y=A/2[sin[(x-(0.25λ))/0.5λ]π+1]

Where,

A = HOOS amplitude;

λ = HOOS wavelength

y = lateral-axis;

x = axial-axis.

The horizontal out of straightness (HOOS) of the flowline being laid on seabed can be defined a simple sine curve. The sine curve equation used to define the flowline HOOS profile is shown below:

y=A/2[sin[(x-(0.25λ))/0.5λ]π+1]

Where,

A = HOOS amplitude;

λ = HOOS wavelength

y = lateral-axis;

x = axial-axis.

y=A/2[sin[(x-(0.25λ))/0.5λ]π+1]

Where,

A = HOOS amplitude;

λ = HOOS wavelength

y = lateral-axis;

x = axial-axis.

During pipelay, tension is applied to the pipeline by tensioner located at the firing line on the lay vessel. The tension applied will determine the curvature of the pipeline between the stinger and the touchdown point. Please note that the higher the tension applied, the touchdown point of the pipeline will be further away and vice versa.

Prior to pipeline installation operation, the installation analysis will be performed. The purpose of the installation analysis is to determine the tension required during the pipelay to ensure the strain/stress of the pipeline overbend and sagbend are within the allowable limit in accordance to the codes and standards.

The tension discussed above is also known as the top tension. Due to the tension applied, there will be residual lay tension acting on the pipeline upon completion of pipeline installation. The residual lay tension is the stress that remains in the pipeline after the tension applied to the pipeline has been removed.

There are several ways of calculating the residual lay tension which depends on the stage of engineering design:

1) Assume as 10% of the lay tension. (This is a common assumption used in calculating the fully restrained pipeline effective axial force and some other analyses if no sufficient information is available. Note that this assumption may not be suitable for some analyses as the residual lay tension may be more than 50% of the lay tension in certain scenarios)

2)* *Simple residual lay tension - *the residual lay tension calculation will be added in the future, if there is any request!*

3) Detailed FE analysis - Model the progressive pipe lay using the FEA software (i.e. Abaqus, Ansys, Orcaflex etc.) and check for the effective axial force of the pipeline upon completion of the pipe laying.

Prior to pipeline installation operation, the installation analysis will be performed. The purpose of the installation analysis is to determine the tension required during the pipelay to ensure the strain/stress of the pipeline overbend and sagbend are within the allowable limit in accordance to the codes and standards.

The tension discussed above is also known as the top tension. Due to the tension applied, there will be residual lay tension acting on the pipeline upon completion of pipeline installation. The residual lay tension is the stress that remains in the pipeline after the tension applied to the pipeline has been removed.

There are several ways of calculating the residual lay tension which depends on the stage of engineering design:

1) Assume as 10% of the lay tension. (This is a common assumption used in calculating the fully restrained pipeline effective axial force and some other analyses if no sufficient information is available. Note that this assumption may not be suitable for some analyses as the residual lay tension may be more than 50% of the lay tension in certain scenarios)

2)

3) Detailed FE analysis - Model the progressive pipe lay using the FEA software (i.e. Abaqus, Ansys, Orcaflex etc.) and check for the effective axial force of the pipeline upon completion of the pipe laying.

The question I often received is whether to land the line on
the seabed during J-tube pull-in?

I have carried out the sensitivity study by performing the
static analysis for J-tube pull-in. The results show that:

- If the pipeline is rigid and the clearance between the bell mouth and seabed is small, the most favorable way of J-tube pull-in is to firstly land the rigid riser onto the seabed and followed by J-tube pulling;
- However, if the pipeline is flexible and the clearance between the bell mouth is bigger (e.g. 2 m to 3 m), the most favorable way of J-tube pull-in is to pull the flexible riser directly into the J-tube without touching the seabed.

Please note that the answer given above is only based on the sensitivity study I have carried out and may not be applicable to all cases.

The purpose of the on-bottom stability analysis is to ensure
the flexible line is stable throughout its design life.

Many Codes and Standards , and requirements have been
developed to evaluate the stability of the flexible lines, the requirements/design
standards to be used are determined by the many factors, the main ones are
shown as below:

- Location of project (Country);
- Local authority requirements;
- Operator standards and requirements.

During FEED or BOD, the 2D on-bottom stability analysis is
deemed sufficient. The commonly used design standard for on-bottom stability
assessment is DNV-RP-F109 absolute stability approach. The absolute static
stability design method is based on simple static equilibrium of forces. The flexible
line is considered absolute stable if it fulfills all the following requirements:

- Vertical stability in water;
- Vertical stability on and in soil;
- Lateral stability.

No further assessment is required if the flexible line is
found to be absolute stable.

On the other hand, if absolute stability of the flexible
line is unable to achieve based on its mechanical properties, 3D on-bottom
stability will be required during Detailed Design.

Since absolute stability is a conservative requirement,
the flexible line may not be necessary to be absolutely stable along entire
route. It is acceptable as long as the 3D on-bottom stability conducted is able
to demonstrate that the minimum bending radius (MBR) of the flexible line is
not exceeded throughout its design lift under the most onerous hydrodynamic
loadings.

Secondary stabilisation is required if 3D on-bottom
stability shows that the bending radius of the flexible line has exceeded its
MBR under the design environmental load.

DNV-RP-F109, On-Bottom Stability Design of Submarine Pipelines, October 2010.

The buckle detector consists of simple metal structure and
the buckle detecting gauging plate.

The diameter of buckle detector gauging plate can be taken
as 95% of the pipeline internal diameter (ID), alternatively, it can be
calculated in accordance with DNV 1981 Section 8.3.5 as shown below:

d = D – 2t – S

Where,

d = diameter of detector;

D = nominal outer diameter of pipe;

t = nominal wall thickness of
pipe;

S = 0.01D + 0.4t +5L;

L = 20% of t, max. 5 mm.

Step 1: buckle
detector design and setting up;

Step 2: The
buckle detector is brought to the firing line where the pipe sections are
joined together;

Step 3: The
buckle detector is inserted into the pipeline;

Step 4: The
required length of cable is attached to the buckle detector (typically, the
buckle detector is placed at least 20 m to 30 m (depends on water depth and
individual project requirement) downstream of pipeline touchdown point);

Step 5: The
buckle detector is pushed to the designated location by ‘blower’;

Step 6: Once
the buckle detector reached its designated location, the cable end located onboard
is tied to the internal clamp which is used to align two pipe joints, hence,
the buckle detector will be pulled continuously once every pipe joint is
installed and the barge moves forward.

- DNV 1981, Rules for Submarine Pipeline Systems, 1981
- http://grabcad.com/library/buckle-detector

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