Vol 2 onshore pipelines the road to success 3rd edition by IPLOCA

Onshore Pipelines

THE ROAD TO SUCCESS

An IPLOCA document – 3rd edition September 2013

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.

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

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

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 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.

Section 9

Welding

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. 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.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

Section 12 Pipelines and the Environment 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.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

Table of Contents (Volume Two) Page

Executive Summary

8. Logistics 8.1

Pipe Handling Operations

8.2

Fuel Logistics

1 27

9. Welding (NEW) 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 (NEW) 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 “Ideal Machine”

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

13.7 Near Real Time Automatic Data Acquisition (NEW)

111

13.8 Innovations in CO2 Pipeline Construction (NEW)

131

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2

Glossary of Acronyms Bibliography Acknowledgements

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8. Logistics Logistics are a key component of any cross-country pipeline project, and as such should be given the same importance as other activities: engineering, procurement, construction, etc… A difficulty arises however in defining “logistics”: do we limit it to the transportation of goods and people, or do we enlarge its perimeter by incorporating other aspects? The choice was made to incorporate into logistics all the activities that are linked to the construction activities, which we would consider as indirect costs. The following chapters will develop the following topics, which have been identified as being relevant to logistic activities:

• • • • • • • •

Line pipe supply chain Customs and administrative matters (visas) Camp, catering & communications Fuel management Goods management on site Transportation of goods and people on site Lifting as a recurrent activity throughout the supply chain Traceability of all items on a project

Below we list some of the key words, concepts and questions which will be developed in each chapter.

Line pipe supply chain: Handling, storage, transport; measurement by tons; traceability / tracking system; what pipe: bare / coated / special coating; where: to different locations: pipe mill, coating yard, stockpile; how: train, trucks, vessels, barge, LTA, helicopter; problems encountered: constraints due to external coating; bevel protection; safety; weather / climate; accessibility; stockpile location / optimization; local rules (road transport)

Customs issues: Visas issues

Camp (temporary construction camp): How to define a camp: specs from client; specs from contractor; first aid facilities; specs from the country (local rules); manufacturing: location, lead time, transportation; easy relocation; utilities: water management; power management; waste management; food management (kitchen, dry store, cold store, etc), final disposal of the camp; optimization of camp location; security; communications

Catering: Population diversity; quality of food / choice; service / availability; health; local content; subcontracted work

Fuel management: Quality / tier IV; fuel local treatment; price: refer to risk allocation; storage / security / safety; transportation & delivery; easy relocation

Goods: Equipment / incorporated materials / consumables; measurement, volume; how: train, trucks, vessels, barge, LTA, helicopter; warehouse & material management; disposal at the end of the project

On-site transportation: Cars / trucks / buses; fleet management; safety: Security

Lifting: Best practices

Traceability: RFID / tagging of valuables

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8.1 - Pipe Handling Operations 8.1.1 Introduction When a pipeline is completed and operational, it is the result of cooperation between a number of parties in the supply chain. These parties perform steps which are sequential and overlapping involved in the design, manufacturing, blasting, coating, handling, storage, transport and construction of the pipeline. The supply chain is illustrated in Figure 1.

Fig. 1 Line pipe supply chain Pipes and coatings can be damaged in each stage of this supply chain. This recommended practice shall address the processes after manufacturing 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

Pipeline construction

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

Handling

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These questions need to be answered to ensure a good end-quality of the pipes 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 ‘normal’ logistic operations, in practice numerous damages are encountered. The types of damage that are most likely to occur are the result of forces associated with impact or abrasion. If the coating is damaged during logistics 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. Damage can also remain undetected or be very difficult to detect like UV degradation. Therefore damage prevention is always the best solution. Owners and developers often choose cheap alternatives, assuming nothing will go wrong as long as minimum requirements or specifications are followed. However specifications and requirements are not always comprehensive. In the long run, asking specialists for advice can save considerably on costs. 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, such as the suitability for the terrain conditions. We shall discuss encountered damages in processes during the supply chain, 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. In the case of overseas transport, there is an especially increased risk of damaged pipe-ends. This is caused by extra handling procedures in ports and shifting of the pipes onboard vessels. Furthermore, it is difficult to control the circumstances in ports overseas. Research and experience show that a good quality pipeend protection can prevent 95% of the damages most likely to occur in practice. How to select good quality pipe-end protection? • For protecting the bevel of the pipe, the most effective method is application of a bevel protector made of steel or another hard material – we refer to steel bevel protectors throughout this chapter. Important features of a good bevel protector: 1. Strong clamping system that can withstand transport vibrations, and also help cope with large diameter pipes. 2. Effective protection of the bevel: Both a deformable buffer zone and material thickness contribute to the effectiveness of the bevel protector (see example in 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 ensure that the complete circumference of the pipe is covered. 5. Diameter tolerances of pipes: If the pipes are produced with a certain tolerance, one should make sure that the bevel protector chosen 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. 7. Fast and easy: fitting and removal. 8. Suitable for hook lifting. 9. Fitting and removal on stacked pipes should be possible.

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

Fig. 2 : Example steel bevel protector: Strong clamping system, buffer profile, no parts sticking out, no open gaps

Fig. 3 Cross-section of a steel bevel protector

Fig. 4 Typical impact damage to the bevel

Tips: Rough transportation or handling procedures may lead to loss or loosening of bevel protectors. One should build in checkpoints after logistic procedures to ensure that all missing bevel protectors are replaced and loose bevel protectors are re-attached before continued handling and transportation.

Pipe Closure One can also choose 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 remain moist for a longer period of time, because the moisture evaporates less easily. Figure 5 shows pipes that have been stored for emergency repairs, which show heavy weathering and contamination both inside and outside of the pipe where the coating disbonds at the pipe-end. Other forms of contamination seen in Figures 6 and 7 are foreign objects that are found inside pipes such as tools, wood, animals, cans etc.

Fig. 5 Contamination of pipes

Fig. 6 Foreign objects in 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 of a steel bevel protector with a plastic plug. These solutions are designed to close off pipes, however it is good to consider the following advantages/disadvantages.

1. Pipe end caps - Made for standard external pipe diameters - Not hookable - Can loosen due to temperature fluctuations, there is no clamping system (this risk increases with larger diameters) - Cannot be applied on stacked pipes 2. Recessed caps - Made for standard external pipe diameters, with a certain wall thickness range - Hookable - Can loosen due to temperature fluctuations, there is no clamping system (Risk increases with 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 clamping system (the steel bevel protector 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 / hot temperatures can cause plastic caps to become brittle and break easily under 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 consider that pipes might come across differing climates during their logistic trail. Nowadays pipelines run through more demanding latitudes and altitudes than ever before.

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

Consequently one should choose a material that is fit for purpose. The example 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 (-50°C).

Fig. 11 Bevel protector combined with plastic plug for extreme climates Tips: • In some cases it is seen that pipes are closed with thin plastic sheets that are attached to the pipe by tape. This is not a solution that is designed to close off pipes, and it is not advisable for harsh circumstances or storage periods longer than 6 months. When choosing this solution, attention must be paid to selecting the appropriate material. Due to its flexible nature, wind can easily move the sheets back and forth repeatedly, causing them to rupture. In addition, tape is often not UV and water resistant, resulting in failure after only a short time. What appears to be a low cost solution may cause a lot of additional costs for repair and cleaning. One must make sure to take the total exposure time of the pipe’s coating into consideration and evaluate the quality of the sheet material and tape carefully. For improved long term fixing, sheets can also be fixed with a steel bevel protector, offering pipe closure and bevel protection at the same time. • When choosing a hookable end cap, one should make sure that the depth corresponds to the length of 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 apply a small ventilation hole in the end cap. Otherwise the end caps might be pushed off due to expansion of air inside the pipe. • The UV stability of end caps varies strongly. One must remember 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 protection of the environment.

8.1.3 Corrosion prevention of the internal pipe surface Desiccant material To prevent corrosion inside the pipe, desiccant material can be added. For this purpose, a tight sealing of the pipe is necessary. A 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, which can be supplied in bags, absorbs moisture from the air. The quantity is calculated according to climate conditions and duration of storage. Not every desiccant material is suitable for applying in steel pipes. Chemical additives such as salts might even speed up corrosion instead of preventing it. 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 regularly monitor 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.

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The main features of desiccant materials are: • Water absorption • CO2 absorption • Non-toxic and dust free

Fig.12 Desiccant bags inside a pipe Volatile corrosion inhibitor) (VCI) method The volatile corrosion inhibitor (VCI) method is an active corrosion protection method, as chemical corrosion processes are actively influenced by inhibitors. In simple terms, the mode of action is as follows: due to its evaporation properties, the VCI substance (applied in a powder or spray formulation) passes relatively continuously into the gas phase and is deposited as a film onto the internal pipe surface. This change of state proceeds largely independently of ordinary temperatures or humidity levels. Its attraction to metal surfaces is stronger than that of water molecules, resulting in the formation of a continuous protective layer between the metal surface and the surrounding atmosphere which means that the water vapour in the atmosphere is kept away from the metal surface, so preventing any corrosion. The attraction means VCI molecules are also capable of passing through pre-existing films of water on metal surfaces, so displacing water from the surface. The presence of the VCI inhibits the electrochemical processes which result in corrosion, suppressing either the anodic or cathodic halfreactions. Under certain circumstances, the period of action may extend to two years. The main advantage of VCI is that it is a very effective corrosion inhibitor that penetrates into the smallest holes and cavities. It maintains its protective qualities for a long period of time. A possible disadvantage is that its effectiveness is difficult to monitor. The powder or spray substrate is more difficult and time-consuming to apply compared to inserting bags or pouches containing VCI. However, when contained in bags in a closed environment without air flow, spreading of the VCI molecules is more difficult and limited up to a few meters.

Fig. 13: VCI method (source: Transport Information Service TIS Germany)

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8.1.4 Protection and efficiency during the coating process If pipe ends are bevelled, 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. Futhermore, 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 specialized tools, blasting plugs, available for this purpose. Tools that are used to protect and close off the pipe-end 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 Shield the pipe’s internal coating from any temperature changes during blasting

By fine tuning the blasting process (manually or automatically), 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. One should prevent pipes from opening up inside the preheating oven or blasting cabin.

Fig. 14 Blasting plug for protecting and closing off the pipe-end during external blasting

Fig. 15 Blasting plug during blasting process

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

During external coating: To improve 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 doesn’t 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 coating application of better quality. A coating process can be unstable due to multiple causes: • Large pipe diameter combined with thin pipe walls

• • • • •

Curved or oval pipes Unequal support rolls Unstable support rolls such as air tires High line speed Long distances between support rolls

Lining up and connecting pipes stabilizes the coating process and minimizes the likely consequences of the abovementioned causes, 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. 16 Male-female pipe coupling

Fig. 17 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 thin pipes)

• •

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 absorb too much heat from the pipe, as this would have a negative effect on the bonding of the coating. Hence contact surfaces between the coupling and the pipe should be limited

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

• • • • • •

Be able to handle oval or curved pipes Be easy to adjust for a large wall thickness range Allow the flow of static electricity between pipes Be able to resist heating by gas or induction oven Be able to bridge thermal expansion of the pipe Remain strongly fixed during the entire coating process

Fig.18 Pipe coupling with automatic clamping

Fig.19 Perfect line up of pipes during coating and centering

If using pipe couplings, these have to be integrated in the 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. 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

8.1.5 Pipe handling Pipes are handled multiple times in the supply chain, for example in ports and storage yards. By handling we mean lifting of pipes and loading to or unloading from trailers, train wagons or vessels. Most damages to pipe ends, surfaces and coatings occur during handling procedures due to a combination of inadequate equipment and poor personnel awareness. This also leads to unsafe situations and accidents. The personnel’s awareness issue is the hardest to overcome as circumstances cannot always be controlled and many different people are involved in handling the pipes during different stages in the pipeline project. Proper trainings, planning beforehand and safe equipment can help to overcome this issue.

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

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 help of a lever arm. Generally these kind of tools are â&#x20AC;&#x2DC;home madeâ&#x20AC;&#x2122; by employees. If not constructed properly these tools can cause damage to pipes 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.20 Pipe roller designed for safe manual handling of pipes Pipe lifting Lifting can be done with hooks, forklift, hydraulic spreader and vacuum equipment. Here we examine these methods and their impact on the pipe coating. It is commonly known that badly-designed pipe hooks could damage bevelled pipe-ends. The hook design and lifting angle determine if forces are spread evenly over the pipe's surface, to avoid deforming the pipe. Bevel protectors can be applied to overcome this issue. A correct lifting angle is also very important to ensure safety - a lifting angle that is either too small or too large can cause the pipe to fall.

Fig.21 Safe lifting angle Less well-known is that hooks can also damage pipe coatings during loading operations, or if dangling hooks knock 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. There are also additional protective sleeves available to shield pipes against hard parts from the pipe hook, such as bolts and shackles.

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Fig.22 Pipe hook with protective sleeve 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 pipe weight Shaped to spread lifting forces on the internal pipe surface and bevel

Fig. 23: Example of a poorly-shaped pipe hook

Fig. 24: Typical damage to the pipe-end caused by unsuitable pipe hooks

Fig. 25: Example of a pipe hook without protective exterior

Fig. 26: Example of a well-designed pipe hook with protective exterior

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 known for forklifts’ forks to be driven directly into the pipe-ends to lift them. This type of handling causes damage to the pipe and internal coating. There are custom made forklifts available with soft covered grippers to hold the pipes during driving – these should be used instead.

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Tip: â&#x20AC;˘ 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 The best way to handle coated pipes is by means of hydraulic spreaders, vacuum lifters or other new lifters. This equipment is designed to minimize 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 also allows the loading and unloading to be done in less time.

Fig. 27: Hydraulic spreader bar

Fig. 28: Vacuum lifter

8.1.6 Pipe transport Pipes need to be transported between parties involved in the supply chain. This is done by truck, train and/or vessel. Pipes need to be fixed during transport. To do this, 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 onto wooden beams. As wood is a product of nature it has widely varying material properties, and is unreliable due to hidden cracks and voids. Besides this, wood is highly subjective to weather influences such as drought and rain that cause fast deterioration. Most specification 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 causea unsafe situations, but also severe coating damage as the nails intrude into the coating layer.

Fig. 29: Nail sticking out of transport system

Fig. 30: Coating damage caused by nail

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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 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 to be broken, wedges are too small, wedges are not made for the correct pipe diameter, wedges are poorly or not nailed to the beam, or nailed at very unfortunate locations.

Fig. 31: Most wooden dunnage is not adjustable for different diameters. It is very difficult to organize a stock and select the appropriate system for a certain diameter Alternatives to wooden dunnage There are more specialized systems available for pipe transport. An example of this system will be presented now. It 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 26-31. With wooden dunnage the pipes are supported on the bottom. Although the pipes are blocked by wedges, almost all the 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 helps maintain the pipe’s roundness, and prevent material stresses, as we shall demonstrate in the next chapter about pipe storage.

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

Fig. 32: Static pressure test (temperature 70°C)

Fig. 33: Measuring coating thickness after test

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

Fig. 34: Pipe transport by train

Fig. 35: Pipe transport by truck with anti-skid rubber layer added

Fig. 36: Pipe transport with System88

Fig. 37: Pipe transport of two 56” pipes on one trailer with a pipe raiser system

The following issues should be checked prior to pipe transport to ensure safety:

•

The first tier of pipes must be long enough to be positioned on all the support blocks; shorter pipes can be placed on the upper tier.

•

Ensure there are no ropes caught between pipe and support blocks or support rubbers. Make sure there are no loose ropes and that zip ties on ropes are checked.

• •

All straps should be in straight vertical alignment over the load, without any twists or knots Check if hook and keepers are correctly secured, and hammer locks must not be caught under bolts or frames

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

8.1.7 Pipe storage Pipes are stored a number of times before they reach their destination. During storage the pipe coating is among other things subject to high pressure, ultra-violet (UV) degradation, design of bottom support, and contamination. 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 approaches the number of pipe layers times the weight of one pipe. These forces are transmitted by the bottom pipes to the ground. 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 it should be avoided that the 3 and 9 oâ&#x20AC;&#x2122;clock positions of the pipes touch each other. Because of the load on top, pipes temporarily become oval. When there is contact between the 3 and 9 oâ&#x20AC;&#x2122;clock positions of the pipe due to this out-ofroundness, 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 â&#x20AC;&#x201C; this helps prevent deformation. If supporting the pipes of a stack it is advised to block every 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 the layers of pipes, the more forces add up, as demonstrated in Figure 38. 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 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 39 are therefore not recommended as they only block the pipes at the end of the stack. Figure 40 shows an example of an overloaded end stop.

Fig. 38 Forces add up towards the end of a pipe stack when using only end stops

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

Fig. 39: Example of a steel end stop

Fig. 40: Overloaded end stop

Tip: • 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 vessel’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 for pipe storage, while steel profiles with only end stops are less used. If left uncovered, sand berms are highly subjective 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 frame for storage is relatively small compared to the time a pipeline lays in the ground, there are well-known 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

•

Use a back-up system to help support the pipe stack, such as pipe clamps

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

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

Fig. 41 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 the pipes’ coating, causing severe damage

If wooden systems 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

Fig. 42 Unstable wooden support

Fig. 43 Weathered wooden support

Pipe support on wedges A pipe storage system as shown in Figure 44 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 for at least 80 mm and settings can be made in such that the distance between the pipes is at least 1% of the pipe diameter.

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

Fig. 44 Pipe support on wedges

Fig. 45 Pipe support in the field

Advantage of wedge support Pipe support 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 46 and 47 show the difference between bottom support and wedge support.

Fig. 46 FEM analysis of bottom support

Fig. 47 FEM analysis of wedge support at two surfaces

The design of these type 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. One should 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 pipeâ&#x20AC;&#x2122;s upper and underside arise, which can lead to coating disbondment or damage and permanent deformation of the pipe. Figure 48 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.

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Fig. 48 Bending of pipe due to support position Calculations prove that the ideal position is at 22% (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, is also determined with FEM analysis. The results of the FEM analysis are shown in figure 49. The smallest displacement can be seen at 22.15%, marked by the green line.

Fig. 49 Displacement of pipes depending on supporting position and width If the supports are placed at 18% of the pipe length, the displacement in the middle is more compared to the displacement at both ends.

Fig. 50 Pipe support at 0.18 x L If the supports are placed at 25% of the pipe length, the displacement at both ends is more compared to the displacement in the middle.

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

Fig. 51 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. 52 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 proved a loss in coating thickness and flexibility, and a loss of gloss with chalking, occurred 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. 53 Poorly-designed pipe clamp

Fig. 54 Twisted pipe clamp

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

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 can be 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 55-57.

Fig. 55 Well-designed pipe clamp

Fig. 56 Well-designed pipe clamp

Fig. 57 Tensile test with pipe clamp When applying pipe clamps, the following should be taken into consideration:

•

In case of internal coating, the pipe clamp should have a soft cover to prevent coating damage

•

For keeping a pipe stack together, one should not rely on pipe clamps only! It is essential to 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

•

One should choose a pipe clamp design based on calculations, rather than the feeling that it will be strong enough

Modern 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 new development is the application of active radio-frequency (aRFID) technology for identification and monitoring of pipes in the supply chain.

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

Small tags, that are positioned in the pipe, actively measure location, movement, humidity, temperature and more. Other data, such as pipe numbers and production data, can also be stored. Data is communicated through micro 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. Integration with existing ERP systems can be achieved with XML streams. Important features of an intelligent pipe monitoring system:

•

Wireless technology, no cables necessary in the field (solar powered routers), which is important in remote areas and to save costs for infrastructure.

• • • • •

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) Historic log

Fig. 58 Schematic representation of a RFID pipe monitoring system at a storage yard

Fig. 59 RFID pipe tags

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8.1.8 Effect of pipe handing on barcoding When using handhelds (barcode scanners) barcoding is very important for inventory purposes and logistical planning, especially when the pipes are stored in more than one laydown area: The following should be looked at when applying barcode labels to the pipes. One should:

• •

Make sure the adhesive will not damage the coating.

•

Make sure the label adhesive to be used will withstand high temperatures, humidity, heavy rain and other environment and weather conditions.

•

Barcoding technology to be used: this depends on the amount of information to be stored in a barcode and the physical damage that it will be able to withstand and still be readable. There are two main technologies to be used:

Make sure the label will withstand different pipe handing stages from the moment of despatching the pipe from the coating facility up to lowering-in without being damaged or removed.

•

One-dimensional barcodes can store a small amount of information; they are not resistant to physical damage along the vertical axis.

•

Two-dimensional barcodes are capable of holding around 2000 characters; they are able to provide readability even if the label is 50% damaged.

Another alternative is to ink-jet the labels on to the surface of the pipe.

8.1.9 Pipeline construction Once one has gone through all the trouble of getting the pipes safely and free of damage to the construction site, it would be a pity to waste all this effort and risk damaging the pipes at the last moment. One should choose adequate equipment during the final stages of the project for handling and support of pipes and prevent last-minute coating damage.

Fig. 60 Poor support of a pipeline in the field

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

8.1.10 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. One should take active responsibility and seek cooperation with professional partners. Responsibility should not be rejected, it should be handed over. The choices that one makes have consequences further along the way. One should not limit oneself to oneâ&#x20AC;&#x2122;s own part in the supply chain. Instead, one 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 lead to more costs in the end. A conscious and well-considered choice for quality is always better than choosing 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.

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

8.2 - Fuel logistics "Gain may be temporary and uncertain; but ever while you live, expense is constant and certain: and it is easier to build two chimneys than to keep one in fuel.” Benjamin Franklin

8.2.1 Introduction Fuel is the blood to be pumped in the construction project, to bring the project to life. The fuel logistics of a pipeline construction project is the discipline of evaluating and managing all the costs and effective risks associated with the sourcing, transport, storage and delivery of fuel during the whole project life-cycle. Construction’s bottom line can be affected by the complex relationships between fuel stocks, the fuel supply chain and the strategies that oil companies use to minimize working capital. The impact on price of a weak fuel supply chain could be very high.

8.2.2 Types of fuels The types of fuel normally used in big onshore pipeline construction projects are: • Diesel fuel

• • •

Gasoline Propane Other less common fuels

Diesel fuel usually represents more than 90% of the total fuel used (even without taking into account the fuel for personnel and material transportation to the yard site or area) Diesel fuel is used to power up all the main construction machines (excavators, bulldozers, loaders, haulers, etc.), most portable power generators and most trucks involved in material transportation. Diesel fuel quality is an important factor in satisfactory engine life and performance. Fuels must provide adequate combustion without producing excess contaminates that can harm the engine. Additionally, fuel selection involves economic and environmental considerations. The availability of certain grades of fuels may be cost-prohibitive or inappropriate for various applications. A variety of fuel oils, also known as middle distillates, are marketed for use in diesel engines. Their properties and performances depend on the refining practices used and on the nature of the crude oils they are produced from. Low grade: low-grade fuels produce a higher heat value which translates into more power for the user motor, but they also produce more contaminates that could negatively impact engine-life. The use of low-grade fuel oil in diesel engines often produces darker exhaust fumes and a more pronounced odour. Moreover, the high sulphur content often found in low-grade fuels causes corrosion, wear and deposits in the engine, resulting in poor starting, or running under adverse operating conditions. The use of low-grade fuels may require the use of high priced, higher detergent lubricating oils and more frequent oil changes to yield appropriate performances and to preserve engine life. High grade: high-grade fuels burn cleaner but they have a lower heat value. Just as an example, aviation jet fuels and kerosene are high-grade fuels and seldom contribute to the

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formation of harmful engine deposits and corrosion. Other attributes of high-grade fuels include the benefits of faster engine starting and less frequent overhauls, and the drawback of reduced lubricity. Experience has proven that distillate fuels meeting basic specifications will result in optimum engine performance and durability. Depending on fuel costs and availability, the proper use of alternative fuels such as crude oil, blended oil or residual oil can also provide cost-competitive engine operation. Crude oil: the term crude oil is used to describe petroleum-based oils/fuels that are not refined yet. They are essentially in the same state as when they were pumped from earth. Certain types of crude oils can be burned in diesel fuelled equipment or generator engines and, in some cases, it is a practical and economical fuel. Crude oils are to be evaluated individually and special equipment may be needed to condition the fuel (see paragraphs and tables below). A great deal of sludge can be removed from crude oil by a proper settling system. Residual oil or blended heavy fuel oil (HFO): residual fuel (which resembles tar and contains abrasive and corrosive substances) is composed of the remaining elements from crude oil after the crude has been refined into diesel fuel, gasoline, or lubricating oil. Residual fuel can be combined or diluted with a lighter fuel to produce a mixture that is called blended or heavy fuel. Heavy fuels tend to create more combustion chamber deposit formations which can cause increased cylinder and ring wear. Blending may improve fuel density; however, adding alcohol (ethanol, methanol) or gasoline causes an explosive atmosphere in the tank and is not recommended. Equipment engines can be modified to run on blended fuels, but extreme preventive measures must be taken, including following a thorough maintenance program and using high-quality fuel treatment equipment. Blended fuels can lower fuel costs, but there are often significant trade-offs. Fuel price must be weighed against the following: - Fuel containment effects - Reduced engine component life - Higher maintenance and personnel costs - Reduced warranty Ultimately, the use of blended fuels should be limited to the cases in which no other fuel is locally available, i.e. in countries with poor refinery capacity or low refinery standards (see Figure 1 â&#x20AC;&#x201C; countries with low refinery standards have high diesel fuel sulphur levels).

Fig. 1: Diesel fuel sulphur level - August 2011

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Distillate fuel: distillate fuels are refined from crude oil and are commonly referred to as diesel fuel, furnace oil, gas oil or kerosene. Marine diesel oil: many different names are used for marine diesel oil, which can often cause misunderstandings. Four types of marine diesel fuels are generally recognized and available at bunkering ports around the world. However, not all types are available in every country.

•

Gas oil: this is a light distillate fuel which does not contain any residual fuel. Gas oil is approximately ASTM No.1 diesel fuel.

•

Marine diesel: this is a distillate that boils at a higher temperature than gas oil. The fuel varies from ASTM No.2 diesel fuel to ASTM No.4 diesel fuel.

•

Blended Fuel Oil: this is a blend of distillates and residual fuel. This fuel is blended to the viscosity that is requested by the operator or the engine manufacturer. Blended fuel is not recommended as a fuel option for engines.

•

Residual fuel: this is a residue from distillation of crude oil in a refinery. It should never be used as diesel fuel

Aircraft jet fuels and kerosene-type fuels: these may be used as diesel engine fuel provided they meet acceptable limits. Adequate viscosity is a major concern, particularly with kerosene-type fuels. Kerosene-type fuels have a lower energy content than diesel fuels and therefore produce less peak power output and/or will require more fuel volume to do an equivalent amount of work. Biodiesel: this is a fuel that can be made from a variety of sources. Soybean oil and rape seed oil are the primary sources, but alternate base stocks may include animal tallow, waste cooking oil, or a variety of other feedstocks. In their original form, these oils are not suitable for use in a compression engine; they must be esterified. Without esterification, these oils will gel in the crankcase and the fuel tank. They should be avoided for use in equipment and generators engines, and they are not cost effective. Ultra low sulphur diesels (ULSD): these represent distillate with ≤ 15 ppm sulphur. They have been developed to reduce particulate engine emissions. A new generation of diesel engines was therefore designed, as the sulphur content of diesel fuel worked also as an internal lubricant for engines, and therefore additives were needed to replace it in ULSD diesel fuels. They have been specifically designed to reduce pollution in highly-industrialized countries. ULSD diesel should not be used in older engines, or in engines designed for standard fuels. Vice versa, standard diesel with sulphur content greater than 500 ppm should not be used in newer engines, to avoid corrosion, the presence of residues and consequent reduction of engine life. Diesel fuels’ general characteristics The following information describes the basic fuel characteristics and their relation to engine performance:

•

Cetane number: this is the index of ignition quality, determined by comparing with fuels used as standards for high and low cetane numbers. The higher the cetane number is, the shorter the ignition delay period (which affects warm-up, combustion, cold start capability and exhaust smoke density).

•

Sulphur: sulphur is an element that occurs naturally in all crude oils, and when burned in the combustion chamber can form oxides of sulphur. These can react with water vapour to create sulphuric acid, which can cause severe engine damage. High sulphur content requires usage of high total base number (TBN) oils or shortening of the oil change period.

•

Gravity: this is an index of weight. Lower ratings indicate heavier fuel containing greater heat content. 29

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

•

Viscosity: this is a time measure to resistance of flow. High viscosity causes poor fuel atomization and therefore decreased combustion efficiency. Low viscosity may not provide adequate lubrication to fuel system components.

•

Flash point: this is the lowest temperature at which fuel will give off sufficient vapour to ignite when a flame is applied.

•

Pour point: this is the temperature 3°C (5°F) above the temperature where the fuel just fails to flow or turns solid.

•

Water and sediment: this is the percentage by volume of water and foreign material removed by centrifuging.

•

Corrosion: a polished copper strip is immersed in fuel for three hours at 50°C (122 °F). Fuel imparting more than slight discoloration should be rejected.

The diesel fuel type to be used could also be prescribed by national rules or laws regulating pollution (see Figure 2). To ensure compliance, not only should a specific type of fuel be used, but also modern engines that are able to burn that particular fuel, to reduce the pollutants released to the atmosphere.

Fig. 2: Emission requirements - 2012 update Impact of the type and quality of fuel on modern diesel engines Modern diesel engines are equipped with sophisticated fuel injection systems, which are electronically regulated and working under very high pressures. Consequently, the diesel fuels used must be of very high quality. Use of lower quality fuels can greatly impact engine life. Fuel quality depends on the geographical location of a given country (see Figure 1) and is related to the level of fuel refining and also quality of storage.

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Poor storage quality can lead to water content and impurities, and while existing mechanical treatments (centrifugation and filtration) can produce clean fuel, low refining levels produce fuels with high sulphur content. There is no transportable system able to reduce sulphur content, consequently some engines will not accept low quality fuels and other engines will work but with reduced intervals for filters changes. It should be noted that fuel filters changes should be concurrent with oil filters changes. General recommendations for frequency of engine oil filters / fuel filters changes Sulphur content <0.3% 0.3% to 0.5% > 0.5%

Change interval 500 hours 250 hours 125 hours

Note: these values are for normal climate conditions down to -10째C; below -10째C these figures should be divided by 2.

8.2.3 Fuel supply chain Fuel transportation Fuel transportation includes fuel logistics to the main camps and through the yard (from the main camps to construction site equipment). Fuel transportation to the main camps could be managed in a variety of different ways, mixing different means of transport according to the way in which storage is organized inside the camps and the nearest fuel terminal (refineries or main fuel deposit). The main means of transport involved are: Truck: tanker trucks could have a capacity ranging from 10,000 to 50,000 litres, and the vehicle carrying the tanker could be provided with different type of assets to cross all type of roads (paved, unpaved, with ice, mud, etc.).

Fig. 3: Tanker trucks of different types and in different environments

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The main feature of a tanker truck is its flexibility, and trucks are the only means of transport that are able to reach remote areas carrying a significant amount of fuel. It is however typically the most expensive means of transport for fuel and liquid. It should be used mainly to supply fuel to the final users on site (usually construction equipment located along the pipeline). Rail: this is probably the cheapest among all the means of transport. It suffers from the main problem that all railroads have: it cannot easily be distributed over a geographic area, only along the railway line. Moreover, it could not move easily to follow the camp development and movement along project areas.

Fig. 4: Tanker cars forming a long train Its limited flexibility is not only due to the need for terminal infrastructure, but also to the costs: the significant logistic management of a fuel train is compensated for only by transporting a large amount of fuel all together to the same location. The capacity of a single tank car could go from 50,000 litres to 75,000 litres (standard size) up to 108,000 liters (jumbo size). A significant advantage is that facilities and tank cars usually already exist, and can be used. Barge: this is not as cheap as rail transport, but it requires less infrastructure and it is not strictly linked to a complicated fuel terminal. Moreover, the logistics of the whole supply chain can be easier. The real disadvantage of this means of transport is that it requires navigable water!

Fig. 5: Fuel barge on a small channel

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Ultimately, fuel transportation is always a combination of 2 or more of the previously stated means. And trucks, are always present as the final step to bring fuel to the final users (construction equipment on site). Fuel storage Fuel storage should be composed of strategic, intermediate and destination fuel storage facilities in order to maximize the robustness of our supply chain and minimize the risk of disruption. Each storage facilty, even smaller ones, are often subject to the stringent local regulations, and they should be designed well to avoid any health, safety or environment risk, not to mention the financial risk due to fuel loss or construction delays related to fuel shortage. Fuel storage could be done though fixed installations (the common concrete or steel fuel repositories, whether above or underground) or through mobile installation. Here below we provide some examples of mobile installations most frequently encountered on site. Containerized tanks: a containerized tank is mainly a cylindrical steel vessel modified (with additional carpentry structures) to be moved as a containerized separate unit. These systems are suitable for the storage and dispensing of diesel fuel, as they are usually provided complete with control systems, safety systems and dispensing systems (pumps). The system offers a more suitable solution for use in demanding condition (remote location, construction yards) when a high protection from weather conditions and/or other requirements (safety, easy handling) are required. They can be moved with flat trucks or similar. The main problem with containerized tank is the small amount of fuel they can contain (usually less than 50,000 litres).

Fig. 6: Containerized fuel storage vessel Bladder tanks: these are also called pillow inflatable tanks (PIT, for the form they keep when inflated), and are inflatable plastic containment systems. They are the simplest and fastest method of creating a large storage area on the ground. There are two main materials used in the manufacture process, PU and rubber. PU is lightweight, easy to manufacture and repair in the field and is better for temporary installations, whereas rubber has an excellent track record for durability. The tissues are fabricated specifically to guarantee that the bladder tank is self-supporting â&#x20AC;&#x201C; that it can stand alone, independent of any support. The installation is fast and simple. It only requires a large surface on which the bladder tank will lay. The surface must be perfectly horizontal, free of rocks and it is strongly recommended that the surface contains a fine layer of sand. The new alternative to sanding under a bladder tank is to lay down a ground cloth. Most ground cloths are made from a geotextile fabric that works in concert

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with the bladder tank to minimize the chance of abrasion causing the tank to fail. The bladder tanks ensures the fuel stored is always clean, is evaporation-free, and no contamination from the exterior can enter and pollute the liquids stored. Moreover, there is a full containment of any smell. Inflatable bags or depots are transportable (once emptied), and therefore can represent the ideal storage for mobile installation. Even if they are really resistant however, extreme caution should be taken when using bladder tanks, and continuous surveillance should be provided to act immediately in case of leakages.

Fig. 7: Two examples of bladder tanks

Fuel cans (jerrycans) or barrels: usually the last fuel storage on site, fuel cans and barrels are easily transportable and can move with the yard. Standard sizes for cans go from 5 to 20 litres, but different sizes (both metal or plastic) can easily be found on the market. Crude oil is typically stored in barrels. These have a standard size of about 160 litres, but barrels of different capacity can also easily be found.

Fig. 8: Fuel cans and barrels

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8.2.4 Fuel management Fuel management on site has two main purposes:

•

To secure the needed fuel, when and where needed, to guarantee continuous work on the field

•

To ensure the needed Health - Safety - Environment standards are met

In the recent past, most fuel management was performed with periodical visual checks and with manual consumption calculations. Recently however, computerized fuel management applications have been introduced on the market. These rely on the development of portable digital instruments (installed locally on bulk fuel mobile reservoirs, or used when needed), and also on modern network communication systems (GPRS, GPS, and web-based applications).. Computerized systems provide operators with a real-time view of inventory data, such as fuel level, temperature, density, standard density, gross volume, water volume and/or net volume. Such systems can automatically calculate density and net volume using industry standards. With these systems, moreover, fuel management can be easily integrated with other asset management tools already present at the yard, significantly improving the efficiency of logistics along the construction project. A recent proposal in that field is the installation of communication devices on board equipment to transfer fuel consumption data directly to the computerized system, therefore giving access to even more precise data on fuel needs, and also giving precious hints on how to save fuel and optimize fuel logistics. Fuel quality control Fuel quality is essential to ensure correct combustion inside engines, and therefore to have the power needed for equipment output, as well as the predicted maintenance frequency (i.e. the lowest outage time of equipment due to engine damage or extraordinary maintenance activities). Fuel quality should be verified with a dedicated chemical analysis performed in each of the following situations:

•

When new fuel arrives at the strategic reservoir (base camp) from outside. This control should be performed also to avoid mixture of different type of fuels (or of fuel with other liquids) in the main storage.

•

Periodically on the bulk fuel reservoirs along the yard

Chemical analysis could be performed in a local laboratory (if present near the construction site) or by a dedicated containerized laboratory located at the base camp. Even if verified, fuel (especially diesel fuel) contains a naturally-high density of residual dirt deposits and water. Therefore, before distributing it to final users (and before delivering it to final reservoirs - cans, barrels or inflatable tanks) it should be treated by filtering it. Usually, normal filters are present, in series, on commercial pumping systems to cover this issue. Ultimately however, this kind of filtration does not solve the problem of sulphur or high densities being present – that should be solved by bringing the correct fuel to the yard, as appropriate for the machines used (see previous chapters).

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Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

9. Welding 9.1

Introduction

This section covers the most important aspects related to vertical circumferential girth welding activities during cross-country pipeline construction. A comprehensive description of each main step of the construction and welding stage is presented including a basic technical background and good working practices. The information within this section is based on the experience of pipeline contractors, welding technology companies, and welding equipment suppliers and is focused on maximizing safety, quality and productivity. • Governance over pipeline welding activities Section 9.2 presents how welding activities are governed during qualifications and production (field installation). The roles of the industrial codes, standards, governmental institutions and third party authorities are also addressed.

9.2

•

Stakeholders In section 9.3 the roles of the different stakeholders involved in pipeline engineering and construction are described.

•

Welding technology Sections 9.4, 9.5 and 9.6 present the pipeline welding technology, the pipeline welding processes and the typical welding imperfections.

•

Field construction equipment Section 9.7 is dedicated to the description of commonly-used pipeline welding equipment.

•

Safety in pipelines Section 9.8 is dedicated to the specific safety matters involved in welding activities.

•

Engineering and construction activities Section 9.9 describes the sequence of activities required from qualifications to mainline welding production start-up. Section 9.10 describes all the field operations related to the pipeline mainline welding.

•

New welding technology Finally section 9.11 describes the latest trends and requirements in welding technologies.

Governance over pipeline welding activities

The cross country pipeline, compared to other oil & gas installations, has the significant difference that over a long distance, it crosses public areas with various types of potential consequences in case of failure, ranging from minor to catastrophic. Maintaining the public’s safety and mitigating environmental impact are very high priorities in the pipeline industry. In the pipeline construction stage, pipe welding activities are some of the most sensitive. The most internal pass, the root pass, is in direct contact with the fluid. Furthermore, the girth weld will have different properties compared to base material of the line pipe, as will the base metal adjacent to the girth weld, that was affected by the heat of welding.

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Welding is a critical element in the construction of a pipeline. The details require strict control in order to maintain the following:

• • • • •

Mechanical properties’ “performance” for both line pipe and the weld metal Qualification of welding procedure specifications (WPS) Conformance to qualified WPS Qualifying of welders and welding operators. NDT acceptance criteria

Therefore, the welding activities are highly regulated by many different bodies, from local and project specifications to international regulations based on national and international standards, supplemented with additional specifications issued for each asset. Because of those strict regulations, welding shall not be treated as a “standard” activity. Welding needs a specific quality management based on destructive and nondestructive tests. These tests should be conducted on actual materials welded per the qualified and controlled welding procedure to be used in the field by trained and qualified personnel. A system that is fully traceable shall enable the retrieval of complete records of each welded joint from line pipe material and filler metal to the final nondestructive tests. These records should be retained until the abandonment and dismantlement of the line.

9.2.1 International and national regulations and codes The highest level of conformance has to be against the applicable project specific, local, national and international regulations. Those are enforced by law. The welding activities for pipeline construction throughout the globe, beside regulations, are predominately governed by one of the following recognized industry codes, but not limited to;

•

American Petroleum Institute: API 1104: “Welding of Pipelines and Related Facilities”/ API 5L: “Specification for Line Pipe”.

•

American Society of Mechanical Engineers: ASME B31.8 Gas Transmission and Distribution Piping Systems ASME B31.4 Liquid Transmission and Distribution Piping Systems

• •

Det Norske Veritas: DNV OS-F101: “Submarine Pipeline Systems” International Standard organization: ISO 13847 “Petroleum and natural gas industries - Pipeline transportation systems -- Welding of pipelines”

9.2.2 Company and local specifications Each company investing in a pipeline asset (the “client”) is keen to maintain the validity of its license to operate and reap the long-term benefits of such investment. For this reason, such companies would have their own technical specifications setting the requirements and the approach to use while designing a pipeline. In the design stage the engineering contractor will, most often, issue an asset specific set of technical specifications based on the client’s generic corporate technical specifications, the applicable regulations and the most suitable national or international standards.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

Those will be known as “project specifications”. One or more of them would focus on the actual and very specific requirements to be met while executing welding operations during the construction stage. The welding crew will refer to those as “welding specifications” which are quite often to be read in conjunction with the selected national or international standards.

9.3

Stakeholders in pipeline projects

All of the below listed parties have an impact on welding activities through their mandatory requirements, declared preferences and other recommendations. Understanding how these parties work together is important in order to streamline and optimize the welding activities from early engineering to final execution and handover of documentation.

9.3.1 The regulator Most times the regulator is a government-initiated body with experts who compose the requirements a pipeline asset has to meet. Once all the requirements have been successfully addressed the client would receive the “fit for service” notification and the pipeline can be legally operated. It is also typically the government body having the authority to validate the pipe line asset before it can be operated or at each periodic mandatory revalidation. This is achieved by reviewing all design, construction, commissioning and operations records.

9.3.2 Pipeline owner/operator The pipeline owner/operator is typically the company that makes the investment in and operates the asset. The asset can be owned by several companies, linked by an operating contract. Depending on the country involved, a license from the regulator or the local equivalent is needed to operate any pipeline.

9.3.3 Pipeline engineering/construction contractor The company investing in a pipeline asset might not necessarily have the engineering and project management resources available internally. Engineering contractor parties are specialized in those activities and will be contracted by the investing company to deliver the overall engineering from the early preliminary design phase until the final commissioning and operating approval. For constructing the pipeline a construction contractor has to be contracted either directly by the investor company or by the main engineering contractor.

9.4

Cross -country pipeline welding activities

9.4.1 Mainline The pipe sections welded on the right of way, across public areas, are considered the “cross-country pipeline”. Main line welding is when the pipe sections are assembled on the right of way in long strings including bends to follow the terrain relief. The mainline welds are normally produced above the ground. Each

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

section would then be welded to each other after lowering down in the trench (tie-in), to finally constitute the full pipeline. The mainline pipe sections are welded in 5G and 6G position; this means that the welding arc(s) travel vertically down around the pipe circumference while the pipe remains stationary.

Fig. 1: Pipe positions All the activities on the mainline are on the so-called critical path. Any delay in any activity on the right of way could have an effect on the ultimate pipeline delivery schedule. The mainline welding crew is, in most cases, the biggest and most expensive crew working in the construction of an onshore pipeline.

9.4.2 Double jointing / triple jointing Double jointing / triple jointing are welding activities connecting two or three pipes together. Its main purpose is to minimize the number of main line field girth welds to be executed on the right of way. The production of double/triple joint sections is also cost effective as the welding, NDT inspection and the coating can be done off-line. Double/triple jointing is only feasible in areas with â&#x20AC;&#x153;easyâ&#x20AC;? transportation in view of access roads, and where it is permitted by local regulations.

9.4.3 Special sections and tie-ins The tie-in welds are the welds that connect two mainline pipe sections. The welding is usually performed in the trench by a crew of two welders and their support crew. The support crew assists by operating the side booms in order to align and maintain the proper position of the two pipe sections, in conjunction with the external clamping device to enable proper welding alignment. Tie-ins welding is performed when the usual mainline construction cannot be performed, in cases like road crossings, rivers crossings, steep slopes and successive directional bends.

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9.4.4 Repair Welding quality is controlled by monitoring the current, pass speed and temperature of the base metal during execution to control that the essential variables of the approved procedures are within the ranges of the approved procedures. Once the welding of a pipeline girth weld is completed, the welding quality is finally controlled by means of visual and non-destructive testing. In those cases where the weld quality is found to be outside specified acceptance criteria, the weld is marked for repair. After removal of the defected area, re-examination is carried out using the same inspection method as used during the initial inspection. When ultrasonic testing is used, the system may include inspection functions specifically configured for testing of repairs to cope with the possible wide variation in groove shape that may limit the detection capability. Nondestructive testing techniques to be used to check weld quality control are defined in section 10.3 “The NDT toolbox”. In case the repaired area is still unacceptable (incomplete removal of initial defect, or defect in the repair weld) the weld will be repaired a second time or completely removed (knows as a “cut out”), pending the requirements of the applicable specification and/or standard. Weld repair areas may affect the overall quality of the weld. The strict adherence to a repair procedure will help to ensure an acceptable repair is made. In most cases the repair procedure has to be qualified. Repair welds often require welders of greater skill and competency.

9.5

Welding methods and processes

9.5.1 Introduction Welding is the primary connecting process in pipeline construction. Several different welding processes can be deployed during the construction phase of the pipeline. Each process has its advantages and limitations when being implemented in girth welding activities. The specific welding process used must be considered based on its overall ease of implementation in the particular welding activity, criticality of the service environment and techno-economic impact. Welding of pipelines and related components comprise of mainline welds (i.e. line pipe-to-line pipe connections), tie-in welds (i.e. line pipe-to-line pipe connections for specific locations), repair welding of girth welds and fabrication welding. Even with the emergence of new technology, arc welding remains the most common welding type used in pipeline construction. Arc-welding activities can be classified into two typical categories such as mechanized/automated welding, and manual welding. Adaptive control welding is also an advanced form of automatic welding, which is welding with a process control system that automatically determines any changes in welding conditions and directs the equipment to take appropriate action. This shall be classified as automatic welding for the purpose of this discussion. This classification is in accordance with the degree of operator involvement in the performance of the welding activity. The following is a breakdown of welding processes involved and considered for each portion of pipeline construction and related components, discussing the advantages and limitations of each process.

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The table below gives a comparison of the pro and cons of the different welding processes. The comparison shows the criteria used for the selection of the welding method. Manual

Semi-automatic Mechanized Automatic

Level of control of welder over the welding arc (voltage and amperage).

High

Medium

Low

Travel speed control

High

Medium

Low

Wire feed control

High

Medium

Low

Welder influence over weld quality

High

Medium

Required level of welder skill

High

Medium

Flexibility

High

Medium

Low

Efficiency grade of the welding

Low

Medium

High

Logistic influence on welding

Low

Medium

High

Equipment maintenance influence on welding

Low

Medium

High

Joint accessibility and design

High

Medium

Low

Effect on the accuracy of assembly

High

Medium

Low

Capacity to weld high-strength steel

Low

Medium

High

Flexibility is defined as how easy it is to change the diameter and wall thickness of the pipe to be welded. As well as the criteria shown in the table, further factors in the selection of the weld method are the type and grade of the base material (steel), specification requirements, company policy and economic aspects.

9.5.2 Choice of welding process A detailed review of the many factors which influence the choice of the welding process is presented below: Pipe strength The increase in the grade of steel used for pipeline has caused some issues, especially when using cellulosic electrodes which are sensitive to cracking on higher strength steels. It is usually recommended to weld high-strength steel with low hydrogen electrodes for all passes. However, past experience has shown that high-strength steel pipe can be successfully welded using a cellulosic root and hot pass with proper preheat and filling the remainder of the joint with low hydrogen electrodes. Matching strength Matching strength is not formally defined, and sometimes it causes the wrong interpretation when using it either to refer to the joint strength, or to the welding consumable specified minimum strength. These two variables are completely different. The former refers to the strength of a welding joint with respect to the pipe base metal, while the other refers to the standardized way to measure the strength of the weld metal of a given welding consumable in certain conditions. Joint strength is very important in pipeline construction. The welding consumable should be selected in order that the welding joint strength matches (or overmatches) the strength of the pipe. In other words in a match or overmatch joint, the joint strength has to be equal to or greater than that of the base metal respectively.

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In order to clarify these concepts, it is necessary to explain that most of the material designations refer to the yield strength (σY), while welding consumable designations refer to ultimate strength (σU) . For example, API 5L Grade X70 has associated a minimum σY equal to 70 Ksi, while AWS E7018 has associated a minimum σU equal to 70 Ksi. Looking at those numbers, it seems that electrode will produce an under-match joint. However, the final strength of a joint will depend on a number of variables, in which can be included the following variables: base material chemistry, dilution, oscillation, travel speed, and others. Consequently, it is impossible to perfectly predict the final strength of a welded joint. Most of the welding consumable standards specify the minimum mechanical requirements based on a particular welding procedure, which is completely different to a typical welding procedure for pipeline. Consequently the results obtained in those tests are just reference values, and they cannot be related directly to the final strength of a joint. Furthermore, the actual yield strength σY of a welded joint is very difficult to define; the size of a typical weld used in pipeline is not large enough to insulate the weld metal for testing. Consequently, the terms under/over/match applied to the joint strength are only meaningful following the results of tensile testing: a joint that breaks on the base metal with a value over the minimum specified ultimate strength σU of the base metal is not under-matched. The need for very high minimum specified strength welding consumables to produce very high over matching joints is dependent upon the joint type and loading condition, and it is generally required for complete penetration joint groove welds in tension applications. Matching can be used for most applications, but in some cases, it may not be the most economical or conservative choice. Under-match welding consumables might be used when the hardness of the root pass is a concern, even if other higher strength consumables are to be used to fill and cap the weld. This “softer” root increases the resistance to certain types of weld cracking. Longitudinal and spiral seam welded pipe Steel line pipe may be manufactured using many different methods. The two most popular methods of manufacturing large diameter steel line pipe are longitudinal seam submerged arc welding and spiral (or helical) seam submerged arc welding. These two types of line pipe can be discerned by locating the pipe weld seam reinforcement and determining if it runs longitudinally or helically relative to the pipe axis. While longitudinal seam submerged arc welded pipe is the most common type of steel line pipe used for cross-country pipelines, spiral seam submerged arc welded pipe has been rapidly gaining popularity. It is often lower cost than longitudinal welded pipe and can be supplied in longer lengths, which lowers overall pipe laying time and costs. Terms referred to tensile testing. σY is define as the stress at which plastic deformation begins to manifest itself, while σU is the maximum stress that a material can withstand while being stretched or pulled before necking. σU is higher than σY . 1

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However, some spiral seam pipes have issues with pipe ends not being round (out of roundness), which may result in excessive offset of the pipe walls during welding. If not properly controlled, this offset results in difficulties welding the root pass and possible inadequate penetration. The internal line-up clamping pressure can be increased to reduce out of roundness, but this increases the risk of stress cracks, especially when using cellulosic electrodes. Facing this scenario characterized by poor fit-up, more robust welding processes and welding techniques are needed. Pulsed gas metal arc welding (GMAW-P) usually accommodates the effects of poor fit-up, producing a thick root pass with low diffusive hydrogen. Consequently, cracking probability is lower and penetration tends to be better than shielded metal arc welding (SMAW). Pipeline diameter and wall thickness Pipe diameter plays a major role in how long it will take to weld a root pass. Larger diameter pipe, such as 1220 mm, takes longer to weld than a small diameter due to the increased circumference. Thus, larger pipe diameter results in slower pipe laying speeds. To offset this, the number of welders (or arcs) may be increased, or a faster welding process may be selected. Increasing pipe wall thickness usually results in higher weld zone hardness, which increases the tendency of weld cracking at the root pass. This is due primarily to the following factors: • Thicker wall pipe tends to have more alloys and a higher carbon equivalent than thinner wall pipe to obtain the same strength. This results in harder weld and weld zone, and consequently, lower weldability.

•

The greater mass of steel cools the weld faster, which increases the weld zone hardness.

•

Thicker pipe is more rigid, resulting in higher residual stress.

It is more difficult for hydrogen to diffuse from the weld zone due to faster cooling and the increased distance it need to travel to the surface. Therefore, it should not be assumed that a root pass method that worked successfully on thin wall pipe would perform as well on thicker wall. Higher preheat temperatures, lower hydrogen welding electrodes, or a different welding procedure may be needed. Also, heavy wall thickness pipes often require toughness evaluation at the root. In this case, the selection of the root pass procedure shall take into account a robust welding technique that can accommodate base metal dilution and keep toughness properties. When wall thickness is heavy, some codes and standard require post heat treatment of the weld. This will have a strong impact on productivity and weld final properties. Toughness, in particular, could be negatively affected. Heat input has to be carefully selected, as does welding technique in terms of welding consumable and parameters. Pipeline terrain and environmental conditions Pipeline laying speed is highly dependent on the terrain and environmental conditions. Fast laying speeds are usually obtained on flat, dry plains. Pipe laying speed is slowed by conditions such as rocky, hilly or wet terrain, bad weather, as well as river and road crossings. If conditions are present for slow laying speeds, there may be limited benefits by selecting a fast root pass method if the root pass welding crew is frequently slowed down waiting for the right-of-way to be cleared.

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Extreme weather conditions like those in deserts or cold regions may affect the performance of welding equipment and welding variables such as preheat and inter-pass temperature. In particular in cold weathers, low temperatures and fast welding process (low heat input) may present a tendency to create welding defects such as lack of fusion; preheat temperature and particularly inter pass temperature should be carefully monitored. Other conditions such as altitude may affect some welding processes, not only reducing productivity but also increasing the tendency to produce welding defects. Additionally, this fact is increased by the drop in efficiency due to the negative effect of altitude on welder’s health and welding generators. In all those cases, robust welding techniques that overcome the extreme conditions should be selected sacrificing productivity but assuring weld quality. Length of pipe Generally, mechanized/automatic welding is more cost effective on longer, larger diameter pipelines, usually above 50 km in length and more than 24 to 48 in. in diameter. On small projects, the high initial capital costs incurred may not be recovered. Rental of the equipment might be more appropriate; however project delays may then induce significant additional costs. Inspection Increasing the root pass welding speeds necessitates faster weld inspection speeds. The results of the traditional method of radiography inspection follow production welding by approximately half to one day. This is due primarily to the health and safety precautions that must be taken when working with a radioactive material or a radiation source. This inspection delay may be satisfactory at traditional root pass laying rates of 40 joints per day. However, automatic welding systems can lay pipe in excess of 200 joints per day. This requires a faster inspection method to keep up and follow closer to the production welders. Automatic ultrasonic testing (AUT) is the preferred method for inspecting automatic pipeline girth welds. Radiation hazards are eliminated. AUT inspection crews can work in close vicinity to others, including the welding and pipe coating crews. It is also fast, with the inspection data automatically processed by computer. Radiography can have a difficult time detecting non-volumetric planar flaws, like lack-of-fusion, which is more common with mechanized/automatic GMAW processes. AUT does an excellent job in detecting these flaws. Also, recent advances in AUT — such as time of flight diffraction (TOFD) and phased array — allow detection of smaller defects and better defect sizing and location. With faster inspection speeds and results, the time to bury the pipe into the ground is reduced, lowering spreads costs. Logistics Generally it can be stated that the more sophisticated welding systems become, the more support is needed to ensure they function correctly (spare parts, pipe-facing equipment, etc). Many of the pipelines being constructed are in the emerging economies of the world. These projects are often in remote, inhospitable climates and must draw on local labour pools for welders. With the shortage of experienced manual pipeline welders, automatic welding has been on the rise. Sufficient training time should be scheduled, considering the skill level of the local labour pool.

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Costs Capital outlay and resulting rental or write off costs differ widely depending on the selected process. Good production rates and welding speed are needed to control those costs. Manual welding offers relatively low initial cost and equipment maintenance, but requires high welding skill, is labour intensive and repair rates can be high. The initial cost for semi-automatic welding is higher than that for manual welding, but lower than automatic welding. Wire feeding equipment and shielding gas bottles are required with semi-automatic welding. Automatic welding has the highest capital outlay and requires expensive logistical support. Therefore, automatic welding is typically best suited for large diameter and long length pipelines. More expensive equipment tends to be faster, but is not as economical for shorter pipeline distances.

9.5.3 Manual welding The use of manual welding offers a high level of flexibility with straightforward equipment and a broad choice of welding consumables. The welder performs the welding function and maintains continuous control of the welding operations by hand. The manual welding processes used for pipeline welding are: â&#x20AC;˘ Shielded Metal Arc Welding ASME process SMAW and ISO process number 111.

â&#x20AC;˘

Gas Tungsten Arc Welding ASME process GTAW and ISO process number 141

9.5.3.1 SMAW (stick rod) Shielded metal arc welding (SMAW), also known as manual metal arc welding (MMA or MMAW) or informally as stick welding, is a manual arc welding process that uses an arc between a consumable electrode coated in flux and a weld pool to accomplish a weld. An electric current, in the form of either alternating current or direct current from a welding power supply, is used to form an electric arc between the electrode and the metals to be joined. As the weld is made, the flux coating of the electrode gives off vapours that serve as a shielding gas and deposits a layer of slag, both of which protect the weld area from atmospheric contamination.

Fig. 2: Process principle SMAW welding As welding progresses, the coated electrode becomes shorter and shorter. Finally, the welding must be stopped to remove the stub and replace it with a new electrode. This periodic changing of electrodes is the major disadvantage of the process in production welding. The most typical welding defects associated with SMAW are porosity and slag inclusions. The latter is usually related to an excessive high stick-out or humidity, while porosity is related to an incorrect welding technique.

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The SMAW process is the simplest process, in terms of equipment requirements, but it is perhaps the most difficult in terms of welder training and skill-level requirements. Although welder skill level is a concern, most welders entering the field start as "stick welders" and develop the necessary skills through training and experience. The equipment investment is relatively small, and welding electrodes (except for very reactive metals, such as titanium, magnesium, and others) are available for virtually all manufacturing, construction, or maintenance applications. Shielded metal arc welding has the greatest flexibility of all the welding processes, because it can be used in all positions (flat, vertical, horizontal, and overhead), with virtually all base-metal thicknesses (1.6 mm and greater), and in areas of limited accessibility. The versatility of the process and the simplicity of its equipment and operation makes shielded metal arc welding one of the world's most common welding processes. Further, the many possible variations in the composition of the electrode coating and the large selection of the core wire chemistry in addition to providing a smooth arc and uniform metal transfer characteristics add to the preference for this process. It dominates other welding processes in the maintenance and repair industry, and though flux-cored arc welding is growing in popularity, SMAW continues to be used extensively in the construction of steel structures and in industrial fabrications.

9.5.3.2 GTAW (TIG) Gas tungsten arc welding (GTAW), also known as tungsten inert gas (TIG) welding, is an arc welding process that uses an arc between a non-consumable tungsten electrode and the work piece to establish a weld pool. The weld area is protected from atmospheric contamination by an inert shielding gas (argon or helium), and a filler metal is normally used, though some welds, known as autogenous welds, do not require it. Recently, gas mixtures have been used containing CO2 and hydrogen as shielding gases. A constant-current welding power supply provides energy which is conducted across the arc through a column of highly ionized gas known as plasma.

Fig. 3: Process principle GTAW welding GTAW is most commonly used to weld thin sections of stainless steel and non-ferrous metals such as aluminum, magnesium, and copper alloys. It is also used to put in root and hot passes when welding pipelines in critical services. Hence, its reputation as a high integrity process. The process grants the operator greater control over the welding arc than competing processes such as shielded metal arc welding and gas metal arc welding, allowing for higher quality welds. The flexibility of the process is another obvious advantage as GTAW allows the heat source and filler metal additions to be controlled independently. Thus excellent control of root pass weld penetration can be maintained. However, GTAW is comparatively more complex and difficult to master, and furthermore it is significantly slower than most other welding techniques as deposition rates are lower. If welding takes place in windy or draughty environments, it can be difficult to shield the weld zone properly. A related process, plasma arc welding, uses a slightly different welding torch to create a more focussed welding arc and as a result is often automated.

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9.5.4 Semi-automatic welding In semi-automatic welding, defined as “manual welding with equipment that automatically controls one or more of the welding conditions” the welder manipulates the welding gun to create the weld while the electrode is automatically fed to the arc. The semi-automatic arc welding processes can be characterized as follows: • The welding gun is manually controlled and quality is directly related to physical dexterity

• •

Wire feed is controlled by the system Voltage is controlled by the system

The most common semi-automatic welding processes for pipeline construction are gas metal arc welding (GMAW) and flux-cored arc welding (FCAW) which can also be implemented as automatic welding operations. Submerged arc welding (SAW) and plasma arc welding (PAW) are other semiautomatic welding processes finding increasing relevance in pipeline construction.

9.5.4.1 GMAW Gas metal arc welding (GMAW) is sometimes referred to by its subtypes metal inert gas (MIG) welding or metal active gas (MAG) welding. GMAW uses an arc between a continuous filler metal electrode and the weld pool. The electrode comes in a wire spool, which feeds the arc automatically by a mechanism of rollers that push the wire into a liner to the end of the welding gun. The process incorporates shielding from an externally supplied gas. GMAW was referred to as MIG since it was initially implemented as a high current density, small-diameter, bare-metal electrode process using an inert gas for arc shielding. Along with the wire electrode, a shielding gas flows through the welding gun, which shields the process from contaminants in the air. For pipeline welding GMAW can be further subdivided into three metal transfer modes: short circuit, globular and spray transfer modes, depending on the energy level of the arc. At lower energy level, the metal melting rate is slow and this short circuit mode of transfer is used for root pass. Globular and spray modes using higher energy levels are used to deposit fill and cap passes

Fig. 4: Process principle GMAW welding

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GMAW is an efficient consumable-electrode process and overcomes the restriction of limited electrode length encountered with SMAW. However, the welding equipment required for GMAW is more costly and less portable than that of SMAW. The welding arc must be protected against winds or air draughts in excess of 5 mph, which may disperse the shielding gas. This limits outdoor applications unless protective shields are placed around the welding area. Surface tension transfer (STT) welding as a variant of GMAW, is a modified MIG process that uses high frequency inverter technology with advanced waveform control to produce high quality welds while also significantly reducing spatter and smoke. STT technology has the ability to control weld pool heat independently of wire feed speed giving the welder more control over the pool and provides the ability to adjust the heat input to achieve the desired root bead profile.

9.5.4.2 FCAW Flux-cored arc welding (FCAW) is a semi-automatic arc welding process. FCAW requires a continuouslyfed consumable tubular electrode containing an internal flux. FCAW can be used with or without external shielding depending on the consumable design. FCAW offers two major variations: self-shielded (FCAWS); and gas-shielded (FCAW-G), which adds great flexibility to the process. In the gas-shielded method, the shielding gas (CO2 or a mixture of argon and CO2) protects the molten metal from the oxygen and nitrogen present in air by forming an envelope of gas around the arc and over the weld pool. Selfshielded flux core wires (FCAW-S) do not require shielding gas, which makes them more practical in field construction. They are also less sensitive to the deleterious effects of wind on weld quality as compared to FCAW-G. Advantages include higher productivity, high quality weld metal deposit and excellent weld appearance. Limitations include higher equipment costs and the need to remove slag in between passes.

Fig. 5: Process principle FCAW welding

9.5.4.3 Submerged arc welding (SAW) Submerged arc welding (SAW) is an arc welding process in which the arc is concealed by a blanket of granular and fusible flux. Heat for SAW is generated by an arc between a bare, solid-metal (or cored) consumable-wire or strip electrode and the base metal. The arc is maintained in a cavity of molten flux or slag, which refines the weld metal and protects it from atmospheric contamination. Alloy ingredients in the flux may be present to enhance the mechanical properties and crack resistance of the weld deposit.

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Fig. 6: Submerged arc welding Advantages of submerged arc welding include the following: • The arc is under a blanket of flux, which virtually eliminates arc flash, spatter, and fumes (thus making the process attractive from an environmental standpoint)

•

High current densities increase penetration and decrease the need for edge preparation

• • •

High deposition rates and welding speeds are possible

• •

Low-hydrogen weld deposits can be produced

•

The slag can be collected, reground, and sized for mixing back into new flux as prescribed by manufacturers and qualified procedures

Cost per unit length of joint is relatively low The flux acts as a scavenger and deoxidizer to remove contaminants such as oxygen, nitrogen, and sulphur from the molten weld pool. This helps to produce sound welds with excellent mechanical properties The shielding provided by the flux is substantial and is not sensitive to wind as in shielded metal arc welding and gas metal arc welding

9.5.5 Mechanized welding Mechanized welding, also sometimes referred to automatic welding, is a method of welding in which the principle operations, excluding the handling of the work piece, are performed by a machine (i.e. movement of torch, wire-feed). The welder’s intervention consists of adjusting the equipment controls in response to visual observation of operations. Mechanized welding uses the same welding processes as described under section 9.5.3. Parameters may be adjusted by the welding operator in response to visual observation of the process. Mechanized welding can be categorized as being in between manual and fully-automatic welding methods. This applies mainly for standard bevel design (refer to section 9.5.7).

9.5.6 Automatic welding Automatic welding is using the same welding processes as described under section 9.5.3, can be characterized as being an improved mechanized welding methodology in terms of: • Narrow weld bevel design compared with standard API bevel

• • •

Computer controlled process of welding parameters Monitoring of essential welding parameters Minimum intervention by the operator

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

• • • •

Repeatability and integrity of the welding parameters Improved weld production rate Reduced required welder skills Advanced options include: o Laser scanning of bevel o Seam tracking of weld joint while welding

It is more difficult to achieve the highest standards of quality using manual welding. This is due to certain welding positions, overhead and down-hand welds for example, that can lead to faulty welds due to restricted access the user has in these welding positions. In order to have complete control over the weld pool, a perfect balance must be maintained between gravitational force and surface tension at every position of the torch. By using mechanized variants of the technique, certain parts of the welding process are handled by mechanical components. Note that a welder will always be monitoring and controlling the process. In an ideal situation, all welding parameters would be fully programmed before welding is started. In practice, however, the presence of variable constraints means that it is often necessary for the welder to make corrective interventions. With automated welding, the computercontrolled welding process runs completely independently, without the need for any intervention from the operator. However, the operator plays an active role in quality control through the identification of the presence of weld discontinuities. When discontinuities are encountered, appropriate measures must be taken on the part of maintenance or programming personnel to correct deviations. The level of automation varies, but the influence of the welder on the weld parameters is, in most cases, limited to pressing start and stop. The most important variable in automated weld processes is the operator. The operator has to be well trained with a lot of discipline. Because of the high welding speeds lack of attention could mean an imperfection in the weld that causes the rejection of that specific weld. The drawings below (section 9.5.7) show some common used bevel designs. High frequency resistance welding, though not an arc welding process, is an automated process and is not adaptable to manual welding. The principal application of high-frequency welding continues to be in the manufacture of seam-welded pipe and tube. High frequency welding processes rely on the properties of high-frequency electricity and thermal conduction, which determine the distribution of heat in the work pieces.

9.5.7 Sequence of welding passes A circumferential girth weld for pipeline construction is composed of a number of welding passes. The sequence of the welding passes is visualized in the below figure. The welding configuration used is typical for the manual welding process, but the used terminology for the different welding passes also applies for mechanized and automated welding techniques.

Fig 7: Welding passes terminology

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9.5.7.1 Root pass The root pass is the first pass a welder makes on a pipeline girth weld and is judged to be the most critical weld pass for several reasons. It is generally the most difficult welding pass to make. The root pass speed determines the speed with which the pipeline may be constructed. Any delay in the root pass slows down the project. Repair of root defects may require removal of all weld passes, the most costly and time consuming type of repair. Comparing root pass processes: â&#x20AC;˘ Pulsed GMAW transfer mode (GMAW-P), manual shielded metal arc welding (SMAW), and gas tungsten arc welding (GTAW) are the most extensively welding process used for root pass ). Similar welding speed is obtained when comparing SMAW cellulosic with GMAW-P, however, deposition rate is higher when using GMAW, which produces a thicker root pass.

â&#x20AC;˘

GTAW typically presents weld metal with excellent properties; however, the productivity is strongly affected by the low travel speed associated with it. This welding process is used when fit-up is extremely poor and root cracking is likely, or when near-perfect weld quality is required.

9.5.7.2 Hot pass This is always the second pass and comes after the root pass. Hot pass is a terminology that has been introduced when using SMAW cellulosic electrodes in the root pass. The hot pass is a fast pass that increases the metal backing thickness to avoid burn-through when depositing the fill passes. For all other welding processes the hot pass terminology is commonly used for the second pass (first fill).

9.5.7.3 Fill & cap The fill passes complete the joint until almost covering the whole wall thickness. These passes usually are deposited with high energy in order to maximize the deposition rate. There is always a difference of 0.5-1 mm between the last pass of the fill and the top of the bevel. This difference is used as a reference to guide the welder during the capping in order to deposit these passes with the correct overlap. A detailed review of this sequence of welding passes is presented in section 9.10.

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9.6

Typical weld imperfections and pipe mill defects

Despite all the good workmanship that is put into every weld produced during pipeline construction, weld imperfections are inevitable. The welding process may be affected by the condition of the base pipe material and/or pipe end geometry. In sections 9.6.1 through 9.6.18 examples of imperfections can be found and section 9.6.19 reviews the pipe mill defects which may induce weld imperfections. The relevant sections will address three general classifications of discontinuities: • Procedure/process

• •

Metallurgical Base metal

The cause of a weld repair can come from many sources including: • Base material

• • • • •

Welding consumable Shielding gas (when applicable) Welding machine Human error Pipe misalignment

Typical pipeline girth weld defects can be seen on the following pages:

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9.6.1 Misalignment The term misalignment is often used to denote the amount of offset or mismatch across a butt joint between members of equal thickness. Many codes and specifications limit the amount of allowable offset because misalignment can result in stress risers at the toe and the root. The misalignment (Hi/Low) of the pipe ends that have to be welded together. This misalignment is in most cases caused by pipe ends being out of roundness and often located close to the longitudinal or helical weld seams. The misalignment can be recognized on a film when an abrupt change in film density across the width of the weld image is found.

Fig. 8: Hi-Lo pipe misalignment

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9.6.2 Misalignment and lack of penetration (LOP) Misalignment of pipe ends could be the cause of root lack of penetration (LOP). This is illustrated by an abrupt density change across the width of the weld image with a straight longitudinal darker density line at the center of the width of the weld image, along the edge of the density change.

Fig. 9: Hi Lo with lack of root penetration

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9.6.3 Distortion The welding operation commonly involves the application of heat to produce fusion of the base metal. Stresses of high magnitude will result from thermal expansion and contraction and weld metal solidification, and will remain in the weld after the structure has cooled. Such stresses tend to cause distortion when the welding sequence is not properly controlled. Careful selection of the welding sequence, welding processes and joint design can minimize this condition.

9.6.4 Overlap Overlap is the condition in which weld metal protrudes beyond the weld interface at the toe of a weld. The condition tends to produce notches which can be detrimental to weld performance. Overlap is usually caused by the use of either incorrect welding or by improper welding parameter settings. Overlap can occur at the toe of either a fillet or groove weld, as well as at the weld root of a groove weld.

9.6.5 Weld profile The profile of a finished weld may affect the service performance of the joint. The surface profile of an internal pass or layer of a multipass weld may contribute to the formation of incomplete fusion or slag inclusions when the next layer is deposited.

9.6.6 External concavity An external concavity exists when the base material is thicker than the weld including the cap reinforcement. On the position of the external concavity the film is darker than the density of the base material extending across the full width of the weld.

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Fig. 10: External concavity

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9.6.7 Excessive penetration Excessive penetration exists when the root weld material extends past the inside diameter surface and is thicker than the base material. On the position of the excessive penetration the film is lighter than the density of the weld.

Fig. 11: Excessive penetration

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9.6.8 Burn through (BT) When too much energy is used, especially when the second weld pass is being used, the root pass is remoulded and a burn through (BT) will occur. This will result in a localized darker density with fuzzy edges in the center of the weld imageâ&#x20AC;&#x2122;s width. It may be wider than the root pass image width.

Fig. 12: Burn through

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9.6.9 Lack of penetration When insufficient energy is applied to melt both edges of the pipe ends together, will result in a lack of penetration defect (LOP). A darker density band, with very straight parallel edges, in the center of the weld image will occur.

Fig. 13: Lack of penetration

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9.6.10 Interpass slag inclusions The SMAW and FCAW processes produce a slag to protect the molten weld material when it solidifies. When previous welds are not properly cleaned the slag becomes trapped between subsequent passes resulting in a slag inclusion. On a film this will result in an irregularly-shaped darker density spot, usually slightly elongated and randomly spaced.

Fig. 14: Interpass slag inclusions

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9.6.11 Elongated slag lines (wagon tracks) Wagon tracks are a typical defect that can be found in SMAW cellulosic welded pipe sections. The film will show elongated parallel or single darker density lines, irregular in width and slightly winding lengthwise.

Fig. 15: Elongated slag lines (wagon tracks)

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9.6.12 Lack of side wall fusion Lack of fusion occurs when the weld metal doesnâ&#x20AC;&#x2122;t fuse with the pipe material. This imperfection is referred to as lack of side wall fusion (LOF). This defect can be recognized as elongated parallel, or single, darker density lines which are very straight in the longitudinal direction.

Fig. 16: Lack of side wall fusion (LOF)

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9.6.13 Interpass cold lap When the previous layer is not re-melted by the covering subsequent weld pass, a lack of fusion between the weld passes will occur. This type of lack of fusion is called interpass cold lap or interrun lack of fusion.

Fig. 17: Interpass cold lap

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9.6.14 Scattered porosity Rounded spots of darker densities, random in size and location, are referred to as porosity (P). Basically this is gas that has been trapped in the solidifying weld material. Under penetration is also classed as a defect where the opening is too small and welding current too low.

Fig. 18: Scattered porosity

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9.6.15 Cluster porosity A group of gas pores is referred to as cluster porosity (CP). The rounded or slightly elongated darker density spots in randomly-spaced clusters can easily be identified on the film.

Fig. 19: Cluster porosity

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9.6.16 Cracks For materials that are sensitive to cracking (C) special precautions are required to prevent the welded joint from cracking. A crack can be recognized as feathery, twisting lines of darker density running across the width of the weld image. The direction of the crack basically gives the name to the imperfection in the welded joint. Cracking of welded joints results from localized stresses that exceed the ultimate strength of the material. When cracks occur during or as a result of welding, little deformation is usually apparent. Three different types of cracks that can occur in weld metal include transverse, longitudinal and crater cracks.

Fig. 20: Transverse crack

Fig. 21: Longitudinal root crack

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9.6.17 Tungsten inclusions In GTAW, the weld arc is interrupted when the tungsten electrode touches the weld pool, causing the pool to solidify. When this location is grinded insufficiently tungsten will remain in the weld causing an irregularly shaped lower density spots randomly located in the film of the weld image.

Fig. 22: Tungsten inclusions

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9.6.18 Surface irregularities Perfectly acceptable welds will naturally exhibit some degree of surface roughness. However, improper technique or equipment adjustment can result in surface irregularities that exceed specification requirements. Arc strikes An arc strike is damage on the base material resulting from an accidental striking of an arc outside the weld area. Weld ripples While depressions and variations in the weld surface are considered to be discontinuities, they may not affect the ability of the weld to perform its intended purpose. The applicable standard should describe the degree of surface irregularity permissible to prevent the presence of high stress concentrations. Spatter Spatter consists of metal particles expelled during fusion welding that do not form part of the weld. Spatter particles that become attached to the base metal adjacent to the weld are the most detrimental. Normally, spatter is not considered to be a serious flaw unless its presence interferes with subsequent operations, especially nondestructive evaluations.

9.6.19 Pipe mill defects Line pipes can be manufacturer using different methods, but in any case the pipe ends are not perfectly round. The manufacturer is allowed to produce line pipes with some tolerance dimensions. Some of them may strongly affect field girth welding. In the following the main pipe mill defects and their effects on welding are listed.

9.6.19.1 Out of roundness The main characteristic of out of roundness is an oval shape, and its main effect on welding is misalignment (Hi-Lo) . Therefore, the welding defects associated with it are incomplete root penetration, burn through, and root undercut. For thin wall pipes, out of roundness is usually compensated for by the internal clamp. Especially when the clamp is pneumatic or hydraulic, the even expansion force of the clamp deforms the pipe ends and make them round. Out of roundness effects are more deleterious in heavy wall line pipes, in which case the clamp may have not enough force to compensate. In those cases, proper root pass technique selection can help to reduce the harmful effects. Typically, GMAW-P can overcome misalignment better than high cellulosic SMAW. Also turning around the pipes to auto compensate the out of roundness may also help

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Fig. 23: Out of roundness

9.6.19.2 Different thicknesses Welding defects similar to out of roundness can occur when welding two pipes with the same nominal pipe thickness, but with excessive difference in the actual thickness. When inspecting with automatic ultrasound technique, it also can cause a false alarm, resulting in an unnecessary repair.

9.6.19.3 Flat spots Flat spots are typically located near the seam weld. They depend on the manufacturing method, but they are more likely to be present in heavy wall thickness line pipes. Even though this defect has effects similar to out of roundness, rotating the pipe to compensate for this geometric defect cannot help to reduce the deleterious effects associated with it.

Fig. 24: Flat spot

9.6.19.4 Laminations Laminations are non-metallic inclusions embedded in the pipe, and if they are present near the pipe end they can cause welding defects such as lack of fusion or slag inclusion.

9.6.19.5 Axial misalignment Axial misalignment occurs when the linepipe axis is not straight but curved. This pipemill defect has negative consequences when the pipe rotates and the weld torch (or electrode) is fixed. This welding position is typically used in double joint welding plants and it is associated with automatic or welding process such as SAW or GMAW.

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When the pipe rotates during welding, the arc length may vary as the pipe rotates, causing welding defects such as lack of fusion or lack of penetration.

Fig. 25: Straight and axially misaligned linepipe

9.7

Field construction equipment

9.7.1 Beveling equipment 9.7.1.1 Flame cutting beveling equipment Flame cutting equipment is commonly used for preparing a standard V-bevel preparation. Flame cutting equipment can vary in complexity from simple hand-guided machines to very sophisticated numericallycontrolled systems. The mechanized equipment is analogous to the manual equipment in principle, but differs in design to achieve higher cutting speeds and better cutting quality.

Fig. 26: Semi manually-operated flame cutting system

Fig. 27: Mechanically-operated flame cutting system

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9.7.1.2 Mechanical beveling equipment Mechanical beveling is applied for narrow gap welding. A pipe facing machine (PFM) is used for machining of the pipe ends, and is used in combination with a hydraulic power unit (HPU). The machining section of the PFM consists of a rotating faceplate with several tool holders. Tool holders are spring-loaded, and are following the shape of the pipe end with a rolling gear. A typical mechanical beveling machine is shown below.

Fig. 28: Typical setup for PFM and HPU

Fig. 29: Facing operation with excavator handling and powering the PFM

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9.7.2 Pre-heating equipment 9.7.2.1 Flame torch heating Radiation heating methods, such as those that employ gas torches or quartz lamps, transfer heat to the pipe material by emitting electromagnetic radiation. For radiation heating to be effective, the heat source needs to be placed in close proximity to the material being heated.

Fig. 30: Flame torch heating of pipe ends

9.7.2.2 Induction heating Induction heaters work by generating eddy currents in the pipe material, which is a very efficient method of generating heat. The eddy currents are a result of an electromagnetic field that is generated by the induction heater coils. The natural resistivity of the pipe material, along with the eddy currents, causes the pipeline to increase in temperature from the inside by resistive heating. Induction heaters have the same benefits as conduction heaters, which are easy access to the weld joint and consistent and continuous heating. An additional benefit of induction heating over conduction heating is that the heating elements themselves do not heat up. The primary benefits of induction heating over conduction heating are improved operator comfort and possibly, because of increased heating efficiency, the ability to achieve and maintain preheat temperature under extreme thermal conditions

Fig. 31: Induction heating of pipe ends

9.7.3 Line-up equipment The line-up clamp can be either internal or external. The internal line-up clamp is used for mainline welding where external line-up clamps are used for special points like tie-in.

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9.7.3.1 Internal clamps Pipe alignment may be maintained by any of the following machines:

9.7.3.1.1 Internal line-up clamp (ILUC) Internal line-up clamp (ILUC) provides line-up of two pipes prior to and during welding. Typically the clamp is pneumatic and has an air tank to store energy to travel to the next joint, to break as it reaches the next joint and to actually clamp the rear expander to be set in position to guide the arrival of the next joint. In steep slopes it is common to have to pull or retain the ILUC with a steel cable attached to a tractor. ILUCs are equipped with a reach-rod allowing ILUC commands to be reached from the other end of the joint by operating it and/or by using it as a conduit to transmit energy and command signals.

Fig. 32: Internal line-up clamp Typically the internal expander of an ILUC is based on a mechanism that can be best compared to the way an umbrella is opened and closed, as is shown below in Figure 33.

Fig. 33: Internal line-up clamp mechanism

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9.7.3.1.2 Stronger internal line-up clamp (Max-ILUC) In order to meet the requirements regarding hi-lo, special ILUCs have been developed to provide enough force to round the pipe ends, so as to be able to match the pipe ends that have to be welded.

Fig. 34: Max-internal line-up clamp

9.7.3.1.3 Internal welding machine (IWM) The Internal Welding Machine is used to line up the pipe pieces. After the line up the first welding pass (root) is welded from the inside of the pipe with the same equipment used for the line-up.

Fig. 35: Internal welding machine (IWM)

9.7.3.2 External clamps External clamps are used on tie-ins and in specific conditions where, due to technical or safety reasons, the use of an internal clamp is not possible. External line-up clamps are not suitable to attain high productivity. The line-up of the pipe is more time consuming, but since the clamp is reachable it is possible to make the necessary adjustments to get the pipe within the specified tolerances. After welding a specified or qualified percentage of the root the clamp has to be removed to finish the weld.

Fig. 36: External clamp (EC)

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9.7.4 Welding For the transportation of the welding equipment on the right of way a pay welder is common used. Since the lifting capacity of the pay welder crane is limited the welding shack must be kept as light as possible. In order to achieve this, the welding equipment is mounted on the pay welder. Generally the welding inverters, electronic control unit (ECU) and gas cylinders are on the pay welder. The wire feeder, water cooler and bug are installed in the welding shack. The power leads and gas hoses are guided by the crane to go from the pay welder to the welding shack. A typical (automatic) welding set-up is shown below.

Fig. 37: Typical (automatic) welding set-up.

Fig. 38: Field pictures

9.8

Welding safety hazards

9.8.1 Introduction Welding is associated with a number of risks, which are produced by the type of activity and physical phenomena related to welding. Cross-country pipeline construction in particular is always in a high productivity scenario, and is an outdoor job site, always in motion. Therefore, welded pipeline construction is associated with very particular requirements in terms of safety. The following section discussed the main topics related to safety.

9.8.2 Personal protection equipment A welderâ&#x20AC;&#x2122;s personal protection equipment shall take into account all the hazards associated with welding such as sparks, spatter radiation, etc. The selection of this protection shall be based on the level of each hazard, which depends on a number of factors which can include welding process, shield gas, base

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metal, etc. Welder’s ergonomic comfort should be given due importance when choosing the protection. Factors such as overweight equipment, heat stress, motion and vision reduction must be taken into account in order to avoid negative effects on welder performance. The personal protection system shall balance protection and comfort for the welder. At a minimum, a welder should wear boots (steel toes), cuff-less trousers made of natural fibres, a flame-resistant welding jacket, leather gloves with wrist and forearm coverage, safety glasses, and a welding helmet with a skull cap.

9.8.3 Main risks The main risks associated with welding pipelines are the following: • Burns

• • • • • • •

Radiation Fumes Hard particle projectiles Fire Explosion Electric shock Engine-powered welders

9.8.4 Burns Burns in the welding process are caused by two sources: • Thermal: skin burns from hot metal, spattering slag and from handling hot tools or electrodes

• •

Erythema: skin burns primarily by ultraviolet light Flash burn: caused when a surge of UV light hits the eye, causing a "sunburn"-like condition on the cornea

Protective material The two most commonly-used materials for welder protective apparel are chrome-tanned leather and specially treated, fire-resistant cotton. Leather is durable and will last several years if dry cleaned regularly whenever the garment becomes noticeably stiffened from accumulated dirt and grime. Treatedcotton garments come in a range of material weights, allowing welders a choice: when working in hot summer environments, they can select lighter-weight materials; otherwise they can opt for heavier weight, more durable garments. All but the most inexpensive treated-cotton garments can be laundered using normal temperatures and cycles without affecting the fire-resistant treatment. Buyers of welder apparel should avoid garments that offer a place for sparks to land. Look to buy trousers, overalls, and coveralls with no cuffs or pockets. Welders should not roll up their sleeves either. Other fabrics High-heat fabrics made of Kevlar® blended with fiberglass, which withstand temperatures of 300°C, are gaining favour for aprons, sleeves, and gloves. Another option is Zetex®, a highly-textured form of silica fabric that is inert and will not burn; it withstands temperatures to 500°C. Zetex Plus® comes coated, and is good to 1000°C. These materials also resist cuts and abrasion. Furthermore, to improve protection from radiant heat, clothing made of any of these materials can carry an aluminized layer. Aluminized fabrics can be used in gloves, aprons, leggings, and hand pads.

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Jackets offer full torso and arm protection, but may be too heavy for some working conditions. A lighter, cooler alternative is a cape sleeve, which protects the arms and chest while leaving the back open. Pair a cape sleeve with a bib to protect the upper torso to the waist. Another option is the bib apron. Specify a split-leg apron for optimum freedom of movement, useful, for example, if the welder needs to kneel a lot. If the welder's arms are heavily exposed, use sleeves, which come in 18- and 23-inch lengths. Protecting the lower body, safety trousers are usually worn over the welder's regular trousers. Chaps offer a good alternative for welders needing the extra protection of leather without the extra weight or warmth. Chaps protect the front of the legs, leaving the back open. They fasten to the legs with straps. Protect only the lower portion of a welder's legs with leggings, which have extensions for foot protection. Spats protect only ankles and feet. Spats, as well as the extension on leggings, keep sparks from falling into the openings on the top of shoes. For one-piece, top-to-bottom protection, select either a coverall or overall. Due to the weight and expense of these large garments, they are usually ordered in fire-resistant cotton. Glove selection Welders can select among two types of gloves - welding gloves and gas tungsten arc welding (GTAW) gloves, the welding type being much heavier. GTAW gloves tend to be unlined for optimum feel, and are often manufactured of leather other than cowhide, including sheepskin and pigskin. GTAW gloves, which generally wear faster than welding gloves, come sized for optimum fit and feel. The standard length of welding gloves is 14 in., enough to cover half of the welder's forearm. For protection to the elbow, specify an 18-in. glove. Most welding gloves are of varying grades of leather. Premium gloves are of side-split cowhide, a better grade than shoulder split. For optimum flexibility, durability, and protection, look for these features: welting, thumb strap, Kevlar thread, one-piece back, and a comfortable, durable lining. For optimum protection from radiant heat, specify a glove with Mylar®, an aluminized material. Mylar can be placed either between the lining and leather outer shell or on the back of the hand outside of the leather. Another option: add a Mylar-covered hand pad placed over a regular welding glove.

9.8.5 Radiation Introduction Welding arcs emit radiation over a broad range of wavelengths from 200 nanometers (nm) to 1,400 nm. This includes ultraviolet (UV) radiation (200 to 400 nm), visible light (400 to 700 nm), and infrared (IR) radiation (700 to 1,400 nm). Certain types of UV radiation can produce an injury to the surface and mucous membrane (conjunctiva) of the eye called "arc eye", "welders' eye" or "arc flash." These names are common names for "conjunctivitis" - an inflammation of the mucous membrane of the front of the eye. The symptoms include: • pain - ranging from a mild feeling of pressure in the eyes to intense pain in severe instances

• • •

tearing and reddening of the eye and membranes around the eye sensation of "sand in the eye" or abnormal sensitivity to light inability to look at light sources (photophobia)

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The amount of time required to cause these effects depends on several factors such as the intensity of the radiation, the distance from the welding arc, the angle at which the radiation enters the eye, and type of eye protection that the welder or bystander is using. However, exposure to just a few seconds of intense UV light can cause arc eye. These symptoms may not be felt until several hours after exposure. Long-term exposure to UV light can produce cataracts in some persons. The intensity of radiation of the welding processes most extensively used in the pipeline construction is shown in Figure 39 below. UV radiation in a welding arc will burn unprotected skin just like UV radiation in sunlight. This is true for direct exposure to UV radiation as well as radiation that is reflected from metal surfaces, walls, and ceilings. Surface finishes and certain paint colours can reduce the amount of UV radiation that is reflected. Visible light from welding processes is very bright and can overwhelm the ability of the iris of the eye to close sufficiently and rapidly enough to limit the brightness of the light reaching the retina. The result is that the light is temporarily blinding and fatiguing to the eye (flash burn). Exposure to infrared light can heat the lens of the eye and produce cataracts over the long term.

• •

Plasma arc welding (PAW) Tubular with gas (FCAW-GS)

• •

Manual welding (SMAW) MIG (GMAW)

•

TIG (GTAW)

Fig. 39: UV exposure comparison among some welding processes Welder helmet The helmet is made of a material that is an electrical and thermal insulator, noncombustible, and opaque to visible, ultraviolet and infrared light (see Figure 40 below). The eyes are protected from the ultraviolet radiation by a filter shade mounted on the welder’s helmet. The shell of the helmet is hinged so that it can be raised and then lowered during welding. Many welders have been observed jerking their neck back to raise the helmet, rather than manually raising it. This jerking motion tends to increase the incidence of neck strain.

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Hand shields or helmets provide eye protection by using an assembly of the following components:

•

Helmet shell – this must be opaque to light and resistant to impact, heat and electricity. It has to cover all of the welder’s face in order to avoid skin exposure

•

Outer cover plate made of polycarbonate plastic which protects from UV radiation, impact and scratches.

•

Filter lens made of glass containing a filter which reduces the amount of light passing through to the eyes. Filters are available in different shade numbers ranging from 2 to 14. The higher the number, the darker the filter and the less light passes through the lens.

•

Clear retainer lens made of plastic prevents any broken pieces of the filter lens from reaching the eye.

•

Gasket made of heat-insulating material between the cover lens and the filter lens protects the lens from sudden heat changes which could cause it to break. In some models the heat insulation is provided by the frame mount instead of a separate gasket.

Fig. 40: Welder helmet components Lens shade selection The selection of the appropriate lens shading depends on the welding process and arc energy level. Table 1 presents the shade grade for a variety of welding/cutting processes. Auto-darkening lenses are available also, which can be set electronically in a range of shade grade and reaction time also. This type of lenses has no shade when the welding arc is off, providing clear vision to the welder before welding, therefore a precise position of electrode or welding torch is possible an instant before the welding arc starts. Consequently, the welder comfort is increased while welding defects associated with bad initial arc position are reduced.

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Operation

Electrode Size 1/32 in. (mm)

Arc Current (A)

Minimum Protective Shade

Suggested Shade No. (Comfort)

Less than 3 (2.5) 3–5 (2.5–4) 5–8 (4–6.4) More than 8 (6.4)

Less than 60 60–160 160–250 250–550

7 8 10 11

– 10 12 14

Gas metal arc welding and flux cored arc welding

Less than 60 60–160 160–250 250–500

7 10 10 10

– 11 12 14

Gas tungsten arc welding

Less than 50 50–150 150–500

8 8 10

10 12 14

Less than 500 500–1000

10 11

12 14

Less than 20 20–100 100–400 400–800

6 8 10 11

6 to 8 10 12 14

Less than 300 300–400 400–800

8 9 10

9 12 14

Torch brazing

–

3 or 4

Torch soldering

–

Carbon arc welding

–

Shielded metal arc welding

Arc carbon Arc cutting

(Light) (Heavy)

Plasma arc welding

Plasma arc cutting

(Light)** (Medium)** (Heavy)**

Table 1: Lens shading selector

9.8.6 Ventilation and fumes In order to improve working conditions of welders, extensive research has performed. Welding fumes and gases have been particularly extensively studied due to their relationship with a number of illnesses and respiratory diseases. Much of the confusion driving the research is related to the difficulty of associating a particular illness with a specific constituent of the welding fume or gas. Determining a direct relationship between an occupational illness and welding is difficult because of the complexity of fumes and gases, the synergistic effect of certain constituent and non-occupational factors (e.g. smoking), and because most of the illnesses are long-term, and take time to manifest themselves. In any case, using correct ventilation considerably reduces any effect of welding fumes and gases on welders’ health. In case welding is performed in an enclosed space such a welding shack, a minimum ventilation rate is required. Those values depend on the base metal, welding process, the consumable type, welding consumable diameter, etc. Indicative values are given in Table 2. In the case of welding shacks used in cross-country pipeline construction, the ventilation system typically consist of an extractor fan for general ventilation and a welding fume extraction system on top of the welding area (see Figure 43 below). Each country has its own requirements on this matter. Contractors shall take into account the applicable regulations when designing the ventilation system. In case extra protection is needed, personal respirators provide a practical, portable solution. These type of devices can be either powered, in which filtered clean air is blown into the welding helmet, or passive, in which a filtration mask is placed over the welder’s nose and mouth. The former provides also a cooling effect that tends to reduce the welder’s heat stress and visor fogging.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

Coated Electrodes Steel, 5/32 in. diam. Steel, 3/16 in. diam. Steel, 1/4 in. diam. Alloy (flouride coated), 5/32 in. diam. Steel, 5/32 in. diam.

Base Metal

Rate, cfm

Steel Steel Steel Alloy Steel Galvanised Steel

250 400 700 250 1000â&#x20AC;&#x201C;1500

Table 2: Suggested ventilation rates for SMAW [from The Welding Environment- AWS]

General ventilation Welding fume extraction system

Fig. 41: Typical ventilation system used in welding shacks

Fig. 42: Personal respirator for welders.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

9.8.7 Hard particle projectiles Introduction Portable grinders (including angle grinders) are intended for cutting, grinding, sanding or brushing metal, stone and timber materials, depending on the type of disc fitted to the machine. The main parts of a typical manual grinder are shown below:

Fig. 43: Main parts of a manual grinder Usually, manual grinders are associated with a high spin speed. Typically, a point at the outer part of a disc can present a velocity of 80 m/sec which is equivalent to 288 km/hr. Therefore, a disc failure will spall out dangerous hard particles at high speed. Types of discs The consumables of the manual angular grinders that usually are used in pipeline construction are made of a reinforced glass fiber/resin composite disc on which the abrasive material is mounted or wire-brush type. There are a number of different tools that may be fitted to a portable grinder design for a verity of applications. For example: • bonded grinding and cutting discs

• • • • • • • • •

bonded wheels diamond grinding and cutting discs flap discs flexible and semi-flexible discs pneumatic wheels rotary hacksaws ultra-thin cutting discs wire brushes woodcarving blades

Fig. 44: Different types of manual grinder tools

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

Hazards identification There are numerous hazards associated with operating a manual grinder, which include: • Electric shocks

• • • • • • • • •

Falls Impact Cuts Burns Fire Explosion Fume/dust Noise Vibration

Choosing the correct tool and controlling the risks Each tool used in manual grinders is designed for a specific type of application. Consequently, each tool is associated with certain variables such as material (carbon steel, stainless steel, high alloy steel, etc), use (cut, grinding, cleaning, etc.), dimensions, maximum rotary speed, etc. Usually the essential parameters are clearly expressed in the tool’s operating manual. Before using a certain tool, the job to be performed must be analyzed in order to select the correct tool. Using the tool incorrectly, in circumstances for which it was not designed, may cause its failure. Follow the manufacturer’s information Before using a portable grinder for the first time, read the manual. Ensure operators are trained Operators must be trained in selecting, fitting and removing, caring for and inspecting discs; and the safe use of portable grinders. Ensure operators are supervised Employers, managers and/or supervisors must carry out checks to ensure grinding operations are being done in a safe manner, and that operators are observing the required safety precautions. Use the correct disc Ensure any disc to be fitted to the grinder is: • the correct type for the material being worked with

•

capable of being safely used at the maximum speed of the machine, stated as revolutions per minute, meters per second or feet per second

• •

the correct size for the grinder

•

fitted in accordance with the manufacturer’s instructions (discs may be flat or have depressed centers and require different methods of setting up. Refer to the machine’s manual)

free of any damage, flaws, dampness, warping or distortion that may result in the disc shattering

Always unplug the grinder from the power supply, or remove the battery, before fitting or removing a disc.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

Set the equipment correctly • When the disc is replaced, rotate the disk by hand in order to ensure it is centered and it does not touch the guard. After that, adjust the locking nut

• •

Never adjust the disc by hand, use the adjusting tool Before starting working, always let the grinder runs for a minute to ensure it is functioning correctly

Use personal protective equipment When using a grinder, always use personal protective equipment (PPE): • eye protection

•

hearing protection

Any additional safety equipment, including respiratory protection, gloves, sturdy shoes, apron and hardhat. Beware of loose clothing that may be grabbed by the grinder. Ensure guards are in place Never use a portable grinder without the guard being in place and correctly adjusted. A properly adjusted guard will minimize sparks hitting the operator and injury in the event of disc shatter. Use all the safety features Although in most cases only premium products have especial feature such as soft anti-vibration handles and dead man’s switch, in order to have full protection this type of feature should be taken into account when selecting portable manual grinders. For safe operation, it important that all safety features are kept in good condition. Angular grinder – safe techniques • Never use a portable grinder one-handed. Always have the auxiliary handle fitted; hold the grinder with both hands and have a stable stance.

•

If it’s not possible to use the grinder with both hands in place, then the grinder is the wrong tool for the job.

•

Do not expose the discs to lateral force, torsion, or excessive pressure. Failure, overheating, efficiency lost, reacting forces and involuntary motion may result.

•

For thin cutting discs, the tool shall be always positioned perpendicular to the material being cut. Thin cutting discs should never be used in oblique positions. For intermediate cutting discs (thicker than 4.8 mm) the maximum inclination angle shall not exceed 60°.

•

Grinding discs (thicker than 6.35 mm) shall be operated at a minimum inclination angle of 30°. This type of disc shall not be used for facing small diameter pipes because the localized over-wearing at the other part of the disc may cause its failure.

•

Never use the grinder over the shoulder level because in case of an involuntary motion or reactive force the machine can hit the operator’s face, shoulder or arm.

•

When working out of position, any involuntary motion or reactive force must move the grinder away from the operator, otherwise it can hit the operator.

•

Ensure the work piece is rigidly supported and firmly clamped. Movement in the work piece during grinding may result in disc shatter or grinder kickback, with the potential for operator injury.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

Other considerations when grinding • Select a grinder appropriate for the work to be done. Remember that grinders have variable speed control, clutch systems and anti-kickback.

• •

Ensure the grinder is turned off before plugging in.

• •

Never put a grinder down while the disc is still turning.

•

Check to make sure there are no flammable materials that may be hit by sparks and check the area for any smouldering material when the work is completed.

•

Never clamp a portable grinder in a vice — a portable grinder is not a bench grinder nor a substitute for one.

•

Use a dust collection/control system whenever possible — some dusts may be carcinogenic, flammable or explosive.

Apply the grinder to the work piece only once the grinder has reached operating speed. Be aware of others in the vicinity of the work area, as sparks and material may be ejected over considerable distances.

9.8.8 Fire protection The risk of fire is always present in welding operations. For a fire to survive there must be oxygen, fuel and heat present. If any of these is removed the fire will be extinguished. Fire precautions should include: • Inspect every location before cutting and welding commences to ensure the potential for a fire to occur is eliminated

•

Suitable fire-fighting facilities are available near the work area and operators know where they are located. Are the fire-fighting facilities adequate for the potential hazard?

•

Work areas being clear of all rubbish and flammable material such as rags, oil etc. These materials should be removed to a safe distance before cutting and welding

• • • •

Removal and/or protection of flammable material.

•

Inspecting the site after cutting and welding has been performed to ensure that the potential for a fire to occur is eliminated

Clear, or soak with water, dry grass and scrub in surrounding area Operators should check their clothing is not impregnated with oil or grease Conveyor belting or other combustible materials should be suitably protected from cutting and welding and its sparks

9.8.9 Explosion / gas containers Cylinders gas containers should generally comply with the following: • Filled, inspected and maintained in accordance with applicable standard and regulations

• •

Gas safety data sheets to be kept at all sites

• • •

Never leave an empty cylinder connected to a process

Cylinder valves should be tightly closed when not in use or where cutting activities are stopped for a period of time, e.g. lunch Never sling or lift a cylinder by the valve cap Do not subject cylinder to abnormal mechanical shocks

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

•

Cylinders shall be located so that sparks, slag and molten material cannot fall on hoses or on the cylinders or attachments

The following considerations for the storage should be taken into account: • All cylinders should be stored in accordance with the applicable standard and regulations.

•

All cylinders should be kept upright, away from any sources of heat, electrical circuits and oil or grease during use.

•

Cylinders should be stored at least 15m away from fuel bays, fuel outlets and mobile equipment under repair.

•

All oxygen and acetylene cylinders should be placed on a stable footing and be secured to prevent falling.

•

Storage areas should be fitted with lockable doors, level floors and should be raised at least 150mm above the surrounding floor.

•

Dry powder extinguisher should not be positioned less than 8m or more than 10m from the storage area.

•

Cylinders should be returned to a safe storage area when operations are completed and kept isolated. Never leave them in the right of way in an unprotected area.

•

Grease, oils or other combustible substances should not be in contact with the valves of cylinders containing oxygen, nitrous oxides or other oxidants. Oils and any fuels in the presence of oxygen may ignite spontaneously.

•

Oxygen cylinders should be stored more than 3m away from fuel cylinders.

•

Cylinders should be made secure when being transported and attached to a rigid support.

• • •

Acetylene and LP Gas cylinders should be transported in an upright position.

•

All cylinders must be labelled, colour-coded and accounted for and removed from the work area after use.

• •

Cylinder valve guards should be used during transport.

Transport:

Cylinders should not be rolled on the ground. Where possible use an appropriate trolley for transporting cylinders, even over short distances.

Cylinders should be lifted in a manner as recommended by the manufacturer.

Ignition: An ignition safety device (flint gun) for flame cutting and burning activities should be used at all times. Matches, cigarette lighters, wicks, smouldering material and other similar devices should not be used to ignite a gas. Hoses:

• •

Hoses should comply with the applicable standard and regulations.

•

An automatic hose reeling system should be used when cutting and welding from heights or in a trench.

• • •

If hoses are burnt in a flashback or damaged they should be replaced.

Hoses should be protected from sparks, hot slag, hot objects, sharp edges and open flames.

Do not use hoses which are longer than necessary. Hoses should be checked for leaks daily.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

9.8.10 Electric shock Primary circuit: Primary circuit protection shall be in accordance with the applicable regulations and standards. Where mains-fed welding machines are to be used next to each other, the main connections shall be phased out to ensure that the open circuit voltage between adjacent electrodes does not exceed the extra-low voltage. If this is not possible fixed barriers should be installed so a person cannot gain access to both electrode holders at the same time. Ensure multiple AC welding machines are installed in phase. Output circuit: Electric shocks in welding occur when a person’s body is in simultaneous contact with any exposed part of the secondary circuit electrode conductor and any metal or conducting material connected to the work terminal. All parts of the welding circuit including the return path is ‘live’, therefore the welding operator must ensure that no part of the body is placed in a position such that it completes a path through the body for the passage of the electric current. To prevent electric shock from the secondary circuit, it is important that: • Welding cable is in good condition and suitably rated, located, protected and insulated, to contain all welding currents within the cable, and not allow any stray currents to occur.

•

The work return lead (cable) is fastened as close as practicable to the welding location to avoid stray currents Note: (i) Gears, bearings, brushings, pipes, etc should not be used to form part of the return circuit. This is to prevent damage to the equipment and arcing or sparking within the gear cases. (ii) Particular care should be taken when using two or more welding machines in close proximity. (iii) The lead (cable) connecting the welding machine to the work is called the “work return lead (cable)”. The work return lead (cable) is commonly (incorrectly) called the earth lead (cable). Deliberate or accidental connection of the work return lead (cable) to earth creates hazardous situations and allows stray currents of significant magnitude to be generated by welding circuits.

•

The electrical connection between the work return lead (cable) clamp and cable is secure.

•

Welding operators should ensure that no part of their body is placed in a position to create a return path for the circuit.

• •

Electrode holders are not defective.

•

When welding has stopped for a period of time, power should be turned off and the electrode removed from the holder in order to prevent inadvertent operation.

•

Prevent bare skin contact with the work piece and always use dry insulating gloves. Gloves should always be used to handle electrodes.

•

An output circuit safety switch, between the welding machine and the hand piece, is recommended.

• •

Two electrode leads are not alongside each other

•

Consideration should be given to the risk of electromagnetic induction with other circuits

Welding machines must be switched off and isolated from supply before connecting and disconnecting leads.

For AC welding machines the electrode terminal is connected to the electrode lead and the work terminal is connected to the work return lead, and not vice versa

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

Welding cables: The welding cables should not be extended beyond 9m in length without consideration of voltage drops. The current-carrying capacity of the work return and electrode cable should be determined in accordance with: • Rated output of the welding machine

• •

Duty cycle of the welding machine The distance of the work from the welding machine

Voltage reduction devices (VRD): VRDs are a safety enhancement that greatly reduce the risk to welding personnel from exposure to the potentially hazardous voltages produced by a welding power source. The VRD function is to reduce the voltage from the electrode to a safe value when the welding machine is not being used. A system (VRD or alternative) shall be provided to reduce the no-load voltage or open circuit voltage (OCV), to a no load voltage of: a) 35V for AC, or b) 35V peak, 25V rms for AC circuits, or c) less when the resistance of the output circuit exceeds 200 Ohms. Note: (i) Alternative systems may include triggers, switches and open circuit safety switch being operated when changing electrodes. (ii) MIGs and TIG machines reduce the voltage to zero when the trigger is not operated.

Response time for VRD: the turn off time (reaction time) for the VRD to reduce the voltage to the low voltage state after the circuit resistance reaches or exceeds 200 Ohms shall be less than 300 ms.

9.8.11 Safety precautions for engine powered welders

•

Always operate in an open well-ventilated area or vent the engine exhaust directly outdoors.

• •

Never fuel the engine while running or in the presence of an open flame.

•

Never remove the radiator pressure cap from liquid cooled engines while they are hot to prevent scalding yourself.

•

Stop the engine before performing any maintenance or troubleshooting. The ignition system should be disabled to prevent accidental start of the engine.

• •

Keep all guards and shields in place

Wipe up spilled fuel immediately and wait for fumes to disperse before starting the engine.

Keep hands, hair, and clothing away from moving parts

9.8.12 Other risks Other risks associated with any other industrial activity are also present in pipeline construction, even the more unexpected ones such as falls. Care must be taken in all the aspects and hazards in order to control them and avoid accidents.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

9.9

Engineering stages for pipeline welding

This section describes the engineering stages that need to be accomplished and approved before field welding activities can commence.

9.9.1 Review of project specifications Based on the project design criteria, subsequent parent material selection and regulations governing the project, the welding methods and processes are reviewed and evaluated to determine the best application and production welding methodology. Criteria for acceptance of girth weld discontinuities are set at this stage and usually depend on the criticality of the in-service pipeline. Criteria may be based on achievable standards of good workmanship, general fitness for service criteria or an engineering critical assessment.

9.9.2 Selection of welding and NDT methodology For the selection of the welding method the quality (mechanical properties and NDT contingency) and quantity (production rate) are the two major criteria that have to be taken into account. Section 9.5.1 shows a table with more detailed selection criteria. Criteria that are evaluated are; • Pipe base material certificate

• •

Environmental conditions Welding consumable certificate

9.9.3 Welding procedures qualification (WPQ) Welding qualifications are carried out to demonstrate the integrity of the weld system, weld parameters (such as heat input), and mechanical performance for both the parent material and the weld material. Weld qualifications are governed by industry specifications such as DNV, API, AS, BS or ISO with frequent supplementation from the owning company’s specific requirements. Normally several welds are made using the proposed welding technique. The weld parameters are optimized to ensure quality and repeatability. The qualification welds are inspected by the required NDT method according to the applicable standard. When the quality is demonstrated (acceptable welding) the welds are sent to the destructive testing laboratory. When mechanical testing is completed and the required mechanical properties are met, the procedure qualification record (PQR) is approved. This documentation is signed off on by both the contractor, and the owning company and the qualified welding procedure specification (WPS) can be issued for construction. The design and preparation of a joint for production welding is also an important engineering stage and should be carefully optimized during the welding procedure qualification. Most pipeline welding documents require that the qualification tests closely resemble production conditions. There are five basic steps in the qualification of a welding procedure: 1. Preparation and welding of suitable samples 2. Testing of representative specimens 3. Evaluation of overall preparation, welding, testing, and end results 4. Possible changes in procedure 5. Approval

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

9.9.4 Welder and welding operators approval and testing After the WPS of the welding methods/processes has been approved for pipeline construction, welder/operator training will be started. After the training has been completed, the welder / operator has to demonstrate the ability to produce acceptable weld(s) in compliance with the WPS. Welder, welding operator, and tack welder qualification tests are used to demonstrate the ability of those tested to produce acceptably sound welds using a qualified welding procedure specification. These tests are not intended to be used as a guide for welding during actual construction, but rather to assess whether an individual has a certain minimum skill level. The welder performance is documented in a welder performance qualification record (WPQR).

9.10 Mainline construction stages The next subsections describe the different stages of the preparation, welding and controlling activities during field construction.

Fig. 45: Mainline construction stages 1234567-

Surveying and clearing right of way Trenching and excavation Stringing pipe along the right-of-way Pipe bending equipment Pipe facing equipment Lining up the pipe ends Welding the pipe joints

8- Weld inspection 9- Field joint coating 10-Pipe protection 11-Buoyancy control products 12-Lowering in 13-Padding and backfill 14-Cleanup and restoration

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

9.10.1 Pipe end inspection Below is a summary of requirements and/or recommendations that control the quality of pipe ends and pipe end surfaces: • Pipe and pipe-end surfaces must be smooth, uniform and free of laminations, tears, scale slag, grease and paint that might adversely affect the welding.

•

Fusion faces on pipes and adjacent material must be free from fins, planar flaws, scale, rust, paint or grease prior to welding.

•

After completion of circumferential weld, prior to UT testing, a compression wave test of the parent metal material must be performed, on both sides of the weld, minimum distance 1.25x the longest surface skip distance.

•

The parent metal, in the scanning zone surface, must be examined with straight beam probes, prior to or after welding, unless it can be demonstrated (by the pipe mill) that the angle probe testing of the weld is not influenced by the presence of imperfections or high attenuation.

•

Examination of the pipe ends for the presence of laminations should be performed after a significant length of pipe has been removed

In modern pipe mills, the pipe ends already undergo various non-destructive tests to ensure sound parent material (see detailed descriptions of techniques used in section 10.5 “NDT at the material supplier and vendor inspection”). In most cases, the parent metal inspection is waived in lieu of the lamination checks that are performed at the pipe mill.

9.10.2 Pipe end preparation The pipe end preparation area should be kept neat and clean. Waste material should be avoided by placing a metal tray under the pipe being cut, following best practices and waste policy. Pipe ends needs to be machined by a pipe facing machine (PFM) with the same bevel design performed during the qualification of the welding procedure specification (WPS). Each bevel is checked for dimensional conformance at four to six locations evenly spaced around the pipe circumference. Correct and accurate bevel profile preparations are essential for the production of sound, defect-free welds. The importance of this step cannot be over-emphasized.

9.10.2.1 Standard bevel design (V-prep) for manual welding Groove welds are the most used joint design for butt joints in pipe welding. There are various types of groove preparations for butt joints for SMAW. Groove welds should be designed so that complete penetration is possible with the least amount of welding. Welds must extend completely through the cross-section of the pipe being joined. Also, complete fusion without slag entrapment, excessive porosity, or cracking must be obtained for a satisfactory weld. The most extensively-used bevel design is single V-60°. When the pipe wall thickness is over 3/4 inches (19 mm), a compound bevel design is recommended for reducing the amount of filler metal. However, for this range of thicknesses, semiautomatic, mechanized or automatic welding should be considered. The root opening (R) is the separation between the members to be joined. A root opening is used for electrode accessibility to the base or root of the joint. The smaller the angle of the bevel, the larger the root opening must be obtain good fusion at the root. If the root opening is too small, root fusion is more difficult to obtain and smaller electrodes must be used, thus slowing down the welding process. If the root opening is too large, weld quality does not

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

suffer but metal is required; this increases welding cost and will tend to increase distortion. Backup strips are used on large root openings. Root opening and joint design will directly affect weld cost (kilograms of metal required), and a choice should be made with this in mind. Joint preparation involves the work required on pipe edges and includes beveling and preparing the root face. Using a compound bevel, in preference to a single-groove, cuts in half the amount of welding. This reduces distortion and makes it possible to alternate the weld passes on each side of the joint, again reducing distortion.

Fig. 46: Typical preparation for cellulosic SMAW

9.10.2.2 Narrow gap welding design For pipes with thicker walls (above 19mm), generally semi-automatic, mechanized or automatic welding is used and compound or J bevel reduces the amount of welding material as shown below:

Fig. 47: Typical bevels designs used for FCAW for heavy wall pipes

9.10.3 Pre-heat Before the first weld pass is made, the weld joint is pre-heated. The minimum pre-heat temperature shall be in compliance with the specified minimum temperature in the applicable welding procedure specification (WPS). Additionally, the interpass temperature is generally controlled between a minimum (typically equal to the minimum preheat temperature) and a maximum level which is a function of the metallurgy and required mechanical properties. The interpass temperature is checked prior to starting each weld pass.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

9.10.4 Lining up the pipe ends The next pipe section is lifted by the front end side boom and transported to the mainline. Line up is performed by the front end foreman, the side boom driver and some helpers. When the next pipe is aligned with the mainline, an internal line up clamp (ILUC diameter >6”) is used to maintain the alignment of both pipe ends.

9.10.5 Manual welding 9.10.5.1 Root pass welding using SMAW One of the most extensively-used welding processes in a cross-country pipeline, used to deposit the root pass, is shielded metal arc welding (SMAW). Depending on the joint configuration and other welding variables, the welding consumables that typically are used are the following:

•

Manual EXX10 (e.g., E6010) cellulose electrode, vertical-down progression. This is the traditional and most popular method and offers the fastest welding speeds (ranging from 25-40 cm/minutes). Cellulosic electrodes may also be used vertical-up with slower travel speeds to handle greater variations in joint fit-up scenarios, such as a tiein.

•

Manual EXX16 or EXX18 (E7016 or E8018) basic low-hydrogen electrode, either vertical-up or vertical down progression. While travel speeds in both case is slower than cellulosic electrode, this is the only option for welding a manual low-hydrogen root pass.

Cellulosic electrodes can also be used in vertical-up progression in the case fit-up is very poor. However, there are two main drawbacks: a) It leaves deep undercut grooves along the edges of the weld face, commonly referred to as wagon tracks b) It is usually necessary to expose these wagon tracks so they can be consumed by the next weld pass — the “hot” pass. This is done by removing the weld crown by grinding. Thus, using cellulosic electrodes requires extra time after welding the root pass to remove part of the weld and then replace with new weld metal. Also, cellulosic electrodes produce weld metal with relatively high levels of weld diffusible hydrogen, rendering it crack sensitive when used on higher strength pipe grades. A low hydrogen manual root pass produces welds with a flat face (no wagon tracks) and less weld reinforcement on the inside of the pipe than with cellulosic electrodes. It produces a thick, crackresistant low hydrogen root weld. However, with basic electrode in vertical- down progression the joint geometry is different from that of cellulosic. Wider gap and smaller root shall be used in order to compensate the less forceful arc. If the bevel geometry is not changed, then the production may slow down. When comparing SMAW welding consumables for root pass, high-cellulose electrodes offer superior welding speeds. This is the main reason for the predominant use of high-cellulose electrodes. However, the weld metal of high-cellulose electrodes contains higher amounts of diffusible hydrogen than that of low-hydrogen electrodes.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Section 9

9.10.5.2 Welding techniques using SMAW A number of factors will determine how many welders will be needed to weld the root pass. In any case, it is best to have welders either (1) weld opposite one another or (2) evenly spaced around the pipe. When the pipe diameter is larger than 46” three welders may be used, but one of the welders should be ambidextrous. This will minimize the amount of distortion in the pipe and prevent the gap from opening or closing. If possible, it is also desirable not to finish a weld in exactly the bottom of the pipe because the tie-in can be more difficult. Similarly, it is best to avoid starting at exactly the top of the pipe (12 o’clock position). As a rule of thumb, for a 5/32” (4.0mm) cellulosic electrode, the welding time for one electrode should be approximately one minute and the length of weld should be approximately the same as the length of electrode consumed. This would produce a travel speed of approximately 300 mm/min (12 in/ min), but this is extremely sensitive to joint preparation and exact welding conditions. The root pass is welded with a “drag” technique. The tip of the electrode is held in contact with both pipes and dragged around the circumference of the pipe, progressing vertically down. The electrode initially should be held roughly perpendicular to the pipe. If there is a proper fit-up and the proper current is used, a small “keyhole” will be seen following behind the electrode. If the keyhole is not seen, the electrode is not penetrating through to the inside of the pipe. The remedies for this would be: • Higher current.

•

Apply more pressure on the electrode which lowers voltage and yields a colder puddle (depending on the type of welding machine).

• •

Use a push angle (although this is not always advisable). Slower travel speed.

If the keyhole becomes too large and difficult to control, the remedies would be: • Lower the current.

• •

Travel faster until the size of the keyhole decreases.

•

Apply less pressure on the electrode which creates a bigger keyhole

Use more of a drag angle while using faster travel speed until the keyhole becomes more manageable.

If it is necessary to interrupt the arc before the run is ended, the tip of the electrode must be rapidly snapped down. This prevents slag inclusion in the weld pool. Remove the slag from the crater and from the last 50 mm of the weld. The restart should be made starting on the weld metal approximately 12 mm before the crater and moving towards it with an arc length slightly above normal. Then push the electrode to the bottom of the joint to fill the crater and continue welding in the normal manner.

9.10.5.3 Hot pass using SMAW On one hand the main purpose of the root pass is to bring a fast first metal backing, and when using high cellulosic SMAW welding, the weld is usually very thin (1.5- 2 mm in thickness). On other hand, in order to increase productivity fill passes are performed by using a high energy welding technique (high current, high deposition rate). Therefore, if the metal backing deposited by the root pass is too thin, then burn-through will occur. Consequently, the main objective of the hot pass is to bring a thicker metal backing for the high energy stage of fill. Another objective of the hot pass is that after the root pass is welded by using high cellulosic SMAW consumable type, the root bead is generally very convex on the exterior of the pipe. The normal procedure is to grind the root pass to eliminate the excessive convexity. Normally, the entire weld is not ground out, rather only enough to expose “wagon tracks”. These are lines of slag that are on either side

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of the built up convex region. Then, another purpose of the hot pass is to burn out the “wagon tracks”. Ideally, this is achieved leaving the joint free of undercut and some filling of the joint is also accomplished. To do this, a high current is normally used. The hot pass should be started as soon as possible after completely finishing the root pass. Too long a delay may cause cracks in the root pass. The time between root pass and hot pass is a very important variable when using high cellulosic electrodes. For that reason, many pipeline constructions standards and codes consider it an essential welding variable. In the case that the root pass is deposited by GMAW-P(or other technique that assures a thick metal backing without excessive convexity), then hot pass is not necessary and the fill stage can start over the root pass.

Fig. 48: High cellulosic root pass in as weld condition. Notice the high convexity and the typical "wagon tracks" The most extensive technique used for hot pass is high cellulosic SMAW (EXX10). In some cases, the hot pass may be performed using the same technique used for fill. In this case a highly-skilled welder is required because the probability of burn-through is high due to the high energy welding technique typically used for fill. Usually 5/32” (4.0mm) cellulosic electrodes are normally used. Typically a current of 160 - 200 amps is used with electrodes, but note that if using higher current values, the electrode can overheat. Larger (3/16” diameter) electrodes can also be used, with currents around 180 amps. However, larger electrodes have a tendency to fill rather than dig. Maintain an arc length equal to the electrode diameter. Do not increase the arc length during movement. If the arc is interrupted before the bead is complete, remove the slag from the crater, restart the arc starting on the bottom bead, approximately 12 mm in front of the second bead and move back up to the crater. Make sure that you have filled the crater, then restart welding as indicated previously. Carry out the second half of the run with the same procedure. It should be noted that the “pulling” technique with which the root bead is laid causes an incomplete fusion and slag inclusion “tramlines”) at the seam edges. Due to the higher current used, the second or “hot” pass does not transfer much metal to the joint, but its greater heat frees the slag and completes the fusion between the weld edges and the base metal.

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Fig. 49: Starting the arc in hot pass

9.10.5.4 Fill and cap The main objective of fill is to complete the type joint, until the weld metal thickness almost equals the pipe thickness, while the purpose of the cap passes is to reinforce the joint and create a smooth finishing joint surface. To carry out the filling passes, the starting position and trailing angles of the electrode are the same as indicated for the root and hot passes, but electrodes of 5.0 mm diameter with current set at 150-180A must be used. Use a swinging movement, maintaining an arc length equal to the electrode diameter (Figure 50). Pause with the tip of the electrode on the edge of the previous bead. Move towards the opposite edge, descending by half the electrode diameter. If it is necessary to restart the arc, use the same procedure as indicated for the hot pass. After having welded the second half of the joint, completely remove the slag. To fill the joint up to 0.8 mm from the external pipe surface it may be necessary to deposit additional passes on the whole circumference (Figure 51). These beads should generally add a 1.6 mm thick layer. Use the same techniques indicated for the previous passes. Often, after having made all these layers, the joint is thicker in the upper and lower zone than in the side zones of the pipe, making it necessary to fill it evenly before making the cap (Figure 52). In this case stripper beads are laid with the same techniques illustrated previously.

Fig. 50: Swinging technique used for fill passes

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Fig. 51: Completion level for fill passes.

Fig. 52: Leveling beads The technique used for the cap pass is the same as indicated for the penultimate bead, but the swinging movement must be wider. A “Z” or “half moon” weaving technique may be used (Figure 53). Dwell with the tip of the electrode on the edges of the previous bead. Advance at a speed that makes it possible to obtain a 0.8 to 1.6 mm thick reinforcement and an overlap of approximately 1.6mm at the edges (Figure 54).

Fig. 53: "Half moon" weaving technique.

Fig. 54: Cap pass. Typical dimensions

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9.10.6 Semi-automatic welding This section presents a brief introduction of the use in cross country pipeline construction of semiautomatic welding processes, which include GMAW, GMAW-P and FCAW.

9.10.6.1 Root pass with semi-automatic welding GMAW is used for root pass when using no backing. FCAW can be used in the root pass only when using copper backing. Since this pass needs low and very controlled energy, GMAW globular and spraymetal transfer mode are not used. Although regular short circuit transfer mode provides low energy, it is not used in semiautomatic welding, but is emulated by pulsing the current (GMAW-P). With GMAW-P and the advance in power supply technology, there are two additional metal transfer modes available: pulsed short circuit and pulsed spray. In both cases, the current is not constant in time and its variation can be represented by a wave with low and high levels (pulses). This wave signature will have direct effect on the metal transfer phenomenon and its custom design can give precise control over the weld deposition, heat transfer and other variables. Pulsed short-circuit mode is used in pipeline construction for root pass deposition. It brings a faster and thicker root pass compared to SMAW. Pulsed spray transfer mode is associated with high deposition rates and good balance of the heat transfer which has a positive effect on mechanical and toughness properties. For that reason, it used in mechanized welding for fill and cap passes. The joint design used in GMAW-P in root pass is similar to SMAW. The root opening can vary in the range of 1.5-4 mm, and the land can be 0-3 mm. This welding process has shown be very robust to overcome pipe fit-up problems. Even with important misalignment (hi-lo) or irregular gaps, this process can perform a sound root pass.

Fig. 55: GMAW typical preparation for root pass

9.10.6.2 Fill and cap using semi-automatic welding The welding processes that are typically used for fill and cap are FCAW-GS and FCAW-SS. These semiautomatic welding processes lead to higher productivity than GMAW. Since FCAW and GMAW are very similar in terms of equipment and logistics, FCAW is the choice of most contractors (particularly when welding heavy wall pipes). FCAW-GS in particular tends to be the most productive of the semiautomatic welding processes. When it is combined with GMAW-P in the root pass, FCAW-GS can duplicate the productivity of manual welding. However, this welding process is very sensitive to wind and requires the use of tents or shacks. It is very prone to create porosity if the wind protection is inadequate.

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The bevel design has an important influence on productivity for pipes thicker than 17mm. Compound or J bevel can diminish the total volume to fill. Consequently, the total time to complete a joint can be quite low with respect to that of single V 60°. Productivity can be improved even further when semi-automatic welding is used. In that case the saving time can be up to 35 minutes when using GMAW-P/FCAW-GS. The saving is based not only on higher deposition rates but also on less dead time. SMAW is associated with low efficiency due to the need to stop and change electrode, grinding, etc. All those unproductive times are increased even further in the case of single V-60° bevel.

9.10.6.3 Welding technique using semi-automatic welding GMAW and FCAW-GS are typically welded in up-hill progression, while FCAW-SS is used downhill. The oscillation technique can vary in terms of pattern, but in any case it is important to limit oscillation. Particularly in the case of FCAW-SS excessive oscillation can increase the chances of having porosity. The maximum width of any weld bead shall not exceed 12 mm (1/2”). Beyond that oscillation, multiple beads should be used. Torch oscillation also is important in terms of shielding and heat distribution. The maximum tilt angle shall not exceed 60°. All the concepts explained in the manual welding section regarding re-starting technique, levelling bead and capping technique are applicable for semiautomatic welding.

9.10.7 Automatic and mechanized welding 9.10.7.1 Introduction The generic terms automatic and/or mechanized welding are used around the world with different meanings. Here, we propose definitions applicable for the purpose of this document to help readers identify some key differences, enabling them to further develop their knowledge when speaking with specialists. Generally the welding head, or “bug”, will not complete a 360° circumference but 180° or less, depending on the total number of welding bugs used. The same scenario is replicated on either side on the pipe at each welding station. The basis of mechanized welding is setting a torch of a semi-automatic system on a carriage (bug); which will turn around the pipe along its guiding band. In this case the welding system will produce effects including, but not limited to, translational motion, oscillation, metal feeding, arc distance setting, etc. During welding, the operator can adjust some of the welding parameters as needed. The typical application is FCAW uphill. Automatic welding is a term that refers to any welding system in which the operator has almost no control on the weld operation, other than the start and stop. All the welding operational control is performed by the system. They are basically a more controlled system than the mechanized ones. Their typical application is solid wire downhill. As computing and welding technology have evolved over the past century, so has the level of automation. Mechanized and automatic welding for pipeline construction has been available for more than 40 years. The first systems were tested onshore and naturally found their way into the offshore market in the early 1970s. The evolution of this technology has mirrored the computing revolution and technology advances in welding power supplies and electrodes. Requirements in pipeline design and the micro-alloying of pipeline steels have increased the potential for mechanized/automatic welding. Consistent heat inputs and superior mechanical performance are drivers for the high performance welds required in today’s construction environment. Financial drivers

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such as increased production rates and the ability of operators to be trained to make high quality welds in short time periods continue to make automation attractive. Worldwide resurgence in the pipeline market to fuel the energy needs of both developed and developing countries have led to a rapid growth of mechanized welding in recent years.

9.10.7.2 The systems and the main components The main focus of a system is to assist the operator and make them more efficient. Mechanization also decreases the physical strain during welding and increases the productivity. Several welding variables are mechanized and automated to ensure consistency of the welds produced. As technology improves so do the capabilities of the systems. Bug and band welding systems are typically engineered with the following components: • Guiding band or travel guide

•

A chassis (also known as a carriage, or bug) to mount to the guiding band and hold the required components

• • • • • • •

Motor and wheels for travelling Motor(s) for manipulating the weld torch (oscillation and stick out control) Computer control board(s) Welding power supply with interface module Wire feed unit(s) with interface module Shielding gas (if required) Grounding

9.10.7.3 Control variables The level of automation depends on the welding system that is selected for the specific application. The components are designed to work together to control travel speed, the electrode feed rate, torch angle, contact tip to work distance, oscillation rate, oscillation width and centering of the torch in the bevel. The sensing and computing monitor make adjustments to the electrical characteristics through the welding power supply. The variables described above are interlinked in the systems and they help ensure consistency of the welds produced. Depending on the type of system used, operators will have some control of the variables within the specified limits as allowed by the approved welding procedure specification (WPS).

9.10.7.4 Automation level The decision on how to select whether mechanization or automation is right for each specific pipeline project, and sections of it; depends on several variables. Typically these variables are driven by either technical requirements or financial reasons. Below is a list of some of the variables to consider when investigating whether the use of mechanized welding is justifiable. • Length of the pipeline

• • • •

Pipe chemistry

•

Wall thickness of the pipeline

Condition of the terrain the pipeline will cross NDT techniques Service environment of the pipeline (H2S and CO2 content, operating temperature and pressure)

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• •

Skill set of the workforce Service condition of the pipeline (fatigue and critical zones)

Refer also to section 9.5.2

9.10.7.5 Welding processes During the 1970s and 1980s, semi-mechanized gas metal arc welding (GMAW) proliferated with the advances in power supply technology. The process became well-established and proved more reliable. The development of this reliable and stable weld process brought the mechanized and automatic welding systems to a new technical level. With the evolution in computer technology it is now possible to control the welding arc digitally in real time. Analogue welding controls are still in use today but the new systems emphasise (thanks to reliable new digital electronics) high level QA/QC control and weld parameter monitoring. These developments make it possible to build machines that are much closer to achieving full automation. The welding processes that are used for mechanized and automatic girth butt welding are: • Gas metal arc welding (GMAW) – typically in short arc mode or “dip transfer”

•

Modified short arc GMAW – used to run root passes without either back up support or cross penetration

• • • • • •

Pulsed gas metal arc welding (GMAW-P) Flux cored arc welding (FCAW) Selfshielded flux cored arc welding (FCAW-S) Metal cored arc welding (MCAW) Gas tungsten arc welding (GTAW) Submerged arc welding (SAW) in the case of double jointing only

The most common used welding techniques are GMAW, P-GMAW and FCAW.

9.10.7.6 Orbital motion mechanism There are a variety of mechanisms that provide the orbital motion of the system: chain, flat band, gear band, etc. Chain mechanism uses a chain around the pipe and the tension is used to fix the bug and make it move. The advantage of this system is that the chain is part of the system itself and it does not need any work prior to welding. In contrast, flat and gear bands need to be set in place before the welding bag arrives at the joint. Usually, in a typical project using mechanized welding for fill and cap, several bands are needed. They are set in place in advance in the joints to be welded. After welding is completed, they are removed and move ahead of the welding crew to be set in place in new joints. Flat bands are usually also used for AUT systems. Then, the same band is used to weld and to inspect the joint.

9.10.7 Mechanized welding The basis of mechanized welding is setting a torch of a semi-automatic system on a welding bug and the typical application is FCAW uphill. Typically this process is using a single torch per bug. The root pass is generally performed from the outside with no back support and a gap, just like on a typical stick rod or semi-automatic weld. This root pass can be “mechanized” but is quite often welded using a manual stick rod (SMAW) or semi-automatic (manual with a gun) modified short arc GMAW using either solid or metal core wire or manual GTAW.

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Quite often as well, a second pass, or even a third pass is performed using one of the above processes to create a strong enough support for the more powerful mechanized welding process to be applied on a sound and solid foundation. For the remaining filling and capping, which are usually the “mechanized passes” the most used welding processes are FCAW-GS; therefore consumables are the flux cored wires, typically with gas, but selfshielded wires are also used (FCAW-SS). Typically these types of welding system are simple and robust. The automation level is low. Travelling and oscillation are usually automatic. The rest of welding parameters are manually controlled by the operator.

9.10.7.7 Automatic welding The basic idea is to further integrate together the welding and carriage systems to optimize the welding arc properties, the quality and the productivity. Single or multiple torches can be set on each single welding bug and single or multiple wires can be fed through each single torch. One of the main reasons to use automatic welding is to achieve high production rates and high quality welds. To reach that goal narrow-groove bevel designs are used. The design of the bevel reduces the weld volume which reduces the arc time. Therefore, with automatic welding, the bevel must be re-machined on site therefore a pipe facing machine (PFM) will be required.

9.10.7.7.1 The root pass and the hot pass The achievable production rate for pipeline welding is based on the speed of root pass welding (first station). Production can only move forward when the root pass and the hot pass are completed and focus on optimizing the cycle time in station 1 is critical. For root pass welding the following technologies can be used: • Mechanized root pass welding (external deposition)

• •

Copper back-up root pass welding (external deposition) Internal root pass welding (internal deposition)

A. Mechanized external root pass welding Recent technology based on hybrid short arc and pulsed waveforms have allowed for more control in the way metal is transferred from the electrode into the molten weld pool. This technology was initially intended for manual welding of the root pass in an open gap scenario and has now been automated to provide advantages. The pipe is first lined-up with a standard internal line-up clamp (see Figure 56). The bevel types used for this method are usually a standard V-bevel or a J-Bevel. When welding a standard V-bevel a root gap of 2-4mm is usually to be applied. The opening depends on the selected weld technique. The J-bevel can be welded with or without a gap. In an open gap scenario the arc must be initiated on the side wall of the bevel and brought into the gap area. For closed roots the arc is started in the weld joint at the faying interface. An advantage of using a standard V-bevel is that it is not necessary to re-bevel the pipe ends. A disadvantage is a much lower weld speed compared to other root pass weld methods.

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B. Copper back-up root pass welding The copper backing shoes are mounted on an internal line-up clamp. The backing shoes are applied to support the weld puddle and allow it to quench without adherence to the surface. Several systems use this method of root pass deposition. The backing ring allows high arc energy in order to achieve higher welding speeds (up to 150 cm/min). The applied bevel type is normally a J-bevel with a closed root gap. The advantage of using copper backing clamps is the increase of the weld speed over open root procedures. A disadvantage is that in case of excessive misalignment of the pipe-ends copper pick-up can occur if the welding procedure is not followed. Line-up clamps with copper backing are available for pipe diameters of 4” and greater.

Fig. 56: Internal lineup clamp with copper backing shoes C. Internal Root Pass Welding The internal welding machine was first debuted in 1969. This machine has three functions: • Line up

• •

Clamping and holding the weld joint together Depositing the root pass internally

The internal welder is a line-up clamp equipped with multiple welding heads to deposit the root pass. This automated innovation was a major step in increasing the weld speeds for root pass welding. By using multiple heads simultaneously, an effective joining speed approaching 2 m/min can be achieved. This industry benchmark explains why newer welding processes have found it so hard to gain acceptance. An advantage of the internal welder is the highest root weld speed in the industry. A disadvantage is the size limitation as it is only for pipes with a diameter of 24” (609,4 mm) and greater. The weight may limit the maximum slope in which the system can move itself.

Fig. 57: Internal welder with multiple weld heads

9.10.7.7.2 Filling and capping passes with automatic welding Most commonly the filling and capping passes are completed using either solid or metal core wire going downhill. The welding processes used are either GMAW – pulsed or dip transfer (short arc). The capping can be performed in 1 single wide pass or in 2 thinner passes deposited during the same run with a double torch bug.

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Short circuit is typically used for the second pass (hot pass). This pass has to provide extra metal thickness to the root pass in order to form a metal backing strong enough to resist the high energy fill passes. Then this pass is made typically using a fast low energy welding arc. The welding systems for this application are typically simple and robust. The level of automation is low. Little (or no) oscillation is used and the operator controls the torch position only in order to keep it centred. For fill and cap spray or globular transfer modes are used. Some welding systems use pulsed arcs, which provide a good balance among productivity, mechanical and impact properties. In order to increase productivity some welding systems include multiple torches in the bug or multiple arcs in each torch (twin arc). The automation level can be high. Some welding systems offer some features such as arc length control, electrical and laser tracking. Welding parameters such as current or wire feed are automatically controlled as a function of the welding position. Tilting sensors inside the bug provide a precise measuring of the actual position of the bug.

9.10.7.8 Advantages / disadvantages Mechanized / automatic welding offers the following advantages as compared to manual / semiautomatic welding: • The training time of the welders is quite short and in a few days they will be able to produce high quality welds.

• • •

The welding productivity is higher and fewer welders are required.

•

With the use of a narrow groove, the volume of filler material is lower.

Welding quality is higher. Mechanical and impact properties are generally better Mechanical properties of the produced joint can be very high, as flux cored wires can be chemically tailored to suit the purpose.

The disadvantages are: • Equipment cost is higher.

• •

Mobilization is more expensive. More specialized maintenance personnel is required.

9.10.8 Weld finish When the welding is finished, the weld needs to be cleaned, and spatter on the outer surface removed, as it may interfere with the NDT process.

9.10.9 NDT The final stage of welding activities is the non-destructive testing (NDT) to identify whether the weld quality is in accordance with the acceptance criteria. The NDT inspection crew should remain as close as possible behind the mainline welding crew.

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9.11 New welding technologies 9.11.1 Welding technologies of today The different factors that are taken into consideration to select a particular welding technique to be used in a cross-country pipeline construction project are described in section 9.5 “Welding methods and processes”. Meanwhile, the latest trends and requirements, already implemented on offshore projects, are gradually being introduced to the landline market: • High quality welds: the ability to ensure weld integrity in all types of welding environments; improved quality leads to lower repair rates and higher productivity;

•

High productivity: the ability to weld quickly, with minimal operational requirements, and thus, costs.

•

Versatility: the ability to weld a large range of materials (carbon steels, corrosionresistant alloys) with different pipeline dimensions, in different positions and on pipes subject to varying levels of criticality (steel catenary risers/fatigue-sensitive lines, offshore offloading lines).

•

Reliability: the high complexity of off-shore pipe lay operations requires that all welding equipment used should be as reliable as possible to prevent extra costs;

•

Customized solutions: the ability to deliver operational support and expertise in the accomplishment of seamless projects.

9.11.2 Technologies of tomorrow Enhanced weld quality, improved spread efficiency of equipment and productivity, risk-mitigation based on off-shore project processes are the different factors that have all contributed to successful accomplishment of projects at a global level. Hence, most research is centered on solid-state welding processes: • Off-shore-driven technology developments in pipeline welding are based on increasingly stringent weld quality requirements for given operational constraints and pipeline design.

•

Off-shore innovations or project service models made to suit the more unpredictable on-shore pipeline construction market, adapting highly technical and state-of-the-art welding equipment, solutions and project management, while overcoming the challenges created by onshore pipeline construction, such as: - control of linear welding energy capabilities - fracture mechanics - pipe end measurements - pipe sorting - pipe counter boring - pipe high grade - out of roundness clamps

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Tomorrow’s welding process must be compatible and meet the following requirements • strain based design

• • • • •

high strength material increased exposure to sour service conditions corrosion tight acceptance criteria stringent health, safety and environment (HSE) trends

9.11.2.1 Hybrid laser (HLAW) Hybrid laser GMAW welding is an automated, high performance welding process which results in a very narrow heat-affected zone (HAZ) with deep penetration and high travel speeds compared to more traditional processes. This breakthrough approach combines the highly focussed intensity of a laser with the joint filling capability of the traditional MIG process. By combining the two processes, hybrid laser welding provides a unique opportunity for thicker welds with less filler metal or higher travel speeds than typical welding, depending on the material thickness. An added benefit is that weld pool stability is greatly improved. The hybrid laser presents a potential interest in terms of mechanical performance, and also productivity and quality. Heat input is close to the minimum required to fuse the weld metal. Heat induced distortion of the work piece and metallurgical effects in the heat-affected zone are minimized. Electrodes are not normally required to conduct current to the work piece, thereby eliminating electrode contamination, indentation, or damage from high currents used in other welding processes. However, start and stop problems are still an issue and must be resolved before this technology can be implemented in the field as well as finding ways of reducing the high expense of the equipment involved, that will hinder its development. Furthermore, joints must be accurately positioned laterally under the laser beam and at a controlled position with respect to the laser beam focal spot. Once the technical hurdles are overcome, HLAW may find its first use on offshore lay barges or spool bases. Eventually, it may be an option for an onshore pipeline construction. However, at this point, it remains in the R&D realm.

9.11.2.2 Friction welding Friction welding is a solid -state process that produces a weld when two or more workpieces, rotating or moving relative to one another, are brought into contact under pressure to produce heat and plastically displace material from the weld interface. The two main variations of friction welding are direct drive friction welding (FRW-DD) and inertia friction welding (FRW-I). Although friction welding is a solid-state welding process, under certain circumstances a molten film may form at the weld interface during the heating stage. Filler metal, flux, and shielding gas are not required with this process. Advantages include no filler metal being required for all similar and most dissimilar material joints; solidification defects and porosity normally are not a concern; and operators are not required to have manual welding skills. Limitations include that the alignment of the workpieces may be critical to developing uniform frictional heat

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9.11.2.3 Friction Stir Welding Friction stir welding (FSW) is a variant of friction welding that produces a weld between two (or more) work pieces by the heating and plastic material displacement caused by a rapidly rotating tool that traverses the weld joint. Like conventional friction welding processes, the FSW process is solid-state in nature. However, FSW differs from friction welding in one important aspect: in friction welding, the relative motion is between the work pieces that are held in compression, whereas the relative motion in FSW is between the work pieces and a rotating tool. In friction stir welding, a cylindrical-shouldered tool, with a profiled threaded/unthreaded probe (nib or pin) is rotated at a constant speed and fed at a constant traverse rate into the joint line between two pieces of sheet or plate material, which are butted together. The parts have to be clamped rigidly onto a backing bar in a manner that prevents the abutting joint faces from being forced apart. The length of the nib is slightly less than the weld depth required and the tool shoulder should be in intimate contact with the work surface. The nib is then moved against the work, or vice versa. Frictional heat is generated between the wear-resistant welding tool shoulder and nib, and the material of the work pieces. This heat, along with the heat generated by the mechanical mixing process and the adiabatic heat within the material, cause the stirred materials to soften without reaching the melting point (hence being known as a solid-state process), allowing the traversing of the tool along the weld line in a plasticized tubular shaft of metal. As the pin is moved in the direction of welding, the leading face of the pin, assisted by a special pin profile, forces plasticized material to the back of the pin while applying a substantial forging force to consolidate the weld metal. The welding of the material is facilitated by severe plastic deformation in the solid state, involving dynamic recrystallization of the base material. Actually this process is in its preliminary stages on metallic materials. The main disadvantage is the toolâ&#x20AC;&#x2122;s limited lifetime, and the main concern is the jointâ&#x20AC;&#x2122;s performance with respect to fracture mechanics and corrosion. Another limitation is that the joint is not self-supporting and must be properly restrained. Advantages include that FSW normally is done in a single pass with full penetration and with little or no joint preparation. Further minimal distortion occurs during welding, provided proper clamping is used.

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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.

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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.

1 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.

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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.

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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.

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

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.

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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

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

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.

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

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.

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

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

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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.

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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.

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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.

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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)

•

3 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

3-Layer polyethylene (3LPE)

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 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

12.1 Introduction 12.1.1 Environmental Assessment: Environmental assessment emerged in the 1960’s and has been identified as a means to elevate environmental concerns to the decision making table that has been traditionally dominated by economic outcomes. The aim of environmental assessment is to ensure that the environmental implications of a decision are taken into account prior to consent being given to the development. (EC, 2011). Currently two main types of environmental assessment exist; Strategic environmental assessment (SEA), and environmental impact assessment (EIA). SEA was developed to ensure environmental accountability in the context of policies, plans, and programmes, whilst EIA focuses on project level decision making.

Policy

Plan

SEA

Programme

Project

EIA

12.1.1.1 Strategic Environmental Assessment: SEA’s are carried out on behalf of governments or regional authorities. They ensure that governmental policies minimize potential damage to the environment and adhere to the principles of sustainable development. In general, SEA’s focus on the broader impacts of a particular sector (energy, transport, education etc…) or a wider region, whilst EIA’s are highly detailed, and focus on the specific project area and its direct surroundings. During the planning phase of a pipeline project, the developer should consult national or regional governmental bodies to familiarise themselves with any SEA’s that are available and relevant to the development. Not only can this help to avoid delays, it can also be a useful first point of source to establish potential environmental risks.

12.1.1.2 Environmental Impact Assessment: EIA is a support tool that provides information on the likely significant impacts of a development, which will in turn help to determine whether a project will gain consent. At the core of EIA is the systematic identification and evaluation of potential impacts arising from proposed developments and the subsequent communication to decision makers and the public. Human development has caused habitat loss and fragmentation, resulting in significant biodiversity reduction. Ecological systems are complex in their nature, making impact predictions a tough exercise. Due to the large scale, high potential risks, and the complex task of predicting the impacts of a pipeline project on the environment an EIA must be undertaken. The EIA follows a standard procedure to ensure consistency across studies and maintain a common ground for authorities to judge the impacts of a particular project in relation to other projects. The exact process required by legislation differs from country to country, especially in relation to the extent of public consultation, consideration of alternatives and consultation with local authorities. However, they all follow the same general format.

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The standard EIA process: Project Proposal (incl. alternatives)

Screening EIA Required

No EIA Required

Scoping

Baseline Study

Impact Prediction & Analysis

Impact Mitigation

Preparation of the EIS (the report)

Review

Decision Making

Project Consent

Project Rejection

Follow Up: Monitoring & Evaluation Figure 1 Standard EIA process

Best practice principles from the International Association of Impact Assessment dictate that the following characteristics should be common to all environmental impact assessments: • • • • •

Purposive Rigorous Practical Relevant Cost effective

• • • • •

Efficient Focused Adaptive Participative Interdisciplinary

• • • •

Credible Integrated Transparent Systematic

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12.1.2 Social and environmental impact assessment process Social and economic development is an essential element of meeting basic human needs, by improving the quality of life and securing better prospects for the community. It is essential, therefore, that this development takes place on a sustainable basis. In the past, developments have taken place that have been destructive to the environment and thereby endangered the very basis on which sustainability of development depends. As a result, there is an ever-increasing need to have a process in place that can enable the decision makers and stakeholders to properly understand the impacts of the proposed development. Social and environmental impact assessment (SEIA) (Figure 1) of a proposed development is the process of: • Gathering environmental and socio-economic information • Describing the development and the alternatives studies in the process of engineering design • Predicting and describing the environmental and socio-economic effects of the development • Defining ways of avoiding, cancelling, reducing or compensating for the adverse effects (mitigation) • Publicising the development and the environmental statement so that the community can play an effective part in the decision making process • Consulting specific bodies with social and environmental responsibilities • Taking all of this information into account before deciding whether to allow the project to proceed • Ensuring the measures prescribed to avoid, cancel, reduce or compensate for environmental and social effects are implemented and monitored • Informing key stakeholders, including affected communities, about the development and any associated negative and beneficial impacts

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Figure 2: Typical SEIA process in a project

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The SEIA assessment focuses on obtaining primary information from key stakeholders, (including affected communities) and site surveys in order to • Feed the results of consultation into the assessment process • Assist with the decision-making process • Identify the best measures to reduce and manage adverse impacts In order to reap the maximum benefits and obtain objective information from the best available sources, the SEIA must place an emphasis on carrying out a bias-free, systematic and holistic process. The most important benefit is the proper understanding which local authorities and communities gain of the proposed development’s potential impacts and how the developer proposes to minimise potential effects. An SEIA involves prediction. Uncertainty therefore becomes an integral part and whilst it cannot be avoided in most cases, one must strive to minimise it. There are two types of uncertainty associated with social and environmental impact assessments: those associated with the process and those associated with the predictions. With the former, the uncertainty is whether the most important impacts have been identified and whether recommendations will be acted upon or ignored. For the latter the uncertainty is in the accuracy of the findings. According to de Jongh (1988), the main types of uncertainty and the ways in which they can be minimised can be summarised as follows: • Uncertainty of prediction: This is important at the data collection stage and the final certainty will only be resolved once implementation commences. Targeted research can reduce the uncertainty together with the use of experienced professionals • Uncertainty of values: This reflects the approach taken in the SEIA process. Final certainty will be determined at the time decisions are made. Improved communications and extensive negotiations with agreed and documented outcomes should reduce this uncertainty • Uncertainty of related decision: This affects the decision-making element of the SEIA process and final certainty will be determined by post evaluation, preconstruction permits and the management plans. Improved coordination between the developers, their engineers, the consents team, contractors and operations teams reduces uncertainty to a large extent.

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12.2 ENVIRONMENTAL AND SOCIO-ECONOMIC SCREENING AND SCOPING 12.2.1 Screening: Screening is the first key decision of the SEIA process that determines whether the proposed development requires an SEIA. It involves making a preliminary determination of the expected impact of the development on the environment and the community, and the relative significance of each impact. A certain level of basic information about the proposed development and its location is required for this purpose. The time taken to complete the screening process depends upon the type of development, the environmental setting and the degree of experience of the assessors or understanding of its potential impacts. Specific methods used in screening include: • A legal or policy definition of developments to which SEIA does or does not apply • An inclusion list of projects (with or without thresholds) for which an SEIA is automatically required • An exclusion list of activities that do not require SEIA because they are insignificant or are exempt by law (e.g. national security or emergency activities) • Criteria for case-by-case screening of proposals to identify those requiring an SEIA because of their potentially significant environmental effects This process establishes the basis for scoping, which identifies the key impacts to be studied and establishes terms of reference for an SEIA. If external funding is required the lenders requirements may, in some cases, be more stringent than the local regulatory regime.

12.2.2 Scoping Scoping identifies the issues that are likely to be of most importance during the SEIA and differentiate them from those that are of little concern. It is a critical step that represents an early, open and interactive process of determining the major issues and impacts that will be important in decisionmaking on the proposed development and which needs to be specifically addressed in an SEIA. Typically, this process concludes with the establishment of terms of reference (TOR) for the preparation of an SEIA. Thus, it ensures that SEIA studies are focused on the significant effects and resources are not wasted on unnecessary investigations. The aim and objective of scoping is to: • Identify and engage key stakeholders early in the process • Identify the important issues/impacts to be considered early in an SEIA • Identify the appropriate time and space boundaries of the SEIA study • Identify the information necessary for decision-making • Review existing baseline data (if any) and identify the key gaps in these data in relation to the needs of the SEIA study • Outline a programme of additional data collection to address these gaps • Outline the proposed methodology for impact assessment • Discuss the next steps in the SEIA process

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12.2.3 Terms of reference TOR specifies what the SEIA is to cover, the type of information to be submitted and the depth of analysis that is required. It provides guidance to the developers on how the study should be conducted and managed. It is a flexible document that is revised as further information becomes available (i.e. in response to newly emerging issues or as existing impacts are reprioritised). The TOR generally requires the following points to be covered: • Whether a range of alternatives should be considered, and if so whether they would be less environmentally damaging than the current proposal • The main environmental effects of the proposed development, both within the project area and surrounding environment, and the expected timescale of the impacts • The size and extent of the impacts based as much as possible on quantitative rather than qualitative assessment • The present policy, institutional and legislative situation and future needs • Groups that will benefit from and those disadvantaged by the project • The impact on any rare/keystone species of plant or animal in the area • The impact on human health • The control and management aspects of the project, to determine if they will be effective • The need for further baseline data collection or other specialist studies • The mitigating measures needed and how they should be incorporated into the project design • The monitoring and evaluation activities that are required to ensure that mitigating measures are implemented and future problems are avoided

12.2.4 Social impact assessment (SIA) In the past, environmental impact assessments (EIA) focused on direct and indirect biophysical impacts of proposed developments (i.e. impacts of development activities on water, air, land, flora and fauna). In recent years, the impacts of industrial development on society, culture and different forms of economic activity have gained equal importance, thus traditional EIA has developed into SEIA. Social impact assessment (SIA) is the systematic analysis used during SEIA to identify and evaluate the potential socio-economic and cultural impacts of a proposed development on livelihood and circumstances of people, their families and their communities. If such potential impacts are significant and adverse, SIA can assist the developer, and other parties to the SEIA process to find ways to reduce, remove or prevent these impacts from occurring. The SIA will: • Describe the current social and economic conditions of the area concerned • Predict the positive and negative effects of a project on people and communities • Identify ways to reduce negative effects and improve positive effects • Dhow changes caused by the project will be managed and monitored It also provides a forum for planning how to maximise the beneficial impacts of a proposed development. These can include a better standard of living owing to increased access to employment, business opportunities, training and education; greater access to and from a community; and increased funding to improve social infrastructure and cultural maintenance programmes.

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SEIAs can address issues such as, but not limited to demographics, socio-economic matters, social infrastructure, resources, psychological and community aspects, cultural property and social equity, which are discussed briefly below.

12.2.4.1 Demographics Demographics include changes in the size and make-up of a population due to migration of people in search of work, emigration from an area because of safety or security issues or any other reasons.

12.2.4.2 Socio-economic Socio-economic issues can include: • Taxes and royalties: expected payments to different levels of government (national, regional, local); time profile of payments • Supply chain impacts: local sourcing opportunities; potential inflationary impacts on local markets for goods and services; impact on non-oil-and-gas-sector industries (e.g.dutch disease ) • Employment: labour practices; changes in existing industries as workers shift from traditional industries to oil and gas activities; movement of other necessary workers (e.g. teachers and police) into the oil and gas industry as translators or security personnel; return of construction workers to lower end jobs • Time profile of projects: construction boom; operation phase; decommissioning; potential oil and gas dependencies.

12.2.4.3 Social infrastructure Social infrastructure issues comprise the adequacy of health care and education facilities, transport and roads, power supply and fresh water supply to support project activities and personnel as well as for the community.

12.2.4.4 Resources Resource issues are land-take for facilities and resettlement, new or increased access to rural or remote areas, and the use of natural resources.

12.2.4.5 Psychological and community aspects Changes from traditional lifestyles, community cohesion, attitudes and behaviour, and perception of risk are considered in an SIA.

12.2.4.6 Cultural property Cultural property is defined as sites and structures with archaeological, historical, religious, cultural or aesthetic values that may be changed or have their access limited by a proposed development.

12.2.4.7 Social equity Social equity identifies those who benefit and those at a disadvantage as a result of the project or operation.

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12.2.5 Health impact assessment The development of natural resources, urban development, the expansion of transport systems and other infrastructure all precipitate changes to environmental and social determinants of health such as: • Income and social status • Education • Physical environment • Social support networks • Genetics • Health services • Gender The resulting health outcomes can be negative or positive. Health impact assessment (HIA) provides an important decision-making tool through which health issues can be addressed early in development planning and design. Like other impact assessment processes it proposes a systematic process for screening, scoping, assessing, appraising and formulating management plans to address key issues in development project implementation. HIA is a fast-growing field that helps policymakers take advantage of these opportunities by bringing together scientific data, health expertise and public input to identify the potential and often overlooked health effects of proposed developments. It offers practical recommendations for ways to minimise risks and capitalise on opportunities to improve health. HIA gives federal, tribal, state and local legislators, public agencies and other decision makers the information they need to advance smarter policies today to help build safe, thriving communities tomorrow. The HIA: • Looks at health from a broad perspective that considers social, economic and environmental influences • Brings community members, business interests and other stakeholders together, which can help build consensus • Acknowledges the trade-offs of choices under consideration and offers decision makers comprehensive information and practical recommendations to maximise health gains and minimise adverse effects • Puts health concerns in the context of other important factors when making a decision • Considers whether certain impacts may affect vulnerable groups of people in a number of different ways Health impact assessment focuses on community health and is generally integrated with the socioeconomic survey, with questions on health included in the household surveys undertaken in projectaffected communities. Information from a desktop literature reviewis used to inform the questionnaire formulation. The heath issues that have the potential to be impacted by the project include: • Organisation of the health care system • Overall health status • Infectious diseases • Non-communicable diseases.

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Overlap with the social and environmental aspects that include health issues are often dealt with in other parts of the SEIA, for example air, water, food, and soil and demography, economics and education. The typical effects that a pipeline project and associated development can have on the health of local communities include: • Introduction of non-local workers, mostly males, to certain localities including construction camps.These workers are sometimes subject to operating rules that allow for, or restrict interaction between workers and local people. • Potential for an increase in communicable diseases arising from interaction between workers and local people • Storage and handling of food and drinks in accommodation/camps and increase in disease from vectors such as rodents if food and drink is not stored properly • Increased risk of respiratory illnesses from changes in air quality (such as dust) • Road traffic accidents and disturbance to sleep from increase noise levels • Increased hazards from solid and liquid waste disposal and potential for water-borne diseases if waste management is not implemented effectively • Open excavations and potential for accidents and injuries • Conflicts between community members and security personnel • Increase in drug and alcohol abuse • Spread of new diseases to indigenous communities • Impacts on health of operations personnel • Impact of local diseases on workers and the spread of pandemics such as HIV and sexually transmitted diseases. Baseline data informs operator and contractor surveillance and control programmes for infectious diseases, security and logistical issues such as supply of drinking water, waste management and access to medical facilities.

12.2.6 Ecosystem services A relatively recent addition to SEIA is the inclusion of ecosystem services, but it is too early to say how these may have an effect on the SEIA process. However, it is intended that these services will assist decision makers in the determination of projects and the interaction on complex natural ecosystems and their dependent human populations. Assessment of ecosystem services is likely to focus on the interaction of development on resources such as food and minerals, waste generation, climate change, disease, nutrient cycles, crop pollination and cultural and recreational benefits.

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12.3 Description Of The Project An integral part of the scoping and SEIA process is the description of the project that includes: • Route selection, including alterative options considered, routeing corridors and eventual route selection by the client, engineers, and environmental and social practitioners. This is done with due considerations to above ground installations (AGIs) such as block valves, pigging, compressors, cathodic protection, storage and import/refining facilities • The nature and scale of specific activities involved during construction, operation and decommissioning, including quantification of emissions and construction/operation activity • Quantifying the project description (emissions, traffic, noise, logistics, waste generation, use of hazardous materials, camp/lay-down) • The geographical location and environmental setting for the project, and baseline environmental, social and cultural information • The use of materials, including their life-cycle and carbon footprint assessment In most cases the design engineers and client take responsibility for providing the written project description. The section should clearly demonstrate the evolution of the proposed route and engineering design to demonstrate that social and environmental considerations have influenced the design, including design changes as a direct result of stakeholder consultation. The project description may include examples of specialist techniques or innovative solutions which may include early input from pipeline contractors.

12.3.1 Routing Web-based tools to assist with the development of route options are useful but no substitute for a walkover survey or drive through of the route with a team of experienced pipeline practitioners, engineers, contractors,field geologists, archaeologists and ecologists to look at pinch points, topography, access routes, geomorphology, crossings, construction methodology and unavoidable protected areas.

12.3.2 Timing SEIA typically occurs before and during front-end engineering design (FEED) when pipeline routeing is being defined. SEIA practitioners are used to working with the engineers in the definition of constraints within ever-decreasing pipeline route corridors. A close working relationship between the SEIA team and the engineers is important, as exchange of information early in the process on environmental issues such as potential pinch points, ground conditions and other constraints may influence engineering design and the eventual construction methods employed. The timing of route selection is critical if a rigorous ESIA is to be undertaken which and the consent obtained.. Insufficient engineering design and a poorly considered SEIA can lead to rejection by the authorities and extend the time for consent. Without consent a pipeline project cannot be built. In the event that options still exist for the routing or engineering design (for example details of the exact nature of the methodology for river crossings) when the consent has to be submitted, the worst case scenario should be assessed together with an outline of other potential construction options. It will then be down to the regulator to determine whether this is acceptable. If there are too many options presented, this may cause delays or even refusal of the consent for the project.

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12.3.3 Project description The project description should be as accurate as possible, but one needs to also bear in mind that detailed engineering is still progressing and hence changes could still occur. This section of the SEIA also presents a description of the proposed works required to complete the project and a` description of the equipment that will be operated during the project lifetime. It should also cover the extent that the activities envisaged for planned routine maintenance of the equipment and for corrective maintenance of faulty equipment at this stage. Furthermore this section addresses the engineering aspects of the project that are the focus of the assessment during its life cycle, which will include the proposals that have been developed to facilitate eventual decommissioning of the facilities. It is easier to undertake the impact assessment using as much quantification in the project design as possible. Quantities and type of waste, amount of water use, number of vehicles to move materials, size of loads/vehicles, lengths of pipe, location and numbers of camps, location of access routes and numbers of construction personnel are all the types of data that can be extracted from typical pipeline projects and should be used. In the event that these subsequently change it is relatively easy to justify and explain the significance of the change.

12.4 Applicable Laws And Regulations As part of an SEIA, it is very important that the relevant laws as well as environmental protection legislation is stated, understood and analysed within the document. Legislation may include a statutory requirement for an SEIA to be carried out in a prescribed manner for specific development activities. When carrying out an SEIA it is essential to be fully aware of the statutory requirements and the legal responsibilities of the concerned institutions. Additionally, a list of all the applicable laws and by-laws, regulations and statutory requirements should be developed and included. In addition, an SEIA should be able to assess the acceptability or severity of impacts in relation to legal limits and standards. Lendersâ&#x20AC;&#x2122; requirements should be stated where necessary. Lenders should be signed up to the Equator Principles, which are a voluntary set of standards for the management of social and environmental risks in project financing. Additionally, operatorsâ&#x20AC;&#x2122; internal best practice guidelines should be taken into account. The SEIA should specify the measurements (generally the most stringent of the regulatory requirements) that will be applied to the project design. Regulatory consent for a project typically includes reference to the SEIA or ESMMP as consent conditions which require formal reporting, audits and licences to be issued prior to construction works commencing. Legal review is typically undertaken by the developer/partners and their funding partners.

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12.5 Description Of Alternatives Descriptions of the alternatives studied during engineering feasibility and early route options are included in the SEIA report. The descriptions generally include a high-level review of alternative options to a pipeline and justification for the selected project, as well as a description of the route options and constraints within the area of search. For some aspects of the project, it is necessary to consider alternative design solutions. For each one, this part of the SEIA presents the options that were assessed and the reasons why the solution adopted in the final design is preferred. These include cost considerations, construction or operational difficulties, as well as environmental and social considerations. A ‘no development’ option is also researched and detailed.

12.6 Description Of Baseline Potential route options are further developed in a series of pipeline route corridors, early in the SEIA process. In some cases this requires baseline surveys, landowner investigation and desk-based research to be progressed in parallel for a range of route options. As the route selection process is refined, detailed surveys can be designed to address gaps in information identified in the desk-based assessment. The nature, extent and seasonality should be agreed with the regulators (generally as part of the scoping assessment). Baseline surveys and reports will form the basis of the environmental baseline description of the SEIA and will typically include: • Ecology (botany and zoology) • Agriculture and land use • Topography and soils • Geology, geomorphology and geohazards (seismic risks) • Meteorology and climate • Landscape and visual • Hydrology and flood risk • Hydrogeology and aquifers • Background noise • Air quality and climate change • Archaeology and cultural heritage • Socio-economics and demographics • Land ownership and land use • Employment skills and livelihoods • Infrastructure and services • Traffic and transport • Community health • Unexploded ordnance • Contaminated land

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Constraints maps using geographic information systems (GIS), aerial photography and satellite imagery are built up from the baseline data and used to further refine the route with the engineers. Data is likely to be collected from and inputted by a variety of sources. It is therefore important that the GIS system uses agreed projections, feature classes and individual attributes so that the global positioning systems (GPS) used in the acquisition of field survey data are compatible with the structure of GIS system. The exchange of constraints data on its own to the engineers is important, however it is vital that a description of the type and extent of any constraints are also provided so the engineers can assist in the formulation of practical mitigation measures. Agreement on terminology (kilometre points/chainage/GPS coordinates) reduces the potential for misunderstandings. Agreed mitigations are documented in the SEIA report, associated constraints maps and management plans. As surveys are completed it is useful to consult with the regulatory authorities and allow them to review the baseline reports ahead of completion of the impact assessment. In some cases regulators may have additional information or insight into the local conditions, which may be useful in the impact assessment process. This is typically done in the form of a preliminary environmental information or social and environmental baseline report. The baseline report is subsequently amended in line with comments and included in the SEIA.

12.6.1 Seasonality Seasonal restrictions may prolong the SEIA timescale, and sufficient time should be left to collect representative samples of environmental and social baseline. The scoping report should provide an indication of any restrictions to survey effort as a result of seasonality in agreement with the regulators. In some cases data from two seasons is required to obtain a representative sample. Licences or restrictions may need to be obtained to undertake surveys at specific times of year, for example nesting, breeding and spawning periods. At other times of year it is easier (or more difficult) to identify species due to hibernation or moulting periods. Typical UK survey timings are shown in Figure 3.

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Figure 3: An Example of UK Environmental Survey Timings

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12.7 Consultation Stakeholders are persons or groups who are directly or indirectly affected by a project, as well as those who may have interests in a project and/or the ability to influence its outcome, either positively or negatively. Stakeholders may include locally affected communities or individuals and their formal and informal representatives, national or local government authorities, politicians, religious leaders, civil society organisations and groups with special interests, the academic community or other businesses (International Finance Corporation (IFC), 2007). Large projects may also consist of a consortium of companies and lenders who will also act as stakeholders and will need their own reporting requirements one of whom may be the ultimate operator. Stakeholders share information and knowledge, and may contribute to the development so as to enhance its success. It is therefore very important to identify and list these groups early in the SEIA process. The range of stakeholders involved in an SEIA typically includes: • Individuals, groups and communities who are affected by the proposed development • The proponent and other project beneficiaries • Government agencies • Non-governmental organisations (NGOs) and interest groups • Others such as donors, the private sector, academics, etc. Public involvement is specifically a valuable source of information when identifying key impacts, potential mitigation measures, landowners and the selection of alternatives. It also ensures the SEIA process is open, transparent and robust, and is characterised by defensible analysis. Consultees can also provide information on the future projects or planned constraints that may affect routeing or the location of specific AGIs and temporary construction and accommodation camps. The stakeholder consultation process should be documented in the public consultation and information disclosure plan (PCDP) and SEIA, and any changes to the project design attributed to stakeholder consultation should be described.

12.7.1 Public consultation and information disclosure plan (PCDP) Many financial institutions and governing bodies now have policies and requirements regarding public consultations and disclosures within their SEIA system to ensure that projects in which they invest are implemented in an environmental, timely and socially responsible manner. These requirements vary widely depending on the particular SEIA system: most, if not all, nowadays require some public involvement as part of the SEIA process, while others require extensive consultation and reporting. There is growing recognition that the public has the right to meaningfully participate in the SEIA process. Some regulatory authorities have even specified that the public must be properly consulted, even when there is no law specifically governing the process. The PCDP is a public document that sets out the company’s commitments relating to stakeholder engagement, consultation and disclosure, and is to be updated for each phase of the project. A PCDP, prepared early in the scoping phase, provides the following benefits: • Ensures transparency and involvement of stakeholders in assessing and managing the potential environmental, socio-economic and health impacts of the project • Identifies and involves all potentially affected groups and individuals

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• Improves decision-making and builds understanding by actively involving key project-affected stakeholders in two-way communication. Through this process, the proposed development better understands the concerns and expectations of stakeholders, and the opportunities to increase project value to the local community • Identifies issues early in the project cycle that may pose a risk to the project or its stakeholders • Ensures that mitigation measures are appropriate (implementable, effective, and efficient) • Establishes a system for long-term communication between the project and communities that is of benefit to all parties During the SEIA process consultations start at an early stage and project information is provided in advance. The proposed development sponsor usually consults stakeholders at least twice; once during scoping before the TOR for the SEIA are finalised, and again once the draft SEIA is ready for circulation to the relevant consultees. In addition, the owner/operator consults with such groups throughout project implementation to address SEIA-related issues that affect them. Despite a number of guidance documents on principles and methods surrounding public involvement programs, there are no set rules about how to involve the public and it is important that the process remains innovative and flexible. It is therefore important to understand how decisions are made locally and what the methods of communication, including available government extension services. Stakeholder consultations can be conducted in different forms (both formal and informal), but not limited to: • public meetings • semi-structured interviews • focus groups • face-face meetings The range of groups outside the formal structure with relevant information is likely to include; technical and scientific societies, NGOs, experts on local culture, and religious groups. However, it is important to find out which groups are under-represented and which ones are responsible for, or have a high influence over access to natural resources (i.e. grazing, water, fishing and forest products).

12.7.2 Consultation disclosure The SEIA process needs to demonstrate that stakeholder concerns have been identified and taken into account. Examples of mitigation commitments designed to deal specifically with stakeholder concerns may comprise: • Land acquisition and livelihoods, including clear guidance on land acquisition and compensation (setting out the principles and key mechanisms by which livelihoods would be maintained) for those individuals likely to be affected by land acquisition. Access for livestock to grazing lands, watering holes and public rights of way will be maintained or, if restricted, to the minimum extent reasonably practical • Infrastructure damage, including a commitment relating to avoiding damage and to repair where any damage occurs • Employment opportunities, including commitments setting out the policies for employing local people if the required skills are available. Targets for local recruitment can be set and monitored to assure that this commitment is met • Pollution: Commitments may be applied to suppressing dust and lowering noise to acceptable levels. Monitoring to assure that the commitments are being applied and achieving their objectives is likely to be needed.

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12.8 CHARACTERISTICS OF POTENTIAL IMPACTS AND THEIR EXTENT Several factors influence the characteristics of potential impacts and are taken into account when predicting impacts and making decisions. They include: • The nature of the impact (positive, negative, direct, indirect, cumulative) • The magnitude and complexity of the impact (severe, moderate, low) • The extent/location (geographical area and size of the affected population) • Timing (during construction, operation, decommissioning, immediate, delayed, rate of change) • The duration of the impact (short term, long term, intermittent, continuous) • The reversibility/irreversibility of the impact • Probability (likelihood, uncertainty or confidence in the prediction) • The significance of the impact (local, regional, global).

12.8.1 Impact assessment The most common impacts are those that are directly related to the proposed development and have a direct correlation with the actions that caused them. Typical examples of direct impacts are destruction of habitat caused by forest clearance; relocation of households caused by reservoir impoundment; and increased air particulate emissions caused by operation of a new power station or, as in the case of a pipeline, the use of gas compressor trains or water bath heaters. Indirect or secondary impacts are changes that are usually less obvious, occurring later in time or further away from the impact source. Examples of these types of impacts are the spread of malaria as a result of drainage schemes that increase standing water and thereby create new vector habitats; bio-accumulation and bio-magnification of contaminants in the food chain through take up of agricultural pesticides; and anxiety, stress and community disruption associated with increased traffic volumes, or construction camp locations and noise/vibration caused by road development. While defining the characteristics of the impact, estimating the magnitude of the impact is also a primary task. Typically, it is expressed in terms of severity, such as major, moderate or low. It also takes account other aspects such as whether an impact is reversible and, if so, the likely rate of recovery. Attempts should be made as much as possible to quantify the impact. The extent or zone of impact influence can be predicted for both site-specific and regional occurrences. Depending on the type of impact, the variation in magnitude needs to be estimated, for example, alterations to range or pattern of species or dispersion of air and water pollution plumes. This is much easier for direct impacts but is not as straightforward for other types of impacts e.g. indirect and cumulative impacts. Impacts arising from all of the stages of the life cycle or phases of the project, such as construction, operation and decommissioning, should be considered. Some impacts occur immediately, while others are delayed, sometimes by many years. These impact characteristics are noted in the SEIA report. Some impacts may be short-term, such as the noise arising from the operation of equipment during construction while others may be long-term, such as the operation of process plant. Certain impacts such as blasting may be intermittent, whereas others, such as electromagnetic fields caused by power lines, may be continuous. Impact magnitude and duration classifications can be cross-referenced, for example, major but short term (less than one year), low but persistent (more than 20 years).

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Cumulative effects can accumulate with time either incrementally (or additively) or interactively (synergistically) so that the overall effect is larger than the sum of the parts. These impacts may be individually minor but collectively significant because of their spatial concentration or frequency in time. The evaluation of significance at SEIA stage depends on the characteristics of the predicted impact and its potential importance for decision-making. Significance is evaluated in terms of environmental loss and deterioration, social impacts resulting directly or indirectly from environmental change, and/or nonconformity with environmental standards, objectives and guidelines.

12.8.2 Impact assessment and commitments register Impact assessment is the systematic assessment of the potential effects of a development on the social, cultural and environmental baseline. There is no prescribed method of impact assessment, and different projects will adopt different approaches. However, all seek to identify the potential impacts arising from the project and will apply either standard, recognised, industry-practice mitigation measures or impactspecific, feasible and cost-effective mitigation measures to minimise the potential effects. The impact assessment methodology takes account of potential impacts on a wide range of receptors including: â&#x20AC;˘ The physical and chemical environment (e.g. climate, air quality, soil and groundwater quality) â&#x20AC;˘ The biological environment (e.g. plants, terrestrial animals, birds and their food chains) â&#x20AC;˘ Communities, social groups and individuals (e.g. employment generation, changes in per capita incomes, threats to vulnerable groups and exposure to health and safety risks). The principles of SEIA are now widely established. All major projects will cause some changes to the environment. In the past the SEIA process mainly identified what these changes would be and, after proposing mitigation, reported them to the decision maker. As SEIA has evolved the emphasis has moved on to the reduction of potential adverse impacts and maximising potential benefits through appropriate design measures. Designing out the significant effects of a project is the central tenet of the approach. Impact assessment is an iterative process, the aim of which is to design out or minimise potential impacts and to do so in a way that prioritises those that are potentially most significant. The assessment process constitutes a systematic approach to the evaluation of the proposed project in the context of the natural, regulatory and socio-economic environments in which development is proposed. Potential impacts arising from the project are identified, and mitigation measures agreed. These can be either recognised industry best practice mitigation measures they should however be feasible and costeffective. Any potential impacts that remain after the application of mitigation measures are referred to as residual impacts. All residual environmental and social impacts are assigned a level of impact of low, medium, high or beneficial. Impacts may be assessed without mitigation then again after mitigation is applied. Residual environmental and social impacts are then described. The objective being to identify mitigation measures which reduce the potential effect before mitigation to a reasonable and acceptable level. Where appropriate, other mitigation options considered in the assessment and the reasons for their rejection can be presented.

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The mitigation measures are typically compiled into a commitments register which sets out all the measures that the project proposes to adopt in relation to potential impacts identified in the SEIA. Mitigation measures include those incorporated into the engineering design process, as well as those proposed for construction, operation and decommissioning. The commitments register should be read in conjunction with the full text of the SEIA document, which provides important context and background, as well as describing the impacts that the listed measures aim to mitigate or manage and the residual impacts that may remain. The SEIA should clearly set out the methodology and legal standards that are being applied to the assessment process. Seeking early agreement with the regulatory authorities early in the project, as part of the scoping/consultation exercise, may also reduce the timescale for consent.

12.8.2.1 Example methodology The residual environmental and social impacts are assigned a level of significance based on the importance/sensitivity of the receptor and the magnitude of that impact. For each impact an importance/sensitivity ranking between A and E, and an impact magnitude ranking of between 1 and 5 is applied using categories of importance/sensitivity of the receptor and magnitude, which are described independently for each topic based on legal guidelines, codes of practice etc. The significance level of the residual impact can then be determined using a matrix such as that in Figure 4.

Figure 4: Typical significance matrix All residual impacts identified from the impact assessment are given a significance ranking with the terms low, medium and high representing a comparative scale. Where an impact is of medium or high significance, it is addressed in greater detail in the text. The SEIA may chose to detail any beneficial impacts (such as employment and local investment as well as impacts of low significance that are deemed to warrant further explanation. Documented commitments form the basis of the environmental and social mitigation and management plans (ESMMP) for construction and operation. They will include generic and site-specific commitments.

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12.8.3 Cumulative and secondary impacts Secondary impacts are a complex element of impact assessment and subject to diverse guidance and application2. They are an integral part of the impact assessment. Direct impacts are relatively easy to assess, whereas those that have an indirect, cumulative, in-combination effect are, by their own nature, more complex. Impact-assessment evaluation techniques include the use of matrices, expert opinion, modelling and carrying capacity analysis, and combinations of these techniques can be applied. However, it is best to keep this process as simple as possible with a clear explanation of the methodology adopted. Cumulative impact assessment generally covers those other development projects which are in the public domain. However prediction of potential effects is often limited by the difficulty in obtaining data in sufficient to undertake a rigorous impact assessment 2

EC DGX11 Guidelines for the assessment of indirect and cumulative impacts as well as impact interactions http://ec.europa.eu/environment/eia/eia-studies-and-reports/guidel.pdf

12.8.4 Unplanned events The majority of the impact assessment process considers the potential effects of the construction and operation of the pipeline and operating facilities under normal operating conditions. However there is a requirement to look at the potential for unplanned events. This section in the SEIA will include a summary of the engineering risk assessment and major accident hazard assessments undertaken during detailed engineering design. Emergency response measures and operational controls will also be explained in this section. The impact assessment criteria in this section generally includes an explanation of likelihood of an event occurring.

12.8.5 Mitigation of impacts Mitigation is a critical component of the SEIA process that aims to prevent adverse impacts from happening or reduce the severity of impacts to occur within an acceptable level. The objectives of mitigation are to: • Find better alternatives and ways of performing tasks • Enhance the environmental and social benefits of the proposed development • Avoid, minimise or improve adverse impacts • Ensure that residual adverse impacts (i.e. those impacts remaining after mitigation) are kept within acceptable levels Early links are established between the SEIA and project design teams to identify mitigation opportunities and incorporate them into consideration of alternatives and design options. In practice, mitigation is emphasised in the SEIA process once the extent of the potential impact of a proposal is reasonably understood. This typically takes place following impact identification and prediction. Once identified, these mitigation measures are implemented during the impact management stage of the SEIA process. The objectives of impact management are to: • Ensure that mitigation measures are implemented • Establish systems and procedures for the implementation of these measures • Monitor the effectiveness of mitigation measures • Take any necessary action when unforeseen impacts occur

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12.9 ENVIRONMENTAL AND SOCIAL MANAGEMENT AND MONITORING PLANS Critical to the successful implementation of the commitments and mitigation measures within this SEIA is the development of a commitments register. The construction-phase commitments are tracked through from the commitments register in the SEIA to environmental and social management and monitoring plans (ESMMP), which will form the environmental and social management system (ESMS) in the construction phase. The ESMMP should also be included in the invitation to tender (ITT) for the construction contractor(s), and implementation of the management plans it contains should become contractually binding. Where the measures to be implemented can be clearly identified/quantified then they should be priced and executed at the contractor’s risk. Where the measures cannot be clearly identified then budgetary allowances (in terms of costs and programme) should be made by either the contractor or the client. The contract should clearly allocate responsibility for unquantifiable measures to either contractor or client. Monitoring during the construction and operational phases of the project, through the audit of impact predictions and mitigation measures, will assure: • Mitigation measures are implemented effectively • Mitigation measures are appropriate and, if not, that they are amended or additional measures are designed and implemented • Compliance with project standards, guidelines and best practice as applicable • Assessment of cumulative and residual impacts, so that appropriate measures can be designed if necessary • The continuation of the SEIA as an iterative process, through the construction and operational environmental and social management systems, will be based on continual improvement Operations-phase commitments are incorporated into an integrated ESMS. The objectives of the ESMMP are to: • Help the developer to achieve its intended environmental and social management outcomes and mitigate the project’s identified environmental and social impacts to the levels predicted in the SEIA • Describe the requirements that the contractor should meet to ensure that the commitments made in the SEIA for the project are fully implemented • Provide a mechanism to achieve compliance with consent conditions and legal obligations and demonstrate conformance with developers environmental and social policies • Provide a framework for the contractor to develop environmental and social implementation plans to address the commitments and requirements in the ESMMP, including method statements taking account of local conditions. The environmental and social implementation plans are developed by the contractors to allow some flexibility in approach and construction techniques/machinery. The method statement may require regulatory approval The client may undertake some of the commitments. A clear description of the responsible party, location and timescale should be included in the ESMMP. The ESMMP may also describe the environmental and social performance criteria (key performance indicators(KPIs)) for the project and also the auditing, reporting and monitoring requirements.

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The project’s ESMMP is the primary mechanism for implementing the measures listed in the commitments register. The ESMMP forms the basis of contractual agreements between the project and the main contractors involved in project construction. The ESMMP is likely to include topic-specific management plans such as those listed below: • Reinstatement/biorestoration plans (translocation/nursery/contract growing) • Emergency response plans • Health and safety plan • Security plan • Ecological management plan • Waste management plan • Pollution prevention plan • Resources management plan • Construction camp management plan • Infrastructure and services management plan • Community health, safety and security plan • Community liaison plan • Local recruitment and training plan • Procurement and supply plan • Cultural heritage management plan • Land management plan • Traffic management plan The ESMMP is provided to the contractor as part of the tender for construction so that commitments are included in the construction costs and contractor implementation plans. These may be integrated with the contractors documented and operational ESMS (such as the international standard ISO 14001 environmental management system). Some elements of the commitments are implemented by the developer using specialist contractors prior to appointment of the contractor, which typically includes preconstruction commitments such as archaeological investigations, translocation of ecology and land acquisition. The roles and responsibilities of the developer and contractor(s) should be clearly defined. Operational management and monitoring plans will be developed to implement operational commitments before the project moves to the operations phase.

12.9.1 Construction phase ESMMP The ESMMP is not a legally binding document, however it may form part of the consent conditions granted by the regulatory authority. While it draws on and replicates commitments made in the main body of the SEIA, it does not make (and should not be read as making) any new, amended or additional commitments by the project. The definitive source for all commitments made in this SEIA is the commitments register. The ESMMP is a tool designed to help implement those commitments and is considered a ‘live’ document that is likely to evolve during the lifetime of the project to encompass the construction and commissioning phase. The plans will be updated to include regulator and stakeholder feedback. The ESMMP provides details of how the project proposes to implement and monitor the commitments made in the SEIA.

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The construction-phase ESMSs will include the ESMMP, which describes: • The legislative framework for the project • Guidance for international industry good practice • Roles and responsibilities of the client/developer and the contractor • The actions required to avoid and mitigate environmental and social impacts and to put the commitments in the SEIA into effect • The monitoring and reporting requirements for environmental and social performance • The requirement to carry out inspections and audits, and to implement corrective actions using an action tracking system The ESMMP typically contains several management plans depending on the client’s requirements and the nature of the project. A sample is listed below: • Reinstatement plan: o Topsoil and sub-soil management o Erosion control during (e.g. at crossings, steep slopes, trench breakers) and after construction o Engineered reinstatement of right of way (ROW) and watercourse crossings o Seeding and matting • Landscape management plan: o Existing land use o Landscape plans o Landscape protection before and during construction o Seeding and re-vegetation objectives/erosion control o Maintenance works of both existing and new vegetation o Monitoring and reporting • Ecological management plan: o Ecological training o Location of protected species and sensitive areas o Preconstruction ecological surveys o Habitat and species protection before and during construction (e.g. working width restriction, translocation, avoiding seasonal sensitivities, traffic restrictions, code of conduct, aquatic environment protection) o Biorestoration (e.g. re-vegetation, selection and procurement of seeds, seeding methods, seed collection, replanting) o Monitoring and reporting • Waste management plan: o Waste management training o Identification and classification of waste o Waste hierarchy and waste minimisation strategy (i.e. reduction at source, reuse, recycling, energy recovery, responsible disposal) o Waste handling (i.e. collection, segregation and containers, storage and treatment, transport and documentation, disposal) o Monitoring and reporting • Pollution prevention plan: o Pollution prevention training o Energy efficiency (vehicle and equipment selection and maintenance) o Emissions and dust management (i.e. vehicle, equipment and generator emissions, dust management) o Wastewater management (e.g. run-off, trench dewatering, hydrotest water disposal and use of chemicals in hydrotest water, vehicle and equipment washing) o Sewage treatment and disposal

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o Noise and vibration management o Oil and chemical management (i.e. storage, handling and spill prevention) o Treatment of contaminated soil o Management of hazardous liquid waste o Monitoring and reporting Resource management plan: o Training (incl. energy efficiency and water use minimisation) o Aggregates management (estimation of requirement, identification of quarries and borrow pits, transportation, control of third parties) o Water management (water supply, hydrotest water abstraction o Construction camp management plan o Consultation with local communities before construction camp is developed o Restriction of access to camp and use of its facilities o Training (including induction briefing on camp rules and awareness of local issues and sensitivities) o Camp rules (e.g. discipline and restrictions on alcohol, drugs, noisy activities and illegal activities, community liaison, ethnic tensions, market distortion and communicable diseases) Infrastructure and services management plan: o Disruption to infrastructure (transport, electricity, irrigation) o Prevention and repair of community infrastructure damaged by project activities o Management of disruption to communities and individuals o Community health, safety and security plan o Worker–community interaction (e.g. spread of communicable diseases) o Management of construction sites (e.g. access to ROW and open-trench philosophy) o Traffic safety (e.g. control of traffic flows through villages) Community liaison plan: o Community liaison officer (CLO) requirements o Maintaining good relations with communities, landowners and land users (e.g. meetings, complaints management procedure) o Community access Local recruitment and training plan: o Local recruitment for construction-phase workforce o Skills and HSE training (for all personnel) including induction training o Retrenchment Procurement and supply plan: o Maximising local procurement of goods and services o Transparency of procurement process Cultural heritage management plan: o Ensure avoidance of heritage site impacts o Mitigation measure to reduce impact to heritage sites where avoidance is not possible o Protection of heritage sites during construction o Monitoring and reporting of results Land management plan: o Assessment of additional land o Spoil disposal sites and borrow pits o Land acquisition and compensation requirements o Monitoring and reporting Emergency response plan o Location of response equipment and response times o Local government arrangements o Joint industry arrangements o Training

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The ESMMP should include in the introduction the allocation of responsibilities for development of implementation plans relating to each management plan. The construction contractors will be required to develop an ESMS, including implementation plans that are in line with the management plans in the ESMMP and give details of how commitments will be implemented and monitored. The construction contractors will submit implementation plans for approval before construction begins. The contractorsâ&#x20AC;&#x2122; implementation plans and associated procedures and method statements will be checked by the client, and/or regulators to ensure they incorporate the relevant environmental, social and cultural heritage requirements stated in the ESMMP. The implementation plans and method statements may be incorporated into consents and agreements with the regulators. Once the plans are approved, any changes will need to be revisited and approved. The public consultation and disclosure plan (PCDP) for the project provides the structure for effective management of consultations with third parties during the design and construction stages of the project. The PCDP and associated stakeholder consultation database are live documents and will be updated as necessary during the project to reflect the status of planned activities.

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12.10 Transboundary Effects Transboundary impacts are impacts that cross the border into neighbouring countries which may be as a result of planned or unplanned events. The 1991 Espoo Convention on Environmental Impact Assessment in a Transboundary Context sets out a process by which countries that are party to the convention inform each other of projects that can have transboundary impacts. The cumulative impact assessment identifies those environmental and/or socio-economic aspects that may not constitute a significant impact on their own, but when combined with impacts from past, present or reasonably foreseeable future activities associated with a proposed development and/or other projects may result in a larger and more significant impact(s). Examples of such impacts include: • The recurring loss of habitat in areas that are disturbed and re-disturbed over an extended period • Additional emissions as a number of projects are developed at the same time or a processing plant or pump station is expanded over a period of time • The on-going development of employment opportunities and enhancement of a local labour skills base as successive projects (related or unrelated) come on stream

12.10.1 Carbon measurement and assessment In the EU, the Environmental Impact Assessment Directive (as amended) requires the consideration of direct and indirect effects of development projects on ‘climate’ (Article 3) and ‘climatic factors’ (Annex IV). Despite these requirements, calculating the greenhouse gas (GHG) emissions (or “carbon footprint”) of a project is a relatively recent approach to impact assessment, and is a separate consideration to those emissions that affect air quality given the very different nature and scale of the impacts. For pipeline projects, sources of GHG emissions may include: • Manufacture of pipe work and associated materials and infrastructure • Transportation of the above materials to the site • Impacts to, or losses of, natural carbon sinks such as peatland or forestry during route preparation • Energy consumption (i.e. fuel or electricity) from site activities • Transport and accommodation of site workers • Waste arisings (depending on their treatment) • Construction equipment for pipeline construction • Fugitive pipeline emissions Where a project entails pumps and compressors, the driving of these is likely to be the most significant source of emissions. It is therefore important that the selection process includes analysis or comparison of the energy efficiency ratings. The UK Institute of Environmental Management & Assessment (IEMA) published guidance on preparing Climate Change chapters for Environmental Statements [IEMA Principles Series: Climate Change Mitigation & EIA; Version 1.1; 1st June 2010]so that climate change impacts of developments, both positive and negative, are better addressed as part of SEIAs.

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The overarching principles of the IEMA guidance are as follows: • GHG emissions from all projects will contribute to climate change; the largest inter-related cumulative environmental effect • The consequences of a changing climate have the potential to lead to significant environmental effects on topics in the EIA Directive including population, fauna, soil etc. • When GHG emissions have a combined environmental effect that is approaching a scientifically defined environmental limit, as such, any GHG emissions or reductions from a project might be considered significant • The EIA process should, at an early stage, influence the location and design of projects to optimise GHG performance For pipeline projects, opportunities to minimise GHG emissions may include: • Routing to avoid natural carbon sinks such as peatland or forestry • Appropriate management arrangements for any impacted natural carbon sinks (e.g. peat management) • The specification of construction materials with low embodied carbon e.g. recycled aggregates, low carbon concrete, local materials (use of padding machines) • The use of local labour and suppliers • Replacement planting for any tree felling • Consideration of fuel efficiency, driver training and carbon emissions when specifying construction plant and vehicles • The use of zero / low carbon energy technologies to contribute to any energy demands Quantifying GHG emissions associated with different pipeline options at the early stages of a project (e.g. different pipeline routes, materials, construction techniques etc), as recommended by the IEMA guidance, enables the relative carbon performance of each option, and hence climate change effect, to be established and feed into the option evaluation process. GHG emissions resulting from the future use of the fossil-fuels transported in a pipeline is typically excluded from the overall assessment.

12.10.2 Carbon offsets The opportunity may also exist to offset GHG emissions associated with a pipeline project, for example its manufacture, construction and/or operation. A carbon offset is a reduction in emissions of GHGs made in order to compensate for an emission made elsewhere. There are two markets for carbon offsets. Firstly in the larger compliance market, companies, governments, or other entities buy carbon offsets in order to comply with caps on the total amount of carbon dioxide they are allowed to emit. This market exists to achieve compliance with obligations of Annex 1 parties under the Kyoto Protocol, and of liable entities under the EU Emission Trading Scheme. Secondly in the voluntary market, individuals, companies, or governments purchase carbon offsets to mitigate their own greenhouse gas emissions from transportation, electricity use, and other sources. Offsets may be cheaper or more convenient alternatives to reducing one's own fossil-fuel consumption. However, some critics object to carbon offsets, and question the benefits of certain types of offsets. Due diligence is recommended to help businesses in the assessment and identification of "good quality" offsets to ensure offsetting provides the desired additional environmental benefits, and to avoid reputational risk associated with poor quality offsets.

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12.11 LAND EASEMENTS AND WAY LEAVES Land access issues and related planning processes are typically addressed in documents that may be prepared and submitted separately from the overall SEIA, but are at least summarised in the SEIA if not appended and disclosed with it. These stand-alone documents require, as stipulated by international norms such as the IFC’s Performance Standard 5 (2012): • A resettlement action plan (RAP), if there is physical displacement (loss of shelter) or if compulsory acquisition processes, will be used which typically has to be submitted and disclosed as part of the SEIA package or concurrently as a separate document • A livelihood restoration plan or framework if there is no physical displacement and no recourse to compulsory acquisition, which in short is a simplified version of the RAP. The RAP is linked to the Environmental and Social Management and Monitoring Plans (ESMMP) which are discussed in Section 9. The planning process is based on baseline studies that typically include: • An inventory of affected assets and an associated census of affected households, which is required to address 100% of affected assets and people • A detailed socio-economic survey of the baseline circumstances of affected households, which may address only a valid sample in situations where there is no physical displacement; focus should be put on the dependency of livelihoods on the affected land such that a proper understanding of the actual impacts can be developed • Land market and valuation studies • Reviews of the local legislation in light of international requirements and of any establishment agreement (“host government agreement” or similar) that may establish exceptional legal regimes to the benefit of project sponsors In addition to these studies, it is critical that the planning process should be based on intensive consultation with affected people and/or their representatives, particularly in situations where there is physical displacement. Pipelines have two particularities compared with other types of infrastructure: • Discrete impacts on one given household are typically fairly benign: o Physical displacement can usually be avoided by re-routeing o Impacts are experienced for a short period during construction, while impacts at operation stage involve restrictions that typically do not impede the resumption of normal agricultural activities • These relatively benign impacts are often experienced by very large numbers of households: numbers of affected plots in the thousands or even in the tens of thousands are not uncommon for pipelines of several hundred kilometres The following aspects are therefore critical to proper planning and implementation of land access on large pipeline projects: • Start early: Land acquisition and resettlement specialists should be associated as of the initial negotiations of the host government agreements, such that key issues can be identified early and solutions reflected in legal documents • Valuation: Land compensation needs to be based upon fair replacement value (market value plus any transaction costs).Under-compensation is unfair to affected people and would adversely

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impact their livelihoods but over-compensation triggers opportunistic or speculative behaviours and must be avoided too. Hence the importance of robust valuation studies, based on a sound assessment of the actual impacts of construction and of further reuse restrictions, using different and proven assessment methodologies, and based on a proper analysis of agricultural land markets, particularly where such markets are in a formative state, as is the case in many developing or emerging economies • Livelihood restoration: Where pipelines affect predominantly agricultural land, livelihood restoration requires both adequate compensation and proper reinstatement of the agricultural potential of affected land; the involvement of experienced reinstatement specialists, and integration of adequate reinstatement provisions in construction contracts are essential to minimising impacts and associated claims • Resourcing: Where there are thousands of compensation agreements to reach, negotiations with large numbers of affected people for compensation payment and grievance management is a hugely demanding task. Associated resourcing, and the costs thereof, should not be underestimated. An order of magnitude of 10% of the total cost of land access should be used as a “rule-of-thumb” estimate of the cost of planning and administering the process. The construction tender documents should clearly identify responsibility between client and contractor as to who is responsible for: • Obtaining planning or other local regulatory consent in respect of the proposed pipeline route and any other necessary accesses, compounds, camps, offices, pipe dumps; workshops etc. • Who is to negotiate and pay compensation to affected landowners Finally, it is important to note that the cost of land access is not a marginal factor of the overall cost of a pipeline project, even in developing countries (ratios of 3–6% can typically be expected). Properly planning land access is therefore not only a matter of ensuring compliance with international requirements or good practice, but also part of sound economic optimisation of the overall project cost. Long-term easement agreements will confer the rights of access in the long term for maintenance operations and security patrols. The operator will implement such agreements to protect the pipeline in the long term from development, erosion or interference.

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12.12 Hazard And Risk Assessment Environmental hazard and risk assessment (EHRA) and social risk assessment (SRA) are processes whereby the SEIA team can: • Confirm its understanding of the project with the design engineers • Identify to the design engineers areas of potential environmental concern • Jointly develop alternatives so that potential impacts can be avoided where possible or proactively mitigated EHRA/SRA issues are discussed with key project engineers and HSE advisers. These discussions are facilitated by members of the SEIA team and the pipeline and facilities engineering team during the design process. These discussions allow input from all participants in the identification of potential environmental and social hazards associated with project activities. In addition, possible alternatives and options could be evaluated. The process considers each activity that will, or may, occur during the project including: • Planned routine activities • Planned but non-routine activities • Unplanned or accidental activities Existing mitigation measures designed into the project are also considered during these discussions. Hazard analysis and risk assessment studies are included in the SEIA; describing and assessing unplanned events that could potentially cause risks to public safety and harm to the environment. In addition proposed mitigation measures and the strategy proposed that aims to manage the risks potentially associated with a project are also outlined. Risk assessment is both a design tool and a valuable tool for ranking potential risks during the lifetime of a gas or oil pipeline or facility, prioritising operational efforts to reduce the likelihood of leakage and to guide emergency planning. It can be used to assist safety-based decision-making on future land use in the vicinity of the pipelines and facility. The main steps in the risk assessment process are: • Identifying potential failure causes • Estimating failure frequencies • Identifying potential release modes • Estimating release frequencies • Assessing release consequences • Calculating risk to the public • Assessing the significance of the risk • Identifying and evaluating additional risk prevention or risk mitigation measures as appropriate, and recalculating risks.

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Wherever practicable the pipeline route will have avoided populated areas, crossings or geologically complex areas (landslip, wadis, and flood plains). Further mitigation measures can take the form of engineering design, construction techniques or operating techniques and technology such as: • Increased wall thickness • An increased depth of cover • Anti corrosion protection/improved welding practices • Concrete slabs and marker tape installed over the pipeline • Motion sensors and CCTV monitoring • Pipeline foot patrols and aerial surveillance • One-call systems and landowner communication The impact significance and probability of occurrence typically considers the potential impact and probability of an unplanned event. It subsequently takes account of the design measures that aim to minimise the probability and consequences of the event and, the proposed operational control measures. This gives an overall assessment of the residual risk of unplanned events.

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12.13 Consent Process 12.13.1 SEIA documentation SEIA documents are provided in support of the development application to the regulatory authorities. Typically they include a non-technical summary, the SEIA report and technical appendices. A separate environmental baseline report may have been issued to regulators and made available by selected stakeholders for comment early in the SEIA process.

12.13.2 Stakeholder engagement and education It is normal practice for the SEIA process to include a disclosure period followed by consultations with stakeholders, who may be individuals, groups or organisations whose interests could be affected by the proposed pipeline route or the associated construction activities. The SEIA process has to demonstrate that stakeholders have been consulted and document any changes to the design that have occurred as a result of the consultation. Consultation continues into construction and during operation of the pipeline. Copies of draft SEIA documents are made available at locally agreed locations. Communities are notified (by means of a number of communication channels, including adverts in local and national papers) of the whereabouts of the documents and the timescales for comments to be returned. In many cases, local meetings are held to support the disclosure process. The disclosure process has the advantage of identifying major omissions and providing an opportunity for stakeholders to comment on the proposals before the formal submission for approval.

12.13.3 Condition negotiation The time taken to consent a project will depend on the statutory regulations in the region and can take weeks, months or even years. However all applications undergo some form of regulatory review, consultation and negotiation of consent conditions. The discussions will focus on the assessment of significant effects, mitigation measures and commitments. Conditions are generally presented in draft by the regulator and discussed and agreed upon with the developer. Reporting and management of the consent conditions by the developer is important, as the regulators have the authority to stop work in the event that conditions are not met to their satisfaction.

12.13.4 Community fund/commitments Discussions on community outreach and social and environmental offset projects are often also included as part of the consent conditions negotiation process if they have not already been discussed and agreed during community consultation. The main goal of community funds and commitments is to build and maintain positive relationships with the pipeline communities by socio-economic development in the communities.

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Many clients and their project partners have developed community outreach and corporate responsibility policies to support enhancement of the quality of life of the affected communities, and elements of the policies are included by agreement in documents such as the SEIA or stakeholder development strategy. The extent or numbers of communities, benefiting from the programme, are generally restricted to the project-affected communities and people (namely landowners and tenants) defined in the SEIA. The areas selected for investment vary, however, for pipeline projects they generally relate to agriculture and civil society capacity building. In such cases country specific information will be considered when identifying the most suitable areas for further intervention. It is important to understand cumulative issues relating to other similar projects that may have affected the communities in the past. It is important that recognised national and international industry guidelines and practices are adopted, as there may well be precedents set by other developers who may have adopted other means to construct a development. Needs assessment and discussion with community leaders and regulators may assist in the identification of projects or programmes to ensure consistency of approach.

12.13.5 Formal Consent Formal consent for a pipeline project can take varying periods of time depending on the number and complexity of the regulatory authorities involved. Generally it is a matter of months, however it may take years to get particularly complex multinational agreements for transboundary pipelines. Pipeline projects typically traverse a number of local, national and international boundaries with different regulatory requirements. SEIA documents may be required in a variety of languages and formats to meet local requirements and the documents should accommodate this requirement or have reached prior agreement with the regulatory authorities or governments on the agreed minimum statutory requirements. These may take the form of host government agreements (HGAâ&#x20AC;&#x2122;s) and potentially are more stringent than local regulatory requirements.

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12.14 Preconstruction The SEIA process is undertaken in parallel to the engineering design it provides a documented snapshot of the engineering design at the end of the FEED process. Engineering design continues to evolve well beyond the submission of the SEIA. Given that the consent process can often take months to gain approval there are inevitable changes to the submitted design that have to be incorporated into the construction contract and approved by the regulatory authorities before construction activities commence. A site visit, aerial photography or Google earth imagery are often used by the client to provide the contractor with a ‘walk through’ of the selected pipeline route. The SEIA team often provides input to the construction tender specification and the tender review and interview of contractors to ensure that the commitments made in the SEIA and presented in the ESMMP are understood and have been included in the costs. Discussions at contract negotiations may be needed to clarify and justify some of the routing and construction methodologies. Where alternatives are proposed they will be more favourably accepted if they reduce the environmental or social impacts and reduce costs.

12.14.1 Client supply 12.14.1.1 Preconstruction consents Preconstruction consents may need to be obtained for items that were not included in the SEIA or have subsequently been changed. It is important that the responsibilities for preconstruction consents are clearly identified in the tender documents. These may include: • Drainage consents • Water use and abstraction consents • Water discharge consent • Temporary planning consent for pipe lay-down and camps • Highways improvement agreements • Tree-felling licences • Translocation of species licences and agreements • Rights of way or footpath diversion consents • Archaeological excavation and rescue • Seed import and plant material import licences • Fuel and hazardous materials storage consent • Licensed waste disposal (incineration/landfill) consents • Borrow pit aggregate extraction licences • Special crossings consent • Additional off-easement land requirements for special crossings The preconstruction consent and the responsible party should be clearly identified in the construction contract documents. Timely management of the consents avoids costly construction delays.

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12.14.1.2 Site visit (flyover) The tender package may contain, in addition to the alignment sheets, constraints maps on GIS systems, together with video footage or aerial photographs as part of the tender package. Field visits or flyovers during the tender preparation phase are important and time should be allowed for contractors to assess the route in the field. Considerable cost savings can be made by removing contingencies as a result of site visits.

12.14.1.3 Geotechnical investigations Geohazards should be assessed as part of the SEIA and geotechnical investigations should be undertaken early and the subsequent results provided as part of the tender package. The Road to Success Earthworks section (see Section 6) contains further details on construction techniques for different rock types.

12.14.1.4 Pre-clearance archaeological investigation Known archaeological sites should be either avoided by amending the route alignment or kept in situ by restricting the working width. Where this is not possible, data and artefacts should be recovered from sites prior to construction activities. The construction contract should clearly specify responsibilities between client and contractor for dealing with archaeological finds. Post-construction scientific reports recording the excavation and any artefacts will be prepared for the respective museum curators and, where required, the artefacts rendered to the care of the museum for safe keeping and display if desired.

12.14.1.5 Seed collection and contract growing of plants In some special areas, local seed may need to be collected, stored and germinated in preparation for reseeding or contract growing. This is a specialist exercise and local nurseries and subcontractors should be employed to undertake the work.

12.14.1.6 Client supply of long-lead items Long-lead items are often supplied free of charge to the contractor. It is important that transport and storage arrangements are clearly understood and are included in the chain of custody documents so that contractors can take possession of long-lead items that are of a quality and standard specified and in a timely manner.

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12.15 Construction 12.15.1 Contractor mobilisation Contractor mobilisation and early works include; • The ROW survey and marking; • Identification and establishment of camps, lay-down areas, ports, transport systems (rail head, bridge reinforcement, road improvement and alternative construction traffic access routes marked where there are “lock out” sections such as at railways and large river crossings) as well as vegetation clearance; • Identification of services, borrow pits, waste disposal routes and facilities, fencing and signage. It is likely that some of these activities and locations have been identified within the SEIA and consent conditions. However, for those items that were not included in the SEIA or have subsequently been changed it is important that the responsibilities for preconstruction consents and mobilisation activities are clearly identified in the contract documents. The contractor will also need to see any additional preconstruction survey work (not included in the SEIA) that has been undertaken, such as: • Special crossing surveys • Geotechnical surveys • Meteorological data • Landowner record of condition surveys and agreements • Highways access/improvements/construction and road/footpath closure agreements • Agreed water abstraction locations • Landowner agreements on stock fencing and watering facilities • Pre-clearance works for archaeology • Waste disposal routes • Borrow pits • Locations sensitive to noise or vibration (protected buildings, schools, hospitals etc.) The Road to Success Logistics section (see section 8) contains more details on contractor mobilisation and logistics.

12.15.2 Consultation On-going stakeholder engagement and public consultation is undertaken with the project-affected people and communities to educate and inform them of the construction activities, timings and safety considerations.

12.15.3 Landowner liaison Constant communication is required to keep landowners informed of progress and how the construction activity affects their land. Entry requirements need to be met to allow the contractor onto each individual landowner’s property. During the course of construction proper heed should be paid to dealing with drainage, and water management; livestock and crops to ensure that the land is not damaged by construction equipment or soils contaminated. On completion of construction, reinstatement needs to be signed off by each landowner. Responsibility for liaising with landowners should be defined as either client or contractor.

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12.15.4 ROW preparation Once all agreements are in place the ROW preparation can start in earnest, including: • Survey and peg route • Agreed alien species and communicable diseases mitigation measures • Ecological mitigations (translocation, fencing, seed collection, turfing) • Vegetation clearance, dewatering, etc. • Fencing • Topsoil stripping • Drainage (dewatering, header drains, etc.) • Signage

12.15.5 Construction/labour For pipeline projects, the majority of social impacts tend to occur during construction stage. Construction camps usually are the source of both negative and positive social impacts. The potential benefits associated with camps are mainly associated with local employment opportunities. Construction camps attract migrant workers from different regions as camps are perceived by many as a key source of employment/income. During construction, employment will reach to its peak level, as there is a demand for direct employment as well as indirect employment. Services such as logistics and catering are required to serve construction workers. Increase in expenditure as a result of workers’ spending could also boost the local economy, and could potentially lead to development of small businesses. However, despite the positive impacts related to employment, there are also a number of potential negative impacts. The negative social impacts associated with construction camps are: • Unplanned immigration of labour towards construction camp locations • Impact on housing market and increase in rents • Increase in traffic and road accidents • Increase in crime as a result of any potential conflict between the locals and the newcomers • Increase in cost of products as a result of localised inflation, which will affect locals’ purchasing power • Local concerns associated with recruiting local contractors/workers from different regions where the construction camps are not located • Increase in incidences of communicable diseases from interaction between workforce in construction camps and local people • Tensions resulting from cultural differences, anti-social behaviour of construction workforce, potential prostitution and attraction of 'hangers on' at camp sites • Frustration and resentment if local workers perceive that foreign workers are receiving better pay or conditions for exactly the same job Overall, construction camps could pose a risk to community health, safety and security if the negative impacts listed above are not mitigated and managed properly. Operation teams and developers need to apply certain mitigation measures to reduce adverse social impacts, and to ensure that local communities’ livelihood is not harmed. A key aspect to reduce adverse impacts is to regularly communicate with local communities to inform them of development stages and risks associated with development and operations. Typical key management plans to cover aspects associated with employment, community health, safety and security, community liaison and camps are:

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• Local recruitment and training plan • Construction camp management plan • Community health, safety and security plan • Community liaison plan

12.15.6 Construction monitoring/reporting Environmental and social management typically apply the ‘plan, do, check, act’ principles of environmental and social protection to activities (Figure 5). These principles include: • Plan – prior assessment of environmental and social impact • Do – implementing design and mitigation measures that reduce or minimise potential impact • Check – monitoring performance and the efficacy of the mitigation measures that are implemented • Act – auditing and tracking the implementation of corrective actions Environmental auditing results are analysed and any necessary amendments to practices are identified and implemented in a timely manner.

Figure 5: Typical environmental and social planning principles

12.15.6.1 Plan The ‘plan’ stage of the cycle identifies hazards and risks to the project(e.g. through the SEIA process), resulting in a commitments register for the project. Planning also involves the identification of legal and other requirements (e.g. developing the legal and permit registers) and sets goals and targets such as KPIs. The commitments register for the project will list the commitments that will have been generated through the project’s comprehensive SEIA process. The register assigns each commitment that will be implemented in the ‘do’ stage of the management cycle to an appropriate plan in the ESMMP and

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clarifies whose responsibility it is for producing a plan to implement the commitment. The commitments register is updated periodically to take account of engineering design, consent conditions and contractor implementation plans.

12.15.6.2 Do A management-of-change procedure typically ensures that any changes during the final design and construction stages are subject to scrutiny and that any implications for environmental, social or cultural heritage issues are identified, approved, and addressed.

12.15.6.3 Check The ESMMP specifies key indicators for environmental and social performance. The contractors’ implementation plans will ensure that monitoring data on these indicators is gathered and reported. Some of the management plans in the ESMMP may require the contractors to carry out regular (e.g. weekly) documented inspections of certain day-to-day items such as pollution control, waste storage, and traffic movements. The contractors’ implementation plans will typically develop pro forma for the inspections and ensure the process for reporting the findings of these inspections. In addition, certain requirements (e.g. adherence to ROW speed limit) are best monitored through informal daily observations, which are made while staff are travelling around the works. The amount of reporting required by the ESMS will be commensurate with the scale and length of the project. The construction contractor may be required to submit combined environmental and social report at periodic intervals. The report may include items such as: • KPI data (e.g. waste volumes, types and disposal; complaints received and resolved) • Activities carried out (e.g. surveys, translocation, meetings with communities, site inspections and findings) • Status of non-conformances identified during inspections • Environmental, social and cultural heritage issues arising in the course of the works (e.g. contaminated land discovered, archaeological finds, ecological issues) It is considered best practice for contractors to prepare and submit individual reports after any environmental or social ‘incident’ and ‘near-miss’ (e.g. spills, pollution incidents, environmental damage, accidents, complaints from communities and neighbours). Other than the regular daily checks along the pipeline spread, it is also best practice to carry out regular weekly audits to track the progress and performance in implementing the commitments in the ESMMP and the effectiveness of the mitigation measures implemented in avoiding environmental and social impacts. Generally, the aim will be to audit all elements of the contractors’ ESMP during the construction phase. The frequency of auditing for individual commitments will be reviewed regularly and adjusted as necessary taking account of audit findings. Spot check audits of any issues that are of particular concern may also be undertaken.

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12.15.6.4 Act The documented inspection and audit processes together with non-conformance reports (NCR’s) and corrective action requests (CAR’s) will entail action-tracking systems to monitor the effectiveness of actions taken in response to NCRs and CARs. Typically, the client’s environmental adviser and cultural heritage monitor will track the implementation of corrective actions and will update the construction manager and the environmental and social manager daily on non-conformances that require follow-up actions.

12.15.7 Training At the ‘do’ stage of the ESMS cycle, training is fundamental to the successful delivery of the SEIA commitments. Pipeline construction activity at any one location will be of relatively short duration, so establishing key environmental and social requirements at the outset is important to the provision of effective training. The main training elements required are: • Management briefings • Induction training for client, construction contractor and subcontractor staff • Toolbox talks 12.15.7.1 Management briefings An environmental and social training session by the project environmental representative on site will provide the project management team with overview of the ESMMP and a common understanding of roles, responsibilities and project standards. Following the award of contract, a second environmental and social training session will ensure that the project management team and the construction contractor’s senior personnel adopt a coordinated approach to implementing the requirements stated in the ESMMP. The session will also affirm the commitment to good environmental performance and to establishing good community relations.

12.15.7.2 Induction training Included in the ESMMP are the following training plans: • The local recruitment and training plan prescribes the delivery of induction training (in the appropriate language(s)) to the construction workforce; it also specifies the delivery of ES training and skills training (including toolbox talks) to the construction workforce • The construction camp management plan requires a camp induction that will address camp security, health and safety, code of conduct, local cultural sensitivities and camp emergency evacuation • All project construction staff will receive an environmental and social induction that will explain the key requirements common to everyone on the site. The induction will have a strong focus on visual presentation (graphics, illustrations, diagrams, photographs, etc.) and will contain simple, clear messages

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12.15.7.3 Toolbox talks In addition to toolbox talks delivered by the construction contractor as part of skills training, it is typical for the client’s environmental and social advisers, CLOs and cultural heritage officers to deliver talks to contractor and subcontractor personnel to make them aware of SEIA commitments to avoid or mitigate specific environmental and social impacts that relate to their tasks.Particularly where the impacts are significant or where the requirements are not covered in the general induction. This could apply to personnel involved in: • Clearing of fly-tipped waste and contaminated soil before construction • Right-of-way and facility site preparation (covering such matters as the archaeological watching brief; fencing for public protection; avoiding encroachment into areas off the ROW and working areas and accidental damage to sensitive receptors; correct storage of topsoil; and relocation of sensitive fauna) • Pipeline lowering and laying (covering such matters as procedures for correct compaction, grading and topsoil replacement) • Construction of rail, road and river crossings (covering such matters as the particular procedures for construction and reinstatement in these areas and expanding and reinforcing pollution control awareness and training, in particular for the watercourse crossings) • Hydrostatic testing (covering such matters as pollution prevention and erosion control) • Driving (covering such matters as vehicle routes, safe driving and vehicle maintenance)

12.15.8 Grievance mechanism A formal grievance (complaint) procedure needs to be established during the early stages of the project to obtain an affected community’s concerns and views. The complaint procedure can be used as a tool to monitor the livelihood and well-being of an affected community with regard to different phases of the project. It is important that the mechanism be impartial, transparent and fair. The mechanism should include the following: • Objectives: a statement of the intended aims and benefits of the grievance procedure • Scope: a clear statement of the types of grievances covered by the procedure • Responsibilities: who is responsible for the various components of the system • A description of the step-by-step process for registering and addressing grievances and provide specific details regarding a cost-free process for registering complaints • A description of the mechanism for appeal, and the provisions for approaching civil courts if other options fail • Procedures for recording and acknowledgement of grievances, comments or complaints • A transparent methodology for investigation of grievances, comments or complaints • Acceptable, publicly stated, timescale targets for responding • Procedures for further review of unresolved issues • Monitoring and feedback, with targets for satisfactory complaint resolution • A brief on how the procedure will be communicated to third parties • Disclosure: how information about grievances/comments/complaints that have been lodged and/or resolved will be made publicly available

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12.15.9 Record of condition Before the contractor takes control of the pipeline route, it is important to survey the areas over which construction works will take place and produce a record of condition report of the land, access roads and lay-down areas. This record will contain photographs of the condition of the pipeline spread, access points and areas where there is planned vegetation removal. The record of condition will enable the project to determine what damage is attributable to the construction activities should there be any dispute over the pre- and post- construction conditions. It is also a useful aid in determining what is required to return the land to its former condition during the reinstatement of the entire area occupied by the construction activities.

12.15.10 Archaeological, preservation and storage write up of finds During the preparation of the SEIA discussions will have taken place with the statutory consultees, including the representative archaeological authorities. Part of these discussions is to determine how to identify and treat archaeological features along the pipeline route. Following the discussions a written scheme of investigation will be produced, in which the developer and the archaeologist will agree how the works will progress, taking account of any previously identified archaeological features and what measures are to be implemented to deal with any undiscovered features or artefacts. To minimise the possibility of encountering any unidentified features an archaeologist should ideally be present during the topsoil strip to act as a watching brief. In certain circumstances the areas where a watching brief is required can be reduced by agreement during the consultation process; provided the desk-based assessment and previous ground survey can prove the watching brief is unnecessary. Statutory regulations and standards govern the handling of any archaeological features or artefacts discovered during the pipeline construction activities. All such finds must be recorded on site by a team of specialist archaeologists and any removable objects bagged, recorded and stored pending transport to the local archaeology department or museum. In the case of any human remains being unearthed it is mandatory to report it to the police and coroner and to involve them in the identification of the remains and in determining the length of time the remains have been buried. All construction-related activities in and around such a discovery will cease until the area is cleared by the respective investigating authorities. Following the completion of the construction works on site a full post-construction report is prepared by the contractorâ&#x20AC;&#x2122;s archaeologist that details all activities, features and artefacts found during the construction phase of the pipeline works.

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12.16 Hydro Testing And Reinstatement 12.16.1 Hydro testing The pipeline is backfilled with the sub-soil (or in certain circumstances a selected backfill if the removed material is unsuitable for screening, such as hard rock) that has been stored adjacent to the pipeline trench. The new pipeline will be subjected to hydrostatic pressure testing to prove the strength and integrity of the section in accordance with the relevant standards and any additional company requirements. The number of test sections will depend on the topography over which the new pipeline is routed. The location of the test station(s) shall be positioned as close to the lowest point of the pipeline section as possible. The test sections must maintain a pressure above the required minimum for a period of 24 hours, and a correlation must be made between the pressures, temperatures, water added and water removed, thus clearly demonstrating that the section of pipeline is leak free. Any malfunction of the pressure recorder during the hydrostatic test may require a repeat test. Hydrostatic testing activities will be carried out in sequence and will include: • Welding certified test ends onto each end of the pipeline test section • Internal cleaning of pipeline sections using cleaning pigs to remove construction debris • Running a gauging pig to confirm the internal geometry is within specified limits • Controlled filling of pipeline sections with water from a suitable agreed source (well, mains, river, lake, sea etc.) • A temperature stabilisation period to allow the water and line pipe steel temperature to stabilise • Temperature stabilisation • Pressurisation of the pipeline test section to its design operating pressure • A test pressure hold period (i.e. commencement of up to 24-hour strength and leak test) • Depressurisation of the pipeline test section • Controlled dewatering of the pipeline test section • Swabbing of the pipeline test section to remove as much water as practicable • Removal of the test ends The displaced hydrostatic test water may be transferred to another section of pipe or discharged at a suitable location. Filters and break tanks will be used to remove any solids and control the rate of discharge. Discharge locations and rates will be agreed in advance with the relevant authorities. If chemical additives have been used, the water will be tested and treated, as required, before discharge to ensure all discharges are in compliance with applicable environmental requirements. During discharging operations, samples for water quality analysis will be taken and stored for reference. Following successful hydrostatic testing and dewatering, tie-in golden welds will be carried out to link each new section. Water for testing will be sourced from nearby approved water sources. It will be either transferred direct to the test sections by a temporary surface-laid pipe or taken by road tanker and stored in temporary ponds until sufficient volume is available for the hydrotest. The abstraction and disposal of water for the hydrostatic testing will require statutory approval from the relevant authority. In normal circumstances the authorities like to have the water returned to the source location once the test is completed. However, because of the potential transport of vast quantities of

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water involved, which can be transferred from section to section along the pipeline route, it is usual to apply for a dispensation on this matter and make arrangements for an alternative discharge location pending the outcome of a formal application to carry this out. Water for hydrostatic testing will be clean, contain the minimum achievable concentrations of contaminants (e.g. sediment, bacteria) and be non-corrosive. Water abstraction sources will be selected to suit the geographical location of the pipeline and be of sufficient quantity and quality to facilitate filling of the pipeline test sections without any detrimental effect to the surrounding ecology and downstream consumers. Potential hydrotest-water abstraction points identified by the construction contractor(s) will be subject to an environmental review by the project team before their adoption. All necessary permits required for water abstraction and disposal will be obtained from the owner/occupier/local authorities and will be in accordance with project environmental requirements. The test water will be analysed to check quality before and after use; the use of chemicals will be minimised but it may be necessary to add corrosion inhibitors, oxygen scavengers or biocides. The water used for the hydrotest will need to be discharged in accordance with the terms and conditions of the abstraction and disposal licence received from the relevant authority; in the UK this is the Environment Agency (EA). Authorities sometimes insist that the test water be returned to the source if taken from a watercourse. However, this may not be a practical or financial option in which case, by agreement with the EA, alternative disposal methods or locations can be agreed during the consenting process. Once the pipeline is successfully tested, and the temporary test ends removed, the open ends of the various test sections need to be closed. This involves welding the individual pipe sections to the neighbouring test section until the pipeline forms one continuous section along the entire length of the new pipeline.

12.16.2 Reinstatement The pipeline running track and trench is reinstated to grade level using the topsoil that has been stored to one side of the running track during the first of the ROW preparation works. The intention during the reinstatement works is return the whole of the construction occupied areas to their former condition. The key areas that require full reinstatement are the ROW, the construction camps and storage areas, the block valve sites and the new temporary access roads. The project reinstatement specification is generally based on the following principles: • Disturbed areas will be reinstated to pre-construction conditions to the greatest practicable standards. This to include for bio-restoration, species translocation, reseeding and replanting and maintenance with the correct measures implemented to include for pest control, weeding and avoidance of introducing or the spreading of foreign/invasive species and notifiable diseases. • There may be a continuing requirement for access along the ROW by patrols and for maintenance. • Levelled working areas on side slopes and ridges may be retained to allow future access for inspection and maintenance. • Disturbed areas will be stabilised to protect the integrity of the pipeline and minimise potential impacts associated with erosion, transportation and sedimentation of material from disturbed areas.

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â&#x20AC;˘ Disturbed areas will be re-vegetated to achieve conditions similar to those that exist immediately adjacent to the ROW. â&#x20AC;˘ Regular monitoring and maintenance of all reinstated areas will be undertaken until environmental requirements and goals are achieved. The commitment to monitor the success or otherwise of the reinstatement plan can vary and can be anything up to a period of ten years, The developer then remains the responsible body for any further reinstatement or erosion control work for the life of the development As well as reinstating the pipeline ROW any temporary areas previously occupied by the construction activities must also be reinstated to their preconstruction condition As mentioned earlier (see Section 15.9) a record of condition report will have been undertaken before works begin and this will prove to be a useful tool in assessing what (if any) damage to land, property, access roads, etc., is attributable to the pipeline build and what is needed to reinstate the matter to its former condition should any repair be deemed necessary. Corrosion protection is installed during pipeline construction and employs an impressed-current cathodic protection system. This may require the installation of additional anode ground beds, transformer rectifiers and associated utility supplies to support the facility.

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12.17 Pipeline Operation Once completed the new pipeline is expected to have a 25–30-year lifespan. This may be less for pipelines transporting CO2 or sour gas. The pipeline lifespan will be achieved by a combination of technology and management techniques including pipeline coatings, protection from external damage (slabs and tape over the pipeline, increased depth of cover), mass concrete and increased wall thickness, effective backfilling/padding and reinstatement to prevent washout or erosion exposing the pipeline and cathodic protection systems (to reduce the potential for induced current corrosion and biological and chemical attack on the pipeline). Sophisticated movement detection systems using fibre optic cable laid alongside the pipeline have been deployed on recent pipelines to detect seismic events or where the risk of illegal hot tapping is considered likely to detect excavation or movement over the pipeline. Internally applied linings and additives to the product can be used to enhance the hydraulic properties of the pipeline. Regular monitoring and maintenance of the pipeline will be required to ensure the safe and continued operation of the pipeline with particular emphasis on any geohazards encountered or thirdparty interference. Techniques for monitoring the pipeline include aerial surveillance, walkover patrols, vantage points surveys and landowner liaison. Registration of the pipeline with ‘one-call’ services and the government agency responsible for development control is also useful, where they exist. Low-level marker posts with identification plates containing contact details may be installed along the pipeline route. Aerial marker posts may also be installed to aid the identification of the pipeline route when viewed from the air. The spacing of block valves (BV) or AGI’s to isolate discreet sections of the pipeline for maintenance, accident, damage or repair of the asset will have been considered during engineering. The BVs are generally located at regular intervals along the pipeline route (they may be buried or above ground) the distance depending, among other things, on the operating philosophy of the pipeline, profile and environmental hazards. For example, on an oil pipeline block valves are often located either side of river crossings to enable the river crossing to be isolated. The BV is a very small installation and, apart from the operating valve stem, all of the pipe work within the security fence is below ground. Where the BVs are not automatic it is important to ensure that the operator has emergency response plans that are regularly exercised, including alternative access routes to the location and whether pollution control/spill equipment/containment measures can be deployed in sensitive areas/watercourses etc. Pipeline operators work closely with the emergency services or develop their own or pooled emergency response teams including containment and mop up kit. Pigging stations allow the pipeline to be inspected, cleaned and gauged. The pigging launch and receiving facility is usually an integral part of a larger AGI, such as distribution off take stations, compressor stations or reception terminals. Operating permits for compressor stations and processing plant will be obtained and maintained by the client in accordance with the consent conditions and the local regulatory requirements.

12.17.1 Operations Phase ESMS Operations ESMS are often certified to national or international standards such as ISO 14001 and follow the ‘plan-do-check-act’ cycle similar to the construction ESMMP shown in Figure 5: Typical environmental and social planning principles. The operations ESMS should be developed before operations begin and are based on the operations commitments in the SEIA and the client’s own operating standards. Transition plans may need to be developed to assist with the movement from the construction-phase to the operations-phase ESMS. The delivery of as-built plans, environmental databases, cadastre of landowners, and stakeholder engagement databases are vital to the operators to ensure continuity at project handover, as are the

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records and more particularly dates for consent conditions, reinstatement monitoring reporting, and defects liability periods for landscape planting works. This body of data will all form an important part of the operational phase ESMS . Similar to the construction management system, the primary functions of the operations ESMS will be to: • Ensure that the pipeline and associated facilities are operated in accordance with relevant legal and regulatory standards and client operating policies • Ensure that the commitments made in the SEIA relating to operations are implemented The management system should regularly assess the environmental and social aspects and impacts of its activities, develop objectives and targets to address any significant aspects, appropriately resource and train staff, and monitor and audit the success of its actions in addressing the significant impacts. This system will be implemented to ensure continual improvement in performance. Key components of an operations ESMS, consistent with ISO 14001 requirements, are shown in Table 1. ISO 14001 EMS Components 1. EMS general requirements

10. EMS documentation

2. Environmental policy

11. Document control

3. Environmental aspects

12. Operational control

4. Legal and other requirements

13. Emergency preparedness and response

5. Objectives and targets

14. Monitoring and measurement

6. Environmental management programmes

15. Non-conformance and corrective action

7. Structure and responsibility

16. Records

8. Training and awareness

17. Environmental management system audit

9. Communication

18. Management review

Table 1: ISO 14001 EMS commitments The operations commitments included within the SEIA, consent conditions and operating consents will be implemented through the management system. Typical operations include: • Emissions management (water, air, noise) • Community liaison, safety infrastructure and services • Employment and training •

Waste management

• Ecological management and monitoring • Cultural heritage management • Local procurement and supply management. • Emergency response plan (ERP) The as built plans and cadastre of landowners, and stakeholder engagement databases will be updated and maintained throughout the life of the development.

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12.18 Decommissioning At the end of the operational and economic life of the pipeline and the associated AGIs a decommissioning programme will be implemented. There are four main options for an onshore buried pipeline: • Abandoned in place and filled with either an inert gas (such as nitrogen) or grouted with a solid material such as concrete or bentonite • Totally removed and the materials recycled or disposed of to the relevant licensed waste stream (scrap metal) • Re-use the facilities in situ provided they meet the set criteria for the new purpose • Extend the operational life of the pipeline which may require risk assessment and engineering improvements and additional facilities The facility will have been condition monitored throughout its operational life. By using this historical data it is possible to formulate a programme of post-decommissioning monitoring to ensure no harm is caused to the environment or other land users provided decontamination procedures and mitigation measures are strictly adhered to during the process. In all cases it is likely that there will be a requirement to discuss the decommissioning with the local regulatory authorities and there may be the requirement for consents or an SEIA to be undertaken for the decommissioning process. Decommissioning any large project focuses on the re-use, recycling or reduction of the waste from the project and the trend is increasingly towards design and engineering projects which consider the deconstruction of the project as part of the carbon footprint or lifecycle analysis process during the design of the project.

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References deJongh, P. (1988), ‘Uncertainty in EIA’, in Paul Wathern (ed.), Environmental Impact Assessment: Theory and Practice (London: Routledge). International Finance Corporation (2007), ‘Stakeholder Engagement: A Good Practice Handbook for Companies Doing Business in Emerging Markets’. International Finance Corporation (2012), ‘Performance Standard 5: Land Acquisition and Involuntary Resettlement’. World Federation of Pipeline Industry Association (Ed 1, Nov 2003), Environmental Guidelines for International Onshore Pipeline Construction The Institute of Environmental Management & Assessment (IEMA) published guidance on preparing Climate Change chapters for Environmental Statements [IEMA Principles Series: Climate Change Mitigation & EIA; Version 1.1; 1st June 2010] International Finance Corporation (2006), Performance Standards on Social & Environmental Sustainability: Performance Standard 1: Social and Environmental Assessment and Management Systems (Washington, DC: International Finance Corporation) World Bank Group (2007), Environmental, Health, and Safety General Guidelines and Environmental, Health, and Safety Guidelines for Onshore Oil and Gas Development (Washington, DC: World Bank Group). The Equator Principles (EP II) (2006); A financial industry benchmark for determining, assessing and managing social and environmental risk in project financing http://www.equator-principles.com Council Directive of 27 June 1985 85/337/EEC (as amended); on the assessment of the effects of certain public and private projects on the environment EC DGX11 Guidelines for the assessment of indirect and cumulative impacts as well as impact interactions http://ec.europa.eu/environment/eia/eia-studies-and-reports/guidel.pdf United Nations Economic Commission for Europe (UNECE) ESPOO Convention on Environmental Impact Assessment on a Transboundary Context (ESPOO, 1991) Austrialian Pipeline Industry Association (APIA) Code of Environmental Practice Onshore Pipelines, March 2009

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Case Studies: Construction Mitigation Measures The following case studies have been provided by IPLOCA members to illustrate a range of social and environmental mitigation measures implemented on pipeline projects. It is proposed that further best practice case studies are added to these, if you have experience which you would like to share please forward them in a similar format (1 page) to IPLOCA secretariat (or upload to Wiki) Plant Nappies as an Alternative to Conventional Drip Trays An above ground installation (AGI) conditioning works project has chosen to replace conventional drip trays with ‘Plant Nappies’ on all 13 sites. The decision was taken as a result of the continual emptying and disposal of contaminated water and the generation of absorbent pads which are used to soak up contaminants with conventional drip trays. Conventional Drip Trays Drip trays are usually made of pressed mild steel and placed under plant and machinery to capture oil leaks and spills. Although these drip trays are suitable for the intended purpose, they are prone to damage and corrosion and require regular emptying which can often be cumbersome and produce hazardous waste (used absorbent pads and contaminated water). Plant Nappies The ‘Plant Nappy’ or ‘mat’ is an alternative to using conventional drip trays and is designed to replace existing forms of drip trays with a light, user-friendly method of containing oil drips and spills. The mat is rugged enough to withstand plant on it in all weather. Drips or spills of oil will be captured by the mat while water is allowed to pass through, thus eliminating costly emptying of contaminated trays after use. The mat can be stood on uneven ground or slight inclines with no loss of performance ensuring protection at all times.

Design The design allows drips of oil or fuel to be caught in the base and rainfall to escape through the side walls as pure clean water. The base of the mat is non-permeable fabric laminated with an oil soak filter, to absorb the oil, and protected by a permeable top fabric to allow free passage of contaminants. The side wall is permeable with a filter fabric that allows free passage of water but not oil. It only discharges clean water. Blue cones highlighting drains The project demarcate watercourses using blue netlon fencing which acts as a prompt to remind site personnel of these sensitive areas. However, often the permanent drainage on a site is forgotten about. It is important to protect drainage systems from spills and silt pollution as often a drain can lead directly to a watercourse.

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To address this problem and ensure all personnel on site are aware of the site drainage system, the company have placed blue cones over all drainage manholes. If a spill were to occur on site, the blue cones clearly identify the manholes where monitoring can take place to check if the spill has entered the drainage system. The cones could also be used to demark open drains. If a spill to ground were to occur in the vicinity of an open drain, or a pumping activity were to take place close by, site personnel would be quickly aware of the location of drains and put procedures in place to protect them.

Spill Kit Checks Spill kits are located at prominent locations on a site to ensure they are quickly available to clean up a spill if they were to occur. Sometimes the whole spill kit is used to clean up a spill, and other times only part of the kit is required. It is important to ensure that the spill kits are replenished after use and continue to be located in these specific areas. In order to ensure complete spill kits are available, this particular project introduced fortnightly spill kit checks. This ensures all spill kits in high risk locations are logged and checked regularly for completeness.

Spill kit located by the mobile fuel bowser

Check sheet attached to spill kit

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The spill kits are given a unique reference number and have a checklist attached to the back which details what must be in it (this is dependent on its location). Typically, this consists of: • Absorbent pads • Absorbent booms • Disposal bag • Gloves (suitable for use with hydrocarbons) • Emergency response procedure • Hazard/near miss reporting cards & pen Once the spill kit has been checked and confirmed as complete, the check sheet is signed. Records are also kept electronically in order to keep a tight control on the number and locations of spill kits on site.

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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

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•

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

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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.

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

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

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

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

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

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

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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

100

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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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13.7 Near real time automatic data acquisition Introduction One of the main challenges of a pipeline project is due to the differing locations of construction facilities, from the pipe mill and coating, intermediate ports and stations to the stockpiles and construction sites. Predictive modelling over vast physical areas is complex due to latency in communication and management control. The geographical nature of pipeline projects further complicates the construction works and raises the requirement to have timeless and accurate update of daily activities. With the recent innovations and enhancements of mobile technology, handheld devices have eliminated the paper-based process, reducing the physical piles of papers on construction sites by having the required data in hand electronically. Examples include specifications and quality standards, construction drawings, inspection check lists and forms. This also works in the other direction too, with daily construction reports now being created electronically directly, eliminating the paper-to-electronic data entry process. A good near real-time reporting tool should integrate: a backend control system for reference data, mobile units for quick data acquisition, and a GIS-based system for geospatial dynamic reporting. The purpose of this document is to highlight the basic specifications of mobile control solutions for automating and reporting daily construction site activities to a backend GIS user-interface system using handheld devices in near real-time This document will cover • Pipeline project controls system for non-spatial reference data • Construction progress reporting using handhelds (data loggers) • Integration with a GIS-based system

Scope Description In pipeline projects, pipes are distributed along thousands of miles of alignment, following a standardized procedure pre-defined by the project’s requirements, dependent on environment, property and safety. Such projects function remotely. With several parties operating autonomously, which require a wellunderstood manageable infrastructure to be established to overcome adverse impacts of loss in communication and dependency that might return as high costs on schedule. The backend project controls system is used to track and control construction activities on daily basis. Integrated with content management and GIS systems, the project controls system stores documents, investigation reports and construction activities data. This system allows the project team and managers to access spatially based information and near real-time construction monitoring data through one portal. Figure 1 illustrates the main integration between these different systems.

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Fig. 1: Pipeline and project data flow

Components of a pipeline near real-time construction management solution Project controls system In construction projects, information is collected from different sources and in different formats. The backend controls system hosts the initial data groups collected from pipeline owner, client and design at the FEED stage, to validate construction processes whereas the electronic data management system (EDMS) archives textual documents (procedures, RFIs, schedules, checklists, specifications, etc), and any graphical documents (drawings, alignment sheets, photographs, etc).

Modules, integrations and electronic data interchange (EDI) The pipeline tracking system starts with some basic information needed to initiate the control systems and to enforce validations of collected data against procedure and requirements. For example, for the pipeline tracking system, the tally sheet and pipe shipments details are required from the vendor. An electronic data interchange (EDI) is used to define the electronic data to exchange between multiple software systems and its format.

Tally sheet Pipe tally sheets list the pipe tags and their main properties and specifications including: • Pipe tag number, the unique number to track each pipe allowing full traceability from mill till welding on site • Heat number: identifies the batch (cast) of the pipe. The materials certificate will be applicable for this batch of pipes • Material specification • Diameter and wall thickness • Length, weight and surface area

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• • •

Coating Certificates Etc…

Pipe shipments Pipeline shipment information is transferred frequently prior to the arrival of each shipment (please refer to Appendix 7.1.1 in “The Road to Success”, 1st Edition Vol. 2 for more details about data group and attributes).

Non-destructive tests Non-destructive tests (NDT) are test methods used to examine an object, material or a system to verify its quality and compliance to the quality standards. The requirements are loaded into the project control system and used by the quality department to guide them during their quality control checks of the pipeline welding.

Alignment sheet Alignment sheets or “as-built” drawings are blueprints of the pipeline route with all the related details of the surrounding areas. Normally in landscape format, it includes a map view of a few kilometres’ section of the pipeline with important topographical features such as soil, wetland, etc. Other information might include the landowner, listing of rivers, crossing, and elevation profile showing the altitude and slope of each segment of the pipeline. At the bottom of the sheet there is usually the list of pipes laid in this section with their properties: material description, grade, thickness, coating, etc.

Project schedule A project work breakdown structure (WBS) can be defined by dividing the pipeline route into sections each formed of multiple kilometres. Construction activities are referenced and updated per kilometre. A progress monitoring system measures the progress completed against planned and reports the earned value versus actual progress calculations per construction activity. Pipeline construction projects are considered linear and planned in sequence along the pipeline route. A march chart is a good planning tool for scheduling construction activities. Also known as timedistance chart, it provides a comprehensive representation of the project plan, indicating the activities required, their location along the pipeline, and their time frame. Addition information such as route profile (elevation), soil content, crossings locations, landmarks, environmental interest areas etc can be indicated at the correct linear location. Figure 2 shows an example of a pipeline project WBS hierarchy.

Fig. 2: Example WBS for a pipeline project 113

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Other reference tables include: â&#x20AC;˘ Welding procedure specifications (WPS) per diameter and thickness â&#x20AC;˘ Welders qualifications The detailed integration and data exchange is illustrated in Figure 3.

Fig. 3: Integration and data exchange system

Mobile pipeline management system (MPMS) Handheld devices Mobile handheld devices are portable computers that come in different sizes, and features. Handhelds include PDAs, tablet PCs, notebooks and lately smart phones. Usually, ruggedized handhelds are used in construction fields for durability. Features differences include size which ranges from palm-size to large display tablet PCs, input methods whether using keypads or touch screens. Handhelds might feature additional integrated components such as GPS receivers, camera, barcode readers and RFID readers.

Fig. 4: Handheld devices

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Mobile data acquisition With a mobile pipeline management system (MPMS), pipeline engineers, storekeepers and/or inspectors can perform inspections and complete tasks at the point-of-work, with more efficiency, enhanced data integrity and reduced workloads. A MPMS covers all procedural aspects needed for monitoring pipeline progress from delivery, transfer, activity updates to welding reports and quality control (QC) inspections/tests. With advances in technology, an automated data collection (ADC) based system is able to operate in mobility using various communication media such as GPRS, EDGE, etc, leveraging for flexible real-time implementations under a diversity of environments.

Fig. 5: Why mobile A MPMS can automate site work, minimizing paper work and manual data entry while providing data reliability and efficiency. This is done through usage of smart selections and drop-down lists and forward compatibility with barcode technology which is also optionally extendable to radio frequency identification (RFID). A MPMS can be enriched with warehouse logistics, handling the tracking of pipe movements and equipped with specialized modules for recording welding of joints, along with optional GPS interoperability. Depending on the accuracy requirement, this can either use a built-in hardware or thirdparty global navigation satellite system (GNSS) system to fetch the x, y and z coordinates of joints. This can then be integrated with a GIS system. Figure 6 lists the data workflow using the handhelds.

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Fig. 6: Handhelds data collection and reporting

Benefits and features

Fig. 7: Benefits and features

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Logistics activities (material tracking) A pipeline project includes material of various specifications, where pipes are usually sourced from multiple pipe manufacturers. Thus, each party would be required to prepare an electronic tally sheet referred as the packing list, to be sent before shipping their pipes to site. These are usually grouped into lots, depending on which mill they were produced in. The tally sheet is an essential requirement for traceability. In case of any defective pipes, other pipes from the same batch can be identified for quarantine via the heat number. MPMS makes it portable and allows validation at the point of inspection. Tracking of pipes starts from the mill or coating yard. The shipments data is created while loading the pipes to be able to validate the quantities and pipe tags received against the shipment lists. For easier tracking, the pipeline route is divided into logical stores designated by the kilometres representation. Each kilometre is considered a store and the pipes are received during the stringing activity are marked with the kilometre number and the location within. A sample logistics distribution is illustrated in figure 8.

Fig. 8: A sample logistics distribution and reporting of pipelines

Material receipt with visual inspection and damage reporting The tally sheet is loaded into a MPMS by the crew handling the delivery at site. The pipe numbers are entered on the system (scanned if barcodes are available, otherwise manually input) to update the stock. The MPMS checks these pipe numbers against the tally sheet retrieving the corresponding info (length, heat number). Minor corrections can be done on the spot (actual length), whereas major errors (heat number, thickness) are to be reported and the pipe quarantined. Missing barcode labels can be created instantly, printed and applied straight away to the pipe, following a standard labelling procedure.

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Aside from mismatch, the crew visually inspects each pipe for any damages. Coated pipes can be given a holiday test to ensure that pipe metal is shielded properly. Accepted pipes can be transported to site or store with the crew feeding MPMS with the pipe issuing data. Rejected pipes would be transferred to a quarantine store and the crew would raise a QC flag via MPMS. This toggled flag would notify an inspector to visually investigate the rejected pipes. Damages are registered using MPMS in an OSD report with details of the damage, along with photos. Figure 9 explains the pipe receipts workflow with snapshots from MPMS handheld forms

Fig. 9: MPMS pipe receipts workflow

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Material issuance (waybills) At any requisition or transition from one store to another, the MPMS automatically writes out the available stock quantity of the requested pipes via simply scanning the corresponding barcode that in return would retrieve live information of their physical location either in terms of grid numbering or GPS coordinates. This assists the storekeeper to swiftly fetch out where to load out, without the hassles of conflicts and rush hour. Plus, for advanced traceability and budget control, the MPMS allows to the storekeeper to make optional record of the recipient at pick-up for those pipes fetching the truckâ&#x20AC;&#x2122;s identity via barcode otherwise manually or selectively entered along with extra information such as department name and that optionally, print out waybills for approvals and tracking purposes. Figure 10 explains the pipe issuance (waybill) workflow with snapshots from MPMS handheld forms.

Fig. 10: MPMS waybill workflow

Construction progress activities MPMS integrated with ERP has allowed progress update on multiple WBS levels of the project such as kilometre section, pipe tag or even a joint. The list of activities is flexible, and is predefined in template tables. Figure 11 lists an example of these construction activities within a template.

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Fig. 11: Construction activities within a template The main pipeline construction activities are shown in Figure 12.

Fig. 12: Main pipeline construction activities All MPMS usersâ&#x20AC;&#x2122; activities are tracked and reported immediately if any failure or unusual validation occurs, allowing for swift action to be taken by designated parties on departmental level or system supporters. At any time, the MPMS can automatically write out the current activity of any requested pipe with live information of its physical location either in terms of coordinates (pipe, joint), section or kilometre numbering. The diagram in Figure 13 illustrates the different construction activities.

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Fig. 13: Construction activities of pipelines

Stringing As soon as the pipes arrive to site, they will be aligned one after the other parallel to the flow line of the pipeline either by using an alignment sheet or markings set by surveyor illustrating the kilometre and sub-meters within it. With a MPMS, those inspectors would scan each pipe loaded off the truck, retrieving its information to empower their decision on where it should be placed. After the pipes have been settled down in the desired location, the MPMS would provide flexibility to fetch the pipes' coordinates using integrated GPS or selectively by feeding in the surveyorâ&#x20AC;&#x2122;s markings. Consequently, MPMS would guide the inspectors visually via a map instantly revealing all the pipes and their location. Figure 14 illustrates the stringing process with snapshots from MPMS handheld forms

Fig. 14: MPMS stringing process and handhelds forms 121

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Cut pipe In case of a defect or damage, pipes often get cut down into pieces. Depending on the location of the damage, this might result in a pipe splitting into two or multiple sub-pieces. In such an activity, a MPMS would assist the QC inspector to scan the defective pipe to retrieve its original length and when the cut occurs, new measurements would be made and the new length would be fed into MPMS. In the case that the cut has resulted in two pipes, then one of them would be named as the original numbered XXXX with a new length, whereas the other would be named in the same syntax of the original followed by the sequential number or character i.e. XXXX_A also with a new length with the original pipe length maintained and stores for reconciliation and tracking. Naming convention is auto-generated by the MPMS.

Bending A similar process takes place for any other activity such as bending, where at some areas of the flow line, pipes need to be bent to satisfy the alignment sheet as pre-designed by the engineers. The MPMS would encapsulate those data according to the assigned position set by the inspectors, or automatically by GPS. This will fetch all the needed bends for the pipes and that would be cross-matched after it has been applied locally or was originally received bent from the manufacturer. In case of local application, inspectors would feed into the MPMS all relevant information such as the bending angle, operator, machines used etc. Figure 15 explains the pipe bending workflow with snapshots from MPMS handheld forms.

Fig. 15: MPMS pipe bending workflow

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Welding The MPMS is equipped with functionalities to assist QC inspectors or engineers with live references or procedures, such as WPS and welderâ&#x20AC;&#x2122;s qualification, etc, for empowering their field control over welders as to assure welding efficiency and, by increasing the quality of data reported, in return improving its assurance. Figure 16 illustrates the welding process with snapshots from MPMS handheld forms.

Fig. 16: MPMS welding process MPMS provides QC inspectors with various parameters to customize their reporting and control over the welding procedure, giving them information at every weld to know which WPS is appropriate, revealing relevant specification i.e. welding types, required preheat for a successful process and which electrodes should be assigned. The MPMS can assist the QC inspector by determining which alignment sheet has been used at kilometre and sub-meter scales, helping maintain the uniqueness of the current weld number by listing all weld created under that selected criteria. However, the MPMS still provides auto-generation of the weld numbers according to preset rules. At the initial stage of any weld, a fit-up occurs between the two pipes, creating a report by the MPMS for the inspector to visually evaluate against standards if it is acceptable or not. If accepted, inspector would feed the MPMS with the fitted pipes by scanning them in the order of the project flow, the first and second pipes being assigned as the start and end tag respectively. At every scan, the MPMS would provide the inspector with the history each pipe has undergone i.e. damages and all its relevant information i.e. length, heat number etc. As soon as that has been verified, welding would go through a sequence of pass types: root, hot, cap, and fill. No matter what order these are done in, the MPMS would force the inspector to ensure all stages are performed.

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At this stage, welders should start welding, but not before their certification is assured to be compliant with selected WPS and pass type, plus that those certifications are within their expiration dates. Normally, this incurs an intensive activity by the inspector to validate the welder’s suitability for the task. In contrast, the MPMS has taken over that obligation by capturing all welders information i.e. certification and expiry, providing it to the inspector as sensible and reliable reference material, after scanning the welder’s badge ID. Having that provided, the inspector can easily record in the MPMS every pass occurred specifying the legitimate welder and optionally the side applied (either ROW or trench or any, the latter usually being used when a single pass is embraced by multiple welders). After the weld is finalized with all the passes, the inspector can optionally use the MPMS’ interoperability with GPS to record the exact location of the pipe in reference to the project. For high accuracy, MPMS can integrate with Trimble’s GNSS system used by the surveyor and improve location drastically to millimetres. As soon as the QC inspector has closed this weld and progressed to the next one, the MPMS would automatically update itself, if it was connected via 3G/EDGE/Wi-Fi, allowing the rest of the QC inspectors to collaborate live, resulting into a real-time presentation, via GIS, of progress on site for the management. As the welds are updated into the backend database, they are all subjected to non-destructive test (NDT) as the automated ultrasonic testing (AUT) to ensure no defects occurred and if there were any, those welds are objected to be cut and re-welded again until no defects are found.

Trenching MPMS does not only maintain track of pipes’ activities, but also has added features to report construction activities. Although lowering (see next section) is an activity for the pipes, it is still dependent on the trench’s availability, which in fact is part of construction, and if not maintained would carelessly compromise the various parties’ ability to collaborate. The MPMS overcomes this by incorporating trenching, to ensure the proper forward planning of activities on site.

Lowering After welding, pipes are not independent anymore. Instead they are distinguished as joints, and progress on various activities is measured with reference to that. An example of such an activity would be lowering, where jointed pipes are lowered on after the other into the trench. It would be difficult to distinguish the pipes, but the MPMS eases this by recording all the related welds, allowing the inspectors to selectively specify pipe sections by start and end joints. The system would accordingly update all the interconnected pipes. Optionally, the MPMS also provides the capability for augmenting the inspectors’ input with GPS, displaying a map hosting all nearby joints. Basically, at every stage, when pipes change from one activity to another, the related information gets manually fed into the MPMS by dedicated operators or inspectors in charge of a single or multiple activities. This provides the project with a history tracked by time stamp, which can be used as a good source for planning and measuring progress.

Other progress activities Safety Usually in any pipeline construction, safety is the most significant concern among all activities, requiring an awareness of any incidents occurring, whether fatal, minor or near-miss. As these could potentially lead to huge losses, affecting the project’s success, it is necessary to be conscious of such vulnerabilities. The MPMS helps this, as it allows the on-site safety team to create a report easily, attaching photos of any incident, with the associated location and direction recorded using the built-in GPS and compass. It can also be supplemented with extra information, such as victims’ identity (by badge scan), or type of incident. When consolidated on a daily basis, such information would help decision makers plan ahead to indicate required improvements at potentially unsafe areas, or changes in staff behaviour required, if possible, to reduce injuries and fatalities.

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Land acquisition For pipeline construction to take place, a passageway along the pipe’s route is required, for pipes, tools and machinery to freely move and perform all necessary functions such as trenching, stringing, etc. Depending on the agreement with the land owner, this passageway (the ROW) would be acquired temporarily, and returned upon completion. The MPMS would help reinstate the land to its original condition, via photos and location details capturing the state of the land before usage, along with additional information such as type of sand, measurements, terraces, etc. After gathering all those details, MPMS would upload them into ERP, EDMS and GIS systems, so the project management can visually envisage how much impact the construction would have, thereby improving their forward planning, and ensuring the best safety and rights for properties.

Handover deliverables PipeBook The PipeBook report is a full-tracking handover document combining all the construction details to be submitted to the pipeline owner/operator. The main information listed in PipeBook is: • Joint number • Starting pipe tag and ending pipe tag numbers • Welding passes completed per joint and the welder used per weld sector (ROW, trench) • The daily welding report number • NDT (RT, MPI, UT) and testing reports • Field coating reports • Alignment sheet • Pipes specifications: material, Dia heat number, certificate number, mill length, actual length, visual check, etc. • Actual progress tracking for activities such as stringing, coating, lowering, cathodic protection and backfilling A sample PipeBook is shown in Figure 17.

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Fig. 17: Sample PipeBook

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Supporting documents Documents such as drawings, site forms, certificates and other scanned documents are handed over in electronic format.

GIS database This is a database of spatial and non-spatial data that includes links to EDMS documents.

GIS-based system A GIS-based project control solution provides the integration between the collected data, documentation and procedures in EDMS, and a dynamic reporting engine. The EDMS and project controls system are the main sources of information for this GIS data group. Therefore, the GIS system must be dynamically linked and integrated with the relevant systems to ensure live update of the GIS based pipes tracking information. The project controls system feeds the GIS system with the full traceability data of the pipes and shipments, in addition to receipt and issuance activities on ports and lay down yards. The GIS system also gets the work schedules and actual progress completed in construction activities, tagged by location (XYZ coordinates). The EDMS provides the link to all drawings and alignment sheets, aerial photos, land parcel information and documentation, certificates and site reports that were used to feed the project controls system with the required pipe tracking data (please refer to Appendix 7.1.1 in â&#x20AC;&#x153;The Road to Successâ&#x20AC;?, 1st Edition Vol2 for more details about data group and attributes). Figure 18 displays sample integration between the GIS-based system and data stored in the EDMS and project controls systems.

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Fig. 18: GIS-based system and data stored in EDMS (integration sample)

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Conclusions This section highlighted the basic specifications of mobile controls solutions used to automate and report daily pipeline construction site activities using handheld devices in near real-time and load it back into a backend GIS user-interface system. It has elaborated on how the electronic document management system (EDMS) can be used as a tool for pipeline project controls. The EDMS provides the link to all drawings and alignment sheets, aerial photos, land parcel information and documentation, certificates and site reports that were used to feed the project controls system with the required pipe tracking data. The EDMS and project controls system are the main sources of information for the GIS-based project control solution. To ensure live update of the GIS based pipes tracking information, the GIS system must be dynamically linked and integrated with the relevant systems. The project controls system feeds the GIS system with the full traceability data of the pipes, shipments, in addition to receipt and issuance activities on ports and lay down yards. The GIS-based system and data stored in EDMS and project controls systems can be easily integrated.

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13.8 Innovations in CO2 Pipeline Construction 13.8.1 Abstract Carbon dioxide (CO2) is captured to prevent it being discharged to the atmosphere, as it is widely recognized around the world as one of the main causes of climate change. The level of CO2 in the atmosphere is rising as a result of human activities. One of the options that can be used to combat climate change is to capture CO2 produced by power generation and industrial processes and store it deep underground, a process known as carbon capture, transport, and storage (CCTS). The process involves capturing the CO2 produced by the burning of hydrocarbons (e.g. coal and natural gas) before it enters the atmosphere, and storing it deep underground. The main components of CCTS are: 1) capture (separation from the gas stream) at a power plant or an industrial source2) compression 3) transport via pipeline 4) injection into an underground storage formation through a well Oil and gas industries have for many decades been injecting fluids and gases (including CO2) into deep underground storage formations to assist oil and gas production in depleting oil and gas fields, this is a technique known as enhanced oil (or gas) recovery (EOR/EGR). This chapter primarily reviews the pipeline transportation of CO2. This cannot be discussed on its own and techniques of capturing, other modes of transport, and storing CO2 will also be briefly touched on. The challenges, opportunities, equipment, sustainability, facilities, and cost models of CCTS are among the other subjects covered Keywords: Carbon capture transport and storage (CCTS), carbon sequestration, pipeline transportation, carbon dioxide, climate change.

13.8.2 Introduction Carbon dioxide gas (CO2) is found in small proportions in the atmosphere. It is produced by many processes, including respiration in plants and animals. It is widely used commercially, to control nuclear reactor temperatures, in the food and beverage industries, in the medical field, and is also used as a fire extinguisher. It is the historically recent burning of fossil fuels that has started to release large quantities of CO2 into the atmosphere. CO2 is a major greenhouse gas that contributes to the Earthâ&#x20AC;&#x2122;s global warming. Over the past two centuries, its concentration in the atmosphere has greatly increased, mainly because of human activities such as fossil fuel burning. One possible option for reducing CO2 emissions is to capture CO2 at its point of production, and transport it to be stored underground. This technique is called carbon capture, transport, and storage (CCTS). There are other solutions being researched, such as extraction of CO2 from the atmosphere. These other solutions are not as well-developed as carbon capture technology, which in itself is currently in demonstration phases around the world. This chapter reviews the techniques of capturing and transporting CO2, talking about the challenges, opportunities, equipment, sustainability, facilities, cost models, etc. To capture CO2 it is first separated from the other gases resulting from combustion or industrial processes. However, CO2 storage gas will have combustion impurities, such as SOX (sulphur oxides) and NOX (nitrogen oxides), and hence is not as clean as the CO2 gas currently being used for EOR.

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When the emission source is not located directly over the storage site, the CO2 needs to be transported. Small quantities of CO2 could be transported offshore by ship, but transport of larger volumes would require pipeline. Pipelines have been used for this purpose in the USA since the 1970s [10]. CO2 is generally transported in a super-critical phase; it is pumped at high pressure, with booster stations to maintain the pressure. Storage in geological formations is the cheapest and most environmentally-acceptable storage option for CO2. The three main types of geological storage are oil and gas reservoirs, deep saline formations, and un-minable coal beds.

13.8.3 The need for CCTS The future of gas within the European energy mix is coming under increasing scrutiny, in the context of ambitious climate stabilization objectives. To date much of the debate around CCTS has focused on coal. However, the December 2011 European Commission Energy Road map and other studies identify scenarios with a significant ramp-up of gas power with CCTS in decarbonizing the power sector from 2030 [10]. There are multiple practical hurdles to CCTS deployment, creating risks of “carbon lock-in” or “stranded assets”. Chief among these is the absence of a clear ‘business case’ for investment in CCTS given uncertainties around technology, carbon prices, potential load factors and the absence of robust economic incentives to support the additional high capital and operating costs associated with CCTS. Nowadays CCTS is developing and further information and data are being made available. The CO2PIPETRANS joint industry project (JIP) is making experimental data freely available, which will further support global CCTS implementation. The data released by the CO2PIPETRANS JIP complements previously-released data and will greatly assist dense phase CO2 computer model development and validation [6]. Over recent years media attention has focused on the rapid expansion of coal use in China, but politically important countries as diverse as the US, India, South Africa, Australia, Poland, and the UK are concerned by the implications of an end to coal use for their domestic energy security [3]. Addressing climate change means addressing emissions from coal, both technically and politically, starting in this decade; although coal has been the main focus, the same issues are beginning to arise for CO2 gas. Some governments plan to use renewable, nuclear and CCTS as three legs of the low carbon strategy. If CCTS is not available, this removes one of the options and means the other two must be relied on more heavily. Without CCTS, the 30-50GW of coal and gas plant remaining in the UK by 2030 will have to be scrapped or run at low load factor [10]. In Europe the regulations around pipelines are well established, as are the design codes. These regulations do not consider CO2 as a specific named substance in the prescriptive manner of the US federal regulations. This may require changes to the regulations; however in the UK it has been stated that from 2008 until the existing regulations are changed, carbon dioxide is to be considered as if a 'dangerous fluid' for the purposes of the Pipeline Safety Regulations 1996 and as if a 'dangerous substance' for the purposes of control of major accident hazards [3]. Other current legislation in the UK also applies to CCTS for pipelines. Specifically, compliance with the following regulations and requirements must be achieved including any regulations enacted under them; Construction (Design and Management) Regulations 2008; Control of Major Accident Hazards (Amendment) 2005; Deregulation (Pipe-lines) Order 1999; Electricity and Pipe-lines Works (Assessment of Environmental Effects) Regulations 1990 and amendments; Environmental Protection Act 1990; Health and Safety at Work etc.; Act 1974; Health and Safety at Work (Northern Ireland) Order 1978; Pipe-lines Act 1962; Pressure Equipment Regulations 1999; Pressure Systems Safety Regulations 2000, Town and Country Planning Act 1990 [11].

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Property Molecular Critical Pressure Critical Temperature Aqueous Solubility at 25oC, 1 bar Standard (gas) density Density at critical point Liquid density at 0oC, 70 bar Sublimation temp. 1 bar Solid density at freezing point Colour

Unit g/mol bar o C g/l Kg/m3 Kg/m3 Kg/m3 o C Kg/m3 -

Value 44.01 73.8 -56.6 1.45 1.98 467 995 -79 1562 None

Table 1: Specific properties of CO2 Table 1 provides various properties of CO2, and Figure 1 illustrates the CO2 phases for a range of pressures and temperatures. Transportation for storage will generally occur above the critical pressure (86 – 172) atmosphere, and temperature (4 - 38 °C). At standard temperature and pressure, the density of CO2 is around 1.98 kg/m3, about 1.5 times that of air.

Fig. 1: Carbon dioxide: temperature – pressure diagram (state diagram) At atmospheric pressure (1 bar) and a temperature of −78.51 °C (−109.32 °F), CO2 changes directly from a solid phase to a gaseous phase through sublimation, or from gaseous to solid through deposition. Liquid CO2 forms only at pressures above 5.1 atmosphere (bar); the triple point of CO2 is about 518 kPa at −56.6 °C. The critical point is 7.38 MPa at 31.1 °C. Another form of solid CO2 observed at high pressure is an-amorphous glass-like solid. This form of glass, called carbonia, is produced by supercooling heated CO2 at extreme pressure (40–48 GPa) in a diamond anvil. This confirms the theory that CO2 could exist in a glass (solid) state similar to other elements of its family, like silicon (silica glass) and germanium dioxide. Unlike silica and germania glasses, however, carbonia glass is not stable at normal pressures and reverts to gas when pressure is released [5].

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The physical properties of a CO2 stream defined by its individual chemical compounds may vary from the physical properties of pure CO2 in terms of but not limited to: toxicity, critical pressure and temperature, triple point, phase diagram, density, viscosity, and water solubility [15]. Before CCTS, CO2 is first separated from the other gases resulting from combustion or industrial processes. CO2 storage gas will have combustion impurities, such as SOX (sulphur oxides) and NOX (nitrogen oxides).

Fig. 2: CO2 phase envelope (pure case and with impurities present) Figure 2 shows the effect of impurities in the CO2 gas mixture. Impurities affect both the phase envelope and the physical properties, which in turn will affect the operability of the pipeline. Equations of state are needed to accurately predict the mixtureâ&#x20AC;&#x2122;s behaviour. A typical CCTS transportation mixture will comprise >95% CO2, with water content <500 ppm, to prevent occurrence of carbonic acid in the pipeline, which would lead to internal corrosion on the pipe wall if free water in the pipeline was to occur.

13.8.4 CO2 equation of state models Equation of state models are available for 100% pure CO2, but these models become inaccurate as soon as any impurity is added to the CO2 composition stream. Flow assurance and software developers are in the process of updating and benchmarking their equation of state software packages, but until then safety margins should be considered. Specifically, currently available versions of the equations of state are not reliable enough to be used in precise pipeline and compression system designs, to predict the properties of supercritical CO2 which is contaminated with other compounds (i.e. A, N2, O2, CO, NH3, H2S,) at conditions near the critical point. Furthermore, pure CO2 â&#x20AC;&#x2122;sequation of state is not good enough when we have water condensing out. Small amounts of impurities in CO2 change the location of the supercritical line.

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Since the equation of state models for CO2 -based mixtures have not to date been fully developed or validated, large differences (15% variation) exist in gas properties predicted by standard equation of state models and pure CO2 correlation models. This will affect equipment sizing and its rupture point. As a result of the deficiencies in the available data, designers and manufacturers use larger margins of safety than may be necessary in their products, by up to 15%. An illustration of the differences in Figure 3 shows the variation in predicted density of CO2 obtained with various prediction models. This confirms that the variation of density between different models could be as high as 15%.

Fig. 3: Variation in predicted gas density for CO2 mixtures

13.8.5 Pipeline transport of CO2 Efficient transport of CO2 via pipeline requires that CO2 be compressed and cooled to the liquid state. Transport of CO2 at lower densities (i.e. gaseous CO2) is inefficient because of the low density of CO2 and relatively high pressure drop per unit length. Moreover, by operating the pipeline at pressures greater than the CO2 critical pressure of 7.38 MPa, temperature fluctuations along the pipeline will not result in the formation of gaseous CO2 and the difficulties encountered with two-phase flow [14]. The properties of CO2 are considerably different from other fluids commonly transported by pipeline, such as natural gas. Thus, it is necessary to use accurate representations of the phase behaviour, density, and viscosity of CO2 and CO2 -containing mixtures in the design of the pipeline. Figure 4 shows the compressibility of CO2 based on the Pengâ&#x20AC;&#x201C;Robinson equation of state. It shows the nonlinearity in the typical pipeline transport region and the sensitivity to impurities (by mole fraction). The compressibility of CO2 is non-linear in the range of pressures common for pipeline transport and is highly sensitive to any impurities, such as hydrogen sulfide (H2S). Figure 4 also shows the significant difference between the compressibility of pure CO2 and CO2 with 10% by volume H2S. To reduce difficulties in design and operation, it is generally recommended that a CO2 pipeline operate at pressures greater than 8.6 MPa where the sharp changes in compressibility of CO2 can be avoided across the typical range of temperatures that may be encountered in the pipeline system [15].

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Line-pipe with ASME-ANSI class 900 flanges has a maximum allowable operating pressure of 15.3 MPa at 38 °C. Operating the pipeline at higher pressures would require flanges with a higher rating [14]. Over the range of typical conditions shown in Figure 4, the density of CO2 varies between approximately 800 and 1000 kg/m3.Operating temperatures of CO2 pipelines are generally dictated by the temperature of the surrounding soil. In northern latitudes, the soil temperature varies from a few degrees below zero in the winter to 6–8 °C in summer, while in tropical locations; the soil temperature may reach up to 20 °C [14]. However, at the discharge of compression stations, after-cooling of compressed CO2 may be required to maintain phase regime and to ensure that the temperature of CO2 does not exceed the allowable limits for either the pipeline coating or the flange temperature.

Fig. 4: The compressibility of CO2 and the typical pipeline transport region [15]

13.8.6 CO2 collection/capture CO2 could be captured from power plants or industrial facilities which produce large amounts of carbon dioxide. Three systems are available for power plants: post-combustion, pre-combustion and oxyfuel combustion systems. The captured CO2 must then be purified and compressed for transport and storage. Problematically, the technology to capture CO2 from small or mobile emission sources, such as home heating systems or cars, is not yet sufficiently developed. Consequently small or mobile emission sources in homes, businesses or transportation are not suitable for CCTS.

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Table 2 shows typical CO2 stream compositions from various capture technologies vs. the current EOR composition (labelled under Weyburn). Component CO2 N2/Ar O2 Hydrocarbons H2 H2o H2s CO Hg Sox Nox

Post Combustion >95% 0.01

IGCC >95% 0.03-0.06%

Oxyfuel >95% 4.1%

0 0 >95% 0 0 0 <0.01%, <100 ppm <0.01%, <100 ppm

0.01% 0.8-2% >95% 0.01-0.06% 0.03-0.4%

0 >95% 0 0

<0.01%, <100 ppm <0.01%, <100 ppm

0.5% 0.01%

Weburn >95% <4% <5% <100 ppm <1450 ppmv

Table 2: typical CO2 stream compositions from various capture technologies vs. current EOR composition Several factors determine whether CO2 capture is a viable option for a particular CO2 emission source [18]: • The size of the emission source

• • •

Whether it is stationary or mobile How near it is to potential storage sites How concentrated its CO2 emissions are

In 2000, close to 60% of the CO2 emissions due to the use of fuels were produced by large stationary emission sources, such as power plants and oil and gas extraction or processing industries. Table 3 shows the profile by process or industrial activity of worldwide large stationary CO2 sources, with emissions in millions of tons of CO2 /year [10]. The distance between an emission location and a storage site can have a significant bearing on whether or not CCST can play a significant role in reducing CO2 emissions. In broad terms, these figures indicate that there is potentially good correlation between major sources and prospective sedimentary basins, with many sources lying either directly above, or within reasonable distances (less than 300 km) from areas with potential for geological storage. Process Fossil fuels Power Cement production Refineries Iron and steel industry Petrochemical industry Oil and gas processing Other sources Biomass Bioethanol and bioenergy Total

Number of sources

Emissions (MtCO2 yr-1) % CO2 Emissions

4,942 1,175 638 269 470 N/A 90

10,539 932 798 646 379 50 33

78.26 6.92 5.93 4.80 2.81 0.37 0.24

303 7,887

91 13,466

0.67 100

Table 3: CO2 emissions due to the use of fuels [9]

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Principles of CO2 capture Three systems are available for power plants: post-combustion, pre-combustion, and oxyfuel combustion systems. To capture carbon dioxide ( CO2) it is first separated from the other gases resulting from combustion or industrial processes. The captured CO2 must then be purified and compressed for transport and storage [10].

•

In a post-combustion system, the gas produced by combustion of the fuel with air only contains a small fraction of CO2. It is captured by injecting the flue gases in a liquid that selectively absorbs the CO2 (such as a cooled or compressed organic solvent). Nearly pure CO2 can then be released from the liquid, typically by heating it or releasing the pressure. Similar separation processes are already used on a large scale to remove CO2 from natural gas.

•

In a pre-combustion system, the primary fuel is first converted into gas by heating it with steam and air or oxygen. This conversion produces a gas containing mainly hydrogen and CO2, which can be quite easily separated out. The hydrogen can then be used for energy or heat production.

•

Oxyfuel combustion uses pure oxygen to burn the fuel instead of using air which only contains 20% of oxygen and a lot of nitrogen. It results in a gas mixture containing mainly water vapour and CO2. The water vapour is then easily removed from the CO2 by cooling and compressing the gas stream. However, for this process one must first separate oxygen from the air, which is a fairly complex process.

Similar capture systems are already used in several industrial processes, such as hydrogen or urea production, and coal gasification. Many institutes aim to develop new capture technologies and make improvements to existing capture technologies in order to provide significant cost reductions in CO2 capture compared to the current estimates.

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•

Solvent systems Solvents systems remain the industry benchmark. They use carbonate and aminebased systems at pre and post-combustion stages, with the aim of reducing energy usage. However, solvent-based capture systems also have applications to all fuel sources and the investigations should be expanded to other fields, including natural gas and industrial applications. They should include developing cheaper construction materials, developing promoters to improve capture characteristics and using membranes in conjunction with solvents.

•

Membrane systems Relative to absorption or adsorption technologies, membrane technology can be considered a new technology that is undergoing major growth and has the potential to provide significant capture cost reductions.

•

Adsorbent systems The development and application of new materials for adsorbent processes are presently in the development phase. Current research areas include improved zeolitic adsorbents, next generation adsorbents, adsorbents that are optimized for vacuum swing adsorption (VSA) processing, high temperature CO2 capture using metal oxides, improved VSA processes, pre-combustion CO2 capture and the capture of CO2 from natural gas using pressure-swing adsorption (PSA) technology.

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•

Cryogenics/hydrates systems Several projects and research efforts are aiming at developing and applying new cryogenic and hydrate removal processes in order to reduce the cost of CO2 separation from a range of industrial applications, particularly pre-combustion capture and oxyfuels in the first instance, and potentially also in other industries such as the cement and steel industry. They also aim to demonstrate the applicability of these technologies. Initial laboratory trials have been completed. Further laboratory and design work is progressing with a view to take these to pilot scale.

Capture systems reduce the CO2 emissions from combustion plants by about 80 to 90%. These figures take into account the fact that capture systems require additional energy. For new fossil fuel power plants, CO2 capture can increase the cost of electricity production by 35 to 85% depending on different assumptions in plant design, operation and financing. This represents 0.01 to 0.03 US$ per kWh of electricity produced; Table 4 compare these costs [10].

New fossil fuel plants without capture New fossil fuel plants with capture Capture alone

Cost in US$/kWh 0.03 – 0.06 0.04 – 0.09 0.01 – 0.03

Table 4: Costs is US$/kWh of power in fossil fuel plants [10] Capture costs can also be expressed in US$ per net ton of CO2 captured. This unit cost varies greatly for different types of combustion plants and for industrial processes. The unit cost of capture is generally lower where a relatively pure CO2 stream is produced, such as in natural gas processing, hydrogen production, and ammonia production [10].

13.8.7 CO2 storage Capture and geological storage of CO2 provides a way to avoid emitting CO2 into the atmosphere, by capturing CO2 from major stationary sources, transporting it (usually by pipeline), and injecting it into suitable deep rock formations. The subsurface is the Earth’s largest carbon reservoir, where the vast majority of the world’s carbon is held in coal, oil, and gas organic-rich shales and carbonate rocks. Geological storage of CO2 has been a natural process in the Earth’s upper crust for hundreds of millions of years. CO2 derived from biological activity, igneous activity and chemical reactions between rocks and fluids accumulates in the natural subsurface environment as carbonate minerals, in solution or in a gaseous or supercritical form, either as a gas mixture or as pure CO2. The engineered injection of CO2 into subsurface geological formations was first undertaken in Texas, USA, in the early 1970s, as part of EOR projects and has been ongoing there and at many other locations ever since [10]. In a little over a decade, geological storage of CO2 has grown from a concept of limited interest to one that is quite widely regarded as a potentially important mitigation option [20]. There are several reasons for this. Firstly, as research has progressed and as demonstration and commercial projects have been successfully undertaken, the level of confidence in the technology has increased. Secondly, there is consensus that a broad portfolio of mitigation options is needed. Thirdly, geological storage (in conjunction with CO2 capture) could help to make deep cuts to atmospheric CO2 emissions. However, if that potential is to be realised, the technique must be safe, environmentally sustainable, cost-effective and capable of being broadly applied. To geologically store CO2, it must first be compressed, usually to a dense fluid state known as ‘supercritical’. Depending on the rate that temperature increases with

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depth (the geothermal gradient), the density of CO2 will increase with depth, until at about 800 m or greater, the injected CO2 will be in a dense supercritical state (Figure 5) [10].

Fig. 5: Variation of CO2 density with underground depth [9] Geological storage of CO2 can be undertaken in a variety of geological settings in sedimentary basins. Within these basins, oil fields, depleted gas fields, deep coal seams and saline formations are all possible storage formations (Figure 6). The cost of CO2 geological storage is site-specific, which leads to a high degree of variability. Cost depends on the type of storage option (e.g., oil or gas reservoir, saline formation), location, depth and characteristics of the storage reservoir formation and the benefits and prices of any saleable products. Onshore storage costs depend on the location, terrain and other geographic factors. The unit costs are usually higher offshore, reflecting the need for platforms or sub-sea facilities and higher operating costs.

Fig. 6: Options for storing CO2 in deep underground geological formations [10]

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The major capital costs for CO2 geological storage are drilling wells, infrastructure and project management. For some storage sites, there may be in-field pipelines to distribute and deliver CO2 from centralized facilities to wells within the site. Where required, these are included in storage cost estimates. For enhanced oil, gas and coal bed methane options, additional facilities may be required to handle the oil and gas produced. Reuse of infrastructure and wells may reduce costs at some sites. There may be additional costs for remediation work for well abandonment that are not included in existing estimates. Operating costs include manpower, maintenance and fuel. The costs for licensing, geological, geophysical and engineering feasibility studies required for site selection, reservoir characterization and evaluation before storage starts are included in the cost estimates. Storage may require more or less public supervision than transport. The composition of the storage market will depend on the geological availability of storage sites, economies of scale and political choices. In a scenario where the number of independent stores connected to a network is small and owned by just a limited number of firms, public supervision would be required to prevent adverse monopoly behaviour. Alternatively, storage could be integrated with transport or publicly-owned companies. In a scenario with multiple independently-owned stores, competition may flourish, and intervention beyond establishing environmental and safety regimes and providing for liabilities might not be necessary.

13.8.8 Transporting CO2 Except when plants are located directly above a geological storage site, captured CO2 must be transported from the point of capture to a storage site. This section reviews the principal methods of CO2 transport and assesses the health, safety and environment aspects, and costs.

Pipelines for CO2 transport Pipelines have been in use for decades, and large volumes of gases, oil and water flow through pipelines every day. Pipelines today operate as a mature market technology and are the most common method for transporting CO2. Gaseous CO2 is typically compressed to a pressure above 8 MPa in order to avoid two-phase flow regimes and increase the density of the CO2, thereby making it easier and less costly to transport [15]. A CO2 pipeline usually begins at the source of capture and travels directly to the storage site; although, in some cases, it might travel as far as it can in the pipe, then transition to a tanker or ship to finish off its journey. It all depends on where the source, pipeline and storage site are located. Both the public and private sector can own pipelines. You can put a pipeline just about anywhere; underground or under water, with depths ranging from a few meters to a kilometer. The first long-distance CO2 pipeline came into operation in the early 1970s. In the United States, over 2,500 km of pipeline transports more than 40 Million ton CO2 per year from natural and anthropogenic sources, mainly to sites in Texas, where the CO2 is used for oil recovery [15]. These pipelines operate in the dense phase mode (in which there is a continuous progression from gas to liquid, without a distinct phase change), and at ambient temperature and high pressure. In most of these pipelines, the flow is driven by compressors at the upstream end, although some pipelines have intermediate (booster) compressor stations. Pipelines can transport CO2 in three states: gaseous, liquid and solid. Solid CO2 is commonly known as dry ice, and it is not cost-effective to transport CO2 as a solid. Pipelines commonly transport CO2 in its gaseous state. A compressor "pushes" the gas through the pipeline. Sometimes a pipeline will have intermittent compressors to keep the gas moving. The CO2 must be clean (free of hydrogen sulfide) and dry. Otherwise, it can corrode a typical pipeline, which is made of carbon manganese steel. As of yet, there are no standards in place for "pipeline quality" carbon dioxide, but experts say that pipelines built

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from stainless steel would have a lowered risk of corrosion. This, however, may not be economical, since we would have to build brand new pipelines just for CO2.

Environment, safety and risk aspects It should be recognised that CO2 pipelines at the scale that will be associated with CCTS projects are novel to many countries and this should be reflected in the risk management strategy adopted. The risks to people in the vicinity of the pipeline must be robustly assessed and effectively managed down to an acceptable level. To achieve this, CO2 hazard management processes, techniques and tools require critical examination and validation [6]. The safety risk related to transport of CO2 should include but not be limited to controlled and uncontrolled release of CO2. Just as there are standards for natural gas admitted to pipelines, CO2 should emerge as the CO2 pipeline infrastructure develops further. Current standards, developed largely in the context of oil recovery applications, are not necessarily identical to what would be required for CCTS. Low-nitrogen content is important for oil recovery, but would not be so significant for CCTS [8]. However, a CO2 pipeline through populated areas might need a lower specified maximum H2S content. CO2 could leak to the atmosphere during transport, although leakage losses from pipelines are very small. Dry (moisture-free) CO2 is not corrosive to the carbon-manganese steels customarily used for pipelines, even if the CO2 contains contaminants such as oxygen, hydrogen sulphide, and sulphur or nitrogen oxides. Moisture-laden CO2, on the other hand, is highly corrosive, so a CO2 pipeline in this case would have to be made from a corrosion-resistant alloy, or be internally clad with an alloy or a continuous polymer coating [8].

Gaps in current codes There are significant gaps in the current code, which current studies are looking to fill. These gaps include: • Dense phase CO2 release modelling validation data

• • • • • • •

Full scale crack arrest testing Corrosion Material compatibility (elastomers/polymers) Examine effects of contaminants on the phase diagram Hydrate formation/ waste solubility Public communication and interaction Update of recommended practice

13.8.9 Current CCTS studies A number of studies are currently ongoing covering CCTS and testing CO2 pipeline transport. Such studies are very important to fill the gaps in CCTS and to understand the problems and risks of pipeline transport of CO2. These studies and testing areas include:

• • • • • • 142

CO2 PVT modelling/impact of impurities on CO2 behaviour CO2 behaviour during pipeline failure Pipeline depressurisation Fracture arrest (full scale crack arrest) Investigation of corrosion rates at high partial pressure CO2 Material compatibility (polymers and elastomers)

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• • • • •

Effects of impurities Hydrate formation CO2 release and dispersion studies Risk management guidance

CO2 PIPETRANS II • Dense phase CO2 release model validation data • Full scale crack arrest testing • Corrosion: determine the corrosion mechanism and the corrosion rate • Material compatibility (elastomers/polymers) • Examine effects of contaminants on the phase diagram • Hydrate formation and water solubility • Update of Recommended Practice (DNV RP J202) Some of these are discussed below.

Technology The hazard and risk profile for CCTS projects will clearly depend on the technology adopted. For example, if intermediate storage of CO2 proves necessary in order to mitigate pipeline operational issues, then the quantities involved could be substantial and the process would be less inherently safe.

Source term modelling It is necessary to be able to model the consequences of a major release of CO2 in order to inform layout and other safeguards and to demonstrate safety. CO2 is likely to be piped as a dense phase liquid (above the thermodynamic critical pressure but below the critical temperature).

Safety evaluations For CCTS, with few companies or people with hands-on experience and few relevant hazard identification studies, great care should be taken during hazard identification exercises since hazards may be missed, or hazards that are identified may be deemed non-credible due to lack of relevant knowledge. Until experience and knowledge is built up and communicated within the CCTS industry, greater focus should be applied to hazard identification (and risk assessment) to compensate for the lack of experience. Major accident hazard (MAH) risk assessment should be performed to provide estimates of the extent (i.e. hazard ranges and widths) and severity (i.e. how many people are affected, including the potential numbers of fatalities) and likelihood of the consequences of each identified major accident hazard. MAH risk assessment could be used as input to design requirements, operational requirements and planning of emergency preparedness.

Risk basis for design The pipeline shall be designed with acceptable risk. The risk considers the likelihood of failure and the consequence of failure. The consequence of failure is directly linked to the content of the pipeline and the level of human activity around the pipeline. Hence, both the content (CO2) of the pipeline and the human activity around the pipeline need to be categorized, and will provide the basis for safety level implied in the pipeline design criteria. CO2 pipelines have MAH potential due primarily to a combination of vast pipeline inventories and the consequences if CO2 is inhaled at concentrations above threshold level. A precautionary approach to risk management is therefore recommended, and it is recommended that, until sufficient knowledge and experience is gained with CCTS pipeline design and operation, a more stringent fluid categorization should be applied in populated areas, than one would normally apply for CO2, for example more stringently than according to ISO 13623.

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13.8.10 Preliminary route selection Modern peopleâ&#x20AC;&#x2122;s lives are based on an environment in which energy plays a predominant role. Oil and gas are the major participants in the supply of energy, and pipelines are the primary means by which they are transported (Figure 7). It is no coincidence that an extensive pipeline network goes hand in hand with a high standard of living and technological progress.

Routing is extremely important for CO2 pipelines, as any gas leakage will be difficult to detect. Population densities should be avoided, with recommended buffer zones of up to 300 â&#x20AC;&#x201C; 500 m from populated areas. Valleys and low points are also to be avoided as CO2 is denser than air and can accumulate to dangerous concentrations.

Fig. 7: Nation's existing pipeline infrastructure used to move oil and natural gas The general recommendation with respect to CO2 pipeline routing is that a standard approach should be applied, as for route selection for hydrocarbon pipelines. The standards referred to, in combination with the specific CO2 safety aspects and the pipeline design considerations, provided elsewhere in the DNV RP, give the necessary guidance on CO2 pipeline routing issues. Route selection is a process of identifying constraints; avoiding undesirable areas; and maintaining the economic feasibility of the pipeline. Having to divert the pipeline around obstacles can be very costly. For example, an NPS 42 (nominal pipe size 42 inches diameter) pipeline costs more than $1,000 per meter to build [17]. The ideal route, of course, would be a straight line from the origin to the terminal point. However, geography, environmental, design, and construction constraints usually alter the route. The following factors must be considered prior to selecting the optimal route for the pipeline: cost efficiency, pipeline integrity, environmental impacts, public safety, land-use constraints, and restricted proximity to existing facilities.

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The initially selected routes should address the intrinsic and extrinsic constraints inherent to pipeline construction and operation by avoiding or minimizing the various geographic and regulatory restrictions. The following elements headline restrictions, construction challenges, factors that affect routes and factors that can actually help routing and are considered during the selection process. Considering all of these factors, possible routes are first selected. Related to rivers, creeks, lakes, and swamps

• • • • •

Unnecessary crossings Braided channels Areas of erosion potential Bedrock Natural meander progression

Related to physiography

• • • •

Excessively steep slopes Side slopes Rocky slopes Erosive soils

Pipeline route selection, survey, and geotechnical guidelines

• • • •

Rocky soils Sandy soils Earthquake intensities/locations Fault locations/types/movements

Related to the environment

• • • •

Fish spawning areas Endangered species’ habitats Historical and archaeological sites Merchantable timberlands

Other factors

• • • • • • • • •

Existing corridors Road and railway crossings Areas of population concentration Restricted areas such as national parks Native reservations Forest regeneration sites Temporary and permanent access Camp locations (if applicable) Construction schedules

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13.8.11 Materials of CO2 pipelines The selection of materials should be compatible with all states of the CO2 stream [17]. Oxygen and free water is usually removed from the CO2 stream to avoid corrosion. Dry CO2 does not cause corrosion in the carbon-manganese steel generally used in pipelines under ordinary circumstances. If the CO2 cannot be dried it can still be transported through corrosion-resistant (stainless) steel pipes, but this will significantly increase the cost of the pipeline.

Line pipe materials Candidate materials need to be qualified for the potential low temperature conditions that may occur during pipeline depressurization situation. Carbon-manganese steel is considered feasible for pipelines where the water content of the CO2 stream is controlled to avoid formation of free water in the pipeline. Application of homogenous corrosion resistant alloy (CRA) or CRA clad/lined line pipe may be an option, but normally only for shorter pipelines.

Non-line pipe materials Dense phase CO2 behaves as an efficient solvent to certain materials, such as non-metallic seals. With respect to elastomers (a polymer with visco-elasticity, generally having low Young's modulus and high yield strain), both swelling and explosive decompression damage must be considered.

Internal coating Internal coating for either flow improvement or corrosion protection is generally not recommended due to the risk of detachment from the base pipe material in a potential low temperature condition associated with a too rapid pipeline depressurization.

Running ductile fracture control The pipeline shall have adequate resistance to propagating fracture. The fracture arrest properties of a pipeline intended for transportation of a CO2 composition at a given pressure and temperature depends on the wall thickness of the pipe, material properties, in particular the fracture toughness, and the physical properties of the CO2 composition in terms of saturation pressure and decompression speed. The pipeline should be designed such that the rupture is arrested within a small number of pipe joints. The fracture control design philosophy may be based on ensuring sufficient arrest properties of the pipeline base material to avoid ductile running fractures or installation of fracture arrestors at appropriate intervals. To prevent ductile running fractures, the decompression speed of the fluid needs to be higher than the fracture propagation speed of the pipe wall, i.e. if the decompression speed outruns the fracture propagation speed, the fracture will arrest. The particular issue related to CO2 is the step change in rapid decompression speed as the pressure drops down to the liquid-vapour line (saturation pressure). Compared to natural gas, the decompression speed of liquid CO2 may be significantly higher. However, as vapour starts to form, the decompression speed of the CO2 stream drops significantly. To that extent running ductile fractures is a higher concern for CO2 pipeline compared to, for example, natural gas pipelines, this needs to be related to the design pressure of the pipeline. For low design pressure (typically less than 150 bar) [17], CO2 pipelines may come out worse compared to natural gas pipelines. This may, however, not be the case for higher design pressure. A fracture control plan should be established. A coarse assessment of fracture arrest may be performed through the following steps, [17]:

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Step 1: Determine fracture arrest pressure (PA) based on proposed pipeline design in terms of pipeline diameter (D), wall thickness (t) and material specifications. Step 2: Determine the critical (saturation) pressure (PC) based on CO2 stream composition Step 3: If PA > PC, fracture arrest It should be noted that for a CO2 stream containing a significant fraction of non-condensable gases, such as H2, the above approach may be non-conservative. As a consequence of the above approach, low (design) pressure pipeline (thin-walled) will have a lower margin between arrest pressure (PA) and saturation pressure (PC), hence be more susceptible to running ductile fractures. In case neither fracture initiation control nor fracture propagation control is ensured by other means, fracture arrestors should be installed. The feasibility and type of fracture arrestors should be documented. Spacing of fracture arrestors should be determined based on safety evaluations and cost of pipeline repair.

Internal corrosion The primary strategy for corrosion control should be sufficient dewatering of the CO2 at the inlet of the pipeline. For a carbon steel pipeline, internal corrosion is a significant risk to the pipeline integrity in case of insufficient dewatering of the CO2 composition. Free water combined with the high CO2 partial pressure may give rise to extreme corrosion rates, primarily due to the formation of carbonic acid. The most likely cause of off-spec water content is considered to be carry-over of water/glycol from the intermediate compressor stages during compression of the CO2 to the export pressure. There are currently no reliable models available for prediction of corrosion rates with sufficient precision for the high partial pressure of CO2 combined with free water. The presence of other chemical components such as H2S, NOx or SOx will also form acids which in combination with free water will have a significant effect on the corrosion rate.

13.8.12 Design considerations of CO2 pipelines Dry CO2 is inert to commonly used industrial materials. However, CO2 is an acid gas and will react with water to form carbonic acid. Carbonic acid corrosion is a formidable challenge and consideration for facilities that process CO2. Material selection in these environments is governed by the corrosion rate, which can be established by a number of predictive tools. For example, the De Waard/milliams nomogram is used to estimate corrosion rates of carbon steel under various operating temperatures and CO2 partial pressures [17]. The use of CO2 for enhanced oil recovery projects typically requires CO2 transmission by pipeline. The properties of CO2, corrosion rates, and gas mixture make-up, are important considerations toward establishing the material specification for a CO2 pipeline. The gas mixture may include a mix of CO2 and hydrocarbons, which could include liquid components, impacting overall pipeline pressures and creating design issues as the pipeline may need to be designed to operate with either gas, or liquid-phase, content. To be transported in a pipeline, CO2 should be compressed to ensure that single-phase flow is achieved. The most widely used operating pressure is between 7.4 and about 21 MPa [17]. Above 7.4 MPa CO2 exists as a single dense phase over a wide range of temperatures (see Figure 1). Clearly a transmission pipeline can experience a wide range of ambient temperatures, so maintaining stability of this single phase is important in order to avoid considerations of two-phase flow that could result in

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pressure surges. The DNV RP contains a separate section related to design issues that are specific to CO2 and that are normally considered as part of the pipeline concept phase. Some of these issues are briefly presented below [13].

Pipeline routing The general recommendation with respect to CO2 pipeline routing is that a standard approach should be applied, as for route selection for hydrocarbon pipelines. The standards referred to, in combination with the specific CO2 safety aspects and the pipeline design considerations provided elsewhere in the RP, should give the necessary guidance on CO2 pipeline routing issues. For onshore pipelines the population density should be determined according to ISO 13623 [2]. The distances used to determine the population densities should, until CO2 specific distances are defined and stakeholder accepted, be determined using dispersion modelling. Due care should be taken regarding the heavier-than-air characteristic of CO2 and ground topography when determining the zone width along the pipeline.

CO2 stream composition evaluations It is recommended that the CO2 stream composition specification shall be determined based upon technological and economical evaluations, and compliance with appropriate regulations governing the capture, transport and storage elements of a CCTS project.

CO2 composition in integrated pipeline networks In case of mixing of different CO2 streams in a pipeline network, it must be ensured that the mixture of the individual compounds from the different CO2 streams do not cause:

• •

Risk of water dropout due to reduced solubility of one of the streams Undesired cross chemical reactions/effects

Water content Maximum water content in the CO2 stream at the upstream shall be controlled to ensure that no free water may occur at any location in the pipeline within the operational and potential upset envelopes and modes, unless corrosion damage is avoided through material selection. For normal operation a minimum safety factor of 2 should be specified between the specified maximum allowable water content and the calculated minimum water content that may cause water drop within the operational envelope.

Typical pipeline-engineering considerations for CO2 include [2]:

• • • • • •

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Operating pressure Operating temperature Gas mixture composition Corrosivity Ambient temperatures Pipeline control (SCADA)

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Examples of additional specific design considerations in place for CO2 pipelines are:

• • • • • • • •

Effect of cooling from pressure changes Requirement for dehydration of CO2 Routing topography Dispersion pattern Valve materials Compressor, seal, and auxiliary materials Requirement to minimise flow transients Risk assessment focused on impact of rupture on human health

13.8.13 Pipeline protection/external protection Buried pipelines are subject to external corrosion caused by the action and composition of the soils surrounding them. During the design stage, the types of external coatingmaterial and cathodic systems required to protect the pipeline from external corrosion must be defined [17]:

Pipeline design and construction: a practical approach Pipeline coating and cathodic protection are chosen according to economics and ability to protect the pipeline. External coating is usually a plastic material that is wrapped or extruded onto the pipe or fusion-bonded to the surface. External coatings have to be designed to serve as a corrosion barrier and to resist damage during transportation, handling, and backfilling. Therefore, in some cases corrosion protection coatings are combined with other external coatings, such as insulation, rock-shield, or concrete.

Internal protection Fluids containing corrosive components such as salt water, hydrogen sulphide (H2S), or carbon dioxide/monoxide can cause internal corrosion. Many of the internal corrosion problems can he corrected in the design stage. This is done by proper design and selection of materials appropriate for the fluid to be transported. Sour gas is natural gas or any other gas containing significant amounts of hydrogen sulphide (H2S). Although the terms acid gas and sour gas are sometimes used interchangeably; a sour gas is any gas that specifically contains hydrogen sulphide in significant amounts, whereas an acid gas is any gas that contains significant amounts of acidic gases such as CO2 or hydrogen sulphide. Thus, carbon dioxide (CO2) by itself is an acid gas, not a sour gas.

Corrosions in CO2 pipelines Pitting corrosion A specification for the line pipe material developed at the design stage ensures that the pipe produced is suitable for the operating temperatures that will be encountered. Pitting corrosion results from chemical attack at low points where fluids settle and accumulate in the piping system.

General corrosion General corrosion results from chemical attack and usually occurs on the upper half of the pipe wall adjacent to low areas where the pipe wall is alternately wet and dry. The use of corrosion inhibitors has proven to be the only effective method to mitigate internal corrosion. On-stream pigging facilities are generally incorporated into the design of the system to permit the removal of liquid accumulation on a schedule. On-stream pigging also improves the distribution of the corrosion inhibitors and is a valuable aid in the mitigation of internal corrosion. 149

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Erosion corrosion Erosion corrosion results from impingement of fluids/chlorides on the pipe surface at high flowing velocities. Piping is generally sized to limit flowing velocities below the critical velocity at which corrosion erosion will begin to occur. Critical velocity is defined as the point at which velocity is a significant factor in the removal of inhibitor films or corrosion products [17].

In-line inspection In-line inspection of pipelines for internal and external corrosion, metallurgy, and weld condition is extensively used for integrity management. A main challenge for in-line inspection is the medium through which the inspection tool must travel. One of the most challenging media is CO2. Although CO2 is not very aggressive chemically, under certain conditions it is a very strong solvent. The size and shape of the molecules allow it to diffuse into nearly every type of rubber or plastic, hence its critical effect on numerous parts of inspection tools, e.g. cables and sensors. Another issue is the dryness of the transported CO2, which can lead to high frictional wear on the cups and discs, and can also prevent the equalization of potential electrical conductivity. The wear of the cups and discs can limit the length of line that can be pigged. The electrical charge that can build up due to the movement of the cups and discs along the pipe wall can damage the electrics of the tool. In-line inspection tool providers are aware of the issues, and solutions are available. For instance, different materials have been developed for the cups and disc. Although parts may still wear, or get damaged, during the in-line inspection, they should not impact the performance and data gathering of the in-line inspection. Therefore, the main consequences for inspecting CO2 pipelines is the additional cost for replacing worn and damaged parts subsequent to an inspection. To overcome this, a number of in-line inspection companies have conducted tests in order to establish appropriate levels of CO2 resistance for in-line inspection materials. In summary, internal inspection of CO2 pipelines in both gaseous and dense phase is deemed to be proven, and commercially available from a number of inspection companies, who are confident in their ability to inspect CO2 pipelines. With ongoing experience and technology updates, inspection of CO2 pipelines will be no different to inspecting oil and gas pipelines.

13.8.14 CO2 dispersion studies Pipeline failure can lead to CO2 escaping from the pipeline, and potentially damaging the pipeline material and also endangering life (Figure 8). It is possible for dangerous levels of CO2 to form outdoors in trenches, depressions or valleys, This is particularly likely when the gas is colder than the surrounding air, which may occur following pressurized release, or due to undetected leaks. Dispersion modelling involves analysing and evaluating risks of how far CO2 will travel following a pipeline failure, or leak, and at what concentrations.

Fig. 8: Dispersion of CO2

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Although dispersion modelling of gases and liquids emitted from vessels and pipelines has been undertaken routinely by industry for several decades as part of a safety risk assessment, carbon dioxide, CO2, presents a number of new challenges to dispersion models due to its particular thermodynamic properties. Due to this, there are a number of industry research exercises ongoing on how to best model CO2 dispersion, and also the validation of the analysis methodology and models. There is currently very little publicly-accessible experimental data on CO2 releases of the magnitude and physical characteristics expected from a dense phase CO2 pipeline. A number of collaborative projects are being planned, and one or two have recently commenced e.g. CO2PIPETRANS II, COOLTRANS. This means that validation of CO2 dispersion models, particularly with regard to prediction of leakage rates and thermodynamic properties of plumes is not as well-developed as would ideally be the case. The COOLTRANS research programme involves collaboration between a number of universities and recognized industry experts to conduct experimental and theoretical studies to address knowledge gaps in the theoretical models used for predicting the behaviour of CO2 under release conditions in which it decompresses, flows out of the pipeline, and disperses, and the pipeline material properties which are required to control failure and the behaviour of any defects in the pipeline. The aim is to enhance existing engineering models and methods applied in dispersion analysis. A primary safety issue is the possibility of solid or â&#x20AC;&#x153;dry iceâ&#x20AC;? discharge during an accidental release. This is relevant given the near-adiabatic decompression process and the unusually high Joule Thomson coefficient expansion of CO2. Solids discharge will affect many aspects of the ensuing hazard spanning the erosion of surrounding equipment, atmospheric dispersion, and potentially the pipe propensity to fracture propagation. The main commercially available software used for dispersion modelling is the PHAST dispersion model (version 6.54 and the new revision 6.6) which can be used to make predictions of CO2 concentrations at sensitive receptors intercepted by the plume from a leaking CO2 source (Figure 9). PHAST can be used to assess the extent of adverse CO2 concentrations, for appropriate leakage scenarios from pipeline under most circumstances, but may not be suitable for dispersion analysis in heavily built-up areas of plant or areas of varying topography.

Fig. 9: Modelling of a plume from a leaking CO2 source

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Computational fluid dynamics (CFD) software, such as ANSYS, is sometimes used to supplement the use of the PHAST model. This is for assessing CO2 flows around buildings as part of a safety risk assessment, and situations of potential CO2 accumulation such as certain topographical features. CFD modelling can also be used to test various assumptions implicit in the PHAST dispersion model, in order to increase the confidence of the PHAST predictions. In particular, the sensitivity of assumptions made regarding rate of sublimation of solid CO2 formed in the initial jet of a CO2 leak to the subsequent dispersion can be examined.

13.8.15 Leak detection Pipelines are built to defined codes and standards that are subject to regulatory approval to assure a high level of safety, particularly in populated areas. Pipelines in operation are monitored internally and externally by corrosion monitoring and leak detection systems. In the event of a leak, transport of gas is shutdown automatically, assuming the leak is detected. CO2 leaking from a pipeline is potentially a physiological hazard to humans and animals. As CO2 has a higher density than air, it may accumulate locally to dangerous levels under calm conditions. Particular care must therefore be taken when CO2 pipelines go through populated areas. This is similar to the challenges involved in pipeline transport of hydro-carbon gases. Should CO2 be transported through populated areas, specified maximums of toxic impurities would be set much lower. If the CO2 contains significant levels of hydrogen sulphide (H2S), this could significantly increase the impact of a leak or rupture. Leak detection systems are continually evolving over the years and can be of different types. A computational pipeline monitoring (CPM) system measures the fluid volume entering the pipeline and compares it to the fluid volume exiting the line, and this system can detect leaks to very low levels. Leak detections systems can sometimes take time to confirm the leak, and hence to initiate closure of any isolation or sectional valves, whilst allowing the leaking gas to accumulate at the land contours and collect in low points on the terrain. Since CO2 is dangerous in low concentrations, the time lag for closing may not be acceptable. The current systems may not be suitable since it is necessary to detect small leaks before these become catastrophic. Considering that embrittlement can occur at the leakage area, a small leak can lead to a large leak of CO2 quite rapidly. To support safe pipeline operation, it may be prudent to use odorants to allow detection of low level leaks that give early warning for impending failures or â&#x20AC;&#x153;weak linksâ&#x20AC;? in the pipeline. Other alternatives include using pipe-in-pipe technology in high risk locations whereby the pipe carrying CO2 is contained within a carbon steel carrier pipe. The annulus could contain sensors and annulus pressure monitors to provide early warning for system leaks (Figure 10) [19].

Fig. 10: Pipe-in-pipe technology with gas detection and annulus pressure monitors [19]

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Other options include event detection methods that sense local ground movement around the pipeline. This would include burying a fibre-optic cable in the same trench as the pipeline. The fibre-optic cable would detect any noise (e.g. hissing noise from a leak), or any ground movement, and alert the operators, who can either go the event location for a visual inspection, or shut the pipeline down (Figure 11) [19].

Fig. 11: Example of event detection method [19]

13.8.16 Pipeline cost model Detailed construction cost data for actual CO2 pipelines are not readily available. Therefore, the data set used to develop the pipeline capital cost model is based on natural gas pipelines. However, there are many similarities between transport of natural gas and CO2. Both are transported at similar pressures, approximately 10 MPa and greater [15]. Assuming the CO2 is dry, which is a common requirement for CCTS, both pipelines will require similar materials. Thus, a model based on natural gas pipelines offers a reasonable approximation for a preliminary design model used in the absence of more detailed project specific costs. The costs of pipelines can be categorised into three items:

• •

Construction costs

• • • • • •

Installation costs (labour)

Material/equipment costs (pipe, pipe coating, cathodic protection, telecommunication equipment; possible booster stations) Operation and maintenance costs Monitoring costs Maintenance costs (Possible) energy costs Other costs (design, project management, regulatory filing fees, insurances costs, right-of-way costs, and contingencies allowances)

The pipeline material costs depend on the length of the pipeline, the diameter, the amount of CO2 to be transported and the quality of the carbon dioxide. The CO2 pipeline capital cost model, published in the literature, is based on regression analyses of natural gas pipeline project costs published between 1995 and 2005 [16]. These project costs are based on Federal Energy Regulatory Commission (FERC) filings from interstate gas transmission companies. The entire data set contains the ‘‘as built’’ costs for 263 on-shore pipeline projects in the contiguous 48-states and excludes costs for pipelines with river or stream crossings as well as lateral pipeline projects (i.e., a pipeline of secondary significance to the mainline system, such as a tie-in

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between the mainline and a power plant) [15]. Costs from each year’s projects have been adjusted to 2004 US dollars using the Marshall and Swift equipment cost index. The pipeline data set contains information on the year and location of the project and the length and diameter of the pipeline. Locations are listed by state in the data set; however, to develop the regression models, the states have been grouped into six geographical regions. The total construction cost for each project is broken down into four categories: materials, labour, rightof-way (ROW), and miscellaneous charges. The materials category includes the cost of line pipe, pipe coatings, and cathodic protection. Labour is the cost of pipeline construction labour. ROW covers the cost of obtaining right-of-way for the pipeline and allowance for damages to landowners’ property during construction. The miscellaneous includes the costs of surveying, engineering, supervision, contingencies, telecommunications equipment, freight, taxes, allowances for funds used during construction, administration and overheads, and regulatory filing fees [22]. Figure 12 shows results from the model as a function of pipeline distance for a project in the Midwest USA for four different design mass flow rates. In this example the pipeline capacity factor is assumed to be 100%, so the annual mass transported equals the design capacity of the pipeline. Figure 12 shows that the levelised transport cost increases with distance and decreases with increasing design capacity for a fixed distance. For a typical 500 MW power plant (emissions of approximately 2–3 million tons per year), the transport cost could range from US$ 0.15 per ton for a 10 km pipeline to US$ 4.06 per ton for a 200 km pipeline based on a 100% capacity factor [15].

Fig. 12: Illustrative results from a transport model showing the total transport cost over a range of pipeline design capacities and pipeline lengths. (All costs in 2004 US dollars) [15] For an annual capacity factor of 75% (typical for existing coal-fired power plants), the levelised cost per ton would increase to between US$ 0.20 per ton for the 10 km pipeline to US$ 5.41 per ton for 200 km pipeline. Figure 12 also illustrates the differences in levelised cost between the same pipeline constructed in the Northeast and Central regions. For all pipeline distances and all pipeline design capacities, the transport cost is lowest in the Central region and highest in the Northeast region [15].

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Illustrative results from the pipeline model were developed using parameters representative of a typical coal-fired power plant in the Midwest region of the United States (Table 5). Several parameter values (e.g. capital recovery factor) are default values from the IECM software [15]. Table 5 includes a nominal CO2 mass flow rate and pipeline length, but these two parameters are varied parametrically in the case study results presented here.

Model parameter Pipeline parameters Design mass flow (Mt/year) 5 Variables Pipeline length (km) 100 Variables Pipeline capacity factor (%) 100 Uniform (50, 100) Ground temperature (8C) 12 Inlet pressure (MPa) 13.79 Uniform (12, 15) Minimum outlet pressure (MPa) 10.3 Pipe roughness (mm) 0.0457 Economic and financial parameters Project region Midwest Capital recovery factor (%) 15b Uniform (10, 20) Annual O&M cost (US$/km/year) 3250 Uniform (2150, 4350) Escalation factor for materials cost 1 Uniform (0.75, 1.25) Escalation factor for labour cost 1 Uniform (0.75, 1.25) Escalation factor for ROW cost 1 Uniform (0.75, 1.25) Escalation factor for miscellaneous cost 1 Uniform (0.75, 1.25)

Deterministic value

Uncertainty distribution

5 100

Variable Variable

100 12 13.79 10.3 0.0457

Uniform (50, 100) Uniform (12, 15)

Midwest 15b

Uniform (10, 20)

3250

Uniform (2150, 4350)

Uniform (0.75, 1.25)

a This parameter is modelled as a series of discrete values. b Corresponds to a 30-year plant lifetime with a 14.8% real interest rate (or, a 20-year life with 13.9% interest rate). Table 5: Illustrative case study values for the model parameters [15] For the case study CO2 pipeline, the total levelised cost is estimated to be US$ 1.16 per ton of CO2 transported. The cost category that accounts for the largest regional difference is the labour cost, which is lowest in the Southwest and highest in the Northeast. In this example the pipeline capacity factor is assumed to be 100%, so the annual mass transported equals the design capacity of the pipeline. CCTS is a high cost abatement option and will remain so in the short-term. It is technically immature (at least in terms of integrating capture, transport and storage in full-scale projects) and, unlike renewable energy and energy efficiency, it does not generate revenues if there is no carbon price or a commercial market for the captured CO2 for enhanced oil recovery. Current carbon prices are well below CCTS costs (Figure 13) [12]. This is because current short-term emissions targets can be met without the use of CCTS. Research and development, and experience gained from demonstration projects will lower costs, while rising carbon prices will boost revenues.

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Fig. 13: Current carbon prices from the EU Emissions Trading Scheme or the Clean Development Mechanism [12]

13.8.17 Future challenges The future role of gas-fired power generation in Europe is coming under increasing scrutiny, in the context of ambitious climate stabilization objectives. Scenarios developed by civil society, industry and the European Commission consistently point to an increasingly important role for gas power to provide flexible generating capacity that can respond to intermittent generation from renewable. But, despite gas possessing lower carbon content than coal, these studies also indicate that gas plants may need to fit CCTS technology in the future. The European Commission’s Energy Roadmap 2050 sets out the scale of the challenge: “For all fossil fuels, carbon capture and storage will have to be applied from around 2030 onwards in the power sector in order to reach the decarbonisation targets […]. Without CCTS, the long term role of gas may be limited to back-up and balancing renewable energy supplies.” These statements present a fresh perspective for consideration in CCTS policy debates, where the overwhelming focus over recent years has been on how CCTS could enable the continued use of coal and lignite. Gas CCTS has not received the same level of priority, for example in respect to funding CCTS demonstration projects. But despite this lower level of attention, the Energy Roadmap 2050 and other studies identify a significant ramp up of gas power with CCTS in decarbonising the power sector through to 2050. Europe is likely to experience a “dash for gas” in its power sector in the next two decades, with currentlyplanned gas plants expected to double EU gas power capacity. This is both an opportunity and a challenge for Europe’s decarbonisation mission. The European Commission’s Energy Roadmap 2050, published in December 2011, identified the need for a significant ramp-up of gas power with CCTS and indicated that gas CCTS will be of greater importance than coal CCTS within two decades. But practical challenges could yet limit the deployment of gas CCTS. In particular, it must be practical to capture CO2 at individual gas plants, and transport it to storage sites with sufficient capacity for storage. It has been reported that by 2030 over 60% of gas power plants will either not have been assessed for capture readiness or will face difficulties in accessing CO2 storage. This highlights the risk of fresh investments locking in generating plant to locations unsuitable for CCTS and increasing the future costs of decarbonisation.

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More positively, our analysis indicates that the practical potential for gas CCTS could reach 50 to 100 GW by 2030 under different policy scenarios. However, this will only be delivered with strong support from governments and the European Commission to require meaningful capture readiness actions from plants constructed during the coming “dash for gas”. Such actions would help provide wider impetus for the application of CCTS for the power sector and industry worldwide. Governments can begin to address the challenges of the capture, transport and storage of CO2 for gas power plants through their implementation of the CCTS directive. The European Commission can actively increase industry expectations and create positive momentum in support of gas CCTS deployment. This will require fresh proposals for financial and regulatory incentives that support the business case for gas CCTS, as well as attention to the practical barriers to deployment. Encouragingly, the five biggest economies of the EU have the greatest potential for CCTS by 2030. It is, therefore, the actions of a few key countries in Western Europe which will largely determine the uptake of gas CCTS in the next 20 years and, by implication, the future of gas-fired power generation in the EU. CO2 capture and storage is technologically feasible and could play a significant role in reducing greenhouse gas emissions over the course of this century. Although parts of the technology are tried and tested, increased knowledge, experience, and reduced uncertainty about specific aspects of CO2 capture and storage would be important to enable its large-scale deployment. First, the technology needs to mature further. While the individual components of CO2 capture and storage are well-developed, they still need to be integrated into full-scale projects in the electricity sector. Such projects would demonstrate whether the technology works when fully scaled up, thus increasing knowledge and experience. More studies are needed to analyse and reduce the costs and estimate the potential capacity of suitable geological storage sites. Regarding other forms of storage, pilot scale experiments on mineral carbonation are needed to reduce costs and net energy requirements. In addition, studies concerning the ecological impact of CO2 in the deep ocean are required. The adequate legal and regulatory environment also needs to be further developed. This must include agreed methods for estimating and reporting the amount of CO2 avoided by CO2 capture and storage as well as the amounts that may leak over the longer term. Long-term liabilities regarding geological storage and potential legal constraints on storage in the marine environment need to be taken into account. Other issues to be resolved include the potential for transfer and diffusion of CO2 capture and storage technologies, opportunities for developing countries to exploit them, application of these technologies to biomass sources of CO2, and the potential interaction between investment in CO2 capture and storage and other mitigation options. There are a number of CO2 storage pipelines already operating. Ongoing CO2 pipeline transportation technology research includes:

•

Quantitative hazard assessment, addressing accurate predictions of fluid phase, discharge rate, and atmospheric dispersion; quantifying hazardous consequences; basis for emergency response and land use planning

• • •

Materials for CO2 pipeline transport systems Steady state and transient modelling Anthropogenic CO2 corrosion with focus on the effect of impurities.

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13.8.18 Conclusions and recommendation One possible option for reducing CO2 emissions is to capture CO2 and transport it to be stored underground. This technique is called carbon capture, transport, and storage (CCTS). This chapter reviews the techniques of capturing and transporting CO2, talking about the challenges, opportunities, equipment, sustainability, facilities, and costs. CCTS is still a high-cost option and will remain so in the short term. It is technically immature (at least in terms of integrating capture, transport and storage in full-scale projects) and, unlike renewable energy and energy efficiency, it does not generate revenues if there is no carbon price or a commercial market for the captured CO2 for enhanced oil recovery. This is because current short-term emissions targets can be met without the use of CCTS. Research and development, and experience gained from demonstration projects will lower costs, while rising carbon prices will boost revenues. CCTS will require support for both capital deployment and the operation of capture units, networks and storage. Faced with a combination of technology risk, immature regulatory and policy frameworks and low or absent market revenues, capital providers will be reluctant to commit substantial sums. Investment support will be necessary, in the form of grants and/or provision of debt or equity capital, as will operating support for CCTS (i.e. incentive mechanisms to provide additional revenue for each unit of output where a CCTS unit is operational). Plants fitted with CCTS will have higher operating costs, but often no additional revenue. Among other conclusions and recommendations are: 1. There are risks associated with CO2 transport; were the gas to leak, it can collect in low ground with a risk of asphyxia at high concentrations, since it is denser than air. This can be mitigated with appropriate design and monitoring and careful siting. 2. It is during the injection of CO2 that the fluid pressures are greatest and the CO2 is most mobile and hence potentially able to escape. Over time, the CO2 will dissolve, precipitate or become trapped and the pressure dissipates. This implies that proper monitoring and injection design is needed for the duration of the project, but not necessarily long afterwards. 3. It is cheaper to collect CO2 from several sources into a single pipeline than to transport smaller amounts separately. Early and smaller projects will face relatively high transport costs, and therefore be sensitive to transport distance, whereas an evolution towards higher capacities (large and wide-spread application) may result in a decrease in transport costs. 4. There is a huge amount of field experience from the oil industry of injection of CO2 deep underground. CO2 storage is quite well understood with over one hundred sites worldwide where CO2 has been injected. Over time, CCTS technology will mature and investors will become more familiar with it. As emission reduction targets become more demanding, firms will come to understand where the best opportunities lie. Policy makers may either direct emissions savings where they believe them to be most cost-effective or simply let the market decide where to invest. Without further policy support for operations, the asset will not be used. The policy choices fall under four broad themes and the policy approach is likely to shift over time: • Funding: incentives for capital deployment or for operations

• • •

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Costs and risks: borne by the public sector or the private sector Subsidies/penalties: subsidising abatement or penalizing emissions Technology support: targeting CCTS-specific incentives or technology-neutral incentives.

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

Over time, risks surrounding the technology will diminish and the regulatory and policy framework will become better established and understood. As returns over the lifetime of the asset are substantiated, investors will be more willing to commit funds without capital support. If expectations are realised, capital support can decline and make way for a greater emphasis on operating support.

References 1.

Aarnesa J. and Selmer-Olsena S. and Carpentera M. Flacha T. (2009): Towards guidelines for selection, characterization and qualification of sites and projects for geological storage of CO2. Elsevier Ltd. Norway.

Barrie J. and Brown K. and Hatcher P. (2004): Carbon Dioxide Pipelines: A Preliminary Review of Design and Risks. Canada.

Blunt M. (2010). Carbon Dioxide Storage: Grantham Institute for Climate Change, Briefing Paper No 4. Imperial College, London.

Carbon Capture and Storage (2012). From Wikipedia, the free encyclopedia: http://en.wikipedia.org/wiki/Carbon_capture_and_storage.

Carbon dioxide (2012). From Wikipedia, the free encyclopedia: http://en.wikipedia.org/wiki/Carbon_dioxide#Physical_properties.

Det Norske Veritas (DNV) (2010). Project Specific Guideline for Safe, Reliable, and CostEffective transmission of CO2 in Pipelines, Energy Report. Joint Industrial Project (JIP),

Eldevik F. and Graver B. and Torbergsen L. and Sau O. (2009): Development of a Guideline for Safe, Reliable and Cost Efficient Transmission of CO2 in Pipelines. Elsevier Ltd. Norway.

Energy Institute (2010). Good Plant Design and Operation for Onshore Carbon Capture Installations and Onshore Pipelines. London, www.energyinst.org

Enviance (2006). Meeting the GHG Challenge, Developing the Right Reporting Solution, White Paper. USA, www.enviance.com.

10.

IPCC Special Report on Carbon dioxide Capture and Storage (2005). Carbon Dioxide Capture and Storage. UK, www.ipcc.ch.

11.

Green Alliance Policy In sight (2012). The CCS Challenge, Securing a second chance for UK Carbon Capture and Storage. London, www.green-allinace.org.uk.

12.

International Energy Agency (IEA) (2012). A Policy Strategy for Carbon Capture and Storage. Information paper. France, www.iea.org.

13.

Johnsen K., Helle K., Roneid S. and Holt H. (2011). DNV Recommended Practice: Design and Operation of CO2 Pipelines. Elsevier Ltd.

14.

Johnsen K., Helle K. and Myhrvold T. (2009); Scale-up of CO2 capture processes: The role of Technology Qualification. Elsevier Ltd.

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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

•

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

โ ข

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.

•

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

•

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).

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Acknowledgements

Third Edition Acknowledgements The persons and Companies who participated in the preparation of this Third Edition are presented below.

•

The work was divided among five working groups: 1. Earthworks Co-Chairmen: Paul Andrews (Fluor) & Bruno Pomaré (Spiecapag) Participants: Adam Thomas, Jon Baston-Pitt & Raphael Denis (Fugro); Mike Sweeney & David Waring (BP); Marco Albanesi & Vincenzo Calabria (Sicim); Diana Pfeff & Marc Peters (Herrenknecht); Marcelo Texeira & Tales Mattos (Petrobras); Marco Laurini & Livia Giongo (Laurini); Flavio Villa (Tesmec); Johannes Mayr (Liebherr); Lars-Inge Larsson (Volvo); David Shilston (Atkins); George Tuckwell (RSK); Neil Smith (Mears); Rene Albert (Wermeer), Daniel Gasquet (IPLOCA) 2. Pipelines and the Environment Co-Chairpersons: Sue Sljivic (RSK) & Adul Waasay Kan (SNC Lavalin) Participants: Alejandro Sarrubi (Techint); Loek Vreenegoor & Fred Williams (Shell); Goeff Tabor (RSK); Ricardo Marcus (TGP); Barbara Lax (Caterpillar); Martin Coleman (Spiecapag) 3. Future Trends and Innovation Chairman: Zuhair Haddad (CCC) Participants: Mustafa Abusalah, Firas Hijazi, Antoine Jurdak & Ramzi Labban (CCC); Luca Prandi (ENI); Abbay Chand & Mike Gloven (Petro IT); Maurizio Truscello (Bonatti); Paul Andrews & Sub Parkash (Fluor); Bruno Pomaré (Spiecapag); Andrea Trevisanello & Massimo Passarella (Goriziane); Geert Dieperink (Maats); Marco Jannuzzi (Caterpillar); Jan van der Ent (Applus RTD); Idsart van Assema (Dhatec) 4. Logistics Co-Chairmen: Bruno Pomaré (Spiecapag) and Bernard Quereillahc (Volvo CE) Participants: Cindy Verhoeven (Dahtec); Christophe Kapron (Renault Trucks); Jean-Michel Gallois (Vopak); Frédéric Teitgen (TOTAL); Oscar Scarpari (Techint); Firas Hijazi (CCC) 5. Welding Co-Chairmen: Jan van der Ent (Applus RTD) & Gustavo Guaytima (Techint) Participants: Benedict de Graaff, Scott Funderburk & Paul Spielbauer (CRC-Evans); Frédéric Lepla (Serimax); Fabio Rinaldi & François Pesme (PWT); Matt Boring (Applus RTD); Kevin Beardsley (Lincoln Electric); Atilla Madazilioglu (TEKFEN); Ramesh Singh (GIE); Derick Railling & Mike MacGillivray (ITW); Daniel Matarrese (Techint); Anthony Van Der Heijden (Lastechniek Europa); photos courtesy of ESAB.

Onshore Pipelines - THE ROAD TO SUCCESS Vol. 2 Acknowledgements

â&#x20AC;˘

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, Sarah Junod and Elizabeth Spalding. Editing and English review were performed by Guy Henley and Edmund Henley (Consultants). Doug Evans (GIE) 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 Third Edition of the Road to Success (in alphabetical order by company): Volker Boerschel (Akzo Nobel); Frits Doddema (Seal-for-Life); Norbert Jansen (Borealis); Barry Turner & Pascal Collet (Axon Coatings); Pascal Lafferierre & Nigel Goward (Canusa CPS); (GE Measurement & Control); Frank Muffels (Industrie Polieco (MPB)); Axel Kueter (NOV Tuboscope); Sean Haberer, Vlad Popovici & Alex Durkovics (ShawCor); Rainer Kuprion (TIB Chemicals).