PART IIAnalysis and Design (continued)
61 (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 no 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
Subsea Production Systems
62 (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 44 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 offshore 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
(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 45, 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 Det norske Veritas Technical Note TNA 503, Flexible Pipes and Hoses for Submarine Pipeline Systems.
(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 41 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
(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.
PART IIIConstruction and Installation Offshore
(a) for a steel platform, sections 17, 18, 19, 20 and 21 of Canadian Standards Association CAN/CSA-S473-92, Steel Structures, Offshore Structures;
(b) for a concrete platform, section 11 of Canadian Standards Association Preliminary Standard S474-M1989, Concrete Structures;
(c) for a gravity-base, fill, fill-retention or piled platform, sections 6.3, 7.3, 8.3 or 9.4, respectively, of Canadian Standards Association CAN/CSA-S472-92, Foundations, Offshore Structures; and
(d) in respect of the foundation, section 5.4 of Canadian Standards Association CAN/CSA-S472-92, Foundations, Offshore Structures.
(2) Every vessel or barge used for the construction, transportation, up-ending or positioning of an offshore installation or a component of an offshore installation shall
(a) be classified by a classification society or have documentation to prove that a similar verification process has taken place;
(c) be certified by the owner as being capable of performing the assigned task or tasks safely and as being otherwise fit for the services it is expected to provide.
(3) All slings, wire cables, shackles and any other component used for lifting and for securing loads during the construction, transportation, up-ending or positioning of an offshore installation or a component of an offshore installation shall have a minimum load factor of 3.
(4) Where loads developed during movement of an offshore platform from the construction site to the production site or drill site or during installation operations are in excess of those that will be encountered after installation, the platform shall be provided with load- and strain-measuring devices during the movement or installation of the platform.
PART IVOperations and Maintenance Offshore
Manual, Plans and Programs for Offshore Installations
(a) limitations on the operation of the installation and its equipment;
(b) information as to environmental conditions at the site where the installation will be installed and the effect of those conditions on the installation, including
(i) environmental conditions for which an offshore installation will be evacuated and the meteorological forecast following which such evacuation will be initiated,
(ii) the amount of snow and ice that may be allowed to accumulate on the installation,
(iii) the amount of marine growth that may be allowed to accumulate on the installation, and
(iv) for a mobile offshore platform, any operating limits imposed by environmental conditions and the effect of wind, sea, snow, ice and marine growth on the strength, stability and seaworthiness of the platform while in transit, in the operating condition or in the survival condition;
(c) for a fixed offshore platform, the characteristics of the platform foundation, bottom penetration and the maximum permitted amount of scour or other changing seabed conditions;
(d) for a mobile offshore platform that is supported by the seabed,
(i) information concerning the different seabed conditions acceptable for the installation, including the varying capacity of the seabed, limiting values of seabed slope, and maximum and minimum penetrations of footings, and
(ii) a program for inspecting for scour at regular intervals and after storms of a specified intensity;
(e) for a floating mobile offshore platform, information concerning stability, including all data and instructions necessary to determine whether any intended configuration of, or change to, the loading or ballasting will satisfy the stability requirement for the platform;
(f) information concerning permissible deck loads, variable load limits and preloading;
(g) details of any colour coding system used on the installation for the safety of personnel;
(h) information on corrosion protection systems used and any requirements for the safety and maintenance of the systems;
(i) details of openings and means of closure in watertight compartments;
(j) drawings that show
(i) the general arrangement of the deck structure, accommodation areas, helideck and equipment contained on the topside facilities,
(ii) for a fixed steel platform, the jacket, piling, risers and conductors,
(iii) for a gravity-base platform and a fill-retention platform, the lower concrete or steel platform including any skirt arrangements or piling, the deck structure connection to the lower structure, the risers and the conductors,
(iv) for a self-elevating mobile offshore platform, the main and supporting platforms, the equipment for the elevating and lowering of the deck structure and any arrangements for towing,
(v) for a column-stabilized mobile offshore platform, the main and support structure, the method for maintaining the station and arrangement for towing,
(vi) for a surface mobile offshore platform and any similar- shaped platform, the hull structure and the positioning equipment,
(vii) for a fill platform, the erosion protection and a cross-section of the platform including the locations of the conductors,
(viii) the locations of escape routes, fixed fire- extinguishing systems and life-saving appliances,
(ix) the fire divisions and the location of associated equipment, such as fire dampers,
(x) the location of the hazardous areas on the installation, and
(xi) for a floating mobile offshore platform, the ballast and bilge systems and all openings and means of closure that could affect the stability of the platform;
(k) the operating and maintenance requirements for all the life-saving appliances on the installation;
(l) the maximum helicopter weight and wheel centres, and maximum size of the helicopter for which the helicopter deck on the installation has been designed, including the extent of the obstacle-free approach zone for the helicopter;
(m) special arrangements or facilities for the inspection and maintenance of the installation, any equipment or plant, and any crude oil storage facilities on or in the installation;
(n) special precautions or instructions to be followed when repairs or alterations to the installation are to be carried out;
(o) any special operational or emergency requirements covering essential features of the installation, including the shutdown systems;
(p) a description of any equipment for elevating and lowering the installation and of any special types of joints, including details of their purpose, proper operation and maintenance;
(q) for a fixed offshore platform, details of the air gap or freeboard;
(r) for a mobile offshore platform, the means of ensuring that the air gap requirements determined in accordance with subsection 51(1) are met;
(s) the environmental loads the anchors can sustain to keep the installation moored in place, including the estimated holding power of the anchors in relation to the soil at the drill site or production site;
(t) for a floating platform,
(i) procedures for dealing with the excursion of the platform because of the failure of any anchor line, as determined by analysis,
(ii) where there is a thruster-assisted mooring system, procedures to control operations when thruster power is lost, and
(iii) where there is a dynamic positioning system, a description of the capability of that system in all operational and survival conditions within stated tolerances, when any single source of thrust has failed and full power is being supplied for all foreseeable operations and emergency services;
(u) details of the number of persons to be accommodated during normal operations;
(v) brief particulars of all the equipment on the installation, including flow sheets and instructions for the installation, operation and maintenance of the equipment;
(w) the procedure for preparing, and the description and format for, periodic reports concerning the integrity of the installation; and
(x) a procedure for notifying the Chief of any situation or event described in section 68.
(2) The part of the operations manual relating to the subsea production system shall comply with the requirements of sections 7.4 and 7.5 of American Petroleum Institute RP 17A, Recommended Practice for Design and Operation of Subsea Production Systems.
- SOR/2009-315, s. 100
- Date modified: