This paper presents data analytics that demonstrates the safe implementation of defect assessment models which use uncertain measurements of defect and material properties as inputs. Even though this validation is done for a corrosion assessment model implementation, it can be generalized for any defect assessment validation where the inputs have uncertainty (as they do in implementation). The questions arising from the validation of the Plausible Profiles (Psqr) model and related review led to a large amount of data analytics to demonstrate various aspects of safety in implementation. The data analytics demonstrates how the safety of model implementation can be verified using a well-designed set of data. The validation of Psqr model was conducted on a unique set of data consisting of metal-loss corrosion clusters with Inline Inspection (ILI) reported size, laser scan-measured dimension, and well monitored burst testing pressure. Therefore, this validation provided an unprecedented set of validation data that could represent many perspectives, such as model performance (with all uncertainties associated with other parameters removed), in-the-ditch decision scenario, and ILI-based decision scenario. Moreover, the morphologies of the 30 corrosion clusters tested is a good representation of large corrosion clusters that have failed historically in the pipeline industry. One of learnings from post-ILI failures due to corrosion in the industry is that corrosion morphology played a significant role. Previous model validations were mostly performed on simple single anomalies or simple clusters with few individual corrosion anomalies. It is important that a corrosion model is validated using real corrosion morphologies that are representative of in-service conditions. The analysis of this unprecedented and comprehensive set of data led to great learning and revealed how safety can be achieved optimally with good understanding of how uncertainties associated with ILI sizing error, material property, model error, and safety factors interact and play into integrity. It also revealed the role of common misunderstandings that are barriers to effective pipeline integrity assessment. Overcoming these misunderstandings have helped in developing a more effective ILI based corrosion management program that will avoid more failures and reduce unnecessary integrity actions.

The present paper deals with the subject of failure of deep-sea pipelines that have thickness metal-loss areas caused by corrosion and are subjected to high external hydrostatic pressure. An extensive research program was launched to observe failure modes, to examine existing and to develop prediction collapse equations, and to determine their accuracy. The program uses finite element modeling and external hydrostatic collapse tests of full-scale specimens. This paper presents and discusses the results of the first 20 collapse tests, which were performed in a new 103 MPa (15 ksi) hyperbaric chamber (760 mm internal diameter and 7200 mm length). The test results obtained with full scale specimens (324 mm external diameter and 23 mm thickness) made of low carbon steel API 5L X60 with external machined metal loss defects are used to verify the level of accuracy and conservatism of four analytical simple equations used to predict collapse of pipes with corrosion subjected to high external pressure.

Pembina Pipeline Corporation (Pembina) monitored three active interacting [1] landslides utilizing arrays of remote real-time GNSS (Global Navigation Satellite System) sensors to assist in the confirmation of safe continued pipeline operation. Each case study utilized remote sending high-precision real-time GNSS sensors to monitor landslides of varying movement rates, from slow-moving landslides which could be condition-monitored for many years, to fast-moving landslides which required pipeline mitigation within months. The first case study was Henderson Creek near Grande Prairie AB, which utilized remote real-time GNSS sensors to monitor over one meter of rotational slope movement in 6 months; both a conventionally-buried pipeline, and a temporary above-ground pipeline bridge were monitored before a permanent HDD replacement mitigation was completed. Sensors were installed on the temporary pipeline, the bridge, as well as shallow ground installations. The second case study was Athabasca River north slope near Ft McMurray AB, which utilized remote real-time GNSS sensors to monitor an above-ground pipeline in a slow-moving valley-scale landslide over a period of several years. The third case study was Smoky River east slope near Grande Cache AB, which utilized remote real-time GNSS sensors to monitor a rapidly-moving landslide on a conventionally-buried pipeline, which has plans for an HDD replacement mitigation in the near future. To verify the results of the GNSS sensors, each of these three landslide sites were monitored utilizing multiple technologies which showed close correlation with the remote real-time GNSS sensors, including conventional ground surveys, monitoring pin surveys, SIs, and repeated ILI IMU caliper runs. The GNSS monitoring system was precise enough to detect operational changes of the above-ground pipelines, including filling of the pipeline with product, suspected changes in internal pipeline operating pressure, and pipeline expansion and contraction due to temperature changes from night to day and winter to summer. Pembina successfully utilized a remote real-time GNSS monitoring system to allow greater assurance of safe continued pipeline operation at three separate moving slopes, until either a slope movement threshold was reached, or mitigation was completed. This paper highlights that pipeline operators can remotely condition-monitor their confirmed or suspected interacting pipelines in landslides with accuracy using remote real-time GNSS, on a real-time continuous basis as part of their Geohazard Management Program.

This paper initiates use of fracture mechanics best practice growth models and tools for pipeline steels with full tri-region da/dN characterization. The utilities associated with establishing negligible crack growth thresholds are demonstrated. Pipeline operators are often presented with decisions that could be supported with scientifically vetted and situationally accurate stress thresholds for negligible crack growth. The threshold stress-intensity factor, ΔK th , is the value for ΔK where the crack growth rate, da/dN, approaches the minimum threshold crack growth rate. Stress-intensity factors at or below this threshold value result in crack growth small enough for operators to practically ignore it in pipeline integrity assessments. Previously, a ΔK th value of 2.0 MPa*m 0.5 had been suggested for general use in API 579[1]. The API 579 value appears conservative when compared to industry experience and established ΔK th for similar steel alloys across all stress ratios. By establishing an on-shore pipeline specific ΔK th which considers a pipeline-specific da/dN threshold and stress ratio effects, operators are afforded the opportunity to: • exclude certain pipelines or portions of pipelines from crack growth susceptibility, • identify features with no life limit, • adjust load / boundary conditions to preclude growth, • improve computational efficiency by discarding load cycles below threshold, and, • more accurately simulate crack growth scenarios Pipeline crack growth testing has been researched to derive reasonable and prudent negligible ΔK th values through a closer examination of loading scenarios and environments which affect ΔK th . A da/dN threshold for when diminishingly small crack growth rates can be neglected for typical pipeline assets was determined based on observed pressure fluctuation frequencies. Applications and value derived from deployment of ΔK th are illustrated for North American pipeline assets. Environmental and blunting effects on ΔK th for near-neutral pH stress corrosion cracking previously developed are shown for comparison and utility. Fully established negligible growth thresholds pave the way toward adoption of next-level fracture mechanics best practice models and tools such as AFGROW and NASGRO, and facilitates crack growth simulations and root-cause analysis.

Some 10 incidents of low strain in-service and pre-service hydrotest failures in girth welds have been reported in North America since the Enterprise Products ethane pipeline failure in 2015. No such failures have been reported in Australia, despite the similarities in Standards, the line pipe data, and the use of manual SMAW using fully cellulosic procedures. There are however significant differences that warrant further investigation and adoption in terms of best practice to ensure the security and safety of our pipeline networks. Some unique differences and observations in terms of pipe properties, weld qualification procedures, test methods and even full scale pressure burst tests before and after coating are described to highlight subtle differences in the standards that may provide clarity in explaining pipeline girth weld failures and it is anticipated may also provide guidance for the future.

Owing to recent concerns regarding pipeline field girth weld performance, particularly heat affected zone (HAZ) softening and toughness, EVRAZ North America has initiated a research program to evaluate the response of API grade line pipe to the current field girth welding practices. In particular, this study aims to elucidate the role of steel alloy design as well as the welding procedure on field girth weld and HAZ properties. This understanding is critical to balance the detrimental effects of HAZ softening on the overall joint strength against factors affecting HAZ toughness. A selection of several different steels with different levels of alloying elements, Ceq and Pcm have been subjected to welding trials to assess the effects of chemistry on joint performance. Furthermore, an analysis on the effect of welding process parameters on the joint properties has been made. The welds, fabricated via a manual shielded metal arc welding (M-SMAW) process, were evaluated in terms of toughness, local vs global strain distribution during tensile testing using digital image correlation (DIC) technique, and hardness contour mapping of the weld and HAZ regions. The results explicitly show that the extent of HAZ softening decreased as the amount of Mo, Mn, Ti/N and Ceq increased. However, this alloying addition resulted in a detrimental effect on the HAZ toughness, particularly towards the cap and fill passes. The HAZ softening increased as the inter-pass temperature and the welding heat input increased. In addition, the strain analysis confirmed the weld passes towards the root/hot passes are more prone to HAZ softening compared with the upper cap and fill passes.

This paper presents a methodology to evaluate pipe stress induced by surface vehicle loading at uncased road crossings that are protected by mat or bridging. When vehicles cross an existing pipeline, additional circumferential and longitudinal pipe stresses induced by surface vehicle loadings should be comprehensively considered to ensure pipe integrity and safe operation. Surface protection measures are sometimes installed to distribute the surface loading away from pipe centerline and reduce “footprint pressure”. A modified CEPA equation was proposed to calculate the radius of relative stiffness (or effective length) of mat and was validated by comparing with results from continuum FEA. The effective length calculated by the modified equation demonstrates good consistency with the FEA-predicted effective length. An approach was proposed to evaluate the pipe stress with user-defined free span of bridging, which provide flexibility for optimizing bridging protection in the field. A tool was developed to facilitate the assessment of surface loading stress of pipeline with mat or bridging protection. Case studies were presented to demonstrate the application of the proposed methods and the effect of mat thickness or bridging free span on the reduction of live load stress. The proposed methods will benefit pipeline operators with derived cost-effective protection measures for vehicle crossing while assuring safety of pipeline operation.

The pipeline industry has long sought a unified near-neutral pH stress corrosion cracking (NNpHSCC) growth model, which fully describes salient growth elements. In response to this gap, the Pipeline Research Council International (PRCI) has funded a multi-year research project, partnering with the University of Alberta (Project SCC-2-12). With the project nearing completion, application of the proposed near-neutral pH stress corrosion cracking growth model to two operating pipelines with known populations of stress corrosion crack features is presented. The remaining life of each crack feature detected by crack in-line inspection tools, under known loading, is calculated for two segments of operating pipelines in North America. The PRCI developed model, referred to as PipeOnline™, is compared to the legacy Enbridge linear growth and Paris Law models. A calibration technique for correcting the length and depth of the ILI feature calls provided by the in-line inspection vendor is reviewed, which takes into account tool tolerance and corrects length and depth to more closely match field findings. Efficiency improvements gleaned from this calibration technique are illustrated. While this calibration methodology is unique to the pipeline operator, the method is reviewed to allow other operators to readily implement the technique if it is found to be warranted. The PipeOnline model is tested for the post-calibration dimensions and compared to the legacy growth model. Each of the required inputs is defined, and methods of quantification are shown. Negligible growth thresholds are reviewed, and the truncation of stress cycles below the growth threshold is discussed. The strategy of deployment is shown, along with the proportion of features that are predicted to remain in dormancy. Methods to account for mean stresses and load application frequency are presented. The resulting PipeOnline re-inspection interval is compared to that predicted by typical existing growth models and then contrasted with excavation results on the asset. Calibration of the governing equation coefficients with rationale for each term is proposed for the pipeline segments examined in the study, and recommendations made for potential implementation for other operators, along with follow-on research.

In-service pipelines are often subjected to longitudinal forces and bending moments resulting from, for example, ground movement or formation of free spans in addition to internal pressures. In practice, there are some site-specific cases where corrosion anomalies interact with the external loads. A refined assessment model is required to understand the load carrying capacity of pipe. In this study, a burst capacity model for corroded pipelines under combined internal pressure and axial compression is developed based on extensive parametric three-dimensional (3D) elasto-plastic finite element analyses (FEA) and artificial neural network (ANN) technique. The parametric FEA employs the ultimate tensile strength (UTS)-based burst criterion and idealizes corrosion defects as semi-ellipsoidal shaped flaws. The FEA model is validated by full-scale burst tests of pipe specimens containing semi-ellipsoidal shaped flaws reported in the literature. Extensive parametric FEA are carried out to evaluate the burst capacity of corroded pipelines under combined internal pressure and axial compression by varying the pipe geometric and material properties, defect depth, length and width, and magnitude of axial compressive stress. Based on the FEA results, an ANN model is developed utilizing the open-source platform PYTHON to predict the burst capacity of corroded pipelines under combined internal pressure and axial compression. The well-trained ANN model is further validated by full-scale burst tests of corroded pipelines under combined internal pressure and axial compression carried out by Det Norske Veritas ( DNV ).

This paper presents the refinement, validation, and operationalization of Plausible Profiles (Psqr) corrosion assessment model that TC Energy (TCE) published in IPC 2018. Metal-loss corrosion continues to be a major integrity threat to oil and gas pipelines. Inline inspection (ILI) based corrosion management, where ILI measured anomalies are assessed and mitigated, has proven to be the best way to manage corrosion. The assessment model used to estimate the burst pressure of pipelines has the most significant impact on integrity decisions. These decisions include (1) which anomalies to excavate based on In-line inspection (ILI); (2) pressure reduction (i.e. derate) required to maintain safety until repairs are completed, and (3) repair decisions during the excavation. Consequently, TCE focused on improving the shape factor of the Modified B31G effective area technique and published an overview of the improvement in IPC 2018 paper titled “A More Accurate and Precise Method for Large Metal Loss Corrosion Assessment”. From 2018 TCE refined the model using further testing, validation, internal review, and external review. In 2019, the model was reviewed by eight industry experts through Pipeline Research Council International (PRCI) project “EC-2-9 Peer Review of the Plausible Profile (Psqr) Corrosion Assessment Model”. The project outcome recommended Psqr as an improved corrosion assessment model. The comments and recommendations provided by the reviewers will be reported in IPC 2020 in a companion paper. Validation results show the Psqr model is safe, and more accurate and precise than RSTRENG. The resulting magnitude of reduction in unnecessary activities depends on the corrosion morphology.

Crack management has become a major focus for many gas and liquid transmission pipeline operators. Failures associated with crack-like features have been a concern for both pipe operators and regulatory agencies. As a result, pipeline operators are excavating large numbers of features for not only in-line inspection (ILI) validation purposes, but also to make repairs. Additionally, ILI technologies have advanced significantly in recent years and are identifying an increasing number of features with greater levels of accuracy. With increased data generation, operators are faced with an unprecedented amount of information that requires response prioritization. Because of high levels of conservatism associated with today’s assessment methods, pipeline operators are spending a significant amount of capital excavating crack-like features. There is a need for improved assessment methods that integrates testing simulated / synthetic crack-like features. This paper will provide details on a study funded to systematically generate crack-like features in pipeline materials with the application of cyclic internal pressure loading. Synthetic crack-like features were generated in 12.75-inch × 0.250-inch, Grade X42 pipe material using electronic discharge machining (EDM) to form notches. Notch depths were 10% of the nominal wall thickness and ranged from 1-inch to 3-inches in length. The pipe samples were then pressure cycled to achieve microcracking at the base of each notch. Initial stages of the program involved sectioning features to quantify crack growth levels. Once a systematic process for growing cracks from EDM starter notches had been validated, testing involved cyclic pressure fatigue to failure and burst testing. The advantage with the crack generation methodology used in this study was the ability to generate sharp, crack-like features without altering the microstructure of the pipe material in the vicinity of the feature. Programs such as the one presented in this paper are useful for both generating features in pipeline materials and quantifying behavior of pipeline materials subjected to cyclic pressure and burst loading.

The use of Geographic Information System (GIS) in managing pipeline database and automating routine engineering processes has become a standard practice in the pipeline industry. While maintaining a central database provides security, integrity, and easy management of data throughout the pipeline’s lifecycle, GIS enables spatial analysis of pipeline data in addition to streamlining access and visualization of results. One of the major benefits of GIS integration lies in the ease of automating the alignment sheet generation for pipelines. This paper introduces a simplified pipeline alignment sheet generation workflow using GIS datasets to produce highly customizable alignment sheets in AutoCAD, a much-preferred format in the pipeline industry. By utilizing existing GIS and AutoCAD features to generate the alignment sheet, writing complicated geo-processing or plotting algorithms is minimized, which in turn reduces the risks of committing any systematic errors. This robust and user-friendly workflow not only ensures safety but also leads to a cost-effective solution.

This paper describes the history of channel changes and associated pipeline exposure problems at five river and stream crossings in Alberta. Each case history reviews the various hydrologic and geomorphic factors that contributed to the erosion problem and describes the corrective action that was taken. A number of the examples illustrate the inherent difficulties in identifying potential erosion problems at the project design stage. Others show that with systematic monitoring and inspection procedures in place, remedial action can be planned and implemented well before pipeline integrity has been compromised.

The resistance to rock penetration and abrasion damage of four advanced pipeline anti-corrosion coatings on buried steel linepipe was quantified by means of controlled pipe burial tests. Production-coated steel linepipes were buried in three different gradations of crushed hard rock, and a Caterpillar 966D wheel loader was driven directly over the buried pipes twice daily for 12 consecutive days. Subsequent excavation and inspection of the pipes showed that the coatings experienced progressively more damage (quantified by the number of holidays) with increase in rock size and progressively less damage with increase in coating thickness. A quantitative relationship between coating damage and coating thickness was defined for the two larger rock sizes.

Mechanical damage, caused by externally applied forces, can deform the cylindrical shape of a pipe, scrape away metal, change material properties, and leave residual stresses and plastic strains. Mechanical damage is especially detrimental when it leaves the potential for delayed failure. In-line inspection tools both must detect mechanical damage and characterize parameters such as microstructure changes, residual stresses and extent of removed metal. These are the parameters that determine whether a defect is a candidate for delayed failure. Magnetic flux leakage (MFL) is commonly used for nondestructive detection and sizing of corrosion and metal-loss defects in pipelines, and it is sometimes cited as useful for detecting mechanical damage. Flux leakage from mechanical damage results from geometric and magnetic changes. The geometric part of the flux leakage signal is caused by denting, metal-loss, and wall thinning. The magnetic part of the signal is caused by cold work, plastic deformation and residual stress. At high magnetization levels, MFL signals are due mostly to defect geometry, such as metal-loss length, depth, and shape. At lower magnetization levels, the signals are caused by both geometric and magnetic deformation. To determine the signal due to magnetic deformation only, the geometric MFL signal obtained at high magnetization levels can be scaled and subtracted from the mixed MFL signal obtained at a low magnetization level. In this way, the MFL signal can be decoupled into its geometric and magnetic components. Using the decoupled magnetic signal, information on cold work, plastic deformation, and residual stresses can be gleaned. This paper shows that scaling of high magnetization level signals is possible and differences between signals at multiple magnetization levels provide unique information about the nature of mechanical damage defects. Representative results from hundreds of mechanical damage defect examined are discussed. Included in the analysis are the effects of pipe material and inspection variables, such as pressure and inspection speed. Prospects for tool design and application for in-line inspection are also presented. This work was supported by Department of Transportation, Office of Pipeline Safety.

On some old long distance transmission pipelines of PetroChina some severe spiral weld defects existed. These weld defects were found to be from a lack of penetration and lack of fusion during pipe manufacturing. To avoid possible failure accidents, tri-axis magnetic flux leakage (MFL) in-line inspections were performed on some certain pipelines. A large quantity of spiral weld defects were detected in the inspections and their sizes were reported, some of them with large depth and large length along the spiral weld seam. However, there is no applicable engineering critical assessment (ECA) method for this kind of defects up to now. Assessment methods provided in BS7910:2005 and other codes are only applicable to assess flaws in cylinder oriented axially or circumferentially. Projection processing must be used to utilize these methods for spiral flaws. Three other different assessment methods for spiral defects in linepipe were proposed by Mok et al., Fu and Jones, and Bai et al. separately. But these methods were originally developed for spiral corrosion and have not been proved to be applicable for spiral weld defects on the old pipelines of PetroChina. In this paper’s work, several burst tests of pipeline with spiral weld defects were carried out. Different projection assessment methods based on BS7910:2005 were conducted as well as the spiral corrosion assessment methods proposed in previous studies. Predicted results were compared with burst tests and analyzed in this paper. As a conclusion of comparison, the axial projection method based on BS7910:2005 was suggested to assess this kind of spiral weld defects despite of its conservatism.

More than 80% crude oils produced in China has a high content of wax. Pipeline transportation for such high waxy Chinese crude has a serious safety risk due to its characteristics of high gel point (up to 30 degree) and high viscosity below the wax appearance temperature. In the case of pipeline shutdown the crude cools down. After a certain amount of time, depending on the crude oil properties, the crude oil temperature plot file, the hydraulic data as well as the pipeline construction and environmental related data, the required pressure to restart the pipeline might exceed the maximum allowable operation pressure (MAOP) which makes the restart of operation become very difficult or even impossible. To mitigate the safety risk in case of the pipeline shutdown or to avoid congeal accident, determining the safe time after which the pipeline is still able to restart is necessary. However, the complexity of the presented problem lies in the uncertainty of the operation parameters and the environmental related data, such as the uncertainly of the flow rate and natural temperature. A method is developed to predict the safe time based on the uncertainty of parameters. In the method, the field data is firstly collected, then processed and analyzed to obtain the static rules of these data. By doing so, the complexity of uncertainty is successfully handled. The method is then applied to two pipelines, the results show that the safety of the pipeline is ensured and the energy consumption is also significantly reduced.

The majority of oil and refined-product pipelines in Brazil have their protection system designs based on spring-type pressure relief valves. Thus, the proper design and operation of these valves is essential to ensure the safety of transport pipelines and loading/unloading terminals during any abnormal operation conditions that generate a surge pressure. In simple terms, these valves have a disk which is pressed by a spring against the inlet nozzle of the valve. When the pressure rises, the force generated on the surface of the disc increases and, depending on the pressure relief valve set point, the force due to pressure overcomes the force exerted by the spring, causing the disk to rise and discharge the fluid through the outlet nozzle to the relief line, reducing the pressure level within the pipeline. Despite its importance, most commercial applications do not present a specific model to simulate the transient behavior of pressure relief valves. This paper presents an experimental study aimed at determining the dynamic behavior of a commercial spring-type relief valve. The valve was installed in a pipe loop instrumented with pressure and flow transducers. The transient motion of the valve disc was measured with a fast-response displacement transducer. The transient in the flow loop was generated by the controlled closing of a block valve positioned downstream of the relief valve. The recorded transient data for disc position, upstream and downstream pressures, and discharge flow rates were used to compute the discharge coefficient as a function of opening fraction and the opening fraction as a function of time. Simulation models based on a spring-mass damped system were developed and implemented in a PID-actuator-control valve system. The systems were implemented in a commercial pipeline simulation program modeling the experimental loop employed in the tests. The numerical and experimental data of the block valve closure transient were compared displaying good agreement. Simulations results employing a generic relief valve model frequently used in simulations were also obtained revealing problems associated with this approach.

Pipeline and storage tank corrosion defect inspection is one of the most important concerns for integrity management of oil & gas storage and transportation industry. Besides the internal inspection for pipeline, tri-axis high-resolution magnetic leakage inspection technique which is applied for trunk line inspection, long range ultrasonic guided wave technique based on Lamb wave is adopted for inaccessible part inspection in technique package for pipeline inspection in PetroChina. Corrosion in the tank floor and wall is a serious threat for environmental and economic safety. Owing to the capabilities of ultrasonic guided wave which are long-range, in-plane propagation, in-service storage tank floor/wall inspection becomes possible by employing an array of SH wave transducers mounting on the edge of the outer storage tank floor. At this point, ultrasonic guided wave shows its capability for pipeline and storage tank corrosion defect inspection. With the advancement of high-performance transducer, its capability will be boosted for even longer and remoter detection. Currently, ultrasonic guided wave system for pipeline could detect defect 200 m away in ideal case while 3∼6 m for storage tank floor in practical case. The complexity of the application of ultrasonic guided wave in tank floor inspection lies in the object containing multiple lap joint welds along the large diameter of the tank (up to 100 m) and the complicated reconstruction of the two-dimensional defect distribution information. The prototype of ultrasonic guided wave system for storage tank is able to detect defects along the edge of storage tank floor. Once the propagation mechanism at overlap joint welds is broken through, the system capability is believed to be greatly improved. The main scope of the paper is to introduce the ultrasonic guided wave principles and the system design of the inspection systems for pipeline and storage tank, respectively, including the system electrical module, hardware program and the module of data acquisition, analysis and processing. Besides, the field application study cases are included to show the capability of both systems and their potential for integrity management in oil & gas storage and transportation field.

Composite repair systems are being successfully and heavily utilized for the repair of a wide variety of pipeline systems operating at high internal pressures worldwide. Many of these pipelines employ cathodic protection systems as a preventative measure of insuring that the pipeline does not corrode. Even with advanced cathodic protection systems, there are still times that a pipeline may become damaged or corroded and composite repair systems are a popular choice. In order to qualify a composite repair system for use on a cathodically protected pipeline, the repair system must undergo specific testing to insure that there will be no issues of disbondment of the composite due to the cathodic protection system. This paper discusses the testing of composite repair systems with varying fiber types, resins, and installation methods. Results have been gathered for several repair system options and indicate that there is variance in the results depending on the above mentioned variables. The results of each of these systems and the impact of the fibers utilized will be discussed and conclusions made as to the effect of cathodic protection on each.