Pipeline Integrity Management External

August 1, 2017 | Author: Javierfox98 | Category: Pipeline Transport, Corrosion, Fracture, Pipe (Fluid Conveyance), Fracture Mechanics
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Asset Management Services

Pipeline Integrity Management Services

Germanischer Lloyd – Service/Product Description

Germanischer Lloyd – Service/Product Description

Pipeline Integrity Management Services Service Title:

Asset Management Services

Lead Practice:

GL Asset Management (UK)

Contents Page 3 Service Description and Values Generated Pages 4 - 16 Detailed Method Statement a: External Corrosion Management b: Fitness for Service Assessments c: Geotechnics and Ground Movement d: In-Line Inspection Services e: Integrity Management System Audits f: Investigation of Pipeline Incidents g: TD/1 Surveys (Affirmation of MOP for Onshore Pipelines) h: Pipeline Uprating i: Welding Technology Services j: Grouted Tee k: Internal Corrosion Management

Pages 17 - 20 Case Studies and Examples a: Investigation of AC Interference Problem on High Pressure Pipeline b: Guidance on SCC Risks on a Pipeline Operators Network c: Coating and Backfill Interaction d: CP Decision Support Tool e: Dent Assessment on a 30” Oil Pipeline f: Advances in Interaction Rules for Corrosion Defects in Pipeline Using FE Analysis and Full Scale Testing



Service Description and Values Generated: Pages 21 - 35 Case Studies and Examples

Germanischer Lloyd (GL) offers a complete pipeline integrity service and many variations to the basic service are possible. Clients may wish a complete PIMS to be provided for them, an audit/review of their existing system or anything in between these two.

GL’s incident investigation service is just one part of a complete integrity package that GL can supply to process plant operators and Gas and Oil producers. This is one of GL’s strengths and can generate a considerable amount of revenue.

This service is primarily aimed at clients whose pipelines are designed and operated to IGE/TD/1. It can however be promoted as a “best practice” offering for all onshore gas pipelines operating in populated areas. The actual detailed implementation could be adapted to suit other pipeline codes e.g. ASME 31.8.

National and international oil and gas (and water?) pipeline owners and operators.

o: In-Line Inspection Scheduling

Oil and gas majors with new assets or joint ventures.

p: Review of Operations and Maintenance Practice

Small scale operators with limited experience in pipeline integrity management.

Oil, gas, and water pipeline owners and operators.

Pipeline contractors and consulting firms.

Major Gas/Oil operators in the Middle East and North Africa.

Gas operators in the UK.

g: Fracture Mechanics Assessment of a Defective Pig Trap h: Fatigue Assessment of Dented Pipeline i: Metallic Gas and Water Mains Affected by Ground Movement j: Pipeline Affected by Collapse of Quarry Face k: Deep Basement Construction - Large Diameter Cast Iron Gas Main Affected by Ground Movement l: Effect of Slope Instability of High Pressure Pipeline m: In-Line Inspection Vehicle Development n: In-Line Inspection Data Analysis

q: China Joint Venture LNG Pipeline r: Investigation of Pipeline Incidents s: TD/1 Surveys t: Pipeline Uprating u: Design and Qualification of Repair Procedures for Bellows Attachment Welding v: Grouted TeeTM w: Weldability Testing of 48” Diameter X80 Europipe Production x: Corrosion Control of a Sour Gas Pipeline y: Naphtha Pipeline Integrity Management Study z: Sour Export Pipeline Study



a. External Corrosion Management

Procedure Qualification Testing

The coating choice and the method by which the pipeline coating is applied will dictate the long term protection afforded to a pipeline.

In order to confirm that a coating applicator is competent to apply the specified coating material, procedure qualification trials must be conducted. The purpose of the procedure qualification trial is to establish that the coating applicator is capable of applying the coating material in accordance with the coating specification and produce a coating which is capable of passing the performance criteria required by the specification. In general, testing will evaluate the following properties of the coating.

As with the coating system, the design, operation and monitoring of the cathodic protection system will also have an impact on the in-service performance of the pipeline. Control, mitigation and management of corrosion anomalies such as AC and DC corrosion, MIC and SCC will safeguard the integrity of a pipeline and extend intervals between inspections and ultimately its service life.



Coating Selection

Impact resistance

The generic choice of a pipeline coating system will significantly influence the protection it affords during, handling, construction, commissioning and service. Small-scale laboratory evaluation is generally performed to rank and select materials prior to their full-scale application. This process evaluates the coating’s physical, chemical and mechanical properties with reference to those properties that are essential for successful in-service performance. The factors during application that influence the long term performance of a coating system e.g. surface preparation, application temperature and time at temperature must be fully appreciated in order to optimise performance. GL has significant experience of coating selection and small and large scale evaluation programme generated over the last 40 years.


Water soak resistance

Cathodic disbonding resistance

Strain polarisation resistance

Coating Application A technical audit is often required at the coating application facility, prior to large scale production coating, to establish whether the plant is capable of controlling the parameters required to achieve the ultimate properties of a pipeline coating, and that operatives are suitably trained to operate this equipment. The technical audit should review the following: 

Facilities for storage of uncoated and coated pipes

Contamination assessment and cleaning prior to coating

Surface preparation

Chemical pretreatment

Coating application/curing

Testing and inspection

Coating protection for storage and transport

GL has been providing technical audits in coating application facilities for a range of customers over many years.


Once procedure qualification testing has been successfully performed production coating can commence. GL instigated the requirements for procedure qualification testing prior to production coatings, and have been active in performing qualification testing of a range of coating materials applied to linepipe, fittings and field joints.


Coating Condition Assessment

Protection Criteria

As part of the pipeline commissioning process, it is necessary to perform a coating condition assessment to minimise any coating damage which may have been sustained during the pipeline construction activities. Any coating damage found must be excavated and repaired. Two techniques are employed to locate coating damage on buried pipelines viz. the Pearson technique and a technique referred to as Direct Current Voltage Gradient (DCVG) measurement. The purpose of these surveys is to locate coating damage that may be associated with mechanical damage to the pipe. Location and repair of coating damage will minimise the current requirement from the cathodic protection system.

Any cathodic protection system must meet the protection criteria specified by the company or international standards being adopted. In general, the following criteria apply when measured against a copper/copper sulphate reference electrode:

GL has developed detailed work procedures for the various survey techniques and has been active in their application.

A polarised pipe to soil potential more negative than minus 850mV

A polarised pipe to soil potential more negative than minus 950mV where sulphur reducing bacteria is known to be present

An ‘ON’ potential more negative than minus 1250mV

Following successful commissioning of the cathodic protection system the following checks will be required. 

Electrical isolation of the carrier pipe and sleeves to be confirmed

The operation of insulation joints and flanges to be checked

That the CP criteria referred to above is being met

In order to establish that the cathodic protection system is operating in compliance with company or international cathodic protection codes, validation of the system is required. This is achieved by measuring the output parameters (voltage and current) of the TRs along the pipeline route, the ‘On’ and ‘instant off’ potentials at test posts, and by performing close interval potential surveys. Management Procedures for Cathodic Protection of Pipelines To ensure a high level of safety and reliability in operation, it is essential that buried steel pipework associated with transmission and distribution systems is designed, installed and commissioned to withstand the potentially harmful effects of corrosion and that corrosion control systems employed are monitored to ensure continued effectiveness. The procedures used for the management of cathodic protection systems should encompass the requirements for design, construction, installation, validation and monitoring.


Routine Monitoring Routine coating condition and CP monitoring is required to confirm that the cathodic protection system is operating in compliance with the codes. As well as monitoring pipe to soil potentials etc., interaction testing to mitigate the effects on third party pipelines will be required along with checks for interference from AC (overhead power lines) and DC (traction systems) electrical sources. GL has been involved in developing policy and procedures for CP design, validation and monitoring.

Before undertaking the design of a cathodic protection system, detailed information on the plant to be protected will be required. This will normally involve a site survey to determine the factors (e.g. soil type and resistivity) relating to the overall corrosion control programme. The design will take account of the route plan, pipe parameters, coating types, the requirement for insulation joints/flanges, proximity to power lines etc. An important choice in terms of the design is whether a sacrificial or impressed system is required.



Review, Mitigation and Management of Corrosion Anomalies Stray DC Corrosion Stray DC current can have a significant effect on pipelines in areas of coating damage. The main source of this interference is from DC electric transit systems that run close-by the buried structure. In most DC transit systems, the power (load current) to operate the 'train' is fed via an overhead feeder connected to the positive pole of the DC supply. This load current is returned to the negative pole of the DC supply via the tracks. Unfortunately, as the tracks are laid at ground level, complete insulation from earth is unlikely and therefore some of the load current may take an earth path back to the DC supply. Pipelines close to a DC system constitute a good return path for a portion of this current. If a pipe offers a less resistant path, the current will travel along it, creating an anodic area where the current dissipates. DC corrosion is usually characterised by localised deep pitting.

Most codes and recommended practices related to CP monitoring and control require interaction testing to be performed in stray current areas and appropriate action to be taken to mitigate the problem. On-line inspection or direct assessment in areas of coating damage will confirm the effectiveness of this action.

CP Shielding An electrically isolating object e.g. a rock or stone, in contact, or in close proximity to a pipe can cause electrical shielding. This form of shielding can prevent the CP current reaching open coating defects. Electrical shielding is also a concern under disbonded coatings. On-line inspection will identify metal loss that may result as a consequence of CP shielding.

AC Corrosion Most codes and recommended practices related to CP monitoring and control should require interaction testing to be performed in stray current areas and appropriate action to be taken to mitigate the problem. On-line inspection or direct assessment in areas of coating damage will confirm the effectiveness of the action taken.

DC Influences When a cathodic protection system is sited near other buried neighbouring structures or services, corrosion may occur to one or other of these due to interference. DC current, applied to cathodically protect a pipeline can be picked up by these buried structures. Where this current is dissipated at coating defects, the structure may experience corrosion. DC current interference may also occur as a consequence of DC traction systems.


AC currents, most commonly induced onto buried structures by overhead power lines or traction systems, may result in AC corrosion. Although there appears to be no consensus concerning the mechanism of AC corrosion, it is reasoned that it is caused by the irreversibility of the corrosion reaction. The corrosion features that result are generally localised, hemi-spherical and crater like and have a smooth surface. AC corrosion rates can be as high as 2 mm/year. The requirement to routinely monitor AC voltage and current should be incorporated into the various codes and recommended practices. If a problem is found to exist, various means of mitigating this can be instigated. Metal loss due to AC corrosion will be detected through On-line inspection or direct assessment in areas of coating damage.


AC Corrosion

Microbially Induced Corrosion (MIC) Corrosion induced by the activity of bacteria, most generally in anaerobic environments, is characterised by large craters, striations running parallel to the longitudinal pipe axis, the presence of sulphate and sulphide compounds and a smell of hydrogen sulphide. MIC corrosion rates are reported to occur between 0.2 and 0.7 mm/year, and to develop preferentially in anaerobic, wet and boggy soils. External MIC has been reported on bitumen/asphalt coated pipelines and those coated with PE (tapes and HSSs) having bituminous-based mastics. Metal loss due to MIC will be detected through On-line inspection. Pipelines that are coated with asphalt/bitumen, and tapes or HSS’s employing bitumen-based adhesives will be at greatest risk.

Stress Corrosion Cracking (SCC) Stress corrosion cracking is a form of "environmentally assisted cracking" where the surrounding environment, the pipe material and stress act together to reduce the strength or load carrying capacity of a pipe. Two types of SCC are known and are referred to as high pH and near-neutral pH SCC. High pH SCC occurs in a relatively narrow cathodic potential range (-600 to -830 mV ref. Cu/CuSO4), in the presence of a carbonate/ bicarbonate environment and at a pH greater than 9. High pH SCC is typically experienced downstream of compressor stations (where the pipe temperature is elevated) and is associated with disbonded or damaged coatings. In the cathodic potential range and environment required for high pH SCC, a protective film forms on the metal surface. If the pipe is subjected to plastic strain, this protective film will crack and create the opportunity for SCC to occur. Stress corrosion

cracks will continue to grow only if the rate of plastic deformation occurs more quickly than the rate at which the protective film re-forms. High pH SCC occurs intergranularly. Although the mechanism of near neutral SCC is not fully understood, it is thought to involve metal dissolution and the ingress of hydrogen into the steel, the hydrogen facilitates crack growth by promoting reduced ductility in the steel. Cracks are probably initiated at corrosion pits on the steel surface containing a localised environment with a pH low enough to produce atomic hydrogen. The low pH solution is produced by dissolution of CO2 in the groundwater. Some of the atomic hydrogen enters the steel, degrading the mechanical properties locally so that cracks can initiate or grow. The plastic stress level necessary to produce cracking may not be related entirely to fracturing the embrittled steel. It may also contribute to rupturing the protective film, allowing hydrogen to reach and penetrate the steel. Near neutral SCC occurs primarily transgranularly. On-line inspection with tools employing ultrasonic or transverse magnetic flux leakage principles may be successful in detecting SCC. Lines should be targeted which have been protected with CTE, asphalt and tapes applied over mechanically cleaned surfaces.

GL has significant experience of all of the corrosion anomalies that can threaten the integrity of a pipeline system. GL has provided consultancy to a range of customers who have wished to confirm that a particular corrosion mechanism is occurring on their pipeline and how to mitigate/manage the problem.



b. Fitness for Service Assessments

Stress Analysis

GL consultants have extensive experience and knowledge in conducting comprehensive fitness for service assessments of pipelines using stress analysis techniques, defect assessment and fracture mechanics assessment methods. This capability has been applied in assessing a wide variety of different types of defects and damage types (including: arc strike, general and pitting corrosion, cracks and spalling, smooth and kinked dents, gouges, smooth dents plus cracks/spalling/gouges, and stress corrosion cracking), and can be tailored to provide damage assessment procedures in line with individual company requirements.

Fitness for Service can be demonstrated using higher level assessment methods such as FEA. GL can undertake work ranging from the stress analysis of individual structural components such as branch connections, hot tap tees, threaded well bore casing strings and damaged (corroded or dented) pipelines. GL consultants have the capabilities to undertake advanced non-linear, static/dynamic analysis, vibration, thermal and fatigue analyses. We use these capabilities to undertake fitness-for-service assessments of pressure systems and in conjunction with full scale testing facilities to develop defect assessment methods for pipelines. GL uses an extensive range of FE and associated software tools that are mounted on both SUN Unix network and PC based Windows system. The software tools we use include:

We have excellent knowledge of the UK Pressure Systems Safety Regulations, 2000 (PSSR) and relevant US Code of Federal Regulations (e.g. CFR 192 and 195). We also have a very good understanding of the capabilities of in-line inspection (ILI) tools, to interpret the results from inspections and to then undertake defect assessments. GL routinely undertakes assessments of damaged transmission pipelines for an international clientele of asset owners / operators worldwide. We have in-depth knowledge and experience in the use of industry recognised assessment methods such as: 


API 579




For any fitness for service assessment, information is required on the input parameters. These include:

ABAQUS (Standard and Explicit) FE analysis program

MSC/PATRAN and ABAQUS CAE FE pre-and post-processor programs

PC based software such as MathCad and MATLAB

In addition to the above, our consultants can write customised programs, user subroutines, etc. in order to overcome the limitations in proprietary software. Areas of expertise include: 

Linear and non-linear analysis. Where necessary, non-linear effects can be included in the analysis; this can be through the modelling of non-linear material behaviour, geometric non-linearity and contact

Buckling, postbuckling and collapse analysis of pipelines

Soil structure interaction

Steady state and transient heat transfer analysis

Original equipment design data

Fatigue and fracture mechanics; cracked body analysis

Operational and maintenance history

Design by analysis

Expected future service

Information specific to the assessment such as defect sizes, stress state, location of flaws, and material properties such as tensile strength and fracture toughness

Fitness for Service can then be demonstrated using methods such as stress analysis, defect assessment and fracture mechanics approaches. These are described as follows:

Windows is a trademark of MicrosoftTM corporation



Defect Assessment Defect assessment is a deterministic approach used to assess the integrity and fitness for service of defects found on pipelines. Defects are features which affect the structural integrity and may be located on the surface of the pipe wall or actually inside the material of the pipe. There are numerous codes that can be used to assess defects and are summarised in documents such as the Pipeline Defect Assessment Manual used for pipelines, which our consultants fully understand the best methods to use. We have in-depth knowledge and experience in the use of industry recognised assessment methods such as: 


API 579




Damage assessment capabilities include the following types of defects: i) Manufacturing Damage, Manufacturing features are often a discontinuity in the geometry of the pipe or shell such as a reduction in wall thickness or in the material itself.

ii) Construction Damage, Construction defects may include girth weld defects or seam weld defects caused by lack of fill or misalignment and in the most severe case cracking. Also, other forms of damage may occur such as indentation damage, corrosion at the girth weld, or even damage to the external coating.

iii)3rd Party Interference, 3rd party damage is often the most severe form of damage resulting in failure of the pipe or requiring immediate repair. Often this involves mechanical damage such as a gouge resulting in metal loss of the pipe wall, or distortion of the pipe wall such as a dent.

iv) Operational Damage. Defects arising from operational usage include external corrosion caused by damaged or disbonded coating where the Cathodic Protection System is not effective. Also internal corrosion caused by water in the product, and even other forms of corrosion namely ‘Sweet Corrosion’ and ‘Sour Corrosion’ may occur in pipelines.

Sources for defect data include pipeline intelligent inspection tools or other NDT methods. Using in-house expertise, appropriate assessment methods can then be chosen and applied to demonstrate fitness-for-service in order to satisfy regulatory requirements and operators’ integrity management strategy.

GL has developed methods for the assessment of corrosion defects in pipelines through a combination of finite element analysis and full scale burst testing. These methods have been included in guidance documents such as the British Standard BS7910. GL is continuing to develop methods for assessing the integrity of corroded pipelines for Pipeline Research Council International.



Fracture Mechanics BS7910 and similar codes such as the UK nuclear industry code R6 and API 579, carry out fracture assessments using the Failure Assessment Diagram (FAD). This provides a graphical method for assessing the proximity of a loaded structure containing a defect to failure by fracture and plastic collapse mechanisms. Proximity to fracture is characterised by the fracture ratio parameter Kr and proximity to plastic collapse is characterised by the parameter Lr. A loaded structure can therefore be represented as an assessment point on the FAD following calculation of Lr and Kr. This approach is used in levels 1 to 3 of BS7910 to determine the acceptability of cracks by plotting a point on the diagram. When deciding which level to use, this depends on the input data available and conservatism required. These levels can be summarised as: 

Level 1 is a simplified assessment method when there is limited data on material properties,

Level 2 is the normal assessment route, and

Level 3 is based on a ductile tearing resistance analysis.

Using the fracture mechanics approach, our consultants can determine whether a defect is SAFE or UNSAFE based on the Failure Assessment Diagram. Finally, using the fatigue assessment approaches described in BS7910, we can then determine the remaining fatigue life and future integrity of the structure if subjected to cyclic loading.



c. Geotechnics and Ground Movement

d. In-Line Inspection Services

The safe and adequate performance of pipelines and piping at installations under conditions of external loading is achieved by:

While there is rarely a standard method for work in this field, we would naturally begin by working with the customer to understand precisely what is required from a project. Then we would select the right specialists from our team of scientists and engineers, including people who have extensive long-term experience in the area of ILI and have worked on product development and exploitation for specialist ILI vendors.

Quantification of pipeline loads and supports by characterising the inherent variability in the geological environment to specified confidence levels.

Ensuring compliance with relevant codes and standards.

Fitness-for-purpose assessments that recognise limit states relevant to the applied loads with appropriate levels of safety.

Estimates of probabilities of failure and system reliability for uncontrolled geological hazards such as landslip events.

For any work that involves making use of ILI data that has already been collected we gather pipeline and inspection information. Where uncertainties exist in the data - for example, with regard to actual material properties (as distinct from material specifications) and inspection errors - these can be accounted for in a probabilistic limit state assessment using the techniques of structural reliability analysis. If there are questions about interpretation of ILI results (see Case Study n) then we would resolve these by examining recorded data, as available, to form an independent opinion on the interpretation.

Geotechnical Aspects Pipelines sustain loads from a range of sources covering engineering activities such as earthworks and other surface construction, tunnelling, transient live loads on road and rail networks and also construction and mining plant, and subsidence events due to mining for example. Natural hazards include landslides, earthquakes, natural subsidence, and erosion and exposure typically around water courses leading to spanning and potentially hydraulic loading. We have expertise to investigate and interpret all forms of ground loading and geological hazards, and quantify instability, movement and load transfer to pipeline structures.

Pipeline Integrity Aspects The performance of a pipeline depends on the imposed loads, ground support and the pipeline structural response. We deal with this by identifying and quantifying ground loading processes, soil/pipe interactions and pipeline performance capabilities. Pipeline integrity is assessed through well-established principles including ground investigations, material testing, structural calculations using pipe stress analysis software and pipeline monitoring. The results of integrity assessments are evaluated based on relevant performance limits. The findings may warrant monitoring, protection, or replacement works. We have experience in the specification, installation, data collection and interpretation for indirect and direct methods of monitoring. Satisfactory monitoring of pipeline performance is typically achieved by a combination of the measurement of existing stress levels, recording changes in pipeline strains and geotechnical instrumentation or topographic surveying as appropriate.



e. Integrity Management System Audits In general an audit or review of a Pipeline Integrity Management System will begin with a Gap Analysis. This entails a thorough review of the Operator’s activities, including the following: 

Compliance with requirements

Integrity threats and mitigations in place -




Generally in such a project there will be a Phase 2 which comprises gap closure actions. Depending on the results from the gap analysis this might entail a complete overhaul of an Operator’s Engineering Documentation System or it may involve some rationalisation and repackaging to ensure that the PIMS is clear and coherent.

Onshore – mechanical damage, corrosion, ground movement etc Offshore – mechanical damage, stress/fatigue type material failures, internal and external corrosion etc

Quantitative risk assessments undertaken

Engineering documentation

Pipeline records and fault data

Quality, health, safety and environmental issues

Pipeline operations and maintenance -


The Pipeline Integrity Management System under review can then be assessed for compliance with prevailing regulations and compared to international “best practice”. Recommendations can be made to the Operator as to how they can improve their processes and systems.

Work scheduling Record keeping Routine and non routine activities Pipeline cleaning Typical Onshore Pipeline Damage/Failure Data

Internal pipeline inspection - ILI

External pipeline inspection -


Onshore - above groundsurveys etc Offshore - ROV surveys etc

Modification and repair process

Emergency management

Defect assessment and repair methods

Training and competency of staff

Safe control of operations

Continuous improvement processes in place


f. Investigation of Pipeline Incidents

g. TD/1 Surveys (Affirmation of MOP for Onshore Pipelines)

The majority of incidents on pipelines usually involve some form of mechanical damage being caused to the outside of the pipe surface. In some cases, corrosion may also be the cause of a pipeline failure. In both scenarios, if the damage or corrosion is extensive, this may cause the process fluid to escape.

A full survey of the pipeline route must be carried out in order to determine the extent of developments. This can be undertaken by a line walk or by means of aerial photography or video. Measurement of population density is based on this survey and the method of calculating this is described in IGE/TD/1.

Incidents involving surface damage to the pipeline where no process fluid has escaped are usually easier to investigate and assess. Typically, this type of assessment involves using a range of mechanical measuring systems to ‘map out’ the damaged area, non destructive testing examinations such as ultrasonics, magnetic particle inspection and/or dye penetrants to detect for defects and cracking in the damaged area, a photographic survey and if required, cuttings of the pipe material are taken for analysis to confirm the grade of pipe material. At the end of the onsite investigation, GL will produce a technical report on the findings from the onsite inspections and will make a number of recommendations to enable the pipeline to be put back into service.

Infringements from changes in proximities, population density or traffic density identified from the survey should be evaluated as soon as possible by means of a quantitative risk assessment (QRA). Any measures identified by the QRA which are viewed as “reasonably practicable” in reducing the risk should subsequently be implemented.

If the damage or corrosion has caused a through wall hole and process fluid has escaped, then the operator will usually have to shutdown the pipeline and fit an emergency wraparound clamp to contain the leak. GL have been involved in a number of these types of incidents and provided support to the client that required a number of GL consultant engineers covering a range of disciplines to produce a solution. In the majority of cases, through wall leaks have been repaired using a specially fabricated wraparound fitting, called an epoxy repair sleeve. No welding is required with this type of fitting and can be fitted in approximately half the time and at a fraction of the cost when compared to a welded fitting.

In addition to the proximity review the following issues are also subject to review: Materials & fittings Road crossings Valve maintenance Hydrostatic testing Rail crossings Ground movement Annual & 5 year MOP records Watercourse crossings Pipeline damage history Fatigue life Exposed crossings Pipeline leakage history Weld quality Other crossings Actual pipe details

Town gas service (manufactured & reformed) Sleeves Environmental issues Depth of cover Impact protection Records Building proximity distances Cathodic protection Abandoned sections Population density (type R&S areas) Condition monitoring Offtakes & spurlines LA planning proposals

In addition to all of the above items, pipeline strip maps, photographs, pressure system drawings and other relevant data are used to produce a Fitness for Purpose Report of the pipeline under review. This report will recommend a suitable Maximum Operating Pressure for the pipeline. The report will include areas of non compliance where remedial work is required before the MOP can be applied.



h. Pipeline Uprating The general approach is: 

Collation of all relevant design, construction and operation data for the pipeline

Assessment of the pipeline at the proposed up-rated pressure in accordance with the up-rating recommendations contained in the pipeline operating code. Where major design non-compliance is identified, then a detailed fitness-for-purpose assessment is carried out to determine whether it is acceptable or not


Where a pipeline infringes surrounding infrastructure then established risk analysis techniques are used to assess both individual and societal risks. Where the risks are demonstrated to be clearly within the pipeline operator’s acceptance criteria, then they are deemed acceptable

In all cases where the pipeline design factor at an infringement exceed 0.72 then potential risk reduction measures are considered and the safety benefits are evaluated in accordance with the As Low As Reasonably Practical (ALARP) principle

All required modifications are identified and then required detail designs are prepared and the modifications are implemented

The pipeline is revalidated using in-line inspection techniques and all necessary repairs are then identified and implemented

Following satisfactory completion of modifications and repairs, the pipeline pressure is raised to the up-rated Maximum Allowable Operating Pressure (MAOP)


i. Welding Technology Services

j. Grouted Tee

GL staff have been involved, in many cases, in the development and qualification testing of procedures and consumables for the construction of pipelines, process plant and ancillary high pressure equipment. GL carries out weldability studies on all candidate linepipe and components used in the UK National Grid Transmission system in accordance with the requirements of National Grid specification T/SP/MPQ/1. For line pipe this involves the production of a full scale girth weld under simulated field conditions, to an approved procedure and including such factors as lifting and manipulation to simulate movement of the line-up clamps following deposition of the hot pass.

The Grouted Tee involves placing two half shells around the pipe and bolting them together. The shells, with a specified wall thickness, have a similar material grade to the parent pipe. The shells are sized to allow a generous gap between the bore of the shells and the outside diameter of the parent pipe. This annular gap is filled with grout, when cured this transfers additional structural loading in the pipe to the tee shell.

Additionally repair special procedures are tested and qualified before being putting into service. Welding consultancy services are also required when new or difficult materials are involved, such as those employed for high temperature or sour service environments and include materials such as Inconel, duplex stainless steels or linepipe clad with these materials. In these cases very specific welding procedure specifications are drawn up and initial production welding is carried out under the supervision of GL expert staff.

Pressure containment is achieved via the "saddle" seal, which is positioned next to the opening of the main pipe. The sealing specification is unusual and demanding. The primary function accommodates large variations in the annular gap between pipe and shell. It also has to cope with a grit blasted surface preparation, which is equivalent to SIS 05-59-00 Sa 2.5 finish. It also needs to withstand elevated temperatures during the drilling operation. Moreover, the saddle seal has been designed to be independent of the quality of the grout and on its own should maintain the integrity of the pressure containment.

GL also carries out welding prequalification of high pressure components produced by new suppliers, and an investigation of the welding procedures and consumables employed by candidate companies is an integral part of this. Site visits are carried out and supervision of component production ensures that they meet the relevant requirements for specific companies and individual projects and can be welded into the system without problems. GL also supplies expert assistance in the selection and application of methods for weld repair of pipelines, process plant and high pressure equipment. This is supplemented by expertise in inspection which ensures that defective areas are professionally repaired and returned to service in fully reliable condition.



k. Internal Corrosion Management GL’s approach to corrosion management is to consider the fluids, materials and safety aspects as an integrated whole. In most respects the transported fluids dictate the materials and corrosion control methods used for pipelines while occasionally the materials technology available will shape the feasible transportation options. Ultimately the objective is to produce a pipeline with an acceptable risk of failure. Thus, all these aspects have to be addressed when considering internal corrosion management. The production of a corrosion management system would generally involve the following stages: 1. Gather process data e.g. temperatures, pressures and fluid compositions during both normal operation and upset conditions 2. Consider the pipeline safety risk assessment in order to:  

Identify major hazards Identify HAZOP actions related to corrosion and materials Determine acceptable level of risk

3. Conduct corrosion risk assessment including:   

Calculation of internal corrosion rates Assessment of stress corrosion cracking threat Assessment of erosion threat

4. Produce corrosion management scheme 


Select materials (corrosion resistant alloys or carbon steel with corrosion allowance) Select corrosion control methods (e.g. inhibition, coatings) Select corrosion monitoring methods and locations Produce corrosion data management strategy and select tools Devise suitable key performance indicators (KPI) for corrosion management Document change procedure for revising scheme if process parameters are altered (e.g. after uprating) Produce pipeline corrosion management guide/manual

5. Feed back the corrosion management activities into the pipeline safety case and risk assessment as mitigating factors Corrosion inhibitor selection is an important aspect of internal corrosion management for pipelines. The figure below shows the work flow commonly used when GL undertakes inhibitor selection for pipelines:



a. Investigation of AC Interference Problem on High Pressure Pipeline

b. Guidance on SCC Risks on a Pipeline Operators Network

Date: Customer: Savings:

Date: Customer: Savings:

2003 Shell UK Ltd Prevention of pipeline rupture

2006 Major Pipeline Operating Company Preventing pipeline rupture due to SCC



The client had experienced up to 40% loss in pipe wall thickness on a high pressure ethylene pipeline within 3 – 4 years of commissioning. It was initially thought that the metal loss was due to microbially influenced corrosion (MIC).

The client requested GL to review the mechanisms by which near neutral and high pH SCC occur on pipelines and to prepare procedures for management of SCC risk.

Methodology & Results: Methodology and Results: The pipeline was coated with a fusion bonded epoxy mainline coating, which does not support the proliferation of bacteria required for MIC to occur. The pipeline was observed to be running in parallel with a high voltage power line for distances in excess of 1 km and high AC potentials and current densities were recorded on the line. Features specific to AC corrosion were noted during direct examination including: 

Hardening of the soil adjacent to corrosion features

Smooth, hemispherical metal loss features

Significant build up of calcite salts within corrosion feature

Stress corrosion cracking is a form of "environmentally assisted cracking" where the surrounding environment, the pipe material and stress act together to reduce the strength or load carrying capacity of a pipe. Two types of SCC are known and are referred to as high pH and near-neutral pH SCC. GL reviewed the mechanisms by which SCC occur on a pipeline and assessed the probability of near neutral and high pH SCC initiating on the client’s pipeline network. Where a risk was perceived to be present, guidance was produced on the actual risk SCC poses to a pipeline’s integrity, the timeframe in which remedial action would need be taken, the conditions under which pipelines could remain in service, the methods of establishing the extent of SCC and how the SCC risk could be managed and controlled in the future.

Savings: Confirmation of the corrosion mechanism, which was occurring at a rate of 1.3mm/year allowed more regular ILI to be scheduled and mitigating action to be taken.


The work allowed the client to identify and target areas at highest risk by better understanding the factors that contribute to SCC. The procedures developed by GL have allowed the client to modify conditions thereby minimising risk and maximising the timeframe in which remedial action can be undertaken.

Confirmation of the corrosion mechanism allowed a pipeline rupture to be avoided along with the associated loss of gas and supply to the customer.



c. Coating and Backfill Interaction

Date: Customer: Savings:

2006 BP Exploration and Operating Company Limited Eliminating the requirement for selective padding

Issue: The client was constructing a pipeline in a remote, environmentally sensitive region of the World, where the importation of selective material for bedding and padding of the pipeline was not practicable. As a consequence, the only means of providing suitable bedding and padding material was to process indigenous spoil, on site, by a method of crushing and screening. The number of crushing and screening units required to would have a major impact on construction costs. The aim of this project was to identify the maximum particle size of bedding and padding that could be accommodated during backfilling, commissioning and service.

Methodology and Results: Pipeline construction often involves the importation of significant amounts of selective backfill to prevent mechanical damage of the external coating during construction and operation. Importation of backfill is extremely expensive, may be impractical in the more remote regions of the world and may present problems in environmentally sensitive areas. By understanding the links between geotechnical ground analysis, trench excavation equipment and performance and backfill materials, it was possible to identify appropriate external pipe coatings for particular ground conditions. In addition, it was also possible to reduce the amount of imported backfill or the processing requirements to match the mechanical resistance of the coating. The data generated during this project enabled an algorithm/decision making chart to be developed which allowed the operator to compare pipeline coating/backfill options based on technical and financial considerations.

Savings: This work resulted in a significant reduction in construction costs by minimising the number of crushing and screening units required on site. There was also a significant reduction in the environmental impact of having to import selective bedding and padding materials onto site.




d. CP Decision Support Tool

e. Dent Assessment on a 30” Oil Pipeline

Date: Customer: Savings:

Date: Customer: Savings:

2008 Major Pipeline Operating Company Compliance with the regulatory authority

2007 Middle East Operator Savings were made due to potential loss of containment and system shutdown



The client operated a number of pipelines that did not comply with the minimum criteria for CP. The regulatory authority was aware of the problem and placed a requirement on the client to demonstrate how they were going to prioritise pipelines for remedial action.

A major Middle Eastern Operator had requested GL to undertake an initial assessment of the integrity of a 30” diameter subsea main oil pipeline, which had sustained dent damage. The operator had indicated that several in-line inspection tools had been damaged due to the restriction in the pipe cross section. The dent was located on the top of the pipe, and in close proximity to the seam weld. The operator therefore provided GL with a damage survey report which included a map of the dent shape, identification of the peak dent depth, and results of a visual inspection and magnetic particle inspection of the damage area on the outer pipe surface.

Methodology & Results: GL developed a software programme to allow the prioritisation of non-compliant pipelines/pipeline sections, based on the integrity threat that being under protected posed. The programme utilised information that was readily available from the original pipeline design data, from coating and CP surveys, from in-line inspections and from adhoc exploratory excavations on the pipeline. The algorithms used within the programme considered the likely failure mode (rupture or leak) that might result from being unprotected, the timescale in which failure might occur (based on the date when CP was first lost, the pipe wall thickness and the likely corrosion rate) and safely and economic considerations. The output of the programme was a priority ranking and a timescale for remedial action.

Savings: The CP decision support tool was accepted by the regulatory authority as a transparent means of prioritising remedial action, thereby preventing improvement notices being issued to the operator. Development of the tool kick started the process of revalidating non-compliant pipelines.

Methodology & Results: The purpose of the work was to provide the operator with an ‘initial assessment’ of the severity of the dent damage in relation to the ability of the pipeline to operate at its original design capacity and continue to be inspected using in-line inspection tools. Assessment was undertaken based on the guidance given in the Pipeline Defect Assessment Manual (PDAM) and background documentation to PDAM. Using information taken from full scale burst and fatigue test data from vessels and ring specimens in PDAM, the data showed that both the static strength and fatigue performance of a pipe with a dented weld could be significantly reduced. With the information available and the uncertainty surrounding the quality of the material (pipe and weld) and the possibility of additional welding defects and damage associated with the inspection tool, the recommendation was that the damage should be repaired or replaced.

Savings: Following recommendations for repair and the implications of any future pressure increases, savings were made due to potential loss of containment and system shutdown.



f. Advances in Interaction Rules for Corrosion Defects in Pipelines Using FE Analysis and Full Scale Testing Date: Customer: Savings:

2007 PRCI Considerably improving the accuracy of pipeline defect assessment and thereby helping to reduce operating costs for pipeline operators by improving repair criteria.


Methodology & Results:

There still remain a number of limitations in the existing methods for assessing corrosion damage in pipelines (ASME B31.G, RSTRENG, API579, BS7910). GL has been undertaking a large programme of work on behalf of Pipeline Research Council International, Inc. (PRCI) to develop methods for:

GL recently undertook a comprehensive review on behalf of Pipeline Research Council International, Inc. (PRCI) of the existing and emerging methods for assessing corroded pipelines. This review identified that the existing criteria used by the pipeline industry to assess interaction of metal loss defects is based on limited experimental data and has not been adequately validated. Existing practice within the pipeline industry is to assume that defect clusters interact when they are spaced six wall thicknesses (6t) from each other. The development of new criteria for defect grouping and interaction would considerably improve the accuracy of pipeline defect assessment and thereby help to reduce operating costs for pipeline operators. GL undertook a comprehensive non-linear FE study and full scale burst testing program to develop new guidance for interaction of metal loss defects in pipelines. It was concluded from this work that the 6t criterion used at present can be over conservative, particularly when assessing interaction of small pit like corrosion defects. The output of this work will be included in a defect assessment guidance document for the pipeline industry.

Assessing interaction of corrosion defects

Assessing corrosion defects in pipelines of low toughness

Assessing pipelines subject to significant external loading

Assessing corroded pipelines subject to cyclic loading

Extending assessment methods for pipelines constructed from higher strength steels

Corrosion metal loss is one of the major damage mechanisms in oil and gas transmission pipelines. The pipeline industry widely uses the ASME B31G and the RSTRENG methods for assessing the remaining strength of corroded pipelines. These methods were developed using an early fracture mechanics relationship for the toughness- independent failure of pressurised pipes and were empirically calibrated against a database of around 80 full-scale burst tests for thin wall pipes, dominated by pipes of material grades B and X52.

Non-Linear Finite Element Models of Pipelines with Corrosion Damage

Savings: Savings were made due to improvements in the accuracy of pipeline defect assessment, which thereby helps to reduce operating costs for pipeline operators through significant improvements in repair criteria.



g. Fracture Mechanics Assessment of a Defective Pig Trap

Date: Customer: Savings:

2007 United Utilities Cost of temporary pig trap and system downtime due to installation

Issue: GL were required to conduct a detailed assessment of a reported crack indication found on the closure casting of a pig trap located at an AGI facility in the UK. Following defect measurement in February 2007, this was recorded at approximately 3-4 mm. A number of pig runs were then subsequently conducted. The defect was then re-measured and reported to have a maximum depth of 5.3 mm. Measurements suggested that the defect had therefore grown since the pigging runs were conducted in 2007. The operator of the site facility intended to conduct further pig runs in February 2008 and hence required an assessment to determine whether the defect was safe for the intended pig runs.

Methodology & Results: The approach that GL used was based on a BS7910 level 2a fracture mechanics assessment. Using fracture mechanics calculations and use of the FAD (Failure Assessment Diagram), the aim was to determine whether the current size of crack was safe under the current design conditions and safe for the intended pig runs. Finally using a BS7910 fatigue assessment of the crack, fatigue calculations were then conducted to determine the remaining fatigue life of the reported defect and whether further pressure cycles can be tolerated due to the intended pig runs. The fatigue assessment results showed that the defective area was likely to endure a large number of cycles before failure. Consequently it was concluded that the defect would endure sufficient further pressure cycles to conduct the intended pigging runs.

Savings: Ultimately the operator would have had to install a temporary pig trap to conduct the required pigging runs. Following this, the temporary trap would have been removed and a new trap installed in its place resulting in costly delays and system downtime. By conducting a fracture mechanics assessment, GL have saved the client costs associated with installing a temporary pig, inspection delays and system downtime.



h. Fatigue Assessment of Dented Pipeline Date: Customer: Savings:

2006 UK Operator The fatigue assessment confirmed the remaining fatigue life of the reported dents, pending confirmation that no further defects were present, was acceptable for the design life of the pipeline.

Issue: The UK operator had requested GL to undertake a fatigue assessment of two ‘smooth dents’ found on one of their pipelines. The dents were inspected during a calliper survey undertaken by T D Williamson, and were reported as being no greater than 3% of the pipe diameter in depth. The dents were originally discovered in 1995 and the operator suspected they had been there since pipeline commissioning.

Methodology and Results: The assessment method used was developed by GL and is recommended for Industry use by EPRG. The results from the assessment were also supported by a series of full-scale fatigue tests on dented linepipe undertaken for National Grid. Fatigue life of the pipeline dents, initially assuming an unconstrained plain dent was then calculated using the method recommended for use by the EPRG. Results of the assessment showed that for smooth and defect free dents, the fatigue life was in excess of the design life of the pipeline. However, recommendations were made to confirm that no additional defects were present such as internal or external surface cracking.

Savings: This fatigue assessment confirmed the remaining fatigue life of the reported dents, pending confirmation that no further defects were present, was acceptable for the design life of the pipeline. The result was that savings were made by the operator through unnecessary repairs.



i. Metallic Gas and Water Mains Affected by Ground Movement Date: Customer: Savings:

2007 UK Gas and Water Distribution Company Specification of pipeline protection

Issue: A new high speed rail link in the UK involved the construction of approximately 19km of twin bore tunnel below east London. The civil engineering work took place in the vicinity of a network of utility services. A total of 261 metallic gas and water distribution mains require an integrity assessment due to the potential ground movement from the tunnel construction. Of these mains units there were approximately 73 that cross existing bridge structures located within the influence zone above the tunnel. If overstressing due to the tunnelling occurred, diversion or protection of the mains would be required.

Methodology & Results: The work has involved the selection of geometric and material parameters for mains units, the selection of dimension and level values for individual bridge structures and tunnelling geometries, the calculation of ground and structure movements, the structural analysis of mains response to loading and restraints, and the checking of calculated stress increments and joint disturbance levels against acceptance limits.

Schematic showing pipeline level, bridge dimensions and tunnel details

Soil load transfer assumptions were considered over a range in order to embrace the uncertainty over actual ground conditions around the mains unit. This permits the sensitivity of piping response to be quantified and reduced uncertainty.

Benefits: Many of the mains had demonstrated that overstressing due to the tunnelling is very unlikely to occur, therefore can be left in place and avoid expensive diversion or unnecessary protection.

PIPELINE model for a cast iron main crosses a bridge structure showing applied ground movements due to twin tunnel



j. Pipeline Affected by Collapse of Quarry Face

Date: Customer: Savings:

2006 UK Gas Transmission Company Improved pipeline integrity



An 18” steel pipeline located on the boundary of a sand and gravel pit became exposed by the collapse of a quarry face. The pipeline was constructed prior to the requirement for 100% inspection of girth welds and therefore could be at risk of tensile fracture when subjected to increased longitudinal tensile stresses. The operator required an investigation into the nature of the loading on the pipeline and the identification of measures to maintain the pipeline integrity.

Rapid reaction to a site incident averted the development of a potentially dangerous leak failure. A coordinated investigation and remediation exercise confirmed the condition of the pipeline and enabled appropriate remedial measures to be taken to ensure the pipeline operated within safe limits.

Methodology & Results: Immediate action was taken to stabilise the slope by designing and constructing a buttress embankment against the quarry face. Excavations onto the pipeline indicated the presence of voids and lateral and vertical deflections consistent with failure of the quarry face. Pipeline profile measurements were carried out to establish the stress state and welds were inspected and repaired where necessary. The pipeline curvatures indicated yield magnitude stresses had developed. A de-stressing operation was undertaken involving uncovering and lifting the pipeline to reduce the pipeline stresses and restore the as-laid profile. The stress relief was closely monitored by fitting strain gauges to the pipeline and these demonstrated that the ground movement loads were successfully reduced. Detailed reinstatement guidance was specified in order to provide sufficient support to the pipeline in the new position.

A section of pipe being supported by airbags to relieve soil loading A section of the exposed pipeline, showing the horizontal bending



k. Deep Basement Construction – Large Diameter Cast Iron Gas Main Affected by Ground Movement Date: Customer: Savings:

2006 UK Gas Distribution Company Appropriate pipeline protection

Issue: A hotel development in Central London involved the construction of a 12-storey block with four basement levels. The basement construction involved excavation to a depth of 20m and the installation of a segmental diaphragm wall of 33 panels with total width of 44m and up to 29m below ground level. Two large diameter cast iron low pressure gas distribution mains are within the site boundary and the closest gas main is only 4m from the diaphragm wall. Ground movement and surface loading associated with the hotel construction may cause some disturbance to the gas mains. This level of disturbance need to be assessed in order to confirm that the gas mains would continue to operate within safe limits.

Surface corrosion of the 24” Gas Main

Methodology & Results: As part of the integrity evaluation, a condition assessment on the two mains was carried out. Two trial pits were excavated on site to establish the exact location of the mains, to obtain samples of the pipe backfill materials for laboratory testing, and to carry out a condition and support assessment on the mains. Although the mains were laid circa 1880 and corroded externally, they were still in an acceptable condition. Their remaining metal thickness was never less than 75% of the British Standard manufacturing minimum thickness value. The structural analysis has been performed using GL in-house pipeline stress analysis programs PIPELINE and SURFLOAD. Both short term and long term ground movement from the basement excavation, together with construction traffic loading have been considered. The integrity assessment shows that ground movements caused by the basement construction raised the stress level in the mains and caused the joints to articulate. Stress levels in the mains were also increased due to the effects of construction traffic. However, the amounts were within acceptance limits.

24” Gas Main

36” Gas Main

Benefits: The integrity assessment shows that, with appropriate temporary protection at the ground surface, the gas mains can be operated safely during and after the basement construction. This resulted in significant cost saving in unnecessary protective measures and possible diversion.



l. Effect of Slope Instability on High Pressure Pipeline

Date: Customer: Savings:

2006 UK gas Transmission Company Improved pipeline monitoring

Issue: A 24” diameter pipeline is known to be routed through an area prone to natural slope instability in West Yorkshire. Two slope failures have affected the pipeline in recent years resulting in two phases of pipeline construction to avoid active areas of movement. The operator required a fitness-for-purpose assessment of the current pipeline configuration to determine whether it has adequate performance for potential future slope failures.

Aerial photograph showing the pipeline route, the region of landslip and the surrounding area


The pipe shown in this photograph sprang out of line when cut

Methodology & Results: The slope was examined to identify landslip dimensions and movements that would represent design ground movement levels for the fitness-for-purpose assessment. In addition to confirming the pipe had adequate strength and toughness, curved wide plate testing was commissioned to determine the strain capacity of field girth welds. Performance limits were selected based on tensile strain capacity, axial buckling due to overload and lateral buckling due to the maximum movement capacity. The structural analysis considered the beam and ring performance of the pipeline subject to a range of landslide geometries and used thermal strain measurements to guide the selection of appropriate longitudinal fixity conditions. The structural calculations of the pipeline behaviour from slope instability identified that the critical performance limit was buckling from movement overload. The level of slope movement was identified to exceed 2m and the development is progressive allowing sufficient time for intervention activities to take place.


The assessment identified that, with appropriate monitoring and surveillance activities, the pipeline is fit-for-purpose. The outcome of the work avoided the need for costly upgrading or diversion work and the need for widespread slope stabilisation measures.


m. In-Line Inspection Vehicle Development

n. In-Line Inspection Data Analysis

Date: Customer: Savings:

Date: Customer: Savings:

2007 China Pipeline Operator Improved inspection

A team of consultants worked with the China Petroleum Pipeline Inspection Technologies company to design and build a new high-resolution magnetic flux leakage (MFL) ILI system. This project started from a ‘blank sheet of paper’ with the aim of delivering a state-of the-art inspection system having outstanding performance for inspection range, maximum pipeline flow speed, detection sensitivity and defect discrimination. Work covered all aspects of hardware and software, including development and coding of algorithms for automated data analysis. Following an intensive two-year programme of work, which included substantial periods spent in China with the customer and their local contractors, the new ILI system was shown in trials in live gas transmission pipelines to meet all of its specified requirements.

2007 China Pipeline Operator Avoidance of excavations

An operator had conducted two ILI operations on the same pipeline segment; one inspection used a calliper tool to identify denting while the other was conducted using high-resolution MFL for metal loss detection. The calliper inspection reported a number of dents, including two of sufficient magnitude to require excavation and repair according to the operator’s standards. However, the locations of these two dents were such that excavations would have been extremely disruptive and expensive. GL were approached by the operator to give an opinion on whether the relevant calliper signals were, in fact, due to dents. GL specialists examined both the low-resolution (single channel) calliper record and flux signals from the MFL tool. Having performed a careful correlation of the two records it was possible to conclude that the two ‘dent’ responses were actually caused by (a) a protruding weldolet fitting and (b) bore reduction at an unusually heavy-walled forged bend. The operator was thus able to avoid digging at either ‘dent’ location.



o. In-Line Inspection Scheduling

p. Review of Operations and Maintenance Practice

Date: Customer: Savings:

Date: Customer: Savings:

2007 China Pipeline Operator Optimised inspection schedule

A major operator of high pressure pipelines required a method for scheduling ILI that would maintain consistent reliability with respect to the corrosion threat. GL applied their expertise in the field of structural reliability analysis to take information from the most recent in-line inspection and model the development of reported metal loss over time, allowing absolute failure probabilities to be calculated for any time after the inspection. Our approach to this problem uses statistical and probabilistic techniques to represent uncertainties in pipe dimensions and material properties, defect dimensions and corrosion growth rates. GL proprietary software then applies these uncertainties with appropriate limit state functions to quantify the time-dependent likelihood of failure for an ILI segment. Thus, the date of next inspection can be chosen so as to keep this failure probability below any required threshold.


2006 Middle East Pipeline Operator Pipeline integrity management strategy

A gas transmission company were operating a small network in the UAE. As part of a major growth strategy they were constructing a new gas import pipeline and taking over responsibility for part of an existing gas network. The operator contracted GL to undertake a study of their current Operations and Maintenance practices as well as those in use for the network they were about to take over. GL undertook a gap analysis and compared the findings against best practice used by other world class operators. The next step was to consolidate practices, processes and documentation from the existing and new networks into a coherent Pipeline Integrity Management Strategy. The gap closure actions entailed the production of a complete Engineering Documentation System to allow the successful adoption and integration of the new network into the existing company asset base. The PIMS was designed so that it can be readily adapted and updated as required in the future.


q. China Joint Venture LNG Pipeline

r. Investigation of Pipeline Incidents

Date: Customer: Savings:

Date: Customer: Savings:

2006 International Pipeline Operator Developed pipeline integrity strategy

A major oil and gas pipeline operator is working in partnership with a locally owned enterprise in China to export gas through a transmission pipeline from an LNG receiving terminal. GL was contracted by the oil major to undertake a review of the Pipeline Integrity Management System in place to see that it was adequate. The review covered the following issues: 

Management strategy

Pipelines operations and maintenance management

Emergency management

Data management

Engineering documentation

Ongoing UK Gas Supplier Incident report compliance

Over the past 12 years, GL have been contracted to a major UK gas supplier to provide an incident consultancy service for both their high pressure and low pressure gas distribution systems. Various incidents have occurred over the intervening years and have involved both pipeline corrosion and mechanical damage to the pipeline. The incidents have ranged from minor to severe, but have all been dealt with quickly and efficiently by GL’s team of specialist incident consultants. GL have also performed a number of investigations involving incidents on process plant. This area of work whilst smaller than pipeline incidents is growing in size. GL have investigated process plant incidents both the within UK and abroad for a number of major energy companies.

Following an in-country visit to gather information and interview operational staff, GL subsequently prepared a report and a presentation for the joint venture company management. This provided a PIMS strategy and process diagrams to provide the client with a road map towards achieving best practice.



s. T/D1 Surveys

t. Pipeline Uprating

Date: Customer: Savings:

Date: Customer: Savings:

2007 - 2011 National Grid Re-affirms M.O.P

2004 Transco Avoids new construction

GL have recently commenced a contract to survey approx 50 pipeline sections per year over a 4 year period for the largest gas pipeline operator in the UK (approx 12,000km in total). GL were well placed to win this work having extensive previous experience of delivering this service in various parts of the UK, including East Anglia, North London, Wales and West, South of England and Scotland. GL also developed the Maintenance Procedure (T/PM/MAINT/5) upon which the detailed aspects of the survey are based.

Transco successfully uprated >1000km of pipeline utilising systems and methods developed by GL

GL worked with Transco in developing the systems and methods

GL has incorporated previous learning points within current methodology

The TD/1 resurvey begins with the existing TD/1 Report (undertaken 4 years previously). A data gathering phase reviewing all the items listed above then commences. A major aspect of this is pipeline faults, modifications and repairs experienced in the intervening period. In parallel with this an infrastructure survey will commence using aerial photographs. A close comparison is carried out between the new photographs and those from the previous survey. From this, new developments and potential encroachments are identified. These are later confirmed via on site surveys. Any changes to area type (e.g. type R area becoming type S) can then be assessed. If necessary pipeline Quantitative Risk Assessments can also be undertaken.

GL, as principal contractor, has successfully uprated 375km of pipeline for Transco when GL executed all works from feasibility study, through assessment and site remedials, to pressure-raise

GL has worked via other principle contractors to provide complete uprate safety justifications for Transco

GL offer modular up-rating work packages that cover an entire project or any discreet part thereof

The final deliverable for the client is a TD/1 Report in line with IGE/TD/1 and T/PM/MAINT/5. This report gives the client the information they require to allow them to re-affirm the Maximum Operating Pressure for the pipeline section in question for the next 4 years.



u. Design and Qualification of Repair Procedures for Bellows Attachment Welding Date: Customer: Savings:

2008 Pipeline Operator Improved welding procedure

A GL report on the bellows connection concluded that the bellows on the pipeline required a weld repair to be undertaken on the cracked fillet welds. The bellows configuration is shown in Figure A of that report, reproduced below:

Proposed weld procedure for the repair. Qualification of this procedure is in progress. Weld Repair instructions:

Consequently, according to British Standard BS 6990, prior to welding onto the live pipeline, it is necessary to qualify a procedure, simulating the cooling effect of the gas which complicates the qualification. The qualification set-up should simulate actual flow conditions. The weld procedure (below) has been developed to minimise the risk of lamellar tearing. For weld procedure qualification, plate material representing the nearest equivalent currently available material is used.

Weld repairs to cracked fillet welds in bellows unit to be carried out after qualification of the attached weld repair procedure and following decommissioning and purging of pipeline 2.

Ensure all necessary risk assessments and safety checks have been undertaken and procedures are followed, including safe control of operations (non routine operation) and entry into confined spaces.

Prior to repair, determine chemical analysis of carrier pipe and box material by on-site material sampling of the carrier pipe and restraining box material in accordance with T/PM/Q/10 (ref clause 12 and appendix B). Report results to GL for assessment.

Remove the two fillet weld cracks in bellows 2 by grinding in accordance with T/PM/P/11 appendix F.

Confirm defect removal by visual inspection and MPI.

Check carrier pipe for defects by UT & MPI below intended area of weld repair prior to welding.

Perform weld repair in accordance with attached procedure: WPS/A/Tinsley/01FR (subject to qualification).

Completed repair welds to be subjected to visual inspection and MPI.

Cracking located in bellows attachment fillet welds.



v. Grouted Tee

Date: Customer: Savings:

Ongoing Various Avoids welding and pipeline decommissioning

National Grid – Transmission – Above 7 bar

National Grid – Distribution – below 7 bar

BP (Forties 36” pipeline) – Approved for high spiked crude oil application

Tullow Oil – Class 600 – 56 bar

Ineos Chlor – (Runcorn former ICI plant)

Laing – Above 55 bar system

Murphy – below 7 bar

BG International – thin wall applications

Comgas (Sao Paulo, Brazil) CLASS 600 – 17 & 35 bar ring mains.

Phoenix Natural Gas (Belfast, N Ireland) – (1 operation One Grouted Tee installation)

Edison Welding Institute (Columbus, USA) – Stainless Steel and Titanium flow lines

36” x 36” - Feeder 7 - July 2003



National Grid - Marsworth Pressure Reduction Date of Installation: Pipeline Diameter: Pipeline Material: Pipeline Wall Thickness: Operating Pressure: Size of Tee installed:

Installation of 4 high pressure double branch Grouted Tee fittings for flow isolation, stopple operation. o 4 bypass connections October 2004 12” Steel (API 5L Grade X42) 7.9 mm 34.5 bar 12” Equal Tee (Class 300) – Double branch

Date of Installation: Pipeline Diameter: Pipeline Material: Pipeline Wall Thickness: Operating Pressure: Size of Tee installed:

Two Grouted Tees were installed, one either side of an existing block valve. The installations were used to create a full-bore bypass around the block valve. October 2003 20” Steel (API 5L Grade X65) 4.5 mm 31 bar 20” Equal Tee (Class 300)

Bishop Auckland Test Loop

Controlled pipeline loop at GL’s test facility at Bishop Auckland

Date of Installation: Pipeline Diameter: Pipeline Material: Pipeline Wall Thickness: Operating Pressure: Size of Tee installed:

October 2000 24” Steel (API 5L Grade X52) 12.5 mm 58 bar 24” Equal Tee (Class 600)

National Grid - Feeder #7 Transmission pipeline

One CLASS600 Grouted Tee was installed onto Transco’s transmission pipeline to allow for a new pipeline tie-in. June 2003 36” Steel (API 5L Grade X65) 15.9 mm 75 bar 36” Equal Tee (Class 600)

BGI / ComGas - Sao Paulo, Brazil

Date of Installation: Pipeline Diameter: Pipeline Material: Pipeline Wall Thickness: Operating Pressure: Size of Tee installed:

Tullow Oil - Bacton, United Kingdom Date of Installation: Pipeline Diameter: Pipeline Material: Pipeline Wall Thickness: Operating Pressure: Size of Tee installed: Duration of Installation: Client name & contact No.

Two Grouted Tees were installed linking two incoming offshore pipelines. The Grouted Tee was considered because of Tullow Oil’s polices of zero hot work, except during a plant shut down. August 2004 20” & 24” API 5L Grade X52 20mm & 24mm 56 ar 18” off 20” & 18” off 24” (Class 600) 15 hours per Grouted Tee plus Grout curing Michael Webster – 01263 725084



w. Weldability Testing of 48” Diameter X80 Europipe Production

x. Corrosion Control of a Sour Gas Pipeline

Date: Customer: Savings:

Date: Customer: Savings:

2007 National Grid (Milford Haven extension) Approved procedures and manufacturing

Weldability testing entails the production of a full-scale girth weld between two 12m pipe joints under field conditions and including the manipulation of the partially-completed weld to simulate the removal and movement of the line-up clamp. Following production of the complete girth weld, the joint is subjected to X-ray inspection and must pass required codes (T/SP/P/2 or API 1104 requirements) and is then subjected to a full suite of mechanical tests. Following satisfactory results from these investigations, the welding procedure and the linepipe manufacturing route are qualified for supply to National Grid.

2006 North Africa Offshore Operator Identified corrosion inhibitor

Description: A major operator produced sour gas and condensate from a field located in the Mediterranean. The field infrastructure consists of a number of platforms to dehydrate the produced fluids, which are then transported to the onshore gas processing plant via a multiphase pipeline. Issues: The processing plant on the platforms and the multiphase pipeline were manufactured in carbon steel. Corrosion protection is required and this is provided by corrosion inhibitor injection. The inhibitor in use was dosed at high rate to ensure sufficient protection resulting in a high cost of treatment. Application: GL carried out a chemicals selection programme with the aim of identifying a corrosion inhibitor treatment providing the optimum balance between dose rate, cost and environmental impact. The programme included a review of vendor-supplied data, corrosion inhibitor performance evaluation in laboratory autoclave tests, (under representative conditions) and field trials. Results: A suitable inhibitor meeting the performance criteria was identified. Dosing was optimised and the following benefits were delivered:

Girth welding of 48” X80 pipe during weldability testing

Simulation lifting of 48” joint after hot pass deposition.


Sample welding procedure qualification record from the 48” X80 trials, showing joint design, consumables, pre-heat requirements, pass sequence and other details.


50% reduction in the chemical unit price Improved corrosion inhibition performance 33% reduction in the chemical dose rate Lower environmental impact Increased plant integrity Increased corrosion awareness (improved corrosion management strategy)


y. Naphtha Pipeline Integrity Management Study

z. Sour Export Pipeline Study

Date: Customer: Savings:

Date: Customer: Savings:

2005 Far East Offshore Operator Corrosion management

2006 Major Oil Production Company Materials and evaluation



GL was contacted by a gas company operating in the Far East to offer recommendations for corrosion management of a naphtha subsea pipeline. A recent in-line inspection revealed that the pipeline had undergone internal corrosion (equating to 10-25% metal loss). As the pipeline was required to operate for a further 20 years, GL was asked to devise a cost-effective lifetime integrity management strategy.

A new ultra sour oil field was to be developed in the environmentally sensitive Caspian sea. It was thus vital that the oil export pipelines did not suffer any leaks during operation to avoid pollution damage. One member of the joint venture suggested the use of corrosion resistant alloy pipelines to avoid any risk of leaks, however this would involve costs of $2 billion just for the alloy so another solution was needed. The oil company asked GL to consider the materials and corrosion control options for the pipeline.

Solution: GL applied its broad knowledge and experience in failure investigation and pipeline corrosion management to determine the reason for internal corrosion and identify the most cost-effective integrity management solution. GL applied risk based lifecycle-costing methods to compare the viable reconditioning strategies. We also delivered an implementation plan and corrosion monitoring strategy to demonstrate long-term effectiveness.

Benefits: GL demonstrated that both corrosion inhibition and in-situ coating would allow a 20-year life for the pipeline. However, based on upon NPV cost and ease of implementation, corrosion inhibition was the preferred option. NPV for inhibition over 20 years was only one third of the coating NPV costs. GL also demonstrated that the in-situ coating option would require complex project management in order to accomplish the work between naphtha shipments.

Solution: GL evaluated the corrosivity of the produced fluids by considering the acid gas composition, water content, pressures and temperatures. These parameters were used for sour gas corrosion modelling using both industry standard methods (e.g. DeWaard and Milliams) and software specifically developed by GL (PrCSM). Sour cracking mechanisms such as sulphide stress cracking and hydrogen induced cracking were also considered in the study. The results of the modelling and an economic study were used to compare various materials options for the pipeline. The options were: 

Sour resistant carbon steel with corrosion inhibition

Nickel alloy lined pipe

Nickel alloy clad pipe

Solid nickel alloy pipe

Results and Benefits: The study showed that sour resistant carbon steel with corrosion inhibition could be used for the sour oil export lines with an acceptable risk of failure. The small quantities of water present within the pipelines allowed corrosion inhibition to reduce corrosion rates and the cracking risk to a minimal value.


Asset Management Services Plant Integrity Management Services 

Germanischer Lloyd Industrial Services GmbH

Pipeline Integrity Management Services Production Optimisation (Includes RAM and Gas Processing) Dynamic and Steady State Simulation Rotating Equipment Performance & Condition Monitoring including Emissions Reporting Gas Quality and Interchangeability

Oil and Gas Steinhöft 9 20459 Hamburg, Germany Phone +49 40 36149-7700 Fax +49 40 36149-1781 [email protected]


Germanischer Lloyd does not warrant or assume any kind of liability for the up-to-date nature, accuracy, completeness or quality of the information provided. Liability claims against Germanischer Lloyd arising out of or in connection with material or non-material loss or damage caused by the use or non-use of information provided, including the use of incorrect or incomplete information, are excluded unless such loss or damage is caused by the proven wilful misconduct or grossly negligent conduct of Germanischer Lloyd. All offers are subject to alteration and are non-binding. Germanischer Lloyd expressly reserves the right without notice to change, supplement or delete parts of the pages or the entire offer or to stop the publication temporarily or definitively.

Issue no.001 15.05.2008

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