Canada Gazette, Part I, Volume 156, Number 25: Canada–Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations

June 18, 2022

Statutory authority
Canada–Newfoundland and Labrador Atlantic Accord Implementation Act

Sponsoring departments

Department of Natural Resources
Department of the Environment

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the regulations.)

Executive summary

Issues

The bulk of regulations currently in place governing offshore petroleum activities in the Canada-Newfoundland and Labrador and Canada-Nova Scotia offshore areas have not been updated since they were developed in the late-1980s and early-1990s, before many of the current technologies were developed, best practices were established, and lessons learned from international incidents realized. The existing regulations use prescriptive language, require the use of outdated technologies and/or methodologies and incorporate by reference a number of standards and codes that are now obsolete.

The prescriptive nature of the existing regulations, and lack of inherent flexibility, has negatively affected the efficiency and effectiveness of the regulatory framework. Currently, industry members must undertake expensive modifications to installations or use equipment and/or methods that are technologically inferior, in order to comply with the regulations. Alternatively, the industry member may submit requests to the Chief Safety Officer (CSO) or Chief Conservation Officer (CCO) of the respective offshore regulator for approval to deviate from the regulations (known as regulatory queries or “RQs”). Given the costly nature of most required modifications, industry members have frequently opted to pursue RQs; however, RQs have also proven to be costly and administratively burdensome in nature for both the regulated parties and the regulators, which must review and approve/reject the proposal.

Stakeholders have provided feedback to governments regarding the high level of duplication between the existing regulations, including requirements that are administrative in nature. This feedback was echoed by the Standing Joint Committee on the Scrutiny of Regulations (SJCSR), which in 2011, recommended a number of changes to the existing regulations to address duplication of text between the regulations, discrepancies between the French and English versions, harmonization of terms used in the existing regulations with the enabling statute, and correction of typographical and grammatical errors.

Given these issues, stakeholders have questioned the effectiveness and competitiveness of Canada’s existing regulatory framework for the offshore petroleum sector, particularly given the administrative burden and lack of regulatory clarity that stem from the outdated regulations. Industry has further questioned whether it is worthwhile to do business in Canada’s offshore areas, given the current state of the regulatory framework.

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^{footnote 1} 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^{footnote 2} 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^{footnote 3} (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, which provided a forum 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 such regulatory changes.

The Frontier and Offshore Regulatory Renewal Initiative (FORRI) was established in 2005 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) are also participants in this initiative.

The objective 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 address the safe operation of drilling and production activities. These regulations came 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 – Offshore Petroleum Administrative Monetary Penalties Regulations, 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, which is at the heart of this proposal, would modernize and amalgamate the suite of operational regulations in the Canada-NL and Canada-NS offshore areas, where offshore petroleum activities in Canada have predominantly occurred. 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 2023.

Standing Joint Committee on the Scrutiny of Regulations recommendations

In 2011, the SJCSR recommended a number of changes to the Newfoundland Offshore Petroleum Drilling and Production Regulations and the Nova Scotia Offshore Petroleum Drilling and Production Regulations. Specifically, the SJCSR recommended changes to address duplication of text between the regulations and discrepancies between the French and English versions, to harmonize the terms used in the existing regulations with the enabling statute, and to correct a number of typographical and grammatical errors.

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, reduce existing administrative burden, and to respond to recommendations of the SJCSR that also pertain to regulatory clarity, which collectively can improve competitiveness of Canada’s offshore petroleum sector.

Description

The proposed Regulations would repeal the existing nine regulations and replace with one consolidated, comprehensive “framework” regulation for each of the Canada-NL and Canada-NS offshore areas, allowing greater ease of use by regulated parties and regulators.

The regulations that would be repealed include:

• Newfoundland Offshore Petroleum Installation Regulations (SOR/95-104)
• Nova Scotia Offshore Petroleum Installation Regulations (SOR/95-191)
• Newfoundland Offshore Certificate of Fitness Regulations (SOR/95-100)
• Nova Scotia Offshore Certificate of Fitness Regulations (SOR/95-187)
• Newfoundland Offshore Area Petroleum Geophysical Operations Regulations (SOR/95-334)
• Nova Scotia Offshore Area Petroleum Geophysical Operations Regulations (SOR/95-144)
• Newfoundland Offshore Petroleum Drilling and Production Regulations (SOR/2009-316)
• Nova Scotia Offshore Petroleum Drilling and Production Regulations (SOR/2009-317)
• Newfoundland Offshore Area Oil and Gas Operations Regulations ^{footnote 4} (SOR/88-347)

The proposed Regulations would enhance the existing management-based regime for petroleum activities by aligning requirements related to safety, environmental protection and resource management with international codes and standards and 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 technology-neutral approach would be established that would provide inherent flexibility to allow operators (with the approval of the relevant Board) to use the best available technologies and/or methodologies, ensuring innovative approaches that enhance safety can be used in the offshore. This additional flexibility is expected to result in fewer RQs having to be developed and submitted by regulated parties and assessed by the Boards.

The proposed Regulations are each comprised of ten parts, addressing the key aspects of offshore petroleum activities, from general authorizations and approvals to technical requirements related to specific types of activities. A description of each part is as follows:

Authorizations and approvals

The requirements related to applications for authorization or approval to conduct any offshore petroleum activity can be found in Parts 1 and 2. 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 prescribe 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 proposed Regulations would expand on the requirements of a plan for decommissioning and abandonment and would codify the requirement for well verification schemes, a requirement that the Boards currently impose as a condition of any well approval.

The proposed Regulations would also establish requirements around the use of spill-treating agents (STA) 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 proposed 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 spill treating agents 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, regulations that pertain to the use of an STA must be co-recommended by the Minister of Environment and Climate Change.

Certificate of fitness

Part 3 would address 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 proposed Regulations would establish a new requirement that an applicant must develop, for the Board’s acceptance, a proposed Certification Plan that would 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 7 (Diving) and 8 (Installations). Under the proposed Regulations, the Certificate of Fitness would be based on the applicant’s proposed Certification Plan.

This new, more adaptable approach would replace the approach used in the existing Offshore Certificate of Fitness Regulations, in which the Certificate of Fitness is based on the prescriptive requirements laid out in other regulations, such as in the antiquated Offshore Petroleum Installation Regulations.

Technical requirements applicable to all petroleum activities

Part 4 contains requirements that are general in nature and apply to all regulated activities, including requirements relating to safety and protection of the environment, storage and handling of consumables, including chemical substances, and the implementation of required plans. This part largely carries over requirements that exist in the Offshore Petroleum Drilling and Production Regulations that were more fundamental in nature and that are expected of regulated parties undertaking any petroleum activity in the offshore.

Geoscientific, geotechnical and environmental programs

Part 5 focuses on requirements pertaining to geoscientific programs, geotechnical programs and environmental programs. It addresses similar topics to those addressed in the Offshore Area Petroleum Geophysical Operations Regulations but has removed much of the prescription pertaining to equipment. Instead, the proposed Regulations would require that equipment and materials used in conducting a geoscientific program, geotechnical program 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 6 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 6 largely carries over requirements that exist in the Offshore Petroleum Drilling and Production Regulations, while serving to strengthen requirements around materials and equipment used in drilling and production to address hazards related to corrosion that arise from increased presence of hydrogen sulphide in wells. Additionally, the proposed Regulations would establish new limits on venting, as well requirements related to compressors, leak detection and leak repair. These requirements have been developed in consultation with ECCC and would effectively be at least as stringent as the comparable requirements under the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector).

Diving

Part 7 contains requirements for diving projects, and in particular, would prescribe 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 3.

Installations

Part 8 is the most substantial part of the proposed Regulations, containing provisions relating to the design, construction, operation and maintenance of drilling, production and accommodation installations, including its equipment and systems.

The most significant proposed changes from the existing regulatory regime can be found in this Part, where the proposed Regulations would replace existing prescriptive requirements found in the Offshore Petroleum Installation Regulations. These prescriptive requirements have proven to limit the use of ever-changing technologies and advanced methodologies and, as a result, have generated a considerable number of RQs.

The proposed Regulations would establish a more robust framework for the design of installations, which would be rooted in comprehensive technical analysis and risk assessment, with the ongoing obligation of the operator to ensure that risk is reduced to as low as reasonably practicable. The proposed Regulations would 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 would be 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 proposed Regulations would address the technical areas as the existing regulations but would allow for 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 international standards, codes and/or best practices. Given Canada’s Atlantic offshore is one of the harshest operating environments in the world and can be significantly remote, where activities can occur upwards of 500 km from shore, the proposed Regulations would, at times, establish more stringent requirements than what is required under international standards or codes. Examples of where the proposed Regulations would 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 would form the foundation of the Certification Plan for drilling, production, and accommodation installations, as required under Part 3.

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 operator must also establish and implements a technology qualification program for ongoing verification of the effectiveness of the technology.

Finally, the proposed Regulations would limit the application of these requirements in this part to drilling, production and accommodation installations only. Requirements specific to diving installation would be prescribed in Part 7.

Support Operations

Part 9 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 largely carries 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, as applicable.

Records and reporting

Part 10 contains requirements related to the record keeping, activity and incident reporting, and investigation of reportable incidents. The proposed Regulations consolidate into one part all of the records and reporting provisions required in the existing regulations and codify records-keeping and reporting requirements that exist under current practice and through Board imposed requirements.

Consequential amendments

The proposed Regulations would 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 currently reference provisions from the existing regulations, with a new part that references the relevant provisions from the proposed Regulations.

Regulatory development

Consultation

The policy intent for the proposed Regulations were subject to a comprehensive stakeholder engagement and consultation process throughout the various phases of the regulatory development process. Overall, stakeholders have been generally 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 proposed Regulations since 2016. NRCan and its provincial partners held engagement opportunities in March and June 2016 and June 2017 on various topical areas to obtain input into the draft policy intent that would support the development of the regulations for both offshore areas. Engagement opportunities included written comment periods as well as in-person sessions held in Ottawa, ON, St. John’s, NL, and Halifax, NS.

The input and advice received during these sessions helped to shape the final policy intent, which was presented at a follow-up engagement session in May 2018. This session provided an opportunity for government partners to demonstrate to stakeholders how feedback received in earlier engagements had been considered and incorporated into the consolidated policy intent, which would form the basis of the drafting instructions for the proposed Regulations for each offshore area.

Comments were received from 15 stakeholders, including associations representing offshore operators, the local service and supply community, professional engineers and land surveyors; Indigenous groups; certifying authorities; industry consultants; an environmental group; and a standards organization. In addition, informal comments were received from contributing government and regulator partners. Feedback received during this consultation period included questions, input and suggested revisions to the regulatory text to improve the clarity regarding the requirements, their applicability, and other administrative provisions.

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 proposed Regulations. The feedback received can be found on the FORRI web page.

Early engagement feedback and issues raised

Written comments were received from the Nunatsiavut Government, the Kwilmu’kw Maw-Klusuaqn Negotiation Office (KMKNO) and the Conseil des Innu de Ekuanitshit, which mainly focused on requests for clarity on the scope of the regulatory proposal and the regulatory process itself, as well as any potential impact on overlap with Government of Canada regulatory activities related to marine protection.

Additionally, the KMKNO acknowledged the appropriateness of performance-based requirements that drive risk down to as low as reasonably practicable in certain contexts, noting that it can capitalize on industry expertise and innovation; however, the KMKNO questioned the Boards’ capacity, knowledge and authority to ensure operators’ obligations are fulfilled. Given the Accord Acts outline the Boards’ authority to regulate activities, no changes to the proposed Regulations were necessary. The KMKNO also requested that the contingency plan for responding to major incidents include a requirement for communication with Indigenous governments, and that the environmental protection plan should require operators to develop procedures to be followed when an archaeological site or a burial ground is discovered during any proposed work or activity in an offshore area. This feedback was incorporated into the proposed Regulations.

The World Wildlife Fund (WWF) commended the government partners’ efforts in modernizing the regulatory framework and seeking the advice of stakeholders throughout this process, noting its view that the modernization of the offshore regulatory regime in Canada was long overdue. WWF identified a few areas of concern, including the role of the regulators in interpreting and applying more outcome-based regulations in the absence of prescribed standards, and the inherent principle that operators must ensure that risk is reduced to as low as reasonably practicable.

Conversely, Energy NL raised concerns that the consolidated policy intent still contained too much prescriptive language and prescribed standards that could result in the regulations becoming quickly outdated. Energy NL also recommended that the Board develop guidelines^{footnote 5} in parallel with the regulations, so that regulated parties could understand how the Board intended to interpret and implement the proposed Regulations. The Boards have confirmed a plan for the development of guidelines, which includes public consultation in late 2022.

The Canadian Association of Petroleum Producers (CAPP) raised the importance of ensuring that the regulations allow for regulators and industry to readily adapt to change, which it suggested can be achieved by allowing industry to propose the standards they would use to achieve a regulatory goal or outcome that is established in the regulations. It emphasized that regulations that prescribe specific technical standards limit industry’s ability to adopt best practices, advance technology, and be innovative when it comes to ensuring safety, environmental protection and responsible resource management.

CAPP provided technical feedback on a number of requirements that was incorporated into the proposed Regulations. However, not all feedback was incorporated, and remains an area where CAPP continues to advocate government partners for change. These include requirements for passive fire protection, which CAPP believes is too prescriptive and would not allow for advancements without triggering the Regulatory Query (RQ) process, and the requirement for fixed fire suppression systems in accommodation areas on installations, which CAPP notes is more stringent than what international convention and standards require. Government partners have retained both requirements in the proposed Regulations on strong recommendation from the regulators, and given the significant remoteness of petroleum activities in the offshore and where weather conditions can limit the response time of rescue operations.

Two Certifying Authorities, DNV and the American Bureau of Shipping (ABS), provided feedback on various technical requirements in the proposed regulations. They also requested clarity on the role of the Certifying Authority with respect to the certification plan and the ongoing validity and recertification and any proposed innovative technology. Following receipt of comments, a workshop was held in 2019 with DNV, ABS, and Lloyd’s Register, another active Certifying Authority. The Boards also participated in the workshop, which was focused on the Certificate of Fitness process, including the certification plan. The proposed regulations have been amended based on the comments submitted by the Certifying Authorities.

The Canadian Standards Association (CSA) and the Association of Canadian Land Surveyors (ACLS) both recommended that the proposed Regulations formally recognize their organization and/or incorporate by reference their published standards. ACLS also provided suggested language edits to the policy intent for greater clarity. The proposed regulations incorporate the CSA standard on Oil and Gas Pipeline Systems, and changes were made based on suggested language edits.

Engineers Canada submitted feedback reminding government partners of the importance that engineering design work related to infrastructure that is to be built for use in offshore Canada should be subject to regulation by the provincial or territorial engineering regulator for the given jurisdiction. A requirement was added to the proposed regulations to ensure that activities must be carried out by a competent person who has the necessary experience, training, qualifications and competence to undertake those activities. Depending on the nature of the activity, a competent person could mean a professional engineer.

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 proposal. The assessment concluded that implementation of this proposal would be unlikely to impact on 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 proposal, which was subsequently availed of by a limited number of Indigenous groups in QC and NS.

Instrument choice

The objective of these proposed Regulations is to modernize and streamline the existing regulations. The use of regulations maintains the Board’s enforcement tools, including the use of administrative monetary penalties, and facilitates the prosecution of operators that violate requirements for safety and environmental protection. The only way to achieve this objective is by replacing the existing 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 concept of outcome-based requirements was considered and eventually applied to these proposed Regulations. The proposed Regulations establish a hybrid-model approach, where outcome-based requirements are used to the extent possible, while maintaining prescriptive requirements, where necessary.

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 6} 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 7} The proposed Regulations would 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 proposed Regulations would result in a net present benefit of $6.15 million between 2023 and 2032 (discounted to 2022 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 proposed Regulations was conducted in accordance with the Policy on Cost-Benefit Analysis. The impacts flow from changes in requirements arising from the proposed Regulations (the Regulatory Scenario) that are incremental to actions arising from the existing 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 proposed Regulations. Interviews with industry representatives, company owners, and the Boards provided many of the inputs and estimates used in both the qualitative and quantitative analyses.

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.

Benefits

The primary benefit of the proposed Regulations would be a continued or improved performance with respect to safety and environmental protection. This benefit is discussed qualitatively, while the total calculated present value benefit of the proposed Regulations would be $6.95 million. This benefit stems from the reduction in costs to both industry and the offshore Boards associated with applications for regulatory deviation ($5.22 million and $1.74 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 proposed Regulations, as opposed to related initiatives.

Benefits to industry

The existing regulations are prescriptive in nature and only permit flexibility through an RQ. The proposed Regulations would provide greater flexibility by establishing a technology-neutral approach that would allow operators (with the approval of the relevant Board) to use the best available technologies and/or 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 Boards. The avoided RQ benefits accrue to industry members who, under the existing 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 $5.22 million.

Benefits to offshore Boards

Benefits also accrue to the Boards, 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 $1.74 million.

Costs

Given that the proposed Regulations largely align with international codes and standards and codify best practices that operators are currently voluntarily complying with, or that have been imposed by the Boards 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 would likely result in increased cost to regulated parties.

Certification Plan costs

The proposed Regulations would require an industry application to develop a Certification Plan, acceptable to the Board, which would identify the codes and standards that they propose to use to meet the requirements of the regulations. Although this new approach to the Certificate of Fitness for an installation would significantly reduce the administration 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 would cost approximately $20,000 in person hours per certification of plan, which, based on activity assumptions, results in present value cost of $449,548.

Spill-treating agent monitoring plan costs

The proposed Regulations would require a spill treating agent monitoring plan 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 would be updated as required, a full new plan would not be required to be developed 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 $3,300/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 would cost approximately $6,600 in person hours per plan, which, based on activity assumptions, results in a present value cost of $117,384.

Administrative costs

There is an expected increase in administrative cost stemming from new requirements for the Certifying Authorities to maintain records of verification activities and to submit a monthly summary report to the Boards. 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 would cost approximately $34,307 in person hours per year, resulting in a present value cost of $240,955.

Cost-benefit statement

• Number of years: 10 (2023 to 2032)
• Base year for costing: 2021
• Present value base year: 2022
• Discount rate: 7%

Table 1: Monetized costs

Impacted stakeholder	Description of cost	Initial year (2023)	Final year (2032)	Total (present value)	Annualized value
Industry	Certification Plan	$120,000	$ 40,000	$449,548	$ 64,006
	Spill Treating Agent Plan	$ 39,600	$ 13,200	$117,384	$ 16,713
Certifying Authorities	Administrative cost	$ 34,307	$ 34,307	$240,955	$ 34,307
All stakeholders	Total costs	$193,907	$ 87,507	$807,888	$115,025

Table 2: Monetized benefits

Impacted stakeholder	Description of benefit	Initial year (2023)	Final year (2032)	Total (present value)	Annualized value
Industry	Reduction in applications for regulatory deviations	$ 742,500	$ 742,500	$ 5,215,009	$ 742,500
Offshore Boards	Reduction in applications for regulatory deviations	$ 247,500	$ 247,500	$ 1,738,336	$ 247,500
All stakeholders	Total benefits	$ 990,000	$ 990,000	$ 6,953,346	$ 990,000

Table 3: Summary of monetized costs and benefits

Impacts	Initial year (2023)	Final year (2032)	Total (present value)	Annualized value
Total costs	$193,907	$ 87,507	$ 807,888	$115,025
Total benefits	$990,000	$990,000	$6,953,346	$990,000
NET IMPACT	$796,093	$902,493	$6,145,458	$874,975

Small business lens

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

One-for-one rule

This regulatory proposal would create two (2) new titles that would replace nine (9) existing titles for the Canada-NL and Canada-NS offshore areas. As a result, the proposal would count as a net seven (7) titles out under the one-for-one rule.

The administration costs associated with the proposed Regulations would 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 existing regulatory regime. Inputs into the calculation and relevant assumptions are described in the above “Benefits and costs” section. These costs were adjusted from 2022 dollars to 2012 dollars for the purpose of calculating the increase in the administrative burden as required under the Red Tape Reduction Regulations. Using 2012 constant dollars, with 2012 as the base year, a 10-year timeframe from the year of registration (i.e. 2022), and a 7% discount rate, the annualized average increase in the administrative burden on businesses is estimated at $14,372 or an average of $7,186 per business as calculated using the Treasury Board Secretariat’s Regulatory Cost Calculator tool.

Regulatory cooperation and alignment

The proposed 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 these proposed Regulations would apply to transient workplaces such as foreign-flagged mobile offshore drilling units that operate internationally, the proposed 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 proposed 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 area are some of the harshest environments in the world in which to operate, that they are remote and emergency response and rescue may be grounded 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 proposed Regulations would modernize the existing regulations and would codify operational safety practices already observed by regulated parties. A gender-based analysis plus (GBA+) was conducted as part of the development of the proposed Regulations and no GBA+ impacts have been identified.

The proposed 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 proposed Regulations would come into force six months after the day they are published in the Canada Gazette, Part II. NRCan will work with the Governments of NL and NS and the Boards to coordinate implementation of these proposed Regulations with mirrored provincial regulations and will jointly develop communication materials to ensure potentially affected organizations and individuals are aware of the publication of the proposed Regulations.

It is anticipated that the Boards will develop guidance materials to assist operators, employers and employees in the interpretation of the proposed 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 proposed Regulations and will work to address any questions operators or employers have with respect to the interpretation and compliance of the proposed Regulations.

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

Compliance and enforcement

Compliance and enforcement activities would follow established C-NLOPB and CNSOPB approaches and procedures to monitoring compliance and enforcing the Accord Acts and the regulations made under them. Enforcement actions may include facilitated compliance, issuance of orders, directives or notices, administrative monetary penalties, suspension or revocations of approvals and authorizations, and/or prosecution.

The Boards regularly conduct safety inspections and safety 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
Senior Policy Advisor
Offshore Petroleum Management Division
Natural Resources Canada
Telephone: 709‑763‑1760
Email: cheryl.mcneil@nrcan-rncan.gc.ca

PROPOSED REGULATORY TEXT

Notice is given, pursuant to subsection 150(1) of the Canada–Newfoundland and Labrador Atlantic Accord Implementation Act^{footnote a}, that the Governor in Council, pursuant to subsections 149(1)^{footnote b} and (3)^{footnote c} of that Act, proposes to make the annexed Canada–Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations.

Interested persons may make representations concerning the proposed Regulations within 30 days after the date of publication of this notice. All such representations must cite the Canada Gazette, Part I, and the date of publication of this notice, and be addressed to Cheryl McNeil, Senior Policy Advisor, Offshore Petroleum Management Division, Fuels Sector, Department of Natural Resources (email: cheryl.mcneil@nrcan-rncan.gc.ca).

Ottawa, June 9, 2022

Wendy Nixon
Assistant Clerk of the Privy Council

TABLE OF PROVISIONS

Canada–Newfoundland and Labrador Offshore Area Petroleum Operations Framework Regulations

Interpretation

1 Definitions

2 Incorporation by reference

Experience, Training, Qualifications and Competence

3 Requirements

PART 1

Management System

4 Development

5 Requirements

6 Human resources

7 Implementation

8 Continual improvement

PART 2

Authorization

Application

9 Documents and information

10 Safety plan

11 Environmental protection plan

12 Contingency plan

13 Spill-treating agent — section 138.21 of Act

14 Field data acquisition program

15 Flow system, calculation and allocation

16 Decommissioning and abandonment plan

Well Approvals

17 Well operation

18 Well data acquisition program

19 Well verification scheme

20 Suspension of well approval

21 Revocation of well approval

22 Suspension or abandonment of well

Development Plan

23 Well approval — subsection 139(1) of Act

24 Concept safety analysis

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

PART 3

Certificate of Fitness

Application

26 Prescribed installations — section 139.2 of Act

Requirements for Certification

27 Issuance of certificate — requirements and conditions

28 Conflict of interest — subsection 139.2(4) of Act

29 Certification plan

30 Scope of work

31 Certification period — five years

32 Applicable site or region

33 Renewal of certificate

34 Revalidation — scope of work

35 Invalidity

Change of Certifying Authority

36 Before initial certificate

Administrative Requirements

37 Organizational structure

38 Annual report

PART 4

General Requirements for Authorized Works and Activities

General

39 Safety and protection of environment

40 Physical and environmental conditions

41 Location of infrastructure or equipment

42 Accessibility, storage and handling of consumables

43 Storage and handling of chemical substances

44 Tampering with equipment

45 Cessation of work or activity

Document Availability

46 Copy of authorization and other documents

47 Emergency response procedures and other documentation

Plans

48 Implementation

PART 5

Geoscientific Programs, Geotechnical Programs and Environmental Programs

Equipment, Materials and Property

49 Measures

50 Certification

51 Damage to property

Energy Sources

52 General requirements

53 Testing of energy sources

Primary Vessel

54 Classification

Destruction, Discard or Removal

55 Destroy, discard or remove from Canada

PART 6

Drilling and Production

General

56 Definition of termination

57 Spacing and production rates

58 Name, classification or status of well

59 Pool, zone or field

Evaluation of Wells, Pools and Fields

60 Implementation of data acquisition programs

61 Formation testing and sampling

62 Formation flow test

63 Samples and cores

64 Remaining conventional core

65 Notice before disposal

Location of Wells

66 Reference for well depth

67 Directional and deviation surveys

Well Integrity

68 Well control

69 Casing and cementing

70 Formation leak-off or integrity test

71 Completion, testing and operation

72 Production tubing

73 Safe operations and production

Measurements

74 Flow, volume and quantity

75 Allocation of group production

76 Testing and maintenance

77 Calibration

78 Proration tests

Production Conservation

79 Resource management

80 Commingled production

81 Pilot scheme

82 Prohibition against flaring or venting

83 Venting limit

84 Prohibition against oil burning

Spill-treating Agent

85 Small-scale test — paragraph 161.1(1)(b) of Act

86 Factors — subsection 161.1(3) of Act

87 Variation of approval

Well Termination

88 Conditions for suspension or abandonment

89 Additional condition for suspension

90 Additional condition for abandonment

91 Conditions for drilling installation removal

PART 7

Diving Projects

92 Definition of light dive craft

93 Vessel used in diving project

94 Dynamic positioning system

95 Light dive craft

PART 8

Installations, Wells, Pipelines and Vessels

Installations

General

96 Definitions

97 Safety and environmental protection

98 Design of installation — certification plan

Quality Assurance

99 Quality assurance program

Work Permits

100 Requirements

101 Operator obligations

Design Analysis and Risk Assessment

102 Innovations

103 Physical and environmental conditions

104 Design for intended use and location

105 Conditions for safe operation and survival

106 Risk assessment — fire, explosion and hazardous gas

107 Reliability and availability

Installations — Design, Transportation, Arrangement and Other Requirements

108 Monitoring program for environment

109 Maintenance

110 Materials for installations

111 Passive fire and blast protection

112 Hazardous and non-hazardous areas

113 Ventilation of enclosed hazardous areas

114 Ignition prevention

115 Safe means of escape, evacuation and rescue

116 Exits, access and escape routes

117 Life-saving appliances for installation

118 Design for removal of installation

119 Transportation and positioning

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

120 Electrical system

121 Control systems — certification plan

122 Integrated software-dependent control systems

123 Emergency electrical power supply

124 Navigation lights and sound-signalling appliances

125 Communication system

126 General alarm system

127 Gas release system

128 Fire and gas detection system

129 Emergency shutdown system

130 Fire protection systems and equipment

131 Boilers and pressure systems — certification plan

132 Mechanical equipment — certification plan

133 Materials handling equipment

134 Subsea production system — certification plan

135 Temporary or portable equipment

Platforms — Additional Requirements

136 Classification

137 Air gap

138 Stability

139 Assessment — self-elevating mobile offshore platform

140 Ballast and bilge systems

141 Watertight and weathertight integrity and freeboard — Codes

142 Station-keeping

143 Mooring system design

144 Disconnectable mooring system

145 Dynamic positioning system design

146 Disconnect system

147 Decisions and exemptions

Asset Integrity

148 Requirements

149 Non-destructive examination

150 Winterization

151 Corrosion management

Operation and Maintenance

152 Limits and requirements

153 Operations manual

154 Programs

155 Maintenance program

156 Preservation program

157 Weight control program

158 Notice of repair, replacement and modification

Wells

159 Drilling fluid systems

160 Drilling riser

161 Fail-safe subsurface safety valve

162 Well tubulars, trees and wellheads

163 Formation flow test equipment

Pipelines

164 Pipeline integrity — standard

Monitoring of Installations, Wells and Pipelines

165 Monitoring of systems

166 Notice of deterioration — Chief Safety Officer

PART 9

Support Operations

167 Support craft

168 Support craft — availability and equipment

169 Rescue boat

170 Safety zone — installation

171 Landing area

172 Aircraft service provider

173 Classification

PART 10

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

General

174 Definition of shotpoint

175 Reportable incidents

176 Accessibility of records

177 Critical information

178 Safety report

179 Annual reports

Geoscientific, Geotechnical and Environmental Programs

180 Notice — key dates

181 Weekly status reports

182 Environmental report — programs

183 Final reports

184 Final interpretation report not required

185 Data purchases

Drilling and Production

186 Reference

187 Results, data, analysis and schematics

188 Survey

189 Survey plan

190 Critical information

191 Daily production record

192 Formation flow test report

193 Pilot scheme report

194 Daily reports

195 Monthly production report

196 Well reports and other information

197 Environmental report — drilling

198 Annual environmental report — production and pipeline

199 Annual production report

200 Gas venting records

201 Compressor records

202 Fugitive emission records

203 Record retention period

Diving Projects or Construction Activities

204 Weekly status reports

PART 11

Repeals and Coming into Force

205 Repeals

Coming into Force

206 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

Interpretation

Definitions

1 (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 one 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, office areas 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 the 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 in combination with other barrier elements forms a well barrier. (élément de barrière)

barrier envelope

means an envelope of one or more barrier elements that prevents fluids from flowing unintentionally from the formation into the well-bore, another formation or the environment. (enveloppe de barrière)

certificate of fitness

means a certificate issued by a certifying authority in accordance with Part 3. (certificat de conformité)

certifying authority

means the American Bureau of Shipping, Bureau Veritas, Det norske Veritas or Lloyd’s Register Canada Limited. (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, used in oil or gas activities in locations with similar physical and environmental conditions. (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 at which a control system that is critical to the operation of an installation or a pipeline, to safety and to the prevention of waste and pollution is located. (centre de contrôle)

control system

means any system, station or panel used to monitor the status and control the operation of the equipment used for or in support of the drilling for, or the production, processing or transportation of, petroleum, including any system, station or panel used to control the operation of an installation. (système de contrôle)

decommissioning and abandonment

means the process for the cessation of operations, the controlled abandonment of all wells and the retirement from service and the abandonment or removal of all installations, including their systems and equipment, as well as of pipelines and materials, as required by the legislation and regulations, the applicable authorization and any approved development plans. (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 a diving system installed on and integrated into an installation or vessel. (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 required to execute a dive, including compression and decompression, and the equipment for rescue and recovery. (système de plongée)

drill site

means a location where a drilling rig is or is proposed to be installed. (emplacement de forage)

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 platform fixed to the seabed and any other foundation specifically used for drilling — and any accommodations area. (installation de forage)

drilling program

means a program for the drilling of one or more wells within a specified area and time 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 a rig that consists of the equipment used to conduct well operations and associated systems, including power, control 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 systems and equipment installed on the platform or vessel that are related to well operations and marine activities. (unité de forage)

environmental load

means a load imposed by climate, winds, waves, tides, currents, ice conditions, regional ice features such as sea ice and icebergs, snow, a seismic event or any other naturally occurring phenomenon. (charge environnementale)

environmental program

means a program pertaining to the measurement or statistical evaluation of the physical, chemical and biological elements of the lands, oceans or coastal zones, including winds, waves, tides, currents, precipitation, ice cover and movement, icebergs, pollution effects, flora and fauna, both onshore and offshore, human activity and habitation and any related matters. (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 to fields that are using a common storage or processing facility. (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 that is used to transport fluids between a well and the equipment for the production of petroleum located at a production site and the systems and equipment that are used in support of production, including all gathering lines but not including pipelines. (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 the surface of a well 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 a program that involves any geological or geophysical work or activity. (programme géoscientifique)

geotechnical program

means a program that involves any work or activity undertaken to determine the physical properties of materials recovered from the seabed or shallow subsurface, in order to assess the suitability of the seabed or shallow subsurface, as the case may be, to support installations or any other structures. (programme géotechnique)

life-saving appliances

includes lifebuoys, survival craft, launching and embarkation appliances, marine evacuation systems and visual signals, as provided for in the LSA Code. (engins de sauvetage)

LSA Code

means the annex to International Maritime Organization Resolution MSC.48(66), International Life-Saving Appliance (LSA) Code. (recueil LSA)

load

includes a functional load, environmental load, accidental load and abnormal load. (charge)

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 activity

means any activity related to stability, station-keeping and collision avoidance of floating platforms, and includes mooring, dynamic positioning and ballasting. (activité maritime)

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 under paragraph 138(1)(b) of the Act. (exploitant)

physical and environmental conditions

means any physical, geotechnical, seismic, oceanographic, meteorological and ice conditions that might affect an authorized work or activity. (conditions physiques et environnementales)

pipeline

has the same meaning as in the Canadian Standards Association standard Z662, entitled 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 the equipment for the production of petroleum located at a production site, including separation, treating and processing facilities, equipment used in support of production, aircraft landing areas, storage areas or tanks and accommodations areas and any associated platform, artificial island, subsea production system, offshore loading system or equipment used to conduct well operations or systems and equipment related to marine activities. (installation 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 installation. (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 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 any of the following occurrences 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 — critical to the safety of persons ;
• (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, critical to the safety and integrity of an installation or critical to preventing the installation from polluting, including

• (a) any system or equipment
  • (i) that is intended to prevent or limit the effect of a hazard that could cause a major accidental event, or
  • (ii) the failure of which could
    • (A) cause a hazard that could cause a major accidental event, or
    • (B) worsen the effects of such a hazard on the installation; and
• (b) any software and temporary or portable equipment that affects the system or equipment referred to in paragraph (a).

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 production 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. (contrôle d’un puits)

well operation

means an operation related to the drilling, completion, recompletion, re-entry, intervention, workover, suspension or abandonment of a well. (travaux relatifs à un 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 59(a). (couche)

Installation

(2) In these Regulations, any reference to an installation is a reference to a drilling installation, production installation or accommodations installation and, for the purposes of Part 3, also a reference to a diving installation.

Platform

(3) In these Regulations, the requirements that apply in respect of an installation also apply in respect of a platform.

Paragraph 138(4)(c) of Act

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

production facility

means the equipment for the production of petroleum located at a production site, including separation, treating and processing facilities, equipment used in support of production, aircraft landing areas, storage areas or tanks and accommodations areas, but does not include any associated platform, artificial island, subsea production system, drilling equipment or diving system. (installation de production)

production platform

means a production facility and any associated platform, artificial island, subsea production system, offshore loading system, drilling equipment, facilities related to marine activities and dependent diving system. (plate-forme de production)

Prescribed installation — section 193.2 of Act

(5) For the purposes of section 193.2 of the Act, any installation is a prescribed installation.

Incorporation by reference

2 (1) In these Regulations, any incorporation by reference of a document is an incorporation by reference of the most recent version of that document.

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.

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 and in compliance with these Regulations.

Sufficient number

(2) The operator must ensure that the persons referred to in subsection (1) are sufficient in number and receive any necessary supervision to carry out that duty, work or activity in a manner that ensures safety.

PART 1
Management System

Development

4 An operator must develop a management system to reduce safety and environmental risks, prevent pollution and ensure the conservation of petroleum resources.

Requirements

5 (1) For the purposes of meeting the objectives set out in section 4, an operator must ensure that the management system meets the following requirements:

• (a) it must apply to all of the works and activities referred to in the application for authorization;
• (b) it must correspond to the scope, nature and complexity of the works and activities and the associated hazards and risks;
• (c) it must be explicit, comprehensive and proactive;
• (d) it must foster a culture of safety;
• (e) it must establish the conditions under which a person who makes a report that relates to safety or protection of the environment will be protected from reprisal;
• (f) it must include processes for the integration of works and activities and technical systems with the management of human and financial resources;
• (g) it must include processes to ensure that all persons have the necessary experience, training, qualifications and competence and receive any necessary supervision to carry out the duties that they are assigned;
• (h) it must set out the roles, responsibilities and authorities of all persons exercising functions under it, as well as the processes for making those persons aware of their roles, responsibilities and authorities;
• (i) it must include processes for the coordination of the carrying out and management of the works and activities among the operator, employers, suppliers, service providers and other persons that are subject to it;
• (j) it must include processes for the internal and external communication of documents and information relating to safety or the protection of the environment;
• (k) it must include a process for the efficient and immediate transmission, at every shift handover, of documents and information relating to any conditions, mechanical or procedural deficiencies or other problems that may have an impact on safety or the protection of the environment;
• (l) it must include processes
  • (i) for identifying hazards that may occur during routine and non-routine operations,
  • (ii) for assessing the risks associated with identified hazards and reducing the risks through the implementation of control measures, and
  • (iii) for establishing an inventory of identified hazards and of the control measures to reduce the risks associated with those hazards and the methods for maintaining that inventory;
• (m) it must include processes for investigation and reporting, for the purposes of section 175, of the root cause of any reportable incident, the contributing factors and the measures to be implemented to prevent its recurrence;
• (n) it must include a process for the establishment of a system for analyzing trends in hazards and reportable incidents;
• (o) it must include processes for identifying, evaluating and managing safety-critical elements;
• (p) it must include processes for identifying, evaluating and managing any changes that could affect safety, the protection of the environment and the conservation of petroleum resources;
• (q) it must include processes for identifying tasks that are critical to safety, the protection of the environment and the conservation of petroleum resources;
• (r) it must include processes for the establishment and maintenance of measurable goals and performance indicators for it;
• (s) it must include processes for periodic internal audits and reviews of it to identify areas for improvement and the preventive and corrective measures to be taken if deficiencies are identified;
• (t) it must include processes for monitoring compliance and preventing non-compliance with the requirements of these Regulations, the provisions of Part III of the Act and any requirements that are established by the Board under that Part;
• (u) it must include processes for inspection, monitoring, testing and maintenance to ensure the continued integrity of all installations, including their systems and equipment, pipelines and vessels and the corrective measures to be taken if deficiencies are identified;
• (v) it must include the policies and standards on which it is based;
• (w) it must include a process to ensure that all documents associated with it are approved by a person with the necessary authority, periodically reviewed and updated when necessary;
• (x) it must include a process for the establishment of a system for managing any records associated with the management system and the records necessary to support operational and regulatory requirements, for the purpose of ensuring that they are generated, identified, controlled and retained and are readily accessible for consultation and examination; and
• (y) it must include a process for the control and coordination of work, including the issuance of work permits that are required under Part 8 and the identification of the works and activities for which a work permit is required.

Documentation

(2) The operator must document the processes, policies and standards required by this section and ensure that they 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

6 (1) An operator must ensure that an organizational structure is put into place within which there are sufficient human resources to implement and continually improve the management system.

Accountable person

(2) The operator must designate an employee as accountable person for the management system and ensure they have 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 authorization is made and when a new designation is made under subsection (2) or each time any change is made to the name, position or contact information of the accountable person.

Signed statement

(4) The operator must ensure that the accountable person submits to the Board, within 30 days after the day on which they are designated, a signed statement accepting the responsibilities of their position as accountable person.

Implementation

7 (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 the 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

8 The accountable person referred to in subsection 6(2) must ensure that the management system is continually improved while the authorization remains valid.

PART 2
Authorization

Application

Documents and information

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

• (a) the scope of the proposed work or activity;
• (b) an execution plan and schedule for undertaking the proposed work or activity;
• (c) a safety plan that meets the requirements of section 10;
• (d) an environmental protection plan that meets the requirements of section 11;
• (e) a contingency plan that meets the requirements of section 12;
• (f) a description of all the installations, including their systems and equipment, pipelines and vessels proposed to be used, including the layout of the installations;
• (g) in the case of a production project, a field data acquisition program that meets the requirements of section 14;
• (h) in the case of a drilling program or a production project,
  • (i) information on
    • (A) any proposed flaring or venting of gas, including the rationale for flaring or venting and the estimated rate, quantity and period of the flaring or venting, and
    • (B) any proposed burning of oil, including the rationale for burning and the estimated quantity of oil proposed to be burned, and
  • (ii) a decommissioning and abandonment plan that meets the requirements of section 16;
• (i) in the case of a geoscientific program, geotechnical program or environmental program,
  • (i) a map illustrating the location of the program works and activities and their proximity to any man-made structures or vulnerable natural structures, and any territorial or other boundaries,
  • (ii) a description of the methods proposed to be used in carrying out the program works and activities, and
  • (iii) a description of a proposed data acquisition plan;
• (j) in the case of a diving project, the dive project plan required under section 171 of the Canada–Newfoundland and Labrador Offshore Area Occupational Health and Safety Regulations; and
• (k) if applicable, the list, risk assessment and action plan required under section 147.

Safety plan

10 (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 the proposed work or activity, including target levels of safety and measures for hazard management.

Documents and information

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

• (a) a summary of and references to the management system that demonstrate how it will be implemented during the proposed work or activity and how the obligations set out in these Regulations with regard to safety will be fulfilled;
• (b) a document that includes
  • (i) a summary of the studies and a description of the processes to
    • (A) identify hazards related to the proposed work or activity that may occur during routine and non-routine operations, including any hazards posed by any other activities taking place near the proposed work or activity, and
    • (B) assess safety risks associated with the identified hazards,
  • (ii) a description of the identified hazards referred to in clause (i)(A) and the results of the assessments referred to in clause (i)(B),
  • (iii) a summary of the measures to anticipate safety risks related to the identified hazards,
  • (iv) a summary and evaluation of the measures to reduce the safety risks associated with the identified hazards, including, if the possibility of ice hazards exists, measures for ice detection, forecasting, surveillance and reporting, including data collection, and any measures for ice avoidance or deflection, and
  • (v) a summary of the measures to communicate the identified hazards and risk mitigation measures for the safety risks associated with those hazards to all persons who are directly affected;
• (c) a description of the installation or vessel and any system or equipment critical to safety to be used during the proposed work or activity, and a summary of the systems in place for their inspection, testing and maintenance;
• (d) a description of the organizational structure and chain of command for the proposed work or activity that
  • (i) explains the relationship between the organizational structure and chain of command, and
  • (ii) includes the name, position and contact information of the employee who is responsible for the management of the safety plan; and
• (e) a description of the measures for monitoring compliance with the plan and for evaluating performance in relation to its objectives.

Environmental protection plan

11 (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 proposed work or activity, including target levels of safety and hazard management.

Documents and information

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

• (a) a summary of and references to the management system that demonstrate how it will be implemented during the proposed work or activity and how the duties set out in these Regulations with regard to environmental protection will be fulfilled;
• (b) a document that includes
  • (i) a summary of the studies and a description of the processes to
    • (A) identify hazards related to the proposed work or activity that may occur during routine and non-routine operations, including any hazards posed by any other activities taking place near the proposed work or activity, and
    • (B) assess environmental risks associated with the identified hazards,
  • (ii) a description of the identified hazards referred to in clause (i)(A) and the results of the assessments referred to in clause (i)(B),
  • (iii) a summary of the measures to anticipate environmental risks related to the identified hazards,
  • (iv) a summary and evaluation of the measures to reduce the environmental risks associated with the identified hazards, and
  • (v) a summary of the measures for communicating to all directly-affected individuals the identified hazards and risk mitigation measures for the environmental risks associated with those hazards;
• (c) a description of the installation or vessel and any system or equipment critical to the protection of the environment to be used during the proposed work or activity and a summary of the systems in place for their inspection, testing and maintenance;
• (d) in the case of a drilling program or a production project, the procedures for the selection, evaluation and use of chemical substances, including process chemicals and drilling fluid ingredients;
• (e) a description of the equipment and procedures for the treatment, handling and disposal of waste material;
• (f) a description of all the discharge streams and the limits of any discharge into the environment, including any waste material;
• (g) a description of the system for monitoring compliance with the discharge limits identified in paragraph (f), including the sampling and analytical programs to determine if those discharges are within the specified limits;
• (h) a description of the organizational structure and chain of command for the proposed work or activity that
  • (i) explains the relationship between the organizational structure and chain of command, and
  • (ii) includes the name, position and contact information of the employee who is responsible for the management of the environmental protection plan;
• (i) a description of the measures for monitoring compliance with the plan and for evaluating performance in relation to its objectives; and
• (j) a description of the procedure to be followed when an archaeological site or a burial ground is discovered during the proposed work or activity.

Contingency plan

12 (1) An operator must develop a contingency plan that sets out the procedures (including emergency response procedures), 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:

• (a) a method for classifying accidental events and a description of the emergency response procedures for each event;
• (b) the procedures for internal and external reporting;
• (c) the procedures for accessing safety-related and environmental information that is necessary to mitigate the effects of any accidental event;
• (d) the organizational structure, chain of command and resources to manage any accidental event, including
  • (i) a list of key emergency response positions and a description of the roles, responsibilities and authorities associated with each of those positions, including a description of related tasks and checklists of actions that must be taken in the context of the contingency plan,
  • (ii) a description of the available support craft and the contact information for its crew or a reference to the number or title of a document that provides that description and contact information,
  • (iii) a description, or a reference to the number or title of a document that provides that description, of available emergency response equipment — including life-saving appliances — and its location, as well as the limits on its use and mitigation measures in the event that it is not available,
  • (iv) a description, or a reference to a number or title of a document that provides that description, of all available medical equipment and its location,
  • (v) a description of the communication system referred to in section 125 and the operating procedures for that system,
  • (vi) a description of all emergency response operations centres and their location,
  • (vii) a description of any good or service that needs to be obtained on a contractual basis for each response measure, and
  • (viii) a description of the location and the contents of any temporary safe refuges, or a reference to the number or title of a document that provides that description;
• (e) mutual aid arrangements with other operators;
• (f) measures for coordination and liaison with all relevant emergency response organizations;
• (g) communication protocols with appropriate federal, provincial, territorial and municipal agencies or Indigenous governing bodies;
• (h) personnel evacuation plans, including any evacuation plan for divers engaged in a dive; and
• (i) the frequency and scope of emergency response drills and exercises.

Uncontrolled well

(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 stop the flow from an uncontrolled well and to minimize the duration of a spill and its environmental effects, as well as the following documents and information:

• (a) a description of the source control and containment equipment to be used in the event of a loss of well control;
• (b) details of contractual arrangements for the source control and containment equipment, including
  • (i) the name and contact information of the owner or owners of the equipment,
  • (ii) the arrangements for transport of the equipment to the location of the uncontrolled well, and
  • (iii) the arrangements for the mode of deployment of the equipment at the location of the uncontrolled well;
• (c) the schedule and plan for the mobilization, deployment and operation of source control and containment equipment, including measures to minimize deployment time that take required regulatory approvals into consideration;
• (d) details regarding the accessibility to the source control and containment equipment and the documents and information referred to in paragraphs (a) to (c);
• (e) an explanation of the adequacy of each of the source control and containment measures; and
• (f) a description of any support systems and equipment, including vessels, remotely operated vehicles and consumables, such as, in the case of a relief well, a spare wellhead, casing and bulk additives.

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:

• (a) the name of the chosen spill-treating agent and an assessment of its efficacy in treating the potential sources of pollutants, including the results of any tests conducted for the assessment and a description of those tests;
• (b) the results of an analysis that demonstrates that a net environmental benefit is likely to be achieved through the use of the spill-treating agent under certain circumstances;
• (c) a description of the circumstances under which the spill-treating agent will be used and the estimated period within which the use of that spill-treating agent will be effective;
• (d) a description of the methods and protocols, including the amount and application rate, for safe, effective and efficient use of the spill-treating agent;
• (e) the international standard or alternative recognized by the Board on which the spill-treating agent assessment, analysis and the methods and protocols referred to in paragraphs (a) and (b) are based, taking the local environment into account;
• (f) a list of the personnel, equipment and materials that an operator will have available for the use of the spill-treating agent in spill response operations and the details of any contractual arrangements for that personnel and equipment and those materials; and
• (g) a monitoring plan for the use of the spill-treating agent.

Assessment of efficacy

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

Methods and protocols

(6) The methods and protocols referred to in paragraph (4)(d) and the monitoring plan referred to in paragraph (4)(g) 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

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

Spill-treating agent — section 138.21 of Act

13 For the purpose of section 138.21 of the Act, the following are the factors that the Board must take into consideration to determine whether the use of a spill-treating agent is likely to achieve a net environmental benefit:

• (a) the assessment of the spill-treating agent’s efficacy required under paragraph 12(4)(a);
• (b) the circumstances referred to in paragraph 12(4)(b);
• (c) the circumstances described under paragraph 12(4)(c);
• (d) the methods and protocols described under paragraph 12(4)(d); and
• (e) the monitoring plan required under paragraph 12(4)(g).

Field data acquisition program

14 In the case of a production project, an operator must develop a field data acquisition program that allows for the collection of sufficient pool pressure measurements, drill cutting and fluid samples, cores, well logs, formation flow tests, analyses and surveys to enable a comprehensive assessment of the field, the performance of development wells and pool depletion and injection schemes and provides for the quantity of samples and cores, the evaluation data and any associated analyses, surveys and reports that will be provided to the Board.

Flow system, calculation and allocation

15 (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.

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 allocate, on a pool or zone basis, the production from and injection into individual wells.

Decommissioning and abandonment plan

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

• (a) a description of the safety and environmental protection measures to be implemented during decommissioning and abandonment to comply with the requirements of these Regulations, the provisions of Part III of the Act and any federal or provincial legislation or international conventions or agreements relating to safety and the protection of the environment;
• (b) a description of the potential effects of the decommissioning and abandonment on the environment and on any other uses of the site;
• (c) the methods for restoration of the site after the decommissioning and abandonment; and
• (d) the forecasted costs of decommissioning and abandonment and the manner in which the operator will finance or pay for those costs.

Costs and financing or payment

(2) The operator must submit to the Board any update on the forecasted costs of decommissioning and abandonment and the manner in which the operator will finance or pay for the costs of decommissioning and abandonment, but, beginning not later than five years before the day on which the decommissioning and abandonment is forecasted to begin, the operator must submit to the Board annual updates of the forecasted costs and the manner in which the operator will finance or pay for those costs.

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, slick line, coiled tubing or similar operation through a tree located above sea level if the following conditions are met:

• (a) the operation does not alter the completion interval or is not expected to adversely affect the recovery of petroleum; and
• (b) the equipment, operating procedures and qualifications of the persons carrying out the work are in compliance with the requirements of the authorization.

Approval application contents

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

• (a) if the well approval sought is to drill a well,
  • (i) a comprehensive description of the drilling program, a geoscientific description of the potential production area and a description of any geohazard,
  • (ii) the digital data necessary to allow for an independent geohazard assessment,
  • (iii) a description of the well data acquisition program referred to in section 18, and
  • (iv) a description of the well verification scheme referred to in section 19;
• (b) if the well approval sought is to perform a workover on, re-enter, complete or recomplete a well or suspend or abandon a well or a part of it, a description of that well or that part of it, the proposed work or activity and the rationale for carrying it out, including barrier envelope diagrams to demonstrate two barrier envelopes throughout the operation;
• (c) if the well approval sought is to complete a well, in addition to the requirements under paragraph (b), information that demonstrates that section 71 will be complied with;
• (d) if the well approval sought is to suspend a well or a part of it, in addition to the requirements under paragraph (b), an indication of the period within which the suspended well or part of it will be abandoned or completed; and
• (e) if the well approval sought is to suspend or abandon a well or a part of it, in addition to the requirements under paragraph (b) and, in the case of suspension, paragraph (d), the methods for verifying the isolation of zones required by paragraph 88(1)(a).

Well approval granted by the Board

(4) 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.

Definitions

(5) The following definitions apply in this section.

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)

Well data acquisition program

18 In the case of a drilling program, an operator must develop a well data acquisition program that allows for the collection of sufficient pressure measurements, drill cutting and fluid samples, conventional cores, sidewall cores, well logs, formation flow tests, analyses and surveys to enable a comprehensive geophysical, geological and reservoir evaluation to be made and provides for the quantity of samples and cores, the evaluation data and any associated analyses, surveys and reports that will be provided to the Board.

Well verification scheme

19 (1) An operator must establish a well verification scheme based on criteria that it establishes to ensure that the design of any well is in accordance with industry standards and best practices to ensure its integrity 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 its ranking and to any changes made to the design during its construction or operation that would affect any previously undertaken verification.

Additional verification requirements

(4) The operator must ensure that the verification requirements referred to in subsection (3) 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

• (a) the operator fails to comply with the well approval;
• (b) the physical and environmental conditions encountered in the area of the work or activity for which the well approval was granted are more severe than those specified by the manufacturer to establish the equipment’s operating limits; or
• (c) the operator fails to comply with the approvals granted by the Board under subsection 15(2), 62(5) or 80(2) respecting the flow system, formation flow tests or commingled production.

Factors for suspension

(2) In deciding whether to suspend an approval in accordance with subsection (1), the Board must take into consideration the following factors:

• (a) whether suspension of the approval is necessary because the work or activity cannot be carried out safely, without creating waste or causing pollution;
• (b) whether suspension of the approval is unnecessary because corrective measures have been taken or will be taken to ensure that the work or activity can be carried out safely, without creating waste or causing pollution; and
• (c) whether there has been non-compliance with the requirements of these Regulations, the provisions of Part III of the Act or any requirements that are established by the Board under that Part with respect to well operations.

Revocation of well approval

21 The Board must revoke a well approval if

• (a) the operator fails to remedy the situation that caused the suspension of the well approval as soon as the circumstances permit within 60 days after the date of that suspension unless, on written request of the operator, the Board grants the operator an extension of time to remedy the situation; or
• (b) the operator continues to operate the well despite the suspension of the well approval.

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 6.

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) An operator must, at the time it applies for a development plan approval under section 139 of the Act, submit to the Chief Safety Officer a concept safety analysis.

Content of concept safety analysis

(2) The concept safety analysis must

• (a) be based on the development concept chosen by the operator as a general approach and described in Part I of the development plan;
• (b) take into consideration all works and activities associated with each phase in the life cycle of the development;
• (c) determine target levels of safety that are to be achieved to ensure safety and the protection of the environment for all works and activities within each phase of the life cycle of an installation, from its design up to and including its decommissioning and abandonment, including its systems and equipment;
• (d) identify all hazards having the potential to cause a major accidental event;
• (e) include a systematic assessment of the unmitigated risks associated with each of the identified hazards, including the likelihood of a major accidental event occurring and the consequences that would result;
• (f) identify all assumptions and control measures that are to be implemented to reduce the risks associated with the identified hazards to a level that is as low as reasonably practicable; and
• (g) identify the effects of any additional risks that may result from the implementation of the identified control measures.

Quantitative and qualitative risk assessments

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

• (a) quantitative, if it can be demonstrated that input data are available in the quantity and are of the quality necessary to demonstrate the reliability of the results; or
• (b) qualitative, if quantitative assessment methods are inappropriate or if the quantitative data is not reliable.

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

• (a) the physical and environmental conditions;
• (b) the operating conditions and the limits taken into consideration in the design assumptions; and
• (c) the operating procedures.

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 of the development to

• (a) account for the circumstances described in subsection (4); and
• (b) ensure the ongoing suitability of the control measures to maintain risks at a level as low as reasonably practicable.

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 include a resource management plan.

Contents of resource management plan

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

• (a) the geological setting and features of the field and of each pool or petroleum-bearing reservoir;
• (b) the petrophysical data and analytical procedures for each pool and the reservoir engineering data;
• (c) estimates of in-place resources and recoverable reserves for each pool, for each fault block and for each reservoir subdivision;
• (d) the proposed reservoir exploitation scheme;
• (e) potential developments and the reasons why they are not included in the proposed development of the field or pool;
• (f) any past drilling in the area related to the proposed development of the field or pool as well as the proposed drilling program and typical completion designs for the development wells;
• (g) the production and export systems related to the proposed development of the field or pool;
• (h) the expected overall operating efficiency and reliability of the proposed development of the field or pool; and
• (i) past expenditures and predicted capital and operating cost data, in sufficient detail to permit an economic analysis of the proposed development of the field or pool.

Organizational chart

(3) The resource management plan must also contain a description of the organizational structure for the proposed work or activity.

PART 3
Certificate of Fitness

Application

Prescribed installations — section 139.2 of Act

26 For the purposes of section 139.2 of the Act, a production installation, drilling installation, accommodations installation or diving installation is prescribed as an installation.

Requirements for Certification

Issuance of certificate — requirements and conditions

27 (1) Before a certifying authority issues a certificate of fitness in respect of an installation referred to in section 26,

• (a) the person that applies for the certificate must
  • (i) provide the certifying authority with all the information it requires in relation to the application for certification, such as design specifications for the installation, including its systems and equipment,
  • (ii) conduct or assist the certifying authority in conducting any inspection, test or survey required by the certifying authority,
  • (iii) except in the case of a diving installation, submit to the certifying authority for approval a maintenance program that meets the requirements set out in section 155 and a weight control program that meets the requirements set out in section 157, and
  • (iv) in the case of a diving installation, submit a maintenance program to the certifying authority for approval;
• (b) the certifying authority must determine that, in relation to the production site, drill site or the region in which the particular installation is to be operated,
  • (i) the installation, including its systems and equipment, is fit for the purposes for which it is to be used and can be operated without posing a threat to persons or the environment,
  • (ii) in the case of an installation other than a diving installation, the requirements set out in the following provisions have been met:
    • (A) the provisions of these Regulations listed in Part 1 of Schedule 1, and
    • (B) the provisions of the Canada–Newfoundland and Labrador Offshore Area Occupational Health and Safety Regulations listed in Part 2 of Schedule 1, other than paragraph 22(5)(b), subsection 28(3), paragraph 28(5)(a), subsection 171(3) and paragraphs 172(1)(a), (g), (j) to (m), (o) and (p), (2)(e) and (3)(c) and (f),
  • (iii) in the case of a diving installation, the requirements set out in the following provisions have been met:
    • (A) subsections 171(1), (3) and (4) and the provisions of Part 7, and
    • (B) the provisions of the Canada–Newfoundland and Labrador Offshore Area Occupational Health and Safety Regulations listed in Part 2 of Schedule 1, and
  • (iv) the installation, including its systems and equipment, will continue to meet the requirements set out in subparagraph (i) and the applicable requirements set out in subparagraph (ii) or (iii), as the case may be, for the time set out in the certificate of fitness if
    • (A) the installation — other than a diving installation — including its systems and equipment, are inspected, monitored, tested and maintained in accordance with the maintenance program and maintained in accordance with the weight control program submitted to the certifying authority under subparagraph (1)(a)(iii), or
    • (B) the diving installation, including its systems and equipment, are maintained in accordance with the maintenance program under subparagraph (1)(a)(iv);
• (c) the certifying authority must
  • (i) in the case of an installation other than a diving installation, determine that the maintenance program and the weight control program are adequate to ensure the continued integrity of the installation, including its systems and equipment, and approve them; and
  • (ii) in the case of a diving installation, determine that the maintenance program is adequate to ensure the continued integrity of the installation, including its systems and equipment, and approve it; and
• (d) the certifying authority must carry out the scope of work in respect of which the certificate of fitness is issued.

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 by 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 or subsection 205.069(1) of the Act.

Limitations

(3) The certifying authority must endorse on 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 — subsection 139.2(4) of Act

28 (1) For the purposes of subsection 139.2(4) of the Act, the following is the extent to which a certifying authority or one of its subsidiaries may participate in the design, construction or installation of an installation in respect of which a certificate of fitness is issued:

• (a) the certifying authority or its subsidiary may participate as the certifying authority or classification society for the original design, construction or installation of the installation and any modification to it; and
• (b) the subsidiary may participate other than as the certifying authority or classification society if it does not participate in the certification or verification activities.

Notice of non-compliance

(2) The certifying authority must monitor for and identify any non-compliance with subsection (1) and must, without delay, inform the person that applied for the certificate and the Board of any non-compliance.

Certification plan

29 (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 30.

Compliance

(2) The certification plan must demonstrate how compliance with subparagraph 27(1)(b)(ii) or (iii) will be achieved.

Other information

(3) Subject to subsection (4), the certification plan must also include the following documents and information:

• (a) a description of the installation that is to be certified, including its systems and equipment;
• (b) a list of all safety critical elements, as well as a description of how the associated performance standards are to be developed;
• (c) the measures to be implemented to reduce safety and environmental risks to a level that is as low as reasonably practicable in respect of
  • (i) the design of an installation, including its systems and equipment, for the purposes of section 98,
  • (ii) the design and operation of an installation that is to be operated in a cold climate, for the purposes of subsections 103(5) and (6),
  • (iii) the design, arrangement, installation and maintenance of barriers, for the purposes of subsections 111(4) and (5),
  • (iv) the design of any control system, for the purposes of subsection 121(1),
  • (v) the design, selection, location, installation, commissioning, protection, operation, inspection and maintenance of mechanical equipment, for the purposes of paragraph 132(1)(a),
  • (vi) the design, construction, installation, commissioning, operation, inspection, monitoring, testing and maintenance of a subsea production system under all foreseeable physical and environmental conditions and operating conditions for all modes of operation, for the purposes of subsection 134(1),
  • (vii) the management of temporary or portable equipment without compromising the ability to achieve the target levels of safety set out in the safety plan and environmental protection plan, for the purposes of subsection 135(3), and
  • (viii) the arrangement and specification of watertight and weathertight appliances, for the purposes of subsection 141(4);
• (d) the measures to be implemented in respect of
  • (i) the design and location of any vent used into release gas to the atmosphere without combustion in order to minimize the risk of accidental ignition of gas, for the purposes of subsection 127(8), and
  • (ii) the design, selection, operation, inspection, testing and maintenance of fire protection systems and equipment in order to minimize the risk of hazards to persons who use those systems and equipment, for the purposes of subsection 130(2),
  • (iii) the design of boilers and pressure systems in order to minimize the risk of hazards to the installation and persons on it and to any other installations, vessel or persons in proximity to the installation, for the purposes of subsections 131(1) and (2),
  • (iv) the design and maintenance of a disconnectable mooring system to ensure that the risk of the system failing to safely disconnect while exposed to situations that would exceed the associated platform’s structural limits or the system’s design limits is reduced to a level that is as low as reasonably practicable, without compromising the ability to achieve the target levels of safety set out in the safety plan and environmental protection plan, for the purposes of subsection 144(2);
• (e) any measures that the operator intends to implement to reduce safety and environmental risks to a level that is as low as reasonably practicable in respect of the design of the installation, including its systems and equipment, in addition to the measures referred to in paragraphs (c) and (d); and
• (f) a list of the standards that will apply to the installation to be certified, including its systems and equipment, and a list of standards on which the measures referred to in paragraphs (c) to (e) are based or, in the event that no standard is applicable, any studies and analyses that demonstrate that the measures to be implemented are adequate to reduce the risks to safety and the environment to a level that is as low as reasonably practicable or to minimize the risk of hazards, as the case may be.

Non-application

(4) Paragraphs (3)(b) to (d) do not apply in the case of a diving installation.

Scope of work

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

Contents of scope of work

(2) The scope of work must include

• (a) a description of the following activities to be conducted by the certifying authority:
  • (i) activities to verify compliance with the requirements set out in paragraph 27(1)(b),
  • (ii) activities to verify the validity of the certificate of fitness, and
  • (iii) any additional activities to be carried out before the renewal of the certificate; and
• (b) a schedule of the activities referred to in paragraph (a).

Approval of scope of work

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

• (a) in the case of any installation,
  • (i) it is sufficiently detailed to permit the certifying authority to determine whether the requirements set out in paragraph 27(1)(b) are met,
  • (ii) it describes the type and extent of reporting in respect of continual monitoring of the certification process being undertaken by the certifying authority, and
  • (iii) it demonstrates how the certifying authority has met the requirements set out in section 28;
• (b) in the case of an installation other than a diving installation,
  • (i) it provides the means for determining whether
    • (A) the environmental criteria for the region or site and the loads estimated for the installation are correct,
    • (B) the list of safety-critical elements included in the certification plan is complete and the elements are in place and functioning as intended,
    • (C) in respect of any installation referred to in a development plan, the concept safety analysis required by section 24 meets the requirements of that section,
    • (D) in respect of a new installation, the installation has been constructed in accordance with the quality assurance program referred to in section 99,
    • (E) the operations manual meets the requirements set out in section 153, and
    • (F) the installation’s construction and installation, including the materials used for those purposes, meet the design specifications,
  • (ii) it includes the list of performance standards and methods that the certifying authority will use to verify compliance with those standards and verify whether the installation, including its systems and equipment, continues to be fit for the purposes for which it is to be used, and
  • (iii) it provides the means for determining whether the requirements set out in the provisions listed in Schedule 2 to these Regulations have been met and, in the case of structures, systems and equipment referred to in those provisions, that they are in place and function as expected; and
• (c) in the case of a diving installation, it provides the means for determining whether the requirements of subparagraph 5(1)(l)(iii) and paragraph 5(1)(u) have been met.

Certification period — five years

31 (1) A certificate of fitness is valid for five years if the certifying authority determines that the requirements of paragraph 27(1)(b) will be met for a period of at least five years.

Certification period — less than five years

(2) If the certifying authority determines that the requirements of paragraph 27(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 endorse on the certificate of fitness its expiry date, which is to be calculated from the date of its issuance.

Extension of period of certification

(4) The certifying authority may, on request of the person to which a certificate of fitness has been issued, extend the validity of that 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

32 (1) A certifying authority must endorse 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 endorsed on it.

Renewal of certificate

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

• (a) the activities outlined in the scope of work under subparagraph 30(2)(a)(iii) have been carried out;
• (b) the certifying authority determines the requirements set out in paragraph 27(1)(b) have been met; and
• (c) the certifying authority has revalidated the scope of work in accordance with the requirements set out in section 34.

Revalidation — scope of work

34 (1) Before renewing a certificate of fitness, the certifying authority must revalidate the scope of work in accordance with the criteria referred to in subsection 30(3) and make any modifications that are necessary.

Revalidation — new circumstances

(2) The Chief Safety Officer must request that the certifying authority revalidate the scope of work if new circumstances such as the following arise that have or could have a significant impact on the scope of work:

• (a) these Regulations or the Canada–Newfoundland and Labrador Offshore Area Occupational Health and Safety Regulations have been amended since the scope of work was approved or last revalidated;
• (b) new information regarding a major accidental event that occurred in any place has been disclosed;
• (c) amendments have been made to any of the standards on which the certification was based; and
• (d) the installation has transitioned from one life cycle phase to another.

Revalidation approval

(3) The revalidated scope of work must be submitted to the Chief Safety Officer for approval under section 30.

Invalidity

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

• (a) the certifying authority or the Chief Safety Officer determines
  • (i) that any of the information submitted under subparagraph 27(1)(a)(i) was incorrect and the certificate of fitness was issued on the basis of that information,
  • (ii) that any of the requirements set out in paragraph 27(1)(b) is no longer being met, or
  • (iii) that any limit endorsed on the certificate of fitness under subsection 27(3) has not been respected; or
• (b) the Chief Safety Officer determines that the certifying authority has failed to carry out the scope of work relating to the installation in respect of which the certificate of fitness was issued.

Notice in writing

(2) At least 30 days before a determination is made under subsection (1), notice must be given in writing

• (a) in the case of a determination to be made by the certifying authority, by the certifying authority to the Chief Safety Officer and to the person to which the certificate of fitness in respect of which the determination is to be made has been issued; and
• (b) in the case of a determination to be made by the Chief Safety Officer, by the Chief Safety Officer to the certifying authority and to the person to which the certificate of fitness in respect of which the determination is to be made has been issued.

Consideration of information

(3) Before making a determination under 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

Before initial certificate

36 (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 purposes of issuing the certificate of fitness.

After issuance of certificate

(2) If the person to which a certificate of fitness has been issued decides to change the certifying authority in relation to an installation, the person must

• (a) notify the Chief Safety Officer as soon as the circumstances permit;
• (b) develop and submit to the Chief Safety Officer a transition plan outlining all of the activities to be carried out before transitioning from the outgoing certifying authority to the incoming certifying authority and demonstrating that there will not be any gaps, delays or negative effects on the extent and quality of the verification activities as a result of the transition from one certifying authority to another; and
• (c) ensure that the incoming certifying authority has submitted for approval to the Chief Safety Officer, in accordance with section 30, a new scope of work before the commencement of transition activities.

Transition plan implementation

(3) The person to which a certificate of fitness has been issued 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.

Administrative Requirements

Organizational structure

37 The 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.

Annual report

38 (1) The certifying authority must submit to the Board, the Federal Minister and the Provincial Minister an annual report on all of its certification activities.

Contents of annual report

(2) The annual report must contain the following information:

• (a) a summary of the certification activities the certifying authority carried out as a certifying authority under the Act; and
• (b) proof of its technical capabilities and experience as a certifying authority.

Monthly reports

(3) The certifying authority must submit a monthly report to the Board that describes the certification activities it carried out during the preceding month in respect of certificates of fitness that are applicable in the offshore area.

Information and documents to Board

(4) 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

(5) The certifying authority must retain records, including the technical drawings, for any activity carried out during its certification or verification activities in respect of an installation for a minimum of seven years after the expiry date of the last certificate of fitness issued for that installation.

PART 4
General Requirements for Authorized Works and Activities

General

Safety and protection of environment

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

• (a) the safety of persons at an operations site or on a support craft has priority, at all times, over any work or activity at the operations site or on the support craft;
• (b) safe work methods are adopted;
• (c) differences in language or other barriers to effective communication do not jeopardize safety or the protection of the environment;
• (d) if there is a loss of well control, all other wells at that installation are shut in until the well that is out of control is secured;
• (e) any equipment that is necessary for safety and the protection of the environment is available and in a condition to perform as expected at all times;
• (f) fires can be controlled and extinguished and any related hazard to safety or the environment is minimized;
• (g) the administrative and logistical support that is provided for any work or activity includes accommodation and transportation and storage and repair facilities that are fit for the purposes for which they are to be used;
• (h) any operations site is equipped with a communication system that meets the requirements set out in subsection 125(1);
• (i) any operating procedure that creates a hazard to safety or the environment is corrected; and
• (j) all affected persons are informed of any correction made under paragraph (i).

Physical and environmental conditions

40 An operator must ensure that observations of physical and environmental conditions and forecasts of those conditions, including sea states and ice movements, are obtained and recorded every day and each time there are substantial changes between the observations and the forecasts, and are maintained at an operations site.

Location of infrastructure or equipment

41 An operator must have data or information that accurately describes the location of any infrastructure or equipment on or attached to the seabed, including any abandoned installation or part of it.

Accessibility, storage and handling of consumables

42 An operator must ensure that explosives, fuel, spill-treating agents, spill containment products, safety-related chemicals, drilling, completion and well stimulation fluids, cement and other consumables are

• (a) readily accessible and stored in quantities that are sufficient for normal conditions and any emergency situation; and
• (b) stored and handled in a manner that minimizes their deterioration and does not create a hazard to safety or the environment.

Storage and handling of chemical substances

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

Tampering with equipment

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

Cessation of work or activity

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

• (a) endangers or is likely to endanger the safety of any other work or activity;
• (b) endangers or is likely to endanger the safety or integrity of any operations site or well; or
• (c) causes or is likely to cause pollution.

Condition for resumption

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

Document Availability

Copy of authorization and other documents

46 (1) An operator must keep a copy of an authorization and other related approvals and plans required under the provisions of these Regulations or Part III of the Act at every operations site and ensure that they are readily accessible for consultation or examination.

Display

(2) The operator must ensure that a copy of the authorization and related approvals is displayed in a conspicuous location at every operations site.

Emergency response procedures and other documentation

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

• (a) readily and reliably accessible at every operations site and any emergency response operations centre; and
• (b) usable under all foreseeable circumstances at each location referred to in paragraph (a).

Plans

Implementation

48 (1) An operator must ensure that the safety plan referred to in section 10, the environmental protection plan referred to in section 11 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 12 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 description of installations, vessels, systems and equipment provided in the safety plan and environmental protection plan in accordance with paragraphs 10(2)(c) and 11(2)(c), respectively, must be updated as soon as the circumstances permit after the modification, replacement or addition of any major component.

PART 5
Geoscientific Programs, Geotechnical Programs and Environmental Programs

Equipment, Materials and Property

Measures

49 An operator must ensure that

• (a) all equipment and materials that are necessary to conduct a geoscientific program, geotechnical program or environmental program are handled, installed, inspected, tested, maintained and operated taking into account the manufacturer’s instructions and industry standards and best practices; and
• (b) following an inspection of the equipment and materials, any defective components are repaired without delay or replaced with components that comply with any manufacturer’s recommendations.

Certification

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

Damage to property

51 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

52 (1) An operator must ensure that any energy sources used in a geoscientific program, geotechnical program or environmental program are

• (a) kept free from any substance that could create a hazard; and
• (b) operated in a manner that prevents inadvertent activation of the energy source.

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, if an energy source is used, the program is conducted in a manner that eliminates all safety risks to divers, including by determining the minimum distances required to be maintained between the divers and the energy sources and ensuring compliance with those distances.

Testing of energy sources

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

Energy source activation

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

• (a) those persons are advised that a test will be conducted;
• (b) all equipment is safely secured; and
• (c) any electrical or electromagnetic energy source is fully immersed in water.

Primary Vessel

Classification

54 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

Destroy, discard or remove from Canada

55 (1) It is prohibited for any person to destroy, discard or, subject to subsection (2), remove from Canada the following material or information that was acquired in the context of a geoscientific program, geotechnical program or environmental program unless the Board has approved it in accordance with subsection (3):

• (a) all field data and final processed data in digital format and a description of the data format;
• (b) any samples; and
• (c) all other data, observations, readings and supporting information obtained during the program.

Exception

(2) The material or information referred to in subsection (1) may be removed from Canada without the approval of the Board for the purpose of being processed in a foreign country provided that the material or information is returned to Canada as soon as the processing is complete.

Approval

(3) The Board must, within 60 days after receiving an application for approval to destroy, discard or remove from Canada the material or information referred to in subsection (1), approve the application if the Board is satisfied that the material or information is not of much use or value.

Material or information

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

PART 6
Drilling and Production

General

Definition of termination

56 In this Part, termination means that a well has been abandoned, suspended or completed.

Spacing and production rates

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

Name, classification or status of well

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

Pool, zone or field

59 The Board may

• (a) designate a zone for the purposes of these Regulations;
• (b) give a name to a pool, zone or field and change that name; and
• (c) define the boundaries of a pool, zone or field.

Evaluation of Wells, Pools and Fields

Implementation of data acquisition programs

60 (1) An operator must ensure that the field data acquisition program referred to in section 14 and the well data acquisition program referred to in section 18 are implemented in accordance with good oilfield practices.

Partial implementation of program

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

• (a) a conservation officer is notified as soon as the circumstances permit; and
• (b) the measures to otherwise achieve the goals of the program are submitted to the Board for approval.

Board approval

(3) If the operator demonstrates that the measures referred to in paragraph (2)(b) 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, the Board must approve them.

Periodic updates

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

Formation testing and sampling

61 An operator must ensure that any formation in a well is evaluated, tested and sampled to obtain data and samples from the formation if the Board determines that the data or samples would contribute substantially to the geological and reservoir evaluation.

Formation flow test

62 (1) An operator must ensure that no development well is put into production unless a formation flow test has been approved by the Board under subsection (5) and conducted in accordance with the Board’s approval.

Well operation

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

Conditions

(3) The operator may conduct a formation flow test on a well drilled on a geological feature if, before conducting the test, it

• (a) submits a formation flow test program to the Board; and
• (b) obtains the Board’s approval under subsection (5) to conduct the formation flow test.

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 protection of the environment and in accordance with good oilfield practices and that the test will enable the operator to

• (a) obtain data on the deliverability of the reservoir and productivity of the well;
• (b) establish the characteristics of the reservoir; and
• (c) obtain representative samples of the formation fluids.

Samples and cores

63 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 14 and the well data acquisition program referred to in section 18 are

• (a) stored in durable containers that are correctly labelled for identification;
• (b) transported and stored in a manner that prevents any loss or deterioration; and
• (c) delivered to the Board, in accordance with those programs, within 60 days after the day on which the well is terminated, or, if analyses are ongoing, the samples or cores, or any remaining parts, must be delivered to the Board on completion of the analyses.

Remaining conventional core

64 (1) 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

(2) 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 drill cutting or fluid samples, cores or evaluation data collected, 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

Reference for well depth

66 An operator must ensure that any depth in a well is measured from the rotary table of the drilling rig.

Directional and deviation surveys

67 An operator must ensure that

• (a) directional and deviation surveys are taken at intervals that allow the position of the wellbore to be accurately known during drilling;
• (b) the directional and deviation surveys are adequate to accurately manage the wellbore in respect of identified geohazard, to intersect the geological targets for the well and to intersect the wellbore in the event a relief well is required; and
• (c) except in the case of a relief well, a well is drilled in compliance with internationally recognized wellbore collision avoidance practices and procedures and in a manner that does not intersect an existing well.

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 operator must ensure that reliable well control equipment is in place 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 taken to reduce the risk of shallow hazards while drilling.

Blowout preventer and barrier envelopes

(4) The operator must, after setting the surface casing, ensure that the blowout preventer is installed before drilling out the casing shoe and that there is a minimum of two independent barrier envelopes — each of which to be verified by the operator — in place throughout the life cycle of the well.

Barrier envelope failure

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

Replacement or restoration of barrier envelope

(6) The operator must ensure that

• (a) the replacement or restoration referred to in subsection (5) is completed as soon as the circumstances permit;
• (b) every effort is made for the replacement or restoration to conform to the original design specifications; and
• (c) the barrier envelope is verified after its replacement or restoration.

Drilling fluid column

(7) 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

(8) The operator must ensure that 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

(9) 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 to rectify the situation are taken without delay.

Definition of surface casing

(10) In this section, surface casing means the casing installed in a well to a sufficient depth, in a competent formation, to establish well control for the continuation of the drilling operations.

Casing and cementing

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

• (a) the well can be drilled safely, targeted formations can be evaluated and developed and waste can be prevented;
• (b) the maximum conditions, forces and stresses that may be placed on the casing and wellhead system are withstood; and
• (c) the integrity of gas hydrate and permafrost zones is protected.

Design requirements

(2) The operator must ensure that, during the design of the casing and wellhead system,

• (a) the wellhead’s fatigue life is taken into account; and
• (b) 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 the 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 the duration of well operations does not exceed 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,

• (a) the movement of formation fluids is prevented and, when required for safety, resource evaluation or waste prevention, the isolation of the petroleum and water zones is ensured;
• (b) support for the casing is provided;
• (c) corrosion of the casing over the cemented interval is minimized; and
• (d) the integrity of gas hydrate and permafrost zones is protected.

Pressure testing and logging

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

Other measures

(7) Measures other than those referred to in subsection (6) may be used if the operator can demonstrate that the other measures provide equivalent levels of verification.

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 design provides the expected isolation and the cement 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) After installing and cementing the casing and before drilling out the casing shoe, the operator must ensure that 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 An operator must ensure that

• (a) a formation leak-off test or a formation integrity test is conducted before drilling more than 10 m of new formation below the shoe of any casing other than the conductor casing;
• (b) a formation leak-off test or a formation integrity test is conducted before drilling more than 10 m when sidetracking from the previous casing string; and
• (c) the formation leak-off test or formation integrity test, as the case may be, is 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

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

• (a) the well is completed, tested and operated in a safe manner that allows for maximum recovery of petroleum without waste or pollution throughout the life cycle of the well;
• (b) except in the case of commingled production, each completion interval is isolated from any other porous and permeable interval penetrated by the well;
• (c) if applicable, the production of sand, carbonate or other solids is controlled and does not create a safety hazard or cause waste;
• (d) the setting depth of each packer is as deep as possible and must be such that any leak through the production casing below the packer will be contained by the barrier envelope outside the casing;
• (e) the formation and any annulus seal can withstand the pressures and temperatures expected throughout the life cycle of the well;
• (f) if practicable, any mechanical well condition that may have an adverse effect on the production of petroleum from, or the injection of fluids into, the well is corrected;
• (g) the injection or production profile of the well is improved or the completion interval of the well is changed if it is necessary to do so to prevent waste;
• (h) if different pressure and inflow characteristics of two or more pools might adversely affect the recovery of petroleum from any of those pools, the well is operated as a single pool well or as a segregated multi-pool well;
• (i) during completion operations and before the removal of pressure control equipment and handover for operations, all barrier elements are tested to the maximum pressure to which they are anticipated to be subjected and, if possible, pressure testing is in the direction of flow; and
• (j) following any workover or intervention, any affected barrier elements are pressure-tested.

Segregated multi-pool well

(2) The operator of a segregated multi-pool well must ensure that

• (a) after the well is completed, segregation within and outside the well casing is verified; and
• (b) if there is reason to doubt that segregation is being maintained, a segregation test is conducted as soon as the circumstances permit.

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 for compatibility with the fluids to which it will be exposed, to withstand the maximum conditions, forces and stresses that may be placed on it 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, to allow for safe and controlled well operations and production and to prevent pollution.

Measurements

Flow, volume and quantity

74 (1) Unless otherwise indicated in the approval under subsection 15(2), an operator must ensure that the following are measured:

• (a) the rate of flow and the volume of the fluid that is produced from each well;
• (b) the rate of flow and the volume of the fluid or waste material that is injected into each well; and
• (c) the quantity of disposed fluids.

Requirements for conducting measurements

(2) The operator must ensure that any measurements are conducted in accordance with the flow system, flow calculation procedure and flow allocation procedure approved under subsection 15(2).

Allocation of group production

75 (1) An operator must ensure that group production of oil, gas and water from wells and the injection of fluids into wells is allocated on a pro rata basis, in accordance with the flow system, flow calculation procedure and flow allocation procedure approved under subsection 15(2).

Allocation of production or injection volumes

(2) If a well is completed over multiple pools or zones, the operator must ensure that production or injection volumes for the well are allocated on a pro rata basis to the pools or zones in accordance with the flow allocation procedure approved under subsection 15(2).

Testing and maintenance

76 (1) An operator must ensure that

• (a) meters and associated equipment in the flow system are calibrated and maintained to ensure their accuracy;
• (b) equipment used to calibrate the flow system is calibrated in accordance with good measurement practices; and
• (c) any component of the flow system that may have an impact on the accuracy or integrity of the flow system and that is not functioning in accordance with the manufacturer’s specifications is repaired or replaced without delay or, if it is not possible to do so without delay, corrective measures are taken to minimize the impact on the accuracy and integrity of the flow system while the repair or replacement is in progress.

Notice

(2) The operator must ensure that a conservation officer is notified, as soon as the circumstances permit, of any modification to, 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

77 An operator must ensure that

• (a) a conservation officer is notified at least 30 days before the day on which any transfer meter prover or master meter used in conjunction with a transfer meter is calibrated or as agreed to in writing by the Chief Conservation Officer; and
• (b) following completion of the calibration, a copy of the calibration certificate is submitted to the Chief Conservation Officer as soon as the circumstances permit.

Proration tests

78 In the case of a development well, the operator must ensure that sufficient proration tests are conducted to measure the rates at which fluids are produced from the well to permit an accurate determination of the allocation of oil, gas and water production on a pool and zone basis.

Production Conservation

Resource management

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

• (a) recovery from a pool or zone is maximized in accordance with good oilfield practices;
• (b) wells are located and operated to provide for maximum recovery from a pool or zone; and
• (c) if there is reason to believe that infill drilling or implementation of an enhanced recovery plan might result in increased recovery from a pool or field, studies on those methods are conducted and submitted to the Board.

Commingled production

80 (1) It is prohibited for an operator to engage in commingled production except in accordance with an approval granted under subsection (2).

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 for the determination of commercial production of petroleum from a pool, field or zone accessible from a production installation that has an approved development plan in order to obtain information on reservoir, production or technology performance for the purpose of optimizing production performance under the approved development plan or determining whether the development plan requires an amendment for the purposes of optimization.

Duration

(2) The Board must establish the duration of the pilot scheme based on the time required to achieve the stated objectives.

Completion of pilot scheme

(3) On the completion of the pilot scheme, the operator must ensure that production activities related to the scheme are discontinued.

Prohibition against flaring or venting

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

• (a) the Board authorizes flaring or venting as part of the authorization or permits it in the approval under subsection 62(5); or
• (b) it is necessary in order to remediate an emergency situation that may cause serious risk to human health or safety and the Board is notified, as soon as the circumstances permit, of the flaring or venting and of the volume flared or vented.

Venting limit

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

Capture or venting of emissions

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

• (a) captured and routed to gas conservation equipment or gas destruction equipment; or
• (b) routed to vents that release those emissions into the atmosphere.

Measure of flow rate of emissions

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

Requirements of continuous monitoring device

(4) The continuous monitoring device must

• (a) be calibrated in accordance with the manufacturer’s recommendations such that its measurements have a maximum margin of error of ±10%;
• (b) be operated continuously, other than during periods when it is undergoing normal servicing or timely repairs; and
• (c) be equipped with an alarm that is triggered when the applicable flow rate limit referred to in subsections (5) and (6) for the vents of the compressor is reached.

Centrifugal compressor

(5) The flow rate limit of emissions that are from the vents of a centrifugal compressor on an installation is

• (a) if the compressor is installed before January 1, 2023 and has a rated brake power of
  • (i) greater than or equal to 5 MW, 0.68 standard m³/min, and
  • (ii) less than 5 MW, 0.34 standard m³/min; or
• (b) if the compressor is installed on or after January 1, 2023, 0.14 standard m³/min.

Reciprocating compressor

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

• (a) if the compressor is installed before January 1, 2023, the product of 0.023 standard m³/min and the number of those pressurized cylinders; or
• (b) if the compressor is installed on or after January 1, 2023, the product of 0.001 standard m³/min and the number of pressurized cylinders that the compressor has.

Corrective action

(7) If the alarm referred to in paragraph (4)(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

84 It is prohibited for an operator to burn oil unless

• (a) the Board authorizes burning as part of the authorization or permits it in the approval under subsection 62(5); or
• (b) it is necessary in order to remediate an emergency situation that may cause serious risk to human health or safety and the Board is notified, as soon as the circumstances permit, of the burning and of the amount burned.

Spill-treating Agent

Small-scale test — paragraph 161.1(1)(b) of Act

85 (1) For the purposes of paragraph 161.1(1)(b) of the Act, the following are the requirements for a small-scale test of a spill-treating agent:

• (a) before conducting the test, the operator must obtain the Chief Conservation Officer’s approval;
• (b) during the test, the operator must measure and record the quantity of spill-treating agent applied, monitor the efficacy of the spill-treating agent used in the test and evaluate the factors that affect the efficacy; and
• (c) after the test, the operator must, without delay, submit in writing to the Chief Conservation Officer
  • (i) the volume of oil released and the volume treated,
  • (ii) the quantity of spill-treating agent that was used to conduct the test,
  • (iii) the circumstances present at the time of the test, and
  • (iv) the efficacy of the use of the spill-treating agent.

Conditions

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

• (a) the operator must demonstrate that the quantity of spill-treating agent to be used in the test is the minimum required to evaluate the efficacy of its use; and
• (b) in the case of a request to conduct an offshore subsurface test, the operator must demonstrate that, due to physical and environmental conditions, a surface test cannot be done or its efficacy cannot be readily determined.

Net environmental benefit — subsection 161.1(3) of Act

(3) No small-scale test is to be approved if the Chief Conservation Officer has made a determination under subsection 161.1(3) of the Act regarding the net environmental benefit of that use of the spill-treating agent.

Oral or written approval

(4) Approval of a small-scale test must 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.

Factors — subsection 161.1(3) of Act

86 (1) For the purposes of subsection 161.1(3) of the Act, the following are the factors that the Chief Conservation Officer must take into account to determine whether the use of the agent is likely to achieve a net environmental benefit:

• (a) the assessment of the spill-treating agent’s efficacy required under paragraph 12(4)(a);
• (b) the circumstances referred to in paragraph 12(4)(b);
• (c) the circumstances described under paragraph 12(4)(c);
• (d) the methods and protocols described under paragraph 12(4)(d);
• (e) the monitoring plan required under paragraph 12(4)(g); and
• (f) the results of any small-scale test conducted under subsection 85(1).

Industry standards and best practices

(2) The operator must ensure that the spill-treating agent is used in accordance with industry standards and best practices for spill-treating agent use, taking into consideration the local environment.

Equipment and materials

(3) The operator must ensure that all equipment and materials listed in paragraph 12(4)(f) are available and maintained in accordance with the manufacturers’ specifications and ready for use at all times.

Monitoring plan implementation

(4) The operator must implement the monitoring plan required under paragraph 12(4)(g) at the commencement of the use of a spill-treating agent in the case of a spill.

Chief Conservation Officer to be informed

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

Variation of approval

87 (1) The Chief Conservation Officer must vary its approval to use a spill-treating agent if new information indicates that a modification to its use is necessary for its use to likely achieve a net environmental benefit.

Revocation of approval

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

Well Termination

Conditions for suspension or abandonment

88 (1) An operator that suspends or abandons a well must ensure that the well can be readily located and is left in a condition that

• (a) provides for isolation of all petroleum-bearing zones and discrete pressure zones; and
• (b) prevents any formation fluid from flowing through or escaping from the well-bore.

Isolation before suspension and abandonment

(2) Before suspending or abandoning a well, the operator must ensure that all petroleum-bearing zones and discrete pressure zones have been isolated and verify the effectiveness of the isolation in accordance with the methods set out in its well approval application under paragraph 17(3)(e).

Additional condition for suspension

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

Additional condition for abandonment

90 The operator of a well must ensure that, on the abandonment of that 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

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

• (a) the well has been terminated in accordance with these Regulations; or
• (b) the removal of the drilling installation is for emergency purposes.

PART 7

Diving Projects

Definition of light dive craft

92 In this Part, light dive craft means a small vessel or secondary craft, equipped to deploy divers from a primary vessel.

Vessel used in diving project

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

• (a) the vessel is capable of providing the necessary dive support functions and operating safely;
• (b) the vessel is designed to withstand or avoid, without loss of the overall structural integrity or failure of the main safety functions, all foreseeable site-specific physical and environmental conditions or any foreseeable combination of those conditions;
• (c) the vessel is a Safety Convention vessel, as defined in section 2 of the Canada Shipping Act, 2001, and holds a valid certificate of class issued by a classification society;
• (d) the vessel has a valid class notation for diving issued by the classification society referred to in paragraph (c) if a permanent diving system is installed on it; and
• (e) a competent third party has assessed and certified the sea fastening of equipment for diving that is temporarily installed on the vessel.

Dynamic positioning system

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

• (a) includes safety-critical systems and components with sufficient segregation and redundancy to maintain the vessel’s position in the event that credible scenarios of equipment failure, fire or flooding are realized; and
• (b) has sufficient redundancy to protect divers while diving.

Design

(2) The design of the dynamic positioning system on a vessel used in a diving project must be based on numerical analysis and model testing to ensure that

• (a) it includes systems to monitor the parameters of critical system operability and the integrity of the dynamic positioning system and to provide alerts for critical system faults;
• (b) the vessel’s position reference and directional control can be maintained within specified tolerances to satisfy design operational requirements in relation to all functional loads and environmental loads to which the system may be subjected; and
• (c) for saturation diving, the dynamic positioning system can withstand loss of all its components situated in a single watertight compartment or fire subdivision of the vessel caused from fire or flooding.

Verification

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

Maintenance

(4) The dynamic positioning system must be maintained so that it continues to perform in accordance with its design specifications.

Light dive craft

95 (1) If a light dive craft is used for a diving project, an operator must ensure that

• (a) it is fit for the purposes for which it is to be used; and
• (b) the craft is designed to withstand or avoid, without loss of the overall structural integrity or failure of the main safety functions, all foreseeable site-specific physical and environmental conditions or any foreseeable combination of those conditions.

Equipment and system

(2) The operator must ensure that, when diving takes place from a light dive craft, the dive support vessel

• (a) is fitted with emergency equipment, including a fast rescue boat, that can provide assistance to the light dive craft in any foreseeable emergency situation; and
• (b) has a launch and recovery system for the light dive craft that has been verified and certified by the certifying authority as fit for the purposes for which it is to be used.

PART 8

Installations, Wells, Pipelines and Vessels

Installations

General

Definitions

96 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 facility 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 to the extent determined in accordance with the applicable recommendations 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. (condition endommagée)

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. (zone dangereuse)

IMO Resolution MSC.81(70)

means the annex to International Maritime Organization Resolution MSC.81(70), Revised Recommendation on Testing of Life-Saving Appliances. (résolution MSC.81(70) de l’OMI)

IS Code

means the annex to the International Maritime Organization Resolution MSC.267(85), International Code on Intact Stability, 2008. (recueil IS)

MODU Code

means the annex to the International Maritime Organization Resolution A.1023(26), Code for the Construction and Equipment of Mobile Offshore Drilling Units, 2009. (Code MODU)

operating limits

means the limits determined during the design of an installation, including its systems and equipment, a pipeline or vessel, as the case may be, within which it will continue to be fit for the purposes for which it is to be used, taking into account operating conditions, including changes in operating conditions, and all operating modes and the effect of those conditions and modes. (limites d’exploitation)

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 those instances when persons are present on the installation, their presence is for the purpose of performing operational duties, maintenance or inspections that will not require an overnight stay. (installation sans surveillance)

Safety and environmental protection

97 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 — certification plan

98 An operator must ensure, for the purpose of meeting the requirement under section 97 in respect of design, that an installation, including its systems and equipment, is designed in accordance with the measures included in the certification plan referred to in subparagraph 29(3)(c)(i).

Quality Assurance

Quality assurance program

99 (1) An operator must ensure that each phase of the life cycle of an installation, from its design up to and including its decommissioning and abandonment, is carried out in accordance with a quality assurance program to ensure that the installation, including its systems and equipment, is fit for the purposes for which it is to be used.

Requirements

(2) For the purpose of meeting the requirement under subsection (1), the operator must develop and implement a quality assurance program that meets the following requirements:

• (a) it must be comprehensive;
• (b) it must include a process to achieve quality objectives and to comply with the requirements of these Regulations;
• (c) it must include the policies on which it is based and a process to communicate the policies to personnel and all other affected persons;
• (d) it must set out the roles, responsibilities and authorities of all persons exercising functions under it, as well as the processes for making those persons aware of their roles, responsibilities and authorities and ensuring that they comply with them;
• (e) it must include processes for the establishment and maintenance of measurable goals and performance indicators for it;
• (f) it must include processes for periodic internal audits and reviews of it to identify areas for improvement and the corrective measures to be implemented if deficiencies are identified;
• (g) it must include processes for ensuring that the integrity of it is preserved when changes to it are planned or implemented;
• (h) it must include processes for internal and external reporting on its performance; and
• (i) it must set out the resources that are necessary to ensure that the requirements under this section are being met.

Documentation

(3) The operator must document the processes and policies required by this section and ensure that they are readily accessible for consultation and examination.

Organization

(4) The documentation associated with the quality assurance program must be 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

100 (1) An operator must ensure that a work permit that is required under this Part is issued, in either paper or electronic form, and sets out the following information:

• (a) the name of the person that issued it;
• (b) the name of the person to whom it is issued;
• (c) the periods during which the permit is valid;
• (d) the work or activity to which the permit relates, the location at which it is to be carried out and any conditions to which it is subject; and
• (e) any circumstances under which the work or activity is to be carried out that may have an effect on the safety and environmental risks associated with it, including
  • (i) physical and environmental conditions,
  • (ii) any impediments to the proper use of the system or equipment, and
  • (iii) any other activities being carried out in the area, specifying the permit or certificate associated with those activities, if applicable.

Signatures

(2) The work permit must be signed by the person that issued it and every person involved in the work or activity to which it relates, to certify that they have read and understood its contents.

Operator obligations

101 (1) An operator must ensure that

• (a) any work or activity that requires a work permit is done in accordance with the permit; and
• (b) any work permit that is issued is made readily accessible for the duration of the work or activity to which it relates.

Retention of copy

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

Design Analysis and Risk Assessment

Innovations

102 (1) An operator must ensure that any technology, including in materials, design methods, joining techniques and construction techniques, that has not been previously used in comparable situations is not used for the purposes of an installation unless

• (a) engineering studies, prototypes or model tests demonstrate that the technology is safe and fit for the purposes for which it is to be used; and
• (b) the technology is verified by a competent third party, in accordance with industry standards and best practices for technology qualification.

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

103 (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 and the environment.

Criteria

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

• (a) oceanographic conditions, including any completely or partially submerged potential navigational hazards;
• (b) meteorological conditions, including the number of daylight hours;
• (c) geotechnical conditions and geohazards;
• (d) ice conditions and any other conditions associated with cold regions; and
• (e) any other physical and environmental conditions or naturally occurring phenomena that may adversely affect the installation.

Ice conditions

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

• (a) minimize or avoid environmental loads associated with ice or ice and snow accumulation on the installation, including on its structural components;
• (b) ensure that ice conditions will not adversely affect the functionality of systems and equipment that are critical to safety and the environment;
• (c) protect risers, offloading systems and other subsea systems; and
• (d) in the case of a mobile offshore platform or vessel,
  • (i) prevent damage to propulsion or positioning systems, and
  • (ii) ensure safe transit through ice-infested waters.

Redundancy

(4) The operator must ensure that there is redundancy included in any measures used for the purposes of paragraph (3)(a).

Certification plan

(5) The operator must ensure that an installation that is to be operated in a cold climate is designed and operated in accordance with the measures included in the certification plan referred to in subparagraph 29(3)(c)(ii).

Design measures

(6) The design of an installation that is to be operated in a cold climate must include measures to

• (a) ensure its functionality in a cold climate, including in the case of property changes in fluids;
• (b) ensure the functionality in that climate of all systems and equipment that are critical to safety and the protection of the environment, including the systems and equipment needed to operate in the event of an emergency; and
• (c) prevent any impact or damage to electrical cabling in open or unheated spaces and ensure that it maintains its properties under cold-climate conditions.

Design for intended use and location

104 (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

• (a) the nature of the works and activities to be undertaken on and around the installation and the hazards associated with those works and activities;
• (b) material properties and dimensions of the installation that may vary over time;
• (c) failure modes; and
• (d) applicable safety factors.

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 and under all foreseeable loads during the design service life of the installation, including any potential geohazards.

Design criteria

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

• (a) withstand extreme loads that may occur during their construction and anticipated use;
• (b) perform as intended during their operation under all anticipated normal loads;
• (c) not fail under repeated loads;
• (d) prevent damage that is disproportionate to the cause;
• (e) prevent localized damage from leading to progressive or complete loss of integrity of the structure;
• (f) in the event of major damage caused by foreseeable hazards, maintain structural integrity for the time necessary to safely evacuate all persons from the installation;
• (g) in the case of a floating platform,
  • (i) have sufficient stability and buoyancy reserve in the case of damage such that credible scenarios of unintended flooding that are realized do not result in loss of the structure, and
  • (ii) incorporate sufficient redundancy in station-keeping systems such that the structure can withstand the loss of a station-keeping component; and
• (h) in the case of a self-elevating mobile offshore platform, withstand all loads to which it may be subjected in each mode of operation, including in the elevated position and during removal.

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

105 Based on the results of any analyses, tests, modelling or investigations undertaken under subsection 104(2), the operator must ensure that

• (a) all physical and environmental conditions that could pose a hazard to the installation are documented and communicated to all affected personnel;
• (b) the environmental limits for the safe operation of the installation are defined, included in operating procedures and communicated to all affected personnel; and
• (c) measures to detect, avoid, prevent and manage the environmental hazards, and reduce their effects, are developed and implemented in operations and incorporated into the design of the installation where required.

Risk assessment — fire, explosion and hazardous gas

106 (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 for any installation in order to identify

• (a) the types of fires, explosions and hazardous gas releases that could occur, their potential sources and unmitigated consequences, including fire and blast loads, and the likelihood of their occurrence;
• (b) measures to be incorporated into the design of the installation, if practicable, to eliminate identified fire and explosion hazards and those related to hazardous gas releases; and
• (c) all necessary control measures to reduce the risks associated with the identified hazards to a level that is as low as reasonably practicable if the hazards cannot be eliminated through design measures.

Elements for consideration

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

• (a) the general layout of the installation;
• (b) production and process activities, including well operations;
• (c) operational limits;
• (d) duration and type of fire, explosion or hazardous gas releases;
• (e) the need for a means of detecting from the potential sources identified under paragraph (1)(a)
  • (i) hazardous gas releases, and
  • (ii) outbreaks of fire;
• (f) the need for a means of isolating and safely storing hazardous substances, including fuel, explosives and chemicals;
• (g) the need for a safe means of escape, evacuation and rescue in the event of a fire, explosion or hazardous gas release; and
• (h) the need for a means to ensure levels of emergency shutdown of the installation, systems and equipment in the event of the detection of a hazardous gas release or an outbreak of fire.

Reliability and availability

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

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 153.

Installations — Design, Transportation, Arrangement and Other Requirements

Monitoring program for environment

108 (1) An operator must develop a monitoring program of the environment for the collection, in sufficient quantity, of data on physical and environmental conditions and the maintenance of that data to

• (a) support hazard identification during all works and activities and the assessment of safety and environmental risks related to those hazards; and
• (b) allow for the timely implementation of control measures to address the identified risks, including the contingency plan under section 12.

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.

Availability of data

(3) 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 those persons that request it.

Program implementation and update

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

Maintenance

109 An operator must ensure that an installation is designed and equipped to allow for its inspection, monitoring, testing and maintenance, including

• (a) clear markings and identification of and access to the areas to be inspected;
• (b) safe access to the areas to be inspected;
• (c) in the case of an installation not intended to be periodically drydocked, the means for on-location inspection of the hull and underwater components; and
• (d) safe access to subsea equipment.

Materials for installations

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

• (a) fit for the purposes for which they are to be used and suitable for the conditions to which they may be subjected, including any foreseeable emergency;
• (b) non-combustible, unless essential properties are available only in materials that are combustible or the use of combustible material will not increase the risk to safety; and
• (c) selected to ensure that, in the case of fire or explosion, their use will not increase the risk to safety in adjacent areas, including exposure of persons to toxic fumes or smoke.

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

111 (1) An operator must ensure that an installation is designed to provide passive fire and blast protection.

Design of passive fire protection

(2) The design of the passive fire protection must

• (a) not take into account the cooling effect from active fire-fighting equipment; and
• (b) reflect the need to inspect and maintain the passive fire protection components and the structures, divisions and equipment they are intended to protect.

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 undertaken in accordance with subsection 106(1) or mitigate their effects.

Barriers — certification plan

(4) The operator must ensure that barriers are designed, arranged, installed and maintained in accordance with the measures included in the certification plan referred to in subparagraph 29(3)(c)(iii).

Barriers — requirements

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

• (a) prevent the spread of fire, smoke, explosions and hazardous gas and their effects on any adjacent areas;
• (b) protect persons from fire, smoke and explosions for the time necessary to enable escape to a temporary safe refuge;
• (c) ensure the integrity of temporary safe refuges and of associated facilities that allow for communication, command, monitoring, control and evacuation for the time necessary, as determined in accordance with the safety studies referred to in section 115;
• (d) protect safety-critical elements and equipment that are to remain operational in the event of an emergency from failure or malfunction that would increase safety or environmental risks; and
• (e) maintain structural integrity for the time necessary to safely evacuate all persons.

Barriers — technical drawings

(6) The level of protection that each barrier must provide is to be based on the results of the risk assessment undertaken in accordance with subsection 106(1) and the description and location of each barrier must be included on the technical drawings of the installation.

Barriers — penetrations and openings

(7) Barriers must not have any penetrations or openings unless

• (a) the penetration or opening is necessary for the functionality of the installation;
• (b) the barrier is equipped to maintain the overall fire and blast integrity, despite the penetration or opening; and
• (c) there is a means of operating closing devices outside the space being protected if those devices require manual activation.

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 to limit the unexposed face to an average temperature increase of 139 °C and a maximum temperature rise of 180 °C above the initial temperature following 120 minutes of exposure to a hydrocarbon fire:

• (a) external bulkheads of the temporary safe refuge, main control centre and control stations that are facing production areas or wellheads, accommodations areas, embarkation stations and evacuation points, excluding the aircraft landing areas; and
• (b) the bulkheads that segregate the wellhead and processing areas from other areas of the installation.

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

112 (1) An operator must ensure that an installation is divided into hazardous and non-hazardous areas, according to the type of works and activities that will be carried out and according to the associated hazards.

Classification of hazardous areas

(2) The operator must ensure that, after the risk assessment undertaken in accordance with subsection 106(1) is conducted, each hazardous area is classified according to a 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 and non-hazardous areas and between hazardous areas of different classifications but, if not practicable, the operator must ensure that any direct access or opening is minimized.

Control of air flow between areas

(5) The operator must ensure that any access or opening between areas is designed to prevent uncontrolled air flow between the areas.

Piping systems

(6) The operator must ensure that piping systems are designed to prevent direct communication between hazardous and non-hazardous areas and between hazardous areas of different classifications.

Ventilation of enclosed hazardous areas

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

• (a) air is replaced at a rate sufficient to prevent hazardous gas accumulations in the enclosed hazardous area;
• (b) all air entering the enclosed hazardous area is from a non-hazardous area;
• (c) the air exhausted from the enclosed hazardous area does not increase the hazard level in an existing hazardous area or create a hazard in a non-hazardous area; and
• (d) the ventilation system for any enclosed hazardous area is separate from the ventilation system for any non-hazardous area.

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 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 let into an outdoor area that would be non-hazardous or classified as equal to or less hazardous than the enclosed hazardous area, had it not received the air from the enclosed hazardous area.

Ventilation pressure differential and functionality

(4) The operator must ensure that measuring devices are installed for each ventilation system of a hazardous area to monitor any loss of ventilation pressure differential and loss of functionality of that system and to activate audible and visual alarms at control points from which the system is monitored after a period of delay not exceeding 30 seconds, if such a loss occurs.

Positive overpressure relative to atmospheric pressure

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

• (a) are maintained at a positive overpressure relative to atmospheric pressure;
• (b) have airlocks for all external doors that provide a primary means of access to that centre or to those areas; and
• (c) have airlocks for all other external doors or other means of maintaining and monitoring positive overpressure relative to atmospheric pressure.

Power shut-off for mechanical ventilation system

(6) The operator must ensure that the power source for a mechanical ventilation system in 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 served by the ventilation system and will remain accessible during any fire that may occur within the area being ventilated.

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 served by the ventilation system and will remain accessible during any fire that may occur within the area being ventilated.

Ventilation system in non-hazardous area

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

• (a) measuring devices to monitor any loss of ventilation pressure differential;
• (b) audible and visual alarms;
• (c) an automated means of isolation to prevent hazardous gas from entering the non-hazardous area; and
• (d) a means to remotely seal the non-hazardous area — including inlets and outlets of all ventilation systems — from the control station and from a position outside the non-hazardous ventilated area that will remain accessible during any fire that may occur within the area.

Ignition prevention

114 (1) In order to prevent the ignition of flammable, combustible or explosive substances on an installation, an operator must ensure that measures are taken 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 prevent fire and explosions taking into account the classification under subsection 112(2) of the area in which it is to be used.

Other requirements — equipment

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

Safe distance operation

(4) The operator must ensure that any equipment that is not rated for use in a hazardous area is operated at a safe distance from any flammable, combustible or explosive substances and equipped with an automatic and manual means of deactivation in the event of fire or hazardous gas detection.

Equipment in event of emergency

(5) The operator must ensure that any equipment that is to remain in service in the event of an emergency associated with a gas release is rated as if it were located in a hazardous area.

Risk assessments

(6) For the purposes of meeting the requirements under subsections (1) to (5), the operator must ensure that any control measures identified in the risk assessment undertaken in accordance with subsection 106(1) are implemented.

Cargo tank

(7) The operator must ensure that the internal gas mixture inside a cargo tank is maintained outside the explosive limits and the systems associated with the cargo tank are designed to

• (a) prevent fire, gas or explosion hazards during all modes of cargo operations by establishing sufficient control measures, including alarms and redundancies in the measures; and
• (b) ensure that affected persons are made aware when such systems become impaired.

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 between the hot work and any well or any flammable, combustible or explosive substances.

Safe means of escape, evacuation and rescue

115 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 undertaken in accordance with subsection 106(1) and comprehensive and documented safety studies.

Exits, access and escape routes

116 (1) An operator must ensure that, in any area where persons are normally present on an installation, there are at least two exits, each connected to an escape route, that provide safe, direct and unobstructed access to temporary safe refuges, muster areas, embarkation stations and evacuation points, as well as the means for persons to descend to the water.

Distancing — exits and connected escape routes

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

Location of escape routes

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

Safe evacuation

(4) The operator must ensure that all escape routes from the accommodations area and the temporary safe refuge to the muster areas, embarkation stations and evacuation points 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 115.

Size of escape routes

(5) The operator must ensure that the escape routes are of sufficient size to enable the efficient movement of the maximum number of persons who may need to use them, as well as unrestricted manoeuvring of fire-fighting equipment and stretchers, taking into account the maximum number of persons who can be accommodated on the installation during normal operations.

Temporary safe refuge

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

• (a) provide sufficient space to accommodate all persons who may need to use the refuge until they have been evacuated or the accidental event has been brought under control;
• (b) protect the persons referred to in paragraph (a) from fire, gas release and explosion hazards until they have been evacuated or the accidental event has been brought under control;
• (c) provide the means for communication, command, monitoring and control of the event until they have been evacuated or the accidental event has been brought under control; and
• (d) provide signage and lighting to enable safe evacuation from the refuge.

Areas required to remain safe

(7) 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 temporary safe refuges, is

• (a) designed to prevent ingress of hazardous substances; and
• (b) designed and located to enable occupation for the time required to implement emergency and evacuation procedures.

Periodic verification

(8) The operator must verify on a periodic basis that the temporary safe refuge meets the requirements of subsections (6) and (7) and must record the findings resulting from the verification.

Life-saving appliances for installation

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

• (a) are sufficient in number and have the necessary redundancy to ensure their availability in any emergency situation; and
• (b) meet the requirements of the LSA Code and IMO Resolution MSC.81(70), as if the installation were a vessel to which the Code and the Resolution apply.

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

• (a) the safety studies referred to in section 115, including any escape and evacuation analysis that takes into account any major accidental events; and
• (b) in the case of fire and explosion hazards and hazards related to hazardous gas releases, the results of the risk assessment undertaken in accordance with subsection 106(1).

Position

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

Lifeboats — availability

(6) The operator must ensure that the lifeboats on an installation

• (a) are in at least two separate locations, one of which is adjacent to a temporary safe refuge;
• (b) have a combined capacity to accommodate the total number of persons on board if one lifeboat at any location is lost or rendered unusable; and
• (c) in the case of a floating platform, have a combined capacity to accommodate the total number of persons on board under any credible scenario of angle of heel accompanied by the most unfavourable combination of ocean currents and wave and wind forces that can be expected over a period of one year.

Lifeboats — specifications

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

Lifeboats — continuous communication

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

Lifeboats — towing devices

(9) The operator must ensure that lifeboats are equipped with towing devices.

Life rafts

(10) The operator must ensure that the life rafts on an installation and of a combined capacity to accommodate the total number of persons on board the installation.

Continuous verification

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

Design for removal of installation

118 (1) An operator must ensure than an installation is designed taking into consideration its removal from the offshore area at the end of its design service life.

Requirement

(2) The design must include measures to facilitate the installation’s removal and to reduce risks to safety, adverse effects on the marine environment and interference with navigation and other uses of the sea, during and after the removal of the installation.

Exception

(3) 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

119 (1) An operator must ensure that the transportation and positioning of an installation, or a part of it, is conducted

• (a) in a manner that does not compromise safety or the protection of the environment;
• (b) in a manner that minimizes interference with and hazards to other activities in proximity to that installation;
• (c) under the supervision of a competent third party;
• (d) in the case of a self-elevating mobile offshore platform, with the legs of the platform secured in accordance with the rules of the classification society that certified it under section 136; and
• (e) with the support of vessels that are classified in accordance with section 173.

Risk assessment

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

• (a) a risk assessment must be conducted that considers
  • (i) personnel requirements,
  • (ii) the towing vessels that will be used, the towing plan, including towing arrangements, and the operating limits of the towing equipment’s components,
  • (iii) the processes and control measures to be implemented to ensure safety and the protection of the environment,
  • (iv) physical and environmental conditions and the ability to reliably forecast those conditions, and
  • (v) any contingency measures, in the event of adverse physical and environmental conditions or any other foreseeable event during transportation and positioning; and
• (b) a transportation and positioning plan that takes into consideration any requirements of the competent third party referred to in paragraph (1)(c) must be prepared and, if applicable, in accordance with the rules of the classification society that certified the installation under section 136.

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

Electrical system

120 (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.

Electrical system components

(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 capable of 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 is capable of continuously monitoring the insulation level to earth and producing 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 an installation

• (a) ensures continuous availability of power generation and distribution;
• (b) includes at least two power plants, not including emergency power plants;
• (c) is capable of supporting all normal operations without recourse to the emergency electrical power supply required by subsection 123(1); and
• (d) is capable of supporting all operations, other than drilling and production, if one of the power plants is out of operation.

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 systems — certification plan

121 (1) An operator must ensure that a control system is designed in accordance with the measures included in the certification plan referred to in subparagraph 29(3)(c)(iv).

Factors and requirements

(2) The design of a control system must meet the following requirements, taking into consideration human factors:

• (a) controlled equipment must not be capable of being inadvertently activated;
• (b) controlled equipment must not create a safety or environmental hazard in the event of system failure or shutdown;
• (c) the system must have basic diagnostic capability; and
• (d) the system must be capable of being operated simultaneously from multiple control stations without compromising safety.

Control system hardware

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

Wireless remote control system

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

• (a) error checking to prevent the controlled equipment from responding to corrupt data; and
• (b) identification coding to prevent a transmitter other than the designated transmitter from operating the equipment.

Alternative means of control

(5) The operator must ensure that 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 as soon as the circumstances permit.

Control system testing

(6) Any equipment 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 in the intended manner.

Documentation

(7) The operator must ensure that the most current version of documentation that describes the design, installation, operation and maintenance of the control systems is readily accessible for consultation and examination.

Integrated software-dependent control systems

122 (1) An operator must ensure that integrated software-dependent control systems, the failure or malfunction of which would cause a hazard to safety or the environment, are maintained to ensure their reliability, availability and security.

Safety-critical software

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

• (a) secure, reliable and capable of being updated;
• (b) designed, commissioned and updated by competent persons; and
• (c) demonstrated to be fit for the purposes for which it is to be used through a testing and validation process that must consider
  • (i) all foreseeable operating conditions and emergency situations, and
  • (ii) system complexity, dependencies and interactions between systems, software failure modes and the level of risk associated with system failure or malfunction.

Modification to software features

(3) No modification to the features of the software referred to in subsection (2) is to be implemented unless the necessary internal approvals for the modification are obtained, including the approval of the installation manager.

Assessment and testing

(4) The operator must ensure that the modified software is not used until it is assessed and tested through the testing and validation process referred to in paragraph (2)(c).

Control measures

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

Emergency electrical power supply

123 (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:

• (a) the lights in the locations referred to in subsection (2);
• (b) hazard detection systems, including the central monitoring system referred to in section 165 and the fire and gas detection systems referred to in section 128, emergency response and life-saving systems, including the life-saving appliances referred to in section 117, and any other system or equipment referred to in the safety plan referred to in section 10 and the contingency plan referred to in section 12;
• (c) the communication system referred to in section 125 and related equipment necessary to comply with the contingency plan referred to in section 12;
• (d) the emergency shutdown system referred to in section 129;
• (e) navigation lights and sound-signalling appliances referred to in subsection 124(1);
• (f) in the case of a floating platform, ballast systems referred to in section 140, pumps and powered watertight doors and hatches necessary to stabilize the installation; and
• (g) systems and equipment necessary to suspend drilling or production in progress at any one time in a safe manner, including the disconnectable mooring system referred to in section 144 and the disconnect system referred to in section 146, blowout prevention systems, including the blowout preventer referred to in subsection 68(4), and pumping systems.

Lights

(2) The operator must ensure that the installation is equipped with lights supplied by the emergency electrical power supply in the following locations:

• (a) embarkation and debarkation stations and evacuation points;
• (b) escape routes, temporary safe refuges, service and accommodations area corridors, stairways, exits and personnel lift cars;
• (c) any control centre, control station and any other area from which the communication system referred to in section 125 is controlled;
• (d) spaces from which drilling or production equipment, including any equipment that is critical to its operation, is controlled;
• (e) spaces where equipment related to the emergency shutdown system referred to in section 129 and the power plants referred to in paragraph 120(4)(b) are located;
• (f) areas where emergency response equipment, described in the contingency plan referred to in section 12, is stored; and
• (g) aircraft landing areas and any obstacle to take-off and landing.

Mechanically driven generator

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

• (a) the installation is equipped with a transitional source of electrical power, unless the generator will automatically start and supply the power in less than 45 seconds from the time the main electrical power supply fails; and
• (b) the installation is equipped with a self-contained battery system designed to automatically supply sufficient power, on failure or shutdown of both the main electrical power supply and the emergency electrical power supply, to operate
  • (i) for a period of at least one hour, the lights located in an emergency exit route, an escape route, any space where equipment incorporating an internal combustion engine, a gas turbine, an electric motor, a generator, a pump or a compressor is found, any control centre, any emergency assembly room and at every launching station of the life-saving appliances referred to in section 117,
  • (ii) for a period of at least one hour, the communication system referred to in section 125 that is used to communicate with persons on the installation and the general alarm system referred to in section 126, and
  • (iii) for a period of at least four days, the navigation lights and sound-signalling appliances referred to in subsection 124(1).

Additional requirements

(4) The operator must ensure that the mechanically driven generator referred to in subsection (3) has redundancy in its starting capabilities and a dedicated source of fuel.

Design and maintenance

(5) 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 it may be equipped, are designed and maintained such that

• (a) the systems and equipment referred to in subsection (1) have an emergency power supply of sufficient capacity, taking into account starting currents and the transitory nature of electrical loads, and duration to ensure that they can function as intended and allow for effective management of the installation during an emergency, including
  • (i) to allow for the complete shutdown and evacuation of the installation,
  • (ii) to facilitate emergency response and the safe escape, refuge and evacuation of persons or to maintain the integrity of the installation,
  • (iii) to ensure sufficient power so that systems that must operate simultaneously can do so,
  • (iv) in the case of a floating platform, to maintain the flotation and stability of the platform, and
  • (v) to bring a well to a safe state and to maintain it in that state;
• (b) the capacity to provide power to essential systems is not compromised during their maintenance;
• (c) they have sufficient redundancy to ensure their reliability and, as far as is practicable, their functional and physical independence from other essential systems but, if not practicable, they are arranged so as not to adversely affect or be adversely affected by the operation of those systems;
• (d) they are arranged, or otherwise protected from mechanical damage and damage caused by fire, explosion or physical and environmental conditions to which they may be exposed, in order to remain capable of fulfilling their intended functions under all foreseeable operating conditions, including, in the case of a floating platform, static and dynamic angles of inclination referred to in subsection 132(7); and
• (e) they are readily accessible.

Navigation lights and sound-signalling appliances

124 (1) An operator must ensure that an installation is equipped with the navigation 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

(2) The 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

125 (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

• (a) external emergency response teams;
• (b) all persons, individually or collectively, at an operations site;
• (c) all persons while in transit to or from an operations site;
• (d) all support craft;
• (e) all onshore support centres or offices;
• (f) nearby vessels and aircraft; and
• (g) nearby installations.

Radiocommunication systems

(2) Except in the case of an unattended installation, the operator must ensure that the following requirements are met in respect of any radiocommunication system on an installation:

• (a) a radiocommunication system must comply with Part 2 of the Navigation Safety Regulations, 2020, as if the installation were a Canadian vessel to which those Regulations apply;
• (b) a radiocommunication system must have a technical acceptance certificate issued under the Radiocommunication Act; and
• (c) a continuous listening watch and radio log must be maintained.

General alarm system

126 (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

• (a) operational other than when the system is being inspected, maintained or repaired;
• (b) if applicable, flagged as being subject to inspection, maintenance or repair; and
• (c) designed to prevent tampering.

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

127 (1) An operator must ensure that an installation that includes process tanks, process vessels and piping has 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 undertaken in accordance with subsection 106(1).

Design

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

• (a) to release gas and combustible liquid from an installation in a controlled manner without creating a hazard to safety;
• (b) to reduce pressure in the entire process system as quickly as possible while ensuring a safe and controlled release of pressure;
• (c) to minimize the effect on the environment; and
• (d) to be activated from the main control centre and from control stations that meet the requirements of subsection (6).

Oxygen

(4) The operator must ensure that the gas release system is designed and constructed to ensure that oxygen cannot enter the system during normal operations.

Location — system

(5) 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

(6) 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 system

(7) The operator must ensure that the flaring system and any associated equipment are designed to

• (a) ensure a continuous flame using an automatic igniter system, with redundancy in its ignition capabilities, if an unlit release of gas could produce toxic gas concentrations or gas concentrations of more than 50% of the lower explosive limit of the released gas;
• (b) withstand the radiated heat at the maximum flaring rate;
• (c) prevent flashback; and
• (d) withstand all loads to which they may be subjected.

Risk minimization — vents

(8) The operator must ensure that a vent that is used to release gas into the atmosphere without combustion is designed and located in accordance with the measures included in the certification plan referred to in subparagraph 29(3)(d)(i).

Liquid removal

(9) 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

128 (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

• (a) provides continuous, reliable and automatic monitoring functions to allow persons to be alerted to the presence and location of fire and hazardous gas, as well as the concentration and composition of those gases;
• (b) is reliable and, as far as is practicable, is functionally and physically independent of other essential systems but, if not practicable, is arranged so as not to adversely affect or be adversely affected by the operation of those systems;
• (c) includes an alarm system, with audible and visual alarms that are distinct from other types of alarms and that are, on detection of fire or gas hazards, automatically or manually activated at the main control centre and in other areas where persons are normally present; and
• (d) allows control measures to be initiated manually or automatically in order to prevent abnormal conditions from escalating and causing major accidental events.

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 undertaken in accordance with subsection 106(1).

Design

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

• (a) detect the types of fire or hazardous gas releases identified in the risk assessment undertaken in accordance with subsection 106(1);
• (b) detect hazardous gas and smoke in the air intakes of any mechanically ventilated non-hazardous areas; and
• (c) ensure that the means to manually initiate fire and gas alarms are available at or near the office of the installation manager, at the main control centre, at every control station and at other locations identified in the risk assessment undertaken in accordance with subsection 106(1).

Requirements

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

• (a) its components must
  • (i) be capable of detecting the types of fire or hazardous gas releases identified in the risk assessment undertaken in accordance with subsection 106(1) in the areas in which they are located,
  • (ii) ensure reliable and early detection, taking into account their response characteristics, redundancy and performance under foreseeable conditions in which detection is required,
  • (iii) be rated and maintained in accordance with the classification system used under subsection 112(2) for use in the areas in which they are located, and
  • (iv) include failure and malfunction indicators;
• (b) the system and its components must be protected from mechanical damage and damage caused by fire, explosion or physical and environmental conditions to which they may be exposed in order to remain capable of fulfilling their intended functions under all foreseeable operating conditions;
• (c) the system must allow for all necessary information to be continuously provided to the main control centre and other strategic locations to permit the management of emergency situations;
• (d) in the event of failure of the main electrical power supply referred to in subsection 120(4), all control centres must be alerted by means of an audible and visual signal and the fire and gas detection system must switch over to the emergency electrical power supply referred to in section 123 to ensure uninterrupted operation of the system until the main electrical power supply is restored or for the time necessary to safely evacuate persons; and
• (e) the system must be capable of being reset only if the cause of its activation has been resolved.

Testing and maintenance

(6) For the purposes of the testing and maintenance of the fire and gas detection system, the operator must ensure that the following requirements are met:

• (a) the system must have override capabilities;
• (b) override commands and functions must be applied for the shortest amount of time possible and with as few as possible simultaneously applied; and
• (c) the testing and maintenance activities must not impair the system beyond what is necessary to undertake those activities or impede its functioning.

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 override effects of the fire and gas detection system must be managed as a condition of the work permit referred to in subsection (7).

Leak repair

(9) The operator must ensure that any leak of hydrocarbon gas 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 the equipment component — and that must be repaired other than for the purposes of safety or resource conservation, is repaired as soon as the circumstances permit.

Emergency shutdown system

129 (1) An operator must ensure that an installation has an emergency shutdown system.

Requirements

(2) The operator must ensure that the emergency shutdown system is capable of

• (a) shutting down all potential ignition sources and potential sources of flammable liquids or gases, including by isolating all potential ignition sources or potential sources of flammable liquids or gases;
• (b) depressurizing all potential sources of flammable liquids or gases, other than reservoirs;
• (c) preventing abnormal conditions from escalating and causing major accidental events; and
• (d) limiting the extent and duration of any major accidental event.

Studies and assessments — design

(3) The operator must ensure that the design of the emergency shutdown system is based on any studies or assessments that identify potential hazards and assess the risks associated with the identified hazards, including the risk assessment undertaken in accordance with subsection 106(1) and the risk and reliability analysis undertaken in accordance with section 107.

Design

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

• (a) allow for automated and manual activation to ensure effective shutdown;
• (b) allow for the shutdown of any system or equipment to bring it to a safe state that has been predetermined in the studies and assessments referred to in subsection (3), unless it has been rated in accordance with the classification system used under subsection 112(2) to remain operational;
• (c) allow for the selective shutdown of the ventilation systems referred to in section 113, except the fans necessary for supplying combustion air to engines required to operate during emergency situations, unless gas has been detected in the intake to engines;
• (d) allow for the isolation of petroleum and flammable fluid inventories, including reservoirs, wells, production systems and pipelines, from ignition sources;
• (e) consider the size and segregation of petroleum and flammable fluid inventories to limit the quantity of substances released on loss of containment;
• (f) allow for the depressurization and the disposal of hydrocarbon inventories in a safe manner and to a safe location without cold venting;
• (g) allow for the closure of the installation’s subsea and subsurface safety valves and of pipeline safety valves;
• (h) allow for essential systems that take into account necessary timelines to support safe escape, refuge and evacuation of persons or maintain the integrity of the installation; and
• (i) consider the activation of fixed fire-suppression systems required under paragraph 130(4)(a).

Shutdown logic

(5) 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 hazards identified in the studies and assessments referred to in subsection (3).

Additional requirements

(6) The operator must ensure that the emergency shutdown system meets the following requirements:

• (a) the system must be reliable and, as far as is practicable, be functionally and physically independent of other essential systems but, if not practicable, is arranged so as not to adversely affect or be adversely affected by the operation of those systems;
• (b) the system includes an alarm system, with audible and visual alarms that are distinct from other types of alarms, that will, in keeping with the hierarchy of shutdown levels referred to in subsection (5), automatically activate in the main control centre and at other strategic locations such that all affected persons are alerted;
• (c) the system status must be continuously monitored from the main control centre, including, if the system or part of the system is overridden, the extent and duration of the override;
• (d) the system and its components must be protected from mechanical damage and damage caused by fire, explosion or physical and environmental conditions to which they may be exposed in order to remain capable of fulfilling their intended functions under all foreseeable operating conditions;
• (e) the system must allow for all necessary information to be continuously provided to the main control centre and other strategic locations to permit the management of emergency situations, including information regarding
  • (i) shutdown level and the source of activation of the system,
  • (ii) shutdown effects that failed to execute on activation of the system, and
  • (iii) status, including failure, of system components;
• (f) the system must be capable of being activated from multiple manual activation points that are
  • (i) clearly marked,
  • (ii) protected against unintentional activation, and
  • (iii) located at strategic positions, with at least one located outside hazardous areas;
• (g) the activation of the system from a manual activation point must trigger the general alarm system referred to in section 126;
• (h) manual activation points for the highest level of shutdown must be located at the main control centre and at other strategic locations, including the aircraft landing area and other embarkation stations;
• (i) if a hydraulic or pneumatic accumulator is used to operate any part of the system, the accumulator must
  • (i) be located as close as is practicable to the part that it is intended to operate, except if that part is part of a subsea production system, and
  • (ii) have the capacity for a sufficient number of activations to ensure that shutdown can be achieved;
• (j) in the event of a failure of an accumulator referred to in paragraph (i), the shutdown valves must revert to a fail-safe mode;
• (k) the system must have the capacity for testing of both input and output signal devices and internal functions of the system in order to ensure the system’s functioning;
• (l) in the event of failure of the main electrical power supply referred to in subsection 120(4), the system must have the capacity to function continuously until the main electrical power supply is restored or all shutdown operations have been concluded;
• (m) in the event that an impairment of the system or any of its components increases the risk to safety or the environment, any other systems that support the emergency shutdown system must revert to a fail-safe mode;
• (n) if two or more installations are connected or if there is temporary equipment on an installation,
  • (i) the emergency shutdown systems of the connected installations must be linked such that emergency shutdown signals are transmitted between the emergency shutdown systems,
  • (ii) the emergency shutdown systems of the temporary equipment must be linked to the installation’s emergency shutdown system such that emergency shutdown signals are transmitted between all emergency shutdown systems and adhere to the logic of the installation’s emergency shutdown system, and
  • (iii) the logic for the emergency shutdown system of each of the connected installations and the temporary equipment must be re-evaluated and modified, if necessary, to take into account that the emergency shutdown systems are linked;
• (o) the system must be capable of being overridden or reset only if the cause of its activation has been resolved and there has been local confirmation that the equipment that gave rise to the system shutdown can be safely used; and
• (p) override commands and functions must not be capable of being unintentionally activated.

Testing and maintenance

(7) If the emergency shutdown system has override capabilities for the purposes of testing and maintenance activities, the operator must ensure that the following requirements are met:

• (a) override commands and functions must be applied for the shortest amount of time possible and with as few as possible simultaneously applied; and
• (b) the testing and maintenance activities must not impair the system beyond what is necessary to undertake those activities or impede its functioning.

Closure — subsurface safety valve

(8) In the case of a production installation, on initiation of the emergency shutdown system, the operator must ensure that any subsurface safety valve referred to in subsection 161(1) closes in not more 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.

Work permit

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

Management of override effects

(10) The override effects of the emergency shutdown system must be managed as a condition of the work permit referred to in subsection (9).

Fire protection systems and equipment

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

Certification 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 included in the certification plan referred to in subparagraph 29(3)(d)(ii).

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 undertaken in accordance with subsection 106(1).

Further requirements

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

• (a) automated fixed fire suppression systems with capability for manual activation outside the space that is being protected;
• (b) fixed monitors, deluge systems and foam systems;
• (c) manual firefighting systems and equipment; and
• (d) necessary redundancies to ensure the systems function in the case of the failure of one of their components.

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 or explosion or physical and environmental conditions to which they may be exposed to 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 the accommodations area, in any hazardous area and in any other areas that require such a system based on the results of the risk assessment undertaken in accordance with subsection 106(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 each of those fire pumps is equipped with at least two independent starting devices.

Location and remote control activation

(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 undertaken in accordance with subsection 106(1), and are designed to include remote control activation.

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.

Number and position of fire hydrants

(11) The operator must ensure that the number and position 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.

Activation 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 activation

(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 to unattended installations.

Boilers and pressure systems — certification plan

131 (1) An operator must ensure that boilers and pressure systems are designed in accordance with the measures included in the certification plan referred to in subparagraph 29(3)(d)(iii).

Design measures

(2) The design of boilers and pressure systems must include measures to

• (a) prevent the occurrence of an abnormal condition that could cause an undesirable event;
• (b) prevent an undesirable event from causing a release of liquids, gases or vapours;
• (c) prevent the ignition of any flammable liquids, gases or vapours that are released;
• (d) safely disperse or dispose of any liquids, gases or vapours that are released;
• (e) prevent formation of explosive mixtures;
• (f) limit exposure of persons to fire hazards;
• (g) monitor safe limits of pressure, temperature and fluid levels and to reliably protect against exceeding those limits;
• (h) permit the examination of components critical to the pressure system to ensure their continued integrity;
• (i) allow for the draining and venting at all stages of operation to
  • (i) permit safe cleaning, inspection and maintenance, and
  • (ii) avoid harmful effects, including water hammer, vacuum collapse, corrosion and uncontrolled chemical reactions;
• (j) prevent the escalation of accidental events that occur outside of the boiler or pressure system; and
• (k) limit and mitigate effects of any loss of containment of the contents of the boilers or pressure systems.

Method of design

(3) The design of boilers and pressure systems must

• (a) be based on methods that incorporate safety margins that are in accordance with good engineering practice and include any analyses and numerical modelling that are necessary to determine their behaviour and failure modes under all foreseeable operating conditions and that consider
  • (i) the internal and external pressure of the boilers and pressure systems,
  • (ii) ambient and operating temperatures,
  • (iii) static pressure and the mass of contents of the boilers and pressure systems when tested or operated,
  • (iv) foreseeable dynamic loads, reaction forces and moments resulting from, among other things, piping and its supports and other accessories,
  • (v) structural and mechanical integrity threats, and
  • (vi) reactions caused by changes in fluids and other substances contained in the boilers and pressure systems over time, including reactions caused by the products of the decomposition of unstable fluids or substances;
• (b) if hazards cannot be eliminated through design measures, include safety measures that take into account
  • (i) the need for closing and opening devices and devices to indicate their status and to prevent their opening or physical access while pressure differential exists,
  • (ii) the need for containment of hazardous substances and mitigation of the effects of any hazard related to the release of those substances,
  • (iii) the surface temperature of the boilers and pressure systems, and
  • (iv) the decomposition of unstable fluids; and
• (c) be approved by an authorized inspector.

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 for manufacturing

(5) The operator must ensure that the materials used for the manufacture of boilers and pressure systems are compatible with their operating environment and 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:

• (a) documents demonstrating that manufacturing, testing and installation have been carried out in accordance with the design specifications provided for in a quality assurance program that is approved by an authorized inspector;
• (b) records of the procedures that were followed in the welding, brazing and non-destructive examination of the boilers and pressure systems, including the results of the welder qualification tests specific to the welding and brazing procedures;
• (c) the qualifications of persons involved in manufacturing, inspection and testing, including welders; and
• (d) traceability records for the components of the boilers and the pressure systems.

Construction, installation, commissioning, inspection and testing

(7) The operator must ensure that boilers and pressure systems are constructed, installed and commissioned by competent persons and, before being put into operation, subjected to any inspections and tests, including non-destructive examination and proof tests, that are necessary to ensure their integrity and compliance with design specifications.

Inspection, testing and verification

(8) The operator must ensure that, after the installation of a boiler or pressure system, or after any modification or repair, including welding, is carried out on it, the boiler or pressure system is not put into operation until it is inspected and tested by an authorized inspector.

Maintenance and repair

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

Operating procedures

(10) 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 that must be taken to reduce risks when the boilers and pressure systems are being used, maintained or repaired.

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.

Inspections

(12) The operator must ensure that the inspection of boilers and pressure systems is conducted by an authorized inspector.

Register

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

• (a) accurate design calculations, technical drawings and specifications, including evidence of the design approval by an authorized inspector;
• (b) a list of the applied design standards;
• (c) their operating limits, including the pressure and temperature ratings;
• (d) all documents and records required from the manufacturer under subsection (6);
• (e) the record of each inspection and test referred to in subparagraph 190(1)(h)(ii); and
• (f) a record of each repair or modification made to the boiler and pressure systems referred to in subparagraph 190(1)(h)(iii).

Identification and information

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

Verification

(15) The operator must ensure that all operating procedures developed in accordance with subsection (10) and the register referred to in subsection (13) are periodically verified by the certifying authority.

Non-application

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

• (a) a heating boiler that has a heating surface of 3 m² or less;
• (b) a pressure system that is installed for use at a pressure of one atmosphere of pressure or less;
• (c) a pressure vessel that
  • (i) has a capacity of 40 L or less, or
  • (ii) has an internal diameter of
    • (A) 152 mm or less, or
    • (B) more than 152 mm but not more than 610 mm and that is used for the storage of hot water or that is connected to a water pumping system that contains compressed air which serves as a cushion;
• (d) a refrigeration plant that has a refrigeration capacity of 18 kW or less; or
• (e) a domestic water and plumbing system.

Mechanical equipment — certification plan

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

• (a) is designed, selected, located, installed, commissioned, protected, operated, inspected and maintained in accordance with the measures included in the certification plan referred to in subparagraph 29(3)(c)(v); and
• (b) can operate safely and reliably under all foreseeable operating conditions, taking into account the manufacturer’s instructions.

Design

(2) The design of the mechanical equipment must take into account the following scenarios:

• (a) loss of containment of hazardous substances;
• (b) overspeeding and loss of restraint of machinery components that have high kinetic energy;
• (c) extreme surface temperatures of the mechanical equipment;
• (d) the movement of mobile components of the mechanical equipment;
• (e) loss of control and integrity of the mechanical equipment;
• (f) ignition of potentially explosive atmospheres in hazardous areas from sparks, flames or excessive heat; and
• (g) escalation of accidental events.

Operating instructions for internal combustion engine

(3) 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 engines.

Controls and manual shut-off devices

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

Turbines and internal combustion engines

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

• (a) equipped to prevent unintended ignition and installed so that
  • (i) their supply of combustion air is from a non-hazardous area, and
  • (ii) their exhaust is discharged to a non-hazardous area; and
• (b) equipped with safety devices, including manual and automatic fuel shut-off devices — except for an automatic fuel shut-off that will increase safety or environmental risks — to prevent major damage from overspeeding, high exhaust temperature, high cooling water temperature, low lubricating oil pressure or from other foreseeable hazards that could impair the safety of operations.

Exception

(6) Despite paragraph (5)(b), the turbines and internal combustion engines that are critical to emergency response, including emergency generators and fire pumps, must not be equipped with the safety devices referred to in that paragraph other than the 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 and propulsion of a floating platform will continue to operate safely and reliably at full rated power under static and dynamic angles of inclination specified by the rules of the classification society that certifies the platform under section 136.

Materials handling equipment

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

• (a) equipped with safety devices;
• (b) if practicable according to industry standards and best practices, designed and constructed so that a failure of any part of the materials handling equipment will not result in loss of control of the equipment;
• (c) designed and constructed based on the conditions under which it is to be operated; and
• (d) operated taking into consideration the manufacturer’s instructions and industry standards and best practices.

Emergency slewing and lowering

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

Identification and information

(3) The operator must ensure that all materials handling equipment is marked with an identifier that permits reference to information that is necessary to permit its safe operation, including any information and records regarding its design, construction, inspection, testing, maintenance and repair.

Inspection and proof test

(4) The operator must ensure that materials handling equipment is inspected and proof-tested by a competent third party to determine its rated capacity before it is put into operation if

• (a) the equipment is new;
• (b) the rated capacity of the equipment is not known;
• (c) there is reason to believe that the equipment is no longer fit for the purposes for which it is to be used, due to its age or prior use, among other things;
• (d) repairs or modifications have been made to the equipment’s load-bearing components; or
• (e) modifications have been made to the equipment which affect the rated capacity.

Criteria for inspection and testing

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

Rated capacity

(6) Following an inspection and proof test under subsection (4), the competent third party must certify in writing the rated capacity of the materials handling equipment.

Pedestal crane

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

• (a) a load chart that specifies the boom angle and the safe working load for each block and for each operating mode must be posted inside its control cab; and
• (b) it must be equipped with
  • (i) a load measuring device that has been calibrated in accordance with the manufacturer’s specifications or any calibration standard that is at least as rigorous as those specifications,
  • (ii) a safe load indicator system that is programmed for different operating modes and includes load and moment measuring devices,
  • (iii) a gross overload protection system,
  • (iv) a device to indicate the boom angle if the rated capacity of the crane is affected by the boom angle,
  • (v) a device to indicate the boom extension or load radius if the rated capacity of the crane is affected by the extension or radius,
  • (vi) boom and block travel-limiting devices,
  • (vii) devices for emergency stopping, and
  • (viii) an anemometer.

Crane hooks

(8) The operator must ensure that all crane hooks are equipped with positively engaged safety latches or equivalents that will prevent load shedding under any operating conditions.

Landing or taking off

(9) It is prohibited to move a crane in the vicinity of a landing area when an aircraft is landing or taking off.

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 — certification plan

134 (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 included in the certification plan referred to in subparagraph 29(3)(c)(vi).

Design of subsea production system

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

• (a) the system can avoid foreseeable hazards or revert to a safe state when hazards are imminent;
• (b) the system supports and seals connections to the well, pipelines, other subsea production systems or other installations;
• (c) in the event of a loss of control or communication, the system will revert to a safe state;
• (d) the failure of a single component cannot cause or contribute to a major accidental event;
• (e) barrier elements in each conduit that carries fluids are reliable, have necessary redundancy and are arranged to
  • (i) prevent uncontrolled flow of well fluids,
  • (ii) minimize the quantity of fluids released from the conduit in the event of unintended release, and
  • (iii) permit testing of the integrity of the barrier elements without increasing safety or environmental risks;
• (f) subsea equipment can withstand or is protected from any load to which it may be subjected that would result in mechanical damage;
• (g) production risers can withstand or are protected from all hazards and environmental loads to which they may be subjected, other than icebergs; and
• (h) the blowout preventer is supported by the system during drilling and the tree and any workover or intervention pressure control equipment are supported by the system after completion.

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 reconnected and before being brought back into service.

Control of subsea production system

(6) The operator must ensure that a subsea production system is controlled from 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

135 (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 an assessment is conducted on the equipment and on its integration with other equipment and systems to determine its impact on existing safety-critical elements and on the quantitative risk assessment.

Certification plan

(3) The operator must ensure that temporary or portable equipment is managed in accordance with the measures included in the certification plan referred to in subparagraph 29(3)(c)(vii).

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.

Platforms — Additional Requirements

Classification

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

Air gap

137 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

138 (1) An operator must ensure that a floating platform is stable and can be operated safely — under intact or damaged conditions — in relation to all motions and loads to which it may be subjected, including by

• (a) determining the stability and motion response characteristics of the platform using analysis or model testing;
• (b) determining the critical maximum loads and motions that the platform can withstand;
• (c) ensuring that all equipment is fastened to prevent unintended movement; and
• (d) monitoring and recording all loads that could affect motions, stability or inclination of the platform.

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 applicable recommendations concerning the stability and motion response of a floating platform in the MODU Code and Part B of the IS Code are mandatory and the operator must comply with them, except with respect to the recommendations for the inclining test for column-stabilized units under paragraphs 3.1.5.1 and 3.1.5.2 of the MODU Code, which are replaced by the requirements under subsections (5) and (6).

Gap analysis

(4) The operator must, every time the MODU Code is updated, undertake a gap analysis between the criteria in the updated version and the version that was used for the construction of the floating platform and any gaps must be risk-assessed and mitigation measures implemented, as required, by the operator.

Inclining test — first survey

(5) The operator must, in the case of a column-stabilized mobile offshore platform, ensure that a lightweight survey or inclining test is carried out during the first five-year classification society survey and that, if a lightweight survey is carried out and it indicates a change from the calculated light ship displacement of more than 1% of the operating displacement, an inclining test is carried out.

Subsequent five-year surveys

(6) During every subsequent five-year classification society survey, the operator must ensure, if the lightweight survey or inclining test during the first five-year survey demonstrated that the column-stabilized mobile offshore platform was maintained in accordance with the weight control program under paragraph 154(1)(c) and this is confirmed by the records referred to in paragraph 3.1.4 of the MODU Code, that light ship displacement is verified in operation by comparison of the calculated and observed draught. If the difference between the expected displacement and the actual displacement based on draught readings is more than 1% of the operating displacement, the operator must ensure that a lightweight survey is carried out in accordance with subsection (5).

Subsequent inclining tests

(7) Beginning with the third five-year classification society survey, the operator must ensure that an inclining test is carried out every 10 years.

Application — self-elevating mobile offshore platform

(8) Subsections (5) to (7) also apply in the case of a self-elevating mobile offshore platform.

Assessment — self-elevating mobile offshore platform

139 (1) An operator must, in the case of 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:

• (a) it must be equipped with systems to actively monitor
  • (i) hull inclination,
  • (ii) leg penetration into the seabed,
  • (iii) loads on each of the platform’s legs, and
  • (iv) rack phase differential, if applicable; and
• (b) its jacking mechanisms must be designed so that the failure of a single component does not cause an uncontrolled descent of the platform.

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

• (a) hull inclination or the rack phase differential exceeds the allowable limits set out in the operations manual in accordance with paragraph 153(3)(b);
• (b) unexplained changes occur in the loads on any of the platform’s legs;
• (c) leg penetration into the seabed increases; or
• (d) any other event threatens the stability of the platform.

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

140 (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

• (a) maintain necessary draught, stability and hull strength under all foreseeable operating conditions;
• (b) return the floating platform to a safe condition from an unintended draught, trim or heel;
• (c) prevent unintended transfer of fluid within the system;
• (d) empty and fill all tanks that are a part of the system; and
• (e) completely and rapidly empty watertight spaces.

Requirement — Code

(2) The recommendations in the MODU Code concerning ballast and bilge systems are mandatory and the operator must comply with them.

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

• (a) an effective means of communication with other spaces that contain equipment relating to the operation of the ballast system;
• (b) a ballast pump control and status system;
• (c) a ballast valve control and status system;
• (d) a tank level indicating system;
• (e) a permanently mounted ballast schematic diagram;
• (f) heel and trim indicators;
• (g) a draught-indicating system;
• (h) a system to indicate the available power from the main and emergency electrical power supplies; and
• (i) a ballast system hydraulic or pneumatic pressure-indicating system.

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 when the floating platform is in a damaged condition.

Failure modes and effects analysis

(5) An operator is not considered to be in compliance with this section unless the ballast and bilge systems have been assessed through a failure modes and effects analysis.

Watertight and weathertight integrity and freeboard — Codes

141 (1) The applicable recommendations concerning watertight and weathertight integrity and freeboard in the MODU Code and Part B of the IS Code are mandatory and the operator must comply with them.

Watertight subdivision

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

Load line certificate

(3) The operator must ensure that a floating platform meets the following requirements:

• (a) it must hold an International Load Line Certificate or an International Load Line Exemption Certificate issued by the government of the state whose flag the platform is entitled to fly as required under Article 16 of the International Convention on Load Lines, 1966; and
• (b) it must be marked in accordance with the certificate.

Watertight and weathertight appliances

(4) The operator must ensure that the arrangement and specification of watertight and weathertight appliances complies with the measures in respect of watertight and weathertight appliances described in the certification plan.

Water ingress

(5) The operator must ensure that a floating platform is designed with systems and equipment that provide for operating, monitoring and indicating — both locally and at the ballast control stations — the opening and closing of the watertight doors and hatches and for detecting and providing 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

142 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 design

143 (1) An operator must ensure that the design of a mooring system is based on analysis and model testing to ensure

• (a) safety and the protection of the environment;
• (b) stability and serviceability of the floating platform;
• (c) integrity and serviceability of the mooring system components, including any related topside equipment;
• (d) integrity and serviceability of drilling risers, production risers, export risers or any other type of riser;
• (e) the redundancy of the components necessary to enable the floating platform to maintain its position with the loss of a single mooring component or, for a thruster-assisted mooring system, the loss of the most effective thruster or a single failure in the power or control system;
• (f) for a thruster-assisted mooring system, the survival of the floating platform in extreme meteorological conditions in the event of a power failure;
• (g) the movement of the floating platform from its position to avoid accidental events for which it is not designed; and
• (h) safe access and safe clearances with respect to subsea and surface components of the installation, any nearby installations, support vessels and evacuation systems.

Excursion limits

(2) The operator must ensure that the excursion limits of a floating platform are established based on the analysis and model testing required under subsection (1).

Loss of station-keeping or failure

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

Monitoring of mooring line tensions

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

Measures

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

• (a) the periodic assessment of the system’s condition;
• (b) the assessment of damage or suspected damage; and
• (c) arrangements for timely repair or replacement in the event of damage or deterioration.

Disconnectable mooring system

144 (1) If a floating platform has a disconnectable mooring system, 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.

Certification plan

(2) The operator must ensure that a disconnectable mooring system is designed and maintained in accordance with the measures included in the certification plan referred to in subparagraph 29(3)(d)(iv).

Primary and backup systems

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

Floating platform capacity

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

• (a) safely manœuvering away under its own power; and
• (b) maintaining a safe position and heading while disconnected.

Criteria and procedures for disconnect

(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 a disconnectable mooring system is capable of

• (a) planned disconnection in order to allow time for depressurizing and flushing of subsea flowlines and for resumption of production after the system has been reconnected to the floating platform;
• (b) emergency disconnection in order to allow time to safely shut in wells and subsea equipment; and
• (c) reconnection in an orderly sequence and within the physical and environmental conditions described in the operations manual under paragraph 153(2)(d).

Periodic verification of disconnect 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 143(2).

Dynamic positioning system design

145 (1) An operator must ensure that the design of the dynamic positioning system for a floating platform

• (a) is based on numerical analysis and model testing to ensure that the floating platform’s position reference and directional control can be maintained within specified tolerances to satisfy design operational requirements in relation to all functional and environmental loads to which each system may be subjected at the floating platform’s intended location;
• (b) is based on a failure modes and effects analysis to ensure the segregation and redundancy of safety-critical systems or their components necessary to maintain the platform’s position in the event that credible scenarios of equipment failure are realized;
• (c) allows the system to withstand the loss of all its components situated in any one watertight compartment or fire subdivision of the floating platform due to fire or flooding; and
• (d) includes systems to monitor the parameters of operability and integrity of the critical systems of the dynamic positioning system and to provide alerts for critical system faults.

Excursion limits

(2) The operator must ensure that the excursion limits of a floating platform are established based on the numerical analysis and model testing required under paragraph (1)(a).

Disconnect system

146 (1) An operator must ensure that a floating platform with a dynamic positioning system has a disconnect system capable of

• (a) planned disconnection in order to allow time to prepare risers and subsea flowlines for disconnection;
• (b) emergency disconnection in order to allow time to safely shut in wells and subsea equipment; and
• (c) reconnection in an orderly sequence and within the physical and environmental conditions described in the operations manual under paragraph 153(2)(d).

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 145(2).

Decisions and exemptions

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

• (a) establish a list of all flag State administration decisions and exemptions in respect of any applicable standards adopted by the International Maritime Organization;
• (b) conduct a risk assessment to identify measures to reduce safety and environmental risks to a level that is as low as reasonably practicable; and
• (c) establish an action plan to implement the measures referred to in paragraph (b).

Asset Integrity

Requirements

148 An operator must ensure that all installations, including their systems and equipment, are inspected, monitored, tested, maintained and operated to ensure safety and the protection of the environment, prevent waste and continue to perform in accordance with their design specifications under the maximum load and operating conditions to which they may be exposed.

Non-destructive examination

149 An operator must ensure that a non-destructive examination of critical joints and structural parts of an installation is conducted at least once in every five-year period after the date of the last inspection or more often as required to ensure the continued safe operation of the installation.

Winterization

150 An operator must ensure that the winterization of an installation is completed in accordance with subsection 103(5) before any cold climate operation is conducted.

Corrosion management

151 (1) An operator must ensure that the corrosion of any equipment, including process vessels, and of any piping, valves, fittings and structural elements that are part of an installation, the failure of which as a result of the corrosion — including corrosion due to exposure to a sour environment — would cause a safety or environmental hazard, 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 ensure the continued integrity of safety-critical elements.

Program requirements

(3) The program must

• (a) identify all safety-critical elements that are susceptible to degradation by corrosion;
• (b) provide for the analysis needed to determine corrosion degradation mechanisms and the limits and failure modes of the safety-critical elements referred to in paragraph (a), taking into consideration foreseeable physical and environmental conditions and exposure to chemicals;
• (c) include measures to prevent corrosion, as far as is practicable, and to mitigate or protect against the effects of corrosion;
• (d) include inspection and monitoring of corrosion and of any corrosion protection and prevention systems;
• (e) provide for the collection and analysis of baseline and continuous data to monitor corrosion;
• (f) provide for the continuous assessment of activities and maintenance schedules referred to in paragraph 155(2)(f), based on the data and analysis referred to in paragraph (e), to determine whether those activities and schedules are adequate for the purpose of corrosion management of safety-critical elements, and the modification of those activities and schedules, if necessary;
• (g) provide for timely preventive maintenance of any corrosion protection and prevention systems; and
• (h) provide for timely inspection, monitoring and maintenance of safety-critical elements in accordance with the requirements of the maintenance program referred to in paragraphs 155(2)(e) and (f) and for any necessary repair before the limits established in paragraph (b) are reached.

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

152 An operator must operate any installation, including its systems and equipment, in accordance with any limitations set out in the certificate of fitness under subsection 27(3), any requirements under this Part and the operations manual referred to in section 153.

Operations manual

153 (1) An operator must develop, adhere to and maintain an operations manual that contains or makes reference to the following documents and information:

• (a) a general description of the installation, including its particular characteristics;
• (b) the chain of command and the roles, responsibilities and authorities of persons during all normal and emergency operations of the installation;
• (c) the operating limits of the installation, including its systems and equipment;
• (d) the physical and environmental conditions under which each installation and pipeline can operate without compromising safety or the protection of the environment and the physical and environmental conditions under which each installation and pipeline can survive, taking into account the results of any analyses, tests, numerical modelling or investigations undertaken under subsection 104(2);
• (e) the results of the risk and reliability analysis under subsection 107(1);
• (f) a list of the procedures necessary to ensure the safe operation of the installation, including its systems and equipment, within the limits described in paragraph (c);
• (g) a list of the accidental events that would require implementing the contingency plan referred to in section 12, any possible trigger for such an event and the measures to be taken to avoid its occurrence;
• (h) a list of the procedures, practices, resources and monitoring measures under the contingency plan referred to in section 12;
• (i) the criteria for the platform’s minimum penetration into the seabed or for maximum scour of its foundation and the arrangement of the anchoring system;
• (j) the characteristics of the platform foundation and its penetration into the seabed or the arrangement of the anchoring system and the measures to be taken to monitor the integrity of the foundation or the mooring and anchoring systems;
• (k) the criteria to identify meteorological and oceanographic conditions and phenomena that require subsea components and pipelines to be inspected;
• (l) plans that show the arrangement of watertight and weathertight subdivisions;
• (m) details of openings in watertight and weathertight subdivisions, including the location of vents, air pipes and all other means of water penetration, and the means of closure of the compartments, as well as the location of downflooding points;
• (n) a plan that contains information concerning permissible deck loads, variable loading limits and preloading;
• (o) details of audible and visual signals and alarms used in the communication system referred to in section 125, the general alarm system referred to in section 126 and the fire and gas detection system referred to in section 128, and of any colour-coding systems used for the safety of persons on the installation;
• (p) information on any corrosion protection and prevention systems, including the type and their location, and any requirements for the safety and maintenance of those systems;
• (q) technical drawings that show
  • (i) if applicable, the arrangement of any deck structure and the equipment on it, accommodations areas, temporary safe refuges and aircraft landing area and sufficient detail to permit verification and management of the integrity of hulls, mooring components, primary and critical structures, foundation elements, jacking mechanisms, risers and conductors,
  • (ii) the arrangement of hazardous areas and any equipment situated in those areas, and
  • (iii) a fire control and evacuation plan, including
    • (A) the location of escape routes, fixed fire suppression systems and life-saving appliances, and
    • (B) the arrangement of barriers that provide passive fire and blast protection and associated equipment;
• (r) the operating and maintenance requirements for all the life-saving appliances referred to in section 117;
• (s) identification of the aircraft used for the design of any aircraft landing area on the installation, their maximum weight and wheel centres and the maximum size of the aircraft for which the landing area has been designed, including the extent of the obstacle-free approach zone for the aircraft;
• (t) special arrangements to facilitate the inspection and maintenance of the installation, including its systems and equipment, and the storage of any crude oil on the installation;
• (u) special precautions to be taken or instructions to be followed when repairs or alterations to the installation, including its systems or equipment, are to be carried out;
• (v) any special operational or emergency requirements and procedures with respect to safety-critical features, including the emergency shutdown system referred to in section 129;
• (w) a description of the air gap or freeboard and the means of ensuring that the requirements under section 137 and subsections 138(2) and 141(1) and (3), as the case may be, are met;
• (x) the number of persons who can be accommodated on the installation during normal operations;
• (y) a brief description of the systems and equipment on the installation, including flow sheets and instructions for their assembly, use and maintenance;
• (z) a description of the main electrical power supply referred to in subsection 120(4) and the emergency electrical power supply referred to in section 123 and any limitations on their operation;
• (z.1) the procedure for periodically documenting the results of the inspection, monitoring, testing and maintenance of the integrity of the installation, including the format and presentation; and
• (z.2) the procedure for notifying the Chief Safety Officer and the certifying authority under subsections 158(1) and 166(1) and (2).

Additional information — floating platform

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

• (a) a description of the capabilities of the platform’s station-keeping system considering the platform’s operating limits;
• (b) all procedures for addressing the failure of any safety-critical component of the station-keeping system;
• (c) the procedures for addressing an excursion outside of the limits established in the context of the analysis and model testing under subsections 143(2) and 145(2);
• (d) a description of the station-keeping system and its operating limits, including, in the case of a mooring system, the environmental loads the moorings can sustain to keep the platform moored in place and the estimated holding power and capacity of the anchors in relation to the soil at the drill site or production site and the physical and environmental conditions for reconnection;
• (e) a description and the limitations of any onboard computer or computer-based control systems used in operations such as ballasting and dynamic positioning and in the platform’s trim and stability calculations;
• (f) instructions on how to assess the loading and ballast conditions of the platform to determine its stability and how to manage those conditions to maintain the platform’s stability in accordance with the recommendations referred to in subsection 138(3);
• (g) data on the location, type and weights of permanent ballast installed on the platform;
• (h) hydrostatic curves or equivalent data;
• (i) a plan that shows the capacities and the centres of gravity of tanks and bulk material stowage compartments;
• (j) tank-sounding tables or curves that show the capacities and the centres of gravity in graduated intervals and the free surface data for each tank;
• (k) stability data that take into account the maximum height of the centre of gravity above the keel in relation to the draught curve or other parameters based on the identified criteria with respect to the stability of the platform;
• (l) the results of the inclining test, or those of the lightweight survey together with the inclining test results, and the updated location of the centre of gravity following a deadweight survey;
• (m) examples of loading conditions for each mode of operation, together with the means to evaluate any other loading conditions;
• (n) technical drawings that show
  • (i) the arrangement and location of all openings that could affect the stability of the platform and their means of closure, and
  • (ii) the arrangement and operation of the ballast and bilge systems, accompanied by the operating instructions, to ensure that
    • (A) the necessary draught, stability and hull strength can be maintained under all foreseeable operating conditions, and
    • (B) the floating platform can be returned to a safe condition from an unintended draught, trim or heel; and
• (o) a towing arrangements plan, if necessary, and the operating limits of the towing equipment’s components.

Additional information — mobile offshore platform

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

• (a) a description of any equipment for elevating and lowering the installation and details of any special types of joints and their purpose, including any operating or maintenance instructions for the equipment and joints; and
• (b) the allowable limits for hull inclination and rack phase differential.

Programs

154 (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:

• (a) a maintenance program that meets the requirements set out in section 155;
• (b) a preservation program that meets the requirements set out in section 156; and
• (c) a weight control program that meets the requirements set out in section 157.

Program implementation and update

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

Maintenance program

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

Requirements

(2) The maintenance program must

• (a) include the measures to ensure that the installation, including its systems and equipment, continues to perform in accordance with its design specifications;
• (b) include the measures to ensure compliance with any inspection, monitoring, testing or maintenance requirements under Part 8;
• (c) include the performance standards developed by the operator for the installation, including its systems and equipment;
• (d) take into consideration the failure modes and mechanisms of safety-critical elements and the causes of their failure;
• (e) include inspection and monitoring activities that occur at a frequency and in a manner to prevent, if practicable, the failures referred to in paragraph (d) or mitigate their effects and ensure that safety-critical elements are repaired, replaced or modified without delay in accordance with section 158; and
• (f) include predictive and preventive maintenance activities and schedules for each safety-critical element that
  • (i) are based on the performance standards under paragraph (c),
  • (ii) consider the manufacturer’s recommendations and industry standards and best practices,
  • (iii) provide for a maximum specified time period for comprehensive inspection of each safety-critical element taking into consideration its condition and the conditions under which it is used,
  • (iv) for rotating equipment, provide for partial or complete dismantling and inspection at a frequency necessary to maintain the equipment in good condition and to ensure the equipment’s functionality, availability, reliability and performance are in accordance with its design specifications,
  • (v) provide for a periodic maintenance regime for any low running-hour equipment, such as emergency generators, essential generators and fire pumps, and
  • (vi) provide for the management of spare parts so that critical spare parts are available on the installation to ensure the continued functionality, availability, reliability and performance of each safety-critical element in accordance with its design specifications.

Preservation program

156 (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

157 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.

Notice of repair, replacement and modification

158 (1) No person to which a certificate of fitness has been issued is to make a repair, replacement or modification to a safety-critical element, or bring on board the installation any equipment that would change the design, performance or integrity of a safety-critical element, without notice to the certifying authority and the Chief Safety Officer.

Approval

(2) Subject to subsection (3), a person to which a certificate of fitness has been issued must ensure that the approval of the certifying authority is obtained before any repair or modification is undertaken under subsection (1).

Verification

(3) The person to which a certificate of fitness has been issued 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

• (a) confirmed that it is fit for the purposes for which it is to be used, can be operated safely without posing a threat to persons or the environment and meets the requirements of these Regulations; and
• (b) imposed any limitation on the operation of the installation that is necessary to ensure that the installation meets the requirements of paragraph 27(1)(b).

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

159 An operator must ensure that

• (a) the drilling fluid system and associated monitoring equipment provide an effective barrier against formation pressure, ensure safe well operations, prevent pollution and allow for well evaluation;
• (b) the indicators and alarms associated with the monitoring equipment are strategically located on the drilling rig to alert persons on it; and
• (c) continuous monitoring of parameters critical to safe well operations or to the detection of a gain or loss of drilling fluid while the installation is connected to the well and is taking fluid returns is provided by dedicated personnel using independent monitoring systems, with one system located on the driller’s station and another located at a distance from the station.

Drilling riser

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

• (a) furnishing access to the well;
• (b) isolating the well-bore from the sea;
• (c) withstanding the differential pressure of the drilling fluid relative to the sea;
• (d) withstanding the maximum loads to which it may be subjected; and
• (e) permitting the drilling fluid to be returned to the installation.

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 is conducted and, in the case of a floating platform that will use a dynamic positioning system, that a weak-point analysis of the drilling riser is also conducted.

Fail-safe subsurface safety valve

161 (1) An operator must ensure that a completed development well is equipped with a fail-safe subsurface safety valve that can be operated from the surface.

Requirements

(2) The operator must ensure that the subsurface safety valve

• (a) is designed, installed, tested, maintained and operated to prevent uncontrolled well flow when activated; and
• (b) in the case of a completed well that is located where permafrost is present in unconsolidated sediments, is installed in the production tubing below the base of the permafrost.

Fail-safe safety valve

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

Requirements

(4) The operator must ensure that the fail-safe safety valve on the A-annulus is designed, installed, tested, maintained and operated to prevent uncontrolled well flow when activated.

Well tubulars, trees and wellheads

162 (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 it may be subjected.

Formation flow test equipment

163 (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 upstream of and including the well testing manifold exceeds the maximum anticipated shut-in pressure.

Overpressure

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

Downhole safety valve

(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.

Formation flow test program

(5) The operator must ensure, in the case of a formation flow test program for an exploratory well or a delineation well, that a downhole safety valve is installed before the tests are conducted unless

• (a) it has been demonstrated as part of the program referred to in paragraph 62(3)(a) that the level of risk of the proposed alternative arrangement in that program is equivalent to or lower than that of using a downhole safety valve; and
• (b) the Board’s approval to conduct the test has been obtained under subsection 62(5).

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

• (a) a valve that can be operated from the surface and automatically closes when required to prevent uncontrolled well flow; and
• (b) a release system that permits the test string to be hydraulically or mechanically disconnected within or below the blowout preventers.

Pipelines

Pipeline integrity — standard

164 (1) An operator must ensure that a pipeline is designed, constructed, installed, operated and maintained in accordance with the Canadian Standards Association Standard Z662 entitled 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 set out in that standard is implemented and periodically updated.

Monitoring of Installations, Wells and Pipelines

Monitoring of systems

165 (1) An operator must ensure that an installation is equipped with a central monitoring system in the main control centre to monitor all systems the failure of which may 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.

Affected persons informed

(3) 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.

Suspension of related system

(4) 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

• (a) in the case of a function that is suspended, that function is returned to service; and
• (b) in the case of a function that was found to be impaired, measures are implemented to offset the risk of a reportable incident or waste.

Notice of deterioration — Chief Safety Officer

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

Notice of deterioration — certifying authority

(2) If any installation, system, equipment, pipeline or part of a well referred to in subsection (1) is within the scope of work referred to in section 30, the operator must also, without delay, notify the certifying authority of the deterioration.

Impairment rectification

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

Mitigation measures

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

• (a) undertake a risk assessment to identify risk mitigation measures;
• (b) implement the measures identified under paragraph (a); and
• (c) ensure that the impairment is rectified as soon as the circumstances permit.

Non-application

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

PART 9

Support Operations

Support craft

167 An operator must ensure that all support craft are capable of safely providing necessary support functions in the foreseeable physical and environmental conditions prevailing in the area in which they operate.

Support craft — availability and equipment

168 (1) An operation must ensure, in the case of an installation on which persons are normally present, that the following requirements in respect of support craft are met:

• (a) a support craft that is at a distance from the installation not greater than that required for a return time of 20 minutes must be available at all times for emergency response;
• (b) whenever an aircraft is landing or taking off, or personnel are working over the side or otherwise exposed to the risk of falling in the water, a support craft must be available in the immediate vicinity of the installation and ready to undertake rescue and recovery operations; and
• (c) a support craft that is referred to in paragraph (a) or (b) must be
  • (i) equipped to supply emergency services, including rescue and first aid treatment, for all personnel on the installation in the event of an emergency, and
  • (ii) equipped with a self-righting fast rescue boat that meets the requirements under chapter V of the LSA Code and is capable of being launched and retrieved when the craft is loaded with a full complement of persons and equipment ready for deployment in the event of an emergency.

Required distance exceeded

(2) 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 this fact and the reason why the distance or time was exceeded.

Vessel master

(3) 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

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

Safety zone — installation

170 (1) 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.

Safety zone — vessel

(2) The safety zone around a vessel engaged in a geoscientific program, geotechnical program, environmental program or diving project 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.

Entry into safety zone

(3) A support craft must not enter the safety zone without the consent of the installation manager or the person in charge of the operations site.

Safety zone boundaries

(4) The operator must ensure that persons who are in charge of any aircraft or vessel that is approaching the safety zone are notified of the safety zone boundaries, the facilities within the safety zone and any related hazards.

Landing area

171 (1) An operator must ensure that the aircraft landing area on an installation or vessel, including its equipment, is designed to ensure safety and the protection of the environment and to prevent an incident or damage from the use of an aircraft.

Procedures and training program

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

Requirements

(3) The operator must ensure that the landing area

• (a) has an obstacle-free take-off and approach area and, in the case of a fixed platform, be oriented relative to prevailing winds;
• (b) can withstand all functional loads imposed by aircraft;
• (c) can accommodate aircraft of expected sizes;
• (d) has emergency response and fire-fighting equipment;
• (e) has conspicuous markings and signage;
• (f) has adequate lighting, including in reduced visibility conditions;
• (g) has monitoring and status light systems and communication and meteorological equipment;
• (h) is readily and safely accessible, including from the accommodations areas and from any temporary safe refuge; and
• (i) in the case of a landing area on an installation, is equipped with fuel storage tanks.

Fuel storage tanks

(4) 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 or fire.

Aircraft service provider

172 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 on any landing area, procedures associated with the support of aircraft operations, including the procedures for emergency response, and the training program for personnel.

Classification

173 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 10

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

General

Definition of shotpoint

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

Reportable incidents

175 (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

• (a) any reportable incident is investigated;
• (b) the person who conducts the investigation includes in their investigation report the root causes of the reportable incident, contributing factors and measures to be implemented to prevent its recurrence and any other relevant information; and
• (c) the investigation report is submitted to the Board not later than 14 days after the day on which the reportable incident occurred.

Accessibility of records

176 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

177 (1) An operator must ensure that records are kept of any information critical to safety, the protection of the environment or the prevention of waste, including information on

• (a) the location and movement of support craft;
• (b) emergency drills and exercises and reportable incidents;
• (c) the quantities of consumable substances at any operations site;
• (d) all wildlife observation data;
• (e) all verification, inspection, monitoring, testing, maintenance and operating activities;
• (f) the status of the systems and equipment critical to safety and the protection of the environment, including any unsuccessful test result or equipment failure leading to an impairment of the systems; and
• (g) the data obtained from the observation and forecasts of environmental and physical conditions required under section 40.

Record retention periods

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

• (a) in the case of the records referred to in paragraphs (1)(a) and (d) to (f) and those referred to in paragraph (g) regarding forecasts, five years after the day on which the record is created;
• (b) in the case of the records referred to in paragraph (1)(b),
  • (i) five years after the day on which a drill or exercise is carried out, and
  • (ii) 10 years after the day on which a reportable incident is reported;
• (c) in the case of paragraph (1)(c), for as long as the consumable substance is at the operations site; and
• (d) in the case of the records referred to in paragraph (1)(g) regarding observations, for the duration of the authorized work or activity.

Safety report

178 (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, 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 31st of that following calendar year.

Requirements

(2) The safety report must include

• (a) a summary of safety performance during the applicable calendar year, including with respect to the objective established under section 4 to reduce the safety risks; and
• (b) a description and analysis of the efforts undertaken to improve safety.

Annual reports

179 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 that a copy of the report is submitted to the Board on request.

Geoscientific, Geotechnical and Environmental Programs

Notice — key dates

180 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

181 (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 include the following documents and information:

• (a) the program number assigned by the Board;
• (b) the identification, location and status of the operations sites and any support craft used in the context of the program;
• (c) a description of the works and activities undertaken during the preceding week, including
  • (i) key dates of the works and activities within the program, in particular their commencement, suspension and completion dates,
  • (ii) the quantity of data collected, broken down by each data acquisition technique,
  • (iii) the identification and location of data collection points, lines or areas,
  • (iv) maps illustrating the portion of the data acquisition program that has been conducted in relation to the proposed data acquisition plan referred to in subparagraph 9(i)(iii),
  • (v) a schedule that specifies the type of all program activities and includes any period in which data acquisition is delayed or interrupted and a summary of the causes of the delay or interruption, and
  • (vi) any failure to comply with a condition of the authorization;
• (d) maps illustrating the upcoming portion of the data acquisition program to be conducted in relation to the proposed data acquisition plan;
• (e) the total number of persons involved in the program who, during the week, were at, or transferred to or from, the operations sites and the means by which they were transferred;
• (f) a summary of any communications or interactions concerning the program activities between persons associated with the program and persons associated with fishing activities;
• (g) a summary of emergency drills and exercises and reportable incidents referred to in paragraph 177(1)(b);
• (h) the quantities of consumable substances at any operations site referred to in paragraph 177(1)(c);
• (i) any wildlife observation data referred to in paragraph 177(1)(d);
• (j) a summary of all verification, inspection, monitoring, testing, maintenance and operating activities referred to in paragraph 177(1)(e); and
• (k) measures taken to avoid disturbing wildlife or interfering with fishing activities or any other uses of the sea.

Environmental report — programs

182 An operator must ensure that an environmental report that includes 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:

• (a) a description of the general environmental conditions under which the program was conducted and, if applicable, a description of ice management activities and non-productive time caused by meteorological or ice conditions;
• (b) a summary of environmental protection measures and actions taken to mitigate the effects of any reportable incident, as well as of their effectiveness and any adjustments made for their continued improvement;
• (c) a summary of program performance in relation to the environment, including with respect to the objectives established under section 4 to reduce risks to the environment;
• (d) a summary of any emergency response drills and exercises for the protection of the environment, including those that were completed in the context of implementing the contingency plan under section 12; and
• (e) any wildlife observation data recorded under paragraph 177(1)(d).

Final reports

183 (1) An operator must ensure that a final operations and data processing report and a final interpretation report are submitted to the Board with the acquired data referred to in subsection (4), 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 and data processing report

(2) The final operations and data processing report must contain the following documents and information, as applicable:

• (a) the program number assigned by the Board;
• (b) the title, author and date of the report;
• (c) an executive summary and table of contents;
• (d) the names of the operator, contractors and any interest owners, as defined in section 47 of the Act;
• (e) a description of all operation sites and any support craft used for the program;
• (f) a description of the program, including
  • (i) key dates, in particular its commencement, suspension and completion dates,
  • (ii) the equipment used,
  • (iii) the operational methods employed,
  • (iv) the number of persons who were involved in the program, and
  • (v) the quantity of data collected, broken down by each data acquisition technique;
• (g) location maps illustrating the data acquisition program, including the identification and location of data collection points, lines or areas and the type of data acquired;
• (h) location maps illustrating the boundaries of each area covered by the program and any interest, as defined in section 47 of the Act, to which the area is subject, as well as the identification number of the interest;
• (i) a schedule that specifies the type and duration of all program activities and includes any period in which data acquisition is delayed or interrupted;
• (j) the accuracy of the navigation system and of the positioning and survey systems, as well as the parameters and configuration of both the energy source and recording system;
• (k) a description of the geoscientific data acquired, including the data processing sequence and parameters; and
• (l) shotpoint maps, track plots, flight lines with numbered fiducial points, gravity station maps, location maps for any samples or core holes, copies of any photographs and a list of any videos.

Content of final interpretation report

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

• (a) the documents and information set out in paragraphs (2)(a) to (e);
• (b) bathymetric or topographic maps compiled from the data collected;
• (c) a description and interpretive maps of the acquired data, including
  • (i) time and depth structure and isopach maps, velocity and residual velocity maps and seismic attribute maps,
  • (ii) final Bouguer gravity maps and any residual or other processed gravity maps,
  • (iii) final total magnetic intensity contour maps and any residual, gradient or other processed magnetic maps,
  • (iv) final controlled source electromagnetic resistivity maps,
  • (v) surficial maps generated from any seabed, geohazard or pipeline route survey, and
  • (vi) any geological maps;
• (d) a description and analysis of the interpretation of the data with respect to
  • (i) geological and geophysical correlations,
  • (ii) correlations between gravity, magnetic, seismic and controlled source electromagnetic data including correlations to any data acquired during previous surveys,
  • (iii) in the case of seabed surveys, the geophysical correlation between shallow seismic data and data from cores and geotechnical boreholes,
  • (iv) corrections or adjustments that were applied to the data during processing or compilation,
  • (v) the velocity information that the operator used in a time-to-depth conversion,
  • (vi) core and sample descriptions,
  • (vii) other geoscientific and geotechnical analyses, and
  • (viii) geohazards; and
• (e) a description of
  • (i) synthetic seismograms,
  • (ii) seismic modelling studies that use synthetic seismograms,
  • (iii) vertical seismic profiles at wells that were used in the interpretation of the operation data,
  • (iv) amplitude versus offset studies,
  • (v) seismic inversion studies, if any, and
  • (vi) any other seismic studies related to the program.

Acquired data

(4) The following are the acquired data that must accompany the final reports, as applicable:

• (a) track plot, shotpoint and sample location data, time stamped when available;
• (b) bathymetric data;
• (c) all final processed seismic data for each 2-D seismic line in time and depth;
• (d) a final processed 3-D volume and each line generated from that volume in time and depth;
• (e) any vertical seismic profiles, synthetic seismograms, amplitude versus offset data and any seismic inversion data;
• (f) in the case of any seabed, geohazard or pipeline route survey,
  • (i) processed high-resolution data for each line,
  • (ii) digital location maps for any samples,
  • (iii) any photographs and videos, and
  • (iv) sub-bottom profiler and side-scan sonar data;
• (g) in the case of an environmental program, any photograph, video or other graphic information that is relevant and contributes to the drafting and interpretation of the final data and final report;
• (h) in the case of a gravity or magnetic survey, a series of gravity and magnetic profiles across all gravity and magnetic surveys; and
• (i) in the case of controlled-source electromagnetic data, final processed cross-sections on all receiver lines, curves from all receivers and 2-D and 3-D final models generated.

Incorporation of previous data

(5) In submitting a map referred to in paragraph (3)(b), the operator must incorporate any previous data 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.

Final interpretation report not required

184 (1) An operator that has conducted a geoscientific program does not need to submit the final interpretation report required by subsection 183(3) if the data acquired from the geoscientific program are made available to the public for purchase or use under licence.

Final interpretation report required

(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

185 (1) A purchaser of data referred to in subsection 184(1), acquired in an area that is subject to an interest, as defined in section 47 of the Act, must submit to the Board the final interpretation report required by subsection 183(3) if the costs of the purchase of the data are 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 the final operations and data processing report required by subsection 183(2), the final interpretation report required by subsection 183(3) and the accompanying data required by subsection 183(4).

Timing of submissions

(3) The data and reports 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, omissions or corrections identified in or made to the data after the report is submitted.

Drilling and Production

Reference

186 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 58 or paragraph 59(b).

Results, data, analysis and schematics

187 (1) An operator must ensure that a copy of the final results, data, analyses and schematics obtained from the following sources is submitted to the Board:

• (a) testing, sampling and pressure measurements conducted as part of the field data acquisition program referred to in section 14 and the well data acquisition program referred to in section 18 and the evaluation, testing and sampling of formations referred to in section 61; and
• (b) any segregation test conducted under paragraph 71(2)(b) or any well operation.

Submission within 60 days

(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 any activity referred to in paragraph (1)(a) or (b) is concluded.

Survey

188 (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.

Canada Lands Survey Records

(2) The operator must ensure that a copy of the survey plan must be filed with the Canada Lands Survey Records.

Survey plan

189 An operator must ensure that a copy of the survey plan filed with the Canada Lands Survey Records under subsection 188(2) is submitted to the Board.

Critical information

190 (1) In addition to the records required under section 177, an operator must ensure that records are kept of information and documents concerning:

• (a) in the case of the assessment of the efficacy of a spill-treating agent under paragraph 12(4)(a),
  • (i) the results of any tests conducted to assess its efficacy, including a description of those tests, and
  • (ii) any oil samples used in the assessment of efficacy;
• (b) the inspection of any installation and its equipment or a pipeline for corrosion and erosion and any resulting maintenance activities carried out;
• (c) the pressure, temperature and flow rate data for compressors and treating and processing facilities and equipment;
• (d) the calibration of meters and other instruments on an installation;
• (e) the testing of subsea, surface and subsurface safety valves;
• (f) the status of each well and the status of well operations;
• (g) in the case of a floating platform, all loads that could affect motions, stability or inclination of the platform, including
  • (i) results of the tests and analyses conducted to assess its stability and station-keeping capability,
  • (ii) all movements, data, observations, measurements and calculations related to the stability and station-keeping capability of the floating platform,
  • (iii) every change in relation to the weight of the floating platform, its centre of gravity or the weight or distribution of temporary or portable equipment on it that may affect its stability, and
  • (iv) the verification of the disconnect capability of any disconnectable mooring system;
• (h) in the case of boilers and pressure systems,
  • (i) the documents and records obtained from the manufacturer referred to in subsection 131(6),
  • (ii) for each inspection and test conducted under subsections 131(7) and (8),
    • (A) the date of the inspection,
    • (B) the identification and location of the boiler and pressure system that were inspected,
    • (C) the range of safe pressure and temperature at which the boiler or pressure system may be operated,
    • (D) a declaration by the authorized inspector who conducted the inspection as to whether the boiler and pressure system meet the standards that were applied in their design and manufacture,
    • (E) a declaration by the authorized inspector who conducted the inspection stating that the boiler and pressure system are fit for the purposes for which they are to be used,
    • (F) any recommendations regarding the need for amendments to the maintenance program established under section 155, and
    • (G) any other observation relevant to the safety of persons, and
  • (iii) a description of each repair or modification made to the boiler and pressure systems;
• (i) each formation leak-off test and formation integrity test referred to in section 70;
• (j) the verification of compliance with the requirements for a temporary safe refuge required under subsection 116(8); and
• (k) the verification of the availability and condition of the life-saving appliances required under subsection 117(10).

Record retention periods

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

• (a) in the case of the records referred to in paragraph (1)(a), for as long as the spill-treating agent is approved for use;
• (b) in the case of the records referred to in paragraphs (1)(b) to (f), subparagraph (1)(g)(iv) and paragraphs (1)(i) to (k), five years after the day on which the record is created;
• (c) in the case of the records referred to in subparagraphs (1)(g)(i) to (iii), for the life of the floating platform while it is in the offshore area; and
• (d) in the case of the records referred to in paragraph (1)(h), five years after the day on which the boiler or pressure system is taken out of service.

Boilers and pressure systems

(3) The records referred to in subparagraphs (1)(h)(ii) and (iii) must be filled out and signed by the authorized inspector who conducted the inspection.

Daily production record

191 (1) An operator must ensure that a daily production record is kept until the field in which the pool or well is located 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 the records on the calibration of meters and other instruments referred to in paragraph 190(1)(d) and any other information relating to the production of petroleum and other fluids in respect of a pool or well, including

• (a) any measurements made under section 74; and
• (b) the manner in which any fluids are disposed of, including through venting, burning or flaring, or transported for processing, whether through offloading or pipeline.

Formation flow test report

192 An operator must ensure that

• (a) in respect of exploratory wells and delineation wells, a report of formation flow test results is submitted to the Board on a daily basis; and
• (b) in respect of all wells, a formation flow test report is submitted to the Board as soon as the circumstances permit following completion of each formation flow test.

Pilot scheme report

193 (1) An operator must ensure that interim evaluations of a pilot scheme referred to in section 81 are reported at intervals agreed to in writing by the Board.

Completion of pilot scheme

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

• (a) the results of the scheme and supporting data and analyses; and
• (b) the operator’s conclusions as to the potential of the scheme for application to full-scale production.

Daily reports

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

• (a) a daily operations report that includes
  • (i) a description of all works and activities carried out on the installation during the previous 24 hours and the current status of those works and activities,
  • (ii) a description of the works and activities that are expected to be carried out on the installation during the next 24 hours,
  • (iii) a summary of any information referred to in paragraph 177(1)(e) obtained during the previous 24 hours,
  • (iv) a summary of the observed data referred to in paragraph 177(1)(g) obtained during the previous 24 hours,
  • (v) a summary of any information referred to in paragraph 190(1)(g) obtained during the previous 24 hours, and
  • (vi) any other information that is necessary to indicate the status of operations on the installation;
• (b) a daily drilling report that includes, in addition to the information required under paragraph (a),
  • (i) the daily and cumulative costs of operating the installation,
  • (ii) well and casing data,
  • (iii) the properties of the drilling fluid and the drilling fluid gas readings,
  • (iv) any directional and deviation surveys,
  • (v) the formations encountered,
  • (vi) the results of any blowout preventer test, and
  • (vii) the results of any formation leak-off tests or formation integrity tests referred to in section 70;
• (c) the daily geological report, consisting of well and field data acquired through the programs referred to in section 60, geological assessments made during the previous 24-hour period of drilling and any other information that is relevant to the evaluation of the geological formation; and
• (d) in the case of a production installation, in addition to the information required under paragraph (a), a daily production report that includes a summary of the records referred to in paragraphs 177(1)(e) and 190(1)(a) to (d) and a summary of the daily production record referred to in section 191.

Monthly production report

195 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 reports and other information

196 (1) An operator must ensure that

• (a) a report in respect of a well is submitted to the Board within 21 days after
  • (i) the day on which the well is abandoned,
  • (ii) the day on which the well is suspended, if the suspension is planned to be for a period that is longer than 21 days, or
  • (iii) the day on which the well is completed or recompleted;
• (b) if a well requires a workover or intervention, a well operation report is submitted to the Board within 30 days after the day on which the workover or intervention is completed;
• (c) a well history report for a development well is submitted to the Board within 45 days after the day referred to in subparagraph (a)(i), (ii) or (iii), as the case may be;
• (d) a well history report for an exploration or delineation well is submitted to the Board within 90 days after the day referred to in subparagraph (a)(i), (ii) or (iii), as the case may be; and
• (e) the actual cost breakdown of well operations is submitted to the Board within 90 days after the day on which a well is completed.

Content of report

(2) The report 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.

Required information

(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

197 An operator must ensure, in the case of a drilling installation for an exploratory well or a delineation well, an environmental report that relates to the well and that includes the following documents and information is submitted to the Board within 90 days after the day referred to in subparagraph 196(1)(a)(i), (ii) or (iii), as the case may be,

• (a) a summary of the physical and environmental conditions under which the drilling program was conducted and, if applicable, a description of ice management activities and non-productive time caused by meteorological or ice conditions;
• (b) a summary of environmental protection measures and measures taken to mitigate the effects of any reportable incident, as well as of their effectiveness and any adjustments made for continued improvement;
• (c) a summary of the performance of the drilling program in relation to the environment, including with respect to the objectives established under section 4 to reduce risks to the environment;
• (d) a summary of any emergency response drills and exercises for the protection of the environment, including those that were completed in the context of implementing the contingency plan under section 12; and
• (e) any wildlife observation data recorded under paragraph 177(1)(d).

Annual environmental report — production and pipeline

198 An operator must ensure that, in the case of a production project or pipeline project, an environmental report that relates to a given calendar year and that includes the following documents and information is submitted to the Board not later than March 31 of the subsequent year:

• (a) a summary of the general environmental conditions to which an operations site related to the production project or pipeline project was subjected during that year;
• (b) a description of ice management activities;
• (c) a summary of environmental protection measures and measures taken to mitigate the effects of any reportable incident, as well as their effectiveness and adjustments made for continued improvement;
• (d) a summary of the performance of the project in relation to the environment, including with respect to the objectives established under section 4 to reduce risks to the environment;
• (e) a summary of any emergency response drills and exercises for the protection of the environment, including those that were completed in the context of implementing the contingency plan under section 12; and
• (f) any wildlife observation data recorded under paragraph 177(1)(d).

Annual production report

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

• (a) for the preceding calendar year, details on performance, production forecast, reserve revision, reasons for deviations in well performance from forecasts in previous annual production reports, gas conservation resources, efforts to maximize the recovery of petroleum and the operating and capital expenditures, including the cost of each well operation; and
• (b) for the preceding calendar year, the current calendar year and the next two calendar years, capital costs and fixed operating costs for each well and field in a production project, variable costs, commodity prices and financial commitments in relation to the transportation of the resource, including by pipeline.

Gas venting records

200 An operator must ensure that a record is kept of each gas venting under paragraph 82(b) that includes the following information:

• (a) a description of the occurring emergency situation that justified the venting;
• (b) a description of the venting, the date it occurred and its duration; and
• (c) the volume of gas vented.

Compressor records

201 An operator must ensure that a record containing the following documents and information is kept of the compressors referred to in subsection 83(2):

• (a) a demonstration, with supporting documents, that the continuous monitoring device has been calibrated in accordance with the manufacturer’s recommendations such that its measurements have a maximum margin of error of ±10%; and
• (b) for each compressor, if its maximum flow rate limit under subsection 83(5) or (6) has been exceeded,
  • (i) its serial number, make and model,
  • (ii) the date on which the maximum flow rate limit was exceeded,
  • (iii) the flow rate indicated by the continuous monitoring device when the maximum flow rate limit was exceeded, and
  • (iv) a description of the corrective action that was taken and the dates on which it was taken.

Fugitive emission records

202 An operator must ensure that a record is kept of the detection and repair of any fugitive emissions from an installation and that the record contains the following information in relation to each emission:

• (a) the date on which the emission was detected;
• (b) the type of equipment from which the emission was released and its location within the installation or identifier;
• (c) the means by which the emission was identified; and
• (d) a description of the corrective measures that were taken and the dates on which they were taken.

Record retention period

203 An operator must ensure that the records referred to in sections 200 to 202 are retained for five years after the day on which the record is created.

Diving Projects or Construction Activities

Weekly status reports

204 (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 include the following documents and information:

• (a) the project number assigned by the Board;
• (b) the identification, location and status of the operations sites and any support craft used in the context of the diving project or construction activities;
• (c) a description of the works and activities undertaken during the preceding week;
• (d) the total number of persons involved in the works and activities who, during the week, were at, or transferred to or from, the operations sites and the means by which they were transferred;
• (e) a summary of emergency drills and exercises and reportable incidents referred to in paragraph 177(1)(b);
• (f) a summary of the quantities of consumable substances at any operations site referred to in paragraph 177(1)(c); and
• (g) a summary of all verification, inspection, monitoring, testing, maintenance and operating activities referred to in paragraph 177(1)(e).

PART 11

Repeals and Coming into Force

Repeals

205 The following Regulations are repealed:

• (a) the Newfoundland Offshore Area Oil and Gas Operations Regulations ^{footnote 8};
• (b) the Newfoundland Offshore Certificate of Fitness Regulations ^{footnote 9};
• (c) the Newfoundland Offshore Petroleum Installations Regulations ^{footnote 10};
• (d) the Newfoundland Offshore Area Petroleum Geophysical Operations Regulations ^{footnote 11}; and
• (e) the Newfoundland Offshore Petroleum Drilling and Production Regulations ^{footnote 12}.
  

Coming into Force

Six months after publication

206 These Regulations come into force on the day that, in the sixth 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 sixth month has no day with that number, the last day of that sixth month.

SCHEDULE 1

(Clauses 27(1)(b)(ii)(A) and (B) and (iii)(B))

Certificate of Fitness

PART 1

Provisions of these Regulations

• 1 Section 24
• 2 Sections 97 to 99
• 3 Subsections 102(1) and (2)
• 4 Sections 103 to 107
• 5 Subsection 108(2)
• 6 Section 109 to 113
• 7 Subsections 114(1) to (7)
• 8 Section 115
• 9 Subsections 116(1) to (7)
• 10 Subsections 117(1) to (10)
• 11 Section 118
• 12 Subsection 119(2)
• 13 Sections 120 and 121
• 14 Subsections 122(2), (4) and (5)
• 15 Sections 123 to 127
• 16 Subsections 128(1) to (6)
• 17 Subsections 129(1) to (8)
• 18 Section 130
• 19 Subsections 131(1) to (7) and (11) to (14)
• 20 Section 132
• 21 Paragraphs 133(1)(a) to (c)
• 22 Subsections 133(2) to (8) and (10)
• 23 Subsections 134(1) to (4) and (6) and (7)
• 24 Section 135
• 25 Section 137
• 26 Paragraphs 138(1)(a) to (c)
• 27 Subsections 138(2) to (7)
• 28 Subsections 139(1) and (2)
• 29 Sections 140 to 142
• 30 Subsections 143(1) to (3)
• 31 Subsections 144(1) to (6). However, subsection (5) applies only with respect to the criteria for disconnect.
• 32 Section 145
• 33 Subsection 146(1)
• 34 Section 147
• 35 Section 149 and 150
• 36 Subsections 151(1) to (3)
• 37 Subsections 171(1), (3) and (4)

PART 2

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

• 1 Section 19
• 2 Paragraphs 21(b) and (c)
• 3 Section 22
• 4 Sections 23 to 25
• 5 Subsections 26(1) and (3)
• 6 Section 27
• 7 Section 28
• 8 Paragraph 29(a)
• 9 Subparagraph 30(2)(d)(ii)
• 10 Subsection 30(3)
• 11 Paragraphs 32(2)(a), (b) and (d)
• 12 Subsection 32(3)
• 13 Paragraphs 32(4)(a), (c) to (g) and (i). However, paragraph (e) applies only with respect to a medical room having surfaces that are easily cleaned and disinfected.
• 14 Paragraphs 46(a) and (b)
• 15 Subparagraph 46(m)(i)
• 16 Clauses 46(m)(ii)(A), (C) and (D)
• 17 Paragraph 47(2)(b)
• 18 Subsection 57(1). However, paragraph (e) applies only with respect to the accommodations area being maintained in good repair.
• 19 Subsections 58(1) and (2)
• 20 Paragraphs 58(3)(a) to (e). However, paragraph (a) applies only with respect to the requirement under paragraph 60(2)(a) concerning handwashing facilities and paragraph (e) applies only with respect to washrooms being maintained in good repair.
• 21 Subsection 60(1)
• 22 Paragraphs 60(2)(a) and (d). However, paragraph (d) applies on with respect to handwashing facilities being maintained in good repair.
• 23 Subsection 61(1)
• 24 Paragraphs 61(2)(a) to (c) and (e). However, paragraph (e) applies only with respect to showers being maintained in good repair.
• 25 Section 62
• 26 Subparagraphs 63(1)(a)(i) to (v)
• 27 Paragraphs 63(1)(b) and (c)
• 28 Section 64. However, paragraph 64(d) applies only with respect to a dining area being maintained in good repair.
• 29 Subsection 65(2), (4) and (5)
• 30 Paragraphs 66(b) and (c). However, subparagraph (c)(iv) applies only with respect to the waste receptacles being maintained in good working order.
• 31 Subsection 67(1)
• 32 Paragraph 73(b)
• 33 Subsection 74(1)
• 34 Paragraph 77(1)(a)
• 35 Subparagraph 77(1)(c)(i)
• 36 Subsection 78(2)
• 37 Section 79
• 38 Sections 81 to 85
• 39 Paragraphs 91(1)(a) to (e), (h), (j) and (n) to (p). However, paragraph (j) applies only with respect to the equipment, machines and devices in question being rated by their manufacturer as appropriate for use.
• 40 Subsection 93(1)
• 41 Paragraph 93(2)(a)
• 42 Sections 97 and 98
• 43 Section 100
• 44 Subsection 101(1)
• 45 Paragraphs 107(a) to (d)
• 46 Subsection 113(2)
• 47 Paragraphs 113(3)(a) and (b)
• 48 Section 120
• 49 Paragraphs 121(1)(a) to (d), (g) to (v) and (z.2)
• 50 Subsection 122(5)
• 51 Paragraph 122(6)(a)
• 52 Subparagraph 122(6)(b)(i)
• 53 Section 123
• 54 Subsections 124(2) and (3)
• 55 Paragraphs 125(1)(a) and (b)
• 56 Paragraphs 126(1)(f) and (g)
• 57 Subsection 126(2)
• 58 Paragraph 127(3)(a)
• 59 Subsection 130(3)
• 60 Paragraphs 144(1)(b), (l), (n), (o), (r) to (u), (w) and (x)
• 61 Subsection 147(1)
• 62 Paragraph 153(1)(e)
• 63 Paragraphs 157(1)(b), (d), (g), (l) and (q). However, subparagraph (q)(iv) applies only with respect to the inspection of a piping system that contains a hazardous substance before it is placed in service.
• 64 Subparagraphs 157(1)(c)(i) and (k)(i)
• 65 Subsection 171(3)
• 66 Paragraphs 172(1)(a), (g), (j) to (m), (o) and (p), (2)(e) and (3)(c) and (f)

SCHEDULE 2

(Subparagraph 30(3)(b)(iii))

Verification of Certificate of Fitness Requirements

• 1 Subparagraph 5(1)(l)(iii)
• 2 Paragraphs 5(1)(o) and (u)
• 3 Paragraph 42(b)
• 4 Section 43
• 5 Subsections 68(2) and (8)
• 6 Section 73
• 7 Subsection 76(1)
• 8 Subsection 102(3)
• 9 Subsection 119(1)
• 10 Subsection 122(1)
• 11 Subsection 131(8)
• 12 Subsection 134(5)
• 13 Paragraph 138(1)(d)
• 14 Subsections 139(3) and (4)
• 15 Subsections 143(4) and (5)
• 16 Subsection 144(7)
• 17 Subsection 146(2)
• 18 Section 148
• 19 Subsection 151(4)
• 20 Sections 159 to 161
• 21 Subsections 162(2) and (3)
• 22 Sections 163 and 164
• 23 Subsections 165(1), (2) and (4)