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Nova Scotia Offshore Petroleum Installations Regulations (SOR/95-191)

Regulations are current to 2019-11-19 and last amended on 2009-12-31. Previous Versions

PART IIAnalysis and Design (continued)

Mooring

  •  (1) The mooring system for a floating platform shall

    • (a) provide an anchor pattern that keeps all anchor lines, anchor chains and anchors a safe distance from existing pipelines, flow lines and other platforms;

    • (b) provide an anchor pattern that gives clear access to any support vessel intended to be used in operations and that clears lifeboat launching areas;

    • (c) be sufficiently stiff so that the excursions of the platform are within the limits established for the risers in accordance with section 61 under all operating conditions; and

    • (d) be sufficiently strong so that the failure of any anchor line during operations will not lead to major damage.

  • (2) The load factor for tension in the mooring lines of every floating platform, based on a quasi-static analysis, shall be

    • (a) in the operating condition with all lines intact, 3.0;

    • (b) in the operating condition with one line failed, 2.0;

    • (c) in the survival condition with all lines intact, 2.0;

    • (d) in the survival condition with one line failed, if the platform will not threaten another platform used for the exploration or exploitation of subsea resources, l.4; and

    • (e) in the survival condition with one line failed, if the platform may threaten another platform used for the exploration or exploitation of subsea resources, 2.0.

  • (3) The fatigue life of the mooring system of every floating platform shall be equal to at least 15 years.

  • (4) The mooring system of every floating platform that is to remain at the production site or drill site for longer than five years shall be designed so that its components can be inspected and replaced.

  • (5) The design of the mooring system of every floating platform that is intended to remain moored in the survival condition shall be based on an appropriate model test or numerical analysis.

  • (6) Where there is an annual probability of 10-2 of ice or icebergs being present at the site of a floating platform, the mooring system of the platform shall

    • (a) incorporate a primary quick release system with a remote triggering device and at least one back-up system; and

    • (b) have been demonstrated to be capable of permitting the quick release of the platform from its moorings and risers.

  • (7) Except where the floating platform may threaten another platform used for the exploration or exploitation of subsea resources, the following factors may be taken into account in determining whether a thruster-assisted mooring system using a remote control thruster system complies with subsection (2):

    • (a) if the remote control is manual,

      • (i) zero thrust, for the operating condition,

      • (ii) 70 per cent of the net thrust effect from all except one thruster, for the survival condition,

      • (iii) zero thrust, for one mooring line failed in the operating condition, and

      • (iv) 70 per cent of the net thrust effect from all thrusters, for one mooring line failed in the survival condition; and

    • (b) if the remote control is automatic,

      • (i) the net thrust effect from all except one thruster, for the operating condition,

      • (ii) the net thrust effect from all except one thruster, for the survival condition,

      • (iii) the net thrust from all thrusters, for one mooring line failed in the operating condition, and

      • (iv) the net thrust from all thrusters, for one mooring line failed in the survival condition.

  • (8) Mooring system components on a floating platform that interface with the mooring chain or rope, except the attachment in the chain locker for anchor chain and the steel rope attachment on the drum, shall be designed to withstand the forces due to tension required to break the chain or rope.

  • (9) The mooring system for a floating platform shall be designed to keep the platform on location, under any ice loads to which it may be subjected as determined pursuant to section 44, and the chain or rope shall be able to withstand, without significant damage, the abrasion forces imposed by such loads.

  • (10) The load factors between the estimated anchor holding power in the mooring system of a floating platform and maximum mooring line tension at the anchor shall be at least

    • (a) in the operating condition with all lines intact, 2.1;

    • (b) in the operating condition with one line failed, 1.4;

    • (c) in the survival condition with all lines intact, 1.4;

    • (d) in the survival condition with one line failed, if the platform will not threaten another platform used for the exploration or exploitation of subsea resources, 1.0; and

    • (e) in the survival condition with one line failed, if the platform may threaten another platform used for the exploration or exploitation of subsea resources, 1.4.

  • (11) For the purposes of paragraphs (2)(d) and (e), subsection (7) and paragraphs (10)(d) and (e), one platform shall be considered to threaten another platform if the platform may drift or be pushed, by environmental conditions, into the other platform when all lines fail, taking into account any action likely to be taken to bring the platform under control.

  • (12) All anchor winches and their stoppers, brakes, fairleads and sheaves, their attachments to the hull, and associated load- bearing structural elements for a floating platform shall be designed to withstand, without risk of permanent deformation or failure or of loss of ability to operate, the application of the breaking load of the associated anchor line with the anchor line in the most unfavourable direction.

  • (13) The catenary mooring system on every floating platform shall be inspected in accordance with the requirements of American Petroleum Institute RP 21, Recommended Practice for In-Service Inspection of Mooring Hardware for Floating Drilling Units.

Dynamic Positioning

  •  (1) The dynamic positioning system used to hold a floating platform in position at the production site or drill site shall be designed, constructed and operated so that the failure of any main component with an annual failure rate of greater than 0.1, as determined from a detailed reliability analysis, cannot result in major damage to the platform, as determined from a failure modes and effects analysis of the main components, unless

    • (a) operational procedures for the dynamic positioning system avoid or take into account the effect of the failure of the single component; or

    • (b) every such component is routinely replaced so that the failure rate, as determined from the detailed reliability analysis, is not greater than 0.1 for the period between replacements.

  • (2) Every floating platform with a dynamic positioning system shall be equipped with an alert and response display system that demonstrates

    • (a) the position of the platform relative to the production site or drill site; and

    • (b) the percentage of the available power that is necessary to maintain the platform in a position relative to the site and that will permit the installation to continue to operate.

Subsea Production Systems

  •  (1) Every subsea production system shall be designed to withstand major damage under the loads listed in Part B, Section 4, of Det norske Veritas Guideline No. 1-85, Safety and Reliability of Subsea Production Systems.

  • (2) Where the concept safety analysis required by section 43 indicates a risk of damage to the subsea production system components from ice, dropped objects, trawl board nets or anchors, the design of the system shall include measures to minimize such damage.

  • (3) The rigid risers in the subsea production system of a fixed platform and the steel flowlines and flowline connectors in every subsea production system shall comply with National Standard of Canada CAN/CSA-Z187-M87, Offshore Pipelines.

  • (4) Every subsea production system and its components shall be subjected to equipment integration tests in accordance with section 7.2 of American Petroleum Institute RP 17A, Recommended Practice for Design and Operation of Subsea Production Systems.

  • (5) Every subsea production system shall be installed in accordance with section 7.3 of American Petroleum Institute RP 17A, Recommended Practice for Design and Operation of Subsea Production Systems.

  • (6) Every subsea wellhead system and subsea tree located in a caisson, silo, or glory hole shall be designed and installed in such a manner that

    • (a) the effect of silting is minimized; and

    • (b) where practicable, inspection and maintenance during its production or injection life is possible.

  • (7) Every subsea production riser shall be designed and operated in accordance with section 6 of American Petroleum Institute RP 17A, Recommended Practice for Design and Operation of Subsea Production Systems.

  • (8) Every subsea production riser shall be designed

    • (a) to withstand the maximum pressure to which the riser may be subjected during its service life;

    • (b) so that every component that is used to transport oil or gas from the seafloor to the production installation can withstand without failure the wellhead shut-in pressure, except where the component is equipped with an isolation valve at the seafloor and a pressure relief system at the platform to relieve the internal pressure of the component; and

    • (c) to withstand any ice loads to which it may be subject as determined pursuant to section 44, except where failure of the riser will not lead to uncontrolled pollution.

  • (9) Flexible flowlines and risers in a subsea production system shall be designed in accordance with American Petroleum Institute RP 17B, Recommended Practice for Flexible Pipe.

  • (10) The end fittings of flexible flowlines or risers in a subsea production system shall have pressure integrity and load-bearing capacities greater than that of the pipe.

  • (11) The fatigue life of risers in a subsea production system shall be at least three times the service life of the production riser.

  • (12) Adequate provision shall be made in the design of the risers in a subsea production system and in the configuration of their individual components, including production, injection, control and instrumentation lines and their attachment assemblies, for the safe and efficient maintenance and inspection of the risers and their components during their service life.

  • (13) The analysis required by section 40 of the risers in a subsea production system in relation to fatigue and stress of the riser components and risk to the personnel and equipment as a result of failure or malfunction of individual components of the risers shall be performed using the methodology specified in section 6.5 of American Petroleum Institute RP 17A, Recommended Practice for Design and Operation of Subsea Production Systems.

  • (14) Every riser in a subsea production system shall be equipped so that it can be disconnected

    • (a) before heave or excursion limits specified in the operations manual are exceeded; or

    • (b) when ice conditions pose a threat of major damage to the production platform.

  • (15) Every riser on a subsea production system shall be equipped so that after it has been disconnected and reconnected it can be pressure tested in accordance with the procedures stipulated in the operations manual.

  • (16) Every component of the riser in a subsea production system that is used to convey the pool fluids to the surface, inject fluids or chemicals into the pool, or transport processed or treated fluids to or from the production installation shall be designed and equipped so that when the fluids pose a threat to the environment, the component can be displaced with water or securely isolated before the riser is disconnected.

  • (17) The templates and manifolds in a subsea production system shall be designed and operated in accordance with section 5 of American Petroleum Institute RP 17A, Recommended Practice for Design and Operation of Subsea Production Systems.

  • (18) The control systems, including control lines and pressurized control fluids, of every subsea production system shall be designed and operated in accordance with section 4 of American Petroleum Institute RP 17A, Recommended Practice for Design and Operation of Subsea Production Systems.

  • (19) Every subsea production system intended for manned intervention in an atmospheric chamber shall be designed in accordance with the requirements of Part B, Section 11, of Det norske Veritas Guideline No. 1-85, Safety and Reliability of Subsea Production Systems.

 
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