The Cathodic Protection industry is a great niche that offers entry-level opportunities with tremendous long-term advancement potential. Unfortunately, we do not have enough Cathodic Protection technicians for the short, medium, and long term.
It’s not a sexy industry, but it has great-paying jobs located in the US. Once you are trained and have a few good years of experience, entry level cathodic protection jobs enable you to pick where you want to live, enjoy tremendous job security, and gain new opportunities.
A growing regulatory environment, aging pipelines that require more frequent monitoring and servicing, aging of the existing CP technician workforce, and decades of failing to attract new people in sufficient numbers has led to a significant shortage of CP technicians.
The Great Resignation
You have probably heard about the Great Resignation, an ongoing economic trend in which employees are resigning from their jobs. According to a recent Times article, Ryan Roslansky, the current CEO of LinkedIn, defined this differently as the Great Reshuffle. We have seen a 54% increase in the number of people changing their job descriptions. For Gen Z, that increase is 80%.
The bottom line is that workers, especially younger generations, are quick to change jobs as they attempt to find their interests in the world. These changes are occurring in the high-paying technical and industrial jobs as well.
Looking for a Great Opportunity?
So, if you are looking for your next job and hoping to find something that can lead to a meaningful career, look no further. MATCOR is always looking for eager young men and women who have an aptitude for hands-on mechanical work and sound math and science skills to fill entry level cathodic protection jobs.
Travel and Training!
Early in your career, you can expect regular travel as you gain more experience – about 75% of the time. We will also provide the requisite training. Many of our technicians advanced within MATCOR or took an opportunity elsewhere to work for pipeline companies as area technicians where the travel requirements are significantly less.
If you are interested in a challenging, rewarding career in an industry where the opportunities are endless, please contact MATCOR. We are hiring! Learn more about MATCOR careers or click below to apply for open positions.
Rusty chats with Dean Lioliou, MATCOR Strategic Account Manager and AMPP Central Area Chairman
Rusty: Dean, thanks for taking a few minutes to discuss the application of VCI for cased pipeline crossings. First, what is a cased crossing?
Dean: Cased pipeline crossings are a common feature in the industry. They are used primarily at road and rail crossings.
The casing (also referred to as the encasement pipe) is a larger diameter pipe that is designed to take the loading from vehicle or train traffic on the road and absorb/deflect that loading from the carrier pipeline inside the casing.
In addition to the encasement pipe and the carrier pipe there are other key elements to a case crossing. Notably, there are non-metallic spacers that position the carrier pipe inside the encasement pipe, and dielectric end seals that prevent the ingress of water and soil. Finally, there are vent pipes on each end of the casing. These provide a warning and route product to a safe location in the event of a pipeline leak inside the sealed casing.
Pipeline Casing Vents on each side of a road crossing in Chalfont, PA
There are tens of thousands of these cased pipeline crossings throughout the United States.
Rusty: So, what are the corrosion challenges with cased crossings? What can go wrong?
Dean: Pipeline operators have found that an inordinate amount of pipeline leaks occur at cased crossings. Therefore, operators are actively looking to eliminate these whenever possible.
It is important to evaluate existing casings periodically. Two mechanisms can adversely affect pipeline integrity at cased crossing locations.
The first is a metallic short. This results from the carrier pipe shifting inside the encasement pipe. It causes a direct metallic contact between the carrier pipe and the encasement pipe.
Shorted casings can significantly impact the cathodic protection system protecting the pipeline. This is due to the encasement pipe drawing CP current away from the carrier pipe. Shorted casings also increase the risk of AC Interference, AC induced corrosion and shock hazards at the above ground vents.
The second casing failure mechanism is related to the integrity of the end seals over time. In many cases, these end seals develop leaks allowing water and soil into the space between the carrier pipe and the encasement pipe. This creates an electrolytic couple. The introduction of these contaminants can lead to accelerated rates of corrosion of the carrier pipe.
Rusty: What are my options if my casing is shorted or the carrier pipe exhibits signs of corrosion?
Dean: You can employ several strategies to address corrosion concerns with cased pipeline crossings:
Excavate ($$$). With this first approach, you dig up the casing and either remove it entirely or repair it. Repairing involves exposing one or both ends to repair the end seals and if necessary, readjust the spacers to clear the shorted condition. This is a construction intensive operation but, in many cases, can restore the cased crossing to an as-new condition.
Fill with Wax ($$). A second approach is to fill the annular space with a high di-electric wax. There are a variety of wax treatment options available. Typically, the wax is introduced through the vents and every effort is made to fill the entire annular space with the wax material.
The wax acts much like a coating covering the carrier pipe and prevents corrosion like a coating system. The industry has found that this is not always a complete solution, since voids in the wax fill can allow pockets of corrosion.
Fill with VCI ($). The third approach is to pump the annular space full of an aqueous gel or powder, or a slurry formulation of corrosion inhibitor material. The corrosion inhibitor is typically a combination of volatile corrosion inhibitor (VCI) and soluble corrosion inhibitor (SCI) that combine to stop corrosion. This method has received industry and regulatory approvals over the past decade and is gaining market share as operators become familiar with the technology and its advantages.
Rusty – How challenging is it to fill a pipeline casing with wax or with VCI?
Dean – Both operations are similar in many respects.
For both wax and VCI filling installations, repairing the existing casing is often the first step. You inspect the end seals and spacers, and where appropriate, remove and replace them.
The interior space between the carrier piping and the casing is flushed clean of dirt and other debris. Once the repairs are complete and the ends are sealed, you calculate the volume of product needed to completely fill the space between the carrier pipe and the casing.
Then the product is prepared according to the manufacturer’s recommendations. Pumping or filling the space is different for each of the type of fill, but both technologies require appropriate equipment and experienced installers.
Wax fills typically use a heated wax product for larger casings. Cold flowing wax can be used on some smaller casings.
For wax fill applications, the space between the carrier pipe and the casings must be completely flushed and cleared out during the repairing of the end seals.
Even with a well-prepared casing, achieving a complete wax fill is very difficult. Voids and gaps are typical.
One published study of 143 wax filled casings found that the average fill was 81%.
For VCI installation plans, the appropriate vapor corrosion inhibitor types and delivery methods are an important considerations. The VCI slurry needs to be mixed properly before being pumped into the casing using the appropriate pumping equipment.
Because VCI applications typically use an aqueous slurry with an experienced installer, VCI is easier to install than a similar wax application. The VCI component is designed to release from the aqueous solution after being pumped into the casing to fill all vapor spaces. Therefore, concerns over gaps and voids are non-existent.
Rusty – What about concerns with bacteria in the space between the carrier pipe and the casing?
Dean – This is an area where the two fill types differ significantly.
For wax filled casings the goal is to completely fill the space with wax displacing or encapsulating any bacteria. However as noted above, areas of incomplete fill or voids in the wax encapsulation can leave space for bacteria to continue to grow.
With VCI, the VCI chemistry increases the pH (9 to 9.5 is typical) inside the casing. This range makes it very difficult for bacteria to grow, while also neutralizing any acid secretions from the bacteria.
Rusty – Can Cathodic Protection help with protecting carrier pipes inside filled casings?
Dean – With wax filled casings, the wax has a high dielectric value and does not allow cathodic protection current to pass.
This prevents the carrier pipe and casing from draining cathodic protection current from the pipeline CP system, but it also provides no protection to the carrier pipe. The VCI gel that sets up is conductive and allows cathodic protection current flow. Some evidence supports the benefit of cathodic protection and VCI working in tandem to prevent corrosion.
Rusty – How can pipeline operators monitor the effectiveness of any cased crossing corrosion solution?
Dean – Most pipelines can be assessed using In Line Inspection (ILI). These pipelines can use smart tools with MFL, and other tools, to assess and monitor corrosion in the carrier pipe with a casing.
For wax filled casings, if ILI is not an option, there are no other good monitoring options. For pipelines that cannot be inspected using smart pig technology, conventional above ground pipeline testing technology is limited.
For VCI filled casings, we employ various technologies in conjunction with VCI including coupons, ER Probes and /or UT probes installed between the carrier pipe and the pipeline casing, to monitor the effectiveness of the VCI in the casing. These are installed and connected to RMUs for remote monitoring, or wired to a local junction box for direct reads during surveys.
Rusty – Any final comments Dean on Cased Pipeline Crossings?
Dean – Cased crossings are a challenge for pipeline owners.
Should you have any additional questions, please reach out to a MATCOR account representative for more information. As a full-service corrosion company, we have extensive experience and a wide range of capabilities including both wax and VCI installations for casings.
We recently received an inquiry on our cathodic protection FAQ asking about “the best corrosion control protection for above-ground steel tanks treating wastewater.” Well, corrosion control for water treatment facilities is such an interesting and relevant topic that it warrants an expanded response, so here goes.
Wastewater treatment facilities generally have many tanks storing and processing wastewater through multiple treatment stages. These tanks and vessels are subject to corrosion, and there are a range of strategies to extend their service life.
Corrosion Protection Strategies for Water Treatment Tanks and Vessels
These strategies fall into four broad categories: material selection, chemical treatment, coatings, and cathodic protection.
Wastewater Tank and Vessel Material Selection
From a material selection perspective, most wastewater treatment vessels are carbon steel. However, some chemical wastewater treatment facilities may require more “exotic” materials early in the treatment process due to the wastewater feed material.
Once the wastewater feed material has been treated and/or neutralized, the remaining process tanks and vessels are likely to be carbon steel construction.
Corrosion Protection via Chemical Treatment
The next broad category of corrosion control strategies is chemical treatment. While chemical treatment is an integral part of the wastewater process, specifically in terms of pH neutralization and chlorination processes, the chemical treatment performed during the treatment of wastewater is not typically intended to control corrosion.
One area where chemical treatment might be a viable corrosion control strategy is with the use of vapor corrosion inhibitors (VCIs) to protect the underside of steel storage tanks.
Coatings for Corrosion Control of Water Treatment Tanks and Vessels
The appropriate selection and application of coatings is a key corrosion control strategy for wastewater treatment facilities.
Coatings are particularly effective in protecting carbon steel structures including above ground piping, atmospheric external tank shells, wetted internal tank walls, submerged steel structures, and many other structures.
Coatings, however, are not perfect and they have a finite life. For structures that are easy to access, inspecting and re-coating are often the sole means applied to protect against corrosion.
The final corrosion mitigation strategy that can be effectively employed to protect wastewater tanks and process vessels is the use of cathodic protection.
Cathodic protection can be used to protect bare steel structures, or in conjunction with coatings.
There are two basic types of cathodic protection, galvanic (often termed sacrificial) and impressed current. Some typical cathodic protection applications in wastewater treatment facilities include protecting the soil side bottoms of large above ground storage tanks and vessels, and protecting the internal wetted surfaces of tanks and process vessels including rotating equipment such as rakes and wiper arms.
MATCOR has extensive experience designing, supplying and installing cathodic protection systems for wastewater tanks and process equipment, including several proprietary impressed current anode systems that are especially well suited for these applications.
Have questions or need a quote for corrosion prevention materials or services? Contact us at the link below. For immediate assistance, please call +1-215-348-2974.
Rusty Talks about the MATCOR PW® anode, which protects near shore structures in water from the effects of corrosion…
“It’s summertime and our thoughts go to water—backyard swimming pools, kayaking along rivers, boating on lakes, and lounging around the ocean.
Well, here at MATCOR, when we think water, we think about the very versatile MATCOR PW® ANODE system.
Check out some details below and contact our team for assistance.” — RUSTY
Corrosion Prevention of Structures in Water
The PW anode is a lightweight, long life anode system that can be installed to protect a wide range of near shore marine structures from corrosion, including:
Sheet pile walls
Wind turbine jackets and monopiles
Stationary floating vessels such as riverboat casinos and historic naval vessels
The PW anode system consists of a custom fabricated PVC anode housing and a MATCOR Mixed Metal Oxide anode assembly.
The PW Anode can be supplied with a lowering rope, eye bolt assembly, and optional weight assembly for hanging.
This versatile anode is available in a wide range of sizes and current outputs or can be custom designed for a specific application’s requirements.
To get in touch with our team of corrosion experts for more information, to ask a question or get a quote, please click below. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.
The American Petroleum Institute (API) recently issued a landmark technical report regarding vapor corrosion inhibitor (VCI) use for storage tank bottom corrosion protection (API TR 655).
VCI has been promoted as a technology for use under above-ground storage tanks for the past decade. This effort recently received a big boost with the American Petroleum Institute’s publication of its long-awaited technical report on VCI.
MATCOR has been an early adopter of VCI technology as we believe that it can be an important and effective component in a corrosion prevention program for tank bottoms. We have partnered with Zerust to be an authorized distributor and installer of VCI products for tank and other applications.
We are excited that API has led the way on recognizing VCI technology, and we would expect that other organizations–AMPP for one–will adopt similar guidelines and recommendations.
For a more detailed review of the technical report, visit our VCI partner company Zerust’s summary at the link below:
To get in touch with our team of cathodic protection experts for more information, to ask a question or get a quote, please click below. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.
The Jolly Green Giant, the Pillsbury Doughboy, the Geico Gecko, Ronald McDonald, the Energizer Bunny… please all step aside and make room for the world’s newest, and soon to be famous, icon, RUSTY the MATCOR Chili Pepper spokesperson.
“My mission is to protect the world’s infrastructure from the evil scourge of corrosion.”
RUSTY is not trying to sell vegetables, biscuits in a can, hamburgers or batteries. No, RUSTY’s mission is to protect the world’s infrastructure from the evil scourge of corrosion. We look forward to RUSTY’s corrosion adventures.
A big shout out to Ted Morris of Nustar Energy, a 38-year veteran of the pipeline industry who has spent the last 29 years in Corrosion Control. Ted Morris was the grand prize winner of our “Name MATCOR’s Icon Contest”. The contest garnered a tremendous number of very thoughtful entries, but RUSTY was an immediate favorite of the selection committee. Ted will be retiring in the near future, having served the industry well, and we at MATCOR dare say that RUSTY may prove to be one of his great legacies. Thanks Ted!
A very close second place in the naming contest goes to Fernando Villamizar Ariza of Ingacor Colombia, with his name entry of “Cowboy Rust”. Thank you Fernando!
There were many honorable mentions and we thank everyone for the effort and creativity.
AC Corrosion Implications for New and Existing Pipelines
AC inference can result in significant and rapid corrosion and is a threat that must be considered for both new and existing pipelines. NACE provides a detailed standard practice to specifically address the threat of AC corrosion; however, it is very important for corrosion professionals to understand the guidelines and their implication for pipeline design, monitoring and risk assessment.
Criteria for Control of AC Corrosion
Approved in December of 2017, NACE SP21424-2018-SG “Alternating Current Corrosion on Cathodically Protected Pipelines: Risk Assessment, Mitigation, and Monitoring” provides supplemental guidance for the control of corrosion for cathodically protected pipelines that are subject to influence from close proximity high voltage AC transmission systems. This standard practice expands significantly on the earlier standard SP0177 “Mitigation of Alternating Current and Lightning Effect on Metallic Structure and Corrosion Control Systems” and introduces new criteria for addressing AC Interference for cathodically protected pipelines.
The criteria detailed in Section 6 of SP21424 allow for two means of assuring that effective AC corrosion control has been achieved:
Document that the corrosion rate is less than the common benchmark for effective corrosion control of 0.025mm/y (1 mil per year). This can be achieved using weight loss coupons, corrosion rate probes or through in-line metal loss inspection tools—provided the inspection tool resolution is sufficient to detect small-diameter attacks such as AC corrosion. This approach is great for areas where AC corrosion risk is considered minimal. Essentially this says we don’t expect AC corrosion and we will demonstrate that AC corrosion is not occurring with a modest testing program. In those areas where AC corrosion can be reasonably anticipated; however, a second criteria is provided.
For areas where AC corrosion mitigation can be anticipated, the criteria for effective control is based on reducing the time weighted average AC current density below a specific threshold that varies depending on the DC cathodic protection current density as follows:
Where the DC current density is controlled to less than 1A/m2, the AC current density should be controlled to less than 100 A/m2
Where the DC current density is not controlled to less than 1A/m2, the AC current density should be controlled to less than 30 A/m2
This first criteria, much like the first criteria for
cathodic protection in SP0169-2013, allows for a prove-it type criteria based
on documenting that corrosion is not occurring.
The second criteria, unlike the criteria for cathodic protection, is not based on a measured potential, but is instead based on measuring current density on a time weighted basis. Not just one type of current density must be considered, but instead the criteria requires evaluation of the time weighted average of both AC and DC current densities.
Current Density vs. Polarization
While conventional criteria associated with control of corrosion through the application of cathodic protection is based on shifting potentials on the pipeline, the control of AC induced corrosion is based on limiting current density criteria on a time weighted basis. These requirements are quite different—and when AC corrosion control is a concern this will require a change in how pipelines are monitored, a shift in CP design philosophy in those areas where AC corrosion is a concern and some understanding of the impact of AC mitigation.
Pipelines are typically designed to monitor polarization levels with the installation of test stations at frequent intervals to support measuring polarization levels at the test station and to facilitate continuous close interval polarization surveys. When AC corrosion is a threat, the monitoring provisions need to shift from providing connections to the pipeline for polarization measurements to the installation of coupon test stations to facilitate current density measurements.
CP System Design Philosophy
The primary concern with cathodic protection design is typically making sure that more than enough current is available to ensure minimum polarization levels (either 100mV shift or -850mV off potential) are met along the length of the pipeline. This often means the CP system is over-designed and overdriven—there is little cost associated with over-polarizing some segments of the pipeline to ensure that the entire pipeline meets the minimum requirements. If the pipeline does not meet criteria in some locations, the first step was to push more current over the entire system until those low potential sections also met the polarization criteria. Little consideration is given to concerns with areas receiving too much current.
However, when we overlay the concerns with AC induced corrosion and the desire to control the DC current density below 1A/m2 or face the requirement to mitigate to a much lower threshold for AC current density, it becomes a more challenging CP system design. Now the CP system designer must:
Understand the interaction between cathodic protection system design and its impact on AC mitigation requirements
Provide provisions to monitor (on a time-weighted basis) both AC and DC current densities
Give consideration to being able to intentionally control DC current densities in those AC corrosion risk corridors—this might require additional CP stations to reduce over-polarization, the strategic use of isolation devices to create DC current density control zones, and the use of auto-controlled rectifiers to vary current output to control DC current densities. Improving the control of DC current density can significantly reduce the amount of AC mitigation that might be required.
For existing pipelines, the AC mitigation requirements should be based on some actual data on the CP current density in specific areas of concern. Current densities are typically highest closer to a CP station and in areas of low soil resistance. Another factor that can impact current density is the quality of the coating. Poorly coated pipelines have more uniform and lower CP current densities while well coated pipelines may have higher localized current densities because of the small size and infrequent nature of the coating defects. For new pipelines, the AC mitigation designer should be careful to presume that the higher AC mitigation threshold based on controlling DC current density can be applied without consultation with the CP system designer to assure that the design provides for sufficient control of CP current density.
The use of AC test stations with specific AC and DC current density coupons is necessary to ensure that localized conditions do not exist where AC corrosion risk is not properly being controlled. These coupon test stations should be equipped with remote monitoring to allow for data polling at regular intervals to allow for time-weighted averaging of the current density data. Mobiltex recently introduced a new series of Test Station RMUs specifically designed to be installed in a conventional cathodic protection test station. These remote monitoring units can record and transmit AC and DC current density information from AC coupon test stations.
The frequency and location of these coupon test stations is a design issue. It is critical to note that within areas subject to AC corrosion risk, coupon test stations should be installed at all significant “inflection” points where predictive modeling and/or AC mitigation design experience would dictate elevated risk including:
Entrance/exit points for HVAC / pipeline collocations
Low soil resistivity areas or areas with notable differential soil resistivity changes within the collocation
HVAC phase transpositions
The criteria for AC corrosion control are different than those typically associated with conventional cathodic protection to control corrosion. The requirements for monitoring both AC and DC current densities are interrelated and can have a significant impact on the AC mitigation requirements and on the cathodic protection system design and operation. Understanding this relationship between AC and DC current density and properly controlling each is critical to properly controlling AC corrosion risk.
For information on MATCOR’s AC mitigation solutions or for assistance setting up testing to prevent AC corrosion, please contact us at the link below.
This article provides an overview of pipeline corrosion in the United States, the two categories of corrosion in pipelines and the primary methods of prevention.
Corrosion of Pipelines in the United States
The United States has over 2,225,000 kilometers of pipelines, the vast majority of which are transporting oil and natural gas. No other country comes close—Russia is a distant second with approximately 260,000 km of pipelines. The US Pipeline network consists of hundreds of public and private companies that own and operate these pipelines within a national regulatory framework managed by the US Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA). While pipelines have proven to be exceptionally efficient and very safe—pipelines are roughly 70 times safer than trucks1 and 4.5 times safer than rail2—the aging network of pipelines continues to be of concern because much of the nation’s pipelines are at least 50 years old and getting older.
Corrosion is one of the biggest problems contributing to leaks and ruptures of pipelines. Corrosion is the natural process where materials made from metal electrochemically react with the environment and deteriorate. Without proper engineering and preventative maintenance, this deterioration from the natural process of corrosion will result in an increasing frequency of pipeline incidents. The good news is that with proper pipeline monitoring and maintenance, corrosion is completely manageable. Operators can utilize existing technologies to ensure the integrity of these critical assets and prevent damaging failures.
Two Categories of Corrosion in Pipelines
Pipeline corrosion can be broken down into two primary categories. Internal Corrosion, which causes approximately 12% of all incidents, occurs on the inside of the pipeline, while External Corrosion, which results in approximately 8% of all pipeline incidents, occurs on the outside of the pipe.
Pipeline Corrosion Protection Strategies for External and Internal Corrosion
Two primary mitigation strategies are employed to prevent external corrosion of pipelines:
When these mitigation strategies are properly employed, monitored and maintained, steel pipelines can last indefinitely. While this sounds simple, pipeline coatings are never perfect and are themselves subject to damage during construction and degradation over time, while cathodic protection is a complex process that requires continuous monitoring and extensive testing, combined with regular maintenance to be effective.
Internal corrosion, in most cases, is a result of contaminants naturally occurring in the product being transported by the pipeline. Common contaminants include oxygen, hydrogen sulfide, carbon dioxide, chlorides, and water.
Many variables can affect the nature and extent of a particular internal corrosion reaction on a pipeline:
The combination of contaminants within the pipeline
Operating pressure and velocity
Pipeline geometry and holdup points
The primary pipeline internal corrosion prevention strategies include:
Controlling or minimizing contaminants prior to transporting them in the pipeline
Internal pipeline coatings
Injection of corrosion inhibitors
Increased frequency of internal pipeline cleaning to remove the accumulation of contaminants
For controlling both external and internal corrosion, regular monitoring and testing programs combined with the appropriate mitigation strategies, are a critical part of any pipeline integrity management program. When performed properly, corrosion can be effectively controlled, assuring that pipelines remain safe from corrosion indefinitely.
To get in touch with our team of cathodic protection and AC mitigation experts for more information, to ask a question or get a quote, please click below. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.
Are Vapor Corrosion Inhibitors Magic Dust or a Viable Corrosion Prevention Tool?
This article is intended to provide a basic primer on vapor corrosion inhibitors for use in corrosion prevention for above ground storage tanks and address where this technology stands.
There has been a significant effort within the oil and gas world to either promote or repudiate the use of vapor corrosion inhibitor technology (VCI) for tank bottom plate corrosion control. As a leader in the above ground storage tank corrosion control industry, MATCOR has partnered with Zerust® Oil & Gas to make VCI options available to our customers that are interested in applying this technology as part of their corrosion mitigation approach.
How Vapor Corrosion Inhibitors Work – Video Courtesy Zerust® Oil & Gas
What are vapor corrosion inhibitors and how do they prevent corrosion?
VCIs are chemical compounds that are released into a confined space, such as the underside of a tank bottom, and diffused through the sand pad material to reach the metal surface. These compounds are adsorbed onto the metal surface forming a strong bond that promotes and maintains a passive oxide layer on the metal and blocks other contaminant molecules from reaching the surface.
Are VCIs a non-permanent solution?
Corrosion protection using VCIs requires sufficient chemical concentration to thoroughly diffuse across the entire tank bottom surface area. The VCI has a finite life, after which it ceases to remain active. When this occurs, further chemical is required to replenish the spent VCI. The frequency of VCI replacement will vary depending a range of factors:
The rate of leakage through the tank chime
The operating temperature of the tank
The sand properties
The amount of chemical initially applied
As VCI technology is still in the early phase of adoption, the typical replenishment frequency remains one of the big unknowns. A conservative estimate would be a minimum of 3-5 years’ service life before replenishment although a least one source has reported upwards of 15 years of effectiveness.
How is VCI applied initially for above ground storage tanks?
There are a variety of application technologies depending on the application and whether the tank is new construction, existing tank during inspection, a tank that is in-service or a double floor tank. Other considerations include the substrate material or concrete pad. The VCI chemical can be provided in a powder or liquid form. Whatever system is utilized to deploy the VCI, consideration should be given to how it will be replenished over the life of the tank.
Can vapor corrosion inhibitor technology be used in lieu of cathodic protection?
Practically speaking, most tank operators are not looking to replace cathodic protection but are considering VCI as a supplement to cathodic protection or as a short-term solution for inadequate or depleted CP systems until a replacement CP system can be installed.
Can VCI be used as a complement to cathodic protection?
This is where VCI provides an exciting opportunity to supplement cathodic protection. While cathodic protection has a proven track record in corrosion prevention for tank bottoms, there are limits to the effectiveness of cathodic protection. Cathodic protection only works when the tank bottom is in intimate contact with the sand bottom. Localized corrosion can occur wherever there are air gaps under the tank bottom. These can occur due to flexing of the tank bottom, imperfections in the plate steel, lapping of the plate steel, poor compaction of the sand bottom, presence of aggregate or non-conductive materials such as asphalt or oil, and at crevices in the tank ring wall. These are all areas where cathodic protection may not be effective and the proper application of VCI would be an excellent means of providing corrosion protection in these localized areas. Cathodic protection and vapor corrosion inhibitors are symbiotic. CP current distribution has been shown to improve in the presence of VCI.
How do I monitor that the vapor corrosion inhibitor is working?
When applying VCI to a tank bottom, coupons, ER probes or UT probes installed under the tank are used to measure the effectiveness of the VCI and to alert the owner when the VCI requires replenishment. One of the concerns with using ER probes to measure corrosion rates under tanks is that ER probes provide an average corrosion rate and not localized pitting rates. It is understood that pitting corrosion is the dominant factor in tank bottom corrosion related failures and pitting rates can be significantly higher than average corrosion rates. There is a distinct correlation between average corrosion rates and pitting corrosion rates and the ER probes can be used to infer changes in the pitting rates.
Where do vapor corrosion inhibitors stand with industry standards and regulations?
According to API 651, there are several situations where CP is not recommended for specific tank foundation designs. In some of these designs, PHMSA recognizes that CP is not feasible. In these cases, VCI can be a viable option. API 2610, the Tanks and Terminals standard outlines the use of VCI for tank bottoms in section 12.5. API 651, the CP standard, is being updated currently and VCI is being included as an option in this document. The State of Florida has identified that VCI can be used in tandem with CP or a standalone solution, for more than 6 years. NACE is currently working on publishing a standard “NACE TG543”, which is a comprehensive document on the application of VCI under tank floors. PHMSA is currently reviewing Special Permit requests for the use of VCI without a functioning CP system. If a non-regulated tank’s CP system is not meeting criteria, or has depleted, but the tank is still a few years from its next inspection, VCI can be applied to protect the floor until CP system repairs can be economically accomplished.
What independent published studies exist supporting VCI?
A 2018 study published by PRCI provides the strongest validation of the effectiveness of VCI and concluded that:
VCIs were found to be effective in mitigating pitting of steel exposed to corrosive sand but was not as effective as CP for reducing pitting corrosion. The study confirmed the importance of using the manufacturer’s recommended concentrations, as low levels of VCI was found to be ineffective.
ER Probes can be used to monitor the efficacy of VCIs
VCIs are compatible with impressed current cathodic protection; however, VCIs change the native potential of the steel and this must be considered when selecting CP criteria in accordance with NACE SP0193
In conclusion, the application of VCI is a viable tool in our corrosion tool box that should be considered in conjunction with cathodic protection for critical service applications and as a standalone solution in some applications.
To get in touch with our team of cathodic protection experts for more information, to ask a question or get a quote, please click below. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.
Did you know that corrosion costs us an astounding 2.5 trillion dollars globally?
Not to mention corrosion can cost lives and jobs…
Today is corrosion awareness day, so we thought it would be a good idea to reiterate the importance of the NACE IMPACT (International Measures of Prevention, Application, and Economics of Corrosion Technologies) study released in 2016.
According to the study, most corrosion failures, and nearly all catastrophic corrosion failures are preventable. And nearly $875 billion can be saved through the right prevention and risk analysis efforts.
Through the IMPACT study, NACE determined that in order to reduce the astronomical cost of corrosion, we would have to change how decisions are made regarding corrosion. We must not only continue to develop corrosion control methods and technology, but we must utilize organizational management systems and risk tools throughout all levels of an organization to achieve the greatest success in saving lives, jobs and money.