Abstract This paper discusses case studies of high voltage direct current (HVDC) & high voltage alternating current (HVAC) crossing Pipelines right of way (RoW) showcasing the effects of alternating current (AC) interference with respect to AC corrosion and Safety Hazards while running parallel and crossing at different angles to the same pipeline at multiple locations in a short span of length and restricting the AC current & safe voltage within maximum tolerable limits through deployment of mitigation measures as per industry code of practice, globally. The paper discusses effects of both powerline fault conditions as well as induced steady state on underground pipelines, AC interference modelling for enhancing effectiveness of Cathodic protection and analysis of AC interference mitigation measures. A comprehensive technical analysis involving collection of baseline information on both the pipeline and powerline and determining powerline fault current effects adjacent to each tower, on the pipe wall, the pipe coating, and the resulting safety hazard for pipeline personnel. Introduction When a pipeline is parallel to a high voltage power line for a significant distance, voltages can be transferred to the pipeline under both normal power line operating conditions and short-circuit conditions on the power line. These voltages can result in electrical shock hazard for maintenance personnel; they can also be detrimental to the integrity of cathodic protection equipment, the pipeline coating, and the pipeline steel, particularly during short-circuit conditions. The challenge is to identify the extent of AC interference on underground pipelines and mitigate these effects for the protection of pipelines. Problem Statement There are three modes of AC interference that can cause damage to pipeline systems and present an electrical shock hazard to pipeline personnel, namely; inductive coupling, resistive (conductive) coupling and capacitive (electrostatic) coupling. INDUCTIVE COUPLING: Inductive coupling occurs both under steady-state (normal operation) and fault conditions and the magnitude of the induced AC voltage depends on the phase current, phase wire configuration, layout and distance between pipeline and transmission line. The induced voltages reach the maximum values at discontinuities and reduces subsequently along the pipeline.

ABSTRACT INTRODUCTION Casing required for all liquid crossings (some isolated exceptions allowed) Casings for flammable gas are not required in most instances. Casings required for non-flammable lines (i.e., water, steam)

ABSTRACT A metallurgical investigation of multiple, externally-initiated, in-service leaks on an above-ground, mineral wool insulated, oil emulsion pipeline concluded that the likely crack-initiating mechanism was stress corrosion cracking (SCC). However, the leaks occurred on an above-ground pipeline and as such, it was not clear to what extent the classic mechanistic principles of SCC identified on buried carbon steel pipelines were applicable to the current instance of SCC, if at all. A root cause analysis (RCA) was used to identify the likely contributors to the SCC, including stress, environment, and the carbon steel material. As part of the RCA, laboratory testing and chemical analyses were performed. The purposes of the laboratory testing were to (1) reproduce the external cracking found in the pipeline, and (2)evaluate the effects of insulation source, electrolyte concentration, and temperature on the SCC behavior of pipe steel in laboratory-produced leachates. Testing consisted of cyclic potentiodynamic polarization (CPP) tests, slow-strain rate (SSR) testing using leachates solutions made from mineral wool insulation, and chemical analysis of those solutions. This paper outlines key findings from the laboratory testing and a current understanding of the primary environmental contributors given that SCC on above-ground insulated pipelines is not commonly observed. INTRODUCTION Stress corrosion cracking of carbon steel has been reported on buried carbon steel pipelines since the 1960s. However, the SCC examined in this study occurred on an above-ground pipeline, which required a closer evaluation of the mechanisms and assumptions associated with SCC on carbon steel pipelines. Ultimately, an objective of this work is to understand whether the mechanisms of SCC identified on buried pipelines are applicable to the SCC observed on an above-ground pipeline. A literature search for SCC on above-ground pipelines was performed and found no reported instances of SCC on above-ground, carbon steel pipelines. However, anecdotal evidence from multiple producers suggests this phenomenon may be more common than recognized. For context, the SCC behavior on buried pipelines has been investigated and scrutinized in the literature. 1,2,3,4,5 External SCC on buried pipelines occurs in two forms: high pH SCC and near-neutral pH SCC. 6,7,8 The cracking morphologies for high pH SCC and near-neutral pH SCC are typically intergranular and transgranular, respectively. Several factors, including, the transported product, the coating type, the operating temperature, the level of cathodic protection, and the soil environment, contribute to the susceptibility and type of SCC observed. 4,6

ABSTRACT This paper provides a brief analysis on the cause of a reported gas leakage incident that happened on the high pressure Gas Transmission System of Greece. The conditions and scenarios investigated in the paper are limited to the impact of a direct lightning strike to some adjacent tree/bush or a direct lightning strike, over or near the respective pipeline branch, to the earth. The paper particularly discusses the conditions that have caused the reported incident and a dedicated risk assessment tool that is currently being developed. The risk assessment tool provides the probability to have a severe coating defect on buried gas pipelines, under episodes related to direct lightning strikes in the adjacent soil. Severe coating defect on the pipeline does not necessarily mean metal wall fusion and gas leakage as a consequence. However, a severe defect may result in the pipeline’s coating be left weakened/damaged and thus susceptible to further deterioration (i.e. wall fusion) in the event of future lightning strikes either on the power lines or directly onto the ground. INTRODUCTION The belief that buried structures are protected against lightning is being abrogated by some serious incidents related to buried Gas pipelines. 1,2,3 Even though soil is interposed between the lightning strike point and the pipeline system, under special circumstances the soil can become conductive allowing lightning current to reach the pipeline. To this extent, the presence or the development of coating holidays may allow some portion of lightning current to be injected into the pipeline’s metallic wall. The high current density and especially the long stroke component of lightning may cause perforation of metallic wall. 4,5,6,7 This paper provides a short analysis to elucidate the cause of a reported gas leakage incident that happened on a secondary branch of the high-pressure underground Gas Transmission System in Greece. The findings in the area testify that a lightning strike has hit the ground very near (i.e. 5m) to the route of the gas pipeline. This has resulted in the perforation of the metallic wall and to the ignition of the flammable gas.

ABSTRACT With the broad use of three layer polyethylene (3LPE) coatings for external corrosion protection of oil and gas pipelines in the world, more and more failures mainly relating to coating adhesion problem were observed. Substantial on-site failure case studies and investigations showed that 3LPE coatings generally retained good adhesion to steel pipelines without being put into service, but complete disbondment of FBE primer to steel substrate have been observed, with some of them noted even after 2-3 years in service. A review of related literatures and broadly used 3LPE standards revealed that current standards are inadequate in assessing the long term performance of 3LPO coatings and the longer term hot water immersion test at elevated temperature was recommended. In this study, a comparative study was conducted by the laboratories on thirteen (13) different 3LPE coatings from ten (10) coating suppliers. Peel strengths of the applied coatings were firstly examined, and the coatings were then soaked in water at temperatures of 50, 70, and 80°C for 28 days. After that the hydrothermally aged coatings were tested for peel adhesion again. In addition, edge disbondment of the selected coatings was periodically assessed during immersion. The paper specially focuses on the disbondment issues on 3LPE coatings and is aimed to establish an applicable and effective test program to identify the problems. The disbondment noted on the tested 3LPE coatings showed good agreement with the failure mode observed in field. The test program can be used to screen weak 3LPE coatings during coatings selection and also it can be used to identify potential problems existed in coating application. INTRODUCTION With the high growth in global pipeline industry, the use of pipe coatings is increasing significantly. Among the versatile pipe coatings, 3LPE coatings grow in popularity in the oil and gas industry and are frequently used in most areas of the world because of their combining advantages from polyolefin coatings and fusion bonded epoxy coatings (FBE) 1 . A typical 3LPE coating comprises of three layers: an inner FBE primer, a polyethylene (PE) topcoat, and a co-polymer PE adhesive middle coat to bond the epoxy primer with PE topcoat. The tough PE topcoat offers the enhanced mechanical protection to damages caused by rough handling, installation, and operation, while the FBE coating provides the long-term corrosion protection owing to its broad range of desirable characteristics, such as excellent adhesion to steel, high electrical resistance, and low oxygen permeability, etc. 2 Despite the advantages of the 3LPE coatings and the improvements in the coating technologies, unexpected adhesion failures of the coatings have been reported around the world where the coatings have been used 3,4,5 Even though it is debatable whether these adhesion failures put the pipeline at risk of corrosion, many believe the disbondment of 3LPE between the FBE and the steel creates potential high risk of CP shielding 6 . For the demonstration purpose, Figure 1 shows the examples of the disbondment failure of 3LPE coatings that were observed in field.

ABSTRACT Blisters are one of the most frequently observed failure modes in FBE coatings of buried pipelines. Initial small disbondment defects at the coating-steel interface, due to embedded abrasives and voids are potential sites for blisters to form and grow. Two types of blisters are observed in FBE coatings - non-osmotic and osmotic blisters. Non-osmotic blisters are associated with water absorption in FBE coatings. Subsequent coating swelling induces compressive stresses in the coating and eventually buckling of the coating at the disbondment locations in the FBE-steel interface to form blisters. Our previous investigation has shown that an initially small disbondment must grow to sufficiently large size before non-osmotic blisters can be formed. Osmotic blistering is a result of an extra amount of water diffusion into the disbondment area due to salt contamination and causing osmotic pressure buildup at the disbonded locations. The osmotic pressure needed to blister FBE coatings is dependent on the size of disbondment. For an initially small disbondment, the pressure required to blister the FBE coating could be very high and the size of disbondment will need to increase before a blister can form. The driving force to enlarge the disbondment is the osmotic pressure generated from the soluble salts. The purpose of this work is to study the blister initiation mechanism. With a clear understanding of the blister initiation mechanism, steps can be taken to mitigate blister formation and improve the integrity of external FBE pipeline coatings. INTRODUCTION Two types of blisters are observed in fusion bonded epoxy (FBE) pipeline coatings. These blisters are (1) osmotic blister associated with water diffusion through coating due to the presence of soluble salt on substrates or interlayer, and (2) non-osmotic blister due to swelling and buckling of FBE films associated with water absorption in the coating. In 2012 Guo, Lo, and Chang published a paper on the non-osmotic blister mechanism of FBE pipeline coatings 1 . In the paper, the authors demonstrated that an initially small disbondment must grow to a certain size before the swelling stress in the coating can cause buckling of the FBE film.

ABSTRACT Shielding of cathodic protection (CP) current is often a significant concern in the selection of pipeline coatings. However, CP shielding properties may be overlooked in the selection of geosynthetic materials, which are regularly installed near pipelines for a variety of applications. Unfortunately, limited information has been published on the CP shielding properties of geosynthetic materials. This study evaluates the CP shielding effects of 19 commercially available geosynthetic material samples through measurements of water permeability and influence on CP circuit resistance. Water permeability was measured by timing the flow of a set volume of water through each sample. A CP test circuit consisting of a magnesium anode, a steel coupon as a cathode and tap water as an electrolyte was utilized to investigate the influence of each sample on CP circuit resistance. CP circuit current and coupon potentials were measured and compared for multiple operating conditions. The results demonstrated that in an aqueous environment, geosynthetic materials that are permeable to water do not completely shield CP. INTRODUCTION When designing and constructing pipelines, external corrosion control is a major consideration. Primary methods of external corrosion control include the effective selection of materials and the application of an external barrier coating. CP is often utilized as a secondary method of external corrosion control, especially in conjunction with external barrier coatings. 1 CP requires a complete electrical circuit to function. In a typical pipeline CP system, electrical current must be able to flow from the buried anode(s) through the electrolyte (soil) to the cathode (pipeline). Electrical shielding occurs when CP is diverted or prevented from its intended path. 1 Pipelines are typically protected by external barrier coatings, which are meant to have high electrical resistance values to “isolate the metal substrate from direct contact with the electrolyte” and “prevent any electrochemical reactions on the metal surface of the pipeline.” 2 However, this high electrical resistance can cause issues in cases where pipeline coatings become disbonded. In these cases, the pipeline surface under the disbonded coating can become electrically shielded from CP current. While CP shielding is fairly well researched for pipeline coatings, 2-6 less information is available for geosynthetic materials, many of which are commonly used during pipeline construction.

ABSTRACT Polymer liners, especially polyethylene liners are commonly used in carbon steel lined pipe for water injection service. Historical seawater/produced water applications have a typical design temperature of 60°C or less and are usually operated from 30 to 40°C. Handling of oilfield water, in the operating temperature range between 60°C to 90°C becomes a challenge. Very limited applications have been reported at elevated temperature and details of specific operational conditions are not known to validate safe and reliable performance at high temperatures. This paper explores the current state of the art for the increased temperature limits of high density polyethylene liners and identifies the most credible failure modes to be mitigated. A testing campaign was conducted on commercial grade high density polyethylene to de-risk the application of the liners to operating temperatures up to 80°C. A series of small scale testing were performed to understand the material properties under different conditions (temperature, oil saturation, oil/water concentration etc.). Performance properties of typical high-density polyethylene were benchmarked against a proposed raised temperature polyethylene grade. The material properties were used as an input to a finite element analysis tool to evaluate the strains experienced by the liner at various locations such as a weld bead, flange connection and vent location. The testing and analysis provides increased confidence to expand the operational envelope of polyethylene liners to higher temperatures in produced water service. A condition monitoring plan has been developed to record the liner condition during operation. INTRODUCTION While the pipeline industry has wide experience handling produced water, it is often proven to be cumbersome due to the corrosivity of the fluids to carbon steel or costly when CRA (corrosion resistant alloy) are selected. Industry wise, plastic lined carbon steel pipeline have been widely adopted for onshore water handling, mostly in Canada where only low concentrations of gas are present in the produced and source water. In Alberta, there are almost 7900 km of lined steel pipelines, according to a report by the local regulator (Alberta Energy Regulator, 2013). Of that inventory, 4700 km is in water service, equating to a quarter of all water pipelines. The remainder of plastic liners are mostly in multiphase service.

ABSTRACT The AC interference between High Voltage AC (HVAC) power lines and pipelines has been modeled with various software programs, all of which have a variety of input data which creates various results and outputs. Important aspects such as the soil resistivity along the pipeline route can have a significant impact on the pipelines coating resistance. This in turn can affect both the computed AC voltages and more specifically the current densities, both of which can significantly affect personal safety and corrosion of the pipeline. The spacing of the soil resistivity measurements can have a significant effect on the accuracy of the modelling results, which in turn can affect the mitigation design and integrity. For example, measurements at 1,000 ft vs. 5,280 ft can have dire consequences on the accuracy of the modelling, the understanding of the interference, and therefore how an owner/operator responds to the threat. However, the measurements themselves do not affect the corrosion threat. Other aspects such as the power line Longitudinal Electric Field (LEF) or Electro-Magnetic Force (EMF) may also be used to “calibrate” the AC Interference computational model, especially where power-line load data is absent. This paper addresses the critical importance of collecting adequate data for the AC Interference studies, to prevent costly installations and to mitigate the incorrect positioning of AC Mitigation systems, due to inadequate information. INTRODUCTION AC corrosion on pipelines has been well documented and researched for a number of decades. 1,2 More recently, standards like EN 15280-2013 “Evaluation of a.c. corrosion likelihood of buried pipelines applicable to cathodically protected pipelines”. 3 This standard addresses the effects of AC on cathodically protected pipelines and has recently been superseded by advances in AC corrosion with the development and publication of ISO 18086 “Corrosion of metals and alloys - Determination of AC corrosion. Protection criteria”. 4 Commercially available computer modeling of the AC interference effects on buried pipelines has been around since the 1980’s, and with the recent hardware and software improvements over the last few years, computational modeling of AC interference has vastly improved and has become an engineering best practice for the pipeline industry, especially for complex pipeline and HVAC right-of-way’s (ROWs). Despite all of these advances in AC corrosion and computational modeling, significant variances and potential integrity issues can still arise due to the variances in input data and input measurements.

ABSTRACT The author uses three recent international pipeline projects as examples, to illustrate that the typical surface profile height and abrasive blast cleaning requirements in today’s coating standards and specifications have not been sufficient to define the adequate level of the abrasive blasting in order to provide wetting and adhesion of the pipe coatings to the pipe substrate, partially causing the pipeline coating disbondment. Adhesion mechanisms, limitations of the current standards of defining surface profile, and recommendations for future pipeline coating projects are discussed. INTRODUCTION Fusion bonded epoxy (FBE) and three-layer polyolefin (polyethylene or polypropylene) are the most common external coating systems for new oil and gas pipelines. These FBE primed pipeline coatings have long track records of successful use, but there are occasional challenges and problems that must be addressed as part of the pipe installation process. One of these challenges and problems often met in the pipeline coating industry is pipe coating disbondment, a delamination normally between FBE and steel at cutback or along the body of the pipe. Pipeline Project Case #1 – In 2014 and 2015, cracking and coating disbondment failures were observed on a significant number of pipes, during the handling and field cold bending processes along the right of way (ROW) of a major natural gas pipeline project in North America (Figure 1a). The 42” OD × 14.27-20.62 mm WT, X70 pipes were coated with a single layer FBE coating. The company pipe coating project specification followed both NACE International (NACE) ? SP0394 (Formerly RP0394) 1 standard and The American Petroleum Institute (API) ? RP 5L9 2 standard. Pipeline Project Case #2 – In 2015 and 2016, at various construction sites of a key natural gas pipeline in South Asia, a dual layer 2LFBE coating applied to 28” OD × 7.14-12.70 mm WT, X70 pipes disbonded randomly on the cold bends along the ROW of the pipeline project. Poor coating adhesion of non-bent pipes was also reported (Figure 1b). The company pipe coating project specification followed also the NACE SP0394 (Formerly RP0394) standard.

ABSTRACT Composite repair systems composed of carbon fiber/epoxy composite materials can be affected by exposure to harsh environments. The vast majority of testing on composite repair systems to date has been to investigate the effects of high temperatures on composite performance. However, depending on the location and time of year, low temperatures can also play a big role in the performance of coatings and composite repairs on pipelines. Therefore, the effects of low temperature should also be tested to prove the reliability of the composite repair systems in low temperature environments. In response to this concern, the impact of exposure to a low temperature environment below -30°C (-22°F) was investigated on a carbon fiber and epoxy composite repair system that had previously been qualified to the ASME (1) PCC-2 1 Article 4.1 nonmetallic repair standard. Tensile tests were performed in accordance with ASTM (2) D3039 2 , and 5 J impact and burst tests were performed in accordance with ASME PCC-2 1 Article 4.1 at temperatures below -30°C (-22°F). Based on the results of the testing, it can be concluded that the specific composite repair system can be employed for low temperature applications on buried pipelines and that there is no degradation in the repair system performance. To prove that the results of the testing apply to the field, the composite repair systems were successfully applied to buried transmission pipelines in cold temperatures, the details of which will be presented. INTRODUCTION Cold temperatures regularly have a severe impact on existing infrastructure around the world. For example, concrete is more likely to prematurely fail in areas where there are frequent freeze/thaw cycles or constant cold temperatures. In pipeline transportation, the freeze/thaw cycles or constant cold temperatures can lead to premature coating failure if a coating is not correctly sourced or applied per manufacturer’s instructions for the specific environment. The introduction and fluctuation of cold temperatures can also lead to formation of various defects on buried pipelines, depending on a multitude of factors.

ABSTRACT With the rapid construction of high voltage alternating current (AC) transmission lines, AC interference problem is becoming a new threat to the pipeline safety, especially for pipelines coated with high quality coating, such as 3PE+. Solid State DC Decoupler and Zinc ribbon groundbed AC mitigation system is the most commonly used mitigation method. But the locations of the mitigation system and the size of the zinc ribbon grounding system still remains a problem for most engineers. In this paper, numerical modeling software is used to fit the real field AC interference data to verify the rationality of related boundary settings. Then possible AC mitigation solutions are evaluated and optimized based on the verified software boundary settings. When it comes to field application, continuous pipe to soil (P/S) AC voltage monitoring units were installed at typical test stations to simultaneously obtain how AC voltage changes with installation. The AC mitigation practice showed that numerical modeling is a great tool for solution design and mitigation effectiveness evaluation, which can eliminate unnecessary mitigation points and to control the cost. Simultaneous AC potential monitoring at typical test stations will provide a complete data record, which can provide engineer a deep understanding how each mitigation point influences the entire AC voltage distribution along the affected pipeline. INTRODUCTION Pipelines that are parallel and crossing with HVAC lines for a long-distance are becoming more and more common in some regions, which brings AC interference problems to these pipelines 1 . There are two main mechanisms for buried pipeline AC interference 2 : inductive and conductive coupling. Inductive coupling energizes pipelines by electromagnetic induction and produces steady state P/S AC interference voltage. While conductive coupling works when power line fault happens or lightning current discharges from tower grounding electrode to remote earth. Even lasting very short time, pipeline coating damage and metal loss may occur. AC interference may result in two threats to pipelines. Firstly, if the AC voltage is very high, it can threaten personnel safety. Secondly, AC interference may lead to AC corrosion. According to European Standard CEN/TS (1) -15280 3 , if AC current density is larger than 30A/m 2 , AC corrosion may happen; and if AC current density exceeds 100A/m 2 , AC corrosion will happen. In the last thirty years, a lot of AC corrosion cases have been reported. In some cases, AC corrosion occurred even with effective cathodic protection 4,5,6 In 2002, an AC corrosion failure occurred on a buried pipeline well protected with off-potential of -1.23V (CSE) and the AC density was 144.13A/m 2 . In 2003, an AC corrosion failure occurred on a buried pipeline with CP potential of -1.2V (CSE) and AC current density of 130 A/m 2 .

ABSTRACT Material mechanical property data including fracture toughness help address potential integrity threats such as material loss through corrosion, stress corrosion cracking (SCC), and fatigue. In-the-ditch (ITD) nondestructive evaluation (NDE) of mechanical properties has expanded beyond traditional hardness testing to provide measurements of strength and fracture toughness of metals without the need for sample removal and laboratory testing. This paper describes two new and complementary mechanical testing methods recently applied to vintage pipeline steels as input to integrity management. In the first method, hard blunt styluses of different geometries slide over the pipe surface at constant loads to measure material hardness. The hardness values for dissimilar styluses are input into predictive equations to determine the yield strength and ultimate tensile strength of the steel. When performed over longitudinal seams or girth welds, the tests identify the heat treatment including normalization. In the second method, the instrument is equipped with a wedged-shaped stylus that includes an opening, or stretch passage, where material is locally subjected to tension that results in microvoid growth and coalescence that match laboratory ductile fracture. The material response is correlated with the fracture toughness through measuring the crack tip opening displacement. Field studies and validation provide examples of application of the methods. 1 Introduction

ABSTRACT Various facilities such as gas compressor stations, storage tank stations, and gathering and distribution stations have buried metallic structure that are both coated and uncoated and of different metal types. These facilities are identified as congested area facilities. For example, facility such as a gas compressor station may have coated pipelines, uncoated screw piles, copper grounding wires, and copper groundrods. Each of these structures has different structure-to-earth resistance and current demand for protection. Increasingly, these structures are electrically interconnected to mitigate the lightning hazard, and to achieve optimal lightning protection throughout the facilities. However, this has an adverse effect on the cathodic protection (CP) system of the facilities because a large fraction of the CP current could be diverted to uncoated carbon steel and copper groundwires and groundrods. In fact, in some congested area facilities, less than one percent of CP current is delivered to the active buried structures such as buried pipelines transmitting oil or natural gas. Further, the approaches available to estimate the CP current distribution for the transmission pipelines are not directly applicable for the facilities with congested buried metallic structures with different structure-to-soil resistances. An analysis was conducted to develop guidelines to design and install and optimal CP system for such facilities, and to remediate insufficient CP to the below grade pipelines at the existing facilities. The analysis included developing a three-dimensional computer model to estimate CP current distribution in congested areas with coated and uncoated buried pipelines, screwpiles, groundwires and copper groundrods. The model was exercised to determine the optimal anode bed structure to deliver sufficient CP current to active buried structures such as transmission pipelines within the facility. The model was used to develop recommendations for optimal CP systems for newer facilities, and remediating insufficient CP at the existing facilities, and anode bed structure that will result in optimal CP system for a given facility.

ABSTRACT CP is an effective method for protecting coating defects on buried pipelines if sufficient current reaches the pipeline surface. In the presence of nearby foundations shielding effects may occur by the construction constraint. A case is discussed of a 57 km long 30 inch 3L-PE coated high pressure natural pipeline section requiring a few milliAmps of CP current that is provided by a single voltage controlled rectifier. The current density is in the range of 0.09 µA/m 2 only. Halfway the trajectory a new 420 m long motorway bridge structure is built above the pipeline. In total 498 concrete reinforced foundation piles are aligned along the pipeline causing a potential risk of shielding the low cathodic current at that particular location. In addition the pipeline is connected to the bridge structure by an anchoring system for stabilization purposes during settlement of the bridge structure after construction. The anchor positions are susceptible locations where significant coating damage may occur on the short or longer term. The degree of shielding effect was validated with FEM based modeling. The protection level of the pipeline and the DCVG sensitivity was computed for various scenarios. Modeling illustrated the CP current path around the pipeline and the foundation piles. The contribution of the rebar structure of the piles was accounted for as well. INTRODUCTION The Desfa pipeline network consists of different sections that are isolated by insulating flanges operated by its own CP system. The pipeline section under study has a total length of 57 km between chainage 279 and 336,7km. The motorway bridge structure starts at chainage 290,835 km. The bridge structure is circa 430 m long and is constructed in two stages because the pipe makes a turn along its routing. In order to protect the pipe from mechanical load and settlement a special corridor of foundation piles is foreseen along the pipe route. Figure 1 shows the bridge structure under construction. A first corridor on the left hand side of the bend in the pipe was already built at time of the study. The second corridor on the right hand side of the bend is in the design stage. The motorway crosses the pipe at two locations in respectively the first and second corridor.

ABSTRACT Coating systems for the corrosion protection of buried steel pipelines extensively use Fusion Bonded Epoxy (FBE) either as a standalone coating or as the base layer in dual or multi-layer coatings. The application of these systems in a coating plant generally requires heating of the steel pipe to temperatures in excess of 230°C, followed by cooling back to ambient after a coating cure time. Although, this thermal cycle occurs for a short duration, it has been shown to affect the strain aging behavior of the steel with a more significant effect on higher strength grades. A desirable attribute to the application of these coatings is to lower the application temperature, preferably to less than 200°C due to: (1) grades of steel such as X100 and X120 cannot be heated above 200°C for long durations without significant change to their stress-strain behavior that is critical in strain based pipeline design; (2) difficulty in heating heavy wall pipe uniformly to temperatures in excess of 200°C without compromising production line speed; (3) improvement of material usage and product throughput for 3LPE/PP; and (4) energy savings. This paper discusses the experience in coordinating with powder suppliers in the development of Low Application Temperature (LAT) FBE materials and the enhancement and process controls for the corresponding application process to constrain temperatures that the steel pipe experiences in a coating plant. Multi-layer coating systems using LAT FBE have been used in several projects around the world. This paper also presents the performance characteristics, production, commercial track record and experience of these systems. INTRODUCTION Fusion Bonded epoxy (FBE) coatings has been widely used in pipeline corrosion protection for more than three decades. They are commonly used as stand-alone coatings, as base layer for dual or multi-layer FBE coatings, and as base layer for multi-layer polyethylene/polypropylene coatings. FBE is a powder coating applied by electrostatic spraying onto preheated steel pipes where the powder melts, flow (wet), fuse and react/crosslink to form a solid protective coating. One of the most important factors to achieve proper adhesion between the steel pipe and the coating is the melt-flow-wet process, which is mainly governed by the temperature of the pipe and the melt-fuse characteristics of the FBE. Typical application temperatures for conventional FBE coatings are in excess of 230°C.

ABSTRACT Studies of Alternating Current (AC) interference on pipelines from nearby power lines usually consider the fundamental (50Hz or 60Hz) frequency of the power line currents. However, these currents can also contain considerable harmonics of the fundamental AC frequency. Measurements on pipelines in Canada and Sweden have shown that these harmonics can produce significant interference in the pipe-to-soil potentials. The electromagnetic fields experienced by the pipeline are dependent on three types of parameters. The first is associated with the phase relations of the power line harmonics, classified as ‘positive sequence’, ‘negative sequence’, and ‘zero sequence’. The second is related to the conductivity of the host media (ground) that affects the electromagnetic field experienced by a pipeline. The third is pipeline series impedance and parallel admittance, which introduces additional frequency dependence. This paper examines the frequency dependence of the phase relation of the power line currents, the Earth response, and the pipeline response and shows how they can be combined to provide an AC risk assessment. INTRODUCTION Where pipelines share the same right-of-way with the power line, there is considerable electromagnetic coupling between the power line and the pipeline. There has been significant work on this issue 1,2 , which has been almost exclusively concentrated on 50 or 60 Hz induction in pipelines. However, harmonics have also been observed in pipelines 3,4 and this raised concerns about their influence on the safe pipeline operations. The harmonics produced in a pipeline depend on the amplitude of the harmonic currents in the nearby power line as well as the phase relation between the currents in the different phase conductors. The electric fields produced in the pipeline are dependent on the Earth response and the currents and voltages produced in the pipeline depend on the pipeline characteristics (Figure 1). This paper examines the frequency dependence of each stage of this process and examines how these combine to determine the harmonic voltages produced on a pipeline.

ABSTRACT Evaluation of the performance of cathodic protection (CP) systems used on subsea structures once in service can be costly due the need for specialized personnel and ROV monitoring equipment. Often areas of a subsea structure can go unassessed in terms of CP coverage when the ability to assess the entire structure is not feasible. Improperly protected areas can lead to premature corrosion or structural integrity issues, or costly maintenance and retrofits. The use of computer software can aid in identifying improperly protected areas. Boundary element analysis (BEA) of a CP system, validated with past inspection data, can produce a computer model that will allow for predictive assessments of the present and future states of the CP system and subsea structure. Identification of under/over protection ‘hot spots’ by using a BEA model can guide the focus of the next inspection for a more thorough assessment of critical locations. In this study, the CP system of an offshore complex consisting of Al-Zn-In galvanic anodes was modeled using BEA. The offshore complex consists of concrete and steel jackets, risers and pipework. Time-stepping, anode degradation and coating breakdown are incorporated to estimate system performance with time since installation. The results of the CP system simulation were validated against existing inspection data and used to optimize the established CP inspection program. INTRODUCTION An offshore complex consisting of concrete structures and steel jackets, risers and pipework operates in the North Sea. The subsea portion of the main platform is comprised of a concrete gravity oil storage tank, concrete tower nearly centered atop the concrete tank and a steel jacket and conductor frame. The concrete tank connects to the lower portion of a steel jacket which rises vertically to create the second connection point to the topside platform structure along with the concrete tower. The first of two ancillary steel jackets reside near the main platform and connects via subsea pipeline to the second ancillary steel jacket approximately 2 kilometers away.

ABSTRACT This paper explores the various degradation mechanisms experienced by a refinery’s RFCC catalyst cooler aeration piping system. A detailed analysis of the most recent failure and a past failure was conducted to determine the various metallurgical and mechanical degradation mechanism(s) that led to these failures. The analysis which covered both the old UNS S30409, TP304H stainless steel, and newly upgraded UNS S34709, TP347H stainless steel catalyst cooler aeration piping system, with the same design, showed the dominant degradation mechanisms to be low cycle thermal fatigue and low cycle fatigue- creep for the TP304H and TP347H stainless steel aeration system’s header and sub header. The TP304H aeration system failed after three years in-service and the TP347H aeration system after six months in-service. The proposed solutions to prevent recurrence include a design change of the aeration piping system, stricter quality control during fabrication, installation of liquid knock-out drums to prevent water ingress resulting in thermo-mechanical strains and a return to the TP304H metallurgy for the aeration system pending a detailed investigation into the TP347H failure. The paper also explores the technical reason(s) for the metallurgy upgrade from TP304H to TP347H and how this change affected the aeration piping’s service life. INTRODUCTION A refinery’s Residue Fluid Catalytic Cracking Unit (RFCC) experienced repeated failures of its Regenerator Catalyst Coolers’ aeration piping system. The RFCC Catalyst Coolers are external vertical shell-and-tube type heat exchangers. In the present unit, two Catalyst Coolers, 1 and 2, are located on either side of the Regenerator. The purpose of the catalyst coolers is to reduce the temperature of the regenerated catalyst by generating of steam from the circulating boiler feed water on the tube side of the exchanger. During operation, regenerated catalyst flows over the entire cross sectional area of the tube bundle. The aeration system provides uniform air distribution on the shell side of the catalyst cooler exchangers thereby fluidizing the catalyst to allow for better catalyst flow and a uniform heat transfer coefficient. A catalyst cooler failure results in a forced refinery stoppage/shut-down for repairs. The primary location failure is at the weld joints of the aeration piping system due to various stresses and strains acting on the aeration system. The catalyst cooler failures follow a general sequence of events, as described below:

ABSTRACT In the past 5 years, Conventional Non-Destructive Examination (NDE) for High-Temperature Hydrogen Attack (HTHA) has been improved with remarkable success. This technology, combined with emerging Fitness-for-Service (FFS) methodologies, has been used in the evaluation of equipment in HTHA service with a higher level of confidence. Some of these evaluations have led to a systematic approach to continued operation, limited service, or retirement decisions not possible just 5 years ago. This paper will highlight some of the ongoing advances of the HTHA Joint Industry Project (JIP) to date and provide a preview into upcoming developments in the NDE and FFS codes. Some case studies will be presented along with recent advances in laboratory methods for HTHA prediction. INTRODUCTION In 2012, a Joint Industry Project (JIP) was launched consisting of support from eight refining and petrochemical companies (ranging from multi-national integrated oil companies to single-site refineries) and managed by The Equity Engineering Group, Inc. † (E 2 G). There was a multi-prong approach for this project. The results of the round robin testing of the commercial NDE service provider were poor and have been previously presented [1, 2]. Since that time, the results of the erroneous NDE calls have been reviewed by a third party NDE SME. A large amount of ex-service HTHA material was analyzed, and methods for both detection and sizing have been developed. This NDE Path, along with a new approach to HTHA assessment similar to that in API 579 methodology, are being formulated into a FFS technology. This paper will summarize some aspects of the JIP. IMPROVED NDE NEEDED FOR FFS TECHNOLOGIES There was a need for finding more reliable NDE methods for HTHA in the refining and petrochemical industries. The primary purpose of NDE is Detection, Characterization and Sizing (surface breaking vs. sub-surface, length, height, depth, crack orientation, singular flaw vs. colonies of cracking). Of secondary importance those involving productivity: screening (as measured in scan rates of feet per minute) and surface preparation (scale or paint removal, weld protuberances, pitting) and accessibility (insulation removal, and for metal temperatures). The only methodologies considered practical for field use and commercially available, although proprietary methods were allowed. As in the case of the JIP Part 1 NDE Round Robin, all NDT indications were validated by metallography. A summary of the modalities tried is provided in Table 1. A further subset of Ultrasonic Methods will be discussed and are found in Table 2. Time of Flight Diffraction and Phased Array Ultrasonic show best Results Time of Flight Diffraction (ToFD) originated in the late 70s as a reliable ultrasonic detection and sizing methodology. During the 80s, several industrial trials validated ToFD to be one of the most reliable ultrasonic defect detection mediums available. Since then ToFD have been the backbone of most AUT pipeline girth-weld inspection and has been used extensively in the power generation industry, nuclear and fossil fuel, to detect and precisely size defects in pressure vessels, high-pressure pipelines and weldments.