Inspection of High Consequence Line Provides Critical Insight

Published by , Digital Assistant Editor
Energy Global, Monday, 19 March 2018 16:26

For pipelines transporting corrosive products, regular monitoring and inspection is vital to ensure long term operation and environmental safety compliance. Recent high-profile pipeline failures have focused increased regulatory scrutiny on the integrity assessment and management of pipeline assets throughout the world. This increase in scrutiny is even more pronounced for pipelines deemed “unpiggable.” When an operator requested an ultrasonic in-line inspection on a pipeline in an environmentally sensitive area, high resolution data provided a complete understanding of the internal condition of their asset, allowing for confident maintenance planning.

History

The inspected pipeline was a sulfuric acid pipeline, located in an environmentally sensitive area. The pipeline had been regularly monitored using hand-held spot ultrasonic (UT) inspection, and had undergone a number of section replacements after several failures, particularly at pipeline bends. Although spot UT can be an effective inspection method, it does not take data measurements of the entire pipeline, but rather takes individual wall thickness measurements at specific intervals along the pipeline surface. Due to the sensitivity of the surrounding environment and corrosive nature of the pipeline product, the performance of an in-line inspection was critical in understanding the full internal condition of the line.

Inspection

There were a number of challenging factors to consider prior to the performance of the in-line inspection. The configuration of the pipeline was such that a number of traditional inspection technologies were not capable of successfully navigating the pipeline. For example, there were numerous 1.0D bends located along the length of the line. For traditional in-line inspection tools, these kinds of navigational features do not allow for the tool to successfully pass through the pipe. It was critical that the in-line inspection tool chosen for this inspection be capable of navigating the challenging configuration of the pipeline. Another component to consider was the pipeline’s liquid product. Since the line carried sulfuric acid, additional actions were taken to ensure the successful inspection of the pipeline. In order to collect accurate data, the tool was contained within a diesel slug with a batch pig, and flowed through the line with 5000 gallons ahead and 10 000 gallons behind, propelled by nitrogen. By using a batching system, the tool was able to both navigate the line and collect high resolution data.

Results

The inspection was successfully performed on the pipeline, and the data was analysed. Interestingly, the data revealed indications of eddy damage near every circumferential weld. These welds were located where newly repaired pipe had been installed. In these areas of newly installed pipe, higher rates of corrosion and erosion were observed. There were also indications of hydrogen grooving adjacent to welds, as seen in Figure 1. However, there were no areas of the pipeline that required immediate remediation.

Figure 1. Inspection data indicating areas of hydrogen grooving along the internal surface of the pipeline.

It was recommended that the areas of deeper weld penetration undergo frequent monitoring, and suggested inspection intervals were presented to the facility. The pipeline was subsequently inspected multiple times in the following years, using ultrasonic in-line inspection. The data from each inspection run was then compared, in order to comprehensively monitor corrosion rates. By performing recurring run comparisons, the rate of any damage occurring on the line could be quantified on a regular basis. Run comparison analyses are largely effective in providing an accurate guideline for future maintenance planning.

Conclusion

By performing repeatable and regular in-line inspections on the pipeline over the course of its lifetime, the operator was able to gauge the complete condition of the asset, identifying localized areas of erosion/corrosion and eliminating the problematic failures that have historically impacted this particular asset. The comprehensive inspection strategy ultimately provided assurance that the asset would continue to operate efficiently, achieving considerable cost savings and peace of mind.

 

 

Protecting a Pipeline When Its Coating Has Aged

An aging pipeline is being prepared for recoating. Photo courtesy of Jeffrey Didas.

 Development of the pipeline systems currently used to transport natural gas, oil, and refined products in the United States began more than 70 years ago,1 with more than 50% of U.S. gas transmission, distribution, and hazardous liquid pipelines built before 1970.2 This means that some of the country’s existing pipeline infrastructure was built with materials that are no longer used today, although they were state-of-the-art at the time. Coating materials, for example, have significantly improved over those used decades ago. As the nation continues to increase its demands for energy transportation, investment in infrastructure upgrades—including aging pipelines—is a necessity to continue moving products safely and with minimal failure incidents.

The exterior of a buried pipeline is exposed to conditions that can lead to corrosion. Early on, pipeline operators began applying coatings to the pipe exterior at the time of installation to prevent corrosion. These initial pipe coatings were usually tape wraps, wax, asphalt, and coal tars. According to the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), two significant risk indicators for pipeline failure are the pipeline’s age and material of construction.3

Coatings are the main tools for protecting a pipeline against external corrosion, but they will weaken due to age and other factors. “All coatings have a service life,” says NACE International member Jeffrey L. Didas, a NACE-certified Specialist in coatings as well as cathodic protection (CP) and corrosion, and a senior corrosion engineer with MATCOR, Inc. (Chalfont, Pennsylvania). “Over time a coating will age and deteriorate due to soil stress, pipe movement, temperature changes of the pipe, and wet/dry, flood/drought conditions,” he adds. Didas notes that major pipeline construction from the 1940s to the 1960s mainly used coal tar enamel or asphalt enamel coatings for pipelines. Although these coatings had a predicted design life of 20 to 30 years, many have far exceeded this expected service life and are approaching or surpassing 70 years of age. Coating failures that have occurred tend to be cracking, disbondment, sagging, and melting from higher product temperatures.

Top: A disbonded, peeling coating on a buried pipeline. Photo courtesy of Jeffrey Didas. Above left: A DCVG survey is performed on a gas pipeline. Photo courtesy of JW’s Pipeline Integrity Services. Above center: A drilling rig is used for installing distributed anodes. Photo courtesy of Jeffrey Didas. Above right: An aging pipeline is being prepared for recoating. Photo courtesy of Jeffrey Didas.

Top: A disbonded, peeling coating on a buried pipeline. Photo courtesy of Jeffrey Didas. Above left: A DCVG survey is performed on a gas pipeline. Photo courtesy of JW’s Pipeline Integrity Services. Above center: A drilling rig is used for installing distributed anodes. Photo courtesy of Jeffrey Didas. Above right: An aging pipeline is being prepared for recoating. Photo courtesy of Jeffrey Didas.

Starting in the 1920s, pipeline operators determined that coatings alone would not provide complete corrosion protection and began installing cathodic protection (CP) systems to enhance the corrosion protection of their pipelines. A CP system applied in conjunction with a coating can also extend the service life of the coating. Typically this pipeline coating will be a dielectric coating, which is a barrier to the flow of electricity. A coating with higher dielectric strength—the voltage required to cause the coating to break down (which is expressed as V or kV per unit of thickness)—will provide superior isolation. The purpose of a dielectric coating is to isolate the pipeline electrically and physically from the environment, while reducing protective current demands on the CP system. Other properties necessary in a dielectric coating are resistance to environmental fluids and the product being transported, impact/abrasion resistance, adhesion, and resistance to cathodic disbondment.

As pipeline coatings age they start to lose their protective properties, such as elasticity and dielectric strength, and will crack or disbond, Didas explains. He comments that an increase over time in CP current requirements to cathodically protect the pipeline is a sign that a coating is deteriorating.

Evaluating a Pipeline Coating

Typically, pipeline operators conduct an “on/off” close-interval potential survey4 (CIS or CIPS) of a pipeline about once every five years to assess the performance of installed CP systems vs. system performance criteria. A CIS can also be used to detect some coating defects.The principle of a CIS is to record the pipe-to-soil (P/S) potential (voltage) profile of a pipeline over its entire length by measuring the potential difference between the buried pipe and surrounding soil—with the CP current sources “on” as well as a synchronized interruption of the CP current sources (“off”)—at test point intervals that do not significantly exceed the depth of the pipe (often ~1 m). Measurements are taken while walking along the length of the pipeline. Didas notes that locations where there is little or no polarization of the pipe indicate the coating may be deteriorating, which can be seen by a downward (less negative) trend of potentials over time that require increased CP current to bring them back to a protective level. Areas where the coating appears to be failing can be further tested using additional aboveground techniques.

The downward potential trend, Didas says, usually prompts the operator to perform a direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG) test—aboveground methods of measuring the change in electrical voltage gradient (the voltage per unit length along a conductive path) in the soil along and around a pipeline to locate coating holidays and characterize corrosion activity.5DCVG and ACVG surveys evaluate in detail the coating condition on buried pipelines and identify and classify coating holidays. They are performed in those areas where the CIS indicates additional CP is needed.

With the CP system operating at its normal output, the DCVG technique applies a DC signal to the pipeline. Any defects in the coating will allow electric current to flow into the pipe from the surrounding soil. These currents cause voltage gradients in the soil above the pipeline, which can be measured using a voltmeter. Voltage gradients between two reference electrodes placed a distance apart are a result of current pickup or discharge at defect locations in the pipeline’s coating. DCVG surveys are capable of distinguishing between isolated and continuous coating damage.

A CIS of a pipeline in West Texas is performed by a cathodic protection technician. Photo courtesy of JW’s Pipeline Integrity Services.

A CIS of a pipeline in West Texas is performed by a cathodic protection technician. Photo courtesy of JW’s Pipeline Integrity Services.

Protective coating conductance techniques6 measure the coating conductance (inverse of coating resistance) on sections of underground pipelines and are also used to determine the general condition of the coating. This test method only applies to pipe coated with dielectric coatings. Conductance tests are performed whenever significant changes in P/S potentials and current requirements occur. Specific areas with high conductance values on a given section of pipeline indicate a deteriorated coating. To obtain data for coating conductance calculations, interrupted P/S potentials and pipeline current readings are taken at preselected intervals. Soil resistivity can directly affect coating conductance measurements and should be considered when evaluating a section of a pipeline coating.

Once the location of the coating defect is determined with aboveground techniques, visual and electrical inspection of in-service pipeline coatings can evaluate the condition and performance of an external coating system. These inspections can be conducted at bell holes (excavations shaped like an inverted bell, wide at the top and narrower around the pipeline to be examined) dug for inspection purposes. Many operators will also run an inline inspection with a smart tool to determine if there is corrosion where aboveground tests indicate the coating has deteriorated. “If you have a coating issue, you want to check out the internal inspection data, too.” Didas says.

Pipeline recoating is a proven method of rehabilitating pipelines with a deteriorated coating. It is considered the best long-term technical option for coating repair, and is required when the coating has failed and will no longer support CP, Didas says. At this point, he explains, the coating has completely lost its dielectric strength and too much CP current is needed to polarize the pipe. When done properly with a high-performance coating system, he says, recoating can increase the pipe’s service life by 50 or more years. When combined with CP, the service life could be extended to 100 years.

Recoating also can be the most expensive option, Didas adds, noting that recoating today can cost anywhere from $125 to $550 per linear ft (0.3048 m). Challenges associated with recoating a pipeline include pipeline excavation and right-of-way (ROW) conditions, which may be rocky, environmentally sensitive, highly populated, or in close proximity to other pipelines; environmental permitting; pipeline operating conditions; time of year (winter/summer); open blasting for surface preparation; handling and disposal of the removed coating; and landowner issues. As recoated areas of the pipeline increase, he notes, CP requirements should be reevaluated as well, since existing CP systems may need to be adjusted or modified for well-coated pipe.

Extending Aging Coating Life with CP

A linear anode is installed near the pipeline. Photo courtesy of Jeffrey Didas.

A linear anode is installed near the pipeline. Photo courtesy of Jeffrey Didas.

When the aging coating is not yet to the point where the pipeline requires recoating, installing a linear or distributed anode system to augment CP is a cost-effective option that provides protection for the pipeline as well as extends its life, says Didas. Typically, for cross-country pipelines, the impressed current CP (ICCP) design installed during construction is a remote anode bed that provides protective current for miles of pipeline. According to NACE member Norm Moriber, chief engineer with Mears Group, Inc. (San Ramon, California) and MP’s technical editor, the distribution of protective current down the pipeline, which is known as attenuation, is dependent on the resistances between the remote anode bed and the target structure’s surface. This causes the current density to decrease as the distance from the remote anode bed increases. When poor coating condition creates a localized area of low P/S resistance, providing adequate protective current to that area can be difficult. Increasing the current from the remote anode bed to keep potentials above criteria, however, can cause interference issues with neighboring pipelines, as well as overprotect areas of the pipeline closer to the anode bed, Didas warns. Also, the original CP design may not support the need for increased current at localized areas along the pipeline, Moriber adds.

A linear anode CP system resolves these problems by configuring the anode bed as a closely coupled structure that parallels the pipeline, Moriber says. “Overall, linear anodes provide a valuable tool for achieving cathodic protection for pipelines with an aging coating or other special requirements,” he comments. A linear anode is a continuous wire anode, typically comprised of a copper or titanium core and a conductive outer layer, and installed in a coke breeze backfill or prepackaged in a porous sleeve filled with coke breeze. The anode facilitates continuous current distribution along the length of the pipe surface, and its low-current output avoids the coating damage that can happen when trying to provide adequate current to distant locations from a localized anode bed, and excessive CP occurs near the current source. Linear anodes are closely coupled electrically with the pipeline, which minimizes current losses to nearby structures, helps eliminate stray current concerns, and also reduces current requirements for the system. Linear anodes can be installed by cable plow, directional drill, trencher, or backhoe and includes the anode and the header cable in the same installation.

A distributed anode system features individual graphite, cast iron, or MMO anodes, in various shapes and sizes, that are located close to the pipeline and spaced along its length (e.g., every 100 ft [30 m]), and interconnected with a header cable. Distributed anodes provide localized high-current output with an average resistance to earth and a high potential gradient. They can be installed by boring or backhoe and require the header cable to be installed between the anodes.

A rectifier provides power for a remote anode groundbed as well as the linear anode and distributed anodes. Photo courtesy of Jeffrey Didas.

A rectifier provides power for a remote anode groundbed as well as the linear anode and distributed anodes. Photo courtesy of Jeffrey Didas.

The primary factor for determining which type of anode system should be used is typically the pipeline’s ROW, says Didas. If plowing, trenching, or directional drilling can be accommodated, then the linear anode is usually the appropriate choice as it is more efficient and provides a uniform current distribution to the pipeline. Distributed anodes are used when ROW conditions allow only single anode installations because of rocky soil, limited easements, etc. The actual evaluation and selection of the CP system, including installation layout, current requirement testing, anode type, and installation method, should be performed by or under the direct supervision of a NACE-certified CP specialist or licensed corrosion engineer. The evaluation will determine whether a linear anode, distributed anode system, or a combination of both can be successfully integrated with the existing coating and recoated areas.

Adding well-designed CP with quality materials can extend the life of a CP system up to 50-plus years, Didas says. CP vs. recoating is a simpler fix and less intrusive on the pipeline ROW in areas where the pipeline coating is still compatible with CP. Considerations for installing additional CP are pipe accessibility, available electrical power, ROW conditions, the length of pipeline to be protected, and cost. A linear anode CP can be installed for ~$15 to $25 per foot for a typical pipeline ROW. The cost can go up to $50 per foot if the ROW has rocky conditions and there is a need for horizontal directional drilling.

Case History

Didas describes a case history where the asphalt enamel coating on a 255-mile (410-km) long U.S. pipeline, applied between 1960 and 1962 at the time of the pipeline’s installation, was reaching the end of its service life. The 32-in (813-mm) diameter pipeline transports refined products. Environmental factors along the pipeline’s ROW—soil stress, clay soil, rocky soil, and severe drought—had caused coating deterioration, disbondment, and failure over 35% of this line. The existing CP system incorporated conventional remote and close-coupled surface anode beds.

The pipeline integrity program called for conducting regular CIS surveys and other tests to monitor the pipeline’s CP potentials. Where survey results indicated possible coating deterioration, the pipeline owner would determine whether it was feasible and more economical to add CP, or if the section of pipeline needed to be placed on the recoating schedule. Didas notes that it is more cost effective to recoat segments of the pipeline as part of a plan rather than to reactively coat a section here or there; however, if there is a corrosion problem, timely mitigation must be implemented. Over a 10-year period, the pipeline was rehabilitated with recoating and CP. High-performance, two-part epoxy with a service life of 50 years was used to recoat 25 miles (40 km) (more than 98 segments) of the pipeline, the total amount of recoating deemed necessary after aboveground surveys and bell hole inspections were done, Didas says.

CP was added as follows: 195 miles (314 km) of linear anodes were installed in areas where the pipeline was responding well to CP and recoating was not necessary. Linear anodes were used because the existing coating had lost some of its properties—mainly attenuation—and the linear anodes were able to supply continuous current along the length of the pipeline segments. Twenty-one remote CP systems were installed perpendicular to the pipeline (with 500 ft [152 m] typically between the pipe and the first anode) in a conventional or surface anode bed configuration, with 20 to 30 anodes spaced 20 to 30 ft (6 to 9 m) apart due to varying soil resistivity, and buried 15 to 25 ft (5 to 8 m) deep. Two deep anode systems were installed where the ROW conditions did not allow the installation of a remote or linear anode bed and/or surface space was restricted due to possible CP interference issues or lack of an easement. Additionally, eight facility CP system upgrades were done with distributed anode systems, and 400 test sites were added. So far, Didas notes, the recoating and CP upgrades have proven to be successful. The entire CP system, in conjunction with the recoating, is 100% effective over the 255 miles of pipeline ROW. The rehabilitation of this pipeline segment is ongoing. Recoating is performed on a two-year cycle and additional linear anode CP is still being installed as the coating ages.

CP augmentation should be the first choice for pipeline rehabilitation if coating deterioration is addressed early enough, Didas says. The use of CP in lieu of recoating is a very cost-effective strategy for ongoing pipeline protection. Pipeline integrity can be restored using CP to supplement deteriorated coatings as well as protect the recoated segments. The engineering/design/evaluation analysis, however, should be done by qualified personnel to ensure the appropriate rehabilitation strategy is selected.

References

1 “The State of the National Pipeline Infrastructure,” U.S. Department of Transportation, https://opsweb.phmsa.dot.gov/pipelineforum/docs/Secretarys%20Infrastructure%20Report_Revised%20per%20PHC_103111.pdf (December 7, 2016).

2 “By-Decade Inventory,” Pipeline Replacement Updates, U.S. Department of Transportation, http://opsweb.phmsa.dot.gov/pipeline_replacement/by_decade_installation.asp(December 7, 2016).

3 “Background,” Pipeline Replacement Updates, U.S. Department of Transportation, http://opsweb.phmsa.dot.gov/pipeline_replacement/by_decade_installation.asp (December 7, 2016).

4 NACE SP0207-2007, “Performing Close-Interval Potential Surveys and DC Surface Potential Gradient Surveys on Buried or Submerged Metallic Pipelines” (Houston, TX: NACE International, 2007).

5 NACE TM0109-2009, “Aboveground Survey Techniques for the Evaluation of Underground Pipeline Coating Condition” (Houston, TX: NACE, 2009).

6 NACE TM0102, “Measurement of Protective Coating Electrical Conductance on Underground Pipelines” (Houston, TX: NACE, 2002).

Risk Assessment Justifies Cathodic Protection Retrofit on an Aging Pipeline

By Samuel Ojo, Jerry Anietie, Humphrey Ezeifedi, and Mercy Aguye on 12/1/2016 3:05 PM

 As pipelines age, it is important to verify the effectiveness of the coating and cathodic protection (CP) systems that protect them against external corrosion, and implement remedial actions if necessary. To confirm a coating and CP system were still protecting a remote, aging pipeline, an external corrosion risk management assessment was carried out. The assessment included a matrix to determine the likelihood of external corrosion based on coating condition and CP survey data. The ultimate objective was to ensure the adequacy of the pipeline’s CP system.

The 74-km buried carbon steel pipeline was originally installed in 1967 and a section had been replaced in 1990. External corrosion protection consisted of a coal tar enamel coating with an impressed current CP (ICCP) system.

An external coating is the primary corrosion mitigation technique for a pipeline, and a well-applied coating can provide good corrosion protection as the pipeline ages. However, as the coating ages, it can sustain damage from natural deterioration caused by elevated temperatures, stresses, permeation, and biological influences, as well as third-party events. This creates a higher risk for external corrosion of aging pipelines compared to newer pipelines, since the coating is the primary means of corrosion protection. CP is applied to pipelines as a secondary corrosion mitigation method that will protect the pipeline in areas where the coating has defects (holidays) or damage. Coating degradation can cause the CP current requirement for aging pipelines to increase, particularly when the coating has severe damage. In cases where CP current does not provide adequate protection, the risk of external corrosion on the pipeline is even higher, and there is a possibility of a pipe failure.

Risk is generally defined in terms of the possibility or likelihood of failure and consequence of failure. Risk assessment helps to screen for risk, identify areas of potential concern, and develop a prioritized list for more in-depth inspection. Indirect evaluation methods such as CP surveys and coating surveys/condition assessments help determine the likelihood of external corrosion. However, the likelihood of external corrosion should be based on established criteria from both CP and coating rather than only one indirect assessment method, because a combination of CP and coating is used on pipelines to achieve effective external corrosion mitigation.

Historically, due to logistical issues, implementing standard inspections and other integrity assurance activities had been a challenge for the aging pipeline. To assess the likelihood of external corrosion, a simple matrix (Table 1) was developed that combined the outcomes from CP potential surveys and coating condition data. It was designed to account for instances where coating or CP survey data were not available.

The assessment included assumptions about the pipeline’s coating condition. Not only was it susceptible to third-party damage, but the coating’s age (>45 years) also affected its condition. Because coating survey data were unavailable during the pipeline assessment, the coating condition was classified as severe based on the coating survey of a similar pipeline.

Historical CP survey data—pipe-to-soil (P/S) potentials taken at test stations at intervals along a portion of the pipeline (referred to as Section 1) during five years of regular monitoring—were also reviewed. The data indicated that CP protection was adequate, with periods of overprotection and under-protection. Past CP survey data were not available for approximately two-thirds of the pipeline (referred to as Section 2) due to logistical challenges. A CP attenuation study for the entire pipeline helped to predict the behavior of CP potential for the pipeline based on coating quality.

A pipeline coating is expected to electrically insulate the pipe wall, and CP provides corrosion protection at the defects in the coating. Essentially, the current drains or attenuates at the pipe surface where coating defects occur. When only a few coating defects are present, CP current demand is lower and pipeline potential attenuation is slower. Alternatively, CP current demand is higher when more coating defects are present on the pipeline, and the pipeline potential attenuation is faster. Attenuation formulas presented in the NACE International CP-4 Cathodic Protection Specialist course1 were used to develop a CP attenuation curve for the pipeline based on the age of the pipeline coating, current sources for the existing ICCP system, and other assumptions. Since the historical CP potential survey data corroborated the prediction from the attenuation curve for Section 1, the surveyed portion of the pipeline, the attenuation curve was relied on to predict the CP current attenuation for Section 2 of the pipeline that did not have historical CP potential survey data.

FIGURE 1: External corrosion defect data from the ILI were combined with the CP potential survey data results and the attenuation curve. Image courtesy of Samuel Ojo.

FIGURE 1: External corrosion defect data from the ILI were combined with the CP potential survey data results and the attenuation curve. Image courtesy of Samuel Ojo.

The results of the historical CP potential surveys and the attenuation curve for the entire length of the pipeline were plotted. Using the external corrosion risk assessment matrix in Table 1, a significant portion of Section 2 of the pipeline was determined to be at severe risk of external corrosion. To verify the external corrosion risk identified in the assessment, inline inspection (ILI) was used to collect and record information about the pipeline, such as the size, location, and orientation of wall loss (both internal and external) along the entire length of the pipeline. The ILI indicated one significant corrosion defect in Section 1 of the pipeline, and 447 significant corrosion defects in Section 2. The external corrosion defect data from the ILI was combined with the CP potential survey data and the attenuation curve so the direct impact of CP on the corrosion defects along the pipeline could be evaluated (Figure 1). The ILI results corroborated the expectations, indicated by the potential surveys and the attenuation curves, that a portion of Section 2 was experiencing corrosion from inadequate CP. The external corrosion risk assessment and ILI verification justified the need to retrofit the CP system.

To mitigate the corrosion of Section 2, the decision was made to augment the existing ICCP system with magnesium sacrificial anodes as an immediate response while other integrity-related remedial actions were planned to be implemented. CP design calculations indicated that 144 15-kg sacrificial anodes were required to ensure adequate CP on Section 2. Initially, 100 anodes were installed near areas of Section 2 where wall loss was most concentrated, and the remaining 44 anodes were then installed so that Section 2 was fully covered. A subsequent CP survey of the pipeline indicated that the installation of the sacrificial anodes polarized the pipeline to the correct P/S potential so external corrosion growth is minimized and risk is reduced.

This case study3 was presented at the 2016 NACE Corrosion Risk Management Conference. Special thanks to Bademosi Adebayo for his support toward completing this study.

Contacts: Samuel Ojo, Jerry Anietie, Humphrey Ezeifedi, and Mercy Aguye, Shell Petroleum Development Co. of Nigeria—e-mail: samuel.ojo@shell.com.

References

1 NACE CP-4, Cathodic Protection Specialist Course Manual (Houston, TX: NACE International).

2 ANSI/NACE SP0502-2010, “Pipeline External Corrosion Direct Assessment Methodology” (Houston, TX: NACE, 2010).

3 S. Ojo, M. Aguye, H. Ezeifedi, J. Anietie, “Retrofitting the Cathodic Protection System of an Ageing Pipeline,” Corrosion Risk Management Conference, paper no. RISK16-8740 (Houston, TX: NACE, 2016).

Protecting Steel Pipelines Using Vapor Phase Corrosion Inhibitors

BY JAMES HOLDEN, P.E., JULIE HOLMGUIST, AND ERIC UUTALA ON NOVEMBER 8, 2016

A recent study from the U.S. Department of Transportation found that between 2006-2010, almost a fourth of significant onshore hazardous liquid pipeline incidents were caused by corrosion, along with a fifth of significant gas transmission pipeline incidents. According to “The State of the National Pipeline Infrastructure,” released by the Pipeline and Hazardous Materials Safety Administration (PHMSA), 4 percent of significant distribution system incidents during 2008-2010 were blamed on corrosion.

These statistics only begin to highlight the importance of protecting gas and oil pipelines from the corrosion failures that can result in expensive repairs, pipeline failure or even loss of life.

1Inevitable Problem

Pipeline corrosion is inevitable and immediate. The question is how long it will take before the corrosion will eat away enough of the piping to cause a problem. Many factors play into the equation of whether a pipeline will have corrosion problems in five, 10 or 20 years. This depends on the corrosiveness of the pipeline fluid, the thickness of the pipe and the level of corrosion protection.

An excellent method for fighting costly corrosion issues and encouraging the longest possible service life is the use of Vapor phase Corrosion Inhibitors (VpCIs). VpCIs are able to perform beyond traditional methods of corrosion protection because of their ability to work effectively in the liquid phase, vapor phase and at the sensitive liquid-vapor interface. They are also adaptable to multiple application methods including fogging, painting, hydro-testing, injection under insulation, injection into flow streams and more.

VpCI technology works by emitting a vapor from the VpCI source, whether applied in a powder, liquid or other form. When this vapor reaches a metal surface, it condenses and adsorbs — or forms a monomolecular protective layer — on the metal surface. This layer is highly hydrophobic and protects the metal from the attack of corrosive agents like moisture. It also neutralizes the electrical surface potential of the metal so that oxygen cannot interact with the metal to create a corrosion initiation site. An added benefit is that many VpCI applications have a self-replenishing capability, where new VpCI ions flow in to replace others that might be knocked away by scratching or marring of a protected surface. In the case of coatings, these VpCIs inhibit corrosion from creeping from areas of coating damage to the surrounding metal.

Pipeline Issues: Construction, Post-Construction, Operation

Corrosion precautions must be taken even prior to pipeline construction. While PHMSA requires that steel piping installations in the U.S. be externally coated for corrosion inhibition and also protected cathodically, internal protection can fall by the wayside.

Manufacturers may face problems simply getting the piping to the field without internal rust. Historically, pipe internals have been protected with heavy, wax based coatings, if they are treated at all. While these coatings can work, they need to be coated on all metal surfaces to be effective. Further, they are difficult to remove, when the pipe system gets commissioned. Conversely, VpCIs disperse and coat all internal metallic surfaces with a monomolecular protective layer. VpCI in powder or liquid form can be applied by fogging and left inside the pipes until they are installed.

After a pipe is installed below or above ground, it is flushed and hydro-tested for leaks. This is normally done with untreated water, leaving the pipe in a damp condition that can lead to rusting. In this case, VpCIs can be incorporated directly into the hydro-testing water (whether salt or fresh) so that the pipe internals are protected during and after the hydro-testing process.

Once a pipe is in operation with fluids running through it, the main concern becomes top of the line corrosion. Less corrosion will occur in areas of the pipe where the fluids are flowing, but the void space at the top of the pipe is left vulnerable to a mixture of moisture, air and corrosive gases that encourage corrosion. Though some pipelines may use no corrosion control at all, even traditional contact corrosion protection is limited because it is carried through the fluid and can only protect surfaces in direct contact with the fluid in the pipe. In contrast, VpCIs have the flexibility of working in the vapor phase, as well as the liquid phase. They can also provide protection to the critical liquid-vapor interface where it is difficult to provide continuous corrosion protection.

Another corrosion trouble spot is pipeline crossings, where pipes run through an extra casing that is intended to allow better pipe access but that tends to promote corrosion in the annular space between the internal and outer pipe. VpCI filling can be used to enhance the effect of cathodic protection in this situation and even reduce its need.

A pipeline rupture at any of these locations could be disastrous in terms of public safe4ty alone. Add to this the potential costs of replacement, downtime and environmental cleanup, and then investment in corrosion inhibitors produces a significant return on investment.

Facility Issues: Equipment, CUI, Storage Tanks

Pipelines cannot function without periodic pumping stations and production facilities located along their route. These structures face corrosion problems common for many industrial facilities. Pumping stations operate with standard equipment such as pumps, turbines and motors. Equipment like this can experience external corrosion where paint is chipped off or never existed or where corrosive elements exist within a lubricating system.

Corrosion in these locations poses serious loss through increased downtime and maintenance costs. Many of the same issues can occur at production facilities, and they also stand to benefit from the many available forms of VpCI protection, such as coatings, additives and powders.

Another significant problem in the petrochemical industry is corrosion under insulation (CUI). Plants often contain pipes carrying extremely high or low temperature fluids, and these pipes must be insulated for the safety of plant personnel. Unfortunately, this is a corrosion-promoting trap, where moisture easily finds its way below the insulation’s surface to start the corrosion process. The insulation in turn hides what is happening, making corrosion difficult to detect. As another testament to the flexibility of VpCI application, this situation can be treated by injecting VpCI right through the insulation and installing a corrosion detection system to monitor the pipe’s condition.

Oil and gas processing facilities naturally contain many storage tanks, which can be at risk for corrosion on tank bottoms. Though cathodic protection can be used and a corrosion rate monitoring system installed beneath the unseen storage tank floor, this method has limitations. Injecting VpCI slurry in the space below tank bottoms provides enhanced protection as its vapor is allowed to spread out and protect surfaces that cathodic protection cannot reach.

Conclusion

While corrosion in gas and oil pipelines and facilities is an inevitable threat, it is also very treatable. VpCI technology offers superior protection adaptable to many pipeline features, protecting areas not reached by traditional corrosion inhibitors and supplying more continuous protection where cathodic protection fails.

When weighing protection costs vs. benefits, it is important to consider that the total cost of pipeline failure is several magnitudes higher than the cost of prevention. Included in the costs of failure are unplanned downtime, labor costs for replacing the failed pipe or equipment and environmental contamination costs. When these liabilities come into play, and when considering that VpCI protection of an entire plant can cost less than traditional protection of one component, the use of VpCI protection becomes very attractive and logical.

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Adapted from https://www.verdek.com/pipeline.htm

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There are 39 cylinders per MAT, each cylinder contains 40 Gallons for a total of 1,560 Gallons. The storage is 52,500 SCF or 420 GGE

Mat Dimensions: Length 127”   Width 100’    Height 90”

 

MAT-B
MAT-B carries a booster which allows the use of 92% of the gas storage. The booster is operated by a hydraulic power unit, the most common used is a 20 KW Caterpillar power generator. The booster is to maintain the MAT-B storage system at a pressure of 3,600 psi. With this feature MAT B becomes an integral part of a cascade system together with the other MAT modules linked together on the transport vehicle. There are 28 cylinders per MAT-B, each cylinder contains 40 Gallons for a total of 1,120 Gallons. The storage is 37,700 SCF or 302 GGE.

MAT-B has an electronic management system which controls compression, filling operation of the platform and delivery system with real-time precision measurement and monitoring features which enables accurate fuel billing and reporting for your customers. MAT – B has an integrated dispenser to fill vehicles on the go.

Transportation Systems

This truck carries one MAT-B and two MAT. The configuration offers 143,000 SCF at 3,600psi or 1,150 GGE.

Hydraulic ramps allow for an easy loading and unloading of the MATs

 

Applications
Galileo`s Virtual Pipeline can be applied to a great number of applications, with equipment specially designed for each particular need.

INDUSTRIAL & POWER GENERATION
Galileo Virtual Pipeline offers a cleaner and more economical alternative for industrial facilities and power generation companies located away from the natural gas pipelines. Galileo has developed RMP (Regulating Modular Plants) a state-of-the-art remote regulating system specifically designed to regulate the high pressure of the MAT modules to the required pressure for the specific application.

CNG REMOTE FUELING STATIONS
A CNG Remote Fueling Station with Virtual Pipeline is the best alternative for those places that lack natural gas infrastructures.
The Remote CNG Station has PAD Platforms for the unloading and unloading of MAT modules which are connected to a MAT-B with a Booster,  module` storage management and Dispensers to fuel CNG Vehicles.

 

 

 

 

 

     

 

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Energy source via Virtual Pipeline for Sabah consumers

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Kota Kinabalu, Sabah, Borneo: The usage of natural gas in the industry will help reduce cost and preserve the environment.

Speaking at the Commissioning ceremony of Sabah Energy Corporation Sdn Bhd (SEC) Compressed Natural Gas (CNG) Project via Virtual Pipeline System at Colourcoil Industries Sdn Bhd in Telipok yesterday, Resource Development and Information Technology Minister, Datuk Siringan Gubat said that using the cleaner fuel is akin to contributing to the environment.

“As compared to the traditional fuel source, natural gas is a much cheaper and cleaner fuel. This will translate directly into cheaper operating cost, hence better bottom line. At the same time by using natural gas, the mother earth will thank you for being green.

“We will also be able to preserve our pristine environment and maintain our position as preferred eco-tourism destination,” he said adding that using natural gas is in line with the government’s policy to encourage the use of cleaner energy to drive economic growth.

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Compressed Natural Gas Project via Virtual Pipeline System is a natural gas distributing mode for distant customers, where ‘mother station’ supplies natural gas to ‘daughter stations’ at customers’ premises.
SEC Chief Executive Officer, Datuk Harun Ismail explained that the Virtual Pipeline System works by having a mother station which is at SEC’s terminal in KKIP.

“CNG is supplied to the customers to their purpose-built daughter stations by lorries. And in order to ensure seamless supply of the fuel, a daughter station monitors the level of gas and automatically order for supply when the gauge is low.

“Upon receiving the order, a lorry laden with CNG will be dispatched to the daughter station from the mother station. The CNG laden containers will roll from the lorry, down to the daughter station purpose-built platform, before the empty containers roll from the platform onto the lorry,” he said adding that all the process are being done without stopping the flow of CNG to the customer’s operations.

Harun said that SEC chose to employ the system due to the high cost involved in building physical piping system to the customers, which renders it uneconomical.
According to him the virtual pipeline system is a proven technology and has been used successfully in many countries including Argentina, Brazil, Bolivia, India, Philippines, and Singapore.

“The technology provider of the virtual pipeline system is GNC Galileo of Argentina, which complies with accepted international standards such as ISO 9001 and ISO 15500.

“The system was officially launched by the Chief Minister, Datuk Seri Musa Hj Aman in July 2012, and the first gas roll out was achieved 11 months later on June 10, 2013,” he said adding that SEC has a complete team of trained and competent engineers and technicians to assist customers on the gas usage and the supply system.

Harun disclosed that Colourcoil Sdn Bhd is one of seven earliest customers who signed the sale and purchase agreement with SEC.

Also present at the ceremony were Argentine Ambassador to Malaysia, Maria Isabel Rendon, CNG Galileo S A, Asia Pacific Regional Manager, Juan Ojenguren, and Colourcoil Sdn Bhd Managing Director, Roger Ling.

Source: newsabahtimes.com.my

 

 

 

 

 

 

Virtual Pipeline System (VPS) – Introduction

zsharer came to know on this VPS when the team were assigned to do Engineering and Management Audit for an Energy company on the other side of Malaysia. A little brief of introduction on what is VPS all about which zsharer adapt from Galileo website http://www.galileoar.com/en/virtual-pipeline/compression-technologies#

 

Virtual Pipelines are substitute to physical pipelines that distribute gas via land or sea transport. They replicate the continuous flow of energy via transportation logistics using trucks or ships.

 

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COMPRESSION TECHNOLOGIES


 

Compression system and loading of CNG storage modules for Virtual Pipeline can be installed by gathering gas from different sources:

• Existing pipelines
• Natural gas production wells
• Natural gas treatment plants
• CNG Stations
• Biodigestors

Depending on the gas source, either a MICROSKID or a MICROBOX is installed. Both of them take low pressure natural gas and compress it until 250 bar pressure is reached, this way, filling the storage MAT modules- which are placed on the PAC loading platforms.

Once load is completed, MAT modules are loaded on truck’s VST trailer and then transported to every consumption center.
Thanks to Galileo`s SCADA System, the entire compression plant`s operation can be monitored in real time, making the this system easy-to-use. If you wish to know more about our compression plants, please download the following document.

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TRANSPORT TECHNOLOGIES


MAT Modules are transport by road from the compression & loading station to the different consumption destinations on trucks with VST trailers specifically designed for their safe transportation.

The VST trailer used for MAT modules transport was specifically designed for this application by Galileo, base on the following principles:

• Safety and reliability in MAT modules transport (using interlocking system).
• Easy-to-use and fast loading/unloading modules on grounding platforms.
• Flexibility regarding modules` maximum capacity to be transported.
• Being able to use in any road.

MAT modules` loading/unloading procedure on VST trailers is very simple, it only takes a few minute and can be done by the truck`s driver itself.
Depending on the application, VST transport systems ® has a capacity for 2, 3 or 4 MAT modules, VST-2, VST-3 and VST-4 respectively, allowing at the same time different configurations according to the demand.For low or moderate consumption applications, Galileo has developed MAT modules that can storage natural gas at pressures of up to 250 bar and at environment temperature.
For moderate and high consumption applications, Galileo has developed CryoMAT modules which can storage natural gas at up to 250 bar and at low temperatures of -30ºC. These modules can storage and transport 30% more gas per module, thus reducing the initial inversion and operative costs.

DAUGTHER STATION


APPLICATIONS

Galileo`s Virtual Pipeline can be applied to a great number of applications, with equipments specially designed for each particular need.

INDUSTRIAL, RESIDENCIAL & POWER GENERATION CONSUMPTION

Virtual Pipeline allows industrial consumers to drastically reduce its operative costs by replacing the fuel used in its natural gas processes – a cleaner and more economic alternative.
Either industrial processes or power generation consumptions, where natural gas supply is required at constant pressure, pressure reduction stations are necessary. Galileo has developed state-of-the-art Regulating Modular Plants, specifically designed for the Virtual Pipeline System. Remote Regulating Plant consists of PAD Platforms for the unloading of MAT modules, with one or more PRP regulating plans in charge of regulating high pressure of MAT modules until the necessary pressure is reached for the corresponding application.
If you wish to know more about our equipments for remote regulating plants, please download the following document.

CNG VEHICLE REMOTE STATIONS

A CNG Remote Station with Virtual Pipeline is the best alternative for those places where there is a need for filling CNG vehicles and conditions are not good enough for a dispenser station to be installed the best alternative is to install a CNG REMOTE STATION WITH VIRTUAL PIPELINE.

The Remote CNG Station has PAD Platforms for the unloading of MAT modules which are connected to a discharge BOOSTER compressor and modules` storage management and Dispensers for the filling of vehicles in CNG Vehicle Station.

Galileo’s Virtual Pipeline® in Borneo

 zsharer baru tau yang actually virtual pipeline telah wujud di Malaysia sejak 2013 lagi. Memang pernah dengar pasal VPS (virtual pipeline system) masa terlibat dengan site visit di KKIP pada tahun 2012. Tapi dah terlupa dan tahun 2016 terlibat lagi dengan audit so itu yang mengagau cari information pasal VPS. Very interesting technologies for natural gas distribution. Mostly information adalah dari Galileo iatu company yang berada di Argentina. Memang Malaysia juga mengunakan khidmat VPS dari Galileo.
Sabah Energy Corporation Sdn. Bhd. (SEC) will supply natural gas to both distant industrial and geographically scattered consumers by using Galileo`s Virtual Pipeline® technology. Once this Virtual Pipeline® is operating, it will be able to distribute natural gas within 70 km radius from Kota Kinabalu Industrial Park (KKIP), in the Sabah State of East Malaysia, on the northwest coast of Borneo.
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While the high costs of laying underground pipelines prevented SEC from distributing natural gas within the inlands of Sabah, Virtual Pipeline® will enable to deliver it cost-effectively just as CNG does. As a system, Virtual Pipeline® involves three stages before completing the distribution to its final users through a direct connection or a local distribution network. These three stages are: CNG compression, transport and pressure regulation.  In addition, the whole operation is remotely monitored in real time through Galileo’s SCADA System for its proper management.

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In its design, Sabah’s Virtual Pipeline® operation starts in the KKIP with a CNG compression process. This process of compression can reach a pressure of up to 250 bar thanks to Microbox® units that work as mother stations. Then, CNG is distributed on modular containers (MAT®) transported by road on specifically designed trailers (VST®) to the daughter stations, which are located in four different spots.

Upon their arrival at the consumption point, the easy-to-operate VST® trailers’ mechanism unload the necessary filled MAT® modules, load the empty ones and the truck continues its route to the next daughter station. As part of the system´s adaptation capability pursuant to the existing demand of each of the daughter stations, all MATs are connected to Pressure Regulating Plants (PRP®) which supply with natural gas at a suitable range of outlet pressure and flow requested by its final users.

Unlike traditional tube trailer, MATs can be exchanged even if the gas has not yet petered out at the consumption points and, thus, avoiding transport waiting times. Once the truck has exchanged all its modules with the empty ones along its route, it goes back to the mother station to restart the cycle. This ensures permanent and suitable gas supply according to the consumption demand. It also enables scalability for an optimal sizing to strike a perfect balance between operating and investment costs.

Working with modules allows the system to increase its capacity at the pace of demand, which makes Virtual Pipeline® the most suitable solution for one of the fastest growing regions in Malaysia. Specially when there is a powerful driver to do it in compliance with environmental protection, since Kota Kinabalu is a popular gateway for travelers visiting rainforest areas in Sabah and Borneo.

“Distributing natural gas via the Virtual Pipeline® System is in line with the aspiration of the State to make this resource available to a wider spectrum of users. Being comparatively much greener and yet competitively priced fuel, natural gas will undoubtedly further spur the growth of industries in the State,” said Yb Datuk Dr. Yee Moh Chai, Deputy Chief Minister Cum Minister of Resource Development and IT of Sabah.

“Apart from savings in fuel costs, industrial users will also achieve other savings  due to lower costs in maintenance, handling and storage, manpower, pollution control, etc.,” added Dato Harun HJ Ismail, CEO of Sabah Energy Corporation Sdn. Bhd. (SEC).

Does pipeline age really matter?

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By Anya LitvakPittsburgh Post-Gazette

PITTSBURGH (AP) — Thirty years of watching metal fail, often spectacularly, and Mehrooz Zamanzadeh has developed some go-to mantras.

“Mother Nature doesn’t like what she didn’t make,” he likes to say.

That means when a man-made object is exposed to the environment — say, a metal pipeline is buried in soil — that environment will begin tugging and pulling, trying to break the metal into its natural parts, to undo the decades of technological advances at steel mills, in coating factories, in the field. All that is another way of describing corrosion, one of the leading causes of pipeline leaks and failures, big and small. Corrosion was found on a weld that burst open in late April on a Texas Eastern pipeline in Westmoreland County’s Salem Township. The explosion left one man severely burned, destroyed his house, charred cars and melted a road.

In Pennsylvania, where half of the natural gas transmission pipeline miles are at least 45 years old, corrosion accounted for 28 percent of serious pipeline accidents over the past 30 years. The vast majority of those struck lines between 30 and 60 years old. That tends to be when corrosion barriers put on pipelines, such as coatings and cathodic protection, start to fail with greater frequency, Zamanzadeh, who everyone calls Dr. Zee, said. As a corrosion specialist, Zamanzadeh studies the menace of age. He leads Robinson-based Exova, a lab stuffed with samples of exploded gas pipelines, leaky valves, airplane filters, transmission towers — any kind of metal that has lost its battle with nature. He’s not an alarmist but much of what he says sounds ominous.

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Zamanzadeh says that just because a pipeline has performed without red flags for decades doesn’t mean something won’t go wrong tomorrow. In fact, the risk increases all the time as that pipeline ages, acquires wrinkles in its coating, and wiggles around underground under the pressure of outside impacts or the seasonal expanding and contracting of the earth.
It’s like his body, Zamanzadeh said. At 65, he’s healthy and agile enough to climb Mt. Everest, but there’s no doubt he’s not as sturdy as he was 30 years ago. And it would be naïve to think he won’t weaken further in another 30 years. When the dust settles on serious pipeline accidents, like the one in Salem Township, the conversation often to aging infrastructure. The majority of pipelines in the U.S. today were put in the ground before 1970. There’s some disagreement on how to assess the dangers of the aging pipelines.

“Not surprisingly, when an older pipeline fails, there is a tendency to suspect that age played a role in the failure,” reads a 2012 report commissioned by the Interstate Natural Gas Association of America, a Washington-based trade group that represents the pipeline industry. “This can lead to the perception that such pipelines are too old to operate safely.”

The trade group’s report disputes that. “A well-maintained and periodically assessed pipeline can safely transport natural gas indefinitely,” the organization’s study concluded. Darius Kirkwood, a spokesman for the federal Pipeline and Hazardous Materials Safety Administration, which regulates gas pipelines in the U.S., said the agency can generally echo those conclusions.

“There is not necessarily a direct relationship between pipeline age and fitness for service,” he said. “You can’t automatically assume that an older pipe is less fit.”
A number of studies, however, including the pipeline administration’s data show that failure events do increase with age. They follow what is known in engineering and risk assessment circles as the bathtub curve. A high number of initial failures gives way to a period of steady status quo which then starts to see more failures again as pipelines age. It is theoretically possibly to monitor an old pipeline so closely and attend to its needs so carefully that it never fails — although Zamanzadeh notes that requires a healthy budget and people who know what they’re doing.

A large number of instruments and techniques — developed in part through lessons learned from accidents from the past — are now available to track pipeline health. Many are mandated by federal regulators. But in Zamanzadeh’s experience, many pipeline operators don’t know the extent of what they have in the ground, which is critical for designing an effective monitoring strategy.

It’s not uncommon for him to surprise his clients with a reading of materials he found in their failed samples.

“They don’t have any idea where did it come from, who was the supplier,” he said. “They don’t have the drawings.” The past is present

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Zamanzadeh’s office is cluttered with failed metal — a porous railroad tie (a manufacturing defect), a thick section of boiler pipe, bulged and ruptured at one end. Across from his desk is a natural gas transmission pipe nearly as tall as its owner, torn open by an explosion several years ago. It happened in Pennsylvania. Mr. Zamanzedeh couldn’t say anymore about it. “I think it’s a beautiful sculpture,” he said, “a case of great importance.” His wife won’t let him display it in their home so the gashed, rusting pipeline takes up a significant chunk of real estate in his office.

“Fractures and failures are releases of energy and are fantastic,” he said.

The walls of Exova are lined with framed pictures of failures — extreme closeups artistically rendered by his mother-in-law. In general, he says, aging materials fail due to either corrosion or fatigue. Either they’re scoured by their environment or overworked. It often happens because pipeline owners don’t have the resources to fully assess the risk. “Many of these gas companies and engineers, they try their best. But their hands are tied.”

An eerily similar case

The boom in shale development over the past decade — in western Pennsylvania and in other parts of the U.S. — has kick-started a major buildout of new pipeline systems designed to avoid the mistakes of the past. These new lines aren’t substituting existing pipelines. They’re supplementing the older lines. And while better technology is added to the ground every day, aging pipelines also carry the burden of outdated design and construction practices. The Salem Township explosion in April originated at a weld that was coated with tape, a method no longer used today. A preliminary study of the burst pipe found a defect in that coating and found corrosion underneath it.

While a definitive cause is not yet known — Spectra Energy, which owns Texas Eastern, and federal regulators are still investigating — the finding prompted Spectra to start digging up and examining hundreds of other tape-coated welds along a 263- mile stretch of the pipeline across much of Pennsylvania.
Thirty-one years ago, almost to the day of the Salem Township explosion, a blast rocked a neighbourhood in Beaumont, Ky. The details were eerily similar. A loud bang and a woosh of air were reported. Nearby residents thought a plane had crashed. A huge fireball menaced the sky. There were other common themes: both explosions involved pipelines 30 inches in diameter along the Texas Eastern system. Both were installed three decades before they burst. Each shared a right of way with other pipelines and was located about a mile from a compressor station.

But the Kentucky accident, which left five people dead and three injured, had something the Pennsylvania accident did not: its gas pipelines were encased in another 36-inch pipe. That was a practice pushed by the railroad industry under its crossings and picked up by municipal officials who thought it added another level of protection in case of a leak or rupture. Instead, it created the conditions for corrosion and shielded the gas pipeline from meaningful detection.

“It’s a huge, huge, huge problem for anybody that has pipelines from the 1940s up to the 1980s,” said David Wint, director of pipeline integrity engineering at Audubon Field Solutions in Oklahoma.
The exploded pipe in Salem Township was installed in 1981 and did not have a casing around it under the intersection of Route 22 and Route 819. But such conditions still exist from older pipelines. In May 2014, a Spectra Energy welder was repairing a casing surrounding 30-inch pipeline on the Texas Eastern system in Greene County when he accidentally dinged the gas pipe and caused a leak. That piece of pipe was installed in the 1950s.

When problems spike again

Corrosion and fatigue aren’t unique to pipelines. They’re ubiquitous in infrastructure: bridges, roads, water towers. With 300,000 miles of natural gas transmission pipelines in the U.S., the network is the safest method of transportation. Last year, more than 38,000 people were killed in vehicle crashes. Deaths from any kind of pipeline totaled 347 for the past 20 years. Pennsylvania has had about two serious incidents a year over the past two decades on natural gas transmission pipelines. Much of the existing infrastructure is at a point where problems creep up with greater regularity. It’s also when corrosion-related failures are most prevalent. Overall, the most common cause of failure in federal and state-level data is material, weld, or equipment failure — such as when a weld defect fails under pressure, for example. Those tend to peak in the first few years of a pipeline’s life, then level off and return to prominence after 50 or 60 years in operation.
At a recent National Association of Corrosion Engineers conference in Houston, two Ohio-based engineers presented data based on five years of failure investigations performed by DNV GL, a Norwegian testing, certification, and advisory firm that’s often a company’s first call after a rupture. DNV is testing the pipe involved in the Salem Township explosion.

The company’s analysis mirrored federal statistics. It showed that about 15 percent of failures hit pipelines in the first few years of operation. Then, after leveling off for the next four decades, accidents picked up again after 50 years of service life. More than half of the failures in DNV’s analysis were caused by material, weld, or equipment failures, and a third was because of corrosion. Studying the causes of pipeline failures has spurred an industry of new risk assessment tools and methods. In Zamanzedeh’s laboratory — where metal is sliced and diced every which way, misted with salt water and probed by $800,000 microscopes — his favorite motto is an uplifting one.

Failure, he says, is a discouraging word. But failure analysis — “the two most beautiful words in the English language.”

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