All posts by MATCOR

Where to Find MATCOR in 2023?


MATCOR’s industry event calendar is jam-packed, starting right after the New Year!

You can find us at these upcoming events:

Contact us at matcorsales@matcor.com or visit our events page for more information to meet up at any of these events.

If you need assistance, please contact us. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.

Contact a Corrosion Expert

Steel Pile Corrosion: Protecting Our Solar Infrastructure

The US is constructing an increasing number of very large solar power generation farms, which brings about the question–what about corrosion? This new article explores solar farm steel pile corrosion. Do the buried galvanized steel piles supporting solar arrays meet service life requirements?


How do you protect the buried galvanized steel piles that support solar arrays from corrosion?
Galvanized steel pile corrosion can occur in as little as five years.

Big Footprint

We continue to construct an increasing number of solar power generation facilities. The United States plans even more as it continues to pursue policies encouraging renewable energy development.

The economies of scale make these facilities more competitive with other electrical generation technologies. These utility-scale solar farms have a capacity of anywhere from 1 MW to 1000+ MW. One feature of these solar farms is their physical footprint. The average solar farm requires 6-8 acres of land to support the tens of thousands of PV cells necessary to generate electricity at this scale.

For example, the Mammoth Solar Farm project in northern Indiana, once completed, will have a generation capacity of 1650 MW. And it will cover an area of 13,000 acres and use more than 2.85 million solar panels. This is the largest project in the US and should become fully operational in 2024.

Steel Piles That support Solar Arrays: What About Corrosion?

Given these facilities’ size, cost, and anticipated service life, a fair question to ask during the design phase is: what about corrosion? Specifically, the buried support structures that hold the solar arrays in place.

Typically, construction crews drive or screw galvanized steel piles into the soil to support the solar panels’ frames. Galvanized steel piles generally have a good service life in most environments for this application. However, as with all steel structures, they are subject to corrosion. Eventually, steel pile corrosion will adversely affect the support structure’s integrity.

Therefore, solar farm operators should consider the impact of corrosion on the service life of the galvanized piles during the project’s design phase.

Start with The Piling Details

The first step in the corrosion assessment process is to know your piles.

Any sizable solar farm project will require thousands of steel piles. The type of pile and the galvanizing thickness significantly impacting the project cost.

Unfortunately, structural engineers often do not consider corrosion when sizing the piles. They are keenly aware of loading concerns and select the pile to use based on a detailed soil load-bearing analysis and wind load analysis. They consider how big and how deep the piles need to be to support the predicted mechanical loads. This is often the only consideration. As a result, any conversation regarding corrosion is often relegated to – don’t worry, the piles are galvanized.

How Corrosive is the Environment?

But even galvanized piles are subject to corrosion, and in a highly corrosive environment, that service life might be much lower than expected. Therefore, additional corrosion mitigation measures, such as cathodic protection, might be warranted in some cases.

Given the massive footprint covering hundreds to thousands of acres these sites require, a thorough corrosion assessment for the entire area is warranted.

Typically, Geotech firms are contracted early in the project to perform detailed soil testing across these sites. This testing provides the requisite soil load capacity data to design the structural supports properly. While performing the site-wide testing, these firms will often perform some representative soil resistivity testing. While these sample soil resistivity tests may indicate the soil’s corrosiveness, they are often insufficient to evaluate correctly.

MATCOR Study: A Soil Testing Analysis

In one study performed by MATCOR, a comprehensive soil testing analysis found that much of a solar farm was in moderately corrosive soils. Still, a significant part of the facility was in very corrosive soils. In addition, the service life calculations varied significantly for the piles depending on their location within the solar farm. Estimated life ranged from 17 years to 30+ years.

Another factor in the service life calculations is the anticipated degradation of the piles during installations. The impact on the zinc coating can vary significantly depending on the soil characteristics.

MATCOR provides comprehensive soil resistivity testing services.

Steel Pile Corrosion: How Long Will the Steel Piling Last?

The first phase of the service life of driven steel piles is the outer zinc layer of the galvanized steel pile. Zinc acts as both a coating and a galvanic anode. As the zinc layer is consumed, the underlying steel substrate is exposed. Therefore, the estimated service life, in simple terms, is the anticipated service life of the zinc coating plus the expected service life of the steel substrate.

We define the service life for solar structural galvanized steel piles as some allowable percentage thickness loss before compromising the pile’s integrity.

There are a lot of factors that affect the pile’s corrosion rate, including:

  • Presence of copper grounding bonded to the pile
  • Degradation of the zinc coating during the driving of the pile
  • Differential soil resistivity strata
  • Differential oxygen levels/aeration
  • Location of the water table in the area of buried piles

One of the biggest drivers of accelerated corrosion for piles is the presence of copper grounding. When steel piles are connected to a copper grounding grid, their service life can be significantly reduced as the zinc coating layer and the underlying steel substrate act as galvanic anodes. This can be very impactful in low soil resistivity environments.

Significant Steel Pile Corrosion Can Occur in as Little as Five Years

In some extreme cases, corrosion of the galvanized piles can be structurally significant in less than five years of service. In most cases, the service life in corrosive environments can be anywhere from 10-25 years of service. A service life of more than 50 years in low-corrosivity soils might be achievable.

Solar farms are a growing part of our electrical generation portfolio and will continue to see substantial investments in the next several decades. Given the footprint and cost of these facilities, design engineers should seek corrosion assessments from qualified corrosion engineering firms such as MATCOR to confirm that the piling systems used to support the solar arrays meet the facilities’ service life requirements.

If you need assistance with galvanized steel pile corrosion protection, please contact us. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.

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Cathodic Protection Connections: Exothermic Welding vs Pin Brazing


Exothermic welding and pin brazing are two methods to connect a cathodic protection system to the protected steel structure. These connections route back to the rectifier to complete the circuit for an impressed current cathodic protection system. Or they connect to the anode lead cable in a galvanic anode system. They are an essential part of any cathodic protection system.

Exothermic welding and pin brazing cathodic protection connections resulted from historical needs in the railroad industry. In addition, both have a long history of use in the cathodic protection industry.

MATCOR has the experience and capability to use either connection technology depending on the client’s specifications or requirements. In the absence of a customer preference, MATCOR generally defaults to pin brazing for CP applications.

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Exothermic Welding for CP

The older of the two technologies is Exothermic or Thermite welding. More prevalent in United States specifications, this technology utilizes the heat generated from the reaction when you ignite a mixture of Aluminum powder and Iron Oxide III (ferric oxide Fe2O3). The resulting reaction is vigorously exothermic, generating temperatures more than 2000 C – sufficient to create molten iron.

Initially developed by German Chemist Hans Goldschmidt in 1893, exothermic welding connected steel rails on the Essen train line. In the 1930s, the technology gained widespread use for connecting bonding cables to railroad ties. This was thanks to the efforts of Charles Cadwell, a physicist for the Electric Railroad Improvement Corporation (ERICO.)

The Cadweld connection process has changed very little over time. It involves cleaning the structure surface down to the bare metal and laying the connector attached to the structure in a graphite mold. Next, you place an appropriately sized cartridge containing the aluminum powder and ferric oxide ready for igniting in the mold. Finally, using an ignitor sparks the reaction. As a result, an iron slug melts and flows over the copper conductor, welding it to the steel surface.

Cathodic Protection Connections: Exothermic Welding vs Pin Brazing

Pin Brazing for CP

Like exothermic welding, the railroad industry developed the second standard cable-to-structure technology—pin brazing.

In Sweden in the 1950s, high heat from thermite welding caused grain growth in the copper cable. As a result, connections to the rails were subject to fatigue failures from cyclical stresses associated with the movement of the rails as trains passed.

To solve this issue, the railroad industry developed lower-temperature joining technology using brazing. Brazing uses a range of silver-based filler metals to achieve the bond. These filler metals have a melting temperature between 620 and 970 C – well below the temperatures reached during exothermic welding.

Commonly specified in European standards, the pin brazing process has remained fundamentally the same since the 1950s, with some refinements to the equipment.

The pre-assembled welding pin and the pin brazing gun are the keys to pin brazing. The pin consists of a stud with a defined amount of flux encapsulated in the brazing metal. When you press the trigger, current flows through the pistol via the pin to the steel pipe. At the same time, an electromagnet is energized, drawing the pin holder and pin away from the steel surface, forming an electric arc. The arc heats the steel and starts to melt the tip of the pin. As a result, it causes the flux to melt and flow onto the steel. The electromagnet de-energizes when the current flow ceases, and the spring forces the molten stud onto the fluxed pipe surface. With the arcing stops, solidification is very rapid.

Comparing Exothermic Welding and Pin Brazing for Cathodic Protection Connections

Safety

Both methods are safe procedures when trained personnel follow the correct procedures. Neither method poses any environmental threat, although users should be sure to properly store and handle the thermite powder charges. For thermite welding, the process can be sensitive to moisture which could vaporize on contact with the molten iron slug. As a result, the potentially dangerous hot metal can be spat out of the mold. For this reason, you should conduct the pin-brazing process in damp environments and offshore applications.

Cathodic Protection Connection Reliability

Both connections have been used extensively and are widely accepted in cathodic protection. Unfortunately, no published data detailing the reliability of either connection technology exists, and reports of Cathodic Protection connection failures are infrequent and anecdotal. Lab testing on tensile load indicates that pin brazing is a slightly stronger bond; however, the loads at failure far exceeded any load possible in regular service. Nevertheless, both techniques will provide reliable, low-resistance connections when properly performed.

Metallurgical Effects

Both processes are thermal and will affect the metallurgical condition of the pipe. Many piping codes typically advise that the design consider the impact of any changes in the parent metal due to localized heating during the attachment process. Microhardness testing has shown that both connections are safe for the normal range of carbon steel pipe; however, some consideration must be given to thin-walled structures. Pin brazing results in lower temperatures and greater process control and should be considered for all thin-walled steel and alloyed piping.

Effects of Cathodic Protection Connections on Internal Coating and Fluids

Using thermal bonding to the exterior pipeline wall of a pipeline filled with highly flammable hydrocarbons requires some consideration. In addition, where internal coatings exist, it is reasonable to question whether or not thermite welding or pin brazing might damage the interior coating. Based on testing, the inner wall temperature rises more with thermite welding than with pin brazing; however, neither method’s results were sufficient to give any reason for concern.

If you need assistance with a cathodic protection assessment, please contact us. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.

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[ARTICLE] Cathodic Protection Failure

Restore, replace, extend, or do nothing?

In the Autumn 2022 issue of Tanks and Terminals, MATCOR’s Ted Huck delves into four strategies you can take when your cathodic protection system is no longer working.


MATCOR provides industry-leading cathodic protection and AC mitigation solutions to tank and terminal operators around the globe.


If you need assistance with a cathodic protection assessment, please contact us. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.

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AC Mitigation: 4 Approaches

AC mitigation is the process of designing and applying pipeline grounding systems to:

  • Prevent voltage spikes during fault conditions
  • Reduce AC current density to protect against AC-induced corrosion
  • Maintain AC step and touch potentials below 15 Vac to protect personnel from shock hazards

AC mitigation prevents voltage spikes and corrosion and protect workers

Pipelines that parallel overhead high-voltage AC transmission power systems are subject to AC interference. AC interference has several potential adverse impacts on the safety of personnel and pipeline integrity. Assuming that these conditions exist, there are several measures that can be taken to mitigate the AC interference present in a pipeline. These AC mitigation strategies are detailed in various international standards including two AMPP (formerly NACE) standard practices: SP0177-2014 Mitigation of Alternating Current and Lightning Effects on Metallic Structures and Corrosion Control Systems, which primarily focus on safety for operators and other people working on or near pipelines subject to AC current and lightning events, and SP21424-2018. This addresses the guidelines and procedures for risk assessment, mitigation, and monitoring of AC-induced corrosion on pipelines.

There are four basic approaches to mitigating AC Interference. These mitigation strategies are:

1. Fault Shielding

One of the primary concerns with high-voltage AC transmission systems parallel to buried pipelines is the risk that a fault condition at a transmission tower could result in the rapid discharge of fault current near the pipeline. This could lead to direct current arcing in soil – rare but very damaging. More common is the rapid ground potential rise that subjects the pipeline coating to large voltage gradients that result in coating damage. Fault shielding is a suitably designed grounding system that is installed between the tower footing and the pipeline that acts to shield the pipeline and shunt harmful currents away from the pipeline by providing a low resistance path to earth. This typically takes the form of a parallel shielding wire, either copper or zinc, connected to the pipeline.

2. Gradient Control Mats

When high levels of AC voltage are present on a pipeline, either during a fault condition or as the result of an inductive coupling during normal steady-state operations, personnel in close proximity to and/or touching any above ground or exposed appurtenance are at risk for electrical shock step or touch hazards. Installing a gradient control mat, which is a system of buried bare conductors, typically galvanized steel, copper, or zinc, connected to the structure, provides localized touch and step voltage protection by creating an equipotential area around the appurtenance.

3. Lumped Grounding Systems

Lumped pipeline grounding systems consist of shallow or deep localized grounding conductors that are connected to the structure at strategic locations to reduce the AC voltage level along the pipeline. This provides protection to the structure during steady-state or fault conditions from the nearby electric transmissions.

4. Gradient Control Wire

Gradient control wire grounding systems function the same as the lumped grounding system. With this type of system, long continuous grounding conductor(s) are installed horizontally and parallel to the pipeline. They are strategically located and sized to reduce the AC-induced voltage along the pipeline during steady-state or fault conditions from the nearby electric transmission.

For mitigating high levels of AC-induced voltage along a pipeline, gradient control wires are the most common form of AC mitigation. Hybrid systems that combine lumped grounding systems with gradient control wires are also common. Regardless of the type of pipeline grounding system used, all of these AC mitigation approaches involve installing a grounding device to the affected structure to allow AC-induced current and fault current to be quickly discharged off of the pipeline.

AC Modeling

Prior to installing an AC mitigation system, it is common to use complex AC modeling software to evaluate the impact of fault currents and estimate the steady state induced currents that can be expected along the pipeline. This information is used to determine the quantity and location of mitigation required based on numerous factors, including the resistivity of the soil, the physical characteristics of the pipeline, the operating parameters of the HVAC transmission system and the spatial distances between them.

Engineered AC Mitigation Systems

Based on a thorough assessment of the pipeline and high voltage AC transmission system interaction, including modeling results when available, an AC mitigation system is designed by experienced engineers familiar with the mitigation strategies detailed above. This engineered AC mitigation system would detail the quantity and location of grounding installations required for a specific application. MATCOR’s MITIGATOR is an example of this type of AC mitigation system.

Other features of an engineered AC Mitigation system include:

Special Backfill

It is quite common to install the grounding conductor in a special backfill material. The purpose of the backfill can vary depending on the conductor material chosen and the type of backfill used. The benefits of various types of AC mitigation backfill include:

  • Enhanced surface area – conductive backfills such as carbon or conductive concrete are used to effectively increase the surface area of the grounding conductor reducing the overall resistance to earth.
  • Corrosion/Passivation Protection – some backfills are designed to protect the grounding conductor from corrosion or passivation of the conductor that could adversely affect the life or impede the performance of the grounding conductor.
  • Hydroscopicity – some hygroscopic backfills readily attract and retain water from the environment, helping to maintain a low uniform resistance around the grounding conductor.

Solid State Decouplers

These devices are almost always used in conjunction with AC mitigation systems and are usually installed wherever the grounding system is connected to the pipeline. These devices are designed to allow AC current to flow off the pipeline during steady-state or fault conditions while blocking all DC current. This effectively isolates the pipeline’s cathodic protection (CP) system from the AC mitigation system, preventing the mitigation system’s grounding conductors from taking CP current from the pipeline.

AC and DC Coupons and Remote Monitoring Test Stations

Regardless of which mitigation strategies are being used, it is important to
design and install a monitoring system to be able to affirm compliance with the AC Mitigation criteria established in SP21424-2018. This includes monitoring both AC and DC current densities. The monitoring system should be designed to collect representative data at regular and continuous intervals.  This usually includes remote monitoring of AC corrosion criteria.

MATCOR provides complete AC Mitigation solutions including design, supply of materials, turnkey installations, and comprehensive testing services.


PHMSA Mega Rule Update

Just last week – PHMSA issued its final rule expanding Federal pipeline safety oversight to all onshore gas gathering pipelines. Known as the PHMSA Mega Rule, this ruling has tremendous impact on the US pipeline industry, adding significant scope to the current pipeline integrity management requirements.

The final rule affects tens of thousands of miles of previously unregulated gas gathering pipelines. Also, pipeline operators have to report safety information for more than 450,000 miles of gas gathering lines governed by Federal reporting requirements.

Some of the impacts of the PHMSA MEGA rule on the industry include:

  • An approximately 20% increase in the number of regulated pipelines in the United States
    The addition of 20% more regulated pipelines had a significant impact on an industry where highly qualified integrity professionals and related services were limited in supply and the industry was already struggling to meet demand.  These additional pipelines required significant integrity resources.
  • Expedited reporting requirements
    The time restrictions for implementing the new rule were accelerated, with initial reporting requirements having started in July 2020. The time to comply with these regulations was reduced by 20% from the initial draft order timeline.
  • Increased cathodic protection requirements
    Many pipelines that previously were not regulated and have not had proper CP required a properly designed, maintained, and tested cathodic protection system.

What Does The Final Rule State?

The final rule expands PHMSA’s Part 192 to gas gathering lines that fall within Class C, a new pipe category. Within Class C, the requirements for operators vary based on a risk scale. The risk scale varies with pipeline diameter and proximity to people (BIHO – buildings intended for human occupancy).

For pipelines that meet these criteria, the requirements for corrosion control (CFR 49 Part 192 Subpart I – Requirements for Corrosion Control) will now apply to these previously unregulated lines. The Part 191 incident and annual reporting requirements have expanded to include all previously uncontrolled gas gathering lines, regardless of Class.

How Can MATCOR Help Company Operators Comply with PHMSA Mega Rule?

Gas producers and midstream gas pipeline operators have to reevaluate their pipeline networks to incorporate any previously uncontrolled pipelines to comply with CFR 191 and CF 192. MATCOR offers a wide range of cathodic protection and integrity services to help our customers including:

It is going to continue to be exciting times in the midstream market.

Read or download the full PHMSA final rule.


If you are looking for help with AC Mitigation systems or services, please contact us. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.

Contact a Corrosion Expert

PHMSA Mega Rule – August 2022 Update

PHMSA Mega Rule Update

Just last week – PHMSA issued its final rule expanding Federal pipeline safety oversight to all onshore gas gathering pipelines. Known as the PHMSA Mega Rule, this ruling has tremendous impact on the US pipeline industry, adding significant scope to the current pipeline integrity management requirements.

The final rule affects tens of thousands of miles of previously unregulated gas gathering pipelines. Also, pipeline operators have to report safety information for more than 450,000 miles of gas gathering lines governed by Federal reporting requirements.

Some of the impacts of the PHMSA MEGA rule on the industry include:

  • An approximately 20% increase in the number of regulated pipelines in the United States
    The addition of 20% more regulated pipelines had a significant impact on an industry where highly qualified integrity professionals and related services were limited in supply and the industry was already struggling to meet demand.  These additional pipelines required significant integrity resources.
  • Expedited reporting requirements
    The time restrictions for implementing the new rule were accelerated, with initial reporting requirements having started in July 2020. The time to comply with these regulations was reduced by 20% from the initial draft order timeline.
  • Increased cathodic protection requirements
    Many pipelines that previously were not regulated and have not had proper CP required a properly designed, maintained, and tested cathodic protection system.

What Does The Final Rule State?

The final rule expands PHMSA’s Part 192 to gas gathering lines that fall within Class C, a new pipe category. Within Class C, the requirements for operators vary based on a risk scale. The risk scale varies with pipeline diameter and proximity to people (BIHO – buildings intended for human occupancy).

For pipelines that meet these criteria, the requirements for corrosion control (CFR 49 Part 192 Subpart I – Requirements for Corrosion Control) will now apply to these previously unregulated lines. The Part 191 incident and annual reporting requirements have expanded to include all previously uncontrolled gas gathering lines, regardless of Class.

How Can MATCOR Help Company Operators Comply with PHMSA Mega Rule?

Gas producers and midstream gas pipeline operators have to reevaluate their pipeline networks to incorporate any previously uncontrolled pipelines to comply with CFR 191 and CF 192. MATCOR offers a wide range of cathodic protection and integrity services to help our customers including:

It is going to continue to be exciting times in the midstream market.

Read or download the full PHMSA final rule.


If you are looking for help complying with the PHMSA’s new Mega Rule and its additional requirements, please contact us. We will respond by phone or email within 24 hours. For immediate assistance, please call +1-215-348-2974.

Contact a Corrosion Expert

Welcoming Kyle Myers and Matt Waldrop to the MATCOR Sales Team!

This month we welcome two outstanding cathodic protection professionals to our sales team.

Kyle Myers

kyle-myers-matcor

Kyle brings a rich background in engineering and field work, as he previously worked in the oil and gas industry.

He assisted corrosion technicians in the field and worked as a pipeline integrity engineer for an inline inspection company.

He most recently worked with an engineering firm where he practiced corrosion engineering on various structural elements, including bridges, concrete tanks, buildings, and maritime port facilities. Kyle is a graduate of Akron University with a degree in Corrosion Engineering and holds CP1, CP2, and CIP 1 AMPP cathodic protection professional certificates.

Matt Waldrop

MATCOR has brought Matt on to develop new markets and field inquiries from west of the Rockies.

He has been involved with the corrosion industry for over 20 years and holds an AMPP CP1 certificate. He has extensive experience in technical sales, field operator qualification (OQ) training support, AC mitigation, and corrosion-related materials and equipment.

He has worked on projects with oil and gas companies, engineering firms, contractors, facilities, tanks, government and municipalities, and industrial and water companies.


For information on hiring MATCOR for your next important cathodic protection or AC mitigation job, please contact us at the link below, or reach out to your local MATCOR account manager.

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MATCOR Adds a New Drill Rig to Our Fleet

Drill rig for cathodic protection installation

MATCOR is excited to announce the acquisition of a new drill rig to our existing fleet of HDD and vertical drill rigs.

Our newest rig is designed to be a cost-effective option for drilling shallow holes. The rig features a much smaller footprint than the conventional deep anode drill rigs used for installing Durammo® and other deep anode systems.

Drill Rig Features

The smaller and more agile auger rig allows MATCOR to be able to maneuver the rig in tighter areas than the full-scale vertical rig would allow. Additionally, the unit is available with a hollow stem drill pipe allowing us to lower anodes in place in environments where an open hole may not be feasible. The rig is capable of drilling holes down to 100 feet deep, but for hollow stem purposes, we are limited to a depth of only 50 feet.

What This Means for Our Future

MATCOR is excited to add this new rig to our industry-leading inventory of cathodic protection installation enabling us to better compete for:

  • Shallow conventional anode beds
  • Distributive anode beds around tanks and congested facilities
  • Mobility is increased since it is loaded on to a semi-trailer

For more information, please contact us at the link below, or reach out to your local MATCOR account manager.

Contact a Corrosion Expert

At What Distance Does Cathodic Protection Continue to be Effective?

This article explores the answer to a question posed by a student about the length of pipeline protected by a cathodic protection system.


What length of pipeline is protected by a cathodic protection system?

We recently received a question from our website from someone who self-identified as a Student. We love when people ask technical questions and are pleased that students visit the MATCOR website–we have always strived to have a content-rich website to help share CP knowledge. The question is as follows:

“For installed impressed current CP systems with 15 anodes, what would be the approximate radius/length of a 200-mile petroleum metal pipe that would be protected?”

So before diving into the answer, let’s frame this question with an assumption, identify some unknowns and provide a definition.

Assumption

The 15 anodes are part of a single anode bed. The anodes are electrically remote from the pipeline and connect to an appropriately-sized DC power supply (transformer/rectifier, solar power/battery unit, thermoelectric generator, etc.)

Unknown #1: Pipeline Details

Before doing any detailed engineering, there are a few details that must be specified:

  • Pipeline diameter and material of construction
  • Coating type and condition
    • The layout of the pipeline (location of pumping stations, valve stations, and metering stations)

Unknown #2: Soil Conditions

Understanding soil resistivity in terms of location, frequency, and spacing, is critical when designing cathodic protection systems for long-length pipelines.

Definition of Attenuation

a lessening in amount, force, magnitude, or value according to Merriam-Webster

When discussing at what distance cathodic protection continues to be effective along a pipeline, you must consider the attenuation of the CP current. At some point, the current diminishes along the length of the pipeline, becomes insufficient, and can no longer protect the pipeline.

The Answer: Impressed Current CP Systems are Complicated

We can effectively use attenuation calculations for signals generated on a uniform conductor and transmitted through a uniform environment.

In this case, the pipeline is not a uniform conductor; unless it is bare, it is anything but uniform. The coating has less than perfect effectiveness and an unknown number of defects distributed in an unknown manner. The environment is equally non-uniform; soil resistivities change based on location and weather changes. The more non-uniformity, the more inaccurate the results will be for any attenuation calculations.

It is virtually impossible to model mathematically for older pipelines with insufficient coatings. The only effective strategy is to collect data by installing a temporary current source to measure the effective current throw in each direction in multiple locations along the pipeline.

For new pipelines with very good coatings, it is possible to perform some attenuation calculations and empirically determine a reasonable separation distance between anode stations.

The math starts with determining something called the propagation or attenuation constant. To calculate this, take the square root of the resistance per unit length of the structure divided by the leakage conductance per unit length.

In Simple Words…

How hard is it for the current to travel along the pipeline versus how easy it is for the current to jump onto the pipeline?

The smaller this number, the further current will spread. Key factors affecting the attenuation constant include earth resistivity (higher resistivity soils mean further current spread) and coating quality (better coating means further current spread). Armed with this, there are six simultaneous equations that we can use, and that include hyperbolic sine and cosine functions.

Larger, new construction pipeline projects require you to consult with a professional engineer. A brief newsletter article will not adequately cover the mathematical gymnastics involved. We did say that the math is complex.

Well-coated, newer pipelines in moderate to high-resistivity soils can typically be protected for 20+ miles in each direction from an anode bed. Poorly-coated or bare pipelines in low-resistivity soils may require anodes every quarter mile or less.


Need more information? Please contact us at the link below.

Is My Tank CP System Working Correctly?


Ted Huck, Director of Manufacturing and QA/QC at MATCOR, recently published an article in the summer edition of Tanks and Terminals Magazine titled “Understanding Cathodic Protection Systems.” He explains how to assess the performance of cathodic protection systems for above-ground storage tank bottoms (Tank CP Systems).

When asked to summarize these performance assessments, Mr. Huck commented, “Tanks are pretty easy to test, except for those rare occasions when they are not. At that point seek professional help.”

Read the full article.


Need information or a quote for MATCOR tank CP systems? Please contact us at the link below.

Cathodic Protection Systems | Cathodic Protection Design | alternatives to sacrificial anodes and galvanic anodes