possible to avoid them, to provide alerts of those conditions and faults and mitigate their effects.

Safety and reliability

(2) The operator must ensure that all electric motors, lighting fixtures, electrical wiring and other electrical equipment on an installation are safe and reliable under all foreseeable operating conditions.

Device for monitoring insulation level to earth

(3) If a primary or secondary distribution system for electrical power, heating or lighting with no connection to earth is used on an installation, the operator must ensure that the system is equipped with a device that continuously monitors the insulation level to earth and produces an audible or visual alarm to indicate abnormally low insulation values.

Main electrical power supply

(4) The operator must ensure that the main electrical power supply on, or to, an installation

Primary circuit shutdown

(5) The operator must ensure that the primary circuits from a power plant serving an installation are capable of being shut down from at least two separate locations, one of which must be the site of the power plant.

Control system

123 (1) An operator must ensure that a control system is designed in accordance with the measures referred to in clauses 9(2)(b)(v)(D) and 10(2)(b)(v)(D) that are described in the operator’s safety plan and environmental protection plan, respectively.

Requirements

(2) The operator must ensure that the control system is designed to meet the following requirements, taking into account human factors:

Protection of hardware

(3) The operator must ensure that control system hardware is protected from circumstances, including excessive vibration, high electromagnetic field levels, electrical power disturbances and extreme temperatures or humidity levels or other physical and environmental conditions, that could cause mechanical damage to or degradation of the hardware or that could otherwise adversely affect the performance of the system.

Wireless remote control system

(4) The operator must ensure that any wireless remote control system includes

Alternative means of control

(5) The operator must ensure that all control system functions that are required to ensure safety and are dependent on wireless communication links have an alternative means of control that can be activated without delay and without modification to the control system.

Inspection and testing

(6) Equipment that is to be operated by a new, repaired or modified control system must not be put into operation until the operator ensures that the control system has been inspected and tested to confirm that it functions as intended.

Documentation

(7) The operator must ensure that documentation containing an up-to-date description of the design, installation, operation and maintenance of the control systems is readily accessible for consultation and examination.

Integrated software-dependent control system

124 (1) An operator must ensure that an integrated software-dependent control system whose failure or malfunction would cause a hazard to safety or the environment is maintained to ensure its reliability, availability and security.

Control measures

(2) The operator must ensure that control measures are implemented to protect the integrated software-dependent system from any threat, including unauthorized access.

Safety-critical software

125 (1) The operator must ensure that any software that is a safety-critical element is

Modification to features

(2) The operator must ensure that no modification to the features of the software is implemented unless

Emergency electrical power supply

126 (1) An operator must ensure that an installation has an emergency electrical power supply that is independent of the main electrical power supply such that the following systems and equipment continue to function in the event of a failure of the main electrical power supply:

Mechanically driven generator

(2) If the emergency electrical power supply is a mechanically driven generator, the operator must ensure that

Design and maintenance

(3) The operator must ensure that the emergency electrical power supply together with any transitional source of electrical power and self-contained battery system with which the installation may be equipped are designed and maintained such that

Protection from damage

(4) The operator must ensure that the emergency electrical power supply, transitional source of electrical power and self-contained battery system referred to in subsection (3) are arranged — or are otherwise protected from mechanical damage and damage caused by fire, explosion and physical and environmental conditions to which they may be exposed — so that they remain capable of fulfilling their intended functions under all foreseeable operating conditions, including, in the case of a floating platform, under the static and dynamic angles of inclination referred to in subsection 136(7).

Alert

(5) The operator must ensure that, in the event of a failure of the main electrical power supply, all control centres are alerted by means of an audible and visual signal that the installation is being powered by the emergency electrical power supply.

Lights and sound-signalling appliances

127 An operator must ensure that an installation is equipped with the lights and sound-signalling appliances that are required by the Collision Regulations as if that installation were a Canadian vessel to which those Regulations apply, unless compliance with the height and distance requirements of those Regulations is not possible, in which case the lights and appliances must be installed to maximize their audible and visual alerting capabilities for collision avoidance.

Radar

128 An operator must ensure that an installation other than an unattended installation is equipped with radar for identifying hazards in proximity to the installation and that the radar is continuously monitored.

Communication system

129 (1) An operator must ensure that an installation is equipped with a communication system that has built-in redundancy and is capable of communicating continuously, including in an emergency, with

Radiocommunication system

(2) An operator must ensure that an installation other than an unattended installation is equipped with a radiocommunication system in respect of which the following requirements are met:

Radiocommunication system — unattended installation

(3) An operator must ensure that any radiocommunication system on an unattended installation meets the requirements referred to in paragraphs (2)(a) and (b).

General alarm system

130 (1) An operator must ensure that an installation is equipped with a general alarm system that is capable of alerting persons on the installation of any hazards to safety or the environment other than fire or gas.

Additional requirements

(2) The operator must ensure that the general alarm system is

Alternative means of alert

(3) If a general alarm system is being inspected, maintained or repaired, the operator must ensure that there is an alternative means of alerting persons of the hazards referred to in subsection (1).

Gas release system

131 (1) An operator must ensure that an installation that includes process tanks, process vessels and piping is equipped with a gas release system that has a flaring system, a pressure relief system, a depressurizing system or a cold vent system.

Risk assessment — design

(2) The operator must ensure that the design of the gas release system is based on the results of the risk assessment conducted under subsection 107(1).

Design

(3) The operator must ensure that the gas release system is designed to

Location — system

(4) The operator must ensure that the gas release system is designed and located taking into account factors, including physical and environmental conditions, that affect the safe and normal flaring or emergency release of combustible liquid, gases or vapours so that when the system is in operation it does not damage the installation — or any other installation, vessel or support craft in proximity to it — or injure any person.

Control stations

(5) The operator must ensure that the control stations from which the gas release system is activated are located and spaced so that they remain protected and accessible for safe operation of the system.

Flaring systems

(6) The operator must, in respect of any flaring system, ensure that

Risk minimization — vents

(7) The operator must ensure that any vent that is used to release gas into the atmosphere without combustion is designed and located in accordance with the measures referred to in clause 9(2)(b)(vi)(A) and subparagraph 10(2)(b)(vi) that are described in the operator’s safety plan and environmental protection plan, respectively.

Liquid removal

(8) The operator must ensure that any liquid, other than water, that cannot be safely and reliably burned at the flare tip of a gas release system is removed from the gas before it enters the flare.

Fire and gas detection system

132 (1) An operator must ensure that an installation is equipped with a fire and gas detection system.

Requirements

(2) The operator must ensure that the fire and gas detection system

Risk assessment — design

(3) The operator must ensure that the design of the fire and gas detection system is based on the results of the risk assessment conducted under subsection 107(1).

Design

(4) The operator must ensure that the fire and gas detection system is designed

Requirements

(5) The operator must ensure that the fire and gas detection system meets the following requirements:

Testing and maintenance

(6) The operator must ensure, in relation to the testing and maintenance of the fire and gas detection system, that the following requirements are met:

Work permit

(7) A work permit is required for the testing and maintenance of the fire and gas detection system.

Management of override effects

(8) The work permit must set out measures to be taken to manage the effects of overriding the fire and gas detection system.

Leak repair

(9) The operator must ensure that any leak of gas that is detected by the fire and gas detection system or by means of an auditory, olfactory or visual method — including the observation of the dripping of hydrocarbon liquids from an equipment component — is repaired

Emergency shutdown system

133 (1) An operator must ensure that an installation has an emergency shutdown system that is capable of

Studies and assessments — design

(2) The operator must ensure that the design of the emergency shutdown system is based on studies, analyses and assessments that identify potential hazards and must assess the risks associated with those hazards, including the risk assessment conducted under subsection 107(1) and the risk and reliability analysis referred to in section 108.

Design

(3) The operator must ensure that the emergency shutdown system is designed to

Shutdown logic

(4) The operator must ensure that the logic for the emergency shutdown system includes a hierarchy of shutdown levels, action sequences and timelines that are appropriate for the degree of risk posed by the hazards identified in the studies, analyses and assessments referred to in subsection (2).

Additional requirements

(5) The operator must ensure, in relation to the emergency shutdown system, that

Testing and maintenance

(6) If the emergency shutdown system is capable of being overridden for the purposes of testing and maintenance activities, the operator must ensure that the following requirements are met:

Work permit

(7) A work permit is required for the testing and maintenance of the emergency shutdown system.

Management of override effects

(8) The work permit must set out the measures to be taken to manage the effects of overriding the emergency shutdown system.

Closure — subsurface safety valve

(9) In the case of a production installation, the operator must ensure that, if the emergency shutdown system is activated, any subsurface safety valve closes not later than two minutes after the tree safety valve has closed unless a longer delay is justified by the mechanical or production characteristics of the well.

Fire protection systems and equipment

134 (1) An operator must ensure that an installation is equipped with fire protection systems and equipment to control and extinguish fires.

Safety plan

(2) The operator must ensure that the fire protection systems and equipment are designed, selected, operated, inspected, tested and maintained in accordance with the measures referred to in clause 9(2)(b)(vi)(B) that are described in the operator’s safety plan.

Design and selection

(3) The design and selection of fire protection systems and equipment, including suppression agents, must take into account their intended use and the results of the risk assessment conducted under subsection 107(1).

Further requirements

(4) The operator must ensure that the fire protection systems and equipment include

Protection from damage

(5) The operator must ensure that the fire protection systems and equipment are protected from mechanical damage and damage caused by fire, explosion and physical and environmental conditions to which they may be exposed so that they remain capable of fulfilling their intended functions under all foreseeable operating conditions.

Fixed fire suppression system

(6) The operator must ensure that an automated fixed fire suppression system is installed in every accommodations area and hazardous area and in any other area that requires such a system based on the results of the risk assessment conducted under subsection 107(1).

Fire pumps

(7) The operator must ensure that at least two dedicated, segregated and independently driven fire pumps supply a dedicated firewater ring main and that each of those fire pumps is

Location

(8) The operator must ensure that the fire pumps are located as far as possible from equipment used for storing and processing petroleum, taking into account the results of the risk assessment conducted under subsection 107(1).

Supply of firewater

(9) The operator must ensure that the fire pumps and piping and their valves are capable of providing a sufficient supply of firewater to any area on the installation, including if a segment of the firewater ring main is damaged.

Firewater system

(10) The operator must ensure that the firewater system is capable of operating continuously for a minimum of 18 hours.

Fire hydrants and hose reels

(11) The operator must ensure that the number and location of fire hydrants and fire hose reels are such that at least two jets of water, not emanating from the same location, can reach any part of the installation where a fire may occur.

Portable fire-extinguishing equipment

(12) In areas where it is not practical to use fire hydrants and fire hose reels, the operator must ensure that portable fire-extinguishing equipment is readily available and accessible.

Alarms at main control centre

(13) The operator must ensure that audible and visual alarms will activate at the main control centre on the initiation of any of the automated fixed fire suppression systems or on the loss of any firewater pressure.

Additional alarms

(14) If the automated fixed fire suppression system creates a hazard to persons, the operator must ensure that audible and visual alarms automatically activate inside and outside the space that is being protected.

Unattended installations

(15) Paragraphs (4)(a) and (b) and subsections (6) to (11) do not apply in respect of unattended installations.

Boilers and pressure systems

135 (1) An operator must ensure that boilers and pressure systems are designed in accordance with the measures referred to in clause 9(2)(b)(vi)(C) that are described in the operator’s safety plan.

Design requirements

(2) The boilers and pressure systems must be designed to

Additional requirements

(3) The design of boilers and pressure systems must

Loads and other factors

(4) The operator must ensure that boilers and pressure systems can withstand all combinations of loads, pressures, temperatures, fluids and substances to which they may be subjected during their design service life.

Materials used

(5) The operator must ensure that the materials used for the manufacture of boilers and pressure systems are compatible with their operating environment and are chemically resistant to the fluids they contain during their design service life.

Manufacturer’s documents and records

(6) The operator must ensure that the following documents and records are obtained from the manufacturer of the boilers and pressure systems:

Construction, installation, commissioning, inspection and testing

(7) The operator must ensure, before a boiler or pressure system is put into operation, that it has been

Authorized inspector

(8) The operator must ensure that a boiler or pressure system is inspected by an authorized inspector and tested by or under the direction of an authorized inspector

Operating procedures

(9) The operator must ensure that operating procedures are developed for the boilers and pressure systems that inform users of operating hazards and indicate any special measures to be taken to reduce risks when the boilers and pressure systems are being used, maintained or repaired.

Conformity with procedures

(10) The operator must ensure that any boiler or pressure system is used, maintained and repaired in accordance with the operating procedures referred to in subsection (9).

Alteration of fitting

(11) It is prohibited for any person to alter, interfere with or render inoperative any boiler or pressure system fitting, except for the purpose of adjusting or testing the fitting.

Register

(12) The operator must keep a register of all boilers and pressure systems that includes the following documents and information in respect of each:

Marking

(13) The operator must ensure that a boiler or pressure system is marked with any information that is necessary for its safe installation and operation, including an identifier that permits reference to the documents and records referred to in subsection (6) and the information referred to in paragraphs (12)(e) and (f).

Verification

(14) The operator must ensure that all operating procedures developed in accordance with subsection (9) and the register referred to in subsection (12) are periodically verified by the certifying authority.

Non-application

(15) This section does not apply to any of the following:

Mechanical equipment

136 (1) An operator must ensure that any mechanical equipment on an installation

Design

(2) Mechanical equipment must be designed to eliminate hazards to safety or the environment in the following scenarios or, if that is not possible, to mitigate the risks posed by those hazards:

Controls and manual shut-off devices

(3) The operator must ensure that controls and manual shut-off devices for mechanical equipment are in a protected and readily accessible location that permits safe operation when an accidental event occurs that renders the equipment inaccessible.

Internal combustion engine — operating instructions

(4) The operator must ensure that the basic operating instructions for an internal combustion engine provide details of stop, start and emergency procedures and are permanently attached to the engine.

Turbines and internal combustion engines

(5) The operator must ensure that turbines and internal combustion engines are

Exception

(6) Despite paragraph (5)(c), turbines and internal combustion engines that are critical to emergency response, including emergency generators and fire pumps, need only be equipped with safety devices to prevent major damage from overspeeding.

Operation of critical mechanical equipment

(7) The operator must ensure that mechanical equipment that is critical to the safety or propulsion of a floating platform will continue to operate safely and reliably at its full rated power under the static and dynamic angles of inclination that are specified in the rules of the classification society that issued the certificate of class required under section 140.

Materials handling equipment

137 (1) An operator must ensure that all materials handling equipment is

Marking

(2) The operator must ensure that all materials handling equipment is marked with its rated capacity and in a manner that identifies its manufacturer and model and that permits reference to any information that is necessary to its safe operation, including information regarding its design, construction, inspection, testing, maintenance and repair.

Inspection and proof test

(3) The operator must ensure that materials handling equipment that is to be used on an installation is inspected and proof-tested by a competent third party in the following situations to determine the equipment’s rated capacity:

Criteria for inspection and testing

(4) The operator must ensure that the inspection and proof-testing is done in accordance with criteria established by the manufacturer or applicable industry design and safety standards, including with respect to the frequency at which the equipment must be inspected and proof-tested to ensure its continued safe operation.

Rated capacity

(5) Following the inspection and proof test, the competent third party must certify in writing the rated capacity of the materials handling equipment and must indicate in writing any limitations that must be imposed on its use having regard to physical and environmental conditions.

Emergency slewing and lowering

(6) The operator must ensure that a crane with slewing capability is capable of retaining its slewing and lowering capability in emergency situations.

Pedestal crane

(7) The operator must ensure that a pedestal crane meets the following requirements:

Crane hooks

(8) The operator must ensure that all crane hooks are equipped with spring-loaded latches or other equally effective means of preventing the load from falling off the hook under any operating conditions.

Landing or take-off

(9) When an aircraft is landing on or taking off from a landing area, it is prohibited to move a crane in the vicinity of the landing area and, if feasible, the person operating the crane must ensure that the crane’s boom is stowed.

Lifting device certification

(10) The operator must ensure that any materials handling equipment that lifts over 10 tonnes is certified by the certifying authority.

Subsea production system

138 (1) An operator must ensure that a subsea production system is designed, constructed, installed, commissioned, operated, inspected, monitored, tested and maintained in accordance with the measures referred to in clauses 9(2)(b)(v)(F) and 10(2)(b)(v)(F) that are described in the operator’s safety plan and environmental protection plan, respectively.

Design

(2) A subsea production system must be designed so that

Disconnectable riser

(3) The operator must ensure that a riser that is connected to a floating platform that has a disconnectable mooring system or dynamic positioning system is designed to be capable of safely detaching in any foreseeable physical and environmental conditions.

Riser disconnect

(4) The operator must ensure that, if risers are designed to disconnect in order to avoid foreseeable hazards, riser fluids may be safely displaced by water or isolated.

Riser integrity

(5) The operator must ensure that, if a riser is disconnected, its integrity is demonstrated through testing once it is reconnected and before it is brought back into service.

Control of subsea production system

(6) The operator must ensure that a subsea production system is controlled from only one location at any given time.

Failure modes and effects analysis

(7) The operator must ensure that any subsea production system is assessed through a failure modes and effects analysis.

Temporary or portable equipment

139 (1) An operator must ensure that any temporary or portable equipment used on an installation is fit for the purposes for which it is to be used.

Assessment of temporary or portable equipment

(2) Before any temporary or portable equipment is installed or brought into service on an installation, the operator must ensure that the equipment and its integration with other equipment and systems are assessed to determine their impact on safety-critical elements and on the risk assessment referred to in subsection 24(3).

Measures

(3) The operator must ensure that temporary or portable equipment is managed in accordance with the measures referred to in clauses 9(2)(b)(v)(G) and 10(2)(b)(v)(G) that are described in the operator’s safety plan and environmental protection plan, respectively, and in a manner that does not compromise the target levels of safety set out in those plans.

Verification by certifying authority

(4) The operator must ensure that temporary or portable equipment that is a safety-critical element is, before being put into operation, verified by the certifying authority to confirm its suitability and safe placement and hook-up.

Additional Requirements for Platforms

Classification

140 An operator must ensure that a floating platform holds a valid certificate of class issued by a classification society that corresponds to the authorized work or activity to be carried out from the floating platform.

Air gap

141 An operator must ensure that a platform that is either founded on the seabed or column-stabilized has a sufficient air gap to operate safely under the maximum environmental load conditions to which it may be subjected.

Stability

142 (1) An operator must ensure that a floating platform, whether intact or in a damaged condition, is stable and can be operated safely, having regard to all motions and loads to which it may be subjected, including by

Freeboard

(2) The operator must ensure that a floating platform has sufficient freeboard to operate safely under the maximum environmental load conditions to which it may be subjected.

Requirement — Codes

(3) The operator must comply with the applicable provisions of the MODU Code and Part B of the IS Code concerning the stability and motion response of a floating platform, which are to be read as mandatory.

Deadweight survey

(4) If the weight of a floating platform or a self-elevating mobile offshore platform changes by more than 1% of the lightship weight, the operator must ensure that a deadweight survey is carried out at the earliest opportunity and an up-to-date value of the lightship centre of gravity is calculated.

Self-elevating mobile offshore platform

143 (1) An operator must, in relation to a self-elevating mobile offshore platform, ensure that a site-specific assessment is conducted of the condition of the seabed, including seabed restraint, to ensure that the platform is stable and can be operated safely.

Requirements

(2) The operator must ensure that a self-elevating mobile offshore platform meets the following requirements:

Suspension of operations and well shut-in

(3) The operator must ensure that the works and activities on a self-elevating mobile offshore platform are suspended and that all wells associated with the platform are brought to a safe shut-in condition if

Corrective measures

(4) In the case of any of the situations referred to in subsection (3), the operator must ensure that the works and activities on the self-elevating mobile offshore platform remain suspended and that all wells associated with the platform remain in a safe shut-in condition until the cause of the situation has been investigated and corrective measures have been taken.

Ballast and bilge systems

144 (1) An operator must ensure that a floating platform is equipped with reliable ballast and bilge systems with the necessary redundancy in their components to

Requirement — Code

(2) The operator must comply with the applicable provisions of the MODU Code concerning ballast and bilge systems, which are to be read as mandatory.

Secondary ballast control station

(3) In the case of a column-stabilized mobile offshore platform, the operator must ensure that it is equipped with a secondary ballast control station that is equipped with

Location — secondary ballast control station

(4) The operator must ensure that a secondary ballast control station is located above the waterline in the final condition of equilibrium after flooding if the floating platform is in a damaged condition.

Failure modes and effects analysis

(5) The operator must ensure that the ballast and bilge systems are assessed through a failure modes and effects analysis before any authorized work or activity is carried out from the floating platform.

Watertight and weathertight integrity and freeboard

145 (1) The operator must comply with the applicable provisions of the MODU Code and Part B of the IS Code concerning watertight and weathertight integrity and freeboard, which are to be read as mandatory.

Watertight subdivision

(2) The operator must ensure that the floating platform is designed with sufficient watertight subdivision to ensure the preservation of reserve buoyancy and damage stability under all foreseeable conditions.

Load line certificate

(3) The operator must ensure that a floating platform

Watertight and weathertight appliances

(4) The operator must ensure that the arrangement and specification of watertight and weathertight appliances complies with the measures referred to in clause 9(2)(b)(v)(H) that are described in the operator’s safety plan.

Water ingress

(5) The operator must ensure that a floating platform is designed with systems and equipment that provide for the operation, monitoring and indication — both locally and at the ballast control stations — of the opening and closing of watertight doors and hatches and for the detection and provision of alerts of any water ingress into watertight spaces that are not designed to accumulate liquid.

Port lights

(6) The operator must ensure that the columns of a column-stabilized mobile offshore platform do not have port lights or similar openings.

Station-keeping

146 An operator must ensure that a floating platform is equipped with a mooring system or a dynamic positioning system to ensure station-keeping of the platform within its operating limits.

Mooring system

147 (1) An operator must ensure that a mooring system with which a floating platform is equipped is designed, on the basis of analysis and model testing, to ensure

Excursion limits

(2) The operator must ensure that the excursion limits of a floating platform that is equipped with a mooring system are established on the basis of the analysis and model testing referred to in subsection (1).

Loss of station-keeping or failure

(3) The operator must ensure that the floating platform has systems and processes to continuously detect loss of station-keeping or the failure of any mooring system component.

Monitoring

(4) The operator must ensure that mooring line tensions or other indicators of the integrity of the mooring system are monitored and kept within the mooring system’s operating limits.

Measures

(5) The operator must ensure that measures to ensure that the mooring system continues to perform in accordance with its design specifications are implemented, including

Disconnectable mooring system

148 (1) If the mooring system with which a floating platform is equipped is disconnectable, the operator must ensure that the system is designed to ensure that disconnection can be accomplished in a controlled manner without creating a risk of drift-off.

Safety plan

(2) The operator must ensure that the disconnectable mooring system is designed and maintained in accordance with the measures referred to in clause 9(2)(b)(vi)(D) that are described in the operator’s safety plan.

Primary and backup systems

(3) The operator must ensure that the disconnectable mooring system includes a primary system and a backup system for disconnection, both of which can be operated locally or from a remote location.

Floating platform capability

(4) The operator must ensure that a floating platform that is equipped with a disconnectable mooring system is capable of

Criteria and procedures for disconnection

(5) The operator must ensure that criteria and procedures for disconnection are developed for all credible disconnection scenarios, including procedures for monitoring environmental conditions and providing alerts for worsening conditions that may require disconnection.

Disconnection and reconnection

(6) The operator must ensure that the disconnectable mooring system

Periodic verification of disconnection capability

(7) The operator must periodically verify the disconnect capability of the disconnectable mooring system and must record the findings resulting from the verification.

Excursion limits exceeded

(8) The operator must ensure that the emergency disconnection referred to in paragraph (6)(b) is initiated if the floating platform exceeds the excursion limits established under subsection 147(2).

Dynamic positioning system

149 (1) An operator must ensure that the design of a dynamic positioning system with which a floating platform is equipped

Excursion limits

(2) The operator must ensure that the excursion limits of a floating platform that is equipped with a dynamic positioning system are established based on the numerical analysis and model testing referred to in paragraph (1)(a).

Disconnect system

150 (1) An operator must ensure that a floating platform that is equipped with a dynamic positioning system has a disconnect system that

Demonstration

(2) The operator must periodically demonstrate by means of a trial or performance test that the disconnect system meets the requirements under subsection (1).

Excursion limits exceeded

(3) The operator must ensure that the emergency disconnection referred to in paragraph (1)(b) is initiated if the floating platform exceeds the excursion limits established under subsection 149(2).

Decisions and exemptions

151 For any floating platform that is registered outside Canada, the operator must

Gap analysis

152 The operator must, every time the MODU Code is updated,

Asset Integrity

Requirements

153 An operator must ensure that all installations, including their systems and equipment, are inspected, monitored, tested, maintained and operated to

Non-destructive examination

154 An operator must ensure that a non-destructive examination of the critical joints and structural parts of an installation is conducted at least once every five years or more often as required to ensure the continued safe operation of the installation.

Corrosion management

155 (1) An operator must ensure that if a safety or environmental hazard would result from the failure due to corrosion — including corrosion from exposure to a sour environment — of any equipment, including process vessels, or of any piping, valves, fittings and structural elements that are part of an installation, that corrosion is prevented and managed throughout the life cycle of the installation.

Corrosion management program

(2) The operator must develop a corrosion management program that sets out the measures that are necessary to prevent critical failures resulting from corrosion-related degradation and to ensure the continued integrity of safety-critical elements.

Program requirements

(3) The program must

Program implementation and update

(4) The operator must ensure that the program is implemented and periodically updated, taking into account the data and analysis referred to in paragraph (3)(e).

Operation and Maintenance

Limits and requirements

156 An operator must operate an installation, including its systems and equipment, in accordance with any limitations that are set out in the certificate of fitness under subsection 28(3), with any requirements under this Part and with the operations manual referred to in section 157.

Operations manual

157 (1) An operator must develop an operations manual in respect of each installation that sets out or incorporates by reference the following documents and information:

Additional information — floating platform

(2) In the case of a floating platform, the operations manual must also contain

Additional information — mobile offshore platform

(3) In the case of a self-elevating mobile offshore platform, the operations manual must also contain

Up-to-date

(4) The operator must ensure that the operations manual is kept up-to-date.

Programs

158 (1) An operator must develop the following programs to ensure the continued integrity of an installation, including its systems and equipment, from the time the installation is commissioned until it is abandoned or removed from the offshore area:

Program implementation and update

(2) The operator must ensure that the programs are implemented and periodically updated.

Maintenance program

159 (1) The maintenance program must set out the inspection, monitoring, testing and maintenance policies and procedures for the installation, including its systems and equipment, that are necessary to ensure safety, protect the environment and prevent waste.

Requirements

(2) The maintenance program must

Preservation program

160 (1) The preservation program must set out the measures that are necessary to ensure the integrity of equipment that is taken out of service and stored for future use.

Periodic inspection

(2) The program must provide for the periodic inspection of the stored equipment to verify its integrity and ensure that it is fit for the purposes for which it is to be used if it is brought into service.

Weight control program

161 The weight control program must set out the measures that are necessary to ensure that the weight and centre of gravity of each installation are kept safely within the installation’s operating limits.

Safety-critical element — repair, replacement or modification

162 (1) The holder of a certificate of fitness must ensure that the certifying authority and the Chief Safety Officer are notified before a safety-critical element is repaired, replaced or modified and before any equipment that would change the design, performance or integrity of a safety-critical element is brought on board the installation.

Approval before repair or modification

(2) The holder of a certificate of fitness must ensure that the approval of the certifying authority is obtained before a safety-critical element is repaired or modified.

Verification

(3) The holder of a certificate of fitness must ensure that a safety-critical element that has been repaired or modified is not put into operation until the certifying authority has verified it and

Emergency repair or modification

(4) In an emergency, subsections (2) and (3) do not apply if the installation manager considers that the delay required to comply with the requirements under those subsections endangers persons on the installation or the environment.

Verification after emergency

(5) A safety-critical element that is repaired or modified in an emergency must be verified by the certifying authority in accordance with subsection (3) as soon as the circumstances permit.

Non-application

(6) This section does not apply in the case of an adjustment made to or the testing of a boiler or pressure system fitting.

Wells

Drilling fluid systems

163 An operator must ensure that

Drilling riser

164 (1) An operator must ensure that every drilling riser is, throughout the duration of a well operation, capable of

Drilling riser support

(2) The operator must ensure that every drilling riser is supported in a manner that effectively compensates for any loads caused by the motion of the installation, the drilling fluid or the water column.

Drilling riser analysis

(3) The operator must ensure that a drilling riser analysis and, in the case of a floating platform that uses a dynamic positioning system, a weak-point analysis of the drilling riser are conducted and that the certifying authority in relation to the installation approves those analyses.

Fail-safe subsurface safety valves

165 (1) An operator must ensure that a completed development well is equipped with a fail-safe subsurface safety valve that

Additional valve

(2) The operator must ensure that a completed development well on a fixed platform that has gas-lift, injection or production capabilities in the A-annulus is equipped with an additional fail-safe safety valve on the A-annulus.

Requirements

(3) The operator must ensure that all fail-safe safety valves are designed, installed, tested, maintained and operated to prevent uncontrolled well flow when they are activated.

Well tubulars, trees and wellheads

166 (1) An operator must ensure that well tubulars, trees and wellheads are operated in accordance with good engineering practices.

Sour environment

(2) The operator must ensure that any well tubulars, trees or wellheads that may be exposed to a sour environment are capable of operating safely in that environment.

Safe and efficient operation

(3) The operator must ensure that the wellhead and tree equipment, including any valves, are designed and maintained to operate safely and efficiently throughout the life cycle of the well under all loads to which the well may be subjected.

Formation flow test equipment

167 (1) An operator must ensure that the equipment used in a formation flow test is designed to safely control well pressure, evaluate the formation and prevent pollution.

Rated working pressure

(2) The operator must ensure that the rated working pressure of formation flow test equipment at and upstream of the well testing manifold exceeds the maximum anticipated shut-in pressure.

Overpressure

(3) The operator must ensure that all equipment downstream of the well testing manifold is protected against overpressure.

Downhole safety valve — development well

(4) The operator must ensure, in the case of a development well, that the formation flow test equipment includes a downhole safety valve that permits closure of the test string above the packer.

Downhole safety valve — exploratory or delineation well

(5) The operator must ensure, in the case of an exploratory well or a delineation well drilled on a geological feature, that a downhole safety valve is installed before a formation flow test is conducted unless

Subsea test tree

(6) The operator must ensure that any formation flow test equipment used in testing a well that is drilled with a floating drilling unit has a subsea test tree that is equipped with

Pipelines

Pipeline integrity — standard

168 (1) An operator must ensure that a pipeline is designed, constructed, installed, operated and maintained in accordance with CSA Group standard Z662, Oil and gas pipeline systems, as it relates to offshore pipelines.

Integrity management program

(2) The operator must ensure that the pipeline system integrity management program required by that standard is implemented and periodically updated.

Monitoring of Installations, Wells and Pipelines

Monitoring of systems

169 (1) An operator must ensure that an installation is equipped with a central monitoring system in the main control centre to monitor all systems whose failure could cause or contribute to an accidental event or waste.

Management of associated systems

(2) The operator must ensure that the alarm, safety, monitoring, warning and control functions associated with the systems that are monitored under subsection (1) are managed to prevent reportable incidents and waste.

Suspension of related system

(3) When a function referred to in subsection (2) is suspended or found to be impaired, the operator must ensure that the use of any related system is also suspended until

Affected persons informed

(4) The operator must ensure that all affected persons are informed when a function referred to in subsection (2) is suspended and when it is returned to service.

Deterioration

170 (1) An operator must, without delay, notify the Chief Safety Officer of any deterioration of an installation, including its systems or equipment, or of a pipeline, well, vessel or support craft if that deterioration could adversely affect safety or the environment.

Notice to certifying authority

(2) If an installation, system, equipment, pipeline or part of a well referred to in subsection (1) is within the scope of work referred to in section 31, the operator must also, without delay, notify the certifying authority of the deterioration.

Impairment rectification

(3) The operator must ensure that any impairment of an installation, including its systems or equipment, or of a pipeline, well, vessel or support craft is rectified without delay if the impairment could adversely affect safety or the environment.

Mitigation measures

(4) If it is not possible to rectify the impairment without delay, the operator must

Non-application

(5) Subsections (3) and (4) do not apply in respect of safety-critical elements.

PART 11
Support Operations

Support craft

171 (1) An operator must, in respect of an installation on which persons are normally present, ensure that

Requirements

(2) The support craft referred to in subsection (1) must be

Required distance exceeded

(3) If the support craft is located at a distance that exceeds the distance referred to in paragraph (1)(a), both the installation manager and the person in charge of the support craft must log that fact and the reason why the distance or time was exceeded.

Vessel master

(4) During any activity or situation referred to in paragraph (1)(b), or any other activity or situation that presents an increased level of risk to the safety of the installation, the vessel master must, under the direction of the installation manager, keep the craft in close proximity to the installation, maintain open communication channels with the installation and be prepared to conduct rescue operations.

Rescue boat — vessel

172 An operator must, in respect of any vessel that is used in a geoscientific program, geotechnical program, environmental program, diving project or construction activity, ensure that a rescue boat is available and ready for use in the event of an emergency.

Safety zone

173 (1) A support craft must not enter the safety zone around an installation or around a vessel that is engaged in a geoscientific program, geotechnical program, environmental program or diving project without the consent of the installation manager or the person in charge of the operations site.

Notice to approaching aircraft or vessel

(2) The operator must ensure that persons who are in charge of an aircraft or vessel that is approaching the safety zone are notified of the safety zone boundaries and of any hazards within that zone that relate to the operator’s installation or vessel.

Boundaries — installation

(3) The safety zone around an installation consists of the area within a line that encloses the installation and is drawn at a distance of 500 m from the outer edge of the installation or, if any component of the installation extends beyond that edge, from the outer limit of the component that extends furthest from that edge.

Boundaries — vessel

(4) The safety zone around a vessel referred to in subsection (1) consists of the area within a line that encloses the vessel and any of its attached equipment and is drawn at a distance that minimizes risks to safety, the environment and property located nearby, including fishing gear or fishing vessels.

Landing area

174 (1) An operator must ensure that the aircraft landing area on an installation or vessel and the equipment that is used in that area or that otherwise supports the take-off or landing of aircraft are designed to ensure safety and the protection of the environment and to prevent incidents or damage resulting from the use of aircraft.

Requirements

(2) The operator must ensure that the landing area

Fuel storage tanks

(3) The operator must ensure that any fuel storage tanks that are in proximity to a landing area are stored safely and protected from damage, impact and fire.

Procedures

175 The operator must ensure the establishment of procedures associated with the support of aircraft operations, including procedures for emergency response, and of a training program for personnel for those purposes.

Aircraft service provider

176 An operator must ensure that, before the start of any operations that require the use of an aircraft, the aircraft service provider has accepted in writing all conditions with respect to the use of the equipment in any landing area, the procedures associated with the support of aircraft operations, including the procedures for emergency response, and the training program for personnel in respect of those matters.

Classification

177 An operator must ensure that any support or construction vessel to be used in conjunction with an installation holds a valid certificate of class issued by a classification society according to the work or activity to be carried out by it.

PART 12
Notice, Records, Reports and Other Information for Authorized Works and Activities

General

Definition of shotpoint

178 In this Part, shotpoint means the surface location of a seismic energy source.

Reportable incidents

179 (1) An operator must notify the Board of a reportable incident as soon as the circumstances permit, but not later than 24 hours after becoming aware of the incident.

Investigation

(2) The operator must ensure that

Accessibility of records

180 An operator must ensure that any records that are necessary to support operational requirements and the requirements of these Regulations are readily accessible to the Board for examination.

Critical information

181 (1) An operator must ensure that records are kept of all information — including the following — that is critical to safety, the protection of the environment or the prevention of waste:

Retention periods

(2) The operator must retain the records referred to in subsection (1) for the following periods:

Safety report

182 (1) An operator must ensure that a safety report that relates to an authorized work or activity conducted in a given calendar year is submitted to the Board within 90 days after the day on which the work or activity is concluded or suspended or, in the case of a work or activity that will continue into the following calendar year, that a safety report that relates to the work or activity conducted in the preceding calendar year is submitted to the Board not later than March 31 of that following calendar year.

Requirements

(2) The safety report must contain

Annual reports

183 An operator must ensure that the Board is made aware, at least once a year, of any report containing relevant information regarding applied research work or studies that the operator has participated in, funded or commissioned concerning the operator’s authorized works and activities in relation to safety, the protection of the environment or resource management and must ensure that a copy of the report is submitted to the Board on request.

Geoscientific, Geotechnical and Environmental Programs

Notice — key dates

184 When any geoscientific program, geotechnical program or environmental program is commenced, concluded, suspended or cancelled by an operator, the operator must, without delay, notify the Board in writing of the date of the commencement, conclusion, suspension or cancellation of the program.

Weekly status reports

185 (1) An operator must ensure that weekly reports are submitted to the Board on the status of field work carried out in relation to any geoscientific program, geotechnical program or environmental program from the commencement of the program until its conclusion, suspension or cancellation.

Content of reports

(2) The weekly status reports must contain the following documents and information:

Environmental report — programs

186 An operator must ensure that an environmental report that contains the following documents and information is submitted to the Board within 90 days after the day on which a geoscientific program, geotechnical program or environmental program is concluded or suspended:

Final reports

187 (1) An operator must ensure that a final operations report, final data processing report and final interpretation report are submitted to the Board with the acquired data referred to in subsection (5), as applicable, within 12 months after the day on which any geoscientific program, geotechnical program or environmental program is concluded, unless a longer period has been agreed to in writing by the Board.

Content of final operations report

(2) The final operations report must contain the following documents and information:

Content of final data processing report

(3) The final data processing report must contain the following documents and information:

Content of final interpretation report

(4) The final interpretation report must contain the following documents and information, as applicable:

Acquired data

(5) The following acquired data must accompany the final reports, as applicable:

Incorporation of previous data

(6) The operator must incorporate into any map referred to in paragraph (4)(b) that is included in a final interpretation report any data previously collected by the operator that are related to the area covered by the map and that are of a type similar to the data from which the map was produced.

Exception — data made available to public

188 (1) An operator that has conducted a geoscientific program, a geotechnical program or an environmental program need not submit a final interpretation report if the data acquired from the program are made available to the public for purchase or for use under licence.

Data no longer available

(2) If the operator ceases to make data available for purchase or use under licence, the operator must ensure that, within 12 months after the day on which the operator ceased to make the data available, the final interpretation report is submitted to the Board.

Data purchases

189 (1) A purchaser of data referred to in subsection 188(1) that were acquired in an area that is subject to an interest, as defined in section 47 of the Act, must submit to the Board a final interpretation report that contains the documents and information referred to in subsection 187(4), as applicable, if the costs of the purchase of the data are to be credited against a deposit or other costs in relation to the interest.

Reports from data purchaser

(2) If the purchaser has reprocessed or reinterpreted the data, and if the costs of the reprocessing or reinterpretation are to be credited against a deposit or other costs of the interest, the purchaser must submit to the Board, with the acquired data referred to in subsection 187(5), as applicable, a final data processing report that contains the documents and information referred to in subsection 187(3) and a final interpretation report that contains the documents and information referred to in subsection 187(4), as applicable.

Timing of submissions

(3) The reports and data required under subsections (1) and (2) must be submitted by the purchaser to the Board before the costs referred to in those subsections are credited.

Notice to Chief Conservation Officer

(4) A person who has submitted a report referred to in this section must, in respect of data that pertain to shotpoints or the location of stations, notify the Chief Conservation Officer, without delay, of any errors or omissions identified in or corrections made to the data after the report is submitted.

Drilling and Production

Reference

190 When submitting any information to the Board about a well, pool, zone or field under these Regulations, an operator must refer to each by the name given to it under section 59 or paragraph 60(b), as the case may be.

Results, data, analyses and schematics

191 (1) An operator must ensure that a copy of the final results, data, analyses and schematics obtained from any well operation, including those obtained as a result of the following activities, is submitted to the Board:

Period for submission

(2) Unless otherwise agreed to in writing by the Board, the operator must ensure that the copy is submitted within 60 days after the day on which the activity that gave rise to the results, data, analyses or schematics is concluded.

Survey

192 (1) An operator must ensure that a survey, certified by a person licensed under the Canada Lands Surveyors Act, is conducted to confirm the location of any well and production installation.

Copy of survey plan

(2) The operator must ensure that a copy of the survey plan is

Critical information

193 (1) The records that must be kept under section 181 include, in the case of an operation involving drilling or production, records containing the following information and documents:

Retention periods

(2) The operator must retain the records referred to in subsection (1) for the following periods:

Daily production record

194 (1) An operator must ensure that a daily production record is kept in respect of a field in which a pool or well is located until the field is abandoned and, at that time, must offer to submit the record to the Board before destroying it.

Contents

(2) The daily production record must contain, with respect to each day, the following information and documents:

Formation flow test records and report

195 An operator must ensure that

Pilot scheme

196 (1) An operator must ensure that interim evaluations of a pilot scheme referred to in section 81 are reported to the Board in writing at the intervals referred to in paragraph 81(2)(b).

Report on completion

(2) On completion of the pilot scheme, the operator must ensure that a report is submitted to the Board that contains

Daily reports

197 An operator must ensure that the following reports are submitted to the Board on a daily basis:

Monthly production report

198 An operator must ensure that a report summarizing the production data collected during a given month is submitted to the Board not later than the 15th day of the subsequent month.

Well records and reports

199 (1) An operator must ensure that

Well termination record — contents

(2) The record required under paragraph (1)(a) must describe the manner in which the well has been abandoned, suspended, completed or recompleted and must include a schematic of the well illustrating the nature and location of the plugs used to abandon or suspend the well or the equipment used to complete or recomplete the well.

Reports — contents

(3) The reports required under paragraphs (1)(b) to (d) must contain a record of all operational, engineering, petrophysical, geophysical and geological information that is relevant to the well operation, including any problems encountered during the well operation and the results of any formation leak-off test or formation integrity test conducted under section 70.

Impact description

(4) The report required under paragraph (1)(b) must describe any impact of the workover or intervention on the performance of the well, including any effect on productivity, injectivity and the recovery of petroleum.

Environmental report — drilling

200 An operator must ensure, in relation to a drilling program that involves an exploratory well or a delineation well, that an environmental report that contains the following documents and information is submitted to the Board within 90 days after the day referred to in subparagraph 199(1)(a)(i), (ii) or (iii), as the case may be:

Annual environmental report — production and pipeline

201 An operator must ensure, in relation to a production project or pipeline project, that an environmental report that contains the following documents and information with respect to a given calendar year is submitted to the Board not later than March 31 of the subsequent year:

Annual production report

202 An operator must ensure that, not later than March 31 of each year, an annual production report for a pool, field or zone is submitted to the Board that contains information on how the operator manages and intends to manage the resource being produced without waste, including

Gas venting records

203 An operator must ensure that a record is kept of the following information in respect of each gas venting referred to in paragraph 82(c):

Compressor records

204 An operator must ensure that a record containing the following documents and information is kept in respect of the compressors referred to in subsection 84(1):

Fugitive emission records

205 An operator must ensure that a record containing the following information is kept in respect of any fugitive emission from an installation that is detected:

Record retention period

206 An operator must ensure that a record referred to in any of sections 203 to 205 is retained for five years after the day on which the record is created.

Diving Projects or Construction Activities

Weekly status reports

207 (1) An operator must ensure that weekly reports are submitted to the Board on the status of any diving project or construction activities.

Content of reports

(2) The weekly status reports must contain the following documents and information:

PART 13
Repeals and Coming into Force

Repeals

208 The following Regulations are repealed:

Coming into Force

Eight months after publication

209 These Regulations come into force on the day that, in the eighth month after the month in which they are published in the Canada Gazette, Part II, has the same calendar number as the day on which they are published or, if that eighth month has no day with that number, the last day of that eighth month.

SCHEDULE 1

(Clauses 28(1)(b)(ii)(A) and (B) and (iii)(B))

Certificate of Fitness

PART 1
Provisions of these Regulations

PART 2
Provisions of the Canada–Newfoundland and Labrador Offshore Area Occupational Health and Safety Regulations

SCHEDULE 2

(Subparagraph 31(3)(b)(iii))

Verification of Certificate of Fitness Requirements

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the regulations.)

Executive summary

Issues: The nine offshore area petroleum operations regulations that governed petroleum activities in the Canada-Newfoundland and Labrador (Canada-NL) and Canada-Nova Scotia (Canada-NS) offshore areas had not been wholly updated in more than 35 years. Those regulations contained many provisions that used prescriptive language, required the use of outdated technologies and/or methodologies, and incorporated by reference a number of obsolete standards and codes. The overly prescriptive nature and lack of inherent flexibility negatively affected the efficiency and effectiveness of the regulatory framework.

Fraught with provisions that no longer adequately addressed some hazards, lack of regulatory clarity, and irrelevantly prescribed controls, Canada’s offshore petroleum regulatory framework for operations was gaining a reputation of being ineffective and was putting the competitiveness of Canada’s offshore petroleum sector at risk.

Description: The new Canada-NL and Canada-NS Offshore Area Petroleum Operations Framework Regulations (jointly referred to as the Regulations) repeal nine offshore area petroleum operations regulations and replace them with one “framework” regulation in each of the Canada-NL and Canada-NS offshore areas. The Regulations will complement the regulations brought into force in 2022 pertaining to the occupational health and safety of the two offshore areas. Comprised of thirteen parts, the Regulations address the key aspects of offshore petroleum activities, from general authorizations and approvals, to decommissioning and abandonment, including technical requirements related to drilling, production, geophysical and geotechnical, and diving activities.

The Regulations establish modern requirements related to safety, environmental protection and resource management that align with the other offshore area legislation, and domestic and international industry codes and standards. They also codify industry best practices and critical mitigations that were imposed by the offshore regulators through other regulatory instruments.

The Regulations have a more technology-neutral approach that provides controlled avenues for operators to use the most advanced technologies and/or methodologies, ensuring innovative approaches that enhance safety can be used in the offshore.

Parts 2 to 5 of Schedule 1 to the Canada–Newfoundland and Labrador Offshore Petroleum Administrative Monetary Penalties Regulations and the Canada-Nova Scotia Offshore Petroleum Administrative Monetary Penalties Regulations (AMPs Regulations) will be replaced as part of this regulatory package. The AMPs Regulations provide the offshore regulators with a tool to supplement their existing compliance and enforcement regime. They are designed to promote compliance with legislative and regulatory requirements. The existing schedules point to regulatory requirements from the nine offshore area petroleum regulations that will be repealed. This consequential amendment ensures that the schedules refer to the appropriate regulatory requirements in the Framework Regulations.

Rationale: The Regulations create a modern suite of technical regulations that optimize operational safety, environmental protection, and resource management. They maintain the regulator’s ability to enforce requirements for safety and environmental protection, and facilitate the prosecution of regulated parties for violations.

The development and design of the Regulations represent the culmination of a multi-year regulatory development process between Natural Resources Canada, Environment and Climate Change Canada, the Governments of Newfoundland and Labrador and Nova Scotia, and the two offshore regulators. The Regulations were subject to a comprehensive engagement and consultation process; stakeholders were provided with multiple opportunities to provide input throughout the various phases of the regulatory development process.

The quantified impacts of the Regulations will result in a net present benefit of $6.56 million between 2024 and 2033 (discounted to 2023 using a rate of 7%). The total present value of the quantified benefits is $7.43 million, while the total present value of costs is $0.86 million.

The Governments of Newfoundland and Labrador and Nova Scotia are committed to each establishing provincial regulations that will mirror the Regulations and respect the joint management regime for each offshore area. The entrance into force date is eight months following the Regulations’ date of publication in the Canada Gazette, Part II, to ensure that the federal and provincial versions of the regulations enter into force simultaneously, and to ensure sufficient time for operators and regulators to prepare for implementation.

Issues

The bulk of the nine original regulations governing offshore petroleum activities in the Canada-NL and Canada-NS offshore areas developed in the late-1980s and early-1990s are outdated. With advancements in technologies, industry best practices, and many lessons learned from incidents worldwide, those regulations have been seen as a barrier to continuous improvement with their use of prescriptive language, outdated technologies and/or methodologies, and obsolete standards and codes incorporated by reference.

Without revised regulations, offshore regulators would be required to continue to enforce outdated regulatory requirements, requiring operators to undertake expensive modifications to installations, and to use equipment and methods that are in many cases technologically inferior. Without revised regulations, the respective offshore regulator would continue to be unnecessarily inundated with administrative submissions for approval to deviate from regulations (known as regulatory queries or “RQs”) at the beginning of an operation, and again through the various stages of activities. Given the costly nature of most required modifications, and considering other measures or alternate approaches equal or superior in effect, industry frequently pursues RQs. These are costly and administratively burdensome in nature for both the regulated parties and the regulators, which must review and approve or reject each query.

Without a consolidated regulation, the offshore regulators and industry stakeholders would be obliged to comply with several administrative requirements that are duplications between the existing regulations. Discrepancies between the French and English versions, and conflicting terms with the enabling statute, also present uncertainty for the regulated parties and legal challenges when prosecuting. This reduces the effectiveness of the regulatory regime and makes Canada’s offshore petroleum sector less attractive for investment.

Background

Joint management regime

The offshore areas of Newfoundland and Labrador (NL) and Nova Scotia (NS) are unique in that they are jointly managed by both the federal and provincial governments. This joint management framework requires mirror federal and provincial legislation and regulations for both the Canada-NL and Canada-NS offshore areas.

In 1985, Canada and NL concluded an agreement to jointly manage petroleum resources off the coast of that province. This agreement is implemented through the federal Canada–Newfoundland and Labrador Atlantic Accord Implementation Act and mirror provincial legislation. Petroleum resource activity in the offshore area of NL is regulated by the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB).

In 1986, Canada and NS reached a similar agreement that is implemented through the federal Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act and mirror provincial legislation. These acts established the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB) to regulate petroleum activities in the offshore area of that province.

The C-NLOPB and the CNSOPB (the Boards) are independent joint regulators that regulate at arm’s length from both the federal and provincial governments. The Boards administer the offshore petroleum regulatory regime to ensure the health and safety of offshore workers and protection of the environment, among other legislative requirements.

Following the promulgation of the enabling federal and provincial legislation, a number of regulations were brought into force to establish requirements related to the safe operation of petroleum activities in those offshore areas. The regulations established requirements related to the acquisition of operations licenses (1988), geophysical and geotechnical data (1995), installation design (1995) and the associated certificates of fitness (1995), and the drilling and production activities (2009).

Frontier and Offshore Regulatory Renewal Initiative

In 2002, the Atlantic Energy Roundtable (AER) was established as a means for governments, offshore industry, regulators and labour leaders to work together to foster a sustainable offshore petroleum industry in the Atlantic region. Following discussions on regulatory issues, the AER identified the need for a modern suite of regulations governing Canada’s offshore petroleum sector and made a recommendation to federal and provincial government partners to pursue regulatory changes.

In 2005, the Frontier and Offshore Regulatory Renewal Initiative (FORRI) was established to oversee the process of regulatory renewal and modernization. FORRI is led by Natural Resources Canada (NRCan), and includes participation of Crown-Indigenous Relations and Northern Affairs Canada (CIRNAC), Environment and Climate Change Canada (ECCC), the NL Department of Industry, Energy and Technology, and the NS Department of Natural Resources and Renewables. The C-NLOPB, CNSOPB, and the Canada Energy Regulator (CER) have been regulatory partners throughout this initiative, providing technical expertise and support to governments.

The goal of FORRI is to improve the existing regulatory framework in Canada’s frontier and offshore areas, in addition to supporting the petroleum industry’s contribution to Canada’s economy and competitiveness by maintaining the highest standards for operational safety, environmental protection and management of resources.

Under FORRI, federal and provincial government partners modernized the Offshore Petroleum Drilling and Production Regulations, which addressed the safe operation of drilling and production activities. These regulations had come into force in 2009 and replaced the antiquated regulations that were first established in the late 1980s. FORRI also led the development of three new regulations — the Offshore Petroleum Administrative Monetary Penalties Regulations, the Offshore Petroleum Cost Recovery Regulations, and the Offshore Petroleum Financial Requirements Regulations — in each of the offshore areas, in order to implement the federal Energy Safety and Security Act (2015).

Following this work, government partners refocused its efforts on developing a modern suite of all operational requirements for frontier and offshore petroleum activities, termed the “Framework Regulations” for each of Canada’s offshore jurisdictions. The Framework Regulations, described in detail in subsequent sections, are a modernized and amalgamated suite of operational regulations in the Canada-NL and Canada-NS offshore areas. A subsequent regulatory proposal, focusing on petroleum activities in Canada’s frontier and offshore areas outside of the two Accord areas, is expected to be advanced in 2024.

Objective

The primary objective is to create a modern suite of technical regulations for the offshore petroleum sector that optimizes operational safety, environmental protection, and resource management by allowing the use of best practices and technologies. A secondary objective is to improve regulatory clarity and efficiency while maintaining high standards and competitiveness of Canada’s offshore petroleum sector.

Description

The Regulations repeal nine regulations and replace them with one consolidated, comprehensive “framework” regulation for each of the Canada-NL and Canada-NS offshore areas.

The regulations that are being repealed include

The consolidated Regulations enhance the existing management-based regime for petroleum activities by aligning requirements related to safety, environmental protection, and resource management with domestic and international codes and standards, while codifying industry best practices that operators are currently voluntarily complying with, or which the Boards have mandatorily imposed through directives or conditions of authorization.

A more technology-neutral approach in the Regulations allows operators (with the approval of the relevant Board) to use the best available technologies and methodologies, and promotes innovative solutions that enhance safety in the offshore.

The Regulations address key aspects of offshore petroleum activities, from general authorizations and approvals, including technical requirements related to specific types of activities, through to decommissioning and abandonment. The main themes and requirements are outlined below.

Consequential amendments are also being made to the AMPs Regulations to align with the new Framework Regulations.

Authorizations and approvals

The requirements related to applications for authorization or approval to conduct any offshore petroleum activity can be found in Parts 3 and 4. These parts largely carry over requirements that exist in the Offshore Petroleum Drilling and Production Regulations, but now extend the application beyond just drilling and production activities, to all regulated petroleum activities. These parts detail the minimum requirements related to an operator’s management system and its plans for safety, environmental protection, development, decommissioning and abandonment, as well as contingency planning in the event of an emergency.

The Regulations expand on the requirements of a plan for decommissioning and abandonment and codify the requirement for well verification schemes, a requirement that the Boards currently impose as a condition of any well approval.

The Regulations also establish requirements around the use of spill-treating agents (STAs) in responding to spills. In 2015, the Energy Safety and Security Act amended the Canada-Newfoundland and Labrador Atlantic Accord Implementation Act and the Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act (Accord Acts) in order to provide the Boards with the ability to authorize the use of STAs to respond to oil spills from offshore exploration and production operations activities. The Regulations strengthen the environmental protections as it relates to STAs by clarifying requirements around the net environmental benefit in relation to the authorization and use of an STA throughout the spill response; reinforcing the importance of testing the efficacy of STAs prior to their use; ensuring that STA application must be done by experienced personnel in a way that ensures efficient and effective application and responder safety; ensuring that monitoring of STA use is based on best practices; and circumscribing the ability to conduct a “small-scale test” of an STA including its purpose, scale of use, availability and implementation. In accordance with the Accord Acts, elements of the Regulations that pertain to the use of an STA are co-recommended by the Minister of the Environment.

Certificate of fitness

Part 5 addresses requirements related to the certification (known as a Certificate of Fitness) by a certifying authority that a drilling, production, accommodation or diving installation is fit for purpose and is in a condition that it can be operated safely.

The Regulations establish a new requirement that an applicant must develop, for the Board’s acceptance, a Certification Plan that will identify the codes and standards the applicant proposes to use to meet the requirements of the regulations pertaining to the design, construction, and maintenance of installations, which are largely found in Parts 9 (Diving) and 10 (Installations). Under the Regulations, the Certificate of Fitness is based on the applicant’s Certification Plan.

This new, more adaptable approach replaces the process used in the Offshore Certificate of Fitness Regulations, where the Certificate of Fitness was based on very prescriptive requirements laid out in other regulations, such as in the antiquated Offshore Petroleum Installation Regulations.

Technical requirements applicable to all petroleum activities

Part 6 contains more general requirements that broadly apply to all regulated activities, including controls for safety and protection of the environment, storage and handling of consumables, chemical substances, and the implementation of required plans. This part is mostly comprised of revised provisions from the Offshore Petroleum Drilling and Production Regulations that were more fundamental in nature and which are expected of regulated parties undertaking any petroleum activity in the offshore.

Geoscientific, geotechnical and environmental programs

Part 7 focuses on requirements pertaining to geoscientific, geotechnical and environmental programs. It addresses similar topics to those addressed in the Offshore Area Petroleum Geophysical Operations Regulations, but has removed much of the confining text and requirements pertaining to equipment. Instead, the Regulations require that equipment and materials used in conducting a geoscientific, geotechnical or environmental program are handled, installed, inspected, tested, maintained and operated taking into account the manufacturer’s instructions and industry standards and best practices.

Drilling and production

Part 8 pertains to drilling and production activities, including requirements related to the evaluation of wells, well integrity and well termination, as well as the reduction of emissions. Part 8 largely carries over requirements from the Offshore Petroleum Drilling and Production Regulations. It has stronger obligations around materials and equipment used in drilling and production to address hazards related to hydrogen sulphide induced corrosion in wells. Additionally, the Regulations establish new limits on venting, as well requirements related to compressors, leak detection and leak repair. These stringent requirements were developed in consultation with ECCC and are comparable to those in the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector).

Diving

Part 9 contains requirements for diving projects, including the technical and design specifications of the vessel and any light dive craft from which the diving activity would be deployed. These requirements establish the foundation for the Certification Plan for diving installations, as required under Part 5.

Installations

Part 10 is the most substantial part of the Regulations, containing provisions relating to the design, construction, operation and maintenance of drilling, production, and accommodation installations, including their equipment and systems.

The most significant changes can be found in this Part, where a number of provisions replace prescriptive requirements from the Offshore Petroleum Installation Regulations that hindered the use of newer technologies and methodologies with RQs.

The Regulations establish a more robust framework for the design of installations, rooted in comprehensive technical analysis and risk assessment, with ongoing obligations to ensure that risk is reduced to as low as reasonably practicable. The Regulations also establish the clear obligation of the operator to ensure that the installation, including its systems and equipment, is fit for the purposes for which it is to be used and can be operated safely without posing a threat to persons or the environment. Quality assurance program requirements are enhanced and elaborated, requiring its application at each phase of the life cycle of an installation, from its design up to and including its decommissioning and abandonment.

The Regulations address the same technical areas as previous regulations, but offer greater flexibility for the operator to determine the most appropriate and suitable technologies and methodologies to meet the regulatory requirement. The requirements related to installation design have been aligned, to the extent appropriate, with domestic and international standards, codes and best practices. Given Canada’s Atlantic offshore area is one of the harshest operating environments in the world and can be significantly remote (upwards of 500 km from shore), the Regulations still purposefully establish more stringent requirements than what is required under international standards or codes. Examples of where the Regulations establish more stringent requirements include requiring optional requirements in the International Maritime Organization (IMO) Mobile Offshore Drilling Unit (MODU) Code related to ballast control stations to be read as mandatory and requiring a greater number of lifeboats than what is required in IMO International Convention for the Safety of Life at Sea (SOLAS).

The technologies and methodologies identified by the operator to be used in the design of the installation form the foundation of the Certification Plan for drilling, production, and accommodation installations, as required under Part 5.

The design of installations may incorporate innovative technologies, provided that the safety of the new technology can be supported by engineering studies, prototypes and/or model tests, and be verified by a competent third party. In this case, the regulated party must also establish and implement a technology qualification program for ongoing verification of the effectiveness of the technology.

Finally, the Regulations limit the scope of these requirements in this part to drilling, production, and accommodation installations only. Requirements specific to diving installation are found in Part 9.

Support operations

Part 11 focuses on the support operations, such as the availability of support vessels and aircraft in the event of an emergency, and the requirements related to their safe interaction with an installation or vessel used for geophysical, geotechnical, environmental or dive programs. This part contains revised requirements from the Offshore Petroleum Drilling and Production Regulations, with broadened application to all regulated petroleum activities, as applicable.

Records and reporting

Part 12 contains requirements related to record keeping, activity and incident reporting, and investigation of reportable incidents. The Regulations consolidate, into one part, all of the records and reporting provisions from the previous regulations and codify record-keeping and reporting requirements that exist under current practice and through Board imposed requirements.

Consequential amendments

The Regulations consequentially amend the Canada-Newfoundland and Labrador Offshore Petroleum Administrative Monetary Penalties Regulations and the Canada-Nova Scotia Offshore Petroleum Administrative Monetary Penalties Regulations to replace Parts 2 through 5 of Schedule 1, which referenced provisions from the previous regulations, with a new part that references the relevant provisions from the Regulations.

Regulatory development

Consultation

The policy intent for the Regulations were subject to comprehensive stakeholder engagement and consultation throughout the various phases of the regulatory development process. Overall, stakeholders were supportive of updating the regulations, with industry specifically advocating for Canada to modernize its regulations, similar to other leading offshore petroleum jurisdictions (e.g. Norway, United Kingdom, and Australia).

Stakeholders have been consulted via bilateral and multilateral fora, including roundtables, on the draft regulations since 2016. NRCan and its provincial partners held engagement opportunities in March and June 2016, as well as in June 2017, on various topical areas to obtain input into the draft policy intent that supported the development of the regulations for both offshore areas. Engagement opportunities included written comment periods, as well as in-person sessions, held in Ottawa, Ontario, St. John’s, NL, and Halifax, NS.

The input and advice received during these sessions helped shape the final policy intent, which was presented at a follow-up engagement session in May 2018. That session provided an opportunity for government partners to demonstrate to stakeholders that feedback received from earlier engagements had been considered and incorporated into the consolidated policy intent and the drafting instructions for the consolidated framework regulations.

Throughout the various phases of the regulatory development process, comments were received from 15 stakeholders, including industry associations representing offshore operators and employers, the local service and supply community, professional engineers and land surveyors, certifying authorities, industry consultants, an environmental group, and a standards organization. Indigenous groups in Atlantic Canada and Quebec were engaged in the regulatory development process and informal comments were received from contributing government and regulator partners. The nature and content of the feedback was largely dependent on the party sending the submission. Feedback received during the early consultation periods included questions, input and suggested revisions to improve clarity, applicability, and administrative provisions. There were also a number of specific comments on more technical matters that were considered and addressed.

More details with respect to the various comments submitted during the early consultation periods can be found in the June 18, 2022, version of the Canada Gazette, Part I. In addition, all formal feedback received can be found on the FORRI web page. All comments received were reviewed in consultation with provincial and offshore Board partners, with some resulting in modifications to the policy intent which informed the drafting of the regulations.

On June 18, 2022, the proposed Canada–Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations and the proposed Canada-Nova Scotia Offshore Area Petroleum Operations Framework Regulations were prepublished in the Canada Gazette, Part I, followed by a 30-day comment period. There were a total of 99 comments received in 6 submissions from stakeholders, including one industry association representing offshore operators (the Canadian Association of Petroleum Producers or CAPP), two certifying authorities, two engineering companies, and the World Wildlife Fund (WWF). In addition, informal comments were received from contributing regulator partners. Feedback received included questions, input and suggested revisions to the regulatory text to improve the clarity regarding requirements, their applicability and other administrative provisions. All comments received were reviewed in consultation with provincial and Board partners, with some resulting in modifications to the regulations. The feedback received, and NRCan and provincial partners’ response, can be found on the FORRI website.

The following subsections summarize the feedback received during the prepublication period, along with NRCan and its provincial partners’ responses and any resulting changes to the Regulations.

Comments with respect to interpretation (defined terms), management system, and authorizations

There were comments from CAPP which resulted in changes to the sections pertaining to the defined terms, management system, and authorizations. Many of the changes were to clarity wording in the Regulations. Two requirements were removed, as they were seen as unnecessary: the requirement to submit a signed statement for the management system, and the requirement to submit contractual arrangements for a relief well drilling installation. The management system is a regulatory requirement, and a signed statement was not seen as necessary to ensure compliance. Submitting contractual arrangements for relief well drilling installations has not been common practice and was not meant to be a policy change in the Regulations.

Comments with respect to Certificate of Fitness

Comments were received from Lloyd’s Register and CAPP on the Certification Plan, and the manner in which the provisions relating to reducing risks were presented. The Regulations have been revised, such that the provisions relating to the reduction of risks have been moved to the sections pertaining to the Safety Plan and/or the Environmental Protection Plan, as appropriate.

Comments with respect to drilling and production

The venting requirements in the Regulations were developed in cooperation with ECCC. To ensure consistency with the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector), as requested by CAPP in their comments, a definition of venting was added to the Regulations.

Comments with respect to installations, wells and pipelines

A number of stakeholders (CAPP, Aker Solutions, and DNV) provided comments with respect to requirements pertaining to installations, wells and pipelines, which resulted in small but meaningful changes in the Regulations, most of which were to ensure that the Regulations are aligned with industry standards and common practice, or to provide further clarity.

With respect to evacuation and rescue, for example, changes were made pertaining to exits, access and escape routes to ensure that the routes are aligned with industry standards. With respect to life-saving appliances, the one-year storm condition reference was removed and the reference to “combined capacity” was altered to provide greater clarity.

With respect to emergency electrical power supply, a modification was made such that requirements for ballast pumps on emergency power are applicable to column stabilized units only. This is aligned with industry standards, as ballast pumps on other units are not always fed by the emergency electrical power system.

With regards to a floating platform, an alternative means of mooring line integrity monitoring is now permitted as per the Regulations, and changes were made to ensure that the Regulations are clear in terms of the requirements for an emergency disconnection if one should be required.

Finally, the Regulations have been revised such that it is clearer that an operator may employ open or closed flaring systems.

CAPP disagreed with the regulatory requirement for an automated fixed fire suppression system in the accommodations area and consulted with both certifying authorities before making their submission on this topic. The certifying authorities agree that requiring a fixed fire suppression system goes above and beyond what is required in other jurisdictions. This has been discussed in numerous rounds of consultation with CAPP, and has been considered carefully by federal and provincial government partners. Concerns were that the requirement for a fixed sprinkler system is cost prohibitive, and there are a limited number of installations worldwide that have fire suppression in their accommodations areas.

The Regulations do not require a “sprinkler system” as in the Offshore Petroleum Installation Regulations, which are being repealed upon entrance into force of the Regulations. The requirements in the Regulations for a “suppression system” is more performance-based and provides the operator with a number of options (other than water/sprinklers) to suppress a potential fire. In the unlikely event that a fire is not prevented, governments believe that a fixed system to extinguish the fire provides the highest level of safety for personnel on board the installation. These installations are often hundreds of kilometres from shore and can have upwards of 100 or more persons on board. Given the remoteness of the operation, and the number of personnel on board, governments did not make any changes with respect to this requirement.

Regulatory language improvements

Stakeholders and partners provided feedback regarding refinements of technical language in the Regulations to ensure clarity in intent and to allow for accurate interpretation by regulated parties and regulators alike. As a result, language was fine-tuned in the provisions related to casing and cementing, management systems, STAs, fire and gas detection system, emergency shutdown system, boilers and pressure systems, stability of platforms, disconnect system, and records and reporting.

There were a number of other requests for clarification by stakeholders, which were addressed in more detail via direct stakeholder letters from governments.

Modern treaty obligations and Indigenous engagement and consultation

In accordance with the Cabinet Directive on the Federal Approach to Modern Treaty Implementation, an initial assessment was conducted on this regulatory initiative. The assessment concluded that implementation of this initiative will unlikely impact the rights, interests or self-government provisions of treaty partners.

Notwithstanding, NRCan and its provincial partners engaged over 40 Indigenous groups in Atlantic Canada and Quebec through written communication and provided an opportunity to meet and discuss the initiative, which was subsequently availed of by a limited number of Indigenous groups.

Instrument choice

The objective of the Regulations is to modernize and streamline the regulations that govern offshore petroleum activities. The Regulations maintain the Board’s tools for enforcing a safe and effective offshore regime, including the use of administrative monetary penalties, and facilitate the prosecution of regulated parties that violate requirements for safety and environmental protection. The only way to achieve this objective is by replacing the previous regulations. No other instrument type would be appropriate in this case.

Building upon the experiences of other jurisdictions with reputable offshore oil and gas regimes (including the United Kingdom, Norway and Australia), the Regulations establish a hybrid-model approach, where outcome-based requirements are used to the extent possible, and prescriptive requirements are maintained where necessary to maintain high standards but still promoting innovation and industry excellence.

Regulatory analysis

Benefits and costs

Globally, major incidents in the offshore petroleum sector are relatively rare. In the past 10 years, the Canada-NL and Canada-NS offshore areas have performed statistically consistent with,footnote 7 or better than, the average performance of comparable jurisdictions in areas of major incidents, such as fatalities, major gas release, loss of well control, major fires and collisions.footnote 8 The Regulations contribute to maintaining or improving safety and environmental protection outcomes in the Canada-NL and Canada-NS offshore areas; however, the benefits related to reduced incidents are not quantified.

The quantified impacts of the Regulations result in a net present benefit of $6.56 million between 2024 and 2033 (discounted to 2023 using a discount rate of 7%). The methodology used as well as the details of the costs and benefits analyses are presented below.

Methodology

The assessment of the impacts of the Regulations was conducted in accordance with the Policy on Cost-Benefit Analysis. The impacts flow from changes in requirements arising from the Regulations (the regulatory scenario) that are incremental to actions arising from the previous regulations and mandatory compliance with codes of practice and Board-issued safety directives and conditions of authorization, as well as voluntary compliance with international industry best practices (the baseline scenario).

Industry stakeholders and the Boards were engaged and provided feedback that informed the analysis of the expected incremental costs and benefits of the Regulations.

The assessment assumes that over the next 10 years in the Canada-NL offshore area, there would be four ongoing production projects, an average of two drilling projects and one seismic program per year, and one diving project every three years. The assessment assumes no future activities in the Canada-NS offshore area, which is consistent with current activity and future forecasts, and therefore references of the “Board” in this section are with respect to the C-NLOPB.

Benefits

The main goal and benefit of the Regulations are a continued or improved performance with respect to safety and environmental protection. The safety benefit is discussed qualitatively, while the total calculated present value benefit of the Regulations is $7.43 million. The monetized benefit stems from the reduction in costs to both industry and the offshore Board associated with applications for regulatory deviation ($5.57 million and $1.86 million, respectively).

Safety benefits

The offshore petroleum sector in Canada has a very low incident record. Continual advancements in industry best safety practices, technology, and an increased focus by industry and regulators on proactive measures, such as enhanced training, preventative maintenance and inspections, have contributed to this improvement. As the number of incidents approaches zero, occasional incidents will likely still occur with only minor further reductions in the injury frequency. Given this, it is not possible to attribute a change in the number of incidents or injuries to the Regulations, as opposed to related initiatives.

Benefits to industry

The previous Regulations are prescriptive in nature and only permit flexibility through an RQ. The new Regulations provide greater flexibility by establishing a more technology-neutral approach that allows operators (with the approval of the Board) to use the best available technologies and methodologies. This greater flexibility is expected to result in fewer RQs having to be developed and submitted by some industry members, and assessed by the offshore Board. The avoided RQ benefits accrue to industry members who, under the previous prescriptive regulations, must submit detailed RQs. The avoided cost of personnel time to prepare each submission, and the improved operating flexibility arising from the reduction in the overall time needed to secure approval, is estimated to result in a present value benefit of $5.57 million.

Benefits to offshore Board

Benefits also accrue to the Board, who must review and respond to the applications for regulatory deviation. This benefit results from the avoided cost of personnel time required to review and approve each submission. The present value benefit from the time savings resulting from a reduced number of applications for regulatory deviation is estimated to be $1.86 million.

Costs

Given that the Regulations largely align with domestic and international codes and standards and codify best practices that operators are currently voluntarily complying with, or that have been imposed by the Board through conditions of authorization or directives, there are few requirements that are incremental from the baseline scenario and, therefore, incremental costs are limited. However, three areas were identified that will likely result in increased costs to regulated parties.

Certification Plan costs

The Regulations require an operator to develop a Certification Plan, acceptable to the Board, which identifies the codes and standards that they propose to use to meet the requirements of these regulations. Although this new approach will significantly reduce the administrative burden that currently exists as a result of prescriptive regulatory requirements, it does require upfront work by the industry applicant in developing the Certification Plan. A Certificate of Fitness is required for all installations and may remain valid for a period of up to five years. Accordingly, the costs associated with the Certification Plan are periodic in nature and occur prior to the authorization of the given activity. Based on industry interviews, it is expected that this will cost approximately $21,360 in person hours per Certification Plan, which, based on activity assumptions, results in present value cost of $480,118.

Spill-treating agent monitoring plan costs

The Regulations require a spill treating agent monitoring plan to be developed and implemented as part of the contingency plan for drilling or production activities. The costs related to developing these plans are also periodic in nature and occur prior to authorization of any drilling or production activity. Although the plan will be updated as required, a full new plan is not required every time an operating authorization is renewed. The time for operators to develop the plan has been estimated to be two weeks at a cost of $3,542 per person-week. The value of personnel time was derived from input received during industry interviews on the cost of personnel time spent on RQs. Therefore, it is expected that this will cost approximately $7,048 in person hours per plan, which, based on activity assumptions, results in a present value cost of $125,366.

Administrative costs

There is an expected increase in administrative costs stemming from new requirements for the certifying authorities to maintain records of verification activities and to submit a monthly summary report to the Board. This analysis assumes the administrative cost will be shared equally between the two certifying authorities that are active in the offshore areas and which are likely to be responsible for the installations associated with the four production projects, the expected two drilling programs each year, and one diving program every three years. The analysis estimates the time required by each certifying authority to create and submit the monthly summaries at three hours for each of three installations. Additionally, the analysis estimates that there will be an average of 20 verification activities per month per installation, and the time associated with saving the individual electronic records of each verification activity is 10 minutes. The analysis further assumes the average hourly wage for the National Occupation Classification (NOC) is that of specialized middle management. As a result, it is expected that this will cost approximately $36,640 in person hours per year, resulting in a present value cost of $257,343.

Cost-benefit statement
Table 1: Monetized costs
Impacted stakeholder Description of cost Initial year (2024) Final year (2033) Total
(present value)		 Annualized value
Industry Certification Plan $128,160 $ 42,720 $480,118 $ 68,358
Spill treating agent plan $ 42,293 $ 14,098 $125,366 $ 17,849
Certifying authorities Administrative cost $ 36,640 $ 36,640 $257,343 $ 36,640
All stakeholders Total costs $207,093 $ 93,457 $862,827 $122,847
Table 2: Monetized benefits
Impacted stakeholder Description of benefit Initial year (2024) Final year (2033) Total
(present value)		 Annualized value
Industry Reduction in applications for regulatory deviations $ 792,990 $ 792,990 $ 5,569,630 $ 792,990
Offshore Board Reduction in applications for regulatory deviations $ 264,330 $ 264,330 $ 1,856,543 $ 264,330
All stakeholders Total benefits $ 1,057,320 $ 1,057,320 $ 7,426,173 $ 1,057,320
Table 3: Summary of monetized costs and benefits
Impacts Initial year (2024) Final year (2033) Total (present value) Annualized value
Total costs $207,093 $ 93,457 $ 862,827 $122,847
Total benefits $1,057,320 $1,057,320 $7,426,173 $1,057,320
NET IMPACT $850,227 $963,863 $6,563,346 $934,473
Quantified (non-$) and qualitative impacts

Positive impacts:

Small business lens

An analysis under the small business lens concluded that the Regulations will not impact Canadian small businesses. None of the offshore operators and other businesses that are impacted by the Regulations are Canadian businesses with fewer than 100 employees or less than $5 million in revenue annually.

One-for-one rule

The Regulations create two new titles that replace nine titles that will be repealed for the Canada-NL and Canada-NS offshore areas. As a result, the initiative will count as a net seven titles out under the one-for-one rule.

The administration costs associated with the Regulations result in an incremental increase in administrative burden on business as a result of record-keeping requirements imposed on the two active certifying authorities that did not exist in the previous regulatory regime. Inputs into the calculation and relevant assumptions are described in the above “Benefits and costs” section. The increase in administrative burden is stemming from Regulations that fall under the Canada-Newfoundland and Labrador Atlantic Accord Implementation Act only. There is currently no forecasted activities in the Canada-Nova Scotia offshore area. Adjusted to 2012 constant dollars, with 2012 as the base year, a 10-year timeframe from the year of registration (i.e. 2024), and a 7% discount rate (as required by the Red Tape Reduction Regulations), the annualized increase in the administrative burden on businesses is estimated at $14,439, or an average of $7,219 per business, as calculated using the Treasury Board Secretariat’s Regulatory Cost Calculator tool.

Regulatory cooperation and alignment

The Regulations are not related to a work plan or commitment under a formal regulatory cooperation forum; however, they were developed in partnership with the governments of NL and NS, under the joint management framework for the offshore Accord areas. Consistent with the joint management framework, the provinces will develop mirror regulations under the authorities of their respective provincial Accord Acts. The federal and provincial regulations will be coordinated to come into force at the same time.

Given that the Regulations apply to transient workplaces, such as foreign-flagged mobile offshore drilling units that operate internationally, the Regulations are tailored to ensure alignment with jurisdictions with comparable offshore petroleum safety regimes, as well as international maritime conventions, for which Canada is a signatory. The latter is accomplished both by incorporation by reference directly to these conventions, such as the International Maritime Organization’s (IMO) Code for the Construction and Equipment of Mobile Offshore Drilling Units (MODU Code), International Code on Intact Stability and the Life-Saving Appliance (LSA) Code, and indirectly by incorporating by reference regulations made by Canada’s Maritime Authority, under the Canada Shipping Act, 2001, which also serve to align Canada’s marine requirements with international standards.

There are instances where the Regulations prescribe a requirement that may differ from what other jurisdictions require, such as the requirement for a fire suppression system to be installed in the accommodations area of an installation, and the requirement that mobile drilling installations be subject to inclining tests to verify stability. These instances are intentional and reflective of the reality that Canada’s offshore areas are some of the harshest environments in the world in which to operate, that they are remote and emergency response and rescue may be delayed by poor weather conditions for days.

Strategic environmental assessment

In accordance with the Cabinet Directive on the Environmental Assessment of Policy, Plan and Program Proposals, a preliminary scan concluded that a strategic environmental assessment is not required.

Gender-based analysis plus

The Regulations modernize the previous regulations and codify operational safety practices already observed by regulated parties. A gender-based analysis plus (GBA+) was conducted as part of the development of the Regulations and no GBA+ impacts have been identified.

The Regulations are not expected to result in differential levels of safety or environmental protection to categories of stakeholders in the offshore petroleum sector, nor to the public at large.

Implementation, compliance and enforcement, and service standards

Implementation

The Regulations will come into force eight months after the day they are published in the Canada Gazette, Part II. NRCan is working with the governments of NL and NS and the Boards to coordinate implementation of the Regulations with mirrored provincial regulations and has jointly developed communication materials to ensure potentially affected organizations and individuals are aware of the publication of the Regulations.

The Boards will develop guidance materials to assist operators, employers and employees in the interpretation of the Regulations, where the Boards determine additional guidance could be helpful. Consistent with their regular practice, the Boards will update their websites to provide information about the Regulations and work to address any questions operators or employers have with respect to the interpretation and compliance of the Regulations.

Operators may need to reassess previously approved RQs from the previous regulations to determine whether an RQ is required from the Regulations. The Boards will establish a process for reconsideration of any previously approved RQs that are assessed as being necessary under the Regulations.

Compliance and enforcement

Compliance and enforcement activities will follow established C-NLOPB and CNSOPB approaches and procedures. Enforcement actions may include facilitated compliance, issuance of orders, directives or notices, administrative monetary penalties, suspension or revocations of approvals and authorizations, and prosecution.

The Boards regularly conduct inspections and audits to verify compliance with the Accord Acts and the regulations made under them. The Boards may become aware of an incident or other hazardous occurrence through the mandatory reporting process required under the Accord Acts.

Contact

Cheryl McNeil
Deputy Director
Offshore Petroleum Management Division
Natural Resources Canada
Telephone: 709‑763‑1760
Email: cheryl.mcneil@nrcan-rncan.gc.ca