World Pipelines - Integrity 2023 by PalladianPublications

2023 2023

AN ANNUAL SUPPLEMENT TO WORLD PIPELINES, FORMERLY ‘COATINGS & CORROSION’ AN ANNUAL SUPPLEMENT TO WORLD PIPELINES, FORMERLY ‘COATINGS & CORROSION’

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CONTENTS WORLD PIPELINES | INTEGRITY 2023

03. Guest comment

Alan Thomas, Chief Executive Officer of the Association for Materials Protection and Performance (AMPP).

05. Editor's comment KEYNOTE: NEW INTEGRITY CHALLENGES 06. The case for full-scale testing

onsidering the variety of threats to pipeline integrity – everything from manufacturing flaws to corrosion to backhoes that unintentionally strike the pipe – being able to detect, identify and size different types of defects and damage is non-negotiable. The key, though, is having the right technology. For decades, inline inspection (ILI) has been a tried-and-true method for keeping pipelines operating safely throughout their lifecycle. After all, you can’t fix what you don’t know exists, and ILI literally provides insight into what’s happening inside your pipeline so you can make repairs and prevent incidents. Traditional ILI systems typically incorporate technologies like geometry (GEO) and magnetic flux leakage (MFL) to gather pipeline integrity data. But when you’re dealing with more complex concerns such as hard spots where cracking might initiate, or material verification which is necessary for determining fitness for service, those tools alone may not provide all the information you need.

For example, while MFL is widely regarded as a stateof-the-art technology for assessing volumetric metal loss, early industry research concluded there’s no clear correlation between the induced saturation magnetic field for a material and its commonly measured mechanical properties, such as yield. In other words, MFL on its own can’t deliver enough information to assign pipe grade, one of the key elements in determining material properties. Adding low-field magnetic flux leakage (LFM) capabilities to your ILI toolkit, however, gives you a more comprehensive picture of your pipeline’s health. At the lower magnetic energy state, minor changes in material permeability can be detected, and that can lead to a more strategic approach to mitigating risk.

Hard spots and hydrogen While most integrity threats occur after the pipeline is installed, hard spots – areas where the material hardness

Dr. Chris Alexander, President and Founder of ADV Integrity, Inc, USA, explains how the use of full-scale testing can help maintain the integrity of pipelines.

PAGE

Matt Romney, Senior Product Manager Global Pipeline Integrity, T.D. Williamson, USA, discusses how low-field magnetic inspection technology enhances general pipeline integrity.

29. ILI with a tethered tool Lance Wethey, ROSEN, USA.

33. Data insights at depth Jim Bramlett, Tracerco, USA.

Figure 1. Full-scale test facility.

Dr. Chris Alexander, President and Founder of ADV Integrity, Inc, USA, explains how the use of full-scale testing can help maintain the integrity of pipelines.

ne of the greatest challenges facing today’s pipeline integrity engineers is determining the threat level a given feature or defect poses to a pipeline system. The process employed by most pipeline integrity engineers starts with inspection measurements made with inline inspection tools or in-the-ditch inspection technologies. If the measured data are deemed a threat to pipeline integrity, an assessment is conducted using either closed-form engineering

PAGE 7

CATHODIC PROTECTION 15. Building it right the first time Cal Chapman, Chapman Engineering, USA.

ILI AND CRACK DETECTION 19. Crack tip diffraction smart pigging

Levi Porter, Seamus Jacobs, and Ryan Caird, Dexon Technology, Thailand.

INTEGRITY AND INSPECTION 24. The hunt for hard spots

PIG TRACKING 35. The new rules for pigging Lauren Westwood, KBL, USA.

DATA AND ANALYSIS 39. Harnessing data potential Jason Rigg, Quorum Software, USA.

MAPPING AND DRONES 41. An advanced aerial solution Didi Horn, SkyX, Canada.

SURFACE PREP AND COATINGS 45. Enhancing pipeline efficiency Chris Johnson, SMB Bearings, UK.

Matt Romney, T.D. Williamson, USA.

RZ-006_Titel_WP_210x297mm_230830-Kleiner.qxp 30.08.23 10:41 Seite 1

2023 2023

AN ANNUAL SUPPLEMENT TO WORLD PIPELINES, FORMERLY ‘COATINGS & CORROSION’ AN ANNUAL SUPPLEMENT TO WORLD PIPELINES, FORMERLY ‘COATINGS & CORROSION’

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GUEST COMMENT

Alan Thomas CEO, Association for Materials Protection and Performance (AMPP) For more industry commentary, listen to the Palladian Energy Podcast

SERIES 2: SUSTAINABILITY IN THE OIL AND GAS SECTOR Episode 3 Sustainability disputes: strategies for managing risk Episode 4 Chemistry at work: sustainability in the oilfield BONUS GASTECH episode Insulating in the extreme Episode 5 Championing ESG in the energy sector Episode 6 Enabling sustainability with automation

orrosion poses a significant and widespread challenge to global pipeline infrastructure, impacting safety, environmental integrity, and the longevity of critical assets. As industries continue to expand and evolve, the demand for efficient and sustainable pipelines becomes increasingly crucial. Corrosion’s consequences are extensive, causing asset degradation, leakages, and costly repairs. According to the National Association of Corrosion Engineers (NACE) 2016 Global Corrosion Costs report, the worldwide direct cost of corrosion exceeds US$2.5 trillion annually. The energy sector, relying heavily on pipelines for oil and gas transportation, bears a substantial share of this burden. The constant exposure to harsh conditions and corrosive substances necessitates innovative and robust solutions. To combat corrosion and enhance pipeline integrity, industry stakeholders focus on advanced materials offering superior resistance. High-strength alloys such as duplex stainless steels and corrosion-resistant alloys (CRA) have gained prominence due to their outstanding performance in aggressive environments. These materials are designed to withstand the corrosive effects of harsh fluids and varying temperatures, prolonging pipeline lifespans and reducing maintenance costs. Additionally, adopting nanostructured materials shows promise in addressing localised corrosion, a common pipeline challenge. Nanocoatings and composite materials exhibit exceptional protective properties, forming a barrier against aggressive substances and corrosive microorganisms. Pipeline coatings are crucial in preventing corrosion and maintaining pipeline structural integrity. Modern coating technologies offer a range of protective solutions. Fusion-bonded epoxy (FBE) coatings, widely used for onshore pipelines, showcase impressive corrosion resistance and mechanical strength. Furthermore, three-layer polyethylene (3LPE) and three-layer polypropylene (3LPP) coatings are popular for offshore applications, providing durability and resilience in marine environments. Innovations in pipeline coatings are also moving towards environmentally-friendly solutions. Developing sustainable, water-based coatings aligns with global sustainability goals, reducing the environmental impact of corrosion prevention practices. AMPP stands at the forefront of facilitating these advancements, with a rich repository of standards, technical articles, research reports, and in-person and online training courses to support stakeholders who protect global pipeline infrastructure. With over 33 000 members across 130 countries, AMPP provides services in accreditation, certification, advocacy, public affairs, standards, research, conferences, education, training, publications, and pre-professional programming. AMPP’s Technical Communities of Interest (TCI) serve as dynamic platforms for discussions and collaboration on pipeline material innovations. These communities enable AMPP members and nonmembers to connect, share experiences, and stay updated on the latest trends. Seminars, workshops, and industry conferences hosted by AMPP, like the upcoming AMPP Annual Conference + Expo in New Orleans next March, offer its global membership opportunities to share research and network with peers. Participating in these events empowers stakeholders to grasp the practical implications of innovations and foster valuable connections. Through its comprehensive approach, AMPP empowers stakeholders to stay informed about innovations and actively contribute to shaping the industry’s future. By embracing the transformative potential of global pipeline material innovations, stakeholders can lead the way toward a more sustainable and efficient future. INTEGRITY 2023 / World Pipelines

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Palladian Publications Ltd, 15 South Street, Farnham, Surrey, GU9 7QU, UK Tel: +44 (0) 1252 718 999 Website: www.worldpipelines.com Email: enquiries@worldpipelines.com Annual subscription £60 UK including postage/£75 overseas (postage airmail). Special two year discounted rate: £96 UK including postage/£120 overseas (postage airmail). Claims for non receipt of issues must be made within three months of publication of the issue or they will not be honoured without charge. Applicable only to USA & Canada: World Pipelines (ISSN No: 1472-7390, USPS No: 020-988) is published monthly by Palladian Publications Ltd, GBR and distributed in the USA by Asendia USA, 701C Ashland Avenue, Folcroft, PA 19032. Periodicals postage paid at Philadelphia, PA & additional mailing offices. POSTMASTER: send address changes to World Pipelines, 701C Ashland Avenue, Folcroft, PA 19032.

read an article recently called ‘The secret life of the 500+ cables that run the internet’ and it opened my eyes to the staggering vulnerability of global subsea cable infrastructure.1 As an industry we know that subsea pipelines can be vulnerable to attack, and subsea telecom cables are no different. Described in the article as the ‘nervous system’ of the internet, subsea fibre optic strands (bundled in cables) transport more than 99% of internet traffic between continents. Despite being housed in tough metal armour, a cable gets cut on average every three days. The usual culprits are ship anchors and fishing equipment, but earthquakes and mudslides also commonly cause damage: SENIOR EDITOR Elizabeth Corner elizabeth.corner@palladianpublications.com Hurricane Sandy cut 11 of the 12 high-capacity cables that connected the US and Europe. As the author of the article, Stephen Shankland, puts it: “As more internet traffic traverses subsea cables, there’s also reason to worry about them. The explosive sabotage last year of the Nord Stream 1 and 2 natural gas pipelines connecting Russia and Europe was much more logistically difficult than cutting an internet cable the thickness of your thumb. An ally of Russian leader Vladimir Putin said subsea cables are fair game for attack. Taiwan has 27 subsea cable connections that the Chinese military could see as tempting targets in an attack.” In the early hours of 8 October, the Balticconnector subsea gas pipeline (connecting Finland and Estonia under the Baltic Sea) recorded a sharp drop in pressure, signifying a rupture and subsequent leak. Damage was sustained to the pipeline and to a neighbouring telecommunications cable. The government of Finland said that it has cause to believe that the rupture was caused by “external” forces. The incident has raised some alarm in Europe, with Finnish officials citing sabotage as the most likely explanation. The Balticconnector’s subsea section runs 77 km across the Gulf of Finland, the easternmost arm of the Baltic Sea, which extends between Finland to the north and Estonia to the south, to Saint Petersburg in Russia to the east. The pipeline was put into service in 2020 to address Finland’s gas isolation, by connecting it to the rest of Europe. With the Nord Stream pipeline blasts still fresh in the memory, suspicion has fallen on Russia, with some analysts suggesting that Russia might have sabotaged the pipeline as ‘retribution’ for Finland joining NATO in April this year. At the time of writing, Finland’s National Bureau of Investigation is looking at a Chinese vessel, Newnew Polarbear, and a Russian ship, Sevmorput, both of which were in the area at the time of the incident. In February this year, NATO announced the creation of a Critical Undersea Infrastructure Coordination Cell at NATO headquarters, to share best practice, leverage technologies and boost the security of Allied undersea infrastructure, bringing “key military and civilian stakeholders together”, in the words of NATO Secretary General Jens Stoltenberg. In addition, NATO has initiated a joint task force with the European Union to protect critical infrastructure. “NATO is stepping up to enhance the security of critical undersea infrastructure,” a statement from NATO headquarters in Brussels said on 10 October. “We have increased naval patrols in the North Sea since the Nord Stream sabotage, and are focusing on technological innovation – including with drones to better detect suspicious activity near underwater cables,” the statement said.2 In response to the damage in the Gulf of Finland, European Commission President Ursula von der Leyen said in a statement that she would “strongly condemn any act of deliberate destruction of critical infrastructure. Our pipelines and underwater cables connect citizens and companies across Europe and to the rest of the world. They are lifelines of financial markets and global trade.”2 This annual ‘Integrity’ issue of World Pipelines focuses on how best to protect pipeline infrastructure from attack, damage and deterioration. A deep knowledge of the ways in which we are vulnerable is key to shoring up defences, against any kind of threat. 1. 2.

https://www.cnet.com/home/internet/features/the-secret-life-of-the-500-cables-that-run-the-internet/?src=longreads https://www.washingtonpost.com/world/2023/10/10/finland-gas-pipeline-leak-sabotage/

Figure 1. Full-scale test facility.

Dr. Chris Alexander, President and Founder of ADV Integrity, Inc., USA, explains how the use of full-scale testing can help maintain the integrity of pipelines.

Figure 2. A burst test to evaluate a crack-like feature.

accompanied with photos from actual tests. Information is also included on the types of equipment and measurement devices that are used in full-scale testing. The goal of this article is to demonstrate the inherent benefits in employing full-scale testing as a means for better understanding and predicting the threat levels associated with certain defects. From a pipeline integrity standpoint, the goal in full-scale testing is replicating conditions that actually exist in the field including pipe material, defects, environment, and loading conditions. The greater the ability to simulate real-world conditions, the more meaningful the results. In this section of the article details are provided on these conditions and elements essential to conducting a successful test. Also included are photographs from prior tests. The closing comments provide a few parting remarks on how a pipeline operator or technology company might apply the concepts contained in this article to their respective operational and business activities.

Types of tests and equipment In the context of pipeline testing there are five different types of full-scale tests that are typically conducted. These are listed below followed with a brief comment on each. Included along with each description are photographs and schematic diagrams.

Burst test In burst testing, pipe samples are normally pressurised to failure. The limit state of the pipe and associated defects are quantified. Strain gages are useful for measuring strain in the base pipe and regions having defects during pressurisation. Burst testing is also an excellent method for validating the performance of repair technologies, including composite repair systems. Shown in Figure 2 is a photograph of a burst test that was used to determine the pressure capacity of a crack-like feature that was compared to burst pressure predictions from a fracture mechanics model. In some standards, such as ASME PCC-2, pressure testing is required as a means to qualify a composite repair system.1

Pressure cycle fatigue test Figure 3. Pressure cycle pumping unit.

equations or numerical modeling techniques such as finite element analysis. This process has been employed effectively for more than 30 years to manage the integrity of high pressure transmission pipelines around the world. In addition to analysis methods, a well-designed and executed full-scale testing programme can provide valuable insights about the true performance characteristics of a defect and help quantify the magnitude of conservatism associated with failure predictions generated by various analysis methods. This article includes examples of full-scale tests that can be used to provide a more complete picture of how defects perform under various loading conditions. Included is a brief description of the types of tests that can be conducted,

8 World Pipelines / INTEGRITY 2023

A pipe sample is pressurised using a pressure cycle pump considering a specific pressure range and number of cycles. Fatigue testing is an excellent method for quantifying future performance of a defect or repair technology when a certain number of cycles are applied to simulate future years of service. Shown in Figure 3 is a photograph of a pressure cycle pumping unit that can achieve approximately 10 000 cycles per day on a 24 in. pipe sample. As with burst testing, pressure cycle testing is also an excellent method for validating the performance of repair technologies, including composite repair systems.

Axial tension testing test To conduct axial tension testing, a load frame is used to pull a pipe sample in tension (or push in compression). Specialised threaded end caps are typically welded to the pipe sample, which are then used to interface with the load frame. Shown

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in Figure 4 is a photograph of a load frame with a capacity to apply 1 million lbs (4448 kN) tension. Also shown is a test sample loaded in the frame.

Bend testing (4-point) Bending testing is useful for quantifying the strain capacity of a pipe sample, often involving girth weld or corrosion features. The advantage of the 4-point configuration is the ability to achieve a constant bending moment between the vertically positioned hydraulic cylinders. This configuration only permits loading in one direction. A 4-pt bend frame with a capacity of 3 million ft-lbs (4.1 million N-m) was used to pressurise a 30 in. pipe with a defective girth weld and was subjected to a bending load of sufficient magnitude to buckle the pipe outside a carbon-epoxy repair system installed over the girth weld.

High strain/low cycle bending test

Figure 4. Axial tension sample in 1 million lbs (4448 kN) load frame.

Figure 5. High strain full-moment bending frame (800 000 ft-lb (1.1 million N-m) capacity).

Certain features can fail when subjected to high strain/ low cycle bending conditions, namely wrinkle bends and girth welds. For this reason, the use of a specialised frame is required to apply a fully-reversible pure bending moment to the pipe sample, permitting bending and compression to be applied to the sample at a relatively fast rate (5 - 10 bending cycles per minute). To achieve this loading condition, a specially designed load frame is used, as shown in Figure 5, where a pair of hydraulic cylinders are used to apply a pure bending moment to the pipe sample. This bending frame has a capacity of 800 000 ft-lb (1.1 million N-m). In this particular test a pressurised wrinkle bend sample was tested to generate an axial tension strain of +/- 1% in the wrinkle, resulting in a failure after approximately 100 cycles were applied. The same test was conducted involving a wrinkle reinforced with an E-glass composite repair system that increased the number of cycles to failure to almost 1800 cycles. Many of these tests are relatively simple in nature to conduct with the right equipment and well-trained personnel; however, it is critically important that test engineers be cognisant of energy levels associated with certain loading conditions and take the necessary precautions to ensure personnel and equipment are safe at all times. Although not a major focus of this article, safety should be the number one goal of any company conducting full-scale testing. This means only experienced personnel with the appropriate testing equipment should be in charge of full-scale test labs and conducting tests.

Defect creation

Figure 6. The installation of an EDM notch.

10 World Pipelines / INTEGRITY 2023

Because there are a limited number of real-world features that are available for experimental assessment, testing often requires the creation of simulated features and defects. An important advantage in creating features is the ability to construct a well-defined test matrix that includes variations of key variables, including corrosion depth and length, dent depth, and crack depth and length. Corrosion features can be fabricated using conventional machining techniques, use of electric discharge machining

particular defect fails, such as a circumferentially oriented crack-like feature? ) Strain capacity – what is the maximum strain that can

be achieved before a particular defect fails, such as a circumferentially oriented crack-like feature?

Instrumentation

Figure 7. Clip gage used to measure EDM notch opening.

(EDM), and chemical etching that can generate a pitted profile. Dents are fabricated by pressing an indenter into the pipe to a prescribed depth, often with pressure in the pipe during the denting process to ensure a representative level of plasticity is generated in the dent. There are several techniques for fabricating axial cracks, although one of the most repeatable involves the installation of an EDM notch into the pipe wall, followed by limited pressure cycling to generate a crack at the base of the notch. A photograph of an EDM machine is shown in Figure 6. Also, girth weld defects have been created by grinding out a portion of the root pass during weld fabrication or in the case of an existing girth weld, using an EDM notch to generate lack of penetration or incomplete penetration features.

Performance metrics One of the most important and challenging elements in using full-scale testing as a means for establishing the structural integrity for a pipeline is determining what constitutes success. From a full-scale test numerous values can be extracted including burst pressure, number of cycles to failure, magnitude of bending required to generate a leak in a defective girth weld, strain in a dent during pressure cycling, and reduction in tensile strength in a composite as a function of temperature. The test engineer is required to synthesise the results from a test in a meaningful way that can be used to manage the integrity of a pipeline defect. Listed below are some of the more important performance metrics that are used in full-scale testing: ) Burst pressure – what is the maximum pressure that can be achieved before a particular defect fails such as a corrosion or crack-like feature? ) Fatigue life – what is the maximum number of pressure

cycles that can be applied before a particular defect fails, such as a dent or crack-like feature?

An important use of full-scale testing results is validating numerical models. A criticism sometimes levied against numerical models is embodied in the saying, “All models are wrong, but some are useful.” The use of full-scale testing helps to calibrate numerical models and ensure their results align with real-world conditions. In order for useful measurements to be extracted from a full-scale test, testing engineers must identify what measurements need to be made and determine the instrumentation required for making those measurements. Listed below are some of the devices commonly used in full-scale testing, along with a brief commentary. ) Strain gages are one of the most useful devices in testing, especially when correlating results with numerical models is required. The key is knowing where to locate strain gages to ensure maximum strains (or stresses) are measured. ) A clip gauge is a device used to the measure crack tip

opening displacement (CTOD) of sub-scale samples in fracture mechanics, but this device can also be used to measure the opening of EDM notches during pressure cycling as shown in Figure 7. Clip gauges can also be useful for controlling the pressure cycle pump by terminating cycling when measurements are made indicating a crack has formed at the base of the EDM notch. ) Displacement transducers make displacement

measurements and are useful for applications where elevated strain conditions exist (greater than 0.5%). In one study where tensile loads were applied to generate strains greater than 3%, displacement transducers were used to calculate strain values after strain gages disbonded. ) Load cells can be used for a variety of applications, but

they are often used to measure contact forces between two bodies under load. ) Pressure transducers are an essential element in pipeline

testing. They are used to measure burst pressures, but also play a critical role as instruments in controlling the applied pressure ranges to a fatigue sample. They are additionally used with hydraulic cylinders to measure pressures that are then used to calculate applied loads (i.e., force equals piston area times hydraulic pressure). ) Thermocouples are used to measure temperature. Most

) Tension and bending load capacity – what is the

maximum applied load that can be achieved before a

12 World Pipelines / INTEGRITY 2023

testing for pipeline applications is done at ambient conditions; however, the author has tested pipe fittings

destructive tests. Provided in Figure 1 is a photograph showing an inside view of the test lab where all of the tests presented in this paper have been conducted.

down to -51°F and composite reinforcing materials up to 250°F. ) Data acquisition (DAQ) systems are used to capture

data made by the above instruments and measurement devices. DAQ systems play a critically important role in generating data that is eventually post-processed for test reports, but can also be used for controlling equipment such as pumps and load frames.

Conclusion

The pipeline industry has used full-scale testing since its inception. Even before numerical models and analytic solutions were developed, design and metallurgical engineers learned that pipe materials have limits and the best way to determine those limits involved pressurisation or loading to failure. An excellent example of the use of full-scale ) General test lab equipment including cranes, pressure testing involved the seminal work conducted by A.R.C. test containment boxes and other assorted pieces of Markl in the 1940s and 1950s as an employee at Tube Turns equipment are essential to safely conduct full-scale that resulted in the development of Stress Intensification Factors for pipe fittings (elbows and tees) ® that are still in use today.2 Another example is the extensive burst testing on corroded pipe samples Introducing the next generation PosiTector conducted by John Kiefner that led gauge body for all your inspection needs. to the development of ASME B31G, RSTRENG, and other calculation methods for assessing corrosion.3 All Gauges Feature... Throughout the last 20 years, over n NEW Larger 2.8” impact resistant color touchscreen 1000 full-scale burst, pressure cycle, with redesigned keypad for quick menu navigation axial tension, and bending tests have n NEW On-gauge help explains menu items at the touch been conducted by the author and of a button others, that have contributed to n NEW Weatherproof, dustproof, and water-resistant the world-wide use of composite —IP65-rated enclosure reinforcing technologies. n NEW Ergonomic design with durable rubberized grip Full-scale testing has and will n Shock-absorbing protective rubber holster for added continue to contribute significantly impact resistance to our understanding on the n Two year warranty on gauge body AND probe capabilities and limitations of pipe n Conforms to national and international standards materials, repair systems, and other including ISO and ASTM pipeline-focused technologies. A n NEW Auto rotating display with Flip Lock well-designed, instrumented, and n NEW Screen Capture—save 100 screen images for record keeping and review executed full-scale test can provide valuable insights for design and integrity engineers charged with the responsibility of constructing and maintaining safe pipelines. With the ageing pipeline infrastructure around the world, the use of full-scale Customized Inspection testing will continue to play a critical Kits... Build your own kit from role in maintaining the integrity a selection of gauge bodies and of pipelines and ensure that probes to suit your needs. appropriate levels of conservatism exist in their operation.

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References

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1. ASME PCC-2, Repair of Pressure Equipment and Piping, published by the American Society of Mechanical Engineers, 2002. 2. MARKL, A. R. C., Fatigue Tests of Welding Elbows and Comparable Double Miter Bends, Trans. ASME, Vol. 69, 1947, pp. 869-879. 3. KIEFNER, J. F., Final Report on Continued Validation of RSTRENG, Prepared for the Line Pipe Research Supervisory Committee, Pipeline Research Committee of PRC International, January 1, 1996.

nderground carbon steel pipelines are, and will continue to be, the transportation mode of choice for many crude oil, natural gas, and other petroleum and petrochemical products. Similar underground or submerged metal pipelines are often used, too, for water, wastewater and other liquid or gaseous products. Taking one famous (indeed, iconic) pipeline as a discussion point, the 48 in. nominal diameter (122 cm) crude oil Trans-Alaska pipeline was put into service in August 1977, spanning a total length of 800 miles (1288 km). Now 46 plus years old in terms of active service, the original pipeline design was for 30 years of useful life. It has thus far performed for 50% more years than originally intended. Is this asset being sustained? Is it being operated in a sustainable fashion and, even now, for a long-term service outlook? This certainly seems to be the case.

The cost of corrosion The pipeline industry over the last 30 years has greatly improved the general principles and practices that encompass asset integrity management. What is the motivation to do so? The first, and obvious motivation, is to avoid the need for complete asset removal and replacement. A study by NACE International (now called ‘Association for Material Protection and Performance [AMPP]’) released in 2016 described that the annual cost of corrosion damage across the globe was in the range of US$2.7 trillion.1 This was true even though some industries were using corrosion control measures quite effectively. If, in 2016, the world’s gross economic product produced was close to US$90 trillion, one could say that all metal infrastructure would need complete replacement every 30 years without significant asset integrity management practices in place. Proper coatings on metal structures is one obvious protection method, which some industries do very well, and others may not do so effectively.

Cal Chapman, Chapman Engineering Inc., USA, argues that pipeline integrity management, and especially cathodic protection, is sustainability work.

The cost of operation A big motivation for asset integrity management is, therefore, to properly maintain the asset, thereby avoiding the much larger costs of failure events, shutdowns, major repairs, or even replacement. Often the operator is looking to manage or reduce costs of operation, even as the asset is put into performance at a higher output, or efficiency, and for longer service life.

applied effectively, so that any poorly coated locations, or spots where coating was scraped away or otherwise damaged, are adequately protected against aggressive external corrosion. External corrosion control is virtually always said to be good coatings, first, and complemented by good cathodic protection. Any other approach is doomed to be too expensive to achieve when it’s complex, or too risky when it is ‘skimpy’.

Cathodic protection Cathodic protection systems, for longer and larger diameter pipelines, are almost always of the impressed-current type. These typically use an AC power supply that feeds a transforming rectifier (most often called just a ‘rectifier’). The rectifier converts AC power to DC power, and then pushes positive DC current to a set of anodes. The Figure 1. Author’s photo at Coldfoot Camp during pipeline construction, March 1976. negative DC output of the rectifier is connected to the metal structure needing protection. Current flow from the anodes, which themselves corrode over Other goals might be to improve safety of an operation, or time, travels through soils and water (whether moisture in soils to gain energy efficiency – and in such ways, reduce operating risk and geology, or even through water bodies) to come onto the or cost, or both. It has sometimes been government regulation structure needing protection. This delivery of current to exposed that has brought the operational improvements, risk reductions, metal in soil/electrolyte contact either greatly diminishes or even and improved safety profiles. Pipeline regulations in the US and eliminates external corrosion reactions. other jurisdictions have periodically been expanded and tightened, Because cathodic protection system anodes are always and frequently in response to high-visibility, high-cost accidents consuming with time and current production, they must be occurring. replaced periodically. Proper design and construction of each The Trans-Alaska pipeline project, first publicly proposed new or replacement anode bed is critical to ensuring that the around 1970, did not get US Congressional approval for high-value structure is continually protected from external construction until 1973, and only after a major piece of federal corrosion damage. In this way, the timely replacing of cathodic legislation was passed. That legislation laid out requirements protection system anode beds, and maybe other components, for complex environmental studies and plans for mitigation of is how below-grade, very valuable metal structures are sustained negative effects to caribou herds, to permafrost soils, and water for long service lives, at lower maintenance costs, and hopefully quality protection, among other requirements. Some risk was avoiding expensive failures, shutdowns, and repairs, or major asset related to the many river and stream crossings required along replacements. the 798 mile (1285 km) route. Thanks to the driving need for A word of caution: not all cathodic protection designers high-quality environmental protection over time, this project’s and construction companies are alike. Our experiences of successful execution led to many improvements in pipeline and the last 20 years, if not longer, show that pipeline owners and pump station designs, and in complex construction/installation operators should purchase such services and systems with more practices in remote, difficult terrains. requirements than just ‘low bid wins’. It is fairly simple to go and This one amazing pipeline example helps to illustrate several take measurements on a newly installed cathodic protection major points. The first is that, once a pipeline is constructed and system and see if the anode bed is going to last the required goes into operation, many parties have an interest in keeping the 15 or 20 years of expected life. In many cases, we assess recent pipeline operating. The biggest costs are field studies and design, cathodic protection installations, and have to tell the owner: “This and then the massive capital investment for installation and may give you five years. Three-quarters of your investment got startup. Once product is flowing, the asset is delivering monetary thrown away.” Our recommendation is to get a strong design firm return on the investment. And because most pipelines serve a involved at the front end, one that produces good design and long-term purpose, or even get repurposed for a different product specification documents; in some cases, the pipeline operating after some time goes by, few people want to shut in and abandon companies have this kind of strength under their own roof. With the typical large diameter pipeline. that set of documents, they should then require contractors to provide a bid package that includes qualifications and experience Keeping pipelines healthy for key contractor field and management personnel; satisfied/ How are pipelines kept healthy over time? Some methods happy business references related to prior work; and then the are used to protect the insides of pipes from corrosion, from project pricing. A choice of contractor can then be made by getting filled up with gunk or water dropout in the wrong places, combining strength of experience and qualifications, testimony etc. To control external corrosion, good coatings must first be from satisfied customers, and the pricing. Low-bid-only choices installed with the asset. Then, cathodic protection must be

16 World Pipelines / INTEGRITY 2023

IT IS MY DEDICATED PASSION for pipelines that compels me to partner with others in the industry, share best practices and collaborate on ideas for future innovations and advanced applications.

It is who I am. I am a pipeliner.

We are pipeliners too. We share this passion and, like you, we are committed to keeping pipelines running safely and reliably. By providing top-of-the-line tools to address your threats, and applying the most advanced assessment techniques, we ensure you get the best return on your pipeline asset, both economically and environmentally. The world counts on you. You can count on us.

critical sustainability practices to use in this process of maintaining the asset. The Trans-Alaska pipeline project was originally estimated, in 1974, to be a US$3 billion project to complete. By the time it was commissioned and began moving crude oil, total costs were said by some to be closer to US$10 billion. What would it cost today to build, or rebuild, the pipeline? To even think about calculating the number is mind-boggling, never mind what the regulatory requirements might be. To maintain it and keep using it is downright affordable, by comparison, as long as it has usefulness!

Postscript I was fortunate enough to drive trucks on the Trans-Alaska Pipeline project, as a member of the Teamsters Union at the time. From August 1975 to April 1977, minus a couple of winter breaks, I lived along stretches of the pipeline from Old Man Camp to Dietrich Camp (all north of the Yukon River), and then up to Pump Station #2. I drove the Haul Road and put loads down along the pipeline right-of-way from the Yukon River to about 30 miles south of Prudhoe Bay. In December 1975, I worked one day at -52˚F, along the Middle Fork Koyukuk River (photo, p.15). After my last layoff, I went to university, and chose mechanical engineering as my degree plan, partly because I had been eyewitness to so much incredible engineering and construction process work, in one of the most beautiful, yet harshest parts of the world. Another interesting point: I learned trucking, heavy equipment, a little about pipeline welding, pipeline bedding and backfilling, and so many other things from older, very experienced workers! I did not hang out with any engineers, surveyors, or geologists, though I saw them at dinner on many nights in the camps. I learned from technicians, labourers, operators, oilers, welders, welders’ helpers, and even post office clerks! Maybe that’s why I know to rely today on great technicians and helpers out in the field. Without them, I can’t be a good engineer. Finally, I was able to take my family to Alaska in the summer of 2012, and drove them up the Dalton Highway (what I knew years ago as the pipeline ‘Haul Road’) to the Arctic Circle. They got a tiny taste of what I was doing many years before, and gained some appreciation for this incredible Trans-Alaska pipeline structure.

Figure 2. Author’s photo of public storyboard at Yukon River crossing, Trans Alaska pipeline route, July 2012.

Figure 3. Author’s photo of Trans Alaska pipeline ar Yukon River crossing, July 2012.

can be dangerous. One of the quotes we frequently use is, “How much does it cost to do the job right the second time?” One judgment asset owners are likely making, and then revisiting over time, is: “How long should we maintain this asset? Is there another way it can benefit us, and/or the general public, compared to what it is now doing?” The North Slope of Alaska and the shallow continental shelf of the Arctic Ocean are known to host large reserves of natural gas, as well as remaining crude oil reserves. Methane hydride formations contain yet more natural gas that may become a usable resource in the future. It is in the pipeline owner/operator’s interest to take good care of the TransAlaska pipeline for decades to come, based on what we know at present. And cathodic protection systems plus related surveys are

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References 1.

NACE 2016 IMPACT Study, Cost of Corrosion.

Further reading

https://ascelibrary.org/doi/abs/10.1061/40621%28254%2910 https://ascelibrary.org/doi/10.1061/40621%28254%2911

Figure 1. An 8 in. UT-CS Hawk ILI undergoes final testing prior to an inspection run.

Levi Porter, Seamus Jacobs, and Ryan Caird, Dexon Technology, Thailand, discuss high-density sensor array and angle beam tip diffraction intelligent pigging for the detection and sizing of cracks and crack-like features. ipelines play a crucial role in the safe and efficient transportation of oil, gas, and other hydrocarbons over long distances. However, like all infrastructure, pipelines are susceptible to defects that can compromise their integrity and pose risks to the environment and public safety. Detecting and addressing these defects early is essential to prevent costly and potentially disastrous consequences. Oil and gas pipelines are prone to various defects that can affect their structural integrity and cause failures, posing a threat to human lives and the environment. Defects can be categorised into the following groups: corrosion, geometric anomalies, and cracking and crack-like features.

The objective Dexon Technology (Dexon) set out to develop a market-leading smart pig for the detection and sizing of sub 1.0 mm cracks and

crack-like features in pipelines, combined with high-resolution wall thickness measurements.

Cracking in oil and gas pipelines Cracks are a common problem in oil and gas pipelines, reducing their ability to withstand pressure. Cracking can be caused by a variety of factors including mechanical stress, corrosion, fatigue, and external forces leading to structural integrity issues. Detection and repair of these defects are crucial before they lead to significant damage or catastrophic failure. While current technology allows for the accurate detection and measurement of corrosion and geometric anomalies, tools for the detection and sizing of critical cracking have been less developed. The issue is exacerbated by the need to detect cracking in the early stages due to the rapid increase in growth rates as the anomaly enlarges. Cracks often form at the site of

pre-existing flaws and grow during operation. For example, fatigue crack growth can occur due to cyclic applied loading or hostile chemical environments. Factors affecting growth rate can include pipe material, material condition, mechanical forces, pressure, temperature, and product. Integrity assessments may forecast defect growth rates using mathematical algorithms. However, these assessments require highly accurate crack dimensions. Figure 2 shows how the crack growth rate increases as the crack size increases. This is because the stress intensity

Figure 2. The crack growth curve depicts the crack size (a) as a function of the applied load cycles (N). The instantaneous slope of this curve is represented by da/dN, which indicates the rate of crack growth.

factor at the crack tip is dependent on the crack size, with the crack continuing to grow until it reaches a critical size, leading to the failure of the asset. The crack grows very slowly in the initial stages, with growth accelerating substantially as the size of the crack increases.

Intelligent pigging Smart pigging (pigs) uses non-destructive testing (NDT) techniques via specialised tools to internally evaluate the condition of a pipeline. Pigs are commonly propelled through pipelines using the flow of transported products and are able to cover hundreds of kilometres in a single inspection. When compared to traditional methods of pipeline inspection, intelligent pigging can offer several advantages in terms of accuracy, speed, and cost-effectiveness. Conventional NDT techniques are limited to accessible areas of pipeline or dig sites. Inline inspection (ILI) enables pigs to examine vast underground pipe sections as well as areas covered by coatings or insulation, allowing for a comprehensive examination. Without the use of ILI, these pipe sections would be inconvenient to inspect, requiring excavation for manual inspection which poses logistical difficulties and increased costs. The three most common technologies used in pigging are ultrasound, magnetic flux leakage (MFL), and geometric ILI. Ultrasonic (UT) pigs utilise high-frequency sound waves to

Figure 3. Graphic representation of varying circumferential sampling resolutions (10 mm x 1 mm, 5 mm x 1 mm, and 1 mm x 1 mm).

Figure 4. Ultrasonic sampling resolutions compared.

20 World Pipelines / INTEGRITY 2023

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Table 1. The number of data points collected at the following sampling resolutions are as follows, 10.0 mm x 1.0 mm - 100 000, 5.0 mm x 1.0 mm - 200 000, and 1.0 mm x 1.0 mm - 1 000 000

detect and measure wall thickness, cracking, and geometric anomalies. MFL uses powerful magnets and triaxial hall sensors to detect changes in wall thickness, while geometric smart pigs use a series of mechanical arms that measure geometric anomalies and changes in pipe ovality.

The solution: ultra high-density sensor array To achieve this objective, Dexon’s R&D team designed a highdensity sensor array with a combination of angle beam and pipe thickness transducers. Dexon’s UT-CS Hawk ILI system uses an arrangement of both zero-degree transducers for the collection of wall thickness measurements and angle beam/ shear transducers (angled around the circumference of the pipe) for the collection of angle beam tip diffraction crack data.

High-density sensor array and sampling resolution A high-density sensor array was used to increase sampling resolution and in turn the accuracy of detection and sizing capabilities. A total of 768 specially designed transducers were used in the development of the initial 8 in. pig, producing a sampling density of 1 000 000 direct measurements per m2 of piping.

Circumferential and axial sampling density Table 1 illustrates the number of data samples generated based on the axial and circumferential sampling distribution. The probability of detection and accuracy of sizing are directly related to the number of data samples collected for a given defect. When measuring axial defects, the axial sampling rate (data samples along the length of the pipeline) directly correlates to the measurement of defect length,

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while the circumferential sampling rate directly correlates to the accuracy of through-wall height measurement in axially oriented cracking. Figure 3 shows a graphic representation of clockwise and anticlockwise angled circumferential sampling density. As the number of circumferential samples is increased and the distance between samples is reduced, the sampling resolution is increased. Axial sampling density is directly dependent on tool speed which is set in accordance to pipeline operating conditions and client inspection requirements. Increased pig velocities result in a possible reduction of axial sampling rates if acquisition electronics are unable to compensate.

Probability of detection and dimensioning As sampling density increases, the probability of detection and accuracy of sizing also increases. The three graphics in Figure 4 show increases in the number of data samples collected for a 3.0 mm simulated seam weld crack as sampling density increases. Improving circumferential sampling from 10.0 - 1.0 mm results in a ten-fold gain in UT data collection. This additional data aids in the analysis of crack dimensions, allowing for greater accuracy in through-wall measurement.

Angle beam tip diffraction As data sampling increases across the face of a crack, the ability to employ tip-diffraction sizing increases. Tip-diffraction has been shown to provide a high degree of through-wall sizing accuracy in comparison to other methods such as amplitude sizing. Amplitude-based sizing methods are highly dependent on defect orientation matching

Figure 5. The image on the left shows ultrasonic shear wave signals entering the pipe wall and returning six direct measurements. The middle image shows A-Scan data points for the six direct measurements collected in Dexon’s proprietary UT data analysis software, Dexon Studio. The image on the right shows each measurement collected in relation to through-wall height.

calibration reflector orientation to ensure sizing accuracy. Angle-beam tip diffraction uses time of flight data from UT sound waves without regard to amplitude. This data shows defect signals recorded from the crack base to the tip as seen in Figure 5. Six individual data points indicate separate geometric reflectors marked by different coloured circles on both the A-Scan data and the graphic representation of the crack. Tip signals appear first due to their closer proximity to the transducer. The difference in time of flight between the crack base and the crack tip can be used to calculate the through-wall dimension of the crack.

Crack inspection verification Inspection verification and testing were performed using natural and artificial defects in an 8 in. test loop at Dexon’s test yard. A test loop system allows a pig to run continuously through a closed loop pipeline, and provides valuable data concerning probability of detection, sizing accuracy, inspection repeatability, tool reliability, and the effect of tool wear on inspection results. Numerous artificial defect shapes were tested including rectangular, elliptical, varying through-wall height, tilted, skewed, ID/OD connected, and multi-angular. In addition, a major oil and gas company provided two natural flaws removed from service piping. These flaws were inspected by Dexon without prior information concerning position, through-wall height, or orientation. Figure 6 and Figure 7 define the shape and orientation of the artificial defects, with all notch dimensions and locations being confirmed by manual inspection.

Verification of detection and sizing results In total, 54 defects were placed in the Dexon test loop. Inspection verification data from these defects show a high probability of detection. All defects with a minimum through-wall height of 0.50 mm were detected, and 94% of all defects were accurately sized to within ±1.0 mm of actual through-wall height. Sizing deviations for all defects produced a minimum of 0.00 mm, an average of 0.49 mm, and a maximum of 1.40 mm. Defects producing the largest deviation tended to be highly tilted. Both natural crack flaws were detected, oriented, and sized within ±1.0 mm. Verification of the natural flaw characteristics was performed with a combination of phased array, full matrix

Figure 6. Rectangular, elliptical, variable, and multi-angular artificial crack defect shapes.

Figure 7. Artificial crack defect through wall height and orientation.

capture, three-dimensional metrology (third party), and macro-etching. Each verification method agreed with the pig inspection results.

Conclusion By notably increasing the sampling density of pipeline inspection, the tip diffraction sizing method can be employed for ILI. The UT-CS Hawk ILI System has produced high-quality UT data, confirming the ability to detect, place, and size defects with a high degree of accuracy. The tip diffraction sizing method combined with high-density sensor arrays proved to be accurate regardless of defect orientation, placement, or through-wall dimension.

INTEGRITY 2023 / World Pipelines

Hard spots and hydrogen While most integrity threats occur after the pipeline is installed, hard spots – areas where the material hardness

Matt Romney, Senior Product Manager Global Pipeline Integrity, T.D. Williamson, USA, discusses how low-field magnetic inspection technology enhances general pipeline integrity.

is greater than the surrounding material – are often there almost from the start. This is because many arise early in the manufacturing process when quenching, the procedure that cools heat-treated plate, is not adequately controlled. Hard spots are susceptible to cracking, especially in the presence of hydrogen. With decarbonisation initiatives expected to increase the volume of hydrogen travelling through existing pipelines in the years ahead, hard spots that have been stable for long periods may become more vulnerable to cracking and its serious consequences. Although hard spots have generally been associated with pipe manufactured by a single mill before 1970, they can

Figure 1. The MDS™ platform performs a holistic inspection of the pipe body and welds in one pass. Low-field axial MFL (LFM) can detect changes in steel permeability, making it a key technology for detecting hard spots.

occur in other pipes too, which makes locating and repairing them more important than ever. Fortunately, LFM technology has a distinct advantage when it comes to detecting hard spots. Like other forms of magnetic flux leakage, LFM magnetises the steel being examined. The magnetic field ‘leakage’ will increase anywhere there is a defect. But unlike traditional high-field MFL technologies, which induce a magnetic field beyond the material saturation point, LFM technology induces a lower magnetic energy state in the pipe wall. At this lower magnetic energy state, characteristics of the pipe material – some of the details whose signals are overpowered by high-field MFL – are visible in LFM data. While often both the MFL and LFM technologies will detect a hard spot, the localised hardened area will have different material properties, so it will react differently to each applied magnetic field. The unique responses between MFL and LFM make it much easier to identify the hard spot and differentiate it from other anomalies. However, LFM isn’t the only sensor technology that is useful in the hunt for hard spots: ) High-resolution GEO measures geometric flat spot features that can occur when the hardened region resists rolling during the pipe formation process. ) High-field axial MFL detects hard spot global response,

allowing for hardness classification (Figure 2). Combining these sensors in systems like the T.D. Williamson MDS™ platform – which can perform a complete inspection of the pipe body and long seam in one pass (Figure 1) – provides the most comprehensive inspection of a pipeline system for integrity threats, including hard spots.

What pipe is this?

Figure 2. MDS data sets for a hard spot, from left: MFL signal results; LFM signal results that show clearer edges of the hard spot compared to the MFL image, providing enhanced length and width sizing accuracy; GEO signal response, which documents a geometric flat spot feature coincident with the MFL/LFM responses, further confirming the presence of the hard spot.

Figure 3. LFM data from multiple joints of line pipe shows striations and patterning that are magnetic permeability artifacts of the pipe material and forming processes. These variations do not represent an injurious pipeline threat but can be used to characterise and group like joints of pipe together for pipeline material verification.

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Being able to mitigate the risk associated with hard spots is an important reason to use LFM technology, but it’s not the only one. LFM also helps pipeline operators tackle a challenging requirement that underpins integrity management: knowing what pipe materials are in the ground. In fact, because of its sensitivity to variations in steel permeability, LFM is considered the key technology for enhanced detection and classification of pipeline material characteristics. Accurate material properties records of pipe diameter, wall thickness, pipe grade and seam type are necessary to validate maximum allowable operating pressure (MAOP) calculations, to ensure worker and community safety, and to protect the environment. And in many parts of the world, they’re the law. In the USA, for example, CFR49 Part 192.607(b) says “Records established under this section documenting physical pipeline characteristics and attributes including: • Diameter • Wall thickness • Seam type • Grade (e.g., yield strength, ultimate tensile strength, or pressure rating for valves and flanges, etc.) These must be maintained for the life of the pipeline and be traceable, verifiable, and complete (TVC).”

Sometimes, though, original material records (and supporting maintenance data) are lost, such as when pipeline assets change hands multiple times over many years. That doesn’t mean the information or compliance is out of reach. By using ILI technologies including LFM, operators can perform the first step in overcoming missing records: collecting and recreating pipeline material characteristics as part of the pipe joint classification (PJC) process. The PJC process leverages the advanced MDS system to characterise and group pipe joints based on similar material properties: wall thickness, seam type, permeability patterning, and joint length. ) LFM is sensitive to minute variations in pipe material microstructure resulting in permeability changes related to manufacturing (Figure 3). ) High-resolution geometry measures geometric features

resulting from rolling and forming during pipe milling and manufacturing. ) High-field axial MFL detects volumetric losses or gains in

the steel, such as wall thickness changes. ) Spiral MFL (SMFL) provides inspection and characterisation

of the long seam. ) Internal/external discrimination (IDOD) is sensitive to

internal surface permeability changes in the radial direction.

By sorting the pipe joints into like groups, it’s possible to determine with a high level of confidence that they were manufactured at the same facility during roughly the same time period, using the same material and processes. The PJC process also enables the operator to identify material record gaps and ‘rogue’ joints, or pipe joints that aren’t reflected in current records. Pipe population discrepancy analysis (PPDA) is a common technique for assessing the differences between historical records and the PJC analysis results. The outcome of the PPDA process can help operators determine when in-ditch testing will be necessary to accurately correlate pipe grade to each pipe joint group.

One platform, many answers Keeping your assets performing safely and reliably is what pipeline integrity management is all about. It’s not an easy task, and there’s no room for shortcuts when so much is at stake. The good news is that using the right ILI technology, like the MDS platform with LFM sensors, can help you detect defects in time to mitigate them. With a single tool deployed just once, you’ll reduce the financial, human and environmental risks associated with hard spot cracking – and also have the information you need to create proper records of seam type, pipe grade and associated mechanical properties.

References 1.

U.S. Department of Transportation. (1998). Variation of Magnetic Properties in Pipeline Steels. Springfield: National Technical Information Services.

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A H T I W I L I o o l t d e r e h t e t

Lance Wethey, Technical Solutions Specialist, ROSEN, USA, discusses inline inspection of unpiggable natural gas pipelines without service interruption.

nline inspection (ILI) has been a critical component of pipeline integrity management for decades. The perpetual innovation of inline inspection tools has allowed pipeline operators to assess the material condition of largely buried pipelines with minimal interruption in service. Free-swimming ILI are introduced into pipeline systems and then propelled by the pipeline’s product flow, gathering valuable data that is reviewed to identify various threats such as metal loss associated with corrosion and external damage. Guided by the resultant inspection defect reporting, pipeline operators can then address these concerns while accommodating efforts to maintain product delivery as well as preventing environmental and life-threatening releases. Since pipelines existed before the introduction of ILI tools, many pipelines had to be retrofitted to accommodate this

inspection method, while newer pipelines are constructed with allowance of ILI incorporated in the initial design. The first natural gas pipelines to enjoy the benefit of ILI were primarily large diameter transmission and distribution assets. Over time, as regulatory requirements expanded, operators sought to inspect additional pipelines, which were once deemed ‘unpiggable’. These included pipelines that had varying diameters, as well as operating conditions that were not compatible with the currently available ILI tools. The industry responded to the demand and developed ILI tools capable of inspecting varying pipe diameters in a single inspection. Further developments included low-friction ILI tool configurations, reducing the differential pressure needed to propel the ILI tool through challenging pipe geometry thereby improving ILI tool inception behaviour in low pressure systems.

a ‘line-pack’ delivery method. This involves the operating maintaining a certain volume of natural gas in a particular segment by ‘packing’ the pipeline to a specific pressure range. As customers draw gas off the line, more gas is introduced from an upstream transmission supply. The pressure limit can be defined by numerous factors, such as customer requirements or even regulatory stipulations. These factors produce transient operating conditions that are incapable of gas pressures and flow rates suitable for propelling a free-swimming ILI tool. If an ILI tool cannot rely upon the product stream for propulsion through a pipeline, alternative methods must be considered if ILI remains the assessment method of choice.

Figure 1. Testing and validation is a key element to the development of new ILI technologies. This image shows the 1.5D 90˚ back-to-back bend test set-up.

Figure 2. The newly developed 8 in. tractor segment.

Figure 3. Dynamometer testing of wheel friction is done to ensure grip to the pipe wall.

Essentially, many pipelines were steadily being stripped of their ‘unpiggable’ moniker due to continual innovations of ILI tool designs. Integrity management demands continue to increase for pipeline operators, thus requiring the capabilities of ILI tools to grow to mitigate the reliance upon assessment methods that involve service interruption such as hydrotesting. In other words, more unpiggable pipeline challenges must be overcome.

Operating conditions not suitable for freeswimming ILI tools create a challenge Natural gas pipelines that deliver gas to customers such as electricity generating plants, factories, and even city gate stations rely upon on

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Considering self-propelled robotics and tethers as a solution Commercially self-propelled robotic axial magnetic flux leakage (MFL-A) ILI tools have existed for more than a decade that are capable of navigation through pipelines and gathering inspection data. The ILI tool is inserted into the pipeline and driven by a tool operator aided by video feed. Furthermore, both wired (tethered) and wireless options exist, each with their own pros and cons. However, options are currently limited if a natural gas pipeline is to remain in-service during inspection. In particular, tethered ILI solution availability suitable for pressurised natural gas pipelines are lagging behind progresses already achieved with wireless solutions. A question that automatically arises when considering tethered robotic ILI tools is, “Why even be concerned with pursuing a wired option if wireless is available?” The answer can depend on the pipeline targeted for inspection. A wireless option may very well be perfectly adequate in many situations, while a tethered option may offer additional contingencies if the need arises. One of the primary advantages of a tethered ILI solution is recovery potential. In the event an ILI tool becomes stationary due to pipeline influence such as debris or mechanical failure of the ILI tool itself, extraction may be facilitated by pulling the ILI tool back to the insertion point. Additionally, wired ILI tool communication is not subject to external attenuation or interference thus ensuring reliable communication. Power constraints are also mitigated. Restrictive pipeline features such as bends with elevation change or uphill travel require more energy to traverse. With a tethered ILI, energy capacity challenges are eliminated, especially if a difficult pipeline obstacle requires numerous attempts to traverse. This discussion would not be complete without also considering potentially negative aspects of tethered robotic ILI solutions. The tether itself introduces certain limitations that must be recognised before being selected for any specific inspection effort. For example, an excessive number of tight radius pipeline bends can increase the friction applied to the tether and limit inspection distance. Also, feeding a tethered element into a pressurised pipeline requires a special apparatus to contain the natural gas and mitigate leakage. A pipeline operator must weigh all the advantages and disadvantages of available self-propelled robotic ILI and consider which optimally suits their requirements. It is the responsibility of ILI vendors to produce as many options as possible to assist the operators with their integrity management efforts. ROSEN is currently expanding the portfolio of self-propelled robotic solutions available to natural gas operators who need to

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avoid service interruption. Currently, the prioritisation is focused on the advantages of a tethered solution. This development will produce MFL-A and MD (geometry) inspection technologies for pressurised 8 in. natural gas pipelines. The scope includes the ILI system with accessories for pipeline insertion and pressure containment.

) A front mounted camera exists to offer a real-time visual

8 in. tethered self-propelled robotic ILI system

) The ILI tool will be tethered to an umbilical winch system that

) The MFL-A measuring segment will be an iteration of ROSEN’s

supplies power and fibreoptic communication. The current specified cable length is 2.5 km (1.54 miles). The expected length of the type of pipelines targeted for this solution are anticipated to fall within this dimension.

low-friction magnetisers. Typically, ILI magnetiser units represent the most restrictive element that requires the most energy to propel through pipeline fittings such as bends. It must involve the necessary mass to achieve sufficient magnetisation of pipe wall, while remaining sufficiently collapsible to navigate tight right radius bends such 1.5D 90° fittings. The friction-reducing aspects reduce drag and thus minimise the required towing force. The MD segment will utilise contactless eddy-current sensors that determine internal pipeline diameter by measuring the ‘lift-off’ response in the sensor coils. This method is resistive to debris influence since it relies upon electromagnetic field induction in ferrous material (pipe wall). ) The tractor(s) that tows the ILI system will incorporate

aluminium wheels mounted on an active suspension system that can be applied against a pipe wall with an adjustable force. This allows for situations in which the ILI tool may need to ascend and descend vertical segments that require a stronger grip against pipe wall.

feed to the ILI tool operator as the tool is driven through the pipeline. This is crucial since unexpected challenges may arise during inspection such as wall thickness changes or tee installations. In such a scenario, the tool operator can make any necessary adjustments to the tractor to accommodate traversal.

) To allow for the introduction of the ILI tool into a pipeline, the

operator must provide a flanged access point with included valve isolation. The ILI tool will be inserted into spool piece that can be installed to the flanged access point. The umbilical (tether) is then fed through a customised stuffing box that includes multi-stage isolation with the ability to transfer any gas leakage in the first stage to a flare. The efforts towards delivery of this solution are ongoing and considered iterative. The expectation is to have this 8 in. solution commercially available by the end of 2023. Unpiggable pipelines will continue to push the boundaries of the technical capabilities for ILI tools. The illusive title of ‘unpiggable’ will continue to be a function of time as these boundaries are continuously crossed.

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Unmatched Performance and Proven Results

Jim Bramlett, Tracerco, USA, explains how Tracerco’s new pipeline inspection technologies can be deployed across deepwater maintenance projects.

s oil and gas assets age over time, the industry faces an ongoing challenge of guaranteeing efficient production whilst always maintaining pipeline integrity. With operations now moving into deeper waters – combined with increasingly challenging and extreme operating environments – innovation in technology has become more important than ever to ensure these assets continue to perform at their optimum efficiency whilst maintaining integrity and extending lifespan. Tracerco’s bespoke Discovery™ and Explorer™ technologies have been purposely designed to provide accurate, in-depth and real-time data insights at considerable water depth and are already proven global successes, being deployed by oil and gas operators across the globe.

Industry first technology In the development of its market leading technologies Discovery and Explorer, Tracerco has developed exclusive and first-to-market methodologies, that enable the online

inspection of a pipe from the outside without any need to remove protective coatings or interfere with production. Designed and developed to give owner operators an enhanced understanding of a pipeline, its coating, and its process fluid – all whilst fully operational – Discovery has quickly become the market leading technology deployed on assets across the world, most recently on deepwater projects in the UK, Europe, US, West Africa and, very recently, South America. The use of pioneering subsea CT scanning technology – the first of its type in the industry and primarily used for non-invasive medical diagnostic technique – has revolutionised the pipeline maintenance industry by providing critical flow assurance and integrity data without any need for the removal of coating and all in real-time. The ground-breaking technology delivers precise sizing of wall thickness in only minutes by capturing a highresolution image of the pipe wall provided from an external scan of the pipeline. This tomographic image then identifies any flaws within the pipe walls, pinpoints location, amount and

density of any material or deposits and all within a density difference of only 0.05 g/cm3. Effortlessly and rapidly deployed – using an ROV and simply clamped on to the pipe – Discovery has been employed across a wide variety of pipeline designs, investigating both internal and external corrosion, detecting blockages and ascertaining flow issues, and is the only technology in the industry that is externally verified and field proven. Having received Lloyd’s Register recognition, Discovery provides a proven technology for deepwater pipeline maintenance, a solution for those pipelines that simply cannot be inspected by traditional means and provides an alternative where operators want to eliminate intrusion and loss of production. The technology boasts the capability to deliver savings of up to 35% on inspection campaign costs compared with more conventional scanning techniques. Align this to Tracerco’s inbuilt fast scanning technology – reducing overall scan time by up to 80% – and operators across the globe are gaining

from maximum data capture never before available in the industry and from one single pipeline inspection. To date, Discovery has successfully collected invaluable data across tens of thousands of pipeline scans, enabling owner operators to improve and enhance the efficiency of existing pipeline models.

Real-time monitoring

Figure 1. Tracerco’s DiscoveryTM technology on a pipe.

Figure 2. Tracerco’s ExplorerTM on pipeline scanning for deposit.

Similar to Discovery, Tracerco’s Explorer tool is an industry first, providing flow assurance screening capabilities to identify areas for further investigation, and which is often deployed as a precursor to Discovery. Comprising bespoke technology, Explorer rapidly screens pipelines for any deposits and offers the capability to screen several km of line per shift – all without interruption to production. A rapid-screening pipeline inspection technique, Explorer is an instrument unique to the oil and gas industry with the capability to screen subsea pipelines for content and deposit build-up at extraordinary pace. Non-intrusive – with no requirement for pipeline preparations – Explorer measures content from the outside of the pipeline with zero need to detach protective coatings or disturb production. As such, Explorer provides owner operators with possibly the most cost-effective solution to flow assurance problems. Performing at depths of up to 3000 m (10 000 ft), Explorer has the functionality to inspect pipe diameters from 2- 60 in. and screen a range of differing piping systems from standard rigid pipe (coated or uncoated) to pipein-pipe, bundles, and flexibles. Explorer delivers a detailed pipeline profile identifying mean densities of contents and the amounts of deposit based on measured densities by detecting the location of deposit build-up, measuring the density profile of the pipeline, and analysing any detected anomalies. Once Explorer has located any suspected blockage, Discovery can then be successfully deployed to accurately characterise precise type and scope.

Empowering data driven decisions The tools and technologies offered by both Discovery and Explorer means owner operators can confidently and accurately – using real-time data – schedule preventative maintenance programmes, engineer the proper remediations to get it right the first time and make calculated decisions focused on how they extend the lifespan of a pipeline asset past its original design life. This economical approach removes any additional cost associated with designing a new pipeline section, undertaking any pipeline modifications or recommissioning work.

Continuous innovation

Figure 3. Tracerco’s Discovery insights showing extent of deposit in pipeline.

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With a history of innovation and a range of industry first market technologies, Tracerco is resolute in its commitment to continued research and development across its industry leading technology suite. As the market leader, Discovery continues to be developed with the introduction of fast screening, baselines scans, corrosion analysis and ongoing development to increase identification of blockages such as asphaltenes, sand, hydrate, and wax.

The I

Lauren Westwood, KBL, USA, discusses offering pigging services with a technological edge in a regulated world.

new rules

for pigging

n the modern age of growing oil and natural gas demand and comprehensive safety mandates, pipeline pigging has become integral to the maintenance and operation of pipeline assets. ‘Pigging’, originally named for the squealing sound the device made as it passed through the line, has developed over many decades in the oil and gas industry and continues to grow in application and popularity. The use of the pigging tools should act as a method to predict, prevent, and avoid accidental pipeline disruptions. A pig is a cylindrical or disk-shaped tool that is launched into a pipeline with the flow of hydrocarbons. Consistent use of pigging is essential to the optimisation of pipeline operations. It’s the ideal method to keep the line clean and remove buildup that reduces flow. This in turn reduces energy consumption and the time it takes for the product to make from one point to another. Additionally, inspection pigs can analyse data to assess the structural integrity of the pipeline as well as detect corrosion or weak points that could potentially lead to leaks or other accidents. These unforeseen mishaps are detrimental to the environment and revenue margins – and are also heavily scrutinised by the media and regulating agencies. So regulated, in fact, that many regulatory bodies require pipeline operators to perform regular inspections and maintenance to ensure compliance with safety and environmental standards.

Figure 1. KBL surveyors place above ground markers for a valued client.

By cleaning and regularly inspecting, pipeline owners can realise a tangible value added with increased optimisation, decreased loss risk, and preemptive measures to meet operating regulations. Considering its many uses and benefits, oil and natural gas pipeline operators have been using various forms of pigs for almost as long as they’ve been using pipelines to move hydrocarbons. Though their design and utilities have changed over the years, pigging has been a reliable tool for various pipeline needs. However, as the needs of the industry have grown, so has the importance of the functionality of the pigging tool being deployed.

four categories of pigs used in the oil and natural gas pipeline industry. Cleaning pigs are inserted into a pipeline to remove debris, sediment, and any other accumulations that block the efficient flow of the product. Inspection pigs, also referred to as ‘smart pigs’ or ‘intelligent pigs’ are used in an effort to collect data and inspect the line for defects or corrosion that will inevitably impact the integrity of the pipeline. Gauging pigs are used for measuring purposes to ensure they meet relevant requirements. And finally, utility pigs are designed to conduct specific functions such as applying a corrosion inhibitor or conducting leak testing.

Not all pigs are created equal

Operators are under a tremendous amount of scrutiny. They must make certain that the integrity of their pipelines is safeguarded to limit or eliminate risks to the environment and surrounding communities. With an ever-changing forecast of pipeline regulation policy changes for existing pipelines and new construction projects, operators must ensure their ducks are in a row now more than ever. Fortunately, by ensuring that pipelines are well-maintained and operating optimally the result is high efficiency, cost savings, and maximum profitability. The Pipeline and Hazardous Materials Safety Administration (PHMSA) is responsible for regulating and ensuring the safety of the nation’s pipelines, including oil and gas pipelines. In a 20 year trend analysis, PHMSA reports approximately 5800 significant pipeline incidents in the two decades, totaling over US$12 billion in losses. Included in this report, the data shows a significant number of injuries as well. Consequently, the agency strives to enact regulations that will avert such incidents in the future. This drive for additional safety standards culminated in the ‘Mega Rule’, which has loomed over the industry with three phases of implementation starting in 2020 and fully integrated in 2023. Each phase added a new level of requirement to most operators, heavily focused on corrosion inspection and integrity maintenance of transmission lines, as well as large-diameter gathering lines. As these regulations have come into effect, operators are hard-pressed to institute a plan to closely monitor their pipelines while at the same time, the industry as a whole has been under pressure with limited margins and growing costs. In times like these, pipeline operators seek solutions that will have a lasting impact on their operations. If they’re strategic, they’re acting proactively to avoid major pipeline repair costs later. Pigging has become the solution for most in the industry, however, it’s become apparent that not all pigs function equally nor do all pigging companies offer services at the same level.

Utilising the right pig for the job on a consistent schedule will improve the efficiency and safety of the pipeline. There are

Figure 2. KBL uses trusted tried and true equipment to guarantee pig passes.

Pipeline regulations grow

Adding layers of protection eases issues in service

Figure 3. KBL affirms its commitment to its customers by developing new age tool tracking technology, known as ‘PigZilla’.

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By partnering with KBL Complete Services, an experienced and knowledgeable pigging software operator, asset owners have the benefit of working with a customer-focused company that is committed to delivering quality services at competitive rates. Recognising the value in offering unrivalled technology, KBL painstakingly developed a robust application to be utilised in its pigging deployments. Pigzilla, a remote tracking software, allows

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customers to access real-time data points including the location and speed of the tool. At the time of deployment, KBL technicians set Above Ground Marker (AGM) sticks, which are utilised in conjunction with geophones and the Pigzilla application, to provide customers with multi-level protection against losing pigs in the line, ‘false trips’ or ‘no trip’ issues thus providing customers with peace of mind and reducing frustration in the time of testing.

Figure 4. Proper vehicle placement is key so as not to interfere with tracking equipment.

Generated in the client dashboard, relevant data points include the customer name, pass/no pass status, AGM number, latitude and longitude, technician name, pass time, mile post, ETA to next AGM, miles per hour, line size, product type, and a link to KMZ file. Stakeholders are notified via automated texts and emails as the test is completed and all the data collected is available for download following the completion of the testing.

Keeping tools moving Pigging tool operators frequently lack the ability to track and gather the necessary data without the use of pig-tracking technology applications. Working with pig deployment crews, KBL ensures pigs are moving through the line and the job gets done. While trying to stay on a timeline for the operator, it can be a huge headache for the pigging crew to have a stuck pig but no idea where it is in the line. Each KBL truck is armed with L22, AGM Sticks Transmitter receiver and/or wavetraks for stateof-the-art onsite pipeline pig tracking. This helps ensure the transmitter is functioning while the tool is being loaded or if it becomes stuck during a run. Moreover, the advanced technology delivered in PigZilla with real-time data and a user-friendly interface will leave the asset owner with a sense they hired the best crews in pigging to offer timely and high-quality services. Following the rollout of the Mega Rule, as operators instate integrity management programmes to identify potential risk areas and monitor performance metrics, they seek to partner with service providers capable of offering extensive information efficiently. The functionality of the technology delivering the data for smart pigs has never been more critical to pipeline operators and pigging tool operators.

Grown in the roots of the highest energyproducing state

Figure 5. Having the right vehicles set up for the job is always important.

Figure 6. KBL assisting with loading a cleaning pig.

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KBL has been in operation for over seven years as of 2023. Owned and operated by company President, Scott Fischer, his wife Deneisha Fischer, and Operations Manager Blaine Gutowsky. A Texas-based company, KBL has provided pig tracking, survey, and project management services to over 5000 miles of pipeline for clients across the nation. In its years of operation, the KBL leadership came to see the gaps in technology in the pigging industry and sought to offer a new kind of application that could reduce the issues that result from stuck or lost pigs while fine-tuning the data reporting process. From the opportunities for improvement KBL witnessed in pigging operation, PigZilla was born. Fischer employs nearly 20 years of experience in oil and gas safety and inspection proficiency in his role as President of KBL Complete Services. With sound knowledge and understanding of federal and state compliance regulations, Fischer and his team have developed a keen awareness of his clients’ needs and work effectively to support their integrity management programme by offering unequalled services and technology. With its extensive backgrounds in safety protocol integration, KBL proudly completed over 40 000+ man-hours without any safety incidents. Focusing on quality and solutionbased services, KBL has worked with pipeline operators and projects of all sizes and complexity.

Jason Rigg, Solutions Architect, Quorum Software, USA, describes how gas and liquid measurement software solutions can increase operational efficiency.

igital transformation efforts continue to be top of mind for many industries, but while some organisations have a plan in place, many remain in the dark. McKinsey1 reports that while many companies have been running digitisation projects across various parts of their operations, 70% of them have not moved beyond the pilot phase due to management that is unwilling to commit necessary resources. Without data analytics tools in place, employees waste valuable time on manual tasks, an ongoing challenge in the upstream and downstream markets. One of the costliest issues is human error, which can easily occur when manually inputting data and having to analyse datasets. The best way to ensure organisations meet their operational efficiency is with a robust gas and liquid measurement

data management system. Gas and liquid measurement software helps streamline the measurement process and optimises data integrity. Let’s take a look at several key issues that the oil and gas industry is currently facing, and the role gas and liquid measurement software can play in alleviating them.

The way it has been done To this day, many operators do not have robust measurement software in place and continue to utilise decades-old homegrown databases to source their data. This is true for companies of all sizes – but they cannot keep up with it forever as the amount of data exponentially increases. Major pain points relate to Excel entry, which is overly manual and doesn’t reflect rapidly changing industry regulations. These systems need to reflect those updates, which can be very timeconsuming if they are manually handled.

Therefore, implementing a robust measurement software helps power a data warehouse capable of serving the needs of the entire organisation. Most employees are not meant to stay in the same role forever, meaning those who initially built the system are faced with the challenge of having to teach the next person overseeing it. Companies who have robust measurement software in place, backed by third-party expertise, automatically have their systems updated based on new industry standards, saving time and effort. From upstream to midstream markets, ensuring compliance and accuracy for gas and liquid measurement data is critical.

Compliance with industry standards and regulations Maintaining compliance with industry standards is a priority for oil and gas companies, including compliance with the Bureau of Land Management (BLM

Having robust measurement software solutions in place helps organisations ensure that industry standard calculations from API, AGA, and GPA Midstream Association remain up to date to help to consolidate, validate, correct, balance, and report gas and liquid measurement data.

Connecting the field to the office

Figure 1. Quorum’s industry-leading solution for hydrocarbon, biogas, and carbon capture and storage measurment ensures data integrity to provide peace of mind.

According to the American Geosciences Institute (AGI), the US has over 200 000 miles of pipelines for crude oil, refined products, and natural gas liquids, 300 000 miles of pipeline for gathering and transmitting natural gas, and 2.2 million miles for distributing gas to various businesses and industrial sites. Operators are focused on moving materials to production as quickly as possible to fill these pipelines, but many are sending out data from production to operations without even validating it. Unfortunately, this causes a potential communication gap between the various departments production data passes through, leading to inaccurate calculations and silos of information. Having a sole source of truth for all measurement data is vital and helps eliminate the constant pressure for operators to communicate with the back office, a process that is also prone to personnel errors. Additionally, it helps minimise risk and ensure compliance with data transparency, and avoids costly errors with validation routines that flag faulty data.

Conclusion

Figure 2. FLOWCAL increases operational efficiency by reducing data management complexity through automation, including a single source of truth for physical volume data throughout the organisation.

Regulations) and the liquid and gas industry calculation standards of the American Gas Association (AGA), American Petroleum Institute (API), and the GPA Midstream Association. Compliance audits are especially strenuous for oil and gas companies, and when using software that isn’t up-to-date with industry standards, they become even more challenging. Both midstream and upstream products have different density ranges and diverse ways they act through different pressures and temperatures. American Petroleum Institute (API) MPMS Chapter 11.1 is the established industry standard outlining the procedure for crude oils, liquid refined products, and lubricating oils for the correction of temperature and pressure effects on the density and volume of liquid hydrocarbons. The API standard ensures that transactions are performed dependent on calculations, and also provides a high level of participation for both parties. Implementing a gas and liquid measurement software helps validate and identify errors and anomalies, as well as offering tools to run recalculations according to these standards. This global standard is updated at least once every five years, and it’s imperative to ensure accuracy is met at all steps of the way.

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For some of the top issues facing upstream and downstream markets today – from complying with industry standards and regulations to inaccurate data due to manual errors – it is integral that organisations take the time to find a trusted, third-party vendor who can help increase operational efficiency with an all-in-one oil and gas measurement software. Home-grown systems that many companies rely on are inefficient, often provide inaccurate measurements, and waste valuable time. A trusted vendor can help tailor the software to your business, so that you no longer have to take a one-size-fits-all approach. That’s why 80% of North American midstream operators trust Quorum Software’s FLOWCAL gas and liquid measurement software to ensure data integrity in this fast-paced market. Additionally, Quorum Software has partnered with the American Petroleum Institute (API) as the only authorised distributor of the API 11.1 calculations and standards for temperature and pressure corrections for liquid commodities. The global measurement community relies on these calculations everyday as the established industry standard for liquids measurement. The FLOWCAL application comes standard with the API 11.1 tables to ensure measured fluids are as accurate as possible prior to financial settlement. Those who get ahead now are better positioned to remain compliant with rapidly changing industry standards and manage hydrocarbon measurement data to maximise revenue by efficiently gathering, validating, storing, and distributing a company’s volume and energy data.

References 1.

https://www.mckinsey.com/capabilities/operations/our-insights/harnessingvolatility-technology-transformation-in-oil-and-gas

Didi Horn, CEO, SkyX, Canada, explores how aerial data helps overcome pipeline surveillance blind spots.

ipelines are a critical component of modern global energy networks. The transportation of oil and gas across vast distances ensures essential services, cities, businesses, homes, and industries continue to function. But while pipelines remain vital, the scale of the transportation infrastructure necessary to power the modern world comes with significant environmental complications and public safety risks. However, aerial surveillance solutions can mitigate pipeline infrastructure challenges not just locally but globally. It might seem counterintuitive that a problem of this size could have a solution that’s comparatively small. Yet the engineers developing these advanced aerial drones are well-prepared to face the slow-moving but devastating Goliathlike problems in pipeline infrastructure. Unmanned aerial vehicles (UAVs) are overcoming the limitations of traditional surveillance with greater efficiency and less laborious workflows. While UAVs aren’t yet the oil and gas industry’s standard inspection tool, the potential benefits of the technology will likely encourage rapid adoption in the coming years. So, to understand the future of pipeline maintenance, let’s look at the aerial solution in greater depth.

Limits to traditional surveillance methods Pipelines are one of the safest methods of transporting essential resources around the world. After all, companies need a way to move natural gas and crude oil from their genesis points to processing plants so they can be dispersed for use. Obviously, this global energy production operation requires an extensive network of pipelines. The logistics of monitoring this entire network have long presented a thorny problem for energy producers. In fact, the sheer scale of the pipeline network requires an inordinate amount of time, funding, and resources to manage. What’s more, the practical limitations of traditional surveillance methods make comprehensive and continuous monitoring all but impossible. This means companies will inevitably miss some cracks and other structural damage or threats. In addition, more cost-effective mitigation measures that could be taken are often left undone. As a result, preventable ecological disasters are widespread, and oil and gas companies bear the costs. Corrosion, third-party intervention, natural disasters, or any number of other factors can damage the structural integrity of the pipeline. The potential resulting leak could go unnoticed until the surrounding environment or populace incur significant damage. As a result, many companies are already allocating significant resources toward surveillance. However, despite this effort, the results aren’t keeping pace with the frequency of new leaks along the line. As with many industry sectors, there’s a lack of applicable technology available to augment the human effort of monitoring pipelines. Historically, this has been largely responsible for the frequency of ecological disasters. So, you can see why aerial surveillance UAVs are showing significant potential to reduce the scale of the issue. To better understand how new technologies can impact pipeline surveillance, let’s break down the pros and cons of traditional methods.

Three traditional pipeline surveillance methods Historically, oil and gas companies have used three primary methods to monitor the structural integrity of their pipelines. While each method offers a degree of protection against leaks, they also carry significant limitations that prevent totally accurate results. 1. Maintenance patrols This is the most basic form of pipeline surveillance. Maintenance patrols are simply an on-foot, visual inspection of the pipeline to identify potential hazards. Needless to say, this method is extremely prone to human error. What’s more, the natural landscape can make certain points along the pipeline inaccessible or extremely laborious to reach. So, maintenance patrols along that section will ultimately be either impossible or infrequent. Additionally, while this method can identify obvious visual problems along the surface of the pipeline, it cannot identify serious underground issues. 2. Ground inspections Ground inspections go one step further than maintenance patrols and use specialised equipment to detect problems beneath the

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surface. However, because this method requires inspectors to traverse the length of the pipeline, it’s still limited by the topographical and environmental factors that may reduce access to certain areas. This method also comes at a high cost in terms of both time and finances. Equipment with the required accuracy range isn’t necessarily cost-effective, especially when accounting for the work hours it takes to collect and analyse data. 3. Manned aerial inspection The last traditional method is aerial inspection through manned helicopters or airplanes. This method has the advantage of covering large areas. Plus, it enables access to portions of the pipeline that cannot be reached on land. However, it also sacrifices accuracy because it can easily miss small details or issues due to the aerial distance.

Drones: the best solution? The limitations of traditional manual monitoring methods have long been known within the oil and gas industry, but the scope of the potential aerial surveillance solution is just beginning to gain traction. UAVs carry the potential to solve or mitigate the major pain points that plague inspectors in the field. Plus, they enable companies to monitor pipelines continuously and with great detail, even in areas with rough terrain. Notably, drones can significantly reduce safety risks and costs for workers in a number of ways: ) They eliminate the need to traverse dangerous conditions to monitor the pipeline while providing a more comprehensive inspection. ) Workers can avoid using scaffolding, ropes, or other risky

means of inspecting hard-to-reach pipeline sections. ) The use of UAVs eliminates both the time commitment and

the associated fees of inspectors travelling from site to site. Another unmatched benefit that comes with aerial surveillance drones is the ability to efficiently scale up data collection and analytics. UAVs can conduct pre-set flights that capture detailed data without any active involvement from workers. So, companies can continuously monitor pipelines even when operations are expanding. In addition, while manual inspections can take several weeks, the most advanced UAVs can complete inspections in a matter of hours. This vastly heightens the level of possible surveillance. These advanced aerial surveillance systems also provide extremely high-quality imagery. Integrated artificial intelligence (AI) capabilities automatically process the images and can flag potential issues for inspector review. This significantly reduces the number of hours it takes an inspector to review a section. As a result, the entire pipeline can be examined more frequently.

Elements of an aerial surveillance system UAVs are likely to become an industry standard for inspections in the upcoming years. After all, the cost and safety benefits to oil and gas companies and workers can’t be beat. But to further clarify why companies are adopting UAVs, let’s delve into the

technical elements of aerial surveillance drones to see how they improve the pipeline inspection process. Early detection of pipeline leaks UAVs can leverage advanced technology like thermal or infrared cameras to pinpoint leaks quickly. This allows companies to respond much earlier, potentially reducing the resulting environmental or human impacts. Plus, proactive notifications that highlight problematic points in the pipeline let inspectors catch leaks before they happen. Efficient reporting UAVs operate with unmatched agility, so the drone can capture imagery for previously inaccessible areas. This increases the overall quantity of inspections and reduces the likelihood of missed cracks, leaks, or corrosion in the pipeline. Reduction of human error The high-resolution imagery captured with precisely timed overlapping georeferenced photos – combined with the processing capabilities of AI and backed by the human inspection of flagged items – creates a rigorous and multi-layered process to capture all potential issues. Plus, hydrocarbon leak verification technology can integrate raw and analysed data into ArcGIS to empower response crews with critical information.

Predictive analytics Proper asset management in the modern era demands the use of predictive analytics. Advanced aerial surveillance systems can track the ageing of long-range assets over time. This feature enables companies to plan for future repairs and perform more targeted maintenance.

Aerial surveillance UAVs The benefits of implementing aerial surveillance drones to monitor oil and gas pipelines are unmatched. The precision manoeuvring, unmanned piloting, survey speed, tireless performance, and processing capabilities for captured data all make UAVs the ideal option for tracking the structural integrity of pipelines. While the energy industry continues to bear the responsibility and cost of frequent accidental leaks, this may soon become a rare occurrence thanks to the impending implementation of this new technology. However, a function this critical can’t be left to chance. Choosing the most advanced drones can ensure your company is benefiting from remarkably precise data capture and analytical abilities. SkyX is at the forefront of developing aerial surveillance technology. In a matter of hours, its UAV systems can perform data-rich surveys that would traditionally require weeks of work from an entire team.

ARTICULATED PIGS Articulated pigs are typically designed to pass pipeline wye connections whilst also negotiating tight bend radius. They are also used to pass oversized features (such as ball valves, check valves or connector hubs). This type of pig is also highly efficient in long run, dewatering/flooding and heavy duty cleaning operations as well as dual-diameter applications.

Propipe Limited - www.piggingsmarter.com For Global Sales Tel: +44 1429 872927 Email: groupsales@propipe.co.uk

For North American Sales Tel: +1 902 417 5075 Email: sales@propipenorthamerica.com

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Chris Johnson, Managing Director, SMB Bearings, UK, delves into the significance of surface preparation and coatings for industrial bearings in pipeline applications.

ccording to a study published in the Journal of Loss Prevention in the Process Industries, the main causes of pipeline failures include corrosion, equipment malfunction and operational errors. These factors contribute to the need for costly repairs and downtime, further highlighting the importance of proactive maintenance and reliable equipment. Industrial bearings serve as vital components in pipelines, facilitating the smooth and efficient flow of oil, gas and various fluids. However, these bearings are susceptible to damage caused by friction, corrosion and wear – factors that can result in costly downtime and repairs for operators of oil and gas pipelines.

Figure 1. Corrosion-resistant stainless steel bearings are designed to withstand challenging oil and gas environments.

Meanwhile, a survey conducted by Ernst & Young found that 60% of oil and gas executives identified unscheduled asset downtime as the biggest barrier to achieving optimal operational efficiency. This indicates that downtime and repairs pose significant challenges to the productivity and profitability of pipeline operators. To mitigate these challenges and ensure optimal performance and durability, surface preparation and coatings for industrial bearings play a pivotal role. By exploring various surface preparation techniques and coating options, we can gain valuable insights to help pipeline operators, engineers and maintenance personnel make informed decisions when selecting the right coating solutions for their pipelines.

Surface preparation techniques Surface preparation is a critical step in the coating process, as it ensures a clean and receptive surface for coatings. Three commonly used surface preparation techniques include shot blasting, grinding and cleaning. Shot blasting involves propelling abrasive particles onto the bearing surface to remove contaminants, scale and oxide layers. This technique not only cleans the surface but also enhances its roughness, promoting better adhesion of coatings. Grinding is another technique that removes irregularities, burrs, and imperfections from the bearing surface. By creating a smooth and uniform surface, grinding enhances the coating’s uniformity and adhesion while reducing the risk of premature coating failure. Cleaning is essential to remove oil, grease, dust and other contaminants from the surface. Different cleaning methods, such as solvent cleaning, alkaline cleaning, and high-pressure water jetting, can be employed based on the nature and severity of the contamination. Clean surfaces are crucial for achieving proper coating adhesion and performance.

Types of coatings for industrial bearings Various types of coatings are available to enhance the wear, corrosion, and chemical resistance of industrial bearings. The choice of coating depends on the specific requirements of the pipeline application. Some commonly used coatings include thermal spray coatings, electroplating and polymer-based coatings.

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Thermal spray coatings involve depositing a molten or powdered material onto the bearing surface using a thermal spray gun. These coatings provide excellent wear resistance and can be customised with specific materials such as ceramics, metals, or alloys to suit the operating conditions. Electroplating is a process where a metal coating is deposited onto the bearing surface by electrolysis. This technique offers superior corrosion protection and can be applied with precision, allowing for controlled coating thickness and uniformity. Polymer-based coatings offer exceptional chemical resistance and can withstand harsh operating environments. They can be tailored to provide specific properties such as low friction, high load capacity, and resistance to abrasion, making them suitable for diverse pipeline applications.

Key factors in coating selection When selecting a coating system for industrial bearings, several factors must be considered. These include the operating conditions, substrate material and costeffectiveness. The operating conditions, such as temperature, pressure and exposure to chemicals, determine the coating’s performance requirements. For high-temperature applications, coatings with thermal stability and heat resistance are crucial. Similarly, corrosive environments necessitate coatings with excellent chemical resistance. The substrate material also influences the coating selection process. Different materials – such as steel, stainless steel or ceramics – require specific coatings to ensure compatibility and optimal performance. The coating must be compatible with the substrate to prevent galvanic corrosion and promote bonding. Cost-effectiveness is a significant consideration when selecting coatings. While advanced coating technologies may have higher upfront costs, they can result in substantial savings by extending the bearing’s lifespan, reducing maintenance frequency and minimising downtime.

Surface preparation and coating technologies The pipeline industry has witnessed remarkable advancements in surface preparation and coating technologies in recent years. These innovations have greatly enhanced the durability and performance of industrial bearings. One such advancement is the development of environmentally friendly coatings that minimise the use of hazardous substances. These coatings adhere to stringent environmental regulations while maintaining exceptional performance characteristics. Nanotechnology has also made significant contributions to surface preparation and coating techniques. Nanocoatings offer enhanced properties such as increased hardness, improved wear resistance and superior corrosion protection. They provide a nanoscale barrier that shields the bearing surface from contaminants and extends its operational life.

Additionally, advancements in coating application techniques, such as plasma spraying and electrostatic deposition, have improved coating uniformity, thickness control and overall quality. These techniques enable precise application and reduce waste, resulting in more efficient and cost-effective coating processes. Surface preparation and coating technologies play a crucial role in reducing losses and downtime in oil and gas applications involving industrial bearings. Proper surface preparation ensures optimal adhesion of coatings, providing enhanced protection against corrosion, wear, and contaminants. These coatings improve the durability and performance of bearings, reducing the frequency of maintenance and replacement. As a result, downtime due to bearing failures is minimised, leading to improved operational efficiency, cost savings, and uninterrupted production in oil and gas applications.

Drones in the oil industry Nanotechnology isn’t the only unusual technology that can enhance maintenance practices in oil and gas pipelines. Another is unmanned aerial vehicles, or drones. Drones offer significant potential for enhancing maintenance practices in oil and gas pipelines, directly contributing to the reduction of losses and downtime. Equipped with advanced imaging and sensing technologies, drones can efficiently inspect pipelines, detecting leaks, corrosion, or structural damage. Real-

time data gathered by drones enables timely maintenance interventions, preventing costly disruptions and minimising environmental risks. However, the effective operation of drones in this challenging environment relies heavily on appropriate industrial bearing selection. Drones used in the oil industry are subjected to harsh operating conditions, including extreme temperatures, high winds and exposure to corrosive elements. They are required to navigate complex terrain, inspect critical infrastructure, and carry heavy payloads such as cameras and sensors. In such demanding circumstances, the reliability and durability of industrial bearings are paramount. Industrial bearings play a vital role in the performance of drones, ensuring smooth and efficient rotation of propellers and other moving parts. Choosing the right bearings can significantly impact the overall efficiency, reliability and longevity of the drone. Appropriate bearing selection involves considering factors such as load capacity, speed, temperature resistance and corrosion resistance. Drones used in the oil industry often require bearings that can withstand heavy loads and high rotational speeds while operating in extreme temperatures. They also need bearings that can resist corrosion caused by exposure to saltwater or other corrosive substances. Failure of bearings in drones can have severe consequences, including catastrophic crashes, equipment damage and costly repairs. By selecting high-quality bearings

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specifically designed for the demanding conditions of the oil industry, operators can minimise the risk of bearing failure and ensure uninterrupted drone operations. When choosing industrial bearings for drones used in the oil and gas industry, key characteristics and considerations include load capacity, speed capability, temperature resistance, and corrosion resistance. Coatings and lubrication are instrumental in optimising the performance and lifespan of industrial bearings used in drones, achieving reduced friction, increased efficiency, and enhanced overall functionality.

Corrosion resistant stainless steel bearings In oil and gas pipelines, corrosion is a major concern due to the presence of aggressive fluids and harsh operating conditions. SMB Bearings’ corrosion-resistant stainless steel bearings are specifically designed to withstand these challenging environments. With their superior corrosion resistance properties, these bearings minimise the risk of damage caused by corrosion, thus reducing the need for frequent repairs and costly downtime. The stainless steel bearings offered by SMB Bearings are manufactured to the highest standards, ensuring reliability and durability. They are designed to operate smoothly even in demanding conditions, providing uninterrupted performance and minimising maintenance requirements. By utilising specialist corrosion-resistant stainless steel bearings and leveraging knowledge from industry experts, oil and gas pipeline operators can significantly reduce downtime and repair costs, improving the overall reliability and productivity of their operations.

Minimising repairs and downtime The use of appropriate industrial bearings is essential for reducing costly downtime and repairs in the oil and gas industry. Factors such as load capacity, speed capability, temperature resistance, and corrosion resistance must be considered when selecting bearings for pipelines and drones used in the industry. The Journal of Loss Prevention in the Process Industries study on pipeline failures highlights the importance of proactive maintenance and reliable equipment to minimise costly repairs and downtime. By choosing high-quality bearings and leveraging technical support from SMB Bearings, operators can significantly reduce downtime and repair costs, improving the overall reliability and productivity of their operations. Surface preparation and coatings also play a crucial role in enhancing the performance and longevity of industrial bearings, ensuring smooth and efficient fluid flow in pipeline applications. Recent advancements in surface preparation and coating technologies further contribute to the capabilities of these bearings. By understanding the critical role of surface preparation, coatings, and appropriate bearing selection, professionals can make informed decisions to optimise the efficiency and reliability of their pipeline systems.

The Argus Pig Valve allows cleaning and inspection of once ‘unpiggable’ lines, improving the eﬃciency and longevity of your pipeline.