Crack on Offshore Pipeline


Standar
Stress corrosion cracking can be a serious threat to the integrity of natural gas and petroleum pipelines. The pipeline industry responded to this threat by performing a comprehensive research program to determine the cause(s) of the failures and investigate various techniques for preventing future failures. A relatively concise list of discoveries has had a measurable impact on mitigation of the stress corrosion cracking threat.
integrity-forest-480x237L
Stress corrosion cracking can be a serious threat to the integrity of natural gas and petroleum pipelines. Photo: DNV
Starting with the first recognized stress corrosion cracking failure in 1965, the intergranular form of cracking (also known as high-pH SCC) was investigated to identify the causative agent and the controlling metallurgical, environmental, and stress related factors. In the 1980s, a second, transgranular form of stress corrosion cracking (near neutral pH SCC) was discovered in Canada, resulting in a similar scope of research activities designed to develop mitigation methods for this form of cracking. The information developed in these research programs has been incorporated into pipeline integrity management programs.
Three techniques
There are three common techniques used for management of the integrity of pipelines subject to stress corrosion cracking and other time dependent threats; hydrostatic testing, direct assessment, and in-line inspection (ILI). Directly following the initial stress corrosion cracking failures of gas transmission pipelines in the 1960s, hydrostatic testing was the primary tool used to confirm the integrity of the affected pipelines and prevent additional failures. The pipelines were pressure tested with water at pressures significantly higher than the operating pressure in order to remove any near critical flaws. This technique has a number of limitations. Very few, if any, stress corrosion cracking flaws are removed, and the pipeline must be taken out of service for testing. In dry climates, obtaining adequate sources of water can be a challenge, while freezing of the water can be an issue in winter months or northern climates. For liquid petroleum pipelines, the water must be extensively treated prior to discharge back into the environment. There also is a finite probability of a phenomenon known as a pressure reversal occurring, where the failure pressure after a hydrostatic test is lower than the maximum test pressure, as a result of subcritical crack growth during the hydrostatic test.
Alternatives to hydrostatic testing
Because of these limitations, there has been significant interest within the pipeline community in the development of alternatives to hydrostatic testing. One alternative is SCC Direct Assessment (SCCDA). The first recommended practice for SCCDA was issued in 2004 (NACE Standard RP0204-2004). SCCDA is a structured process intended to assist pipeline companies in assessing the extent of stress corrosion cracking on buried pipelines, thus contributing to their efforts to improve safety by reducing the impact of external stress corrosion cracking on pipeline integrity. The term is somewhat of a misnomer in that the process is much more extensive than simply examining the pipeline for evidence of stress corrosion cracking.
The first step in the process (pre-assessment) involves the collection of existing information on the pipeline that can be used to assess the likelihood that the pipeline is susceptible to stress corrosion cracking. The applied research described above has formed the basis for establishing the critical information that should be collected. In the case of high-pH stress corrosion cracking, the initial selection of the most susceptible segments is based on five factors; operating stress (>60% of the specified minimum yield strength), temperature (>100°F), distance from compressor station (< 20 miles), pipeline age (>10 years) and coating type (other than fusion bonded epoxy (FBE)). In the case of near neutral pH SCC, there are four factors, excluding operating temperature.
Other types of information on the pipeline can be used for the selection of dig sites in the chosen segments. Again, much of this information is based on the applied research performed and includes factors such as topography, drainage, and soil type (near neutral pH SCC), the magnitude and frequency of cyclic pressure fluctuations, the specific coating type, including the girth weld coating, surface preparation for the coating, coating condition and prior history on the pipeline. A significant issue with SCCDA is that it is not capable of reliably identifying the location or locations of the most severe stress corrosion cracking on a pipeline segment. Accordingly, it is not necessarily a replacement for hydrostatic testing or in-line inspection in all instances. The pre-assessment phase of SCCDA may indicate that a particular pipeline segment is not likely to be susceptible to stress corrosion cracking and therefore, other threats are of a more immediate concern. An example would be a newer pipeline with an FBE coating. On the other hand, ILI, hydrostatic testing, or even pipe replacement may be warranted if extensive, severe stress corrosion cracking is found.
In-line inspection is the third technique used to manage time-dependent threats on operation pipelines. There is a long history of using magnetic flux leakage and, to a lesser extent, ultrasonic tools to address internal and extern corrosion threats on transmission pipelines. Around the time the NACE SCCDA recommended practice was being developed, there was a growing consensus within the pipeline industry that the new generation of crack detection tools would eliminate the need for hydrostatic testing or any of the elements of SCCDA. Integrity management would consist of four elements; find the cracks, size the cracks, assess the cracks and repair the cracks.
Unfortunately, the experience with crack detection tools has not been as desirable as had been hoped. Over the past few years, there have been at least two service failures of pipelines in which the operators were using crack detection tools for integrity management. In the case of one failure in Carmichael MS, the cause and contributing factors could not be confirmed because of extensive fire damage to the failed pipe. A portion of the fracture did propagate along the seam weld and the pipeline had a history of seam weld defects. The pipe section that contained the failure also had been previously hydrostatically tested at a pressure much higher than the failure pressure. This information, taken together, suggests that a likely cause of failure was the growth of a seam weld defect in service. In the second case, a failure near Marshall MI, there was evidence that fatigue cracks grew from a colony of pre-existing stress corrosion cracks.
Accuracy of crack sizing
The problem with the current generation of crack detection tools appears to be related to the accuracy of crack sizing. The tools are very good at finding crack-like features, and the length accuracy for the features also typically is good. The problem is the depth accuracy. The feature calls are usually binned by depth into several depths; e.g. <15% of wall thickness, 15–30% of wall thickness, 30–45% of wall thickness and >45% of wall thickness. Currently, there does not appear to be sufficient accuracy in the binning process for integrity management purposes. The failure pressures in pipelines containing cracks are much more sensitive to depth than to length of the flaws. The problem could be related to the precision and accuracy of the tool, or the analytical process for analyzing the tool data.
Because of these sizing issues, pipeline operators are sometimes required to perform a confirmatory hydrostatic test on portions of their system to demonstrate the performance of the crack detection tool. In some cases, pipeline operators also may be faced with a situation where a large number (thousands) of features are found on a segment of a pipeline. The elements of SCCDA can then be used, in conjunction with the standard crack sizing, to identify which feature are most likely to be an integrity threat and should be excavated. These elements are also used to prioritize pipeline systems for in-line inspection. The point is that fundamental understanding of the SCC process, developed through applied research, is still of significant value in integrity management.
As previously described, the information developed in the research programs is also used by pipeline companies to operate their pipelines in a way that reduces the risk of stress corrosion cracking failures. Where there is a risk of high pH SCC, after-coolers are installed at compressor stations to reduce outlet temperatures. Operators may control pressure fluctuations to reduce the risk of both forms of stress corrosion cracking. Cathodic protection systems are enhanced, monitored, and maintained to keep the pipe to soil potential out of the potential range for cracking. Finally, this research information is used by prudent operators in construction activities to reduce the risk of stress corrosion cracking in the future. Near white surface preparation procedures and coatings, such as FBE, are selected to minimize stress corrosion cracking initiation. Girth weld coating systems are selected to minimize shielding. The pipeline systems are designed to minimize operating temperatures and cyclic pressures.
Future trends
The detection and sizing capabilities of the crack detection tools will undoubtedly improve, but there will always be a need for elements of SCCDA, developed through applied research, to prioritize pipeline segments for inspection. Depending on the pace of improvements in the precision and accuracy of these systems, there may continue to be a necessity, for the near future, to use elements of SCCDA to help identify which features are most likely to be SCC threats.
Although not discussed in this article, there are other stress corrosion cracking threats to operating pipelines. Ethanol is used in almost all of the gasoline consumed in the United States as an oxygenating agent and octane booster. The current blend limit is 10% ethanol, but this may be increased to 15% in the near future. Denatured fuel grade ethanol is transported to terminals where it is blended with gasoline. Pipelines are the most efficient method to transport the ethanol but the threat of internal stress corrosion cracking has prevented general transportation via pipelines. Research is ongoing to address this threat.
A new internal stress corrosion cracking threat from alcohol was recently identified. Methanol is sometimes used as a drying agent for pipelines directly following hydrostatic testing. In northern climates, neat methanol is also sometimes used for hydrostatic testing to avoid freezing. There is growing evidence that this methanol has caused internal stress corrosion cracking of some pipelines; research is ongoing to address this threat.
Text: John A. Beavers, DNV
Source :
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Pipeline Stress Analysis

Pipe Stress Analysis: Basic Concepts

Introduction

It is common practice worldwide for piping designers to route piping by considering mainly space, process and flow constraints (such as pressure drop) and other requirements arising from constructability, operability and reparability. Unfortunately, pipe stress analysis requirements are often not sufficiently considered while routing and supporting piping systems, especially in providing adequate flexibility to absorb expansion/contraction of pipes due to thermal loads. So, when “as designed” piping systems are handed-off to pipe stress engineers for detailed analysis, they soon realize that the systems are “stiff” and suggest routing changes to make the systems more flexible. The piping designers, in turn, make changes to routing and send the revised layout to the pipe stress engineers to check for compliance again.

Such “back and forth” design iterations between layout and stress departments continue until a suitable layout and support scheme is arrived at, resulting in significant increase in project execution time, which, in turn, increases project costs.
This delay in project execution is further worsened in recent years by increased operating pressures and temperatures in order to increase plant output; increased operating pressures require thicker pipe walls, which, in turn, increase piping stiffnesses further! Such increased operating temperatures applied on “stiffer” systems increase pipe thermal stresses and support loads. So, it is all the more important to make the piping layout flexible at the time of routing. (checkSTRESS, another SST’s product [different from CAEPIPE] for AutoCAD, CATIA, Autoplant, PDMS, Cadmatic and others, directly addresses and solves this problem).

Figure 1. Pipeline Stress Analysis
Ref : http://admin.midasuser.com/UploadFiles2/80%5Ctuto12.jpg

Types of Loads

Piping systems experience different types of loadings, categorized into three basic loading types — Sustained, Thermal and Occasional loads.

Sustained Loads

These mainly consist of internal pressure and dead-weight. Dead-weight is from the weight of pipes, fittings, components such as valves, operating fluid or test fluid, insulation, cladding, lining, etc.

Internal design or operating pressure causes uniform circumferential stresses in the pipe wall, based on which a pipe wall thickness is determined during the process P&ID stage of plant design. Additionally, internal pressure gives rise to axial stresses in the pipe wall. Since these axial pressure stresses vary only with pressure, pipe diameter and wall thickness (all three of which are preset at the P&ID stage), these stresses cannot be altered by changing the piping layout or the support scheme.
A pipe’s deadweight causes the pipe to bend (generally downward) between supports and nozzles, producing axial stresses in the pipe wall (also called “bending stresses”) which vary linearly across the pipe cross-section, being tensile at either the top or bottom surface and compressive at the other surface. If the piping system is not supported in the vertical direction (i.e., in the gravity direction) excepting equipment nozzles, bending of the pipe due to deadweight may develop excessive stresses in the pipe and impose large loads on equipment nozzles, thereby increasing its susceptibility to “failure by collapse.”
Various international piping standards/codes impose stress limits, also called “allowable stresses for sustained loads,” on these axial stresses generated by deadweight and pressure in order to avoid “failure by collapse.”
For the calculated actual stresses to be below such allowable stresses for sustained loads, it may be necessary to support the piping system vertically. Typical vertical supports to carry deadweight are:
  • Variable spring hangers
  • Constant support hangers
  • Rod hangers
  • Resting steel supports
Rod hangers and resting steel supports fully restrain downward pipe movement but permit pipe to lift up.
Two examples are presented in this tutorial to illustrate how piping can be supported by spring hangers and resting steel supports to comply with the code requirements for sustained loads.

Thermal Loads (Expansion Loads)

These refer to the “cyclic” thermal expansion or contraction of piping as it goes from one thermal state to another (for example, from “shut-down” to “normal operation” and then back to “shut-down”). If the piping system is not restrained in the thermal growth/contraction directions (for example, in the axial direction of pipe), then, for such cyclic thermal load, the pipe expands/contracts freely; in this case, no internal forces, moments and resulting stresses and strains are generated in the piping system. If, on the other hand, the pipe is “restrained” in the directions it wants to thermally deform (such as at equipment nozzles and pipe supports), such constraint on free thermal deformation generates cyclic thermal stresses and strains throughout the system as the system goes from one thermal state to another. When such calculated thermal stress ranges exceed the “allowable thermal stress range” specified by various international piping standards/codes, then the system is susceptible to “failure by fatigue.” So, in order to avoid “fatigue” failure due to cyclic thermal loads, the piping system should be made flexible (and not stiff).
This is normally accomplished as follows:
a) Introduce bends/elbows in the layout, as bends/ elbows “ovalize” when bent by end-moments, which increases piping flexibility.
b) Introduce as much “offset” as possible between equipment nozzles (which are normally modeled as anchors in pipe stress analyses).
For example, if two equipment nozzles (which are to be connected by piping) are in line, then the straight pipe connecting these nozzles will be “very stiff”. If, on the other hand, the two equipment are located with an “offset,” then their nozzles will have to be connected by an “L-shaped” pipeline which includes a bend/elbow; such “L-shaped” pipeline is much more flexible than the straight pipeline mentioned above.
c) Introduce expansion loops (with each loop consisting of four bends/elbows) to absorb thermal growth/contraction.
d) Lastly, introduce expansion joints such as bellows, slip joints, etc., if warranted.
In addition to generating thermal stress ranges in the piping system, cyclic thermal loads impose loads on static and rotating equipment nozzles. By following one or more of the steps from (a) to (d) given above and steps (e) and (f) given below, such nozzle loads can be reduced.
e) Introduce “axial restraints” (which restrain pipe in its axial direction) at appropriate locations such that thermal growth/contraction is directed away from nozzles.
f) Introduce “intermediate anchors” (which restrain pipe movement in the three translational and three rotational directions) at appropriate locations such that thermal deformation is absorbed by regions (such as expansion loops) away from equipment nozzles.
A few example layouts are presented later to illustrate how loops/offsets, axial restraints and intermediate anchors are used to reduce thermal stresses in piping (and nozzle loads).

Occasional Loads

This third type of loads is imposed on piping systems by occasional events such as earthquake, wind or a fluid hammer. To protect piping from wind and/or earthquake (which normally occur in a horizontal plane), it is normal practice to attach “lateral supports” to piping systems (instead of “axial restraints”). On the other hand, to protect piping for water/steam hammer loads, both “lateral supports” and “axial restraints” may be required.
To carry sustained loads, normally vertical supports are required. For thermal loads, having no supports gives zero stresses. So, fewer the number of supports, lower the thermal stresses. Axial restraints and intermediate anchors are recommended only to direct thermal growth away from equipment nozzles.

References : "Pipe Stress Analysis : Basic Concepts" 
http://www.sstusa.com/pipe-stress-analysis-tutorial.php#prelim-procedure
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Pipeline Corrosion

Understanding and preventing corrosion


Corrosion causes billions of dollars worth of damage each year. As a result of this chemical-physical process, pipeline sections often have to be taken out of service and replaced.
Corrosion can be caused by ineffective pipeline coatings, soil conditions and the circumstances under which a pipeline’s coating is rehabilitated onsite. In practice, surface preparation and the application circumstances appear to be critical in creating a long-lasting, high-performance coating.
The chemistry of corrosion
Corrosion can also be described as oxidation because the process involves the formation of bonds between steel and oxygen. Oxygen, however, is not solely responsible for the oxidation process. In dry environments, many materials, including steel, do not rust. The cause of oxidation is to be found in the presence of water.
Figure 1. Corrosion on Underwater Pipeline 
 http://www.process-controls.com

Coating types
In order to prevent corrosion, the bare substrate can be protected by means of several available coatings including:
Factory coatings
  • Fusion-bonded epoxy (FBE), high-density polyethylene (HDPE) and urethanes.
Field-applied coatings
  • Spray coatings like epoxy, urethane and zinc;
  • Residues of refinery like waxes and petrolatum;
  • Bitumen-based coatings; and,
  • Single or multiple-layer PE/butyl tapes.
The selection of the coating depends on various factors such as:
  • The estimated lifetime of substrate;
  • Environment;
  • Material, shape, and position of the substrate; and,
  • Application and repair costs.
Phenomena and problems facing pipe coating
There are a number of phenomena that contribute to the corrosion process and that should be considered when discussing the application of pipeline coatings and the corrosion process.
Salts and osmosis
The presence of salt plays an important role in a corrosion mechanism because salt particles are present in most situations and are difficult to remove. Rinsing a blasted pipeline coating with clean water will not remove the salt particles and other contaminations in the voids of the pipe. As many pipeline coatings are not 100 per cent water resistant, the presence of salt is always a risk because it attracts water. When water and salt are present, the phenomenon of osmosis occurs. Water permeability
If the slightest permeability for water exists, corrosion will occur. Regardless of how well a coating has been applied in the factory, practice has revealed that disbondment due to the presence of water may still occur. While corrosion is always caused by a combination of factors, permeability for water should be viewed as a serious hazard to pipeline health. 
Adhesion problems
Any pipeline coating must have good adhesion to the substrate. To obtain an effective adhesion is not easy because application circumstances must be taken into consideration, and many coatings require a perfect surface preparation. The difference between tensions of the surface and coating material also play an important factor in adhesion failures.
Surface preparation
Studies have shown that bad surface preparation appears to be a main cause of corrosion problems. Very often field-applied coatings need a well-prepared surface in order to secure excellent adhesion and sandblasting is often required. However, remaining pollutions in the voids of the blasted surface and salt particles can create problems, and rapid disbondment may occur. Microbiologically-influenced corrosion
Microbiologically-influenced corrosion (MIC) is a phenomenon in which corrosion is initiated or accelerated by the activities of micro-organisms. The first case of MIC was discovered in 1934 in which sulphate-reducing bacteria were responsible for the corrosion failure of cast iron pipe.
MIC is responsible for a large portion of corrosion problems experienced in the pipeline industry. During the metabolic process, sulphate is reduced to sulphide, which reacts with hydrogen to produce hydrogen sulphide. Hydrogen sulphide is very corrosive to ferrous metals and further reacts with dissolved iron to form an iron sulphide film over the metal pipe.
Overcoming these problems In order to prevent corrosion, steel parts must be protected from contact with water. This can be achieved through the application of a protective coating. This coating must be 100 per cent water-repellent, with the capability to perfectly-match the surface of the pipeline. It should have a perfect adhesion and reduce the risk for MIC

References : http://pipelinesinternational.com/news/understanding_and_preventing_corrosion/043736/
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Pipeline Commissioning






Pipeline commissioning means introducing crude/ product/Gas in the pipeline from originating station, filling the entire length and then start delivering to receipt system. 
Critical issues in commissioning a Petroleum Pipeline

  • Movement of hydrocarbon in empty pipeline can generate static current
  • Hydrocarbon Vapor mixed with oxygen may lead to explosion.
  • There may be formation of Air / Vapor pocket that may get compressed leading to rise in pressure.
  • Air / vapor pocket may explode in receiving tank leading to damage of the tank roof seal.
  • Leakage of any hydrocarbon may lead to fire or damage to environment . 
Source : http://petrofed.winwinhosting.net/upload/15-18June11/13.pdf
https://www.youtube.com/watch?feature=player_embedded&v=QAnzYVrsvBQ
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Pipe Flange

There are different types of pipe flanges  used in the piping systems depending upon the fluid, PT rating, material of construction, connecting equipment etc.  Below are the types of flanges used in piping based on facing
Source : http://www.piping-engineering.com/pipe-flanges-types-systems.html

1) Flat Face (FF) Flanges:

These pipe flanges are used when the counter flanges are flat face. They are mainly used at connection to cast iron equipment, valves and specialties. This flat face flange has a gasket surface in the same plane as the bolting circle face.
Flange flat face FF
Flange flat face FF

2) Raised Face (RF) Flanges:

These pipe flanges are the most commonly used flanges. The raised face thickness for 150# and 300# are included in the specified flange thickness and for higher rating they are not included in the flange thickness.
Flange raised face (RF)
Flange raised face (RF)

3) Male-Female (M/F) Face Flanges:

These pipe flanges are better version of Raised face flanges.
Flange male female MF
Flange male female (MF)

4) Tongue-Groove (T/G) Face Flanges:

These pipe flanges are most reliable type of flange joint but are costlier than the other type of flanges.
Flange tongue groove joint (TG)
Flange tongue groove joint (TG)

5) Ring Type Joint (RTJ) Flanges:

These pipe flanges are most reliable type of flange joint but are costlier than the other type of flanges. The Ring Type Joint flanges are generally used in high pressure (Class 600 and higher rating) and/or high temperature services above 800°F (427°C).


Flange ring joint (RG)
Flange ring joint (RG)
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Pipeline Crossing

Where two pipelines have to cross over each other there is a need to provide some protection to the pipeline crossing. There are several ways which this can be achieved. Protection is mostly provided at crossings by laying small pieces of rock to form a bridge over the bottom pipeline which in turn is covered by rock. This method is undertaken using a rock placement vessel, as seen in the picture to the right.
These specialist vessels are capable of laying the rock in exactly the correct location, direct from the surface. Stone mattresses may also be used in conjunction with rock placement, as seen in the image below.
Source : http://fishsafe.eu/en/offshore-structures/pipelines.aspx

Pipeline crossing
Pipeline crossing 2
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Pipeline Bottom Roughness Analysis

What’s is bottom roughness?It’s an analysis to predict the location of span along subsea pipeline after installation or during operation. So, what’s the different between free span analysis?free span analysis is “only” determine the maximum allowable length of pipeline that unsupported when laid on seabed. The criteria of allowable span is divided into VIV(Vortex Induced Vibration) and ULS (Ultimate Limit State or Static Criteria). Why bottom roughness analysis is so important?Without bottom roughness analysis you don’t know how many support (sand bag, grout bag, etc) that you need to rectify of over span. However, it’s only prediction, so you need further inspection to ensure the location of over span.
Picture4
2D OBR analysis is very simple, you can use any FEA softwere such as ABAQUS, ANSYS, etc..For this note, I used ABAQUS FEA as mny OBR simulator. The pipeline can be modelled using 1D element (PIPE31H) and the seabed can be modeled using anlaytical rigid of surface. The common step that used for Bottom Roughness is adopted from Subsea Pipelines & Riser book (2005,Yong Bai & Qiang Bai)
Picture5
After ODB file is produced from your ABAQUS FEA machine, for the next step you need to extract COORD1 (coordinate of pipeline KP), COORD3 (water depth of your Bottom of Pipe [BOP]), and CPRESS (Contact pressure as indicator only to make sure each node of pipeline BOP is touching seabed or not). You can use python file or extract manually using Abaqus Viewer.
  1. Open your ODB file (double click you ODB file or open using Abaqus Viewer). On the left side you will see the tree and 2 X click the step you want to extract.
  2. Create Path. On the menu bar, please click Tools>Path>Create and you type your path name, click OK then you will face “Edit Node List Path” and please fill Node Labels you want to extract the value, for example 1:7399 (it means node 1 to node 7399).
  3. Create XY Data. Click Tools>XY Data>Manager. Please see picture below for easy explanation. Each of your XY data shall be copied in Microsoft Excel. Please check any bug/error with your output result.
ABAQUS_extracting
Before you try process further with your excel spreadsheet, you must interpolate your water depth of seabed (that has been inputed in abaqus) against your COORD1 data (coordinate of pipeline KP), then you will get new water depth of seabed with same KP with your COORD1 data. Divide your Excel spreadsheet into 2 Sheets.
In the sheet no.1 you need to set your sheet as a sample below. You will see any number span start & span end along the pipeline. Please make sure during pipeline embedded (negative value of span gap) there are any value of CPRESS and vice verse. The maximum gap value along pipeline must be inputted into allowable free span analysis (onset/screening/fatigue criteria as per DNV RP F105)
Picture1
After that, you have to “sort & filter” each span start & span end, then copy this KP into sheet no.2 as a picture below. From each this formula you will get the overspan results. Please notice that this screening will used maximum gap value along KP start and KP end.  The minimum span gap value that influence VIV, is 30% OD (Ref: OTC No. 4455, 1983, The Influence of Boundary Layer Velocity Gradients and Bed Proximity On Vortex Shedding from Free Spanning Pipeline). Some people used 20% OD (Ref: Sumer and Fredsoe, 1989, Hydrodynamiccs around Cylindrical Structures) as conservatism result
Picture2
The analysis has not over yet. First, you need to check with centre third of pipeline criteria. If the average center third of pipeline below allowable gap value, you can ignored this over span if it is caused by VIV only (not ULS/Static criteria). But if, you want get the conservatism result, you can consider this span is over span (But it will affect your span rectification cost). Second, you need to check the uplift possibility (or look like upheaval) in your ABAQUS FEA model. It should be not happened because the weight of pipeline and wave/current will forced this uplift section to drop on seabed as lateral buckling. So, if your over span is occur in this uplift section, please ignore it as a span, but you must check the integrity of this section (Using Load controlled Check & Displacement Control Check as per DNV F101). Third, you need to reassessed again each over span section with each gap value and recalculate again in allowable free span assessment, so you will get new allowable span that longer than before.
Your 2D Bottom Roughness Analysis is end from here. But if you want, you can do re-analysis (start form sheet-1) with interactivity phenomenon [during VIV, your span is will induced vibration with its neighbor span, so make this effective length is longer than isolated span]. As per DNV RP F105, you can determined each  span is a kind of isolated or interacting span as a diagram below.
Picture3
Source : Danar Yurindatama, " 2D Pipeline Bottom Roughness", January, 2013
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