UK pipeline decommissioning provides potential for innovation

Since 1966, 45,000 km (27,962 mi) of pipeline has been installed in the North Sea to transport hydrocarbons from the UK continental shelf (UKCS) to shore. Of this pipeline, less than 2% has been decommissioned.

The UK government and industry continue to focus on maximizing recovery of around 15-24 Bboe from the UKCS, and 2013 brought record investment in new projects. Collaborative work has resulted in fiscal change and technological advances, but as the basin continues to mature, decommissioning is emerging as a parallel and growing business opportunity.

Decommissioning expertise is available within the UK supply chain, but without significant activity in this area, the sector has not been fully tested. To help contractors better understand the opportunities, Oil & Gas UK has produced several documents.

In its “Decommissioning Insight” published in 2013, the association forecasts that between 2013 and 2022 more than 2,300 km (1,429 mi) of pipeline, infrastructure from 74 fields, more than 70 subsea projects, and about 130 installations are scheduled for decommissioning at a total forecast expenditure of £10.4 billion ($17 billion).

Inventory of UKCS pipelines

The pipelines mentioned in the forecast represent a fraction of the extensive network of pipeline currently installed in the North Sea to transport oil and gas production to host platforms or to shore. Overall, the UKCS pipeline inventory covers a broad range of equipment designed to accommodate the transportation of many different fluids under diverse conditions, varying water depths, and different oceanographic environments.

In many cases, the existence of nearby pipeline infrastructure has led directly to the exploitation of marginal fields that would otherwise be uneconomic. Such opportunities remain a key factor in the timing of any pipeline decommissioning. A more detailed description of the different types of pipeline infrastructure can be found in Oil & Gas UK’s 2013 report, “The Decommissioning of Pipelines in the North Sea Region.”

Trunklines represent the major element of subsea infrastructure transporting large quantities of oil and gas from offshore to onshore receiving facilities and end users across Europe. They account for 18% of the total number of pipelines and 63% of the total pipeline length in the North Sea inventory.

Such pipelines include some of the longest in the North Sea, often with diameters of more than 30 in., and tend to be installed offshore using the S-lay pipelay method from a specialist lay vessel.

The pipeline inventory also includes rigid flowlines, flexible flowlines, umbilicals, and power cables, as well as associated equipment such as the concrete mattresses used extensively in the UKCS to provide protection and stability to subsea pipelines, cables, and umbilicals. These flexible mattresses are typically manufactured by joining different shapes of concrete blocks together with polypropylene or Kevlar rope. Oil & Gas UK estimates that 35,000-40,000 mattresses have been deployed since operations began in the North Sea.

While pipelines are integral to field life extension and future development opportunities, some fields in the UKCS have reached the end of their economic life. Specific parts of the pipeline system naturally become redundant, and with no potential future use, they are available to be decommissioned.

Seven Navica reeling vessel. (Image reproduced with permission from Subsea 7)

Decommissioning to date

Oil and gas pipeline decommissioning has been taking place in the North Sea since the early 1990s, when the Crawford field pipelines were decommissioned. Since then, pipeline decommissioning has continued at a modest rate and only when all potential reuse options for the infrastructure, including new field developments, have been carefully considered.

Less than 2% of the North Sea pipeline inventory has been decommissioned, and of the pipelines which have been decommissioned, 80% are less than 16-in. in diameter. Half of the larger diameter pipelines (16 in. or greater) decommissioned to date were removed; these were all infield pipelines less than 1 km (0.6 mi) long. The longest large diameter trunkline to be decommissioned so far is the 35-km (21.7-mi) Piper A to Claymore 30-in. export line, which was decommissioned in situ.

Under current regulations, decommissioning of oil and gas pipelines is considered on a case-by-case basis using the comparative assessment (CA) process to determine the best option for decommissioning. The CA process enables the particular diameter, length, and configuration of individual pipelines to be taken into account when considering decommissioning options against the criteria of safety, environmental impact, cost, and technical feasibility.

Health and safety is a dominant factor in any CA, with the focus aimed at minimizing the long-term risks to other users of the sea and the short-term risks to those carrying out decommissioning operations. An integral part of the process is the environmental impact assessment, which is prepared to support all pipeline decommissioning plans.

Each decommissioning solution needs to be considered on its individual merits, as pipeline installations vary widely according to model, location, environment, and maintenance status. It is at the CA stage, when a number of options are considered, that significant opportunities exist for supply chain companies to develop innovative technologies for decommissioning pipelines.

Opportunities for innovation

When evaluating a preferred option for decommissioning a pipeline and its associated equipment, the availability and track record of technology used in previous projects provides the context for the other key CA criteria of safety, environmental impact, and cost.

Supply chain companies specializing in particular services will have the opportunity to develop innovative techniques in the key technology areas for pipeline decommissioning, many of which are in their infancy. These are:

  • Pipeline cleaning
  • Trenching, burial, and de-burial
  • Subsea cutting
  • Lifting
  • Reverse installation methods
  • Mattress removal.

Pipeline cleaning is performed prior to decommissioning and involves the depressurization of a pipeline and the removal of any hydrocarbons in accordance with the Pipelines Safety Regulations. At this stage there are opportunities for companies skilled at minimizing the potential contamination of the marine environment.

The technology for trenching and burial of pipelines during installation is well established, and a number of contractors offer a range of trenching tools capable of trenching and burying pipelines of various diameters in all soil types. There is, however, limited experience of existing pipelines, laid on the seabed surface, being buried specifically for decommissioning in situ.

While there are different methods and types of equipment for cutting pipelines subsea using “cold cutting” tools such as abrasive water jets, diamond wire cutting, reciprocating cutting, and hydraulic shears, significant opportunities exist for contractors capable of developing new technologies to improve these techniques. These might include automated techniques to help reduce the use of divers in these activities. Lifting sections of infrastructure from the seabed is another area where innovative thinking is in demand. The “cut and lift” process of decommissioning requires cut sections of pipeline to be lifted from the seabed to a transportation vessel; supply chain companies providing innovative cutting techniques could help increase efficiency in this area by reducing the duration of lifting operations for long lengths of pipeline.

Reverse installation methods encompass both reverse reeling and reverse S-lay techniques. The process by which rigid or flexible pipelines can be recovered from the seabed by reeling them from the seabed using a specialist reel vessel is known as “reverse reeling.”

For rigid pipe, there are a limited number of specialist reel vessels available from the leading installation contractors. These vessels are usually engaged in installation activities, but can be adapted to recover pipelines as part of a decommissioning project. Subsea 7’s Seven Navica is one vessel capable of performing this work.

For larger diameter and concrete coated trunklines, the industry is considering a reversal of the S-lay installation process by which pipelines could be removed and recovered on to the deck of a specialist S-lay vessel. However, this has not been done in the North Sea, and more study is needed before the technique can be considered feasible for decommissioning long distance large diameter pipelines.

As yet, no established technique or technology has been universally adopted for mattress recovery. Solutions developed by contractors will need to take into account the age and condition of the mattresses being recovered.

Regional variations

Oil & Gas UK’s 2013 “Decommissioning Insight” highlights the contrast between different UKCS basins, noting that in the central and northern North Sea (CNS and NNS), decommissioning of pipelines and mattresses is estimated to cost more than £400 million ($655 million) from 2013 to 2022. Over this period, nearly 40 trunklines (130 km/81 mi), 115 rigid and flexible flowlines (420 km/261 mi), 87 umbilicals (250 km/155 mi), and almost 900 mattresses have been identified for decommissioning in these basins.

The forecast indicates significant expenditure will take place from 2019 to 2022, suggesting that pipeline decommissioning will occur toward the latter end of decommissioning programs. The peak in 2019 can be attributed to at least 10 pipeline decommissioning projects.

While containing a similar number of pipelines to the southern North Sea (SNS), the decommissioning of rigid and flexible flowlines in the CNS and NNS basins is more expensive, suggesting a greater degree of complexity in these regions.

Over the same period in the SNS and the Irish Sea, four trunklines (64 km), 116 other pipelines (1,300 km/808 mi), and 21 umbilicals (150 km/93 mi) will be decommissioned at a cost of around £100 million ($164 million). Additionally, 2,100 mattresses have been scheduled for decommissioning.

While these decommissioning activities represent a fraction of the overall market of oil and gas activities, they are part of a burgeoning sector. By making more information on decommissioning available, Oil & Gas UK aims to help the industry prepare for decommissioning projects, increase the efficiency of processes involved, and help ensure that future projects are enabled by an “at the ready” supply chain.

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Pipeline pre-commissioning

Pipeline pre-commissioning is the process of proving the ability of a pipeline and piping systems to contain product without leaking. This product may be liquid, gaseous or multiphase hydrocarbons, water, steam, CO2, N2, petrol, aviation fuel etc.

Pre-commissioning is the series of processes carried out on the pipeline before the final product is introduced. The process during which the pipeline is made “live” i.e. the product is put in the pipeline, is called pipeline commissioning or start-up.

Despite being seen as an offshoot, or minor part of the business for the larger oil service companies, the pipeline pre-commissioning industry possesses quite a large portfolio of services including, but not limited to the following services:

Pipeline Cleaning – this is carried out by pushing pigs or gel pigs through the pipeline to remove any debris dirt.

Pipeline Gauging – this is carried out to prove the dimensional quality of the internal diameter of the pipeline.

Pipeline Filling (Flooding) – which can be carried out by propelling pigs through the pipeline with water or free flooding with water (normally for smaller or unpiggable pipelines).

Hydrotesting – this is a process by which the pipeline in question is pressure tested to a predefined pressure above the operating design pressure of the pipeline.

Dewatering – this involves pushing pigs through the pipeline propelled by a gas to remove the water prior to start-up.

Other services include vacuum drying, pneumatic testing, barrier testing, leak testing, decommissioning to mention but a few.

On the pipeline process pre-commissioning side, there are various services such as chemical cleaning, helium leak detection, bolting, hot oil flushing, pipe freezing, foam inerting etc…

Other services include valve testing, umbilical testing, hot tapping, leak metering, riser annulus testing.


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Gooseneck (piping)

A gooseneck (or goose neck) is a 180° pipe fitting at the top of a vertical pipe that prevents entry of water. Common implementations of goosenecks are ventilator piping or ducting for bathroom and kitchen exhaust fans, ship holds, landfill methane vent pipes, or any other piping implementation exposed to the weather where water ingress would be undesired. It is so named because the word comes from the similarity of the pipe fitting to the bend in a goose‘s neck.[1]

Gooseneck may also refer to a style of kitchen or bathroom faucet with a long vertical pipe terminating in a 180° bend.

To avoid hydrocarbon accumulation, a thermosiphon should be installed at the low point of the gooseneck


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Basics for Stress Analysis of Underground Piping using Caesar II

Underground or buried piping are all piping which runs below grade. In every process industry there will be few lines (Sewer or drainage system, Sanitary and Storm Water lines, Fire water or drinking water lines etc), part of which normally runs underground. However the term buried piping or underground piping, in true sense, appears for pipeline industry as miles of long pipe run carrying fluids will be there.

Analyzing an underground pipe line is quite different from analyzing plant piping. Special problems are involved because of the unique characteristics of a pipeline, code requirements and techniques required in analysis. Elements of analysis include pipe movements, anchorage force, soil friction, lateral soil force and soil pipe interaction.

To appreciate pipe code requirements and visualize problems involved in pipe line stress analysis, it is necessary to first distinguish a pipe line from plant piping. Unique characteristics of a pipe line include:

  • High allowable stress: A pipe line has a rather simple shape. It is circular and very often runs several miles before making a turn. Therefore, the stresses calculated are all based on simple static equilibrium formulas which are very reliable. Since stresses produced are predictable, allowable stress used is considerable higher than that used in plant piping.
  • High yield strength pipe: To raise the allowable, the first obstacle is yield strength. Although a pipe line operating beyond yield strength may not create structural integrity problems, it may cause undesirable excessive deformation and possibility of strain follow up. Therefore, high test line with a very high yield to ultimate strength ratio is normally used in pipe line construction. Yield strength in some pipe can be as high as 80 percent of ultimate strength. All allowable stresses are based only on yield strength.
  • High pressure elongation: Movement of pipe line is normally due to expansion of a very long line at low temperature difference. Pressure elongation, negligible in plant piping, contributes much of the total movement and must be included in the analysis.
  • Soil- pipe interaction: The main portion of a pipe line is buried underground. Any pipe movement has to overcome soil force, which can be divided into two categories: Friction force created from sliding and pressure force resulting from pushing. The major task of pipe line analysis is to investigate soil- pipe interaction which has never been a subject in plant piping analysis.

Normally these lines does not have high design temperatures (of the order of 60 to 80 degree centigrade) and only thermal stress checking is sufficient for underground part. Common materials used for underground piping are Carbon Steel, Ductile iron, cast Iron, Stainless Steel and FRP/GRP.

In this article I will try to explain the steps followed while analysing such systems using Caesar II. However this article does not cover the basic theory for analysis.

Inputs Required for Analysis:

Before proceeding for analysis of buried piping using Caesar II collect the following information from related department
1. Isometric drawings or GA drawings of the pipeline from Piping layout Department.
2. Line parameters (Temperature, Pressure, Material, Fluid Density, etc) from process Department.
3. Soil Properties from Civil Department.

Caesar II for Underground Piping Analysis:

The CAESAR II underground pipe modeler is designed to simplify user input of buried pipe data. To achieve this objective the “Modeler” performs the following functions for analyst:

  • Allows the direct input of soil properties. The “Modeler” contains the equations for buried pipe stiffnesses that are outlined later in this report. These equations are used to calculate first the stiffnesses on a per length of pipe basis, and then generate the restraints that simulate the discrete buried pipe restraint.
  • Breaks down straight and curved lengths of pipe to locate soil restraints. CAESAR II uses a zone concept to break down straight and curved sections. Where transverse bearing is a concern (near bends, tees, and entry/exit points), soil restraints are located in close proximity and where axial load dominates, soil restraints are spaced far apart.
  • Allows the direct input of user-defined soil stiffnesses on a per length of pipe basis. Input parameters include axial, transverse, upward, and downward stiffnesses, as well as ultimate loads. Users can specify user-defined stiffnesses separately, or in conjunction with CAESAR II’s automatically generated soil stiffnesses.

Modeling steps followed in Caesar II: 

The modeling of buried piping is very easy if you have all the data at your hand. The following steps are followed for modeling:

  • From the isometric model the line in the same way as you follow in case of above ground pipe model i.e, enter line properties in Caesar Spreadsheet, enter lengths by breaking the line into several nodes or select an existing job for converting it into an underground model.
  • Analyst can start the Buried Pipe Modeler by selecting an existing job and then choosing Input-Underground from the CAESAR II Main Menu. The Modeler is designed to read a standard CAESAR II input data file that describes the basic layout of the piping system as if it was not buried. From this basic input CAESAR II creates a second input data file that contains the buried pipe model. This second input file typically contains a much larger number of elements and restraints than the first job. The first job that serves as the “pattern” is termed the original job. The second file that contains the element mesh refinement and the buried pipe restraints is termed the buried job. CAESAR II names the buried job by appending a “B” to the name of the original job.
  • When the Buried Pipe Modeler is initially started up, the following screen appears:

Buried Piping

This spreadsheet is used to enter the buried element descriptions for the job. The buried element description spreadsheet serves several functions:

  • Allows analyst to define which part of the piping system is buried.
  • Allows analyst to define mesh spacing at specific element ends.
  • Allows the input of user-defined soil stiffnesses.

From/ To node:-

Any element of pipe in CAESAR II can be define by two elements first is start point and second is end point. In buried pipe model, before conversion the From/ To nodes remains same as unburied model.

Soil model no. :-
This column is used to define which of the elements in the model are buried. A nonzero entry in this column implies that the associated element is buried. A 1 in this column implies that the analyst wishes to enter user defined stiffnesses, on a per length of pipe basis, at this point in the model. These stiffnesses must follow in column numbers 6 through 13. Any number greater than 1 in the soil model no. column points to a CAESAR II soil restraint model generated using the equations outlined later under Soil Models from analyst entered soil data.

From/ To mesh type:-
A critical part of the modeling of an underground piping system is the proper definition of Zone 1 bearing regions. These regions primarily occur:
• On either side of a change in direction
• For all pipes framing into an intersection
• At points where the pipe enters or leaves the soil
CAESAR II automatically puts a Zone 1 mesh gradient at each side of the pipe framing into an elbow. Note it is the analyst’s responsibility to tell CAESAR II where the other Zone 1 areas are located in the piping system.

User defined stiffness & ultimate load :-
There are 13 columns in the spreadsheet. Column 6 to 13 carry the user defined soil stiffnesses and ultimate loads if analyst defines soil model 1. Analyst has to enter lateral, axial, upward, downward stiffnesses & loads.

Procedure :-

  1. Select the original job and enter the buried pipe modeler. The original job must already exist, and will serve as the basis for the new buried pipe model. The original model should only contain the basic geometry of the piping system to be buried. The modeler will remove any existing restraints (in the buried portion). Add any underground restraints to the buried model. Rename the buried job if CAESAR II default name is not appropriate.
  2. Enter the soil data using Soil Models.
  3. Describe the sections of the piping system that are buried, and define any required fine mesh areas using the buried element data spreadsheet.
  4. Convert the original model into the buried model by the activation of option Convert Input. This step produces a detailed description of the conversion.
  5. Exit the Buried Pipe Modeler and return to the CAESAR II Main Menu. From here the analyst may perform the analysis of the buried pipe job.

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Basics for Stress Analysis of Underground Piping using Caesar II


A new procedure for assessing and rectifying subsea pipeline freespans was successfully used in 1992 in Mobil North Sea Ltd.’s Beryl field and the Scottish Area Gas Evacuation (SAGE) pipeline.

The span assessment method is in two parts, each part having two stages, and consists of preliminary stress and vibration frequency checks followed by detailed strain and fatigue life checks where appropriate.

Comprehensive software, automatically linked to an inspection data base, has been written to allow efficient use of the methodology.

Results from the freespan assessment indicate that the assessment procedure, and in particular the strain based and fatigue analyses, gave significant savings in terms of reduced number of freespans for rectification.

Critical freespans were stabilized by grout bags positioned by an ROV. The ROV based system enabled both risks and costs to be reduced in a normally hazardous and costly environment, and utilized technology already on board a pipeline inspection vessel.

The overall freespan assessment and rectification program represents a significant step forward for Mobil North Sea in terms of reducing costs, while simultaneously improving the speed and simplicity of freespan assessment.

The system provides the possibility that future freespan rectification works may be performed in a single offshore program, which includes pipeline inspection, survey, assessment, engineering, and repair of all freespans from a single survey vessel.


The Beryl A platform was installed in Block 9/13 in 1973. Subsequent developments in the block include the Beryl B platform; the Ness, Bwiss, Linnhe, and NESS II multiwell subsea developments; and four single subsea wells.

A total of 25 pipelines are laid in the block. Most are 6-in. OD flow lines from the subsea wells to the platforms but include one 16 in. and one 20 in. hydrocarbontransfer line between the production platforms and two short 36 in., oil export lines to loading buoys.

All the facilities noted are operated by Mobil North Sea Ltd. on behalf of the Block 9/13 co venturers Amerada Hess Ltd., Enterprise Oil plc, BG North Sea Holdings Ltd., and OMV (UK) Ltd.

Additionally, the recently installed SAGE (OGJ, Mar. 8, 1993, p. 37) gas export line runs 323 km (200 miles) from Beryl A to St. Fergus and is operated by Mobil North Sea on behalf of the Beryl and Brae groups.

The fines are inspected annually in compliance with regulatory and Mobil North Sea requirements and for continued fitness for purpose. As with most pipelines, the annual surveys identify numerous freespans which must be assessed and, if necessary, rectified.

Mobil North Sea has now implemented several improvements to its methods for collecting and recording pipeline inspection data and for automatically assessing the significance of freespans in relation to the service, pressure, temperature, and orientation of pipelines.

The methods of data storage and freespan assessment are based on PC programs for use onshore and at sea.

The basis for recording and displaying the inspection results is a data base system (Coabis). Survey data can be entered into the system in real time on the inspection vessel as the inspection is performed.

Further checks can be undertaken on the data in the office and include graphical comparison of all features from one year to another.

The benefits include the ability to correct mismatches iii datum locations between surveys by reference to fixed features (for example, flanges, anodes, and major debris) and a visual representation of how freespans, buried lengths, and any deterioration vary from year to Near.

The freespan assessment procedures are incorporated into a PC based suite of freespan assessment programs. The data base and freespan-assessment software are linked so that there is no manual transcribing of data following their entry into the data base on the vessel.

This extent of automation eliminates the previous errors made during manual transcribing of data and also reduces the time required for freespan assessment.

The freespan assessment procedure consists of two separate stages. The first stage is designed to be undertaken by Mobil North Sea’s inspection representative on the vessel and can be used to identify the more critical freespan@ where additional measurements (natural frequency, for example) may be beneficial.

This enables more data to be collected on these freespans, optimizes utilization of the inspection vessel, and may also reduce the extent of freespan rectification that is subsequently recommended, using the techniques described presently.

Before implementation of the system described here, selection of freespans for rectification occurred by reference to a “limiting value” for each diameter of pipeline. Calculation of the limiting value was based on the worst possible combination of conditions for any pipeline of that size.

The change in assessment techniques was prompted by, a belief within Mobil North Sea’s engineering department that the technique was overly conservative with excessive numbers of freespans being identified for correction. Indeed, for a number of Nears Mobil North Sea applied “engineering judgment” to the requirements for rectification.


Pipeline freespans are at risk from damage by one of two distinct mechanisms: by excessive bending from externally applied hydrodynamic or self weight loading, or by long term fatigue damage, from flow induced vibrations.

The traditional means of ensuring that excessive bending deformation cannot occur is to define a maximum allowable freespan length such that the maximum equivalent stress in the freespan is less than an acceptable fraction of the pipeline steel’s yield stress.

This approach has been used extensively for pipelines in the North Sea and elsewhere. The approach is conservative, however, in that it fails to recognize the post yield strength of a pipeline freespan and does not recognize that a pipeline can remain perfectly serviceable and fit for purpose even though the part of the pipeline steel may have exceeded the yield limit.

The traditional means of ensuring that flow induced vibrations cannot occur is to define a maximum allowable freespan length such that the natural frequency of the freespan is too high to allow any flow induced vibrations to develop.

Again, this approach has been used extensively in the North Sea and elsewhere but is also conservative. The approach prevents any form of freespan vibration and does not recognize that modest freespan vibrations may not cause fatigue failure.

More sophisticated and less conservative freespan-assessment methods have been introduced in recent years. Modern pipeline design codes, such as the recently, issued BS 8010 Part 3,1 explicitly allow the more sophisticated approach.

In the freespan analysis program described here, the simple stress and vibration criteria described previously are used for a first pass analysis to identify the more critical freespans which are then examined in more detail.

These freespans are re analyzed with more sophisticated strain based criteria to assess bending deformation and fatigue criteria to assess the extent of fatigue damage induced by freespan vibration.

The overall flow chart for the freespan assessment is described in Fig. 1. The preliminary and detailed freespan assessment methods are described in more detail presently.

The preliminary freespan assessment consists of checks for overstress in the freespan and the possibility that vortex induced vibrations may occur. These are also described presently.


The preliminary freespan analysis performed in this study is based on a freespan model described by Palmer and Kay.2 The model considers the effect of the axial force in the freespan, tension induced by the sag of the freespan, and partial foundation support at the freespan ends.

Most seabed soils in the North Sea provide only partial foundation support at the ends of a freespan. In fact, the pipeline embeds into the soil at each end of the freespan.

The point at which the freespan is subject to complete end fixity is usually some distance along the seabed beyond the end of the freespan.

This end fixity controls the rotational and vertical stiffness of the freespan supports and affects the bending moments within the freespan itself.

For bending moment calculations in this study, the end supports were assumed to be completely fixed, that is, “clamped crimped” end conditions.

This assumption provides a conservative estimate of end moments over a wide range of typical soil conditions in the North Sea.

The maximum bending moment in the freespan, as a result of both the pipeline’s self weight and external hydrodynamic loading, is calculated with beam column theory, taking into account the effective axial force in the freespan. This force includes both the force in the wall of the pipeline and the force resulting from the pressure of the pipeline’s contents.3

Additionally, the effect of tension generated by the sag of the freespan is also taken into consideration. This effect can be significant for long freespans and has an important effect on both the axial stresses in the freespan and the freespan’s natural vibration frequency.

Hydrodynamic forces are calculated with Morison’s equation with appropriate force coefficients. The maximum bending, axial, and hoop stresses in the wall of the pipeline are then calculated, and the greatest von Mises equivalent stress in the freespan is evaluated.

This stress is compared against the yield stress of the pipeline steel:

  • If the ratio of the maximum equivalent stress to the specified minimum yield stress (SMYS) is less than 0.96, the freespan is concluded to be safe.
  • If the ratio is greater than 0.96, then the freespan is unacceptable on the preliminary stress criteria and requires further analysis.


A pipeline freespan can be subject to flow induced vibration from vortex shedding from the freespan. Vortex induced vibration is predominantly controlled by a dimensionless parameter called the reduced velocity written as shown in Equation 1 in the accompanying equations box.

Generally, relatively small amplitude vibrations of the freespan in line with the flow direction occur at values Of VR greater than 1 and peak at VR between 2 and 3, while larger amplitude vibrations across the flow direction begin at VR around 3 and peak at VR of about 5.

The traditional design approach is to adopt a critical VR which must not be exceeded in design storm conditions. The selection of the critical reduced velocity and the appropriate storm velocity is open to engineering judgment, however, and the application of this approach is often inconsistent.

In the analysis described here, the critical reduced velocity has been taken as equal to 3.5, in which the incident velocity (V) is the sum of the maximum wave-induced velocity and the maximum current velocity.

In order to assess whether vortex induced oscillations will occur, it is necessary to calculate the freespan’s natural frequency (fN).

In this analysis, the natural frequency, is calculated by modeling the freespan as a clamped clamped beam under an axial force which yields Equation 2.

In order to model the finite foundation stiffness at each end of the freespan, LE in Equation 2 is taken as 1.1 multiplied by the observed length of the freespan.

The freespan frequency can be a difficult quantity t@ predict accurately. To investigate this further, the natural frequency of longer freespans was measured during the 1992 survey program with an ROV mounted accelerometer package.

Fig. 2 shows the calculated natural frequency for various freespans in (he 30 in. SAGE gas export pipeline plotted against the measured frequency,. The figure shows the calculated frequencies for isolated freespans only.

The general agreement is clearly good, despite some inconsistencies in the data. The agreement for multiple freespans is noticeably worse, however.

Although not shown in Fig. 2, the comparison for multiple freespans suggests that predicted frequencies for multiple freespans strongly depend on the extent of support provided by intermediate touchdown points.

The detailed freespan assessment consists of a check for excessive strain in the freespan and the calculation of the fatigue life of the freespan,


The serviceability of a pipeline which fails the overstress check previously described will be unaffected provided that the post yield deflections of the freespan are not excessive.

The BS 8010 design code,1 for example, allows yield due to large bending stresses provided that certain requirements on the plastic strains, weld ductility, and diameter wall ratio are satisfied.

These conditions can often be met by subsea pipeline freespans where the seabed provides a boundary which prevents excessive deformation of the freespan. Once the freespan touches down, it becomes essentially two freespans separated by a single support.

The central touchdown limits the bending deformation of the original freespan and provides a support which reduces the stresses in the subsequent double freespan.

The greatest possible bending strain which could occur can be calculated from the gap below the freespan and the length of the freespan. This maximum possible strain is then compared against two limits, based on the following:

  • The maximum allowable strain governed by weld ductility and steel properties
  • The buckling strain on the compressive side of the pipeline, which is a function of the pipe diameter/wall thickness ratio.

If either of these limits is exceeded, there is a risk of excessive pipeline deformation and the freespan must be rectified.


A detailed and accurate assessment of the consequences of flow induced vibrations of the freespan can be performed by predicting the amplitude of freespan vibrations over the freespan life and evaluating the subsequent fatigue damage.

The fatigue calculation is performed by first generating a probability distribution of the incident wave and current velocities over the design life of the freespan.

For waves, this is usually provided by a scatter diagram. For currents, the data are often much more difficult to obtain but can often be estimated from the statistical distributions of the tidal and storm current components.

For a given freespan, the incident reduced velocity can then be calculated for each wave and current combination in the environmental data set. The amplitude of freespan vibration can be predicted by interpolation of experimental measurements of freespan vibrations.4

The prediction of the expected amplitude is complicated by the presence of the oscillatory wave component superimposed on a steady current. This can be resolved by reference to more extensive data or (as followed in this study) more detailed modeling of freespan vibrations with steady and oscillatory flow.

The effect of wave induced oscillations is also included in the analysis. In this case, the wave induced displacement was estimated from the oscillatory hydrodynamic force on the freespan with an allowance for any resonance of the freespan.

For each wave current combination, the oscillatory stresses induced by the applied vortex displacement or wave loading can be predicted from beam column theory. The corresponding fatigue damage at that stress range is calculated from S N curve fatigue data.

If the number of cycles to failure for a particular wave-current combination (i) is given by Ni, then the total fatigue damage for that combination is shown in Equation 3.

The total fatigue damage for all wave current combinations can be calculated with Miner’s rule as the sum of all particular combinations (Equation 4).

If the total fatigue damage is greater than 1, then the freespan is deemed to be unacceptable and rectification should be considered. If total fatigue damage is less than 1, the freespan does not require correction, but it would be prudent to monitor the freespan during subsequent surveys to determine if it will grow with time.

It should be noted that spans can reduce with time and the rate of fatigue damage may decline.


Figs, 3 5 show the results of the inspection and analysis program for the SAGE gas export pipeline and the Beryl B to A 16 in. gas and 20 in. oil transfer lines.

Each figure shows the total number of freespans observed during the survey, the number of freespans that failed the preliminary analysis, and the number of freespans that failed the detailed analysis.

The freespans have been grouped into 10 m lengths to help identify which freespans have failed. Results are summarized in Table 1.

The portion of freespans within each length group which failed the preliminary and detailed analyses increases with increasing freespan length. Several short freespans were observed during the survey, but of these freespans none failed either the preliminary or detailed analysis.

As the freespan’s length increases, the total number of freespans observed decreases; of the observed freespans, an increasing proportion failed the preliminary analysis and an increasing proportion of these freespans failed the detailed analysis.

None of the freespans in the 6 in. flow lines failed the detailed analysis or required rectification.

The cost saving that results from using the revised freespan analysis is demonstrated by Figs. 3 5 and by Table 1. For example, Fig. 3 shows the results for the 30-in. SAGE pipeline (Beryl gas export to St. Fergus).

If the freespan failure criteria were based on the worst case limiting freespan length from the preliminary analysis, which is typical of the previous Mobil North Sea approach, then all freespans greater than 30 m would require rectification.

This gives a total of 166 freespans. Clearly not all these freespans would be stabilized, but the selection of appropriate freespans for stabilization would then be based largely on intuitive engineering judgment rather than engineering calculation.

If the freespan failure criteria were based on the preliminary analysis but applied to each individual freespan, the total number of freespans requiring rectification would be reduced significantly to 20. Of these freespans, only 11 failed the detailed analysis described previously.

The total number of freespans requiring some form of stabilization is therefore reduced from 166 to only 11. Many of these freespans failed assessment by fatigue only. Where the remaining life extends over several years, rectification could be delayed and advantage taken of any natural backfilling of the line.

Similar conclusions can be made for the Beryl B to A oil and gas transfer pipelines in Figs. 4 and 5. The trends are rather less clear because of the lower total number of freespans in these two pipelines, but the revised assessment procedure again provides a better and less conservative basis for the selection of freespans requiring some form of rectification.


The normal techniques for stabilizing spanning pipelines are rock dumping, grouted support, or gravelcement bag supports. These techniques are normally installed and deployed by either a custom built vessel, such as rock dump vessels, or diving support vessels.

Both types are extremely costly with associated high mobilization costs.

The decision was made to consider not only these types of vessels but also new techniques such as ROV systems. The cost of running an ROV based vessel capable of remote maintenance operation is approximately 25 33% that for a diving vessel.

In addition, it has been a Mobil North Sea initiative over the past few years to remove the diver from as many subsea applications as possible to reduce hazards and costs.

A technical and cost comparison was made of the three options and of remote maintenance using ROV systems.

The costs (Table 2) are indicative and based on a Mobil North Sea cost estimate of critical freespans on both the SAGE and Beryl B to-Beryl A pipelines. It was assumed that a total of 12 freespans required support, split equally into two locations approximately 200 km apart.

On the basis of the cost comparison, the ROV based techniques were eventually chosen and used successfully in 1992.


The critical freespans requiring rectification in the 1992 pro,ram varied greatly in length and height off the seabed. In particular, the height of freespans ranged 75 250 mm off the seabed.

The system of deploying and installing the grouted support had to deal with both extremes of freespan height.

The chosen method of rectification was to deploy a grout bag and position it below the pipeline. The bag was then inflated with grout which, when cured, provides a rigid support to the line.

The vessel used for the freespan rectification program was the Kommandor Subsea operated by SubSea Offshore Ltd. This vessel had already been charted for the SAGE pipeline inspection program and was ideally suited for ROV operations.

The only additional equipment required was a grouting spread and launch and-recovery system for the ROV installed grout bags.

A standard grouting spread was employed to mix and pump a grout mixture specified by Mobil North Sea.

The grout design was based on achieving a minimum compressive strength within a 28 day period.

The grout bag support was designed to ensure that it be inflated correctly and that it be easy to use for the ROV and deployment frame system. The bag itself was built from industry standard fabric.

The operation was carried out in five operations:

  1. Grout support location. The ROV’ was deployed to survey the freespan and mark the location on the pipeline where the proposed grouted support should be placed.This marking was made by use of a white marker chain visible by ROV sonar and cameras.
  2. Grout-bag deployment. The grout bag was deployed on a circular swivel deployment frame, launched from an A frame over the side of the Kommandor Subsea.The grout bag deployment frame and rout hose umbilical were then lowered to the seabed surface, landing approximately 5 10 m from the pipeline support location.
  3. Grout bag installation. The deployment frame was turned on its swivel base by ROV to ensure that the grout bag’s leading edge was facing towards the pipeline. The ROV was used to push a needle attached to the grout bag under the freespan and then to pull the bag through on the other side of the pipeline and pull the bag away from its deployment frame.This operation was carried out slowly to ensure the accurate placement of the grout bag under the pipeline.
  4. Grout bag inflation. Grout was pumped through a 58 mm bore grout hose which was attached to the grout bag via a quick release connector.Once the desired support shape was achieved and grout was seen venting from the top the bag, grouting was stopped and the quick-release connection broken by the ROV.
  5. Deployment frame recovery and post installation survey. The deployment frame was pulled away from the location to allow flushing of the grout hose; the deployment frame was then recovered back to the vessel.

The ROV then made its final post installation survey, of the freespan and the newly, installed support, recording positional and visual data.

The total duration for these five operations, based on a grout bag volume of 1.5 cu m, was approximately 3 hr depending on weather. Approximately four grout bags could be placed in close proximity, within a 12 hr shift.


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What are PIG’s, PIG Launchers, and PIG Receivers and Why Are They Important?

What are PIG’s, PIG Launchers, and PIG Receivers and Why Are They Important?

What Are PIG’s?

PIG’s are devices that are inserted into pipelines and used to clean, inspect, or maintain the pipeline as they pass through it. They may also be used to separate different batches or types of product within the pipeline. For effective movement through the pipeline they are usually cylindrical or spherical and may be bullet shaped.

PIG’s were traditionally used in the oil industry for large diameter pipelines. However, because of their useful qualities and the benefits they bring to pipelines, they have begun to be used in a very broad range of pipelines from small to large diameter. Nowadays they are also by no means found only in the oil and gas industry; they can be found in use at many plants and industrial sites and are effective just about anywhere a pipeline is in use. For example PIGs and PIG systems may be found in operation at plants and factories that process lubricating oils, toiletries, paints, a host of different chemicals, consumer cosmetics, and even foodstuffs.

Because the demands placed on PIGs are so diverse, the PIGs themselves may be made out of a wide variety of different materials. Often some type of steel is used and depending on requirements and budgetary concerns it could be stainless steel, duplex stainless steel, low-strength carbon steel, high-strength carbon steel. Again depending on how corrosive the materials the PIGs will be coming into contact with are, the PIGs may also be coated with corrosion-resistant materials or other specialty coatings. In addition to steel, PIGs may also be made out of polyurethane foam and other material types.

The earliest PIGs were likely made of straw and wrapped in wire to facilitate pipe cleaning. Conventional wisdom holds that it was from this early use that PIGs get their name since the squealing sounds they made as they passed through the pipes reminded people of the sounds a pig makes. The industry term PIG is likely a backronym and it is generally explained to mean ‘Pipeline Inspection Gauge;’ however, some people also use it to mean’ Pipeline Intervention Gadget.’

A special type of PIG called a “Smart PIG” puts a more high tech spin on things. This type of PIG has special electronics and sensors that allow it to not only clean and maintain the pipeline but to also gather additional information about the condition of the pipeline itself such as surface pitting, corrosion, cracks, or weld defects. This information is usually gathered using magnetic flux leakage (MFL) PIGS or PIGS equipped with electromagnetic acoustic transducers.

What are PIG Launchers and PIG Receivers?

In simplest terms the PIG launchers and PIG receivers are the sections of the pipeline which allow the PIG to enter and exit the pipeline. They are generally funnel, Y-shaped sections of the pipe which can be pressurized or depressurized and then safely opened to insert or remove PIGs. Most pigging systems use bidirectional launchers and receivers that can work in either direction. This is important to allow the PIG to be retrieved by the launcher if there is a blockage in the pipeline which prevents it from reaching the receiver.

PIG launchers and receivers come with safety valves and locking system to prevent accidents. They are also optimized to be suitable to the pressure and temperature requirements of the pipeline. Launchers and receivers may be horizontal or vertical depending on the needs of the pipeline.

Some launchers are designed to hold multiple PIGs at once and configured to launch them according to preset conditions. This is very useful because it allows much of the work to be done remotely. Additionally it prevents the launcher from having to be depressurized and repressurized again each time a single PIG is needed. It is the pressure from the flow of product that moves the PIGs through the pipeline. Thus one of the main roles of launchers and receivers is to safely interface between the low-pressure outside world and the high-pressure pipeline.

How Do PIG Launchers and Receivers Work?

The exact procedure for operating a PIG launcher or PIG receiver will vary somewhat depending on the particular pigging system being used. However, for the most part it will include the following steps:


  • Pipeline operator should make sure that the isolation valve and kicker valve are closed.
  • If the system is a liquid system then the drain valve and vent valve should then be opened to allow air to displace the liquid; if the system is a gas system then the vent should be opened so that the launcher reaches atmospheric pressure.
  • After the PIG launcher is completely drained to 0 psi, with the vent and drain valves still open, the trap door should then be opened.
  • The PIG should then be loaded with its nose in contact with the reducer.
  • Closure seals and other sealing surfaces should be cleaned and lubricated as needed and then the trap door should be closed and secured.
  • The drain valve is then closed and the trap is slowly filled by gradually opening the kicker valve.
  • Once filling is complete the vent valve is closed so that the pressure will equalize across the isolation valve.
  • The isolation valve is then opened and the PIG is ready for launching.
  • Next the main valve is gradually closed, increasing the flow through the kicker and behind the PIG until finally the PIG leaves trap altogether and enters the pipeline itself.
  • After the PIG leaves the launcher the mainline valve is fully opened and the isolation valve and kicker valve are closed.


  • The receiver should be pressurized.
  • The bypass valve should be fully opened.
  • The isolation valve should be fully opened and the mainline valve partially closed.
  • Once the PIG arrives the isolation and bypass valves should be closed.
  • The drain valve and vent valve are then opened.
  • Once the trap is fully depressurized to 0 psi the trap can be opened and the PIG removed.
  • The closure seal and other sealing surfaces should be cleaned and lubricated as needed and the trap door should then be re-shut and secured.
  • The receiver should then be repressurized and returned to its original condition.

These processes may differ somewhat on different systems and of course if the launcher will be launching multiple PIGs then they should all be loaded at the loading stage.

Why Are PIGs and PIG Launchers and Receivers Important?

There are four main benefits for using PIGs:

Separation – PIGs can be used to physically separate different products within a pipeline. Without PIGs the pipeline would need to either be flushed out between products, or a portion the second product would be contaminated with the first product. Both options would result in waste. With PIGs acting as separators, however, this problem is eliminated.

Cleaning and Maintenance – PIGs clean the pipeline by scraping away building up and debris and pushing it safely into the receiving trap. This improves the efficiency and flow of the pipeline and helps prevent corrosive damage to the pipes.

Inspection – Smart PIGs using technologies such as MFL and ultrasonics can inspect the pipeline for welding defects, cracks, pitting, and other problems. Caliper PIGs can also take estimates of the internal geometry of the pipeline.

Positioning and monitoring – Smart PIGs not only inspect and retain the data about the pipeline, they can also provide information about where the particular defect or trouble area of the pipeline is located. This prevents unnecessary digging up of healthy parts of the pipeline and if a problem isn’t severe enough to warrant replacing, it also allows the trouble section to be closely monitored and the PIG results to be compared across multiple time frames to track damage progression.

PIG launchers and PIG receivers are integral to the pipelines pigging system. Their safety valves, security locks, and ability to pressurize and depressurize provide a safe way for the PIGs to be loaded and removed without danger to the pipeline and equipment or human personnel. STI Group provides its customers with high quality, dependable PIG launchers and PIG receivers that can be used in standalone systems or as a skid mounted unit.


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What are PIG’s, PIG Launchers, and PIG Receivers and Why Are They Important?

DEEPWATER RISERS Steel catenary, flexible risers battle for technical supremacy

Flexible risers are being usurped by metallic systems in some of the newer deepwater developments. Shell chose steel catenary risers for its three latest TLPs in the Gulf of Mexico, and Petrobras has followed suit for gas export from the Marlim semi. In Norway, titanium is making its mark in the riser for the Heidrun TLP.

The downside of metallic systems is the extra expense perceived for many applications. For this reason, flexible risers will remain popular for all water depths. However, there are serious design challenges to surmount as development heads deeper.

In a paper delivered at Deeptec ’96, Aberdeen, Svein Are Lotveit of SeaFlex put collapse capacity and weight limitations at the top of his list. He also drew attention to related concerns for deepwater flexible pipe, namely:

  • General demand for large bore risers
  • High pressure, high temperature and aggressive fluids
  • Complicated replacement/repair of deep water risers, which needs to be avoided.

SeaFlex, a Norwegian engineering consultancy, is also part of the technical support team evaluating Coflexip and Wellstream pipes at Shell’s facilities in The Hague. The project, known as the Deep Water JIP, is led by four major oil companies.

Coflexip and Wellstream are two of the dominant producers of non-bonded flexible risers (bonded pipes are currently not in the picture for deepwater risers). Another emerging heavyweight is NKT (Furukawa). Lotveit went on to outline this trio’s current R & D work.

The market leader for deepwater, large diameter and high pressure applications is Coflexip, which favors a five-layered construction for its pipe. The innermost section is a carcass, providing collapse resistance. This is normally cold formed from stainless steel (316L), although Coflexip is working on alternate, T-shaped carcasses made from aluminum or ferritic stainless steel.

A key thrust of its development has been the middle layer hoop spirals. Main aim has been to increase the pressure rating and to improve service life. Traditionally, the hoop spiral has a Z-shaped cross-section (Zeta). However, a new hoop spiral wire geometry has been developed, called T-wire, which has been used in several test pipes but has so far not been installed offshore.

Advantages of the T-wire geometry are said to be:

  • Larger and stronger hoop spirals can be made
  • Less susceptible to initiation of fatigue cracks than the Zeta. In accelerated tests, it has been shown to improve service life of Coflexip risers.

The T-wire is currently being tested by the Deep Water JIP. To date, thicknesses up to 14mm have been examined, and wires up to 16 or even 18mm may also shortly be tested. This will increase substantially the pressure rating of large-bore Coflexip risers. A further increase in capacity is achieved through use of a secondary hoop spiral outside the T-wire.

T-wire’s main impact will be in extreme pressures and dynamic risers. However, long length production of Coflexip risers with T-shaped wires will likely involve substantial investments, meaning that the cost of these risers will be relatively high.

Tension armors in the company’s risers are normally made of rectangular steel wires. To increase the depth range of flexible pipes, Coflexip has qualified tension armors of reduced weight composite material. One composite riser has been installed offshore Brazil and is still in operation.

However, the cost of composite-reinforced systems is higher than a steel-reinforced pipe. They are only justifiable, therefore, at great depths where traditional pipes are too heavy. Maximum depth for a steel-reinforced flexible riser in a free-hanging configuration is typically 1,000 meters. For greater water depths, riser weight is critical and there composite may become attractive again, according to Lotveit.

During 1994-95, a number of failures occurred in risers in high temperature service (above 80C). Both Coflexip and Wellstream responded by re-evaluating their designs, making significant changes. This work is still some way from completion.

Coflexip had considered 20 different designs before selecting a prototype for testing. A 20 meter test pipe and a second sample with the old end fittings were both manufactured and tested by cycling the temperature from ambient to 130C. The new end fitting included a steel sleeve inserted under the main fluid barrier in order to control accurately the diameter and circularity of the barrier close to the main pressure seal.

While the failure rate of the old design in tests confirmed misgivings, the new sample did not perform perfectly either. Coflexip then designed and built five new pipes with different end fittings, incorporating different methods of PVDF layer termination. Since June 1995 when the first set of tests were completed, the second series of pipes have proven these end fittings to be stable.

One customer was sufficiently convinced to accept the first dynamic jumper with a new end fitting design, for short-term service (two to five years) in the Far East. This has been in service since last October. Following further tests, Coflexip is now predicting 20 years of service life.


Wellstream’s long-term R&D program for non-bonded flexible pipe focuses on extending the product’s capability through higher design pressures with large diameters; higher design temperatures (up to 180C); deeper water; and extremely sour production fluids, up to 5,000ppm H2S. It aims to achieve these targets by 2000, but this will involve improved technology and manufacturing processes.

Current Wellstream can cold form a 1.8mm thick stainless steel strip to a 10mm thick carcass. Tests performed by the Deep Water JIP have shown the collapse resistance of the 10-in. inside diameter structure to be 120 barg, when supported by Wellstream’s Flexlok hoop spiral. Allowable water depth with this design is 1,040 meters.

To increase collapse resistance for larger diameter pipes, a new carcass machine is being developed capable of producing up to 16-in. ID: this should be in place by late 1997. Wellstream is also evaluating other profiles and materials such as aluminum alloys which reduce weight and cost while providing greater collapse resistance and sufficient corrosion resistance.

The Flexlok hoop spiral currently comes in three sizes, 4.8, 6.4 and 8mm. However, a prototype 10mm spiral has been produced. Machinery for 10 and 12mm profiles will be in place by the end of next year.

Last year the Flexlok profile was refined using finite element analysis optimization. The design was proven to be successful in a recent dynamic test for a 6-in. riser with 420 barg internal pressure. This riser included for the first time (from Wellstream) a secondary hoop spiral, the Flexpress, for increased pressure capacity.

A thicker Flexpress layer will be applied on the second Deep Water Riser JIP Wellstream pipe, planned to be tested early in 1997. The upgraded Flexlok machine will also be capable of applying a thicker and wider Flexpress layer to increase the pressure capacity of the larger diameter pipes.

Wellstream is also in the process of developing a carbon fiber thermoplastic composite strip to replace the steel tensile armor layer for deepwater sour service and onshore arctic applications. The composite armor is lighter in weight, stronger and more resistant to corrosion than steel. This extends the use of the flexible pipe to dynamic risers for deeper water applications.

Static qualification will likely be achieved by early 1997, with dynamic qualification later in the year and dynamic field demonstration in 1998. The company has also worked closely with Emerson & Cumming to develop a syntactic foam thermal insulation suitable for water depths down to 1,000 meters. This material has been used by Wellstream on Norsk Hydro’s Troll project (340 meters water depth). E&C is qualifying similar materials for depths down to 2,000 meters.


NKT is currently establishing a large manufacturing line for non-bonded flexible pipes in Kalundborg, Denmark. From next year risers will be produced of the Furukawa design that were qualified for dynamic service by Shell in the mid-1980s. Static flowlines will be produced this year.

Production capacity will typically be 70 km of flexible pipe per year, with a maximum of 10-in. ID and 5,000 psi design pressure. Manufacturing is based on turntables with large capacities, allowing up to 10 km of 10-in. pipe to be produced in one length.

Although the NKT/Furukawa riser has been considered promising, the two companies have until recently been reluctant to put sufficient resources into entering the flexible riser market. They have chosen to do so now when demand for flexible pipes is buoyant.

But as Lotveit points out, they also face hard competition. Coflexip has increased its production capacity in France and opened a new factory in Australia. Wellstream is established in the market, and metallic pipes in flexible riser configuration are being viewed as feasible for deep water applications.

Most of NKT’s R&D relates to getting production up and running. But there is also a continual dialogue with the oil companies to ensure that NKT’s products are in line with industry needs.

One of its first steps needs to be to gain third party verification of the design analysis tools, in line with API Spec 17J. NKT has also been liaising with Shell to develop a composite armored flexible flowline. A prototype may be constructed this year. The aim is reduced weight and use for sour service.

Steel catenaries

Speaking on behalf of steel catenary risers at the same IIR-organized conference, Dr Hugh Howells of 2H Offshore Engineering, Woking, UK, outlined why steel had won the day on Shell’s new US TLP developments. Compared with vertically tensioned risers, he pointed out, the steel catenary offers reduced deck space, elimination of the riser base and tensioner and a fixed valve stack: this adds up to a simple arrangement at reduced cost.

Scope for flexibles was also limited by Shell’s pressure requirements, he added. The Auger platform’s export lines are already close to the maximum diameter/internal pressure combination of flexible risers. Lines larger than 12-in. diameter are beyond current flexible riser capability, which would limit use of flexibles for the Mars Field export lines.

However, steel catenaries wouldn’t appear to travel easily to the deep waters west of Shetland, due to the harshness of those operating conditions compared with the Gulf or Brazil. Factors weighing against steel risers off Scotland are larger waves and currents, which would increase extreme loading.

These currents might necessitate use of vortex-induced vibration suppression strakes over longer lengths. Also, the greater average wave height would increase the risk of fatigue damage. Assuming that vessels remain the in-vogue production method west of the Shetlands, Howells prognosticated that drift offsets of up to 25% water depth might be needed in this region for a catenary moored vessel, in order to accommodate intact and damaged mooring systems. This compares with under 10% offset maximum for TLPs in the Gulf, which would mean substantially greater compliancy requirements for the steel riser.

One way of handling these large vessel offsets and dynamic motions, he suggested, might be to use buoyancy arrangements for the steel catenary similar to those applied to flexibles. Loads applied to the vessel would be lower than with flexible risers, as these are 20-40% heavier than steel equivalents in production mode.

Installation of steel catenaries and attached flowlines could be performed using conventional laying methods such as S-lay, J-lay and reel lay. To cut costs, risers and flowlines could be installed in one operation, eliminating the need for a subsea tie-in between riser and flowline.

Vessel tie-in procedures would be the most difficult aspect of steel catenary installation off the Shetlands, said Howells, so greater care would be needed to control curvature. But the extra controls required would not impact cost significantly. In fact, weight of flexible risers may be 40-80% heavier than steel lines during installation, assuming lines are filled.

Howells concluded that steel catenaries could prove a money-saver for TLPs in this environment – perhaps up to 100,000 per riser – through lesser requirements for the riser base and flowline tie-ins.


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