3/2022 Pipeline Technology Journal Construction & Coating Alkali resistance of coatings? Will tests of cathodic disbondment provide reliable statements to this question? The Feeder 9, River Humber, replacement pipeline project, United Kingdom Safely repurposing existing pipeline-infrastructure for CO2 transport – Key issues to be addressed PE Pipelines – Improvement of productivity and safety using mobile VFT Welding Tracs www.pipeline-journal.net e-ISSN 2196-4300 / p-ISSN 2751-1189
The answer to the most extreme conditions: DEKOTEC® shrink sleeves.Reliable corrosion protection - even for largest pipe diameters and extreme temperatures.Meets ISO 21809-3 and EN 12068. denso-group.comDEKOTEC® Made for Extremes DEKOTEC® Shrink SleevesReady for the greatest challenges.North Africa, 128 Inches (DN 3200)NEW: DEKOTEC®-HTS100 Secure protection up to 100°C/212°F.
Pipeline Technology Journal - 3/2022 editorial The Future in Pipeline Industry Welcome to this latest edition of the Pipeline Technology Journal addressing a variety of contemporaneous pipeline topics including improvement in productivity and safety, repurposing old pipelines, advancement in repair techniques and inspections, coating integrity and achievements in under water installation. Zahi Ghantous Vice President - Construction Support & Quality Management- Consolidated Contractors Group S.A.L. I am honored to have this opportunity to address the readers of this edition and share my insights on our pipeline industry and the trends affecting its future. Unlike other industry segments, pipelines are unique in terms of being invisible structures when completed; they are normally constructed underground in highly challenging terrains and environments with a stretched-out operation area that entails the active engagement of multiple stakeholders and groups. These facts necessitated the need to adopt distinc- tive construction and inspection techniques that would ensure an efficient and streamlined workflow while also guaranteeing the integrity and longevity of the asset. Unfortunately, this also dictated that the adoption of changes that challenged established methods was an arduously slow process that required extensive examination prior to effectively being incorporated into the field. The construction industry, in general, still lags other industries in terms of the application of technologies and innovations. However, and with more de- veloping technologies in recent years, the industry –especially Pipelines pro- jects – increasingly started adopting more and more innovations and advanced methodologies capitalizing on the extensive R&D efforts now invested and the industry’s general shift towards digitalization. This has enabled the achieve- ment of better results and records ranging from the use of alternative pipe ma- terial, welding techniques, modes of inspections, integrity checks and the like. What was not achievable or doable a few years back is now happening and being successfully incorporated in the standard safe building process. With the current movement towards carbon capture and green energy gain- ing more momentum, existing pipeline networks are now being repurposed to transport non-conventional media such as CO2 and hydrogen. The ability to safely re-use existing pipeline networks will be a game changer soon. This further requires the industry readiness to actively engage in adapting mod- ernized techniques and deploying them effectively into their operations. With further progress in Artificial Intelligence, Digital Technologies, and boundary-crossing collaborations, this course is set. It seems inevitable for future successful players in the industry to be on board the earliest possible. Yours sincerely, Zahi Ghantous, Vice President - Construction Support & Quality Management Consolidated Contractors Group S.A.L. eme conditions: TEC®ves.es.Meets ISO 21809-3 and EN 12068. DEKOTEC®tremes
Pipeline Technology Journal - 3/2022 This Issue’s COMPLETE CONTENT 10 Alkali resistance of coatings? Will tests of cathodic disbondment provide reliable statements to this question? T. Löffler 20 The Feeder 9, River Humber, replacement pipeline project, United Kingdom W.Koop; m. Lubberger; T. Jaguttis 30 Safely repurposing existing pipeline-infrastructure for CO2 transport – Key issues to be addressed E. Østby, L. E. Torbergsen, S. Røneid, B. H. Leinum Pipeline Technology Journal - ptj www.pipeline-journal.net # @pipelinejournal #pipelinejournal
Pipeline Technology Journal - 3/2022 40 PE Pipelines – Improvement of productivity and safety using mobile VFT Welding Tracs S. Schwarzer 44 Ask the Experts Construction & Coating Company Directory Page 50
STREICHER PW150-E - Electric driven weldig tractors on duty STREICHER OFFERS COMPLETE SOLUTIONS WITHIN THE ENERGY SECTOR System Provider and Equipment for Pipeline & Plant Construction Save the Date OCTOBER 24-30, 2022 MUNICH VISIT US! BOOTH: FN 1022/5 Feasibility studies, engineering, procurement, commissioning, execution, technical services and innovative working methods for pipeline and plant construction Drilling rigs for hyrdogen, hydro-carbon and geothermal exploration installations Fully electric driven HDD rigs for trenchless Future-focused tailor-made equipment: inhouse developments – ecotec series Electrical engineering and automation from concept to realisation The STREICHER Group, with more than 4,000 employees worldwide, carries out large-scale projects in different sectors, such as Pipelines & Plants, Mechanical Engineering, Electrical Engineering, Civil & Structural Engineering and Supply of Construction Material. MAX STREICHER GmbH & Co. KG aA · Schwaigerbreite 17 · 94469 Deggendorf · Germany T +49 991 330-0 · E email@example.com · www streicher.de
Pipeline Technology Journal - 3/2022 This Issue’s COMPLETE CONTENT
Pipeline Technology Journal - 3/2022 Global Pipeline Community to Meet Again in Berlin in May 2023 After two years of online Pipeline Technology Conference (ptc) and a hybrid event, ptc 2023 will once again focus entirely on face-to-face networking. From 8-11 May 2023, participants from all over the world will again travel to Berlin for the Pipeline Technology Conference and exhibition. About two- thirds of ptc visitors come from abroad. Delegations from 70 different pipe- line operators were registered for the last ptc. In addition to the traditional topics of safety, inspection, leak detection, construction and maintenance, next year's focus will again be on hydro- gen, CO2 transport and methane emissions. Against the backdrop of the current geopolitical situation, political discussions and in-depth ex- changes with operators from Europe, Asia and Africa will be addressed in the keynote lectures and discussion panels. Besides the current topics and news on development and application in the conference, the exhibition is gaining more and more importance. Next year, the entire Hall 2 with 4,600 sqm will be occupied for the first time. Additional alternative space in the transition area between confer- ence and exhibition will be used for special events. Already about 30% of the space has been sold. A special focus will again be devoted to the area of promoting young talent. Apart from the active participation of pipeline students in the execution of the event, there will again be a joint booth of the international Young Pipeline Professional organizations and, for the first time, a separate award ceremony for students and young professionals. With an extensive evening program and various networking events, next year's ptc will again offer a wide range of opportunities to exchange ideas with old acquaintances and new contacts from the global ptc community. The call for papers for the conference is open until 30 September 2022. More news from the ptj newsletter: www.pipeline-journal.net/news
10 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY Alkali resistance of coatings? Will tests of cathodic disbondment provide reliable statements to this question? T. LöFFler > denso Abstract It is generally accepted that the effect of cathodic protection is based on the activation polarization and the concentration polarization of the steel surface resulting in an increase of the pH at the interface between steel and soil. This increase in pH value may affect the ad- hesion of the corrosion prevention coating in the immediate vicinity of the defect. The criterion of cathodic disbondment CD is therefore part of all serious standards for the corrosion protection material of steel pipelines laid in soil and water in conjunction with CP. Interestingly, the effects of the alkaline environment on corrosion protection materials themselves have not yet been the subject of normative considerations, although possible damage to the coat- ing material by alkali may pose a significant risk to the pipeline. To close this knowledge gap, experts from various areas of the pipe- line industry have developed a quick and easy to perform test. The first results of this study will be presented in this paper. The results confirm a very different behaviour of the investigated materials, which properties can also differ significantly from the behaviour shown in the established CD test.
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 11 1. Introduction A functioning and coordinated active and passive cor- rosion protection are decisive for the lasting integrity and failure-free functionality of a newly installed steel pipeline as well as for the achievement of its intended and planned service life. Passive corrosion protection includes all measures which achieve a shielding/protective effect against corrosive media. This can be attained e.g. by an appro- priate selection of anti-corrosion coating as well as de- sign features. The function of a coating is to separate the metal surface to be protected from the surrounding corrosive medium (electrolyte) with respect of mass as well as charge transfer. Such the formation of corro- sion cells is inhibited. The requirements for a coating are shown in figure 1. Cathodic Protection CP (see figure 2) will act as a sec- ond line of defence in the event a defect occurs in the corrosion prevention coating. It is generally accepted that the effect of cathodic protection is based on the activation polarization and the concentration polarization  of the steel surface resulting in an increase of the pH at the in- terface between steel and soil (cf. figure 3). This in- crease in pH value may affect the adhesion of the cor- rosion prevention coating in the immediate vicinity of the defect. The criterion of cathodic disbondment CD is therefore part of all serious standards for the corrosion protection material of steel pipelines laid in soil and water in conjunction with CP. Interestingly, the effects of the alkaline environment on layered corrosion protection materials - e.g. polymeric tapes or shrinkable sleeves- have not been the subject of normative considerations yet, although possible dam- age to the coating material by alkali – here layer to layer adhesion - may pose a significant risk to the pipeline. The same applies for the often-neglected parameter of the shape stability. As long as the delaminated coating rests tightly on the steel surface in the form of a tube (shape stability), no corrosion problems occur . For technical and economic reasons pipelines are usu- ally protected by a combination of active and passive corrosions protection. This combination has proved its value for many decades. Corrosion can only occur under delaminated coat- ing if a relevant volume is able to push in between the coating and the pipe surface. In other words, if the coating is not dimensional stable or has lost the Figure 1: Requirements for a coating
12 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 2: principle of cathodic protection CP Figure 3 – schematic diagram of the effects of activation and concentration polarization (pH-gradient)/ according to  shape stability, a relevant volume is able to push in between the coating and the pipe surface. As a result galvanic elements are formed in combination with heterogenic aeration (oxygen concentration gradi- ents) resulting in an enhanced local corrosive attack despite of the low oxygen permeation through the coating. In the case of a very low shape stability one even could expect, that a very large and continuous volume between the coating and the pipe surface is formed- in a worst case leading to a flow of oxygen containing water between the coating and the pipe surface. If the coating parameters layer to layer adhesion and shape stability degrade due to a high pH, i.e. pH > 10, the coating loses its functionality. This is independent of the origin of the high pH, e.g. effect of cathodic pro- tection or the use of fluidized soil. 2. Background / occasion for new survey There is a plenty of norms and standards for the construction and operation of pipeline structures. Nevertheless, unexpected damage occurs again and test institutes are given the task of investigating their
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 13 cause. The field of cathodic protected pipelines is not an exception. Two examples from practice should make this clear: Example 1: pipeline carrying warm media before bring- ing into service The pipeline was designed for a maximum continu- ous operation temperature of 40 °C. Hot shrinkable tapes were used as the field joint coating. In one seg- ment a liquid soil with a high pH was used in order to increase the stability of the bedding. Before bringing into service a specific electric insulation resistance of the pipeline lower than the limit of 108 Ωm² was measured. The result of a further investigation clearly showed, that the affected area is identical to the to that area, where the liquid soil was used. Example 2: cathodic protected pipeline in operation for a few years In the course of a routine CP above ground survey, e.g. Direct Current Voltage Gradient [DCVG] Survey, a se- ries of nearly equidistant defects were detected. The distance of the survey points was more or less identical to the pipe length. Therefore, these observations were attributed to defects of the field joint coatings. This was confirmed by several excavations. The inspection of the excavated field joints showed, that the adhesion of the field joint coatings was drastically reduced and only punctual existent. The humidity in the volume between steel surface and coating was high alkaline. Both examples have in common, that layered corro- sion protection systems with test certificates accord- ing to DIN EN 12068 were used. Furthermore, in both cases a high alkaline medium was found. Obviously, the specified parameters were not sufficient to exclude future failures.At the first glance this is remarkable, as the respective standards DIN EN 12068, DIN EN ISO 21809-3 or DIN 30672-1 include relevant requirements concerning alkalinity, as for example the cathodic dis- bondment test. If the presumption is confirmed, these tests are obviously not sufficient to characterize the be- havior of these materials in an alkaline environment and to make a reliable statement about their suitability. This is particularly noteworthy since an alkaline envi- ronment inevitably arises when the cathode protection takes effect. The technically responsible process is the formation of the OH ions. The direct consequence of alkali-sensitive materials would be continuous and practically self-increasing damage to passive corrosion protection. This would mean a high-risk potential for the pipelines and would negate the idea of additional protection of a pipeline by the cathode protection in the event of mechanical damage to the casing. The task was thus to find an explanation for the ob- served behaviour as well as a simple and meaningful test for the alkali resistance. 3. Preliminary tests - First considerations for testing alkali resistance DIN EN 12068 already provides a number of require- ments, such as the maximum continuous operating temperature, testing of the specific electrical insula- tion resistance, testing of cathodic disbondment (CD test), testing of the saponification number (without de- fining the extent of the saponification). These frame- work conditions were the basis for a new simple test on alkali resistance. There were ideas on other key points that determine feasibility. • Duration of test: The test duration should be as short as possible. One week appeared practice-ori- ented and desirable. • • Test temperature: The maximum continuous oper- ating temperature of the coating must be at least represented the test temperature. With regard to a time-lapse, this may also be increased to a reason- able extent, on the one hand to enable a statement to be made for the test period specified above. On the other hand, thus the significantly longer expo- sure times to the products in the actual operation of the pipeline can be considered. Concentration of the test medium: The test of the specific electrical insulation resistance specifies the concentration of the test medium at 0.1 mol / l. Instead of the NaCl solution, a 0.1 molar alkaline solution is used analogously to the test of the sa- ponification number, namely a 0.1 molar sodium hydroxide (NaOH) solution instead of an alcoholic potassium hydroxide (KOH) solution.
14 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 4: coating materials after one week after one-week storage in 0.1 molar NaOH solution at 50 °C  For a first assessment, a preliminary test was carried out with four samples of different products. For this purpose, the sample pieces are introduced into the de- scribed solution at constant temperature without a mechanical load for the named time. The results were very impressive and confirmed the path taken, as the effects were already very different, e.g. the deform- ing of the samples or impairing the adhesion between the carrier and the adhesive layers. Figure 4 shows the samples after the first preliminary test. In addition to these obvious qualitative changes, a quantifiable feature was sought that could explain the different behaviour. From other tests, e.g. according to DIN EN 15189, the characteristic of the mass change after storage in various media is known. In comparison to the one-week storage in 0.1 molar sodium hydrox- ide solution, the corresponding storage in deionate (deionized water) at the same test temperature pro- vides information about the pure water absorption. Since the mass change due to the water absorption in both media, deionate and sodium hydroxide, should be similar, the extent of the saponification can be as- sessed from the difference of the mass change. Here, saponification is the decomposition of organic mol- ecules or polymers by lye. So, if the mass increase is larger after storage in the alkaline test medium than in deionate, it is not so far off to assess the extent of alka- line induced decomposition of the coating. Figure 5 shows the mass difference in the two media sodium hydroxide solution (ΔNaOH) as well as deion- ate (ΔH2O). The logarithmic scale in the right picture facilitates the evaluation and classification of the val- ues. For samples C and E, the mass changes are less than 0.5%. These samples can be considered as re- sistant to saponification. For the other three samples A, B and D, on the other hand, the differences in both test media are large and, therefore, clearly indicate a saponification. Figure 5: mass difference of field joint coatings after one-week storage in 0.1 molar NaOH solution and deionate at 50 °C 
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 15 Series A: deionized water at (50 ± 2) °C Series B: 0.1 molar NaOH at (50 ± 2) °C Series C: deionized water at (80 ± 2) °C Series D: 0.1 molar NaOH at (80 ± 2) °C In the first interlaboratory test, 11 different tape stripes from 6 manufacturers from Europe, North America and Asia were tested. 4.2 Test procedure: The samples are completely immersed in deionized water for one hour, then dabbed with a lint-free cloth and weighed (weight in grams). They are then freely suspended, but completely immersed in the appro- priate media. Wires are used to store the samples so that the contact area is as small as possible (cf. figure 6). The covered containers with the samples are laid into heat chambers with the appropriate temperature. After a week, the samples were removed, rinsed with deionized water, blotted with a lint-free cloth and im- mediately weighed (weight in grams). The difference between the weighed-out and weighed-in results in the mass change in grams were measured. The surfaces of the carrier and adhesive are checked for visual changes and documented photographi- cally.Special changes such as softening of the mate- rials, impairment or loss of shape stability must be described and, if possible, documented photograph- ically.Then the bond between the carrier and the 4. interlaboratory tests - systematic investigations The results of the preliminary tests thus substanti- ated the first assumptions and called for a further and broader investigation for further confirmation. A reli- able statement is only permissible with a broad basis and is mandatory for the acceptance of an additional requirement and test. For the aforementioned reasons, a simple, quick test was developed under the umbrella of the DVGW together with experts and corrosion pro- tection experts from pipe network operators, test in- stitutes and product manufacturers . The test, that will be carried out in a short-term test of 7 days at ele- vated temperature, provides a statement about the rel- evant behaviour. An additional test temperature of 80 °C was added to the test temperature of 50 °C, which is the standard temperature for field joint coatings ac- cording to DIN EN 12068. On one hand, this tempera- ture corresponds to the maximum continuous operat- ing temperatures of factory coatings, which are quite common today, and on the other hand represents the time lapse already mentioned compared to 50 °C. The following criteria were defined as the subject of the investigation: 1. The bond between adhesive and carrier, 2. Changes in the carrier or coating material 3. The determination of the mass change after stor- age for one week in deionized water and sodium hydroxide solution. 4.1 test description: Storage media: deionized water and 0.1 M NaOH solution Storage temperature: 50 °C and 80 °C Storage period: 1 week / 1 w 3 samples (e.g. 10 mm x 50 mm) are required for each test series: Series 0: reference sample, no storage in water or caus- tic soda Figure 6: Open sample container for storing multiple samples at the same test temperature 
16 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY adhesive is checked manually and the fracture pattern is documented. d. highly softened and very easy peeling off 4.3 Results Figure 7 shows four specimens of the considerable range of results. a. no change b. adhesive gets bubbles and softens extremely, so that there is no longer any adhesion to the carrier foil, i.e. easy detachment c. highly softened Figure 7: Examples of four specimen after one week of storage in NaOH A “traffic light display” was therefore defined in order to classify the different behavior with three colours (see table 1). It has been shown that the results of the traffic light display from different test institutes match well. The results of the investigations carried out so far can be summarized as follows • There are significant differences in the behaviour of the products (cf. Figure 4) • The results range from: • No or almost no changes • Noticeable loss of the adhesion between the adhesive and the carrier film • Softening of the carrier film and thus loss of shape stability • Loss of stability of the adhesive • In some cases, the damage patterns mentioned were observed simultaneously Figure 8: Results of the mass change  - 50 or 80: test temperature in °C | D: deionized water | N: 0.1 M NaOH
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 17 Evaluation of the adhesive layer after one-week storage Test sample Temperature in H2O in 0,1 M NaOH A B C D E F G H I J K 50 °C 80 °C 50 °C 80 °C 50 °C 80 °C no change no change minimal softening of the carrier foil minimal softening of the carrier foil no change no change no change no change no change no change no change no change 50 °C no change adhesive gets bubbles and softens extremely, so that there is no longer any adhesion to the carrier foil adhesive gets bubbles and softens, so that the adhesion to the carrier foil is decreased significantly adhesive gets bubbles and softens extremely, so that there is no longer any adhesion to the carrier foil Additionally, the shape stability of the carrier film is impaired no change Bubble formation in adhesive Bubble formation in adhesive Bubble formation in adhesive Bubble formation in adhesive Bubble formation in adhesive adhesive gets bubbles and softens, so that the adhesion to the carrier foil is decreased. Additionally, the shape stability of the carrier film is impaired. adhesive gets bubbles and softens, so that the adhesion to the carrier foil is decreased significantly 50 °C Bubble formation in adhesive Bubble formation in adhesive 80 °C 50 °C 80 °C 50 °C 80 °C 80 °C Bubble formation in adhesive no change no change no change no change 50 °C 80 °C 50 °C 80 °C 50 °C Bubble formation in adhesive und distinct softening effect. Bond to carrier foil however is acceptable. no change no change no change Bubble formation in adhesive Bubble formation in adhesive Bubble formation in adhesive 80 °C Bubble formation in adhesive Bubble formation in adhesive und softening effect 50 °C Bubble formation in adhesive Bubble formation in adhesive 80 °C Bubble formation in adhesive Bubble formation in adhesive und softening effect Table 1: Traffic light display  - Green: Red: Failure of the tape with regard to one of the criteria of adhesive bonding and shape stability no change; Orange: optical observation does not impair functionality;
18 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY The presence of one of these failures only leads to failure of the corrosion protection effect, i.e. either loss of adhe- sion between adhesive and carrier film or loss of shape stability. • A comparison of the traffic light displays with the measurement results of the mass increase (see Figure 8) indicate a possible correlation between the extent of the material change and the increase in mass. • The visual impression and the observed shape sta- bility immediately enable an evaluation of the property of interest. 5. Summary • An alkaline environment can have different causes, e.g. a coating defect at a cathodic protected pipeline • The shape stability of corrosion protection materi- als is an important prerequisite for ensuring per- manent corrosion protection. • The influence of an alkaline environment on the shape stability as well as the layer to layer bond of corrosion protection materials is of great importance. • The results of the CD test provide no or only insuf- ficient information about this effect. • Despite good values in the CD test, corrosion pro- tection materials can behave completely differ- ently with regard to the effects on their shape stability. • The test described here is simple, can be carried out in a short time and without expensive equip- ment or special knowledge. It gives a very good im- pression of the expected behaviour of the materi- als when used in an alkaline environment. 6. Conclusion persistence against the boundary conditions, that are affecting or prevailing during use. A simple test can be used to check a previously little-considered but im- portant property for everyone. This test is easy to carry out and understandable. This makes it easy to identify inferior or less suitable systems by means of a fast and simple test. 7. Outlook The possible influences of the surrounding area exam- ined here on the cut surface, in the case of continuous defects, of layered corrosion protection systems, such as tape systems or heat-shrinkable sleeves, have so far not found their way into the known national and inter- national standards for the specification of field joint coatings.For this reason, interlaboratory tests were started under the umbrella of the DVGW with the co- operation of experts, test institutes, pipe network op- erators and product manufacturers . The knowledge gained is gradually presented to the professional audi- ence. On the basis of this, corresponding requirements for coating systems are to be formulated and included in the relevant national and international standards. References 1. M. Büchler, Effectiveness of cathodic protection under disbonded coatings: On the implications of shielding conditions on the integrity of pipelines, Pipeline Technology Conference 2019 2. W. v. Baeckmann, W. Schwenk, W. Prinz, Handbuch des kathodischen Korrosionsschutzes Theorie und Praxis der elektrochemischen Schutzverfahren". (VCH Verlagsgesellschaft Weinheim, 1989) 3. Th. Löffler, N. Klein, Th. Heim, Alkalibeständigkeit von Korrosionsschutzsystemen - Beantwortet die Prüfung auf kathodische Unterwanderung alleine diese Fragestellung zufriedenstellend, bbr, 3-2020, p. 38ff 4. DVGW-Information, Gas/Wasser Nr. 28, Juli 2021 Author The quality and long-lasting lifetime of a coating sys- tem is largely determined by the choice of raw ma- terials, the compatibility with each other and the Dr. Thomas Löffler DENSO Group Germany Head of Business and Engineering Developmemt firstname.lastname@example.org
The Future of Energy: Sustainable, Affordable, SecureStrategically taking place before COP27, ADIPEC is the global platform for leaders to reinforce commitments that will drive the industry towards reducing emissions, meeting decarbonisation goals, and providing a realistic view on short- and long-term energy outlooks.Supported By31 October - 3 November 2022Abu Dhabi, United Arab Emirates Strategic ConferenceView the Strategic Conference Programme www.adipec.com/strategicprogrammeInnovation and the energy transition: pioneering a new era of technology developmentThe road to COP27 and COP28 The long-term impacts of geopolitics on the global economy and energy industryThe new management agenda: future workforce and the leaders of tomorrowAn industry transitioning: adapting to the new fundamentals of supply, low carbon and new energy solutions• Offshore & Marine Conference• Strategic Conference• Forum for Diversity, Equity & Inclusion Conference• Downstream Technical Conference• Smart Manufacturing Strategic & Technical Conferences• Technical ConferenceSTRATEGIC CONFERENCE THEMES:CONFERENCES AT ADIPEC: • Decarbonisation ConferenceNEWPartnersCe ﬁchier est un document Gold SponsorsADIPEC BroughtTo You ByVenuePartnerHostCityStrategic Insights PartnerOfficial HotelPartnerKnowledgePartner
20 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY The Feeder 9, River Humber, replacement pipeline project, United Kingdom W.Koop1; m. Lubberger2; T. Jaguttis3 > A.Hak International1; Herrenknecht2; de la Motte & Partner3 Abstract The Feeder 9, River Humber Pipeline project is required to replace the existing Feeder 9 gas pipeline with a new 1,050 mm high pressure gas pipeline under the estuary of the River Humber. To avoid any impact on the local environment, the pipeline will be installed inside a pre- cast concrete lined tunnel. The tunnel is being excavated utilizing a 4.4 m diameter Slurry Pressure Balance Machine to provide a tunnel of 4.9 km in length with an internal diameter of 3.65 m. Following completion of the tunnelling works the pipeline is inserted as a continuous 4,992 m string into the water filled tunnel before con- necting at each end to the existing Feeder 9 pipeline. Despite the huge technical challenges involved in this project, the project team in col- laboration with National Grid, have developed a solid technical solu- tion to the installation of a circa 5 km pipeline into a flooded tunnel, an achievement that has not been equaled anywhere in the world, which gave a registration in the Guinness Book of records! This EPC-project was commenced in May 2016 and will be fully com- pleted by August 2021.
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 21 A 5km pipeline 48” inserted into a tunnel under the River Humber - A new record 1. Project Overview • Connection of the new pipeline to the existing con- nections approximately 120 m onshore at Goxhill and 400 m at Paull • Decommissioning of the existing Feeder 9 pipeline • Cathodic protection facilities for the new pipeline A strategic component of the United Kingdom Gas National Transmission System (NTS) is the Feeder 9 pipeline that crosses the Humber estuary near Kingston Upon Hull. • Two construction compounds, one each side of the river at Goxhill and Paull, adjacent to the existing AGIs In 2009, underwater surveys highlighted an unprece- dented amount of erosion near Feeder 9 which had ex- posed sections of the pipeline in the navigation chan- nel. It was necessary to find a long-term solution for this Feeder 9 pipeline. A tunneled solution was deter- mined to be the most; economical, environmental, and safe way to proceed. • Significant environmental works to mitigate the impact on the existing protected environment • Associated works for permanent and temporary accesses, highway works, drainage works, tempo- rary spoil storage, temporary lay-down areas and ancillary works The Feeder 9 pipeline project, upon completion in 2021, will be the longest pipeline in a tunnel in the world and will transport up to 20% of the UK gas supply. The pipeline is designed to have a minimum operation life of 40 years and the tunnel a minimum design life of 120 years. The new pipeline will not be subject to the uncertain conditions of the Humber Estuary and will thus ensure the reliable and safe transportation of gas for the fore- seeable future. As well as being economically significant, the Humber Estuary and the intertidal mudflats surrounding the area are of significant ecological importance for many species including birds, mammals (seals and otters), and fish. As such it is afforded some of the highest levels of environmental protection available through International, European and National legislation. The Humber Estuary is an internationally a European des- ignated Special Area of Conservation (SAC), a Special Protected Area (SPA), a nationally designated Site of Special Scientific Interest (SSSI) and an Important Bird Area (IBA). Scope of this Project is: • Construction of a concrete lined tunnel up to 30m deep below the Humber for nearly 5 km • Installation of a 1,050 mm diameter concrete weight coated pipeline with a maximum operat- ing pressure of 70bar 2. Tunneling Activities The tunnel between the launch pit in Goxhill and the reception pit in Paull has an overall length of 4,862 m and follows a nearly straight horizontal alignment. The planned vertical alignment follows a decline of the gradient of approximately 4% for a length of 450 m. Beneath the estuary the tunnel drive is virtually hori- zontal and will revert to an inclined gradient of approx- imately 4% on the north bank of the estuary for the last 600 m. Excavation is mainly within the Burnham and Flamborough with a minimal overburden to the seabed of approximately 10 m. However, within the launch pit and reception shaft the tunnel passes through layers of the Alluvium and Glacial Deposits. 3. Pipeline Insertion Following completion of the tunnelling drive and strip out of the tunnelling services preparations will begin for the pipeline insertion. No pipe welding activities are possible within the tunnel and therefore the pipes (each 12 m long) will be welded into strings of between
22 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 612 m and 624 m on the surface whilst tunnelling ac- tivities continue. The pipes have been delivered to site by truck and are made up of two different types; concrete weight coated (CWC) for installation inside the tunnel with a pipe weight of 16 tons, and fusion bonded epoxy (FBE) coated pipe for installations outside the tunnel with a pipe weight of 5.9 tons. Unloading and stockpiling in the pipe lay-down area was carried out utilising a crane with a vacuum lifter for the FBE pipes and traditional lifting equipment for the CWC pipes. In the pipe stringing yard eight strings will be constructed providing two lines of 624 m in length and six lines 612 m in length, Figure 8: Installation of the pipe strings in the pipe stringing yard. The pipes will be semi- automatically welded allowing for a tol- erance or misalignment of 0.5°. All welds will be in- spected and tested using automatic ultrasonic testing. A total of 13 winches or strand jacks will be used to move the pipe strings laterally on bogies across the foundations in the yard. The bogies run on a rail sys- tem which will be laid perpendicular to the line of insertion. Prior to the insertion of the pipes into the tunnel the following activities must be completed: and a bulkhead installed at each end. The total amount of water required is approx. 51,000 m³ and will be sup- plied from either the local potable water supply or boreholes. Two pipe thrusters with a capacity of 750 tons and 500 tons will be installed in the launch ramp to push the pipe gently into the tunnel and as the first section is pushed into the tunnel a tie-in weld to the second string will be completed. In total seven tie-in welds are required before the pipeline is completely inserted into the water filled tunnel. 4. Conclusion The project delivery phase for the Feeder 9 pipeline re- placement, which will be the longest pipeline in a tun- nel in the world, has passed all it’s key milestones to completion. Despite the huge technical challenges involved in this project, the project team in collaboration with National Grid, have developed a solid technical solution to the installation of a circa 5 km pipeline into a flooded tun- nel, an achievement that has not been equaled any- where in the world. Not only will this project set the bar in respect to overcoming technical challenges never before encountered it will provide a long-term sustainable solution to the transmission of gas across. 1. Strip out/Removal of all utilities from the tunnel- ling works 2. Installation of cathodic protection (CP) equipment (monitoring cables, anodes with power cables, ref- erence cells) A new Gas Pipeline under River Humber: The role of small diameter tunneling for pipeline installations 3. Installation of a gravel bed 1. Introduction 4. Installation of an internal ramp at Goxhill 5. Partial construction of a tunnel bulkhead at the launch shaft in Goxhill 6. Filling the tunnel with water The pipe string will then be winched from the string- ing yard to the pipe thrusters in the launch ramp. Prior to installation of the pipe the tunnel is filled with water Different points of view of all involved parties have to be considered when it comes to the planning of pipe- line routes and the evaluation of potential installation technologies. Due to a rising public attention paid to environmental issues and landowners´ concerns, the impact of pipeline construction on the surroundings has to be reduced to a minimum. While a large pro- portion of cross-country pipeline installations are still executed by conventional open-trench methods, trenchless technologies are mostly considered for
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 23 sensitive crossings of water and traffic routes or pipe- line landfalls. In order to create a reliable and sustainable pipeline network for the upcoming decades, existing pipe- lines have to be expanded and new pipeline capacities have to be built. Innovative construction methods are needed to fulfill the project requirements, to match the time schedule and to comply with environmental reg- ulations and concerns. Different trenchless pipeline construction methods are available to cross existing surface and sub-surface obstacles along the route in a safe, effective and environmentally acceptable man- ner. Innovative technical concepts enable these tech- nologies to be used also in the construction of outfall structures and pipeline landfalls. Whereas in conven- tional HDD or Direct Pipe® the product steel pipeline is installed directly in the ground, methods from the tunnelling industry provide pipe jacked or segmen- tally lined casing tunnels in which the pipeline is in- stalled in a second step. This paper will focus on the role of small diameter segment lining TBM (up to ap- prox. 4 m internal diameter) for pipeline projects on the given reference pipeline project Feeder 9 under the river Humber. 2. Small Diameter Tunnels for Pipeline Installations Tunnelled solutions are often considered for challeng- ing & long crossings or the landfall sections along the pipeline route. Conventional pipeline installation methods like HDD come to their geological limits in highly permeable soil, under high groundwater pres- sures or with low soil coverage. Of course, Direct Pipe® presents an alternative to install a pipeline in one step in the ground using Slurry Microtunnelling in combi- nation with the Pipe Thruster technology. In 2020, a Direct Pipe® distance record was set in New Zealand with 2,120 meters installing a 48” pipeline. For even longer drives, through changing ground conditions or with high overburden, tunnelled solutions often pres- ent the only choice in order to procure safety and reli- ability in pipeline installation. In North America, several pipeline sections are cur- rently in discussion to be tendered as tunnelled cas- ings as there is no other choice to overcome complex ground conditions or long distances through moun- tains with high overburden. 2.1 Machine technology overview Concerning the machine concept, various factors must be considered to choose the best-suited tunne- ling technology for a specific pipeline crossing project, such as geology, tunnel length, curve radii and instal- lation depth. Within this process, the detailed anal- ysis of the geotechnical report is the most important deciding factor. According to geology and requested diameter the following machine types are available for pipe jacked and segmentally lined pipeline casing tun- nels. In order to increase versatility in tunnelling, com- bined shield concepts have been developed in the past to cope with changing soil conditions along the tun- nel route. 2.2 Machine concepts and face support In mechanized tunnelling, there are three different shield types: Slurry shields, earth pressure balance shields (EPB), and open shields. Each of these proven Figure 1: M-2141M_Mixshield 4340 for Humber Crossing
standards are summarized in DIN EN 16191:2014, which is currently being reviewed to even improve health and safety conditions by taking into consideration lessons learnt. The latest ´DIN published in 2014 tightened regulations in regards of machine diameter and acces- sibility, also considering several other aspects as res- cue systems and fire protection. This lead to confined space conditions in the machine, especially where seg- ment lining logistics have to be considered. European manufacturers of tunnelling equipment must comply to European regulations and the leading DIN EN 16191. The logistic is the main key for a good overall perfor- mance on a segment lining TBM. A California crossing inside the tunnel is often needed for segment lining tunnels to allow trains to pass in order to reduce delays due to the travel times of the train. On the California crossing two trains can pass each other and an escape route along the California needs to be maintained at all times. The segment length is generally not less than 1000 mm to keep the number of joints and seg- ment seals to a minimum and to improve production. Furthermore, the smallest standard locomotive has a width of 1 meter. Considering a California crossing with two trains of 1000 mm in width and a sufficient escape route a minimum inner diameter of approxi- mately 2850 mm is required. 24 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY methods has advantages within its special range of ap- plication in certain ground conditions. Slurry shields and EPBs work with a closed pressure system to ac- tively support the tunnel face by slurry or excavated soil. In varying ground conditions, specially adapted and combined shield concepts are advantageous, but are not further discussed in this paper. 2.3 Slurry / Mixshield machines A slurry shield machine is most economical in sandy and gravel ground conditions. The most common ma- chine type for pipe jacking operations with the broad- est range of application in terms of ground conditions and hydrogeology is the slurry based AVN and AVND (with air cushion) technology with a market share of over 85%. This machine range is characterized by a cone-shaped crusher inside the excavation chamber that crumbles stones and other obstructions to a con- veyable grain size. For Mixshield machines from 4 m shield diameter onwards, it is more common to use a jaw crusher instead of a cone crusher. 2.4 General tunnel lining procedures Tunnel and surrounding ground behind the tunnelling machine require immediate support. Two different lining methods are proven technology in tunnel con- struction: Pipe jacking and segment lining. Segment lining has a long tradition in mechanized tunnelling. The principle of ground excavation by TBM and con- secutive ring building are well known in the construc- tion industry. Segment lining offers a high degree of flexibility concerning the planning of tunnel routes. Long drives and tight curve alignments are possible. The erection of the segment rings takes place in the rear part of the machine. Thus, the tunnel is built di- rectly behind the tunnelling machine. The annulus be- tween the ring extrados and ground is backfilled with grout. However, the minimum diameter for segment lining tunnels is increasing due to restrictions given by tightened safety regulations. 2.5 Safety standards in tunnelling During the last decades, safety aspects in mechanized tunnelling gained more and more importance and safety standards are consequently improved: start- ing from basic topics such as PPE (Personal Protective Equipment) and space requirements, including ref- uge chambers and detailed rescue statements. From a European point of view, the latest tunnelling safety Figure 2: General cross section of small diameter Segment Lining TBMs To allow enough space for a ventilation duct and the necessary tunnel lines, an inner diameter of 3000 mm becomes the preferable size for segment lining tun- nels with a certain length. In order to achieve an opti- mal use of the available space on the California cross- ing, it may then be possible to increase the segment length to 1200 mm. The compromise is that two fully
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 25 loaded trains with 1200 mm segments cannot pass on the California crossing. 3. Reference Project: River Humber Crossing, United Kingdom 2.6 Drive length and ventilation The maximum achievable single drive length is driven by several factors. One factor is the logistics for the supply of the TBM with the necessary material such as segments and consumables. Another even more im- portant factor is the logistics for the mucking of the ex- cavated material. An optimized logistic concept might require California switches to allow trains to pass in- side the tunnel. Ventilation for the TBM and the tun- nel has to be maintained at all times, and this may also affect the limits in drive length.The required ventila- tion volume of fresh air is specified in local regulations. The following Table gives a rough overview for the maximum air duct size for different tunnel diameters. The table also shows the possible drive length consid- ering a minimum air flow of 0.3 m/s in the free sec- tion of the tunnel and a maximum pressure of 6,000 Pa in the air duct. For example, a tunnel with a length of 8 kilometers can be built (and this has already been done) with a 3000 mm inner diameter tunnelling ma- chine and an air duct of 1000 mm. Please note that the figures in the table are only rough estimations, which depend on individual project and design parameters. Table 1: Guideline of diameter, air duct size and drive length (without booster fans in tunnel, without any diesel power in the tunnel) For an efficient design and planning of a tunneling project with a given drive length, all these parameters have to be considered to define the optimum tunnel diameter, air duct diameter and minimum cross sec- tion for emergency purposes as described and suffi- cient size to accommodate the rolling stock for mate- rial supply and discharge. If a slurry TBM is chosen for the project, then the slurry pumps and lines in the tun- nel need to be considered in addition to other tunnel lines, such as power supply, compressed air, cooling water and discharge water. The new gas pipeline under River Humber replaces the existing Pipeline 9 which was laid in a trench just below the river bed, exposed to shifting tides. The pipe- line replacement project consists of a segment lining tunnel which will house a 42” gas pipeline to connect the national network in Goxhill in North Lincolnshire to Paull in East Yorkshire, where the gas comes on- shore. The 4,862 meter long tunnel runs with 10 meter coverage below the Humber River bed. With a slope of up to 4% in both riverbank areas, the tunnel alignment is situated in chalk, alluvium and glacial deposits. The main challenge in tunnel construction was the length of the tunnel section without intermediate shaft, with impact on detailed planning and design for working safety and logistics in this relatively small inner tunnel diameter of 3650 mm. A Mixshield Slurry TBM with a shield outer diameter of 4340 mm was used for the project. Logistics have been handled by a Multi Service Vehicle (MSV), not by a rail-bound locomotive, which was a premiere in England for this diameter range. A sophisticated safety concept was implemented to as- sure additional worker safety at all times during the tunnelling progress. 3.1 Pipeline Installation with Pipe Thruster After completion of the tunnelling works, all tunnel in- stallations were removed from the tunnel. For safety reasons no welding in tunnel was authorized to con- nect the 12 meter concrete coated pipe sections. The new 42” gas pipeline has been installed in the segment lining tunnel using two Pipe Thrusters with 500 and 750 Tonnes of push force. A total of eight pipe sections have been laid out on Goxhill site and welded together to two 624 meter and six 612-meter-long sections. Two Pipe Thrusters were installed in the shaft area. The tunnel was flooded to reduce the push forces by the buoyancy force of the pipeline. In July 2020, the new pipeline has been completely installed in the tunnel, setting the world record for the longest hydraulically inserted pipeline. Pushing pipelines into existing tunnels (created by Pipe Jacking or Segment Lining technology) with the Pipe Thruster is becoming more and more common in the pipeline industry. This method has already been implemented in several projects worldwide, with its
26 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 3: Pipe Thruster clamping the 42” pipeline for insertion in segment lining tunnel premiere in Australia, where 750 Tonne Pipe Thruster was used to install the 14,270 feet (4,350 meter) long pipeline in a segment lining tunnel in 2014. Pushing the Limit - Pipeline Installation Design Aspects With their tender Pipe9 JV proposed for a ‘wet in- stallation’ of the pipeline an alternative construction method, which was considered to offer several advan- tages over the initial design but also included the chal- lenge of setting a new record for this method of pipe- line installations. 2. Pipeline Tunnel Cross Section 1. Introduction Pipe9 JV, a cooperation of Skanska UK, Porr and A.Hak, had been awarded by National Grid with the contract to design and construct the Feeder 9 gas pipeline re- placement under the River Humber, UK. The specialist design services for the installation of the pipeline into the 5 km long tunnel were provided by de la Motte & Partner for Pipe9 JV. The client’s front-end design comprised a segmentally lined tunnel of 3.5 m internal diameter with a 40” di- ameter FBE coated high pressure gas pipeline installed on roller supports. After the pipeline installation the tunnel was to be flooded with water for the operational phase, to allow for future modifications or repairs. In general, the proposed ‘wet installation’ of the pipe- line is based on the concept of moving the pipeline into a flooded tunnel, thus reducing its effective weight by buoyant forces. Further it was intended to push the complete pipeline into the tunnel rather than pull in order to utilize the space of the tunnel launch shaft and improve control of the string handling and movement during installation. Several installation options were assessed in close co- operation with the client’s engineers as part of the de- sign process in order to achieve pipeline stability dur- ing the operation while at the same time minimizing the effective pipeline weight for the installation phase. Figure 4 shows the tunnel cross section of the final in- stallation option with the pipeline resting on the tun- nel invert. The selection of materials for this configu- ration was restricted to the client’s qualified solutions and strongly driven by the cathodic protection system
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 27 Figure 4: Tunnel cross section – an impressed current system, with several anodes and monitoring points installed along the tunnel’s inside. Aside from the 1067 x 22.1 mm pipe with an FBE coat- ing the final solution comprised a 75 mm concrete weight coating of 3040 kg/m3 density for negative buoyancy as well PUR collars at approx. 6 m spacing to reduce friction during the installation. In summary, the effective weight of the pipe strings amounted to approx. 13 kN/m in dry and 1.4 kN/m in submerged conditions. 2.1 Installation design The tunnel cross section as outlined above had been selected during the design phase as a ‘compromise’ in order to meet the contradicting requirements of a suf- ficient operational stability (heigh weight), acceptable installation forces (low weight) and a maximum safety against buckling (hight weight, low friction), which could occur at high push forces if the restoring forces from pipe and tunnel geometry are too low to prevent an increasing lateral deflection of the pipe. Aside from knowledge of the friction between the pipe string and tunnel wall, accurate information of the ef- fective submerged pipeline weight is required for an assessment of installation forces as well as critical loads. Several tests have been carried out to narrow the uncertainty of this data, such as friction tests (Figure 5), Figure 5: Friction test sampling of water densities and inspection of pipe and coating weights and dimensions. A total installation force of approx. 4000 kN had been determined from this information for the complete installation over 4850 m length as shown in Figure 6, the subsequent welding and installation of eight par- tial pipe strings resulting in a characteristic saw-tooth shape of the push force. Figure 6: Installation loads The compressive force required to push the pipe sec- tion inside the tunnel is determining the risk of string buckling, which had been assessed by additional FE models also considering the effect of the of the
28 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 7: Shaft installations / Pipe Thruster concrete weight coating onto the pipe’s stiffness. To move the pipeline into the tunnel, a twin setup of Pipe Thrusters had been designed inside the tunnel launch shaft (Figure 7). The base frames for these devices were designed for their full capacity of 7500 kN and to intro- duce the reaction forces into the base slab of the shaft. To ensure that push and clamping forces of the Pipe Thrusters can be introduced through the weight coat- ing into the pipeline, shear tests had been carried beforehand. As-Built surveys were taken after completion of the tunnel construction and prior to pipeline installa- tion to the verify design assumptions and assess pos- sible pipe spanning from misalignments of the tun- nel invert as well as increased friction from segment misalignments. 2.2 Construction data With the information of the as-built surveys a forecast of the minimum and maximum range of installation loads had been derived and a monitoring regime was defined to update and refine this forecast during the pipeline installation process. The operation data of the Pipe Thruster was logged electronically and processed off site to provide updated results and limit values for each shift briefing. A record of the installation loads is given below in Figure 8. The averages of the recorded data coincide well with the anticipated installation loads and the increasing distribution of these data points is an indication of ‘minor’ effects such as stick-slip friction and axial com- pression of the pipe string. Although these effects may generally be assessed qualitatively during the design phase, a quantification may not be possible due to the uncertainty of the contributing factors. In conclusion, the push installation of the Feeder 9 re- placement pipeline had been carried out successfully, setting a new record in length. However, it is also evi- dent that even after significant efforts in testing, sur- veying and modelling effects that are commonly disre- garded minor amount to a substantial fraction of the design load. Figure 8: Monitored installation loads
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 29 Authors Wilko Koop A.Hak International Director email@example.com Michael Lubberger Herrenknecht Head of Business Division Pipeline lubberger.michael@herrenknecht .de Dr. Tim Jaguttis de la Motte & Partner Managing Partner firstname.lastname@example.org Decarbonization of the Pipeline Industry 8 December 2022, Live on Get your free ticket: www.pipeline-virtual.com
30 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY Safely repurposing existing pipeline- infrastructure for CO2 transport – Key issues to be addressed E. Østby, L. E. Torbergsen, S. Røneid, B. H. Leinum > DNV Høvik-Norway Abstract In the context of carbon capture and storage (CCS) or utilization (CCUS), offshore pipelines are foreseen to play an important role for the transport of large quanti- ties of carbon dioxide (CO2) from sources sinks/consumers. There is currently a strong interest within the industry to explore the possibility for repurposing of existing pipeline infrastructure to leverage on existing CAPEX investments. Even though this may seem attractive from a cost perspective, the technical, safety and financial risks need to be acknowledged and addressed accordingly. Several decades of industry experience exists for onshore CO2 pipelines, mainly for enhanced oil recovery (EOR), however, the experience is rather limited for offshore pipelines. Change of product will per applicable pipeline design codes require a re-qualification to ensure that the new premises for change in opera- tion is properly assessed and confirmed acceptable with regards to pipeline safety, operability, and transport capacity. This paper addresses key issues with main focus on pipeline structural integrity.
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 31 1. Introduction The potential for repurposing of existing onshore and offshore pipeline infrastructure for transporting CO2 has over the last decade been given increased atten- tion. Both regarding cost and environmental footprint of building new dedicated pipelines, repurposing is considered a potential attractive option. The topic is addressed in several previous research studies, such as Rabindran et al . In a recent techno-economical study performed by Carbon limits and DNV , a high-level screening of the European oil & gas pipeline network was per- formed to assess repurposing potential either for trans- porting CO2 or hydrogen gas. The study concludes on a significant potential for CO2, however also that the re-use potential will depend on several factors such as location, pipeline route, product composition, operat- ing condition (dense or liquid phase), physical condi- tion and other factors. There are several key criteria that need to be consid- ered carefully, and checks that need to be made, before approving a piece of onshore or offshore infrastruc- ture for re-use. Implicitly the feasibility of repurpos- ing of a specific pipeline needs to be confirmed and documented through a re-qualification process to con- firm acceptable pipeline integrity as well as transport capacity. It is the intention of this paper to describe a methodology and to address key considerations spe- cifically needed for re-qualifying oil & gas pipelines for transport of CO2 in line with guidance provided in DNV-RP-F104 . 2. The Value of Industry Standards & Guidelines Industry standards, recommended practices and guide- lines provide requirements, specifications, guidelines, and characteristics that can be used consistently to en- sure that materials, products, processes, and services are fit for their purpose. Further, they provide guid- ance for the safe management of pipeline infrastruc- ture - both for new design and re-use. Ultimately, they reflect industry experience and are often results of joint industry projects which establishes trust and con- fidence between stakeholders, authorities, and society. For pipeline transport of CO2, there are existing design codes that provides design criteria and guidance spe- cifically for CO2 transport such as e.g. ASME B31.4 , DNV-RP-F104  and ISO 27913 . Figure 1 provides a high-level overview of existing codes across the CCS value chain within the ISO and DNV regime. 3. Key Considerations of Repurposing Pipelines for CO2 Transport In the context of carbon capture, the CO2 may come from various sources and be captured by different techniques leading to variation in product-composi- tion. Within the industry, there are specifications stat- ing minimum 95% CO2 in the composition, where the remaining 5% is typically represented by hydrocar- bons, nitrogen and other non-condensable, and with traces of sulfur, oxygen, glycols, and water . The CCS industry is currently requiring a conservative compo- sition close to 99% CO2, driven by limitations on ac- ceptable impurities across the value chain from cap- ture to storage or utilization. It is foreseen that this strict composition will be challenged in the future, hence this should be accounted for when considering repurposing of pipelines for CO2 transport. Further, in- dustry experience shows that the corrosion rates, and possibly the impact on fractur control evaluations, are strongly affected by the type of impurities, combina- tion of impurities and concentration of impurities . The first challenge relates to risk of internal corrosion for C-Mn steel due to the high corrosion rates caused by CO2, hence the requirement to avoid free water across the pipeline system and foreseeable operating condi- tions. Corrosion risk assessment also needs to consider the additional effects of other impurity elements as e.g O2 and H2S in the composition. The second main challenge is related to what extent the pipe could have sufficient toughness to arrest a running ductile fracture when operated in dense phase, which is also affected by the composition of the CO2 and the material properties of the pipeline. There is now an increasing body of evidence regarding the more challenging situations with respect to run- ning ductile fracture in dense phase CO2 pipelines. It has become clear that the original Battelle Two Curve Method is non-conservative when applied to dense phase CO2 pipelines . Recent large-scale tests point to potential requirements for high toughness,
32 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 1: Overview of existing DNV and ISO codes related to CCS with CVN energy above 300 J in some cases, to arrest running ductile fracture (see  for a summary). Such high CVN energy values could be challenging to doc- ument for older CMn-pipelines and could point to the need for considering alternative solutions, e.g. the use of crack arrestors as commonly used for onshore CO2 pipelines. For offshore pipelines, retrofitting crack ar- restors may however be challenging and costly. There has also been raised a concern as to whether smaller leaks in CO2 pipeline systems could lead to more severe cooling, which again could increase the risk of brittle fracture. The importance of this issue is, however, not fully understood . From a more general perspective there are also po- tential challenges that needs to be handled related to change of flow direction, not only related to one-way equipment but also due to the change of pressure and temperature profiles with regards to pipeline load conditions. Further, interpretation of existing regulations and po- tential change of location class (or safety zones) also needs to be evaluated as part of the re-qualification process. 4. How to safely repurpose a Pipeline System for CO2 Transport 4.1 General DNV-RP-F116  provides recommendations on how to manage integrity of submarine pipeline systems for the intended service life (Figure 2). Pipelines transport- ing CO2 are not specifically addressed in DNV-RP-F116 but gives references to DNV RP-F104 covering pipe- lines for CO2 transport specifically. Generally, when a pipeline is considered used for a purpose other than it was originally intended, or by not fulfilling the original design criteria, a need for re-qualification is triggered. 4.2 An outline of the various steps in a re-qualiﬁcation process As a general rule, the re-qualification shall comply with the same requirements regarding safety and op- eration as for a pipeline designed specifically for trans- portation of CO2. The re-qualification process is recog- nized through the process given in Figure 3 and briefly described through the steps 1-9 below. Step 1 - Initiation: The original design basis and any later modifications, operation parameters, operational history and battery limits extracted from the DFI ré- sumés needs to be established. Key elements within the battery limits, materials selection as well as the pressure rating of the pipeline system needs to be iden- tified. This is key information that needs to be screened as part of the re-assessment part (step 7), i.e. forms the basis for the gap analysis for requirements for CO2 op- eration. A risk assessment should be carried out and a project risk register developed which identifies the risks associated with changing the type of product to be transported from existing to in dense phase or gas phase. The base requirements for the re-qualified pipeline should be established. This includes aspects such as 1) capacity (how much CO2 to be transported),
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 33 Figure 2: Integrity management system 2) delivery pressure, 3) CO2 state and composition to be transported which will influence the later integrity and safety studies. Step 2 – Integrity assessment: As a starting point, the current integrity of the pipeline system shall be addressed through assessment of the technical condi- tion prior to changing to CO2 operation. Historical in- formation of how the system has been operated com- pared with the requirements for operation should be assessed and documented. Identification of material selections as well as the pressure rating and the cur- rent condition of the pipeline system are key infor- mation that shall be screened as part of the integrity assessment. Step 3 – Hydraulic analysis and flow assurance: Changing existing product to CO2 may have implica- tions for the pipeline transport capacity and load con- ditions. A flow analysis should be performed to iden- tify feasibility with regards to transport capacity and corresponding pressure and temperature distribution along the route. A high-level hydraulic analysis, com- paring the key operational parameters when operating with current product and CO2 respectively shall be per- formed as input to the pipeline load conditions. Figure 3: Re-qualification process for pipeline system change into CO2 transport  A representative set of operating conditions shall be covered to establish pressure (steady state and transient
34 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY operation) and temperature profiles. Requirement for modifications of the pipeline system should be identi- fied and evaluated. Step 4 – Safety Evaluations: Safety evaluations should be performed, addressing the implications of a change of product. The system as it is designed should be evaluated toward the specific safety requirement for CO2 pipelines. Need for modifications of the pipeline system should be identified and evaluated, e.g. addi- tional block valves, upgrade of leak detection system etc. The suitability of components / replacements of valves and gaskets not suitable for CO2 should also be evaluated. Attention shall be given to accidental re- lease scenarios, and the effects on consequence radius due to the change of product. Step 5 – Define CO2 transport premises: Premises for CO2 transport should be defined incorporating the results from the hydraulic analysis (3) as well as safety evaluation (4). These aspects will define func- tional as well as system requirements that may devi- ate from the original design conditions. Requirements to the system should be identified and included as part of a complete premise for the re-qualification. This in- cludes stating design / incidental pressure, receiving pressure etc. Step 6 – Reassessment: Based on the input from the integrity assessment (2) and the CO2 transport prem- ises (5), the integrity should be evaluated for the new premises. Parts of the system that is identified not to be compliant with the integrity requirements will require design modifications and reiteration on the re-assess- ment. In some cases, the required modifications are not feasible e.g. from a cost-benefit standpoint, lead- ing to termination of the re-qualification process. Assessment of additional Failure Mechanisms: Additional failure mechanisms relating to the changed opera- tional conditions shall be identified, considered, and evaluated. Key areas to be addresses are typically: • Compliance with existing material properties • Load conditions: Re-assessment of the pipeline system, specifically addressing the implication of new premises on pipeline load conditions. The assessment shall be performed comparing the requirement in the original design code and with specific requirements for the system in question. • The change in operational conditions Risk register: The risk register established in (1) shall be updated and any risks associated with the pipeline in- cluding upstream and downstream battery limits iden- tified. The risk assessment shall confirm that these changes are appropriately addressed in relevant man- agement and replacement plans for the pipeline. Comparison of original and new design standards: A gap-analysis to identify gaps between the original de- sign standard and applicable current design require- ments and CO2 specific guidelines or recommended practices should be performed. Re-assessment of the pipeline system shall be performed, specifically ad- dressing the implication of new premises on pipeline load conditions. Step 7 – Modifications: Modification alternatives should be evaluated with respect to feasibility, safety, and integrity. A re-assessment of the modification al- ternative will be performed through documenting the integrity status. This activity shall cover identification and description of possible mitigations or modifica- tions to ensure safe operation with CO2, considering acceptable levels of impurities and operating envelope, other modifications/mitigations for improving load condition for the pipeline, material testing to docu- ment (original) material properties when information is lacking etc. Step 8 – Document: Documentation of the re-quali- fication process as well as update of system documen- tation, drawing, equipment lists, and operating pro- cedures is required to ensure that the re-purposed pipeline can be safely and effectively operated. Step 9 – Implement: Implementation of changes to the system should be performed prior to transition of the system into the new operational mode for CO2. 5. Hydraulic Analysis and Flow Assurance (Step 3) For existing pipelines purposely built for transporting CO2, the pipeline design and operating envelope is in
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 35 most cases adapted to transport the product in liquid (dense) phase. This is due to the favorable combination of high product density and low viscosity for the liquid phase, allowing for optimization of both installation (i.e. reduced pipeline diameter) and operational cost. Figure 4 shows a typical phase envelope for pure CO2 and for a ’synthetic’ composition containing 97%CO2 and 3%N2. Operation in liquid phase requires mini- mum pipeline pressure rating in the range of 80 to 100 bar, depending on stream composition and range in operating temperature, ref. Figure 4. For offshore pipe- lines, the pressure rating will in many cases be higher than 100 bar, i.e. sufficient to enable operation in liq- uid (dense) phase. Offshore gas pipelines typically have a design pressure in the range of 150 bar. It should be acknowledged that in most cases it is not possible to re-qualify a pipeline to higher pressure rating, considering that pipelines are normally optimized on design loads, including pressure containment. Hence, with regards to deter- mining transport capacity, the pipeline pressure rating should first be identified to conclude feasibility of op- eration in liquid phase, or whether gas phase at lower pressures is the only viable option. For onshore oil & gas pipelines, pressure rating is typi- cally less than 80 bar and the pipeline would normally be operated in close balance with ambient tempera- ture, either exposed above ground or buried. Pipelines with pressure rating less than 80 bar may still be feasi- ble for transporting CO2 in gas phase, however the lim- itation in upper operating pressure for the avoidance of two-phase flow condition needs to be acknowledged. Conservatively the maximum operating pressure for gas phase transport may be determined by the satura- tion pressure at the minimum operating temperature of the pipeline, i.e. the pressure at which a liquid phase will start to drop-out (condensation). Minimum oper- ating temperature will typically be governed by a com- bination of inlet temperature and thermo-hydraulic response of the pipeline from inlet to outlet, including the effects of pipeline insulation and variations in am- bient temperature. To confirm acceptable margin to two-phase flow, hy- draulic simulations should be performed with appro- priate tools to determine relevant range in pressure Figure 4: Phase envelope for pure CO2 and composition of 97%CO2+3%N2; for illustration; typical operating envelope for dense and gas operation indicated.
36 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY and temperature profile along the pipeline route for the actual product composition. As an example, if the minimum ambient soil temperature for a buried pipe- line is 10°C, the maximum operating pressure in gas phase needs to be limited to approximately 45 bar, de- pending on product composition. Combined with the pipeline size, length and minimum required arrival pressure, this limitation will have direct implications for the pipeline transport capacity. Regarding flow as- surance, one key concern is to ensure sufficient control on product water content to prevent drop-out of free water and subsequent corrosion risk. In this context it should be acknowledged that water solubility varies sig- nificantly between liquid and gas phase and may also be affected by the presence of other impurities in the product . Also the potential for free water drop-out in upset conditions, including off-spec product should needs attention. In addition to the assessment of transport capacity, tem- perature and pressure profiles should be established from thermo-hydraulic simulations for a representa- tive range of operating conditions to provide input to the new pipeline load conditions. The simulation cases should typically include design cases, normal opera- tion, turn-down case(s), line-packing, shut-down and re-start. Pipeline depressurization (rare event) should also be simulated to document that the pipeline can be safely depressurized within reasonable time and within the specified design conditions such as minimum de- sign temperature. Repurposing existing oil & gas pipelines for transport- ing CO2 will in many cases require reversing the flow direction which will have implications for pressure and temperature profiles. Any ’one-way‘ equipment or func- tions needs to be identified and assessed. Booster or pressure reductions stations may need to be bypassed or reconfigured and non-return valves etc. may need to be removed or locked open. 6. Safety Evaluations (Step 4) Safe operation of CO2 pipelines has been demon- strated through a number of pipeline projects related to enhanced oil recovery (EOR) and CCS . There is currently no evidence to support that the failure fre- quencies for CO2 pipelines should be higher than for comparable oil & gas pipelines . However, it should be acknowledged that these pipe- lines are purpose built for transporting CO2, and that special measures both regarding design and opera- tion are implemented to manage integrity and mit- igate major accident scenarios. It should also be ac- knowledged that most of the existing CO2 pipelines run through remote areas with limited interference by and potential for exposing 3rd party. To lean on the current experience from onshore CO2 pipelines, it therefore needs to be evaluated whether the relevant safeguards can be achieved and is also sufficient for existing oil & gas pipelines repurposed for CO2 in more highly popu- lated areas, alternatively whether this can be mitigated by other safeguards. The safety evaluations for operation with CO2 should be performed on the back of the hydraulic analysis to ensure correct assessment of the hazard potential, both considering normal planned operations and acciden- tal release scenarios. Due to the significant difference in pipeline inventory between CO2 pipelines operated in dense and gas phase the corresponding differences in consequence scenarios for pipeline failures should be acknowledged regarding release rates and duration. 7. Re-Assment (Step 6) 7.1 General This section outlines some key material aspects and as- pects in design of CO2 pipelines. 7.2 Key material aspects for pipeline systems Steel material: As outlined in Section 3, there are mate- rials aspects related to CO2 transport that needs special considerations when assessing pipelines for such use. These are related to potentially increased degradation of the steel pipeline due to: • Internal corrosion in presence of water • • Embrittlement in case of CO2 compositions with certain impurities, e.g. H2S Embrittlement in case of low steel temperatures in relation to small leaks There are also scenarios where the CO2 could lead to higher loading of the pipeline, and thus increased re- quirements to material properties, which especially is
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 37 related to toughness requirements to arrest running fracture in CO2 pipelines. Non-metallic materials: Dense phase CO2 behaves as solvent to certain non-metallic materials such as elas- tomer seals and gaskets. With respect to polymeric ma- terials elastomers, both swelling and explosive decom- pression damage needs to be considered. Swelling of the elastomers is attributed to the solubility/diffusion of the CO2 into the bulk material. Explosive decom- pression may occur when system pressure is rapidly decreased and the gases that have permeated into the elastomers expand. Candidate materials also needs to be qualified for the potential low temperature condi- tions that may occur during e.g. the pipeline depres- surization scenario. Natural gas pipelines with internal flow coatings may run a risk of coating detachment from the base pipe material in a potential low temperature condition as- sociated with rapid pipeline de-pressurization. 7.3 Design aspects The same limit states as for other pipelines applies for pipelines transporting CO2. However, due to differ- ent characteristics of the CO2 compared to e.g. natural gas, a pipeline designed to transport CO2 including re- quired intervention may not be identical to a pipeline transporting natural gas, even for cases when the de- sign pressure and diameter are identical. Internal corrosion: If free water is present in the CO2 flow, this could lead to significant corrosion rates and selecting a corrosion allowance to mitigate this will not be sufficient. Therefore, both strict control of the containments in the flow and drying of the flow is es- sential for transport of CO2 to prevent internal corro- sion. Corrosion resistance alloys may be selected for new pipelines but comes with an increased cost, and this is obviously not an option for repurpose of exist- ing carbon steel pipelines. Fluid category and safety zones: The recent revisions of ISO 13623  and DNV-ST-F101  have moved CO2 into a more severe fluid category compared to ear- lier revisions of the codes. The fluid category for CO2 is now the same as for natural gas, and hence the de- sign factor for pressure containment for a pipeline conveying CO2 and natural gas is the same, provided that the population density (number of people) within the consequence zone is the same. Depending on the volumes in the pipelines, the consequence zones for CO2 pipelines may be larger as the CO2 is spreading along ground and not up in the air. If the consequence zone is increased this may give a larger/stricter loca- tion class, which in turn will result in a reduced pres- sure containment design factor which again will result in a reduced design pressure. Running ductile fracture: Full scale fracture arrest tests have revealed that pipelines conveying CO2 are more vulnerable to running ductile fractures than natural gas pipelines, i.e. the design approaches applied for natural gas pipelines are non-conservative for CO2 pipelines. Hence, a pipeline transporting CO2 is ex- pected to require a higher fracture toughness and/or thicker wall thickness or having restrictions with re- spect to CO2 composition and temperature to con- trol the saturation pressure which governs the driving force for running ductile fractures. For re-qualification it is not possible to increase fracture toughness or wall thickness, so in case insufficient characteristics an al- ternative is to control the CO2 composition and tem- perature to arrive at acceptable saturation pressure, or to mitigate fracture arrest by e.g. fracture arrestors where required and possible. Brittle fracture: If there is a small leak in a CO2 pipeline in combination with significant stresses in the area, initia- tion of brittle fracture is a possible scenario. A detailed analysis of this issue is currently challenging. Beneficial information would be if existing materials certificates point to good low temperature toughness (e.g. low CVN energy transition temperature). Further, effort to mini- mize the risk of leaks in critical regions would also be of benefit to reduce the likelihood of such events. Reversed flow direction: Pipelines being re-qualified for CO2 transport (in case of storage) may often change inlet to outlet (and vice versa). The original design of the pipeline has typically accounted for expansion forces due to pressure and in particular temperature, to allow safe operation of the pipeline. Since the tem- perature loading is most pronounced at the inlet end of the pipeline, typically little or no considerations have been placed to the outlet end of the pipeline due to lim- ited expansion forces. However, when inlet and outlet ends are changed, expansion forces may be relevant at
38 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY the (new) inlet end. This will require that the expan- sion potential and forces are evaluated and may lead to additional intervention to accommodate the increased expansion forces, by e.g. increased burial to avoid up- heaval buckling or by allowing the pipeline to expand in a controlled manner. Effects of weight and mass of fluid: The density of the CO2 in dense phase could be in the range of 10 times higher than the density of the natural gas, while the density of CO2 in gas phase is more similar to natural gas. Hence, if CO2 is transported in gas phase the weight and mass of the pipe- line may not change significantly, however, for dense phase CO2 the weight may increase significantly. If the weight of the pipeline increases, this may decrease the acceptable free span lengths as the bending of the pipe- line increases on supported shoulders, and additional mitigation may be required. Further, an increased mass will change the natural frequencies of e.g. free spans and hence the acceptable free span length may be shorter due to changes in the fatigue/fracture loading response, and additional mitigation may be required. The dynamic loads from e.g. waves and current may also change due to changes in weight and mass. Changes in weight will also influence on-bottom stability. Third party loads: Loads from third party are generally not changed when changing from natural gas to CO2 transport, however, if weight and mass of the pipe- line is changed this may change the response of the pipeline. 8. Summary and Conclusion This paper has discussed a general approach for re-qualification of pipelines for CO2 transport. There are several key criteria that need to be considered carefully, and checks that need to be made, before ap- proving a piece of onshore or offshore infrastructure for re-use. Implicitly the feasibility of repurposing of a specific pipeline needs to be confirmed and docu- mented through a re-qualification process to ensure acceptable integrity, safety as well as transport capac- ity. General codes and recommended practices that lay out requirements and guidelines for design an opera- tion of CO2 pipelines are already available and can be used as basis for re-qualification of CO2 pipelines. It is foreseen that these standards will evolve with the CCS industry to incorporate latest research. In this paper, the various steps in the re-qualification process in DNV-RP-F104 has been outlined. There are however aspects that could benefit from fur- ther research, e.g. formulation of requirements for running ductile fracture and eventual environmental embrittlement. Impurities in captured CO2 affect crit- ical pressure, critical temperature, and phase behavior, which may affect pipeline materials and design param- eters. Other challenges related to repurposing of pipe- lines may be general lack of design and construction documentation for older pipelines. Also, repurposing of pipelines for CO2 transport may be challenged by local rules and regulations, and interpretation of such. Thus, re-qualification of pipelines, especially for CO2 transport in dense phase, is therefore not considered trivial and requires a careful evaluation but is never- theless considered as fully possible in many cases. ‘The feasibility of repurposing of a spe- cific pipeline needs to be confirmed and documented through a re-qualification process to confirm acceptable pipeline integrity as well as transport capacity.’ References IEAGHG, “CO2 Pipeline infrastructure”, 2013/18, December 2013 1. 2. DNV-ST-F101 ‘Submarine pipeline systems’, 2021 3. DNV-RP-F104 ‘Design and Operation of carbon dioxide pipelines’, 2021 4. Rabindran, P. et. Al , Integrity Management Approach to Reuse of Oil and Gas Pipelines for CO2 Transportation, 6th Pipeline Technology Conference 2011 5. Re-stream – reuse of oil and gas infrastructure to transport hydrogen and CO2 in Europe, October 2021 (https://www.carbonlimits.no/project/re- stream-reuse-of-oil-and-gas-infrastructure-to-transport-hydrogen-and- co2-in-europe/) 6. ASME B31.4: Pipeline Transportation Systems for Liquids and Slurries 7. ISO 27913 Carbon dioxide capture, transport and geological storage – Pipeline transport system’, 2016 8. IPCC Special Report on Carbon dioxide Capture and Storage, Chapter 4 – Transport of CO2. 9. B.H. Morland ‘Corrosion in CO2 transport pipelines – Formation of corro- sive phases in dense phase CO2’, PhD 2019 10. G. Michal, B. J. Davis, E. Østby, C. Lu and S. Røneid, "CO2Safe-Arrest: A full-scale burst test research program for carbon dioxide pipelines - Part 2: Is the BTCM out of touch with Dense-phase CO2?,", 18th International Pipeline Conference IPC2018, Calgary, Canada, 2018. 11. G. Michal, E. Østby, B. J. Davis, S. Røneid, and C. Lu, " An empirical fracture control model for dense phase CO2 carrying pipelines" , 9th International Pipeline Conference IPC2020, Calgary, Canada, 2020. 12. Barnett, J., Cooper, R. The cooltrans research programme - Learning for the design of CO2 pipelines (2014), Biennial International Pipeline Conference, IPC, 1 13. DNV-RP-F116 ‘Integrity management of submarine pipeline systems’, 2021 2017 14. Wetenhall, B. et al, Impact of CO2 impurity on CO2 compression, liquefac- tion and Transportation, GHGT-12 15. DNV-REP-2017-0474, Rev.2, Recommended Failure Rates for Pipelines, 16. ISO 13623, 2017, Petroleum and natural gas industries — Pipeline trans- portation systems 17. DNV-RP-F104 ‘Design and Operation of carbon dioxide pipelines’, 2021
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 39 Authors Erling Østby DNV Høvik-Norway email@example.com Lars Even Torbergsen DNV Høvik-Norway Senior Principal Specialist; Oil & Gas Flow Technology firstname.lastname@example.org Sigbjørn Røneid DNV Høvik-Norway Senior Pipeline Engineer email@example.com Bente H. Leinum DNV Høvik-Norway Senior Principal Consultant – Subsea System Integrity firstname.lastname@example.org PHOTO CONTEST “Working in the Pipeline Industry” Submit your Photo www.pipeline-conference.com/photo-contest
40 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY PE Pipelines – Improvement of productivity and safety using mobile VFT Welding Tracs S. Schwarzer > VIETZ Abstract Nowadays plastic pipelines form an integral part of modern infrastructure. The most common applications for butt-fused plastic pipelines are water and natural gas distribution networks. Inventions of new materials, production and installation methods for extruded pipes enables new applications and dimensions in a growing range of needs. Climate changes causes challenges for urban and non-urban regions around the globe. Periods of heat require irrigation for farms as well as water to fight against wildfires. Environmental energy from wind farms, solar farms and hydroelectric power plants will reduce the carbon dioxide output level for en- ergy production, however the high voltage grid needs to be updated to avoid shutdowns. New power grids like "SuedLink" in Germany, where hundreds of kilometres of protection pipes for cables will be required, are the markets for the future. It is now possible to optimise the installation method for fuseable plastic pipes to make long distances more reliable and cost effective. VFT welding Tracs are suitable for safe and economic plastic pipeline in- stallation. They are self contained and self propelled all terrain machine carriers for butt-welding machines. In combination with state of the art welding equipment and the onboard generator a full automatic weld- ing process is possible. Data logging systems enable a 100% report for all joints. The automatic self load and clamping system for the pipe in- creases the health and safety standards for the operators. The accident risk is much lower than with pipe handling with a crane or excavator. There is no need for lifting equipment during the welding process. This saves labour expenses and equipment costs.
Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 41 1. Application fields for Polyethylene (PE) and Polypropylene (PP) pipes • Slurry processing • Water transportation 1.1 Public services and energy: • Oil and gas • Water and stormwater • Sewage • Desalination of seawater • • Protection pipes for telecommunications Protection pipes for power grids • Hydroelectric power 1.2 Construction and farming: • Drainage and groundwater lowering • Pipeline rehabilitation • Trenchless technologies • Irrigation and firefighting water 1.3 Mining: • Coal bed dewatering • Methane extraction • Heap leaching • Water processing 2. Benefits using VFT Fusion Tracs VFT Welding Tracs are self contained and self propelled all terrain machine carrier for butt-welding machines. In combination with state of art welding equipment and the onboard generator a full outomatic welding process is possible. Data logging systems enable a 100% report for all joints. The automatic selfload and clamping system for the pipe increases the health and safety standards for the operators. The accident risk is much lower as with pipe handling with a crane or excavator. There is no need for lifting equipment during the fusioning process. This safes labor expenses and equipment costs. The large 360° panorama view cabin protects the opera- tors against all elements i.e. rain and snow, sun and UV radiation and heat and coldness, dust and dirt and wind and cold. The climatic controlled cabine (heater and air- condition) guarantees a constant temparature for the operator as well a high quality joint according to the in- ternational welding standarts for PE and PP pipes. A special fusioning working yard is redundant. The setup of fusioning equipment, weather protection tent or container, generator, pipe handling equipment Figure 1: VFT 500 (180-500 mm) System setup
42 Pipeline Technology Journal - 3/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY Figure 2: VFT 500 (180-500 mm) on jobsite in Australia (excavator, crane) for a limited range of distance is not efficient in comparasion to the all-in-one VFT solution moving forward with the installation process. Setup times are minimized. A one man operation and the optimized fusioning pro- cess using the VFT welding tractors enables more pro- ductivity. Savings against conventional process are 30- 50% depending on pipe size, wall thickness and local situations. As an option "optimized cooling equip- ment" can increase the savings up to 50-70% based on reduced cooling times. Track undercarriage with op- timized cross-country mobility, reduced compression of ground and road-liner rubber pads as option for as- phalt/paved surfaces. 3. Range of application VFT Tracs Table 1: Available VFT Trac sizes 4. Conclusion Plastic pipes i.e. Polyethylene (PE) and Polypropylene (PP) pipes are and will be a significant part of all ap- plications related to fluid transports. Underground or above ground, long service life or short term solution does´t matter, the material caracteristics of the mate- rial enables all facets in all applications. In addition to the common applications farming will requires irrigation solutions, the mining business needs effective fluid solutions and the transformation of our power grids to environmental energy a lot of new high power grids within protection pipes. Figure 3: VFT 900 (340-900 mm) 800 mm trials before delivery to the client Within a growing market the VFT Fusion Tracs enable a efficient, more save and reproducibility of all jobs. The pipe range from 110 to 1600 mm (4-56") guaran- tees a full range in all applivcations. The health and safety aspects of the operators are optimized and part of the VFT Trac concept. Author Sebastian Schwarzer VIETZ International Sales Manager email@example.com
44 Pipeline Technology Journal - 3/2022 ask the experts Ask the Experts Construction & Coating Q1) What is the key to success for coating joints in the field ? Q2) What kind of technologies are available to check the quality of buried pipeline coatings? Answer: If weld seams or joints are to be safely pro- tected in the field, the processing of the coating ma- terial is often subject to very difficult environmen- tal conditions. Whether the influence is temperature, humidity, wind - or even construction site conditions: they can all have a significant impact on the process- ing and the result, and thus the quality of the coating. As the international standard ISO 21809-3 defines 11 different families of coating systems, which are them- selves subdivided into many sub-categories, the choice of the right coating is very wide and makes the selec- tion of the most successful coating material a challeng- ing task. This task becomes even more difficult when one considers that ISO 21809-3 distinguishes the dif- ferent products according to their material composi- tion and not according to load classes or resistance in the field. As the coating of the joints is applied in the field where application conditions are difficult to control and often unpredictable, coating materials requesting the least restrictive application procedure are generally the ones who succeed in the long term. However, limiting yourself to the conditions during the application of the products would not meet the re- quirements of the very long service life of pipelines. These can vary greatly depending on soil conditions, chemical, mechanical and temperature loads. Therefore, the key to success in selecting the right coat- ing for the joints is to use a product that is very easy to process, involves only as few steps as possible, can be corrected during application and withstands the real stresses in the field with the most appropriate corro- sion prevention performance. Answer: First of all, one must distinguish between the quality control of the applied coating in the field when having free access to the coating, e.g. prior backfilling the pipe trench or after excavation of the pipe, and the check during the operation of the pipe in the buried condition. When checking the quality of the coating onsite hav- ing free access to the coating, e.g. in the trench, there a lot of non-destructive as well as destructive methods available, that are listed in the respective standards of the different coatings, e.g. mill coatings or field applied coatings. The most important methods in the field are the following Non-destructive tests: • Visual inspection • Thickness measurement • Electrical holiday detection • Electrolytic holiday detection Destructive test: • Coating adhesion test • Peel strength testing • Shore-D measurement for material hardness • Chemical analysis According to our knowledge, a direct check of the qual- ity of the coating in the buried condition is not possi- ble up to now. However, there are methods available to get an indirect impression of the quality of the existing coating, i.e. either detecting a reduction of the pipe wall thickness or detecting coating defects. These methods include internal inspection techniques such as in line inspection tools, or above-ground non-intrusive techniques such as direct current voltage
Pipeline Technology Journal - 3/2022 ask the experts 45 gradient surveys (DCVG), alternating current voltage surveys (ACVG) and close-interval potential surveys. partial pressure. This can be a complicated asset spe- cific analysis, but we are finding that some systems may be compatible nearly as-is, with minimal modi- fications, while some may require modification or up- grading of certain components, whereas other systems may not be feasibly converted without significant up- grades and costs associated. Q3) How do pipeline coatings interfere with cathodic protection systems ? Answer: A functioning and coordinated active and pas- sive corrosion protection are decisive for the lasting integrity and failure-free functionality of a newly in- stalled steel pipeline as well as for the achievement of its intended and planned service life. Passive corrosion protection includes all measures which achieve a shielding/protective effect against corrosive media. This can be attained e.g. by an appro- priate selection of anti-corrosion coating as well as de- sign features. The function of a coating is to separate the metal surface to be protected from the surrounding corrosive medium (electrolyte) with respect of mass as well as charge transfer. Such the formation of corro- sion cells is inhibited. In the case of cathodically protected pipelines any coating is the First Line of Defence. Cathodic Protection (CP) will act as a Second Line of Defence in the event a defect occurs in the corrosion prevention coating. For technical and economic reasons pipelines are usu- ally protected by a combination of active and passive corrosions protection. This combination has proved its value for many decades. It is generally accepted that the effect of cathodic pro- tection is based on the activation polarization and the concentration polarization of the steel surface result- ing in an increase of the pH at the interface between steel and soil. This increase in pH-value may affect the adhesion of the corrosion prevention coating in the immediate vicinity of the defect. The criterion of ca- thodic disbondment (CD) is therefore part of all serious standards for the corrosion protection material of steel pipelines laid in soil and water in conjunction with CP. Interestingly, the effects of the alkaline environment on layered corrosion protection materials - e.g. poly- meric tapes or shrinkable sleeves- have not been the subject of normative considerations yet, although pos- sible damage to the coating material by alkali – here layer to layer adhesion - may pose a significant risk to the pipeline. The same applies for the often-neglected parameter of the shape stability. As long as the delam- inated coating rests tightly on the steel surface in the form of a tube (shape stability), no corrosion problems occur. Corrosion can only occur under delaminated coating if a relevant volume is able to push in between the coat- ing and the pipe surface. In other words, if the coat- ing is not dimensional stable or has lost the shape sta- bility, a relevant volume is able to push in between the coating and the pipe surface. As a result, galvanic el- ements are formed in combination with heterogenic aeration (oxygen concentration gradients) resulting in an enhanced local corrosive attack, e.g. crevice cor- rosion, despite of the low oxygen permeation through the coating. In the case of a very low shape stability one even could expect, that a very large and continu- ous volume between the coating and the pipe surface is formed- in a worst case leading to a flow of oxygen containing water between the coating and the pipe surface. If the coating parameters layer to layer adhesion and shape stability degrade due to a high pH, i.e. pH > 10, the coating loses its functionality. This is independent of the origin of the high pH, e.g. effect of cathodic pro- tection or the use of fluidized soil. Q4) Do you believe that organic coatings (epoxy etc.) applied inside the pipe would prevent or slow the hydrogen ingress into the steel pipeline ? Answer: The diffusion processes of hydrogen differ ele- mentarily for organic coatings and for steel. Therefore, the comparison of the diffusion coefficients of hydro- gen for these materials is not sufficient to enable a re- liable answer to the question. In the case of organic coatings hydrogen diffuses molecular through the porous material, whereas in the case of steel individual hydrogen atoms diffuse through the metal lattice. This implies in a pre-step the dissociative adsorption of hydrogen leading to ad- sorbed hydrogen atoms. For this adsorption process free iron atoms are needed at the surface.
46 Pipeline Technology Journal - 3/2022 ask the experts On the one hand these iron atoms at the surface can be partially covered by the epoxy coating, whereas in the absence of an epoxy coating iron oxide layers are formed and therefore the number of free, reactive iron atoms is also limited. To what extent an epoxy coating influences the rate of adsorbed hydrogen atoms is still the subject of current research and not clarified. Finally, we have to state, that due to the described mechanisms a simple comparison of the diffusion co- efficients of hydrogen for the different materials is not helpful, in fact it may be misleading. Q5) Why are there 2-ply and a 3-ply plastic tapes and what is their difference? Answer: Corrosion prevention tapes and tape systems, made of a combination of i.e. Polyethylene (PE) and Butyl rubber have been on the market for over half a century and have established themselves as the lead- ing quality solution. Out of a wide range of possible combinations, the usual distinctions are between 2-ply and 3-ply tapes. 3-ply tapes are used as corrosion prevention tapes and are wrapped around the pipe as the primary protective layer. Those 3-ply tapes are made of three layers: from the top to the bottom: “compound” – “carrier film” – “com- pound”. The top and bottom layers can be symmet- ric (same thickness) or asymmetric (very thin layer on the top and thicker layer on the bottom). Due to strong amalgamation of the compounds (butyl rubber) at the overlap area, 3-ply tapes form a homogenous sleeve type coating with no path for water and oxygen and with superior adhesion between tapes layers. A thick compound layer at the bottom for instance ensures best coverage: cavities and picks on the steel surface are protected. 2-ply tapes made of PE/butyl rubber should only be used as additional mechanical protection on top of 3-ply tapes. 2-ply tapes consist of two layers of material: the top laser is called “carrier film” and the bottom layer is called “compound”. If the carrier film is made of Polyethylene and the compound is made of butyl rubber, the 2-ply tape wrapped onto a 3-ply tape perfectly bonds to the outer compound of the 3-ply tape. In combination, this tape system provides very good corrosion prevention and mechanical resistance. 2-ply tapes can also be made of Polyvinyl chloride (PVC) as carrier film and bitumen. However, no bitumen is used to manufacture 3-ply tapes. When using 2-ply tapes as only solution for corrosion prevention, the risk of spiral corrosion occurs as there is no amalgamation between the carrier film and the compound. Q6) Are there different ways in producing corro- sion prevention tapes? Does it have an influence on quality? How can you test the difference? Answer: Tapes are made of different materials that are interlinked by lamination or coextrusion during the production process. All lamination technologies have in common that at least one layer has already cooled before it its covered by an- other layer: a material is applied to a cold, solidified carrier film, which adheres to the carrier material like gluing. The different layers create a bond but are still independent from each other. In coextrusion technology, different materials are present in molten form during the joining and bond- ing process. The different melt streams flow into a multi-layer common die through different channels. Along the flow path, the individual melt flows – and therefore the macromolecules of the molten materi- als – are increasingly combined with each other and mixed to the extent that they penetrate into each other generating at the end of the process one single material line that consists of several layers. The bond established between the materials is so strong that it can be compared to welding. The carrier and the coating material form one indivisible unit. As a result, the tape cannot be separated into its indi- vidual functional layers, as it might be the case with laminated tapes. Compared with laminated tapes, co- extruded tapes show higher layer to layer adhesion and stronger lap shear resistance which ensure out- standing sustainability in the long term. As a simple test to distinguish between a laminated tape and a coextruded tape we recommend to immerse a piece of tape into petrol for a minimum of 2 hours. If the residual adhesive is easily removed and the carrier film is smooth or glossy, you can assume a lamination process. If the residual adhesive can only be removed with strong mechanical devices, you can assume a coextrusion process.
Pipeline Technology Journal - 3/2022 ask the experts 47 avoiding waste. Likewise, no substances or solvents that are hazardous to health should be used. If, in ad- dition, the work steps for the applicator are reduced and no additional equipment (such as gas flame or UV lamps) must be used, this not only improves the work- ing environment but also the protection of people. Innovative developments based on high standards ful- fillment of ISO 21809-3 and EN 12068, like a tape appli- cation without primer and just one wrap to secure cor- rosion and mechanical protections at the same time, are recently introduced to the market. This represents a milestone in the development of sustainable and safe corrosion protection solutions. The Experts Dr. Thomas Löffler, Head of the Competence Centre Corrosion Prevention, DENSO Thomas Löffler holds diploma and Ph.D. in chemistry, special- ization in electrochemistry. He has over 17 years’ experience in chemical engineering, electrocatalysis and mainly in corrosion protection. He also worked at E.ON Ruhrgas (today OGE) and was responsible for the issues of passive corrosion protection. At DENSO Group Germany he is the head of the Competence Centre Corrosion Prevention. He is a member of several na- tional and international working groups of DVGW, DIN, EN and ISO and author of various scientific publications. Luc Perrad, International Sales Director, DENSO Luc Perrad has a master’s degree in civil engineering – spe- cialization in Electronics & Mechanics. He has over 14 years’ experience in sales and marketing of field applied pipeline coatings in Western Europe, Africa and the Middle East. His functional experience includes marketing, strategy appraisal, due diligence and business management in sales of cold ap- plied polymeric tapes, liquid epoxy coatings, heat shrinkable sleeves, visco-elastic tapes and mesh backed tapes. He joined DENSO Group Germany in 2019 and took over the position of International Sales Director in March 2021. Luc Perrad is NACE Coating Inspector Level 2 since February 2014. With each issue of the journal, the "Ask the Experts" section focuses on a new topic of particular relevance to the pipeline industry. People from the international pipeline community are invited to send in their questions which will afterwards be answered publicly by selected experts from the respective field. This issue's partner Q7) How does pipeline surface preparation and coatings application determine the success of coating? Answer: This question is related to field-applied coat- ings where application conditions are more difficult to ensure and verify in comparison to factory applied coatings. Surface preparation includes cleanliness (from dust, grease, etc.), surface profile (anchor pattern), and moisture (rain, fog or condensation). Cleanliness and moisture affect adhesion, whilst the surface profile af- fects cathodic disbondment. Coatings application conditions depend on the coating type: • Heat shrinkable sleeves need enough heat, including preheat and post-heat, as well as avoiding trapped air under the sleeve. • Liquid coatings need the correct mixing ratio, proper application thickness, and enough curing between the different passes. • Tapes need enough tension and constant overlap, both of which are generally easily secured by a man- ual or motorized wrapping machine. The vast majority of coating failures that occur on-site are not caused by intrinsic failure of material proper- ties, but by improper surface preparation and/or in- appropriate application of the coating. Therefore, the human impact on coating failures must be minimized by developing easy-to-apply and failure tolerant coat- ings, ideally with only one work step. A coating system which can be corrected or adjusted during application (also with a machine) is most likely to be the most successful solution. Q8) What is the recent, innovative advancements being made in the pipeline field applied coatings industry? Answer: The challenges in the coating industry are con- stantly increasing with shorter project times, higher standard requirements and still complex application of some products. Besides the permanent protection of pipe sections and weld seams, speed, safety and ef- ficiency are all essential requirements. A very decisive aspect has been added in recent years: sustainability and environmental protection – also in the corrosion protection solutions used. A clear focus is placed on using as little material as possible and
PIGGING PRODUCTS & SERVICES ASSOCIATION • Free technical • Sourcing of pigging information service equipment and services • Independent expert • Buyers’ Guide and advice Directory of Members • Pigging seminars • Training courses PPSA Seminar on Pipeline Pigging at the Ardoe House Hotel, Aberdeen, UK TUESDAY 15TH NOVEMBER 2022 Networking reception in the exhibition area WEDNESDAY 16TH NOVEMBER 2022 Seminar presentations and exhibition Details at https://ppsa-online.com/seminar Registration opens in July 2022 www.ppsa-online.com PO Box 30, Kesgrave, Ipswich, Suffolk, IP5 2WY, UK T: +44 1473 635863 F: +44 1473 353597 E: firstname.lastname@example.org An international trade association serving the pipeline industry
50 Pipeline Technology Journal - 3/2022 company directory Association DVGW - German Technical and Scientiﬁc Association for Gas and Water Germany www.dvgw.de IAOT - International Association of Oil Transporters Czech Republic www.iaot.eu Automation Siemens Energy Germany www.siemens.com Certification Cleaning Coating Bureau Veritas Germany www.bureauveritas.com DNV Norway www.dnv.com TÜV SÜD Indutrie Service Germany www.tuvsud.com Reinhart Hydrocleaning Switzerland www.rhc-sa.ch Denso Germany www.denso-group.com Feromihin d.o.o. Croatia www.feromihin.hr Kebulin-gesellschaft Kettler Germany www.kebu.de Polyguard Products United States www.polyguard.com Premier Coatings United Kingdom www.premiercoatings.com RPR Technologies Norway www.rprtech.com Shawcor United States www.shawcor.com Sulzer Mixpac Switzerland www.sulzer.com TDC International Switzerland www.tdc-int.com TIAL Russia www.tial.ru TIB Chemicals Germany www.tib-chemicals.com Construction BIL - Federal German Construction Enquiry Portal Germany www.bil-leitungsauskunft.de Herrenknecht Germany www.herrenknecht.com Liderroll Brasil www.liderroll.com.br LogIC France www.logic-sas.com MAX STREICHER Germany www.streicher.de/en MTS Microtunneling Systems Germany www.mts-tunneling.com
Petro IT Ireland www.petroit.com Prime Drilling Germany www.prime-drilling.de Vlentec Netherlands www.vlentec.com Construction Machinery Maats Netherlands www.maats.com VIETZ Germany www.vietz.de Worldwide Group Germany www.worldwidemachinery.com Engineering ILF Consulting Engineers Germany www.ilf.com KÖTTER Consulting Engineers Germany www.koetter-consulting.com Inspection 3P Services Germany www.3p-services.com Ametek – Division Creaform Germany www.creaform3d.com Baker Hughes United States www.bakerhughes.com Dacon Inspection Technologies Thailand www.dacon-inspection.com Eddyﬁ Technologies Canada www.eddyﬁ.com Pipeline Technology Journal - 3/2022 company directory 51 EMPIT Germany www.empit.com Entegra United States www.entegrasolutions.com INGU Canada www.ingu.com Intero Integrity Services Netherlands www.intero-integrity.com Kontrolltechnik Germany www.kontrolltechnik.com NDT Global Germany www.ndt-global.com Pipesurvey International Netherlands www.pipesurveyinternational.com PPSA - Pigging Products and Services Association United Kingdom www.ppsa-online.com PIPECARE GROUP Switzerland www.pipecaregroup.com Romstar Malaysia www.romstargroup.com Rosen Switzerland www.rosen-group.com Integrity Management Associated Technology Pipeline Ltd United Kingdom www.atpuk.co.uk Metegrity Canada www.metegrity.com Pipeline Innovations United Kingdom www.pipeline-innovations.com
52 Pipeline Technology Journal - 3/2022 company directory Leak Detection AP Sensing Germany www.apsensing.com Asel-Tech Brazil www.asel-tech.com Atmos International United Kingdom www.atmosi.com Fotech Solutions United Kingdom www.fotech.com GOTTSBERG Leak Detection Germany www.leak-detection.de Hiﬁ Engineering Canada www.hiﬁeng.com Liwacom Germany www.liwacom.de MSA Germany www.MSAsafety.com/detection OptaSense United Kingdom www.optasense.com Pergam Italia Italy www.pergamitaly.eu PermAlert United States www.permalert.com Prisma Photonics Israel www.prismaphotonics.com PSI Software Germany www.psi.de SENSOTOP France www.sensotop.com SolAres (Solgeo / Aresys) Italy www.solaresweb.com Materials Monitoring Vallourec France www.vallourec.com Operators Airborne Technologies Austria www.airbornetechnologies.at Fibersonics United States www.ﬁbersonics.com Krohne Messtechnik Germany www.krohne.com PHOENIX CONTACT Germany www.phoenixcontact.com Teren United States www.teren4d.com OGE (Open Grid Europe) Germany www.oge.net Transneft Russia www.en.transneft.ru/ TRAPIL France www.trapil.com Pump and Compressor Stations TNO The Netherlands www.pulsim.tno.nl
Qualification & Recruitment YPI - Young Pipeliners International International www.youngpipeliners.com Repair CITADEL TECHNOLOGIES United States www.cittech.com Clock Spring NRI United States www.clockspring.com T.D. Williamson United States www.tdwilliamson.com Research & Development Pipeline TransportInstitute (PTI LLC) Russia www.en.niitn.transneft.ru Safety Dairyland United States www.dairyland.com DEHN & SÖHNE Germany www.dehn-international.com OVERPIPE France www.overpipe.com Signage Franken Plastik Germany www.frankenplastik.de Trenchless Technologies Bohrtec Germany www.bohrtec.com Pipeline Technology Journal - 3/2022 company directory 53 GSTT - German Society for Trenchless Technology Germany www.gstt.de IMPREG GmbH Germany www.impreg.de Rädlinger Primus Line Germany www.primusline.com TRACTO-TECHNIK Germany www.tracto.com Valves & Fittings AUMA Germany www.auma.com Franz Schuck GmbH Germany www.schuck-group.com Zwick Armaturen Germany www.zwick-armaturen.de Pipeline Technology Journal Further boost your brand awareness and list your company within the ptj - Company Directory www.pipeline-journalnet/advertise
18TH PIPELINE TECHNOLOGY CONFERENCE 8–11 MAY 2023, BERLIN AN EVENT BY #ptcBerlin Connect Share Expand Meet the International pipeline community www.pipeline-conference.com DIAMOND SPONSOR PLATINUM SPONSORS GOLDEN SPONSORS SILVER SPONSORS