4/2022 Pipeline Technology Journal Leak Detection & Monitoring Leak Detection for Energy Transition Real-Time Monitoring of Critical Flanges Fiber Optic Sensors Third Party Interference Damage Ageing Pipelines Illegal Hot Tapping www.pipeline-journal.net e-ISSN 2196-4300 / p-ISSN 2751-1189

Pipeline Technology Journal - 4/2022 editorial PTJ EDITORIAL Welcome to the new issue of the Pipeline Technology Journal (ptj). I am honoured to sit on the ptj Editorial Board and am pleased to introduce this issue’s editorial theme: leak detection and monitoring. Mike Kirkwood Director, Integrity Engineering and Emerging Energy T.D. Williamson The latest CONCAWE Performance of European Cross-country Oil Pipelines report highlights that since 1971 (the start of the CONCAWE data), improvements in leak detection and monitoring systems have translated to better leak detection in liquid pipelines. The report identified that systems have detected 25% (as a moving average) of leaks over the last five years. With the technology used in leak detection improving year-on-year, it's interesting to examine what's changes and what the future trends are especially with the move to net zero and emerging fuels. There will be new products flowing in our pipeline infrastructure, and detection and monitoring systems will need to address new challenges, including hydrogen, carbon dioxide and even ammonia. In this issue, ptj looks at how the industry is gearing up for the future. We have a great line-up of papers, including an interesting in-line inspection approach to detecting theft, which has increased in recent years and is likely to be a continuing issue as energy prices soar. There’s also a paper on an extended, real time transient approach that uses continuous monitoring and pattern recognition to spot leaks in difficult products such as hydrogen and carbon dioxide. Two papers focus on the use of fibre optic cable applications; one is about external detection and the other describes a novel use of fibre inside the pipe. Finally, an article about leak prevention introduces a plastic mechanical protection system that sits over the pipeline to reduce the impact of third-party damage. We hope you enjoy this edition, and that it will educate you on the status of current and future technologies for leak detection and monitoring. Your sincerely, Mike Kirkwood Director, Integrity Engineering and Emerging Energy T.D. Williamson

Pipeline Technology Journal - 4/2022 32 An increasing concern: Third Party Interference Damage on buried pipelines - A European case study Y. Joubeaux 42 Considering the Challenges of Optimizing Aging pipelines H.Smith 46 Illegal Hot Tappings – Qualifi- cation Stages of an innovative Inline Inspection Tool S. Benichou, A Levy, J. De Morel, J.L. Bonneville, B. Marquis Company Directory Page 60 58 Ask the Experts Leak Detection & Monitoring

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Pipeline Technology Journal - 4/2022 9 In-depth Analysis of the Energy Crisis in Europe: auses and Remedies — Dr Carole Nakhle The prevailing energy crisis in Europe has exposed the EU's underlying problems that were overlooked for many years. According to an energy economist, Dr Carole Nakhle, CEO of Crystol Energy, an advisory, research, and training company in London, Russia's invasion of Ukraine only amplified the already existing problem that was brewing over the years, explaining how the problem has been in the making for years and how the current crisis can be resolved and averted in the future. Dr Nakhle broadly categorized the causes of the current energy crisis in Europe into three: the development of gas markets, dependence on Russian energy supplies, and confusing policy signals. About Dr. Nakhle Dr Carole Nakhle specializes in international petroleum contractual ar- rangements and fiscal regimes; upstream oil and gas regulations; petro- leum revenue management and governance; energy policy, security, and investment; and world oil and gas market developments. With a unique breadth of experience, she has worked with oil and gas com- panies (NOCs and IOCs), governments and policymakers, international or- ganizations, academic institutions, and specialized think tanks on a global scale. She is a regular contributor to Geopolitical Intelligence Service on energy matters, a program advisor to the Washington-based International Tax and Investment Centre, and a Participant in the OECD Policy Dialogue on Natural Resource-based Development. She is also active on the Advisory Council of the Natural Resource Governance Institute (NRGI). Read the full interview: www.pipeline-journal.net

1. Introduction With a shift from fossil-based systems of energy pro- duction and consumption to renewable energy sources also comes a shift for the transportation. This is also true for pipeline leak detection systems. To guarantee the safe and efficient monitoring of the pipelines, leak detection systems must be adapted to the new require- ments coming with the shift. While there are pipelines transporting 100% hydro- gen, there are others transporting a blend of hydrogen with natural gas. In carbon capture applications, the captured CO2 is transported to sites where the CO2 is stored or utilised. This CO2 can be transported as gas, liquid or in supercritical state. As a result the leak de- tection system needs to be able to work with these dif- ferent mixtures and phases. For classical leak detection systems this is often a prob- lem. Negative Pressure Wave leak detection systems are affected due to damping in gas. Classical statis- tical systems are affected due to compressibility and linepack changes. This leads to long detection times or high thresholds. The systems will react with a loss of sensitivity or in the worst case with false alarms. Different mixtures and phases in the same pipe- line are a typical application for Real-Time Transient Model technology (RTTM) based systems, which try to consider all blends of different products and pipeline properties in its calculations. However, if the fluid can- not be accurately modelled by the system this leads to false results. Unforeseen operating conditions will also lead to false alarms. The Extended Real-Time Transient Model technology (E-RTTM) can compensate for these disadvantages. The following chapter shows how the technology works. 2. Principle of E-RTTM (Extended Real-Time Transient Model) E-RTTM is a leading technology for continuous in- ternal monitoring of pipelines. It was developed by KROHNE, a manufacturer of measuring technology and established supplier of systems for the pipeline industry. The E-RTTM introduced here is the basis of the Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 11 PipePatrol leak detection system by KROHNE. With more than 35 years of experience with the technology and over 430 installations, the system has proven itself in monitoring liquid and gas pipelines (including liq- uefied gas and supercritical products) and meets all the requirements of TRFL and API RP 1130. Requirements of recent publications like API 1175 are also met. Next to the vertical combination of the virtual pipeline with pattern recognition, a horizontal approach combining different API 1130 methods into one system is present. Figure 1: Basic functional principle of E-RTTM E-RTTM extends a feature generation module with leak signature analysis using leak pattern detection: an E-RTTM leak detection system creates a virtual image of a pipeline based on measured data. Measured values from flow, temperature and pressure sensors installed at the inlet and outlet of the pipeline and along the pipeline in places such as pump and valve stations are crucial. The flow, pressure, temperature and density at each point along the virtual pipeline are calculated from the measured pressure and temperature values. The model compares the calculated flow values with the actual values from the flow meters. If the model detects a flow discrepancy, the leak signature analysis module then determines whether it was caused by an instrument error, a gradual leak or a sudden leak.

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 13 Figure 3: Energy transition also means de-carbonisation: Electrolysis Systems in Power-to-Gas applications use electricity generated by wind turbines hydrogen is generated by means of electrolysis and fed via a 1.6 km hydrogen pipeline into the gas grid. As the leading leak detection system provider in Germany, KROHNE had been recommended by an in- dependent 3rd party authority to be the supplier for the leak detection system which monitors the hydro- gen pipeline connecting the alkaline electrolysis with the natural gas grid. The E-RTTM technology was se- lected due to its ability to measure a supercritical prod- uct even in small leak quantities and the model was adapted to the hydrogen properties. This was the first Power to Gas Application equipped with a PipePatrol leak detection system in 2013. Since then, PipePatrol has been installed on several hydrogen pipelines. With all pipelines, a leak test was done under 3rd party review of TÜV, resulting in a swift leak alarm from PipePatrol. Since beginning of operation, the system has secured the transport of over 10 million kWh of hy- drogen (“WindGas”) fed into the grid. 4. Leak Detection System for Carbon Capture The second application takes place in Western Australia: natural gas from the Gorgon gas field contains around 14% naturally occurring CO2. Prior to converting the natural gas to LNG by cooling it to -162°C / -259.6°F, the CO2 is removed. To minimize the environmental footprint, the separated CO2 is not vented but injected in a storage formation. ‘With energy transition, product blends in pipelines have become more common, and this is often a problem for classical leak detection systems.’ A 7 km long underground pipeline transports the CO2 from the LNG liquefaction plant to the CO2 injection wells. The CO2 is transported in supercritical phase at ele- vated pressures. The underground pipeline has a di- ameter of 300 mm / 12”. Three compressor modules feed CO2 in the pipeline that transports it to nine in- jection wells at three drill centers. The measurement requirement for this project was to provide a pipeline leak detection system that provides timely and accu- rate leak information for the three pipeline-segments between the LNG plant and drill-centers.

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 15 well as carbon capture applications and is ready for the energy transition. Smallest detectable leak rates are typically 0.5% and below. Leak detection time in seconds, confirmation within minutes It has an ex- ceptionally low false alarm rate due to onsite opti- mization. Due to the pattern recognition process it detects smallest leaks reliably and delivers repeata- ble results over a long period. Leak size information is statistically refined and the leak localization is best-in- class by Gradient Intersection Method and Extended - Negative Pressure Wave Method. Authors Maximilian Ihring KROHNE Solutions Product Group Manager, Pipeline Management Solutions m.ihring@krohne.com Daniel Vogt KROHNE Solutions Business Unit Manager, Pipeline Management Solutions d.vogt@krohne.com Creaform has the most trusted 3D scanning technology solution for pipeline integrity assessment. Designed for harsh environments, the Creaform solution ensures fast field deployment, user-independent results, versatile geometry analysis, easy reporting, and a complete 3D visualization of internal and external surfaces. Interested in raising your quality of service to a level never seen before? Contact us today! creaform3d.com l +49 711 1856 8030REMOVE INTERPRETATION FROM THE EQUATIONTHE NEW VXintegrity SOFTWARE PLATFORMNEW

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 17 1. Introduction Hydrocarbons are of great technical and economic im- portance, especially in the oil, gas and petrochemical industries, due to their use as fossil fuels and in or- ganic synthesis. The oil, gas and petrochemical indus- tries are mainly characterized by the production and processing of hydrocarbons. For this purpose, pipes and flanges are ubiquitous in all areas of upstream, midstream and downstream piping systems. In this context the industry is facing one common chal- lenge: Preventing flange leakage as a particular weak point for leakage of hydrocarbons to the enviroment [1]. A refinery can emit more than 600 tons of vola- tile organic compounds per yer from leaking equiment and in more than 90% of these cases the connecting flanges are accountable for this. There are several possible causes for flange leakages. For example unequal or insufficient bolt loads can af- fect the required compression load level of the gas- ket. Those conditions can lead eventually to leakages, as well as the influence of varying temperatures and ageing influences on the heavily loaded bolts. Also improper flange alignment, unequal gasket compres- sion or local overload causes subsequent leakage [1, 2]. Various damages to flanges in the form of dirt, scaling, internal and external scratches, protrusions, and weld spatters result in flange leakage [2, 3]. Also, the flanges with warped seating surfaces increase the chances of leakage. Thus, there are many differ- ent reasons for flange leakages and this can lead to serious consequences. [1, 2, 3] Hydrocarbons are vola- tile and flammable, any possible failure of the contain- ing or carrying equipment could lead to catastrophic events. Detecting hydrocarbon leaks at an early stage is critical to reduce the risk of fire and explosion ac- cidents [1]. This is especially important for flamma- ble liquids and gases that can form explosive mixtures with air. But the economical aspect of it is also impor- tant. Besides the safety related consequences, leakages come with directly accountable costs for loss of prod- ucts, pressure or heat energy as well as costs for inspec- tion,downtime, environmental cleanup cost and pos- sible fines and legal suits from habitants [1, 2]. Besides this, there are also labor and material costs for the re- active repair of a leakage and a risk of loss in reputa- tion. If a severe leak or the repair of it causes an impact on the operational production process (e.g. product quality) or an unplanned downtime of a subprocess or even the whole plant, the accountable damages can re- sult in millions of dollars [1]. For example, the incident of a leakage on a pipe in a refinary in Philadelphia, USA in 2019 injured five people. The critical (elbow) pipe was not monitored periodically and there was a major loss of primary containment on the hydrofluoric acid alkylation unit at the refinery resulted in a large fire and sub- sequent explosions. More than 307 tons of hydro- carbons and two tons of highly toxic chemical were released to atmosphere. The refinery shut down shortly after incident, filed for bankruptcy.[8, 9] If leakages could be detected with a high confidence and reliability at that very moment they occur, this would considerably decrease the probability of se- vere consequences and therefore costs of unplanned downtime, emergency repairs, clean ups and risk related costs like insurances [1, 6]. Unfortunately, pipe operators appear to have inadequate indus- trial technology to manage real-time monitoring of flanges. The definition and corresponding require- ments on“real-time” monitoring are depending on the application context; real-time in this paper is de- finined as continous monitoring to be able to detect a leakage in a adequate time interval before seroius consequences will take place. Most of the existing methods can not deal with the complex situation of optimizing transportation and production and min- imizing costs associated with the operation while maximizing reliability and real-time monitoring at the same time [2, 6, 12]. Based on these challenges, new data-based mainte- nance solutions offer the possibility to optimize the overall system of leakage management. With the help of condition monitoring it is possible, to find the opti- mum between early leak detection on the one hand and costly repairs, production losses and unplanned down- time on the other hand [5]. The widespread use of da- ta-based maintenance concepts for real-time monitor- ing of critical flanges has not yet become established. This is mainly due to the formerly complex integra- tion requirements and high costs for sensor systems and data analysis. As the costs of sensors providing valuable data and tools to analyze the data became tre- mendously cheaper in the last years, the trend is now

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 19 methods are irrespective of the class of the causal dam- age and potential leak identification due to metal loss. In the following, the different approaches are described and evaluated with respect to their suitability in the context of real-time monitoring of piping systems and resulting data-driven maintenance strategies. In the end there is a summary of pro and cons of each technology. Acoustic leak detection utilizes noise emission or vibra- tion caused by an unexpected fall in pressure to de- tect the existence of a leakage in a pipe [2, 7]. Due the high-pressure in the pipe elastic waves were generated by fluid escaping from the perforated point. There are serval installed sensors and the time lag between an acoustic signal detected by two sensors helps to iden- tify the leakage position [12, 14]. However, especially for piping systems on the ground of a refinery with a high level of background noise critical leakage may not be detected reliably, because the noise hides the acoustic signal of leakage at a high flow rate. Also, it is not suita- ble for small leaks. [1, 11, 13] Fibre Optic Methods uses sensors installed along the ex- terior of the pipe. When a leakage in a pipeline or pip- ing system takes place and hydrocarbons engross into a coating cable, the temperature of this cable will change [2]. This leads to a temperature variation in the fibre optic cable which can be measured and anomalies along a pipeline or piping system can be detected [11]. The im- plementation cost of this method is high and will not work for systems protected by a cathodic protection sys- tem. [1, 11, 12] A Leakage detection system using the infrared thermog- raphy (IRT) mechanism is also relevant for the detection of hydrocarbon leakages. The infrared cameras show an infrared range of 900–1400 nm, which allows this technique to detect temperature changes in the pipe environment. The result is a thermogram, which cap- tures all images from the IRT camera. IRT can be used for different condition monitoring applications like heat transfer or tensile failure as it is a contactless and non-invasive. However, the cost of a high-resolution in- frared camera is very high, while only covering the visi- ble field for a mounted system. Moreover, quantifying a very small leak using this method is challenging. There is a range of common methods utilizing Magnetic Fields to monitor piping systems and equipment regarding cracks, corrosion and reduced wall thickness. The common element of those meth- ods is a magnetic field, which is generated by per- manent magnets or electromagnets. The flow of ei- ther the magnetic resp. the induced electrical field in the base structure is observed, which will be influ- enced by structural flaws in the material. This is ei- ther carried out with sensors or visually with the help of magnetic powders or dyes. Magnetic Flux Leakage and Eddy Current Technology can also be applied in larger sensor arrays via Smart Pigging, where the car- rier device (smart pig) is inserted into the pipe and scans continuously as it passes through. Due to mag- netism based principles, these methods are only ap- plicable for metal resp. magnetizable pipelines and piping systems [15, 16, 17]. Electromechanical impedance (EMI)-based techniques uti- lize piezoelectric transducers and the analysis of electro- mechanical impedance to detect structural flaws. EMI transducers are made up of small surface-bonded piezo- electric ceramic patches, as actuators and sensors. They emits high-frequency structure excitation to the host structure [18], at the same time, they also measure the overall dynamic impedance, in order to assess the struc- tural integrity and thus, causes for leaks. In the situation of mechanical pipe defects, the EMI senses the variations in structural point impedance. The method shows oper- ational limitations in high temperature environments. Furthermore the method is a high-cost factor and has high requirements on equipment. [1, 18] Visual inspection methods of detecting leakages uses traditional processes of detecting leakages in a pipe- line or a piping system using trained dogs, quali- fied personnel or air vehicles [1, 2]. These methods are most of the time based on experienced person- nel who inspect the pipes and search for anomalous and unusual situations in the pipe’s environment with or without measurement equipment. High ex- perienced personnel i.e. recognise leakages through visual inspection or smelling the aroma coming from the hydrocarbon emission [1]. Also, the vibra- tion and noise coming from a leakage point could be recognized by experienced personnel. Trained dogs work in a similar way focusing on smelling leak- ages. In all of the cases mentioned above the detec- tion time is dependent on the frequency of inspec- tions which varies from weekly up to even annual

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 21 Figure 2: Schematic solution overview environment for a certain period. The sensor can de- tect leakages in almost real-time and can be lever- aged to monitor critical sections of pipes notifying the operator through an app and email notifications. Continuous digital documentation of the asset sta- tus and its accessibility increase transparency and reveal potential for improvement. Therefore, the in- tegrity of every leak critical asset can be monitored con- tinuously. Leakages can be repaired when they have not yet developed into more severe leakages. This helps operators to prevent costly unplanned downtimes and risky consequences that might develop from a leak. On the other hand, the solution may reduce the required efforts for manual inspection, while increasing the in- spection quality. The carbon nanotube-based sensors detect even small hydrocarbon amounts and allows the operator to undertake countermeasures before they es- cape into the environment. These sensors collect data in almost real-time (Step 1) and transfer the information through dedicated IoT networks (Step 2), to a central- ized database for analysis. Through an edge device the sensor data will be transmitted to a cloud (Step 3) and will be analysed (Step 4). The edge device is independent of local network thanks to cellular communication. The cloud runs that data through a set of prebuilt predictive algorithms to detect small leaks. A web-based platform independent of end device or operating system provide the information about leakages in real-time. Figure 2 shows a schematic solution overview. 4. Real Time Monitoring as Enabler for Predictive Maintenance The advantages of predictive maintenance may be im- mense from a cost-savings perspective and include minimizing planned and unplanned downtime, max- imizing the lifetime of a piping system, optimizing maintenance strategies including productivity of em- ployees and increasing revenue [5]. The advantage of predictive maintenance is its ability to transform both a maintenance team and an organization, as im- plementing predictive maintenance allows asset man- agers to improve outcomes, continuously monitoring equipment and better balance different priorities such as profitability and reliability [5, 10]. Predictive mainte- nance cannot exist without real-time monitoring. There are two facets of real-time monitoring: online and re- mote. Online real-time monitoring is defined as the continuous monitoring, with data collected on critical parameters in an adequate time interval. Remote mon- itoring, as its name suggests, means equipment in this case piping systems can be monitored from a remote lo- cation, with data transmitted for analysis of critical pa- rameters. The described LOCTITE® Pulse Smart Flange is one solution meet these requirements. This enables to go from the reactive (run-to-failure) strategy to a da- ta-based predictive maintenance strategy (see Figure 3). Thus, continuous, real-time monitoring of critical flanges results in five key value drivers for plant oper- ators described in the following. 1) Contribution to increased safety: The greatest added value of continuous monitoring of critical flanges is certainly the contribution to increasing plant safety. Continuous monitoring in real-time enables early detection of leaks even before they can progress significantly and thus, pose a considerable safety risk. Consequently, it provides an additional level of safety in addition to existing systems and processes. In addition to the obvious added value in terms of health and safety risks, this can also result in an economic advantage, as the cost of insuring against safety-related incidents may be reduced.

will continue to drive the shift from reactive to pro- active maintenance. Especially in relation to falling costs for sensor systems, future solutions will not only be available or profitable for the most critical flanges and pipes, but for a wide range of equipment. References 1. Adegboye, Mutiu Adesina, Wai-Keung Fung, and Aditya Karnik. "Recent advances in pipeline monitoring and oil leakage detection technologies: Principles and approaches." Sensors 19.11 (2019): 2548. 2. Agbakwuru, Jasper. "Pipeline potential leak detection technologies: assessment and perspective in the Nigeria Niger Delta region." Journal of Environmental Protection 2.08 (2011): 1055. 3. Bolotina, Irina, et al. "Application of phased antenna arrays for pipeline leak detec- tion." Journal of Petroleum Science and Engineering 161 (2018): 497-505. 4. Oyedeko, K. F. K., and H. A. Balogun. "Modeling and simulation of a leak detection for oil and gas pipelines via transient model: A case study of the niger delta." Journal of Energy Technologies and Policy 5.1 (2015): 16-27. 5. Mykoniatis, Konstantinos. "A real-time condition monitoring and maintenance management system for low voltage industrial motors using internet-of-things." Procedia Manufacturing 42 (2020): 450-456. 6. Mujica, Luis Eduardo, Magda Ruiz, and Juan Manuel Mejía. "Leak detection and loca- lization on hydrocarbon transportation lines by combining real-time transient model and multivariate statistical analysis." Struct. Hlth. Monit 1.2 (2015): 2350-2357. Iwaszenko, Sebastian, et al. "Detection of Natural Gas Leakages Using a Laser-Based Methane Sensor and UAV." Remote Sensing 13.3 (2021): 510. 7. 8. MacCarthy, G. A. K., et al. "Analyzing Domino Effects Occurring on Gasoline Storage Tanks at the Bulk Oil Storage and Transportation (BOST) Depot." Russian Journal of Construction Science and Technology 5.2 (2019). 9. Marsh LLC. “100 Largest Losses in the Hydrocarbon Industry, 1974 - 2019”. Online source available at: https://www.marsh.com/content/dam/marsh/Documents/PDF/ UK-en/100-largest-losses-in-hydrocarbon-history.pdf 10. Wang, Jinjiang, et al. "A new paradigm of cloud-based predictive maintenance for in- telligent manufacturing." Journal of Intelligent Manufacturing 28.5 (2017): 1125-1137. 11. [11] Hussels, Maria-Teresa, et al. "AGIFAMOR—Application of distributed acoustic and fibre optic sensors for continuous monitoring of pipes." Proceedings of the 12th Pipeline Technology Conference, Berlin, Germany. 2017. 12. Boaz, Lawrence, Shubi Kaijage, and Ramadhani Sinde. "An overview of pipeline leak detection and location systems." Proceedings of the 2nd Pan African International Conference on Science, Computing and Telecommunications (PACT 2014). IEEE, 2014. 13. Chis, Timur. "Pipeline leak detection techniques." arXiv preprint arXiv:0903.4283 (2009). 14. Fiedler, Jonathan. "An overview of pipeline leak detection technologies." American School of Gas Measurement Technology (ASGMT), Peabody, MA, US (2014). 15. Reber, Konrad. “Eddy Current Testing in Pipeline Inspection.” 10.1002/9781119019213. ch36. (2015). 16. Atherton, David. (1989). Magnetic inspection is key to ensuring safe pipelines. Oil and Gas Journal; (USA). 87:32. 10.1016/S0963-8695(97)80905-X. 17. Lee, Jinyi, Lee, Hoyong and Berkache, Azouaou: Novel Approaches for Nondestructive Testing and Evaluation. 10.3390/books978-3-0365-3600-2 (2022). 18. Liang, Yabin, et al. "Loosening monitoring of a threaded pipe connection using the electro-mechanical impedance technique—Experimental and numerical studies." Sensors 18.11 (2018): 3699. 19. Thiberville, Caitlyn et.al. “Modeling of Smart Pigging for Pipeline Leak Detection. SPE Production & Operations”. 35. 10.2118/198648-PA. (2020). Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 23 Authors Jana Frank Henkel AG & Co. KGaA Country Business Head Singapore & Malaysia Jana.Frank@henkel.com Michael Honné Henkel AG & Co. KGaA Head of MRO 4.0 Michael.Honne@henkel.com Kourosh Bahrami Henkel AG & Co. KGaA Corporate Vice President Henkel – Adhesive Technologies Kourosh.Bahrami@henkel.com Jens Schoene Henkel AG & Co. KGaA Global Technical Customer Service Management Jens.Schoene@henkel.com

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 25 1. Widening the application range of fiber optic sensing Distributed Fiber Optic Sensing (DFOS) has been successfully applied for in the oil and gas industry for many years, first with Distributed Temperature Sensing (DTS), then Distributed Strain Sensing (DSS) and, most recently, Distributed Acoustic Sensing (DAS). Over the last years, the performance of DFOS systems and the related knowhow have increased while DFOS hardware prices have dropped, broadening the appli- cation range of fiber optic-based pipeline monitoring to new markets such as the chemical and manufactur- ing industry to monitor the risk at corrosion under in- sulation on pipelines, tanks, and cryogenic facilities, as well as the utility sector (drinking water, sewage water, district heating, …). For the utility sector, and especially the drinking water sector, additional challenges arise compared to oil & gas pipelines. These include: • Pipelines can be of a very old age (up to 100 years), with the pipeline condition and even the route not fully known at the start of a project. • A very wide variety of pipeline materials are used (concrete, steel, cast iron, asbestos cement, PVC, polyethylene, and several others). • Pipelines are buried in heavily urbanized areas, under roads, railways, canals, and other infrastructure. Both in the chemical sector and in the utility market, there is a vast volume of existing, ageing pipeline as- sets that are much more prone to leakage or corrosion than newly constructed pipelines. To minimize the maintenance (opex) and replacement (capex) expendi- tures, inspection methods should therefore focus on retrofitting existing water pipelines with fiber optic monitoring. 2. DAS and DTS working principles Distributed Acoustic Sensing systems (DAS) and Distributed Temperature Sensing systems (DTS) are optoelectronic instruments that record acoustic vibra- tions and temperature along the length of a fiber optic cable. DAS and DTS are distinguished from (industrial) IoT sensors by the fact that they give a continuous and distributed acoustic or temperature profile down the length of the sensing wire rather than at discrete sens- ing locations. The physical principle behind DAS and DTS is as follows [1]: 1. The interrogator fires light pulses into the fiber using a highly coherent laser. 2. Photons reflect on small inhomogeneities in the glass matrix due to Rayleigh (for DAS), Raman or Brillouin (for DTS) scattering. These reflections are dependent on thermal and acoustic vibrations on the fiber and return to the interrogator where they are recorded and analyzed. 3. Since a pulsed light source illuminates only a piece of the fiber at a time, this allows for a distributed measurement of the scattering on the fiber that is highly spatially accurate, a principle known as OTDR (Optical Time Domain Reflectometry). As a result, a DAS or DTS system essentially converts a single fiber into a string of thousands of highly sensi- tive acoustic vibration or temperature sensors. Due to the optical nature of the measurements, a single DAS or DTS device has a range of up to 90 km, is not vul- nerable to electric interference, and is fundamentally ATEX-proof. Due to the huge amounts of data produced by distrib- uted sensing systems, a data management, processing, and visualization approach is essential. The interroga- tion devices are usually connected to a processing unit (such as an industrial PC or a server) that handles data storage and processing. 3. Detecting early stages of corrosion The CUI-CONTROL system was developed by Fluves, an engineering company specialized in fiber optic moni- toring. It consists of several components: 1. A fiber optic cable is attached to the outer cladding of the insulated pipeline, tank, or cryogenic facility. There is no need to dismantle or rupture the clad- ding, insulation, or pipe.

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 27 Figure 3 The return on investment of installing CUI- CONTROL is less than two years. monitoring. The overall return on investment of a CUI-CONTROL monitoring installation was calculated for a fictitious plant with 155 km in insulated pipelines, which is rep- resentative for a large chemical production facility. In this example, the return on investment of installing the CUI-CONTROL system is less than two years Figure 3). 4. Locating leaks in water pipelines For underground utility pipelines, such as trunk mains for drinking water, retrofitting by trenching an ex- ternal fiber is uneconomical due to the presence of other infrastructure above the pipeline. For this rea- son, a pipeline monitoring system that uses a fiber optic cable installed inside the pipeline was devel- oped: the DALI (Distributed Acoustics for Leakage and Intrusion) system. It was jointly developed by Fluves, an engineering company specialized in fiber optic monitoring, and Vigotec, a manufacturer and distrib- utor of pipe systems and engineered plastics. The com- ponents are similar to CUI-CONTROL although there are some differences: 1. A fiber optic cable is installed inside the pipeline. The cable housed in a durable cable mantle that is certified for safe use in drinking water. An innova- tive installation system was developed that allows to install the cable in the pipeline while it is pres- surized and in operation. Figure 2: Corrosion was detected on the exact points that the CUI-CONTROL system pointed out. In response to the pilot test results, Robin Guldentops, the Asset Manager ESP/IL at BASF, said that “CUI- CONTROL was able to find the exact locations of poten- tial corrosion sites. The system is able to measure the degree of risk at corrosion with great precision, and the system has the added advantage that it can be ap- plied on the outer layer of the jacketing, without hav- ing to dismantle anything”. 3.2 CUI-CONTROL return on investment The installation of a fiber-based CUI monitoring sys- tem provides direct financial gains to the pipeline by reducing inspection costs, reducing asset damage and downtime due to CUI, prolonging the asset lifetime, and reducing energy losses. Additional benefits that happen are reduction in downtime and welding costs, reduction of urgent leak repair, improvement in in- spection planning, the gain of an active leak detection and fire detection system in place. Not to forget: the positive publicity because innovation steps are being made, and on the other side avoiding negative public- ity on environmental risks. The fiber that is placed on the pipes also opens the door to add-on applications such as steam trap monitoring and pipeline vibration

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 29 Figure 5 Results from blind tests. Top: frequency spectrogram. Bottom left: view during synthetic leak test. Bottom right: view of lawnmower used for intrusion detection test pipeline owner. Figure 5 shows results of two blind tests in which a synthetic leak was created by open- ing an air release valve on the pipeline (Figure 5, bot- tom left) and by driving over the pipeline with a lawn mower (Figure 5, bottom right) The two events have a clearly distinct acoustic signature, as seen in the spec- trogram (Figure 5, top). Numerous synthetic leak tests were performed varying valve types, valve openings, and leak flow rate, and were used to develop a classifi- cation system using machine learning, in order to cor- rectly identify different types of events such as leaks, vehicles, and intrusions. overview of the pipeline status. The online dashboard displays the overall sound level, the timing and loca- tion of any incident alerts (e.g. leaks) along the pipe- line, and sends e-mail alerts to the pipeline operator when an incident occurs. 4.2 Deployment types Having been successfully validated, DALI can now be installed on existing infrastructure with a novel system that allows to insert the cable without taking the pipe- line out of operation. Several use types are possible: After the machine learning system was set up and suc- cessfully validated during the blind tests, the mon- itoring system was implemented in an operational dashboard that provides the pipeline operator a 24/7 • Permanent monitoring, in which the fiber and the DAS sensor are permanently installed on the pipe- line, allowing for permanent, 24/7 tracking of the pipeline status. This is most applicable for large, critical pipelines.

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 31 6. Acknowledgements We gratefully acknowledge FARYS for their support in the development of DALI and the pilot deployment. We gratefully acknowledge BASF for their enthusiasm during the whole pilot process and the further roll out of the CUI-CONTROL system. References 1. A. H. Hartog, M. Belal, and M. A. Clare, “Advances in Distributed Fiber- Optic Sensing for Monitoring Marine Infrastructure, Measuring the Deep Ocean, and Quantifying the Risks Posed by Seafloor Hazards,” mar tech- nol soc j, vol. 52, no. 5, pp. 58–73, Sep. 2018, doi: 10.4031/MTSJ.52.5.7. Authors Thijs Lanckriet Fluves nv Project Manager thijs@fluves.com Thomas Van Hoestenberge Fluves nv CEO thomas@fluves.com Timothy Van Caelenberghe Fluves nv Sales Advisor timothy@fluves.com PHOTO CONTEST “Working in the Pipeline Industry” Submit your Photo www.pipeline-conference.com/photo-contest

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 33 1. An increasing and worldwide concern Data reinforces this is the case globally. Some examples: For sure, 30 or 40 years ago, when this HP gas pipe was installed, it was in an empty land, with no specific safety issue. But today, close to various sections of this pipe, there are residential buildings, schools, shopping areas and factories. Moreover, there is a plan to build a new mall at less than 1000 m from the gas line and it is just impossible to shut off the gas during the works. This is exactly the kind of concern that every gas company (or oil, chemicals, etc…) meets in any country. It is a world- wide issue. Considerable progress has been made in recent years, especially regarding pipeline location accuracy (warn- ing & GIS systems) and prior notification before start- ing any works (one Call, Dial Before You Dig). However, third party interference – mainly excavation damage – is still the first cause of accidents on gas pipes. • US Department of Transportation 2014 report estab- lishes that during 1993-2012 there were 1630 inci- dents caused by third party damage on gas lines in the USA, with 141 deaths and 440 injuries (Table 1). • • European Gas Pipeline Incident Data Group (EGIG) reports in 2015, 1309 incidents for the period 1970- 2013 on 143 000 km of transportation lines, with 35% due to external interference (Figure 1). In Japan, Keijo Gas Co 2009 reports 37.7% of inci- dents (2003-2007) due to third party construction (Figure 2). Today, most end-users are conducting QRA studies to determine the sections of their pipelines impacted by this risk and to identify the appropriate solutions, for both new projects and existing lines. Table 1: Comparison of Consequences of Third-party Excavation Damage incidents Over 20 Years Figure 1: Distribution of incidents (2004 - 2013)

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 35 Figure 3: The Ghislenghien accident The disaster caused 23 deaths and 132 injured. Some bod- ies were found up to 100 m from the explosion. The shock at the magnitude of the disaster was felt not only in Belgium, but across Europe and in France in particular. 4. The French reaction to Ghislenghien There are on the French territory 50,200 km of pipe- lines carrying hazardous products (36,500 km of which for HP gas transmission) with an average age of 26 years (2009). After the Ghislenghien accident, the risks posed by the age of the network, growing urbanization encroach- ing on pipeline reserves and the lack of recent, relia- ble Quantitative Risk Assessment (QRA) were deemed as no longer acceptable. The French government made an “order” (which does not require a parliamentary vote) published on 2006 August 4th. It is called “arrêté multifluides”. locations and protection measures. Regulations for prior notifications, declarations and authorizations were substantially reinforced. Generally speaking, all actions to be taken were aimed to enhance security of buried lines. Regarding specifically the risk of third-party interfer- ence, this “order” led to several legally binding guides, established by a committee composed of all companies involved in transport of hazardous products by buried pipelines (called “GESIP). One of those guides sets the rules for QRA as seen in Figure 4. These new obligations required the operators to dra- matically change their practices to manage third- party damage prevention. Due to the level of measures to be implemented in such a short time frame, oper- ators had to be innovative. Examples of this innova- tion were early use of drone surveying and the use of optical fibers for pipeline monitoring. The” SIG” (geo- graphic information system) was also strengthened, a system of ONE CALL was established (eg Dial Before You Dig) and training was made mandatory for exca- vator operators. This order stated new rules for the design, construc- tion and operation of transmission pipes. New values for danger thresholds and calculation of lethal effects were adopted, leading to important changes in class But the most substantial changes may have been the ones brought to mechanical protection, due to the challenging nature of the issue.

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 37 5. Mechanical protections: a pressing need for innovation GdF, Yannick Joubeaux was invited to join this group in 2005. When the studies were conducted, several hundred kilometers of existing transmission pipelines were re- vealed to need a mechanical protection to comply with the new security regulations. All to be completed by the end of 2012. At the time the only possibility was to install reinforced concrete slabs above the pipelines. Although theoreti- cally possible, this was practically inconceivable. Such works would need to manufacture and transport hun- dreds of km of concrete slabs and considerable re- sources (both personnel and equipment). As an ex- ample one full truck will transport about only 100 m of concrete protection slabs. Pipeline owners, primar- ily Gaz de France (now named ENGIE), were also con- cerned with the practicality of removing concrete slabs in cases of inspection or repair. The R&D Department of Gaz de France took the initi- ative to create a working group with the goal to sug- gest innovative solutions. As a regular contractor for 6. The idea: replace concrete with plastic! The terms of reference for mechanical protection were to find an easier, lighter and cheaper solution to con- crete. Yannick suggested designing a plastic plate to protect the pipes. Proposing to replace 150 mm of re- inforced concrete by 15 mm of plastic was not at first regarded as the magic bullet. However, after an ex- tensive program of testing various raw materials and processes (with GdF its own tests in their laboratory), HDPE plates were recognised as a reliable solution. GdF R&D department reported the following at the IGRC conference in 2008 (Figure 6) Figure 5: The logo of the IGRC 2008 Figure 6: Extract from the IGRC report 2008

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 39 Figure 7: Table of risk reduction or aggravation factors

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1. Defining aging pipelines and their risks There is no universal definition for an aging pipe- line, but regulatory organizations make an effort to at least provide some criteria. In response to a series of gas pipeline incidents in 2011, the US Department of Transportation (DOT) and the Pipeline and Hazardous Materials Safety Administration (PHMSA) enforced a call to action on the repair, rehabilitation and replace- ment of the highest risk pipelines and it is worth not- ing that pipeline age is among the high risk indicators.3 Since 2005, PHMSA has also began conducting an annual inventory report which charts the reduction of pre-1970 gas and hazardous liquid pipelines, sug- gesting pipelines 35 years or older may be considered within the “aging” category.4 Age alone may not be the only criteria for defining aging pipelines though. The ability to categorize a pipeline as “aging” is also made possible by charting a pipeline’s periods of failure over a period of time and conducting a reliability analysis. Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 43 A reliability analysis can be applied to most pipeline lifetimes and projects and they typically discover three periods of failure rate in the project lifecycle: • • Early failure period Intrinsic failure period • Wear out failure period If we apply this model to the installation of a pipeline, the early failure period can be recognized within the expected incidents that arise when a new pipeline is installed or introduced within an existing pipeline’s in- frastructure and could be caused by installation error and poor handling. Incidents then rapidly decrease to a minimum as the pipeline transitions into an intrinsic failure period, when the pipeline is at a point where it is successfully used at an operational level and has a low failure rate. Figure 1: Table showing the reduction in miles of pre-1970 pipelines since 2005 (accurate on the date shown)4 Figure 2: A visualization of the bathtub curve, as used to define the reliability of a product

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 45 Figure 3: Atmos Eclipse non-intrusive instrumentation Figure 4: Atmos Simulation suite (SIM) pressure and temperature data without needing to penetrate an aging pipeline’s infrastructure.9 A com- bination of Atmos Eclipse and Atmos Wave Flow was used to provide a leak and theft detection system, al- lowing a solution to be installed with reduced hard- ware and project costs. Another challenge of optimizing aging/legacy pipe- lines can be seen in incidents like ruptures and explo- sions, an example of what can happen when aging in- frastructure struggles to meet the demand for cleaner burning fuels.1 The transition to carbon neutral energy will present further challenges for the aging pipeline infrastructure due to concerns that the fuel can cause hydrogen embrittlement, when the metal degrades, resulting in a leak or rupture.10 Simulation software like Atmos SIM can calculate and forecast pipeline pressure and flow thus helping pipeline operators run aging pipelines safely and cost effectively. In ad- dition, it uses model-based leak detection to detect and locate leaks in gas pipeline networks effectively, minimizing the consequence of leaks .11 Some aging pipelines are restricted in terms of their audit trail too. For example, some pipeline operators still refer to physical maps of their pipeline network. Again, simulation software like Atmos SIM is effec- tive by using real-time modeling offering more visi- bility of the actual pipeline operating conditions than a hand-drawn map. With external factors presenting new challenges to aging pipelines every day, new pipe- lines are being increasingly considered. But for pipe- line operators who have no choice but to repair and maintain their existing infrastructure, leak detection systems such as Atmos Wave Flow and hardware such as Atmos Eclipse can be retrofitted to an aging pipeline and are a tried and tested method of effective leak and theft detection, mitigating the risk of leaks if the pipe- line fails. References 1. https://www.bloomberg.com/news/articles/2022-02-25/ china-to-fix-thousands-of-miles-of-gas-pipelines-after-blasts 2. https://www.pipeline-journal.net/news/ poland-plugs-leak-60-year-old-druzhba-pipeline 3. https://www.phmsa.dot.gov/data-and-statistics/ pipeline-replacement/pipeline-replacement-background 4. https://www.phmsa.dot.gov/data-and-statistics/ pipeline-replacement/decade-inventory 5. https://www.epa.gov/system/files/documents/2022-04/ds-tool- box-fact-sheets_water-age-mgt_final-508_revised.pdf 6. https://www.sustainalytics.com/esg-research/resource/ investors-esg-blog/esg-risks-aging-pipelines-us 7. https://mexiconewsdaily.com/news/aging-poorly-maintai- ned-pipelines-present-major-risk-to-safety-for-pemex/ 8. https://www.matcor.com/aging-pipeline-coating-systems/ 9. https://www.atmosi.com/en/resources/videos/ atmos-eclipse-non-intrusive-leak-detection/ 10. https://www.atmosi.com/en/news-events/blogs/ how-midstream-needs-to-prepare-for-the-hydrogen-economy/ 11. https://www.atmosi.com/en/products-services/ atmos-simulation-sim-suite/ Author Harry Smith Atmos International Sales and Senior Research Engineer harry.smith@atmosi.com

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 47 1. Description of the device This article concerns a device for the examination of the interior of pipelines using ultrasound technology. Such a device is designed to inspect pipelines trans- porting fluids, in particular liquids of homogeneous type. It may be, for example, water, refined hydrocar- bons or certain crude oils. Operators of transmission pipelines must regularly implement means of controlling and monitoring the integrity of these pipelines within a regulatory frame- work. Over time, with changes in the environment and operating methods, anomalies appear in these pipe- lines. With improving tehcnologies, transportation pipeline operators have to implement a large num- ber of control means or devices called intelligent pigs that are able to detect geometric anomalies, corrosion, cracks or metallurgical type anomalies. These defects can affect the base metal, welds, straight or bended parts. They can evolve and, if not treated, can lead to the loss of containment of the pipeline and seriously impact people, property and the environment. Today these operators are also facing new threats defined as illegal tappings. These defects are caused by the inter- vention of an association of organized criminals who drill the pipe, install a tap or a valve connected to a hose at the end of which a tank or other storage capac- ity is connected. These losses of products can repre- sent up to nearly 40% of the volumes lost by European refined hydrocarbon carriers (cf Concawe Report No. 12/20). The restof these losses is caused by problems of mechanical origins, third-party activity, corrosion or operation. The means currently available for detect- ing and identifying illegal tapping can be devided into three parts: • Human resources for land and/or air surveillance • Systems of monitoring and recording on the pipe- line with a monitoring and remote monitoring device • Acoustic or magnetic intelligent pig The second means requires a rather heavy infrastruc- ture and substantial investments and more if the pipe- line is already laid and in service (for example laying of optical fiber, strain gauge, composite piezo sensor and other cables and relay remote transmission sta- tions, particularly complex data processing software and maintenance of all these means). The third means which includes the two types of Intelligent pigs already mentioned: - The acoustic pig; it needs to encounter illegal tapping and therefore sufficient noise when the pig passes to be able to be detected, it is not able to detect illegal tap- ping without active tapping. - For the magnetic intelligent pig ; these are high res- olution MFL (Magnetic Flux Leakage) type intelligent pig, these pigs are designed to detect generalized cor- rosion or pitting. In the context of tapping detection, they are used in a particular way by adapting the hard- ware and software configurations. They require rather heavy means of implementation (length of tools, spe- cific handling means and associated risks and pres- ent analysis difficulties). They involve significant operating costs and cannot be used regularly and in- dependently by pipeline operators. To offer operators of hydrocarbon transport pipelines a reliable and economically viable solution, TRAPIL has developed and manufactured an instrumented inline inspection tool which, through the combina- tion of various components and computer process- ing, detects, identifies and locates clandestine deriva- tions and other types of faults which could appear on these pipes. This device is called T3 (TRAPIL THEFT TRACKER). This tool is based on the implementation of an ultra- sonic control method. The ultrasonic control module is made up of several dozen piezo-composite trans- ducers, half of which are dedicated to acoustic wave emissions and the other half dedicated to the recep- tion of these waves. Thus, to cover the complete cir- cumference of the pipe, several tens of pairs (transmit- ter/receiver) are staggered. To be able to discriminate between illegal tappings and other defects that may be present in the pipe (cracks, laminations, dents, etc.), two other rings of about ten couples are placed on the device knowing that a phase shift angle is ap- plied between each of the three rings. Thus, when the pig passes, the wall of the pipeline is locally and uni- formly traversed by ultrasonic waves.

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 49 several passages by the software. This tool makes it possible to compare the results of the automatic detec- tion of two inspections of the same pipeline, in order to highlight the differences and target changes in the pipeline condition like the presence of new elements. Once the automatic analysis has been performed, a final step is to analyse the most notable signals and anomalies using a data visualization software. This operation is carried out by trained and qualified per- sonnel with the necessary experience. This software makes it possible to view and navigate among the dif- ferent data generated by the T3 (pressure, temperature, battery voltage, navigation angles, etc.) in particu- lar the ultrasonic data, presented under several con- ventional views for this type of information (A -Scan, B-Scan, C-Scan, D-Scan). It also allows the end-user to notify events that will be displayed and saved in a da- tabase. In addition, the software integrates a module for the simultaneous display of two inspections of the same pipeline in order to be able to perform a visual comparison. Certain information or illustrations pro- duced by this tool can be extracted and attached to the inspection report. To be able to locate illegal taps or any other anomaly, the T3 pig produces a certain amount of data and pro- cess it in order to target a place and landmarks in the surroundings which aim to guide the operator to the anomaly to be investigated. Thus, the weld log, the longitudinal position between the consecutive girth welds, the angular position of the anomaly in the pipe, coupled with pressure information, navigation angles and external data, are all means which make it possi- ble to make the location of the detected elements more reliable. The speed range of passage of the T3 in the pipe allows easy programming for the operator, and this by guar- anteeing the same performances of detection, identi- fication and localization of illegal taps. The speed of propagation of the ultrasonic waves and their path in the liquid medium and in the steel of the pipe wall on the one hand, and the sampling and storage capacities of the on-board electronics on the other hand, offer a great tolerance to the variations in the speed of dis- placement while maintaining the detection and iden- tification capacities. Figure 2: Pressure recorded during an inspection

The design of on-board electronics, particularly in the choice of its architecture, active and passive compo- nents and their associations, makes it possible to limit electrical consumption. The definition of the battery which provides electrical power to the on-board elec- tronics is based on the integration of lithium cells. These cells have a high energy density and a capacity that guarantees an autonomy of more than 60 hours. The T3 pig is equipped with a low frequency electro- magnetic transmitter (22 Hz), which enables its detec- tion by above ground marker within a radius of one meter above the pipe. The information is updated by Figure 5: Side view of the assembled T3 scraper before an inspection Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 51 the recording by the above ground marker of the sig- nals produced by the transmitter present on the T3 pig and the synchronization of the internal clocks of the T3 and the above ground markers. This instrumentation makes it possible to carry out readjustment points on the route of the pipeline which aims to help the opera- tor to locate the anomalies detected. 2. Bench performance validation To verify, validate and produce technical performance specifications for the T3 tool, a test bench was built. It has several nozzles of different manufacturing meth- ods and size. These taps are representative replicas of what has been discovered on various pipes in Europe. This test bench has been a key instrument to qualify the capacity of detection of the tool on the different typical illegal tappings presented, to characterize the acoustic responses of each of them and to develop the processing algorithms embedded in the automatic analysis software. It also qualified the data visualiza- tion software. Table 1: Specifications of the T3 Scraper

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 53 3. Results obtained in real situation Once the validation of the method and the integration has been carried out on the test bench, several inspec- tions in real conditions were performed. Two pipelines located in the Normandy region (north-west of France), were inspected on several occasions. Pipeline #1: 12.75’’ x 25.3km, average thickness 7.92mm 3.2 Analysis process Once the inspection has been carried out, the recorded data is extracted and formatted, then transmitted to the analysis center. The automatic analysis developed in-house by the TRAPIL teams makes it possible to de- tect, identify and locate defects such as illegal taps and to quickly submit an analysis report. The automatic analysis software allows analysis of the data generated by the T3 pig. This analysis takes place in several steps: Pipeline #2: 12.75’’ x 43.7km, average thickness 7.14mm • Automatic detection of girth welds, 3.1 Reproducibility of the measure Given the nature of the faults to be detected and the monitoring strategy, one of the essential points to be validated is the reproducibility of the measurement. Knowing that the information recorded is the ampli- tude of the analogic signal and the time of flight of the echoes, it was necessary to check the level of re- producibility obtained. Thus, the average max ampli- tudes, the average number of echoes and the average flight time per tube have been compared, it can be ob- served on the graphs below that the results obtained are particularly close and therefore make it possible to easily compare several successive inspections (the or- ange and blue curves on each graph correspond to the two rows of probes mounted on the T3 pig). • Creation of pipe tally, • Illegal Taps detection: automatic data analysis, tube per tube, looking for elements with the typ- ical signature of illegal taps. For each illegal tappings type indication a probability of identification is associated. This probability is estab- lished according to several criteria such as: • The signal-to-noise ratio in the area surrounding the suspect indication, • The variation in the number of echoes, • The slope of the amplitude drop, Figure 9: Statistics obtained during two successive inspections of pipeline # 1 Right and left (amplitude/number of echoes and time of flight)

Pipeline Technology Journal - 4/2022 RESEARCH • DEVELOPMENT • TECHNOLOGY 55 Tables 2 & 3: Defect types found on Pipeline #1 Tables 4 & 5: Defect types found on Pipeline #2 are planned. Thus, the returns of ten controls are being compiled on pipeline #1 and five on pipeline #2. Surface checks are carried out in particular with an electromagnetic pipe detector. An excavation is also scheduled on one of these points in connection with an electrical disturbance, even if the risk of an illegal tapping has been lifted. 5. Conclusions The primary objective of the T3 "TRAPIL Theft Tracker" is to meet the particular need to detection of illegal taps, whether the sampling is active or not during in- spection. Only the defects that may be related to this type of indications are therefore identified during the inspection performed with the T3.

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Pipeline Technology Journal - 4/2022 ask the experts 59 Find more of your questions answered here: www.pipeline-journal.net/ news/ask-experts The Experts David Stobb, Principal Pipeline Engineer, DNV David Stobb has been with DNV for over 26 years and has been involved with the deployment of real-time transient mod- el-based leak detection systems for transmission pipelines. In addition to leak detection systems implementations, he pro- vides technical oversight to a team of engineers and consul- tants as they deliver various solutions involving transient hy- draulic models. Victoria Monsma, Senior Pipeline Integrity Specialist, DNV Victoria is a Senior Integrity Specialist at DNV. She provides ex- pert technical advisory services for oil and gas companies, in- cluding design and post-construction verification of oil/gas transmission pipelines, safety and integrity assessments, asset integrity management programs, and many other aspects of pipeline technology. Victoria is a Subject Matter Expert in the field of reuse of exist- ing natural gas networks for the transport of hydrogen. She is also involved in the development of hydrogen service portfo- lios, methodologies, guidelines, and service specifications. With a broad range of expertise, Victoria supports DNV’s customers in making informed decisions when converting their existing assets to hydrogen. Victoria is a member of a working group developing Dutch standards for pipelines NEN 3650/3651- Requirements for pipeline systems. Chris Davison, Product Manager, DNV Chris has 25 years of experience deploying, maintaining & supporting real-time transient model-based leak detection systems. He spent the last 13 years with DNV as a Principal Consultant and subject matter expert. Chris recently assumed the role of Product Manager for Synergi Pipeline Simulator, DNV's transient flow simulation software, and drives the future strategy, roadmap, and QA for this internationally recognised tool. He is based in the UK and has overseen several leak de- tection projects in the EMEA & APAC regions. With each issue of the journal, the "Ask the Experts" section focuses on a new topic of particular relevance to the pipeline industry. People from the international pipeline community are invited to send in their questions which will afterwards be answered publicly by selected experts from the respective field. This issue's partner staff and a communication environment that pro- motes the relay of key operational details. Regardless of the leak detection system you invest in, to truly un- lock its potential, pipeline control room and support or planning staff must stay up to speed on regulations, abnormal field operations, measurement infrastruc- ture status and capabilities, facility changes, and un- derstand how that influences day-to-day operations while having a good overview of the network and the internal and external factors impacting it. An operat- ing company benefits greatly from having dedicated leak detection staff to stay abreast of all this important information. Unfortunately, in a recent industry sur- vey of pipeline operators, skills shortage and an ageing workforce were cited as the second most significant barrier to growth after political risk and instability. This reiterates the need for regular training to ensure your leak detection support staff and controllers are fully trained. Realistic simulation environments to train pipeline controllers will help them recognise and respond to abnormal pipeline behaviours or emergen- cies while ensuring that your leak detection systems are up-to-date and compliant with legislation. Q5) How can I change my instrumentation to im- prove leak detection? David Stobb: For optimal leak detection, it is vital to secure high-quality, high-accuracy flow and pressure measurements along the pipeline. If you are trans- porting a fluid highly dependent on temperature, it is also essential to have frequent temperature meas- urements along the pipeline. For Real-Time Transient Model (RTTM) based leak detection systems, those measurements should be provided on a 1 to 20-second scan period. Q6) What do I look out for when investing in a leak detection software system? David Stobb: A sound leak detection system is robust, not just in what the software offers but also in how ef- fectively it performs under all operating conditions. It is also essential to consider how comprehensive and flexible the solution is. As the industry evolves, you need a solution that can handle variations. Victoria Monsma: Always opt for a fast, robust, relia- ble solution based on proven technology. Also, I rec- ommend using a combination of different techniques.

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