Reliability-based corrosion assessment criteria were developed for onshore natural gas and low vapor pressure (LVP) pipelines as part of a joint industry project. The criteria are based on the limit states design (LSD) approach and are designed to achieve consistent safety levels for a broad range of pipeline designs and corrosion conditions. The assessment criteria were developed for two corrosion limit states categories: ultimate limit state, representing large leaks and ruptures; and leakage limit state, representing small leaks. For the ultimate limit state, a safety class system is used to characterize pipelines based on the anticipated severity of failure consequences as determined by pressure, diameter, product, population density and environmental sensitivity. Since the leakage limit state does not result in significant safety or environmental consequences, a single reliability target, applicable for all pipelines at all locations is used. The assessment criteria formulations are characterized by three elements: the equations used to calculate the characteristic demand (i.e. operating pressure) and capacity (i.e. burst pressure resistance at a corrosion feature); the characteristic values of the key input parameters for these formulas (such as diameter, pressure and feature depth); and the safety factors defining the characteristic demand as a ratio of characteristic capacity. The process used to calibrate safety factors and characteristic input parameter values that meet the desired reliability levels is described, and an assessment of the accuracy and consistency of the resulting checks in meeting the reliability targets is included. The assessment criteria include two methods of application: feature-based and section-based. The feature-based method divides the allowable failure probability equally between all features. It is simple to use, but conservative in nature. It is suitable for pipelines with a small number of corrosion features. The section-based method considers the failure probability of the corrosion features in a pipeline section as a group, and ensures that the total group failure probability is below the allowable threshold for the section. This method produces less conservative results than the feature-based method, but it requires more detailed calculations. It is suitable for all pipelines, and is particularly useful for those with a large number of features. The practical implications of the application of these criteria are described in the companion paper IPC2018-78608 Implementation of Reliability-based Criteria for Corrosion Assessment .

Corrosion anomalies which reduce the strength of the pipeline must be mitigated appropriately. When corrosion defects have varying morphologies it is not always simple to determine the point at which the corrosion region becomes a safety concern, particularly for complex corrosion areas where multiple corrosion anomalies may interact with one another. Therefore, understanding how various anomalies may interact is important to determining the overall remaining strength of a pipeline under pressure. Many criteria for this spacing and how to apply the rules are recommended in the literature and have been studied either as the focus or periphery by several more, but no single criterion is provided as regulation. The task is left to the pipeline operator to choose the interaction rule for what is defined as ‘closely spaced corrosion.’ The method by which the failure pressure is calculated should be considered as varying levels of conservatism are inherent in these assessments. Recommendations for interaction guidelines have been determined by either empirical or analytical approaches. The empirical approaches may be limited when an insufficient number and variety of pipes can be burst tested. Many analytical approaches are based upon relationships of remaining wall and simple corrosion morphologies which may not be applicable to real world corrosion. The source of the corrosion anomaly data is an important variable when selecting and applying interaction rules. In-line inspections (ILI) are the most common methods by which to obtain corrosion anomaly data, but each technology has an inherent measurement error and bias which should be considered. This paper will go into detail on each of the items discussed, present the current state of research into this subject in the industry, and will present a general recommendation for selection of an interaction criterion for corrosion features reported by ILI.

Throughout North America there are many crude oil storage tank facilities — also called terminals — serving as hubs, transfer points and storage. Safety precautions such as pre-service integrity testing, cathodic protection, primary and secondary containment measures, and grounding techniques have been utilized to assure safety as a top priority. These tanks undergo an in-service API 653 external inspection at least every 5 years, and are taken out of service to undergo an API 653 internal/external inspection at least every 30 years [1], [2], [3]. For these aboveground storage tanks, the bottom plate is the most vulnerable area to corrosion [4] and is also the most challenge area to inspect visually. Both sides (product-side and soil-side) of the tank bottom plate are prone to high rates of corrosion in comparison to other components such as the roof and shell [5]. Corrosion generally starts with coating defects such as air or water ingress to underling layers and exposing the steel to uncontrolled environmental factors. Internal inspection can be performed using ultrasonic measures to calculate the sheet thickness, however, external inspection is impossible without having access to the tank bottom. This paper will introduce a novel inspection method for external monitoring of the surface of the tank bottom plate in real-time. The proposed technique proactively approaches the problem by predicting the corrosion before it occurs. In this technique an array of microwave-based sensors operating at ISM band (2.57 GHz) are introduced for defect prediction. The array is composed of equally-distant and identical microwave spiral ring resonators (SRR) [6] that are electromagnetically coupled to a transmission line. All resonances created by the array elements merge in one band-stop frequency response with very high isolation. Once the sensors’ environment is altered by any defects such as an air breach, liquid ingress [7] or corrosion initiated, a resonance shift will occur indicating coating risks. To prove the concept, an initial prototype for small tanks of 3–5 ft. diameter is investigated. Two-port system data illustrates that in case of a coating defect, the frequency profile accordingly changes and provides a signature. The obtained data is used to predict possible corrosion in timely manner. The proposed sensor array enables external monitoring of tank bottoms surface where visual inspection is impossible while the tank is in-service.

Internal corrosion modeling of oil and gas pipelines requires the consideration of interactions between various parameters ( e.g. brine chemistry, flow conditions or scale deposition). Moreover, the number of interactions increases when we consider that there are multiple types of internal corrosion mechanisms (i.e. uniform corrosion, localized corrosion, erosion-corrosion and microbiologically influenced corrosion). To better describe the pipeline internal corrosion threats, a Bayesian network model was created by identifying and quantifying causal relationships between parameters influencing internal corrosion. One of the strengths of the Bayesian network methodology is its capability to handle uncertain and missing data. The model had previously proven its accuracy in predicting the internal condition of existing pipelines. However, the model has never been tested on a pipeline in design stage, where future operating conditions are uncertain and data uncertainty is high. In this study, an offshore pipeline was selected for an internal corrosion threat assessment. All available information related to the pipeline were collected and uncertainties in some parameters were estimated based on subject matter expertise. The results showed that the Bayesian network model can be used to quantify the value of each information (i.e. which parameters have the most effect now and in the future), predict the range of possible corrosion rates and pipeline failure probability within a given confidence level.

The pipeline industry has been using Inline Inspection (ILI) since the 1970s. High resolution tools have been available for inspecting corrosion from about the 1980s and related ILI-based programs have been evolving. In this study incident rate data from the last 30 to 40 years of experience was examined and trended. Corrosion related incident rates have reduced where ILI programs have been implemented. Significant changes in programs have shown related incident reductions or positive trends. Throughout this time there have been a few post-ILI incidents and by taking a closer look at these incidents and learning from the findings the ILI-based assessments and programs were further improved. In this study, all of the post-ILI corrosion related ruptures on the TransCanada system have been closely examined and trended. The effects of program changes and related changes to performance indicators have been examined. Some significant industry failures, where data is publicly available, have also been examined. These failures have been analyzed and trended to understand significant commonalities between these failures. Data was analyzed with the intention of learning from them and applying this learning to avoid similar failures in the future. By understanding the uncertainties, technology limitations, and limits of applicability as well as the types of programs used and where these have not identified probable failures practical solutions were derived. All of the failures have been examined (as allowed by the data available) to find approaches which would have proactively identified these events, so that similar events can be avoided in the future. ILI tools generate a wealth of information and appropriate use of this information has shown to be effective in managing pipelines. However, it is also important to understand the limitations of technologies, learn from the failures, and acknowledge uncertainties so that undesirable events can be avoided.

Over the past 15 years, extensive studies have been conducted on the tensile strain capacity (TSC) and compressive strain capacity (CSC) of pipelines. The existing studies were mainly targeted at the design and construction of new pipelines. However, the impact of anomalies (e.g., corrosion anomalies) on the TSC and CSC has not been explicitly and adequately considered. This paper summarizes work performed as part of a major effort funded by the US Department of Transportation Pipeline and Hazardous Materials Safety Administration (DOT PHMSA) aimed at examining the impact of corrosion anomalies on the TSC and CSC of pipelines. In this work, the strain capacities were examined analytically, and the analytical work was compared to results from selected full-scale tests. Based on the summarized work, guidelines were developed for assessing the TSC and the CSC of corroded pipes. The guidelines are applicable to different types of corrosion anomalies, including circumferential grooves, longitudinal grooves and general corrosion. The strain capacities can be calculated using the key material properties and dimensions of pipe and corrosion anomalies as inputs.

Integrity reliability science plays a major role in the integrity management of transmission piping, which is piping that traverses long distances across the continent, at high pressures, and can experience high pressure cycling. This science can be applied to non-transmission piping such as lateral piping, which traverses between a transmission line and a facility, or between two facilities, at lower pressures and with lower pressure cycling. Laterals are susceptible to the same threats as transmission lines (internal corrosion, external corrosion, cracking, geotechnical hazards, etc.). However, due to their operation, laterals are only highly susceptible to internal and external corrosion. While site specific conditions may result in a high susceptibility of a geotechnical hazard, this threat is outside of the scope of this paper. On transmission piping, corrosion is generally managed with In-Line Inspection (ILI), Non-Destructive Examination (NDE), and corresponding repairs (e.g. sleeving) to assess and mitigate. With laterals, there can be limited ILI and NDE data. As such, the data used in the quantitative reliability framework for these threats is not available and this creates a gap in the process. This paper addresses this gap through the application of semi-quantitative reliability analysis for internal and external corrosion on laterals along with a risk-based integrity decision making framework. The proposed approach is designed to enable pipeline and facility operators to make effective decisions around lateral integrity programs given the available data, and to better understand the limitations of integrity decision making. Moreover, the paper expands the discussion around the difference between risk-informed and risk-based integrity decision making in order to provide a guideline for optimal and safe integrity management programs considering different criteria. Case studies that include limited or no ILI or NDE information are used to demonstrate the application of semi-quantitative and quantitative reliability assessment of laterals along with the exploration of challenges in calibrating the two assessment methods to provide an example of how reliability science can be applied to laterals and how this can be used in effective decision making given such limitations.

Since the late 1980’s Ultrasonic tools have been used for the detection and sizing of crack like indications. ILI service providers developed inspection technologies for liquid and gas lines that are widely used nowadays. In comparison to axial cracking, circumferential cracking is not a prevalent risk to most pipelines and therefore is not as well understood. Nevertheless, pipeline Operators observe from time to time circumferentially oriented defects, often in combination with circumferential welds or local stress/strain accumulations. These are often caused by pipeline movement, which may especially occur in mountain areas. With the introduction of Ultrasonic circumferential crack inspection tools in the late 2000’s the knowledge has steadily increased over time. Extensive data collected from in-ditch NDE validations has provided NDT Global with an increased knowledge of the morphology of single cracking and stress corrosion cracking defects both in the axial and circumferential orientations. Field verifications have shown that not all features have the same morphology. Some of the challenges with circumferential cracking are for features that fall outside of the industry standard specifications. These types of features can exhibit characteristics such as being sloped, skewed or tilted. In 2016 NDT Global was approached by Plains Midstream Canada to complete inspections utilizing the 10″ Ultrasonic Circumferential crack inspection technology. The pipeline system spans 188km within Canada and consists of 2 segments. The pipeline traverses several elevation changes and crosses several creeks and roads. Circumferential cracking was identified during dig campaigns performed for other threats, therefore the need to inspect each pipeline segment with the Ultrasonic circumferential technology was identified. Plains Midstream Canada and NDT Global formed a close collaboration to assess the severity of circumferential crack features in this line. This paper will discuss integrity aspects from an Operator and Vendor perspective. Challenges identified due to the morphology of the circumferential crack like indications and derived analysis rules and interpretation methodologies to optimize characterization and sizing are presented. Finally, potential opportunities to maintain the integrity of similar assets by applying some of the findings and enhance the management and decision making process are suggested.

A pipeline operator set out to assess the risk of circumferential stress corrosion cracking and to develop a proactive management program, which included an in-line inspection and repair program. The first step was to screen the total pipeline inventory based on pipe properties and environmental factors to develop a susceptibility assessment. When a pipeline was found to be susceptible, an inspection plan was developed which often included ultrasonic circumferential crack detection in-line inspection and geotechnical analysis of slopes. Next, a methodology was developed to prioritize the anomalies for investigation based on the likelihood of failure using the provided in-line inspection sizing data, crack severity analysis, and correlation to potential causes of axial or bending stress, combined with a consequence assessment. Excavation programs were then developed to target the anomalies that posed the greatest threat to the pipeline system or environment. This paper summarizes the experiences to date from the operator’s circumferential stress corrosion cracking program and describes how the pipeline properties, geotechnical program, and/or in-line inspection programs were combined to determine the susceptibility of each pipeline and develop excavation programs. In-line inspection reported crack types and sizes compared to field inspection data will be summarized, as well as how the population and severity of circumferential stress corrosion cracking found compares to the susceptible slopes found in the geotechnical program completed. Finally, how the circumferential SCC time-average growth rate distributions were calculated and were used to set future geohazard inspections, in-line inspections, or repair dates will be discussed.

The failure of a corroded pipe is generally controlled by the depth and the longitudinal extent of the metal loss area subjected to hoop stress. However, the failure of metal loss due to its circumferential extent under longitudinal stress is possible if significant longitudinal stress exists in the pipe or the metal loss has considerable circumferential extent and depth. If such circumstances exist, it is prudent to conduct a complementary analysis of pipe integrity to assess the potential for circumferential as well longitudinal failure. Most existing approaches for assessing circumferential metal loss, such as Miller’s equations, were derived by assuming the metal loss to be centered at the extreme stress position around the pipe circumference, i.e., the center of the metal loss is centered at the location of the maximum bending stress in the pipe. The assessment may be over-conservative if the metal loss area deviates from the extreme position related to the bending plane. Described in this paper is a new approach to assess the potential for circumferential failure of metal loss centered at an arbitrary angle from the location of maximum bending stress. The approach results in the same failure stress as existing models when the metal loss is centered at the location of maximum bending stress. The failure stress increases when the metal loss deviates from the location of maximum bending stress and reaches the maximum value when the metal loss is centered at the neutral axis. The equations of the model developed in this paper can be easily implemented into a spreadsheet tool for routine integrity assessment. Other considerations related to the assessment of circumferential metal loss are also discussed, including non-uniform corrosion, negligible corrosion, and the interaction of multiple corrosion areas in the same pipe cross section. The model developed in this paper can also be used to determine the cutoff line for plastic collapse in a failure assessment diagram (FAD) based approach for assessing circumferential cracks, such as API 1104 Appendix A and API 579.

Existing corrosion assessment models were developed and validated under the assumption that internal pressure was the principal driver for burst failure and that longitudinal strain levels were low. The impact of moderate to high levels of longitudinal strain on burst capacity had not been explicitly considered. This paper summarizes work performed as part of a major effort funded by the US Department of Transportation Pipeline and Hazardous Materials Safety Administration (DOT PHMSA) aimed at examining the impact of longitudinal strain on the integrity of pipelines with corrosion anomalies. This paper focuses on the burst pressure of corroded pipes under high longitudinal strains. It is known that longitudinal tensile strain does not reduce the burst pressure relative to that of pipes subjected to low longitudinal strains. Therefore, existing burst pressure models can be considered adequate when the longitudinal strain is tensile. However, longitudinal compressive strain was found to lead to a moderate reduction in burst pressure. Numerical analyses were conducted to study the effect of longitudinal compressive strain on the burst pressure of corroded pipes. A burst pressure reduction formula was developed as a function of the longitudinal compressive strain. Full-scale tests were conducted to confirm the findings of the numerical analysis. Guidelines for assessing the burst pressure of corroded pipes under high longitudinal compressive strains were developed from the outcome of numerical analysis and experimental tests. The guidelines are applicable to different types of corrosion anomalies, including circumferential grooves, longitudinal grooves and general corrosion.

Oil pipelines and gas pipelines operations result in very different pressure fluctuation schemes due to different compressive properties of liquids and gases. Liquid fluids such as oil are less compressible and pressure fluctuations during oil pipelines operations are more frequent and vary over a wide range of magnitudes and frequencies, compared with those during gas pipelines operations. Despite the differences in operating conditions indicated above, both oil pipelines and gas pipelines are susceptible to stress corrosion cracking and corrosion fatigue failures. This investigation was initiated to understand the different crack growth rate behavior of pipeline steels characteristic to the type of pressure fluctuation schemes in near-neutral pH environment, that is, oil pipelines vs. gas pipelines. It was suspected that the similar range of service life between oil pipeline steels and gas pipeline steels could be attributed to a higher rate of direct dissolution at the tip of a crack during gas pipeline operation because of much higher mean pressures, despite their lower crack growth caused by corrosion fatigue. In the case of near-neutral pH stress corrosion cracking, corrosion makes minor contribution to crack growth but produces diffusible hydrogen that interacts with cyclic loading to make cracks grow. This study was performed using specimens with surface cracks, which simulated the following two environmental conditions: 1) fully exposed to the environment, 2) shielded from the environment, exposed to hydrogen only. In Case 1), the specimen surface, on which the surface cracks were made, was fully exposed to a near-neutral pH solution, allowing the occurrence of corrosion at the crack tip. In Case 2), a narrow strip of a coating was applied to prevent the cracks from direct contact with the corrosive solution; however, the cracks were affected by diffusible hydrogen which had been generated as a by-product of corrosion on the adjacent steel surface free of coatings. These specimens were mechanically loaded under different pressure schemes typical of both oil and gas pipeline operations. It has been found that crack growth caused by direct dissolution of crack tip materials is insignificant, regardless of pipeline operating conditions. A much higher crack growth rate, attributed to hydrogen embrittlement, was found under gas transmission conditions, while a higher corrosion fatigue crack growth was found under oil transmission conditions. Based on these findings, strategies on crack growth mitigation, characteristic to each type of pipeline operation are also proposed.

At the forefront of the effort to understand and mitigate pipeline corrosion is the prediction of corrosion growth rates. It is important to understand the effect of corrosion growth estimates on integrity management decisions. An overly conservative approach results in unnecessary digs, while removing conservatism increases the potential for a missed feature to grow to a threatening size. While approaches to feature depth growth have been well-established, there has been less investigation into the growth of feature lengths. A literature review was performed on the methodologies applicable to length growth, and their performance was compared to those that only account for depth growth using a sample analysis. For pipelines with multiple in-line inspection (ILI) runs, feature or signal matching can be used to estimate the change in feature size. These rates can be used directly on individual features, averaged across pipe joints, or compiled into a statistical distribution. Alternatively, only one ILI measurement can be used and an assumption made on the age of the defect. These approaches are more commonly applied to depth growth but could be used to predict length growth as well. To compare the growth methodologies, the study used historical ILI measurements of a liquid pipeline to predict feature sizes and estimated burst pressures determined at the time of the latest ILI. The number of defects correctly predicted to have an insufficient burst pressure safety factor for safe operation was compared to the number of defects that were erroneously predicted to not meet this criterion, and those that were predicted to be safe but later found to not meet the safety factor requirement. The number of erroneously flagged defects was found to vary the most between methodologies. For the assessed data set, using the joint average rate based on feature box-matching was non-conservative on average. It was also found that incorporating length growth did not significantly affect the accuracy of the burst pressure predictions.

In-line inspection (ILI) data is commonly used in corrosion growth models (CGMs) to predict the corrosion growth in energy pipelines. A hierarchical stochastic corrosion growth model is considered in this paper which considers the variations in the corrosion growth, both spatially and temporally, the inherent measurement error of the ILI tools as well as the model uncertainties. These uncertainties are represented as unknown model variables and are often inferred using a Bayesian method [1], [2] and samples of the unknown parameters’ posterior probability density functions (PDFs) are obtained using Markov Chain Monte Carlo (MCMC) sampling techniques [3]. ILIs can result in massive data sets. In order for MCMC-based inference techniques to yield reasonably accurate results, many samples (approaching infinity) are required. This fact in addition to the massive data sets exponentially increases the scale of the inference problem from an attainable solution to a potentially impossible one that is limited by today’s computing power. For this reason, MCMC-based inference techniques can become inefficient in the cases where ILI datasets are large. The objective is to propose variational inference (VI) as an alternative to MCMC to determine a Bayesian solution for the unknown parameters in complex stochastic CGMs. VI produces approximations of the posterior PDFs by treating the inference as an optimization problem. Variational inference emerged from machine learning for Bayesian inference of large data sets; therefore, it is an appropriate tool to use in the analysis of mass pipeline inspection data[4]–[7]. This paper introduces VI to solve the inference problem and provide a solution for a hierarchical stochastic CGM to describe the defect-specific corrosion growth experienced in pipelines based on excessively large ILI datasets. To gauge the accuracy of the VI implementation in the model, the results are compared to a set of values generated using a stochastic gamma process that represents the corrosion growth process experienced by the pipe.

To improve the safety of a pipeline system, engineers use different methods to diagnose the hazardous pipeline accidents. However, most methods ignore the time dependence of pipeline failures. The aim of this paper is to provide a novel approach to analyzing the hazardous liquid pipeline incidents’ temporal structure. The database of hazardous liquid spillages from the US between 2002 and 2018 is collected by the Pipeline Hazardous Material Safety Administration of the US Department of Transportation. The result suggests that the whole oil pipeline incident sequence cannot be modeled as a Poisson (random and independent) process, which means that a hazardous liquid pipeline incident is not statistically independent from the time elapsed since the previous event. But the serious pipeline failures are random and unpredictable. The analysis also indicates that the equipment failure, corrosion, material failure and incorrect operation are the four leading failure causes, responsible for most of the total incidents. The study provides insights into the current state of hazard liquid pipelines in the US and baseline failure statistics for the quantitative risk assessments of such pipelines.

Pipeline risk models are used to prioritize integrity assessments and mitigative actions to achieve acceptable levels of risk. Some of these models rely on scores associated with parameters known or thought to contribute to a particular threat. For pipelines without in-line inspection (ILI) or direct assessment data, scores are often estimated by subject matter experts and as a result, are highly subjective. This paper describes a methodology for reducing the subjectivity of risk model scores by quantitatively deriving the scores based on ILI and failure data. This method is applied to determine pipeline coating and soil interaction scores in an external corrosion likelihood model for uninspected pipelines. Insights are drawn from the new scores as well as from a comparison with scores developed by subject matter experts.

CSA Z662, Oil and gas pipeline systems, defines class location as “a geographical area classified according to its approximate population density and other characteristics that are considered when designing and pressure testing piping to be located in the area.” In other words, the purpose of class location designations is to identify areas where specific measures are considered necessary to enhance public safety. Designations range from Class 1 (rural) to Class 4 (urban with high-rise buildings). The current class location framework relies mainly on a location factor (L) to represent reliability. Higher reliability is achieved by using more resistant pipe — that is thicker and/or stronger — to reduce the probability of failure from operational hazards, such as corrosion and mechanical damage caused by line strikes. Currently, the need for a particular level of reliability is driven principally by the number of people impacted. This paper discusses possible measures that can be implemented in the next edition of Z662 that, beyond requiring thicker pipe for certain products, will strengthen the class location designation system by considering the potential impact radius of an ignited gas pipeline rupture, as well as the occupancy and nature of buildings within assessment areas. The paper also discusses possible changes to improve environmental protection by introducing the concept of a designated geographical area (DGA) and associated requirements, enhancements to valve spacing requirements, and the handling of changes to class location designations for existing pipelines through interim measures and retroactivity.

Carbon steel piping can be exposed to environments that contain various chemical and organic elements that induce corrosion and cracking events. This can lead to the loss of fluid into surrounding sensitive and remote environments. To minimize this inherent risk, various coating technologies have been utilized over the years in industry. These coatings typically suffer from complex application methods, high application cost, and vulnerabilities to environmental effects such as mechanical damage and cathodic disbondment. To overcome these challenges, a novel epoxy based composite coating that utilizes the properties of various nano-particulates such as graphene nanoplatelets (GnP), multi-walled carbon nanotubes (MWCNTs), chitosan, and hBN (Hexagonal boron nitride) is developed. These nanoparticles create a nano-scale “brick and mortar” type effect that is analogous to various natural structures such as the abalone shell (nacre). These nano-structures also enhance coating performance by increasing mechanical strength and anti-bacterial properties while simultaneously decreasing gas permeability. This performance enhancement serves to reduce overall corrosion-induced disbondment area. The dispersion of nanoparticles is verified using various microscopy methods such as scanning election microscopy and an optical 3D profilometer. To confirm the role of nanoparticles in the epoxy composite, the samples undergo rigorous testing to determine both mechanical properties as well as the feasibility of coating application, in particular, for use on girth welds. Using a dynamic mechanical analysis (DMA), the material strength of each combination of nanocomposites is tested and used to determine the glass transition temperature. The testing also includes abrasion, and both long-term mechanical and thermal behaviors of the coating. To test the feasibility of the coating, cathodic protection tests in an accelerated corrosive environment, and gas permeability tests are carried out. The results show that the composite coating made from these nanomaterials had a decrease in cathodic disbondment area and gas permeability and an increase the glass transition temperature and scratch resistance. Therefore, the nanocomposite coatings are found to be a significant improvement over standard epoxy-based coating.

For almost 30 years composite repair technologies have been used to reinforce high pressure gas and liquid pipeline transmission systems around the world. The backbone of this research has been full-scale testing, aimed at evaluating the reinforcement of anomalies including, corrosion, dents, vintage girth welds, and wrinkle bends. Also included have been the assessment of reinforced pipe geometries including welded branch connections, elbows, and tees. Organizations sponsoring these research efforts have included the Pipeline Research Council International, regulatory agencies, pipeline operators, and composite repair manufacturers. Many of these efforts have involved Joint Industry Programs; to date more than 15 different industry-sponsored programs and independent research efforts have been conducted involving more than 1,000 full-scale destructive tests. The aim of this paper is to provide for the pipeline industry an updated perspective on research associated with composite repair technologies. Because of the continuous advance in both composite technology and research programs to evaluate their effectiveness, it is essential that updated information be provided to industry to minimize the likelihood for conducting research efforts that have already been addressed. To provide readers with useful information, the authors will include multiple case studies that include the reinforcement of dents, wrinkle bends, welded branch connections, and planar defects.

This work proposes an assessment procedure for the determination of the remaining strength in pressure vessels with pitting type metal loss, trough the developed of integrity diagrams according to the pitting density, pitting depths and the internal pressure of the component using Finite Element Analysis simulations. The simulations results indicate that the pitting density and depths according to the Gumbel Max Distribution, are the main factors that determine the mechanical integrity of the component; where 45% damaged area by pitting generates a stress concentration that multiplies at least ten times the stress compared with components without defects, since these variables present a synergistic behavior in the stress state. The proposed assessment procedure facilitates the evaluation of the components that present pitting corrosion damage, due to the geometric and population effect of the pitting is considered in the finite element simulation.