API Recommended Practice 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms—Working Stress Design API Recommended Practice 2RD, Design of Ri
Terms and Definitions
For the purposes of this document, the following definitions apply.
The maximum difference, at each cross section, between internal pressure and external pressure during operating conditions
NOTE Section 4.3.1 sets limits on design pressure.
Loads that are unlikely to be exceeded during the lifetime of the pipeline.
4 American Welding Society, Inc., P.O Box 351040, 550 NW Le Jeune Road, Miami, Florida 33135, www.aws.org.
5 Det norske Veritas, Veritasveien, 1, N-1322 Hovik, Norway, www.dnv.com.
6 Department of Energy, Petroleum Engineering Division, 1 Palace St., London, SW1E 5HE, United Kingdom, www.hss.doe.gov.
7 Manufacturers Standardization Society of the Valve & Fittings Industry, Inc., 127 Park Street, NE, Vienna, Virginia 22180, www.mss-hq.com.
8 National Association of Corrosion Engineers International, 1440 South Creek Drive, Houston, Texas 77084, www.nace.org.
9 Offshore Mechanics and Arctic Engineering Symposium, ASME International, 3 Park Avenue, New York, New York 10016-
10 The Code of Federal Regulations is available from the U.S Government Printing Office, Washington, DC 20402.
The area seaward of the established coastline that is in direct contact with the open sea, and seaward of the line marking the seaward limit of inland coastal waters.
The vertical or near-vertical section of an offshore pipeline connects the platform piping to the pipeline located at or above the seabed This design is specifically intended to enhance personnel safety by reducing the risk of third-party damage and protecting against dropped objects.
For internal pressure design, the "pipeline riser" design factor is applicable to the riser pipe within a recommended horizontal distance of 300 feet from the surface facility, starting at the hang-off point for deepwater suspended risers In contrast, for shallow-water fixed platforms, the entire riser connected to the facility should utilize the "pipeline riser" design factor, and the pipeline on the seabed linking to the shallow-water fixed platform riser should also adhere to this design factor for a horizontal offset distance of 300 feet.
Loads that may occur during normal operation of the pipeline.
Piping that transports fluids between offshore production facilities or between a platform and a shore facility, often subclassified into the three categories: flowlines, injection lines, and export lines.
In this RP, the term "pipeline" encompasses three specific categories: an Export Line, which transports processed oil and gas between platforms or to shore facilities; a Flowline, which carries well fluids from the wellhead to the first downstream process component, specifically originating from subsea wellheads or manifolds; and an Injection Line, which directs liquids or gases into formations or wellheads to enhance hydrocarbon production activities, such as water or gas injection.
Any part of a pipeline that may be subjected to pressure by the transported fluids.
A pipeline and its components, including compressor stations and pump stations that are subjected to internal pressure by the transported fluids.
Piping is limited to a production or transportation hub platform, either confined to the platform itself or situated between launching and receiving traps, or from the first boarding Subsea Distribution Valve (SDV) to the last outgoing block valve in the absence of traps For further details on platform piping requirements, refer to API 14E.
NOTE 2 Launching and receiving facilities inclusive of the associated valves for pipeline cleaning/inspection devices shall be considered part of the pipeline from a design standpoint
A load necessary for equilibrium with applied loads.
NOTE A primary load is not self-limiting Thus, if a primary load substantially exceeds the yield strength, either failure or gross structural yielding will occur.
A facility that is operated to produce liquid or gas hydrocarbons and that includes such items as wells, wellhead assemblies, completion assemblies, platform piping, separators, dehydrators, and heater treaters.
The area of the pipeline riser or other pipeline components that is intermittently wet and dry due to wave and tidal action.
The pressure produced by sudden changes in the velocity of the moving stream of hydrocarbons inside the pipeline or riser.
Acronyms, Abbreviations, and Symbols
For the purposes of this document, the following acronyms, abbreviations, and symbols apply.
A cross-sectional area of pipe steel, in mm 2 (in 2 )
A i internal cross-sectional area of the pipe, in mm 2 (in 2 )
A o external cross-sectional area of the pipe, in mm 2 (in 2 )
CEBP capped end burst pressure in N/mm 2 (psi)
CEYP capped end yield pressure in N/mm 2 (psi)
D outside diameter of pipe (equation dependent)
D i inside diameter of pipe, in mm (in.) = (D – 2t)
D max maximum diameter at any given cross section, in mm (in.)
D min minimum diameter at any given cross section, in mm (in.)
DSAW double submerged arc welded d pipe outside steel pipe diameter d reel reel or aligner diameter
E Young’s modulus of elasticity, in N/mm 2 (psi)
The article discusses various factors related to flow-induced vibration and design considerations for pressure and bending loads Key terms include the collapse factor (\$f_c\$), internal pressure design factor (\$f_d\$), weld joint factor (\$f_e\$), and propagating buckle design factor (\$f_p\$) It also addresses safety factors for bending under installation and in-place conditions (\$f_1\$ and \$f_2\$), as well as the collapse reduction factor (\$g(\delta)\$) and computed burst factor (\$k\$) Additionally, it mentions the temperature derating factor (\$f_t\$) and the measurement of feet of saltwater (\$f_{sw}\$), along with the natural logarithm (\$ln\$) for calculations.
P a incidental overpressure (internal minus external pressure), in N/mm 2 (psi)
P actual actual measured burst pressure, in N/mm 2 (psi)
P b specified minimum burst pressure of pipe, in N/mm 2 (psi)
P c collapse pressure of the pipe, in N/mm 2 (psi)
P d design pressure of the pipeline, (internal minus external pressure) in N/mm 2 (psi)
P e elastic collapse pressure of the pipe, in N/mm 2 (psi)
P i internal pressure in the pipe, in N/mm 2 (psi)
P o external hydrostatic pressure, in N/mm 2 (psi)
P p buckle propagation pressure, in N/mm 2 (psi)
P t hydrostatic test pressure (internal minus external pressure), in N/mm 2 (psi)
P y yield pressure at collapse, in N/mm 2 (psi)
S SMYS of pipe, in N/mm 2 (psi)
SMYS specified minimum yield strength (see S)
T a axial tension in the pipe, in N (lb)
T eff effective tension in pipe, in N (lb)
T y yield tension of the pipe, in N (lb) t nominal wall thickness of pipe, in mm (in.) t min minimum measured wall thickness, in mm (in.)
U specified minimum ultimate tensile strength of pipe, in N/mm 2 (psi)
U actual average measured ultimate tensile strength of pipe, in N/mm 2 (psi)
The average measured yield strength of the pipe is expressed in N/mm² (psi), while the thermal coefficient of expansion and density are also critical factors, with density measured in lb/ft³ Key parameters include δ for ovality, ε for bending strain, ε_b for buckling strain under pure bending, and ε_nom for nominal bending strain in the pipe Additionally, ε_1 represents the maximum installation bending strain, and ε_2 denotes the maximum in-place bending strain Axial stress in the pipe wall is indicated by σ_a, measured in N/mm² (psi), and Poisson’s ratio is typically 0.3 for steel.
Design Conditions
4.1.1.1 Offshore hydrocarbon pipelines, with the exceptions noted in Section 1, should comply with all sections of this RP.
The selection of pipes for offshore pipelines is primarily influenced by installation and operational loads, alongside stresses from internal pressure The design process should initiate with material selection and pipe sizing based on flow requirements, followed by adjustments through design cycles that account for various factors These include burst resistance from internal pressure, combined bending and tension during installation and operation, collapse risks from external pressure, and buckling due to combined bending and external pressure Additionally, considerations for pipeline stability against displacement, thermal expansion and contraction effects, repair capabilities, fatigue from hydrodynamic and operational loading, spanning impacts from route selection, crossing requirements for pipelines and umbilicals, and fatigue during construction are essential for a comprehensive design.
4.1.1.3 This document is a limit state design practice because design is based on the strength of the pipe for each of the above limit states
4.1.2 Design for Internal and External Pressures
Pipeline components must be engineered or chosen to endure the maximum differential pressure between internal and external forces encountered during both construction and operational phases.
NOTE Design equations in this section using differential pressure apply to pipe or other round cylindrical shells only and may not be suitable for valves and similar components.
For such components, more detailed analysis is required to assess the combined effect of internal and external pressure, which is beyond the scope of this RP.
The maximum differential pressure in a flowline can arise from a shut-in pressure condition, which may occur when a valve at the production facility is closed while valves at the tree, manifold, or downhole safety valve remain open This condition can also result from leakage in these valves or plugging within the flowline It is essential to account for the shut-in pressure condition unless an overpressure protection device or system is in place, as outlined in API 14C.
In offshore pipeline design, it is crucial to account for external pressure affecting undersea pipeline systems The impact of external pressure is highlighted by instances of large pipelines buckling due to extreme bending and pressure conditions.
The design of the pipeline system must account for thermal expansion and contraction To accommodate anticipated temperature changes, it is essential to incorporate additional flexibility at the pipeline's connection to platforms or subsea junctions This can be achieved through the use of slack curves, pipeline bends, and thermal expansion devices.
To prevent excessive strains or fatigue damage from thermally induced upheaval buckling in buried pipelines and lateral buckling in non-buried pipelines, it is essential to implement adequate measures Design considerations must address fatigue, longitudinal, and combined loads, as outlined in sections 4.5 and 4.6.5, with additional details available in reference paper OTC 6335 [5].
High production temperatures can cause thermal expansion of production casing, resulting in increased elevation of subsea wellheads These elevation changes may lead to displacements and additional loads on connected equipment, including jumpers and flowlines.
Thermal expansion of subsea flowlines can cause movement in the mat foundations that support piping and valve equipment It is essential to design the mat foundation to handle repeated expansion movements, ensuring it prevents excessive rotation or settlement due to soil displacement beneath it.
The design must account for static loads on the pipeline, which encompass the weight of the pipe, coating, appurtenances, and attachments, as well as external and internal hydrostatic pressures, thermal expansion loads, and static forces resulting from bottom subsidence and differential settlement.
Weight-related forces are particularly critical in areas where pipelines lack continuous support, leading to potential spans These spans pose additional risks in regions susceptible to seismic liquefaction of the underlying ground and mudslides, notably in certain locations around the Mississippi River delta.
The submerged pipeline's weight can be managed by adjusting the pipe wall thickness along with the density and thickness of the external concrete weight coating It is essential to perform weight calculations that take into account the stability of the pipeline in three conditions: when it is empty (the typical as-laid condition), when it is filled with the transported fluid, and when it is flooded with seawater.
4.1.4.4 Consideration should be given to preventing unacceptably long unsupported lengths by use of dumped gravel, anchor supports, concrete mattresses, sand bagging, or other suitable means
4.1.4.5 Thermal expansion loads are not considered primary loads unless they can lead to buckling or axial collapse of the pipeline (see 4.3.1.3).
When designing pipelines, it is crucial to account for dynamic loads and the associated stresses, including those from impact, vibration from vortex shedding, seismic activity, soil movement, and other natural events Additionally, construction-related forces can create bending, compressive, and tensile stresses, which, when combined with other stressors, may lead to pipeline failure.
4.1.6 Relative Movement of Connected Components
4.1.6.1 The design should consider the effect of the movement of one component relative to another and the movement of pipe-supporting elements relative to the pipe.
An SCR must be designed in accordance with API 2RD standards, ensuring that the catenary risers can move without interfering with other risers and mooring lines The touchdown point of the catenary riser is anticipated to shift throughout its service life, which is acceptable as long as strain limits and fatigue life requirements are satisfied Additionally, the seafloor in areas where the SCR may touch down should be free of debris.
To ensure effective protection against external corrosion, it is essential to implement adequate anticorrosion coatings and cathodic protection, following the guidelines outlined in NACE SP 0607 Notably, when cathodic protection is in place, a corrosion allowance for external corrosion is unnecessary.
To safeguard against internal corrosion, it is essential to implement effective strategies such as choosing the right pipe material, applying internal coatings, and injecting corrosion inhibitors Additionally, the pipe wall thickness may need to include a corrosion allowance, although calculating this allowance is not covered in this guideline.
Design Criteria
This subsection provides design factors governing the maximum operating pressure (MOP) and the maximum incidental pressure of a pipeline system, and how these pressure levels relate (see Figure 2).
The Maximum Operating Pressure (MOP) must not surpass the design pressure of any component, such as pipes, valves, and fittings Additionally, it should remain below 80% of the hydrostatic test pressure as specified in section 8.2, ensuring safety within the burst pressure limit state.
NOTE See 9.2.2 for primary and secondary overpressure protection device settings. hydrostatic test pressure incidental overpressure maximum operating pressure (MOP) design pressure
0.750 0.675 0.600 operating pressure (OP) normal range atmospheric pressure
4.2.2.1.2 For purposes of design, pressure shall be interpreted as the difference between internal pressure and external pressure acting on the pipeline.
Some regulations link the Maximum Operating Pressure (MOP) to a maximum internal source pressure Although these regulations may permit the consideration of external pressure, the definition of the required hydrostatic test pressure may vary from the definition provided in this Recommended Practice (RP) Please refer to the note in section C.2 for further details.
Incidental overpressure refers to conditions where a pipeline experiences surge pressure, unintended shut-in pressure, or other temporary incidents It is crucial that this incidental overpressure does not surpass 90% of the hydrostatic test pressure While incidental pressure may temporarily exceed the Maximum Operating Pressure (MOP), it is essential that the normal shut-in pressure remains within the MOP limits.
4.2.3 Pressure Ratings for Pipeline Components
Valves, flanges, and other components should have pressure ratings that are equal to or exceed the requirements for the pipeline or flowline See note in 4.1.2.1.
Components that do not meet standard specifications can still be qualified for use according to ASME B31.4 or ASME B31.8 It is essential that nonmetallic trim, packing, seals, and gaskets are constructed from materials that are compatible with both the pipeline fluid and the offshore environment.
Pipelines designed to function at varying Maximum Operating Pressures (MOPs) must include an isolation valve and related components rated for the highest MOP at the pressure segmentation point To safeguard the lower MOP segment from overpressure, high-pressure shutdown devices should be installed at the relevant connected platforms, or a relief system should be implemented if the segment ends onshore Additionally, the automatic or remote operation of the valve at the pressure segmentation point should only be considered if the reliability of communication and power supply to the valve is adequately guaranteed.
For lines where there is a pressure break topsides, a redundant shutdown system consisting of two independent isolation valves with independent pressure shutdown switches should be considered.
Pressure Design of Components
The hydrostatic test pressure, pipeline design pressure, and incidental overpressure—encompassing both internal and external pressures on the pipelines—must not surpass the limits established by the relevant equations (refer to Figure 2).
P a ≤ 0.90 P t (3) where f d is the internal pressure (burst) design factor, applicable to all pipelines;
For pipeline risers, a weld joint factor (\$f_e\$) of 0.75 is applicable for both longitudinal and spiral seam welds, as outlined in ASME B31.4 and ASME B31.8 It is important to note that only materials with a factor of 1.0 are deemed acceptable Additionally, the temperature derating factor (\$f_t\$) specified in ASME B31.8 is 1.0 for temperatures below 121 °C.
P a is the incidental over pressure (internal minus external pressure), in N/mm 2 (psi).
P b is the specified minimum burst pressure of pipe, in N/mm 2 (psi).
P d is the pipeline design pressure, in N/mm 2 (psi).
P t is the hydrostatic test pressure (internal minus external pressure), in N/mm 2 (psi).
The specified minimum burst pressure (P b ) is determined by one of the following equations:
D is the outside diameter of pipe, in mm (in.);
D i is D – 2t = inside diameter of pipe, in mm (in.);
S is the specified minimum yield strength (SMYS) of pipe, in N/mm 2 (psi) (see API 5L, ASME B31.4, or ASME B31.8 as appropriate); t is the nominal wall thickness of pipe, in mm (in.);
U is the specified minimum ultimate tensile strength of pipe, in N/mm 2 (psi); ln is the natural log.
NOTE 1 The two equations, Equation (4) and Equation (5), for the burst pressure are equivalent for D/t > 15 For low D/t pipe (D/t < 15), Equation (4) is recommended.
NOTE 2 Determination of specified minimum burst pressure for unlisted materials shall be in accordance with Annex A.
NOTE 3 Improved control of mechanical properties and dimensions can produce pipe with improved burst performance The specified minimum burst pressure may be increased in accordance with Annex B.
When a corrosion allowance is required, the design process should consider the following adjustment to the wall thickness used in the design equations:
1) the hydrostatic test pressure prior to first placing the pipeline in service shall not exceed the code test limit where the wall thickness includes the corrosion allowance;
2) the MOP (usually equal to the shut-in pressure for a flowline) shall not exceed the code operating limit where the wall thickness does not include the corrosion allowance.
The effective tension due to static primary longitudinal loads (see 4.6.2) shall not exceed the value given by:
A is the cross-sectional area of pipe steel, in mm 2 (in 2 );
A i is the internal cross-sectional area of the pipe, mm 2 (in 2 );
A o is the external cross-sectional area of the pipe, mm 2 (in 2 );
P i is the internal pressure in the pipe, in N/mm 2 (psi);
P o is the external hydrostatic pressure, in N/mm 2 (psi);
T a is the axial (material) tension in pipe, in N (lb);
T eff is the effective tension in pipe, in N (lb);
T y is the yield tension of the pipe, in N (lb); σ a is the axial stress in the pipe wall, in N/mm 2 (psi).
The term "effective" tension refers to the interaction between a pipeline and surrounding structures, such as sleds and anchor points The effective tension is defined as the applied force at a boundary condition, which fluctuates with changing loading conditions along the pipeline's on-bottom section Initially, when a pipeline is installed on the seabed, the effective tension matches the residual horizontal lay tension For a single pipeline under fully restrained conditions, the effective tension, denoted as \( T_{\text{eff}} \), can be calculated accordingly.
T lay is the residual lay tension;
In the case of a pipe-in-pipe (PIP) system, where the inner pipe is free-standing within the outer pipe during construction, the term \$T_{lay}\$ will be negative without mitigation, contributing to both pressure and temperature loading The internal pressure change since the pipe's laydown is represented by \$\Delta P_i\$.
E is Young’s modulus of elasticity; α is the thermal coefficient of expansion of the pipe; ΔT is the temperature change in the pipe since laydown; ν is the poisson ratio.
In an SCR, the surface effective tension matches the hangoff load at the end fixture To accurately calculate the axial material tension in the pipe, it is essential to account for both internal and external pressure loads.
The combination of primary longitudinal load (static and dynamic) and differential pressure load shall not exceed that given by:
4.3.1.3 Axial Collapse/Burst Due to Combined Axial Compressive Load and Internal Pressure
Axial compressive loads combined with internal pressure can lead to material stresses that exceed the yield strength of pipes, posing a risk of axial collapse or burst failure due to overload and strain localization This risk is particularly significant in deepwater PIP construction using J-lay or S-lay methods, where the inner and outer pipes are not continuously linked structurally During pipelay, the inner pipe may remain nontensioned and free-standing within the outer pipe, with all tension loads borne by the outer pipe The inner pipe must support its own weight, resulting in compressive stress at touchdown on the seabed As the PIP is laid, the inner pipe's compressive load becomes permanently captured by friction with the outer pipe By the end of pipelay, the inner pipe experiences a permanent compressive stress that can be calculated as (water depth × inner pipe unit weight/inner pipe steel area), which in deep water (greater than 1500 m) can reach 25% to 50% of the axial compressive yield load.
High operating temperatures can cause axial stress in pipes, potentially exceeding their yield strength This may lead to excessive strain accumulation in weak sections of the inner pipe, resulting in failure through axial collapse or burst when the wall strains surpass the material's capacity For more information, see OTC 18063 [7].
Offshore hydrocarbon pipelines face external pressures that can exceed internal pressures during construction and operation, potentially leading to pipe collapse due to differential pressure from hydrostatic head It is crucial to select pipes with sufficient strength to withstand these conditions, accounting for variations in physical properties, ovality, bending stresses, and external loads The design calculations for external pressure must incorporate the combined application of Equations (9) through (17) as outlined in the subsequent sections.
For operational loads For extreme loads For hydrotest loads
4.3.2.1 Collapse Due to External Pressure
The collapse pressure of the pipe shall exceed the net external pressure everywhere along the pipeline as follows:
(9) where f o is the collapse factor;
= 0.7 for seamless or electric resistance welded (ERW) pipe;
= 0.6 for cold expanded pipe, such as double submerged arc welded (DSAW) pipe.
In certain situations, cold expanded pipes can benefit from a partial recovery of compressive yield strength through heat treatment at a minimum of 233 °C (450 °F) for several minutes This heat treatment can occur during the fusion bond epoxy coating process, provided that the temperature and duration are meticulously controlled Consequently, the collapse factor may be increased from 0.6 to a maximum of 0.7, but this proposed enhancement in the design factor must be validated through a comprehensive testing program.
P c is the collapse pressure of the pipe, in N/mm 2 (psi).
The following equations can be used to approximate collapse pressure:
E is the modulus of elasticity, in N/mm 2 (psi);
P e is the elastic collapse pressure of the pipe, in N/mm 2 (psi);
P y is the yield pressure at collapse, in N/mm 2 (psi),
To ensure the appropriate wall thickness is selected for varying water depths, it is essential to compare the collapse pressure predicted by these equations with the hydrostatic pressure resulting from the water depth.
4.3.2.2 Buckling Due to Combined Bending and External Pressure
Combined bending strain and external pressure load should satisfy the following:
+ ≤g( )δ where f c is the collapse factor for use with combined pressure and bending loads; recommended value for f c : f c = 0.6 for cold expanded pipe such as DSAW pipe; f c = 0.7 for seamless pipe.
For installation conditions, higher collapse factors of up to 1.0 may be considered It is essential to ensure that the conditions for collapse, as outlined in Equation (9), are met, regardless of the chosen value for \( f_c \).
The collapse factor \( f_c \) has been incorporated into Equation (13) in this edition of the practice, addressing its previous absence This addition ensures consistency among DNV design codes, this practice, and API 2RD, as referenced in OTC 13013 [8].
To avoid buckling, bending strains should be limited as follows:
The collapse reduction factor, denoted as \( g(\delta) = (1 + 20\delta)^{-1} \), is crucial in assessing the bending strains in pipes Key parameters include \( \epsilon \), the bending strain; \( \epsilon_b \), the buckling strain under pure bending; \( \epsilon_1 \), the maximum installation bending strain; and \( \epsilon_2 \), the maximum in-place bending strain Additionally, \( f_1 \) represents the bending safety factor for installation bending combined with external pressure, while \( f_2 \) indicates the bending safety factor for in-place bending under external pressure.
D max is the maximum diameter at any given cross section, in mm (in.);
D min is the minimum diameter at any given cross section, in mm (in.).
NOTE Equation (13) is acceptable for a maximum D/t = 50 Refer to the OMAE article for utilizing ratios higher than 50.
Bending strains \$\epsilon_1\$ and \$\epsilon_2\$ are not merely nominal global bending strains; they must account for potential strain concentrations For instance, when a pipe is reeled, the nominal bending strain experienced by the pipe on the reel or aligner is defined as:
(16) where d pipe is the outside steel pipe diameter; ε≥f 1ε 1 ε≥f 2ε 2 ovality D max–D min
- d reel is the reel or aligner diameter.
The maximum installation bending strain is then given by:
SAF is the strain amplification factor (≥ 1.0)
In insulated reeled flowlines, if the stiffness of the field joint coating is lower than that of the pipe insulation, the bending strain at the field joint exceeds the nominal strain, ε nom Additionally, discrepancies in wall thickness and yield strength between adjacent pipe joints can lead to considerable strain amplification at the field joint Therefore, a more detailed analysis is essential to establish a suitable value for the Safety Assessment Factor (SAF) It is crucial to avoid abrupt changes in wall thickness of reeled pipes.
Marine Design
The design of an offshore pipeline must account for the forces, stresses, and strains experienced during the laying process, as well as those from the offshore environment over time In scenarios like installation by reeling, these strains can significantly influence the selection of the specified minimum yield strength (SMYS) and the wall thickness of the pipeline Additionally, when dynamic loading is involved, conducting a fatigue analysis for both pipelines and pipeline risers is essential The relationship can be expressed as \$\epsilon_1 = \text{SAF} \times \epsilon_{\text{nom}}\$.
4.4.1 Installation of Pipeline and Riser
Normal lay methods for pipe installation include several techniques: Conventional pipe-lay, or S-lay, involves laying the pipe from a near-horizontal position on a lay vessel using horizontal tension and a stinger for support Vertical pipe-lay, known as J-lay, utilizes an elevated tower on a lay vessel to install the pipe with longitudinal tension, preventing over-bend at the sea surface The reel barge lay method consists of assembling the pipe at a remote location, spooling it onto a large reel on a reel lay vessel, and then reeling it off with longitudinal tension, often requiring pipe straightening Lastly, the towed lay method transports the pipe from an assembly site to the installation location by towing it on the water surface, at a controlled depth, or along the seabed.
Offshore pipelines experience forces induced by waves and currents, leading to lift and drag forces when resting on the seabed In sections suspended above seabed irregularities, oscillations may arise due to vortex shedding It is essential to evaluate these forces under different conditions: when the pipeline is empty (construction condition), when it is filled with transported fluid (operating condition), and when it is filled with seawater.
The lift and drag forces from water flow can cause significant strains and fatigue on offshore pipelines, potentially leading to issues such as lateral movements and encroachment on other structures To mitigate these effects, a restraining force is typically provided by the pipeline's on-bottom weight, which can be adjusted through the wall thickness of the pipe and the density of the weight coating In suitable bottom conditions and water depths, alternatives like anchors or weights may be used, and burial of the pipeline below the seabed can enhance stability.
4.4.2.3 The AGA Level 2 or Level 3 analysis for submarine pipeline on-bottom stability may be used for assessing on bottom stability requirements.
Specific geographic locations may experience natural phenomena that can subject offshore pipelines to unusual forces Therefore, it is essential to incorporate these forces into the design of offshore pipelines to ensure their stability and safety.
Natural phenomena significantly impact offshore pipelines Earthquakes can liquefy seabottom sediments, causing pipelines to either sink or float based on their specific gravity, and may also result in spanned conditions due to surface uplifts along fault lines Similarly, hurricanes, cyclones, and typhoons generate high currents and cyclic wave action that can weaken seabottom sediments, leading to potential sinking, floating, or lateral movement of pipelines Additionally, gross seabottom movements, such as mudslides or subsidence, exert large lateral forces on pipelines, which may also sink, float, or shift laterally as sediments become liquefied Furthermore, sediment transport or scour from bottom currents and wave action can expose buried pipelines, reduce soil restraint, or increase free spans.
In water depths up to approximately 200 m where pipelines are not buried, it is crucial to assess severe bottom currents and potential soil instability This evaluation helps determine if design modifications are necessary, such as incorporating additional weight coating and increasing wall thickness.
Quantifying the impact of natural phenomena on a specific offshore pipeline and location can be challenging It is essential to consider adjusting the design to avoid areas prone to seabottom movement In unique situations where traditional weight-coating or trenching methods are ineffective, such as on solid rock or in shallow waters with strong currents, utilizing anchors or pipeline weights may serve as a practical alternative.
The length of unsupported spans on an offshore pipeline should be controlled to avoid excessive loads or deformations in the pipeline.
4.4.3.1 Span Limitation Due to Weight, Pressure, and Temperature
See 4.1.4 and 4.6.3 for the static loads and limits on combined loads in determining the span limitation due to its own weight, pressures, temperature, and primary longitudinal loading.
4.4.3.2 Span Limitation Due to Vortex Shedding
Spans exposed to the transverse flow of seawater from currents and waves experience a phenomenon known as vortex shedding, which can lead to oscillations in the pipeline This occurs as shedding vortices create alternating pressure changes above and below the pipe Significant oscillations may arise when the span's natural frequency aligns closely with the frequency of vortex shedding.
4.4.3.2.2 Detailed procedures for vortex-induced vibration (VIV) are beyond the scope of this RP; detailed guidance on VIV analysis is available in DNV-RP-F105.
To enhance the fatigue resistance of circumferential welds in predictable spanning areas, stricter weld acceptance criteria can be implemented VIV suppression devices, including strakes or fairings, may be installed during pipelay operations or added post-lay in identified span regions It is essential to use a "CP-porous" design for strake materials when covering fusion bonded epoxy (FBE) coated pipes to avoid interfering with cathodic protection Additionally, effective strategies to mitigate VIV excitation of spans include jetting pipe ends to shorten span lengths and providing support at discrete points to minimize the affected length.
Fatigue Analysis
All pipeline components, including risers, flowlines, and welds, must undergo a fatigue assessment due to potential cyclic loadings such as VIVs, wave-induced hydrodynamic loads, and internal flow-induced vibrations The fatigue life is defined as the duration until a through-wall-thickness crack develops, with the design fatigue life, as predicted by the Palmgren-Miner (S-N) methods, needing to be at least five times the service life of the pipelines Additionally, risers may require larger safety factors as per API guidelines.
2RD) An S-N fatigue analysis to the stated criteria is sufficient to assure integrity for anticipated base metal components however a fracture mechanics crack growth analysis may be required for weldments
Weld procedures for fatigue-sensitive pipeline sections often necessitate full-scale fatigue testing of welded pipe specimens to ensure they have adequate lifespan It is essential to test a sufficient number of specimens to achieve a 95% probability that the welds satisfy the mean S-N design performance criteria.
In a fracture mechanics crack growth analysis, it is essential to use the smallest rejectable flaw size identified during the nondestructive testing of the component during manufacturing.
4.5.3 Bending is an important consideration for fatigue For instance, wave-induced bending moments in the splash zone are important for fatigue consideration.
For an SCR, the S-N method dictates that the accumulated fatigue damage from a 100-year hurricane event, lasting 30 hours, must remain below 1.0 This scenario is equivalent to a 100-year design storm of three hours with a safety factor of 10, ensuring the riser's integrity against fatigue during hurricanes Additionally, the riser must be evaluated for vortex-induced vibrations (VIVs) that may occur during significant events, such as a 100-year loop current in the Gulf of Mexico If vibrations are anticipated, it is essential to install suppression devices like fairings or helical strakes along the affected riser section, which should be regularly inspected and cleaned to ensure optimal performance.
Fatigue damage from installation activities should be considered in the fatigue design of the riser Further guidance is given in API 2RD.
Load Limits
Field cold bends are acceptable provided that their radii are within the limits of Table 1 and the bent pipe meets the collapse and buckling criteria in 4.3.2
Static primary longitudinal loads, like the top tension of a catenary riser, must not exceed 60% of the pipe's yield tension In contrast, displacement-controlled conditions, including bending in J-tubes and catenary risers, do not have this limitation; however, the resulting strain must remain within acceptable limits For comprehensive design considerations, refer to API 2RD, ASME B31.4, and ASME B31.8.
Table 1—Minimum Radius of Field Cold Bends
(NPS) Minimum Radius of Field Bends
The combined load due to internal pressure and primary longitudinal loads should be limited to 90 % for functional loads, 96 % for extreme loads, and 96 % for hydrostatic test load [see Equation (8) in 4.3.1.2].
See 8.2.4 for limitations on hydrostatic test pressure.
The design and material criteria applicable to the expansion and flexibility of offshore hydrocarbon pipelines should be in accordance with 4.6.2 and 4.6.3.
Valves, Supporting Elements, and Piping
4.7.1 Valves, Fittings, Connectors, and Joints
When the wall thickness of adjoining ends of pipes, valves, or fittings is unequal, the welding joint design must adhere to ASME B31.4 for liquid pipelines or ASME B31.8 for gas pipelines Additionally, transverse segments from factory-made bends and elbows can be utilized for directional changes, provided that the arc distance along the crotch measures at least 50.8 mm (2 in.) for pipes with a nominal pipe size (NPS) of 4 or larger.
When designing seals for valves, fittings, and connectors, it is crucial to account for external pressure, especially in deep-water pipelines where it can surpass internal operating pressure Additionally, seal designs must consider operating conditions that lead to frequent fluctuations in internal pressures, as these can cause pressure reversals on sealing mechanisms when combined with high external water pressure.
4.7.1.3 Where pigging devices are to be passed, all valves shall be of full-bore design.
4.7.1.4 Consideration should be given to the effects of erosion at locations where the flow changes direction.
Pipelines must have supports, braces, and anchors designed according to ASME B31.4 for liquid pipelines and ASME B31.8 for gas pipelines Additionally, it is essential to incorporate a riser guard for any riser that may come into contact with floating vessels during installation.
Riser guards are essential for protecting risers in areas vulnerable to marine traffic impacts They must be designed to withstand the impact from vessels of appropriate size and speed Additionally, the design should account for how the loads from the riser guard transfer to the platform structure In some cases, the platform structure itself can function as a riser guard when the riser is routed within its structural members.
4.7.3 Design of Supports and Restraints
Design of supports and restraints should employ the latest edition of API 2A-WSD.
Auxiliary hydrocarbon and instrument piping that carries pipeline fluids must be designed and built in accordance with ASME B31.4 for liquid pipelines or ASME B31.8 for gas pipelines, as well as the guidelines outlined in this RP for offshore hydrocarbon pipelines.
Route Selection
The offshore pipeline route must be carefully evaluated using data from charts, maps, and field hazard surveys It is essential to avoid areas such as anchorage zones, submerged objects, active faults, rock outcrops, chemosynthetic communities, and mudslide regions whenever possible Additionally, the chosen route should consider applicable installation methods to reduce installation stresses, and it must be accurately represented on appropriately scaled maps.
4.8.2 Preliminary Environmental, Bathymetric, and Hydrographic Surveys
When selecting a suitable route for an offshore pipeline, it is essential to conduct a field hazards survey to identify potential risks, including sunken vessels, piling, wells, geological and man-made structures, mudslides, and existing pipelines Understanding the bottom topography, geological features, and soil characteristics is crucial Additionally, data on normal and storm winds, waves, currents, and marine activity should be collected when available In areas where soil characteristics significantly impact design and previous studies have not sufficiently defined the bottom soils, on-site sampling is necessary Always consult the relevant regulatory agencies for the minimum requirements for conducting hazard surveys.
Flow Assurance
Flow assurance is crucial in the design of offshore pipelines for liquids, gases, and multiphase systems, ensuring sustained flow throughout the pipeline's lifespan under various conditions It encompasses the necessary facilities and operational procedures to maintain adequate flow during start-up, normal operations, shutdowns, and emergencies Key considerations include evaluating fluid properties, heat transfer, pressures, and flow conditions, as well as implementing flow treatments and pigging operations Design efforts should aim to prevent issues such as hydrate formation, paraffin and asphaltene deposition, inefficient multiphase flow, cooling below pour points, salt or sand drop-out, emulsion formation, and liquid slugging, all of which can lead to operational failures and flow restrictions.
In pipeline system design for colder environments, such as deeper waters off the Gulf of Mexico, maintaining temperatures above critical thresholds like pour point, cloud point, and hydrate formation temperature is crucial due to the higher operational risks To address these challenges, the industry is utilizing and developing solutions such as PIP, vacuum-insulated pipes, electrically heated flowlines, and chemical additives to mitigate the negative impacts of cold deep water conditions.
Thermal Expansion Design
Deep water pipelines are installed in seabed environments with temperatures between 3 °C and 5 °C (37 °F to 40 °F) and must cool to these temperatures before production begins Once oil or gas is introduced, the pipeline system heats up to operating temperatures of 50 °C to 150 °C (120 °F to 300 °F), leading to significant thermal expansion This expansion can cause unrestrained ends of the pipeline to move considerably, while restrained sections may experience elastic (Euler) buckling at unintended locations if not properly designed to accommodate this expansion Buckling can manifest as upheaval buckling in buried pipelines or lateral buckling in unburied pipelines.
Pipelines can experience complete failures due to cyclic thermal expansion fatigue damage from buckles shortly after start-up Unplanned upheaval or lateral thermal expansion buckles can result in a cyclic strain range exceeding 1%, which may lead to the collapse of pipeline sections or cause high strain-low cycle fatigue, ultimately resulting in cracking or rupture.
Insulated pipelines must be assessed for thermal expansion loading, but thermal expansion fatigue is not limited to insulated oil and gas production pipelines Water injection pipelines have also experienced fatigue failures caused by thermal and pressure-induced buckling.
Detailed guidance on thermal expansion design is outside the scope of this limit state design Designers are directed to SAFEBUCK [9] and HOTPIPE [3] for additional information.
Materials
Materials and equipment intended for permanent installation in any piping system constructed under this RP must be appropriate and safe for their intended conditions They should meet the necessary specifications, standards, and special requirements to ensure their suitability for use.
When designing liquid pipelines according to RP, ASME B31.4, or gas pipelines per ASME B31.8, it is crucial to account for temperature and environmental conditions that affect material performance, including toughness and ductility at minimum operating temperatures Additionally, the impact of corrosion must be evaluated, along with necessary measures to mitigate material deterioration during service It is important to note that the maximum hydrostatic test pressure specified in this RP may induce stresses that exceed yield strength near the pipe's inner surface, necessitating consideration of the potential growth of existing flaws under such loading conditions.
Components made from manufacturer-recommended composite materials can be utilized, while cast iron, bronze, brass, or copper pipes, valves, and fittings are prohibited for primary service applications in hydrocarbon pipelines This restriction applies when these materials are exposed to pipeline operating pressures or come into direct contact with the transported gas or liquid.
Only steel pipes that meet the standards outlined in ASME B31.4 and ASME B31.8, with a weld joint factor of 1.0, are deemed acceptable Any materials not specified must be qualified according to the relevant sections of ASME B31.4 or ASME B31.8, along with Annex A of this RP.
Valves that conform to API 6D or API 6A, as appropriate, are acceptable and should be used in accordance with service recommendations of the manufacturer.
Flanges that conform to ASME B16.5, ASME B16.47, MSS SP-44, or API 6A are acceptable.
5.1.5 Fittings Other Than Valves and Flanges
Acceptable components include elbows, branch connections, closures, reducers, and gaskets that meet the requirements of ASME B31.4, ASME B31.8, or API 6A Any components not specified by these standards must be qualified according to the guidelines set forth in ASME B31.4, ASME B31.8, or API 6A.
Riser hang-off support devices, including tapered stress joints, riser tensioning systems, and flexible hang-off elements, must be engineered to endure the specified environmental conditions, platform movements, snag loads, and extreme pressure and temperature fluctuations associated with the production program For comprehensive guidance on riser design parameters for floating production systems and tension leg platforms (TLPs), refer to API 2RD.
Dimensions
Offshore hydrocarbon pipelines must adhere to ASME dimensional specifications whenever feasible Alternative dimensional standards are permissible as long as the design strength and testing capabilities of the components meet or surpass those of the referenced components.
General
For each pipeline system, a safety system should be provided that will prevent or minimize the consequences of overpressure, leaks, and failures in accordance with API 14C.
Liquid and Gas Transportation Systems on Nonproduction Platforms
6.2.1 Hydrocarbon Systems on Platforms with Liquid Pumps or Gas Compressors
Pipeline facilities for liquid and gas hydrocarbons on nonproduction platforms must implement a safety system that complies with API 14C standards Additionally, the design of this safety system should address the necessity of controlling surge pressures and other operational deviations.
6.2.2 Hydrocarbon Systems on Platforms Without Liquid Pumps or Gas Compressors
Hydrocarbon pipeline facilities that include only junction piping, block valves, scraper traps, or measurement equipment on nonproduction platforms without liquid pumps, gas compressors, or other flow input sources are exempt from section 6.2.1 However, these facilities must have check valves or similar valves installed on each incoming line to prevent backflow.
Liquid and Gas Transportation Systems on Production Platforms
Pipeline facilities for liquids or gases on production platforms must implement a safety system that meets the standards set by the platform owner or operator However, the safety system must not fall below the minimum requirements specified in section 6.2.1.
Breakaway Connectors
In areas prone to mudslides, the potential for significant tensile pull on pipelines necessitates the use of breakaway connectors or specialty design failure joints to protect platforms and subsea connections To mitigate the risk of oil spills during a breakaway, it is essential to incorporate a built-in check-valve that minimizes fluid loss Careful selection and installation of the check-valve are crucial for ensuring prompt and effective closure Additionally, breakaway devices can serve as a weak link in the piping design at connection points.
Construction
Pipeline systems must be built according to written specifications that align with this RP The lay methods outlined in section 4.4.1, along with other construction techniques, are permissible under this RP as long as the pipeline fulfills all specified criteria.
The construction of offshore pipelines necessitates meticulous control during installation on the sea floor, requiring a well-designed and monitored installation system to ensure safe handling and maintain pipeline integrity A comprehensive written construction procedure must be established, outlining the permissible limits for key installation variables such as pipe tension, departure angle, water depth during laying and temporary abandonment, retrieval processes, termination activities, valve sled installation, and riser transfer to the host facility.
The construction procedure must adhere to the permissible limits for continuous lay operations, identify when correction or temporary abandonment is required, and outline the conditions that necessitate additional inspections for potential damage.
7.1.2.3 Construction workers should be advised of their safety-awareness responsibilities to protect themselves and the pipeline during construction.
The installation of pipelines must utilize an electronic tracking system, such as a GPS-based survey system, to ensure accurate positioning along the designated route It is essential to highlight all hazards and areas of concern near pipelay activities on the surveyor's tracking system Additionally, for shallow-water applications, physically marking pipelines or structures with buoys may be necessary to provide clear visual indications.
7.1.4 Handling, Hauling, and Storing of Materials
Materials intended for offshore construction must be managed according to ASME B31.4 for liquid pipelines or ASME B31.8 for gas pipelines When transporting pipe by railroad to the loading site, compliance with API 5L1 is essential Furthermore, if the transported loads experience harsh conditions during transit from the mill to the coating site, additional line pipe inspections may be necessary.
To ensure the integrity of materials during offshore transit, it is essential to secure them properly to prevent damage or deterioration Additionally, once at the offshore work site, materials must be safeguarded and protected from potential harm.
All materials must undergo inspection prior to their transfer to the offshore work site Any damaged materials should be either replaced or repaired in compliance with ASME B31.4 for liquid pipelines or ASME B31.8 for gas pipelines.
Welding
Welding and weld inspection of pipelines must adhere to API 1104 standards, ensuring that the accepted welding procedures are properly documented and maintained It is essential that construction practices consistently follow these established procedures.
Arc burns can lead to significant stress concentrations and must be prevented or eliminated To address the metallurgical notch caused by arc burns, grinding is required, ensuring that the remaining wall thickness meets the minimum specifications The process involves grinding the affected area until the arc burn is no longer visible, followed by applying a 20% ammonium persulfate solution to check for any remaining metallurgical notches, indicated by black spots that necessitate further grinding If the wall thickness falls below the specified limits after grinding, the section of the pipe with the arc burn must be removed, as patching is not allowed.
AWS D3.6M should be used in conjunction with this RP to specify fabrication and quality assurance standards for underwater welding.
Welding in a pressure-vessel in which the pressure is reduced to approximately 1 atmosphere, independent of depth, is permitted.
Three types of hyperbaric welding are recognized: Habitat Welding, which occurs in a large chamber with displaced water, allowing the welder-diver to operate without diving equipment; Dry Chamber Welding, conducted in a simple, open-bottomed chamber that accommodates the welder-diver's head and shoulders while in full diving gear; and Dry Spot Welding, performed in a small, transparent gas-filled enclosure with the welder-diver outside the enclosure and in the water, fully equipped for diving.
Hyperbaric welding must adhere to specific guidelines, including the use of low-hydrogen processes, the implementation of preheating to an appropriate temperature for effective moisture removal and hydrogen diffusion, and the establishment of detailed procedures for welding consumables.
1) storage and handling on the support vessel,
2) storage and handling within the welding chamber,
3) sealing in preparation for Item 4),
4) transfer between the support vessel and the welding chamber.
Before construction welding begins, it is essential to establish a detailed procedure specification that must be qualified through testing weldments under actual or simulated site conditions in an appropriate testing facility In addition to adhering to API 1104 or ASME Boiler and Pressure Vessel Code Section IX, the specification should encompass the internal pressure range of the chamber, the range of water depths (ambient pressure), the gas composition within the chamber, humidity levels, temperature variations inside the chamber, and the temperature range of the pipe section to be welded.
The key factors outlined in API 1104 and ASME Boiler and Pressure Vessel Code Section IX include the pressure within the chamber, the composition of gases present, and the range of humidity.
Underwater welders must successfully complete relevant welding tests above water before qualifying for underwater welding Adequate training is essential to help welders understand how pressure, temperature, and atmospheric changes affect the welding process The AWS D3.6M standard can be utilized alongside this RP to outline the fabrication and quality assurance requirements for underwater welding.
Other Components and Procedures
7.3.1 Installation of Underwater Pipelines and Risers
Proper installation procedures are essential to protect pipe materials, structures, and the final configuration of the pipeline Handling criteria during installation must take into account the chosen technique, minimum bending radii, differential pressure, and pipe tension It is acceptable to adhere to stress or strain limitations that are both safe and practical.
7.3.2.1.1 Where trenching is specified during or after the installation of a pipeline, trenching equipment should be installed, operated, and removed to prevent pipe and coating damage.
The standard trench depth for a pipeline is set to ensure a 0.9 m (3 ft) elevation difference between the pipe's top and the average seabed In cases where extra protection is required or mandated, a thorough evaluation of potential hazards will determine the necessary trench depth.
7.3.2.2.1 Cover material is not normally installed over the pipeline except where the pipeline will not acquire a natural cover or where more protection is required early in the pipeline’s life.
In surf zones where backfill or riprap is required, it is essential to install these materials to prevent damage to the pipe and its coating Additionally, when pipeline-padding material is specified, it should be meticulously placed to ensure the protection of the pipe and coating from potential harm.
Pipeline crossings must adhere to the design, notification, installation, inspection, and as-built record requirements set by regulatory agencies and pipeline owners or operators It is essential to maintain a minimum separation of 12 inches, typically achieved through the use of sand-cement bags or concrete-block mattresses.
7.3.2.4 Seabottom Protection of Valves and Manifolds
To safeguard subsea pipeline valves, manifolds, and other equipment from fishing trawls and anchor lines, it is essential to implement protective measures While direct protection from anchors is limited, minimizing damage from the lateral movement of anchor cables—often the primary cause of harm to these structures—is crucial.
Regulatory agencies typically require the burial and covering of valves and manifolds, although exceptions may be granted In these instances, it is essential to implement and maintain protective measures to safeguard the pipe and related equipment These protective designs must ensure that they do not hinder trawling or other offshore activities.
7.3.3 Fabrication of Scraper Traps, Strainers, Filters, and Other Components
Pipeline components, such as pumping and compressor piping manifolds, as well as storage and auxiliary piping, must be fabricated in accordance with the provisions of this standard, whether done in a shop or in the field.
General
During construction, it is essential for the operating company to ensure that qualified inspectors conduct thorough inspections of pipelines and related facilities to comply with material, construction, welding, fabrication, testing, and recordkeeping standards This includes inspecting materials and conducting transport surveys to verify the proper securing of loads during vessel, rail, or truck transport Underwater inspections must utilize appropriate methods and equipment tailored to specific conditions, with personnel qualifications and inspection scope adhering to established recommendations Repairs during new construction or system replacements should follow specified guidelines Special attention is required for inspections in areas with unstable soils, trenched sections, pipeline crossings, mechanical connections, and other critical points such as J-tube entries and riser connections to platforms.
Qualified inspection personnel must possess relevant experience or training specific to the construction phase they are overseeing Inspections are essential for various aspects, including pipeline routing, pipe condition, alignment, welding, coating, tie-in, pipelaying, trenching, and pressure testing.
The operating company must ensure proper inspections are conducted, with inspectors empowered to mandate the repair, removal, or replacement of any components that do not comply with the relevant design codes or specifications.
In specific cases, the permitting authority may mandate an independent third-party inspection to assess the design, fabrication, and installation of deepwater risers A certified verification agent (CVA) might be necessary to evaluate the operating company's riser program and provide approval for all three phases of the project.
Proper cleaning of pipes is essential for effective inspection and detection of defects that may affect their strength and serviceability Before applying any coating, it is crucial to inspect the pipes for both internal and external defects, including bends, buckles, ovality, and surface issues like cracks, grooves, pits, gouges, dents, and arc burns Additionally, when using pipes of varying grades or wall thicknesses, it is important to ensure proper identification throughout the handling and installation process.
8.1.2.1.2 All pipeline components should be inspected for evidence of mechanical damage.
Pipe coating inspection must adhere to the guidelines outlined in section 10.2 and comply with ASME B31.4 for liquid pipelines or ASME B31.8 for gas pipelines It is essential to inspect externally coated pipes before applying weight coating.
To ensure the integrity of pipe surfaces, it is essential to inspect coating equipment for any harmful gouges or grooves Additionally, pipe coatings must be evaluated for adherence to weight, dimension, and material specifications.
8.1.2.2 Inspection During and After Installation
Records must be kept detailing the installation location of pipes, including specifications such as grade, wall thickness, manufacturing process, manufacturer, coating, anode location, and size Prior to coating, pipes should be swabbed for a clean interior and inspected for defects, ensuring damage-free bevels and proper joint alignment A visual inspection of the pipes is required just before the coating process, which includes field joint coatings Areas with damaged coatings must be inspected before any repairs, and any damaged or defective coatings, pipes, and components should be repaired or replaced, followed by inspections as outlined in Sections 7 and 10 before installation.
All phases of the pipeline installation procedure must be closely monitored to ensure operations remain within acceptable limits Components suspected of installation damage require supplemental inspection before the pipeline system is operational Both field and shop welds must comply with the procedures outlined in Section 7.1, and all girth welds should undergo visual inspection For offshore pipelines, it is essential that 100% of girth welds are inspected using radiographic, ultrasonic, or other nondestructive methods before coating, with a minimum requirement of 90% inspection coverage The inspection process must encompass the entire length of the welds being examined.
To ensure proper installation of seabottom pipes, it is essential to inspect their condition whenever feasible This includes verifying the correct placement of material for pipeline cover, particularly when installed to control scouring Suitable underwater inspection methods may involve saturation diving, atmospheric diving suits, remotely operated vehicles, submarines, sonar inspections, seismic inspections, or a combination of these techniques.
Certified as-built surveys and drawings must be created during or after construction, utilizing reliable methods to ascertain actual pipeline coordinates These records and maps should reference preconstruction route survey data and encompass details such as hazards, spans, trenching, soil conditions, anomalies, pipeline crossings, and both existing and new facilities or appurtenances, along with pipe and coating properties.
Construction reports must document inspection records for all materials, such as pipes, valves, and fabrications, focusing on any physical damage Additionally, these reports should include records of damaged external coatings and details regarding the repair of those affected areas.
Records must document welder qualifications and approved welding procedures, adhering to ASME B31.4 for liquid pipelines and ASME B31.8 standards It is essential to retain nondestructive inspection records that include inspector qualifications and inspection procedures Additionally, these records should detail the results of each test and the outcomes of any rejected welds.