New Aluminum Batteries are Corrosion Resistant, Cheap and Hold a Lot of Renewable Energy

Posted on May 3, 2018 · Leave a Comment

To contact the author of this article, email Siobhan.Treacy@ieeeglobalspec.com

In energy production, energy transition is dependent on technologies that boast cheap and temporary storage of renewable energy. Researchers have found that aluminum batteries are one of the most promising candidates to fill this need because they are made from cheap and abundant raw materials and can hold a good amount of renewable energy.

The researchers produced aluminum button cells in the laboratory. The battery case is made of stainless steel coated with titanium nitride on the inside to make it corrosion resistant. Source: ETH Zurich / Kostiantyn Kravchyk

The scientists and researchers from ETH Zurich and Empa were led by Makysm Kovalenko, Professor of Functional Inorganic Materials. This team is just a small number of the researchers worldwide who are focusing on developing these kinds of batteries. The team found two new materials that could be huge for the development of aluminum batteries. The first, a corrosion-resistant material, would be used in the conductive parts of the battery. The second is a novel material that would be used on the positive pole and that can be adapted for many technical requirements.

The electrolyte fluid in aluminum batteries is aggressive and corrodes many materials like steel, gold and platinum. Researchers have been seeking corrosion-resistant materials that would work for the conductive areas of the batteries. Kovalenko’s team found the answers in titanium nitride, a ceramic material that exhibits high conductivity.

“This compound is made up of the highly abundant elements titanium and nitrogen, and it’s easy to manufacture,” explains Kovalenko.

Aluminum batteries with conductive parts made out of titanium nitride were successfully made in the team’s lab. The material is easily produced in a thin film or as a coating over other materials like polymer foils. Kovalenko says it could be possible to manufacture conductors from a conventional metal coated with titanium nitride or print conductive titanium nitride track on plastic.

“The potential applications of titanium nitride are not limited to aluminum batteries. The material could also be used in other types of batteries; for example, in those based on magnesium or sodium, or in high-voltage lithium-ion batteries,” says Kovalenko.

The second new material is polypyrene, a hydrocarbon with chain-like (polymeric) structure. Polypyrene is used for the positive electrode (pole) of aluminum batteries. The positive electrode in aluminum batteries is typically made out of graphite. The new material discovered by the team is competitive to graphite because it can hold more energy than graphite. The initial experiments show that the material is successful.

“A lot of space remains between the molecular chains. This allows the relatively large ions of the electrolyte fluid to penetrate and charge the electrode material easily,” Kovalenko explains.

Polypyrene allows scientists to influence its properties, adapting the materials for any specific application.

“In contrast, the graphite used at present is a mineral. From a chemical engineering perspective, it cannot be modified,” says Kovalenko.

Titanium nitride and polypyrene are flexible. The researchers say that the flexibility of the materials would be useful for “pouch cells”, which are batteries enclosed in a flexible film.

The new batteries would be used to store energy harvested from an eco-friendly source, like solar or wind, when these resources are unavailable. The batteries store this energy in a cost-effective way while being inexpensive and made out of abundant sources.

The paper on this research was published in Advanced Materials.

Filed Under: Coating, Corrosion

Evaluating Internal Pipe Coatings with Electrochemical Impedance Spectroscopy

Posted on April 28, 2018 · Leave a Comment

By Materials Performance on 3/1/2018 5:54 PM

EIS testing apparatus. Photo courtesy of Amal Al-Borno, Charter Coating Service (2000), Ltd.

A new generation of high-temperature fusion-bonded epoxy (FBE) coatings are being developed as a lower-cost alternative to alloy steels for protecting the internal surface of tubing, casing, flowlines, and pipelines. In the new FBE coatings with a high glass-transition temperature (T_g), the highly functional epoxy resin and ingredients can make interpretation of testing results difficult for coating specifiers.

According to NACE International member Dustin Traylor, global functional product manager/technical services manager with Axalta Coating Systems (Houston, Texas, USA), tests for internal FBE coatings are very different than tests designed for external pipe FBE coatings because of the nature of the exposure environment for internal pipe coatings (e.g., temperature, pressure, gas, and chemical contaminants). To simulate these field conditions in a controlled laboratory setting and accelerate the evaluation process, coating scientists use an autoclave test.

During this type of test, coating samples are exposed to liquids and gases under high temperature and pressure inside a specially designed metal vessel. The conditions of the autoclave test are typically selected to simulate the potential upper limits of service to facilitate any degradation of the coating. Coatings that demonstrate the least reaction to the environment are considered the most suitable.

Autoclave testing is widely accepted as the most effective laboratory test for evaluating the performance of internal pipe coatings, Traylor says; however, he notes there are major differences within the coatings community on the length of testing time utilized to observe a coating’s reaction to the environment, as well as the interpretation of the results gathered at the test’s conclusion. Typically, laboratories will compare swelling, blistering, adhesion, and color change of exposed coating samples to a sample that is unexposed.

Although the parameters of an autoclave test should be determined based on field conditions and will vary depending on the application, the coating exposure time in an autoclave environment could be standardized. Table 1 lists the average price of an autoclave test performed at various time intervals.

Recently, Traylor notes, specifiers have started to require longer autoclave tests as part of the approval process, with some engineers requiring exposures as long as 60 days. Because specifiers must judge a coating’s life expectancy based on the results, he says, the theory is that longer autoclave exposures should produce more reliable results. The tendency to require longer autoclave tests is not without merit, he adds; coatings are used to protect expensive piping assets. The issue is exacerbated, however, by the wave of newer technology resins that may allow a coating to survive an autoclave environment of a certain length of time with no visible signs of failure and good performance in post-exposure testing.

This is particularly true of lower T_g coatings exposed to higher autoclave temperatures, he says. The T_g is the temperature where a polymer (coating) changes from a hard and relatively brittle solid state to a viscous or rubbery condition. At or above this temperature, the permeation rate of oxygen, moisture, and other ionic substances increases considerably, which may lead to rupture of the polymer structure and ultimately failure of the coating system. Although the coating’s molecular structure is compromised when exposed to temperatures above its T_g, there may not be sufficient time and pressure during the test to produce a blistering failure.

Traylor comments that electrochemical impedance spectroscopy (EIS) is quickly gaining recognition as a fast, cost-effective tool for evaluating a coating’s ability to withstand exposure to a specific environment, and allows specifiers to determine if the coating can be expected to survive in a particular service environment for the entire design life of the asset (five to seven years or longer).

Organic coatings provide corrosion protection by isolating the corrosive environment from the steel structure to which they are applied. In general, Traylor says, a coating needs to have good barrier properties to provide good protection. Low permeability to water, ions, gases, and other corrosives is essential to the success of a coating system at higher temperatures. He explains that field experience and laboratory research have shown that highly protective coatings with good barrier properties have a high electrical resistance.

EIS is now a well-established laboratory technique for evaluating the corrosion protection of organic coatings. By testing the coating’s impedance, Traylor adds, EIS can simultaneously measure coating degradation caused by exposure to an electrolyte as well as the change in the corrosion rate of the substrate caused by coating perforation. Impedance (alternating current [AC]) is calculated the same way as resistance (direct current); however, impedance also includes reactance, which is a measure of the type of opposition to AC electricity due to capacitance or inductance. According to Ohm’s Law: R=V/I, where R= resistance, I= current flow, and V= voltage, the impedance changes at distinct frequencies.

A three-electrode arrangement that includes a working electrode, reference electrode,and counter electrode is used to perform EIS in aqueous solutions. During the EIS test, an AC voltage of varying frequencies is applied to the coating sample through an electrode submerged in an electrolyte. This allows information about a coating’s resistance to electrochemical reactions to be collected and evaluated.

According to Traylor, the impedance of the coating will change during the experiment as a result of water swelling or absorption, which is why the application of EIS as a tool for evaluating coating life span is theorized to be so effective. The corrosion protection from a coating, expressed in terms of Log Z, increases as its impedance increases. Therefore, a newly applied, high-performance coating will have high impedance in the range of a Log Z value of 9 to 11.

While there is no consensus on utilizing EIS for making decisions on internal pipe coating service life, Traylor notes that coatings experts are continually working to perfect the application of this technique. He mentions several suggestions for including this technology in a coating specification. One is to use EIS in conjunction with accelerated weathering (in an autoclave) to speed up the decision-making process. While there is no agreed-upon duration for exposing a coating sample to an autoclave environment, 96-h and 7-d tests have yielded results that support a change in EIS occurring within that time span.

Measuring impedance prior to exposure to obtain a baseline is another suggestion. Because it is impossible to replace the electrode in the exact place after exposure, it is good practice to develop a range using three or more measurements. After exposure, one test per phase should suffice. Another recommendation is to measure the impedance of the sample for each exposure phase (water, hydrocarbon, and gas). The advantage of a static autoclave test is that the coating’s resistance to each phase can be easily evaluated. This information can be used to make future decisions for coatings in similar environments. Additionally, he suggests comparing the results of pre- and post-exposure testing to determine loss of barrier properties. Post-exposure Log Z values should be at least 90% of the baseline range.

Lastly, Traylor proposes using a holistic approach. An effective specification should require use of EIS data inclusively with other tests (e.g., blistering, swelling, softening, intracoat foaming, undercreep/metal attack, interface of phases, color change, and adhesion) to determine a coating’s fitness for service.

To accomplish the goal of developing a standard for evaluating autoclave results for internal pipe coatings using EIS, Traylor comments that participation of the entire industry (specifiers, owners, applicators, and coating manufacturers) is required. The exchange of field information and tracked performance of coatings in high-temperature/high-pressure environments is critical. Detailed analysis of the coating’s exposure environment before installation and periodically during service is also valuable information that can be used by specifiers to develop realistic expectations of design life.

He also recommends that inspectors certified by NACE and SSPC: The Coatings Society evaluate coatings after service and send reports to the coating manufacturer for archival. Applicators should also record details of the application procedure. If a foundation of information is laid, he concludes, the entire industry will benefit from faster, less expensive coating testing.

Source: Dustin Traylor, Axalta Coating Systems—email: dustin.traylor@axaltacs.com.

Filed Under: Coating, Corrosion Tagged With: EIS

No excuse for cutting corners on corrosion in downstream plants

Posted on April 19, 2018 · Leave a Comment

Published by Anna Nicklin, Editorial Assistant
Hydrocarbon Engineering, Monday, 09 April 2018 12:00

Corrosion is a major challenge and an essential risk to contain for any oil and gas operator. Loss of containment can mean loss of process, loss of revenue, expensive repairs and – most importantly – a potentially major safety hazard. However, while a breach in a cross-country pipeline can be a major incident and environmental risk, it is another matter downstream. Different plants and processes are tightly packed together, with all manner of hydrocarbons and other combustible fluids boiling, cooling or flowing. Workers dart in-between, never more than a few dozen feet from a potential corrosion risk. In this environment, loss of containment could be catastrophic. It does not take more than a quick web search to find a multitude of incidents related to corrosion control issues.

All of which is to say that, when it comes to the downstream industry, the stakes are high, and corrosion control is too important to ignore. However, in conjunction with increased risk comes increased complexity: the number of different processes and the variety of different mediums and hydrocarbons entails a diverse, heterogeneous environment for monitoring. One monitoring system does not fit all, so it can be difficult for operators to avoid a pick ‘n’ mix of systems with patchwork, incomplete coverage.

So how can the risk be managed? Most, if not all, refineries and petrochemical plants employ talented and knowledgeable corrosion engineers with the expertise to do so. But to do the best job, they need the best data. That, in turn, requires a fully integrated monitoring system – something that has historically been in short supply.

An aggressive environment

The difficulty involved in downstream corrosion monitoring cannot be underestimated. And it is growing.

The refining industry has many elements that can contribute to increased corrosion rates. Corrosive substances can be found in the feedstock – amines and sulfuric acid as an example – and often further elements can be added and produced during the refining process itself, such as oxygen, nitrogen, trace metals, salts, carbon dioxide, and naphthenic acids. Refinery processes themselves involve extreme temperatures and velocities in many of the processes including distillation, catalytic crackers, and alkylation that all contribute to elevated corrosion rates.

Downstream operators are dealing with more than hydrocarbons. There are a variety of fluids used in different processes, many of which can be extremely corrosive themselves. Getting corrosion right, in this instance, can be the difference between profitability and throwing money away on unscheduled repairs and maintenance.

To add to this, the ripple effects of the recent downturn are still being felt across the oil and gas sector. With ageing assets, extended operating windows and high demands on production rates, one technique firms adopted in order to adapt was crude blending, mixing different qualities of conventional and TAN crudes to a level that they had not before. This practice makes financial sense, TAN crudes can be one-third of the cost to operators compared to conventional crudes but also make corrosion less predictable and increases risk due to their higher acid content. Prices have recovered, but not to anything like previous highs, and crude blending is still common practice. If refineries are to continue to blend crudes and remain profitable they must ensure that a robust, accurate integrated corrosion monitoring system is in place.

Keeping tabs

In this environment, corrosion is unavoidable. The key is to keep tabs and effectively monitor the issue. And accuracy is key. Underestimate corrosion, and the risk of failure rears its head, along with all the safety and business risks that come with it. However, if an operator errs too much on the side of caution, they risk unnecessary maintenance downtime, premature replacement of equipment or an overzealous corrosion inhibitor programme – all potentially expensive and avoidable mistakes.

But accurate monitoring – across a diverse downstream facility – is easier said than done. Different pipework and different processes require a different approach to corrosion.

For example, one of the most tried and tested methods for corrosion monitoring is the use of a corrosion coupon. This is a small sample of metal, inserted into the flow at selected locations, which is then subject to the same corrosive factors as the pipework. At regular intervals – perhaps as often as every few months – corrosion coupons are removed and engineers measure how much of the metal has been corroded, taking that as a representation for pipeline corrosion. A corrosion coupon can also give valuable data on the type of corrosion and potential localised pitting corrosion issues. This is appropriate in many instances, but not all.

Another commonly used monitoring method is to insert electrical resistance probes inline into the pipework. These are capable of real-time monitoring and can detect changes in corrosivity within hours, making them ideal for highly changeable applications. High resolution ER probes allow operators to directly monitor levels of corrosion in their system and react quickly to process changes in a system, rather than using a coupon as a proxy. This approach is extremely effective and the only viable method to accurately monitor and control corrosion inhibitor injection programs, as it allows operators to adjust volumes injected based on live, granular data. A huge cost saving potential.

However, as with coupons, there are certain process within the downstream industry where intrusive monitoring cannot be used due to extreme process conditions. It is not appropriate for all applications.

This is why, in many cases, corrosion engineers have turned to external ultrasound thickness (UT) monitoring systems that affix directly to the outside of the pipe and require neither downtime nor intrusion to install. However, by itself the approach is no silver bullet. The trade-off for these advantages is that operators have to settle for a lower level of sensitivity, resolution and accuracy. Modern ultrasonic technology has made great progress on this front, but still does not match ER probes for accuracy and response times.

So, there is no one-size-fits-all perfect solution for corrosion engineers working downstream. Likely they will have a patchwork of different systems, selecting the best option process by process, pipe by pipe. This gives the best possible corrosion monitoring performance at the individual application level, but carries its own risks at the facility-wide scale.

The holy grail for the corrosion engineering team is an overall view of corrosion risk across the facility. Understanding which equipment is suffering from near problematic corrosion levels, and which other processes are in close proximity, helps give a more accurate gauge of overall risk to the operator and personnel. Similarly, understanding if one process is due downtime for corrective maintenance helps operators plan more effectively. For example, if one process has knock-on effects on another, it may best to schedule maintenance for both at the same time even if one is not quite at its corrosion limits, rather than have to shut down a second time a couple of months down the line.

The only way for corrosion engineers and operators to effectively monitor plant wide is through assimilating those disparate systems into one broader integrated system, incorporating corrosion coupon, ER probe and UT devices together feeding the data back into a central platform to give a holistic, facility-wide view of risk. Corrosion engineers are then empowered to make the most informed decisions, guarding safety while maximising asset profitability. In the past, this might have been a pipe dream. However, companies like Cosasco now have decades of accumulated experience with these individual technologies and have invested in platforms to bring them together in a fully integrated way.

For corrosion engineers at refineries and petrochemical plants, there is really no excuse not to implement an integrated, multi-pronged corrosion monitoring strategy. No excuse because the risks to safety and revenue are too high to ignore, and no excuse because the technological limitations that may have once hampered such a programme are no longer insurmountable. A modern system utilises intrusive electrical resistance probes and state of the art, high accuracy non-intrusive ultrasonic ones. Feeding that data back into a central view of risk, is the logical next step in keeping the downstream sector safe and profitable.

Filed Under: Corrosion

Thermal Imaging Used for Nondestructive Testing of Concrete Pillars

Posted on April 18, 2018 · Leave a Comment

By Ben DuBose on 3/29/2018 6:24 PM

The study was completed at Russia’s Trans-Siberian Railway, using an experimental facility for conducting induction and infrared thermal imaging. Photo courtesy of TPU.

Scientists from Tomsk Polytechnic University (TPU) (Tomsk, Russia) proposed a thermal imaging technique to study the corrosion of steel reinforcement within concrete railway pillars. The researchers say the nondestructive testing (NDT) method, which they tested in a recent study, enables efficient and quicker detection of corrosion hidden behind the concrete shell of the supporting structure.

“As the service life expires, the pillars become unfit for use with obvious negative consequences,” says TPU professor Vladimir Vavilov, head of the school’s research and development laboratory for thermal control. “It is impossible to replace all pillars simultaneously. Therefore, it is necessary to identify those that should be replaced first.”

“Ultrasonic testing is traditionally used for this purpose,” he adds. “Such testing takes up to one day. We propose thermal testing. Here, the process takes a few minutes and about an hour together with all preparation works.”

The mass electrification of Russian railways began in the 1980s, so the researchers’ study¹is focused on railway pillars because those reinforced concrete poles are nearing their assumed lifetime of about 50 years. Thus, efficient inspection techniques to evaluate the concrete supports are expected to become increasingly important. The work was supported by a Russian Scientific Foundation grant.

Limitations of Traditional Methods

Pole damage often starts in the underground sections of supports, where corrosion initiates because of varying soil moisture and high mechanical stresses. Corrosion damage is often related to cracks that appear in concrete boundary layers adjacent to steel rebar. These cracks lead to the permeation of various corrosive agents, with chlorides being especially troublesome.

The corrosion defects are generally found under the concrete surface layer that is often hidden in the soil, thus making them visually undetectable, the researchers explain.

In addition to time inefficiencies, they say ultrasonic methods to detect corrosion—such as measuring ultrasound velocity in different directions, recording acoustic emission signals, or analyzing resonance features of the reinforcement—have limitations because they can only detect corrosion damage just prior to a pole’s failure. On the other hand, they say thermal techniques can “see” through the layers of a pole well enough to detect damage before failure.

While the researchers acknowledge classic thermal NDT techniques such as surface heating of test samples, they say this route is inappropriate for concrete poles because of the considerable pole thicknesses and the low thermal conductivity of concrete with regards to highly conductive steel.

As such, the researchers sought to develop a thermal heating technique that could be applied in the field, thus accounting for the unique properties of each pole.

In-Field Method Sought

After testing various thermal solutions on computer model simulations, the researchers decided their best option was to stimulate the metallic reinforcing steel by applying high-frequency inductive heating. Their goal was to detect any displacement of the reinforcement and better predict each pole’s residual strength.

A thermogram of a concrete pillar (a) without a defect and (b) with a defect. Photo courtesy of TPU.

When inductive heating is applied, they say infrared (IR) thermographic monitoring of the temperature distributions on the bottom 1- to 2-m section of a pole allows them to evaluate both the longitudinal and circumferential rebar reinforcement. Because the technique uses natural grounding, users only need to dig out the bottom sections of poles by about 0.5 m to allow direct IR surveying.

To test a pillar, an inductor coil is placed around it, which heats the steel reinforcement inside the pillar. It is applied to a narrow circular area on the pole surface, since the use of additional electrodes could damage any protective layers, such as coatings or linings, the researchers say. The inductor is powered at a rate of ~10 MW/m³ by an autonomous gasoline generator mounted on a nearby truck. This process is enough to heat the reinforcement a few degrees higher than the ambient temperature.

The heat radiated by the reinforcement is detected with IR cameras that are installed several m away from the pillar. By moving both the heater and IR camera for about 20 seconds, researchers say this allows them to gauge the pole’s temperature response under constant heating without putting too much stress on any one area. The technique is safe for personnel and fully nondestructive, since the excess pole temperature does not exceed 15 °C.

A thermogram, which shows temperature distribution at the tested surface, is transmitted from the cameras to a computer. Surface temperature signals in defect areas, characterized by high thermal resistance, may reach 3 to 10 °C depending on reinforcement depth, as well as rebar thinning and the presence of corrosion products. These defects diminish the rate of temperature changes by two to four times, the researchers explain.

“The fact is that the metal corrosion is most likely in the place contacting the ground,” Vavilov says. “In places already damaged by corrosion, the reinforcement is thinner. It is otherwise heated, which is displayed on thermograms. Up to the point, a thermal footprint disappears when air gaps and corrosion products occur.”

Pillar Findings Verified

The researchers tested their technique on 14 working pillars at the Trans-Siberian Railway in Russia’s Tomsk region, finding that two needed to be replaced due to defects associated with corrosion.

Because those two pillars were already near failure, the researchers were able to confirm their IR-based findings with ultrasonic and vibroacoustic testing. The ultrasonic and vibroacoustic tests came to the same conclusion, thus adding credibility to their method. Visual inspection of the underground pole sections also revealed some cracks and weak traces of corrosion products, the researchers say.

Further comparisons on the results of the IR thermographic surveys with the ultrasonic and vibroacoustic testing conducted on the same pillars will be discussed in a forthcoming paper.

Source: TPU, www.tpu.ru/en.

Reference

1 “Heat May Detect Invisible Damage in Railway Pillars,” TPU News, Feb. 13, 2018, https://tpu.ru/en/about/tpu_today/news/view?id=4014 (March 15, 2018).

Filed Under: Coating, Corrosion

Challenges of Installing a New Pipeline

Posted on April 10, 2018 · Leave a Comment

By Eric S. Langelund and Kimberly-Joy Harris on 3/29/2018 6:22 PM

During the installation of a new pipeline, corrosion engineers must consider many different aspects of the pipeline and its corrosion protection.

Pipeline installation is accomplished through the efforts of multiple teams of personnel, all of whom have their own duties and concerns. Safety, transportation, materials, equipment, and construction are some major components of pipeline installation. Corrosion engineers must address all of these areas to ensure the corrosion protection system is installed and functioning to meet the requirements of the federal, state, and local regulatory agencies as well as the company’s requisites and timelines.

Pipeline Coating

Fusion-bonded epoxy coatings are often used on pipelines.

The coating is the first line of defense against pipeline corrosion, and most pipelines are coated. Selecting a coating system that is appropriate for the pipeline’s route, or right-of-way (ROW) conditions is very important. Some coatings are petroleum based and may not be suitable for soils with existing hydrocarbons. Other coatings are pliable and are ideal for filling voids along the surface of the pipe, but are not compatible with clay soils that exert stresses onto the coating. If the ROW environment is rocky, a thicker coating may be preferred. If the ROW requires horizontal directional drilling to install a pipeline underneath a river or other obstacle, a thick, abrasion-resistant overcoat may be selected. Common coatings used for cross-country pipelines are fusion-bonded epoxy or two-part epoxy coatings with a standard layer that measures from 19- to 24-mils (482- to 610-µm) thick. Once a coating is selected, it is recommended that the pipe coating process is inspected at the mill. This helps to ensure the surface is properly prepared and the pipe is handled appropriately.

During pipeline installation, welded joints must be coated in the field. It is crucial to select a coating that is compatible with the mill coating and also suitable for use in the field. Inspecting the application of the field coating at the pipeline joints is important as well. This ensures that the appropriate surface preparation, pipe preheating (if necessary), and specified coating application is taking place. Additionally, the joint coating should be tested for holidays (i.e., coating flaws) and repaired if necessary.

Cathodic Protection System Design

The CP system is the second line of defense for protecting the pipeline from corroding. Although most pipelines have an effective coating, the CP system is essential for protecting areas of the pipeline where the coating has a holiday or may be deteriorating. Since the demand put on the CP system is determined by the coating quality, the condition of the coating should be the best it can be when the pipe is installed.

Many factors are involved when designing the CP system for a new pipeline. Apart from the actual current calculations, environmental conditions along the ROW must also be addressed. Many new pipelines will cover a lot of terrain with varying soil types. Supplemental CP may be required in areas where the soil has high resistivity.

Additionally, CP designs for new pipelines must consider any existing CP systems for other nearby pipelines (known as foreign pipelines). In some instances, there isn’t an easy way to establish an electrical bond between pipelines. This means the CP system for the newly installed pipeline would need to overcome the influence of any other CP system.

Right-of-Way

The first thing to review for CP of a new pipeline installation is whether there are foreign pipelines crossing the new pipeline’s ROW. Existing pipelines in the ROW of the new pipeline can pose many obstacles when designing a CP system. New pipelines in crossings may experience interference from stray current—which is current from another voltage source, such as a CP system for a nearby foreign pipeline or current from an adjacent electrified railway—or shielding of CP currents. Often the extent of stray current interference is unknown until the new pipeline is fully installed. CP design allowances for pipeline crossings and stray current interference should be made, as much as possible, on the front end of a project.

Once construction has commenced, several tasks are required to ensure a safe and successful pipeline installation with effective cathodic protection and mitigation of interfering current.

Stray Current Interference

CP systems from foreign pipelines can cause depressed structure-to-electrolyte (S/E) potentials (i.e., potential readings that are more electro-positive than the accepted criterion of –850 mV vs. a copper/copper sulfate [Cu/CuSO₄] reference electrode) for the newly installed pipeline. In this case, the electrical current picked up by the affected pipeline will be discharged from that same pipeline. The discharge site on the affected pipeline is where the depressed S/E potentials appear and where corrosion occurs. One way to mitigate this interference is to establish an electrical bond between the newly installed pipeline and foreign pipeline. The bond provides a path that allows electrical current involuntarily picked up on the affected pipeline to be returned to the pipeline with the CP source. Most operators and the corrosion consultants who support them participate in regional electrolysis committees that meet periodically to set up pipeline interference tests to determine the impact, if any, of a pipeline’s CP system on other cathodically protected structures in the vicinity.

Schematic of a typical pipeline test station.

Another way to address stray current interference is to install supplemental CP at the current discharge location on the affected pipeline. Often this involves installing sacrificial anodes so that the current discharge takes place at the anodes instead of the affected pipeline’s surface. There are many configurations for this type of stray current mitigation.

Stray current interference can also originate from rail systems powered by direct current (DC). The DC used to power the trains inadvertently leaks into the earth. The current then finds the path of least resistance back to its source. Often this path is a nearby pipeline. Where the current is picked up on the pipeline, there is free CP for the pipe. However, corrosion occurs where the current is discharged from the pipe. For a carbon steel pipeline, 1 A of DC over the course of a year takes ~20 lb (9 kg) of iron with it. Mitigation of stray current under these conditions may involve an electrical bond back to the rail power source or the installation of supplemental CP.

Within the last 30 years, induced alternating current (AC) voltage has been identified as a pipeline safety concern. Pipelines that parallel overhead high-voltage AC (HVAC) transmission lines pick up induced AC voltage from the magnetic fields produced by the overhead wires. The induced AC voltage has been found to be dangerous to field personnel, and NACE International set a safe limit of 15 VAC. When testing pipelines beneath HVAC transmission lines, it is recommended to measure and record the AC voltage of the pipe in addition to the S/E potential. Where pipelines exceed 15 VAC, grounding mitigation is recommended, such as grounding mats at test stations and valves where personnel come into contact with the pipe, or linear grounding along the length of a pipeline where it is positioned beneath HVAC transmission lines. Such grounding is typically connected to the pipeline through an electrical isolation device, which conducts AC to effectively ground and discharge the induced AC voltage and blocks DC voltage so the CP system is not adversely affected. The magnitude of induced AC voltage is based on many factors, including distance between the pipeline and the HVAC transmission line towers, routing of the pipeline, number of HVAC transmission lines, and pipeline coating system. Typically, the AC voltage is higher where the pipeline enters and leaves the power corridor.

HVAC transmission lines near the pipeline can cause induced AC safety and corrosion issues.

More recently, induced AC voltage has been found to cause AC corrosion, which is due to improved pipeline coatings. This phenomenon is the result of induced AC voltage being discharged from the pipeline surface at a coating holiday. The effect of a large amount of AC being discharged from a small, focused holiday location can result in aggressive corrosion. This corrosion is so destructive that there have been instances where a pipe has experienced through-wall penetrations in a matter of months. Soil resistivity, induced AC voltage, and AC current density are all factors that influence AC corrosion. Identification and mitigation of AC corrosion is imperative. Coupon test stations and remote monitoring are good tools in areas where AC corrosion may be a concern.

Test Stations

Test stations are used to measure S/E potentials so the effectiveness of the CP system can be monitored and evaluated. Although there are different types of test stations with different materials of construction, their purpose is the same. They simply house test lead wires that are connected to a buried pipeline to provide an easy connection to the pipe for testing the CP system. The best time to install test stations is when the pipeline is being installed. Test lead wires (normally two) are attached to the buried pipeline and routed up to grade into a protective housing (test station).

Selecting the proper locations for test stations is important. Typically test stations are installed at each road crossing as the pipeline is routed from Point A to Point B. Additional test stations are often placed at fence lines when there is a large distance between roads, at or near crossings with foreign pipelines, and at any other location identified as a concern for the effectiveness of the CP system. Typically, one test station is installed every mile along a pipeline.

A permanent reference electrode may be buried near the pipeline to provide good earth contact for measuring S/E potentials in an area where soil conditions for measuring S/E potentials are not ideal (e.g., the ground is very dry, susceptible to freezing, or covered with asphalt or concrete). The permanent reference electrode test lead wire is routed into and terminated within the test station with the other pipe wires.

Where stray currents or poor soil conditions exist, a test station with coupons may be installed. A coupon is a small metal sample, installed adjacent to the pipeline, that represents a holiday in the pipe coating. Ideally the coupon size is selected based on estimations to represent the worst-case holiday on the pipeline. The S/E potentials of the coupon are used to evaluate the effectiveness of the CP system, with the theory being that if the coupon is being protected by the CP system, so is the pipeline.

Since foreign pipeline crossings can result in stray current interference between pipelines, test stations with test lead wires on all pipelines should be installed at foreign pipeline crossings to allow comprehensive testing of all pipes. This would include interference testing to ensure that one pipeline’s CP system is not hindering the effectiveness of the other pipeline’s CP system. Test stations at foreign pipeline crossings often include permanent reference electrodes and coupons to facilitate thorough testing of the pipes at pipe depth.

Additionally, a bond may be established between pipelines to alleviate the influence of one CP system on another, and so it is advisable to install a larger cable on the new pipeline during construction and route it into a nearby test station. If interference is found, the new pipe will already have a suitable bond cable installed, which makes the process of establishing an electrical bond easier and more cost effective.

Cased Crossings

As a pipeline is routed from Point A to Point B, it will cross many obstacles along the way, such as roads, rivers, railroads, foreign pipelines, etc. Depending on local regulatory requirements, some of these crossings may require the installation of a casing pipe for the carrier pipe to pass through, although it may not be desirable. Casing pipes are avoided for several reasons. A casing pipe may come into contact with the carrier pipe and short out the carrier pipe’s CP system, which would result in low pipe potentials in the vicinity of the casing and the absence of CP for the carrier pipe within the casing pipe. Because a casing pipe can become filled with ground water, which is very likely, an electrolytic short between the casing pipe and carrier pipe can occur. This also results in low pipe potentials in the vicinity of the casing. Recent construction practices tend to avoid casings wherever possible, and may include techniques such as horizontal directional drilling to lay a pipe at a greater depth below an obstacle.

Should the installation of a casing pipe be unavoidable, several practices can help protect the carrier pipe. Casing spacers should be used to support the carrier pipe within the casing pipe to ensure that there is no direct contact between the pipes. The appropriate number of spacers for the carrier pipe diameter should be installed, and the spacers should be comprised of a suitable dielectric material to electrically isolate the pipes from one another.

Sealing the ends of a casing may be desired to help keep water out of the casing and contain vapor-phase corrosion inhibitors (VCIs) within the annular space between the carrier pipe and the casing pipe. Nowadays many operators are using VCIs in the annular space. The vapors provide corrosion protection and some VCIs raise the pH of the annular space to further reduce corrosion. Pumping dielectric wax into the annular space between the carrier and casing pipes is an alternative that can help to keep water out of the casing. The wax displaces any water and provides a nonconductive environment around the carrier pipe. Prior to installing sealing materials at the ends of the casing, any debris inside the casing pipe should be removed. Sealing the ends of the casing may include rubber links or boots that squeeze between the pipes or clamp around the pipes. Metallic bolts or banding should not come into contact with both pipes. Some sealants used to close the ends of the casing are non-metallic and may also be used in conjunction with other systems.

Test lead wires should be installed on both the carrier pipe and casing pipe. During backfilling of the pipes, care should be taken to ensure the lead wires are protected and do not come into contact with both of the pipes. Many electrical shorts between the carrier pipe and casing are the result of the lead wires coming into contact with both pipes during the backfill process. It is recommended that two lead wires be connected to each pipe at both ends of the casing. Advanced troubleshooting of casing shorts would require the additional wires, which are much easier to install during pipeline construction. Installing permanent reference electrodes at casing pipes is recommended because the pipe is often much deeper than normal at these locations.

Company Standards for Engineering and Design

Because of the many issues related to designing a pipeline CP system, company standards for CP engineering and design should be established. The company standards should call for written specifications for approved materials and detailed drawings depicting approved installation practices. Written specifications should spell out the coatings, test stations, anodes, etc. that are approved for use. They should also address design requirements so stray current interference or induced AC voltage are not overlooked during pipeline installation. Detailed drawings should depict approved installation methods of CP system components. They should be detailed enough to prevent improper or incomplete installation of test stations, anodes, pipeline coating, etc.

Where to Go for More Information

NACE CP courses present a wealth of information on CP. Short courses, such as the Western States Corrosion Seminar, Northern Plains Short Course, Purdue Underground Corrosion Short Course, and others, also deliver valuable CP training. Becoming involved in NACE sections and attending their meetings, however, is instrumental for providing corrosion practitioners with the opportunity to learn about problems encountered in the field by other local corrosion professionals, and how these corrosion problems are successfully mitigated.

In summary, many factors must be considered when designing a complete CP system for a new pipeline system. With awareness of the possible complications that are best addressed during construction, plus quality company standards for engineering and design, an effective CP system can be achieved on a new pipeline installation.

This article is based on CORROSION 2017 paper no. 8947, “Pipeline New Construction Challenges,” presented in New Orleans, Louisiana, USA.

ABOUT THE AUTHORS

ERIC S. LANGELUND is a project engineer with Piping & Corrosion Specialties, Inc., Millersville, Maryland, USA, email: ericl@pipingandcorrosion.com. He is a corrosion control consultant specializing in cathodic protection system testing, troubleshooting, design, and installation. A NACE International member for more than 25 years, Langelund is NACE-certified Cathodic Protection Specialist. He holds a B.S. in materials engineering from the University of Wisconsin, Milwaukee.

KIMBERLY-JOY HARRIS is with Pipeline Integrity Services at Enbridge Pipelines, Inc., Edmonton, Alberta, Canada, email: kimberlyjoy.harris@enbridge.com. She specializes in external/internal corrosion control design, monitoring, and inspection for onshore/offshore pipelines and above-grade tanks; pipeline corrosion integrity management; and coating materials selection and inspection. Harris holds a M.S. degree in instructional/organizational leadership, a Ph.D. degree in science (physics), and a B.S. degree in electronic engineering. A NACE International member for 26 years, she is the recipient of a NACE International 2015 Distinguished Service Award and holds seven NACE International certifications.

Filed Under: Cathodic Protection, Coating, Corrosion

Inspection of High Consequence Line Provides Critical Insight

Posted on March 1, 2018 · Leave a Comment

Published by Nicholas Woodroof, 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.

Filed Under: Corrosion, Oil & Gas, Pipeline

Study: Graphene Technology Boosts Performance of Epoxy Coatings

Posted on February 7, 2018 · Leave a Comment

By Ben DuBose on 1/2/2018 8:59 PM

Tests were conducted on the chemical and mechanical properties of the graphene-added epoxy coatings, including the tensile strength. Photo courtesy of Talga Resources.

Mark Thompson, managing director of technology materials company Talga Resources (West Perth, Western Australia, Australia), says tests using the company’s branded graphene, Talphene,^†have shown superior results when tested against reference epoxies and commercial zinc-rich epoxies.

“Most large-volume steel anticorrosion coatings are made from epoxies, so that’s where we’re targeting first,” Thompson says. “Marine coatings could be positively impacted by this stuff. Then the composite carbon-fiber resins will follow.”

So far, the tests have used a formulated dispersion of the company’s few layered graphene and graphene nanoplatelets, mixed in a proprietary way into a two-party epoxy resin widely used in marine coatings.

“By substituting current active ingredients such as zinc with lower quantities of non-toxic graphene alternatives, the application, environmental, and maintenance costs of steel infrastructure can be reduced,” Thompson says. “We think over time, a lot of the zinc [used in epoxies] can be replaced.”

Benefits of Graphene

According to Thompson, graphene offers desired qualities including high strength-to-weight ratio, impermeability, and chemical inertness. These characteristics have been shown to result in additional corrosion protection and more environmentally friendly polymer matrixes when used as an additive. He says graphene contains several other benefits, including a high aspect ratio and functionalization to provide passivation reactions, both anodic and cathodic protection (CP), depending on the substrate.

“It’s a powerful anticorrosion tool, if it’s done right,” Thompson says. “It does require intimate knowledge of the chemistry so that it hooks up chemically with both the resin system and underlying metal substrate. You need to functionalize the graphene properly. The fundamentals of graphene’s passivation effect are poorly understood, but it is hypothesized the graphene takes electrons off the substrate and into the coating, thereby reducing the electron interaction,” Thompson says of the passivation potential. “But depending on the substrate it appears to be a tunable effect,” he adds, referring to CP.

In that way, graphene-enhanced epoxies can offer additional versatility by having the flexibility to be used on substrates of varying conditions.

Improved Dispersion

Thompson says his company has found a route via a new patent-pending method to distribute the particles into epoxies in a much more homogenous manner.

“Our technology relates to both the formulation and, importantly, the method of incorporating the graphene into the epoxy to maximize its effectiveness,” Thompson says.Led by Cambridge, United Kingdom-based chief technology officer Siva Bohm, the company believes its new dispersion method could also be applied to other systems besides epoxies—including fiber-reinforced polymer composites—that have also suffered in the past from homogeneity issues with graphene.

“Delayed graphene dispersions have been a problem for a long time,” Thompson says. “You can’t disperse in these viscosities very well, and the curing time reactions are also a factor. To get the physical particles to be homogenously distributed at a nanoscale, while minimizing workability changes, that’s been the holdup. We think this is the game changer.”

Corrosion Test Results

To test the corrosion-resistant properties, Thompson’s team used an epoxy resin system using bisphenol A (BPA) (C₁₅H₁₆O₂) as the base matrix. Formulations containing graphene in various concentrations were incorporated with the base matrix and applied on standard mild steel panels for performance testing. A free film of each formulation was also made to evaluate tensile properties.

Scored coating tests found superior corrosion protection using graphene-added epoxy coatings, right, as compared to a commercial zinc-rich epoxy primer, left. Photos courtesy of Talga Resources.

Meanwhile, a commercially available zinc-rich epoxy primer at 75 vol% zinc was used as the control variable for the corrosion evaluation, which consisted of electrochemical tests utilizing electrochemical impedance spectroscopy, linear polarization, and salt spray, as specified in the ASTM G59¹ standard.

“Within the first 500 hours of salt-spray testing, there was practically zero corrosion of the graphene-enhanced unit,” Thompson says. “The measureable one was the electrochemical evaluation, and that was a decrease in the corrosion rate of the underlying steel by two orders of magnitude when compared with the zinc-rich coatings.”

The abrasion resistance of the coating, tested under the ASTM D4060² standard, improved by 80% relative to the control coatings. Similarly, a 160% improvement in tensile strength and 95% boost to elongation were seen when testing the free film.

Thompson said his company would not yet disclose which graphene vol% formulation achieved those figures, adding that the project remains in development. However, he says there was a “significant impact” with even a 1 vol% graphene addition.

“It’s a massive decrease in the overall corrosion rate,” Thompson says, adding that the thickness of zinc-rich coatings may be reduced if using graphene, reducing overall volume requirements.

Next Steps

Going forward, the company says it recently entered into a product development agreement with independent materials and research group The Welding Institute (TWI) (Cambridge, United Kingdom) to further develop and validate the technology.

“They’re a really respected materials development institute, and we’re now working with them on increasing the range of performance and having their outside validation of what we found,” Thompson says. “Once that matures and gives us a bigger amount of data for industry, we go out looking for coatings industry partners, such as one we have already with Chemetall [Frankfurt, Germany], a subsidiary of BASF’s coatings business, on graphene-enhanced metal pretreatments.”

Meanwhile, in the company’s own labs, the next stage of research will investigate whether the graphene additive technology can be successfully applied to other composite resin systems in addition to epoxies.

“We do have indications from some lab work that other systems will respond similarly,” Thompson says. “Others are conceptual at this stage. But we have good reason to believe this will expand and be around for a while.”

Source: Talga Resources, www.talgaresources.com. Contact Mark Thompson, Talga—email:mark@talgaresources.com.

^†Trade name.

References

1 ASTM G59 (2014), “Standard Test Method for Conducting Potentiodynamic Polarization Resistance Measurements” (West Conshohocken, PA: ASTM, 2014).

2 ASTM D4060 (2014), “Standard Test Method for Abrasion Resistance of Organic Coatings by the Taber Abraser” (West Conshohocken, PA: ASTM, 2014).

Filed Under: Coating, Corrosion

Corrosion under insulation poses major threat to offshore asset integrity

Posted on February 5, 2018 · Leave a Comment

By: Archie Crawford

The battle against corrosion is an ever-present issue for the offshore oil and gas industry, with structures, pipework, and equipment widely exposed to seawater and humid, salty air.

Corrosion under insulation (CUI) is a major and well-understood threat, and the industry is researching new technology to help identify the impact earlier and more reliably. Mainly, CUI affects steel components, which corrode when they are in contact with water and air.

Insulation of plant and pipework can create a space where water can collect and rest against the metal surface over extended periods of time. With outdoor equipment, even very small gaps in insulating cladding can let in sufficient volumes of water to cause significant corrosion issues.

Advances in imaging technology are providing offshore maintenance crews with much more data on the ‘hidden’ condition of their assets than was available 10 years ago. (Photo courtesy Bilfinger Salamis)

A further dilemma created by insulation is that it can hide the effects of the corrosion from view, so that a heavily corroded pipe can appear normal when visually inspected. But by the time the effects have become clearly visible from the outside – often in the form of particles of oxidized metal or discolored water running off – significant damage may already have occurred.

Removing insulation to check the condition of pipework is a laborious process and a costly method of assessing the condition of an asset. Maintenance specialists have developed a suite of different solutions that can make managing CUI across an installation more efficient and help ensure pipes and structures conform to HSE guidelines.

INSPECTION EFFICIENCY

The biggest cost associated with inspecting for corrosion is manpower, and this is exacerbated in the case of offshore facilities – mobilizing the right personnel onboard and ensuring that they receive the correct briefing is a time-consuming process. The focus must therefore be on minimizing the resources needed to carry out the work. The preferred approach is for the inspection and fabric maintenance departments to work together, using three-man teams comprising an inspector, insulator and painter, all of whom are rope access-qualified. Keeping the teams as small as possible can lead to considerable reductions in cost.

It is better still to avoid the process of transporting new people to site to perform an inspection by instead training team members already on location to handle inspection work. Advances in technology to help automate the process have played a big part in making this possible, increasing the efficiency and effectiveness of inspection crews. Equipping teams with CUI detection tools such as digital radiography and pulsed eddy current (PEC) technology can significantly speed up site inspection processes and improve the likelihood of early detection.

Although radiographic and PEC imaging are not new, the techniques used to perform inspections have advanced rapidly. Previously each radiographic exposure took several minutes to capture and subsequently needed to be processed using lab equipment. These steps can now be taken in a matter of seconds and images can be viewed on the spot on a mobile device.

As recently as five years ago PEC readings needed to be performed on a point-to-point basis, making it time-consuming to capture all the angles and positions required to scan a length of pipework. In response, Bilfinger worked with imaging specialist Eddyfi to develop a system that runs continuously. This cuts the time taken and significantly increases the number of data points available, providing greater certainty of results. Using mobile data processing devices, engineers can now output easy-to-interpret condition reports showing the location and extent of any defects without any need for desktop analysis. This means response times to priority corrosion issues can be much faster.

CASE STUDY

Bilfinger was called in by a contractor operating a platform for a major global energy company to renew the insulation on all exterior pipework where CUI was detected. The existing insulation was mineral wool, enclosed in neoprene cladding, and the cause of the CUI in each case was failure of the elastomeric sealant used in the joints between sections.

Where replacements were needed, the mineral wool was replaced with foam glass. This was clad in banding tape sealed with Terostat PC vapor-barrier mastic, a long-life sealant proven to deliver better resistance than elastomeric options. The insulation was applied in the form of pre-fabricated shells supplied tailor-made, allowing fast installation on site and reducing costs.

The scale of the project, which involved replacing hundreds of meters of insulation, meant that the works took place over several months. Throughout delivery, the project team provided a monthly report with information on productivity, tool-time, costs, man allocation hours, work pack tracker, health safety, environment and quality CUI statistics and linear distance re-insulated.

CONCLUSION

CUI is critical, especially where ageing infrastructure is involved, and the current trend for maximizing the lifespan of large pieces of offshore infrastructure presents increased challenges, especially at mature fields on the UK continental shelf. Failure to manage CUI can, at best, lead to expensive and time-consuming maintenance operations; at worst, it can pose a major threat to the safety of facilities and personnel, so this is not an area offshore operators can afford to overlook.

The financial burden involved in performing inspections can be significant, but advances in both inspection technology and strategies have dramatically increased the efficiency of the process in recent years, decreasing the temptation to push back or skip what is an essential safety monitoring process.

Filed Under: Corrosion, CUI, Oil & Gas

Stopping corrosion in the LNG sector

Posted on January 24, 2018 · Leave a Comment

Published by Will Owen, Editorial Assistant

While corrosion is a serious issue in virtually all oil, gas, pipeline, and industrial facilities, it is a particular challenge for the LNG sector, whose facilities must remain corrosion resistant despite rapid growth in areas prone to high humidity, rainfall, and monsoons.

According to the International Gas Union (IGU) 2017 World LNG Report, global LNG trade set a record for the third consecutive year, 258 million t, with the greatest growth in China, India, and Pakistan, which have seasonal monsoons.

In such conditions, the traditional barrier type coatings that are commonly reapplied every few years do not hold up, and often cannot be applied due to flash rusting (rust occurring within minutes or hours) caused by the wet, humid environment.

The frequent required maintenance is disruptive to production, requiring blasting off the old coatings, cleaning the surface, and reapplying multiple coatings. Despite this costly process, excessive corrosion of LNG vessels and carbon steel assets can lead to leaks, fires and accidents, as well as accelerate premature replacement.

Now an innovative coating approach is providing LNG facilities a long-term solution to fighting atmospheric corrosion even in monsoon vulnerable environments, while minimising production downtime and increasing safety. As an added plus for countries like China that are concerned about pollution, the application involves no Volatile Organic Compounds (VOCs), a hazardous component of traditional paints.

Protecting LNG Assets from Corrosion

Southeast China’s Zhejiang province has high humidity, annual average rainfall of 1000 mm – 1900 mm, and frequent typhoons in late summer.

In this region, the Zhoushan LNG Project is located in the Zhoushan Economic Development Zone amid these challenging conditions. As the region’s first import LNG receiving station project in which private enterprise is the main investor, total project investment is more than US$1.45 billion.

The project includes a LNG receiving station, LNG terminal, and pipe connection line, which is being constructed in phases, with completion and operation slated for 2020. It is operated by Xinao Group Co., Ltd., a wholly-owned subsidiary of ENN (Zhoushan) Liquefied Natural Gas Co., Ltd.

However, in phase I of the LNG project, traditional corrosion protection, which typically involves applying polymer paints and rubber type coatings, was ineffective due to very rainy, humid, windy conditions. Such coatings, in fact, often could not be applied because the humidity level was too high and the steel kept flash rusting.

While such methods can create a physical barrier to keep corrosion promoters such as water and oxygen away from steel substrates, this only works until the paint is scratched, chipped, or breached and corrosion promoters enter the gap between the substrate and coating. Then the coating can act like a greenhouse – trapping water, oxygen and other corrosion promoters – which allows the corrosion to spread.

Traditional solvent-based paints also posed another problem. When the solvents evaporate, they release VOCs, which are a source of air pollution, and contain a variety of chemicals linked to adverse health effects. For this reason, China has moved toward coatings that eliminate organic solvents, such as water-based paints.

In response, when the Xinao Group sought long term, external, corrosion protection for two fire fighting water tanks, the company turned to EonCoat, a spray applied inorganic coating from the Raleigh, North Carolina-based company of the same name. EonCoat represents a new category of tough, Chemically Bonded Phosphate Ceramics (CBPCs) that can stop corrosion, ease application, and reduce production downtime even in very wet, humid, monsoon susceptible conditions.

In contrast to traditional polymer coatings that sit on top of the substrate, the corrosion resistant CBPC coating bonds through a chemical reaction with the substrate, and slight surface oxidation actually improves the reaction. An alloy layer is formed. This makes it impossible for corrosion promoters like oxygen and humidity to get behind the coating the way they can with ordinary paints.

Although traditional polymer coatings mechanically bond to substrates that have been extensively prepared, if gouged, moisture and oxygen will migrate under the coating’s film from all sides of the gouge.

By contrast, the same damage to the ceramic coated substrate will not spread corrosion in LNG projects because the carbon steel’s surface is turned into an alloy of stable oxides. Once the steel’s surface is stable (the way noble metals like gold and silver are stable) it will no longer react with the environment and cannot corrode.

Visible in scanning electron microscope photography, EonCoat does not leave a gap between the steel and the coating because the bond is chemical rather than mechanical. Since there is no gap, even if moisture was to get through to the steel due to a gouge, there is nowhere for the moisture to travel. This effectively stops atmospheric corrosion of LNG carbon steel assets.

The corrosion barrier is covered by a ceramic layer that further resists corrosion, fire, water, abrasion, impact, chemicals, and temperatures up to 400°F. Beyond this, the ceramic serves a unique role that helps to end the costly maintenance cycle of replacing typical barrier type coatings every few years.

“In LNG installations, including receiving stations, terminals, and pipeline, if both the ceramic layer and the alloy layer are ever breached, the ceramic layer acts as a reservoir of phosphate to continually realloy the steel,” explains Merrick Alpert, President of EonCoat. “This ‘self heals’ the breach, depending on its size, and stops the corrosion if necessary. This capability, along with the coating’s other properties, enables effective corrosion protection for the life of the asset with a single application.”

The Xinao Group has successfully coated one Zhoushan LNG Project fire fighting water tank with the spray applied inorganic coating, which is compatible with a wide range of commonly used topcoats, and the other tank is expected to be completed in January 2018.

Because of the ceramic coating’s multiple layers of corrosion protection, and the ability to ‘self heal’ breaches, the LNG project is on track to see long term protection of its equipment, effectively breaking the costly cycle of blasting and repainting every few years.

Beyond corrosion resistance, LNG operation managers or corrosion engineers looking to reduce costs are finding additional advantages to CBPC coatings like EonCoat.

For instance, one of the ways China is working to mitigate the negative effects of air pollution is by turning to green alternatives such as CBPC coatings, which are inorganic and non-toxic, so there are no VOCs, no HAPs and no odor. This means the non-flammable coatings can be applied safely even in confined spaces, and satisfy the same goals as water-based paints.

Such CBPC coatings consist of two non-hazardous components that do not interact until applied by a standard industrial plural spray system like those commonly used to apply polyurethane foam or polyuria coatings.

One of the greatest additional benefits is the quick return to service that minimises facility downtime. The time saved on an anti-corrosion coating project with the ceramic coating comes both from simplified surface preparation and expedited curing time.

With a typical corrosion coating, near white metal blast cleaning (NACE 2 / SSPC-SP 10) is required to prepare the surface. But with the ceramic coating, only a NACE 3 / SSPC-SP 6 commercial blast is typically necessary.

For corrosion protection projects using typical polymer paints such as polyurethanes or epoxies, the cure time may be days or weeks before the next coat of a traditional ‘three part system’ can be applied, depending on the product. The cure time is necessary to allow each coat to achieve its full properties, even though it may feel dry to the touch.

With traditional coatings, extensive surface preparation is required and done a little at a time to avoid surface oxidation, commonly known as ‘flash rust’, which then requires re-blasting. But with CBPC coatings, the flash rust is not just acceptable but is desirable. The reason for this unique CBPC characteristic relates to the fact that the presence of iron in the rust aids in the creation of the magnesium iron phosphate alloy layer. It is this alloy layer that allows CBPCs to so effectively protect carbon steel from corrosion.

In contrast, a corrosion resistant coating for carbon steel utilising the ceramic coating in a single coat requires almost no curing time. Return to service can be achieved in as little as one hour. This kind of speed in getting an asset producing again can potentially save hundreds of thousands of dollars per day in reduced downtime in LNG applications.

With atmospheric corrosion a perennial problem for LNG facilities with massive carbon steel structures, the utilisation of CBPC coatings that can control corrosion for decades will only help the bottom line.

Filed Under: Corrosion, Oil & Gas

Historic Corrosion Tools Tell the Story of Early Corrosion Control

Posted on January 15, 2018 · Leave a Comment

By Mark Lewis and Kathy Riggs Larsen on 2/1/2018 6:01 PM

The Weston Mil-Ammeter Model 264 was first patented in 1888.

Where the current left the pipe, it took metal with it, which led to rapid failure of buried water and gas pipelines. This phenomenon was referred to as electrolysis and was considered to be caused by “vagrant” or “vagabond” current, which is known presently as electrical interference or stray current. At the time, all corrosion of buried utilities was blamed on electrolysis, and many electrolysis departments, committees, and engineers came into existence as a result.

Left, the Western Electro-Mechanical Co. Portable AC Ammeter. Right, the Weston DC Millivoltmeter Model 622.

The East Bay Municipal Utility District (EBMUD) (Oakland, California), organized in 1923 to provide reliable, high-quality water for the people of San Francisco’s East Bay area, employed a corrosion engineering staff early on to help mitigate corrosion of its buried water pipe infrastructure. Known originally as the Electrolysis Department of the East Bay Water Co., this group helped pioneer the implementation of corrosion-control techniques for EBMUD, including the use of cathodic protection (CP) on large water transmission mains, which was groundbreaking at the time. Their corrosion laboratory was housed on the second floor of the District’s Claremont Center building, a critical pump station in Berkeley, California.

Weston DC Millivoltmeter Model 622.

The Electrolysis Department used a variety of equipment to conduct comprehensive surveys to track the flow of the electrical current. Results of the surveys were recorded by hand, compiled, and mapped. Before the pump station building was demolished and reconfigured in 1996, a collection of historic instruments used by the District was discovered—antique tools that date from about 1893 through 1950.The tools span the period from the beginnings of commercialization of electricity in the 1880s to the development of CP in the 1930s, and beyond. Aside from the fact that these antique instruments are beautifully and artfully crafted of fine materials such as black walnut, cherry, mahogany, oak, and polished nickel and brass, they represent what might be called the golden age of electrical instrumentation. Also retrieved from the building were historical records of the Joint Committee for the Protection of Underground Structures in the East Bay Cities, a group formed in 1922 that was dedicated to the preservation of underground utilities.

The instruments in this collection were used not only in the early studies of electrolysis,but were also witness to the emergence of electrical bonds as a method of corrosion mitigation. The electrolysis engineers recognized that bonding the rail to buried pipelines was one method of mitigating stray current. Where current flow was determined to be detrimental, they installed drainage bonds between the pipe and the rail itself, or at railway substations, to drain excessive current from the affected structure. In its simplest form, a bond was a wire that connected a rail to a buried pipe.

Left, a nineteenth-century 150-A DC shunt. Center, the McCollum Earth Current Meter. Right, cantilevered electrode used with the McCollum Earth Current Meter.

To monitor and manage this current exchange, amperage and voltage measurements were taken at bond stations using ammeters, voltmeters, and shunts. Ammeters measured the amount of electric current in amperes in a circuit. Voltmeters measured the electrical potential difference between two points in an electrical circuit. Shunts were used to measure current. When a shunt was placed in the wire or bond that connected the rail and the pipe, current passing through the drainage bond could be measured. By knowing the resistance of the shunt and measuring the voltage with a millivoltmeter, the amount of current passing through the shunt could be calculated using Ohm’s Law (I=V/R, where I iscurrent, V is voltage, and R is resistance).

Weston potential transformers housed in walnut cases.

Over the years, testing and remote monitoring techniques have advanced significantly; and these antique meters have been replaced with smaller, lighter, more accurate digital versions, with some digital meters combining many functions in one tool. For the early electrolysis engineers who were mitigating corrosion 80 to 100 years ago, today’s range of corrosion-control equipment available for the modern corrosion professional surely would have been unimaginable.This is a condensed version of the article published in the November 2017 issue of MP. A complete version of this article can be viewed here.

Bibliography

Lewis, M. “How ‘Vagrant Current’ Became Impressed Current Cathodic Protection— Part 1.” MP 64, 11 (2008): p. 36.

Lewis, M. “How ‘Vagrant Current’ Became Impressed Current Cathodic Protection— Part 2.” MP 64, 12 (2008): p. 34.

Editor’s Note: Mark Lewis is the unofficial curator of EBMUD’s antique corrosion test equipment and instrumentation collection, which was on display during CORROSION 2013 in Orlando, Florida, USA from March 18 to 21 in the Exhibit Hall. The collection, generously on loan from EBMUD, is currently on display at NACE International’s Elcometer Building in Houston, Texas, USA.

ABOUT THE AUTHOR

MARK LEWIS is a recently retired associate corrosion control specialist at East Bay Municipal Utility District, Oakland, California. He has been involved in cathodic protection and corrosion engineering since 1980, both within the United States and internationally. A NACE member for 35-plus years, Lewis is past chair of the NACE San Francisco Bay Area Section and received a NACE 2001 Distinguished Service Award. He has been an instructor at the Western States Corrosion Seminar at California State Polytechnic University in Pomona, California, and was a contributor to Peabody’s Control of Pipeline Corrosion, 2nd Edition and the upcoming 3rd edition of the book. He is a member of the American Water Works Association and Engineers Without Borders. Lewis attended Bethany College in West Virginia and is a graduate of Kent State University.

Filed Under: Cathodic Protection, Corrosion

An aggressive environment

Keeping tabs

Limitations of Traditional Methods

In-Field Method Sought

Pillar Findings Verified

Pipeline Coating

Cathodic Protection System Design

Right-of-Way

Stray Current Interference

Test Stations

Cased Crossings

Company Standards for Engineering and Design

Where to Go for More Information

ABOUT THE AUTHORS

Benefits of Graphene

Improved Dispersion

Corrosion Test Results

Next Steps

By: Archie Crawford

INSPECTION EFFICIENCY

CASE STUDY

CONCLUSION

ABOUT THE AUTHOR

zsharer takes on everything

Photo of the day

Quote of the Day

Recent posts

Categories

Profile

Classes

Research

Supervision

Publications