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X80 Pipeline Cost Workshop

Conference Preprints

Editor and Technical Director

Leigh Fletcher

Hotel Grand Chancellor, Hobart Wednesday 30 October 2002

In conjunction with the APIA Annual Convention

the

australian PIPELINE industry association Inc.

Page 2 of 131 Hobart October 30 2002

1st Floor, National Circuit, Barton ACT 2600

PO box 5416, Kingston ACT 2604 Telephone: 02 6273 0577 · Facsimile: 02 6273 0588

EMAIL: [email protected] WEBSITE: www.apia.net.au

X80 Pipeline Cost Workshop

An initiative of the APIA Research and Standards Committee

Chair

Sue Ortenstone

Chief Executive Officer Epic Energy

Editor and Technical Director

Leigh Fletcher

Managing Director MIAB Technology Pty Limited

PO Box 413 Bright Victoria 3741 Tel: 03 5755 1242 Mobile: 0418 426 419

Email: [email protected]

8:00 am to 5:30pm Wednesday 30 October 2002

Hotel Grand Chancellor 1 Davey St Hobart Tasmania 7000

X80 Pipeline Cost Workshop Australian Pipeline Industry Association Research and Standards Committee


APIA acknowledges and expresses its gratitude to the Sponsors whose contributions made the

Workshop possible



Preface Seven years ago in 1995, only 3 years after the first Australian X70 pipeline was commissioned, the WTIA/APIA Research panel 7 held a Conference in Wollongong entitled "Welding of high strength thin – walled pipelines". That Conference, like this one, was also held in conjunction with the APIA Annual Convention of that year, and to further the coincidence, I was also the Technical Director and Editor of that event. The purpose of the 1995 Conference was directed to the "… safe, more cost effective and trouble free construction of high strength thin walled pipelines". At the time, it was fully expected that that first X70 pipeline, the Santos Ballera to Moomba pipeline (BMP), would be rapidly followed by the first X80 pipeline. The BMP had also been the first pipeline designed for an MAOP of 15.3MPa, and it had been explicitly designed to transport rich gas in two phase flow. It was very much a cutting edge design, and Australia was clearly in a leadership position at that time with respect to the adoption of new technology for small diameter pipelines. The 1995 Conference, and the research which led up to it, was the forerunner of a very intensive period of Australian pipelines research, most of it directed to the safe and effective use of thinner walled high strength steels so as to reduce the capital cost of building new pipelines, and so as to ensure that the wall thickness reductions did not pose problems for the safe operation and maintenance of those pipelines. I was involved in all of this work. At the time I was working for Tubemakers of Australia, and was involved in the development of the technical and business cases for the development and commercial offering of X80 pipe. And soon after that I became the Director of the CRC for Welded Structures which played a large role in the conduct of the ensuing industry sponsored and led research. In the period since that time, a great deal of research and development has been promulgated in various ways that was intended to identify all of the barriers to the use of high strength pipe, and to overcome those barriers so that the industry and its stakeholders would reap the benefits of increased efficiency. So, it is with a mixture of some disappointment and a sense of challenge that I agreed to a request from Richard Robinson (then of Epic Energy) to take on the task of directing this Workshop. We have not yet built an X80 pipeline in Australia, and this is in spite of there being several opportunities that, on the face of it, seemed to be ideally suited. (A section of the Roma-Brisbane pipeline was built with X80 pipe, but that pipeline is not designed to take full advantage of the properties of the X80 pipe.) Despite numerous enquiries and discussions on the subject I have been unable to discover any technical reason for this failure to proceed to the next step. The answer on each occasion has been that the decision to continue with X70 was because the risk/reward profile of the decision was not sufficiently attractive. It has also been said by a number of observers that although there is a great deal of information which can be obtained which bears upon the decision, it is not assembled in a systematic way that makes it possible to ensure that all of the risks have been addressed, and all of the mitigations put into place so that the residual risk is acceptably small. Perhaps it is also the case that the benefits, and how those benefits are to be shared between the participants, are not sufficiently understood and quantified. It is therefore the purpose of this Workshop to examine the incremental threats that come with a decision to use X80 pipe, to assess the mitigations that have been developed in response to each of the threats, and determine the level of residual risk. The topics of the papers presented in the Workshop have been structured with this aim in mind. The authors have been chosen on the basis of their internationally accepted expertise in their assigned topics. I hope that the Workshop is successful in identifying and overcoming all of the barriers to the construction of an X80 pipeline, and that another 7 years doesn't pass before we go ahead and build one.

Leigh Fletcher



List of Papers No. Title

Author(s) Page

1 Getting stakeholder ownership of the adoption of new technology: balancing risks and rewards

Sue Ortenstone, Chief Executive Officer, Epic Energy

6

2 Design constraints against the use of X80 for Australian pipelines

Phil Venton, Principal, Venton and Associates

13

3 International use of X80: the experience base Paul Bilston and Milan Sarapa GHD Pty Ltd

24

4 X80 linepipe for large diameter high strength pipelines

H.-G. Hillenbrand, C. J. Heckmann and K. A. Niederhoff, Europipe

35

5 X80 Line pipe for small diameter (DN450 and smaller) high strength pipelines

John Piper, OneSteel, Oil & Gas Pipe, Kembla Grange

50

6 An independent view of linepipe and linepipe steel for high strength pipelines: how to get pipe that's right for the job at the right price

J. Malcolm Gray, Microalloying International, LP,Houston, Texas

62

7 An economic assessment of mechanised welding of high strength linepipe for the Australian pipeline industry

Steve Blackman, Director of Welding Engineering, Cranfield University, UK

77

8 Welding small diameter high strength pipe Frank Barbaro, Chief Development Officer, BHP Steel, and John Norrish, CRC-WS Chair of Materials Welding & Joining, University of Wollongong

90

9 Special problems to be overcome in the construction of small diameter high strength pipelines

Jim Reaman, Business Development Manager Nacap Asia Pacific

112


Paper 1: Ortenstone Page 6 of 131 Hobart October 30 2002

Getting stakeholder ownership of the adoption of new technology: balancing risks and rewards

Sue Ortenstone, Chief Executive Officer, Epic Energy

Slide 1

APIA X80 Linepipe Workshop

Chair - Sue Ortenstone

• Welcome to everyone

• Pleasing to see the number of people here and in particular the technical experts of our industry

• This workshop provides a unique opportunity to further enhance the efficiency of pipeline

development in Australia

• Please use the day well



Slide 2

APIA X80 Linepipe Workshop Background

Due to the vast distances and small markets inherent in Australia we have a very efficient pipeline development industry

X80 linepipe has been available for over a decade, it appears tooffer considerable cost benefits but has achieved essentially nomarket penetration in Australia

Decisions regarding the possible use of X80 to date appear to have been taken by individual projects against a backdrop of short decision making timeframes

In such circumstances it is easy to “stay with convention”

It is possible that previous decisions may have been taken from a position of ignorance which may have led to a higher than appropriate perception of risk

This workshop is designed to ensure that that ignorance is not an issue in future decisions

• Because of the nature of Australia where we have a small population base that is mainly located in centres that are a long way from gas supply sources, our pipeline development industry has had to be very efficient just to be able to exist

• On the face of it, the use of X80 linepipe would seem to be a value improvement opportunity,

yet despite being commercially available for over a decade, it’s penetration of the Australian market has been minimal

• X80 would only seem to be an option for the major projects. Often the design and

procurement decisions for these projects are made against a backdrop of a short timeframe and limited risk evaluation. Such circumstances can easily lead to conservative decisions. We tend to stick with what we know rather than take a risk or delay the decision awaiting more data

• This may mean that some of these decisions were taken, usually for very good reasons,

without having complete knowledge about the risks associated with the use of X80 linepipe. This can lead to an overestimation of the risks reinforcing the conservative approach

• This workshop is designed to ensure that all the available knowledge in the industry is drawn

out and assembled so that in the future ignorance will not be a factor in these decisions



Slide 3

APIA X80 Linepipe Workshop Why Develop Pipelines?

Businesses develop pipelines to provide an investment return for their shareholders

If a pipeline has the following characteristics:Capital Cost of: $300MM

Annual Operating Cost of: $3MM

Annual Revenue of: $37.4MM

It will provide a return to Shareholders over 20 years of 15% pa

But there are many inherent risks:Capital &/or Operating Cost Changes

Technical Risk

Regulatory Risk

Market Risk

Financing Risk

• Pipeline owners develop pipelines in order to provide an investment return for their shareholders. If there is no return on investment, then there is no reason to invest. Thus, if the cost of the investment can be reduced without increasing risk, then the owners will wish to realise that reduction and the value improvement inherent in it

• Lets look at a theoretical, and grossly simplified, pipeline that has an initial capital cost of

$300MM and annual operating cost of $3MM and an annual revenue of $37.4MM. This pipeline will provide its investors with a nominal return of 15%pa, dependent of course on financing structure, tax treatment, length of contract and a myriad of other factors

• But, there are risks in this investment:

• The original capital and operating cost estimates for the pipeline are just that, estimates,…...

the actual costs will be higher or lower

• There are risks that the technology used, be it steel, coating, equipment, control system or whatever will not perform as expected

• There are major risks inherent within the current regulatory environment in Australia that we

are all aware of

• The market may not develop as expected or a major customer may have problems

• Debt is a key part of all major pipeline developments and thus investors are exposed to the interest rate market



Slide 4

APIA X80 Linepipe Workshop Sensitivity to Risk

The sensitivity to the cost risks include:Parameter Nominal ReturnBase Case 15%Capex +10% 12.3%Capex -10% 17.9%Opex +20% 14.4%Opex -20% 15.5%

These sensitivities form part of the technical and commercial decision making process. For example a possible design change may reduce the capital cost of this pipeline by 5% but lead to an operating cost increase of 10%

This would change the nominal return to 15.7%

• Of course this matrix of risk is extremely complex and not necessarily relevant to today’s workshop. But lets just look at the cost risks on our theoretical pipeline

• If Capex increases by the rate of return decreases by 2.7%

• If Capex decreases by 10% the rate of return increases by 2.9%

• If Opex increases by 20% the rate of return decreases by 0.6%

• If Opex decreases by 20% the rate of return increases by 0.5%

• These sorts of analyses are all part of the decision making process. For example a potential

design change, for example a change in pipe coating or compressor type might reduce estimated Capex by 5% but increase estimated Opex by 10%. This would lead to an increase in the rate of return of 0.7% thus making the proposed change a value adding one, provided of course that it did not increase risks in other areas

• Any detailed project analysis will include a myriad of such sensitivity analyses



Slide 5

APIA X80 Linepipe Workshop Potential for X80

Lets assume that our pipeline now uses X80 linepipe instead of X70

Assumed total cost of X70 linepipe - $100MM

Weight reduction with X80 - 14%

Assumed X80 premium - 7%

Thus reduction in pipe cost - $7MM

Assumed reduction in logistics and welding costs - $1MM

Total cost saving for using X80 - $8MM or 2.67% of Capital

If all this saving could be realised and not offset by other increases then the nominal return increases to 15.7%

As investors we need to understand if this saving in capital andimprovement in return is real

The $8MM saving appears to be the best case scenario, unlikely to be realised.

• So what might happen if we decided to use X80 linepipe instead of X70 linepipe for our theoretical pipeline?

• If we assume that of the $300MM of original capex $100MM was for bare linepipe • The reduction in steel weight is 14%, but the premium per tonne paid for X80 over X70 is 7%,

then the saving in steel cost is $7MM

• Assume that there is a further saving of $1MM due to a reduction in logistics and field welding costs giving a total cost saving of $8MM or 2.67% of total Capex

• This saving, if realised, would increase the nominal rate of return by 0.7%

• However, all changes have inherent risks and as investors we need to understand if this

saving, and thus the value improvement, is real or only apparent

• On the face of it, the $8MM appears to be the upper bound of the available costs saving and thus the real saving is likely to be lower, The key question is how much lower?



Slide 6

APIA X80 Linepipe Workshop Probability of Achieving Savings

X80 Risk Profiles

0.20

0.40

0.60

0.80

1.00

-8 -7 -6 -5 -4 -3 -2 -1 0 1 2 3 4 5 6 7 8

Cost Savings ($MM)

Probabilityof Occurrence

High RiskProfile

ModerateRisk Profile

Low RiskProfile

• If the low risk profile is the correct one then clearly the use of X80 linepipe for this theoretical pipeline would be expected to add value

• Conversely, if the high risk profile is the correct one, then the value of X80 linepipe for our

pipeline is quite problematical

• With the moderate risk profile there still remains some question mark as to whether the use of X80 is worth the effort

• The technical managers of the industry need to be able to define the risk profile and/or

improve the level of potential savings available from X80 if the investors are going to be persuaded to use it



Slide 7

APIA X80 Linepipe Workshop Investor’s Perspective

As a pipeline investor it is fundamental to know what the real X80 risk profile is. Unless the risks are well understood and the mitigating strategies well developed it is likely that these risks will outweigh the potential benefits

The technical leaders of the industry need to be able to demonstrate that these risks are known and under control

This workshop is an opportunity to give that demonstration

If the arguments are not very compelling, then there is a high likelihood that we will go another ten years without significantmarket penetration by X80 linepipe in Australia

• Investors will not put their money into any venture where they perceive that the risks are likely to outweigh the rewards.

• These investors need to understand the risks and be convinced that there are mitigating

strategies in place that will manage these risks. The Technical leaders of the industry need to be able to demonstrate that this is the case

• This workshop has been designed as an opportunity for you to do this

• You need to understand that if your arguments are not compelling and you cannot clearly

demonstrate that the risks inherent in the use of X80 linepipe are both minor and under control plus that there is obvious value available from such use, then we could easily go another decade in Australia without using X80

• It would be a real pity if you do not take this opportunity to advance the case for what could be

a very high value adding product for the development of our industry • Please, enjoy your day and make it a worthwhile one


Paper 2: Venton Page 13 of 131 Hobart October 30 2002

Design Constraints against the use of X80 for Australian Pipelines

Philip Venton Venton & Associates Pty Ltd

Sydney

SYNOPSIS To date no Australian pipeline has been constructed using API 5L Grade X80 steel, even though the material provides an opportunity for significant project cost benefits. Furthermore the Australian pipeline industry, together with steel and line pipe manufacturers have spent very significant amounts of money undertaking research to understand the material manufacturing, converting and joining parameters of the steel. This paper considers the design constraints that could create a technical or commercial risk to a project that is constructed using X80 grade steels. It finds that there are no significant risks provided the proper design process is followed, and provided that adequate technical resources are used in developing the specification for supply and manufacture of the line pipe. Some developmental work will be necessary to establish suitable procedures for constructing the first X80 pipelines and some welding staff training may be required to establish proficiency and productivity levels in these people. The same challenge was faced in moving from X42 to X65 steel grades, and from X65 to X70 grade, as well as moving from a maximum operating pressure of 7 MPa to 10.2 and now commonly, 15.3 MPa. – we have all forgotten the detailed analyses that were made to develop the confidence in each of those major contributions to the cost effectiveness of the Australian pipeline industry. The X80 challenge is a continuation of that efficiency development. Design risk is not considered a constraint in meeting this challenge.



Introduction Many basic decisions about as pipeline project are made at a very early stage in its development – these include the pipeline route and the line pipe material. In many cases the steel grade choice does not reflect sound engineering principles but rather fear of the unknown assisted by a less than robust capital cost estimation and economic evaluation process. The economic analysis is addressed elsewhere – perhaps the commercial regulation process (optimised replacement cost) will drive people to place more importance on the potential for reductions in cost of the component that makes a contribution of about 40% to the cost of the pipeline, to reducing transportation tariffs. The purpose of this paper is to identify the engineering issues associated with designing a high pressure transmission pipeline using X80 grade steels and to analyse the processes by which these issues can be addressed during the material procurement and the detailed design process to mitigate any potential risk from the use of X80 grade steels in high pressure transmission pipelines.

What Does Steel Strength Offer ? High steel strength offers saving in pipeline capital cost as a direct result of the reduction in the mass of steel that must be purchased and incorporated in the pipeline. The following tables show the pressure design wall thickness for pipelines of various diameters calculated for a design pressure of 15.3 MPa and design factors of 0.72 and 0.80 respectively.

Wall Thickness for Steel Grade (mm) – Design Pressure = 15.3 MPa, Fd = 0.72 Diameter

X42 X46 X52 X56 X60 X65 X70 X80 X100 200 8.1 7.4 6.6 6.1 5.7 5.3 4.9 4.3 3.4 250 10.1 9.2 8.2 7.6 7.1 6.6 6.1 5.3 4.3 300 12.0 10.9 9.7 9.0 8.4 7.8 7.2 6.3 5.0 350 13.1 12.0 10.6 9.8 9.2 8.6 7.9 6.9 5.5 400 15.0 13.7 12.1 11.2 10.5 9.8 9.0 7.9 6.3 450 16.9 15.4 13.6 12.6 11.8 11.0 10.1 8.9 7.1 500 18.7 17.1 15.1 14.0 13.1 12.3 11.2 9.8 7.9 550 20.6 18.8 16.6 15.4 14.4 13.5 12.4 10.8 8.7 600 22.5 20.5 18.2 16.8 15.7 14.7 13.5 11.8 9.5 650 24.3 22.2 19.6 18.2 17.0 15.9 14.6 12.8 10.2 700 26.2 23.9 21.2 19.6 18.3 17.1 15.7 13.8 11.0 750 28.1 25.6 22.7 21.0 19.7 18.4 16.8 14.7 11.8

The tables show that the principal advantage of the higher steel strength is that for the same diameter and pressure, the steel thickness progressively reduces with increasing steel strength. Thus the primary benefit of higher steel strength is that the mass of steel purchased to satisfy a given design is reduced, directly reducing the capital cost of the pipeline. While the material cost increases with grade (because of increasing alloy content and specification requirements), the cost saving flows through all subsequent processes including convert to coated pipe (through reduction in energy to weld and coat the pipe), transportation, field welding, weld inspection and coating.



Wall Thickness for Steel Grade (mm) – Design Pressure = 15.3 MPa, Fd = 0.80 Diameter X42 X46 X52 X56 X60 X65 X70 X80 X100

200 7.3 6.7 5.9 5.5 5.1 4.8 4.4 3.9 3.1 250 9.1 8.3 7.3 6.8 6.4 6.0 5.5 4.8 3.8 300 10.8 9.8 8.7 8.1 7.6 7.1 6.5 5.7 4.5 350 11.8 10.8 9.5 8.9 8.3 7.7 7.1 6.2 5.0 400 13.5 12.3 10.9 10.1 9.5 8.8 8.1 7.1 5.7 450 15.2 13.8 12.3 11.4 10.6 9.9 9.1 8.0 6.4 500 16.9 15.4 13.6 12.6 11.8 11.0 10.1 8.9 7.1 550 18.5 16.9 15.0 13.9 13.0 12.1 11.1 9.7 7.8 600 20.2 18.5 16.3 15.2 14.2 13.2 12.2 10.6 8.5 650 21.9 20.0 17.7 16.4 15.3 14.3 13.2 11.5 9.2 700 23.6 21.5 19.0 17.7 16.5 15.4 14.2 12.4 9.9 750 25.3 23.0 20.4 18.9 17.7 16.5 15.2 13.3 10.6

Also the thinner, higher strength steel:

• Reduces the penetration resistance (the reduction in thickness is not offset by tensile strength increase)

• Increases the toughness required to arrest fracture

• Introduces specific issues with field welding, including weld metal matching (where this is required)

• Introduces issues relating to interfacing with pipeline assemblies

• May introduce other construction issues in areas of bending, buoyancy control, cad weld attachment

• May have some impact in the response of the pipe to a stress corrosion cracking environment

• May increase the cost of pipeline development and maintenance (by increasing the difficulty of welding onto a live pipeline)

• May reduce the strain to failure reserve provided by lower strength steels that have a lower yield to tensile strength ratio

If AS 2885.1 should permit the pressure design factor to be increased from 0.72 to 0.80, higher strength steels can offer even greater savings to a pipeline project. Clearly these and other similar issues are matters that must be solved by engineering design in order to enable the full cost benefit of the increased steel strength to flow to the project capital cost.

What are the Design Risks

Pipe Wall Thickness For any high pressure pipeline designed to AS 2885, the wall thickness must be selected to satisfy the governing design constraint at each location along the whole of the pipeline. Many of these constraints are interactive, and all interact with the material grade choice. Issue paper 4.19 developed by Standards Australia Committee ME-038/1 (AS 2885.1 – Pipelines – gas and liquid petroleum - Part 1: Design and Construction) and posted on the APIA web site has identified the most significant considerations in establishing the wall thickness. The risk associated with using X80 steel rather than a lower grade for each of the items identified in the issue paper are assessed in the following table:



Thickness Design Item. Risk in Changing from a lower Grade to X80 The thickness required for pressure containment Nil.

Each pipeline is subjected to a hydrostatic strength test at 1.25 times design pressure, to establish its maximum allowable operating pressure. The pressure strength margin is independent of steel grade.

The sum of the pressure design thickness and allowances

Nil. Where allowances are required, they are applied for a purpose other than steel grade.

The thickness required for resistance to penetration by the design threat, if this is used as a method of providing external interference protection in accordance

Nil. Where resistance to penetration is a controlling factor in the design it must be satisfied. This may require thicker pipe and / or a change in steel grade. Increased tensile strength offered by X80 steel partly counteracts the reduction in penetration resistance that occurs with reduction in thickness. For example – DN 450 pipe the force to puncture the pipe with “tiger” teeth is approx:

• 10.1 mm X70 = 380 kN • 8.9 mm X80 = 355 kN (6.6% reduction)

In this case, both would resist puncture by a 40 t excavator. (see section 3.2)

The thickness required to provide the minimum critical defect length needed to prevent rupture in Location Classes T1 and T2, or elsewhere if required by the Design Basis.

Nil. In locations where rupture is not an acceptable failure mode, the critical defect length (CDL) criterion governs the selection of steel thickness and grade. The difference is only modest – for example DN 450 pipe, 15.3 MPa:

• CDL for 10.1 mm X70 = 107 mm • CDL for 8.9 mm X80 = 99 mm

(see section 3.2) The thickness required to satisfy the stress and strain criteria

Nil. Stress and strain is calculable from the physical parameters of the design. AS 2885 (and other design codes) express stress limits as a percentage of the SMYS. Hence higher grades can sustain a higher absolute stress value without exceeding the code limit.



Thickness Design Item. Risk in Changing from a lower Grade to X80 The thickness required to control fast running fracture

Nil to Medium. For Lean Gas the minimum all heat average toughness for X80 pipe complying with API 5L is 68 J (transverse). This is the minimum required value calculated from the Battelle Lean Gas equation. X70 line pipe toughnesses typically exhibit an all heat average greater than 100 J. For Rich Gas, the toughness required may limit the application of X80 steel, particularly in the smaller diameter / thinner wall combinations. Because the fracture arrest requirement is calculable, the most significant risk in specifying X80 occurs if the pipeline is designed for lean gas, and once in service the duty is changed to rich gas. This same risk occurs for lower steel grades, but there may be a higher reserve toughness available to draw on to accommodate the change. Note: Additional Risk is associated with the

limited experimental work undertaken to date to establish the validity of predictive techniques that were developed for lower grade steels and lower pressures, for application to X80 and higher grade steels. If future experimental work should determine that current techniques are invalid, then the pipeline’s use may be constrained in the future, and the potential revenue from the pipeline reduced.

The thickness required to achieve a design stress level selected for its contribution to SCC mitigation at locations where the SCC risk is increased by operation at temperatures above 45°C, and at locations subject to high pressure fluctuations

Nil. The SCC threshold stress appears to be approximately a constant proportion of the actual yield stress. If the X70 and X80 pipeline are each designed for the same percentage of SMYS they will be operating at roughly the same proportion of actual yield stress – hence of have similar SCC risk, all other conditions being the same. Conditions that contribute to SCC are well known and at the design stage, appropriate mitigation measures including temperature, coating, joint coating, operating pressure ranges, and cathodic protection controls can be properly assessed and implemented. If the pipelines are designed for operation at 80% of SMYS, or if the pipeline MAOP is uprated, the SCC risk may increase, but again the risk is roughly similar for each steel grade.

The thickness required to achieve adequate fatigue life where this is determined to be a consideration in the operating life of the pipeline

Small. Fatigue is a function of the stress range and the number of cycles through the stress range. For pipelines that operate at the same percentage of yield stress, the fatigue risk is essentially independent of material



Thickness Design Item. Risk in Changing from a lower Grade to X80 The thickness required for constructability and maintainability of the pipeline including provision for future hot tapping, where required

Risk Exists (in existing and future pipelines). In-service welding becomes increasingly difficult with increasing steel grades and reducing thickness. At the design stage, the cost impact of providing sections of thicker, more weldable pipe, or installing branches for future connection is relatively small. During operation it is normally possible to plan a construction or maintenance activity around a time of reduced transmission demand that will permit the pressure to be reduced to facilitate welding. Note: This risk exists in thin wall pipes that are currently in service. The risk is managed by the above procedures.

Issue Paper 4.7 published by the same committee proposes that the factor to be used for establishing the pressure design thickness of the pipeline be changed from 0.72 in the current revision of AS 2885.1 to a value of 0.80. While this change has not yet been adopted by the Standard, the probability of its adoption has significance to this discussion on the choice of steel grade.

Is X80 Pipe too “Thin”? One of the criticisms of thin wall pipe that is available as a consequence of using higher grades of pipe steel is that it is too “thin”. The following graph plots the force required to puncture a pipe using an excavator equipped with a single “tiger” (two pointed penetration) tooth. The graph illustrates the puncture force for X70 and X80 grades of steel, with thicknesses for each pipe calculated as the pressure design thickness using a design factor of 0.72. Each of the pipe diameter-thickness-pressure combinations exists in Australia with X70 grade steel. The important conclusion to be drawn from this graph is that:

• The pressure design thickness for larger diameter and higher strength pipelines significantly increases their resistance to penetration.

• The reduction in pressure design thickness provided by using X80 grade steel makes a small reduction in the force to puncture.

Hence the risk of a pipeline being “too thin” simply because it is manufactured from higher strength steel is essentially negligible.



Comparative Force to Puncture Pipe from X70 and X80 Steel

0

50

100

150

200

250

300

300 350 400 450

Nominal Pipe Diameter (mm)

Forc

e to

Pun

ctur

e w

ith "

Tige

r" T

ooth

(kN

)

X70-10.2 MPaX80-10.2 MPaX70 - 15.3 MPaX80-15.3 MPa

Pipeline Assemblies Pipeline assemblies are designed and fabricated in accordance with the requirements of AS 2885.1. This is intended to permit them to be fabricated from line pipe and high test components that are typically used in the pipeline construction. The pressure design factor for pipeline assemblies is set in AS 2885 as 0.6. This is the same as the value typically used for “heavy” wall pipe in the pipeline. There is no reason that this same philosophy could not be applied with X80 line pipe. The main material problems are associated with material availability and thickness matching and include:

• Supply of “pup” pipe for welding to the mainline valves, and developing a suitable welding procedure to safely weld the valve and pipe.

• Supply of fittings of appropriate strength and thickness.

• Supply of transition pipes between unequal thicknesses.

This risk is managed by undertaking the necessary calculations early in the project (as part of the pipeline thickness calculation), and purchasing the required material as long lead items at the time of the line pipe order to ensure that there is no construction constraint. Too often the detail design associated with pipeline assembly design is left until late in the project where even with existing X70 steel grades, delivery of the required material becomes critical.

Coating As with recent major Australian pipelines, the coating process for large diameter high pressure pipelines will be either fusion bonded epoxy (single or dual layer) or a three layer system. Each of these processes involves heating the pipe to 230-250°C. This heating has the potential to cause embrittlement by strain ageing, together with an increase in the pipe yield strength (and an increase in the yield – tensile ratio). Some testing undertaken as part of the APIA hydrostatic testing research project has shown that the yield strength of X70 pipe increases by around 35 MPa during the coating process. There is insufficient data on these effects to fully understand the potential impact on X80 grade pipe. During



the development phase of an X80 project (and prior to commitment to the steel) testing to develop this data is recommended. Once sufficient data is obtained to allow the effects and their management (if any) to be quantified, any risk associated with coating the high strength pipe with modern coating materials will be fully understood and is expected to be manageable.

Material Specification

Steel and Pipe Specification There is a relatively small body of experience in the manufacture of ERW line pipe in X80 grade material. Most of the existing X80 pipe production has been in diameters that require submerged arc welding techniques. In Australia, Onesteel and BHP have undertaken extensive development and several successful pipe making trials, including the installation of some X80 pipe in a new pipeline to establish production and construction data. X80 steels involve more complex chemistry and processing than X65/X70 steels, and the strength grade can be achieved through a number of routes. Unless there is close liaison between the steel maker, the pipe maker and the end user (the pipeline welder) there is a significant risk that the delivered product will contain defects, or characteristics that impact on the performance of the product –during pipe manufacture, production girth welding, or field hydrostatic testing. A weakness in any of these areas will impact on the cost effectiveness of the X80 material. Particular threats that require management include: Factor Integrity Impact X80 Threat Management Steel Strip Manufacture

Steel Manufacture (scrap, electric arc furnace, nitorgen)

Continuous casting

Alloy design – Rolling procedure

Centre slitting

Alloy strength range

Toughness and Weldability Centreline segregation, toughness, strength, weldability Surface quality, toughness, strength and weldability Seam weld toughness and defects Girth weld undermatched

Specification, Steel maker prequalification. Increased control and quality inspection. Specification, prequalification preproduction testing Increased control and quality inspection. Specification, quality control, girth weld procedure development

Pipe Manufacture Edge preparation

Seam welding Weld heat treatment

Inspection and NDT

Hydrostatic test

Defects, seam weld toughness Defects, seam weld toughness Seam weld toughness Seam weld integrity Seam weld integrity, pressure strength

Equipment suitability Manufacturer experience Equipment capability, manufacturer experience Purchaser specification – third party testing Pressure and test duration

While X80 grade steels are relatively new to the pipeline industry they are by no means novel. The control measure to manage this risk is simple:

• Recognise that the specifications and procedures copied from the last three projects do not apply to X80 steel pipe.

• Engage the services of a qualified professional to assist in developing the steel and pipe specification.

• Carefully pre-qualify both steel and pipe makers.

• Allow a little more time at the start of the project to undertake qualification testing of each of the processes (steel making, pipe making and girth welding).



• Undertake an appropriate level of quality inspection and testing during the manufacturing phases.

Construction (Design Concerns)

Welding Specific girth welding issues are not part of this paper – however performance of the welded joint, and its ability to deliver a joint that satisfies the design load requirements for the pipeline are part of this paper’s scope. It has been argued that the ability of the girth weld in an onshore pipeline to tolerate significant axial strain should not be a design requirement of the girth weld, because the loading condition is not applicable to almost every weld on an onshore pipeline constructed in Australia. That is, the pipeline is effectively restrained by burial. This proposition suggests that the designer should be capable of identifying the locations where axial loading is credible (including land slip areas where there may be displacement loads, areas subjected to settlement, and areas subject to thermal stresses and bending). AS 2885.2 has made it mandatory that the welding procedure for Tier 2 defect acceptance criteria produce girth welds that are at least as strong as the pipe. This is to ensure that in a situation where the weld containing defects up to the limits permitted in Tier 2 is subjected to an axial strain, the strain will be distributed along the pipe, and not concentrated in a narrow, low strength weld. To manage this risk the designer must:

• Determine whether the defect acceptance criteria are to be based on Tier 1 or Tier 2 requirements.

• Identify locations along the pipeline route where weld strength matching must be achieved (land slip areas, areas at risk from large scale flotation, areas of potential settlement etc).

• Initiate weld procedure development and testing.

Research undertaken in Australia has demonstrated that with appropriate steel: • X80 pipe can be welded with full matching characteristics using GMAW techniques in all

thicknesses.

• X80 pipe can be welded with adequate matching characteristics using Exx10 electrodes in thicknesses above about 7 mm.

• Below 7 mm, Exx10 electrodes will not produce full matching. This may be acceptable in locations where the pipeline route is known to be not subject to displacement controlled loading.

Where it is necessary to demonstrate weld metal matching it must use wide plate or full pipe section tensile testing. There are a limited number of laboratories that have the capability to undertake these tests – it is important that the project plan incorporate sufficient time for the welding procedure development and tensile testing. Some iteration of weld procedure development and testing may be required. Where the welding procedure or electrode combinations require different processes from those “normally” used, it may be necessary to provide additional welder training prior to commencement of production welding. Some training is normally required, and this represents an extension of that process. It is worth noting at this point the subtle change in AS 2885.2 which requires “qualification of a welding procedure”, not “welding procedure qualification”. Pipeline welding contractors and where they exist, the designer’s or the owner’s welding engineer have shown no inclination over recent years to develop welding procedures that will deliver matching welds, even though the limitations of existing procedures for X70 line pipe based on combinations of E6010/E8010 electrode combination have been reported to the industry on many occasions as delivering potentially undermatched welds. The approach to a new project has generally been to copy the last procedure and assume that it will work for the new project. Compliance with AS 2885.2 for all high strength steel grades requires development of a welding procedure and qualification of that procedure over the extremes of each combination of variables for



which that procedure will be used. This requirement exists irrespective of the steel that is to be welded. Additional effort, including specifying, sourcing and controlling higher strength electrodes may be required to achieve the performance characteristics necessary for welding X80 steel.

Cold Field Bending Higher steel grades are expected to have some impact on the cold field bending performance of line pipe because the reduced wall thickness necessarily increases the D/t ratio of the pipe. In combination with the increased steel strength, increased care may be required to achieve the same bend radius in X80 compared with X70. However at the pressures and diameters where X80 grades will be effective the D/t ratio is relatively low (for example for 15.3 MAOP, DN 450 pipe – X70 has a D/t ratio of 45, while the ratio for X80 thickness is 51). AS 2885 Appendix J provides procedures for establishing an appropriate bending procedure, including provisions for accepting a procedure where small buckles are formed. Consequently it is not anticipated that there is any significant risk to the construction productivity as a result of field bending limitations imposed by X80 steel. Furthermore if there is any limitation, it will be established prior to construction commencing, (during qualification), enabling the construction practice to be modified to accommodate the qualified procedure.

Induction Bends Even though modern induction bending processes are able to process the high strength pipe with minimal change in the yield strength, it is common practice in major projects to fabricate induction bends from increased thickness pipe to provide a margin that allows for possible strength reduction. If increased wall thickness pipe is used, it seems unlikely that the use of X80 steel in induction bends would pose a risk to the project. It is usual to conduct procedure qualification trials to establish constraints and the properties of the bent pipe. Until such time as the induction bending performance of more complex steels such as grade X80 is better understood the risk should be managed by the specification of X70 or X65 pipe material of appropriate thickness for induction bending. The induction bending characteristics of these materials are well understood by competent manufacturers.

Field Hydrostatic Testing Field hydrostatic testing represents the proof test of the pressure strength of the pipeline. AS 2885 has established that this test is undertaken at a pressure that is 1.25 times the maximum allowable operating pressure. There is no evidence that the use of X80 line pipe has any influence on the satisfactory completion of the hydrostatic test, and no additional provisions are required when the design factor (Fd) is 0.72. If the design factor is raised to 0.80, then the minimum pressure strength test pressure will induce 100% of SMYS in the pipe at the high point in the test section, and a stress that exceeds 100% SMYS elsewhere. This is a constraint that applies to all steel grades where the pressure design thickness is determined using a design factor of 0.80.

Conclusion In conclusion, there are risks to pipeline design using X80 grade steels that cannot be managed using existing design procedures in combination with a competent technical approach to steel and pipe procurement, together with some procedure development and testing. For most large transmission pipeline projects, the incremental cost of this developmental and quality control work is expected to be small compared with the potential cost saving offered by the higher material grade. In fact, the incremental cost probably represents costs that should already be included in each pipeline project but which are ignored because X70 steel is a “known” quantity – but in the same way as “oils ain’t oils” the industry is perhaps fortunate that this complacency has not resulted in project cost impacts. X80 steels will permit pipe thickness reduction and capital cost savings, and will not result in pipes that are too “thin” unless the wall thickness analysis is not competently and honestly done.



As with all engineering based projects the risk is minimised by undertaking the engineering first to establish the key parameters and constraints of the project and based on this, to plan the completion of the detailed design and construction based on this understanding. X80 line pipe may require more detailed assessment than pipelines constructed with lower grade steels, but when the project developer requires the lowest cost for all manageable items, there is no reason that this philosophy cannot be applied to design using this material. AS 2885.1 provides the guidelines and procedures that permit competent and experienced designers to undertake a proper engineering design for a pipeline using each steel grade, including X80.


Paper 3: Bilston Page 24 of 131 Hobart October 30 2002

International use of X80 Pipelines: “The Experience Base” By Paul Bilston and Milan Sarapa

GHD Pty Ltd Australia

Introduction Pipelines are the most economical mode of transportation of hydrocarbon fluids from production sites to the consumers. The ever increasing demand for energy worldwide resulted in a necessity for construction of pipelines with higher transportation capacity ie with larger diameters and higher operating pressures. High grade steels were developed and started to be used in pipe manufacturing to reduce the required pipe wall thickness and optimise pipeline construction costs.

The use of X80 or GRS 550 steel pipes for pipeline construction started on a trial basis as early as 1985, and has been increasing worldwide ever since. It must be noted though that with only minor exceptions such as the Roma Stage 4 Looping Project constructed in Australia, the core experience with X80 for cross country pipelines is for very large diameter pipe (42 Inch DN 1050), generally operating at pressures less than 10 MPa.

This is very different to the pipeline construction typically used in Australia.

This paper focuses on four key areas: A summary of the use of X80/GRS 550 pipe for high pressure pipeline construction

worldwide

Project Descriptions for some specific significant projects, including an analysis of issues or problems that have been experienced during the construction of X80 Pipelines

A discussion of specific problems that may be anticipated using X80 pipe for the smaller diameter higher pressure pipelines typically constructed in Australia.

To date X80 pipe has been used in projects in Australia, Canada, Europe and the UK. The earliest use was in Europe, followed by Canada, with both Australia and the UK only using small quantities of X80 pipe in the last few years.

Development Projects Using X 80 Pipe The first pipelines constructed of X80 pipe were all small trial sections generally only of a few km in length. Clearly these pipelines were built to demonstrate the feasibility of using X80 pipe in field construction.

The first X80 pipeline was built 17 years ago in 1985. The pipeline was 3.2km long 44 Inch (DN 1100) diameter and 13.6mm wall thickness and was constructed as a trial in the MEGAL II pipeline in Germany.

Subsequently, another trial section was done in 1985 for Transit Gas Pipeline in Czechoslovakia. This pipeline was 1.5km long, 56 Inch (DN1400) with 11mm wall thickness.

The following table summarises the known X80 pipeline projects.

Deleted: most



Name Owner Location Diameter W.T. Length MAOP %

SMYS

Year

inch mm mm Km MPa

Megal II Megal Germany 44 DN 1100 14 3.2 9.37 72 1985

Transit Gas Pipeline

Czechoslovakia 56 DN 1200 16 1.5 9.89 72 1985

Empress Comp. Station.

NOVA (TPL)

Alberta, Canada 42 DN 1050 11 1.6 8.1 80 1990

Werne to Schluchtern

Pipeline

RuhrGas Germany 48 DN 1200 18.4/19.3 250 10.0 62 1992-3

Eastern Alberta Mahtzwin

NOVA Eastern Alberta, Canada

48 DN 1200 12.1 54 8.65 80 1994

Central Main Line Loop

TPL Central Alberta, Canada

48 DN 1200 12.0/ 16.0 91 8.65 80 1997

Eastern Main Line Loop

TPL Eastern Alberta, Canada

48 DN 1200 12.0/ 16.0 27 8.65 80 1997

Peters Green to South MImms

Transco UK 48 DN 1200 - 1 7.5 1998

Drointon-Sutton on the Hill

Transco UK 48 DN 1200 - 25 7.5 2000

Transco UK 48 DN 1200 15.1/21.8 112 - 2001

Canadian Resources

Steam

Canadian Resources

Canada 24 DN 600 25.4 18 - - 2001

Roma-Brisbane Australia

APT Roma-Brisbane Australia

16 DN 400 8.83 16 10.2 72 2001

Transco UK 48 DN 1200 - 46 - 2002

Nova Corporation X80 Trial It was almost 5 years until the next X80 pipeline was constructed, and this was a short section in Canada. Nova Corporation (now part of Transcanada Limited) had carried out an extensive investigation into the use of X80 pipe to ensure that it was in fact, readily available and that conventional pipeline construction methods were able to be used for this grade pipe.

Pipe Trials Testing was carried out on pipes in over a range of diameters from 24 Inch (DN600) – 44 Inch (DN 1100) with various wall thicknesses that were supplied by seven different pipe mills from throughout the world. Mechanical testing of the pipe body and seam weld, as well as chemical analysis of the pipe body, was conducted at NOVA's Airdrie, Alberta. laboratories. At the time the testing indicated that only three mills were capable of supplying pipe that actually met all of the mechanical properties required for X80 pipe.



Welding Trials Nova also carried out extensive welding trials in order to determine what methodology was effective for welding this grade of pipe. Weldability calculations carried out in accordance with a modified Welding Institute of Canada (WIC) restraint test to determine preheat requirements for the use of a cellulosic root bead (E41010-AWS 6010). The published results indicate that the this was achieved with a preheat temperature of 75° C or less, and as such the Nova Standard pre-heat temperature of 100° C was specified for all cellulosic welding.

Nova tested a broad range of welding procedures, including a range of MMAW and GMAW based procedures.

A combination cellulosic/low hydrogen process was tested initially. The root and hot passes utilised conventionally down hill runs with E48010 (AWS 7010) electrodes. Fill and cap passes were completed uphill with E69018 (AWS 10018) low-hydrogen electrodes. This combination had very low productivity and also failed the CSA Z184 guided bend test requirements.

Further tests were completed with both root and hot passes completed downhill with E55010 (AWS 8010) electrodes, followed by fill and cap passes made with modified E62010 (AWS 9010) electrodes. Whilst the productivity of these welds better reflected the industry norm, it was felt that strength levels obtained were marginal, with significant strength mis-matching.

Following this further test welds were completed in an all downhill procedure with (E48010-AWS 7010) root and hot pass electrodes which provided reduced susceptibility to hydrogen-assisted cracking with superior operating characteristics resulting in freedom from internal undercutting.

The fill and cap passes were completed with (E62018-AWS 9018) electrodes which provided the required productivity and mechanical properties. This procedure proved to be the best combination for manual MMAW.

Nova had also been working with mechanized Gas Metal Arc Welding (GMAW) which is commonly used for larger diameter pipelines. As part of this a modified “Full Pulsed” GMAW process was developed and used for the Hot Pass, as well as fill and cap runs. The Pulsed GMAW was not considered suitable for the root pass due to the presence of residual magnetism in the pipe.

Empress East Project Following this research, Nova selected the Empress East crossover project in south eastern Alberta for the Grade 550 pipe trial. It comprised approximately 2.5 km of 42-in. pipe with 10.6 mm and 16.9 mm W.T.

Pipe This pipeline was built in 1990 from pipe supplied by the Japanese mill, NKK-Fukuyama. For the 10.6-mm W.T. pipe, a process known as "intensified controlled rolling" (ICR) was used. This process differs from a "normal" controlled rolling practice in that the reduction ratio under the re-crystallisation temperature is higher and the finish rolling temperature is lower.

The 16.9-mm W.T. heavy-wall pipe was rolled with "online accelerated cooling" (OLAC).

The OLAC process features plate cooling after finish rolling within a specified temperature range and with a specific, controlled cooling rate. This process results in transformation



hardening and grain refinement of the steel which in turn provides high strength and toughness. The primary reason for utilizing the two different plate-rolling methods was the potential difficulty in controlling the flatness of the thinner wall plate if OLAC was used.

Construction During the construction, all attempts were made to ensure that standard pipeline construction practices were followed including pipe handling, field bending, lowering-in, hydrostatic testing, and back filling. In all cases, no problems were encountered. It was only for welding and inspection that any special procedures were followed.

Main line welding of both pipe thicknesses was performed with the mechanized, pulsed GMAW. Initial relatively high repair rates occurred, with approximately 50% of the welds requiring some repair. The defects encountered were primarily lack of fusion; the total length of the repairs in comparison to the total weld length was well below that typically encountered on other pipeline projects. With increased experience with the full pulsed process, repair rates were found to decrease drastically. At the same time, an analysis of the welding equipment used showed that some additional development work could lead to improved performance.

Approximately 14% of welds made on the last day required repair with repair lengths approximately 3-4% of the total length of welds made.

Main line weld inspection was carried out with conventional X-ray radiography complemented by automatic ultrasonic inspection.

Larger Scale “Real” X80 Pipelines

RuhrGas The first time X80 pipe was used in what could be termed a commercial pipeline construction project was in 1992-1993 by Ruhrgas in Germany. This pipeline is the largest X80 (in terms of tonnage) pipeline that has been built to date. The pipeline which was constructed from Schluechtern to Werne has a total length of 250km, and was constructed from 48 Inch (DN1200) mm SAW pipe with 18.3 and 19.44 mm wall thicknesses.

The RuhrGas pipeline operates at a pressure of 10 MPa, and was constructed within a 20 metre ROW for the majority of its length. In contrast to the later Canadian and UK experience, the RuhrGas pipeline was constructed entirely using MMAW welding processes.

Like the other experience the pipe was pre-heated. The pre-heat temperature was 120° C. The root and hot pass welds were completed using standard vertical down welding with E 7010-A1 electrodes. The fill and cap passes were also completed using vertical down welding techniques with a Low Hydrogen E 10018-G electrode.

Given the significant role that the welding speed has in governing overall construction rates and times, a comparison was made between the welding time for welds completed using all cellulosic welding procedures, and those completed with the combined cellulosic, low hydrogen procedure described above. The results of the tests demonstrated that when experienced welders were used, the welding deposition times were almost identical. The key difference in overall times was attributed to the difference in interpass cleaning times. All cellulosic procedures were cleaned with wire brushing, and the low hydrogen electrodes required grinding. In spite of this difference in time, the project was able to achieve



production rates of 30 welds per day with 25 welders. Interestingly the repair rates on the project were much lower than those quoted for the later mechanised welded pipelines, with an average repair rate of only 3%.

The pipe had an average length of 17.3 metres, with each joint weighing up to 10.3 tonnes. Bending for the project was carried out at a central bending station using a 60 tonne bending machine with an internal mandrel. Bend angles of up to 0.5 degrees per 300 mm or 2 degrees per diameter were achieved. The ovality was limited to 4% which was easily achieved.

Significantly, whilst all reports on this pipeline appear positive, there does not appear to have been any further pipelines constructed in continental Europe from X80 pipe since this project was completed.

RuhrGas also successfully tested and evaluated a mechanised welding alternative using the CRC Evans GMAW technology. The test results were positive, however due to the rugged nature of the terrain this technology was not used.

TransCanada Pipelines (Includes Nova Gas Transmission)

The use of X80 pipe in Pipeline construction in Canada appears to have developed more consistently following the initial trial. A number of Canadian pipe mills developed the capability to supply X80 pipe, with Ipsco Inc., Regina, being the first Canadian mill to achieve commercial production of Grade 550. The development of its Grade 550 was a co-operative effort between Ipsco, TransCanada Pipelines Ltd (TCPL), Canadian research laboratories, universities, and government.

In total TCPL (Which merged with Nova Gas Transmission in 1999) now has approximately 400 km of pipelines constructed from X80 material in their system, approximated 39 km of this is 42 Inch (DN 1050) with the balance being 48 Inch (DN 1200).

Eastern Alberta System In 1994, the Matzhiwn pipeline in Eastern Alberta was constructed from spiral welded X80 material, this pipeline was 33km long 48 Inch, (DN1200) pipe with 12.1mm wall thickness. The pipe was welded using a mechanized gas-metal arc welding procedure identical to those used for X70 pipe. No welding problems were encountered that could be attributed to the process, the procedure, or the higher strength material being welded.

The Tie-ins were completed with a combination of cellulosic (E55010G) for the root and hot pass, with 100° C. preheat, followed by self-shielded FCAW for all remaining passes. using an E9IT8-G wire.

Construction in summer 1994 of 33 km of TCPL's Eastern Alberta system main line (48-in. OD; 12-mm W.T.). This pipeline was the first North American long-distance, large-diameter pipeline to use Grade 550 steels. Here, a pipe crew lines up the next joint before performing the root pass with an internal welder. (Photograph from TCPL, Calgary)



The particular self-shielded consumable selected was optimized in terms of deposit strength and toughness by the manufacturer for application to X 80 pipe, and the welds produced consistently met yield-strength requirements and exceeded the toughness requirements at the -5° C. design temperature.

Central Main Line Loop Following the successful construction of the Eastern Alberta Pipeline the same internal-external configuration for mechanized welding was also used for the 1997 91-km expansion of Nova’s Central Alberta system 48 Inch (DN 1200) with 12.1 and 16 mm W.T.).

The welding procedure was identical to that used on the previous project with additional fill passes for welds in the 16-mm W.T. pipe. The spread of mechanized welding equipment involved an additional fill-pass shack; 130 joints/day were achieved at a repair rate of 7%.

Eastern Main Line Loop Also in 1997, 127 km of the 1,219 mm OD Eastern Alberta system main line loop were designed and constructed with X80 Pipe. In this case, all-external mechanized welding was used to join the 12 mm and some 16-mm W.T. pipe.

One welding shack was used to complete the root pass, and three additional shacks would each complete the remaining hot, fill, and cap passes of a weld. Production rates of some 70 welds/day with repair rates of around 5% were achieved.

Low-hydrogen, vertical-down MMAW with cellulosic root and hot passes were used for tie-ins and repairs.

Transco Pipelines (Includes British Gas)

Like Nova, Transco carried out an extensive development program prior to and as part of the introduction of X80 pipe. Including:

Parent pipe and seam weld property tests

MMAW welding trials

GMAW welding trials

Validation of defect acceptance criteria – Wide plate tests

Cold field bending trials

Evaluation of Induction bends

Damage tolerance – ring tension & full-scale tests

The Fill and Cap stations leap frog to complete the welding (Photograph from TCPL, Calgary)

Full Scale X80 Burst Test (Photograph from Advantica Technology).



Hydrogen embrittlement tests

Risk assessment – ALARP

Hot tap welding trials

It appears that the use of cellulose based electrodes were precluded during the development program, and Transco adopted a GMAW system which included internal welding heads to deposit the root pass, followed by conventional GMAW welding for the subsequent passes.

Transco also carried out an investigation into the bendability of X80 pipe. This trial was carried out using 48 In (DN 1200mm) 15.9 mm pipe in both X65 and X80 thicknesses. This provided for a D/t ratio of approximately 75.

The test results indicated that it was more difficult to bend the X80 pipe compared with X65, and the X80 pipe could only be bent to 0.4 degrees per 12 Inch (300 mm) compared with the 0.5 degrees used for the lower strength X65 pipe.

Additionally the tests demonstrated that using a hydraulic mandrel was preferred over a pneumatic mandrel as it reduced the propensity for the pipe to buckle. Using a hydraulic mandrel bend radii of 40D (or approx 1.5 degree per diameter) were achieved.

In UK X80 was first used in 1998 for a short section of X65 48 Inch DN1200mm pipeline from Peters Green to South Mimms in England.

Following this, in 2000, the 25 km Drointon to Sutton-on-the-Hill pipeline was built. This pipeline was constructed by Transco using 48 Inch DN1200mm pipe. No real difficulties were identified during the construction of either of these pipelines.

In 2001 Transco completed the construction of a further 112 km of 48 Inch (DN1200) X80 pipeline, and in 2002 a further 46 km 48 Inch of (DN1200) was completed. Though no details of these pipelines have been published, it is understood that Transco were planning to construct these pipelines using heavier wall thickness in order to allow operation at a pressure of up to 9.4MPa compared with the 7.5 MPa at which the earlier pipelines were designed to operate.

Bending Trials (Photograph from Advantica Technology)

Pipeline Construction Drointon to Sutton Pipeline (Photograph from Advantica Technology)

Deleted: Internal

Deleted: Root

Deleted: Pass



Pipe manufacturing In 1950s and 1960s, large diameter pipes were manufactured from hot-rolled and normalised steel plate with material characteristics up to X60.

The introduction of thermomechanical rolling created a finer grain structure and improved the yield strength and toughness of the material. This enabled manufacturing higher grade steels such as X70. It was then found that the structural transformation necessary to further increase the yield strength could be achieved through accelerated cooling produced by water quenching the steel immediately after the final stage of the rolling process.

This transformation created an extremely fine grain structure with high material toughness.

The composition of X80 grade steel consists of over ten elements; the main five elements being C (0.07-0.09%), Mn(1.7-1.9%), Nb(0.04%)Ti(0.02%) and Si(0.32%).

The process used for X80 pipe manufacture are different. In Canada, Ipsco supplied helical double submerged arc welded (DSAW) pipe.

Europipe supplied longitudinal submerged arc welded (SAW) pipe for pipeline projects in Germany and UK. And in Australia, electric resistance welded (ERW) pipe was used which was manufactured by Onesteel.

The material properties for various high grade steels ie X80 to API 5L, GRS 550 to DIN 17172 (StE 550, 7 TM) or E10208-2 (L555MB) are different to some extent. The tensile properties of different steels are listed in Table 2 below

Steel Grade Standard Yield Strength

Min

Ultimate Strength

Min

X80 API 5L 551 520

StE 550, 7 TM DIN17172 550 590-640

L555MB E10802-2 555-575 625

It is evident that the specified ultimate tensile strength for GSr 550 and 555 is higher than for X80. This results in slightly higher carbon content and Carbon Equivalent (CE). Nevertheless, a CE of less than 0.44% could be assured.



Issues for X80 in Australia

Cost Effectiveness The use of X80 in the large diameter pipelines reported in the above appears to have a clear economic benefit. For the RuhrGas pipeline which consisted of some 145,000 tonnes of steel, a projected saving of approximately 14.5% or 21,000 tonnes of steel. At current Steel prices of A$1100 per tonne, this equates to a $23 million dollar benefit for the steel alone. This saving alone is more than the pipe order value for most projects in Australia.

Savings of this level provide considerable incentive as well as allow for a significant R&D budget to develop the implementation.

For the pipelines in the size range constructed in Australia, the differential in steel is often offset to some degree by the differential in construction cost and the perceived higher risk.

Welding Because of the higher CE than the lower grade steel, X80 is more susceptible to hydrogen cracking. Welding for all cellulosic procedures was carried out after pre-heating to between 100 - 120 degrees C. This may not be required for the sizes typically used in Australia, even with the higher strength material.

Given that all of the overseas experience was with larger diameter pipe where GMAW is normally used, it is not surprising that for all the later projects some form of GMAW based welding has been used. The experience demonstrates that using modified procedures with either GMAW or MMAW was able to provide effective welds at or close to the productivity typically seen for the lower grade pipe.

Although very good production rates can be achieved, the mechanised welding has its limitations in use on difficult terrain and with frequent interruptions ie ( road and river crossings etc.). In such conditions manual welding can be more economical.

In Australia, the vast majority of the welding is completed using manual cellulosic procedures as opposed to mechanised processes. Standard manual metal arc welding (MMAW) for pipeline construction had to be considerably changed for X80 pipeline construction. It was not possible for the weld metal deposited by cellulosic weld electrode to fulfil the requirement for the specific yield and tensile strength and to have simultaneously satisfactory toughness and resistance to hydrogen cracking This was solved by use of combined electrodes, where the root pass and the hot pass are deposited with well established cellulosic electrodes, and filler and cap passes are deposited with high strength electrodes.

The RuhrGas experience using a combined cellulosic – low hydrogen procedure demonstrated that suitable welding procedures will be able to be developed for this style of construction.

One issue for smaller diameter pipelines may be that the defect height for any single weld pass may be a substantial proportion of the wall thickness, this is a common issue already with welding of the thinner walled pipes in Australia.



Bending and pipe handling and laying Whilst there is some evidence to suggest that bending of the higher D/t ratio X80 pipes was more difficult to bend than lower strength pipes, all projects were able to achieve bending radii close to that achieved for lower grade pipes.

In some instances lower bend angles were required, however bending at or near 0.5 degrees per 12 Inch (300mm) were achieved for the lower D/t ratios, and just under this for the Higher D/t ratios. This is close to 2.0 degrees per diameter which is higher that the 1.5 degrees per diameter typically used on Australia pipelines.

Personal experience of the first Author in bending 10 Inch (DN250mm) pipe demonstrated that it was possible to obtain bend angles in excess of 3 degrees per diameter in X80 pipe, and that the X80 pipe behaved in a similar manner to X70 pipe.

The only other documented issue was that X80 pipe requires a longer lowering arc to ensure that it is not overstressed as the pipe does not have the same stiffness when laying the pipe into the trench compared with lower grade steels. As a consequence, more sidebooms may be required to provide continuity when spreading the load along the pipe arc.

The haulage costs and the size of the machinery handling the pipe can be reduced when compared to lower grade steels because of the thinner pipe.

Conclusion X80 pipe is increasingly used in large diameter pipeline construction worldwide and it may be expected it should soon be recognised as an engineering standard material for pipeline construction in the same manner as X70 was 5 years ago.

All of the overseas experience is with large diameter pipelines, the vast majority of which are in excess of 44 Inch (DN 1100mm), and none of which are operating at pressures over 10 MPa. This is a quantum different to the sizes and pressures typically used in Australia.

However experience has shown that the problems or complications which arise from the use of X80 can be mitigated and controlled by careful implementation of correct procedures without any significant premium being paid.

Grade X80 pipe would appear to be more economical in the larger diameter projects because of the reduced overall pipe tonnage and therefore overall project costs; it has consistently predictable and reproducible mechanical properties and good field weldabilty can be achieved without major difficulties.

From the operational perspective, the aspect of the thinner pipe wall and therefore greater probability that integrity of the pipeline is affected and subsequent required repairs should be considered.

Acknowledgements The preparation of this paper would not have been possible without the assistance of a number of people, in particular the authors would like to thank Brian Rothwell of TransCanada Pipelines Limited, and David Batte of Advantica Technology.

Deleted: produces

Deleted: because of its stiffness

Deleted: than



REFERENCES 1. Hildemann, Niederhoff, Heckmann: “X80 linepipe for large diameter high strength

pipelines” 3R International 41 (2002), Special Steel Pipelines

2. Curry N : “Practical Experiences with X80”, Pipeline World, October 2001.

3. Coulson K, Russell J, Tsukamoto H : “Grade 500 Line Pipe Passes Tests for Canadian Project”, Oil & Gas Journal, Aug 12, 1991

4. Glover A, Horsley D, Dorling D, : “High-Strength steel becomes standard on Alberta Gas System”, Oil & Gas Journal, Jan 4, 1999

5. Beirmann K, Bruhl F, Zschau M, “Experiences with Site erection and field welding of the pipeline steel X80”, Europipe Website

6. Chaudhari V, Ritzmann P, Wellnitz G, Hillenbrand H, Willings V, “German Pipeline first to use new generation line pipe” Europipe Website.

7. Private Communications Brian Rothwell – Transcanada Pipelines Limited

8. Private Communications David Batte – Advantica Technology.


Paper 4: Hillenbrand Page 35 of 131 Hobart October 30 2002

X80 line pipe for large-diameter high strength pipelines By H.-G. HILLENBRAND1, C. J. HECKMANN2 and K. A. NIEDERHOFF2

1 EUROPIPE GmbH, Ratingen, Germany 2 Mannesmann Forschungsinstitut, Duisburg, Germany Abstract This paper gives an overview on manufacturing and field welding of high-strength steel grade X80 line pipe. Aspects of the production of induction bends are also discussed. Large projects have already been implemented with satisfactory results. Manual combined-electrode welding and mechanised gas metal arc welding (GMAW) as field welding methods for pipeline construction are well-established. This is also true for welding consumables, which have been well-tuned to match the pipe material in strength. The pipe material X80 is suitable for unrestricted use in onshore applications. 1. Historical Review The ever increasing demand for energy world wide requires the construction of high-pressure gas transmission lines with the greatest possible transport efficiency, so that the cost of pipeline construction and gas transportation is minimised. This is particularly true when large distances are to be covered. The trend is therefore towards using line pipe of larger diameter and/or increasing the operation pressure of the pipeline. This, in turn, necessitates the use of higher strength steel grades to avoid large wall thickness that would be otherwise needed. Also, in some long distance lines, where an increase of the capacity is not required, a reduction of wall thickness (no change of diameter and pressure) can be an economic incentive for applying X80 pipe. This is going to be more and more implemented in Australia using HFI (ERW) pipes and in Canada using spiral pipes of grade X80 (hot strip material from Steckel mill). The development started about 30 years ago along with the introduction of thermomechanical (TM) rolling practices, and will continue in future. It was mainly governed by the large-diameter pipe manufactures [1-5], due to the fact that TM-treatment (with or without accelerated cooling) can optimally be applied for plate only. Therefore, the availability of high strength hot strip material for manufacturing spiral and ERW pipes seems to be limited to grade X80. It is also limited with respect to the available maximum wall thickness (Fig. 1). Today it is possible to produce grade X100 (TM) line pipe from plate and lay it under field conditions, maintaining all safety-related criteria [6-7]. In the early 70s, grade StE 480.7 TM (X70) was introduced for the first time in Germany for the use as line pipe in construction of gas transmission pipelines. Since then, grade X70 material has proven a very reliable material in the implementation of numerous pipeline



projects. The material has been optimised in the course of further development of TM rolling, and can be welded trouble-free with cellulosic electrodes providing care is taken to avoid hydrogen induced cold cracking. Following satisfactory experience gained with StE 480.7 TM and X70 in the subsequent period, grade X80 (GRS 550) line pipe came into use for the first time as a 3.2 km pipeline section in 1985 on a trial basis (Fig. 2). Subsequently, the material was used in the construction of several additional trial sections. In 1992/93, Ruhrgas AG constructed the world's first ever pipeline of 250 km length in this material, again in Germany [5, 8]. The reason why Ruhrgas AG selected this material was the reduction in pipe wall thickness needed in the construction of the pipeline designed to operate at 100 bar pressure. The yield strength values specified in various standards (DIN 17172, API 5L, EN 10208-2/ISO 3183-2) for the different high strength line pipe steels differ only slightly (Fig. 3) between 550 MPa (DIN 17172) and 555 MPa (EN 10208-2). To ensure that pipes are not supplied with excessive yield strength in individual cases, the current versions of API-5L, EN 10208-2/ISO 3183-2 specify an allowable scatter range of 120 MPa for yield strength. The yield strength measured on the transverse tensile specimens is required to lie in this range. The intention of specifying an upper limit for the yield strength was to enable the weld metal strength to be better matched to the pipe material. The specified yield strength range of 120 MPa applies to all line pipe grades that are included in these standards. Significant differences are noticeable in the specified minimum tensile strength among the different standards. For instance, the minimum required tensile strength of GRS 550 (StE 550.7 TM to DIN 17172) is 70 MPa higher than that of API 5L grade X80. Therefore, this material was quite close adapted to a thought API 5L grade X90. 2. Development and Production Results of X80 2.1 Large EUROPIPE projects The first large scale X80 line pipe was ordered by the German Ruhrgas running from Werne-to-Schlüchtern. This pipeline passes through the states of North Rhine-Westphalia and Hessen in Germany. The geometry of the pipe to be used was 48" O.D. x 18.4 and 19.3 mm wt. EUROPIPE supplied 145,000 t of pipe in the years 1992 and 1993 for this project. Furthermore, line pipe bends (QT-treated) were produced for the first time in this material grade by the Mannesmannröhren-Werke. In 2001 and 2002 further X 80 pipes were manufactured for a project in UK. Several parts of the gas pipeline network were ordered to a total length of 42 km in the past. Further quantities being about 70 km are also booked for this and next year. A challenging project of 2001 was a hot steam pipe line system for CNRL in Canada [9]. The longitudinally welded pipes were qualified for operation temperatures up to 354 °C. The high temperature properties with respect to creep were tested, and the results indicated sufficient creep resistance.



2.2 Steel making The basic work towards the development of the high strength grade X80 and GRS 550 materials was already completed by us in 1985. On the basis of extensive laboratory inves-tigations and mill trials, a MnNbTi steel was found to fulfil the necessary requirements. The strengthening mechanisms in this steel type have been described elsewhere [3]. The base composition of the steel used consisted of 0.09 % Carbon, 1.9 % Manganese, 0.04 % Niobium and 0.02 % Titanium. Additions of Copper, Nickel or Molybdenum were not necessary in the case of pipe wall thickness up to 25 mm. Alloying with Boron was not permitted. Because of the higher specified minimum tensile strength of 690 MPa, the carbon content and carbon equivalent are slightly higher in the case of GRS 550 than in the case of X80 for a given wall thickness. Nevertheless, a carbon equivalent according to IIW formula of less than 0.44 % could be assured. A Ti/N ratio of greater than 3.5 is necessary for the MnNbTi alloying system to be effective. The Titanium content of the steel must be less than 0.025 % so that there is no detriment to the toughness in the HAZ of the longitudinal weld seam. As a consequence, the Nitrogen content during steel making was only allowed to vary up to a maximum of 50 ppm. Therefore, an adequate vacuum treatment of the melts is necessary. Fig. 4 shows the Titanium and Nitrogen contents found in the ladle analyses of the casts for the Ruhrgas order. 2.3 Plate Production The effect of rolling and cooling parameters on the mechanical properties of MnNbTi steels has been described in detail in previous publications [1-5]. As an example the 18.3 mm thick GRS 550 plates for the Ruhrgas order were rolled under the following conditions, which were maintained within narrow limits: • Slab reheating temperature 1168 °C ± 10 °C • Intermediate thickness 100 mm • Finish rolling temperature 772 °C ± 8 °C • Cooling start temperature 760 °C ± 10 °C • Cooling stop temperature 560 °C ± 11 °C • Cooling rate 15 °C/s Accelerated cooling of the plate from finish rolling temperature has a remarkable effect on the microstructure and hence, on the mechanical properties of the steel. To obtain an almost fully bainitic microstructure, it is necessary that the accelerated cooling should be started before the transformation of austenite into ferrite begins. Fig. 5 shows typical temperature profiles along the length of the plate before and after accelerated cooling. The two curves shown in each case represent the temperature profiles for the top and the bottom sides of the plate. Numerous additional investigations carried out in the plate mill have shown that the variation in strength could be controlled in a narrow range of only 10 MPa along the plate width and only 20 MPa along the plate length within each plate. These results document that the rolling and accelerated cooling techniques are fully matured, which, coupled with the steel composition selected, ensure that the material readily complies with the strength and toughness requirements specified.



2.4. Pipe Production The parameters for the pipe manufacture of the Ruhrgas order were selected, drawing upon the experience gained in the course of the production of the pipe for the previous trial sections (Megal II, CSFR) [4]. The results of testing carried out at that time for single-case approval by the German technical regulator, TUEV, which became necessary because the material grade was not standardised, could be applied to the present case since there was no decisive difference in pipe geometry and since the chemical compositions were almost identical. The yield and tensile strength values measured for the pipe in circumferential direction are shown in Fig. 6. As seen in the figure the specified minimum values were comfortably achieved. The strength values were determined using round bar tensile specimens, since the strain hardening behaviour of the bainitic material leads to a large Bauschinger effect. The higher the strength level, the greater the Bauschinger effect. In other words, the proof stress values measured on flattened rectangular specimens taken from the pipe do not correlate well with the true proof stress values of the pipe wall. It should also be noted that the yield strength of high strength pipeline material shows an unisotropic behaviour. Using round bar specimens, the yield strength of an X80 material is about 30-40 MPa higher in circumferential direction than in longitudinal direction. Therefore it is easier to realise girth weld overmatching requirements. The tensile strengths in both directions are comparable. The impact energy values measured on the base material were in excess of 95 J, thereby exceeding the minimum value recommended by the EPRG for crack arrest. The ductile-to-brittle transition temperatures measured on the individual DWTT specimens were well below the specified test temperature of 0 °C.

Fig. 7 shows the chemical composition of the longitudinal seam weld metal deposited by the two-pass SAW method. Also shown in the figure are the impact energy values measured at 0 °C, which is the commonly specified test temperature in Germany. The weld metal has a high Manganese content and is additionally alloyed with Molybdenum. This Ti-B-free weld metal represents a good compromise with respect to toughness and mechanical strength. The average impact energy values measured varied between 100 and 200 J.

The strength of the seam weld was checked by means of flattened transverse weld specimens, with the weld reinforcement removed by machining. All specimens broke in the base material, i. e. outside the weld region. Thus, all the tensile strength values measured reflect the strength of the base material and were above the specified minimum value of 690 MPa. One of the latest projects using X80 was a UK pipeline for Transco in 2001 [10]. The results on EUROPIPE’s production tests, performed in the context of certification of the pipe, are shown in Fig. 8 and 9. All values of the round bar tensile tests and impact tests conform to the requirements of X80. The standard deviations of tensile testing are 15 MPa for yield strength and 13 MPa for tensile strength. Average values of impact testing were 227 J for base metal and 134 J for weld metal. To give an example of the manufacturability of heavy wall X80 pipe, EUROPIPE commercially produced 36” diameter pipe with 32.0 mm wall thickness. The manganese-niobium-titanium steel used here has a sufficiently high ratio of titanium to nitrogen and is additionally alloyed with molybdenum. The low carbon equivalent (CEIIW = 0.42) ensures good field weldability. The Charpy V-notch impact energy measured at -40°C was in excess of 200 J and the shear area of DWTT specimens tested at –20°C was greater than 85%. The

Deleted: u



forming and welding operations carried out on this high strength steel did not cause any problems. 2.5. Production of Induction Bends The induction bending machine at Mülheim works of Mannesmannröhren-Werke AG is designed so as to enable bends to be produced from pipes with outside diameters up to 64". In the course of the execution of the Ruhrgas order 600 large diameter pipe bends of various angles were produced from GRS 550 QT pipe for the first time in 1992 and 1993. The double submerged-arc welded line pipe being used for the production of the bends was 1220 mm OD and 22 mm in wall thickness. The bending radius was 6,000 mm (corresponding to approx. 4.9 times the pipe diameter) for all bends. The bends contained no straight pipe portions at the ends. The induction bending operation has been carried out on a computer-aided bending machine specially designed for this purpose. Heating is done by means of a ring-shaped inductor. The pipe next to the heated zone, which is subjected to bending, is quenched with water by means of a ring nozzle. The heat condition of the heated zone being inductive bent corresponds to that of full austenitization heat treatment. Following bending operation, the bends were tempered full length in a furnace at 620 °C ±10 °C. Thus, the finished bends were delivered in the quenched and tempered condition. For this reason, the base material for bends exhibits an increased alloy content compared to the straight line pipe. The bends contain Molybdenum additions and a slightly increased carbon content. Fig. 10 shows the average chemical composition of the bend body material. This figure also includes the mechanical properties measured in the course of the production of the bends and the specified requirements. It is clear from the data in the figure that the measured values were comfortably above the specified minimum values. The IIW carbon equivalent of the chemical composition of the bends was 0.46 % in average and thus good field weldability of the bends was ensured. The weld metal of the longitudinal seam was alloyed with Nickel and Molybdenum. The submerged-arc welds were performed using high-basic flux. In the quenched and tempered condition, the requirements for the weld metal toughness were readily fulfilled (Fig. 10). Also the strength of the weld was quite satisfactory. Finally, it should be mentioned here that X80 bends made from ERW or spiral pipe have not been produced so far. In any case the material should be able to be quenched and tempered, therefore the material will differ from straight pipe. For thin wall X80 line pipe also X70 induction bends with thicker wall can be used. 3. Weldability Before GRS 550 (StE 550.7 TM to DIN 17172) was first used on an industrial scale in 1985, the cold cracking behaviour of the material had been studied extensively by means of laboratory and full-scale tests [4]. Fig. 11 shows the minimum preheating temperature for avoiding heat affected zone (HAZ) hydrogen cracking determined for different steel compositions of pipeline steels in the implant test on welds deposited with cellulosic vertical-



down electrodes. It is evident from this figure that a preheating temperature of only 100 °C is necessary to deposit welds in GRS 550 (X80) without any risk of cold cracking in the HAZ. Unlike the conditions for the implant test, girth welds on large diameter pipe deposited during actual pipe laying are not allowed to undergo interruptions with cooling to room temperature after only the root pass has been deposited. It would therefore be possible to use lower preheating temperatures than those determined in the implant test (Fig. 12). Even the most critical weld, No. 2 in Fig. 12, which was deposited completely without interruption using cellulosic electrodes at a preheating and interpass temperature that was deliberately maintained at a low value of only 50 to 60 °C, was free of cold cracking. Hence, there is no increased threat of cold cracking in the HAZ compared to X70 line pipe material. This has been also demonstrated by the practical experience gained with the Ruhrgas pipeline construction. The high-strength basic girth weld metal (AWS electrode E10018-G) itself, however, has been found to be somewhat more sensitive to cold cracking than the girth weld HAZ of X80 material. Therefore, it is recommended to control that the preheating and interpass tempera-tures are maintained at about 80 to 100 °C minimum. If this requirement is fulfilled and if it is ensured that the basic electrodes are kept dry, there will be no threat of cold cracking in the weld metal as well as in the HAZ of base material. As the diffusible hydrogen content (HD) in deposited weld metal of mechanised gas metal arc welding lies below 3 ml/100 g, a preheating temperature of 80 °C (freedom from condensed water) is quite sufficient. Extended interruptions associated with intermittent cooling should however be avoided also in the case of gas metal arc welding. 4. Field welding methods 4.1. Manual vertical down welding Considerable changes had to be made to the manual welding method required in the construction of large-diameter pipelines in high strength materials as X80, GRS 550 and higher for the following reasons. The material StE 550.7 TM to DIN 17172 (GRS 550) has the same yield strength (550 MPa) as grade X80 to API 5 L, but a specified minimum tensile strength which is 70 MPa higher than that of grade X80. The material could therefore be considered as grade X90 from the point of view of tensile strength. Because of this high tensile strength, it was not possible for the weld metal deposited by the cellulosic electrode to fulfil the requirement for the specified minimum tensile strength and to have simultaneously satisfactory toughness and satisfactory resistance to cold cracking. This problem was solved by the use of a combined-electrode manual welding method (Fig. 13). In this method, the root pass and the hot pass are deposited with well-established cellulosic electrodes of lower strength grade, and filler and cap passes with a high strength basic vertical-down electrode of the AWS type E 10018-G. It is thus possible to ensure an unchanged high front end progress during pipelaying. This method is well-established now and regarded as sufficiently tried for large-scale practical use [4, 8, 11]. 4.2. Mechanised gas metal arc welding (narrow-gap, vertical-down) All established mechanised gas metal arc welding methods (GMAW) developed for use in onshore pipeline construction can be employed. Gas metal arc welding, however, encounters certain limitations in the case of onshore pipe laying in difficult terrain. It should be carefully



considered also in the case of frequent interruptions (roads, rivers, etc.) whether it would be more economical to apply manual welding. Fig. 14 shows, by way of example, the welding procedure that was employed to construct parts of the 250 km long Ruhrgas pipeline. 5. Strength behaviour of girth welds (overmatching) As the strength of line pipe material increases, weld metals of increased strength and sufficient toughness are required. For the reasons mentioned in earlier publications (in-adequate toughness, susceptibility to cold cracking of the weld metal), the cellulosic electrode cannot be improved beyond the AWS type E 9010-G with the highest strength [12-14]. Therefore, it was necessary to resort to basic vertical-down electrodes to deposit filler and cap passes by manual welding. As well as the extensive service experience gained, the results of recent wide plate tests, which involved welds with artificial planar defects in the HAZ, indicated that the high-toughness weld metal deposited with the basic vertical-down electrode of the AWS type E 10018-G is tuned to match the pipe material strength optimally. This applies also to the welding consumables needed for making welds by mechanised gas metal arc welding.

6. Final remarks HFI welded pipe is limited in diameter, wall thickness and material grade (X 80 maximum). One reason is the restriction of hot rolled strip production. The use of a better hot strip rolling process like Steckel mill enables helical seam weld X80 pipe to be produced with a larger wall thickness of up to about 16 mm. By comparison, longitudinal SAW seam welded X80 line pipe is available with wall thickness from 10 mm to 35 mm at outside diameters from 20 inches to 56 inches. This pipe is particularly suitable for operation at the highest pressures. The pipes produced by the various methods overlap in the lower part of the size range. The quality level of the pipes can be considered to be the same. Price wise each product has its optimum range. In overlapping sizes a specification should allow all products.

While it is not possible to produce HFI welded and helical seam welded pipes in grades higher than X 80, longitudinal seam welded grade X 90 line pipe has been already produced on a commercial scale. Materials meeting the requirements for grade X 100 have already been produced. EUROPIPE is partner in some JIP to develop X100 line pipe.

Grade X 80 pipe in most cases is more economical than X70. Consistently predictable and reproducible mechanical properties and good field weldability can be achieved without difficulty.

Deleted: Therefore, HFI welded pipe is an option only for use at operational pressures below 100 bar



In the case of grade X 100, questions regarding its cost-effectiveness cannot be answered in general terms yet, because other aspects such as the need for crack arrestors etc. might arise with this material.

References [1] W. M. Hof, M. K. Graf, H.-G. Hillenbrand, B. Hoh and P. A. Peters: New high-strength large-diameter pipe steels; Journal of Materials Engineering 9 (1987), 191 – 198

[2] M. K. Gräf, H.-G. Hillenbrand and K. A. Niederhoff: Production and girth welding of double submerged-arc welded grade X80 large-diameter linepipes; EPRG PRCI Meeting, Paris, Mai 1991

[3] H.-G. Hillenbrand and P. Schwaab: Quantitative determination of the microstructure of HSLA steels for correlation with their mechanical properties; Materials Science and Engineering 94 (1987), 71-78

[4] H. Engelmann, A. Engel, P. A. Peters, C. Düren and H. Müsch: First use of large-diameter pipes of the steel GRS 550 TM (X80); 3R International 25 (1986), No. 4, 182 - 193

[5] M. K. Gräf, H.-G. Hillenbrand and K. A. Niederhoff: Production of large diameter line pipe and bends for the world's first long-range pipeline in grade X80 (GRS 550); 8th Symposium on Line Pipe Research, Houston (Texas), September 26 - 29,1993

[6] H.-G. Hillenbrand, E. Amoris, K. A. Niederhoff, C. Perdrix, A. Streißelberger and U. Zeislmair: Manufacturability of line pipe in grades up to X100 from TM processed plate; Pipeline Technology Conference, Sept 1995, Ostend, Belgium

[7] H.-G. Hillenbrand, A. Liessem, G. Knauf, K. A. Niederhoff and J. Bauer: Development of large-diameter pipe in grade X100 – state-of-the-art report from the manufacturer’s point of view; Pipeline Technology Conference, May 2000, Brugge, Belgium

[8] V. Chaudhari, H. P. Ritzmann, G. Wellnitz, H.-G. Hillenbrand and V. Willings: German gas pipeline first to use new generation line pipe; Oil & Gas Journal, January 1995

[9] M. D. Bishop, O. Reepmeyer, H.-G. Hillenbrand, J. Schröder and A. Liessem: Longitudinal welded X80 pipes for a high temperature, high pressure steam pipe line; 3R international 41 (2002) No. 2, 113-117

[10] C. Kalwa, H.-G. Hillenbrand, M. K. Gräf: High strength steel pipes: New developments and applications; Onshore Pipeline Conference, June 2002, Houston, USA

[11] H.-G. Hillenbrand, K. A. Niederhoff, G. Hauck, E. Perteneder, G. Wellnitz: Procedure, considerations for welding X80 line pipe established; Oil & Gas Journal, Sept 15, 1997

[12] E. Perteneder, H. Königshofer and J. Mlekusch: Characteristic Profiles of Modern Filler Metals for On-Site Pipeline Welding; Pipeline Technology Conference, Sept 1995, Ostend, Belgium

[13] M. K. Gräf and K. A. Niederhoff: Overmatching Criterion and Manual Welding of Linepipe in Grade X70; Pipeline Technology Conference, Sept 1995, Ostend, Belgium

[14] M. K. Gräf and K. A. Niederhoff: The influence of girth weld mis-matching on the behaviour of pipelines in high strength steels up to grade X100; Conference Mis-Match ´96, April 1996, Reinsdorf-Lüneburg, Germany



Figures

Process Diameter Wall thickness

Longitudinally welded large-diameter pipe 20 “ to 64 (56) “ ca. 10-35 mm

Spirally welded large-diameter pipe 20 “ to 64 “ ca. 6-16 mm *)

HFI (ERW) welded pipe ≤ 24 “ ca. ≤ 10 mm

*) Hot strip material from Steckel mills

Figure 1: Limitation of Dimensions to be manufactured in grade X80 on different production routes

Project Dimension Quantity Realization

MEGAL II, Germany 1118 x 13.6 mm 3.2 km 1985

4th Transit Gas Pipeline,

Czechoslovakia

1420 x 15.5 mm 1.5 km 1985

Empress Eats Compressor

Station Alberta; Canada

42” x 10.6 mm 126 welds 1990

Werne-Schlüchtern Pipeline,

Ruhrgas, Germany

48” x 18.4 and

19.3 mm

250 km; 145.000 to 1992/1993

NOVA Pipeline; Matzhiwn

project, Alberta, Canada

Spiral pipe, 48” x

12.1 mm

ca. 54 km 1994

Trans Canada Pipeline Spiral pipe, 48” x

12.0mm & 16.0mm

ca. 118 km 1997

Transco/UK 48” x 15.1 mm and

21.8 mm

42 km 2001

Canadian Natural Resources,

Canada

24” x 25.4mm 18 km; hot steam

onshore pipeline

2001

Figure 2: Reference list of X80 onshore projects in large-diameter pipe world-wide



Figure 3: Specified strength for high strength line pipe steel grades

Figure 4: Distribution of Titanium and Nitrogen contents of the base material of the pipes produced (Ladle analyses)



Figure 5: Temperature profiles measured before and after accelerated cooling

Figure 6: Distribution of transverse yield strength (Rt0.5) and tensile strength (round bar specimens to DIN

50125)



Figure 7: Mean chemical composition and distribution of impact energy values measured on ISO V-notch specimens for the SAW longitudinal seam weld metal

Base Material - Tensile Test

YieldStrength

2” Elongation (%)

560 600 650 700 750

35302520151050

4035302520151050

Yield/Tensile Strength (MPa)

TensileStrength

0.76 0.80 0.92 28 30 32 34 36

Frequency (%)

Frequency (%)

25

20

15

10

5

0

Y/T ratio0.84 0.88

Frequency (%)

n = 164

Figure 8: Strength properties of X80 Pipes (48” OD x 15.1 mm WT); Transco pipeline



Frequency (%)50

45

40

35

30

25

20

15

10

5

0

Impact Energy (J)

50

45

40

35

30

25

20

15

10

5

0

Frequency (%)

2000Impact Energy (J)

Base MaterialTest Temperature 0°C

Weld MaterialTest Temperature 0°C

100 300 2000 100 300

n =70 n = 70

Figure 9: Impact properties of X80 Pipes (48” OD x 15.1 mm WT); Transco pipeline

Figure 10: Chemical composition and mechanical properties of the GRS 550 QT (Grade X80) line pipe bends



Figure 11: Preheating temperature for crack resistance as a function of the C-equivalent - Welding with cellulose coated electrodes –

Figure 12: Comparison between the preheating temperatures required in the laboratory and those required in the field for ensuring crack-free welds in X80 steel



Figure 13: Manual downhill welding procedure for high-strength line pipe steel

Figure 14: Typical girth welding procedure for mechanized gas metal arc welding of

X80 line pipe (CRC-Procedure)


Paper 5: Piper Page 50 of 131 Hobart October 30 2002

X80 Line pipe for small diameter (DN450 and smaller) high

strength pipelines.

by

John Piper OneSteel, Oil & Gas Pipe, Kembla Grange

with Contributions from

Nippon Steel Corporation and

Kawasaki Steel Corporation

ABSTRACT Major pipe manufacturers in Australia and Japan have developed the HFERW X80 grade to the point of commercial viability and have been ready to supply for some years. While concerns within the Australian industry primarily to do with weldability have delayed introduction of the grade, recent research and developments in welding techniques may have changed this viewpoint. Apart from welding issues, X80 should be seen as just the next incremental step in pipe grade development. The sections offered in Australia can be readily seen as a small step up from X70 grade. This is because X80 uses the same alloy family (C-Mn-Mo-Nb-Ti) as Australian X70. There is low risk in manufacturing X80 as it is easier to form in the pipe mill as, for the same pressure strength, the wall is thinner. X80 has been extensively trialed in ERW sizes up to 610 mm wall thickness both in Australia and in Japan. It has been shown to have acceptable strength, toughness, hardness and resistance to SCC. Pipe in quite large quantities has been produced and in one case is in commercial operation where it was successfully coated, cold field bent, and welded using cellulosic consumables. As such, API 5L X80 PSL2 is a viable option for cross country oil & gas pipeline construction in Australia.



INTRODUCTION API 5L X80 PSL2 line pipe, manufactured using the high frequency electric resistance welding method (HFERW) has been commercially available since 1995 from both Australian and Japanese pipe mills. Nevertheless, it has not been used commercially, except on one occasion, in these past 7 years. This has primarily been caused by concerns about welding the grade. While other papers at this seminar will deal with the welding issues, and likely allay these concerns, it is the purpose of this paper to describe the history and experience the mills have in producing X80. This paper will also describe the attributes of X80 line pipe showing that the grade is not all that different to the lower strength grades it may shortly replace. Indeed, the X80 pipe produced has exhibited entirely acceptable integrity, strength, ductility, toughness, bendability and weldability. PIPELINE GRADE HISTORY IN AUSTRALIA. The use of line pipe in the oil and gas industry commenced in earnest in Australia in the 1960s. At that time steels used for line pipe were relatively unsophisticated and of low strength. Pipeline construction was rare as each State jealously guarded its own reserves. The pipelines which were built were relatively high in cost. As the industry progressed, it became apparent that, with the gas a long way from potential markets, relatively small consumption would occur at the end of relatively long pipelines. As such, potential pipeline developers looked for ways of cutting cost on successive projects. The most effective means of doing so were to increase operating pressure (and hence flow rate), and reduce the tonnage of steel used in a pipeline. The latter occurred by increasing the strength of the pipe and in turn reducing its wall thickness. This trend to higher and higher grades of pipe was limited only by the ability to construct a safe pipeline, and by grade availability. This process pushed pipe manufacturers to stronger more technically challenging steels and was aided by the advent of major steel making advances in the 1970s and 80s. These took the form of basic oxygen furnace production, ladle processing for alloy additions, vacuum degassing and continuous slab casting. With these technologies the pipe grade most commonly used evolved rapidly through X52 to X60, then X65 and on to the point where most pipelines were constructed in X70 through the 1990s. The exceptions were smaller diameter or lower pressure pipelines where either X70 was not available or the resultant wall thickness was deemed too thin to weld or be safe from third party interference. Figure 1 (1) illustrates this trend, showing the rise and fall of the various grades.

Figure 1: LIFE CYCLE OF ERW PIPE GRADES

0

40000

80000

120000

1970 1980 1990 2000

Ton

nes

X65Moomba -

Sydney

X42

X52/56

Jackson -Moonie

X60

Darwin -Alice

X65

ethane

X70EGP

GGT

X



The expectation in the early 90s was that X80 would follow this trend and become the preferred grade of the late 90s. This expectation was driven by the rapid and universal acceptance of X70. To the surprise of many, X80 did not receive this treatment due primarily to concerns regarding weldability. AUSTRALIAN X80 DEVELOPMENT.

The main mills active in Australia developed the X80 grade through alloy design and trial rollings in readiness for commercialisation. This process commenced in 1993 and was, to a large extent a parallel development with X70. The reason for this was the recognition that the alloy system used for X65 production consisting of titanium stabilised carbon manganese steel strengthened with niobium and vanadium had a limited ability to be extended to higher strengths. As strength was increased by higher alloy content, carbon equivalent approached an unacceptable level. Also, the strength attained was disproportionately lost on conversion to pipe due to the Bauschinger effect. A new alloy family was required. To this end, vanadium was deleted from the steels and molybdenum, a strong carbide former, and thus a very effective strengthening agent, was added. This new family of alloys achieved the strengths required and maintained them upon pipe manufacture. The high effectiveness of molybdenum along with the use of niobium (which is not active in the two carbon equivalent relationships, IIW CEq1 and Pcm2 which relate to weldability) allows for strong alloys This reduces the need for both carbon and manganese both of which reduce weldability. As such, alloys with strengths up to X80 level can readily be produced with CEq and Pcm maxima of 0.42% and 0.20% respectively. The significance of this is that 0.42% is a de facto industry standard limit consistent with the WTIA Technote 1(2) approach to pre-heat free welding without risk of hydrogen induced cracking of

1 CEq = C + Mn/6 + (Cr+Mo+V)/5 + (Cu+Ni)/15 2 Pcm = C + Si/30 + (Mn+Cu+Cr)/20 + Ni/60 +Mo/15 +V/10 + 5B

Table 1: History of Australian Trial X80 Production.

Date Project Aim Heat # Thickness Diameter Coils Rolled

1993 Initial 273 mm Dia Trial

Base Data 6974826 3.0, 5.2, 8.0, 9.0

273.1 3

1994 Initial 406 mm Dia Trial

Base Data 6974826 4.6, 7.6,7.8 406.4 1

1995 First 457 Class 900 Trial

Base Data 7213359 8.6 457.0 5

1995 457 Class 900 1st trial

Low Strength extreme data

7213367 7213369

8.6 457.0 3

1996 457 Class 900 2st trial

Increased Ti Addition

7266296, 6259686 6259697

8.6 457.0 5

1999 Commercial Rolling

Various 8.8 406.4 45

2000 457 Class 900 4th trial

Potential Pilot Rolling

7266295 7420149

8.8 457.0 6

2002 355 Class 900 trial


826508 826509

6.9 355.6 20



the weld heat affected zone. A PCm limit of 0.20% is also considered good practice. A consequence of this philosophy is that thousands of kilometres of X70 line pipe comprised of the C-Mn-Nb-Mo-Ti alloy steel have been successfully manufactured, coated and installed in Australia. There is no need to summarise this history here. Suffice it to say that the successful production and use of this pipe forms a very firm foundation for the extension of this alloy family to X80 strength. To develop X80, trial rollings are needed. These demonstrate the required attributes of the pipe grade and section, confirming composition and processing limits, and provide material for welding development and the like. To date, five trial rollings and one commercial rolling of X80 have been undertaken since 1993. These comprise a total of 20 steel heats, or about 4000 tonnes of steel. The first trial covered a broad thickness and diameter range and was designed to examine fundamental strength relationships. Later trials placed emphasis on two commercial products, ANSI/ASME Class 900 main line wall thicknesses in 457 and 355 mm diameter pipe as these are the most likely section to be used in the near future. Standard and lean compositions have been used to provide a range of properties and explore lower limits. JAPANESE X80 DEVELOPMENT. The Japanese mills also developed HFERW in parallel with the Australian efforts. As but two Japanese mills are currently active in exports of ERW line pipe, these remarks will be limited to their work. Nippon Steel Corporation operates their HFERW Mill at Hikari in southern Japan. They have undertaken development of X80 in the early nineties, producing a number of heats concentrating on the larger ERW sizes with heavy wall thicknesses with potential for application in sour service conditions. As with the Australian experience, these are C-Mn-Nb-Mo Ti steels although, with sour service in mind, NSC has limited Mn to 1.2% and added nickel to achieve the required strength. A section used in their development is 406 x 11.3 mm and the work has been extensively reported(3). Nippon Steel contends that it is capable of producing ERW X80 in diameters up to 610 mm but will need additional trial rollings to verify its various pipe section designs. Kawasaki Steel Corporation has also extensively developed X80 at their 26” HFERW mill at Chita in central Japan. Again, they have produced several heats of steel with their emphasis on heavy wall large diameter sections which complement the lower thickness main line sections. Typical of their recent work are the sections 457 x 12.4, 508 x 15.9 and 610 x 14.8 which have been produced in 1999 and 2000(4). Again, KSC is using a C-Mn-Nb-Mo steel, but with an addition of vanadium for additional strength in the heavy sections produced. However, they have a lesser emphasis on the use of titanium stabilisation. While these larger sections are technically outside the scope of this paper, they have been included as they represent the current direction of the KSC development work for ERW pipe. THE MANUFACTURING PROCESS. As with lower grades of pipe, X80 uses the same quite sophisticated steel and pipe manufacturing methods, irrespective of the manufacturer. Figure 2, courtesy of KSC, describes a typical manufacturing path. Blast furnace iron is de-sulphurised, then combined with high quality scrap in a BOS vessel and converted to raw steel, usually containing the appropriate levels of major alloying elements such as manganese and molybdenum. This is then further treated to add microalloys such as niobium, and then treated to further reduce sulphur levels and non-metallic inclusion levels using calcium additions and a vacuum de-gassing process. Great



care is taken in the slab casting process to promote a homogenous cast structure, avoiding cracking and segregation of the alloys. Depending on the mill, such techniques as magnetic stirring and soft reduction are used. Superheat, casting speed and mill geometry monitoring (demonstrated by a slab macroetch method) are universally used.

Blast Furnace Flux Injection

De-P De-S

Soda Ash

RH Degassing

De-N Al addition Alloy addition

Vacuum

Circulate

De-CDe-SiDe-PMn addition

Basic Oxygen Converter

O2 gas

O2 jet

Figure 2: Steelmaking Process of The Linepipe Material

Ladle

Tapping

Al addition

S ? 0.005% P ? 0.035% P? 0.020%

Tundish

Ladle

Slab

Ar gas shielding

Continuous Casting

Ca wire

Ca Addition

Equally, great care and skill is required during the hot rolling of the slab to produce hot coil. Each mill uses a different specific technique, nevertheless, they are all characterised by carefully designed slab soaking programs to optimise microalloy effectiveness and careful control of temperatures throughout the mill, with great emphasis on finishing temperature, accelerated cooing systems and coiling temperatures. Pipe manufacture is similar in each mill with the scale of the equipment determining the maximum size of the sections which can be formed and welded. The Japanese mills are capable of larger sections than the Australian mill. Still, X80 is easier to produce at any given pressure strength than X70 as the section is 12.5% thinner. Despite their obvious differences, each mill is characterised by :

a) Careful attention to strip forming to produce round, straight pipe suitable for coating and field welding.

b) HFERW welding, usually with temperature, and sometimes the heat input, monitored and controlled to achieve a sound weld .

c) Either accelerated cooling or a quench and temper seam weld heat treatment process, used to ensure good weld line toughness.

d) Careful attention to bevel machining to promote high productivity field welding. COMPOSITION AND PROPERTIES. The attributes of line pipe are of central importance as they permit and limit the way it is designed into a pipeline. Strength, weldability and toughness are fundamental. Yet less readily specifiable attributes such as ability to be coated and to be hot and cold bent have their own significance.



COMPOSITION AND WELDABILITY

The composition of the steel largely determines strength, weldability toughness and hardness. Limits on unwanted impurities such as phosphorous, sulphur and tin also ensure the integrity of the resultant pipeline by avoiding welding problems. The composition of X80 steels is, at least in the case of Australian production, an incremental development from X70 steels. The challenge has been to find the right combination of strengthening alloys to provide the high strength required yet still achieve an acceptable weldability. In this context, weldability is defined as the ability to weld ‘preheat free’ without risk of hydrogen induced cracking using a cellulosic electrode welding technique. While there are substantial challenges facing the electrode manufacturers in achieving acceptable weld metals, the difficulty from the pipe manufacturing viewpoint is less onerous, and essentially comes down to meeting an IIW CEq upper limit of 0.42% and a Pcm limit of 0.20%. When these limits are achieved, other composition based concerns such as propensity to segregation, and hardness can be controlled acceptably.

Table 2: Chemical Composition Project Purpose Heat # C Mn Si Mo Ni Nb V Ti CEq Pcm OST Initial 273mm Dia

Trial

Base Data 6974826 0.075 1.59 0.31 0.22 - 0.057 - 0.013 0.384 0.180

OST Initial 406 mm Dia

Trial

Base Data 6974826 0.075 1.59 0.31 0.22 - 0.057 - 0.013 0.384 0.180

OST First 457 x 8.6 Class 900

Trial

Base Data 7213359 0.055 1.65 0.26 0.22 - 0.056 - 0.012 0.374 0.161

OST 457 x 8. 6 Class

900 1st trial

Low Strength

extreme data

7213367 7213369

0.060 1.55 0.19 0.20 - 0.040 - 0.012 0.358 0.157

OST 457 x 8.6

Increased Ti Addition

7266296, 0.065 1.60 0.31 0.27 - 0.064 - 0.019 0.386 0.173

Class 900 Trial

6259686 0.065 1.57 0.29 0.28 - 0.078 - 0.020 0.383 0.172

6259697 0.060 1.58 0.30 0.25 - 0.079 - 0.021 0.373 0.166 Commercial

Rolling Various 0.067 1.54 0.32 0.28 - 0.069 - 0.019 0.387 0.173

OST 457 x 8.8 Class 900

Pilot


7266295 7420149

0.065 0.070

1.60 1.51

0.32 0.29

0.26 0.26

- -

0.0630.076

- -

0.0180.018

0.384 0.374

0.173 0.173

355 x 6.9 Class 900

Pilot


826508 826509

0.065 0.070

1.47 1.47

0.33 0.33

0.26 0.28

- -

0.0600.065

- -

0.0190.019

0.38 0.37

0.18 0.17

NSC 406 x 11.3 mm

Sour Service Trial

0.08 1.09 .26 .25 .31 0.049 - 0.011 0.332 0.165

KSC 457 x 12.4 mm

Class 900 heavy wall

0.07 1.48 0.18 0.38 - 0.050 - 0.007 0.393 0.172

KSC 508 x 15.9 mm


0.065 1.64 0.29 0.18 - 0.049 0.074 0.010 0.40 0.180

KSC 610 x 14.8 mm


0.048 1.45 0.24 0.18 - 0.047 0.071 0.009 0.36 0.150



Table 2 lists the compositions of the various steels used for X80 manufacture. It can be seen that quite a different approach has been taken between the Australian and Japanese mills. In Australia the focus has been on diameters up to 457 mm and wall thicknesses suitable for main line (72% Design Factor), whereas the Japanese mills have concentrated on these diameters and even larger diameter pipe and wall thicknesses consistent with the heavy wall component of a pipeline (Design Factor <60%). Despite this, the compositions used are rather similar, being C-Mn-Mo–Nb-Ti steels with an addition of nickel (NSC) or vanadium (KSC) used to achieve adequate strength where the thickness is above 13 mm. In each case, weldability, as measured by CEq and Pcm is within the appropriate limits. It is noteworthy that these limits really apply only to cellulosic welding and that the larger KSC sections may well be amenable to automated welding economically. STRENGTH The strength limits required by API 5L for the X80 grade are a yield strength range of 552 to 690 MPa, a tensile strength range of 621 to 827 and ductility of 17 to 21% elongation depending on wall thickness. With concerns expressed about overmatching the strength of the field girth weld, there has been pressure to reduce the yield strength range (this allowing less strong weld metals to ‘overmatch’ the pipe strength). To this end and for a large order, most mills will accept a strength range of 552 to, say, 682 MPa with a large proportion in the range 552 to 652 MPa. Table 3 lists the strength ranges achieved form the various trials. Elongation values have been excluded as in all cases they were readily met. While some of the Australian trials produced yield strengths lower than the lower grade limit of 552 MPa this was part of the process of establishing very tight range limits desire by the industry to achieve weld strength overmatching. Indeed, the commercial production and the 355 mm diameter. pilot rolling produced quite acceptable yield strength ranges of 50 and 61 MPa, with average values of 608 and 576 MPa respectively. Equally, the Japanese trials are producing strengths in the desired ranges. TOUGHNESS Achieving 85% shear in the Drop Weight Tear Test is ordinarily considered proof against brittle fracture propagation in a pipeline. Under normal design rules, this value must be achieved at the minimum design temperature of the pipeline. In Australia, this is usually set at either 0 oC, -10 oC or rarely –20 oC. With the exception of the very heavy wall trial X80 material produced by KSC which is suitable for a minimum design temperature of –10 oC, all other sections produced in the trials meet the 85% shear requirement at – 20 oC. Doubtless, KSC is addressing this issue and as such there should be no concern in using X80 from a brittle fracture resistance viewpoint. Determining a strategy to avoid ductile fracture propagation in an X80 pipeline is more difficult. In lower grade pipelines it has become common to rely on body Charpy values which meet or exceed the Battelle equation for fracture arrest. (See AS2885.1 Appendix F). Doubt about this approach has been expressed(5) and higher than Battelle Charpy toughness values have been proposed, although there seems to be little justification in specifying a toughness above 100J on a 10 x 10 mm test piece (f.s). The body Charpy results in Table 3 for the trials undertaken reflect performance consistent even with 100J f.s. performance, although in the case of Australian production, a 0.004% S limit would be needed to guarantee performance.



It is becoming more and more common to specify minimum levels of ERW weld line toughness, first as a defence against crack initiation and second through the perception that higher levels of toughness somehow indicate that the pipe is of ‘better’ quality. The former concern is entirely legitimate and there is good understanding of the processes involved in crack initiation. Perhaps the best analysis is that of Maxey described in reference (6). This provides a Charpy toughness at some fraction of the limiting critical crack length at infinite toughness. The required toughness is always well below the arrest toughness requirements and usually in the range of 20 to 40 J full size. Since the event being guarded against is third party damage to a pipeline, it is unlikely to occur under blow down conditions. As such the temperature normally specified for initiation toughness testing is 0 oC or higher. The other reason for specifying weld line toughness i.e. ’pipe quality’ is rather a more nebulous concept. Nevertheless, as sulphur levels are reduced, and approach those used in sour

Table 3: Strength, Toughness and Hardness.

Project Purpose Thick Dia Pipe Yield Strength

Pipe Tensile Strength

Body Toughness

J pro rata f.s.

ave.

Weld line Toughness

J pro rata f.s.

ave.

Weld region

Hardness max Hv

OST Initial 273 mm Dia Trial

Base data 5.2, 8.0, 9.0

273.1 549 to 607 713 to 760 Accelerated Cooling not

used

OST Initial 406 mm Dia Trial

Base data 4.5, 7.6, 7.8

406.4 574 to 607 698 to 737 Accelerated Cooling not

used

OST First 457 x 8.6

Class 900 Trial

Base data 8.6 457.0 577 to 607 687 to 739 Accelerated Cooling not

used

OST 457 x 8. 6 Class 900 1st trial

Low Strength extreme

data

8.6 457.0 521 to 577 666 to 695 Accelerated Cooling not

used

OST 457 x 8.6 Class

900 Trial

Increased TI addition

8.6 457.0 595 to 659 717 to 792 Accelerated Cooling not

used

Commercial Rolling

8.8 406.4 572 to 622 712 to 764 114 to 183 @-20C

51 to 209 @ 0 C

272 @ parent metal

OST 457 x 8.8 Class 900 Pilot

Potential pilot

rolling

8.8 457.0 602 to 626 698 to 750 78 to 140 @ 0C

Accelerated Cooling not

used

264 @ Parent metal

355 x 6.9 Class 900 Pilot

Potential pilot

rolling

6.9 355.6 563 to 624 698 to 754 106 to 138 @-20 C

44 to 130 @ 0C

254 @ Parent metal

NSC 406 x 11.3 mm

Sour service trial

11.3 406.4 602 689 201 @-5 C

71 @-5C

250 @ HAZ

KSC 457 x 12.4 mm


12.4 457 571 to 602 681 to 709 140 @-20C

80 @ 0C

256 @ HAZ

KSC 508 x 15.9 mm


15.9 508 584 685 230 @-20C

250 @ 0C

250 @ HAZ

KSC 610 x 14.8 mm


14.8 610 580 709 370 @-20

330 @0C

230 @ parent metal



service, weld line toughness does increase. It is not uncommon for specifier to press for increased weld line toughness where this can be achieved at marginal incremental cost. Examination of the weld line toughness levels reported in Table 3 shows them to be acceptable from an initiation viewpoint. Indeed, as the Japanese pipe is approaching sour service ‘quality’, the values reported are excellent. HARDNESS Hardness across the ERW weld zone has been a concern as high hardness levels correlate with preferential corrosion, and hydrogen induced cracking either during welding or from sour gas. As such a limit of Vickers 250 (Hv 250) has traditionally been placed on line pipe, but is extended to Hv 270 or even Hv 290 for higher strength grades in non-sour service, such as X80. Some peak hardness values are listed in Table 3. While all trials meet the proposed limit of 290 Hv , the Australian pipe approaches this level in the parent metal, whereas the Japanese mills have achieved significantly lower hardnesses peaking at about Hv 250 in the heat affected zone of the ERW weld. CONSTRUCTION ATTRIBUTES The attributes of the pipe dealt with above are those which the material standard API 5L focuses upon. While vitally important, they are incomplete as they don’t deal with all the attributes of pipe which are important in pipeline construction. These include the ability of the pipe to be coated, hot bent, cold field bent, field welded and survive stress corrosion cracking (SCC). The commercially produced X80 was coated with factory applied extruded Mastic/PE with no apparent difficulties. While only a 14 km job, this is indicative that no major problems will arise in the coating of X80 line pipe. Certainly, on that occasion there was no problem in blast removing the mill scale as some had suggested. Indeed this is not surprising as the pipe is of the same composition family, and only a little stronger than the thousands of kilometres of X70 which have been successfully coated. To date, however, X80 has not been FBE coated in Australia. Again, there should be no difficulty, the steel being similar to that coated previously and, indeed with hardness only a few percent higher than X70. Nevertheless, care should be taken in assessing the mechanical properties of the pipe after FBE coating as , while toughness is not likely to change, longitudinal strength will likely increase marginally despite these steels being generally classed as non-aging. This effect will be of most interest where the welding process is being specifically designed to be overmatching. Again we are not aware that X80 has been hot bent, but see no difficulty as the remaining hot bending contractor in Australia has had extensive experience; at least with the alloy system primarily used in Australia. As for cold field bending, this was carried out successfully for the commercial quantity installed. This was not unexpected as cold field bending was examined at length by Bilston (7) with quite satisfactory results. X80 can and has been successfully field welded using both cellulosic electrodes and automated processes. The former method was used for the commercial quantity of pipe installed some years ago. The latter method has been used on a number of occasions very successfully, but not as a production process in Australia for X80. Other papers in this seminar will deal in detail with welding. Suffice it to say that X80 manufactured with the compositions used to date and in thicknesses up to perhaps 10 mm should be capable of being successfully field welded using cellulosic electrodes with minimal or no pre-heat, and up to around 13 mm with only low levels of preheat. In thicker sections, pre-heat will likely be needed and, of course, these comments need to be tempered with an understanding of the need for overmatching the pipe strength. This need can only be established through pipeline



detail design and must take into account the available consumables. As a fall back position, the pipe can be welded using hybrid low hydrogen processes or automated gas metal arc welding methods. Finally, stress corrosion cracking was at one stage seen as a significant threat to pipelines and indeed to higher strength pipelines. Research undertaken in the early nineties demonstrated that for grades, including X80 (8), the threshold stress for SCC in carbonate/bicarbonate environments is a function of the actual yield strength of the pipe. As operating pressure is also a function of pipe strength, no particular grade of steel is more prone to SCC than any other. Some care needs to be exercised when using the notion of 'threshold stress' in relation to the design of a pipeline. The 'threshold stress' as a defined term is determined in an accelerated test that bears no relation to pipeline operation, and a value determined from that test which is higher than the stress equivalent to MAOP will be no guarantee against failure by SCC in service. The best available defence against SCC is a good quality factory applied coating applied on a grit blasted surface, good control of the operating temperature and stress range, and a functional CP system.



SUMMARY. Major pipe manufacturers in Australia and Japan have developed the HFERW X80 grade to the point of commercial viability and have been ready to supply for some years. While concerns within the Australian industry primarily to do with weldability have delayed introduction of the grade, recent research and developments in welding techniques may have changed this viewpoint

. Apart from welding issues, X80 should be seen as just the next incremental step in pipe grade development. The sections offered in Australia can be readily seen as only a small step up from X70 grade. This is because X80 uses the same alloy family (C-Mn-Mo-Nb-Ti) as Australian X70. There is low risk in manufacturing X80 as it is easier to form in the pipe mill as, for the same pressure strength, the wall is thinner. X80 has been extensively trialed in ERW sizes up to 610 mm wall thickness both in Australia and in Japan. It has been shown to have acceptable strength, toughness, hardness and resistance to SCC. Pipe in quite large quantities (4000 t in Australia) has been produced and in one case is in commercial operation. In this first commercial project, 8.8 x 406.4 mm, X80 was successfully coated, cold field bent and welded using cellulosic consumables. Other pieces of this pipe were successfully automatic welded using a GMAW process. Table 4 summarises these issues as

Table 4: Risk Matrix for X80. Hazard Mitigation Strategy Residual risk Can not source appropriate diameters and wall thicknesses competitively.

Both Australian and Japanese mills offer up to 457 mm dia. Both Japanese mills offer larger sections.

Very Low

X80 is a new grade. The mills may fail to produce the required strength, toughness, hardness ductility etc.

Both Australian and Japanese mills have run extensive and successful trials. The steel is an extension of X70 technology and is well understood. The pipe sections are thinner than X70, and as such, are easier to form

Very Low

The pipe cannot be coated. Extruded Mastic/PE coating has been successfully used commercially. No blasting difficulties were experienced (the steel is of the same alloy family as X70 and not much harder). There should be no difficulties with FBE coating. Any additional strength increment from coating should be considered.

Very Low

The pipe cannot be hot bent. The steel is of the same alloy family as X70, so no difficulty is expected.

Very Low

The pipe cannot be cold bent Both trials and a small project installation have demonstrated that X80 can be cold field bent satisfactorily.

Very Low

The pipe cannot be welded As the usual CEq (0.42%) and Pcm (0.20%) limits can be met with X80 there should be no difficulty in welding with cellulosic consumables. Where appropriate cellulosic consumables are not available to overmatch the pipe, automated GMAW welding has also been demonstrated to be an effective X80 welding method

Very Low

The pipe may suffer SCC. So long as a factory applied coating is employed, along with effective joint coating and CP there will be no additional risk compared with other grades.

Very Low



a risk matrix and demonstrates that the risk in using X80 is very low. As such, API 5L X80 PSL2 is a viable option for cross country oil & gas pipeline construction in Australia. Acknowledgements. The author would like to acknowledge the valuable contributions made on behalf of Nippon Steel Corporation by Mr Ayukawa and on behalf of Kawasaki Steel Corporation by Mr Nakamura. References.

1. F.J. Barbaro, G.F. Bowie and W. Holmes. “Welding the First ERW X80 Grade Pipeline” AS2885.2 Seminar August 2002.

2. WTIA Technote 1-94 “The Weldability of Steels”

3. A Belloni, H Kashimura, Y Murakamii, T Fujii. “Manufacturing and Welding on

an X80 (HF-ERW) Pipe - A new technical approach.” Nippon Steel Corporation 1995.

4. Private communication with Mr Nakamura of KSC.

5. J Piper, R Morrison “The International Database of Full Scale Fracture Tests

and its Applicability to Current Australian Pipeline Designs”

6. J Piper, R Morrison, L Fletcher. “The integrity of ERW welds in high strength line pipe”.

7. P Bilston “Bending Procedure Qualification” 273 x 5.2 x X80” Advanced Pipeline

Technology P/L. July 1993.

8. D B Wells. “Stress Corrosion Cracking Threshold Measurements on X80 Line Pipe” Industrial Research Ltd. August 1995.

=======


Paper 6: Gray Page 62 of 131 Hobart October 30 2002

An Independent View of Linepipe and Linepipe Steel for High Strength Pipelines:

How to get Pipe that's Right for the Job at the Right Price

by

J. Malcolm Gray

Microalloying International, LP

Houston, Texas

Summary

This paper describes the state of development of high strength linepipe up to X-100 and beyond. API Grade

X-80 pipe steel, the subject of this conference, is available in the market place in ERW, DSAW and SMLS

product forms and has been for several years, however, only large diameter DSAW systems and seamless

risers have been installed to date.

This paper describes a reliable, proven methodology to be applied in sequential steps for procuring large

or small quantities of high quality linepipe from mills worldwide. It is expected to be especially useful for

sourcing a new grade such as X-80 from an unproven manufacturer. The approach was developed and

refined during the past two decades and was successfully used for purchase of 1,766 miles of sour service

X-70 linepipe for the All American Pipeline System, a summary of the project outcome is included in the

paper.



1.0 Introduction

Linepipe strengths have increased steadily during the past 40 years as metallurgical practices and

manufacturing techniques have evolved in response to the demands of the marketplace. Technical

requirements and expectations have escalated continuously as both the oil and gas industry and pipe

production have become fully internationalized and very competitive. It can be argued that linepipe

installability and reliability have simultaneously improved due to impressive improvements in steelmaking,

rolling, pipe manufacturing and inspection technologies. Despite this, adoption of new grades

representing increments in strength has been impeded by tangible and intangible factors, many of which

are being discussed in this workshop. The present paper reviews the state of the art concerning pipeline

steels having yield strengths of 80 ksi (551 MPa) and above and presents a methodology for procuring the

correct steel at a sensible price.

2.0 Line Pipe Development X-80 and Beyond

Available yield strength levels have doubled in the past 50 years from the X-42 to X-52 (289 - 358

MPa) range in 1950 to 100 ksi (689 MPa) and above. The overlapping development periods for each

grade are presented in Figure 1. The early higher strength steels were based on heat treatment of

vanadium microalloyed steel whereas more recent steels, up to the present day, are based on

thermomechanical processing of low carbon complex steel compositions which universally depend on the

beneficial effects of niobium during hot rolling.

Figure 1. Development periods for high strength linepipe.



The adoption dates for new or even improved steels have lagged the initial developments by

between 10 and 15 years. This is true even as the pace of metallurgical development has accelerated due

to the emergence of Exxon-Mobil, an end user in the steel development business. This can be traced to

conservatism in the pipeline industry as well as the time it takes to develop the data necessary to support

the end user design and safety concerns.

The inertia concerning the adoption rate has held despite seemingly impatient or irresistible

demands of the marketplace, some of which are chronicled in Table I. For example, one of the first

initiatives to transport natural gas from Alaska to Canadian and USA market circa 1970 was based on X-

80 strength levels (48 inch [1202 mm] O.D., 0.60" [15.24 mm] w.t. and 90 ft-lbs [120 J] CVN energy at -

90°F [-69°C]). The steels were mostly developed by 1972[1] but the first Alaskan gas project has yet to be

built! However, X-80 linepipe was indeed adopted some eleven years later in the Megal and Ruhr Gas

Projects,[2-5] a delay of 10-12 years. By this yardstick significant usage of small diameter X-80 HFERW

linepipe, which has been available since 1993[6], may be imminent.

Table I

Stimuli for Technological Development

Date Event Industry Reaction

1943 Discovery of ductile-brittle transition in carbon steels.

Introduction of 15 ft-lb CVN energy requirement into specifications for ship plate.

1954 Above characteristics considered relevant to pipelines.

TÜV introduced 3.5 mkg/cm2 energy requirement for pipelines.

1960 Brittle fracture propagation of 13 km in NPS 30 pipeline.

Development of Battelle drop weight tear test (BDWTT).

Dec. 1968 - Jan. 1969

Propagating ductile fracture in non-brittle, supposedly crack resistant, material.

Introduction of minimum Charpy energy requirements based on various fracture models.

1970 Proposed construction of Alaskan/ Canadian gas pipelines (CAGSL)

Steel development frenzy centered on X-80 (551 MPa) and -69°C (-90°F) toughness requirements.

1972 HIC failure in X-65 BP pipeline in Ummshaif (Arabian) Gulf.

Introduction of BP test (NACE TM-02-84 [Solution B]).

1974 Unpredictable fracture arrest in full scale (CAGSL) tests. Attributed to rich gas, separations, high hoop stress and faulty models.

Introduction of crack arrestors, improved fracture arrest modeling and revision of rolling ideas for high strength linepipe.

1978 Stress corrosion cracking failures in newly installed Australian and Canadian pipelines.

Better metallurgical (hardness) controls and improved external coatings. Improved operating practices.

1978 Molybdenum "shortage" and price escalation. Mo designed out of X-70 steels. Nb-Cr design introduced plus TMCP.

1988/89 Vanadium price increase to $50/kilo Vanadium eliminated from many steels. Mo and Cr + TMCP



substituted. 1990 Development of deepwater oil and gas

reserves and design of Oman-India and Black Sea pipeline.

Very heavy wall thickness (44 mm) collapse-resistant DSAW linepipe developed for pipelines and TLP tendons as well as high strength (80 ksi) seamless risers.

1997 Need for very high pressure systems for Arctic developments in remote areas.

Ultra high strength (135 ksi UTS) steels considered and composite reinforcement of conventional steels introduced.

The literature abounds with technical data concerning the metallurgy, welding and fracture

resistance of X-80 linepipe in all diameters and pipe types (ERW, SMLS and DSAW). The required

technology is undoubtedly available, in many quarters, for manufacturing high quality pipe in large

quantities. All obstacles appear to be surmountable. For example higher strength grades such as X-80 or

ultra high strength X-100/120 require very high Charpy V-notch or DWTT energies for ductile fracture

control which can only be achieved in clean low sulfur steels. Fortunately, steelmaking and desulfurization

technologies have advanced to the point where sulfur content <10 ppm are available on a large scale and

even amongst the emerging steel producers in Korea, Ukraine, India and China. The effect of the reduced

Figure 2. Effect of sulfur content on toughness of linepipe.



sulfur contents on Charpy V-notch energy is shown in Figure 2. This paper describes effective

methodologies for efficient procurement of these new steels.

3.0 Steel Purchase

Successful execution of the procurement function requires a complete understanding of the several

essential steps chronicled in Table II. The various steps are briefly introduced below.

Table II Procurement Sequence – Referencing Engineering & Technical Issues

Finalization of design premise by the owning company or

engineering contractor.

Preparation of project specific specifications or review and updating of existing documents. Demand Manufacturing Procedure Specification

(MPS) and Inspection and Test Plan (ITP) as part of specification.

Develop list of qualified or potentially qualifiable vendors.

Develop a commercial strategy based on above documents and

knowledge of the marketplace.

Develop bid package and sent out to selected mills.

Review bids for technical ad commercial content.

Review MPS and ITP for low bidders.

Hold preaward clarification meetings and preproduction meeting if necessary.

Award pipe contract and third party inspection contracts: (a) Steel/slab Production. (b) Skelp Production (c) Pipe Mill (d) Coating

Provide technical assistance as required, especially during steelmaking and skelp production.



3.1 Definition of Project Requirements

The profile of the project helps to determine options for steel sourcing. Apart from obvious factors

such as diameter, grade, wall thickness and intended use one must consider challenges related to

installation and options. Onshore, even very high strength pipelines in advanced countries such as

Australia, may only represent the moderate end of the risk spectrum whereas offshore, deepwater sour

hydrocarbon lines to be installed by J-Lay or reel barging in hostile waters may present additional

challenges. The "personality" of the engineering company and installation contractor also plays a part in

the selection of the pipe mill(s). Cavalier contractors with fixed price contracts and limited knowledge of

the pipe market and a "poor boy" mentality can purchase the wrong steel at the right price and then they

and their clients will pay dues later.

Some additional comments on the above methodical steps are presented below:

(a) Design Premise

This is the fundamental basis for the project which immediately defines the project risk and the

potential to qualify marginal manufacturers.

(b) Specifications

The specification should accurately match the technological requirements of the project.

Prescriptive specifications are preferred by the author since they outline expectations of the

buyer and minimize surprises during the preaward discussions. The bid price should thereby

represent a quality level closely paralleling that required and which can be accepted as is.

Nevertheless, technical requirements can usually be improved from this platform without

attracting significant increase in cost. The Manufacturing Procedure Specification (MPS),

once approved, becomes the guiding document during pipe production.

(c) Bidders List

There is a very wide spectrum of linepipe production available ranging from seamless and

ERW in the smaller diameters to longitudinal seam and spiral seam linepipe in the larger

diameters, with substantial overlap throughout the diameter range. The basic diameter ranges

for the different linepipe products are as follows:



Product Diameter Range Number of Manufacturers Seamless ERW DSAW (UOE)

4 to 28 inch 4 to 24* inch 12 to 72** inch

11 40 22

*Except for Kawasaki Chita Works which produces 26". **UOE up to 60" O.D. with three roll bending up to 72" O.D.

It is useful and desirable to maximize the different linepipe manufacturing options in the

bidders list. HFERW linepipe production economics put pressure on both SMLS and DSAW

when the size ranges overlap. Likewise, small diameter DSAW is encroaching on SMLS

markets in deep offshore development including linepipe and production risers.

The quality of linepipe from each mill can be assessed using a variety of assessment or

scoring systems and field audits. Each mill's equipment and track record are important

components in the assessment process. A formalized system for assessing ERW mills is

presented in Figure 3. Critical components of the pipe mill assessment are as follows:

(i) Proven ability to produce the size and grade of linepipe and a documented supply

record.

(ii) Reliable skelp source with proven track record, especially when considering sour gas

service.

(iii) When a new grade such as X-80 is involved, availability of trial data and existence of an

enlightened technical organization reduces the risk of disappointment or project delays.



(iv) Enlightened management organization and strong QC/QA functions demonstrating

proper awareness of the opportunity and the risk

Figure 3. Example of ERW pipe mill audit form.

Whatever the scoring system, criteria must be developed for establishing the cut off point

below which mills are not to be seriously considered. Nevertheless, wild cards in the form of

new producers, geographically advantaged or indigenous mills, or simply commercially

aggressive entities may be usefully added to the list if there is a fair chance that they can be

qualified and technically supported during execution of the project. However, to reduce risk

the technical team must control the final selection of producer to avoid awarding of the order

to the low cost but otherwise unproven and possible naive or overzealous vendor.

(d) Commercial Strategy



A keen working knowledge of the local and international market is invaluable when developing

an effective strategy. The objective is to put price pressure on the desired or even inevitable

(indigenous or otherwise advantaged) supplier. Local or indigenous producers must be

considered in terms of realistic capability plus risk. For example, the local mill may be able to

offer lower strengths or alternative grades with a competitive advantage. Market distortions

arise from time to time due to currency fluctuations, duties and tariffs, financing packages,

overcapacity in adjacent markets and the need of some mills to sell at any price to survive.

In Australia, there is one major linepipe producer with another possibility in the works within its

limited size range. One Steel is a competent and maybe preferred, domestic producer which

nevertheless has its eye on competition from Korea, Indonesia, Japan, Greece and other low

cost sources. In connection with the X-80 theme of this conference, One Steel may have a

tactical advantage due to its pioneering research and development of X-80 linepipe and past

trial production data. However, the experience is unlikely to justify a sizeable premium for this

type of product.

(e) Distribute Bid Package

The full bid package should be sent out direct to the selected bidders. Distribution to trading

companies is not always useful since they often duplicate contacts, confuse the market

environment and may try to manage competition particularly in Japan. We have found that the

presence of trading companies in technical meetings also hinders open dialog.

(f) Review of Bids for Technical Content and Commercial Terms

The commercial evaluation should be completed before the MPS and Inspection Test Plan

(ITP) are submitted for formal review. In this way, the three or four lowest bidders can be

properly evaluated and technical exceptions assessed and scrupulously compared in formal

spreadsheets.

(g) Preaward Clarification Meeting

This meeting involves a thorough review of the MPS and ITP as well as outstanding

commercial issues. This is a critical step in procuring the "right steel at the right price". The

meeting affords a last opportunity to extract final concessions related to quality issues. Once

the order is let, or letter of intent signed, it becomes increasingly difficult to challenge

exceptions or deviations raised in Item (f) above. Participation of experienced metallurgists in

this critical meeting, to represent the buyer is advised and is usually very beneficial.



(h) Inspection

Third party inspection of pipe production and coating is traditionally used in the USA. It is less

intense in Australia and often non-existent when engineering companies operate under EPC

(engineer, procure, construct) contracts. Consequently, pipe and coating quality may suffer.

Some form of oversight represents a prudent expense, especially when it is focussed early in

the manufacturing process in the steelmaking plant and rolling mill. Embryonic problems may

be identified long before they create or contribute to a pervasive decline in quality and

productivity during pipe making. Oversight of X-80 skelp production would likely be prudent

since segregation and yield strength issues could be addressed early in the production cycle.

(i) Technical Assistance

If the linepipe purchaser is willing to fund technical assistance during all states of the

manufacturing process it is possible to buy technically sophisticated product from low cost

emerging or even marginal producers.

3.3 Alternative Procurement Strategies

Conventional bidding is considered in Item (e) above. Direct negotiation with available producers

also works well especially when qualified mills are limited in number. This option has been used in

Australia, especially by EPC contractors. It is also useful to "piggy back" on an existing MPS or ongoing

production run. Third party inspection is rarely used in typical "partnering" schemes or negotiated

agreements which is a risky proposition in the author's opinion.

Online or reverse auctions have become popular as the proponents have sought to commoditize

linepipe technology. While the technique undoubtedly puts pressure on prices, it has serious drawbacks,

for example old loyalties are destroyed and the low bidder is rarely qualified to perform as required. The

several online auctions known to the author have all failed miserably due to naivity in assembling the list of

participants, allowing inclusion of rogue traders, not prequalifying mills, poor definition of required steel,

poor or non-existent supplementary specification and not mandating an appropriate and preapproved

MPS. In the absence of a level playing field, the competent mills are mistreated and the less competent

cause damaging static in the marketplace.

4.0 A Case History

The All American (Sour Crude) Pipeline Project (AAPL) was completed in 1984 and consisted of

1,766 miles (476,000 tons) of 30 inch O.D. x 0.281 inch X-70 linepipe. At the start of the project, the pipe

order was placed with four pipe producers as illustrated in Figure 4. Due to trade issues and import

restrictions resulting from the actions of domestic steelmakers and pipe producers, it was not possible to



source the steel as originally planned. However, the principals of AAPL refused to buckle under the

pressure of the domestic steel mills and elected to source from interested and motivated pipe mills

worldwide, taking advantage of all available quotas and favored trade agreements.

Figure 4. Original supply plan (letters of intent) for AAPL linepipe supply.

The methodology described in Section 3.2 of this paper was fully applied, detailed MPS and ITP

documents were prepared and technical assistance was provided to several pipe mills. The end result

was that the pipe was purchased from 18 pipe mills utilizing skelp from 20 different sources, Figure 5. All

steel was covered by detailed MPS documents and was fully inspected at source. High quality steel

tested according to NACE TM0284, Solution B arrived on schedule and under budget. The project was

completed without technical problems and is operating today as a gas pipeline, in the reverse direction,

transporting natural gas to California.



Figure 5. Actual supply contracts AAPL X-70 sour service linepipe.

5.0 Risk Factors

5.1 Project Experience

The author and his associates have participated in several projects in recent years and routinely

utilizes the methodologies presented herein. Despite this exposure, problems may still occur due to

insufficient oversight or overestimation of producer capability and integrity. Breakdown in mill quality

systems and loss of corporate memory are becoming increasingly frequent. A listing of certain problems is

presented in Table III which covers both Microalloying International assisted and other projects.



TABLE III Linepipe Non-Conformances

Technical Problem Background & Manifestation Corrective Action

(A) When using Microalloying Intl. or similar methodology. Low Pipe Yield Strength (circa 2000)

10 percent of heats <70 ksi found during hydrotest @ 100% SMYS. Steel composition and rolling practices changed without client notification.

Require all ( even minor) changes to agreed MPS to be approved by client.

Excessive Centerline Segregation (a) Malaysian Project circa 1988 (b) Australian Project circa 1999 (c) Korean Production circa 1997 (d) German Pipe Mill circa 2000

Introduced proper macro etch procedure (no sulfur prints), increase surveillance at the slab stage. Improve concast parameters such as speed and superheat.

Toe cracks in I.D. weld area created during expansion due to peaking.

X-70 linepipe with yield strengths up to 108 ksi produced poor shape before expansion. Seven additional cracks found during receiving inspection.

Use PSL-2 maximum yield strength limits and check dimensions (shape or peaking) before expansion. Improve final weld seam U.T.

Non-complying Hydrotest Initial hydrotest aborted due to pipe distortion but not recorded in the mill tracking system. About 49 pipes found on the right of way.

Automatic recording of final hydrotest pressure and computerized accept/reject procedure. Audit of hydrotest charts introduced.

Oil Contamination Pipe received at destination with either OD or ID oil contamination, required expensive detergent wash.

Intensified or focused pipe mill inspection and updated (improved) pipe mill housekeeping and inspection.

Tungsten carbide contamination of seam weld (DSAW)

Large particles of tungsten carbide found in weld metal traced to flux reprocessing facility or maintenance tools which fell onto the plate surface.

Prohibit flux crushing and refurbishment, audit plate mills to identify potential problems.

Non-conforming pipe with missed end x-ray or improper hydrotest pressure arrived at customer’s site.

Bar code system overridden by shipping supervisor. Bar code system updated and working instructions mandate reliance on computer database.

(B) Other Projects End cracks in DSAW weld 28 defective pipes identified after installation (during audit of end x-rays)

required internal crawler to locate affected pipe. Two others found during offshore lay in girth weld X-ray took $3 million to locate and repair.

Improve radiographic film contrast, improve film viewers and audit or duplicate mill inspection.

Weld metal Chevron (hydrogen) cracking (I) Chevron cracking found during transit from Europe to Middle East. Ban on moisture prone titaniferrous agglomerated fluxes. Check storage and rebaking procedures for other fluxes.

Weld metal delayed cracking (II) Hydrogen assisted cracking found during UT traced to oil bevels and moisture prone flux

Cleaned bevels with detergent and followed flux vendors recommendations.

Failed stepwise cracking (HIC) tests Pipe shipped prematurely before completion of HIC (NACE TM0284) tests. Poor CLR results.

Review proposed steel chemistry and reject high calcium levels and inappropriate Ca:S ratios.

Cracks in weld area caused by transit fatigue Poor loading, procedures for lasch barges allowed pipe-to-pipe contact and excessive pipe movement.

Enforced API RP5LW ship loading recommended practices and intensify inspection.

Hot bends having low yield strength and/or poor toughness

Failed test bends due to inappropriate bending parameters and wrong assumptions about material and procedure.

Required vendor to qualify MPS on actual pipe to be used. Witness bending esp. bending temperature and speed.

Poor weld seam toughness in HFI linepipe Normalizing (seam annealing) temperature excessive Establish proper <1000°C peak normalizing temperature.



5.2 X-80 Linepipe Risk Issues

The methodology and project experience presented in this paper may be used to identify and

address the predominant and relevant risk issues related to procurement of X-80 linepipe. These are

presented in Table IV below.

Table IV

Risk Issues Specific to X-80 Linepipe

Risk Factor Mitigation Residual Technical Risk

I. Low Yield Strength Integrate efforts of skelp and pipe manufacturer. Require demonstrated competence. Utilize 100% SMYS mill hydrotest. Avoid thin slab cast skelp.

Poor pipe dimensions caused by 100% SMYS hydrotest.

II. Excessive Centerline Segregation

Require rigorous monitoring of macro, etc. results and caster parameters. Utilize medium manganese Nb-Mo formulations rather than high manganese alloy designs. Restrict phosphorus to 0.010%.

Centerline condition may cause cracking during girth welding if supplier is not conscientious.

III. Non-Complying Hydrotest

Deny request for <100% SMYS and require automated recording of hydrotest pressure with go-no go shipping release.

Minimal – same as Item I above.

IV. Poor Weld Seam Toughness

Use milled edge skelp. Prevent use of center-slit skelp. Assess track record of potential vendors. Encourage use of Q&T weld seam heat treatments. Use reverse bend testing.

Occasional low toughness values may slightly increase the probability of fracture initiation.

V. Transit Fatigue Witness loading operation and provide for reinspection on unloading.

Inconsequential. Missed defects will be found during field hydrotest.

6.0 Conclusions

High strength linepipe is a metallurgical sophisticated product that is produced by more than 65

mills worldwide. High quality product can be purchased from new or unfamiliar sources utilizing the

methodology described and documented in this presentation. For the produces to succeed, there

must be close cooperation between all parties, especially the skelp and pipe producers. Supervision



by experienced metallurgists during the preaward and subsequent phases has proven invaluable in

the past and should be incorporated into the master execution plan.

References:

1. J. M. Gray and William G. Wilson, "Molycorp Develops X-80 Pipeline Steel", Pipeline and Gas Journal, p. 50, December, 1972.

2. H. Engelmann, A. Engel, P.A. Peters, C. Duren and H. Musch. “First Use of Large-Diameter

Pipes of the Steel GRS 550 TM (X-80) in a High Pressure Gas Pipelines”. 3R International, Issue 5, 1986.

3. M. Matousu, Z. Skarda, I. Beder, J. Lombardini, H. G. Schuster and C. Duren. "Large Diameter

Pipes of Steel GRS 550TM (X80) in the 4th Transit Gas Pipeline in Czechoslovakia". 3R International, Vol. 8, October 1987.

4. H. G. Hillenbrand, K. A. Niederhoff, E. Amoris, C. Perdrix, A. Streisselberg and U. Zeislmair.

"Development of Linepipe in Grades up to X-100". EPRG/PRC Biennial Joint Technical Meeting on Linepipe Research, April 1997, Washington, D.C.

5. M. K. Graf, H. G. Hillenbrand, K.A. Niederhoff. “Production and Girth Welding of Double

Submerged Arc Welding Grade X-80 Large-Diameter Linepipe”. EPRG/NG-18, 8th Biennial Joint Technical Meeting on Linepipe Research. Paris, France, May 1991.

6. J. G. Williams, C. R. Killmore, F. J. Barbaro, A. Meta and L. Fletcher. "Modern Technology for

ERW Linepipe Steel Production (X-60 to X-80 and Beyond)". Microalloying '95 Conference Proceedings; June 11-14, 1995; Pittsburgh, PA.


Paper 7: Blackman Page 77 of 131 Hobart October 30 2002

AN ECONOMIC ASSESSMENT OF MECHANISED WELDING

OF HIGH STRENGTH LINEPIPE FOR THE AUSTRALIAN PIPELINE INDUSTRY

Stephen A. Blackman

Director of Welding Engineering, Welding Engineering Research Centre,

Cranfield University, Cranfield, Bedfordshire, MK43 0AL, United Kingdom.

ABSTRACT For a given pipeline, the choice of material and welding process can have a significant impact on the total capital expenditure. The use of higher strength linepipe requires less steel and the reduced tonnage can result in a significant cost reduction even after paying a premium $/tonne rate. For large diameter pipelines, mechanised welding provides a much higher productivity than manual welding and requires less labour and equipment so significant cost savings can be achieved. However, this is not the case for smaller pipe sizes and this together with potential technology problems means that mechanised welding can be significantly more expensive than manual welding. The Australian Pipeline Industry typically uses high pressure, small diameter, thin wall pipelines for gas transmission and the use of mechanised welding has been very limited. This has held back the implementation of high strength steels as selecting higher strength linepipe has an impact on the choice of welding process with mechanised welding being preferred for higher strength steels. In some circumstances, the choice of higher strength steel and the consequential need to use mechanised welding may be considered detrimental in the perception that gains in material savings may be more than offset by the higher costs of welding. This paper reviews the economic benefits to be obtained from higher strength steels and assesses the selection and implementation of mechanised welding processes to provide guidance to the Australian Pipeline Industry in selecting the lowest cost solution.

Keywords Pipeline, Linepipe, X80, X100, Welding, Mechanised, Cost-Benefit, Risk



AN ECONOMIC ASSESSMENT OF MECHANISED WELDING

OF HIGH STRENGTH LINEPIPE FOR THE AUSTRALIAN PIPELINE INDUSTRY

Stephen A. Blackman

INTRODUCTION Cost reduction is a major driving force for technological change and innovation in the pipeline industry and it is essential if long-distance transmission pipelines are to remain competitive with alternative technologies. Two areas that have long been recognised as major cost factors in the construction of transmission pipelines are linepipe grade and girth welding process. Both areas have seen significant developments in recent years with a general trend towards higher strength steels and mechanised welding processes. To date, there has been extremely limited use of either of these two technologies in Australia. The Australian Pipeline Industry typically uses high pressure, small diameter, thin wall pipelines for gas transmission and has not selected high strength steels because of the consequential need to use mechanised welding processes which are perceived as being more expensive than manual welding on small diameter pipelines. However, Australian transmission pipelines can be well over one thousand kilometres in length and so the saving in steel costs for thinner wall X80 or X100 linepipe can be substantial. This paper therefore attempts to quantify the impact of implementing mechanised welding on these pipelines and to assess the net benefit that may be obtained in order to provide guidance to the industry on the choice of the lowest cost solution.

The Benefits of High Strength Linepipe The use of X80 grade linepipe with a specified minimum yield strength (SMYS) of 550MPa has increased over the last ten years. It was first used in Canada and Europe in the late ‘80s and early ‘90s and there have been no major welding problems (Dorling et al., 1992:Dorling, 1993:Gawlick et al., 1993:Dittrich, 1992). Since that time it has become TransCanada Pipelines’ standard grade for large diameter transmission pipelines, it has been used on several pipelines within Europe, most pipe manufacturers can now supply this grade and it is included in international linepipe standards. There has been interest in X100 linepipe with a SMYS of 690MPa for many years (Gwin and Ryan, 1965). In the last few years, there has been considerable development in the manufacture of thermo-mechanically controlled processing (TMCP) for X100 linepipe and in the development of appropriate girth welding procedures (Hammond and Millwood, 2000:Millwood et al., 2001:Ohm et al., 2000:Hillenbrand et al., 1995:Hillenbrand et al., 2000:Hudson et al., 2002). Although it is not yet incorporated in the international linepipe standards, the Canadians have recently moved to specify it in CSA Z245.1-2002 and, in September 2002, a 1km section was installed as part of TransCanada Pipelines’ West Path project (TransCanada Pipelines Ltd, 2002). X100 is being investigated for several long-distance, large-diameter pipelines and it is expected that this material will be utilised in a transmission pipeline within the next few years. The interest in high strength pipe is brought about through the savings in steel cost that are obtained from the use of lower wall thicknesses at the same operating pressures. These can be calculated from the following formula:

t=P.D/2.S.F

Where t=thickness mm, P=operating pressure MPa, D=outside diameter mm, S=design pressure MPa and F=safety factor (e.g. 0.72).



Once the wall thickness is established the weight of the steel W in kg per metre of pipe can be found from the following equation:

W=0.02466 (D-t)t Where t=thickness mm and D=outside diameter mm. From these equations, when the pipe yield strength is increased there is a percentage reduction in the weight of steel required for a given pressure. This reduction in steel weight is shown in Table 1. As steel grade is increased, there may also be an increase in the cost of the steel in $/Tonne. This will vary with market conditions and availability of local supply but typical ranges are given in Table 1. The savings in weight of steel can then be combined with the percentage increase in US$/Tonne to provide an estimate of the average cost saving that might be expected.

Table 1: Reduction in Steel Weight and Cost for High Strength Linepipe

Change in Pipe Grade

Cost Factor Weight Factor

Total Saving

min max min max avg

X65 to X70 0.0% 0.0% -7.1% -7.1% -7.1% -7.08%

X65 to X80 0.0% 5.0% -18.2% -13.2% -18.2% -15.68%

X65 to X100 5.0% 15.0% -34.5% -19.5% -29.5% -24.52%

X70 to X80 0.0% 5.0% -11.9% -6.9% -11.9% -9.44%

X70 to X100 5.0% 15.0% -29.5% -14.5% -24.5% -19.53%

X80 to X100 5.0% 15.0% -20.0% -5.0% -15.0% -9.97%

At present, there is little or no increase in cost when purchasing X80 in place of X70 so almost the full saving in weight of steel is obtained. There is a 5-15% increase in US$/Tonne when purchasing X100 but this is more than offset by the large savings in weight. For the purposes of this paper, a number of cases will be considered and these are listed in Table 2, Table 3 and Table 4. Cases A, B and C relate to three Australian pipelines currently under consideration by EPIC Energy. The remaining cases are included for comparison. Case D is based upon the Alliance pipeline (Gilroy-Scott et al., 2001:Gilroy-Scott et al., 2000). Case E is a typical UK pipeline and cases F and G are based upon proposed North American pipelines. The following tables show the wall thickness for X70 and the subsequent reduction in wall thickness and cost if X80 or X100 were specified. The cost of linepipe fluctuates significantly with market conditions and region of supply. A rate of US$700/Tonne has been used in the following tables.

Table 2: Pipe Dimensions and Steel Costs in X70 Case Pipe

Diameter X70 Wall

Thickness Pipeline Length

Total Weight

(Tonnes)

Estimated Cost

(US$m)

A 323.9 mm 6.4 mm 620.0 km 31212.2 $21.85 B 508.0 mm 10.1 mm 1760.0 km 217847.3 $152.49 C 559.0 mm 11.1 mm 350.0 km 52447.9 $36.71



D 914.0 mm 14.2 mm 3000.0 km 945311.8 $661.72 E 1219.0

mm 16.3 mm 45.0 km 21690.1 $15.18

F 1321.0 mm

32.6 mm 3200.0 km 3310686.5 $2,317.48

G 1422.0 mm

17.0 mm 76.0 km 44767.0 $31.34


Diameter X80 Wall

Thickness Pipeline Length

Total Weight

(Tonnes)

Estimated Cost

(US$m)

Cost Saving

from X70

A 323.9 mm 5.7 mm 620.0 km 27564.3 $19.78 $2.07 B 508.0 mm 8.9 mm 1760.0 km 192385.9 $138.04 $14.46 C 559.0 mm 9.8 mm 350.0 km 46317.9 $33.23 $3.48 D 914.0 mm 12.5 mm 3000.0 km 834383.7 $598.67 $63.05 E 1219.0

mm 14.3 mm 45.0 km 19139.7 $13.73

$1.45

F 1321.0 mm

28.7 mm 3200.0 km 2925486.1 $2,099.04 $218.44

G 1422.0 mm

15.0 mm 76.0 km 39496.5 $28.34 $3.00


Diameter X100 Wall Thickness

Pipeline Length

Total Weight

(Tonnes)

Estimated Cost

(US$m)

Cost Saving

from X70

Cost Saving

from X80 A 323.9 mm 4.5 mm 620.0 km 22136.1 $17.04 $4.80 $2.73 B 508.0 mm 7.1 mm 1760.0 km 154499.6 $118.96 $33.53 $19.07 C 559.0 mm 7.8 mm 350.0 km 37196.6 $28.64 $8.07 $4.59 D 914.0 mm 10.0 mm 3000.0 km 669547.4 $515.55 $146.17 $83.12 E 1219.0

mm 11.5 mm 45.0 km 15352.4 $11.82

$3.36 $1.91 F 1321.0

mm 23.0 mm 3200.0 km 2351434.0 $1,810.60

$506.88 $288.43 G 1422.0

mm 12.0 mm 76.0 km 31673.4 $24.39

$6.95 $3.95 From these tables, it can be seen that, on the assumptions made, there is a potential saving of US$20 million if the EPIC Energy pipelines were specified as X80 instead of X70. A further US$26.4 million cost saving may be obtained if X100 could be utilised. Due to the length of these pipelines, the net $ saving is higher than that of the shorter large diameter pipelines for which X80 would now be the base design case. However, the choice of X80 or X100 linepipe has implications for choice of welding process that may negate the projected cost savings.

Influence of steel grade on Pipeline Welding method The influence of steel selection is illustrated schematically in Figure 1.



Cellulosic SMAW

Cel/LHVD SMAW

Cel/FCAW

Mechanised GMAW

X70

Cel/LHVD SMAW

Cel/FCAW

Mechanised GMAW

X80

Mechanised GMAW-PulsedX100

Selection of Steel Grade

Figure 1: Influence of steel selection on welding method

With X70 linepipe E8010-G cellulosic electrodes (Figure 2) can be used up to a wall thickness of about 25mm. Above this there is a high risk of hydrogen cracking and cellulosic electrodes are not recommended. Hence, cellulosic electrodes could be used for all of the pipeline cases under consideration except case F. Cellulosic electrodes could also be used in combination with low hydrogen vertical down electrodes or flux cored arc welding. Low hydrogen vertical down electrodes have a higher productivity than uphill low hydrogen electrodes but take about 25% longer than cellulosic electrodes due to the need for additional grinding between passes. Mechanised GMAW is also an option for X70 and would be the preferred choice for large diameter pipelines. For X80, cellulosic electrodes can only be used under limited circumstances. They have however been used successfully for root and hot pass welding in combination with low hydrogen vertical down electrodes for fill and cap passes.(Hillenbrand et al., 1997). Mechanised GMAW has been the most widely used process for X80. The three main welding contractors: CRC-Evans Automatic Welding, Houston, USA; RMS Welding Systems, Edmonton, Canada and Serimer-Dasa, Paris, France all have experience of girth welding X80 linepipe and there are no differences in equipment or welding technique when using their systems on X80 rather X70 linepipe. In most cases, the same welding consumables and welding procedures can be used. There has been a long record of mechanised welding in Canada and the contractors treat an X80 pipeline in exactly the same way as an X70 pipeline. Because of the availability of equipment and experienced welders, mechanised welding is selected even when the pipeline is as short as 1km.



Figure 2: Cellulosic Welding (courtesy of ESAB) Unfortunately, the step up from X80 to X100 is not as straight forward as the step from X70 to X80. A major factor in this is the overmatching criteria for the weld metal. Although the pipe has a SMYS of 690 MPa, the need to overmatch the actual pipe strength leads to a minimum yield of 810 MPa being required in the weld metal. The commercially available flux-cored wires and the low hydrogen vertical down electrodes will only achieve a yield strength of about 750 MPa and are therefore not suitable. With mechanised GMAW, pulsed current transfer or specialised dual-torch procedures are recommended to achieve the overmatching criteria whilst maintaining good CTOD values (Hudson et al., 2002). However, research has shown that procedures can be developed to avoid hydrogen cracking and solidification cracking and TransCanada Pipelines have installed a short section of X100 (TransCanada Pipelines Ltd, 2002). The X100 weld metal is sensitive to variations in cooling rate so greater care is required in monitoring field welding but the use of pulsed GMAW should not have a major impact on the implementation of mechanised GMAW for X100. Pulsed welding was initially used on the X80 pipelines in Canada and on the Alliance pipeline in North America, one contractor used CRC-Evans equipment with pulsed current and achieved the same productivity as other contractors using the same equipment with dip transfer (Gilroy-Scott et al., 2001:Gilroy-Scott et al., 2000).

The Cost Impacts/Benefits of Mechanised Girth Welding In onshore pipeline construction, the speed of the first welding station affects the maximum productivity that can be obtained. With a favourable right-of-way, the number of fill and cap pass welding stations can be increased to ensure that they do not hold up the front-end so the root pass welding speed and alignment time sets the critical path. Table 5 shows the root pass travel speeds for a variety of pipeline welding processes. The travel speed and the number of welders or welding heads vary with pipe diameter and this is also indicated. Cellulosic electrodes offer the highest travel speed of the manual processes. There are a variety of different GMAW options and each offers a different range of application.



Table 5: Comparison of Root Pass Travel Speeds for Different Welding Processes

Process Pipe Diameter (mm)

No. of Welders or Welding Heads

Root Pass Travel Speed (m/min)

Cellulosic SMAW <406.4 2 0.35 Cellulosic SMAW >406.4 3 0.35

Low Hydrogen Vertical Down All 2 0.2 STT GMAW All 2 0.4

Syncrowire GMAW All 2 1.2 Copper ILUC <406.4 2 1.0 Copper ILUC 406.4-508 2 1.2 Copper ILUC >610 2 1.5

Internal Welding Machine 610-711 4 0.762 Internal Welding Machine 762-914 6 0.762 Internal Welding Machine 914-1219 8 0.762 Internal Welding Machine >1219 8 or 10 0.762

The main welding contractors offer either an internal welding machine (IWM) or a copper internal line up clamp (CuILUC) with external welding bugs for root pass welding. The CuILUC can be used on all pipe sizes from 168.3mm upwards and dual torch external welding heads travel at 1-1.5 m/min depending upon diameter.

Figure 3: Copper Internal Line Up Clamp and Dual-Torch External Head

An IWM has 4 to 10 welding heads depending upon pipe diameter. Half the welding heads weld clockwise at 0.762 m/min and then the other half weld clockwise to complete the weld root.

Figure 4: Internal Welding Machine The multiple welding heads on the IWM increase the effective travel speed and alignment time is quicker as a welding shelter is not required. However, the IWM can only be used above 610 mm diameter. Figure 5 shows the root pass profiles with each system. Figure 5 b) shows a dual-torch cap.



a) b)

Figure 5. Typical girth weld profile in X100 a) IWM, b) CuILUC

In comparing the cost impact of mechanised welding, the commercially available systems with experience of X80 linepipe will be analysed against the use of cellulosic electrodes on X70 linepipe. Figure 6 shows the predicted welds per day based upon the root pass travel speeds in Table 5. A major benefit of cellulosic electrodes is that the welding clamp can sometimes be moved after 50% rather than 100% of the root pass is completed. Two productivity figures are therefore given for cellulosic welding.

0

20

40

60

80

100

120

140

160

0 200 400 600 800 1000 1200 1400 1600

Pipeline Diameter (mm)

Wel

ds/D

ay Cellulosic - 50% clamp releaseCellulosic - 100% clamp releaseGMAW - Cu ILUCGMAW - IWM

Figure 6: Predicted Productivity in Welds/Day for Different Root Pass Techniques



The data in Figure 6 is based upon a 10 hour working day. The predicted welds per day can be compared with those actually obtained in production. CRC-Evans have welded a 7mm wall thickness 508 mm diameter pipeline in Brazil using a CuILUC. With only three welding stations they averaged over 150 welds per day and peaked at 205 welds per day. On 914mm diameter pipe, the CRC-Evans IWM was used to obtain an average of 148 welds per day in Canada (Gilroy-Scott et al., 2001). On the same size pipe Serimer-Dasa averaged 137 welds per day using a CuILUC with dual-torch welding heads and only five welding stations. The production figures indicate what can be obtained with a favourable right-of-way but it may not always be possible to achieve the full root pass productivity due to terrain and tie-ins etc. From Figure 6 it is seen that the best productivity for cellulosic electrodes is when the alignment clamp is moved after only 50% of the root pass is completed. This will be used as the base case for X70 pipelines and 18m pipe lengths will be considered. The predicted productivity figures and the estimated welding spread costs are shown in Table 6 for each of the pipeline cases. Case F is not considered as cellulosic electrodes cannot be used on this wall thickness.

Table 6: Predicted Productivity and Welding Spread Costs for X70 SMAW

Case Total Welds

SMAW arc time for 50%

pull

SMAW 50% pull

welds/day

Total Days

Welding

No. of Passes

No. of Welding Stations

Spread Cost per

Day

A 34444 0.73 138.76 248 3 3 $26,000.00 B 97778 1.14 122.09 801 5 5 $33,000.00 C 19444 1.25 118.16 165 6 6 $36,500.00 D 166667 2.05 96.53 1727 9 9 $47,000.00 E 2500 2.74 83.41 30 10 10 $50,500.00 F 177778 G 4222 3.19 76.49 55 11 11 $54,000.00

The number of welding stations is based upon one station per pass as a best economic case but this may not keep up with the root pass on the thicker pipe. If X80 linepipe was selected, mechanised GMAW would be the preferred welding method for material properties. For cases A, B and C a CuILUC would be used and dual-torch external welding heads would be the lowest cost option. For the other cases an IWM with dual-torch welding external welding heads would be preferred. The use of mechanised GMAW affects the welding productivity and hence the duration of the welding activity. This may either decrease or extend the number or days pipelay and the total cost of the welding spread. The number of welding stations in the pipelay spread affects the daily pipelay cost. From Table 7 it is seen that mechanised GMAW reduces the number of days pipelay and the number of welding stations required in all cases and so it has a beneficial impact on economics. These savings can be added to the savings in steel costs. However, there is an additional cost for the rental of the mechanised welding equipment. The rental cost incorporates the cost for pipe-facing machines, hydraulic power pack, CuILUC or IWM, external welding heads, guide bands, spare parts, mobilisation and demobilisation, welding engineering assistance and weld procedure qualification. It is normally quoted on a rate per weld and will vary considerably with pipe diameter, pipe length, location of the pipeline and market conditions. It typically varies between US$ 50 and US$ 150+ with the lower rates for smaller diameter pipe and the higher rates for larger pipe in extreme environments. The additional equipment costs have also been estimated in Table 7.



Table 7: Cost Impact of X80 Linepipe with Mechanised GMAW

Case GMAW arc time

GMAW welds/day

Total Days Welding

No of Days Saved

Saving on Spread Days

A 0.51 149.53 230 18 $464,940 B 0.66 141.65 690 111 $3,649,044 C 0.73 138.53 140 24 $883,205 D 0.94 142.76 1167 559 $26,277,955 E 1.26 128.98 19 11 $534,759 F 1.36 124.94 1423 G 1.47 121.19 35 20 $1,099,447

Case No. of

Passes No. of

Welding Stations

Welding Stations Saved

Saving on Welding Stations

Steel Saving

Additional Equipment

Cost

Net Saving

A 3 2 1 $806,224 $2,071,211 $2,066,667 -$1,275,709 B 4 2 3 $7,247,706 $14,456,282 $6,844,444 -$18,508,587 C 4 2 4 $1,965,010 $3,480,442 $1,361,111 -$4,967,546 D 5 5 4 $16,344,808 $63,047,949 $21,666,667 -$84,004,046 E 6 6 4 $271,369 $1,450,332 $325,000 -$1,931,460 F 10 9 G 6 6 5 $609,700 $2,998,153 $548,889 -$4,158,411

From the above table it can be seen that under the conditions considered the use of X80 linepipe with mechanised welding results in a net saving for all three of the EPIC Energy pipelines although Case A is marginal. A similar analysis can be done for X100 linepipe and the data is presented in Table 8.

Table 8: Cost Impact of X100 Linepipe with Mechanised GMAW

Case No. of Passes

No. of Welding Stations

Welding Stations Saved

Saving on Welding Stations

Steel Saving Net Saving

A 2 1 1 $806,224 $2,732,555 -$3,538,779 B 3 2 0 $0 $19,072,183 -$19,072,183 C 3 2 0 $0 $4,591,747 -$4,591,747 D 4 2 3 $12,258,606 $83,118,782 -$95,377,389 E 5 5 1 $67,842 $1,911,332 -$1,979,174 F 8 8 1 $4,980,093 $288,432,072 -$293,412,165 G 5 5 1 $121,940 $3,950,244 -$4,072,184



The rate per weld for the rental of mechanised welding equipment for X100 will be very similar to the X80 costs. Welding productivity will be the same so the saving in spread days will remain unchanged from X80 costs. However, the reduced wall thickness will reduce the number of welding stations in the pipeline spread. The saving on welding stations can be added to the saving on weight of steel. Hence assuming that the X100 wall thickness satisfies all design requirements, there is a considerable benefit in moving from X80 to X100 linepipe. The potential saving in moving from X70 to X100 for the EPIC Energy Pipelines is predicted to be US$ 52 million. The cost data presented in these tables is generalised and will obviously vary with market conditions. A lower cost of steel and a lower spread cost will tend to reduce the overall savings and favour SMAW with X70 as the lowest cost solution. Shorter pipelines will also reduce the potential savings. A restriction on moving the alignment clamp until 100% of the root pass is completed will favour mechanised welding. A lower rental cost for mechanised welding equipment will also favour the use of X80/100 with mechanised welding. It is assumed that the terrain will be such that maximum productivity can be obtained from the mechanised welding processes. A lower mechanised welding productivity will tend to favour the use of manual welding and SMAW although the number of mechanised welding stations could be reduced in this case which would provide a cost benefit. This analysis has considered 18m pipe lengths. 12m pipe lengths would require more welds and would favour the use of mechanised welding and X80/100 linepipe. The analysis has not considered the potential cost savings in accommodation/catering for welding crews or pipe transportation savings with lower weight pipes. There are new developments in mechanised welding such as dual tandem arc welding which will reduce the number of mechanised welding stations required and will improve the benefits from mechanised welding (Blackman, 2001).

conclusions The use of high strength linepipe offers potential savings in steel costs due to the thinner wall thickness required for a given operating pressure. However, the use of X80 and X100 linepipe restricts the welding processes available and mechanised GMAW is preferred. In implementing mechanised GMAW there are additional equipment costs that can offset the savings in material costs. However, there are potential net benefits even for small diameter, thin wall pipelines. The savings on long distance large diameter pipelines are very significant but there are also significant potential benefits for Australian pipelines due to the long distances involved. The cost data used in this assessment is generalised but indications are sufficiently encouraging that a detailed cost-benefit analysis be undertaken for each of the Australian pipelines considered.



References Blackman, S. (2001), "Developments forecast to reduce pipeline construction costs",

Welding and Metal Fabrication, vol.69, no.8. Sept.2001. pp.7-10. 5 fig., 6 ref.

Dittrich, S. (1992), "Welding of the high yield strength steel X80 - state of the art in 1991", Welding in the World/Soudage dans le Monde, vol.30, no.1-2. 1992. pp.33-36. 12 tab., 10 ref.

Dorling, D. V. (1993), "Aussie involvement in Canadian experience of GMAW [GMA welding]", Australasian Welding Journal. Third Quarter 1993. pp.12, 14.

Dorling, D. V., Loyer, A., Russell, A. N. and Thompson, T. S. (1992), "Gas metal arc welding used on mainline 80 ksi [550 MPa yield strength] pipeline in Canada", Welding Journal, vol.71, no.5. May 1992. pp.55-61. 5 fig., 8 tab., 7 ref.

Gawlick, S., Hauck, G., Kiewel, G. and Sandner, G. (1993), "Automatic GMA welding of the X80 Werne-Wetter [steel] Ruhr gas pipeline by application of the CRC process (Automatisches Schutzgasschweissen an der X 80-Ruhrgasleitung Werne-Wetter ...)", DVS Berichte, no.155. Welding and Cutting '93. Proceedings, Conference, Essen, 15-17 Sept.1993. Publ: 40010 Dusseldorf 1, Germany; DVS-Verlag for Deutscher Verband fur Schweisstechnik; 1993. ISBN 3-87155-460-X. pp.166-170. 12 fig., 2 tab., 4 ref.

Gilroy-Scott, A., Huntley, B. and Gross, B. (2000), "Welding challenges constructing the Alliance pipeline", In: IIW Asian Pacific Welding Congress. Proceedings, NZIW 2000 Annual Conference and WTIA 48th Annual Conference, Melbourne, 29 Oct.-2 Nov.2000. Ed: C.Smallbone. Publ: Silverwater, NSW 2128, Australia; Welding Technology Institute of Australia (WTIA); 2000. ISBN 0-909539-83-9. Vol.1. Paper 6. 8pp. 3 fig., 3 tab.

Gilroy-Scott, A., Huntley, B. and Gross, B. (2001), "Welding challenges constructing the Alliance pipeline", Australasian Welding Journal, vol.46. First Quarter 2001. pp.6, 8-10. 8 fig., 3 tab.

Gwin, R. B. and Ryan, R. S. (1965), "The first experience in welding a 100 000 lb/in2 yield pipeline", Welding Journal, vol.44, no.11. 1965. pp.915-920.

Hammond, J. and Millwood, N. A. (2000), "Construction of ultra high strength steel pipelines", In: Pipeline Technology. Proceedings, 3rd International Conference, Brugge, Belgium, 21-24 May 2000. Ed: R.Denys. Publ: 1000 AE Amsterdam, The Netherlands; Elsevier Science BV; 2000. ISBN 0-444-50271-8. Vol.1. pp.69-88. 1 fig., 9 tab., 5 ref.

Hillenbrand, H. G., Amoris, E., Niederhoff, K. A., Perdrix, C., Streisselberger, A. and Zeislmair, U. (1995), "Manufacturability of linepipe in grades up to X100 from TM [thermomechanical] processed plate", In: Pipeline Technology. Proceedings, 2nd International Conference, Ostend, Belgium, 11-14 Sept.1995. Ed: R.Denys. Publ: 1000 AE Amsterdam, The Netherlands; Elsevier Science BV; 1995. ISBN 0-444-82197-X. Vol.2. pp.273-285. 10 fig., 6 ref.

Hillenbrand, H. G., Liessem, A., Knauf, G., Niederhoff, K. and Bauer, J. (2000), "Development of large-diameter pipe in [API 5LX] grade X100 [steel]", In: Pipeline Technology. Proceedings, 3rd International Conference, Brugge, Belgium, 21-24 May 2000. Ed: R.Denys. Publ: 1000 AE Amsterdam, The Netherlands; Elsevier Science BV; 2000. ISBN 0-444-50271-8. Vol.1. pp.469-482. 11 fig., 4 tab., 12 ref.



Hillenbrand, H. G., Niederhoff, K., Hauck, G., Perteneder, E. and Wellnitz, G. (1997), "Procedures, considerations for welding X-80 line pipe established", In: Oil and Gas Journal, 15 Sept 1997, pp. 47-56.

Hudson, M., Blackman, S., Hammond, J. and Dorling, D. (2002), "Girth welding of X100 pipeline steels", In: International Pipeline Conference IPC 02, Calgary, Alberta, Canada, 29 Sept - 3 Oct, 2002.

Millwood, N., Sanderson, N. and Hammond, J. (2001), "Design and construction of pipelines in ultra-high-strength linepipe", Pipes and Pipelines International, vol.46, no.2. Mar.-Apr.2001. pp.17-22, 44. 1 fig., 1 tab.

Ohm, R. K., Martin, J. T. and Orzessek, K. M. (2000), "Characterisation of ultra high strength linepipe", In: Pipeline Technology. Proceedings, 3rd International Conference, Brugge, Belgium, 21-24 May 2000. Ed: R.Denys. Publ: 1000 AE Amsterdam, The Netherlands; Elsevier Science BV; 2000. ISBN 0-444-50271-8. Vol.1. pp.483-496. 8 fig., 7 tab., 4 ref.

TransCanada Pipelines Ltd (2002), In: Press Release, Calgary, Alberta, Canada, 15th July, 2002.


Paper 8: Barbaro Page 90 of 131 Hobart October 30 2002

Welding Small Diameter High Strength Linepipe

F.J.Barbaro and J.Norrish

Abstract Although the Australian Pipeline Industry has utilised some of the available technological advances in steel alloy design to improve the economics of construction of pipeline operating systems, it has not so far taken up the opportunity to use X80 pipe. Since the use of X80 offers a 14% reduction in the amount of steel used when compared to X70, there are likely to be substantial cost savings provided that technical problems do not erode these savings. The avoidance of such problems requires an appreciation of the factors controlling structural integrity and the risks that arise directly from the choice of X80. This paper highlights the considerations necessary to exploit these high strength materials and factors that need to be considered in the welding of high strength linepipe.

Author Details Frank Barbaro Chief Development Officer, Metallurgical Technology Department, BHP Steel, Port Kembla Steelworks. John Norrish CRC-WS Chair of Materials Welding & Joining, University of Wollongong, Australia

Deleted: ¶¶¶¶¶¶¶¶¶¶

Deleted: ¶¶



Introduction The Australian Pipeline Industry has, over the past three decades, enjoyed significant economic benefits from the use of high strength pipe. The pipe of choice has moved from API 5L grade X52 in the early 1970’s to grade X70 which today is commonplace. The economic benefits have been substantial [1] because this transition in pipe grade has occurred without any significant change to the construction method, particularly the welding process. Field welding of Australian pipelines has always achieved exceptional construction rates because of their small diameter, thin walled design but most importantly because the conventional manual metal arc (MMA) cellulose welding process enabled consistent and guaranteed versatility in the field. This uninterrupted transition in pipe grade provided the opportunity to achieve maximum benefits from the reduction in pipe wall thickness. These benefits not only included reduced overall pipe tonnage requirements but also savings in transportation costs and field construction time in terms of quantity of deposited weld metal. Progression to X80 grade pipe however presents a completely different situation which requires an informed assessment of the requirements for its use. This paper will detail the results of Australian research conducted over the past 8 years which has defined the boundary limits for the use of high strength API 5L grade pipe. The issues of weld metal strength matching, hydrogen crack susceptibility and most importantly the appropriate welding process are considered. It is important to note that the findings of this research work have already resulted in the successful utilisation of X80 grade pipe in a demonstration section of the Roma - Brisbane pipeline. The two requirements that are critical in the girth welding of high strength linepipe are the mutually competing factors of susceptibility to hydrogen assisted cold cracking (HACC) and sufficient weld metal strength to match the pipe[2,3]. It is appropriate to acknowledge that progression beyond X70 to X80 grade pipe has now challenged the continued use of conventional MMA welding process. This arises from the high weld metal hydrogen contents and the limited strength range of cellulosic consumables. Figure 1 clearly demonstrates the strength issue confronting cellulosic consumables in the welding of high strength linepipe. It is the view of the authors that the overall risk involved in the adoption of X80 is low and that appropriate solutions are available for all of the perceived problems. Some of the following are discussed in the paper:

• Hydrogen Assisted Cold Cracking (HACC) • Weld strength matching and testing • Defect tolerance • Welding process considerations • Mechanised girth welding • Process monitoring • Productivity • Procedure qualification

The key issues are identified and a brief summary of the mitigation steps is provided in the next section. The incremental increase in risk to the successful on-time, on-budget completion of the project in the welding of X80 pipe compared to X70 Table 1 summarises the potential risks and mitigation measures prior to the detailed discussion of the factors which must be considered. Some of the mitigation measures may be technically sound but may be debatable from a practical or economic standpoint; these issues are discussed more fully in the body of the paper.



Table 1

Incremental Risk/Threat

Comment

Mitigation

HACC The choice of X80 brings an increase in the risk of HACC in both the weld and the HAZ. The increased risk of HAZHACC arises from the higher CE of the pipe. The increased risk of WMHACC arises from the need to use stronger more highly alloyed weld metal to achieve strength matching.

• See below

HAZHACC Since the weldability of the weld metal will be poorer than the weldability of the pipe, generally measures taken to prevent WMHACC will guard against HAZHACC

• specify low CEQ and Pcm pipe

WMHACC Unlike HAZHACC where WTIA TN1 may be used, there are no recipe book procedures for guarding against WMHACC

• use lowest strength level consumables consistent with matching

• follow AS2885.2 • use low hydrogen

consumables • use pre and post heat • consider using GMAW

Strength matching

In low strength pipe strength matching comes more or less automatically. As the pipe strength increases this becomes more difficult and filler metals must be alloyed to meet the required strength in the ‘as welded’ condition

• use highest strength

consumable consistent with WMHACC limitations

Defect tolerance The defect tolerance levels previously used were based on thicker wall lower strength pipe. New defect tolerance criteria need to be adopted for thin wall, high strength pipe.

• Use recommendations

of AS 2885.2 (2002) • Use procedure outlined

in defect acceptance section below

Mechanised GMAW

Process has been used extensively overseas but there is little direct experience in Australia. Systems are generally more complex. Users may need advice on selection of systems, realistic costs and a knowledge of support requirements

• Refer to CRCWS/APIA group sponsored project reports on mechanised GMAW in Australia

• See below

Mechanised system variants

There are several potential system suppliers users need to be ‘informed purchasers’

• Refer to CRCWS/APIA report on the evaluation of commercial mechanised girth welding systems

Mechanised GMAW defects

Mechanised GMAW is a low hydrogen process and less susceptible to HACC but lack of fusion, porosity and solidification cracking may arise if the correct techniques are not adopted

• Refer to AS 2885.2 (2002)

• Adhere to procedural limits

• Use on line monitoring • Use recommended filler

wires Mechanised Capital cost of girth welding systems is high (in • Consider total project



system costs comparison with manual welding plant) cost Mechanised system support

Adequate welding knowledge and service support are essential requirements of a mechanised GMAW welding supplier or contractor. More complex equipment needs preventative maintenance and spares back up

• Check track record of system supplier/contractor

• Allow for regular maintenance

• Check spares and support availability

Hydrogen Assisted Cold Cracking From a metallurgical viewpoint HACC, or cold cracking, is perhaps the most serious of all weld cracking problems. Cracking is associated with the accumulation of hydrogen at internal sites, made susceptible by the metallurgical structure and the presence of defects, under the action of stress. Pipeline construction is a demanding process that imposes adverse conditions during the welding process which can increase susceptibility to HACC. These include high strength steel, lifting stresses during welding, and when cellulosic electrodes are used, extremely high levels of hydrogen. It is imperative that girth welds be free from HACC over the range of essential welding variables because of the difficulties in finding cracks with conventional NDT, and because hydrogen cracking may occur sometime after NDT inspection. In short the prospect of cracking must be designed out of the welding procedure. HACC has traditionally been an issue associated with the heat affected zone (HAZ) of the base pipe however with improved steel alloy design and advanced thermomechanical processing it is now more common to experience weld metal HACC. Although quantitative guidelines for weld metal HACC avoidance are yet to be established, considerable experimental data from laboratory tests such as the Welding Institute of Canada (WIC) and the Rigid Restraint Cracking (RRC) tests in conjunction with established field welding experience have defined conditions which limit the risk of occurrence to extremely low levels. These conditions are now incorporated in Australian Standard AS2885.2 – 2002. Under normal field construction conditions where no more than two standard (18 meter) pipe lengths are lifted clear of the skids on a basically level right of way then HACC is considered remote where welding conditions are controlled within the boundaries presented in Figure 2. These conditions are considered safe because the pipe wall thickness limitation restricts the weld cooling rate and imposed stresses. The appropriate timing of the hot pass which occurs within 8 minutes of completion of the root pass also provides considerable benefits which include :

• decreased weld cooling rate to increase time and thermal energy for hydrogen effusion,

• increased weld throat thickness and decrease stress concentration, and • refinement of the root pass microstructure thus improving the fracture toughness.

Qualification of the weld procedures over the range of expected field conditions or under worst case conditions will confirm weld integrity while the essential variables defined in AS2885.2 will outline the broad boundaries which provide a safe operating window to minimise the risk of HACC (discussed later). The greatest risk of the occurrence HACC is due to the tendency to increase field productivity beyond that which has been defined by the qualified weld procedure. Obviously there are significant economic benefits arising from early completion of the project. However changes to the weld procedure not only alter the metallurgical effects during welding but may also influence



the level of imposed stress on the weld. Such conditions dramatically increase the susceptibility to HACC. Increased root pass weld speeds and hence decreased weld heat inputs, can lead to rapid weld cooling rates and abnormal weld solidification structures [6]. Depending on weld metal impurity levels and weld joint stress, hot cracking has also been known to occur. Such cracking can itself generate significant longitudinal centre line cracks, and can serve as initiation sites for hydrogen cracks. Clearly there is a significant increase in risk of welding problems when unqualified modifications to the welding procedure occur. In contrast to cellulosic electrodes, mechanised gas metal arc (GMA) welding systems produce very low levels of diffusible weld metal hydrogen and so are much less susceptible to HACC. In fact to the Authors’ knowledge there has never been an example of problems due to HACC in GMAW pipeline girth welds.[7] This is not to say that HACC is impossible, it is just much less likely. The problem that does arise with low weld metal hydrogen levels is that if HACC is generated, it would be expected to occur as much as 24 hours or more after welding. This is because of the time taken for the hydrogen to build up to critical concentrations by diffusion to the susceptible sites. In contrast to this, the hydrogen levels are so high (around 30 to 40mL/100g) in cellulosic electrode weld metal that there will always be sufficient hydrogen at susceptible sites, and so if cracking is going to occur, it will do so within minutes. The use of hybrid procedures involving the use of cellulosic electrodes for the root and hot passes, followed by basic coated low hydrogen electrodes for the fill and capping passes may give some reduction in the susceptibility to HACC, however that advantage has to be balanced against the need to be aware of the risk of delayed cracking. The hydrogen content of these hybrid welds will be much higher than welds made with GMAW., Although the essential variables defined in AS2885.2 are designed to provide a safe operating window, it is known that any significant variation of a combination of these variables could lead to HACC. For this reason the welding process should be supported by a robust quality assurance system to govern the field welding process; such a system is greatly enhanced by involvement of a competently trained welding engineer or supervisor. It is important to point out that despite these precautions, high strength linepipe, up to grade X80 has been shown to be weldable using conventional welding processes, including manual cellulosic consumables. The resistance of X80 grade pipe to HACC has been evaluated by:

• Welding Institute of Canada (WIC) tests [6], • Rigid Restraint Cracking (RRC) tests [9], • Simulated field welding trials using the British Gas test [10], and • Pipeline construction [8]

The results have demonstrated that Australian produced X80 grade pipe, up to a pipe wall thickness of 9mm, is comparable to X70 in terms of susceptibility to HACC. This is clearly illustrated in Figure 3 where, at yield stress loading the critical heat input to generate HACC in 9mm thick X80 pipe was lower than that in 10mm thick X70 grade pipe. This is an important comparison because in terms of pipe design, this represents the typical reduction in wall thickness in moving from X70 to X80. It is also important to highlight the importance of pipesteel alloy design, which can be significantly different depending on the pipe supplier. Weld Metal Strength Matching Girth weld integrity requires the weld metal to have sufficient strength so that there is a high probability that when a weld containing defects (at the permitted limit) is overloaded in axial tension in adverse conditions, the weldment will be strong enough to cause plastic strain in at least one of the adjacent pipes. That is, the weld joint should have sufficient strength and work hardening characteristics to ensure that fracture, if it was to occur, would proceed by gross section yielding (of the parent pipe) rather than by nett section yielding (of the weld). The controlling factor in determination of girth weld integrity is the permitted level of defects. The Australian Standard AS2885.2 permits a 3-tier approach to assessment of girth weld defect acceptance which consists of:



• Tier 1 - workmanship base level, similar to that of API 1104, • Tier 2 - a generalised fitness for purpose (FFP) based level, and • Tier 3 - which provides for an Engineering Critical Assessment (ECA).

In essence the 3-tier approach permits increased levels of weld defects provided additional mechanical property specifications are satisfied. In other words the level of conservatism is decreased moving from Tier 1 to Tier 3. This approach provides economic benefits to pipeline construction because, provided other factors are equal, this would mean less welds would require rectification. Selection of the appropriate Tier to which girth welds will be sentences should be agreed upon prior to the finalisation of weld procedures. The factors controlling defect tolerance are understood and have been presented in the form of a causal tree (Figure 4). It is well known that weld metal yield strength matching with the pipe will provide maximum defect tolerance and although this may be evaluated using a notched tensile test this is a relatively rapid test it is conservative and sometimes difficult to interpret [8], particularly where different yielding phenomenon can occur in pipe sourced from different suppliers. It is however more appropriate to determine weld strength matching rather than weld metal yield strength matching. The former takes into account the factors detailed in Figure 4 such as work hardening characteristics, defect limits (particularly depth) and also pipe wall thickness. Guidelines for determination of defect tolerance require careful assessment using instrumented tests to quantitatively determine critical defect size for particular girth weld configurations. It is therefore appropriate to briefly describe these tests before discussion of the above factors controlling girth weld defect tolerance. Test Methods It is difficult to simulate the range of conditions that a buried pipeline may experience so various test methods have been developed to assess the relative performance of defects in different pipe designs. These include the wide plate test (WPT) and the full section pipe tension test (FSPTT). In summary these test methods provide a measure of the overall load bearing capacity of the welded joint containing an artificially produced defect at the maximum allowable limit. Loading is in the axial direction of the pipe and the strain in both the weld metal and parent pipe are accurately monitored. Maximum loads in conjunction with strain levels provide an assessment of the performance of the girth weld. The tests are conservative from the point of view that the defect size used is likely to be at a maximum in terms of length depth and area rather than having a more realistic weld defect profile. More importantly it has been shown that for the wide plate test (WPT) the width of the test piece significantly influences the experimentally determined critical defect size, ie narrow WPTs can underestimate defect tolerance, refer Figure 5. The Australian approach has been to determine defect tolerance using a FSPT test, which was developed by the Cooperative Research Centre for Welded Structures. The test involves loading a complete section of pipe, containing a girth weld and the defined defect, in uniaxial tension up to the point of fracture. Assessment of the complete pipe diameter eliminates the conservatism associated with the smaller WPT. A more detailed description of the FSPTT rig has been presented elsewhere [4,5,8]. The aim of the test is to demonstrate that gross section yielding (GSY), and not nett section yielding (NSY), occurs before fracture. There is no universal agreement on the actual minimum acceptable value of strain which must occur in the base metal prior to fracture however there is general agreement that a level of 0.5% is sufficient. This ensures that the yield point of the adjacent pipe is reached and that strain will be distributed along the length of the affected pipeline, and not just the weld metal. This level of strain in a 15m length of pipe represents a displacement of 75mm, which would improve accommodation of displacements in the event of movement such as landslip, errodable valleys or river crossings.



It is important to state that the GSY criteria is not designed to prevent catastrophic failure but to ensure a defined level of defect tolerance or weld performance. Defect Size and Pipe Wall Thickness The other important parameters in the determination of defect tolerance, as shown in Figure 4, include the pipe wall thickness and the defect size, particularly depth. The current standards assume all girth weld defects to be at least one weld pass deep and one weld pass is assumed to be 3mm deep. This is a reasonable assumption however as pipe wall thickness decreases the defect proportion increases dramatically. For example in 9mm thick pipe the defect represents 30% of the pipe cross section however in 5mm thick pipe this increases to 60%. This has a significant influence on defect tolerance and is the reason that thick walled pipe can tolerate a lower level of weld metal strength matching compared with thin walled pipe. The influence of pipe wall thickness and critical defect length, at the standard depth of 3mm, is shown in Figure 5. This relationship between pipe wall thickness and required weld metal strength provides an opportunity for X80 grade pipe to be safely welded using conventional cellulosic consumables. It has been demonstrated that 8.6mm thick X80 grade pipe can be successfully welded using cellulosic consumables and achieve defect tolerance levels significantly greater than that specified in Tier 2 of AS2885 part 2 - 2002 [8]. Mechanical property assessment for tiers 1 and 2 however differ significantly. Tier 1 specifies the standard battery of weld tests which basically requires that the girth weld demonstrate tensile strength matching using the conventional cross weld tensile test. Tier 2 because of the increased defect allowance requires additional demonstrated weld performance in terms of fracture toughness and weld metal strength. The toughness requirement is 30J minimum individual and 40J minimum average at the minimum design operating temperature and provides assurance against the possibility of brittle fracture. The weld metal strength, as outlined above, provides protection against defect propagation. Since the introduction of the 3-tier approach it is true to say that that the tier 2 FFP based criteria have not been used. However it should be pointed out that pipelines constructed using X70 grade pipe welded with the cellulosic combination E6010/E8010, which meets Tier 1 Workmanship requirements and has served the industry without any incident, would not meet all current Tier 2 requirements. The results of Australian research have enabled the construction of tables which provide guidance on acceptable weld procedures for X80 grade pipe as a function of wall thickness. These are presented in Tables 2 & 3, which clearly identify a range of opportunities for the welding of high strength X80 grade pipe. The Welding Process

The feasibility of using MMA welding has been demonstrated, but as steel strength increases, the possibility of HACC in the weld cannot be ignored and additional care and a higher level of procedural control must be exercised. Where thicker material is used the possibility of weld metal HACC increases and a low hydrogen process is required. In many parts of the world mechanized GMAW has therefore been adopted for land and lay barge based girth welding of thick wall large diameter pipelines. The feasibility and cost effectiveness of mechanised GMAW for high strength, thin wall pipe has also been evaluated for Australian conditions. To meet the Australian operating requirements several modifications to the conventional GMAW technique were required as described below.



GMAW Welding Procedures Current commercial mechanised GMAW girth welding systems often utilize an internal root bead or a copper-backing strip with an external bead. This approach is adopted due to the difficulty of ensuring adequate penetration and freedom from blow through with the conventional transfer modes of GMAW. In addition it is common to use compound or ‘J’ type bevels to ensure root bead integrity and reduce joint completion times on thicker wall pipe. It was felt that these techniques were inappropriate for Australian pipelines due to the restricted access for internal welding heads and concerns about copper pick up from internal backing systems. Compound bevels also require machining in the field and this would introduce a further complication for the Australian industry which is accustomed to using factory prepared API bevels. It was therefore decided to evaluate controlled dip transfer in an attempt to facilitate unbacked root runs in standard API bevels. Initial investigations [11] demonstrated the successful application of controlled dip transfer in a mechanised, single sided root run situation. It was possible to obtain high integrity root runs in the 5G position using commercial controlled dip transfer equipment (Lincoln Invertec STT II™) mounted on a simple orbital tractor. These trials indicated acceptable tolerance to variations in joint fit up at travel speeds of 390mm/min. No evidence of lack of fusion defects could be found and the penetration bead was uniform and slightly convex. The throat thickness of the root bead was typically in excess of 3mm and clamp removal after 50% of root run completion is feasible. From these results it was concluded that a dual bug girth welding system would be capable of meeting equivalent lay rates to cellulosic MMAW. The main productivity issue remained the set up time for the mechanised system. Ideally this needs to be less than one minute if the system is required to meet high lay rates. Since these early trials an alternative controlled dip transfer system has been developed [12] and this has been shown to produce equally acceptable root beads. Considerable experience elsewhere has indicated that pulsed transfer GMAW is most suitable for fill and capping runs and is capable of producing high integrity welds in X80 pipe. Mechanised Welding Procedure Validation Mechanised GMAW welding procedures have been developed in Australia using a controlled dip transfer root run and pulsed GMAW fill and cap in a standard API bevel. Pipe welds have been made in 18”, 8.7mm wall X80 pipe and 5 to 7.1mm X80 plate. These trials indicated excellent fusion and matching hardness properties across the weld. The test welds were made using a matching consumable (AWS A5.28 ER 90S-G). The welds were subjected to conventional tensile testing and wide plate tensile tests with artificially defects. The welding procedure is summarized in the Table 4 and the mechanical test results in Tables 5 and 6. The test results indicate satisfactory matching ratios and this has been confirmed by defect assessment trials. After subjecting the welds made under the conditions specified in Table 4 to wide plate tensile tests, Barbaro [13] stated that “ GMAW processes offer a greater range of weld metal strengths and increased defect tolerance”. Process Monitoring The importance of maintaining essential variables within close limits is equally important for mechanized GMAW. Fortunately on-line computer based monitoring is easily incorporated. In the Australian research the process monitoring technique has been developed to allow detection of potential defects during welding. The concept of continuous process monitoring of welding is recommended in ISO 9000 and has been embodied in the latest version of AS2885 Part 2. The possibility of in process weld integrity monitoring was discussed in the original work [14]. This concept has been developed in the most recent work to link the welding procedure with the on line monitoring. Since welding is undertaken in the field remote from the site office a facility was incorporated to create and store the welding procedure at a central office then download it via the internet to the site, where it is used to set up the welding system. The local computer



monitors and detects faults and performs high-speed control tasks. The monitored data from the weld is stored locally, compressed then fed back to the remote server where it may be analysed using SPC techniques. This approach integrates the welding procedure, routine process monitoring and weld integrity monitoring into one package. In the prototype demonstration system developed at the University of Wollongong facilities are also incorporated for recording the GPS coordinates of the weld joint, wireless data entry of welder details and bar code scanning of the material identification labels. Commercial Mechanized Girth Welding Systems One of the most significant ‘risks’ involved in deploying mechanized GMAW is the capital cost of the equipment. An evaluation of commercial mechanised GMAW girth welding systems [15] indicated that at least three of the commercially available systems had the potential to satisfy the technical welding requirements of the Australian industry. The implementation of mechanised welding does however require substantial investment in equipment and support infrastructure. Experienced international GMA welding contractors have developed field support strategies designed to maximize productive time. These strategies include regular equipment calibration and maintenance, backup spares on site and considerable practical welding expertise.

Recent Developments Most GMAW pipe welding systems require manual intervention to correct slight variations in joint geometry as the bug traverses the weld seam. More recent systems can be equipped with seam tracking using through arc sensors or laser seam tracking devices [16]. It is also necessary to maintain a constant torch height, or more precisely, contact-tip-to-workpiece distance (CTWD). In recent Australian research a robust and reliable torch height control has been developed. The system developed is based on monitoring welding voltage and current during the root run. In dip transfer the wire extension during the short circuit is proportional to the CTWD. The average resistance of a series of short circuits is therefore calculated on line by the monitoring computer. Shortly after initiation of the arc the process stabilizes and the calculated resistance may be assumed to represent the CTWD at the pre determined value. The resistance is continuously monitored and if it deviates from the preset level the torch height is adjusted. This approach has proved very acceptable for controlled short circuiting transfer. However, since fill passes may be made with a lateral weave, using pulsed GMAW or FCAW, it is unlikely to be an effective approach for fill runs. To circumvent this problem the concentricity of the ring gear with respect to the pipe is recorded during the root run and used as a preset correction factor for the remaining runs.

High Speed Root Runs One potential limitation of the controlled dip transfer approach is the low travel speed. In order to operate with normal joint tolerances on an unbacked single ‘V’ joint a maximum travel speed of around 400mm/min is used. This is a process-controlled limitation of this type of transfer. Recent work on the fundamental control of metal transfer has resulted in the development of a new technique, which allows much higher travel speeds to be obtained. The technique, known as ‘Synchrowire’ has been applied to standard API bevels and has enabled sound, unbacked root runs to be made at 1.2m/min. Other Process Options Other process options also exist for meeting the requirements for good root run performance combined with low susceptibility to HACC. A hybrid approach using a cellulosic MMAW root run



followed by manual or mechanized GMAW or FCAW for the fill is feasible and would be permissible within the requirements of the new AS 2885 Part 2 provide the procedure was qualified. Several other process developments have been under investigation during the last 5 years; these are:

• Flux cored wire fill passes • Multiwire GMAW

Flux cored wires offer improved control of weld metal chemistry and improved productivity. This is particularly beneficial with higher alloy weld metals as reported by Widgery [17]. Both gas-shielded and self-shielded wires have been developed for pipe welding. The self-shielded wires offer additional protection from side winds but in normal field operations with GMAW transportable habitats are used to surround the welding head and side wind is not normally an issue. Gas-shielded wires generally allow greater flexibility in tailoring running performance and weld metal properties. The chief advantage of flux cored wire on thin wall pipe in Australia would be the ability to produce matching weld metal properties on higher strength pipe. The productivity gains would be marginal on pipe thicknesses less than 9mm. Multiwire techniques have been discussed previously [16] and although it is planned to use these on thicker wall X80 pipe the productivity benefits may be worth exploring now that the process and welding systems have become commercially available.

Productivity and Risk The productivity of mechanized GMAW has been shown to be equivalent to best practice MMAW pipeline girth welding [11] on 18” pipe using a twin bug system. Recent developments in high-speed root run techniques could further enhance the productivity on X80 girth welds. Although mechanized welding has been used extensively and successfully elsewhere in the world [18] the implementation barrier still appears to be the initial capital cost of the systems. A hybrid MMAW root and manual GMAW fill or manual GMAW using controlled transfer root runs could be a lower entry cost option. It must be emphasized that the capital cost of the mechanized equipment is insignificant when amortized over the total pipeline construction project costs but the investment risk is relatively high for small pipeline welding contractors. The MMAW procedures described offer a lower initial cost but whilst the process is well proven the recommendations given above must be observed for effective implementation on X80 pipe. Qualification of a Weld Procedure The above discussion highlights the steps required in qualification of a weld procedure. For economic reasons these steps should take the shortest path both during weld procedure qualification and also during pipeline construction ie no deviation on procedure. Clearly pipeline structural integrity and risk minimisation requires a thorough evaluation of susceptibility to HACC and determination of weld metal strength matching. In terms of designing out HACC, there already exist guidelines within AS2885.2 - 2002 that assist with development of crack free weld procedures up to and including X70 grade pipe. For X80 grade pipe recent Australian research has identified boundary limits and precautions as shown in Tables 2 & 3. The overall approach to qualification of a procedure is presented in Figure 6. It should be noted that the determination of defect acceptance could proceed via a number of different routes depending on the Tier selected. Tier 1, workmanship criteria simply requires among other tests a cross weld tensile test to qualify for the more conservative defect tolerance level. For Tier 2 approval weld metal strength can be determined by different methods. Determination of weld metal yield strength matching is readily and economically achieved using the notched tensile test.



In the event of weld yield strength undermatching, which can occur with cellulosic welding of pipe grades greater than X65, the more detailed and expensive wide plate or FSPTT will be necessary to determine the level of weld metal strength matching. It would be advisable to discuss development of the weld procedure with the steel / pipe supplier and evaluate current weld test data. In the majority of Australian pipe designs, these results are readily available from our Australian suppliers.

Concluding Comments Australian research has identified opportunities where, in particular pipe designs, appropriate levels of defect tolerance can be achieved in weld metal that undermatches the yield strength of the pipe. These opportunities exist in pipe above about 7mm because of the assumed defect depth of 3mm, which currently resides in the majority of standards. Knowledge of the pipe design and range of mechanical properties of the both the pipe and weld metal in conjunction with defect limits, provides opportunities where the X80 grade pipe can still be used at maximum economic benefits using cellulosic consumables. Where pipe design requires weld metal strength outside that currently available using cellulosic consumables then mechanised GMA welding systems have been shown to provide economic alternatives.

Acknowledgements The authors would like to thank colleagues at BHP Steel and UOW for their assistance in preparing this paper and in particular Mr Leigh Fletcher for his many helpful suggestions. The authors would like to acknowledge the support of the Australian Pipeline Industry Association (APIA) and the Cooperative Research Centre for Welded Structures (CRCWS) for funding the research. The CRCWS was established and is supported under the Australian Governments Cooperative Research Centres Program. References 1. P.Venton “Pipeline Construction Costs in Australia” WTIA/APIA Research Panel 7 Seminar,

Paper 21, Wollongong, Australia, October 1995. 2. Barbaro FJ, Bilston K, Fletcher L, Kimber M and Venton P “Research shows that X80 pipe

can be economically and safely welded by conventional methods” Australian Pipeliner, July 1999, p22.

3. Barbaro FJ “Types of Hydrogen Cracking in Pipeline Girth Welds” WTIA/APIA/CRC-WS Intl. Conf on Weld Metal Cracking in Pipeline Girth Welds. Wollongong, Australia, March 1999.

4. Bowie GF and Barbaro FJ “Defect Acceptance Levels and Fracture Risk in Pipeline Girth Welds” CRC-WS Final Report 98-62. July 2000.

5. Barbaro FJ and Bowie GF “Assessment of Workmanship Defect Acceptance Levels in High Strength 5mm Wall Thickness Pipeline Girth Welds” IIW Asian Pacific Intl Congress, Melbourne, Australia, October 2000.

6. Alam N, Dunne DP and Barbaro FJ “Weld Metal Crack Testing for High Strength Cellulosic Electrodes” WTIA/APIA/CRC-WS Intl. Conf on Weld Metal Cracking in Pipeline Girth Welds. Wollongong, Australia, March 1999.

7. First International. Conf on Weld Metal Cracking in Pipeline Girth Welds. WTIA, Wollongong, Australia, March 1999.

8. Barbaro FJ, Bowie GF and Holmes W “Welding the First ERW X80 Grade Pipeline” Int’l Conf. on Pipeline Construction. Wollongong, Australia. March 2002.

9. Feng B “Weld cracking in X80 Pipeline Steel” BHP Steel Report PK/TIC/94/026, June 1994



10. Barbaro FJ, Meta A, Williams JG and Fletcher L “Weldability of High Strength ERW X80 Grade Pipe” Pipe Tech Conf. II, Ostend, Belgium. Sept. 1995

11. Norrish.J.,Carapic.M,, Interim report, Mechanised girth welding for the installation of land based transmission pipelines in Australia, GMAW trials, CRC for Materials Welding and Joining, Wollongong, August 1998.

12. Cuiuri.D, Norrish.J, Cook.C, Droplet size regulation in the short circuit GMAW process using a current controlled waveform, AWS Conference, GMA welding for the 21st Century, Orlando, Florida, December 2000.

13. Barbaro FJ. et.al, Proc International Conference on Pipeline Construction Technology, 4-5th March, Wollongong, 2002.

14. Norrish.J. Process options for pipeline girth welding in Australia, Proc. 47th WTIA Annual Conference, 17th to 19th of October 1999.

15. Norrish.J., Review of Commercial Girth Welding Systems, CRC for Welded Structures, Wollongong, October, 2001.

16. Blackman.S., Walker.P.,Michie.K, High speed tandem GMAW, Recent Developments and Future Trends in Welding Technology, Cranfield University, 3-4th September 2001.

17. Widgery.D., Recent Developments in Welding with Tubular Wires, Recent Developments and Future Trends in Welding Technology, Cranfield University, 3-4th September 2001.

18. Gilroy-Scott A.,Huntley.B.,Gross.B., Welding Challenges Constructing the Alliance Pipeline, Proc. IIW Asian Pacific International Congress - WTIA Annual Conference, 29th October to 2nd November 2000. Melbourne, Australia.



Table 2 Performance of different weld procedures in X80 grade pipe 5 - 7mm thick

Welding Method

Resistance to

HACC

Toughness Probability Yield

Strength matching

Probability Strength matching

Tier 1 rating Tier 2 rating

Gas Metal Arc

(GMAW)

Very High High Very High Very High Acceptable Acceptable

E8010 / E10018

Medium (control

required)

High High Very High Acceptable Acceptable

E6010 / E91T8

Medium (control

required)

Low Medium

High Not recommended

Not recommended

E9010 throughout

Medium (control

essential)

Medium Low

Medium Not recommended

Not recommended

E6010 / E9010

Medium (control

essential)

Medium

Low Low Not recommended

Not recommended

Table 3 Performance of different weld procedures in X80 grade pipe >7 - 9mm thick

Welding Method

Resistance to

HACC

Toughness Probability Yield

Strength matching

Probability Strength matching

Tier 1 rating Tier 2 Rating

Gas Metal Arc

(GMAW)

Very High High Very High Very High Acceptable Acceptable

E8010 / E10018

Medium (control

required)

High High Very High Acceptable Acceptable

E6010 / E91T8

Medium (control

required)

Low * Medium Very High

Not recommended

Not recommended

E9010 throughout

Low (control

essential)

Medium Low High Acceptable Acceptable

E8010 / E9010

Low (control

essential)

Medium

Low Medium Acceptable Acceptable



Table 4 Welding parameters for X80 Pipe Parameter Root Run Fill 1 (hot pass) Fill 2 Cap Processs Controlled Dip

GMAW Pulsed Transfer GMAW

Filler Wire 0.9mm Thysen NiMo 80, AWS A5.28 ER 90S-G Parent material

18” x 8.7mm wall ERW X80 pipe

Shielding gas

Argoshield Universal ( 81.25%Ar, 16% CO2, 2.75% O2 ) @ 20 L/min

Preparation: API bevel, 60° included angle, 1.5mm nose, 1.6mm root gap.

Position 5G, Vertically Down Equipment Lincoln Invertec STT

II Fronius Transpuls Synergic 2700

Set wire feed speed

5.8m/min 8.7 m/min

CTWD 12mm Set arc current

85

Set peak current

270

Tailout 6 Hot start 5 Program - wire

1.0mm (Setting B)

Program - gas

Ar82 CO2 G3/4 Si 1

Arc length set

+15

‘Inductance’ 0.7 Dwell 0 0.1 Weave shape

None Rectangular

Weave amplitude

4.5mm 7.0mm 8.5mm

Weave speed

22mm/sec

Travel speed 390 mm/min 385 mm/min 300 mm/min 235 mm/min Measured current (mean)

120 187

See figure 2

Pulse peak 330 amps Background 81 amps



Peak duration

1.6 milliseconds

Background duration

2.6 milliseconds

Measured voltage (mean)

18 29

Heat input 0.33 0.84 Kj/mm 1.08 Kj/mm 1.4 Kj/mm Hardness Peak hardness 270 VPN, Average weld metal hardness 240 VPN ( on centerline of pipe

thickness)



Table 5 Mechanical tests on 5.1mm to 7.1mm thick X80 plate and pipe Material 0.5% TEYS

(plate) UTS (plate) 0.5% TEYS

(weld) UTS (weld) Matching ratio

5.1 mm plate 659 751 564 721 0.97 6mm plate 619 732 575 732 0.93 7.1 mm plate 628 708 578 706 0.92 5.1 mm pipe 657 747 Table 6 Previous results from independent tests on X80 pipe3 Maximum hardness HV10

Average hardness HV10

YS (Mpa) UTS (Mpa) Elongation

270 246 650 725 21.4

3 Bernasovsky. P. IIW Doc. SC XI-E 6/98, May 1968



Figure 1 Specified minimum mechanical properties of pipe and cellulose weld consumable grades.

0

100

200

300

400

500

600

700

MPa

X52 X60 X65 X70 X80

Pipe yieldElectrode yieldElectrode tensile

E6010E7010

E8010E9010

'E10010'

Figure 1 Comparative pipe and electrode strength levels. The pipe yield values are in blue and the electrode yield and tensile values are shown in red and yellow. The ‘E10010’ electrode is not available and shown for illustrative purposes only; for the reasons given in the paper it is unlikely that a cellulosic electrode would be viable at this strength level.



Figure 2 Schematic diagram of guidelines given in AS2885.2 which under “normal” field construction conditions reduce the risk of HACC. The X80 extension is a provided by the current authors for reference only and is not included in AS2885

Pipe wall thickness (mm)

PipeGrade

15 10 5

X60

X70

X80

E6010 only

E6010 root E8010 (Ceq limit)

X80 Refer Tables 1 & 2

Qualn required

Low Risk

High Risk



0.55

0.7

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

9 10

X80 X70

Pipe wall thickness, mm

Crit

ical

hea

t inp

ut, k

J/m

m

a)

0.55 0.6 0.65

00.10.20.30.40.50.60.70.8

E60105P+ E8010Ni E9010G

Electrode

Crit

ical

Hea

t Inp

ut,

kJ/m

m

b) Figure 3. RRC test results on susceptibility to HACC of root pass welds both X70 & X80 grade pipe, a) Critical heat input required to initiate HACC in both 9mm X80 & 10mm X70 grade pipe using E6010 consumable, and b) Critical heat input required to initiate HACC in 9mm X80 grade pipe using different strength cellulose consumables.



Figure 4 Causal tree of factors controlling weld metal defect tolerance.

Applied

Load

Strength

Matching

Cross

Sectional

Area

Test

Method

Pipe

Y/T ratio

Weld

Y/T ratio

Defect

Location

Weld

Reinforcement

Plate Thick

Defect Size

Wide Plate

Full Scale

Depth

Length

Temperature

Width

Misalignment Surface

Embedded

Weld Metal Defect

Tolerance

Pipe

Strength

Weld

Strength

Alloy

Design

Rolling

Microstructure



Defect Length mm Figure 5 Influence of weld metal yield strength matching ratio, pipe wall thickness and test method on defect tolerance ie length of a 3mm deep defect.

0.8 0.9 1.0 1.1

Yield Strength Matching Ratio

FSPTT 5mm

5

10

15

20

150mm

360mm

5mm

150mm

360mm

8.6mm

WPT



Figure 6 Simplified Weld Procedure Qualification Flowchart

Tier 1 Defect Acceptance Limits


Tier 1 Mech Prop

Assessment Fail

Pass

Conduct NDE

Fail

Pass

Tier 3 Assessment

Fail

Pass Tier 2

Charpy + Notch Tensile

Test

Fail

Defect Acceptance

Tier

Tier 1

Tier 2

Tier 3

Conduct WPQ tests: 1 Over the range of expected field conditions, or 2 Under worse case conditions


Review AS2885.2 Review previous WPS Review pipe supplier data

Develop weld procedure sheet

Define Defect Accept Tier

Tier 2 Wide Plate

Test Fail

Tier 2 FSPT Test Fail

Pass

Pass

Pass


Paper 9: Reaman Page 112 of 131 Hobart October 30 2002

SPECIAL PROBLEMS TO BE OVERCOME IN THE CONSTRUCTION

OF SMALL DIAMETER HIGH STRENGTH PIPELINES

By

Jim Reaman Business Development Manager

Nacap Asia Pacific



1.0 INTRODUCTION Good afternoon ladies and gentlemen and fellow presenters. It is indeed a privilege to have the opportunity to present this paper on behalf of Nacap at this APIA X80 Pipeline Cost Workshop in the company of such distinguished and professional representatives of the pipeline industry in Australia and abroad. I would also like to thank Leigh Fletcher and Richard Robinson for inviting Nacap to present a paper at this Workshop Unfortunately, Mr. Bob Burgess of our head office in the Netherlands, was unable to attend the Workshop who was to have addressed this topic from the perspective and experience of Nacap relative to pipeline construction in Europe. However, I will endeavor to address the issues relative to the construction and installation of high strength small diameter pipelines, which for the purposes of today’s presentation we have defined as “Grade X80 Welded Steel Pipe” and as per the guidelines that Leigh has set out for me relative to this topic. The purpose and objective of our paper is to address the real and potential risks and / or problems associated with the installation of X80 pipe and the managing and / or mitigating of the same from the perspective of the on-shore cross country pipeline construction contractor in Australia including an economic risk assessment and risk mitigation strategy which will also identify any advantages and / or benefits to the pipeline contractor. The more technical and economic aspects relative to the use of X80 pipe from the perspective of the Owner and the Engineer has been most professionally and more than adequately addressed in the papers presented by others earlier to day some of which have also included aspects relative to the construction and installation of X80 pipe which overlap with our paper and as such I will do my best not to contradict and/ or to embarrass myself relative to the same. Our presentation today focuses more on the risks and / or problems associated with the installation of X80 pipe rather than the advantages and / or benefits to the pipeline contractor as the contractor, in most instances, is more concerned with managing and / or mitigating the risks and / or problems that may be encountered when constructing an X80 pipeline than with the potential advantages and / or benefits of the same in view of the contractor believing and / or assuming that in most instances it is the Owner who reaps most of the benefits in terms of reduced pipe supply costs and increased operating pressures. There are certain advantages that can be attained by the contractor when installing X80 pipe but which are relative to the “methods” employed to install the X80 pipe rather than being attributed to the use of X80 pipe itself and we will identify and assess the same today. However, Nacap do not believe that the benefits and / or advantages in terms of a reduction in construction costs to be considered a significant factor in the “big picture” with regards to the future construction of X80 small diameter pipelines in Australia In short, the impacts, risks and / or advantages relative to the installation of X80 pipe from the point of view of the pipeline contractor can be categorized into two main aspects of construction being “welding” ( including NDT/UT) and “handling” ( including bending) of the pipe the impacts of which vary substantially between small and large diameter pipe. In view of the “norm” in the Australian Pipeline Construction Industry being that involving the construction of long distance, small diameter, cross country pipelines, we will focus today more on the small diameter pipe assessment relative to the construction and installation of X80 pipe in Australia. We have also assumed that the wall thickness of the X80 pipe to be installed would be compared to that of the current X70 pipe bench mark.



To the best of our knowledge there have been a limited number of on-shore Projects in the World, let alone Australia, involving the installation of small diameter X80 pipe and even less involving the installation of ERW manufactured pipe and as such we have had to make certain assumptions and / or conclusions in the preparation of our paper based on our experience and the advise and experience of others some of whom are represented here today including Steve Blackman of Cranfield University of the UK , Bill Marhofer, of RMS Welding Systems of Canada and Bob Teale of TPMW of the USA. 2.0 THE PIPELINER & THE X-FACTOR The “X Factor” in pipe has been a major concern and / or consideration to the pipeline contractor since the beginning of the installation of welded steel pipelines. During my 30 years in the industry in the USA, Canada, Australia and other regions of the World, each stage involving the increasing of the X-Factor in line pipe, from X52 to X60 to X65 to X70 and now X80 to X100 presented and will continue to present new challenges to the pipeliner which require and will continue to require the development and implementation of new and improved procedures, consumables, methods, and equipment to minimize the risks and / or problems in terms of costs and quality relative to construction and installation of the higher strength pipe. The risk, in terms of costs, at the end of the day is usually on the pipeline contractor as the rewards are normally flow on to the Owner. The most difficult problem for the contractor is to understand the nature of the risks and the most cost effective method by which to offset and/ or mitigate the risks relative to construction. There has been and always will be several options available to the contractor but it is critical to the success on any pipeline construction project involving a major X-Factor to adopt and implement the best option for the task which, in many instances , the procedures, methods, and equipment associated with the same that were successful on a previous project are not always successful on subsequent project which may even involve the same grade of pipe in terms of the X-Factor. I have been involved in and / or aware of major problems encountered on the following Projects in Australia which involved or were believed to involve the X-Factor: Moomba to Sydney Gas Pipeline - X65 Pipe x 34”

“Welding” problems – Cracking of the welds on the X65 pipe produced in Australia which I believe was the first X65 line pipe produced in Australia

Roma to Gladstone State Gas Pipeline – X70 pipe x 12”

“Bending” problems – Buckling and egging of the line pipe during cold field bending

Roma to Brisbane Gas Pipeline Looping – X80 pipe x 16”

“Welding” problems – Welding problems relative to the use of a “mechanized” ( automatic) welding system

The argument and often the claim of the contractor relative to problems encountered on a pipeline project relative to welding and bending has been based on the “actual” X Factor being



substantially greater than the “specified” grade of pipe. That is, the actual tensile strength of a specified and supplied grade X70 pipe could vary such that a substantial number of the joints supplied would have a X Factor far in excess of X70. During the early times the problems and / or difficulties experienced by the contractor related to the “higher” X-Factor often resulted from the welding procedures, methods, equipment, and consumables being developed under ideal “laboratory” conditions that often were not suitable in terms of application and / or production under actual field construction conditions. In more recent times and with more complex issues arising out of the higher strength steels used in the manufacturing of pipe, the development and implementation of various construction procedures have been undertaken on a more joint engineering / contractor approach and / or has involved more “field” testing prior to the approval and implementation of the procedures for construction. The “off-shore” pipeline industry more often takes the lead in the developing and introduction of new procedures, methods, materials and equipment relative to the installation of high strength steel pipelines which is then adapted for the installation of on-shore pipelines. The procedures, and methods developed for the installation of high strength “smaller” diameter pipe for off-shore projects, including automatic welding techniques for the same, have been implemented and proven but to date have not been adequately proven and tested for on-shore pipeline projects which involves a much less controlled and a much more severe environment than that on a “lay barge” Further, the improved and strengthened grade of pipe is often manufactured and supplied to the industry prior to the construction and installation methods being fully developed and proven for the same and as such it normally requires the completion of a number of Projects over a period of time involving the installation of the higher strength steel pipe in order to develop and prove the most effective and practical procedures by which to successfully construct the pipelines. With regards to the construction and installation of X80 pipe, the methods, procedures, equipment and consumables to install the same has been developed and successfully implemented for the construction of on-shore pipelines in several countries in the World but for the most part these involved the construction of large diameter SAW X80 pipe. In Canada and the USA and parts of Europe, the construction and installation of on-shore X80 pipelines is currently considered the bench mark and the development and field proving phase involving the installation of X100 pipe has recently commenced To the best of our knowledge there is a limited history to date involving the installation of small diameter ERW in various part of the World with the possible exception of “off-shore” pipelines and therefore, there is limited information and / or experience available on which to identify and assess any additional construction risks relative to the installation small diameter ERW X80 pipe to those that have been encountered on the installation of larger diameter SAW X80 pipe The contractor today generally understands and / or assumes the cost impacts in terms of the reduction in costs to the Owner relative to the supply of the higher strength / reduced wall thickness pipe but often the contractor does not totally understand the cost impacts in terms of the risk and / or problems relative to the installation and construction of the same. However, today , the modern pipeline contractor, with the assistance and cooperation of the Owners, the Engineers, the Suppliers, and the Technical Services Groups and others in the Industry has become much more aware and knowledgeable of what the X-Factor involves relative to construction and the most effective methods and procedures to be adopted, qualified and



implemented to minimize the construction risks and / or to maximize the construction advantages relative to the execution of an X80 pipeline construction project. 3.0 HIGH STRENGTH (X80) PIPE CONSTRUCTION IMPACTS & RISKS The activities involved in the construction of a X80 pipeline that are impacted by the same and which represent a risk and / or a potential risk to the contractor are generally quite visible and / or identifiable. However, the most effective methods by which to minimize and / or to mitigate the risks associated with the same are not always that obvious. The main aspects of construction that are impacted and / or affected when installing an X80 pipeline, the degree or severity of which will vary significantly in terms of risks and rewards between smaller diameter and larger diameter “thin” wall pipe, are those activities associated with welding and handling of the pipe.

Welding – “Definitely” the “most” critical aspect - large or small diameter

NDT/UT – “Definitely” a critical aspect – large or small diameter

Handling – “Potentially” a significant aspect – large diameter

o Stockpiling o Transporting o Stringing o Lowering-in/ Backfilling o Tieing-in

Bending – “Definitely an aspect – large or small diameter

Hydrotest/ Pigging – “Potentially” an aspect – large or small diameter

4.0 SMALL DIAMETER “vs” LARGE DIAMETER HIGH STRENGTH PIPE As I have previously stated there are significant variations in the degree and / or severity of the risks and impacts relative to construction associated with the installation of small or large diameter high strength pipe which becomes a much more critical factor with the reduced or “thinner” wall high strength pipe. For the purpose of our presentation we have defined “large” diameter pipe as that which has an internal diameter of DN600 ( 24 inch) and greater and the “small” diameter pipe having an internal diameter of DN500 ( 20 inch) and less which has been determined for the most part on the basis of the “mechanized” (automatic) welding systems now on the market that can complete the root pass ( stringer bead) by means of an “internal” welding/ clamp unit as opposed to an “external” welding unit. The impacts on construction from the point of view of the contractor are not necessarily those which are directly a result of the higher strength pipe but rather are more associated with the “methods” of construction by which to install the pipe. Large Diameter SAW Pipe (<NB600) Advantages / Benefits / Rewards:



Welding / UT:

The preferred accepted and proven method for the welding of X80 pipe is the Mechanised GMAW ( automatic) system utilizing an internal clamp/welder which provides several advantages and / or benefits to the contractor:

• Higher Production Rates • Lower Preheating Required • Reduced Costs • Improved Quality • Lower Repair Rates • Reduced Construction Period

The heavier the wall thickness, the more advantages to the automatic welding method.

Facilitates the use of mechanized (UT) inspection and alternative defect acceptance

criteria. Disadvantages / Threats / Risks:

Handling & Bending & Hydro Testing / Gauging

The “handling” of the large diameter “thinner” wall pipe requires the implementing of specific construction methods and procedures in order to avoid damaging the pipe during the various phases of construction

Stockpiling of Pipe

• Requires larger area for stockpile site due to the reduced number of pipe tiers (height of stockpiled pipe) to avoid “egging” of the pipe

• Increased protection / separation of the pipe joints in the stockpile • The use of spreader bars/ pipe hooks may result in damaging the ends/ bevels of the

pipe

Transporting of Pipe

• Number of joints per load reduced to avoid “egging” of pipe • Additional protection / separation of pipe joints during transport • Loads restricted by “number” of joints and not by “weight” ( tonnage)

Stringing of Pipe

• Potential damage to pipe including buckling and egging when placing on skids • Use of spreader bar / pipe hooks may damage ends/ bevels of the pipe • Additional support / protection when setting pipe on skids

Bending of Pipe

• Reduced production to due reduced length for each “pull” ( normally one pipe diameter per degree) resulting in smaller bends of a longer radius

• Potential buckling or egging of the pipe due to excessive “pulls” and / or mandrel deficiencies



• Requires substantial additional bending force due to the high tensile strength of the pipe

• It is critical that the “bent” pipe joint once welded into the line and lowered-in into the trench conforms to the contour and / or profile of the trench in order that the sags and overbends do not become pressure points that could result in buckling or egging of the same during backfilling and hydrotesting

• Additional costs relative to the developing and qualifying bending procedures prior to construction under field conditions

Welding / Coating

• Potential to buckle or egg pipe during the welding and the coating of the field joints if the welded / coated sections are not properly and uniformly supported or “skidded” prior to lowering-in of the sections

Lower-In / Tie-in/ Backfill

• Extra measures must be undertaken to prepare the trench bottom to a very high standard in order to avoid buckling / denting / egging of the pipe during the lowering-in and tieing-in of the welded and coated section and the subsequent backfilling of the trench

• Large diameter / light wall pipe is very susceptible to excess ovality ( egging) at open cut crossings at the point of transition from the excavated mainline trench to the excavated open cut crossing trench which most often does not become evident until the section is pigged or gauged..

Hydrotesting / Pigging

• Filling of the test section with water will place considerable added pressure on the pipeline in terms of weight which may result in buckling, denting and / or egging the pipe following backfilling in the event the lowered-in pipe is not uniformly supported on the bottom of the trench resulting in “pressure points” being exerted on the pipeline at specific locations

• Potential problems may arise during the “pigging” or gauging of the pipe due to buckles, dents, and / or egging of the pipe taking place during backfilling of the mainlines sections, installation of the open cut crossings , and the hydrotesting of the pipeline

• Higher strength pipelines often are designed to a higher operating pressure which will require an increase to test pressures during hydrotesting.

Small Diameter ERW Pipe ( >NB500

There is limited experience in the installation of small diameter ERW X80 pipe in Australia and the other regions of the World

However, specific aspects and / or impacts relative to the risks involved in the installation

of large diameter SAW X80 pipe are considered relevant to the certain risks associated with installation of small diameter ERW X80 pipe but these specific risks will vary in degree and / or severity in terms of the large diameter as compared to the small diameter pipe

Advantages / Benefits/ Rewards

Welding / UT



The automatic welding systems that have been developed for the smaller diameter high strength pipe are based on an “external” welding unit for all passes as an internal welder / clamp has not been developed for pipe with a internal diameter of less than NB600 ( 24 inch). Therefore, the advantages, in terms of costs and production, to the use of the automatic welding system by the contractor for the smaller diameter X80 pipe are substantially less and/ or non-existent as compared to the larger diameter X80 pipe regardless of the grade of the same.

The advantages and / or benefits relative to the smaller diameter pipe would be limited

• Improved Welding Quality • Lower Repair Rates • Use of UT Inspection

Handling

Pipe Transport and Haulage

• Reduction in costs associated with the transport of pipe to the right-of-way as a result in the reduced weight of the “thinner” wall pipe as the number of joints per load is determined by “weight” (tonnage) and not the “number” of joints as is the case for the larger diameter pipe

Disadvantages /Threats / Risks

Welding / UT

Lower production rates vs Additional Costs

• Mechanised GMAW ( automatic welding) system is the preferred and proven welding method for X80 pipe

• Welding production rates are lower for automatic welding spread as compared to conventional cellulose “stick” welding spread

• Additional costs in terms of personnel and equipment required for the automatic welding spread in order to achieve similar welding production rates to that of the “stick” welding spread..

Handling / Bending

High strength pipe of “smaller” diameters are not as prone or susceptible to potential risks and damage as the “larger” diameter pipe relative to the “handling” of the pipe during the various phases of construction. However, certain precautionary measures and procedures will have to be implemented to insure that the “thinner” wall high strength pipe is not damaged during construction.

Bending potentially could become an issue due to the higher tensile strength of the pipe

which would involve smaller bends over a longer radius as in the case of the larger diameter pipe and may also require the use of an internal mandrel to avoid buckling and / or egging of the pipe.

It is critical, although not as critical as in the case of large diameter pipe, that the bent

pipe joint once welded / lowered-in conforms to the excavated trench profile in order that the sags and overbends do not become pressure points prior to backfilling and hydrotesting



Bending procedures should be developed and qualified prior to construction under field conditions

5.0 MITIGATION & MANAGEMENT OF RISKS Welding – X80 Pipe General The most critical potential risk involving the installation of X80 pipe is without question the “welding” phase of the Project whether it be large or small diameter pipe the impacts of which we have previously identified. The major risks in terms of construction and the cost to construct an X80 pipeline from the perspective of the contractor, is the failure by the contractor to implement the most effective and industry proven method my which to mitigate the risks relative to welding which, for the most part, the contractor is dependent on and /or at the mercy of others with regards to the developing of the highly technical methods, procedures, consumables and equipment required to successfully weld the pipe at an acceptable rate of production We will identify the “options” available to the contractor for the welding of X80 pipe and which method is considered to be the most effective in terms of mitigating the risks and / or addressing the potential difficulties and problems associated with the same but we will not get into the technical aspects of the various welding systems as a detailed in depth assessment and description of same has been presented earlier to day by Frank Barabaro and John Norrish. The obvious major advantage to the contractor, besides quality, in the welding of high strength “large” diameter pipe by implementing the mechanized GMAW system is “production” mainly due to the root pass being deposited by means of an internal welding clamp which is considerably faster than an external automatic welding and / or a low hydrogen welding electrode procedure However, as we previously indicated, we will focus on the welding of “smaller” diameter X80 pipe which is considered more relevant to the Australian industry. We have also taken the view that, although there is limited information available, the welding of ERW manufactured pipe should not present any additional risks and / or problems to those relative to the welding of SAW manufactured pipe in terms of construction Small Diameter Pipe ( > NB 500) The major risks to the contractor relative to the welding of X80 pipe are:

#1 Quality – Elimination of cracking and maintaining an acceptable defect / repair rate

#2 Production – Obtaining acceptable production rates which sets the pace for other mainline construction activities.

Based on the experience of Nacap in Europe and the advice of other contractors involved in the installation of X80 pipelines , the following are the options that are proven and accepted procedures and methods in the Industry for the welding of X80 pipe Option # 1 Mechanised GMAW Welding Systems ( Automatic) – RMS/CRC Evans/Vermaat

Systems are based on an internal lineup clamp with copper back up plates



Welding, including root pass, completed by external welding units ( bugs)

Critical aspect of the system is “production” which is determined by the number of

external welding units that can be used for each pass which in turn is restricted by the diameter / circumference of the pipe

Example:

Pipe Diameter - NB 250 (10 inch)

• Limited to one external welder • Root Pass / Arc Time – 1.2 minutes

Pipe Diameter – NB 450 ( 18 inch)

• Two external welders per pass • Root Pass/ Arc Time – 0.7 minutes

System requires end preparation for each joint by re-facing or re-beveling the ends prior

to welding in order to modify the standard bevel in order to reduce the amount or volume of weld metal to be deposited which also reduces the welding time.

Preheating requirements in the same range as for lower grade pipe

Low Hydrogen welding consumables basically the same as those required for X70 pipe

Advantages:

• User/Welder Friendly • Welding Speed • Weld Quality • Consistency Disadvantages:

• Additional labor and equipment for end preparation • Additional labor and equipment for front end ( root pass) welding to obtain

required production rates • Potential contamination of weld due to “copper” back up plates • Additional support costs to conventional stick welding crew

Option # 2 Open / External Root Systems - Lincoln STT / Miller CMT / University of Wollongong

Manual external open root pass which does not require copper back up plates on the internal line up clamp

Following the manual root pass, the weld is completed by automatic external welding

units



Advantages:

• Does not require the modifying of the standard bevel • Does not require the use of copper back up plates thereby avoiding potential

weld contamination • More competitive in terms of costs compared to the Mechanised GMAW systems

relative to additional labor and equipment requirements Disadvantages

• Slower welding speed for root pass resulting in lower production • Inconsistency in quality of root pass

Option # 3 SMAW – Manual Low Hydrogen Downhill Electrodes – Bohler BVD 80/90 up to 110

The use of the a low hydrogen electrode procedure has been used successfully for the welding of high strength pipe on several projects.

However, the quality of the welds were inconsistent and without maintaining strict

procedures relative to the storing of the electrodes, the interpass grinding and pre-heating/ re-heating the defect/ repair rate level became unacceptable .

Lower production rates due to the difficulties experienced by the welder in “handling” the

electrode.

Low Hydrogen electrode procedures/ methods are now generally restricted to tie-ins and the welding of short sections for open cut crossings.

Option # 4 FCAW – Manual Flux Core Wire – Lincoln NR 208H

This procedure and method has generally become the least preferred method due to the “mechanical” destructive testing meeting only the “minimum” requirements of the code and / or standard the relative to weld qualification and acceptance .

Option # 5 Combination of above and / or other options The welding of high strength ( X80) pipe has been successfully undertaken by implementing procedures which are a combination of the above methods and / or systems. As the running of the “root pass”, in terms of production, is most critical to the contractor, the root pass has often been deposited by means of a “manual” electrode/ wire procedure as opposed to



the “automatic” procedure and the remaining passes have been deposited by means of external automatic welding units NDT vs UT – X80 Pipe The major risk to the contractor relative to the inspection and / or testing of the completed welds by the “automatic” welding process is not identifying specific weld defects and / or not detecting the defect until a considerable time following the testing and / or inspection of the welds as when a defect is a result of equipment and / or a specific welder problems the defect is most likely to continue to occur until detected and the required adjustments made. The Mechanised GMAW welding system is essentially immune to hydrogen cracking but is prone to lack-of-side-wall- fusion and other planar defects. It has been proven that the conventional NDT method for testing welds has difficulty in detecting and / or identifying this type of weld defect and secondly, weld defects in general are not detected and/ or identified until a relative lengthy period following the completion of the weld due to the time required for exposing and developing the radiograph The implementation of the mechanized ultrasonic testing (UT) system is the most effective method and procedure for minimizing risks relative to detecting and identifying defects in welds completed by the “automatic” system and is also the most efficient method for the timely detecting and identifying of defects in a weld soon after the weld is completed which will result in lowering the weld defect/ repair rate. The other significant advantage of UT is that this method will enable the development of an “alternative weld acceptance standard or criteria” which will ensure that “actual” potentially harmful defects are detected relative to the Mechanised GMAW welding process Bending – X80 Pipe The major construction risk involved in the cold field bending of the higher tensile strength and thinner wall pipe is buckling and / or causing excess ovality ( egging) in the pipe. Therefore it is mandatory that a bending procedure be developed and qualified prior to the start of construction The procedure to be developed and qualified would maximise the number of degrees that can be bent in each joint and the minimize radius of the bends The developing, qualifying and executing of the bend procedure is very much dependent on the mechanical equipment to be used. Due to the increased tensile strength (hardness/stiffness) of the X80 pipe, a new and / or as new operating bending machine with the required power to exert the increased bending force is most critical as is the operating of the bending machine by a highly experienced and qualified operator. Although not as critical in the smaller diameter pipe ( say NB300 – 12 inch and below), the use of a “top notch” internal bending mandrel is required to avoid buckling and egging of the pipe. The mandrel must be a hydraulically powered in order to withstand the forces exerted on the pipe during bending. The completed bends should also be checked either regularly or randomly by means of an internal gauging plate and a external caliper to insure that excess ovality and / or egging of the pipe is not occurring during bending of the pipe joint. In general the production rates relative to bending of X80 pipe would be less than that of lower grade pipe in terms of the time to complete a bend but in view of the long distance cross country pipeline projects in Australia not involving a substantial amount of bending due to the relative flat



open terrain, the loss of production relative to the same is not considered to be a major construction consideration. Handling – X80 Pipe Potential risks relative to the “handling” of the pipe during the various phases of construction can be effectively mitigated by the contractor adopting construction procedures which would normally be implemented for any pipeline as the risks are considered to be much less when installing smaller diameter pipe as compared to the larger diameter pipe. However, the contractor must take greater care in executing the various methods when handling the “thinner” wall pipe Stockpiling/ Loading/ Transporting / Stringing The use of an excavator mounted “vacuum lift” as opposed to the use of a conventional sideboom mounted spreader bar/ pipe hooks method will prevent the possible damage to the bevels or ends of the pipe joint The construction of suitable “berms” which will provide adequate support for the stockpile pipe will prevent the egging of the pipe and the number of pipe tiers or height of the stockpiled pipe should be reduced. Pipe trailers to be equiped with properly sculptured / padded bolsters and pipe joint separators to avoid damage during transporting of the pipe especially if being transported over long distances and / or rough roads. More attention and care must be taken in the preparation of a trench bottom such that the lowered-in pipe will be uniformly supported on the bottom of the trench in order to avoid creating any hard and / or pressure points on the pipe that would result in buckling , denting and / or egging the pipe during backfilling or hydrotesting of the pipeline. The lowering-in of the welded / joint coated sections should be undertaken by means of a suitable and properly designed “pipe cradle” ( ie rolli type cradle) in order to avoid excessive pressure or stress being applied to the section during lowering-in of the section. The lowered-in pipe should be shaded and / or padded prior to backfilling when the excavated soils could damage the pipe which is normally undertaken to avoid damaging the pipe coating . Extra caution needs to be taken during the installation / tie-in of open cut crossings to ensure that the installed crossing is uniformly supported and the trench is transitioned at the tie-in point to the mainline trench. Hydrotest / Gauging – X80 Pipe The key factor in preventing damage to the pipe during hydrostatic testing is, as described above, ensuring that the lowered-in and backfilled pipe is uniformly and evenly supported on the bottom of the trench to prevent buckling and/ or egging of the pipe once the pipeline has been filled with water which will add considerable weight to the installed pipeline. Prior to the filling of the test section with water, a pig fitted with a mild / flexible steel gauging plate, the diameter of which should be a minimum of 95% of the internal diameter of the pipe, to be run through the section in order to identify any internal damage to the pipe in terms of



excessive ovality and / or buckles and dents which could be located and repaired prior to filling the pipeline with water which could result in additional and / or more severe damage to the pipe. 6.0 CONSTRUCTION COST IMPACTS The most significant and real and / or actual cost impacts or implications associated with the installation of X80 pipe are those relative to the “welding” phase, including UT, of the Project in terms of the methods and procedures to be implemented in order to mitigate and minimize the risks and / or problems that could be encountered during the same in terms of quality and production. The cost impacts in terms of risk / reward for the welding of X80 pipe as compared to the welding of lower grade/strength pipe are dependent and / or subject to the specific parameters and / or nature of the project including pipe diameter, pipe wall thickness, length of the pipeline, nature of terrain, contractor’s experience, and the Owner’s contracting strategies. The economic perceptions of the Owner and the contractor for a particular project may differ such as in the case of a lump sum EPC fixed priced contract the benefits of installing an X80 pipeline, in terms of X80 pipe supply costs are passed on to the Owner where as the risks associated with the welding of the X80 pipe by mechanized welding are borne (often heavily) by the contractor The welding of larger diameter X80 pipe by the Mechanised GMAW (automatic) welding process ( internal root pass) will, in most instances generate substantial cost savings, as compared to a conventional manual (stick) welding procedure, as a result of the additional and / or increased production rates achieved relative which normally should more than offset the additional costs incurred by the contractor as well as minimizing the risks associated with the same However, with the welding of smaller diameter pipe by the automatic welding process involves additional costs as compared to the conventional manual (stick) welding procedure which are not offset by an increase in production rates The potential risks relative to the other aspects of construction, including the handling, bending and hydrotesting, can, in most instances, be mitigated, managed, and/ or avoided by the contractor at minimal and / or no additional costs and therefore are not considered to be a significant factor in the “big picture” Therefore, we have focused our paper on the cost impacts relative to the automatic welding of high strength (X80) small diameter thin wall pipe as compared to the historical and conventional manual stick welding of the lower grade pipe ( X70) in Australia Installation of X80 Pipe – Economic Risk Assessment As previously stated, the most significant cost consideration to the contractor relative to the installation of X80 pipe involves the welding phase of the project and as such our economic risk assessment for the most part is based on the same. The cost impacts set out below for the welding of the high strength light wall (X80) pipe in the range of NB300 ( 12 inch) to NB 450 (18 inch) are based on the actual estimated costs that would be incurred to develop, procedure, qualify, implement and execute the welding phase of the project by the most effective, proven, and practical mechanized GMAW automatic welding system the same and/ or similar to that as developed by RMS, CRC Evans, and Vermaat for an on-shore long distance cross country pipeline project in Australia



The welding system which is based on the “open” root method developed by Lincoln, and the Wollongong University and / or the Bohler low hydrogen electrode procedure may be more competitive in terms of costs but Nacap believe that the mechanized GMAW system is the most reliable and effective method to be employed especially in view of the current advancements and improvements in the development of the system for small diameter pipelines. As I have stated earlier, the risks and cost impacts associated with the welding of X80 pipe by the contractor are more often relative to the “method” to be implemented to weld the X80 pipe rather than “potential” risks of installing X80 pipe and as such no major costs in terms of contingency are included in our assessment as it is assumed that there are methods and / or systems proven and available with will mitigate and / or minimize any potential and / or unexpected risks other than those which are considered to be normal during the welding phase of a project. Basis for Cost Impacts In order to maintain and / or obtain the production rate normally achieved by a manual “stick” welding crew, additional end preparation and automatic welding personnel and equipment would have to be mobilized Equipment and Consumables

Hire / Purchase of Automatic Welding Equipment

Autoweld Technicians by Auto Weld Equipment Supplier

Mobilisation / Demobilisation of Auto Weld Equipment / Technicians

Rig Up Autoweld Crew – Welding sleds, shelters, bottle truck etc

Increased cost in Consumables – wire / gas Weld Procedures/ Qualifications & Welders Training / Qualification

A minimum of 4 to 6 weeks prior to the start of construction required to develop and qualify weld procedures and the subsequent training and qualifying of welders and other personnel to successfully utilize the automatic welding system.

Labor One of the major cost impacts and / or considerations relative to the implementing of an automatic welding system is relative to the “Industrial” impacts of the same in terms of the “manning” requirements for an automatic welding crew as stipulated and / or agreed by the relevant union. In North America, due to the union manning requirements, the automatic welding approach to a small diameter pipeline project cannot be competitive in terms of costs as compared to a manual “stick” welding approach to the same as the unions insist that all labor associated with the automatic welding crew be classified as highly skilled ( top end of the wage scale) workers and / or journeymen to undertake the various activities and / or functions including pipe end preparation , setting of bands, etc The cost impacts set out below are based on a more flexible “Australian” approach to the labor cost component and it is assumed that welders / spacers would undertake only the traditional activities relative to welding on an automatic welding crew



However, there would be a real significant increase in the “number” of workers that would be required to man the automatic welding crews as compared to a conventional manual “stick” welding crew

End Preparation / Modification of Standard Bevel

Front End / Root Pass – Additional Personnel to achieve required production rates

Support Personnel – Cradling welder tents / bottle truck/ welding tractors etc UT Inspection The providing of UT weld inspection services on the basis of a specialized subcontractor will involve additional costs to that of the conventional NDT subcontractor which would also include additional costs to train and qualify UT technicians Learning / Ramp Up Period Additional costs to the contractor would result from the lower production rates that would be experienced during the “start up” of welding activities until such time the welding crews are able to operate efficiently and have become comfortable with the equipment and the system in order to obtain the required weld quality and production rate Cost Impacts The cost impacts in terms of plus or minus are set out as an increase or decrease in cost to that of a mainline welding crew on a conventional small diameter cross country pipeline construction spread installing a pipeline of X70 pipe as compared to an automatic welding crew constructing a small diameter light wall X80 pipeline. Nacap have priced previous Projects and / or undertaken studies in Australia which have confirmed that, at the current costs to implement an “automatic” welding system for the welding of a small diameter pipeline of any grade, the manual “stick” welding approach is significantly more competitive in terms of costs to construct. The “norm” or rule of thumb in North America is that on a “union” pipeline construction project it is most difficult to be competitive in terms of “bidding” a fixed lump sum pricde project on the basis of implementing a full “automatic” welding system for pipe which is NB400 ( 16 inch) or less in diameter. The following cost impacts are indicated in either terms of a percentage (%) for various pipe diameters and length and / or a dollar ($) amount for fixed costs irrespective of pipe diameter and length relative to “each” activity which can be considered to be generally applicable to the construction of long distance small diameter light wall cross country pipelines in Australia.

Operations/Phase Cost Increase Cost Decrease Pipe Transport – Subcontract per tonne Mob/Demob Auto Weld Equipment Procedure & Qualify Welds/Train welders Auto Weld Equipment Hire Weld Technicians x 2

$150,000

$300,000

20 %

$1000 / day each

5 %



Rig up / Additional Support Equipment Weld Consumables – Wire/Gas Labour – 10 no.+/- UT Inspection Ramp Up Period

5 %

12 %

18 %

14 %

$180,000

Bottom Line “Premium” Relative to Total Construction Costs The “premium” for the constructing and installing of an X80 pipe in terms of the increase to the total cost to construct will vary depending on the diameter and the length. However, we have prepared a “rough order of magnitude” in order to provide an “indicative” cost increase relative to the “premium” as applied to the “bottom line” cost to construct an X80 thin wall small diameter pipeline by “automatic” welding as compared to the current industry costs expressed in $ / meter to construct an X70 cross county small diameter pipeline by “stick” welding Length / Dia / Grade Spread $/Meter Total Cost $Increase %Increase 500 km/NB300/X70 Stick $100 $50,000,000 n/a n/a 500 km/NB300/X80 Auto $105 $52,500,000 $2,500,000 5% 1000 km/NB300/X70 Stick $ 90 $90,000,000 n/a n/a 1000 km/NB300/X80 Auto $ 93 $93,000.000 $3,000,000 3% 7.0 CONCLUSIONS & COMMENTS Nacap have concluded the following relative to the construction of high strength ( X80) small diameter (>NB 500) and light wall ( 8 mm +/-) long distance (500 +/-) cross country pipelines in Australia

Yes, most definitely, all risks relative to the construction and installation, including welding, of X80 pipe in Australia whether large diameter or small diameter can be mitigated and managed by the contractor

Yes, there is a definite “premium” to be paid for construction in order for the contractor to

mitigate the construction risks relative to the installation of X80 small diameter pipelines in Australia as it is difficult to offset the additional construction costs by increased production rates and other possible construction advantages and / or benefits

The Australian pipeline Contractor has, for the most part, the required experience,

personnel, and resources to successfully execute all phases associated with the construction of an X80 pipeline in Australia.

The construction impacts and/ or risks vary significantly between large diameter and

small diameter pipe

The technology relative to the methods, procedures, equipment, and consumables required to successfully weld and install an X80 pipeline in Australia has been proven



and are available to the Australian pipeline Contractor from within Australia and / or overseas

The most critical aspect of construction relative to the installation of an X80 small

diameter pipeline, in terms of both technology and costs, is the welding phase of the Project

The proven and most successful method for the welding of X80 pipe is the mechanized

GMAW welding system 8.0 RISK ASSESSMENT SUMMARY General The following “Risk Assessment Summary” relative to the construction and installation of X80 small diameter thin wall pipelines in Australia has been set out in the following format which for the most part does not indicated and / or identify any “reward” to the contractor relative to the installation of X80 pipe The “Summary” includes an assessment of the risks associated with the “individual” construction operations and / or activities as well as an assessment of risk in terms of the “overall” construction phase of a project in Australia Operation / Activity

Identification of the construction operation and / or activity that is at risk and / or potentially at risk when installing X80 pipe

Risk Potential

Indication of the degree of risk to which each of the construction operations and / or activities could be exposed

Risk Description

Description of risks and / or potential risks that could impact each of the construction operations and / or activities

Risk Mitigation

Description of the measures, methods and / or procedures that would and / or could be implemented in order to mitigate the risks associated with each of the construction operations and / or activities

Risk Cost Impact

Indication of the cost impacts associated with each of the risks relative to the mitigation of the same.



RISK ASSESSMENT SUMMARY

INSTALLATION OF X80 SMALL DIAMETER THIN WALL PIPE

OPERATIONS RISK POTENTIAL RISK DESCRIPTION RISK MITIGATION RISK COST IMPACT Pipe Transport Pipe Stringing Bending Welding Weld Inspections & Testing Lower-in/Tie-in Mainline/Crossings Backfill Hydrotest

Low

Low

Medium

High

Medium

Low

Moderate

Moderate

Excessive Ovality Damage Bevels Ovality / Buckling & Reduced Production Weld Quality & Production Rates Defect Identification Ovality & Buckling Ovality & Buckling Ovality & Buckling

Sculptured Bolsters Use of Vacuum Lift New Bending Equipment & Mandrel Mechanised GMAW Welding System Mechanised UT System Rolli Cradles Trench Bottom Preparation Trench Bottom Preparation & PreGauging Pipeline

Nil

Nil

Nil

30%+ Increase

14% Increase

Nil

Nil

Nil

Total Construction Spread

Medium

Welding Quality & Production Rates

Mechanised GMAW Welding System

3% - 5% Increase

Overall



Date post:	07-Oct-2018
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