Onshore Pipelines The Road to Success Vol 2 by Pedemex BV

Onshore Pipelines

THE ROAD TO SUCCESS

An IPLOCA document – 2nd edition September 2011

VOLUME TWO

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

IPLOCA OBJECTIVES Objective 1 To promote, foster and develop the science and practice of constructing onshore and offshore pipelines, and associated works. Objective 2 To make membership of the Association a reasonable assurance of the skill, integrity, performance, and good faith of its Members, and more generally to promote good faith and professional ethics in industry. Objective 3 To maintain the standards of the contracting business for onshore and offshore pipelines and associated works at the highest professional level. Objective 4 To promote safety and develop methods for the reduction and elimination of accidents and injuries to contractorâ&#x20AC;&#x2122;s employees in the industry, and all those engaged in, or affected by, operations and work. Objective 5 To promote protection of the environment and contribute to social, cultural and environmental development programs, both in Switzerland and worldwide. Objective 6 To promote good and co-operative relationships amongst membership of the Association as well as between contractors, owners, operators, statutory and other organisations and the general public. Objective 7 To encourage efficiency amongst the Members, Associate Members and their employees. Objective 8 To seek correction of injurious, discriminatory or unfair business methods practised by or against the industry contractors as a whole. Objective 9 To follow the established Codes of Conduct set out by the industry and others with respect to working within a free and competitive market, and in doing so, to promote competition in the interests of a market economy based on liberal principle, both in Switzerland and worldwide. Objective 10 To maintain and develop good relations with our Sister Associations as well as Associations allied to our industry and play a leading role in the World Federation of Pipeline Industry Associations.

Disclaimer

In the preparation of THE ROAD TO SUCCESS, every effort has been made to present current, correct and clearly expressed information. However, the information in the text is intended to offer general information only and has neither been conceived as nor drafted as information upon which any person, whether corporate or physical, is entitled to rely, notably in connection with legally binding commitments. Neither its authors nor the persons mentioned herein nor the companies mentioned herein nor IPLOCA accept any liability whatsoever in relation to the use of this publication in whatsoever manner, including the information contained or otherwise referred to herein, nor for any errors or omissions contained herein. Readers are directed to consult systematically with their professional advisors for advice concerning specific matters before making any decision or undertaking any action.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

Executive Summary â&#x20AC;&#x153;Onshore Pipelines: THE ROAD TO SUCCESSâ&#x20AC;? was produced under the patronage of IPLOCA to describe state-of-the-art project development and execution practices for onshore pipeline projects. It is the collaborative result from six different working groups with the goal of covering all stages in the development of a pipeline project. The updates (*) and the new developments (**) introduced into this Second Edition are highlighted in this executive summary. Section 1

Introduction Pipeline issues and challenges.

Section 2

Development Phases of a Pipeline Project Section 2 describes the key points to be addressed during the FEL (Front End Loading) phases in order to properly prepare for the project execution phase. Much of FEL is done well before a project is sanctioned and begins construction to ensure a complete project assessment so as to fully understand the challenges and risks associated with a proposed pipeline project. During this period, project investors and their design contractors typically have due diligence obligation to themselves and their shareholders to achieve good FEL and therefore control the work process and make the key project decisions. A detailed review of the data requirements and activities during those phases is included.

Section 3

The Baseline of a Construction Contract The next steps take place at the point of project sanction, where construction soon begins. A baseline understanding of the project scope and its risks must be established when investors and contractors enter into mutual agreement underlying a construction contract. This section offers recommendations for establishing the baseline for the Project Execution phases with four chapters: the Scope of Works, the Programme, the Cost and the Contract.

Section 4

Dealing with Risks in Pipeline Projects * After project sanction, irrespective of all the efforts to reduce challenges and risks through the FEL phases, there will inevitably be other challenges and risks that arise. These may represent disruptions and changes to the established project baseline, so any pipeline construction contract must document how these residual risks will be addressed and managed.

Section 5

Best Practices in Planning and Design * Best practices are developed in this updated section for planning and design, with the process leading to the definition of the ROW and the information to be gathered during the different phases of a project. The routing and design of a pipeline requires a disciplined and organised sequence of actions to ensure that the most acceptable and optimised route avoiding as many hazards as possible has been selected and that the system has been designed under acceptable standards to satisfy fitness for purpose, environmental constraints and safety.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

The Minimum Data Requirements and Activities for the Five Typical Project Stages introduced in section 2 are defined in this chapter. Section 6

Earthworks The terrain, soil types, and geohazards traversed by the pipeline are key factors to consider in the design, construction, operation and maintenance of a pipeline project. Firstly, the terrain typically affects pipeline hydraulics, above ground stations and pipeline protection. Secondly, soil types will affect heat transfer, pipeline restraint, and constructability. Finally, geohazards often require special design and construction considerations. The Earthworks section offers guidelines on how to prepare the right of way (ROW) in different types of terrain, on the earthworks design, on the recommended measures to reduce the impact on the environment, and finally on the approach to health and safety.

Section 7

Crossings ** This new section, to be further developed, is initiated with a description and comparison of the different methods to execute major trenchless crossings.

Section 8

Logistics ** The risks associated with the logistics of pipe such as handling, transport, coating and storage begin this new section. Other logistic constraints of pipeline projects will be further developed in future editions.

Section 9

Welding (section to be developed) This important topic deserves a section of its own, yet to be developed.

Section 10 Non Destructive Testing ** The section starts with a review of the main concerns of the different stakeholders of the pipeline for completing the project. The second subject will be the role of codes and standards in the design and building of pipelines. Finally the issues involved with NDT at the various stages of the project are addressed: • • • •

The role of NDT in the FEL/FEED stages. Vendor inspection and NDT at the material suppliers Girth weld inspection during the construction stage NDT during the use of the pipeline; considerations during the construction stage for future maintenance

Section 11 Pipeline Protection Systems * Most of the installed and currently planned onshore transmission pipelines around the world are steel pipelines and their integrity during all the manufacturing, handling, storage, installation and service life stages is an important aspect of any pipeline project. As the external corrosion and the mechanical impacts have been identified as the most common causes of pipe damage and failure in onshore pipelines, industry’s efforts have been focused on addressing these issues in order to avoid potential economic, environmental and human costs from pipeline failures. Therefore, this document reviews the passive external anti-corrosion systems as well as the active cathodic protection approach.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

However, onshore pipeline projects can have other specific requirements. Supplementary mechanical protection systems that protect the steel pipes and their coatings against damage from external impacts are reviewed, along with internal coating systems and thermal insulation. The floatability phenomenon has to be mitigated on onshore pipelines crossing wet environments, such as lakes, rivers, or swampy areas and the industry has developed specialized buoyancy control systems which are being presented here.

Section 12 Pipelines and the Environment (section to be developed) This multiple-aspect topic also deserves a section of its own, yet to be developed.

Section 13 Future Trends and Innovation * The onshore pipeline industry involves collaborative efforts between multiple stakeholders, each of them having a key role to play at one stage or more during the project life cycle. Understanding the involvement of each of these players is a vital step towards enhancing the operations on the pipeline project in the areas of efficiency, quality, safety, and the environment. The GIS-based construction monitoring tool, the pipeline simulation tool, the Equipment Tracking System and the use of Google Earth in pipeline construction monitoring are presented as components of a well-rounded Integrated Pipeline Construction Management (IPCM) System. Innovative construction techniques (the “skidless methodology”) and developments in construction machinery (features of the “ideal construction machine”, machine control systems – GPS – and data transfer) are being proposed to the industry to complete this section.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

Table of Contents (Volume Two) Page

Executive Summary

8. Logistics 8.1

Pipe Logistics Operations

9. Welding (section to be developed) 10. Non-Destructive Tests (NDT) 11. Pipeline Protection Systems 11.1 Review of Key Mainline External Anti-Corrosion Coatings

11.2 Field Joint Anti-Corrosion Coating Selection Guide

11.3 Bends and Fittings

11.4 Mechanical Protection Selection Guide

11.5 Internal Coating

11.6 Insulation

11.7 Buoyancy Control Systems

11.8 Cathodic Protection

Appendix 11.1.1: Comparison of Mainline External Anti-Corrosion Coatings

Appendix 11.1.2: Field Joint Coating Selection Table

Appendix 11.1.4: Supplementary Mechanical Protection Systems Selection Table

12. Pipelines & the Environment (section to be developed) 13. New Trends and Innovation 13.1 Functional Specifications for a Near-Real-Time Construction Monitoring Tool

13.2 Conceptual Specifications for Building a Pipeline Construction Simulation 7 Tool 13.3 Equipment Tracking System

13.4 Google Earth in Construction Monitoring

13.5 Skidless Methodology

13.6 Machine Development

13.6.1. Features and Functional Specifications of the â&#x20AC;&#x153;Ideal Machineâ&#x20AC;?

13.6.2. Use of Computer-based Technologies

13.6.2.1 GPS in Machine Control and Operation

13.6.2.2 Data Transfer

Appendix 13.1.1: Conceptual Functional Specifications for a GIS-based NearReal-Time Construction Monitoring Tool

Glossary of Acronyms Bibliography Acknowledgements

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 8

8. Logistics 8.1 - Pipe Logistic Operations 8.1.1 Introduction When a pipeline is completed and operational, it is the result of a cooperation between a number of parties in the supply chain. These parties are sequential and overlapping in time, being involved in the design, manufacturing, blasting, coating, handling, storage, transport and construction of the pipeline. The supply chain is graphically displayed in Figure 1.

Fig. 1 Line pipe supply chain During each stage of this supply chain pipes and coatings can be damaged. This recommended practice shall address the processes after pipe manufacture of the pipes and discuss risks and available solutions during logistic operation. For every pipeline project the sequence of logistic operations and the circumstances in which they take place are different. It is important to have an exact overview of this logistic trail. When mapping out this trail, the following questions need to be answered

•

What are the different stages for the pipes in a project, and where do they take place geographically? For example:

Manufacturing

Handling

transport

Handling

Coating

Storage

Handling transport

Field storage

Handling

• • • •

Handling transport

transport

Handling

Storage

Concrete coating

Handling

Pipeline construction

How are pipes transported to their next destination, by truck, train or vessel? How does the loading / unloading (handling) take place at each transport stage? Where along the trail are the pipes being stored, and in which climate conditions? What is the duration of each storage period?

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These questions need to be answered to ensure a good pipe end-quality and coating layer. The answers help to make a selection of equipment and protection that is fit for purpose. Although modern coatings such as 3 layer polyethylene and fusion-bonded epoxy are designed to resist damage associated with â&#x20AC;&#x2DC;normalâ&#x20AC;&#x2122; logistic operations, numerous damages are encountered in practice. The damages that are most likely to occur are the result of forces associated with impact or abrasion. If the coating is damaged during logistic operations it needs to be repaired. These repairs are project-specific but due to the use of imprecise technical specifications, repairs can fail and result in many in-ground coating problems. Damages can also stay undetected, or are very difficult to detect, such as UV degradation. Therefore preventing damage is always the best solution. People often choose a cheap alternative, assuming nothing will go wrong as long as minimum requirements or specifications are followed. However specifications and requirements are not always indepth on every subject. Asking specialists for advice can save many costs in the long run. Often with only a small extra initial investment, one can win not only in terms of quality but also on other grounds such as safety and efficiency. A fair cost comparison is only made when not just the buying price is taken in to consideration, but also the consequences of choosing for a certain product. We shall discuss damages encountered in processes during the supply chain, their root causes and ways to prevent or minimize them. This chapter is aimed to secure the quality of coated pipes and also to improve the safety and efficiency in related processes. This chapter is relevant for all parties involved in the line pipe supply chain, from the early phases in project management and planning to the last construction operations

8.1.2 Pipe-end protection Pipe-end protection is advisable in case the pipe-ends are bevelled at the pipe manufacturer. Especially in case of overseas transport there is an increased risk of damaged pipe-ends. This is caused by extra handling procedures in ports and shifting of the pipes aboard vessels. It is difficult to control the circumstances in ports overseas. Research and experience show that a good pipe-end protection can prevent 95% of the damages as they are most likely to occur in practice. How to select proper pipe-end protection? â&#x20AC;˘ For protecting the bevel of the pipe, there are steel bevel protectors available. Important features of a good bevel protector: 1. Strong clamping system that can withstand transport vibrations, also in case of large diameters. 2. Effective protection of the bevel: Both a deformable buffer zone and material thickness contribute to the effectiveness of the bevel protector (example: figure 2). 3. No parts sticking out: To promote safety and prevent damage to other pipes, it is important that the bevel protector has no sharp edges or parts sticking out that might cause harm or damage. 4. No open gaps: Two overlapping ends make sure that the complete circumference of the pipe is covered. 5. Diameter tolerances of pipes: If the pipes are produced with a certain tolerance, make sure that the bevel protector of your choice can deal with this tolerance. 6. Re-usability: For example if pipes are being transported from the manufacturer to a coating plant on a different location, the bevel protectors have to be removed before coating and re-installed after coating.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 8

Fig. 2 Example of a good steel bevel protector: Strong clamping system, no parts sticking out, no open gaps

Fig. 3 Cross-section steel bevel protector

Fig. 4 Typical impact damage to the bevel

Pipe Closure One can also chose to close off pipes after manufacturing in order to protect the internal pipe surface against contamination by sand, snow, animals and vegetation. Contamination of the pipes is often seen, especially when pipes are stacked and stored for long periods of time, at project locations, or close to the sea. Contaminated surfaces can remain moist for a longer period of time, because the moisture is kept from evaporating. For instance, pipes that were stored for emergency repairs at a location in the Netherlands showed heavy weathering and contamination both in and outside of the pipe where the coating disbonds at the pipe-end. Other forms of contamination are foreign objects that are found inside pipes such as tools, wood, animals, cans etc.

Fig. 5 Contamination of pipes

Fig. 6 Contamination of pipes

Fig. 7 Foreign objects in pipes

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 8

â&#x20AC;˘

For closing off pipes, there are different types of plastic caps available, as well as combination possibilities such as a steel bevel protector with a plastic plug.

1. Pipe end caps - Made for standard external pipe diameters - Not hookable - Might loosen due to temperature fluctuations (risk increases for larger diameters) - Cannot be applied on stacked pipes 2. Recessed caps - Made for standard external pipe diameters, with a certain wall thickness range - Hookable - Might loosen due to temperature fluctuations (risk increases for larger diameters) - Cannot be applied on stacked pipes 3. Steel bevel protector combined with plastic plug - Made for any internal diameter, also for non-standard external diameters - Hookable - No difficulties with temperature fluctuations, because of the secured fit (the steel bevel protector also keeps the plastic plug firmly positioned during logistic operations) - Can be applied on stacked pipes - Additional bevel protection

Fig.8 End cap

Fig.9 Recessed cap

Fig.10 Plastic plug with steel bevel protector

4. Solutions for extreme climates Plastics can deteriorate fast in extreme climates. Both UV degradation and extreme cold temperatures can cause plastic caps to become brittle and break easily under the influence of wind, sand, ice, snow or rain. The material quality and thickness is crucial when selecting end protection for demanding project circumstances. It is also important to realise that pipes might come across alternating climates during their logistic trail. Nowadays pipelines run through more demanding latitudes and altitudes than ever before. Fig. 11 Bevel protector combined with plastic plug for extreme climates

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Consequently it is important to choose a material that is fit for purpose. The example in Figure 11 shows a bevel protector combined with a plastic plug that is made from very low density polyethylene (VLDPE). This material is highly UV-resistant and keeps its flexible qualities in low temperatures (down to -50°C)

Desiccant material To prevent corrosion inside the pipe, desiccant material can be added. For this purpose, a tight sealing of the pipe is necessary. The steel bevel protector in combination with a plastic plug is the best solution, as the steel ring forces the plastic plug against the internal pipe surface. Desiccant material is available in bags that absorb moisture from the air. The quantity is calculated according to the climate conditions and duration of storage. Not every desiccant material is suitable for use in steel pipes. Chemical additives such as salts might even speed up corrosion instead of preventing it. Consequently it is important to check if the desiccant is suitable for use in combination with steel products. In case of long-term pipe storage (> 6 months) it is advisable to monitor on a regular basis if the desiccant material is still active. This can be done by looking on indicator cards that change colour depending on the relative humidity inside the pipe.

Fig.12 Desiccant bags inside a pipe Tips: • When choosing a hookable end cap, make sure that the depth corresponds with the hooks that are used to handle the pipes. • If there is a large altitude difference between the location where the end caps are put on the pipes and the location where the pipes are being transported to, it is advisable to make a small ventilation hole in the end cap. Otherwise the end caps might be pushed off due to expansion of air inside the pipe. • UV stability of end caps varies strongly. Don’t forget to check if the UV-resistance of the end caps corresponds with the climate in which the pipes are stored and the duration of storage. • Recycling: Make sure the plastic caps can be recycled for the protection of the environment. This should be discussed with the supplier.

8.1.3 Protection and efficiency during the coating process In case of bevelled pipe-ends it is advisable to protect the bevel during external blasting and coating. During external blasting: It is advisable to protect and close off the pipe-end during external blasting. This prevents loss of steel grit and damage to the pipe-end and internal pipe surface. Especially when internal coating is done prior to external blasting, the pipe needs to be closed to prevent any steel grit from entering and damaging the internal coating. There are specialised tools – blasting plugs – available for this purpose.

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Tools that are used to protect and close off the pipe-ends during external blasting should: • Be easy to handle for employees • Provide strong clamping inside the pipe • Resist friction between rotating pipes • Resist the pre-heating oven • Resist impact of steel grit in the blasting cabin • Resist acid wash or chromate treatment • Take in to account the cutback of any present internal coating By fine-tuning the blasting process (manually or programmatically), damages to the pipe-ends can be prevented. When pipes run against each other, friction forces between pipes should be minimized and a constant line speed should be maintained. Pipes should also be prevented from opening up inside the pre-heating oven or blasting cabin.

Fig.13 Blasting plug for protecting and closing off the pipe-end during external blasting

Fig.14 Blasting plug during blasting process During external coating: To improve the efficiency during external coating and the quality of the coating application, it is possible to line up and connect pipes. An unstable coating process can cause unwanted movements in the coating line and damage to the bevelled pipe-end. Because the pipe does not rotate in a straight line, the coating thickness can vary over the length and circumference of the pipe. In the worst-case scenario, unwanted movements can even cause air seals underneath the coating layer. If pipes are lined up, there is less movement which ensures a better quality coating application. A coating process can be unstable due to multiple causes: • Large pipe diameter combined with small wall thicknesses • Curved or oval pipes • Unequal support rolls • Unstable support rolls such as air tires • High line speed • Long distances between support rolls

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The process of lining up and connecting pipes stabilizes the coating process and minimizes the consequences of abovementioned problems, such as air seals underneath the coating layer. Lining up pipes can be achieved with a pipe coupling. Pipe couplings are ideally made for one external diameter and adjustable for a certain wall thickness range. There are two types of pipe couplings available: Male-female pipe couplings and single side pipe couplings. The male-female pipe couplings exist out of two parts that have to be inserted in both pipe-ends that are running against each other. The single side pipe couplings have to be inserted in only one pipe-end. The upcoming pipe is automatically lined up.

Fig.15 Male-female pipe coupling

Fig.16 Single side pipe coupling

Which features are important for a good pipe coupling? A good pipe coupling should: • Line up pipes accurately • Cause no permanent deformation to the pipe after fastening (especially in case of small wall thicknesses) • Provide bevel protection • Not scratch the internal pipe surface (usually caused by insufficient clamping or blocking of the coupling when pipes move away from each other) • Not take up to much heat from the pipe, as this would have a negative effect on the bonding of the coating. Contact surfaces between the coupling and the pipe should be limited. • Be able to handle oval or curved pipes • Be easy to adjust for a large wall thickness range • Allow static flow between pipes • Be able to resist heating by gas or induction oven • Be able to bridge thermal expansion of the pipes • Remain strongly fixed in place during the entire coating process

Fig.17 Pipe coupling with automatic clamping

Fig.18 Perfect line up of pipes during coating and centering

Pipe couplings have to be integrated in a coating process. It is important to choose a good position for inserting and removing the couplings. For large diameter pipe couplings a lifting crane or balancer is necessary for fitting and removal. Transport of the couplings back to the beginning of the process can be done by manual carts or an automatic rail system.

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Tips: • It is advisable to insert the coupling in the pipe-end of the pipe that enters the cooling street first. In that way the coupling will cool down and shrink slightly earlier than the upcoming pipe, which allows a more easy release of the other pipe-end. • In case of a fragile bevel or thin wall, choose softer material for rollers, such as heat resisting nylon (nylon 6.6) • Make sure that the coupling allows conductivity flow through the coating line to prevent sparks caused by static electricity

8.1.4 Pipe Handling Pipes are handled multiple times in the supply chain for example in ports and storage yards. Handling here is taken to mean lifting of pipes and loading in or unloading from trailers, train wagons or vessels. Most damages to pipe-ends and pipe coatings occur during handling procedures due to a combination of inadequate equipment and poor personnel attitudes. This also leads to unsafe situations and accidents. The attitudes issue is the hardest to overcome as circumstances can’t always be controlled and many different people are involved in handling the pipes during different stages in the pipeline project. Proper training, planning beforehand and safe equipment can help to overcome this issue. Practical example In many factories and coating plants, pipes are occasionally moved by hand. Special tools are made for this purpose, that allow rolling of pipes with the help of a lever arm. Generally these kind of tools are ‘home made’ by employees. If not constructed properly these tools can cause damage and injuries to people. That is why training and technical insight into the fragility of the bevel and internal / external coating are so important.

Fig. 19 Pipe Roller designed for safe manual handling of pipes Pipe lifting Lifting can be done with hooks, forklift, hydraulic spreader and vacuum equipment. In this paragraph these methods and their impact on the pipe coating are examined. It is commonly known that pipe hooks could damage bevelled pipe-ends when badly designed. Bevel protectors can be applied to overcome this issue. Less known is that hooks can also damage pipe coatings during loading operations. It is no exception that hooks dangle against the pipes causing impact damage to the coating. Proper handling of coated pipes with pipe hooks is possible, but employees must be made aware of the vulnerability of pipe coatings. A well designed pipe hook should be selected for this purpose.

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Features of a well-designed pipe hook: • Covered with a softer material such as PU to prevent impact damage to the pipe coating • Exchangeable pads • Handgrip and rope shackle for safety of personnel • Calculated for a prescribed lifting angle and tonnage • Shaped to spread lifting forces on the internal pipe surface and bevel

Fig.20 Example of a poorly-shaped pipe hook unsuitable pipe hooks

Fig.21 Typical damage to the pipe-end caused by

Fig.22 Example of a pipe hook without a protective hook exterior

Fig.23 Example of a well-designed pipe hook

Forklifts are frequently used for handling pipes. Damage to coated pipes is caused when the steel forks are not covered with a softer material to protect the coating. It has been seen that forklifts drive the forks directly into the pipe-ends to lift them. This type of handling causes damages to the pipe and internal coating. There are custom made forklifts available with soft covered grippers to hold the pipes during driving. Tip: • Grippers are appropriate if the driving area is bumpy or not straightened. If a normal forklift, carrying a pipe, drives through a hole or bump in the road, one of the pipe-ends might scrape over the floor causing serious coating damage and deformation of the pipe, not to mention the risk that the pipe might slide off the forks.

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The best way to handle coated pipes is by means of hydraulic spreaders or vacuum lifters. This equipment is designed to minimise the risk of damaging pipe coatings. An investment is required, but is well worth the effort. It not only has the advantage of needing less ground personnel, but the loading and unloading practices can be done in less time as well.

Fig.24 Hydraulic spreader bar

Fig.25 Vacuum lifter

8.1.5 Pipe Transport Pipes are transported between parties involved in the supply chain. Ways to do this are by truck, train and/or vessel. Pipes need to be fixed during transport. Wooden dunnage can be applied in combination with tensioning belts; however there are some risks that need to be considered. The quality of the wooden dunnage varies strongly and depends on the design and person who makes them. Various specifications are found for the design of wooden supports. In most cases wedges are nailed on wooden beams. As wood is a product of nature it has widely varying material properties and it is unreliable due to hidden cracks and voids. Besides this, wood is highly subjective to weather influences such as drought and rain that cause rapid deterioration. Most specifications do not take these factors into consideration and only focus on the basic design. A risk that also needs to be considered is that nails can loosen due to transport vibrations. This not only causes unsafe situations, but also severe coating damage as the nails can intrude into the coating layer.

Fig.26 Nail sticking out of a transport system

Fig.27 Coating damage caused by a nail

If wooden dunnage is used, the following measures are advisable: • Thorough inspection after each use • Immediate disposal of broken supports • Use only 1-4 times

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 8

• Always store inside • Have the dunnage tested before use Immediate danger for everyone involved in pipe transport occurs when the wooden supports are not constructed with care. Plenty of examples have been found during field work. Beams are found broken, wedges are too small, wedges are not made for the correct pipe diameter, wedges are not or poorly nailed to the beam, or nailed at very unfortunate locations. Fig.28 Most wooden dunnage is not adjustable for different diameters. It is very difficult to organise a stock and select the appropriate system for a certain diameter

Alternative for wooden dunnage There are more specialised systems available for pipe transport. This type of system has the following advantages: • Safe for any coated pipe surface • Wedges are made from one part, with a constant material quality • No nails sticking out • Adjustable for multiple diameters • Durable • Design based on static and dynamic calculations in accordance with API Recommended Practice 5L1 and VDI 2700 There is one other essential difference to consider between wooden dunnage and a system as shown in figure 29-34. With wooden dunnage the pipes are supported on the bottom. Although the pipes are blocked by wedges, almost all weight rests on the beam underneath the pipe. With a system as shown below, the pipe doesn’t touch the bottom, but is fully supported by the wedges. This has a very positive effect on the roundness of the pipe and material stresses, as shall be demonstrated in the next section on pipe storage.

Fig. 29 Static pressure test (temperature 70°C)

Fig. 30 Measuring coating thickness after test

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This type of transport system is especially developed for safe pipe transport on truck and train:

Fig. 31 Pipe transport by train

Fig. 32 Pipe transport by truck with anti-skid rubber layer added

Fig. 33 Pipe transport

Fig. 34 Pipe transport of two 56” pipes on one trailer with a pipe raiser system

8.1.6 Pipe Storage Pipes are stored a number of times before they reach their destination. During storage the pipe coating is subject to high pressure, ultra-violet (UV) degradation, design of bottom support, and contamination among other things. In this paragraph the impact of these influences on the pipe coating is examined. Impact of storage method on coating Pyramid stacking is the most common way to stack pipes. When pipe stacks are built layer on layer, the forces on the bottom row of pipes can be approximated by the number of pipe layers times the weight of one pipe. Pipes in the stack deform as a result of these forces. The coating is subject to these forces as well. The resulting pressure on the coating must be considered to avoid damage. The maximum pressure that coating material can take is known. A careful estimation should be made of the area that transfers the forces. This could either be the contact area between the pipes or between the bottom pipe and the support that carries the pipe. In any case the 3 and 9 o’clock positions of the pipes should not touch each other. Because of the load on top, pipes become oval. When there is contact between the 3 and 9 o’clock positions of the pipe due to this (temporary) ovality, the pressure on the coating becomes extreme. There should be just enough distance between the pipes to make sure that pipes do not touch due to deformation after the stack has been completed. This is one of the reasons why some manufactures apply ropes around the pipes.

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If the pipes of a stack are being supported it is advised to block every single pipe from rolling. Using only stops at the end of the stack is advised against. If only end-stops are used, forces add up at the end of the stack. The more layers of pipes, the more forces add up, as demonstrated in Figure 35. The diagonal lines represent the forces that the pipes transfer to the pipes underneath. The bottom pipes in the middle of a stack experience the same forces from the left and from the right. They are in static balance. The forces on the pipes more towards the end of the stack are not in balance, as they experience more pressure from one side than the other. If only end stops are used, the bottom pipes transfer the forces to each other which add up till the last pipe. This force is blocked by the end-stop only, resulting in extremely high pressure (depending on the surface of the end stop). Steel supports as shown in Figure 36 are therefore not recommended as they only block the pipes at the end of the stack.

Figure 37 shows an example of an overloaded end stop. Fig. 35 Forces add up towards the end of a pipe stack when using only end stops

Fig. 36 Example of steel end stop

Fig. 37 Overloaded end stop

Tip: â&#x20AC;˘ Similar calculations can be made for stacks in a vessel. Inside the vessel there is an even higher chance of damage due the movements at sea. The pipes are blocked by the vesselâ&#x20AC;&#x2122;s cargo hold only and sometimes pipes are stacked higher inside the vessel than on land. This needs to be taken into consideration. Risks when using sand berms for pipe storage Sand berms and wood with wedges are commonly used, steel profiles with only end stops are less used. If left uncovered, sand berms are highly subject to erosion. Erosion takes place slowly by wind and water washing away the sand. Pipe stacks might seem stable in the beginning but they become unstable after a period of time. The degree of erosion is difficult to measure and monitor. Therefore bare sand berms are unreliable and unsafe. This especially holds when berms are reused without rebuilding. Besides safety risks, the composition of sand and rocks for the sand berms is not specified. Although the time

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frame for storage is relatively small compared to the time a pipeline lays in the ground, there are familiar cases in which the sand berm was highly contaminated with salts that affected FBE-coated pipes with pitting corrosion. There are also better examples of sand berms, constructed following a predefined specification with polyethylene to cover the sand and periodical examinations to assess the stability of the stacks. However, when applying sand berms a level of uncertainty always remains, as you can never tell if sand is about to shift either because it is too wet or too dry. If sand berms are used, the following minimum measures are advisable: • Cover the sand with PE or rubber sheets • Pre-define the height, depth and shape of the sand berm • Use indicators to monitor any movement in the pipe stack, such as markings on the ground or on the pipes • Use a back-up system to help support the pipe stack, such as pipe clamps

Fig. 38 Eroded sand berm, the sand is too dry Risks when using wooden systems for pipe storage There are three main risks when using wooden pipe supports: 1. Wood is a natural product with an inhomogeneous structure. Pipe supports can have hidden cracks and weaknesses 2. Wood deteriorates fast due to weather influences, losing its capacity to carry loads 3. Nails that stick out intrude into pipe coatings, causing severe damage. If wooden systems are used, the following minimum measures are advisable: • Pre-define the design of the wooden system • Use indicators to monitor any movement in the pipe stack, such as markings on the ground or on the pipes • Use a back-up system to help support the pipe stack, such as pipe clamps • Use rubber padding to prevent coating damage

Fig. 39 Unstable wooden support

Fig. 40 Weathered wooden support

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Pipe support on wedges A pipe storage system as shown in Figure 41 has some advantages compared to the systems discussed earlier. It requires an initial investment, but pays itself back in the longer run because of its reusability and minimized risk of coating damage or accidents. This system comprises low-density polyethylene compound wedges that are positioned on a steel-reinforced polyethylene compound gear rack. The gear racks can be connected to create the needed storage length. Pipes are raised from the ground by at least 80 mm and settings can be made such that the distance between the pipes is at least 1% of the pipe diameter.

Fig. 41 Pipe support on wedges

Fig. 42 Pipe support in the field

Advantage of wedge support Supporting pipes on two wedges instead of on one bottom beam has a big advantage. Because there are two support surfaces instead of only one, the deformation of pipe is reduced significantly. Finite element method analysis indicates 3.8 times less displacement and 1.8 to 1.9 times less Von Mises stress. Figures 38 and 39 show the difference between bottom support and wedge support.

Fig. 43 FEM bottom support

Fig. 44 FEM wedge support at two surfaces

The design of these types of systems is based on calculations and pressure tests. In addition these systems are certified by third parties. Uncertainties and hidden weaknesses are eliminated. TIP â&#x20AC;˘ Sometimes pipes are stored on a slope. Even a slope of only a few degrees makes a large difference in the way forces are transmitted in a pipe stack. Make sure that the storage system can handle the forces when storing pipes on a slope. Position of supports When a pipe is not supported over its full length, it is going to bend under its own mass. Because of the bending, compression and tensile stress on the upper and under side shall arise, which can lead to coating disbondment or damage and permanent deformation of the pipe.

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Figure 45 shows a schematic storage situation of a pipe, using two support rails. To achieve as little deflection of the pipe as possible it is necessary to calculate the ideal position of the supports.

Fig. 45 Bending of pipe due to support position Calculations prove that the ideal position is at 22.05 percent (measured from the ends) of the total length of the pipe, when using two supports underneath one pipe. This results in the lowest possible displacement and thus the lowest bending stress. This ideal position of the supports, distance a in Figure 45, is also determined with FEM analysis. The results of the FEM analysis are shown in Figure 46. The smallest displacement can be seen at 22,15 percent, marked by the green line.

Fig. 46 Displacement of pipes depending on supporting position and width

Figures 47-49 show the deflection of the pipe by FEM analysis at three different positions. If the supports are placed at 18% of the pipe length, the displacement in the middle is greater than the displacement at both ends.

Fig. 47 Pipe support at 0.18 x L

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If the supports are placed at 25% of the pipe length, the displacement at both ends is greater than the displacement in the middle.

Fig. 48 Pipe support at 0.25 x L When supporting the pipe at 22% of the pipe length, the displacement at both ends and in the middle of the pipe is equal. Forces are spread in an optimal way. A support position at 22% of the pipe length therefore gives the best result.

Fig. 49 Pipe support at 0.22 x L UV radiation Another vicious enemy of pipe coating is UV radiation. Damage caused by it is difficult to see with the naked eye. Serious consequences of UV radiation are addressed by Argent & Norman. In their paper an example is shown with severe coating embrittlement caused by UV radiation. Studies undertaken by Cetiner et al on fusion-bonded epoxy (FBE) coated pipes for the 3,700 km Alliance pipeline proved a loss in coating thickness and flexibility, and a loss of gloss with chalking as a result of degradation by UV degradation. Based on their results they conclude that pipes which are stored outside for longer than one year should be protected against UV degradation. This can be done by adding UV stabilizer additives to the coating or by shielding the pipes from direct sunlight with a pipe stack cover.

Pipe Clamps One tool that is seen at many locations is a clamp that connects pipe-ends in a stack. It is used to keep the pipes together and to prevent the stack from collapsing. As described earlier, the heavy pipes exert high forces on the pipes on the bottom. The clamps must be designed to handle these forces. Many clamps that are used in the field are not fit for purpose.

Fig. 50 Poor designed pipe clamp

Fig. 51 Twisted pipe clamp

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What proved to be the limiting factor in the design of a good pipe clamp, is the resistance to twisting. With 20 mm thick steel pipe clamps, tensile strengths over 80 kN were reached. With a safety factor of 2, that results in a safe working load of 40 kN. An example of a well-designed pipe clamp can be found in Figures 52-54

Fig. 52 Well designed pipe clamp

Fig. 53 Well designed pipe clamp

Fig. 54 Tensile test with pipe clamp When applying pipe clamps, the following should be taken into consideration: • In case the pipes have an internal coating, the pipe clamp should have a soft cover to prevent coating damage • For keeping a pipe stack together, do not rely on pipe clamps only! Make sure there is a good support system for the pipes. Pipe clamps can (accidentally) be removed, creating an unstable pipe stack and a dangerous situation • Choose a pipe clamp design based on calculations, not based on the feeling that it will be strong enough New pipe monitoring technology Logistic processes in the supply chain of line pipes are becoming more complicated, demanding and global. With today’s high value assets, it is important to reduce uncertainties and control the total project data management. A recent development, is the application of active radio-frequency (RFID) technology for identification and monitoring of pipes in the supply chain. Small tags, that are positioned in the pipe, actively measure location, movement, humidity, temperature and more. Other data, such as pipe numbers, can also be stored. Data is communicated through routers and a gateway in a self-organizing and healing mesh network. The central database is accessible by WiFi or ethernet through a connect-box. With such system all pipe data can be monitored by multiple users on any desktop computer or mobile.

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The technology offers more insight in logistic operations and more control, for example to optimize pipe storage buffers and reduce errors in pipe data. Important features of an intelligent pipe monitoring system: - Wireless technology, no cables necessary in the field (solar powered routers) - Easy to install, self-organizing, self-healing network - Low total cost of ownership - Long battery life of the tags (up to 5 years) - Reprogrammable - Uniform data output, such as XML streams, that can easily be processed in other software applications Possible functions of the pipe tag: - Localization - Identification - Movement alert - Battery alert - Temperature measurement - Humidity measurement - LED-light (flashes on command) - Additional data storage (1 MB)

Fig. 55 Schematic representation a RFID pipe monitoring system on a storage yard

Fig. 56 RFID pipe tags

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6.3.4.6 Pipeline Construction Once all the trouble of getting the pipes safely and damage-free to the construction site has been made, it would be a pity to waste all this effort and risk damaging the pipes at the last moment. Adequate equipment should be chosen during the final stages of the project for handling and support of pipes and preventing last-minute coating damage. An example of poor on-site practice in shown in Figure 56.

Fig. 56 Poor support of a pipeline in the field

6.3.4.7 Key message The key message of this chapter is that quality, safety and efficiency should be pursued during each step in the supply chain of line pipes in order to build a successful pipeline. A chain is only as strong as its weakest link. Control of the entire supply chain, including every movement of pipes is necessary. Active responsibility should be taken and cooperation sought with professional partners. Responsibility should not be rejected, it should be handed over. The choices that are made have consequences further along the way. The reader should not limit themselves to their own part in the supply chain â&#x20AC;&#x201C; they should make choices that contribute to a good quality in the end, by thinking ahead and feeling co-responsible for other processes in the supply chain. Good communication lines with other involved parties are essential for achieving this goal. A small extra investment in a good solution pays itself back in the long run. There are numerous examples where cost savings in the wrong areas led to more costs in the end. A conscious and wellconsidered choice for quality is always better than choosing for a poor solution only because it is cheap. Costs are usually calculated per project, but if a solution reduces risks and can also be used for future projects, it is worth making an extra investment.

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9. Welding (section to be developed) This important topic deserves a section of its own, yet to be developed.

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10. Non-Destructive Tests This chapter will describe the issues involved with non-destructive testing (NDT) of pipelines in the various stages of the project. The different stakeholders of the pipeline and their main concerns for completing the project are reviewed, followed by a discussion of the role of codes and standards in the design and building of pipelines. Finally, the chapter will cover the role of NDT in each stage: • The role of NDT in the FEL/FEED stages. • Vendor inspection and NDT at the material suppliers • Girth weld inspection during the construction stage • NDT during the use of the pipeline; considerations during the construction stage for future maintenance

10.1 The background of inspection – public safety In its most general definition inspection and NDT are a formal examination of the pipeline. Performing this examination is useful for a number of reasons. It may be useful to check on the work of contractors, or to check if a pipeline is still fit for purpose after a number of years. When viewed in the framework of national and international regulations, it is clear however that behind all this is the need for public safety. Although specific regulations are different in every country, the focus is often on the containment of hazardous materials and the safety of pressure systems. This is motivated by the need for public safety and is often the result of legislation that was implemented in response to tragic accidents. One example is the “Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006” in the USA, which was written in response to two incidents; a 1999 gasoline pipeline explosion in Bellingham, Washington, causing three fatalities, and $45 million in damage and also the 2000 natural gas pipeline explosion near Carlsbad, New Mexico, which killed 12 campers, including four children. Another example is the Seveso directive in Europe (Council Directive 96/82/EC) the first version of which was developed as a response to the release of a cloud of herbicides and pesticides from a chemical plant near the town of Seveso in Italy. As a result European legislation was passed in order to control major-accident hazards. In general terms, the structure of these regulations is that they mandate that a number of management systems need to be in place. An example of this is that in many countries it is now mandatory to have a pipeline integrity management system. These management systems are increasingly risk based; making an inventory of the threats to the pipeline, and deriving measures for prevention and/or reduction of the risk, and mitigation of the consequences. For the technical details both regulations and integrity management systems refer to technical codes and standards. These standards provide guidance for the NDT and inspection to be performed.

10.1.1 Codes and standards for inspection and NDT In the second half of the 18th century, industrialization had proceeded to the point that agreement was needed in industry to enable engineers to work together. Practices for making engineering drawings had to be agreed on, and some parts had to be specified to be interchangeable. The resulting standards enable that someone could buy a bolt on one side of the country, a nut on the other, and still have them fit together. Standards can be written by government departments, national and international standardization organizations like DIN and ISO and engineering societies like ASME and IEC. Some companies also independently write standards. From the oil and gas industry, the design and engineering practice (DEP) specifications of Shell are an influential example.

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An important driver for standards was that many countries saw a sharp increase in the number of steam boiler explosions in the 1880s. Governments of industrialized countries demanded that industry improve its safety record. As a response standards for the manufacturing and testing of boilers and pressure vessels were developed. In the USA this task fell to the American Society of Mechanical Engineers (ASME) which developed the Boiler and Pressure Vessel Code, today still the largest engineering standard. In Germany, the industry founded industry associations for inspection of pressure vessel which became the TĂźV association network. In the Netherlands, this task was given to a government department (Dienst voor het Stoomwezen) which by now has been privatized. The difference between a code and a standard is, that adherence to a standard is voluntary, while a code has been adopted by a government body and has the force of law. In the European context however, another word used for standards is â&#x20AC;&#x153;normâ&#x20AC;?, which is the name for standards in many European languages, and can refer to both legally-binding and voluntary standards. Currently another driver for standards development is that many insurance companies base their premiums on adherence to codes and standards.

10.1.2 The USA codes and standards system United States standards are used in many countries beside the USA, and are typically the most generally accepted standards. In the USA most standards are written by engineering societies. For non-destructive testing important engineering societies are the American Society of Mechanical Engineers (ASME) and American Petroleum Institute (API) which write the standards for many of the products tested; the American Society for Testing and Materials (ASTM) which specifies many of the tests performed; and the American Society for Non-destructive Testing (ASNT) which also specifies tests, and regulates the personnel certification in the USA. All of these standards organizations are affiliated with the American National Standards Institute (ANSI) which specifies the procedures for development of standards. American standards are developed in a consensus process. The committee meetings of a standards organization, which is comprised of engineers with knowledge and expertise in the particular field, have to be open to the public and must have representatives from all interested parties. Any comment on technical documentation must be considered in the approval process, and any individual may appeal to and demand actions from the committee. In the context of pipelines, this means that every stakeholder, is permitted to participate in the standards writing process, and can make sure that the standard is practical as well as meeting its purpose of specifying a practice that, if followed, results in a pipeline that is fit for purpose and safe for both the people working around it, and the general public

10.1.3 National standards systems Almost every sovereign country has its own standards system, which is now in the process of being harmonized. The organization of these systems is different in every country and for every industry. To give some examples, the standards for pressure vessels were written by government institutes in Germany and England, while they were written by industry committees in the Netherlands. In the nuclear industry, almost all standards are government controlled.

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The enforcement of standards is again something that is organized different in every country. For pressure vessels, in Germany this is performed by industry associations (TĂźV), while in the Netherlands and England it was performed by government agencies (Stoomwezen and HSE respectively). Under European harmonization, government inspection organizations have now been disbanded or privatized.

10.1.4 Harmonized standards In 2001 the Vienna agreement came into effect, in which technical cooperation between ISO and CEN (the European Committee for Standardization) is agreed. This agreement offers a route for European standards to become worldwide standards, although this is not automatic. Combined with the harmonization of standards in the common European market, this means that in the future many more standards will have a worldwide scope. For non-destructive testing, the ISO 9712 is an extension of EN 473, which specifies the personnel qualification for NDT. Another example is ISO 13847 â&#x20AC;&#x153;Petroleum and natural gas industries -- Pipeline transportation systems -- Welding of pipelinesâ&#x20AC;?, in which the NDT at pipeline construction is also specified.

10.2 Stakeholders in the pipeline project From the point of view of inspection and NDT, the pipeline project has a number of stakeholders that have different objectives. For the future pipeline owner, NDT is one of the ways to make sure the required quality is achieved. For the construction contractor it is a method to obtain feedback on the progress of various steps in the construction process. This section will review these stakeholders, the quality issues they face, and how inspection and NDT can help in addressing these issues.

10.2.1 The future pipeline owner For the future pipeline owner, the main reason to perform NDT and inspection is to demonstrate to his regulators that all the requirements that were specified for building the pipeline are met. At every stage of the production process checks are made to ensure the quality of the final pipeline, starting at the base material coming from the supplier, to the pipe forming process, and finally the welding in the field. The inspection and NDT results are also an important item in the information that needs to be compiled to obtain a complete overview of the as-build condition of the pipeline. This information will be stored for future reference, and used as the starting point for the pipeline integrity management process It is in the interest of the future pipeline owner to record and document each flaw in the pipeline.

10.2.2 The pipeline construction company For the company performing the welding on the pipeline, inspection and NDT is used to demonstrate performance and capabilities. NDT is used at various stages of the pipeline project. During the welding procedure qualification and the welder qualification, tests to verify the material properties are performed. These properties may have changed due to welding and need to be determined both in the base and weld material. The tests are typically tensile strength tests and nick break tests. NDT is performed to verify that no unacceptable weld flaws result from the welding process, and to verify the competence of the welders. These tests will typically be subcontracted to an NDT service provider.

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During the pipeline installation welds are tested as part of the quality control process. NDT can provide valuable feedback to the welders to make sure all of the parameters of the welding process are still within acceptable limits. For the pipeline contractor it is important to finish the project within time and budget. For this reason, unnecessary rejection of welds can put a strain on the project. Consequently, an important step is to determine how production welds will be judged. This can be done according to workmanship criteria, which are contained in pipeline codes, but it is often beneficial to perform a fitness for purpose analysis (often called an engineering critical assessment), as this may result in a more generous allowance for weld flaws, and consequentially fewer rejected welds. Nowadays, most pipeline welding standards allow for acceptance criteria based on engineering critical assessments.

10.2.3 The regulator In many pipeline projects there will be an independent third party which acts as the representative of the government or certification agency, whichever is appropriate for the local regulatory situation. This third party will primarily be checking if every part of the pipeline building process is performed in compliance with the specification and standards that were agreed upon and certify the pipeline accordingly. For the third party inspector, NDT and inspection are the eyes and ears that bring the information to make this judgment.

10.2.4 Conflicts of interest No contract is watertight, and every specification is to some extend open for interpretation. These interpretations may lead to conflicts around the pipeline. As explained above, the future pipeline owner will want every part of the pipeline to be of the highest quality possible, and the pipeline contractor wants as little disruption of the pipeline building process as possible. This may lead to a conflict of interests when flaws are found. As inspection and NDT is often the messenger bringing the news of whether the pipeline is accepted or not, the NDT technician may likely find himself to be the centre of such conflicts. Because of this is it important that NDT and inspection are performed transparently, inspection results are clear and that acceptance criteria are simple and recognized by all parties. Modern technology may be a big help in this. On top of this it is important to realize that NDT is not perfect. In industry trials it was determined that even the most advance NDT equipment finds only about 90% of the flaws present in pipeline welds, and traditional NDT methods such as film radiography (especially with isotopes) and manual ultrasonic testing may find as few as 50% of the defects present in a weld. NDT and inspection can be of great value in establishing a high quality pipeline, but at the current state of the art is no guarantee that no flaws are present.

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10.3 The NDT toolbox In this section the four most important NDT methodologies for pipelines are discussed. The basic principle will be explained, and the applications, advantages and disadvantages of each technique will be described. Where appropriate some future capabilities are also presented.

10.3.1 Radiography Industrial radiography is a method of testing for hidden flaws and defects in various types of materials with X-ray or gamma radiation. Industrial radiography is similar to medical X-ray technology in that a film records an image of an item placed between it and a radiation source. The basic principle of the process is fairly simple and common to all radiography applications. The radiation from a controlled source is allowed to penetrate the test item and expose a specially formulated film. As the radiation passes through the item, a portion of it is absorbed by the molecular structure of the material. The amount of radiation absorbed depends on the density and composition of the material. Simply put, the amount of radiation that passes through the item to expose the film depends on the density of the material. As cracks, fissures, and pockets in the material obviously have different densities, they will be characterized by different exposure values as more or less radiation penetrates at those points during exposure. The radiation used with radiography can be generated from various sources. The most common ways to generate the radiation are the use of an X-ray tube (see picture below), or the use of a radioactive isotope such as Iridium (Ir-192) or Cobalt (Co-60) which generates gamma radiation. Other sources, such as a particle accelerator are also possible, but will rarely be encountered at a pipeline. Before commencing a radiographic examination, it is always advisable to examine the component with one's own eyes, to eliminate any possible external defects. If the surface of a weld is too irregular, it may make detecting internal defects difficult. Defects such as planar cracks are difficult to detect using radiography, which is why some form of surface inspection (e.g. magnetic particle or dye penetrant inspection) is often used to enhance the contrast in the detection of such defects. The most common way to capture the image is silver halide film. The film is processed in a processing machine. The image will be a black and white photograph which needs to be viewed on a light box. Some image quality indicators will be attached to the film to have a reference for determining if the quality of the image is sufficient. Recently several digital options for capturing the image have become available. Some of these replace the film material with an image plate containing storage phosphor which can be read in a laser scanner, while other options use a direct digital detector.

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Top row from left to right; an x-ray tube, radiography film material, a film development machine and a radiography light box. Bottom; a practical example of a radiography film from manual welding. The fuzziness of the picture is typical of film results in practical situations. One of the big disadvantages of radiography is the fact that (fairly heavy) ionizing radiation is needed. Personnel performing radiography needs to be specifically trained for working with radiation and need to get a medical check-up regularly. Also, work areas need to be shielded or evacuated before radiography is performed. Industrial radiography is one of the last applications where silver-halide photographic materials are still used. The other main application that used this material was medical radiography. For this application however, the transition to digital radiography is nearly complete. Suppliers of film material have confirmed that the production of film material will at some point be discontinued. At the same time the raw material for radiography film includes silver, which recently has risen in price considerably (doubling from 2010-2011)

10.3.2 Ultrasonic testing Next to radiography, ultrasonic testing is one of the most well-known and applied NDT methodologies. Manual or automatic ultrasonic testing (MUT and AUT respectively) is used for different applications such as wall thickness measurements and defect detection in steel components or welds. Ultrasonic testing makes use of high frequency (ultrasonic) sound waves. Typically, the frequency range for most applications of these waves is 0.5 to 20 MHz. Under certain conditions, the ultrasonic waves can propagate freely through the material. Usually, the ultrasonic waves are generated by piezo-electric crystals or composites. When such a crystal is exposed to a mechanical vibration, an electric potential is generated. Vice versa, a mechanical vibration is generated when the crystals is subjected to an electric potential. Crystals with these characteristics are called transducers. In practice, the crystal is exposed to a short potential pulse causing the crystal to vibrate with a frequency bandwidth and directivity pattern characteristic for the crystal design.

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Typical cross country AUT inspection When the ultrasonic waves travel through a material, they will reflect or diffract (scatter in all directions) at boundaries or inhomogeneities in the material. Like an echo, the waves reflected from boundaries or inhomogeneities can travel back to the transducer. The transducer will start to vibrate when the waves are received and an electric signature can be recorded in a time-amplitude graph. The time of arrival relates to the distance between the point of reflection and the transducer. The amplitude of the signature relates the size of the inhomogeneity. The electric signature is called an A-scan. A-scans are the fundamental building blocks for data display and interpretation. Defects are mostly inhomogeneities in material and can be detected using this principle, also referred to as the well-known pulse-echo method. The direction in which the waves travel after reflection depends on the geometry of the inhomogeneity or boundary. The directivity pattern of the ultrasonic waves can be compared with a small beam like a laser pointer (typically being 2-3 mm wide, depending on the transducer design). When the reflected wave travels towards a different direction than the transducer, no signal will be received if the beam misses the transducer. Therefore, it is vital to understand the type of defect so that the transducers can be designed based on the expected defect characteristics, such as location, size, orientation and shape (planar or volumetric). For newly constructed welds, an overview of the different types of defects is presented in Figure 1.

Figure 1: An overview of different defects that may occur in newly constructed welds

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When ultrasonic responses are measured the results have to be evaluated. Responses caused by the irregular geometry of boundaries can usually be identified. Before the inspection starts, the geometry of the weld and the materials the weld and the pipe consist of, are known. Locations that cause responses are, for example, the weld reinforcements (cap and root, see Figure 1), clad layers or buffer zones. Since the positions of those locations are known, the concomitant signals can be identified by their travel times. Sometimes the travel time from a defect to the receiver is almost the same as the travel time from a boundary to the receiver. In this case the defect’s responses are masked. By using a data presentation of colour-coded stacked A-scans, a pattern appears as a result of the geometry. This data display method is called mapping, because the geometry responses are mapped as a pattern that can be recognized. Defects can be identified in the mapping display because they interrupt the pattern. When a response is received from a defect, its size may be evaluated from the amplitude height of the response. Defect sizing based on amplitude height of the ultrasonic signal usually is done with the help of a reference reflector with known characteristics and dimensions. Commonly used reflectors are bore holes, flat bottomed holes or notches. Relationships have been established to calculate a reflector’s diameter from the measured amplitude, given the probe characteristics, the distance of the reflector and the calibration amplitude. Diagrams are made from relationships, known as AVG curves (amplitude verstarkung grösse), DAC curves (distance amplitude correction) or sizing curves. In practice, the amplitude caused by a defect will be compared to the amplitude of a reference defect. Then the dimensions of the reference defect with the corresponding amplitude obtained from the curve are used as the defect size. Amplitude based sizing has got some disadvantages. Firstly, by using the dimensions of a corresponding reference reflector, the assumption is made that the shape of the defect is identical to the shape of the reference defect. Furthermore, the amplitude of a reflected signal is highly dependent on the orientation of the defect. The consequence can be that a large defect under a certain orientation is accepted because the amount of received energy is much lower than the total reflected energy. There are alternative methods for sizing that are not based on the amplitude height but rather are based on the travel times from waves that are diffracted at defect tips. The most common method is the time of flight diffraction method (ToFD). The transmitting and receiving transducers are placed in a so called pitch-catch configuration. The travel time from source to defect tip to receiver contains the location information of the defect. The ToFD technique is less dependent on defect orientation. When diffractions caused by the upper tip and lower tip are measured, reasonably accurate sizing is possible, depending on the frequency bandwidth of the signal. A disadvantage of the technique is the ‘dead zone’ caused by the direct wave traveling just below the surface, also called the lateral wave. Cracks connected to the surface are obscured by the lateral wave. The ToFD technique is widely accepted and special standards are available. In most practical situations a combination of pulse-echo techniques and ToFD techniques is used to increase the probability of detection of defects and to improve sizing by combining the results. Good results have been obtained with both the pulse-echo technique and ToFD techniques in controlled laboratory and field circumstances. Still, those results involve interpretation by experienced operators. Improvement of technologies can offer potential solutions for the limitations of defect detection, sizing and data interpretation. One such technology is based on ultrasonic phased arrays. Conventional transducers have fixed directivity properties for the ultrasonic beam. With a phased array transducer, the directivity properties such as beam angle and beam spread can be controlled with a computer. With this flexibility, advanced ultrasonic techniques are possible. Such advanced ultrasonic techniques have been studied and applied to make an image of a defect illustrating the defects characteristics with so called sectorial scans. Phased array sectorial scans are used successfully in medical imaging. With the development and miniaturization of ultrasonic array equipment, sectorial scans have become popular for industrial applications. Although the interpretation possibilities of data have improved with sectorial scans, the same drawbacks regarding defect shape and orientation remain.

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One of the disadvantages of automated ultrasonic testing compared to radiography is, that a validation of the performance of the ultrasonic set-up on the specific welding process used in the pipeline project is needed, and specific reference pieces (also called calibration blocks) made from the pipeline material need to be made. This is an additional cost, which is only offset by the higher productivity of ultrasonic testing on longer projects. An advantage of ultrasonic testing is, that it is more generally sensitive to all flaw types (i.e. planar flaws that are not detected readily with radiography) and that therefore engineering critical assessment methodologies for determination of acceptance criteria are possible (see above)

10.3.3 Magnetic flux leakage Magnetic flux leakage (MFL) is a magnetic method of non-destructive testing that is used to detect corrosion and pitting in steel structures, most commonly pipelines and storage tanks. The basic principle is that a powerful magnet is used to magnetize the steel. At areas where there is corrosion or missing metal, the magnetic field "leaks" from the steel. In an MFL tool, a magnetic detector is placed between the poles of the magnet to detect the leakage field. The leakage field is evaluated to determine damaged areas and to estimate the depth of metal loss

Figure 2a: Field lines of the magnetic field. Left: just the magnet, Middle: magnet with an undamaged plate, Right: magnet with a damaged plate

Figure 2b: Typical MFL in-line inspection tools. Typically, an MFL tool (a â&#x20AC;&#x153;smart pigâ&#x20AC;?) consists of two or more bodies. One body is the magnetizer with the magnets and sensors and the other bodies contain the electronics and batteries. The magnetizer body houses the sensors that are located between powerful magnets. The magnets are mounted between the brushes and tool body to create a magnetic circuit along with the pipe wall. As the tool travels along the pipe, the sensors detect interruptions in the magnetic circuit. Interruptions are typically caused by metal loss, which in most cases is due to corrosion. Mechanical damage such as shovel gouges can also be detected. The metal loss in a magnetic circuit is analogous to a rock in a stream. Magnetism needs metal to flow and in the absence of it, the flow of magnetism will go around, over or under to maintain its relative path from one magnet to another, similar to the flow of water around a rock in a stream. The sensors detect the changes in the magnetic field in the three directions (axial, radial, or circumferential) to characterize the anomaly. An MFL tool can take sensor readings based on either the distance the tool travels or on increments of time. The choice depends on many factors such as the

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length of the run, the speed that the tool intends to travel, and the number of stops or outages that the tool may experience. The second body is called an electronics box. This section can be split into a number of bodies depending on the size of the tool. This box, as the name suggests, contains the electronics or "brains" of the smart pig. The electronics box also contains the batteries and in some cases an inertial Measurement Unit (IMU) to tie location information to GPS coordinates. On the very rear of the tool are odometer wheels that travel along the inside of the pipeline to measure the distance and speed of the tool As an MFL tool navigates the pipeline a magnetic circuit is created between the pipe wall and the tool. Brushes typically act as a transmitter of magnetic flux from the tool into the pipe wall, and as the magnets are oriented in opposing directions, a flow of flux is created in an elliptical pattern. High field MFL tools saturate the pipe wall with magnetic flux until the pipe wall can no longer hold any more flux. The remaining flux leaks out of the pipe wall and strategically placed tri-axial Hall effect sensor heads can accurately measure the three dimensional vector of the leakage field. Given the fact that magnetic flux leakage is a vector quantity and that a Hall sensor can only measure in one direction, three sensors must be oriented within a sensor head to accurately measure the axial, radial and circumferential components of an MFL signal. The axial component of the vector signal is measured by a sensor mounted orthogonal to the axis of the pipe, and the radial sensor is mounted to measure the strength of the flux that leaks out of the pipe. The circumferential component of the vector signal can be measured by mounting a sensor perpendicular to this field. Earlier MFL tools recorded only the axial component but high-resolution tools typically measure all three components. To determine if metal loss is occurring on the internal or external surface of a pipe, a separate eddy current sensor is used to indicate the wall surface location of the anomaly. The unit of measurement when sensing an MFL signal is the Gauss or the Tesla. Generally speaking the larger the change in the detected magnetic field, the larger the anomaly Because the MFL method responds to both far side (FS, external surface) and near side (NS, internal surface) corrosion it is necessary to introduce a strong magnetic field into the component wall. The closer this field becomes to saturation for the component, the more sensitive and repeatable the method becomes. For typical steels this value is large, generally between 1.6 and 2 Tesla. In this range any residual magnetism from previous scans or operations will be eliminated during subsequent scans so that the resulting flux leakage signals remain relatively constant and repeatable. Working below the 1.6 Tesla level will still detect pitting on the first scan, but residual magnetism tends to cause a progressive deterioration of signal amplitude during subsequent re-scanning unless alternate scans are made from opposite directions. For a given magnet system the flux density achieved in the component will depend on the thickness and permeability of the material. The factor controlling flux density becomes one of plate thickness. There will be an upper thickness limit for each given magnet system above which the flux density will be too low to give adequate sensitivity to pitting. Centred between the poles of the magnet bridge and stretching the full scanning width of the system is an array of Hall effect sensors. These are spaced between centres to give optimum resolution and coverage. The sensing range of each sensor is sufficient to allow overlap with its neighbour. Hall effect sensors give a voltage signal proportional to the flux density of the field passing through the sensing element. If the sensing elements were to be arranged perpendicular to the surface, then it would be the tangential (horizontal) vector component that would be measured. There are advantages and disadvantages with these alternatives. The sensors are arranged to be close to but above the scanning surface to avoid wear and other mechanical damage during scanning.

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Although primarily used to detect corrosion, MFL tools can also be used to detect features that they were not originally designed to identify. When an MFL tool encounters a geometric deformity such as a dent, wrinkle or buckle, a very distinct signal is created due to the plastic deformation of the pipe wall There are cases where large non-axial oriented cracks have been found in a pipeline that was inspected by a magnetic flux leakage tool. To an experienced MFL data analyst, a dent is easily recognizable by trademark "horseshoe" signal in the radial component of the vector field. What is not easily identifiable to an MFL tool is the signature that a crack leaves. An MFL tool is known as an "intelligent" or "smart" inspection pig because it contains electronics and collects data real-time while travelling through the pipeline. Sophisticated electronics on board allow this tool to accurately detect features as small as 1 cm by 1 cm. MFL technology has evolved to a state that now makes it an integral part of any cost effective pipeline integrity program. Although high-resolution MFL tools are designed to successfully detect, locate and characterize corrosion, a pipeline operator should not dismiss the ability of an MFL tool to identify and characterize dents, wrinkles, corrosion growth, mechanical damage and even some cracks

10.3.4 Magnetic Particle Inspection This method is suitable for the detection of surface and near surface discontinuities in magnetic material, mainly ferritic steel and iron. The principle is to generate magnetic flux in the object to be examined, with the flux lines running along the surface at right angles to the suspected defect. Where the flux lines approach a discontinuity they will stray out into the air at the mouth of the crack. The crack edge becomes magnetic attractive poles North and South. These have the power to attract finely divided particles of magnetic material such as iron filings. Usually these particles are of an oxide of iron in the size range 20 to 30 microns, and are suspended in a liquid which provides mobility for the particles on the surface of the test piece, assisting their migration to the crack edges. However, in some instances they can be applied in a dry powder form. The particles can be red or black oxide, or they can be coated with a substance which fluoresces brilliantly under ultra-violet illumination (black light). The object is to present as great a contrast as possible between the crack indication and the material background. The technique not only detects those defects which are not normally visible to the unaided eye, but also renders easily visible those defects which would otherwise require close scrutiny of the surface. There are many methods of generating magnetic flux in the test piece, the simplest one being the application of a permanent magnet to the surface, but this method cannot be controlled accurately because of indifferent surface contact and deterioration in magnetic strength. Modern equipment generates the magnetic field electrically either directly or indirectly. In the direct method a high amperage current is passed through the subject and magnetic flux is generated at right angles to the current flow. Therefore the current flow should be in the same line as the suspected defect

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If it is not possible to carry out this method because of the orientation of the defect, then the indirect method must be used. This can be one of two forms: • Passing a high current through a coil which encircles the subject. • Making the test piece form part of a yoke which is wound with a current carrying coil. The effect is to pass magnetic flux along the part to reveal transverse and circumferential defects. If a bar with a length much greater than its diameter is considered, then longitudinal defects would be detected by current flow and transverse and circumferential defects by the indirect method of an encircling coil or magnetic flux flow. Subjects in which cracks radiating from a hole are suspected can be tested by means of the threading bar technique, whereby a current carrying conductor is passed through the hole and the field induced is cut by any defects. Detection of longitudinal defects in hollow shafts is a typical application of the threader bar technique. The electricity used to generate the magnetic flux in any of these methods can be alternating current, half wave rectified direct current or full wave rectified direct current. A.C. generated magnetic flux, because of the skin effect, preferentially follows the contours of the surface and does not penetrate deeply into the material. Normally, to ensure that a test piece has no cracks, it is necessary to magnetise it in at least two directions and after each magnetising and ink application process visually examine the piece for crack indications Magnetic crack detection equipment typically takes two forms. Firstly, for test pieces which are part of a large structure, or pipes, heavy castings, etc. which cannot be moved easily, the equipment takes the form of just a power pack to generate a high current. This current is applied to the subject either by contact prods on flexible cables or by an encircling coil of cable. These power packs can have variable amperages up to a maximum of 2000 Amps for portable units, and up to 10,000 Amps for mobile equipment. The indicating material is applied by means of a spray and generally the surplus runs to waste. For factory applications on smaller more manageable test pieces the bench type of equipment is normally preferred. This consists of a power pack, an indicating ink system which recirculates the fluid, and facilities to grip the work piece and apply the current flow or magnetic flux flow in a more methodical, controlled manner. The work pieces are brought to the equipment and can be individually tested in one operation. This type of universal equipment is ideally suited to either investigative work or routine quality control testing. These bench type equipments often incorporate a canopy to prevent direct light falling on the subject so that ultra-violet fluorescent material can be used to the best effect. The indicating particles may be suspended in very thin oil (kerosene) or water. In some circumstances the indicating medium can be applied dry These equipments are suited to production work and in certain circumstances can be automated to the extent of loading, magnetizing, inking and unloading. The work pieces still have to be viewed by eye for defect indications. Specialized equipments are also frequently manufactured to test a particular size and type of test piece. Advantages of magnetic particle crack detection: • Simplicity of operation and application. • Quantitative. • Can be automated, apart from viewing.

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Disadvantages of are: â&#x20AC;˘ Restricted to ferromagnetic materials. â&#x20AC;˘ Restricted to surface or near-surface flaws. â&#x20AC;˘ Not fail safe in that lack of indication could mean no defects or that the process was not carried out properly.

10.3.5 Dye Penetrant Inspection Dye penetrant inspection or liquid penetrant inspection (LPI) is used on non-porous metal and non-metal components to find material discontinuities that are open to the surface and may not be evident to normal visual inspection. The part must be clean before inspection. The basic purpose of dye penetrant inspection is to increase the visible contrast between a discontinuity and its background. This is accomplished by applying a liquid of high penetrating power that enters the surface opening of a discontinuity. Excess penetrant is removed and a developer material is then applied that draws the liquid from the suspected defect to reveal the discontinuity. The visual evidence of the suspected defect can then be seen either by a colour contrast in normal visible white light or by fluorescence under black ultraviolet light. The penetrant method does not depend upon ferromagnetism like magnetic particle inspection, and the arrangement of the discontinuities is not a factor. The penetrant method is effective for detecting surface defects in non-magnetic metals and in a variety of non-metallic materials. The method is also used to inspect items made from ferromagnetic steels and its sensitivity is generally greater than that of magnetic particle inspection. The method is superior to unaided visual inspection but not as sensitive as other advanced forms of tests for detection of in-service surface cracks. The major limitation of dye penetrant inspection is that it can detect only those discontinuities that are open to the surface; some other method must be used for detecting subsurface defects. Furthermore surface roughness or porosity can limit the use of liquid penetrants. Such surfaces can produce excessive background indications and interfere with the inspection. The method can be used on most pipeline parts and assemblies accessible to its application

10.4 NDT during the FEL stage 10.4.1 Stress and strain based designs This section covers how different terrain situations will lead to different type of pipeline designs with different NDT acceptance criteria. Examples are flat country and hill country. It is generally recognized that pipelines are the safest and most economical mode to transport large quantities of liquid oil and gas. Most existing pipelines have been designed according to codes, which are based on limiting the stress in the construction and service phase of the lines. These stress-based design codes are widely used and considered as safe and conservative. An alternative for the conservative stress-based design method is the less widely used strain-based design method. The strain-based design method takes advantage of well-known steel properties.

10.4.1.1 Stress-based design Steel pipelines design codes were originally developed in the USA. The first codes were ASME/ANSI

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B31.4 for Liquid Petroleum Transportation and B31.8 for Gas Transmission and Distribution Pipeline Systems. As oil and gas was discovered around the world, countries and companies developed their own standard, but used ASME as a good practical basis. The pipeline codes used (maximum) design factors. Design factor is hoop stress/material yield strength. For oil pipelines no account was taken for population density in the location of the pipeline; a typical design factor was 0.72. For gas lines account was taken of population density. This resulted in lowered design factors in populated areas down to 0.3 resulting in thicker pipe. The advantages of stress-based design are: • Simple and established; • Accepted by regulatory authorities; • Historical failure data shows safe pipelines. The disadvantages of stress-based design are: • Overly prescriptive design rules, leaving less freedom for design engineers; • Prescribed unknown safety factors (e.g. conservative input SMYS) • Many parts of codes are based on historical decisions and data (not recognizing new and safer materials (e.g. higher steel grade, toughness, coatings) • Cannot easily accommodate new technology (e.g. using distributions as inputs and not a minimum value like minimum wall thickness) • Specific parts of codes differ from country to country (resulting in wall thickness changing at border crossings)

10.4.1.2 Strain-based design Strain-based design is a design method that places a limit on the strains at the design condition rather than the stresses. The methods using strain allow selected extensions to the stress-based design possibilities to take advantage of steel’s well-known ability to deform plastically, but remain a stable structure. Strain-based design is used for many situations for pipelines where the loadings from forces, other than the internal pressure can be the largest generators of stress and strain in the pipe wall. Such loadings can be generated by soil subsidence, frost heave, thermal expansion and contraction, landslides, pipe reeling, pipe laying, and several other types of environmental loading. Designing based on strain for these cases has an advantage over designing based on stress because these loadings tend to apply a given displacement rather than a given force to the pipe.

10.4.1.2.1 Parent pipe requirements for strain based-design When designing pipelines that may experience high axial strains during installation or in-service it is important to ensure that the parent pipe materials have adequate strength and ductility. All pipe material standards specify minimum yield and tensile strength requirements for each pipe grade. However, while all pipe material standards specify minimum properties, many standards do not place limits on maximum properties. As a result, pipe ordered to a specific pipe standard might exhibit tensile properties well above the minimum requirements. This can give rise to a range of problems including: • Reduced Y/T ratio (decreased work hardening) • Reduced elongation to failure • Weld material may unintentionally be of lower strength then the parent material

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10.4.1.2.2 Girth weld strength requirements for strain-based design It is generally accepted that pipeline girth weld should overmatch the tensile properties of the pipe material to avoid excessive strain accumulation in the girth weld during pipeline laying or normal operation. This is generally achieved by selecting weld consumables that produce higher tensile properties than the pipe material. In selecting welding consumables for pipeline applications it is important to consider the variability in both parent pipe and weld metal tensile properties. While most welding codes require overmatched welded joints, there are a number of reasons why excessive overmatching should be avoided, particularly for high strength line pipe.

10.4.1.2.3 Girth weld toughness requirements for strain-based design It is now common practice to specify minimum toughness requirements for pipeline girth welds to ensure adequate resistance to brittle and ductile fracture. Minimum toughness requirements are generally determined by conducting fitness-for-service assessments assuming the worst case loading condition and the maximum permissible flaw size.

10.4.1.2.4 Engineering critical assessment methods for strain-based design (of girth welds) Engineering critical assessment (ECA) is primarily used in strain-based design to assess the allowable flaw size for inspection or to check that the material toughness is sufficient for a given flaw size. The methods are applied to both girth- and seam-welded areas based on the engineering understanding of brittle and ductile fracture and plastic collapse. The design process for girth-welded pipelines that can experience high applied strains will usually need to include an ECA to demonstrate that the choices made regarding the girth weld area provide sufficient resistance to fracture under the peak strains. The methods that are used for the ECA must be applicable to the situation. Todayâ&#x20AC;&#x2122;s situation in ECA methods is that routine methods are available for strains up to the yield strain in tension and extensions of these methods have been used for higher strain, although the methods have not become routine standard methods. As the strain in the pipe design is increased up to 2% strain and beyond, very few methods are available and these methods may not cover all the required behaviour.

10.4.1.2.5 Inspection by AUT of strain-based designed pipelines The use of ECA for stress-based designs leads to safe weld defect acceptance criteria provided NDT is capable of detecting and sizing critical defects. Automated ultrasonic testing (AUT) has come a long way and is currently the most advanced inspection technique for inspection of girth welds. To ensure safe strain-based pipeline design and construction, the applied AUT needs a high probability of detection (POD) and defect sizing capabilities. High POD precision and defect height and length sizing is a must for strain-based pipeline girth weld defect acceptance

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10.5 NDT at the material supplier and vendor inspection Non-destructive testing (NDT) is a key technology in all modern pipe mills. The concept is one where particular techniques are specified according to the expected type of discontinuities inherent to the process route selected for pipe manufacture. The NDT regime is determined primarily by a combination of line pipe standard and client purchaser specification, with due consideration given to the available technologies at the pipe manufacturer’s mill and their associated limitations. This section describes the various NDT regimes currently in use for different line pipe manufacturing routes, and briefly highlights the key aspects of each technique

10.5.1 Submerged Arc Welded Pipe 10.5.1.1 Feed stock The first area to address for submerged arc welded (SAW) pipe is the feedstock. The feedstock forms the body of the line pipe and must be checked for internal soundness if it is intended to carry high pressure gas. The usual method for checking for internal soundness is via compression probe ultrasonic testing by either a manual ultrasonic testing (MUT) or automated (AUT) technique. International standards such as API 5L/ISO 3183 and DNV OS-F101 are very specific regarding the requirements for feedstock checking; specifically designed standards for MUT/AUT checking such as ISO 12094 or ASTM A578 are referenced, along with specific minimum area coverage requirements (e.g. 20%) and maximum acceptance criteria for both body and edges. For helically welded pipe (SAWH), the norm is to apply the feedstock AUT at the pipe mill just after forming and welding due to the inherent difficulties involved with AUT testing in the coil plate mill. However for longitudinally welded pipe (SAWL), most modern producers of line pipe steel will have the AUT applied at the plate mill via a sophisticated automated system. This system uses specially designed calibration plates with appropriate reflecting targets to set the sensitivity and coverage requirements of the standards. As mentioned above, SAWH mills will conduct the feedstock AUT regime required by the standard/specification to the agreed requirements but in pipe form. The same principles apply in that coverage and acceptance criteria are guaranteed by prescribed scanning/oscillating patterns and appropriate calibration reflectors. It is important to note that most automated systems do not make a qualitative judgment; they merely identify indications that have breached a sensitivity threshold. When this happens, MUT is usually applied to finally ‘size’ the indication and evaluate acceptance or rejection, although there are some systems in place which combine detection with interpretation and acceptance/rejection.

10.5.1.2 Weld Seam Once in pipe form, the next NDT requirement is to confirm the quality of the SAW weld. Again, an AUT system is the norm in this case. As detailed at the start of 10.5, the aim is to generate a calibration block within a section of pipe that recreates typical and expected discontinuities. This block is usually created by removing a section of pipe weld and introducing a series of notches, holes or ceramic inserts which represent typical defects. It is then reinserted into the donor pipe and forms a calibration pipe which is used to set up the AUT system (static calibration) and confirm the ongoing validity of the initial set up (dynamic calibration). The initial set up is the responsibility of qualified experts (Level 3 in UT) to define the requisite probe configuration, angles and frequencies to best be able to detect the reflecting targets in the calibration pipe.

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It is at this stage that the subtleties of weld seam AUT become important; factors such as the amount of additional sound energy applied to ensure safe calibration, and the sensitivity of couplant monitoring systems can all directly influence the integrity of the AUT set up. If there is too great a level of sensitivity, the system will produce many spurious indications which will serve to undermine confidence and productivity by requiring an inordinately high volume of MUT or radiographic testing (RT) to confirm. On the other hand, a lack of sensitivity may allow a reject able discontinuity to be passed and so affect confidence from a different perspective. The international standards mentioned above have addressed these issues and a standard approach has been developed which most operators are happy to apply. In addition to the AUT system, there are a number of other techniques also applied for the weld seam. As detailed before, the AUT system only detects indications; all such areas are recorded and sprayed for identification. These areas of concern are then checked by RT or MUT or both. The selection of RT or MUT is usually controlled by a manufacturer defined decision tree and by reviewing which AUT probe system detected the indication. It is here that a differentiation between RT and MUT should be made. RT is a non-volumetric check (unless stereoscopic RT is being considered) – it simply looks down in plane view, and a discontinuity with an acceptable cross section in plane view could have an unacceptable depth to it. Conversely, MUT does enable a definition of depth, but doesn’t provide a readily reviewable record of the inspection such as a radiographic image. The AUT systems in place around the world all tend to have an area where coverage is limited; this is usually at the start and end of inspection where the probes have to drop down/lift up. Such areas are usually covered by mandatory MUT and/or RT. Finally, there are a number of periodical, complementary tests which are performed on the weld metal. Specific tests for shallow surface breaking discontinuities which are undetectable by the AUT system can be specified. The appropriate techniques for this inspection are magnetic particle inspection (MPI) or other magnetic flux based system, and eddy current inspection (ECI). These techniques are specifically focused on detecting surface breaking discontinuities, but are not easily automated and are time consuming. If specified, these checks are normally performed on just the start and end areas of the weld, or on the full weld length of one or two pipes per production shift to maintain practicality. Careful consideration of whether this inspection applies to the internal and external surface must be made due to access issues with performing the test inside the pipe. The other occasionally required inspection is to check for delayed hydrogen cracking. This feature can appear after the main AUT inspection has taken place; industry practice recognizes that it can take up to 48hrs after welding for any cracks to appear. In this case, one or two pipes per shift are held back for 48hrs from welding and MUT is applied with a probe specifically designed (45°) to detect the typical delayed hydrogen crack (the so-called chevron crack). It is clear that these additional checks have practical limitations, and only in the event of discovery of such features is the inspection frequency raised to try and encapsulate the issue.

10.5.1.3 Pipe Ends The final area where NDT is applied for SAWH or SAWL pipe is at the pipe ends. The ends of the weld area have already received various inspections as detailed in 10.5.1.2 above, so the focus is now on the parent material. Typical requirements that are codified within such standards as DNV OS-F101 require that the bevel face receives a full circumferential MPI check, and that the final 50mm of pipe material at each end receives a compressive probe MUT or AUT check for laminations. This UT test can be conducted from the inside or outside, and can also be supplemented with a shear wave (45°) MUT/AUT check for cracks and other non-lamellar features.

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The importance of the pipe ends is obvious; this is where the critical girth welds will be performed, so the acceptance criteria at the pipe ends is sometimes more stringent than would be the case for the pipe body.

10.5.2 Seamless Pipe Due to the manufacturing processes involved with seamless pipe, feedstock inspection is unnecessary. The absence of a weld also makes for a conceptually simpler approach, and the basis of inspection is still complex automated systems. For seamless material, it is better to consider each applicable technique rather than each part of the pipe.

10.5.2.1 AUT Systems The AUT system is usually a rotary probe system; a standard pipe with machined targets (notches/holes etc.) is scanned by a system of probes that spin around the pipe (or the pipe spins around them). These systems are usually quite complex and perform in a similar way to the AUT systems for the weld seam of SAWH/SAWL material. The required targets are oriented, sized and positioned to represent typical discontinuities (usually controlled by international standard and occasionally by purchaser specification), and specific probes are set up to target their detection. The targets are placed on the external and internal surfaces, and oriented to represent transverse, longitudinal or lamellar flaws, and the target sizes, probe settings and system sensitivity set the criticality of the regime. A complex interpretation system is commonly used to define acceptance or rejection; there still exists an option to determine final acceptance via an MUT check of an AUT system detection as is the case with SAWH/SAWL material. During the AUT check, it is also quite common for seamless pipe to also be full-body checked for wall thickness by a compressive probe. This provides a large volume of data and therefore confidence in the thickness control of the seamless material. The rotation of the probe assembly and the probe distribution are carefully designed to ensure that 100% coverage of the pipe surface is achieved by each of the variously targeted probes for the given throughput speed.

10.5.2.2 Surface Testing Systems The limitation of UT techniques to detect shallow surface breaking features is well known and has been discussed in the section on SAWH/SAWL material. As a result, seamless pipe producers have developed systems that can perform a full body surface test on both the internal and external surfaces. The techniques commonly used are either magnetic flux leakage (MFL), eddy current (EDI) or MPI based systems, and the approach is the same as for AUT in that representative targets are located in a calibration pipe/block and the system must be able to detect each required target. As previously, the targets have sizes, locations and orientations that are controlled by the international standards which work together with the system sensitivity settings to define how critically the inspection will be conducted. As with AUT systems, alarms and sprays can be used to identify indications and acceptability is either determined within the automatic nature of such systems, or is decided by manual prove up using an appropriate surface detection technique (e.g. MPI).

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In line with the welded products, there are often complementary inspections for surface testing which can see the full body (usually only the external surface) receiving 100% MPI for a small proportion of pipes. This has practical limitations, and is usually seen as part of a procedure qualification process.

10.5.2.3 Pipe Ends As stated previously, the pipe ends are critical to the integrity of the field girth weld, and extra inspection and tighter acceptance criteria are usually applied. The pipe ends of seamless material often require the same inspections as the ends of welded material. Indeed, most international standard define the requirements for pipe ends independent of the manufacturing process.

10.5.3 Electric Welded Pipe (e.g. ERW/HFW) Electric resistance welded (ERW)/high frequency induction welded (HFW) material is primarily checked by UT techniques; MPI or EDI is not normally specified. However, MFL techniques can be specified for the detection of some longitudinally oriented discontinuities in the pipe body. The presence of a weld zone within the product means that there are separate systems for inspecting the body and weld areas.

10.5.3.1 Pipe Parent Material As for SAWH material, the coil feedstock is usually checked in pipe form. The difference for ERW/HFW material compared with SAWH material is the use of a full body rotary probe system. Again, target reflectors are introduced to the calibration pipe and a combination of compression and shear probes can be used to search for lamellar or longitudinal discontinuities in the parent material. As for all the other AUT techniques, the size, location and orientations of these targets are often controlled by international standards and specifications so as to define system sensitivity/robustness. The scanning pattern and probe spacing etc. define the area coverage achieved, which is also usually specified within standards and specifications. An additional specific check of the parent material adjacent to the weld is also usually made. While this is usually performed in plate form for SAWL material, for ERW/HFW material an additional set of AUT probes focus on a zone of parent material usually around 15mm wide either side of the weld. This area normally has more stringent acceptance criteria, and so different reflective targets are required to ensure sufficient sensitivity. The probes used for this part of the inspection are not rotary; they are fixed.

10.5.3.2 ERW/HFW Weld Area Typically, only longitudinal indications are found within the ERW/HFW weld; this is a function of the size of the weld zone in an ERW/HFW pipe. The width is to all extents and purposes infinitely small as the weld has no filler material and is in fact a fusion line; the available width for a transverse indication to manifest itself over is therefore very small. Nevertheless, AUT systems are designed to scan the full depth of the weld and are calibrated in the regular manner via representative targets being detected when passing the calibration pipe through. The systems in place around the world range from those requiring MUT prove up and those that rely on the AUT system to reject or accept.

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10.5.3.3 Pipe Ends The pipe ends of ERW/HFW pipe are treated in the same manner as the pipe ends of seamless and SAWH/L pipe; please see the relevant sections.

10.5.4 Limitations of NDT Techniques As discussed previously, some detection techniques have limitations; RT is non-volumetric, UT does not necessarily produce a permanent record and struggles with shallow surface breaking defects, and MPI is slow and labour intensive. In short, there is no, one perfect system. A blend of techniques, with deployment as appropriate is the best solution. One must also address the question of detectability; what many engineers would consider implicit is an unobtainable ‘ideal’. No pipe will be free from discontinues; steel is not a fully homogenous material and welding is not a perfect science. A particular NDT regime comprising different techniques, coverage and sensitivity can be described as having a high probability of detection (POD), but cannot be said to have a 100% POD. Certain discontinuities may only be discernable to techniques that are limited in application frequency due to practical concerns; it is considered to be more accurate to say that a pipe has no ‘detectable’ discontinuities after passing through a prescribed NDT regime. The pipe may contain discontinuities that were not readily detectable by the techniques employed.

10.5.5 Other Vendor Inspections Aside from the various NDT techniques described above, there are other inspections that are necessary; in the main, this means visual inspection. This is a sometimes overlooked area of inspection, as it is a fundamentally subjective view, with human influence always being present. It is important to recognize some key aspects of visual inspection: • Fully trained inspection team, with direct experience and awareness of the appearance of each type of typical feature • Sufficiently assured eyesight abilities (via regular testing) • Sufficiently illuminated viewing areas • Robust procedural control of where and when to look Careful selection of various inspection points in the process is also critical; when the product is potentially changed and new features are possibly introduced, re-inspection is necessary to reaffirm the product compliance.

10.6 NDT in the field – weld inspection How to inspect pipeline girth welds and what to inspect for: choice between ultrasonic testing and radiography.

10.6.1 AUT inspection technique on pipelines Application of automated ultrasonic testing on pipeline welds is advancing rapidly through new innovations in AUT technology. AUT is replacing radiographic inspection techniques as the industry

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standard for inspection of pipeline welding and is recognized as the quickest, most reliable and beneficial weld testing method available.

10.6.1.1

AUT Inspection Principle

Pipeline AUT uses fully automated ultrasonic equipment travelling circumferentially around the pipe girth weld on a welding (guide) band in a linear scan, with the array pulsing to cover all the weld zones. An electric motor drives the scanner and an encoder measures positions around the circumference. The vertical cross-section of the weld is divided into approximately equal sections (zones,) with the height of each zone roughly equal to the height of a single welding pass. Each zone is assessed by a pair of ultrasonic search units (probes) on either side of the weld, the total of these ultrasonic search units called an array. The probe array is in a fixed position with respect to the weld centreline, resulting in a series of pulse-echo probes with their beams positioned to intersect the weld bevel centred on each vertical zone. To ensure that the ultrasound energy and reflected signals are transferred from the probe to the pipe surface, water is used as a couplant or in freezing climates; a water methanol mix is used. The ultrasonic information from the scanner / probe array is transferred to a computer through an umbilical cable. The computer is used for data presentation and analysis and is housed inside a 4WD vehicle. A trained ultrasonic technician / operator evaluates the returning data and assesses the results. The display consists of multiple strip charts where each strip represents a specific zone on either side of the weld. Each strip displays both signal amplitude and also the time-in-the-gate for defect location in the weld. This allows more accurate interpretation as to the vertical height of a flaw or indication and its position within the weld, whether lack of fusion on the weld bevel or a volumetric type flaw within the weld body. To establish a reference point as to the start of the weld bevel and be able to assess the vertical height of an indication, the system is calibrated on a calibration block made out of identical pipe material using surface notches and/or side-drilled holes to represent weld imperfections on the weld fusion line, each zone having a dedicated reflector. For each pipe diameter, wall thickness and weld bevel design a specific project specific calibration block is used. Step by step AUT inspection • After weld bevel preparation and prior to fit-up/welding, a scribe line is put on the pipe end to be used as a reference line for the position of the guide band relative to the weld centreline. • After welding, the OD surface on both sides of the weld is cleaned of weld splatter to allow proper coupling of the ultrasonic probes to the pipe surface. • The weld is identified and marked with a unique number prior to inspection. • The zero point, (usually top centre,) and the direction of the scan are clearly marked on the pipe. • The guide band is placed around the pipe using the scribed line as a reference for exact position in relation to the weld centreline. • A calibration on the cal block is performed to establish the start of the weld bevel and the required inspection sensitivity. • The scanner is placed on the guide band, at the zero datum point described in point 4. • A scan is performed over the entire weld circumference using the unique weld ID number for weld identification and as part of the filename. • Evaluation is performed in real time as the scanner moves around the circumference of the pipe. • Data is stored immediately following final evaluation and determination as to weld acceptability dependant on client specification or code.

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• Rejectable welds are documented and can be reported immediately following the weld scan. Defects are identified in the data file and file is stored. • During data analysis by the ultrasonic technician, the scanner technician will remove the scanner and guide band, and prepare for the next weld or calibration as required

10.6.1.2

Applications

10.6.1.2.1 Onshore Mainline This is usually a 4 man crew able to scan up to 200 welds in a 12 hour working day; smaller crews may be applied when production rates are lower. Welders are provided with immediate results due to the AUT crew being able to remain approximately 3 to 5 welds behind the capping crew. When automatic welding is used process control is a key factor with this near instant feedback with results which assists in keeping the repair rate as low as possible. Furthermore with the ability to size flaws vertically, relative to height and depth, an ECA may be applied to further reduce unnecessary repairs. The inspection cycle involves mounting the scanner, scanning, analysing, removing the scanner and driving to the next weld. This can usually be performed in around four (4) minutes on large bore pipes up to 42" or larger diameter pipe.

10.6.1.2.2 Onshore Tie-ins This consists of a 2 man crew able to scan as many as 20 to 30 welds per day dependant on accessibility of the welds, geographic location and diameter. Tie-ins are manual welds that are only accessible on the outer diameter (OD) of the pipe and where results are desired immediately due to open excavations that could need to be closed as soon as possible. The crew is generally able to provide results immediately on final completion of the weld scan as opposed to the long exposures and development times needed for a radiographic tie-in crew.

10.6.1.3

Advantages of AUT as opposed to Radiographic inspection

• Engineered critical assessment (ECA) criteria vs. a good workmanship criteria can be applied which can avoid unnecessary repairs, due to zonal discrimination and the ability to size flaw height and depth. • Process control can be applied with far more accuracy as to the nature and cause of the imperfection and with quicker feedback to the welding crew. • Higher probability of detection. • Weld to weld inspections generally of 5 minutes or less. • No radiation hazards – reduced HSE issues. • Real-time and computer-aided analysis increases productivity and accuracy. • All digital data archived electronically eliminating the need for huge filing and archiving rooms to store film. • Digital data archiving allow emailing of weld scans to allow next day assessment by clients or project management and audit. • The AUT systems are deployed on the OD of the pipe only as compared to a radiographic crawler which must enter the ID of the pipe. This avoids possible delays due to crawlers being stuck, as well as time spent with crawler battery changes each shift.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 10

10.6.2

Radiography inspection technique on pipelines

Application of radiographic approach to inspect pipelines was the preferred inspection method in the past until the arrival of ultrasonic inspection technique. It is however doubtful that automated UT will ever supplant radiography due to the relative simple application and relative low cost.

10.6.2.1

Inspection Principle

A source of radiation is placed on one side of the pipe and a recording medium (film) is placed on the other side. It is based on the ability of X-rays and gamma rays to pass through metal to obtain photographic records of the transmitted radiant energy. All materials will absorb known amounts of this radiant energy and, therefore, X-rays and gamma rays can be used to show discontinuities and inclusions. As the X-ray absorption coefficient depends strongly on material density, radiography is particularly effective at detecting volumetric defects, which have either extra mass or less mass (such as porosity or slag inclusions).Thus, the radiation that reaches the film in a potential flaw area is different from the amount that impinges on the adjacent areas. This produces on the film a latent image of the flaw that, when the film is developed, can be seen as an “indication” of different photographic density from that of the image of the surrounding material. Digital Radiography is one of the newest forms of radiographic imaging. Since no film is required, digital radiographic images are captured using special phosphor screens containing micro-electronic sensors. Captured images can be digitally enhanced for increased detail and are easily archived as they are digital files. Real-Time Radiography (RTR): is the latest application for inspecting pipelines that allows electronic images to be captured and viewed in real time allowing cycle times of 4 minutes or less like AUT. Step by step radiographic inspection • Weld will be identified by client with a unique number prior to inspection. • Surface area will be cleaned to avoid masking of any imperfections. • Zero point and direction of scan will be clearly marked on pipe. • Location markers shall be placed around the pipe for circumferential reference • Films shall be clearly identified by lead numbers, letters or flash cards, or any other method for identification • Film is placed in the desired location • A source of radiation is put in place and activated for a set time • Radiation is shut down and film is removed • Film is developed in a dark room and evaluated for film quality and weld imperfections • Film is stored immediately • Rejectable welds are documented and can be reported immediately

10.6.2.2

Application

10.6.2.2.1 Onshore Mainline This is usually a 4 man crew using an internal crawler; smaller crews may be applied when production rates are lower. The X-Ray Crawler is similar to conventional radiography however an x-ray source tube on a crawler device is run inside the pipe to each weld. Film is wrapped around the welds and the source tube is excited. The film is then developed in a mobile dark-room on location. The technique is

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quick and can inspect on average 150 welds per day. The advantages of x-ray crawlers are their speed and the short exposure time. The quality of the image is far better due to the x-rays passing through less material compared to conventional radiography. The disadvantages are that the tool must be run into the pipe and the testing must be performed a significant distance from the welding crews for radiation safety and the potential risk of risk of crawlers being stuck in the pipe.

10.6.2.2.2

Onshore Tie-ins

This consists of a 2 man crew able to inspect up to 15 welds per day depending on diameter, wall thickness and accessibility of the welds. Tie-ins are manual welds that are only accessible on the OD of the pipe. The x–ray film is placed on the external surface of the pipe section to be inspected and the x– ray source is placed against the pipe wall on the opposite side. This way, the section of the weld joint is radiographed through two walls. Multiple exposures are needed to cover the entire circumference of the pipe that may result in a relative long period of time before the weld quality can be evaluated.

10.6.2.3 • • • • •

Advantages opposed to AUT inspection

More sensitive at detecting volumetric imperfections Less coating cut back required Able to inspect materials that are not suitable for ultrasonic inspection Able to deal with relatively large wall thickness variations Requires no dedicated calibration or reference blocks resulting in less preparation time

10.7 Future developments

10.7.1 Ultrasonic Imaging techniques A new ultrasonic array technology for direct imaging of subsurface defects (2D & 3D visualization of welding defects) makes use of advanced algorithms that reconstruct the image of the defect from signals received from multiple detectors. Examples of these techniques are IWEX and sampling phased array. Both in new construction and in service, detection, sizing and, characterization of defects are essential for integrity assessment of metal components and welds. Ultrasonic non-destructive testing using pulse echo technique or Time of Flight Diffraction (ToFD) has been proven to be reliable approaches to assess weld integrity. However, quantitative defect characterization with pulse-echo remains challenging because the signal caused by the reflection at the defect is very dependent on defect orientation. ToFD has sizing capabilities, but only limited capabilities in flaw characterization. In phased arrays inspection, the image obtained from sectorial scans cannot be directly related to defect size and orientation. Data display and interpretation are not straightforward and require operator skill and experience. A better and more reliable ultrasonic inspection would be achieved if a methodology would be used that allows direct imaging of defects. These new imaging techniques have the potential to image welding defects in 3D, giving absolute values for the orientation, length and height. This will enable the NDT result to be interfaced more directly with fracture mechanics calculation, potentially allowing more accurate determination of acceptance or non-

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acceptance of the weld. An example of what an image would look like is shown below, showing three perspectives (a though c) of the same defect.

10.7.2

3D Radiographic inspection

10.7.2.1

Future of radiography

In normal photography almost all pictures and cameras are now digital. Similarly, radiography is become more and more digital. There are a number of ways in which digital radiography can be performed, each with their advantages and disadvantages. A distinction is made between computer radiography, where the film is replaced by an image plate, and digital radiography where the image is directly captured on a digital detector array. In the future it will also be possible to produce a 3D image of weld flaws, using topographic reconstruction.

10.7.2.2

Computed radiography

Computed radiography (CR) uses very similar equipment to conventional radiography except that in place of a film to create the image, an imaging plate (IP) made of photo-stimulable phosphor is used. The imaging plate is housed in a special cassette and placed under the body part or object to be examined and the x-ray exposure is made. Hence, instead of taking an exposed film into a darkroom for developing in chemical tanks or an automatic film processor, the imaging plate is run through a special laser scanner, or CR reader, that reads and digitizes the image. The digital image can then be viewed and enhanced using software that has functions very similar to other conventional digital imageprocessing software, such as contrast, brightness, filtration and zoom.

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An advantage is that no processing chemical and silver based films are used, and that radiation levels and exposure times are typically much lower than needed with film radiography. The replacement of film by the image plate is very straightforward, and the process in the field will hardly change at all. For weld radiography however, it is very hard to find an image plate and scanner than offers sufficient image quality. Also at the high resolution needed for weld radiography the scanner time will become very long. Additionally although image plates are reusable, they are sensitive to scratching, and combined with manual handling in this field this may lead to problems.

10.7.2.3

Digital Radiography

Digital radiography is a form of x-ray imaging, where digital X-ray sensors are used instead of traditional photographic film. Digital radiography (DR) is essentially filmless X-ray image capture. In place of X-ray film, a digital image capture device is used to record the X-ray image and make it available as a digital file that can be presented for interpretation, making real time interpretation of welds possible. Digital Radiography can achieve the same image quality as film radiography. The advantages of DR over film include immediate image preview and availability, a wider dynamic range which makes it more forgiving for over- and under-exposure as well as the ability to apply special image processing techniques that enhance overall image display. The largest motivator to adopt DR is its potential to reduce costs associated with processing, managing and storing films. Crew sizes for radiography can be significantly reduced. A disadvantage of digital radiography in the field is that a big and heavy manipulator is needed to move the x-ray tube and detector around the pipe. In this sense the operation of digital radiography is very similar to automated ultrasonic testing.

10.7.2.4

3D radiography

An even more advanced development is the use of topographic reconstruction to make 3 dimensional images of weld flaws. The feasibility of this technology has been demonstrated in the detection and sizing of flaws in nuclear components. The detector needed is very similar to the one used in digital radiography discussed above, but additionally to make a scan along the weld, and additional motion across the weld is needed. Of cause this increases scan time considerable, but it gives an unprecedented image of weld flaws, and could be directly linked to fracture mechanics calculation, further simplifying the process of accepting welds.

10.8

Concluding remarks

In this chapter the use of NDT in pipeline construction was presented. NDT uses a number of techniques to ensure the integrity of pipelines in every stage of a pipelineâ&#x20AC;&#x2122;s lifecycle. In the FEL stage NDT is used to check the assumptions of the pipeline design. At the pipe factory many tests are done to the surface, weld seams and the pipe ends. In the field the girth welds are tested. All of this is to ensure that the pipeline is fit for purpose, conforms to codes and standards and is safe for the general public. In the future, new imaging techniques will make an even better assessment. NDT ensures that everyone involved in the pipeline project can rest assured that the pipeline is sound.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

11. Pipeline Protection Systems Pipeline integrity for durations well above the nominal 25-35 years of service is an important aspect in any pipeline’s design, construction and operation. Pipelines should not fail during their entire service life because such failures could lead to human and economic costs. As the public’s perception of pipeline failures is (generally) much worse than the actual human and economic failure costs, considerable resources have been dedicated to protect the pipes against any potential damage that could lead to pipeline failure. As the majority of installed and planned onshore transmission pipelines around the world are steel pipelines, this document will focus on the protection of steel pipes. In order to ensuring a service life without failure, we need to apply a life-cycle approach to the steel pipe protection, so that we avoid damage and failure during all the steel pipe’s life stages: • Pipe transportation – from pipe mill or coating facility to temporary storage yards or to the right-of-way • Pipe handling – loading, unloading at different locations • Pipeline installation – stringing, lowering in, backfilling • Pipeline service life until decommissioning The industry has been trying for decades to target the most common causes of onshore pipe damage and failure. In this context, the statistical data available for the onshore transmission pipeline systems – both gas and liquids – show that mechanical impact damage (including third-party damage and construction/repair damage) and external corrosion represent the cause for between half and two-thirds of the reported onshore pipelines incidents and failures1. Corrosion is an electrochemical phenomenon that leads to the degradation of the steel pipe material and could ultimately cause pipeline failure. There are multiple ways of preventing corrosion or protecting the pipe against it, such as the use of corrosion-resistant alloys, steel pipe design corrosion allowance, external anti-corrosion coatings and cathodic protection (CP) systems. Some prevention and protection systems are called passive systems, such as external anti-corrosion coatings for line pipe (discussed in Section 11.1), the field joint area (Section 11.2) and for other pipeline components such as bends and fittings (Section 11.3), whereas others are considered active prevention and protection systems, such as the cathodic protection systems (discussed in Section 11.8). Mechanical damage can be sustained when the steel pipe suffers an external impact or penetration from rocks, outcrops, construction equipment (excavators, backhoes, drills), other pipe joints etc. There are multiple ways of preventing mechanical damage and protecting the pipe and its coatings, such as pipeline above-ground markers, call-before-you-dig numbers, sand bedding and padding, concrete coatings, mechanical padding with select backfill etc. The most common mechanical protection systems are reviewed in section 11.4. Internal coatings are used to increase the flow efficiency for natural gas pipelines and to mitigate corrosion damage to the steel pipe. The most common internal coating systems are reviewed in section 11.5.

For onshore pipeline incident information, please see the reports and statistics published by government agencies such as the US Pipeline and Hazardous Materials Safety Administration (PHMSA), the US Department of Transportation Research and Special Programs Administration, industry associations such as Association of Oil Pipe Lines (AOPL), Conservation of Clean Air and Water in Europe (CONCAWE), as well as other sources such as “Transmission Pipelines and Land Use: A Risk-Informed Approach”, Special Report 281, US Transportation Research Bureau, 2004 or “Subsea Pipeline Engineering”, Palmer, A.C., King R.A., 2004.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

More recently, onshore insulation systems have been developed for the external anti-corrosion protection and thermal insulation of pipelines operating at temperatures ranging from 85°C up to 650°C. These systems generally include a corrosion resistant coating, a thermal insulation layer and an outer jacket or protective topcoat and are discussed in Section 11.6. In order to avoid the floatation phenomenon in onshore wet environments (such as lakes, river crossings or swamps) the industry has developed solutions to mitigate the pipeline buoyancy phenomenon. These solutions are based on the extensive experience in mitigating the pipeline buoyancy phenomenon offshore and are discussed in Section 11.7. Finally, as mentioned above, steel pipes and coatings can be damaged during each stage of the supply chain, including pipe handling (loading, unloading) and installation (stringing, lowering in), storage and transportation. Section 11.9 discusses risks and available solutions during these logistic operations.

11.1

Review of Key Mainline External Anti-Corrosion Coatings

The purpose of the mainline external anti-corrosion coatings is to isolate the pipe steel from the external environment (soil, air and water) and thus to protect the steel from corrosion damage that could lead to failure. The mainline coatings protect the whole length of the steel pipe except for the variable-length area where two pipes are joined – this area is usually protected by separate field joint coating solutions (assessed in the next section). The mainline external anti-corrosion coatings can be categorized using several criteria: • Coating materials – powder systems (based on epoxy resins), polyolefin systems (polyethylene, polypropylene), liquid systems, other materials (asphalt, coal tar) Except for the single-layer coatings, all the others usually have a primer layer (closest to the steel), one or more topcoat layer and sometimes an adhesive between two coating layers • Application method – electrostatic spraying, extrusion, liquid spraying, liquid painting, tapewrapping, hybrid application (electrostatic spraying/extrusion) Other categories are starting to be used, based on new criteria such as application temperature ranges, operating temperature ranges etc. The most widely used coatings in the industry are reviewed in the following sections. The list of coatings described below is not exhaustive, as other mainline external anti-corrosion coatings are also used in the onshore pipeline projects, but on a more limited scale. Appendix 11.1 provides a table comparing the strengths and weaknesses of the mainline coatings described below.

11.1.1

Fusion-Bonded Epoxy (FBE)

Fusion-bonded epoxy (FBE) coatings are thin film coatings based on epoxy-resin powder materials. Thickness and other coating configuration requirements can be found in the new EN ISO 21809-2 standard, as well as CSA Z245.20. Most FBE coatings are rated for operating temperatures up to 85°C in dry conditions and 65°C in wet conditions, but new products have been developed and are currently developed for higher operating temperatures. FBE coatings were separately developed in Europe and North America and are usually applied in specialised coating facilities in powdered form by electrostatic spraying. The pipes are pre-heated and then blast-cleaned. The pipe surface is then inspected for any defects and the pipe is then washed and rinsed. Induction heating then brings the pipe to the temperature required for the spraying of the epoxy powder. The epoxy particles flow, melt and bond to the steel.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

The next step is to cool down the pipe through water quenching. Finally, the pipe is inspected for coating defects (known as holidays) and then loaded out for storage.

Fig.1 – Fusion bonded epoxy (FBE) external coating FBE coatings have undisputed benefits for the users. They offer excellent corrosion protection and excellent adhesion properties. FBE coatings are very flexible, resistant to soil stresses and have good handling characteristics. They are usually used in pipeline projects that have standard requirements – i.e. do not have challenging terrain configurations, soil types, climatic conditions, exposure to water/moisture or harsh storage and handling conditions. For the external anti-corrosion field joint coatings that are most commonly used with FBE mainline external anti-corrosion coatings please see section 11.2.

11.1.2

Dual-Layer Fusion-Bonded Epoxy (2L FBE)

Dual-layer fusion-bonded epoxy (2LFBE) coatings are also based on epoxy-resin powders. Their thickness and minimum technical performance requirements are standardized in CSA Z245.20. Like the single-layer FBE coatings, most dual-layer FBE coatings are rated for temperatures up to 85°C in dry conditions. Dual-layer FBE coatings are usually made of a fusion-bonded epoxy primer, similar to the coatings in section 11.1.1 and, depending on the targeted application, a tougher FBE topcoat, usually called abrasion-resistant overcoat (ARO), or a high operating temperature FBE topcoat. The application process for dual-layer fusion-bonded epoxy coatings is very similar to the one for singlelayer FBE coatings, with the two FBE layers being sprayed successively, and also takes place in a specialised coating facility.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

Fig. 2 â&#x20AC;&#x201C; Dual-layer FBE (2LFBE) external coating Dual-layer FBE coatings are usually used in specialty applications that require high abrasion resistance, such as horizontal directional drilling (HDD) projects and offer improved handling, as well as higher abrasion and impact resistance than single-layer FBE coatings. Other dual-layer FBE coatings are used for high operating temperature environments where increased flexibility is considered a benefit. For the external anti-corrosion field joint coatings that are most commonly used with dual-layer FBE mainline external anti-corrosion coatings please see section 11.2.

11.1.3

Three-Layer Polyethylene (3LPE)

Three-layer polyethylene (3LPE) mainline coatings are multilayer anti-corrosion systems consisting of a layer of fusion-bonded epoxy primer, a polyethylene-based adhesive layer and an outer layer (topcoat) of polyethylene. Their thickness and minimum technical performance requirements are the subjects of multiple industry and international standards such as DIN30670, NFA49711, CSA Z254.21 and the upcoming EN ISO 21809-1 (draft). Most 3LPE mainline coatings are rated for operating temperatures of up to 85Â°C. 3LPE coatings are applied in specialised coating facilities. The pipes are pre-heated and then blastcleaned. The pipe surface is then inspected for any defects and the pipe is then washed and rinsed. Induction heating then brings the pipe to the temperature required for the spraying of the epoxy powder of the primer. The epoxy particles flow, melt and bond to the steel. The polyethylene-based adhesive and then the polyethylene topcoat are then successively extruded on the rotating pipe. The next step is to cool down the pipe through water quenching. Finally, the pipe is inspected for coating defects (holidays) and then loaded out for storage.

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Fig. 3 – Three-layer polyethylene (3LPE) external coating Each of the three 3LPE coating layers adds specific technical performance characteristics to the final coating system: the FBE primer offers excellent adhesion to the steel substrate, as well as an excellent corrosion resistance potential; the adhesive bonds the epoxy primer to the polyethylene outer layer; and the polyethylene topcoat offers very good damage resistance, making the whole coating system tougher, more durable and resistant to environment factors such as moisture penetration. 3LPE coatings are used in projects that present technical challenges, such as rough storage or handling conditions, challenging backfill material or harsh climatic conditions. For the external anti-corrosion field joint coatings that are most commonly used with 3LPE mainline external anti-corrosion coatings please see section 11.2.

11.1.4

Three-Layer Polypropylene (3LPP)

Three-layer polypropylene (3LPP) mainline coatings are multilayer anti-corrosion systems consisting of a layer of fusion-bonded epoxy primer, an adhesive layer and an outer layer (topcoat) of polypropylene. Their thickness and minimum technical performance requirements are the subjects of multiple industry and international standards such as DIN30670, NFA49711, and the upcoming EN ISO 21809-1 (draft). Most 3LPP mainline coatings are rated for operating temperatures of up to 110° C. The application process for three-layer polypropylene (3LPE) coatings takes place in a specialised coating facility and is very similar to the one for 3LPE coatings – described in section 11.3 – with the epoxy primer being applied by electrostatic spraying on the induction-heated rotating pipe, followed by the application of the adhesive layer and the extrusion of the polypropylene top layer.

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Fig. 4 â&#x20AC;&#x201C; Three-layer polypropylene (3LPP) external coating Each of the three 3LPP coating layers adds specific technical performance characteristics to the final coating system: the epoxy primer offers excellent adhesion to the steel substrate, as well as an excellent corrosion resistance potential; the adhesive bonds the epoxy primer to the polypropylene outer layer; and the polypropylene topcoat offers very good damage resistance, creating the most durable and damage-resistant plant-applied external anti-corrosion coating systems. 3LPP coatings are used in projects that present technical challenges, such as rough storage or handling conditions, challenging backfill material or harsh climatic conditions. For the external anti-corrosion field joint coatings that are most commonly used with 3LPP mainline external anti-corrosion coatings please see section 11.2.

11.1.5

Three-Layer Composite Coatings

Three-layer composite mainline coatings are multilayer anti-corrosion systems. As an example, a threelayer composite coating system currently supplied for onshore pipeline projects consists of a layer of fusion-bonded epoxy primer, a specially formulated polyolefin adhesive layer that achieves a strong chemical bond with the FBE primer and a fused mechanical bond with the topcoat, and an outer layer (topcoat) of polyethylene. The thickness and minimum technical performance requirements of the threelayer composite external coatings are the subjects of multiple industry and international standards such as CSA Z245.21, and the upcoming EN ISO 21809-1 (draft). Existing three-layer composite mainline coatings are rated for operating temperatures of up to 85Â° C. Three-layer composite coatings are applied in specialised coating facilities. The pipes are pre-heated and then blast-cleaned. The pipe surface is then inspected for any defects and the pipe is then washed and rinsed. Induction heating then brings the pipe to the temperature required for the spraying of the primer epoxy powder. The epoxy particles flow, melt and bond to the steel. The polyolefin-based adhesive and then the polyethylene topcoat are then successively sprayed on the rotating pipe. The next step is to cool down the pipe through water quenching. Finally, the pipe is inspected for coating defects (holidays) and then loaded out for storage.

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Fig. 5 â&#x20AC;&#x201C; Example of a 3-layer composite external coating Each of the three layers of the three-layer composite coatings adds specific technical performance characteristics to the final coating system: the epoxy primer offers excellent adhesion to the steel substrate, as well as an excellent corrosion resistance potential; the adhesive bonds the epoxy primer to the outer layer; and the topcoat offers very good damage resistance, creating a very durable coating system. Like 3LPP and 3LPE coatings, three-layer composite coatings are used in projects that present technical challenges, such as moisture penetration, rough storage or handling conditions, challenging backfill material or harsh climatic conditions. For the external anti-corrosion field joint coatings that are most commonly used with three-layer composite mainline external anti-corrosion coatings please see section 11.2.

11.1.6

Tape Coatings

Tape mainline coatings are multilayer anti-corrosion systems. As an example, a tape coating system consists of a layer of liquid epoxy primer, an adhesive layer, and an outer layer (topcoat) of polyethylene. The thickness and minimum technical performance requirements of a tape coating system are described in DIN30670. Existing tape mainline coatings are rated for operating temperatures of up to 60Â°C. Tape coatings are applied in specialised coating facilities or in the field. The pipes are blast-cleaned, then the pipe surface is inspected for any defects. The pipe is then washed and rinsed. The epoxy primer is usually applied in liquid form (painting, brushing). The adhesive layer is then applied. The polyethylene topcoat tape is finally wrapped on the pipe. Finally, the pipe is inspected for coating defects. Tape coatings are used in certain markets in projects that need good damage resistance. For the external anti-corrosion field joint coatings that are most commonly used with tape mainline external anti-corrosion coatings please see section 11.2.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

11.2

Field Joint Anti-Corrosion Coating Selection Guide

High performance pipeline corrosion protection and insulation coatings have been developed to meet the demanding requirements of current pipeline operating and field conditions. A variety of pipelinecoating technologies are available and selection has evolved along geographical lines. These coating decisions are generally based on the owner-company or engineering company preferences, but also on the pipeline construction and operating conditions. As an example, coating damage is a real concern in regions where limited transportation infrastructure, rough pipe handling, aggressive backfills and high populations are prevalent. This creates the need for robust, multi-layer coatings. Once the coated pipe is delivered to the right-of-way and pipeline welding begins, then application of the field joint corrosion protection must commence. There are several types of commercially available external anti-corrosion and insulation field joint coatings. For the purposes of this document, the specific types of field joint coatings have been identified as being most suitable for use with the various mainline coatings. Aside from the mainline coating compatibility the criteria for determining which field joint coating to use encompass a number of variables. Pipe diameter, operating temperature, construction conditions, backfill, soil conditions and contractor capabilities all affect coating choice. Appendix 11.2 outlines the various mainline anti-corrosion coatings along with the most suitable field joint coatings and relevant standards. While mainline coatings are applied in consistent factory environments, field joint coatings are applied in a variety of conditions which the photos below depict.

Fig. 6 â&#x20AC;&#x201C; Application of field joint coating protection in desert conditions In desert conditions, sand storms and huge day/night temperature fluctuations present special problems.

Fig.7 â&#x20AC;&#x201C; Application of field joint coating protection in cold climates Cold climates require additional equipment and expertise to deal with the low temperature construction conditions.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

The paragraphs below provide a brief description of the most common onshore anti-corrosion and thermal insulation field joint coatings in use today.

11.2.1

Fusion Bonded Epoxy (FBE)

Fusion-bonded epoxy (FBE) coatings are thin film coatings based on epoxy-resin powder materials. They can vary in thickness depending on specification and be applied as single layer or dual layer coatings. For the purposes of field joints, FBE is only recommended for use with FBE mainline coatings due to the high pre-heat temperatures required by certain FBE materials, which could damage other types of mainline coatings. Prior to application, the field joint must be blast-cleaned to minimum Sa 2.5 and inspected for soluble salt contamination. Induction heating is then used to bring the field joint cutback to the temperature required for the application (typically 240ºC) of the epoxy powder which is flocked on using manually held or semiautomatic spray nozzles/application equipment. The field joint is allowed to cool naturally or through water quenching. Finally, the field joint is inspected for thickness and coating defects such as holidays and then readied for burial.

Fig. 8 – Field-applied FBE joint coating

11.2.2

Two-Layer Polyethylene Heat-Shrinkable Sleeve (2LPE HSS)

These types of heat-shrinkable sleeves have been commercially available since pipeline coatings applied in manufacturing plants became commonplace in the early 1960s. They consist of a cross-linked and stretched polyethylene sheet coated with a mastic or butyl-based adhesive resulting in the 2-layer system. The application is direct to metal with surface preparation requirements varying from simple hand wire brushing to commercial blasting. No primers are required. Application is done by preheating the field joint to a specified temperature (typical maximum of 80ºC), wrapping the sleeve around the field joint, securing a closure strip and heat-shrinking the sleeve using suitable propane or natural-gas-fuelled torches.

Fig. 9 – 2-layer sleeves ready for application

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11.2.3

Three-Layer Polyethylene Heat-Shrinkable Sleeve (3LPE HSS)

Three-layer polyethylene heat-shrinkable sleeve systems consist of an epoxy primer and a heatshrinkable sleeve. In rare cases, the epoxy primer can be a fusion bonded epoxy but, more commonly, a 2-component, liquid epoxy. The heat-shrinkable sleeve consists of a cross-linked and stretched polyethylene sheet coated with a hot-melt, hybrid or polyethylene-based adhesive layer depending on the pipeline design service temperature. The field joint must be blast-cleaned to minimum Sa 2.5 and inspected for soluble salt contamination. If the soluble salt levels are deemed as being too high, then remedial measures to remove the contamination and re-blast will be required. Application is done by preheating the field joint to a specified temperature, applying the liquid epoxy primer to the steel cutback, force-curing the epoxy primer (typically 90 - 120ºC) then wrapping the sleeve around the field joint, securing a closure strip and heat-shrinking the sleeve using suitable propane or natural-gas-fuelled torches. Preheating and force-curing stages may be done with either induction heating or gas-fuelled torches.

Fig. 10 – 3-layer heat-shrinkable sleeve graphic

11.2.4

Fig. 11 – Completed and tested 3-layer HSS

Three-Layer Polypropylene Heat-Shrinkable Sleeve (3LPP HSS)

Three-layer polypropylene heat-shrinkable sleeve systems consist of an epoxy primer and a heatshrinkable sleeve. The epoxy primer is a 2-component, liquid epoxy. The heat-shrinkable sleeve consists of a cross-linked and stretched polypropylene sheet coated with a polypropylene-based adhesive layer. The field joint must be blast-cleaned to minimum Sa 2.5 and inspected for soluble salt contamination. If the soluble salt levels are deemed as being too high, then remedial measures to remove the contamination and re-blast will be required. Application is done by preheating the field joint to a specified temperature, applying the epoxy primer to the steel cutback, force-curing the epoxy primer (typically heating to 175ºC), then wrapping the sleeve around the field joint, securing a closure strip and heat-shrinking the sleeve using suitable propane or natural-gas-fuelled torches. The force-curing stage must be done with induction heating.

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Fig.12 – 3-layer polypropylene sleeve application

11.2.5

Three-layer Polypropylene Field-Applied Systems (3LPP, IMPP, FSPP)

Systems consist of a polypropylene tape or sheet (3LPP Tape), flame-sprayed powder (FSPP) or injection-moulded polypropylene (IMPP). Each of these systems consists of a fusion-bonded epoxy primer, a powder applied polypropylene adhesive and an outer layer of polypropylene applied by wrapping, spraying or injection moulding. All of these systems are applied using specialised application equipment. The methods of application may be proprietary to the service company and generally require specialised equipment and highly-trained applicators.

11.2.6

Adhesive Tape Systems (CAT)

Tape coatings are multilayer anti-corrosion systems. As an example, a tape coating system consists of a solvent-based liquid primer, an adhesive layer, and an outer layer (topcoat) of polyethylene. These systems often use two types of tapes such as a soft first layer for corrosion protection and a tougher second layer for mechanical protection.

11.2.7

100% Solids, 2-Component Liquid Epoxy or Polyurethane (2CLE, 2CPU)

Commonly referred to as “liquids”, most liquid coatings in use for pipeline protection are either 100% solids, 2-component epoxies or polyurethanes. The 2 components are “base (or polyurethane: polyol)” and “cure (or polyurethane: isocyanate)” parts, sometimes referred to as Part A (base) and Part B (cure). The base and cure must be formulated to work together and mixing a base from one manufacturer and cure from another is not possible. The cure component is formulated to impart various cure times depending on type of application and application environmental conditions. Liquid epoxies are formulated using a variety of epoxy raw materials. A few high performance epoxies have operating service temperatures up to the 130ºC range. Liquid epoxies are applied to field joints of FBE-coated pipelines and appear to be most companies’ choice for pipeline rehabilitation projects. Polyurethane coatings are generally used as pipeline coatings for ambient temperature water pipelines or for lower operating service temperature conditions. Liquid coatings are usually available in sprayable and brushable formats. The spray versions generally have a much faster set-up time and very limited “pot-life”. The extended pot-life of the brushable version provides adequate time for the applicator to mix and brush-apply the coating onto the pipeline section.

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Fig. 13 – Liquid epoxy brush application

11.2.8

Pre-Insulated Pipe Onshore Field Joint Sealing and Corrosion Protection Selection Guide

The purpose of the field applied joint coating system is to maintain the continuity of the mainline coating across pipe connection points. In the case of pre-insulated pipes the field joint coating systems are required to provide not only anti-corrosion continuity but also thermal protection continuity. Moreover, similarly to the mainline pre-insulated coatings, the insulating materials used in the joints usually have to be isolated from the environment and therefore most joint protection systems used with thermally protected pipes are designed to provide sealed, jacketed protection across the adjoining jacketed mainline coated pipes. The most common insulating materials used on pre-insulated pipes are polyurethane (PU) foams, mineral wools and more recently aero gels. The insulation is either supplied to the field in the form of half-shells or wrap-around blankets or, in the case of PU foams, it can be moulded on the pipe and filled or “foamed” at the job site. The insulation materials are rated through measurable methods such as the thermal conductivity coefficient, compressive strength, density, thermal life expectancy and operating temperature. The selection of the pre-insulated field joints is governed by the operating environment of the pipeline (ex. above/below ground), geographical location, and operating temperature of the pipeline, pipe diameter, construction conditions, backfill method, soil conditions, contractor’s capabilities and required in-process testing. The paragraphs below provide a comprehensive summary of the most common pre-insulated pipe field joint coating systems.

11.2.9

Heat-Shrinkable Casing System

The heat-shrinkable joint casing systems consist of an expanded high-density polyethylene (HDPE) casing which is attached to the mainline polyethylene jacket using either a hot melt adhesive or electrofusion process. There are several variations of heat-shrinkable casing systems and they can be categorized using the following criteria: • Material type: cross-linked vs non-cross-linked HDPE • Application method: foam-in-place* vs pre-foaming (*casing used as a mould for field-injected PU foams) • Casing sealing method: adhesive vs electrofusion • Secondary sealing requirement: collar sleeves The method and complexity of field installation as well as functional performance of the product are unique to each variant of the heat-shrinkable casing system. Appendix 11.2 contains a comparative table describing the strengths and weaknesses of the above described casing systems.

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11.2.9.1

Cross-linked Heat Shrinkable Casing Systems

Cross-linked heat shrinkable casing systems are the most technologically advanced joint protection systems used with PU foam based pre-insulated pipe systems. As the name suggests these types of joint systems consist of cross-linked high density polyethylene (HDPE). Cross-linking of HDPE enhances the functional performance of the material and enables fast and simple field application of the product. One of the most notable features of the cross-linked material is its stability in hot climates. Cross-linked heat shrinkable casing systems do not pre-shrink due to the exposure to summer-like conditions as is the case with non-cross-linked casing systems. There are several variants of cross-linked heat shrinkable casing systems available on the market. Some system designs allow the casings to be used as a mould during field injection of PU foam in addition to performing their primary function of sealing and mechanically protecting the joint. Other options include inspection of the foam before sealing the joint off (see figure 14 below). There are also systems which allow field testing to verify the seal performance. The seal between the adjoining polyethylene jacket pipes is primarily achieved through hot melt adhesives. Figure 14. “Foam in place” vs “pre-foamed” pre-insulated cross-linked joint casing systems “Foam in Place”

“Pre-Foamed”

The sequence of the application steps for cross-linked joint casing system depends on the type of system: foam in place vs pre-foaming. In the case of foam in place systems, the casing is secured over a joint before the foam is injected into the cavity. The first step of the application includes preparation of the PE surface on the adjoining PE jacket pipes. The second step consists of pre-heating the jacket pipe, using suitable propane of natural-gas-fuelled torches, and wrapping the adhesive around the jacket pipes. The next step consists of centrally locating the casing over the joint and shrinking the applicable sections with suitable torches as described above. Upon verification of the proper installation of the casing, appropriated PU foam material is injected into the cavity formed by the casing. In the case of the pre-foamed joint casing systems, the foaming of the cavity is completed as the first step of the system application. Removable external moulds are used to form the foaming cavity. The casing is applied after the foam is inspected and the application of the casing follows the same general steps as the foam in place systems.

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Figure 15: Typical pre-insulated pipeline joint coating operations

11.2.9.2 Non Cross-linked Heat Shrinkable Casing Systems Non cross-linked heat shrinkable casing systems consist of expanded polyethylene tubes. Most projects involving these casing systems use them as moulds during field injection of PU foam in addition to their primary function of sealing and mechanically protecting the joints. Application of this type of casing is relatively slow, compared to cross-linked casing systems, and therefore shrinking of the entire casing (as is the situation with the pre-foamed casing systems) is impractical. Additionally, these casings have a tendency to pre-shrinking on the pipes when exposed to summer temperatures. Pre-shrinking makes the casings unusable as they cannot be moved over the joint. Another shortcoming of the non-crosslinked casing systems is their inability to maintain geometrical conformance to the shape of the pipe they embrace. To counter the relaxation of non-cross-linked casing systems, heat-shrinkable cross-linked collar sleeves are used on both ends of such casings. The application of a non-cross-linked casing starts with the preparation of the PE surface on the adjoining PE jacket pipes. The second step consists of pre-heating the jacket pipe, using suitable propane or natural-gas-fuelled torches, and wrapping the hot melt adhesive around the jacket pipes. Alternatively, instead of preheating the adjoining PE jacket pipes and applying the adhesive strips, electro-fusion system components are wrapped around the adjoining jacket pipes. The next step consists of locating the casing over the joint and shrinking the applicable sections with suitable torches as described above. In the case of electro-fusion systems, after the shrinking step, the sides of the casing are then fused with the adjacent jacket pipes. Upon verification of the proper installation of the casing, an appropriate amount of PU foam material is injected into the cavity formed by the casing.

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Figure 16. Non-cross-linked joint casing systems with protective collars.

11.2.9.3 Heat-Shrinkable Sleeve Systems Heat-shrinkable sleeve systems consist of cross-linked and stretched polyethylene sheets coated with adhesive layers. These systems are only applied on joints which have been pre-foamed using external removable moulds or where PUF half shells are used to provide the insulation at the joints. The application consists of pre-heating the adjoining polyethylene jacket pipes, wrapping the sleeve around the pipe, securing a closure strip and heat-shrinking the sleeve with suitable propane or naturalgas-fuelled torches. Compared to casing systems, heat-shrinkable sleeve systems provide inferior mechanical protection continuity for pre-insulated pipe joints.

Figure 17. Cross-linked heat-shrinkable sleeve installed on a pre-foamed joint of a PUF pipeline

11.3 – Bends and Fittings 11.3.1 Application of Polyolefin Coatings Bends and fittings are typically protected from external or internal corrosion by liquid coatings such as polyurethane or epoxy, or by polyolefin coatings applied by two different processes. These components are coated individually and the process is usually referred to as ‘custom coating application’. The two processes employed for the application of polyolefin coatings are fluidised bed or flock spraying onto hot surfaces. In the fluidised bed coating process, after pre-heating, the item is dipped into a bed of fluidising powder. This bed consists of two compartments, one on top of the other. The upper, larger compartment contains the coating powder. The lower compartment, or "plenum chamber", is a reservoir for pressurised air. A porous membrane, sometimes called a diffuser, separates the two compartments. Usually the membrane is made of canvas or a high quality filter paper. The porosity of the membrane is critical to the quality of the fluidisation of the powder. Compressed air is forced into the lower compartment. It diffuses through the membrane and moving upwards, still under pressure, passes

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between the fine powder particles that are contained in the upper compartment. As a result, the bulk density of the powder is reduced and this permits the preheated metal object to be lowered easily, without any resistance, into the now "fluidised" bed of powder. The powder behaves like a liquid and continues to do so, as long as the air is forced into the lower plenum chamber. By careful agitation or controlled movement of the hot metal object underneath the surface of the "fluid" powder, the cold powder comes into contact with every point of the hot metal and fuses onto it. A thickness of between 300 and 750 microns is suggested in order to achieve the optimum potential of the coating material. Thicknesses outside the recommended range may be detrimental to the coating. Thicknesses above 1500 microns are to be avoided. The benefits of this process include: 100% coating efficiency; faster cycle times than other application processes; thicker coating providing functional protection, longer life, impact resistance but with higher material usage and superior edge coverage. However, this application process requires capital to be invested in the fluidised bed unit. Flock spraying is sometimes called "powder spray coating". This method consists of blowing powder through a suitable spray gun onto metal items that have been preheated to a predetermined temperature. The powder hits the hot metal and sticks to it, where it melts and gradually fuses to form a homogenous coating. This method of powder application is particularly suited to coating large or oddshape objects, which would otherwise be impractical to process by the fluidised bed process. Flock spraying has the added benefit that more than one coat of powder can be applied, if the metal object is carefully re-heated before re-spraying. This process can be repeated several times, if necessary, in order to build up and achieve the desired coating film thickness. This method is used for the application of 3 layer polyolefin coatings where FBE, adhesive and top coat layers can be successively applied. Maximum thickness is limited by the application method to not more than 2mm. Other benefits of this application process include: recycling of the coating material is possible; no major investment in equipment. However, this process has a lower coating efficiency than the fluidised bed process. The steps of a typical custom coating process are detailed in Appendix 11.3.

11.3.2 Internal Protection of Bends and Fittings The use of internal coatings for corrosion protection, electrical isolation and deposit mitigation is a common industry practice. A wide variety of pipeline components such as elbows, bends, valves, pig launchers, and isolation spools are manually coated using spray and/or flocking guns. A wide variety of liquid or powder coating materials are employed. Careful selection of the coating material based on the intended service environment is essential in order to ensure proper coating adhesion and a long service life of the component. Some liquid coatings can cure at ambient temperatures which makes them useful for large surface applications such as tanks and vessels. Powder coatings require factory-applied coating application because of the temperatures involved, but generally provide better chemical and temperature resistance versus typical liquid systems.

Fig 18 Internal Coating Materials for Immersion Service

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A variety of internal coatings are used for corrosion protection in continuous immersion service. Coatings which cure by chemical reaction (for example epoxy, polyester, polyurethane and coal tar epoxy coatings) have proven to be the most durable materials. Over the last 20 years epoxy based coatings have proven themselves to be very successful in immersion service. The success of fusion bonded epoxy (FBE) coatings is rooted in their excellent chemical resistance and long service life. FBE coatings are powder materials that are applied to a heated surface allowing the powder to melt and flow. Typically a liquid primer is first applied to allow for the maximum level of adhesion of the overall coating system to the metal substrate. During the ‘curing’ process, the primer and top coat react together and chemically cross-link, yielding a single system well adhered to the metal surface. In order to ensure proper application of FBE coatings the surface preparation is very important. The first step is to thermally clean the component to be coated at temperatures of up to 399°C. The part is then grit blasted with blast media, such steel grit or aluminium oxide. The blasting is done to a NACE # 1 White Metal Finish (SSPC 5), the aim being to obtain a surface structure (anchor pattern) rough enough to allow excellent mechanical adhesion and a surface clean enough to allow excellent chemical adhesion by the primer system.

Chemistry

Characteristics

Epoxy

Temperature limit 225ºF (107ºC), the amount of flexibility and temperature resistance are inversely related. Inherently have a fair amount of chemical resistance.

Phenolic

Temperature limit 400ºF (204ºC), high abrasion and temperature resistance along with good chemical resistance. Can be brittle.

Epoxy Phenolic Temperature limit 250ºF (121ºC), produces a middle-of-the-road coating with good flexibility, temperature resistance, and chemical resistance. Epoxy Novolac

Temperature limit 400ºF (204ºC), excellent chemical resistance (generally better than straight phenolic), temperature resistance and flexibility close to a phenolic coating. Table 1 Main internal coating systems for bends and fittings

11.3.3 Substrate Suitability for Custom Coating – General Guidelines Not all substrates are suitable for the application of internal coatings. An assessment of the metal substrates suitability for coating should be done using DIN 14879-1:2005. The material to be coated should be free of all sharp edges and corners that could interfere with the coating’s ability to provide adequate physical coverage, and the metal substrate must be easily accessible to hand tools in order for proper surface preparation. Any weld beads must be ground smooth, providing a surface where an adequate anchor profile can be generated for proper coating flow and adherence. In order to obtain the desired anchor pattern (a surface roughness profile between 25-80 microns) the metal substrate requires blasting, usually with steel grit or aluminium oxide. Critical to the success of a coating system will be the ability to overcome the dimensional limitations and geometry of the material to be coated. All surfaces must be accessible not only for proper grit blasting but also for hand-held coating guns as well as proper quality control measurements. Some coating applications call for thermal cleaning for the purpose of eliminating organic deposits, at elevated temperatures in excess of 370°C. Care should be taken with corrosion resistant alloys (CRA), as they could possibly suffer from some level of embrittlement after thermal cleaning. Other special tubulars i.e. nonmagnetic drill collars, cannot be thermally cleaned without changing the metallic surface structure. These special substrates are instead chemically cleaned prior to the coating application.

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Fig 19. Metal Substrates Not Suitable for Custom Coating Spiral &Weld Imperfections

Burrs & Longitudinal Chamfer

Weld Seam & Surface Imperfections

11.4 â&#x20AC;&#x201C; Mechanical Protection Selection Guide As mentioned earlier, mechanical impact damage is one of the most common causes of onshore pipeline incidents. Pipelines thus need mechanical protection in order to avoid or reduce the damage from impacts. The mechanical protection need for each onshore pipeline project has to be addressed, whenever possible, at an early stage in the design and/or construction of the pipeline in order to ensure the integrity of the corrosion protection system(s) and thus the long-term pipeline integrity. All the most common external anti-corrosion and insulation plant and field-applied coatings have an embedded basic mechanical protection potential coming from the intrinsic damage resistance of the raw coating materials. Multi-layer external coatings have been developed to specifically improve the basic mechanical protection potential of the single-layer external coatings. However, the basic mechanical

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protection potential that can be obtained at a reasonable total installed cost, even by using multi-layer external anti-corrosion coatings such as those detailed in section 11.1, is rather limited, especially during potential high-impact activities such as backfilling. For example, field trials have shown that even with the most impact-resistant coating systems, the maximum size of the backfill material that could be used during standard backfilling should be no more than 5-6 cm in diameter2. Therefore, the onshore pipeline industry has focused on developing supplementary mechanical protection systems that increase the damage resistance of the pipe and pipe coating during the various stages of their life-cycle. In this context, as mechanical impacts from different sources can happen at any time during the life of a pipe joint, the supplementary mechanical protection systems can be categorized based on the time horizon of their protection: • Protection during transportation – separation pads etc • Protection during handling (loading in and out) and storage – protection pads, sand berms, wood pads etc. • Protection during installation (lowering in, backfilling) – sand padding, concrete coatings, nonwoven geotextiles etc. • Protection during pipeline’s service life – above-ground pipeline markers, coatings, concrete slabs etc • Whole pipe life-cycle protection – including all stages above – selected plant-applied concrete coatings The existing supplementary mechanical protection methods and systems can also be separated in several categories based on their location relative to the pipe: • Above-ground systems – pipeline markers, ‘call-before-you-dig’ numbers, separation or protection pads etc • Buried trench protection systems – tunnels, concrete slabs, steel plates or wires that protect or deny access to the pipeline trench etc • Buried pipe protection systems – can be either protection systems that protect just part of the diameter or length of the pipe (such as foam pillows, sand bags etc) or systems that protect the whole diameter and length of the pipe (such as plant and field-applied coatings, sand padding, select backfill [mechanical padding], non-woven geotextiles, rock shield materials etc) Supplementary mechanical protection systems can also be categorized based on the location where the protection is applied – in a specialised facility or in the field by a specialised contractor. Based on these categories, for the purpose of this document, we are going to focus on the systems that protect the whole diameter and length of the pipe – the buried total pipe protection systems, both plantapplied and applied in the field. The most widely used buried total mechanical protection systems in the industry are reviewed in the next sub-sections. Note that the list of systems described below is not exhaustive, as other systems are also used in onshore pipeline projects, but on a more limited scale.

For some examples of such field trials, please see Optimization of Pipeline Coating and Backfill Selection, Espiner R., Thompson I, Barnett J, NACE, 2003 and other similar sources listed in the section’s Bibliography

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11.4.1 Concrete Coatings Concrete coatings were created to offer supplementary mechanical protection to the pipe and pipe coating. When applied in a specialised coating plant, concrete coatings are the only mechanical protection systems in the industry that protect the pipe during the whole pipeline construction process (transportation to ROW, temporary storage, handling, stringing, lowering in, backfilling) and the entire pipeline service life. Concrete coatings can be plant-applied (through side-wrap, spraying or impingement processes) or applied in the field – as form-and-pour or moulded concrete and are covered by the EN ISO 21809-5 (draft) standard. All concrete coatings are reinforced by either wire mesh, rebar cages or different types of fibres. While the reinforced concrete coating covers the pipe length, its field joint areas are protected by either field-applied reinforced concrete, wire-reinforced polyethylene open-cell sheets or wood slats. Some concrete coatings are wrapped in a perforated polyethylene outer tape that prevents concrete spalling and allows curing (the PE tape can then be removed at the customer’s demand). The minimum thickness of the concrete coatings is 6-7 mm (fibre-reinforced concrete), while the maximum that can be applied is 150 mm for the side-wrap process and around 200 mm for the impingement and form and pour processes. Some of the fibre and wire mesh reinforced concrete coatings with a thickness of up to 25 mm are bendable according to the industry specifications – 1.5° per pipe diameter. Some of the fibre-reinforced and higher thickness concrete coatings are not bendable, reducing their ability to follow the terrain configuration in the field.

Fig. 20 – Bendable plant-applied concrete coating Concrete coatings offer some of the highest mechanical protection among the existing systems whilst taking up little space. A 25 mm wire mesh reinforced concrete coating, for example, offers the equivalent impact protection of a layer of 300 mm of sand padding. Some concrete coatings are capable of resisting penetration from trench bottom outcrops, if specific point loading parameters supplied by the applicators are satisfied. If available in the project’s region, concrete coatings offer the highest flexibility to pipeline designers and contractors, as they have no limitations of use in terms of terrain configuration (they work very well on steep slopes), trench material type (large rocks) or climatic conditions (very cold climates), as all the other systems have. When applied in a plant, the concrete coatings do not delay the construction of the pipelines and do not require additional material, equipment or manpower on the right-of-way. On the other hand, while reducing other pipeline construction costs, concrete coatings increase the weight to be transported and handled to and on the right-of-way. Non-bendable concrete coatings are also less useful, as the coated pipe cannot follow the terrain configuration. Field-applied concrete

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coating is slow, can delay the pipeline construction and usually cannot offer the quality guarantee of a plant-applied coating.

11.4.2 Sand Padding Sand bedding and padding is one of the most frequently used supplementary mechanical protection system during the last decades. This system only protects the pipe against impacts during its lowering in, trench backfilling and during its service life after installation. Sand padding is applied in the field. After the pipeline trench is opened, sand or fine gravel is brought in using sand trucks, usually from a commercial sand pit in the region. The fine material is dumped next to the trench. A first layer of sand, the sand bedding – usually 20-30 cm thick – is then placed on the trench bottom for protection against rock or other hard outcrops. The pipe is then lowered in and another layer of sand or other fine material is placed (padded) around and on top of the pipe – usually another 20-30 cm on top of the pipe. The trench backfill is finished with some of the material excavated from the trench and the topsoil. Finally, the surplus spoil – the original trench material displaced by the imported sand/fine gravel, such as shot rock, cobbles, boulders – is usually removed from the right-ofway and disposed of – at a cost – at a different location. The sand padding provides adequate mechanical protection to the pipe and pipe coating and, by changing the thickness of the top sand layer can withstand backfill impacts from virtually any size of trench material. Sand also offers a certain degree of protection against penetration from trench bottom outcrops, as long as there is sufficient sand to ensure outcrops are not in direct contact with the pipe. Sand padding has some limitations in terms of climatic conditions – sand can freeze in large chunks in cold weather, making padding more difficult or impossible. Its protection can also be impaired by sand washouts on steep slopes or in other draining areas. Sand padding needs additional material (sand), equipment (sand trucks, padding machines), additional manpower (truck drivers, one bedding team after the trenching team and one padding team after the lower-in team), space (sand truck access and sometimes temporary sand dump areas) on the right-ofway and adds surplus trench material disposal costs.

11.4.3 Select Backfill (Mechanical Padding) The select backfill method (also called mechanical padding) was created to offer mechanical protection to the pipeline by taking advantage of the local material that was excavated at the opening of the trench. This method protects the pipe only during its lowering in, trench backfilling and during its service life after the installation. The select backfill (mechanical padding) is applied in the field. The local material excavated at the opening of the trench is fed into the mechanical padding machine, where it is screened based on size. The finer material is then placed under, around and on top of the pipe for protection against large backfill materials – the layer under and on top of the pipe are each usually 20-30 cm thick. The trench is then closed by adding the remaining larger size trench material and the topsoil.

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Fig. 21 – Mechanical padding machine The select backfill method provides adequate mechanical protection to the pipe and pipe coating and, by changing the thickness of the top padding layer can withstand backfill impacts from virtually any size of trench material. The biggest advantage of this system is that only the original trench material is used, and there is no requirement for imported fine materials (sand etc). Select backfill has the best results with dry granular trench materials. The performance of this system is reduced in regions with wet, silty or clay trench materials. There are some limitations in terms of climatic conditions – mechanical padding is more difficult when trench materials are frozen. This system is also not very practical on steep slopes or areas with reduced or no right-of-way access for equipment. Mechanical padding needs additional equipment (mechanical padding machines), additional manpower (padding machine operators) on the right-of-way, as well as additional time for setting up and demobilizing the padding machines.

11.4.4 Rock Shield and Non-Woven Geotextile Systems Rock shield materials are polyethylene or PVC-based solid sheets or open-cell extruded pads; nonwoven geotextiles are needle-punched polypropylene fibre-based rolls. These materials are designed to protect the pipe and pipe coating against damage during pipe lowering in, trench backfilling and during the pipeline’s service life after installation. Rock shield and non-woven geotextile materials are installed on the pipe in the field outside the trench, in a spiral “cigarette” wrap application using tape or Velcro to secure the seam. Smaller diameter pipes can be longitudinally wrapped. Rock shield materials are available in rolls of various styles, sizes, thicknesses (usual range 6-11 mm per layer for rock shield and 4-14 mm per layer for non-woven geotextiles) and technical performance properties.

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Fig. 22 â&#x20AC;&#x201C; Non-woven geotextiles installed on pipe Rock shield and non-woven geotextile materials offer good mechanical protection to the pipe, especially in gravel/small cobble trench materials: according to the suppliers, the strongest multi-layer non-woven geotextiles can withstand impacts from backfill material up to 10 cm in diameter without any damage (holidays) to the anti-corrosion coating or the pipe. They do not protect against penetration from trench bottom outcrops and have to be combined with other systems (sand) in order to create some degree of protection. Rock shield and non-woven geotextile systems will not provide adequate mechanical protection in rocky trenches and with largebackfill material. A rock shield could produce cathodic protection system shielding if it is not an open-cell material, while, based on the information available from the industry, the impact of the non-woven geotextiles on the cathodic protection system is unclear and needs further research. Installation of rock shields or non-woven geotextile materials could slow down the pipeline construction and needs additional material (rock shield, geotextile sheet), manpower (field installation crew) on the right-of-way, and sometimes other mechanical protection systems (sand, select backfill). Costly wastage can also arise if the rock shield sheet width does not match the pipe diameter. The protection efficiency will be dependent on the quality of the field installation crewâ&#x20AC;&#x2122;s work.

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11.4.5 Mechanical Protection Selection Guidelines In order to make the most informed choice for the supplementary mechanical damage prevention and protection of the onshore pipelines, the parties involved should use the following categories of selection criteria: - Technical performance criteria – such as time horizon of the protection (e.g. is this whole lifecycle protection or just protection during installation?); impact resistance during backfill (maximum allowable backfill size); resistance to penetration (from trench bottom etc); flexibility (impact on pipe cold bending); impact on the cathodic protection system etc. - Pipeline design and constructability criteria – such as limitations in terms of trench material, terrain configuration, harsh climatic conditions; right-of-way allowance and access limitations; increased contractor risk (additional equipment and manpower needed, construction delays, potential future remediation cost risk etc); regulatory limitations (pipeline operator specifications, government/industry standards and regulations) etc. - Environmental criteria – minimum impact on the right-of-way and surrounding environment during pipe transportation, handling, installation and service life – impact can be measured by vegetation loss, increased erosion potential, volume of excavated and landfilled trench material, fauna and flora disturbance etc. - Economic criteria – system availability in the region; total installed cost (including the material supply cost, but also all the direct and indirect mechanical protection installation costs) Please find in Appendix 4 a table comparing the discussed supplementary mechanical protection systems based on the criteria listed above. In terms of selection methodology, based on the criteria categories above, and if the basic mechanical protection provided by the external anti-corrosion coatings is not enough for the needs of a pipeline project, the stakeholders can take a three-step approach in selecting the optimal supplementary mechanical protection system or combination of systems (as some of the systems discussed above can be combined for increased mechanical protection): 1. Shortlist the preferred supplementary mechanical protection systems or combinations of systems based on the pipeline project specifics and on technical, design, constructability and environment impact criteria – see table in Appendix 1 for help 2. Once the most interesting systems or combinations of systems are selected, check the availability of those systems in the project’s region or in a region with easy logistic access to the project’s region 3. Choose among the available short-listed systems or combinations of systems the option with the lowest total installed cost or the best cost/benefit ratio The selection of the supplementary mechanical protection solution should be done, as the selection of the mainline and field joint coatings, as early in the pipeline design and construction as possible, in order to ensure consistent and cost-effective corrosion and mechanical protection for the pipeline. Although the general technical performance of the different supplementary mechanical protection systems is well understood in the industry, we recommend that further research be done to clarify some technical performance aspects such as the comparative resistance of the different systems to penetration from outcrops in the trench bottom, re-validate the maximum backfill size that is allowed for the different systems and the impact of increasing pipeline operating temperature on the performance of the different mechanical protection systems.

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11.5 – Internal Coatings

11.5.1 Internal Coatings’ Purpose Internal coatings are used to increase the flow efficiency for natural gas pipelines and to mitigate corrosion damage to the line pipe. Internal plastic coatings (IPC) have a very low surface roughness in relation to the steel pipes they protect. This impacts pipe hydraulics and provides a surface change that will aid in the mitigation of organic and inorganic deposit formation, increasing the economic justifications for using IPC. The surface finish of an internally plastic-coated pipe has a fraction of the surface roughness of bare pipe, reducing the friction generated at the surface during product flow. The usage of IPC in gas pipelines have shown a reduction in friction coefficient of up to 50% resulting in a transmission increase of 15 to 25% (2) (4). The potential pipeline transmission increases are more pronounced in smaller sized pipes, as well as systems with higher Reynolds numbers where flow is turbulent. Fluid flow is characterized as laminar, or turbulent with most gas pipeline having turbulent flow conditions. Even for systems which are characterised by turbulent flow conditions, a minute laminar (sub) layer exists at the pipe wall, and the extent of the laminar sub layer is dependent upon the surface roughness of the pipe surface. Under laminar flow conditions, fluid and particle movements are more predictable. The greater the laminar sub layer extends into the pipe ID the less friction is a factor on produced flow. In uncoated pipe the surface will have a greater physical roughness which will increase turbulence leading to greater friction being generated during flowing conditions. The overall effect of this friction will vary based on the type of product being transported and the rate of flow. Hydraulic modelling software is now available to conduct simulations inputting varying surface roughnesses in an effort to identify any possible increases in product throughput and also for research into the modelling of multiphase flow that is becoming ever more important as large offshore developments call for the pumping of gas, and oil/water emulsions in pipelines over extended distances. Internal plastic coatings aid in maintaining fluid purity by mitigating product interaction with the bare steel substrate which can lead to harmful reaction products. They also aid in the prevention of organic and inorganic deposits adherence (3). Deposits of corrosion by-product, water born scales and microbiological ‘biofilms’ are usually encountered in low spots of the pipeline, i.e. road crossings, or at the foot of a mountain and can result in premature pipeline failure due to corrosion (mostly localised pitting corrosion). Undesirable bacteria such as acid-producing bacteria (APB) and sulphate-reducing bacteria (SRB) associated with water transmission pipelines form dense ‘biofilms’ which can result in pitting corrosion of line pipe. The biofilm provides a habitat for the microorganisms, providing shelter from bulk fluid movement and contact with most surfactant biocides able to effectively kill off the bacteria. Biofilm

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deposits can require extensive pipe pigging operations in addition to costly biocide treatments in order to control corrosion. The material composition of the surface has little effect on the biofilm development (5) or adhesion to the substrate, bacteria will secrete polysaccharides and attach to metals as well as to plastics. The smooth surface (roughness) of coated pipe will however expose these microbiological deposits (biofilms) to a much higher degree of sheer stress from the bulk fluid movement compared to bare pipe. The higher surface roughness of uncoated pipe helps shield the bacteria from the bulk fluid movement, enhancing growth conditions for bacterial colonies. Coated pipe also provides an effective barrier (barrier coating) against the detrimental and corrosive effects of contact with the bacteria metabolic byproducts such as H2S and/or acids. In water-injection systems where produced water from various formations and/or other sources such as river water or seawater are mixed, the potential for the development of scale deposits in the pipeline line is a possibility. Coatings can also provide benefits for production systems which are prone to have scale deposits forming on the pipe surface. As in the case of bacteria, the low surface roughness of coated pipes exposes the scale to higher sheer stress from the bulk fluid movement, additionally the coated surface provides reduced mechanical binding locations for the crystal lattice of the developing scale. Improved fluid purity will also increase the service life of pumps while reducing their power requirements (6) and resulting in cleaner filtration units.

Additional benefits of using internal flow coatings include: corrosion protection of the pipe during storage prior to installation; improved pigging conditions; faster drying times; and improved conditions for visual inspection of the internal surface of the pipe walls. Pipe storage periods prior to construction should be kept to a minimum as studies (1) have shown that the surface roughness of bare pipes will increase during storage due to surface corrosion. The high surface gloss of most internal plastic coatings are an excellent aid in the visual inspection of the pipe interior prior to line commissioning, while the smooth coating surface finish aids to extend the life of pipeline pigs during production/clean-up operations. The application of internal plastic coatings involves several surface preparation steps. Initially there will be a thermal cleaning step or chemical wash to remove any organic species that might be on the pipeâ&#x20AC;&#x2122;s internal surface. The next step will include some level of grit blasting of the pipeâ&#x20AC;&#x2122;s internal surface to a cleanliness level specified by the coating manufacturer/applicator. During the surface preparation of the pipe, all mill scale and metallic deposits are removed from the pipe ID; removal of this debris following the hydro testing of the pipeline would be extremely expensive. During hydro testing the water used is usually chemically treated so as not to cause corrosion or have water-borne bacteria becoming sessile and adhering to the new pipe. Studies have shown that the typical payback for the internally coated pipe investment is between three to five years, based purely on pipeline hydraulic improvements (8). Plastic coatings can reduce the pressure drop in pipelines, and have been shown to allow the operator to use a smaller ID line pipe while still maintaining the same throughput as with a larger diameter internally-bare pipe (9). One additional economic benefit of using coated line pipe is the reduction in power consumption required to move the

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gas and/or liquids from one end of the line to the other. In countries such as Norway, over 30% of the produced gas is used in offshore power generation that is required to fuel the compressors used for the export gas pipeline.

11.5.2 Main Internal Coating Systems Cement Lining Cement mortar lining (CML) is a centrifugally-applied continuous lining of dense Portland cement mortar with a smooth and uniform finish. These products were developed to provide an economical form of internal corrosion and abrasion protection for oilfield tubulars and line pipe. CML is used primarily in water injection and disposal lines. These products are also suitable for potable water lines but should not be specified for lines where hammer conditions or fluid pH below six (acidic condition) exist. The lining provides economical and lasting protection against the corrosive effects of saline solutions and other types of industrial liquids and wastes. It has excellent structural and spall-resistant properties. This is a proven technology with over a century of use in municipal water mains and water service lines. The system is compatible with other external coatings. Extruded polyethylene external coating may be applied over CML pipe provided the steel is not heated rapidly by more than 80°C during the coating process. Cement is alkaline in contact with water which reduces the corrosion impact to the metal substrate under the cement mortar. Cement mortar however has restrictions with regards to water fluid speeds and reduces the pipe ID to a larger extent than FBE coating systems would. Cement also has a higher surface roughness compared to FBE and promotes microbiological growth to a larger extent, furthermore the degree of flexibility of cement mortar lined pipe and impact resistance is inferior to FBE type of linings.

Fusion Bonded Epoxy Typically when fusion bonded epoxy (FBE) is referenced, it is assumed to be for the external protection of line pipe. There are a wide array of FBEs, primed and unprimed, that have proven to be successful in the area of corrosion protection, hydraulic improvement and deposit mitigation for the internal of line pipe. FBE is a plant-applied thermoset lining for steel pipes where internal corrosion protection or a smooth surface is required. This lining reduces friction costs and compression costs, and provides a clean internal surface along with corrosion protection. As with internal plastic coatings, FBE has been used since the early 1960s. FBE coatings are used extensively in the oil and gas industry for the coating of line pipe, valves, fittings and for downhole materials such as tubing and casing. The fusion bonded epoxy coating systems are applied at what is called the “cladding temperature” of the powder. The cladding temperature is the point at which the powder will melt and flow allowing it to adhere to the preprepared (grit-blasted and/or thermal-cleaned surfaces). Powder coating systems are applied in a one layer process as opposed to liquid coating systems which can be applied in numerous, thin layers with an intermediate drying/baking cycle between each layer. As opposed to cement linings, FBEs are thick film coatings usually with a Dry Film Thickness (DFT) of less than 400 microns. Advantages of FBE coatings are their adhesive properties, their chemical resistance, their high degree of flexibility and good impact resistance. Drawbacks of FBE coating systems are the high degree of surface preparation required for their application as well as a curing temperature in excess of 200°C, all of which requires ‘shop applied’ coating application.

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Polyamide Coatings Internal coatings based on polyamide chemistry are defined as thermoplastics. Unlike thermoset materials, thermoplastics do not undergo a final curing step at elevated temperatures. Instead, these materials are applied at very high temperatures and are then led through a controlled cool down process that will vary depending on the type of polyamide and the desired final properties. Due to this, heatresistant polyamide powder coatings are primarily plant-applied coating systems. Polyamide coatings have advantages over FBE coating materials due to a higher degree of flexibility and less damage experienced from mechanical impact. Polyamide coatings generally require a liquid epoxy or phenolic primer in order to ensure good adhesion.

Flow Efficiency Coating Flow efficiency coatings (FEC) are thin film epoxy coatings applied in natural gas pipelines to smooth the internal pipe surface for improved flow. Application of FEC replaces the internal rough surface of a steel pipe with a smooth surface finish which reduces friction and turbulence to increase flow efficiency. This may allow for use of a smaller diameter pipe or lower compression requirements resulting in reduced capital and operating costs. After application of FEC, the clean internal surface of the pipe provides corrosion protection prior to installation and allows for easier visual inspection. The cleaner surface reduces the cost and effort of drying the pipe after hydrostatic testing. Anti-Corrosion for Potable Water â&#x20AC;&#x201C; Epoxy Lining One type of internal coating system for potable water applications is a 100% solids, two component, and solvent free, high build epoxy lining used to provide corrosion protection for the internals of steel pipes in potable water applications. BS6920 and ANSI/NSF 61 are local standards for potable water, and can also be used for other applications including raw water, process water, sewage, wastewater, crude oil, and white oils. These standards usually call for testing of the applied coating material with regards to taste, smell, microbiological growth and possible leaching out of heavy metals and/or solvents. Coatings used for potable water handling must be solvent free in an applied form and are used on valves, fittings, tanks and elbows as well. These products are designed for high build, single coat applications by airless spray equipment. Performance Properties These products are allowed to cure to form a hard and glossy surface film with excellent resistance for a wide range of aqueous chemicals including potable water, effluents, raw water, process water, sewage, crude oils, and white oils. These products exhibit excellent adhesion on correctly-prepared steel surfaces. They are compatible with most readily-available field joint coating systems such as heatshrinkable sleeves, liquid epoxy, FBE and polyurethane coatings. Easy Application These products are suitable for application as a single coat system, using both standard and/or plural component airless spray equipment. They are capable of being applied by roller or brush for small applications and repairs. Environmentally Safe With a 100% by volume solids, zero volatile organic compound (VOC) formulation, these products are designed to meet strict health, safety and environmental standards. They eliminate solvent emissions, explosion risk and fire hazard and are designed to eliminate the risk of solvent retention which can influence water quality and coating defects.

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Anti-Corrosion for Potable Water - FBE Powder Coatings Another type of internal coating is the FBE system. FBE powder coatings have been used in the pipeline industry for more than 40 years. These powder coatings contain no solvents and are 100 % solid without any dangerous raw materials. FBE powder coatings meet a lot of standards around the world like DIN/ISO/EN, GSK, AWWA and drinking water approvals such as - UBA-Guideline, Germany - ACS, France - WRAS, United Kingdom - KIWA, Netherlands - Belgaqua, Belgium - NSF 61, USA The purity of the water for human consumption is the highest priority for the companies involved in the supply chain of manufacture and management of the mains distribution systems. Therefor the control of the products used in the industry must also be of the utmost importance. In Europe the control of materials used is normally determined through government departments or independent test institutes or a combination of both. In certain cases only raw materials that are on a “positive” list can be used in a fusion bonded epoxy formulation. In this case the powder manufacturer would also be audited on a regular basis and samples taken from production of FBE products to confirm they continue to meet the approval documentation. In the case of the KIWA or NSF drinking water approval the control of raw materials is very strict, with the chemical composition of individual raw materials assessed to ensure the products conform to their requirements. In addition to these regulations further testing is performed on the growth of microorganisms on materials intended for use in drinking water. In particular the FBE technology has been tested in Germany by the Hygiene-Institut des Ruhrgebiets for examination and assessment following the regulations of the DVGW (German Association of Gas and Water) technical rules, method W 270. The test is targeted at determining any signs of bactericidal or fungicidal properties of the FBE-coated surface. The FBE technology has been tested to and meets the requirements of this specification with documentation available. Anti-Corrosion for Potable Water – Polyurethane Lining Polyurethane-based products are 100% solids, either one or two component systems, 1:1 mixed by volume, high performance, high build, fast set, aromatic and rigid polyurethane lining. They have been specifically designed as corrosion and abrasion resistant coating for long term protection of water pipe internals. They should comply with the requirements of NSF/ANSI 61 standard for potable water and AWWA C222 standard. They can also be used for other applications including raw water, process water, sewage, and wastewater. Excellent Performance Properties Polyurethane based systems cure to form a very hard and tough surface film with excellent resistance to abrasion, impact, chemical attack, and cathodic disbondment. They exhibit excellent adhesion on correctly-prepared steel and ductile iron surfaces. The application of a primer is not necessary. They are compatible with most readily available field joint coating systems such as heat-shrinkable sleeves, liquid epoxy, FBE, and polyurethane coatings. All Temperature Cure and Unlimited Film Build PU can be cured at almost any ambient temperature. These products have a very fast curing time and are therefore applied using plural component spray equipment. The unlimited film build can be achieved in a single coat multi-pass application. The end result is a thick,

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impervious, and holiday-free internal coating film within minutes of spray application. Inspection and quality testing can be made within 30 minutes and pipes can be put into service within hours. Environmentally Safe PU is a 100% solids system, being free of solvents and VOCs, and is designed to meet strict health, safety and environmental standards. The product contains only pure resins and the finished coating is safe for drinking water and food contact.

11.5.3 Coating Qualification Testing Regardless of the purpose of an internal plastic coating in a pipeline application, the coating must be ‘fit for purpose’. For example, it must have sufficient resistance against delamination, swelling and disbonding in its intended environment. Advances in coating chemistry and technology over the last decade have led to the usage of coated line pipe in environments where this was previously not feasible. Oil and gas fields with service temperatures in excess of 120°C, and extreme chloride concentrations in excess of 160,000 ppm, coupled with substantial concentrations of sour gas are not uncommon any more. When choosing the qualification tests to be used for the testing of the most appropriate coating system it needs to be kept in mind that the coating standards used for ID coatings originated from the external coating business. The confusion is amplified by the extensive number of ANSI, AWWA, API, NACE, DIN and ASTM standards that are associated with coatings and paint. These may not be suitable for internal coatings. Care has to be taken that these standards are not confused with one another and the testing during fit for purpose trials is relevant to the system in question. The coating material under consideration should be tested for its resistance in its intended environment. It has to be kept in mind that most test work relating to internal plastic coatings is derived from external coating test procedures. As such there are several tests which, while appropriate for external coating systems, provide little beneficial data regarding the performance of an internal coating in a particular environment. One such test is the salt spray resistance test (discussed in API RP 5L) for coating systems designed for immersion services. Another test that will not provide a realistic view of coating performance in a line pipe application is the 90° degree impact testing which was used in the past to expose brittle coatings that were susceptible to disbonding. Given the nature and direction of flow through a pipeline, 90° impact angles are not representative of potential coating damage to the internal surface. General environmental parameters such as temperature and pressure are important variables for the coating selection, especially when it comes to immersion service in sour environments. As the temperature increases resistance to H2S generally decreases, these effects and results are best evaluated in an autoclave test series. For sour-service environments it is advisable to conduct autoclave testing simulating the field conditions with regards to gas compositions, pressures, temperatures, and if applicable, reconstituted field/formation waters can be used. These tests are conducted according to NACE TMO185 “Evaluation of Internal Plastic Coatings for Corrosion Control of Tubular Goods by Autoclave Testing”. The test coupons from the autoclave testing can then be used to test for the adhesion of the coating material prior to and following exposure to the corrosive environments. An appropriate test for adhesion is according to ASTM D4541-02 “Standard Test Method for Pull-off Strength of Coatings using Portable Adhesion Testers”. The possible formation of blisters, classified according to ASTM D-714 “Standard Test Method for Evaluating the Degree of Blistering of Paints”, following autoclave testing indicates loss of adhesion to the steel substrate. In the past internal coatings have failed due to different rates of thermal expansion and contraction between coating and the metal substrate. This could be due to simple temperature gradients between day and night-time or large temperature differences between pipe ID and OD.

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Another important test indicating coating ‘flexibility’ is the Mandrel Bend Test (ANSI/AWWA P213-07), the coating requires sufficient flexibility to resist cracking and disbonding of the coating during pipe laying operations.

References 1.

J. Nelson “Internal Tubular Coatings used to maximize hydraulic efficiency.” Corrosion 200 , Paper 00173

Harald Strand “Economical and Technical Benefits of Internal Coatings of Oilfield tubulars and Equipment.” 10th International Symposium Celle

Crowe , R. H. “What Transco Learned about Internal Coating of gas Pipelines.” The Oil and Gas Journal Vol 57, No. 15: pp 107-111

D.R. McLelland “Field Testing of Friction Losses in Plastic-coated Tubing.” API Division of Production

Pedersen 1990 “ Stainless Steel vs. PVC Surfaces”

A. Tamm, L. Eikmeier, B. Stoeffel “The influence of surface roughness on head, power input and efficiency of centrifugal pumps.” Hydraulic Machinery and Systems 21st JAHR Symposium, 2002 Lausanne.

F.F. Farshad and H.H. Rieke “Flow Test validation of direct measurement methods used to determining surface roughness in pipes (OCTG).” University of Louisiana

E. Sletjerding, J. Gudmundsson “Flow experiments with high pressure natural gas in coated and plain pipes: Comparison of Transport Capacity.” Department of Petroleum Engineering and Geophysics, NUST Norway

M. Tobin, J. Labrujere “ High Pressure Pipelines – maximizing throughput per unit of pipeline diameter”, Shell Global Solutions, Moscow April 2005

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11.6 – Insulation Onshore pipelines may require anti-corrosion coatings, insulation and internal coatings to maintain product flow, UV protection (for above-ground lines) or protective and weight coatings for rocky areas, river and lake crossings. Onshore insulation systems available today have been developed for external protection and insulation of pipelines operating at temperatures ranging from 85°C up to 650°C. Systems generally include a corrosion-resistant coating, a thermal insulation layer and an outer jacket or protective topcoat.

11.6.1 Onshore Insulation Systems Onshore insulation systems are moulded and/or spray-applied polyurethane foam coatings developed for external protection of buried or above ground steel and plastic pipe. The polyurethane foam provides a cost-effective alternative for preventing hydrate formation in gas pipelines, maintaining viscosity of hot oil lines and providing freeze protection for water and sewage lines. Systems use a multi-layer coating consisting of an anti-corrosion layer, thick polyurethane foam and a polyethylene outer water barrier. The compressive strength is high to resist damage from handling and burial. The polyethylene jacket may also be formulated for cold weather installation. For systems up to a maximum operating temperature of 85°C, tape and primer may be applied as an anti-corrosion undercoat. For higher temperatures up to 110°C, fusion bond epoxy is used as the anticorrosion layer.

1. Corrosion Resistant Coating 2. Thermal Insulation Layer 3. Outer Jacket - Protective Topcoat

11.6.2 Onshore Insulation to 150°C High temperature systems use spray-applied polyurethane foam coating developed for external protection of buried or above ground steel pipe. The polyurethane foam provides a cost-effective alternative for maintaining the viscosity of hot oil lines, diluent bitumen and hot bitumen lines to a maximum service temperature of 150°C. It consists of a high-temperature fusion bond epoxy anticorrosion layer which has also been rated for up to a maximum service temperature of 150oC under insulation. A sprayed-on low density polyurethane foam offers excellent insulation characteristics for extended service life at high temperatures. The thickness and compression strength can be tailored to match the pipeline project requirements. The foam is protected by an extruded high-density polyethylene jacket that provides excellent mechanical protection to prevent damage and moisture ingress into the system. The system is designed to be installed in environments down to a temperature of -40°C. This high temperature system provides a watertight barrier. The polyurethane foam reduces heat loss to prevent hydrate formation in gas pipelines and helps to maintain viscosity in hot oil lines. An optional design for further protection against temperature loss is the application of heat tracing channels.

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11.6.3 High Temperature Systems to 650°C In addition to existing coating solutions, new products are being developed to address new requirements for abrasion resistance, higher operating temperatures, and installation in extreme cold temperatures to serve the oil sands and Arctic regions. Pre-insulated pipelines are used to transport both high and low temperature mediums where maintaining pipeline temperature is important. Applications range from low temperature LNG pipelines to high temperature bitumen pipelines. The pipelines consist of an inner carrier pipe covered in an insulating material and jacketed externally for protection and integrity. Pre-insulated pipe systems for above-ground pipelines reduce project costs and improve schedules for construction of in-situ oil sands production installations. Pre-insulating pipes prior to shipping to construction sites should reduce field labour and is more time efficient than insulating pipes at congested, space-constrained construction sites. Very high temperature systems are required for above ground piping for thermal recovery operations where operating temperatures are 650°C such as: hot oil and bitumen, steam lines and hot process water lines. These systems consist of wrapped aerogel insulation blanket and an aluminium cladding for weather proofing. Aerogel insulation offers very high thermal insulation efficiency resulting in reduced insulation thickness compared with other alternatives such as rock wool or calcium silicate. Corrosion protection is not required.

1. Aerogel Blanket 2. Metal Cladding

11.7 –Buoyancy Control Systems Virtually all onshore pipelines have to cross aquatic environments – rivers, channels, lakes, fjords or narrow sea gulfs, bays and channels – along their route. Sometimes, their route goes through semiaquatic environments, such as swamps, marshes, or permafrost. In all these environments, if the pipeline is not buried in solid ground, it will tend to move from its design position and float towards the surface. This phenomenon – identical to the one occurring in offshore environments – can affect any pipeline crossing an onshore wet environment. Moreover, it is more frequent in large diameter pipelines and in pipelines transporting gas. As the pipeline moves from its design position, this creates buckling or even rupture risks. Of course, an easy solution for the floatability/buoyancy issue would be to increase the wall thickness of the steel pipe; however, this solution is very expensive, so that the industry has researched other cheaper but effective solutions for pipeline buoyancy mitigation. Therefore the industry has developed similar solutions for the onshore wet environments, based on the extensive experience in mitigating the pipeline buoyancy phenomenon offshore, as well as other onshore pipeline construction techniques used for crossing or avoiding obstacles.

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In order to avoid the floatation phenomenon in onshore wet environments, the industry uses three main types of approaches: -

Wet environment aerial crossing – the pipeline is installed from the beginning at a safe distance over the wet environment area. This is usually done by using existing road/railway bridges to carry the pipeline or install a dedicated bridge for the pipeline over the river, lake or swampy area. This approach has the advantage of minimizing the wet environment disturbance, but exposes the pipeline to potentially damaging weather-related factors – UV degradation, impacts, floods etc.

Wet environment under-crossing – the pipeline is installed from the beginning at a safe distance under the wet environment area – under the river or lake bed. This is usually done by using horizontal directional drilling (HDD) techniques. This approach has the advantage of minimizing the wet environment disturbance, but will not solve the problem in certain types of onshore wet environments, such as marshes or permafrost, where the thickness of the wet layer is too high creating technical challenges for installing the pipelines

Buried pipeline – the pipeline is installed at the bottom of the wet environment – sometimes a trench is prepared to receive the pipeline – and then buried (by rock dumping etc). The advantage of this approach is that it reduces the risk of the pipeline floating to the surface. However, the effectiveness of this method is dependent on the quality of the burial operation – strong river currents, suboptimal trench cover material or incorrect burial could, for example, lead to the pipeline being uncovered and starting to float. Moreover, this approach is rather ineffective in marshes or permafrost areas where the thickness of the wet layers is high.

Buoyancy control systems - the main purpose of these systems is to avoid the above-mentioned risks by creating negative buoyancy that will counter the floatation effect described above and will thus allow the pipeline to stay in the design position. The advantage of these systems is that most of them are effective in onshore wet environments where other approaches show limited results, such as marshes, swamps or permafrost. Some of them also offer supplementary mechanical protection against potential impacts from ship anchors, rocks, etc. Their main weakness is that the relative instability of some of them (such as aggregate-filled bags) means they cannot usually be used for environments such as rivers, lakes, sea channels etc.

The review in this section is going to focus on the buoyancy control systems. The first buoyancy control systems were developed in the early part of the last century, when two cast iron half shells were bolted together around the pipe. Cast iron weights were then replaced by the less expensive and easier to manufacture cast concrete weights – set-on or bolt-on. The concrete weight coatings have been developed during the second part of the century to become the main buoyancy control system in the industry. Finally, during the 1990s, aggregate-filled envelopes were developed for use in regions where the other systems could not be used. The most widely used buoyancy control systems in the industry today are reviewed in the following sections. Note that the list of systems described below might not be exhaustive; other systems could be used in onshore pipeline projects, but on a more limited scale.

11.7.1 Concrete Weight Coatings Concrete weight coatings have been developed and used for more than 40 years to provide negative buoyancy to pipelines crossing onshore wet environments. Just like the concrete coatings for mechanical protection, previously when applied in a specialized coating plant, the concrete weight coatings are the only buoyancy control systems in the industry that also offer supplementary mechanical protection to the pipe and an anti-corrosion coating during the whole pipeline construction process (transportation to ROW, temporary storage, handling, stringing, lowering in, backfilling) and the entire pipeline service life.

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Concrete coatings can be plant-applied (through side-wrap, spraying or impingement processes) or applied in the field – sprayed or form-and-pour (moulded) concrete, and are covered by the new EN ISO 21809-5:2010 international standard. All concrete coatings are reinforced by wire mesh, rebar cages or different types of fibres and use a dry concrete mix (5-7% water) to allow for the pipe to be handled right after the application of the concrete. Their required 28-day compression strength is in the 40-50 MPa range. Some concrete coatings are wrapped in a perforated polyethylene outer tape that avoids concrete spalling and allows curing (the PE tape can then be removed). Other concrete weight coatings are cured allowing the concrete to cure naturally outdoors through accelerated curing using steam. The field joint area is usually protected by fast-setting reinforced concrete that is applied by specialised contractors in the field. Compared to the mechanical protection concrete coatings, concrete weight coatings are thicker and heavier. Concrete weight coatings are usually 50-75 mm thick, although the maximum thickness that can be applied is 150 mm for the side-wrap process and around 200 mm for the impingement and form-and-pour processes. The negative buoyancy potential is given by the high density of the concrete weight coatings – between 1800 and 3700 kg/m3 – which is usually obtained by using heavy natural aggregates (iron ore, barite) or industrial by-products (such as different types of heavy slags) in the concrete mix. Concrete weight coatings are generally not bendable, reducing the capability of the pipeline to follow the terrain configuration.

Fig. 23 – Plant-applied concrete weight coating If available in the region where the pipeline is built, concrete coatings offer the highest flexibility to pipeline designers and contractors, as they have no limitations of use for negative buoyancy applications and can be used in any type of onshore wet environment from rivers to permafrost. Another advantage is that the concrete weight coatings offer not only negative buoyancy, but also mechanical protection against potential impacts. Finally, the concrete weight coatings’ long-term stability is another strong point – the pipeline operators can be sure that the concrete weight coatings will remain in place (if correctly applied) around the pipe for the entire service life of the pipeline, which is not always the case with other onshore buoyancy control systems that can slip away from the pipe or move along it, causing pipeline stability issues. A factor that has to be taken into account is that the plant-applied concrete weight coatings increase the weight that has to be transported and handled to and on the right-of-way, thus slightly increasing the project costs. Field-applied concrete coating, although having a neutral impact on the logistic costs, is a relatively slow process and can delay the pipeline construction process. Finally, using concrete weight coatings, applied in a plant or in the field, could be challenging in some remote ROW areas with difficult or restricted access.

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11.7.2 Cast Concrete Systems Cast concrete systems were developed to replace the earlier cast iron bolt-on weights that were more expensive and more difficult to manufacture. Although there are many variations of cast concrete buoyancy control systems, one can divide them in two main categories based on their installation method: - Set-on (saddle-type) cast concrete systems – these systems are built as a single-piece of cast concrete that is lowered on the pipeline at pre-determined distances. Because of their shape, they are sometimes called doghouse weights. The set-on systems sit on the top of the pipeline, with their sides straddling the pipe like a saddle. These systems tend to be used in semi aquatic environments, such as marsh or permafrost areas, as their relative instability on the pipe creates challenges for use in river or lake crossings - Bolt-on (half-shell) cast concrete systems – these systems are made of two cast concrete halfshells that are installed on the pipeline at pre-determined distances. The two half-shells are bolted together, usually using steel bolts, or strapped on the pipe, and cover the whole circumference of the pipe. These systems are used more often for aquatic environments, such as river and lake crossings, as their stability on the pipe is better than that of the set-on systems.

Fig. 24 – Set-on cast concrete weight Cast concrete systems are usually manufactured in a specialized facility and based on the specific requirements of the project – level of negative buoyancy needed, pipe diameter etc. They are always steel rebar reinforced and the concrete mix usually includes special sulphate-resistant cements that are suitable for construction applications in wet environments, as well as heavy aggregates for increasing the buoyancy control potential. They do not have limitations in terms of pipe diameter and – especially for the heavier ones – have handles provided for lifting and handling during transportation and installation. Because the contact between the pipe and the cast concrete can damage the anticorrosion coating of the pipe, the pipe itself or both, all the cast concrete systems have a protective lining installed at the interface between pipe and concrete. These linings are made of materials such as rubber, neoprene or non-woven geotextile fabrics. Cast concrete systems are used in regions where concrete weight coatings are not available or are available at a much higher cost. Their main advantage is that they can be built by any cast concrete manufacturer, even having minimum previous experience in the pipeline construction industry. The quality of their long-term buoyancy control is dependent on the quality of their installation on the pipeline by the field crews of specialized contractors. Moreover, the installation of some of these systems – done on the right-of-way – can be slow, such as the bolting on of the concrete weights underwater by diver crews. Set-on cast concrete systems are inherently less stable and therefore cannot be used in most aquatic environments. Even the bolt-on systems can become unstable or move due to strong water currents or other external impacts (ship anchors etc). Finally, cast concrete systems present a risk of damaging the pipe and its anti-corrosion coating during the installation – for example, the risk of a cast

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

concrete weight falling on the pipe â&#x20AC;&#x201C; and later, during the service life, especially if the concrete system moves from its designed place.

11.7.3 Aggregate Envelope Systems Aggregate-filled envelope systems have been developed during the 1990s as a new method for solving the floatability issue in onshore wet environments. These systems have quickly carved a market niche for themselves as solutions of choice in regions where the restricted access does not allow for the use of concrete-based buoyancy control systems or where these systems have a much higher cost. The aggregate envelope systems, or saddle weight bags, are usually strong membranes made of materials such as non-woven geotextile fabric, with one or more compartments that are filled with sand or local aggregates and then placed on the pipeline for buoyancy control. The industry has developed different versions of these systems that can replace the two main categories of cast concrete systems; there are strap-on versions that are replacing the bolt-on cast concrete systems and set-on versions that are replacing the set-on cast concrete systems.

Fig. 25 â&#x20AC;&#x201C; Aggregate-filled geotextile envelope system Just like any of the competing systems, the aggregate envelope systems have some strong points and some weaknesses. The aggregate-filled envelope systems are less expensive on a total installed coat basis compared to the cast concrete or concrete weight coating systems. This cost advantage comes mainly from the fact that the transportation costs are lower â&#x20AC;&#x201C; only empty saddle bags have to be transported to the ROW, where they are then filled with local material. The use of locally available filler material (sand, natural aggregates) also reduces the costs, compared to concrete systems. Their installation is also simpler and quicker than that of cast concrete systems. Aggregate envelope systems also conform better to the bottom of the pipeline trench and do not require a deeper trench like some of the cast concrete systems. They do not need a protective liner as the cast concrete systems do. Finally, they can easily be transported to restricted access areas where other systems cannot be transported and extra bags left after the installation can be returned or easily stored and retained for the next project. Although the aggregate envelope systems can easily be used in semi-aquatic environments (marshes, permafrost), they are more challenging and slow to install than cast concrete systems in aquatic environments (such as rivers and lakes). Their stability in areas with strong water currents or other potential impacts is also questionable. Installation teams have to pay extra attention to the handling and installation of the saddle bags, in order to avoid rendering them useless through tearing or shredding. Finally, the efficiency of these systems will always be dependent on the quality of the installation process in the field, which cannot always be guaranteed.

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11.7.4 Steel Screw Anchors An emerging technology used for pipeline buoyancy control is screw anchors. Screw anchors are steel shafts with helices welded to them that are literally ‘screwed’ into the soil beneath the pipeline. One anchor is installed on each side of the pipeline, and then connected over the top of the pipeline with a saddle which will allow the anchors to resist the uplift forces on the pipeline. This technology was used extensively in North America in the late 1960s, but was phased out and traditional concrete buoyancy control methods took over. It re-emerged in the 1990s in North America as pipeline owners and contractors performed value engineering analysis, and studied ways to reduce the ever-escalating costs of pipeline construction. Since that time, they have been used extensively in North American and Asia, as well as South America, Africa, and Europe. There are several steps involved in the design of a proper screw anchor buoyancy control system: • Identify pipe characteristics, and safety factor required • Gather data on soil parameters (where feasible) or define assumptions for soil conditions (often in conjunction with contractor or screw anchor supplier) • Calculate maximum allowable centre to centre spacing of anchors along the pipeline, taking into account soil strength, anchor strength, allowable pipe stresses, and pipeline deflection

Fig. 26 – Pipeline with steel screw anchors Generally cost effective on pipelines with an outside diameter of 300 mm and larger, a screw anchor buoyancy control system can offer cost savings over concrete weight coatings or cast concrete systems. Cost savings are obtained through relatively large spacing between anchor sets along the pipeline length. This results in less material, transportation, and construction costs. The quality of screw anchors’ long-term buoyancy control is dependent on the quality of their installation on the pipeline by the field crews. Moreover, the installation of some of these systems – done on the right-of-way – can be slow, especially if installation has to be done underwater. Screw anchors do not offer any mechanical protection for the pipe and its anti-corrosion coating against impact and penetration damage from external sources (ship anchors etc). Finally, additional padding has to be inserted between the steel connection on top of the pipe and the pipe itself to avoid any damage to the anti-corrosion coating and the pipe. Screw anchor systems also present a risk of damaging the pipe and its anti-corrosion coating during the service life if the anchors move from their designed place.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

11.7.5 The Optimal Buoyancy Control System – Selection Guidelines In order to minimize the risks for the stakeholders involved in an onshore pipeline project, the buoyancy control approach has to be discussed as early as possible during the early stages of the project. In order to choose the optimal buoyancy control system(s), the parties involved have to use criteria that are similar to those used for the other pipeline protection systems. -

Technical performance criteria – in the case of buoyancy control systems, the most important technical performance criteria will be the ability of the buoyancy control system to reach and maintain the required level of negative buoyancy over the entire service life of the pipeline. The stakeholders will have to assess if the selected systems have to fulfil other needs, such as the need for mechanical protection against various types of impacts.

Design and constructability criteria – based on the specifics of the project, it is possible that some of the buoyancy control systems could not be used, due, for example to the limited access to the right-of-way

Environmental impact criteria – the stakeholders will be interested in selecting the buoyancy control system that will minimize the overall environmental impact of the project, such as habitat loss for aquatic fauna and flora, disturbance of environmentally-sensitive areas (marshes and permafrost) etc.

Economical criteria – the stakeholders will assess the availability of different buoyancy control systems in the project’s region and will compare the total installed cost of each system; the stakeholders will be interested in selecting the system that offers the optimal level of buoyancy control with the lowest total installed cost. The total installed cost will include not only the purchase price of the buoyancy control systems, but also the direct and indirect installation costs – such as additional transportation and handling costs, additional manpower and equipment needed for installation, installation time etc.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

11.8 – Cathodic Protection 11.8.1 Background Typically, an external pipeline corrosion protection system consists of two components – the coating and the cathodic protection (CP) system. Corrosion takes place when electrons are removed from the metal at the anode area on the pipe surface and consumed by the reaction at the cathode with oxygen or hydrogen. For corrosion to take place there must be: • • • •

Anode (corroding area) Cathode (protected area) Electrically conductive metallic path connecting the anode and the cathode Ionically conductive electrolyte immersing the anode and cathode

There can be various causes of corrosion including: • Differential Aeration Cells: A pipe installed under a paved road in compact soil reduces the amount of oxygen at the pipe whereas as pipe in nearby ditches may be in aerated soil. Corrosion takes place in the pipe beneath the road. • Dissimilar Soils: In soils that are more conductive, corrosion takes place along those sections of the pipe. • New / Old Pipe: New pipe used to replace a section of line becomes the anode and corrodes, protecting the old sections.

11.8.2 Purpose / Objective of the CP System The anodic or corroding areas and the cathodic or protected areas on a pipeline are commonly on the same surface but separated microscopically. The coating system is the primary barrier against environmental corrosion while the CP system is a secondary defence to protect areas of the pipe that become exposed due to scratched, missing or damaged coating. CP is typically used to prevent corrosion at any weak areas in the coating such as field joints or damaged spots. CP is fundamental to preserving a pipeline's integrity by replacing the electrons generated by the normal corrosion process. CP controls corrosion by supplying an external direct current that neutralizes the natural corrosion current arising on the pipeline at coating defects. CP prevents corrosion by converting all of the anodic or active sites on the metal surface to cathodic or passive sites by supplying electrical current from an alternate source. The current required to protect a pipeline is dependent on the environment and the number and size of the coating defects. The greater the number and size of coating defects, the greater the amount of current required for protection.

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11.8.3 Available Cathodic Protection Systems There are two main CP methods of providing protection against external corrosion â&#x20AC;&#x201C; the impressed current and the galvanic protection methods. Impressed Current Cathodic Protection Impressed current CP describes the case in which the electric current for protection is provided by an external power supply. This type of system uses a ground bed and an external power source to impress current onto the pipeline. For a buried, onshore pipeline, a generator or a local utility provides the electricity. Commercially supplied AC is converted to DC. The system uses an anode bed and an external power source to impress current onto the pipeline. Impressed current protection involves connecting the metal to be protected to the negative pole of a direct current (DC) source, while the positive pole is coupled to an auxiliary anode. Electrons are introduced into the pipe and leak out at the bare areas where the cathodic reaction occurs. Impressed current CP is rarely used in subsea pipelines. The ground bed is important for the effectiveness of the impressed current systems. It transfers current from the source through the ground to complete the circuit with the pipeline. One of the most common ground beds is the horizontal type with anodes installed with a backhoe at a depth below the frost level in the soil. Negative Return Cable (Structure Connection)

DC Power Supply

Insulated Anode Cable Protected Structure Sea Water Impressed Current Anode

Galvanic-Anode Cathodic Protection Subsea pipelines are commonly protected by galvanic anodes. This method employs the basic conditions needed to produce an active corrosion cell: an anode, cathode, electrically conductive pathway and electrolyte; and a difference in energy level between anode and cathode. The flow of current through the electrolyte is always from the anode to the cathode. Wherever electrical current leaves the anode to enter the electrolyte, small particles of iron are dissolved into solution, causing pitting at the anode. Wherever the current enters the cathode, hydrogen gas is formed on the surface and the cathode is preserved and protected from corrosion. If one of the conditions above is removed, corrosion cannot continue. It is the removal of one of the conditions, to reduce or interrupt the flow of current, which is the basis for CP.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 11

Protected Structure (Steel) Sea Water Aluminium Anode

Anode Connection

For ground installations, the electrolyte is the moisture of the soil. The anode is a material having a more electronegative potential than steel. Typically, it is made from materials such as aluminium, zinc, magnesium or alloys of those metals. When the materials used as anodes are mechanically coupled to steel with an attachment wire, the steel pipe becomes the cathode. Subsequently, a current flows, and the anode corrodes to provide electrons that protect the pipeline. CP trades corrosion on the pipe for corrosion on the sacrificial anode. The driving voltage (the difference in potential between the anode and cathode when coupled together in a corrosion cell) is limited with galvanic anodes; the amount of current that can be delivered tends to be low. Galvanic anodes are normally used in low resistivity soils to provide current to pipes having an excellent coating.

11.8.4 Anode Material Selection Zinc has been in use as a sacrificial anode for longer than aluminium and is considered the traditional anode material. However, aluminium has several advantages as a sacrificial anode material and is now the material of choice (magnesium can be used for onshore pipelines but is not efficient for subsea pipelines because it corrodes rapidly in seawater and only provides about half the electric current for CP). Aluminium is capable of delivering more current in seawater and has higher a current capacity, so a lower consumption rate. Thus a smaller mass of aluminium anode will protect the same surface for a given period of time as compared to a zinc anode. This leads to greater economy and improved performance in using aluminium as opposed to zinc. Moreover, the effect of operating temperature on the anode materials is very important. Zinc anodes alloy contains small quantities of iron which leads to intergranular corrosion. Aluminium is also usually preferred to zinc because it is less expensive. The temperature will have an important impact on the electrochemical capacity â&#x20AC;&#x201C; as seen below the anode current capacity decreases as the temperature increases, reducing the CP effectiveness.

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11.8.5 Cathodic Protection System Design The goal of CP system design is to provide the minimum potential that provides CP. A potential above that level increases the cost and the electrical stress across the coating and may lead to cathodic disbondment. The galvanic anode system should be designed such that a sufficient current is provided to the pipeline to maintain the required potentials throughout the design life. There are two different kinds of galvanic cathodic protection available. Below is an overview of both, together with the benefits and limitations of each method. Bracelet Anodes Today, almost all new pipelines installed are equipped with bracelet anodes. Two different kinds of materials are normally used: aluminium and zinc. Bracelet anodes are cast as two halves that fit together around the pipe. If there is no weight coating, the anodes are profiled with tapered ends, otherwise with shouldered ends when a weight coating is used. Bracelet anodes may be fitted to the pipe as it is laid or retrofit anodes may be attached to the pipeline once it is in place. Retrofit anodes have the benefit of being separated from the pipeline and so are not exposed to elevated temperatures. The anodes are electrically connected to the pipeline by copper braided wire (pigtails), one end connected to the steel insert and the other brazed or welded to the pipeline.

Square shouldered bracelet anodes are typically used on pipe that has a concreted weight coating.

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Tapered anodes are designed to be installed on pipelines with only a corrosion or insulation coating. It is to protect the bracelet anodes during the pipe-laying process, and stopping them snagging on the rollers used on the vessel firing line and stinger. Even with these tapered designs, non-weight coated pipelines can still suffer anode damage, which can in turn cause coating damage. Several methods are being used to combat this problem such as polyurethane tapers or mounting both halves of the bracelet on top of the pipe thus avoiding contact with the stinger during pipe laying. Retrofit Anodes Retrofitting is normally used for the installation of additional anodes when a CP system is not adequate, or for extending the design life of the CP. It is also possible to use a retrofit system when it is not possible to use anode bracelet, for example where the temperature of the pipeline would render bracelet anodes ineffective. Finally, a retrofit CP survey is usually less expensive and easier to undertake.

11.8.6 Coating breakdown factor The purpose of a protective coating on the pipeline is to restrict the access of oxygen to the pipeline and thus reduce the current demand. For CP design it is assumed that the protective coating is 100% effective except at areas of coating breakdown. The bulk of the protection current passes through the coating because all organic coatings are permeable to oxygen to some extent. When the oxygen arrives at the steel surface, it will remove electrons. This appears as a current flux through the coating. As the coating ages, the resistance to permeation decreases and a higher oxygen flux occurs resulting in a higher current flow through the coating. The final coating breakdown has a higher value than the mean coating breakdown. This means that the coating will protect the pipeline less, and will be more prone to external corrosion

11.8.7 Total net anode mass The total net anode mass corresponds to the weight of anodes which must be used to provide sufficient potential protection to the pipeline over its life. The total net anode mass is directly related to the anode

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utilization factor and the electrochemical capacity of the material used. For example, as zinc and aluminium do not have the same properties, the total net mass required may change considerably. The table below shows the difference between materials for a pipeline with no external coating.

11.8.8 Anode utilization factor The anode utilization factor is required because it is not possible to obtain 100% utilization of the anode material. Anodes are made by casting the anode material in a steel former. During fabrication the anode corrodes down to the inner ligature of the casting around the former, meaning the anode material loses electrical connectivity with the former, thus rendering a percentage of the anode unusable.

11.8.9 Anode Numbers The required number of anodes is calculated from the weight of each individual anode as a function of the total net mass demand. So if, we are using lighter anodes the number of anodes required will increase. Because it is necessary to respect a maximum distance between anodes (see section 11.8.5), it is important to find a compromise concerning the number of anodes. Using fewer anodes will reduce the cost of installation but may not provide sufficient current along the pipeline, whereas using a large number of anodes will provide sufficient current, but result in a higher installation cost. The number of anodes is also dependent of the final individual anode current output and the demand for cathodic protection of a pipeline section. This will usually provide a lower anode numbers. But in order to have sufficient protection, the required number should satisfy both criteria.

11.8.10 Cathodic Protection Surveys Periodic inspection of the pipeline CP system is necessary to ensure that the system is functioning correctly. There is no corrosion allowance provided for external corrosion. A common approach is to inspect the pipeline shortly after installation, usually within the first year of service to ensure that the anodes are functioning and, then to resurvey about halfway through the design life of the CP system. The long delay from initial to second survey is acceptable because the coating on the pipeline should remain intact and the anodes are designed for protection of a significantly deteriorated coating.

11.8.11 Overprotection Overprotection refers to the use of excessively high potentials to protect the pipeline. High potential can become a problem if the spacing between ground beds is too great or when poorly-coated lines are electrically connected to well-coated pipelines. Calculations take into account factors such as pipe resistance, soil resistivity, coating conductance and potential limitations to determine the spacing that meets the CP criteria without causing excessive potential near the ground bed. It may also be necessary to insulate segments with poor coating quality from those with good coating quality. Proper CP design should minimize overprotection.

Conclusion The industry has come a long way in ensuring the integrity of pipeline projects. However, as the pipeline sector is growing further, challenges are born from the complexity of the new pipeline projects â&#x20AC;&#x201C; more

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extreme climatic conditions, populated areas, longer pipelines, etc – and from the new pipeline operation requirements – increasingly high or low operating temperatures, higher pressures, new products transported through pipelines etc. Innovation is thus needed to continue to ensure the integrity of new pipelines and to maximize their transportation potential. Therefore nowadays the companies in the pipeline industry pay equal attention to all the aspects of pipeline integrity during all the stages of the supply chain, as well as during the pipeline installation and service life. The keyword for the future in this field is innovation - new coating materials, new coating systems, new application processes - and new holistic approaches to make the pipelines safer and more efficient.

References 1 J. Alan Kehr, “Fusion-Bonded Epoxy (FBE) – A Foundation for Pipeline Corrosion Protection”, Houston, Tx, NACE International, 2003 2 D. Newman, “Pipeline Corrosion Protection for High Pressure High Temperature Deepwater Pipelines”, 2010 3 A. Palmer, R. King, “Subsea Pipeline Engineering”, Tulsa, Oklahoma, PennWell, 2004

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Appendix 11.1.1 Comparison of Mainline External Anti-Corrosion Coatings3

Coating System Single-layer Fusion-Bonded Epoxy (FBE)

National/ International Standard • •

CSA Z245.20 EN ISO 21809-2

Strengths

• • •

Excellent corrosion resistance Does not shield CP system High adhesion limits damaged areas

Weaknesses

•

• Dual-Layer Fusion-Bonded Epoxy (2L FBE)

•

CSA Z245.20

•

• 3-Layer Polyethylene (3LPE)

• • • •

DIN 30670 NFA 49 711 CSA Z245.21 EN ISO 21809-1 (draft)

• •

3-Layer Polypropylene (3LPP)

• • •

DIN 30670 NFA 49 711 EN ISO 21809-1 (draft)

• • • •

Depending on the topcoat selection, very good abrasion and damage resistance – ideal for special applications such as HDD – or very good performance in high operating temperature environments Excellent corrosion protection

• •

Excellent handling Superior low temperature flexibility and impact resistance Excellent corrosion resistance Excellent moisture resistance

•

Excellent handling Excellent impact resistance Excellent corrosion resistance Excellent moisture resistance

•

• • • • • • •

3-Layer Composite Coatings

• •

CSA Z245.21 EN ISO 21809-1 (draft

• • •

• • Tape Coatings

•

DIN 30670

• •

Low impact resistance results in considerable damage during pipe handling, storage, transportation and installation High moisture absorption and permeation especially at high temperatures Affected by UV during storage Low flexibility Sensitive to steel surface preparation and condition High moisture absorption and permeation especially at high temperatures Affected by UV during storage

Prone to thinning across raised weld seams Side extrusion prone to delaminations and voids Sensitive to steel surface preparation and condition Minimum thickness constraints Prone to thinning across raised weld seams Side extrusion prone to delaminations and voids Sensitive to steel surface preparation and condition Minimum thickness constraints

Excellent handling Excellent corrosion resistance Excellent low temperature impact resistance and flexibility Excellent moisture resistance Excellent raised weld coverage

• •

Thickness constraints Sensitive to steel surface preparation and condition

Good corrosion resistance Good impact resistance

•

Prone to delaminations and voids Protection is dependent on the quality of the installation crew (if installed in the field)

•

Adapted after New developments in high performance coatings, Worthingham R., Cettiner M., Singh P., Haberer S., Gritis N., 2005

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Appendix 11.1.2 Field Joint Coating Selection Table Mainline Coating

Most Common Field Joint Systems

Alternate Field Joint Systems

Relevant Standards and Specifications*

Fusion-bonded epoxy (FBE)

- Fusion-bonded epoxy (FBE) - 2-Component liquid epoxy (2CLE)

3-Layer heat-shrinkable sleeve (3L HSS)

1, 2, 7, 8, 9, 10, 12

Dual-layer FBE (2L FBE)

- 2-Layer fusionbonded epoxy (2L FBE) - 3-Layer heatshrinkable-sleeve (3L HSS)

2-Component liquid epoxy (2CLE)

2, 4, 7, 8, 9, 12

Adhesive tape systems (CAT) - <50ºC - 2-Layer heat-shrinkable-sleeve (2L HSS) - >50ºC - 3-Layer heat-shrinkable-sleeve (3L HSS)

1, 3, 4, 5, 7, 9, 12

- 3-Layer polypropylene heatshrinkable-sleeve (3LPP HSS) - 3-Layer polypropylene tape (3LPP Tape)

- Injection-moulded polypropylene (IMPP) - Flame-sprayed powder (FSPP)

1, 4, 6, 7, 9, 12

3-Layer composite

3-Layer polyethylene heat-shrinkable sleeve (3LPE HSS)

Flame-sprayed powder (FSPE)

1, 4, 7, 9, 12

Tape

- <30” diameter adhesive tape systems (CAT) >30” diameter - 2-layer polyethylene heatshrinkable sleeve (2LPE HSS)

- 2-Layer polyethylene heatshrinkable sleeve (2LPE HSS) - 3-Layer polyethylene heatshrinkable sleeve (3LPE HSS)

1, 4, 7, 9, 11, 12

3-Layer polyethylene (3LPE)

3-Layer polypropylene (3LPP)

* Standards and Specifications: 1. ISO/FDIS 21809-3:2008(E) Petroleum and natural gas industries — External coatings for buried or submerged pipelines used in pipeline transportation systems — Part 3: Field Joint Coatings 2. CSA Z245.20, External fusion bond epoxy coating for steel pipe 3. CSA Z245.21, External polyethylene coating for pipe 4. EN 12068 Cathodic Protection - External Organic Coatings for the Corrosion Protection of Buried or Immersed Steel Pipelines Used in Conjunction with Cathodic Protection - Tapes and Shrinkable Materials 5. NFA 49-710, Steel tubes. External coating with three polyethylene based coating. Application through extrusion. 6. NFA 49-711, Steel tubes. External coating with three polypropylene layers coating. Application by extrusion. 7. DNV-RP-F102 Pipeline Field Joint Coating and Field Repair of Linepipe Coating 8. NACE RP0105-2005, Liquid-Epoxy Coatings for External Repair, Rehabilitation, and Weld Joints on Buried Steel Pipelines 9. NACE RP0303-2003, Field-Applied Heat-Shrinkable Sleeves for Pipelines: Application, Performance, and Quality Control 10. NACE RP0402-2002, Field-Applied Fusion-Bonded Epoxy (FBE) Pipe Coating Systems for Girth Weld Joints: Application, Performance, and Quality Control 11. AWWA C209 Cold-Applied Tape Coatings for the Exterior of Special Sections, Connections, and Fittings for Steel Water Pipelines 12. AWWW C216, Standard for Heat-Shrinkable Cross-Linked Polyolefin Coatings for the Exterior of Special Sections, Connections, and Fittings for Steel Water Pipelines

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Field Joint Coating Selection for Polyurethane Foam Coated Pipeline Systems

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Appendix 11.1.4 Supplementary Mechanical Protection Systems Selection Table

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Pipelines and the Environment (section to be developed)

This multiple-aspect topic also deserves a section of its own, yet to be developed.

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Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 13

New Trends and Innovation

13.1 Functional Specifications for a Near-Real-Time Construction Monitoring Tool Introduction The concept of developing a responsive and prompt project controls tool, aiming to enhance the efficiency, quality, safety and environment of onshore pipeline construction operations, emerged as a prospective route towards establishing an integrated GIS-based pipeline construction management system. The purpose of this section is to recommend the basic functional specifications for developing a "nearreal-time (near-live) monitoring tool”, a comprehensive project controls tool with a GIS-based interface, which can be used during the life-cycle of the pipeline construction project. Technical specifications and subsequent development of a system that meets these specifications would follow this preliminary phase.

Scope of Innovation The tool aims at presenting an accurate outlook on the major aspects of the construction cycle as well as significant related events, as soon as they occur or can be recorded, and in a visual geographical environment. Updated feedback would include:

• • • • •

Construction progress reporting Project information and documentation Assets and resources management Material control and traceability information Quality control data

The ensuing visual controls platform shall comprise data-rich feeds and dynamic reporting which would enhance the proactive involvement of project staff for better anticipation of construction conditions and improvement of the critical decision making process.

Description Building on the collaborative experience of pipeline contractors, major data groups were identified as key elements of the pipeline construction phase. While these groups are not necessarily conclusive, they provide the guideline for the way forward. Appendix 13.1.1 provides a more comprehensive profiling of the groups, information sources, attributes, data workflows, and potential operations enhancements. The following is a list of these data groups with their associated classes:

•

Material management

• Pipe shipments • Pipe yards • Stores information

•

Manpower

• Accommodation information • Manpower data

•

Equipment

• • • •

Machinery and vehicle stores Emergency equipment Equipment tracking information Vehicles tracking information

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 13

•

Progress

• Construction progress of activities • Planning/scheduling of activities

•

HSE and social

• • • •

•

Points of interest (hospitals, medical centers, police stations etc.) Accidents and incidents Grievances and complaints Areas of special status Engineering data

• • • • • • •

Pipeline routes Crossings Access roads AGIs and tie-in points Marker points Fiber-optic cables Geotechnical and cathodic protection data

The diagram below indicates the information associated with the data groups identified in this section, and how they and the technical specifications serve to provide the high-level users with an integrated controls platform.

Features

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With this scope in mind and to facilitate user interaction, the development of this platform must encapsulate state-of-the-art features and workflows built on the concepts of a GIS interface, web accessibility and shared data repositories. The tool would be empowered by:

• •

Links to the existing project controls and logistics systems

• • •

Modern technologies and practices in systems development

Business features such as electronic data interchange (EDI), flags, notifications, flexible reporting tools, and improved procedures State-of-the-art market tools R&D on new concepts with innovation potentials

For each of the data groups, an EDI needs to be developed with the related systems to which the tool will link. An EDI is generally defined as a standardized or structured method of transmission of data between two media, and in this context the EDI will govern what information will be collected for each data group, its format, in addition to how, when and by whom it shall be acquired. Properly characterized and implemented EDIs are integral to the successful design and operation of the tool. Flags and notifications are also essential features. The idea is to have intelligent reminders or prompts that are automatically generated to highlight anomalies, points of concern arising, or cues for further considerations, and that require action (flags) or raised awareness (notifications). The trigger for flags and notifications would be based on the data processed from various data groups and, crucially, their design and scope needs to be based on a well-founded knowledge of the construction workflows and on the different roles of the project players who would need to interpret them and take consequent actions.

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Flags and notifications would take on different formats, including RSS feeds, SMS, multimedia messages, emails, or even image and video feeds, with access through the interface. The accessibility to these flags would be linked to different roles on the project, for example equipment notifications would be directed mainly to plant managers and engineers whereas material shortages would be displayed for material personnel and control managers. The format for these notifications should allow for an adequate level of flexibility to meet different needs and work practices by different players, for instance the ability to subscribe to specific RSS feeds upon demand, and secure limited access to sensitive feeds. The figure abovr is a conceptual example of a GIS-based dashboard that collects information about site construction equipment and associated systems, and acts as a monitoring tool for these assets. It incorporates the EDI concept, GPS locating technology, and an RSS-type strip for flags and notifications. Another feature of vital benefit to the management is the ability to extract various formats of progress, statistical, analytical and listing reports. While formal reports can be obtained by links to the EDMS, the tool must accommodate more interactive reporting techniques including pivot tables, dashboard queries, data-mining techniques and visual charts. The concept of near-real-time inherently implies the employment of the latest available technologies. As such, development of this tool would typically involve innovations in:

•

IT and communication such as satellite connectivity, WiMAX and WiFi technologies, GPRS, and GSM

•

Automated data acquisition techniques such as the use of handhelds, PDAs, RFIDs etc.

•

Modern construction approaches and technologies such as computerized NDT, AUT, automatic welding, and GPS surveying

•

Business process management and project control workflows and solutions

Expected Advantages In line with the IPLOCA Novel Construction objectives, the development of this tool will stimulate innovation in the processes of controlling the pipeline construction. It will also invoke improved technology techniques, market software and R&D on new concepts to achieve this step forward. Potential benefits include:

•

Efficiency: The tool would instigate an overall improvement in the efficiency of project construction tasks by allowing decision makers to monitor site activities, retrieve up-todate progress reports, foresee possible hiccups and take immediate action

•

Quality: By serving as near-live information storage and sharing container, the tool would improve the quality of work done at supervisory level, drilling down to the direct manpower level. The data would be available at a secure role-based portal for all key players including project management, engineers, construction crew leaders and project partners

•

Safety would be enhanced by adopting this tool through:

• Providing immediate alerts on safety and security threats and concerns that would otherwise escalate without prompt action

• Assisting management in better planning for safer manpower activities (including accommodation, transportation and emergency plans) by providing a multilevel geographical view of the project’s different locations and facilities

• Cutting down site visits by supervisory personnel by providing remote access to

•

most of the information required Environmental awareness is promoted through the use of the tool by:

• Better control and maintenance of project equipment with early notifications of breakdowns and spills, leading to a better control of emissions

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• Identification of environmentally sensitive issues and zones and propagating this knowledge to the different levels of project staff

• Decreasing the carbon footprint created by the project supervisory personnel by reducing the necessity for direct site visits, hence promoting “Green Construction Culture” The conceptual specifications in Appendix 13.1.1 are the first step towards building this tool. The latter would in turn provide a cornerstone for the pipeline simulation tool discussed in the following section, by providing the prerequisite information needed for more accurate simulations of construction activities and related what-if scenarios.

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13.2 Conceptual Specifications for Building a Pipeline Construction Simulation Tool Computer Simulation â&#x20AC;&#x153;A simulation is the imitation of the operation of a real-world process or system over time.â&#x20AC;? Computer simulation involves the creation of an artificial history of a system and the observation of that history to make analogies and conclusions about the operation of the real system. A simulation model, in the form of assumptions, is required to describe the behaviour of the system over time and the relationship between its constituents usually expressed mathematically, logically and/or symbolically. A simulation model can be used to investigate a wide variety of what-if questions about the real-world system. It can be used as an analysis tool to assess the impact of potential changes on the system and study the performance of a system in the design stage. Computer simulation and modelling is especially effective for real-world systems which are too complex to be solved manually using mathematics. Computer simulation can run at virtual speeds, much faster than real life, so results can be obtained in a fraction of the time required in real life. It offers insights into resource interaction and their effect on the system. Bottleneck analysis and elimination can be performed on the computer without any real life resource costs and time requirements. What-if analysis and scenarios can be run quickly and at much reduced costs. Simulation has gained a lot of momentum in recent history. Universities now dedicate courses and programmes to the study of computer modelling and simulation. Corporations are adopting it as a means for predicting outcomes, adapting to change during execution, and for retrospective analysis. The knowledge gained through simulation reduces the risk associated with important decision making in real life.

Computer Simulation In Construction Computer modelling and simulation is an important management tool well suited to the study of resource-driven tasks and processes. This makes construction activities prime candidates for the application of computer simulation as it helps analyse resource requirements, process interaction and factors that affect construction processes (random internal and external factors).

Case Studies (from an IPLOCA member) At this IPLOCA member company, we have successfully applied computer modelling and simulation of construction activities over the past few years. Such applications included using different modelling and simulation techniques for the different situations encountered. We have been able to effectively apply our different simulators during the tendering phase, during execution and retrospectively for lessons learnt and quantification and justification of a claim. The following are two of our more recent case studies of applying computer simulation in construction.

Case Study 1: Using the earthworks simulator during the tendering phase Scope: A large excavation and removal of material operation (55 million m3) needed to be performed within a specific period of time. The process also involved screening the removed material for possible use as fill material. The estimators wanted to test different methodologies and equipment mix alternatives to assess time and equipment requirements, find the optimal solution, and use it as basis to estimate the cost of the operation. Achievements: The Earthworks simulator presented itself as an advanced tool capable of quickly and accurately mimicking real world earthworks operations enabling engineers to quickly and efficiently build and run scenarios to examine all the proposed alternatives. Each of the possible alternatives was fed into the simulator and the results compared to the proposed mix. The simulator helped in quickly

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reaching an optimal equipment mix for use as the basis for estimating the operation. The results of the simulator were soon after validated against site findings during execution.

Case Study 2: Use of simulation in quantification and justification of a claim for extension of time Scope: a major early site works project had as its two major operations the excavation and transportation of existing material away from site, and the import of fill material from a distant quarry. After project award, many additional constraints were placed on the project, and which had not existed during the estimation of the project. Such additional constraints included allowable truck sizes and weights, transportation routes, onsite speed and routing, weight bridges for both in and out traffic, and additional security gates. The simulation team was called upon to assist in quantifying the impact of those additional constraints on traffic congestion (truck trips per hour along the different routes) and the total duration of the project. Achievements: Traditional critical path method (CPM) planning tools were not able to incorporate all the variables and constraints to estimate the new time and equipment requirements. Computer simulation presented itself as a viable option to handle all the new variables and constraints and incorporate them into a new time and equipment requirements estimate. In order to assess all those constraints, two simulators were used in sequence. The first simulator summarized and combined all the variables related to the route sections into a single average route speed variable. The average route speed variable was then fed into the earthworks simulator along with the remaining constraints to assess total truck requirements and total duration for each of the operations. Total truck requirements over the prescribed duration allowed the calculation of truck traffic per hour. The use of the simulators was invaluable in quantifying the effects of the additional constraints mixed with the number of variables involved in the earthworks operations, and running numerous alternative scenarios quickly and efficiently, a task that proved very difficult to manually handle. The quantified results produced by the simulator helped determine the total duration of the operations and the calculation of truck traffic per hour; those results were then exclusively presented to the client as justification for the request for additional time.

Pipeline Construction Simulator Pipeline construction projects are by nature complex linear projects with dynamic properties that vary along the length and duration of the project. Although it is possible to use analytic techniques to plan and manage the performance of such projects, using simulation can provide us with an advantage in addressing the complexity and dynamicity involved in pipeline projects. A computer simulation of pipeline construction projects is a valuable predictive tool where we can vary inputs, collect and analyse outputs, and determine bottlenecks and sources of waste and delay. We can also determine the best preemptive measures to take to minimize risks of delays and cost overruns. The basic objective of the simulator is to be able to simulate construction of pipelines at any point of the project life, before or during construction. It will allow us to perform scenario-based planning and forecasting during execution. The target users of this simulator include project managers, planners, estimators, procurement, engineering, construction engineers.

Major Operational Components of the Simulator 1. Pipeline Construction WBS: The basic subdivision of a pipeline project in terms of construction is through the construction work breakdown structure (WBS). For the simulator, this will follow a generic WBS suitable for all projects. It is broken down into seven levels as follows: a. Project: the top level definition of the pipeline construction project. b. Areas: these are the major sections of the pipeline. c. Subareas: these are the subsections of the pipeline.

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d. Fragnets: these are the sequence of activities to build the subarea. In the case of a pipeline project these can be represented by the March charts (sequence of work of crews) for the relevant subarea. e. Schedule Activities: standard activities for the subarea as per the construction schedule. f. Objects: these are usually distinct construction objects which in the case of a pipeline construction project would be the kilometers within the subarea. g. Operations: if needed, further elaboration or subdivision of work for an activity 2. Resources: The main resources to be managed within the simulator will be equipment, crews, and camp capacity. The simulator can run in either of two modes with respect to resources. In unlimited resources mode, the simulator will attempt to finish the project within the shortest possible time and deduce the corresponding required resources. In constrained resources mode, the simulator will run with the assigned resources and indicate the total time required to finish the project. 3. Material Management: Required piping material as extracted from alignment sheets will be assigned and handled by the simulator at the kilometer level. Hauling routes of material between stores and site and in-between sections will be optimized by the simulator. Material in different phases (already on-site, being shipped, ordered, requisitioned) can be selectively used in the simulator to examine the effect of material availability on the project. 4. Camp Management: Camp capacities dictate the available number of crews per construction area and sub area. The simulator will aid in planning camp logistics over the duration of the project in relation to progress and managing transfer of camp units from camp to camp based on the manning chart produced by the simulator. 5. Pipeline Construction Activities: Every sub area and kilometer combination is usually represented by one or more March charts. Each line of the March chart is the work of one crew whose scope can be deduced from data extracted from engineering (alignment documents?). The slopes of the lines of the March charts represent the productivities of the crews and it is assumed that these lines should stay parallel at all times with no interruption in work. The simulator will examine and validate the aforementioned assumptions based on activity parameters and resource, material and camp constraints, and indicate any convergence or divergence in the March charts. The simulator can also help manage multiple crew assignments to same task/location, work priorities and sequencing. 6. Other Construction Activities: These activities are usually considered as independent subareas with no pipeline work such as pump stations, river crossings etc. Each will have its own fragnet and will be simulated in terms of activity parameters and resource, material and camp constraints. 7. Spatial Integration: GIS systems can help both visually and with spatial data and information for the simulator. Two-way integration with a GIS system would allow the simulator to read spatial information for optimizing camp locations and sizing, borrow pit locations, and truck routing and send back progress and output information for visualization. 8. Optimizer: One of the objectives of the simulator is to address chronic issues with standard planning tools which offer only one perspective on construction execution by examining complex dynamic relationships between activities. Such dynamicity might allow for minimization of total time of execution through changing the sequencing of the activities when possible. Areas where such re-sequencing/optimization maybe examined and potentially applied include activities such

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as environmental protection related activities, tie-ins, cathodic protection, crossings, hydrotesting etc... 9. C3D - Simulation Integration: This simulator is meant to integrate with a core construction management platform, C3D, used by this IPLOCA member to manage pipeline projects, enabling C3D users to run comprehensive simulation models on construction WBS objects and their corresponding activities in C3D. This will allow users to call a simulation model, pass parameters to it, and receive simulation results, all from within the C3D environment. The three components of the integration between the simulation model and C3D can be summarized as follows: A. Model: A simulation model that describes the processes to be simulated and the interaction between them. This model is usually made up of: a. Objects that are the subject of the simulation b. Activities applied to those objects c. Process flow and logic d. Resources required for application of the activities on objects B. Parameters: Parameters are required to inform the simulator of the number of available resources for the current scenario. Users may also wish to experiment with the productivities of specific resources. As such, these can also be passed within the scenario. a. Resource Quantities b. Resource Productivities C. Inputs: For our purposes, C3D will pass to the simulator a list of objects that will act as inputs for the simulation model. The objects will each have a set of properties. a. List of objects b. Properties of each object: these properties in conjunction with the business logic built into the simulation model will dictate: i. The amount of resources needed ii. Time required for each of the activities to be applied to each object iii. Logical flow within the simulation model Running the simulator model with the objects and resources from within C3D will return a result set consisting of a list of time-stamped object statuses (activities completed) and resource requirements over time. This will allow the user to perform output analysis on the artificial history produced by the simulator and examine idle times for each of the resources. From within C3D, the user will also be able to run more than one model back to back, using the results from the running of one model as parameters for the subsequent model.

Basic System Requirements The pipeline simulator should run on a typical desktop or laptop computer. It should adhere to computer simulation industry standards such as discrete event simulation and high level architecture. It should be built on an industry standard development platform.

Proposed Methodology Ontology In building this simulator, we propose to use an ontology of the pipeline construction simulation with the following classes: Product: The product is a class which defines the pipeline to be constructed along with all associated permanent and temporary structures associated with the final product or the building process including the pipeline, segments, sections, routes, impediments, and structures.

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Process: The process is a class which defines all process-related activities, project schedule, resources and constraints. Environment: The environment is a class which defines all geotechnical information and constraints, weather, calendar, camp locations etc. Simulator Architecture Simulations can be based in any of many modelling paradigms. For our purposes, we propose to use discrete event simulation (DES), where the states in the system change when activities take place, and high level architecture (HLA; IEEE Standard 1516). The architecture of the simulator will be a two-tier mapping of the ontology defined above to the DES and HLA. The first tier will consist of process simulation models of the different pipeline project logistical and construction activities using DES. Each of the process simulation models will represent in detail either a main construction activity (ROW, stringing, welding, trenching etc.) or a logistical process (supply chain, camp operations etc.). The second tier will furnish a distributed simulation infrastructure allowing the different process models of the first tier to assimilate into a fully integrated pipeline construction simulation model where the processes can run from different locations and communicate and interact seamlessly. The different data sources required for the simulator will have to be defined throughout the simulator development process and mapped to the different process models. Simulator Outputs: A preliminary definition of the outputs to be delivered by the simulator to meet the above mentioned objectives along with an output analysis methodology are to be defined initially and continuously updated throughout the model development process.

Figure 1: HLA/DES Simulator Architecture

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Data Collection and Aggregation Historical data from previous pipeline projects is required for producing initial data trends to be used for populating simulator parameters. This will involve a comprehensive analysis of the proposed simulator parameters and definition of the sources of existing data required for input data modelling, analysis and distribution fitting. Fitted distributions will be used as stochastic parameters for productivities and process durations. Simulator Development Simulator development will structurally follow simulator architecture to deliver a high level architecture simulator composed of discrete event simulation models. Discrete event simulation models will be used to simulate the process models of the different pipeline construction and logistical activities. Each process model will have its own user interface that allows input of parameters and monitoring of simulation progress and outputs during simulation running. The simulation engine allows for the collection of various statistical data for each of the process models for analysis at the end of the simulation run. The distributed simulation infrastructure will be developed using an implementation of the high level architecture (IEEE Standard 1516) consisting of a runtime infrastructure, an object model template and a development framework for building and running distributed simulations Verification and Initial Validation Verification of a computer simulation model is performed to ensure that the programming and implementation of the model is conceptually correct. For this simulation model, a purposefully built simulation language will be used in conjunction with Visual Basic for both the DES and the HLA tiers. This inherently decreases the possibility of errors when programming simulation models compared to using a regular high level programming language such as Visual Basic, Java or C++ alone. It is essential that the model be verified continuously by the development team while it is being developed. Validation of the model is also a critical process as it involves ensuring that the model built does in fact mimic real life processes using the computer. Validation can be performed either by the development team or by an independent expert third party. The third party either performs a full independent verification and validation process, or an independent validation process in conjunction with a review of the verification process performed by the development team. Pilot Application We propose that a specific project be selected as an example application for the simulation model. This example application can be used for both developing the model and then running the simulator after initial verification and validation have been performed. Development Requirements It is estimated that a team of at least one leader and three specialized engineers will be required to work full time on this project for at least one year. The phases listed above will require a large amount of software development, travel, hardware, software, consultant work etc.

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13.3 Equipment Tracking System Overview The objective of this project is to satisfy the needs of companies owning a diversified fleet of equipment acquired from many major manufacturers in the market. For them, the option of using each manufacturerâ&#x20AC;&#x2122;s monitoring and tracking system on their respective equipment will render the monitoring task complicated. Efforts and initiatives to create a homogeneous architecture and technical platform as a unified base to enable data collection from the diversified fleet (via unified or similar systems adopting readily available interfaces or using the same normalized protocols) will have to be backed-up by partnerships, participation and dedication, which are requested from all the IPLOCA members. This chapter provides an overview of and vision for the near-real-time prototype equipment tracking system (ETS) recently developed by an IPLOCA member. It also presents the challenges, details and capabilities of the system. The aim is to share this prototype openly with the IPLOCA community, expecting other members to further contribute to its development. ETS is an equipment tracking system designed to monitor and administer the different aspects of an environment where equipment and machinery are used. These aspects include: Projects Equipment Employees Geographical fences (Geofences) Equipment commands and actions The remainder of this chapter serves to introduce this system, its features, its current implementation, as well as ideas for future development.

Vision The purpose of ETS is to provide management and staff with the ability to monitor and control equipment locations and operations. This will not only serve as a security measure, to keep track of the whereabouts of every piece of equipment at near-real-time, but can also assist in improving the project operations, availability, productivity rates, and resource management. One of the major benefits of such a system is lowering operating costs, thereby indirectly lowering the owning cost, by inducing better management of idle time, timely attendance to preventive maintenance, repairs and equipment fuel usage, and updating of enterprise asset management computerized systems. By enabling monitoring and management of these aspects, we expect to keep the assets in better technical conditions and eventually increase their useful lifespan which will provide the option to extend the periods over which the landed cost is depreciated, hence maintaining a lower owning cost and higher resale value. The system can also lead to increased productivity, by identifying over- and under-used assets based on observed modes of operation, and to improved logistics for fuel, transportation and service dispatch. The system also improves safety and risk management, through the monitoring of unauthorised areas and geographical fencing.

Challenges The goal of ETS is to provide a generic open solution, applicable across organisations, for any type of equipment or machinery. To support that, a universal standard must be agreed on for describing equipment GPS and CANBUS data and constructing a dictionary to support the CANBUS protocol (CANBUS, or controlled-area network bus, is a data bus standard which allows vehicle electronics to

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communicate with each other). By unifying this standard across equipment manufacturers, the process of outfitting new equipment with the hardware module and integrating them within the organisation’s tracking system can be a simple “plug-and-play” operation. Thus, regardless of the type of equipment, manufacturer, and CANBUS data (CANDATA) available, the overall procedure to capture and process data would be the same. However, reaching such a standard is no easy task and requires the collaboration of all parties involved in the field. Work is underway with major equipment manufacturers to find solutions for unifying the CANBUS protocols or to develop interfaces, so that specific equipment data that can be read, such as: Vehicle speed (wheel speed) Cruise control status Clutch status Power take-off (PTO) status Accelerator pedal position Overall fuel consumption Fuel tank level Engine speed Axle load of individual axles Total engine operating hours Vehicle ID number Software ID number Total vehicle mileage Next regular service Tachograph information Engine coolant temperature Fleet management system (FMS) standard information Seat belt on/off Harsh braking Excessive idling Over-speeding Over-revving Depending on the type of equipment, such data shall be modified and attributes added or deleted accordingly. Similarly such tracking systems can collect performance, diagnostic, tracking and safety data from other manufacturers of pipeline equipment producing pipe-facing machines, line-up clamps, automatic welding rigs, bending machines and others. Besides equipment malfunction errors, diagnosis and standard information, a variety of performance data can assist the production teams in their performance on site. For the following machines, examples of such data are: - Pipe-facing machines: bevel angle setting, rotational speed, cutting bit travel, idle rotations, etc. - Line-up clamps: hydraulic or pneumatic pressure, idle time, copper shoes thicknesses, etc. - Automatic welding machines: Bug speed, welding current, wire feed speed, Hiab crane usage, generator output, welding gas level, etc. - Bending machines: pipe sizes, counts, bend measurements, etc. With the help and assistance of major contractors, IPLOCA members and equipment manufacturers, the aim is to reach, as a first phase, the following goals: 1. Unification of the CANBUS standards 2. Free submission of the dictionary or Process IDs behind the CANBUS protocol 3. Alternatively, provide a low-cost interface unit to secure the CANBUS from client access and manipulation and have it restricted to be read-only; although the tool currently cannot feed to the CANBUS, it is “read-only”, designed to provide reports for data analysis. 4. IPLOCA members to push their equipment suppliers to follow the IPLOCA standard for data connectivity

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Components & Features The general purpose of the system is to provide monitoring capabilities of the equipment and their operations to the end-user. This is facilitated via two components: Hardware Module: a device deployed on every piece of equipment to be monitored and responsible for detecting, gathering and transmitting all location and CANBUS data. Monitoring Interface: a component integrated within the VBC Dashboard[1] software and designed for displaying equipment location and monitoring their motion in real-time. Via these components, the equipment tracking system can provide a fully-integrated solution having the following features: Posts GPS and CANBUS data from the device module deployed on each piece of equipment to a recipient endpoint which processes this data and inserts it into the ETS database

Figure 1. ETS monitoring interface [1] VBC Dashboard is a highly-usable interface using the latest rich internet applications (RIA) technologies. It allows the customizable consolidation of personal, team, departmental, project, corporate, and other external information into a single portal. It thereby provides the end user with a consolidated view of an organisationâ&#x20AC;&#x2122;s knowledge sources, and immediate access to key business information.

Visualizes ETS data via the monitoring interface by querying a web service created on top of the ETS database, exposing the functions required to get equipment information and latest locations Allows authorised users to force the application of specific actions on selected project equipment, to stop the engine or change a configuration for example, or to dispatch commands or messages to the equipment and its operator Restricts the presence of selected equipment to certain geographical locations and upon violation allows the transmission of alerts and/or execution of actions directly on the equipment Before exploring the components in detail, we stop to highlight two of the major features in the ETS system: geofencing and equipment actions.

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Geofencing The “geofencing” feature allows administrators to restrict the operation of equipment to selected geographical areas. Any violation to the bounds of these geofences is logged, indicating the violating equipment, in addition to the time and location of the breach. Accordingly, certain actions can be taken, from alerting an assigned employee to the violation as soon as it occurs, to the forcible shut-down of the equipment itself. Geofences can be associated with zero or more projects and/or zero or more equipment. Since a piece of equipment is contained within a single project, that equipment either inherits its project geofences (if any) or can be associated independently with its own separate geofences.

Equipment Actions Equipment actions allow administrators or authorised users to issue commands to control equipment or machinery operation or to configure the deployed device’s functionality. Such commands include but are not limited to: Turning the equipment engine on/off Turning the wireless on the device on/off Changing the interval of data transmission Upgrading the device module firmware or configuration A user can apply an action by scheduling it for execution on selected equipment at a certain date and time. The database keeps track of all actions scheduled, in progress, and completed. Upon request, the scheduled actions, whose time has passed, are dispatched to the device for execution. In addition to manually scheduling actions, equipment commands can be automatically triggered by certain events, e.g. a geofence violation or an infringement of predefined rules of operation. At such instances, an action can either be scheduled for immediate execution on the equipment itself or executed server-side, to send out an alert for example.

Monitoring Interface The monitoring interface is a web component within VBC Dashboard that communicates with a web service built on top of the ETS database. The service exposes all the required functionality for querying the data accumulated in the database. By invoking the service operations, this component can receive a list of all available equipment, their current positions and all associated data. In general, it is designed to: 1. Provide a graphical representation of the available equipment and associated data Equipment can be located by filtering on certain search criteria, either by the equipment fleet hierarchy or by project (or both). The equipment fitting the selected criteria are listed in a grid, and can be chosen to be displayed on the map. The latest posted geographical position of the equipment is shown on the map, indicating the equipment which is identified by its unique code. Selecting a certain vehicle shows the collected information relevant to that particular position, including the GPS latitude/longitude coordinates, the CANBUS data, all sensor-detected data, and the vehicle operator (if any). 2. Enable real-time tracking of equipment and vehicle movement The monitoring web component refreshes its view on a regular interval, each time requesting updated data from the web service. Since each deployed device is constantly posting its current geographical location to be stored in the ETS database, the service has access to the latest position received from the device, thereby enabling near-real-time tracking of the monitored vehicles’ motion. 3. Enable viewing of equipment location history All data transmitted from each device is stored and maintained in the database. Via the monitoring interface, a user may choose to view the history of locations for a particular piece of equipment on a particular date. The positions are shown in ascending order of time, allowing the user to track the trajectory followed by the vehicle on that date.

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4. Enable viewing of equipment geofences and their violations One of the options available on any equipment’s context menu is “Show GeoFences”. It displays all the geofences associated with the selected equipment, either directly or through its containing project. In addition, if, at any point, the current equipment position was recorded as a geofence violation, it is indicated as such on the interface.

Figure 2. ETS monitoring interface - menu options 5. Enable viewing and scheduling of equipment actions Other context menu options are related to the actions available for execution on the equipment (discussed in a prior section). A list of all “Allowed Actions” designated as applicable on the equipment can be displayed on the monitoring component. From these, an action can be chosen for execution at a specific date and time and with the required parameters (if any). Also available is a list of all “Queued Actions” waiting for execution by the equipment; they are the actions that have been scheduled for execution at any time prior to the current time at the equipment’s location and which have not yet been requested by the equipment. Once the request for actions is transmitted by the deployed device and the queued actions are received, they are removed from this list and transferred to the “Actions History” list where all actions, either in progress or completed, can be viewed.

Figure 3. ETS monitoring interface - associated data

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Administration Tool Authorised users are given the ability to manage equipment information, their categorisation and distribution, as well as the organisation of projects and employees, and the definition of geofences through an administration tool, a Windows application exposing all the CRUD (create/retrieve/update/delete) operations required for the entities related to the equipment tracking system as a whole.

Project Hierarchy Projects in ETS are defined under a geographical location hierarchy, namely a Zone containing Areas containing Countries which in turn include Projects. The entire hierarchy may be manipulated via this tool, and project information can be created, edited or removed accordingly.

Equipment Hierarchy The equipment organisation hierarchy is structured as Groups composed of Types composed of Fleets. Each piece of equipment or machinery belongs to a single fleet, and the entire hierarchy, as well as equipment information, may be manipulated as required. Any piece of equipment must also belong to a particular project, and can be associated with the collection of employees who are allowed to operate it.

Employees (operators) The tool exposes a list of registered equipment operators, with their full personal information, which administrators may create, edit or delete as needed. Through the employee section of the tool, employees can also be associated with projects and equipment.

Figure 4. ETS administration tool

Equipment Actions Equipment actions can be viewed and queued for execution via the monitoring interface, but their actual definition is done through this administration tool. An action is identified by a unique code, a description, an action type, and a domain. An action domain is the set of equipment hierarchy entities on which the action can be applied, i.e. the Group, Type, Fleet, or Equipment instances for which this action is allowed. Naturally, an entity at a certain level of the hierarchy inherits the actions allowed at the higherlevel entity containing it, i.e. the actions allowed for a Type are also allowed for its child fleets and their

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contained equipment. Consequently, the actions created and associated with a certain entity in this tool are the ones shown under the “Allowed Actions” list for any particular equipment in the monitoring component.

Geofences Geofences are created, allocated or deleted via a Windows administration tool. An authorised user can draw the geofence, by assigning its boundary points on the given map, give it a unique code and description, and then add it to the ETS database. At this point, geofences may also be linked to entire projects and/or separate equipment to indicate association and allow for monitoring of boundary breaches. For all related equipment, any number of allowed actions may be selected to be used in cases of violation of the geofence in question.

Figure 5. ETS administration tool - geofences

Excel Import and Export All of the above-mentioned features are managed through the administration tool’s visual interface. However, the tool also provides the option for importing and exporting to and from Excel sheets. The Excel sheets are designed in a specific format to support these features, and all ETS entities may be added, edited, or removed directly via these Excel sheets. This would facilitate the process of managing bulk operations.

Device The final component of the ETS system is the hardware module, which is to be installed on the monitored equipment and is designed to collect CANBUS information from the available ports on the equipment, as well as its GPS location. The CANBUS information can include but is not limited to speed, mileage, engine temperature, RPM, fuel level and fuel consumption. Also, by installing RFID readers on man-operated equipment, the device can also post identifying information on the occupants of the vehicle, i.e. the operator and all employees onboard.

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Composition The device itself is composed of several modules to handle each of its operations (see pictures below): GPS: tracks the equipment position in latitude/longitude coordinates CANBUS: collects equipment data, such as speed, mileage, RPM, fuel consumption, etc. It allows only data extraction, and cannot be used for accessing or manipulating equipment parameters. • GSM/GPRS: transmits and/or collects information from a certain endpoint • WIFI: downloads data over wireless networks • RFID: identifies authorised personnel, either as equipment operators or as passengers on the transportation vehicle. In addition, it allows for keyless-go, where equipment can be started and operated via RFID only, which would also enable restricting equipment operation to only selected authorised operators. • 8 Digital Inputs / 8 Digital Outputs: collect equipment data via installed two-state sensors, e.g. a door sensor (door opened - door closed) • 8 Analogue Inputs: collect equipment data via installed analogue sensors, which normally measure data as analogue voltage, e.g. a temperature sensor • Serial Port: allows device configuration and data download to an attached computer

Operation The device is installed on each piece of equipment or vehicle to be monitored. It is configured to conduct all required readings and to communicate with a configurable endpoint on which a webpage is deployed, ready to reply to the device requests. The device tracks its current position, records all collected information, and transmits a message containing this data on regular intervals, determined during device installation and dependent on the device operation and supporting infrastructure in its hosting environment.

Figure 6. Device package

Figure 9. Tracking unit

Figure 7. Unit & package

Figure 8. Unit & modules

Figure 10. CANBUS

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Figure 11. RFID

Figure 12. WIFI

The message is in XML format,, and has been adopted in the absence of a universal standard for describing CANBUS data, and which enables easy information posting on the part of the device as well as easy processing on the server receiving end. The webpage deployed on the server, upon receiving any transmission from the device, processes the XML message and records it in the ETS database, for use by the other system components. As new data is posted from the device, the geofences associated with the transmitting equipment are checked. If the equipment is detected to be outside the bounds of all its geofences, then the violation is logged and the configured handling mechanism, if pre-set, is executed. Note that the interval of transmission by the device can differ from the interval of data collection. For example, in environments where obtaining a server uplink is an expensive operation, the transmission interval may be made larger, while the recording interval can be kept at a smaller regular interval, and each transmission can contain multiple data recordings. Also note that the transmission interval can be configured dynamically, even after the device is deployed on the equipment, and the interval while the equipment is operational can be different from that while the equipment is stationary or shut down. Below is a sample of the XML format to be exchanged between the device and the webpage: <Root ID="…"> <method v="PostData"/> <operator v="…" /> <Employees> <Employee v="…" /> <Employee v="…" /> </Employees> <Post> <GPS LN="03530.54000" LT="3353.22000" Time="15:02:53" Date="2011.05.11" Heading="0" Sat="2" SP="55"/> <CANBus v="xx;xx;xx;xx;xx;xx"/> <INPUT D="xx" A1="xx" A2="xx" A3="xx" A4="xx" A5="xx" A6="xx" A7="xx"/> </Post> <Post> <GPS LN="03530.51000" LT="3353.31000" Time="15:03:23" Date="2011.05.11" Heading="0" Sat="2" SP="55"/> <CANBus v=" xx;xx;xx;xx;xx;xx "/> <INPUT D="xx" A1="xx" A2="xx" A3="xx" A4="xx" A5="xx" A6="xx" A7="xx"/> </Post> </Root> In addition to the submission of location and sensor data, the device is also programmed to periodically check for actions scheduled for execution (introduced in a previous section). The device sends a request

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to the webpage for actions queued for execution at this time. It receives a list of all actions still scheduled on its equipment up until the time of the request; these actions are then marked in the database as being “In Progress”. The actions are supposed to be executed by the device by modifying a configuration or changing the status of one of the equipment’s ports for instance. After execution, the status of the action is returned in a reply to the webpage, which marks the action as “Completed” or “Failed” accordingly.

Future Development The ETS system is a growing project, with room for improvement in its multiple components, and the features to be considered for development in the near future can be categorised as follows: 1. New system features a) Modifications and improvements on the viewing capabilities of the monitoring component b) Support for scheduling of repeated actions, i.e. equipment actions set to run on a periodic schedule and not just at a single specific date and time 2. Business intelligence opportunities This system is data-intensive, with the possibility of thousands of records of data being collected on a daily basis. This fact opens up vast opportunities for integrating the system with business intelligence (BI) solutions, which will assist administrators and moderators in not only having a better global view of the data and its implications, but also in understanding current trends and building projections into the future. The BI solution transforms the data collected from the system into meaningful information to be analysed from various angles using slicing and dicing techniques, which in turn enables decision makers to reach the right assessments within the necessary timeframe for the improvement of the project. 3. Integration with other systems a) Integration with GIS-based systems b) Integration with enterprise resource planning (ERP) or asset management solutions, e.g. IBM’s MAXIMO asset management system c) Integration with fuel management system controls and handheld devices d) Integration of a built-in battery in the device for stand-alone cases and emission of distress signals 4. Compatibility with other mapping technologies

Figure 13. ETS monitoring interface - integration features

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13.4 Google Earth in Construction Monitoring Introduction Google Earth is a virtual globe, map and geographical information program. It maps the Earth by the superimposition of images obtained from satellite imagery, aerial photography and GIS 3D globe. Google Earth is client-based software that is installed on individual PCs and also can be viewed using web browsers through a Google Earth plug-in. It is available in two versions: 1) Free license that uses public satellite photos and maps from Google servers 2) Licensed Google Earth Professional that can be used by advanced users and also can be connected to local licensed Google Earth servers with private satellite images and maps. Google Earth is widely used by different industries to design, monitor and maintain earthwork and construction projects. Municipalities and governments, for example, use Google Earth to design and track the installation of water pipelines, cities and urban design, roads construction, earthworks etc. The use of Google Earth to design and monitor the construction of pipelines reduces the time and effort spent in studying the landscape and elevation changes along pipelines. Google Earth can be also used to monitoring the actual construction of the pipeline, especially if high-quality satellite imagery is aligned to the Google Earth system. This section will focus on the implementation of Google Earth in a near-real-time monitoring system to simulate the construction of a pipeline project. It can also be used at the design stage, for the preliminary definition of pipeline routing – see Appendix 5.1.2.

Requirements The implementation of Google Earth in a near-real-time monitoring system to simulate the construction of a pipeline project is a very useful tool to monitor and track the progress during construction. It requires the implementation of the functional specifications specified in section 7.1 of the 1st edition of “The Road to Success” and section 13.6.1 (volume 2) of the 2nd edition. The installation of Google Earth client or Google Earth Web browser Plugin is also required to be able to view KML files containing the geometric data to be illustrated.

Engineering Details Required Engineering details of pipelines can be illustrated on Google Earth pipeline simulations. Details available may include the following, based on the availability of project data: • Pipe information • Diameter • Wall thickness • Material grade (X60 , X65, X70 etc…) • Coating • Depth of cover • Cut pieces • Chainage • Bends, elbows • Crossings (road, river, rail) • Terrain type • Property name and limits • Joints • QC Data • Valve information (valve tag number, type, manufacturer, XY location) • Cathodic protection information (location, type) • Testing information • Pipeline markers (type and location)

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â&#x20AC;˘

XYZ coordinates from surveyorsâ&#x20AC;&#x2122; GPS readings

These engineering elements are normally stored in the material management system/ERP (see implementation section). Photos from the site during installation and construction process will be displayed on Google Earth if those photos exist in the material management system. The system will be designed to use Google Earth elevation data in case the elevation data does not exist in the Material Management System. The use of elevation data of Google Earth may create dummy nodes that monitor and record elevation changes along pipelines. The pipeline route geometric points are collected from each joint by surveyors and the distance between joints indicates the pipeline size. Keyhole markup language (KML) will be used to represent the pipeline route in Google Earth. KML is an XML notation, developed for use with Google Earth, for expressing geographic annotation and visualization within Internet-based, two-dimensional maps and three-dimensional Earth browsers. An example KML file is shown in the KML module section. KML data are often distributed as zipped (compressed) KMZ files. The contents of a KMZ file are a single root KML document (notionally "doc.kml") and optionally any overlays, images, icons, and COLLADA 3D models referenced in the KML, including network-linked KML files.

Figure 1. The near-real-time pipeline simulation in Google Earth In Figure 1, which shows the design of the near-real-time pipeline simulation in Google Earth, Talisman is the material management system. This is the center of data acquisition, which is connected to the GIS and the centralised electronic database management system (EDMS). The KML module creates the KML file, which then becomes ready for viewing on Google Earth.

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Implementation Material Management System: The material management system is used for data acquisition. The system is administered by the operating network group located in the pipeline site or facility. The material management system, integrated with the plant management and vehicles (PMV) system, monitors all pipeline, machinery and PMV elements at all locations along the pipeline and consolidates the data and then transfers it to the central EDMS via a VPN internet connection (microwave, 3G or public communication carrier). Google Earth will connect and use this data for visual representation. Coordinates: All data referring to locations must comply with the project coordinate reference system (sometimes referred to as projection parameters). This includes all spatial and non-spatial data either for linking to spatial data or for transformation to spatial data format. Where information is to be tied to a specific geographic location, GPS coordinates in the project projection parameters must be collected for every feature. The below table shows an example of a coordinate reference system: Standard for Azerbaijan and Georgia Horizontal coordinate reference system: Geodetic datum

Pulkovo 1942

Ellipsoid

Krassowski 1940

Semi-major axis (a)

6378245.0 meters

Inverse flattening (1/f)

298.3

Prime meridian

Greenwich

Map projection

CS42, zone 8

Projection method

Gauss-Kruger (a form of transverse Mercator)

Projection parameters Latitude of origin

0 degrees North

Longitude of origin

45 degrees

Scale factor at origin

1.0

False Easting

8,500,000metres

False Northing

0 meters

Grid units

International meters

Vertical coordinate reference system Vertical datum

Baltic Datum (sometimes referred to as Krongstad Datum)

Height units

International meters

Note: The Caspian Sea level is 28 meters below Baltic Datum, therefore elevations in some parts of the pipeline route will have a negative value in respect to Baltic Datum. KML Module: The KML module reads the GPS XYZ coordinates, which are then converted to latitude, longitude and altitude points using universal transverse Mercator (UTM) based on the coordinate reference system (see previous section). Those points represent the pipeline joints. The points after being stored in the EDMS are annotated automatically to the project KML file (also stored in the EDMS) which can be viewed in Google Earth to show the progress of the pipeline. In addition to the pipeline route, the KML file may present any other places, photos, roads etc. available in the KML file. For example, the KML file may be annotated with the latest welds (joints between pipes)

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during the construction of the pipeline. Depending on the site update status and project monitoring requirements, this could be every 30 minutes, one hour or more. The simple KML file below demonstrates how the pipeline route is presented: <?xml version="1.0" encoding="UTF-8"?> <kml xmlns="http://www.opengis.net/kml/2.2"> <Document><name>Pipeline Route Example</name> <description>www.ccc.gr</description> <Style id="rangecolour"> <LineStyle><color>660000FF</color><width>0.1</width></LineStyle> <PolyStyle><color>660000FF</color></PolyStyle> </Style> <Style id="linecolour1"> <LineStyle><color>660000FF</color><width>3</width></LineStyle> </Style> <Placemark> <name>Mechata pipeline CL</name> <description></description> <styleUrl>#linecolour1</styleUrl> <LineString id="Line 1"> <tessellate>1</tessellate> <altitudeMode>clampToGround</altitudeMode> <coordinates> 6.027586622,35.91654266,932.5223066 </coordinates> </LineString> </Placemark> </Document> </kml>

Construction Monitoring Results This section proves the ability monitor the progress of the construction of the pipeline on a daily basis. The image below illustrates the pipeline route:

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The image below presents a closer look at the pipeline:

The above images use default Google Earth satellite images; for more landscape details at higher resolution images can be acquired from satellite images providers. During the construction, Google Earth may also illustrate the progress of the pipeline construction. The image below shows the progress of the pipeline construction, using colour to by reflect the status of a pipeline section. For example, green shows the finished section, yellow shows the hydrotesting process and red shows the material missing/non-received section

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Benefits: Google Earth provides a reliable and user-friendly tool for near-real-time monitoring of the pipeline construction, which can handle day-to-day operations of work on site. Installation delays, equipment usage, material shortage and many other elements can be visually tracked by the continuous link provided between Google Earth and the pipeline control system (ERP). The work done in this section used the free Google Earth client and Google Earth Web browser plugin. For advanced usage with proprietary satellite photos the Google Earth Enterprise server (which requires licensing) can be used.

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13.5 Skidless methodology Introduction The Facing, Lining-up and Welding (FLUW) group’s mission is to stimulate innovation in the area of bending, stringing, facing, lining-up up and welding activities and deliver appropriate technologies and working practices to facilitate the overall goals of the Novel Construction Initiative. The key goal of the group is to provide processes and equipment recommendation that can consistently reduce the repair rate in the full range of anticipated environmental and safety conditions with reduced human intervention and supervision. The intention was also to create favourable conditions for proven welding techniques and new welding techniques to be used. The boundaries of the project included pipe between 30 and 56” diameter, cross-country hydrocarbon pipelines and existing international design codes and material standards. Our activities include: • An analysis of existing processes and technologies for pipe handling, stringing, facing, bending and welding • Identify technology gaps and areas for innovation • Develop and demonstrate appropriate new technologies and working practice The development of the process below and the related equipment would in many cases also offer the possibility to eliminate the use of skids, or at least considerably reduce it. This study is presented in 2 steps: 13.5.1 Activities to perform at the pipeyard 13.5.2 Activities to perform on the ROW

13.5.1 Activities to perform at the pipeyard The pipeyard is the pipe receiving and storing area. This proposed new process favours work done at the pipeyard for as many operations as feasible, thus drastically reducing work done along the line. Work at the pipeyard is done in a single location allowing better and easier control resulting in better quality and reduced risks to safety and the environment. Surveying and data collection was not part of FLUW’s charter but it will be needed to implement the new process. • • • •

The first task to be performed is measuring and inspecting pipes for quality and dimensions From the ROW surveying data, which needs to be available from the system, final positioning and bending requirements of each pipe is established and the bending is done at the pipeyard Then bevelling is performed with pipe ends protection Whenever site conditions allow it, pipes will be double jointed, UT controlled, and possibly field joint coated, then stored again, according to their respective positions on the line

13.5.2 Activities to perform on the ROW and “skidless methodology” Activities to perform on the ROW are presented in 3 steps 13.5.2.1 Transportation 13.5.2.2 Stringing 13.5.2.3 Skidless methodology

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13.5.2.1 Transportation On site transportation, can be a very challenging and costly operation, depending on topography and ground conditions. The study of new means of transportation which could include longer and pre-bent pipes would certainly be very useful. Our current new process is based on traditional on site truck transportation.

13.5.2.2 Stringing Pipe stringing will be done in accordance with the work programme and each pipe will be delivered in sequence to its pre-established position. Pipe unloading is done by a pipe layer or excavator equipped with vacuum-lift attachment to avoid any damages to the pipe and the coating. They will be supported by a few basic types of skids, such as sand bags, to avoid contact with the ground.

13.5.2.3 Skidless methodology This new process will be presented in 5 steps 13.5.2.3.1. Overall description of the new process 13.5.2.3.2. Description of the process on the ROW with illustrations 13.5.2.3.3. Description of the new equipment needed 13.5.2.3.4. Equipment preliminary technical specifications 13.5.2.3.5. Analysis of potential savings in terms of cycle time, productivity and manpower

13.5.2.3.1 Overall Description of the new Process In the new process equipment is moved underneath the pipe, rather than being alongside the pipe, thus avoiding the use of wooden skids. The first crew is the front end gang composed of: â&#x20AC;˘

1 excavator equipped with a grabbing tong able to rotate the new pipe for seam alignment and bend orientation just before setting the pipe on the line-up station.

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The front-end line-up station is composed of 2 stations: • 1 back-end line-up and welding station (called “S1” for first station) guided by GPS • 1 front-end line-up carrier (called “FEC”) guided by GPS and controlled by welding station S1

The next crew is the back end welding crew with stations for Fill and Cap (number of stations is dictated by welding system, pipe wall thickness and number of passes required). •

Each back end station is identical and guided by the pipe (called S2-1 for the first fill, S2-2 for the next one and so on...)

•

All stations (S1 and S2) have the capacity to be pulled out from the line should a station encounter a problem that cannot be quickly solved.

When moving to next weld, each S2 type station is not in contact with the pipe in order to avoid vibrations while other stations are working. In addition, each station has the capacity to support 4 pipes. An automatic system will prevent a station from moving should the pipe not be secured correctly by a sufficient number of stations. All stations will have a cab offering the workers an enclosed working environment where heat, cold and dust will be fully controlled. After the last welding station come the NDT station, repair station and joint coating station. The last coating station pulls a lay-down stinger unit in order to bring the pipe from the welding level (about 1.7m or 6 feet) down to the sand bags level as shown on the sketch Phase V. The welding supervisor can remotely monitor actual welding production and parameters from the stations. All parameters will be downloaded using wireless connections.

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13.5.2.3.2 Description of the process on the ROW with illustrating Sketches Phase I. To initiate a section, an excavator picks up the pipe and sets it on stations S1 and S2-1. S1 is aligned using a precise geo-positioning system (GPS). S1 and all S2 stations have a gripping capability to prevent the pipes from moving during the line-up operation and on lateral or longitudinal slopes. Phase II The front end line-up carrier (FEC), also using a precise GPS system, is set ahead of S1, ready to support the next pipe to be welded. The excavator is equipped with a pipe rotator for proper seam alignment and for bend orientation. Phase III The second pipe is now set on line-up rollers, and the line-up operation starts. The line-up rollers on S1 and FEC are controlled by an operator located in S1. Once the line-up operation is done, S1 starts the welding cycle. Phase IV When root and hot welding passes are completed, the internal clamp is moved ahead. S1 moves forward while still, supporting the pipe. When S1 reaches the middle of the second pipe, the FEC is moved ahead to the front end of the third pipe, which is to come next. S1 then moves to its final position and holds the line, allowing S2-1 to move ahead, and S2-2 to enter the line. The internal clamp is set on the pipe end, the clamp operator being located within the S1 cab. Phase V A new pipe is positioned on FEC and S1 and so on. Once all welding stations have completed their work, the following stations will operate in sequence: S2UT is to perform UT, S2-RP repair, S2-SB sand blasting, S2-JH joint heating and S2-JC joint coating The last station (S2-JC) pulls a lay down stinger unit to smoothly position the line on sand bags. Phase VI When a bend is integrated in the line, the FEC is equipped with a rotating table that allows the bended pipe to be backed up in position against the last welded pipe. The last station S2-JC pulls a lay down stinger unit that will allow a smooth positioning of pipe on sand bags. The six sketches in the following pages illustrate the above, together with the four images at the end of the section which are extracted from the animation included in the attached CD.

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13.5.2.3.3 Description of the new equipment needed Grabbing tong A grabbing tong prototype has already been built and tested on the 56â&#x20AC;&#x2122;â&#x20AC;&#x2122; OPAL pipeline in Germany. Basic station design Stations include one track-mounted self-propelled platform, the tracks being on each side of the pipe. The platform itself includes two sets of pipe support devices (probably rollers front and back). These devices will have to be adjustable in height (when unit moves up to the next weld, the pipe should not be supported in order to avoid vibrations/movements of the line while other stations are welding). All platforms will be equipped with a cab, which will be easily removable. Welders and helpers will stay in the cab while the station moves to the next joint. Each platform will be equipped with a power unit to provide either power for travel or for welding and any other related equipment. With this system, there are no parts exposed to damage such as umbilical cables or hoses. All S2 type stations are of modular design and each module can be removed from the string for a quick exchange of faulty components, or replaced easily in case of major problems. The carrying capacity of one station, when double jointed pipe are installed, should be approximately 2 pipes 24 m long each (56â&#x20AC;? diameter) allowing for some potential delay in one cabin operation. However, generally all stations should be a maximum of 48 m apart. Each station is controlled by one onboard operator, however, each cab should allow up to 5 persons inside. These cabs will be air-conditioned and heated. A safety device will automatically stop the machine in case a person or an obstacle is on the travelling route or too close to the machine. Each station behind the front end will be guided by the pipeline. Each station has holding pads to prevent the pipe or line from moving during the line-up operation or when working on lateral or longitudinal slopes. An automatic safety device prevents a station from moving if the line is not secured by other stations. Each station also has its own operating mode for loading/unloading into transport units. Station S1 Station S1 has the same design as the basic stations, except that its front rollers (which support the back end of the new pipe) can move up/down and left/right for line-up purposes. Rollers have a 30T holding capacity and are positioned outside the cab in order for the excavator to easily set the pipe. Station S1 is positioned by a precise geo-positioning system. Rollers are positioned outside the cab in order for excavator to easily set the pipe. Front end carrier (FEC) The FEC is a self-propelled track carrier remotely controlled by an operator located in S1 and precisely positioned by GPS. It is designed to carry one pipe. The FEC is fitted with holding pads and rollers that move up/down/right or left. The unit has also a rotating bearing between the undercarriage and support rollers in order to accommodate a bent pipe and back it up in line with the preceding one. A safety device automatically stops stations in case of obstacles or hazards. Lay down stinger unit The last station will pull a lay-down stinger unit in order to bring the line down to the sand bags. The capacity of this unit will be 4 pipes.

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13.5.2.3.4 Equipment preliminary technical specifications The main technical specifications should include the following. Stations Platform

Maximum width in transport mode: less than 3.00 m Maximum height from the ground up: 1.70 m Necessary power: 200 KVA. The power unit must be able to withstand temperatures from -50°C to + 50°C, in lateral slopes of +/-10% and longitudinal slopes of max. +/- 30% Pipe bottom above ground: 1.7 m Weight to be supported by the roller: 30 tonnes Holding and lining-up devices (S1) GPS system for station S1 Possibility of lowering a roller for guiding rings Adjustable cab support Anti-collision system and other safety devices

Cabin

Dimensions: L 3.50 m, width and height to meet main specs. Adjustment “curtains” to enclose the pipe Areas to accommodate generator, gas bottles, air distribution Heater and/AC units Cab floor for operators and helpers Floor to cope with slopes up to 30% Quick connection/disconnection devices The unit must be able to be removed from the pipe sideways

Front end carrier Transport width: maximum 3 m Necessary power as required Weight to be supported by rollers: 15 tons Control system and GPS positioning Safety devices Lay down stinger The last station on the line pulls a non-propelled stinger to lay pipes on sand bags or equivalent devices.

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13.5.2.3.5 Potential savings in terms of cycle time and productivity Preliminary studies indicate that significant reductions of cycle time as well as savings in terms of manpower and equipment in the order of 10 to 30% can be expected. Furthermore, this new methodology will have a positive impact on: Safety • Elimination or at least strong reduction of skidding operations. This will decrease the number of workers on the ROW • Less manpower on the ROW means fewer transportation requirements, consequently fewer risks of hazards and accidents • Welders will no longer be on the ground but will work in an enclosed and clean environment, even when moving to the next pipe • Cabs are seated on a solid base and are no longer hanging on a boom • Cabs are dust-controlled and air-conditioned or heated for better working conditions Quality: • Line-up and fit-up processes are improved with consequences for productivity and quality • As cabins no longer hang on booms, they can be adapted to sophisticated welding processes for better quality and productivity • Fixed computerized cabins allow for the latest technologies and improved pipe positioning Environment: • Decrease in air pollution due to a reduce number of operations on the ROW • The new equipment will be of the latest technology and meet all new air pollution requirements • As all operations will be conducted from an enclosed environment, collection of debris will be facilitated and more efficient

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13.6 Machine Development 13.6.1 Lowering & Laying: Functional Specifications of the Ideal Machine 13.6.1.1 Objectives 13.6.1.1.1 Initial objectives The initial objectives of the Lowering & Laying working group as defined in February 2007 were: Key Objective • Develop processes and equipment that match pipeline string design and conditions to ensure minimum installation stresses, minimum handling and zero pipe and coating damage when integrating with other innovations developed by other working groups of the Novel Construction Initiative for improved construction production rates Primary Objectives • To stimulate innovation in the area of pipe lower-and-lay processes in order to deliver appropriate technologies and working practices • In particular the key goal was to develop lower and lay processes and equipment which would integrate with the other Novel Construction processes and which would be engineered to match the pipeline string design and environmental/terrain conditions to provide: Minimum installation stresses • Minimum handling of the completed pipe string • Zero damage to pipe and external corrosion protection systems • These objectives covered both the “process” and the “product” aspects of the lowering-and-laying operation in pipeline construction.

13.6.1.1.2 Revised objectives After analyzing the lowering-and-laying operation, the group concluded that the process aspect of this operation was directly connected with many other factors in pipeline construction, such as: • Constructability and general layout of the pipeline • Processes and machinery used in the alignment, welding and coating phases of pipeline construction We could not therefore improve existing processes or develop new ones in the lowering-and-laying operation, with the certainty that these new processes would be totally consistent with all other operations on the pipeline construction project. The working group then decided to focus on the product aspect of the lowering-and-laying operation, rather than on the process. Within the product perspective, the group identified and developed a workplan to address two targeted projects: 1. Develop functional specifications for the “ideal” sideboom. 2. Develop functional specifications for the “ideal” attachment.

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It was then decided to conduct a survey amongst IPLOCA members, who are the contractors actually using those machines. A questionnaire was developed and addressed as a survey to the contractors through the IPLOCA website, with the support of the IPLOCA Secretariat and their web-site coordinator. The survey’s objective was to identify: • Current applications of sidebooms • Design weaknesses of current sidebooms • The features of the ideal sideboom to perform lowering operations • The features which contractors would like to see on the ideal attachment The specific questions were: • which features are “most liked”and which are “most disliked” • which features the ideal sideboom and attachment “must have”, or would be “nice to have” Responses were received from over 20% of the contractors. The respondents included some of the major on-shore pipeline contractors, which gave a high degree of credibility and reliability to the survey results. The next phase of the project consisted in analysing the responses and comments, and in translating those into functional specifications for the ideal lowering-and-laying machine and attachment. This work was performed during summer 2008 and concluded at the working group’s meeting in Italy in July 2008. One consideration which also came out of the survey is that often some contractors asked for features which already exist on machines available on the market, and yet are not used, such as: • Factory-installed & certified cabs, roll-over protective structures (ROPS), seat belts etc. • GPS positioning systems (Product Link) • Electronic jobsite management (Accugrade) • Operator simulation training tool This prompted the question: Why is so much effort spent in developing new products and state-of-the-art features to improve the industry practices in terms of productivity, health and safety and environmental impact when – in the real world – machines which are 40 year old, have Tier Zero emissions engines, non-original ROPS or noncertified modifications are still accepted on jobsites? Section 13.6.1.1.3 below propose certain recommendations to progressively correct this situation.

13.6.1.1.3 The ideal machine Once they had developed the functional specifications of the ideal side boom, the group realized that most of the features identified could be extended to all types of machinery used on pipeline jobsites. This actually represented the second shift in the Lowering & Laying Group objectives and deliverables. From nalyzing the process and the product aspects of the lowering-and-laying operation in pipeline construction the scope was restricted to analyzing the product aspects of this operation. With the survey results, it was broadened again and extended to the functional specifications which we had developed to all products, i.e. all machines used on the pipeline construction jobsite, instead of limiting its application to just sidebooms. The newly-developed functional specifications are presented in the next section. As for the ideal attachment functional specifications, the group has developed the concept of a tool which can be installed either on a sideboom or on an excavator, and which can hold the pipe sections in

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 13

any desired position, including rotation of the pipe section around its axis. This is under development by one of the manufacturers participating in the grooup.

13.6.1.2

“Ideal Machine” Functional Specifications.

13.6.1.2.1

Transportability

Transportation of the machine is the prime end-user selection consideration, due to the transient nature of pipeline construction and to the frequent need to move machinery around. Machine transportability can be further broken down into: Ease of Disassembly and Re-Assembly Machine dimensions Ease of Disassembly and Re-Assembly The ideal machine will have NO disassembly and reassembly operation. Should this target not be met, then the goal for the machine design should permit easy disassembly and loading within one hour and without special tools or lifting devices. Machine Dimensions It is highly desirable that the basic shipping dimensions of the machine be achieved or improved upon. The overall machine size, weight criteria and transportation restrictions must be carefully considered. Height The machine, loaded on a low bed trailer, should not exceed non-permit limitations in height with minimal disassembly, as follows: Location

Minimum Height Requirement (m)

North America

4.12

Europe

4.20

South America

4.40

Width The machine, loaded on a low bed trailer, should not exceed non-permit limitations in width with minimal disassembly, as follows: Location

Maximum Width Requirement (m)

North America

3.05

Europe

Category 1 – below 3.00 Category 2 – below 4.00 Category 3 – above 4.00

South America

3.00

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Weight The machine, loaded on a low bed trailer, should not exceed non-permit limitations in weight with minimal disassembly, as follows: Location

Maximum Weight Requirement (kg)

North America

54,500

Europe

42,000

South America

45,000

13.6.1.2.2 Safety The implementation of safety measures is a prime end-user selection consideration. How a machine performs in this area is of utmost importance. Roll Over Protection System (ROPS) A roll-over protection system (ROPS) should be implemented as standard on all machines capable of carrying a load. The ROPS device shall support the whole load (weight) of the machine in working configuration, in a rollover event, including to some extent the dynamic load associated to such event. Safety belts should be compulsory. Load Monitoring A load-monitoring device should be implemented as standard on all machines capable of carrying a load. In addition, the machine shall be equipped with a printed table with safe limits of operation in all situations as well as a table of the recommended steel cables to be used. Slope indicator A slope indicator device should be implemented as standard on all machines capable of carrying a load. This should be useable both when the machine is under load and when it is not under load. The slope indicator should be lateral and longitudinal. Visibility Functional visibility in all directions from the operator station is a requirement in critical areas as follows: 1. Forward and side view of the left-hand track and ditch area 2. Forward view over the front of each track 3. Rearward for towing device and a towed load 4. Drawworks 5. Upwards to the tip of the boom Reduction of visibility with an enclosed cab should be minimal over a non-enclosed ROPS. A separate alarm signal is desirable for areas in â&#x20AC;&#x153;dead anglesâ&#x20AC;?.

13.6.1.2.3 Accessories and Comfort The implementation of operator comfort features should be taken into great consideration when designing a machine.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 13

The following are some of the features which should be considered. Enclosed Operator Cab This will allow installation of air conditioning and/or heating. Extreme ambient temperatures should be considered, with attachments that would allow the machine to operate in ambient temperatures varying between +42 to â&#x20AC;&#x201C;45ÂşC. The cab should be pressurized to prevent dust from penetrating the operator environment. Controls Machine controls should require minimum operator effort and should consist of effort-assisted levers or joysticks which will allow operation with the maximum possible precision. Controls shall have also an "anti-jolting" system and a blocking system to prevent sudden drops of the boom/load. Noise Level The reduction in noise exposure during machine operation should match or fall under the applicable requirements as required by law in the location.

13.6.1.2.4

Environmental Features

The machine should be designed to meet the most advanced environmental requirements in areas such as: Low Engine Emissions Engine emissions should meet or fall under Tier IV requirements. Fuel Efficiency The machine should have a proven fuel efficiency (gallons of fuel consumed per quantity of work produced). Bio Fuels The engine should be able to run with biodegradable fuels. Bio Oils The machine should be able to run with biodegradable oils. In addition, the machine should be equipped with leaking protection devices to prevent contamination of soil in the event of normal maintenance (oil changes) or of oil leakage. Manufacturing process The machine should be manufactured in the most environmentally respectful manner. Use of remanufactured components would be a plus. Also, manufacturing processes and facilities should have a proven track record of environmental friendliness (low CO and GHG emissions, process for water recuperation and recycling etc.). Machine Recyclability The machine should be recyclable as much as possible.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 13

13.6.1.3

Recommendations to improve the existing quality of equipment used on existing pipeline projects

The â&#x20AC;&#x153;Ideal Machineâ&#x20AC;? functional specifications were then submitted to manufacturers of all type of machines used on on-shore pipeline projects (e.g. welding tractors, padding machines, dozers, excavators, loaders, dump-trucks etc.) The manufacturers were asked to indicate which features of their current models already comply today with those ideal specifications, which features do not comply and which plans are in place for making the machine comply with the required ideal specifications. The results of this survey are that construction and pipeline machinery of major manufacturers already meets most of the ideal functional specifications. However, it has to be noted that this result applies to machines which are new, ex-factory today, and not to old equipment which may still be used on pipeline jobsites. Manufacturers also highlight the fact that, although their appearance may be similar, current machinery is very different from old machinery, and that it is virtually impossible to upgrade old machines to the specifications of new ones.

To bring this work to a positive and concrete conclusion, the working group proposes that clients consider including contractual means in order to require and certify that a certain percentage of the machines used by contractors on the future jobsites actually comply with the ideal functional specifications (or with a minimum requirements to be established by themselves, based on the ideal functional specifications). As an example clients may want to require 10% (or any percentage to be determined by them at their discretion, as long as it drives increases in safety, productivity and environmental features) of the machines in the first year (2010), with a plan to increase by such percentage in each subsequent year. We trust by having the client drive such best practices, will result in improved efficiency, productivity, safety and environmental respect on the projects and jobsites.

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13.6.2

Use of Computer-based Technologies

13.6.2.1

GPS in Machine Control and Operation

1. GPS Global positioning system (GPS) satellites provide precise location information for elevation and alignment control with potentially centimeter-level accuracy. The GPS system considered here uses GPS satellites to determine precise blade / bucket positioning. The system features fully-automated blade adjustments for elevation control, and vertical and horizontal guidance light bars for manual control. Such a system complements the Equipment Tracking System described in section 13.3. 1.1 Operation Machine control systems use advanced GPS technology to deliver precise blade positioning information to the cab. The information necessary for the system to accurately determine blade / bucket positioning with centimeter-level accuracy is determined using machine-mounted components, an off-board GPS base station, and real time kinematic (RTK) positioning. The system computes the GPS positioning information on the machine relative to the base station, compares the position of the blade relative to the design plan, and delivers that information to the operator via an in-cab display. Information provided includes blade elevation; how much cut/fill is necessary to achieve the required grade; a visual indication of the bladeâ&#x20AC;&#x2122;s position on the design surface; and a graphical view of the design plan with the machine location. Machine control systems put all the information the operator needs to complete the job in the cab, resulting in a greater level of control. Vertical and horizontal guidance tools visually guide the operator to the desired grade. Automated features allow the hydraulic system to automatically control blade adjustments to move the blade to grade. The operator simply uses the light bars to steer the machine for consistent, accurate grades and slopes resulting in higher productivity with less fatigue. 1.2 Single GPS system When combined with cross/slope, the single GPS system provides automated blade adjustments to one side of the blade for cross slope and elevation control. 1.3 Dual GPS system When two GPS receivers are used, the system provides automatic elevation control to both sides of the blade or bucket. 1.4 GPS receiver A GPS receiver is mounted on top of a mast above the cutting edge or on counterweight. GPS satellite signals received by the GPS receiver help define the horizontal and vertical position of the blade or bucket. This allows the system to precisely measure the machineâ&#x20AC;&#x2122;s blade/ bucket tip location in real-time with centimeter-level accuracy. 1.5 Mast A rugged steel mast is used for mounting the GPS receiver above the blade cutting edge or counterweight for optimum GPS satellite reception. 1.6 Radio The communications radio is mounted on the machine cab to ensure maximum signal reception. The radio receives real-time compact measurement record (CMR) data from the GPS base station radio for calculating high-accuracy GPS positions. Radio broadcast frequencies work in all weather conditions, penetrating clouds, rain and snow. This allows the machine control system to accurately control blade operation in fog, dust and at night.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 13

1.7 In-cab 3D display The in-cab graphical 3D display/control box with keypad allows the operator to interface with the system using push buttons and a colour monitor. As the machine works the operator can view information in real-time, including machine location, blade / bucket position and elevation relative to the design plan. The system uses design files that are stored on a compact flash data card and inserted into a slot below the keypad. 1.8 Light bars Three light bars are mounted in the machine cab and provide vertical and horizontal guidance to the operator. • Two “vertical guidance” light bars visually indicate where the blade/bucket tips are relative to the grade. • The “horizontal guidance” light bar indicates blade/bucket location relative to the selected horizontal alignment. 1.9 Controls The controls are located on the levers in the cab. They are used to activate the automatic/manual operating modes and increment/decrement switches. 1.9.1 • Automatic/manual button Allows the operator to toggle between automatic and manual mode. In automatic mode, the system automatically controls blade adjustments. In manual mode, the operator manually controls the blade/bucket, while using cut/fill information on the display and light bars to guide blade movements. 1.9.2 • Increment/decrement switch Allows the operator to set elevation offsets at a preset distance from the design plan to optimize cutting depth in various soil conditions or accommodate sub base fill requirements. 2. Features and Benefits Machine control systems are easy to use and deliver a wide range of benefits. In order to evaluate the potential benefits of the systems mounted on the machines, comparison tests were carried out on two short road works running in parallel on the same terrain. One roadwork was carried out using the traditional method, the other used exactly the same equipment but with the machine control systems installed. Larger scale tests should be carried out to obtain a meaningful quantification of the results but the initial results show the definite benefits listed below. 2.1 Increased productivity and efficiency • Increased productivity • Accurate operations lead to reduced guesswork and costly rework • Reduced survey costs • Reduced material useuse • Reduced operating costs • Extended work days • Increased operator efficiency • Improved accuracy 2.2 Assistance with labour shortages • Reduced labour requirements and costs • Allows customers to get the job done more quickly and efficiently • Reduced need for staking, string lines and grade checkers • Improved operator confidence, empowering them by delivering grading information to the cab 2.3 Worksite Safety • Grade stakers and checkers are removed from the worksite and away from the heavy equipment • Safety interlock features can ensure blade security when the system is inactive • Improved road safety by maintaining consistent crowns

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2.4 Improved employee satisfaction and retention • Elevation control brought to the cab by in-cab display • Operators empowered with real-time results • Real-time feedback on progress increases job satisfaction, eliminates guesswork and reduces operator stress • Improved operator skills, taking performance to the next level • Investing in the latest technology leads to a sense of value and trust by the operator 3. Current industries using this technology • Road building and excavation have used machine control systems successfully in the past. • They have achieved the benefits in processes from ranging from bulk use of materials for site development to paving. • Compaction companies also use this to determine pass counts and compaction values. 4. Future benefits to the Pipeline Industry • Site line work to show ROW, environmental areas, center of ditch line. • Ability to record GPS locations with machine blade / bucket. • Machine guidance at all times for the operator.

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13.6.2.2 Data Transfer What is a Data Transfer System? Data transfer systems are data transmission and positioning systems for construction machines, based on state-of-the-art data transmission technology. Most data transfer systems provided by construction equipment manufacturers can provide data sets at two levels. • The basic level is in general less sophisticated, requires no integration with the machine electronics, and can be installed on many types of machine, irrespective of their brand. • Advanced parameters are linked to data coming out of the electronic machine controller. Advanced parameters include fault codes, fuel consumption and idle time. Data transfer systems are designed to provide information which can help contractors, optimize productivity and increase machine use. The Association of Equipment Management Professionals (AEMP) protocol calls for data transfer systems to use a common XLM-based dataset, providing 4 parameters that are common to most OEMs How does it work? Construction machines are equipped with an integrated GPS receiver, modem and antenna. Using this technology, machine data is then transferred to a central database via GPRS/GSM mobile network or satellite. GPS is also used to detect the exact machine location. All that is needed to access information about a specific construction machine is an internet-connected computer and a personalized and secure user log-in. What information does a data transfer system provide? The generic data available from a basic system is as follows: • Location • Geofencing data (see below) • Timefencing data • Hours More advanced systems can include the following data: • Engine start / stop • Fuel level • Operator / machine ID • Fuel consumption • Idle time • Fuel spent in idle mode • Digital switches • Maintenance scheduling • Events and diagnostics. Below are some examples of functions above, and the screens that construction equipment manufacturers make available with their systems. The screens below show the location of a fleet of machines. This also allows the tracking of machine movement over any specified time period.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 13

Data transfer systems have the capability to establish â&#x20AC;&#x153;geofencingâ&#x20AC;?, i.e. boundaries beyond which the machines are not supposed to be. Street maps and satellite views simplify setting up of site boundaries, providing valuable asset-tracking and security-monitoring tools. Additional features can include setting times for alerts, such as security alerts on nights or weekends only.

Position of the machine on the map can also be combined with other machine data (fuel level, alerts, idle vs working time), to provide a user-friendly dashboard, as in the examples below.

Daily hour reports keep track of how many hours per day machines have worked over a selected time period, for better planning of machine usage and fleet size. Alternatively, the system can instantly relate and compare the use of all assets on a job site. This will allow the rapid identification of assets working under capacity.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 13

Another key function that can be performed by the data transfer system is service planning and fast parts ordering. The system can indicate impending service requirements (how many machine hours are left until that service, and approximately what date the service will be needed on, based on past machine usage), or “to do” checklists for common preventive maintenance and service procedures. In some cases, the data transfer system can even lead the user directly to ordering the parts needed for a specific maintenance operation. Benefits and Advantages In general, the benefits of data transfer systems can be summarized in two major areas: 1. Lower Owning and Operating Costs • Monitor and manage idle time and fuel usage • Avoid costly machine failures • Extend machine life through proactive maintenance and identification of harsh operation Data transfer systems provide operation reports providing detailed fuel consumption information. It can be analyzed on its own or compared to other machines or between operators using workshift functionality, enabling the customer to take a proactive approach towards operator training or application in order to achieve best practice and drive down fuel costs. Likewise, simple features like daily hours take the hassle out of administration and invoicing. Information is provided directly in the web portal, means operators don’t waste time looking for a specific gauge on the machine just to get the hour meter reading for example. 2. Increased Productivity • Know where the fleet is • Identify over and under-used assets • Improve logistics for fuel, transportation and service dispatch • Maximize asset up-time • Thanks to the above, help to keep jobs on schedule Data transfer systems capture detailed machine use data where critical performance information like work and idle time, work mode, distance travelled and fuel consumption are displayed. Analysis of the data enables the customer to look for areas of opportunity to enhance machine performance and productivity. The data can also help in making machine acquisition decisions, for example is another machine required or can increased workloads be managed with the existing fleet? Data Transfer Systems capture machine-specific alarms and error codes. Depending on the severity, immediate action can be taken by the customer or OEM dealer to avoid costly repairs and unscheduled downtime. Smaller issues can be planned and taken care of at the next scheduled maintenance, reducing cost and increasing convenience.

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It should never be necessary to stand a machine down during a shift for routine maintenance. Ensuring this however, and servicing machines efficiently requires planning. When will machines be due for service? How many mechanics are required? What parts and tools are needed? Is the workshop big enough? Data transfer systems typically incorporate service reminders, giving advance warning when a machine is due for service and enabling all service requirements to be fully planned well in advance, to reduce inconvenience and avoid downtime. And for machines in remote areas, the OEM dealer can use the mapping functions to fully plan the route for the field service van and be sure they find the machine quickly, reducing travel costs.

There are also some additional benefits, including: â&#x20AC;˘ Monitoring unauthorized areas through geo-fencing â&#x20AC;˘ Identifying opportunities for operator training â&#x20AC;˘ Maintaining peak operating conditions to reduce emissions

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Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Appendix 13.1.1

Appendix 13.1.1 Conceptual Functional Specifications for a GIS-based Near-Real-Time Construction Monitoring Tool Table Of Contents Foreword

Purpose Scope

59 59

Potential Benefits Efficiency Quality Safety Environment

Features Electronic Data Interface/Interchange Flags And Notifications Reporting Techniques And Technologies

Data Groups Material Management Manpower Equipment Planning And Progress HSE And Social Engineering Data

Material Management Pipe Shipments Pipeyards Stores Information

Manpower The Accommodation Information Manpower Data

Equipment And Vehicles PMV Stores Locations Emergency Equipment Equipment Tracking Information Vehicles Tracking Information

Planning And Progress Daily Pipeline Progress Activities Pipeline Planning/Scheduling Activities

HSE And Social Points Of Interest (Hospitals, Medical Centers, Police Stations, Etc.) Accidents And Incidents Grievances And Complaints Areas Of Special Status

Engineering Data Crossings Access Roads

60 60 60 60 60

61 61 61 61 62 63 64 64 64 64 64 64 65 65 67 69 71 71 73 76 76 78 80 82 85 85 87 89 89 90 92 94 96 96 98

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Marker Points Pipeline Routes Above Ground Installations (AGIs) Tie-In Points Fiber-optic Cables Additional Features, Geotechnical And Cathodic Protection Data

Recommended Technical Specifications Gis Software Connectivity To Data Sources Web Mapping Of Pipeline Data

Glossary

100 101 102 104 105 107 109 109 109 109

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Foreword Purpose The purpose of this document is to recommend the basic functional specifications for developing a "near-real-time (near-live) monitoring tool” (NRT), a comprehensive project controls tool with a GIS-based interface, which can be used during the life-cycle of the pipeline construction project. This preliminary phase would be succeeded by detailed technical specifications and subsequently actual development of the NRT.

Scope The NRT aims to present an accurate outlook on the major aspects of the construction cycle as well as other significant events, as soon as they occur or can be recorded, and in a visual geographical interface. Updated feedback would include: • Construction progress reporting • Project information and documentation • Assets and resources management • Material control and traceability information • Quality control data These recordings set the foundation for an integrated GIS-based pipeline construction management system that comprises data-rich feeds of information and dynamic reporting, and enhances the proactive involvement of senior project staff for an improved decision making process. To this extent, this document profiles the major relevant data groups, with specifics on what and how to acquire the details for each group. It also presents some recommendations for technical tools selection.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Appendix 13.1.1

Potential Benefits In line with the primary IPLOCA NC objectives, the development of this tool stimulates innovation in the processes of controlling the pipeline construction, and invokes improved technology techniques, market software, and R&D on new concepts to achieve this step forward. The results would have positive repercussions on the construction phase of the project, specifically in the aspects of efficiency, quality, safety, and environment.

Efficiency A successfully operational monitoring tool would instigate an overall improvement in efficiency of project control tasks, and in effect all related construction activities. An elaborate and well-rounded NRT would be a useful project management tool to: • Monitor site activities • Retrieve up-to-date progress reports • Foresee possible hiccups • Take immediate action

Quality The NRT would serve as near-live information storage and sharing container, with an interface to be used at different levels of project management, engineers, construction crew leaders, and project partners. Such a medium would have a positive effect on the quality of work done at supervisory level, and drill down to the direct manpower level.

Safety Adopting this tool would potentially enhance safety by: • Providing immediate alerts on safety and security threats and concerns that would otherwise escalate without prompt action. • Assisting management in better planning for safer activities related to manpower, including accommodation, transportation, and emergency plans by providing a multilevel view of the project’s different locations and facilities. • Cutting down site visits by supervisory personnel by providing remote access to most of the information required for improved decision making.

Environment Environmental awareness is promoted through the use of this tool by: • Better control and maintenance of project equipment with early notifications of breakdowns and spills, and better control of emissions. • Identification of environmentally sensitive issues and zones, and propagating this knowledge to the different project staff levels. • Decreasing the carbon footprint created by the project supervisory personnel by reducing the need for direct site visits, hence promoting “green construction culture”.

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Features The development of this platform must encapsulate state-of-the-art features and workflows built on the concepts of a GIS interface, web accessibility, and shared data repositories. The tool would be empowered by: • Links to existing project controls and logistics systems. • Business features such as EDI development, flags, notifications, flexible reporting tools, and improved procedures. • Modern technologies and practices in systems development. • State-of-the-art market tools. • R&D on new concepts with innovation potentials. Additionally, it is envisioned – for improved performance – that a central database would serve as the main information container for collection of extracted data, in addition to direct links to the existing systems.

Electronic Data Interface/Interchange For each of the data groups defined hereafter, an electronic data interface (EDI) will need to be put together with the related systems to which the NRT will link or extract information from. An EDI is generally defined as a standardised or structured method of transmission of data between two media, and in this context the EDI will govern what information will be collected for each data group, its format, in addition to how, when, and by whom it shall be acquired. Properly characterized and implemented EDIs are integral to the successful design and operation of the NRT.

Flags and Notifications Flags and notification are essential features of the NRT. The idea is to have intelligent reminders or prompts that are automatically generated to highlight anomalies, arising points of concern, or cues for further considerations, and that require action (flags) or raise awareness (notifications). The trigger for these flags and notifications would be based on the data processed from various data groups, while their design and scope needs to be based on a well-founded knowledge of the construction workflows, and the different roles of the project players who would need to interpret these flags and take consequent actions. A flag section is referenced as a guideline within each data group where applicable. Flags and notifications would take on different formats, including RSS feeds, SMS, multimedia messages, emails, or even image and video feeds, with access through the NRT interface. The accessibility to these flags would be linked to different roles on the project, for example equipment notifications would be directed mainly to plant managers and engineers whereas material shortages would be displayed for material personnel and control managers. The format for these notifications should allow for an adequate level of flexibility to meet different needs and work practices by different players, for instance the ability to subscribe to specific RSS feeds upon demand and secure limited access to sensitive feeds.

Reporting The ability to extract various formats of progress, statistical, analytical, and listing reports from the NRT interface is one feature of substantial benefit to managers. While formal reports can be accessed through links to the electronic document management system (EDMS), the NRT must accommodate more interactive reporting techniques including pivot tables, dashboard queries, data mining, and visual charts.

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Techniques and Technologies The concept of NRT inherently implies the incorporation of the latest innovations to achieve the nearreal-time handling of information. Whereas current and future solutions would be welcome additions for incorporation into the development of the tool, the following are some suggestive samples that can be effectively employed for data production, capturing, or processing, and that have been used within one setting in pipeline construction.

Modern Communication technologies The field of IT and communication is always on the move, and designing the NRT entails making use of the availability of innovations in this field. Connectivity examples include satellite connectivity, WiMAX and WiFi technologies, GPRS, and GSM.

Improved Business Procedures Construction workflows are continually nourishing on advancement in electronics and communications, and in turn the digital aspects of many procedures have improved significantly. Although the decision on the construction procedures is not within the scope of the NRT, the use of techniques that allow for capturing digital data in the field would be a major advantage. Examples of such technologies include computerized NDT, AUT, automatic welding, and GPS surveying.

Engineering and Construction Control Software Improvement in business procedures has been accompanied by development of data control software that tackles the related workflows. The more the NRT makes use of such systems, the better the quality of available data. These control software comprise such categories as: • Pipeline design software • Document management systems: e.g. VBC™, Documentum™, etc. • Material management systems: e.g. Talisman™, Marian™, etc. • Quality control systems • GIS systems (refer to technical specifications section) • Vehicle tracking systems

Hand-Held Machines Handheld machines or PDAs are significant tools to speed the control aspects of construction activities. Handheld forms can be used to replace traditional hardcopy documentation to record/register the progress of construction activities like stringing, bending, pipe cutting, welding, and others. The benefits of such advanced solutions would be apparent in the time saved on multiple processing of the data, the minimization of handling errors, and the speed with which the data can be provided. Alternative handheld machines would have a GPS capability for taking location, direction, and digital images of relevance.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Appendix 13.1.1

Data Groups Thorough functional specifications for the NRT defined above would address the different domains of the construction phase of the pipeline project. Fig. 1 below is an indicative schematic of the information associated with the data groups identified in this document. Fig. 1 Functional Specs - Data Groups Relations

The data groups will be illustrated in the following sections by identifying the detailed information required in each group, the source and methods of obtaining them, the format, the frequency of update, and who is responsible for collecting them. The following data groups will form the basic functional specifications for the NRT tool inputs.

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Material Management • Pipe shipments • Pipeyards • Stores information

Manpower • Accommodation information • Manpower data

Equipment • Plant machinery and vehicle stores • Emergency equipment • Equipment tracking information • Vehicle tracking information

Planning and Progress • Construction progress of activities • Planning/scheduling of activities

HSE and Social • Points of interest (hospitals, medical centers, police stations etc.) • Accidents and incidents • Grievances and complaints • Areas of special status

Engineering Data • Crossings • Access roads • Marker points • Pipeline routes • AGIs • Tie-in points • Fiber-optic Cables • Geotechnical and cathodic protection data

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Appendix 13.1.1

Material Management This main group comprises the following data group classes: • Pipe shipments • Pipeyards • Stores information

Pipe Shipments Description This data group covers pipe shipment data and related features such as port/harbour locations. The main purpose of this section is to provide all information related to the delivery of line pipe to sites for expediting purposes.

Data Delivery to the NRT Tool The EDMS and expediting/shipment tracking (ExTr) systems are the main sources of information for this data group. The NRT must be dynamically linked and/or integrated with the relevant systems to ensure live GIS-based update of the line pipe shipments information.

General Information

Data Specifics Spatial (Geographical) Data Harbour location: The harbour location refers to the area(s) of the main entry of line pipes to the country. This would be a representation of the geographical data, in this case the location features and boundaries. Non-Spatial Data Non-spatial data for this group are: Contact Information: This includes the main contact details of the person who is responsible for logistics related to the pipe shipments at the harbour. The EDMS contact module (CMod) will be used to store this information and EDIs will be used to extract required information to the NRT data containers. Expediting/Tracking Information: This includes shipment details such as the reference number, expected arrival date, status, actual arrival date, total number of pipes, and the total number of pipes expected to be received at that harbour per type. These data will be extracted from the ExTr system via a live link and EDI. The shipment reference number(s) will act as the key link(s) between the two media. Expediting Documents: These include shipment expediting and logistics documents, which are normally stored in the EDMS. The link between the NRT and the EDMS will be the shipment reference number. Once the link is activated, a query is sent to the EDMS to display documents/drawings related to the shipment in question, on the NRT interface. Digital Photos: Digital photos will be taken periodically and geo-referenced for the harbour(s), and will be stored in the EDMS; a link between the NRT and the EDMS will be established. The linking query based on the harbour in question will extract all related photos for display.

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Data Details/GIS Attributes

Flags/Notifications Within this data group, flags/notifications are related to shipment statuses and pipe delivery times. Their purpose is to provide early alerts about events that would potentially affect pipe shipments and delay subsequent construction activities or cause resources to be idle. Sample alerts include:

1 Connection type refers to the way the data is accessed from the original source. 2 Extract refers to the process of importing the data from the original source at the defined frequency update interval to the central storage database of the NRT. 3 Link refers to the process of directly accessing the data from the original source and displaying them on the NRT GIS-based interface on demand.

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Pipe Shipment Data - Workflow & EDIs

Pipeyards Description This data group covers pipeyard locations in addition to line pipe management and control data. It is intended to assist material and logistics teams in handling line pipes efficiently.

Data Delivery to the NRT Tool EDMS and MMS are the main sources of information for this data group. The NRT tool must be dynamically linked or integrated with the relevant systems to ensure live GIS-based update of the pipeyardâ&#x20AC;&#x2122;s information.

General Information

Data Specifics Spatial (Geographical) Data Pipeyard location is the geographic information for this data group. Spatial data are mainly the external boundaries of the pipeyard, or just a simple point presentation in case there are no engineering drawings available for the pipeyards. An EDI is to be deployed to capture the graphical information from the CAD system to the GIS interface automatically. To achieve this task, all pipeyard drawings must be properly created and geographically projected. Non-Spatial Data Non-spatial data for the GIS are divided into three sets: Contact Information: This includes the main contact details for the person who is responsible for all logistics related to the pipeyard, the pipeyard superintendent. The EDMS contact module will be used to store this information and EDIs will be used to extract this information to the GIS.

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Pipe Material Management Information: This includes the number of pipes available, the total number of pipes expected to be stored at the pipeyard, the date the last update was done to the pipeyard material management information, and the kilometers of the project that will be covered by this pipeyard capacity. All this information will be extracted from the material management system via live link and/or EDI to the NRT. The pipeyard name will act as the main link between the two systems. This link will be used as well to retrieve detailed reports from the material management system about each and every pipe in the yard. Digital Photos: Digital photos will be taken frequently for the pipeyards where pipes are stored. These photos will be kept in the EDMS where a link, the pipeyard name, between the NRT and the EDMS would be established. Once the link is activated, a query will be sent to the EDMS to extract all photos related to the pipeyard in question. Data Details/GIS Attributes

Flags/Notifications

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Pipeyards Data - Workflow & EDIs

Stores Information Description This data group handles store locations in addition to the data related to material management (other than line pipe material). Its main purpose is to help material personnel maintain a better control of the local material required for project execution by providing updated inventories.

Data Delivery to the NRT Tool EDMS and MMS are the main sources of information for this data group. The NRT must be dynamically linked or integrated with the relevant systems to ensure live GIS-based update of the stores information.

General Information

Data Specifics Spatial (Geographical) Data The store location is the geographic information for this data group. Spatial data are mainly the external boundaries of the storage area, or just a simple point presentation in case there are no engineering drawings available for the stores. An EDI is to be deployed to capture the graphical information from the CAD system to the NRT directly. To achieve this, all stores drawings must be properly created and geographically projected. Non-Spatial Data Non-spatial data for the GIS is mainly divided in three sets: Contact Information: This includes the main contact details for the store material superintendent, the person who is charge for the store and for all logistic issues related to the store. EDMS contact module will be used to store this information and EDIs will be used to extract this information to the NRT.

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Stores Material Management Information: This includes a link to some queries and dynamic reports extracted from the material management system to reflect the material status, material balances, material shortages, and material take-off reports in addition to the kilometers of the project that will be covered by this store. All this information will be extracted from the material management system via a live link/EDI to the NRT. The store name will act as the main link between the two systems. Digital Photos: Digital photos will be taken frequently for the stores. These photos will be kept in the EDMS where a link, the store name, between the NRT and the EDMS is established. Once the link is activated, a query will be sent to the EDMS to extract all photos related to the store in question. Data Details/GIS Attributes

Flags/Notifications Alerts related to stores would include:

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Stores Data - Workflow & EDIs

Manpower • Accommodation information • Manpower data

The Accommodation Information Description This data group refers to camps locations, layouts, accommodation details such as capacity and vacancies, and any other related information. Its main purpose is to assist in controlling mobilization/demobilization activities, and make sure logistics arrangements are in place to handle manpower needs.

Data Delivery to the NRT Tool EDMS, Camps Control System (CCS) and the project schedules are the main sources of information for this data group. The NRT must be dynamically linked or integrated with them to ensure live update of the camp’s information.

General Information

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Data Specifics Spatial (Geographical) Data Spatial camp information mainly refers to the external boundaries of the camp. To eliminate the redundant work of retracing the camp layout in the NRT, EDIs need to be developed to capture the graphical information from the CAD system directly. To achieve this, all camp drawings must be properly created and geographically projected. Non-Spatial Data Non-spatial camp data is mainly divided into the following sets: Contact information: The EDMS contacts module will be used to store contact information for the camp key contact. The camp name will be the reference to extract the contacts data from the EDMS CMod to the NRT. Planning/Progress Information: This includes the camp construction date, the progress of construction, and camp demobilization date. All this information would be extracted from the scheduling system via a live link or EDI to the NRT. This link between the construction schedule and the camp data is typically established using four fields to identify different schedule activities related to the camp. While one field might be sufficient, additional fields provide a more accurate depiction of progress. Camp Accommodation Information: This will include the number of camp residents, their statuses, the vacancies per type of room, camp facilities, and related details. This information will be extracted from the camp control system via a live link or EDI to the NRT. The camp name is the linking property. Engineering/Logistics Information: Logistics documents include approvals, permissions, and agreements among others, whereas engineering documents include camp design and construction layouts/drawings. The link between the NRT and the EDMS will be the camp name. Once the link is activated, a query will be sent to the EDMS to extract all documents and drawings related to the camp in question. Digital Photos: The construction team would be required to submit for each camp two sets of photos, one set for the camp sites status before construction and the other set after construction. Those photos will be stored in EDMS where a link with the NRT is established. Once the link is activated, a query will be sent to the EDMS (web client) to extract all photos related to the camp in question. Data Details/GIS Attributes

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Flags/Notifications Alerts related to accommodation/camps are primarily targeted at providing early feedback of issues related to manpower accommodation, assisting decision makers in the administration of manpower logistics activities, and addressing any related safety or security concerns. These would include:

Accommodation/Camps Data - Workflow & EDIs

Manpower Data Description This data group refers to construction site locations with available human resources in each by skill type. Its main aim is to provide management with a quantitative tool to audit and control manpower distribution, and assess the need for any changes that would improve productivity.

Data Delivery to the NRT Tool EDMS, daily progress reports, organisation charts, and daily time sheets are the main sources of information for this data group. The NRT must be dynamically linked or integrated with the relevant systems to ensure live update of the manpower information.

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General Information

Data Specifics Spatial (Geographical) Data The actual locations of the construction sites or the actual spread where the construction team is operating, act as the geographic information for this data group. This information will be updated daily and dynamically using an EDI from the daily progress reports. This EDI will translate the actual site location (surveying coordinates) or spread (from/to km) into linear objects reflecting the actual geographic location of the construction. Non-Spatial Data Non-spatial manpower data is mainly divided into three sets: Contact information: The EDMS contacts module will be used to store contact information for each site construction team supervisor. The team reference code will be used as the unique identifier for the contacts and the link between the EDMS and the NRT. Manpower: This includes the number of staff available at the construction site per category. This information will be extracted from the daily progress report, the organisation chart, and the daily time sheets. The link between these systems and the NRT will be the construction team reference code. Typical categories are: • Management • Senior engineers • Junior engineers • Pipeline Welders • Surveyors • Skilled labourers (other than welders) • Non-skilled labourers • Crane operators • Machine operators (other than cranes) • Drivers Manning Schedules: These include the detailed schedules of manpower resources for each construction spread. This report is generated from the timesheet system and is linked to the NRT using the construction team reference code. Once the link is activated, a query will be sent to the timesheet system to extract all related information for the period in question.

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Data Details/GIS Attributes

Flags/Notifications

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Manpower Data - Workflow & EDIs

Equipment and Vehicles • Plant machinery and vehicles (PMV) stores • Emergency equipment • Equipment tracking information • Vehicle tracking information

PMV Stores Locations Description This data group covers project local stores for equipment and vehicles (plant machinery and vehicles stores) and all relevant information. The main purpose of this group is to provide and control spares required for the operation and maintenance of project equipment, and to ensure there are no construction delays due to shortage.

Data Delivery to the NRT Tool All data related to the location and details of the equipment stores will be collected directly from the PMV control system. A unique identifier for each equipment store will be given as per the project standards. This identifier will be used to link the NRT with the PMV system and EDMS.

General Information

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Data Specifics Spatial (Geographical) Data PMV storesâ&#x20AC;&#x2122; geographical locations are the spatial information for this data group. This would be the external boundaries of the storage area, or just a simple point presentation in case there are no drawings available for the PMV stores. An EDI is to be deployed to capture the geographical information from the CAD system to the NRT directly. To achieve this, all drawings developed for stores must be properly created and geographically projected. Non-Spatial Data Non-spatial data is mainly divided into these sets: Contact Information: This includes the main contact details for the PMV store superintendent, the person who is charge for the store and related logistical issues. The EDMS contact module will be used to store this information and EDIs would be deployed to extract this information to the NRT. PMV Stores Spare Parts List: An inventory report for the spare parts that are available in the PMV store per each equipment/vehicle category will be retrieved from the PMV system to the NRT interface, via a live link or EDI where the store name and the equipment/vehicle category will act as the link. Digital Photos: Digital photos will be taken frequently for the PMV stores. These photos will be saved in the EDMS where a link - the PMV store name - between the NRT and the EDMS is established. Once the link is activated, a query will be sent to the EDMS to extract all photos related to the PMV store in question. Data Details/GIS Attributes

Flags/Notifications

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Equipment Stores - Workflow & EDIs

Emergency Equipment Description This data group refers to locations of emergency equipment and facilities. Its purpose is to provide detailed information regarding emergency equipment so it can be located easily in case of an emergency.

Data Delivery to the NRT Tool The EDMS, the emergency equipment HSE report, HSE system, or PMV system would serve as the main sources of information for this data group. The HSE department must maintain the database related to emergency equipment up to date reflecting the latest status, details and availability.

General Information Data Specifics Spatial (Geographical) Data The locations of the emergency facilities â&#x20AC;&#x201C; the X and Y coordinates â&#x20AC;&#x201C; serve as the geographical presentation of the emergency equipment data group in the NRT interface. Non-Spatial Data Non-spatial emergency equipment data are mainly divided into two sets: Contact information: The EDMS contacts module will be used to store the contact details concerning each person responsible for any emergency facility in each site or location along the pipeline route. Each emergency facility will be given a unique identifier which will be used as a link to the EDMS contacts module.

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Emergency Equipment Details: This includes the emergency depot type and its details. This information can be available in the HSE system or as an HSE report loaded in the EDMS or in an equipment inventory system (PMV system). In all cases, the emergency facility reference number will be used to link to the relevant system and extract the required details for that facility. Data Details/GIS Attributes

Flags/Notifications

Emergency Equipment - Workflow & EDIs

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Equipment Tracking Information Description This data group covers the locations and status of operational equipment along the pipeline route and related vital information. The concept behind equipment traceability is the capability of acquiring the actual location of any equipment at any given time. This will provide the management with powerful and effective tools for controlling, reporting and studying the equipment operations closely, so that proper measures are taken to improve the construction operations, productivity rates, risk management, and rescue requests responses. The equipment traceability system consists of four major components: • A GPS-based tracking device installed on the equipment; this device will record and send, at minimum, the location and operation status of the equipment. • A server with the proper hardware to receive the data transmitted periodically from each tracking device. • Software to process the tracking information and save it within the database. • Communications infrastructure (GPRS or GSM), which will serve as the media for data transmission.

Data Delivery to the NRT Tool The EDMS, the equipment tracking system, and the PMV system are the main sources of information. These systems will collect reference and active (live) information about the equipment in question.

General Information

Data Specifics Spatial (Geographical) Data The location of the equipment – the X and Y coordinates – is the geographical presentation for the equipment tracking data group. These data will be extracted from the equipment tracking system periodically and automatically, typically through an embedded device that transmits relevant location status information for processing. Each equipment will be given a unique reference number, which will act as the link between the NRT and relevant systems. A sample basic format for this number is: TTT-NNNN where: • TTT is a three letter identifying the equipment type (e.g. EXC for excavator, CRN for crane) • NNNN is a sequential number per equipment Non-Spatial Data Non-spatial equipment tracking data is mainly divided into four sets: Contact Information: The EDMS contacts module will be used to store the contact details for each person responsible for operational equipment in each location along the pipeline route. The equipment reference number will be used as a link to EDMS contacts module. Equipment List: This includes a list of the available major equipment per category and their locations. The list includes categories involved in the pipeline construction operations such as: • Earth-moving including excavators, trenchers, bulldozers, loaders, scrapers, graders, and rollers. • Pipe handling (lifting and loading) including cranes, side booms, fork lifts. • Pipe-bending machines. • Pipe-welding machines. • Trailers and pipe carriers

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Equipment Details: For each of the above types, a detailed list of reports will be available showing additional information, such as manufacturer, capacity, part suppliers, fuel type, power, and maintenance schedule for every equipment within the selected category. This information will be extracted from the PMV system via a live link or EDI with the NRT. These data will be shown on the NRT interface once the link to the PMV system is activated, using the equipment reference number. Active Information: The main data to be shown is the equipment type and operation status (idle or operating, static or moving). This inforamtion will be extracted from the equipment tracking system periodically and automatically via a live link or EDI. The reference number will be used to link the NRT with the equipment tracking system. Digital Photos: Digital photos will be taken frequently for equipment to show the equipment visually, and will be saved in the EDMS. A link, the equipment reference number, is established between the NRT and EDMS. Once the link is activated, a query will be sent to the EDMS to extract photos related to the equipment in question. Data Details/GIS Attributes

Flags/Notifications

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Equipment Tracking - Workflow & EDIs

Vehicle Tracking Information Description This data group refers to the locations of project operational vehicles along the pipeline route with related vital information. This is almost similar to the previous group, the equipment tracking data group, except that it covers moving passenger vehicles, such as cars and buses, and any operation that includes distance movement like material transport. This will provide the management with several powerful and effective tools for controlling and reporting the use of vehicles in the project, so that proper measures are taken to improve the use of these vehicles, manage risks, and respond to rescue requests. The vehicle traceability system consists of four major components: • A GPS-based tracking device to be installed on each equipment; this device will record and send, at minimum, the location and status of the equipment. • A server with the proper hardware to receive the data being transmitted periodically from each tracking device. • Software to get the tracking information and save it in a database. • Communications infrastructure (GPRS or GSM), which will serve as the media for data transmission.

Data Delivery to the NRT Tool The EDMS, the vehicle tracking system, the journey management system (JMS), and the PMV system are the main sources of information for this data group.

General Information

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Data Specifics Spatial (Geographical) Data The location of the equipment – the X and Y coordinates – is the geographical presentation for the vehicle tracking data group. These data will be extracted from the embedded unit of the vehicle tracking system periodically and automatically. Each vehicle will be given a unique reference number, which will act as the link between the NRT tool and the relevant systems. A simple format for this number is: TTT-NNNN where: • TTT is a three letter identifying the vehicle type (e.g. BUS for buses, 4WD for four-wheel drive cars) • NNNN is a sequential number per vehicle Non-Spatial Data Non-spatial vehicle tracking data is mainly divided into four sets: Contact Information: The EDMS contacts module will be used to store the contact details for each person responsible for operational vehicles in each location along the pipeline route. The vehicle reference number will be used as a link to the EDMS contacts module. Vehicle List: This includes a list of the available vehicles per category such as: • Trucks • Buses • Four-wheel cars • Saloon cars Vehicle Details: For each of the above types, a detailed list of reports will be available showing additional information, such as brand, manufacturer, capacity, part supplier, fuel type, power, and maintenance schedule about each vehicle within the selected category. This information will be extracted from the PMV system via a live link or EDI with the NRT. The vehicle reference number will act as the link between the two systems. Active Information: The vehicle type and operational status (static or moving) are the major data to be shown on the NRT interface. These data will be extracted from the vehicle tracking system and journey management system periodically and automatically via a live link or EDI. The operational vehicle reference number will be used to link the NRT with these systems. Digital Photos: Digital photos will be taken frequently for each vehicle to show the vehicle visually, and will be saved in the EDMS. A link, the vehicle reference number, between the NRT and the EDMS is established. Once the link is activated, a query will be sent to the EDMS to extract all photos related to the vehicle in question. Data Details/GIS Attributes

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Flags/Notifications

Vehicle Tracking - Workflow & EDIs

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Planning And Progress This data group comprises the following two classes: • Construction progress of activities • Planning/scheduling of activities The contents of each section represent different stages of the construction, namely on-site activities versus planned schedule. The flags and notifications will be considered within the context of the two classes.

Daily Pipeline Progress Activities Description The daily progress of the pipeline main construction activities in kilometer ranges are shown and projected in the NRT interface on a near-real-time basis (a maximum delay of one day). The main activities of pipeline construction operations are: • Route clearance (clearance, de-bushing, demining, etc.) • Route survey • ROW preparation (top soil removal, grading, etc.) • Stringing • Bending • Welding (end face preparation, joint welding, NDT, field joint coating) • Trenching (excavation, bedding, padding, etc.) • Lowering and laying • Backfilling • Hydrotesting • Cleaning and gauging • ROW reinstatement • Any other project specific activity Each one of these activities will be treated as a separate data group for ease of viewing and manipulation of data by the end user.

Data Delivery to the NRT Tool Daily progress reports, progress measuring and monitoring systems, and EDMS are the main sources of information for these data groups. To ensure daily updates of the progress data groups, the NRT must be dynamically linked and integrated with the relevant information sources via EDIs. This will reduce redundant data entry efforts needed for updating the progress statuses.

General Information

Data Specifics Spatial (Geographical) Data The geographic information for this data group is the progress achievement of each activity per day in kilometers, from the start km to the end km. An EDI is to be deployed to capture the geographical information from the daily progress report and project it directly to the NRT interface.

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Non-Spatial Data Non-spatial data are mainly divided into two sets: Daily Progress Information: This includes the progress report reference number, the report date, and the progress achievement (distance in km). This information will be extracted from the daily progress report or the progress measurement system via a live link or EDI. Additionally, this daily progress report will be kept in the EDMS, where it can be retrieved via a dynamic link using the report number as a reference. Digital Photos: Digital photos are to be taken for the daily progress activities. These photos are to be kept in the EDMS where a link, the report reference number, is established between the NRT and the EDMS. Once the link is activated, a query will be sent to the EDMS to extract all progress photos related to the specific pipeline construction activity for any specific period. Data Details/GIS Attributes (For Each Pipeline Construction Activity) A similar data group is to be developed for each construction activity in the above list. This would include the information required for building the pipebook handover document, specifically related to welding, NDT, line pipe, and as-built survey data.

Progress Activities - Workflow & EDIs

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Pipeline Planning/Scheduling Activities Description This data group class refers to the construction schedule of the major activities on the pipeline. The NRT will reflect the planned dates for the main construction works in kilometers. These activities include: • Route clearance (clearance, de-bushing, demining, etc.) • Route survey • ROW preparation (top soil removal, grading, etc.) • Stringing • Bending • Welding (end face preparation, joint welding, NDT, field joint coating) • Trenching (excavation, bedding, padding, etc.) • Lowering and laying • Backfilling • Hydrotesting • Cleaning and gauging • ROW reinstatement • Any other project specific activity Those activities must be identical to the way progress is measured, such that at any point of time a comparison can be made of planned versus achieved. Similarly, each one of these activities will be treated as a separate data group for ease of viewing by the end user.

Data Delivery to the NRT Tool The planning/scheduling system is the main source of information for these data groups. The NRT tool must be dynamically linked or integrated with the planning/scheduling system via EDIs to ensure automatic update of modifications in the plan.

General Information

Data Specifics Spatial (Geographical) Data The planned route coverage of any activity in kilometers, from the start km to the end km, is the geographic spatial information for this data group. An EDI is to be deployed to capture the graphical information from the scheduling system and project it directly in the NRT tool interface. Non-Spatial Data Non-spatial data are: Planning and Scheduling Information: This includes the activity code, activity description, expected early start and finish dates, expected late start and finish dates, total float and the portion of the pipeline that is planned under this activity. All this information will be extracted from the planning/scheduling system via a live link or EDI to the NRT. The activity code would act as the reference link between the systems. Data Details/GIS Attributes (For Each Pipeline Construction Activity) A similar data group is to be developed for each construction activity in the above list.

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Flags/Notifications

Planning/Scheduling Activities - Workflow & EDIs

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HSE and Social • Points of interest (hospitals, medical centers, police stations, etc.) • Accidents and incidents • Grievances and complaints • Areas of special status

Points of Interest (Hospitals, Medical Centers, Police Stations, etc.) Description This data group covers the location of hospitals, medical facilities, police stations, and any other points of interest with their contact details. Its main purpose is to provide fast access to key information for project stakeholders.

Data Delivery to the NRT Tool All data related to the location and details of point of interest will be collected directly by the HSE team and stored in the HSE system or database if available. EDMS will be used to capture this information. A unique identifier for each facility or point of interest will be given, based on a defined naming convention such as TTT_NNNN where: • TTT is a three-character code describing the type of facility (e.g. HOS for hospital, POL for police station) • NNNN is a four-digit sequential number for each point of interest.

General Information

Data Specifics Spatial (Geographical) Data The location of the point of interest – the GPS X and Y – is the main geographical information in this data group. Non-Spatial Data Non-spatial point of interest data are mainly divided into three sets: Contact information: The EDMS contacts module will be used to store contact information for each point of interest captured into the NRT. The reference code for each facility will be the unique identifier and the link to the EDMS contacts module. Other Information: This includes the name, type, and the location description of the facility. This information can be entered directly into the NRT or extracted from the HSE system or database via a link, being the unique identifier of the facility. Digital Photos: Digital photos taken for the points of interest will be saved in the EDMS where a link, the reference number, between the NRT and the EDMS is established. Once the link is activated, a query will be sent to the EDMS to extract photos related to the point of interest in question. Data Details/GIS Attributes

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Points of Interest - Workflow & EDIs

Accidents and Incidents Description Pipeline construction accidents/incidents, their locations, details, categories, and related reports are all covered and presented under this data group. Any incident (or accident) whether fatal, minor, or a near miss is to be recorded and presented on the NRT. The availability of such crucial information will expose the safety status of the construction operations on a daily basis for decision makers, giving them an early indication of the potential areas for improving the construction operations and staff behaviour,to help them become more safety-alert and conscious, and eventually achieve the target of zero fatalities.

Data Delivery to the NRT Tool The EDMS incident recording module acts as the main source of information for this data group. To ensure daily update of the incident data group, the NRT must be dynamically linked or integrated with the incidents recording module via an EDI. The incident reports are kept in EDMS, whereas the incidents recording module will provide all the attributes required to register the occurrence of this incident and its vital information. A better approach would be the automation of the incident reporting process, for instance using handheld devices equipped with GPS and a camera and carried by safety officers. The officer will record all related information on the handheld so that an incident report can be generated automatically and fed into EDMS and the incident recording module. The information recorded on the handheld will constitute the attributes for that incident report and digital photos will be linked as well. An EDI will transfer all this information automatically to the NRT.

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General Information

Data Specifics Spatial (Geographical) Data The incident location - X and Y coordinates that are recorded as part of the incident report â&#x20AC;&#x201C; is the geographic information for this data group. An EDI is to be deployed to capture the graphical information from EDMS incident recording module, and project it directly to the NRT. Non-Spatial Data Non-spatial data include: Incident Report Details: These include the incident report number, the report date, the incident type, the incident category, and the incident description. This information will be extracted from the EDMS system on a daily basis via an EDI. The incident report reference number will act as the main link between the NRT and the EDMS. Additionally, the actual incident report will be kept in the EDMS where it can be retrieved through the NRT interface via a dynamic link using the report reference number. Digital Photos: Digital photos taken for the incident are to be kept in the EDMS where a link, the incident report reference number, is established between the NRT and the EDMS. Once the link is activated, a query will be sent to the EDMS to extract photos related to the incident in question. Data Details/GIS Attributes

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Accidents/Incidents Information - Workflow & EDIs

Flags/Notifications

Grievances And Complaints Description With the increased significance of social interaction especially in pipelines passing through populated areas, grievances and complaints that are recorded against the project should be available for reference within the NRT, to assist management in taking corrective actions and plan activities with increased social awareness.

Data Delivery to the NRT Tool Grievance reports are the main source of information for this data group. Therefore, the interface management department, logistics department, or equivalent entity would record any grievance or complaint that arises during construction. Among others, GIS team must be duly informed for proper registration within the NRT. This is achieved by adding the GIS team to the project distribution matrix for such issues.

General Information

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Data Specifics Spatial (Geographical) Data The location where the complaint occurs - the GPS X and Y coordinates â&#x20AC;&#x201C; will be registered as attributes for the report in the EDMS. An EDI is to be used to upload the graphical location into the NRT from EDMS attributes. Non-Spatial Data The main non-spatial data include: Grievance Report Details: This includes the type and description of the grievance or complaint. These values will be saved as EDMS attributes for the reports, and the interface management departmentâ&#x20AC;&#x2122;s EDMS user will be responsible for inputting these data. An EDI is to be used to extract these data into the NRT. The Grievances report reference number will act as the main link between the systems. Additionally, the actual report will be kept in the EDMS where it can be retrieved through the NRT interface via a dynamic link (report reference number). Digital Photos: Digital photos taken related to the grievance or complaint are kept in the EDMS where a link, the report reference number, is established between the NRT and the EDMS. Once the link is activated, a query will be sent to the EDMS to extract all photos related to the grievance report in question.

Data Details/GIS Attributes

Grievances and Complaints - Workflow & EDIs

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Areas of Special Status Description This data group includes all areas of specific environmental, safety, or security concerns which might affect the pipeline operations. The system should spot these areas and display any significant information on the NRT interface to be reviewed as needed by key personnel for decisive action when construction operations are near or within such areas. Contaminated sites, water sources, natural reserves, waste emission sites, historical zones, and archeological sites are examples of environmentally sensitive areas covered by this data group. Access-restricted areas and military zones are examples of special security areas whereas mine fields, unstable explosives zones, and socially unsafe areas are examples of special safety areas.

Data Delivery to the NRT Tool HSE reports and surveys provide the main source of data for this group. The HSE team will ensure that all related findings are properly distributed to concerned project teams, including the GIS team who can thus have access to any report or survey related to any area classified as of special status.

General Information

Data Specifics Spatial (Geographical) Data The outmost boundaries of the special area represent the geographic information for this data group. If available, an EDI should be developed to upload the geographical location into the NRT from electronic HSE reports/surveys. Alternatively, standard GIS functions would be used to create these features for the NRT system, based on surveying reports. Non-spatial data The non-spatial data for this group are mainly divided into three sets: Contact information: The EDMS contacts module will be used to store contact information for persons responsible for these areas. A unique reference number will be given for each site, and this will link the EDMS with the NRT. Other Information: This includes the category of the site (e.g. environmental, safety, security), the type of the special area (water source, contaminated site, restricted area, nuclear area, military area etc.), in addition to details and description for this site. These values will be stored in the EDMS as properties for the HSE/surveying report. An EDI will be used to extract these values from EDMS to the NRT. The special site reference number will be used as the link between the systems. Photos, documents and reports: Digital photos and reports related to the special area will be kept in the EDMS, where a link (the special area reference number) between the NRT and the EDMS is established. Once the link is activated, a query will be sent to the EDMS to extract all documents and photos related to the special area in question.

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Data Details/GIS Attributes

Areas of Special Status - Workflow & EDIs

Flags/Notifications

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Appendix 13.1.1

Engineering Data The NRT should also capture information about essential activities other than those directly linked to the construction of the line pipe itself. The key purpose of these data groups is to provide relevant information for the project stakeholders to consider in planning on-site activities for pipeline and observe the progress of additional supporting activities. The main source of information would be the engineering and design documents, and they would fall under one of the following categories: • Accessibility • Crossings • Access roads • Marker points • Design • Pipeline routes • AGIs • Tie-in points • Fiber-optic cables Non-pipeline Features: geotechnical data and cathodic protection data • • These include boreholes, soil resistivity information, cathodic test points, rectifiers, ground beds, galvanic anodes, bond leads, etc. • Any additional project-specific data groups

Crossings Description This data group refers to all crossing types along the pipeline route such as gas pipes, oil pipes, fences, electric lines, telephone lines, water pipes, roads, railways, rivers, canals and ditches. Prompt access to accurate information about crossings would assist construction personnel to prepare better for construction activities by highlighting what permits need to be prepared and what special construction methods need to be considered.

Data Delivery to the NRT Tool Alignment sheets, crossing drawings and the crossing register are the main sources of information for this group. These documents are maintained within the EDMS, and EDIs are to be developed to capture their data from the relevant engineering documents directly to the NRT. Each crossing will be given a unique identifier as per the project standards. This unique reference will act as the link between the NRT and the EDMS or any other data container that might carry valuable information related to the crossings.

General Information

Data Specifics Spatial (Geographical Data) Spatial crossing information is mainly the centerline of each crossings and the width of the crossing at its beginning and end. To eliminate the redundant work of retracing the crossings layout in the NRT, EDIs should be developed to capture the geographical information directly. To achieve this task, all alignment sheets and crossing drawings must be properly created and geographically projected. Moreover, crossing features that are required should be created on separate layers and according to proper CAD standards.

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Non-Spatial Data Non-spatial crossing data for NRT are mainly divided into the following sets: Contact information: The EDMS contacts module will be used to store contact information for each crossing. The crossingâ&#x20AC;&#x2122;s unique name will be used as the unique identifier for the contacts. An EDI will be adopted to capture contact data from EDMS to the NRT. Others: This includes the crossing identifier, crossing type, crossing category, and reference to site surveys. An EDI is used to capture these data from the crossing register or EDMS to the NRT. All documents related to a specific crossing whether drawings or site surveys, would be stored in EDMS with properties holding the crossing identifier that would act as a link between the EDMS and NRT. Once the link is activated, a query will be sent to the EDMS to extract all drawings or documents related to the crossing in question. Digital Photos: The construction team is to submit for each crossing two sets of photos, one set taken before construction and the other set showing the status after construction. Those photos are kept in the EDMS where a link, the crossing reference number, between the NRT and the EDMS is established. Once the link is activated, a query will be sent to the EDMS to extract all photos related to the crossing in question. Data Details/GIS Attributes

Crossing Type per Crossing Category

Additional Properties

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Crossings - Workflow & EDIs

Access Roads Description This data group refers to the project existing and to-be-constructed access roads along the pipeline route, with all relevant information. It is intended to assist management in logistics and construction support functions by displaying accessibility options at different project locations.

Data Delivery to the NRT Tool Access road drawings are the main source of information. The GIS team must be updated on any changes on the access road drawings issued to have updated information within the NRT.

General Information

Data Specifics Spatial (Geographical Data) Spatial access road information is mainly the centerline of the access road. To eliminate the redundant work of retracing the access roads layout in the GIS interface, EDIs need to be developed to capture the geographical information to the NRT directly. To achieve this task, all access road drawings must be properly created and geographically projected. Moreover, access road features that are required should be created on separate layers and according to proper CAD standards. Non-Spatial Data Non-spatial access road data for GIS are divided into the following sets: Contact information: The EDMS contacts module will be used to store contact information for each access road. The access road name will be used as the unique identifier to extract the contacts details.

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Others: This includes the access road identifier, the name of the facility serviced, road type, and description. This information is typically available on the access road drawings. The EDMS operator will be responsible for inputting the drawings with attributes into the EDMS, and the unique access road identifier would link the EDMS and NRT, to extract the drawings and data on demand. Digital Photos: The construction team is to submit for each access road two sets of photos, one set is for the access road status before construction and the other set is for the status after construction. Those photos would be kept in the EDMS and linked by the unique access road reference number to the NRT for extraction on call. Data Details/GIS Attributes

Access Road Data - Workflow & EDIs

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Marker Points Description This data group refers to the different types of markers for the constructed pipeline, such as aerial and ground markers; this information would assist in tracing the pipeline design and as-built routes.

Data Delivery to the NRT Tool Alignment sheets and as-built data are the main sources of information for this data group.

General Information

Data Specifics Spatial (Geographical Data) Spatial information for this shape file is mainly marker locations along the pipeline route. To eliminate the redundant work of retracing the marker points in the NRT, EDIs will be developed to capture the point locations of the pipeline marker directly. To achieve this task, all alignment sheets must be properly created and geographically projected, and marker points created on separate layers and according to proper CAD standards. Non-Spatial Data Non-spatial data for the marker shape files is mainly the name and type of markers, which are typically available in the alignment sheets as block attributes. EDIs will be developed to extract the required values for use in the NRT. Data Details/GIS Attributes

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Marker Points - Workflow & EDIs

Pipeline Routes Description This specific data group refers the pipeline routes considered at the different stages of the project, including at the design and as-built stages. Its purpose is to provide a geographical display of the pipeline centerlines in comparison with the other features shown on the NRT interface in order to assist in better visual planning.

Data Delivery to the NRT Tool Alignment sheets, route surveys, and other reference drawings maintained within the EDMS are the main sources of information for this data group. The GIS team should be informed of any relevant updates to maintain the latest accurate display of the route centerline within the NRT.

General Information

Data Specifics Spatial (Geographical Data) Spatial pipeline route information refers mainly to the properly-projected pipeline centerline at engineering (and later as-built) stage. To eliminate the redundant work of retracing this information for the NRT, EDIs need to be developed to capture the geographical information to the NRT directly from alignment sheets and survey data. To achieve this task, all relevant drawings must be properly created and geographically projected.

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Non-Spatial Data These include a route unique identifier with descriptive details of the route. Survey reports and reference drawings will be maintained in the EDMS with proper attributes referencing the pipeline route. An EDMS query/EDI will use the route identifier value to extract all documents or drawings related to a specific route. Data Details/GIS Attributes

Pipeline Routes Data - Workflow & EDIs

Above Ground Installations (AGIs) Description This data group refers to AGI information along with the basic outline of the AGIs. These include facilities such as block valves, check valves, pigging stations, pump stations, pressure boosting stations, and metering stations. The information within this group helps present a visual clarified scope of the AGI from within the NRT interface.

Data Delivery to the NRT Tool AGI drawings are the main source of information for this shape file. The GIS team should be informed of any AGI drawings issued to update the NRT promptly.

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General Information

Data Specifics Spatial (Geographical Data) Spatial AGI information is mainly the outline fence of the facility, the track leading to the facility and the main AGI point location. To eliminate the redundant work of retracing this information for the NRT, EDIs need to be developed to capture the geographical information directly. All AGI drawings must be properly created and geographically projected, and related AGI features created on separate layers according to proper CAD standards. Non-Spatial Data This includes the AGI unique identifier, AGI type and references to all AGI reports. The first two are typically available on the AGI design drawing title block. The EDMS will be used to capture these values as attributes for the AGI drawing. The EDMS operator will be responsible to input these data in the EDMS. All AGI reports will be given an attribute that will hold the unique name of the AGI, and an EDMS query/EDI will use this value to extract all documents assigned for a specific AGI with all relevant attributes.

Data Details/GIS Attributes

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AGI's Data - Workflow & EDIs

Tie-In Points Description This data group refers to points where the pipeline ties in to external facilities outside the main scope of work such as gas lines, electric lines, water pipes, and other utilities. It is intended to provide a visual scope of the expected interaction with external players for management and other key players to assist in the coordination efforts.

Data Delivery to the NRT Tool Alignment sheets and any tie-in schedules available as a part of the tender or engineering documentation are the main sources of information. The EDMS operator shall ensure that these documents are readily available and up-to-date within the EDMS, and that any changes are highlighted to the GIS Team, to be incorporated within the NRT.

General Information

Data Specifics Spatial (Geographical Data) Spatial information for this shape file is mainly the location of the tie-in points. To eliminate redundant data-entry work, EDIs should be developed to capture the location of the tie-in points to the NRT directly. To achieve this task, all alignment sheets must be properly created and geographically projected. Tie-in points should be created on separate layers and according to proper CAD standards.

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Non-Spatial Data Non-spatial data for the tie-in points include the type of the facility that the project ties in, and any special reports or construction references (e.g. before/after photos) that need to be considered in the tying-in process. It also includes contact information of personnel involved with this facility. A unique tiein reference will be used to identify each tie-in point, and EDIs should be developed to extract the tie-in information to the NRT. Data Details/GIS Attributes

Tie-in Points - Workflow & EDIs

Fiber-optic Cables Description This data group refers to the routes of the fiber-optic cables, the cable pulpits, and the termination points. Its purpose is to provide the FOC scope in visual display on the NRT to assist in planning related activities.

Data Delivery to the NRT Tool Fiber-optic design drawings and related cable schedules are the main sources of information for this data group. This information should be readily updated within the EDMS, and provided to the GIS team who will be responsible for displaying these data on the NRT interface.

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General Information

Data Specifics Spatial (Geographical Data) Spatial information for this shape file is mainly the cable route, and locations of the pulpit and termination points. To eliminate the redundant data-entry work, EDIs should be developed to capture this information to the NRT directly. All fiber-optic cable general arrangement drawings must be properly created and geographically projected, and related features should be created on separate layers and according to proper CAD standards. Non-Spatial Data Non-spatial fiber-optic cable data are mainly divided in two sets: Progress Data: The construction progress for the fibre-optic cable will be measured per KP (kilometer point). This information would be available in the progress monitoring system or the daily construction reports. An EDI should be developed to capture this information to the NRT directly. Other Information: This includes the tag numbers for the optic cables, the pulpits and termination points in addition to references for the faults reports and the test results. The tag numbers are typically available on the design drawings as block attributes. EDIs should be developed to extract the required tags and assign them to the relevant feature in the NRT. These references to fault reports and test results are static values for the same section of the optical cable, and should be available in the EDMS for extraction into the NRT. Data Details/GIS Attributes

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Fiber-optic Cables - Workflow & EDIs

Additional Features, Geotechnical And Cathodic Protection Data Description This data group comprises information related to additional features of the pipeline not included under any of the previous sections, and of significant value to key personnel during the construction phase. This includes activities and reports such as boreholes, soil resistivity information, cathodic test pointsâ&#x20AC;&#x2122; data, rectifiers, ground beds, galvanic anodes, and bond leads. Data related to the design and installation locations, and the attributes of each feature are the main constituents of this group.

Data Delivery to the NRT Tool Design documents/drawings, alignment sheets, test reports such as cathodic protection and resistivity tests, and construction progress reports are the main sources of information for this data group. The EDMS team is responsible for ensuring that the EDMS is populated with the latest updates of these data in a timely fashion, so that the GIS team has access to the related information for displaying in the NRT.

General Information

Data Specifics Spatial (Geographical Data) The main spatial information for this data group is the feature location. Wherever possible, EDIs should be developed to capture the location points to the NRT directly. All alignment sheets and reference drawings must be properly created and geographically projected, and related features created in separate layers as per proper CAD standards.

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Non-Spatial Data Non-spatial data for these features are mainly the reference ID and attributes. The reference IDs can be obtained from the design documents. EDIs should be developed to extract the required attribute values and assign them to the relevant feature in the NRT. Reference reports and static values would be available in EDMS and would be retrieved to the NRT by linking the unique reference ID. Data Details/GIS Attributes

Additional Features â&#x20AC;&#x201C; Workflow & EDIs Workflows are dependent on the specific feature to be displayed on the NRT, and what type of information is extracted, rather than linked from the EDMS. Whereas spatial and any contact data would be extracted to the NRT database, reference documents, photos, and other non-spatial data would be linked via a query/EDI connecting on the unique identifier of the feature in question.

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Recommended Technical Specifications This section presents general recommendations for the selection of technical tools to be used in the development of the NRT. It is intended as a guideline during the detailed system design phase, specifically for areas of technical significance related to building the GIS-based interface, acquiring data from system repositories, and the display of this information. These recommendations are derived from market studies of available open source and commercial software, historical information, programming tools, common practices, modern technologies, standardized formats, and other relevant research items. The results recorded herewith are intended to highlight key technical features to be considered to meet the conceptual functional specification requirements.

GIS Software The GIS-based interface is one of the core concepts of the NRT. Careful selection of the GIS software to be used is hence of vital importance. The selected software should: • Have the capability to work with vector and raster data, so that combinations between satellite images and pipeline objects are possible. • Run under different platforms and operating systems, such as MS Windows, Linux, and UNIX. • Have interoperability with other GIS software, as GIS data from different sources and with different formats might have to be readable. • Be able to manage topology and 3D representations. This allows the user to have 3D outlooks on the pipeline project for improved analyses. • Produce good quality cartographic representations. The additional advantage of preparing detailed project layouts is a very useful tool for construction teams. • Allow for developments with common languages like VB and C++, so that users can add and manipulate scripts for more efficient use. • Work with large data structures, as the pipeline project would entail a huge amount of data. • Allow advanced spatial analysis of vector data and raster data, simultaneously if possible. • Allow for multilingual interfaces.

Connectivity To Data Sources With a wide scope of information to handle, the NRT would have to not only extract but also link to existing databases, to make use of data in existing control systems. Finding the right connectivity tools is a critical factor in ensuring the data is not only provided promptly, but also accurately. Based on our review of common connectivity techniques, including Microsoft ActiveX data objects (ADO), object linking and embedding database (OLE DB), and open database connectivity (ODBC), the better choice for our NRT is the one that can: • Work with different operating systems. • Handle both relational and non-relational databases. • Connect to multiple databases simultaneously.

Web Mapping Of Pipeline Data There are two main ways to publish GIS information on the web. Creating a specific website is one, and exporting the data and maps to existing websites is the other. The recommended technical specifications for web mapping of pipeline projects depend on the selection made. In the case of creating a new website, it is useful to have a website that can: • Be dynamic. • Visualize maps with advanced functionalities.

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• Use vector and raster data. • Have good compatibility with different navigators, programming languages, and database formats. In the case of exporting data to existing web sites, the selection should be a web site that is: • A known geographic website with a simple data format. • Compatible with different programming software formats.

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Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Glossary

Glossary The following definitions and abbreviations apply in the context of this Appendix unless otherwise mentioned: AGI Above ground installations AUT Automatic ultrasonic testing CAD Computer-aided design CANBUS Controllerâ&#x20AC;&#x201C;area network bus standard CANDATA CANBUS data CCS Camp control system CMod EDMS contacts module CP Cathodic protection CPM Critical path method CSE Confined space entry DES Discrete event simulation ECI Eddy current inspection EDI Electronic data interface/interchange EDMS Electronic document management system ERP Emergency response plans ERW Electric resistance weld ExTr Expediting and shipment tracking system FBE Fusion bonded epoxy FLUW Facing, lining up and welding (IPLOCA working group) FMS Fleet management system FOC Fiber-optic cables GIS Geographic information system GPRS General packet radio service GPS Global positioning system GSM Global system for mobile HAZID Hazard identification HAZOP Hazard and operability study HFW High frequency induction weld HLA High level architecture HSE Health, safety and environment HSEIA/HSEIS Health, safety and environment impact assessment/study HSES Health, safety, environment and socioeconomic IP Injured person IPLOCA International Pipe Line and Offshore Contractors Association JMS Journey management system KP Kilometer point LLI Long lead items LNG Liquified natural gas MAOP Maximum allowable operating pressure MFL Magnetic flux leakage MMS Material management system MPI Magnetic particle inspection MTO Made to order MUT Manual ultrasonic testing NC/NCI IPLOCA Novel Construction Initiative NDT Non-destructive testing NRT Near-real-time tool OD Outside diameter OEM Original equipment manufacturer PDA Personal digital assistant PDC Planning, design and control (IPLOCA workgroup) PFD Probability to fail on demand PK Point kilometre (see KP) PMV Plant machinery and vehicles POD Probability of detection

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Glossary

PPE PTO QA/QC QRA R&D RFID RFQ ROW RPE RSS RT SAWH SAWL SCADA SIL SIMOPS SIS SMS SMYS UPI UT VOC VPN WBS WiFi WiMax WPS WT XML

Personal protective equipment Power take-off Quality assurance/control Quantitative risk assessment Research and development Radio-frequency identification Request for quotation Right of way Respiratory protective equipment Really simple syndication (web feed format for publishing frequently updated works) Radiographic testing Submerged arc-welded pipe, helical seams Submerged arc-welded pipe, longitudinal seams Supervisory control and data acquisition Safety integrity level Simultaneous operations Safety instrumented system Short message service (texts) Specified minimum yield strength Unique purchase items Ultrasonic testing Volatile organic compound Virtual private network Work breakdown structure Wireless networking technology Worldwide interoperability for microwave access (protocol) Welding procedure specifications Wall thickness Extensible markup language

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Bibliography

Bibliography Section 11

• •

•

Pipeline Protection Systems

Various company coating manuals, construction specifications, engineering manuals and material specifications, material, equipment manufacturer and coating applicator websites Selected national, industry, and international standards, specifications and recommended practices: • CSA Z245.20-02/Z245.21 - External Fusion Bond Epoxy Coating for Steel Pipe - External Polyethylene Coating for Pipe • DVGW GW 15: 2007-01 - Protection from corrosion; coating of pipes, fittings and moulded parts • DVGW GW 340:1999-04 – FZM-Ummantelung zum mechanischem Schutz von Stahlrohren und –formstücken mit Polyolefinumhüllung – Anforderungen und Prüfung, Nachumhüllung und Reparatur, Hinweise zur Verlegung und zum Korrosionschutz • EN ISO 21809-1 (draft) - Petroleum and natural gas industries – External coatings for buried or submerged pipelines used in pipeline transportation systems - Part 1: Polyolefin coatings (3- layer PE and 3- layer PP) EN ISO 21809-2 - Petroleum and natural gas industries - External coatings for • buried or submerged pipelines used in pipeline transportation systems - Part 2: Fusion-bonded epoxy coatings (2007) • EN ISO 21809-3 - Petroleum and natural gas industries -- External coatings for buried or submerged pipelines used in pipeline transportation systems -- Part 3: Field joint coatings (2008) • EN ISO 21809-5 (draft) - Petroleum and natural gas industries -- External coatings for buried or submerged pipelines used in pipeline transportation systems -- Part 5: External concrete coatings Selected technical papers, books and reports: • Comparison Methodology of Pipe Protection Methods, CIMARRON Engineering Ltd, 2005 Design and Coating Selection Considerations for Successful Completion of a • Horizontal Directionally Drilled (HDD) Crossing, Williamson A.I., Jameson J.R. • Development of a Cost Effective Powder Coated Multi-Component Coating for Underground Pipelines, Singh P., Cox J. Field joint developments and compatibility considerations, Tailor D., Hodgins • W., Gritis N., BHR 15th International Conference on Pipeline Protection • High temperature pipeline coatings - field joint challenges in remote construction, Buchanan R., Hodgins W., BHR 16th International Conference on Pipeline Protection • The importance of hot water immersion testing for evaluating the long term performance of buried pipeline coatings, John R., Alaerts E., BHR 16th International Conference on Pipeline Protection Long term performance - critical parameters in materials evaluation and • process controls of FBE and 3LPO pipeline coatings – Guan S.W., Wong D.T., World Pipelines, 2008 • Mechanical Protection of Fusion-Bonded Epoxy Coatings by Use of Fibre Reinforced Mortar, Schemberger D., BHRA, Nov 1985 • New developments in high performance coatings, Worthingham R., Cettiner M., Singh P., Haberer S., Gritis N., 2005 • Optimization of Pipeline Coating and Backfill Selection, Espiner R, Thompson I, Barnett J, NACE, 2003

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Bibliography

• • • • • • • • • • • •

•

The Performance Capabilities of Advanced Pipeline Coatings, Singh P., Williamson A.I., Hancock J.R., Wilmott M.J. Pipeline Coatings & Joint Protection: A Brief History, Conventional Thinking & New Technologies, Buchanan R., Rio Pipeline 2003 Pipeline Girth-Weld Joint Corrosion Protection: Remote Project Field Installation Challenges, Buchanan R., Dunn R., Gritis N., International Conference on Terrain and Geohazard Challenges Facing Onshore Oil and Gas Pipelines The Resistance of Advanced Pipeline Coatings to Penetration and Abrasion by Hard Rock, Williamson A.I., Singh P., Hancock J.R., October 2000 Rock Jacket – A Superior Pipe Protection System for Rocky Terrain, Bragagnolo P., NACE, Nov 1991 Simulation of Coating Behaviour in Buried Service, Andrenacci A, Wong D.T., NACE, 2007 Subsea Pipeline Engineering, Palmer, A.C., King R.A., 2004 Transmission Pipelines and Land Use: A Risk-Informed Approach – Special Report 281, US Transportation Research Board (TRB), 2004 Trends in Pipeline Field Joint Coatings, Buchanan R., Pipeline Coating Conference 2009, Vienna, Austria Vancouver Island Pipeline Project – Material Selection, Engineering Design and Construction Plan, Yamauchi H., NACE, Nov 1991 Various company coating manuals, construction specifications, engineering manuals and material specifications, material, equipment manufacturer and coating applicator websites Selected national, industry, and international standards, specifications and recommended practices: o DNV-OS-F101 – Submarine Pipeline Systems o EN ISO 21809-5:2010 - Petroleum and natural gas industries -External coatings for buried or submerged pipelines used in pipeline transportation systems -- Part 5: External concrete coatings o NAPCA Bulletin 18-99 - Application Procedures for Concrete Weight Coating Applied by the Compression Method to Steel Pipe Selected technical papers, books and articles: o Lepech, M., Popovici, V., Fischer, G., Li, V. and Du, R., Improving Concrete for Enhanced Pipeline Protection, in Pipeline and Gas Journal, March 2010 o McGill, J.C., Novel Approach to Pipeline Weighting Reduces Buoyancy, Cost and Materials, in Water Engineering & Management, April 2002, Volume 149, Number 4 o Palmer, A.C., King R.A. Subsea Pipeline Engineering, 2004 o Popovici, V., A Concrete Legacy, in World Pipelines, September 2008 o Popovici, V., Getting the Best from a Byproduct, in World Cement, May 2010

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Bibliography

• Various company coating manuals, construction specifications, engineering manuals and material specifications, material, equipment manufacturer and coating applicator websites • Selected national, industry, and international standards, specifications and recommended practices: o CSA Z245.20-02/Z245.21 - External Fusion Bond Epoxy Coating for Steel Pipe - External Polyethylene Coating for Pipe o DVGW GW 15: 2007-01 - Protection from corrosion; coating of pipes, fittings and moulded parts o DVGW GW 340:1999-04 – FZM-Ummantelung zum mechanischem Schutz von Stahlrohren und –formstücken mit Polyolefinumhüllung – Anforderungen und Prüfung, Nachumhüllung und Reparatur, Hinweise zur Verlegung und zum Korrosionschutz o EN ISO 21809-1 (draft) - Petroleum and natural gas industries – External coatings for buried or submerged pipelines used in pipeline transportation systems - Part 1: Polyolefin coatings (3- layer PE and 3- layer PP) o EN ISO 21809-2 - Petroleum and natural gas industries - External coatings for buried or submerged pipelines used in pipeline transportation systems - Part 2: Fusion-bonded epoxy coatings (2007) o EN ISO 21809-3 - Petroleum and natural gas industries -- External coatings for buried or submerged pipelines used in pipeline transportation systems -- Part 3: Field joint coatings (2008) o EN ISO 21809-5 (draft) - Petroleum and natural gas industries -- External coatings for buried or submerged pipelines used in pipeline transportation systems -- Part 5: External concrete coatings • Selected technical papers, books and reports: o Comparison Methodology of Pipe Protection Methods, CIMARRON Engineering Ltd, 2005 o Design and Coating Selection Considerations for Successful Completion of a Horizontal Directionally Drilled (HDD) Crossing, Williamson A.I., Jameson J.R. o Development of a Cost Effective Powder Coated Multi-Component Coating for Underground Pipelines, Singh P., Cox J. o Field joint developments and compatibility considerations, Tailor D., Hodgins W., Gritis N., BHR 15th International Conference on Pipeline Protection o High temperature pipeline coatings - field joint challenges in remote construction, Buchanan R., Hodgins W., BHR 16th International Conference on Pipeline Protection o The importance of hot water immersion testing for evaluating the long term performance of buried pipeline coatings, John R., Alaerts E., BHR 16th International Conference on Pipeline Protection o Long term performance - critical parameters in materials evaluation and process controls of FBE and 3LPO pipeline coatings – Guan S.W., Wong D.T., World Pipelines, 2008 o Mechanical Protection of Fusion-Bonded Epoxy Coatings by Use of Fibre Reinforced Mortar, Schemberger D., BHRA, Nov 1985 o New developments in high performance coatings, Worthingham R., Cettiner M., Singh P., Haberer S., Gritis N., 2005 o Optimization of Pipeline Coating and Backfill Selection, Espiner R, Thompson I, Barnett J, NACE, 2003 o The Performance Capabilities of Advanced Pipeline Coatings, Singh P., Williamson A.I., Hancock J.R., Wilmott M.J. o Pipeline Coatings & Joint Protection: A Brief History, Conventional Thinking & New Technologies, Buchanan R., Rio Pipeline 2003 o Pipeline Girth-Weld Joint Corrosion Protection: Remote Project Field Installation Challenges, Buchanan R., Dunn R., Gritis N., International Conference on Terrain and Geohazard Challenges Facing Onshore Oil and Gas Pipelines

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Acknowledgements

o The Resistance of Advanced Pipeline Coatings to Penetration and Abrasion by Hard Rock, Williamson A.I., Singh P., Hancock J.R., October 2000 o Rock Jacket – A Superior Pipe Protection System for Rocky Terrain, Bragagnolo P., NACE, Nov 1991 o Simulation of Coating Behaviour in Buried Service, Andrenacci A, Wong D.T., NACE, 2007 o Subsea Pipeline Engineering, Palmer, A.C., King R.A., 2004 o Transmission Pipelines and Land Use: A Risk-Informed Approach – Special Report 281, US Transportation Research Board (TRB), 2004 o Trends in Pipeline Field Joint Coatings, Buchanan R., Pipeline Coating Conference 2009, Vienna, Austria o Vancouver Island Pipeline Project – Material Selection, Engineering Design and Construction Plan, Yamauchi H., NACE, Nov 1991

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Acknowledgements

First Edition Acknowledgements More than 100 persons and 45 companies participated in the preparation of this publication. Each person’s name is mentioned in the main area of her/his participation as follows:

•

as a member of one, or more than one, of the six Working Groups

•

in the coordination and support functions

•

as having given editorial support to members of the Working Groups

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as having attended one or more Plenary Sessions of the Novel Construction Initiative

This work is the outcome of six Working Groups: 1. Planning, Design & Control (PDC) Co-Chairmen: Mike King *(BP) & Zuhair Haddad (CCC) Participants: Yasser Hijazi* (CCC), John Truhe (Chevron), Paul Andrews* (Fluor), Cris Shipman (GIE), Paulo Montes (Petrobras), Tales Matos (Petrobras) 2. Contract Negotiating & Risk Sharing (CRS) Co-Chairmen: Barry Kaiser* (Chevron) & Bruno de La Roussière* (Entrepose) Participants: Sarah Boyle (Heerema), Barbara de Roo (Heerema), Paul Andrews* (Fluor), Frank Todd (Land & Marine), Jean Claude Van de Wiele (Spiecapag), Daniel Picard (Total) Consultant to IPLOCA and principal writer: Daniel Gasquet* 3. Pipeline Earthworks (EW) Co-Chairmen: Paul Andrews* (Fluor) & Bruno Pomaré (Spiecapag) Participants: Mike Sweeney (BP), Ray Wood (Fugro), Helen Dornan* (Serimax), Sue Sljivic* (RSK Group plc), Flavio Villa (Tesmec), Francesco Mastroianni (Tesmec), 4. Facing, Lining-Up & Welding (FLUW) Co-Chairmen: Frederic Burgy (Serimax) and Bernard Quereillahc* (Volvo) Participants: Zahi Ghantous (CCC), Jim Jackson (CRC-Evans), Marco Laurini (Laurini), Claudio Bresci (Petrobras), Derek Storey (Rosen) 5. External Corrosion Protection System (ECPS) Chairman: Sean Haberer* (Bredero Shaw) Participants: Dieter Schemberger (Akzo Nobel), Vlad Popovici* (Bredero Shaw), Nigel Goward (Canusa-CPS), Micheal Schad (Denso), Graham Duncan (Fluor), Damian Daykin (PIH) 6. Lowering & Laying (L&L) Chairman: Marco Jannuzzi* (Caterpillar) Participants: Zahi Ghantous (CCC), Kees Van Zandwijk (Heerema), Peter Salome (Heerema), Marco Laurini (Laurini), Claudio Bresci (Petrobras), Marcus Ruehlmann (Vietz), Lars-Inge Larsson (Volvo)

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Acknowledgements

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Overall Coordination and Support to the six Working Groups Coordination was carried out by Luc Henriod* (IPLOCA), Ian Neilson (BP) and Franรงois Pesme (BP), supported by the IPLOCA staff in Geneva who organised the plenary sessions, conference calls etc: Juan Arzuaga*, Caroline Green, Alain Hersent (IPLOCA Consultant), Sarah Junod and Liz Spalding. Roberto Castelli (Bonatti) was in charge of coordinating with the Board of Directors of IPLOCA. *Names of the writing and editing team of the final document are designated in this Acknowledgement by an asterisk (*).

The following persons have given editorial support to members of the Working Groups or have showed their interest and support by attending some of the Plenary Sessions of our IPLOCA Novel Construction Initiative (in alphabetical order by company): Antonio Galetti (Bonatti), Andrea Piovesan (Bonatti), Barry Turner (Borealis), Bill Blosser (BP), Patrick Calvert (BP), Shaimaa Fawzy (BP) , Roger Howard (BP), Hikmet Islamov (BP), John McAlexander (BP), Colin Murdoch (BP), Geoff Vine (BP), Jean-Luc Bouliez (BS Coatings), Ray Paterson (BrederoShaw), Adrian Van Dalen (BS Coatings), Cortez Perotte (Caterpillar), Kurt Wrage (Caterpillar), Issam El-Absi (CCC), Joseph Farah (CCC), Hisham Kawash (CCC), Ramzi Labban (CCC), Fernando Granda (Chevron), Keith Griffiths (Chevron), Karlton Purdie (Chevron), Brad Stump (Chevron), C.S. Sood (CIT), Bo Wasilewski (Conoco-Phillips), Martin Kepplinger (deceased) - (CRC-Evans), Brian Laing (CRC-Evans), Gus Meijer (CRC-Evans), Bernhard Russheim (CRC-Evans), Oliver Zipffel (Denso), Peter Schwengler (E.ON Ruhrgas), Claudia Mense (Elmed), Carlo Spinelli (ENI), Paul Leyland (Entrepose), Jean-Pierre Jansen (Europipe), Daniel Delhaye (Fluor), Sub Parkash (Fluor), Conrado Serodio (GDK), Karl Trauner (HABAU), Marc Peters (Herrenknecht), Frank Muffels (Industrie Polieco MPB), Lorne Duncan (Integrated Project Services), Ed Merrow (IPA Global), Hudson Bell (ITI Energy), Nigel Wright (ITI Energy), Adam Wynne Hughes (Land and Marine), Tom Lassu (Ledcor), Boris Boehm (Maats), Jorge Baltazar (Petrobras), Sergio Borges (Petrobras), Paulo Correia (Petrobras), Ney Passos (Petrobras), Jimmie Powers (PRCI), Max Toch (PRCI), Jie-Wei Chen (Rosen), Mike Mason (RSK Group plc), David Williams (Serimax), Massimiliano Boscolo (Socotherm), Danillo Burin (Socotherm), Lotfi Housni (Somico), Remy Seuillot (Spiecapag), Luis Chad (Tenaris-Confab), Livia Giongo (Tesi), M. Lazzati (Tesmec) Francesco Mastroianni (Tesmec), John Welch (Tesmec), Andrea Zamboni (Tesmec), Paul Wiet (Total), Bart Decroos (Volvo), Jack Spurlock (Volvo).

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Acknowledgements

Second Edition Acknowledgements More than 100 persons and 46 companies participated in the preparation of this Second Edition.

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The work was divided among six working groups: 1. Planning and Design Co-Chairmen: Criss Shipman (GIE) & Mike King (BP) Participants: Mustafa Abusalah, Firas Hijazi, Ramzi Labban (CCC); Sub Parkash (Fluor) 2. Monitoring & Control Co-Chairmen: Zuhair Haddad (CCC) and Mike Gloven (Petro IT Americas) Participants: Jan Van der Ent (Applus RTD); Aref Boualwan, Firas Hijazi, Antoine Jurdak, Hazem Rady, Khaled Al-Shami (CCC); Abhay Chand (Petro IT); Paul Wiet (Total) 3. Pipeline Earthworks Co-Chairmen: Paul Andrews (Fluor) & Bruno Pomaré (Spiecapag) Participants: Ray Wood (Fugro); Marc Peters (Herrenknecht); Marco Laurini (Laurini); Flavio Villa (Tesmec); Lars-Inge Larsson (Volvo) 4. External Corrosion Protection System (ECPS) Co-Chairmen: Sean Haberer (ShawCor), Vlad Popovici (Bredero Shaw FJS) Participants: Volker Boerschel, Dieter Schemberger (Akzo Nobel); Norbert Jansen, Barry Turner (Borealis); Raphael Moscarello (Bredero Shaw); Adrian Van Dalen (BS Coatings); Paul Boczkowski (Canusa-CPS); Cindy Verhoeven (Dhatec); Bill Partington (Ledcor); Fred Williams (Shell); Dan King, Steve Shock, Dave Taylor (TransCanada); Axel Kueter (Tuboscope) 5. Facing, Lining-Up & Welding (FLUW) Co-Chairmen: Frédéric Lepla (Serimax) and Bernard Quereillahc (Volvo CE) Participants: Subhi Khoury, Ramzi Labban (CCC); Matthew Holt (CRC-Evans); Christian Hädrich (Max Streicher); Mladen Kokot (Nacap) 6. Lowering & Laying Chairman: Marco Jannuzzi (Caterpillar) & Bernard Quereillahc (Volvo CE) Participants: Andreas Clauss, Scott J. Hagemann, Cortez Perotte (Caterpillar); Jim Jackson (CRC-Evans); Marco Laurini (Laurini); Hannes Lichtmannegger, Johannes Mayr (Liebherr); Scott Haylock, Lars-Inge Larsson (Volvo CE)

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Acknowledgements

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Overall Coordination and Support to the Working Groups Coordination was carried out by Juan Arzuaga (IPLOCA) and Daniel Gasquet (IPLOCA Consultant), supported by the IPLOCA staff in Geneva: Caroline Green, Guy Henley, Sarah Junod and Elizabeth Spalding. Osman Birgili (Tekfen) was in charge of coordinating with the Board of Directors of IPLOCA. Additionally, we thank the following companies and individuals for their valued participation in the Second Edition of the Road to Success (in alphabetical order by company): Paul Harbers, Dirk Huizinga, Niels Portzgen, Casper Wassink (Applus RTD); Maurizio Truscello (Bonatti S.p.A.); SC Sood (CIT); Rita Salloum Abi Aad (CCC); Russell Dearden (Corus); Ryan Fokens, Dennis Haspineall (CRC-Evans); Ivan Gallio, Nicola Novembre, Luca Prandi, Carlo Spinelli (ENI); Andreas Meissner (EPRG); Shiva Vencat (Euro Airship); Graham Duncan, Jason Fincham, Sub Parkash (Fluor); Henk De Haan (Gasunie); John Balch (GIE); Claudio Dolza (Goriziane); Gerhard Wohlmuth (HABAU); Geert Dieperink, Gerben Wansink (Maats); Mark Roerink (Nacap); Greg Rollheiser (PipeLine Machinery); Reiner Lohmann, Ralf Prior (PPS Pipeline Systems GmbH); Peter Döhmer (Techint); Hasan Gürtay, Dinc Senlier, Alpaslan Sumer (Tekfen).