Corona, RIV/TVI Testing Complete

By Carl R. Tamm

If your concept of corona is that it is commonly consumed with a slice of lime, you might wish to read a bit more about issues in our industry that differ slightly from that concept!

Fair weather radio and television interference (RIV and TVI) generated by overhead lines are most frequently caused by corona. Corona results from voltage overstress on the surfaces of conductors and other energized components. On distribution lines, sparking at lightly loaded connections and associated non-conductive films may also generate RIV/TVI. Corona also results in resistive power loss on transmission and distribution lines. Under foul weather conditions virtually all energized conductors and components are in corona.

With all this concern about Corona and at the request of a few customers we recently conducted RIV and Corona tests on CSF-1108-024-COR345 and CSF-1302-024-COR500 standard production ClampStar® units.

The tests were conducted in the HPS (Ohio Brass Company) high voltage environmental test chamber in Wadsworth, OH on September 13, 2012. The RIV tests were conducted in accordance with NEMA 107, “methods of measurement of radio influence voltage (RIV) of high-voltage apparatus”. Corona observations in complete darkness were made with the aid of a Noctron V night vision system (night image intensifier) S/N 5046. Click here to get the full report.


Important Facts You Need To Know About Surge Arrester Currents

Surge Arrester Currents
By Waymon P. Goch

Discharge current is the surge current that flows through a surge arrester during discharge of an overvoltage surge (and discharge voltage is the voltage that appears across the terminals of an arrester during that time). There are four additional currents that are of significance in the design, application, and performance of a surge arrester. Those currents can be defined as follows:

  • Grading current: Current that flows through the arrester internal grading circuit.
  • Leakage current: Current that flows over the outer surface of the arrester housing that is primarily a function of the application environment.
  • Fault current: Current from the connected power system that flows in a short circuit.
  • Power follow current: Current that continues to flow following discharge of the surge by the arrester.

The difference in fault and power follow current is timing. The low arrester impedance during discharge is, for all practical purposes, a short circuit but the arrester must interrupt and reseal against power follow current.

Fault current is dictated by the power system and the available current at the arrester location. Power follow current is dictated by the power system and the surge arrester design. The others depend upon the arrester age, class, rating, and design [gapped silicon-carbide (SiC), gapped or gapless metal oxide (MOV)].

Surge arresters manufactured before about 1977 are gapped SiC and there are many distribution, riser pole, intermediate, and station class arresters in service today that are of that design. The majority of these arresters were manufactured from 1950 through 1977. They represented state of the art at the time they were installed and for the most part their service history has been satisfactory.

The design of the earliest SiC arresters consisted of a simple multigap structure in series with non-linear SiC valve blocks. In those arresters, all system voltage was applied to the gap structure. The gap structure sparked over in response to an overvoltage surge to prevent damage to line or equipment insulation and the resulting power follow current flowed through the series gap-valve block combination. The non-linear blocks limited the follow current to a level that the gap structure could typically interrupt on the next voltage zero crossing (although restrikes were not uncommon). Following successful reseal the arrester returned to normal operation.

A major improvement in that design, primarily for station and intermediate class arresters, occurred with the introduction of the current-limiting gap in 1957. The current-limiting gap helped limit system follow current by generating a back EMF which, in combination with the non-linear SiC blocks, allowed
current interruption without reliance on a voltage zero crossing.

Most gapped SiC arresters also utilized resistive (R), capacitive (C) or resistive-capacitive (RC) grading circuits to grade the system voltage and obtain uniform voltage distribution across the gap structure. These grading circuits were electrically connected external to the gaps and blocks so that grading current flowed only through the grading circuit. Typical grading circuits resulted in a few milliamps of line to ground current.

A concern with gapped SiC arresters was operation in severely contaminated environments. Severe external contamination and the resulting leakage currents could couple and upset weaker internal grading circuits and alter the voltage distribution over the gap structure.

One method of monitoring grading and leakage currents as well as the number of line to ground discharges primarily through station arresters is a discharge counter with a leakage/grading current meter, Counters are used with gapped SiC and gapped and ungapped MOV arresters to assist in monitoring their duty and condition. Installation of discharge counters requires grounding the arrester through the discharge counter. This is typically done by mounting the arrester on an insulating sub base, as shown in Figure 1. (Many years ago, one manufacturer offered a discharge counter that also contained a mirrored replica gap in the discharge path. By examination of the replica gap and the copper mirror electrodes one could theoretically judge the condition of the arrester internal gaps and determine the duty to which they had been exposed).

The introduction of metal-oxide [primarily zinc-oxide (ZnO)] semiconductors for use in MOV surge arresters in 1977 was the second major advancement in surge arrester design and performance. The metal-oxide varistor is characterized by an extremely non-linear current-voltage relationship resulting in a much higher voltage exponent over the nonlinear portion of the volt-amp curve than SiC. This characteristic is what allows the design of gapless surge arresters. It also requires the introduction of another current called the reference current (Iref), which is an AC current specified by the surge arrester manufacturer in conjunction with a reference AC voltage (Vref) that essentially defines the point at which the arrester elements go into conduction. Below that point (and when energized at normal line to ground operating voltage) MOV elements can be characterized as lossy capacitors with current leading voltage by almost 90⁰. As voltage is increased above Vref the MOV elements become more resistive and at full conduction almost purely resistive with current and voltage in phase.

The significant improvement in operating characteristics and protective levels afforded by gapless MOV surge arresters also renders them virtually immune to the effects of contamination and external leakage currents.

Figure 1 Typical Installation (Cooper)

The IEEE C62 family of standards covers surge arresters and their application. For example, C62.11 is titled, “IEEE Standard for Metal-Oxide Surge Arresters for AC Power Circuits (>1kV)”.

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Problem Connectors on Multiple Sub-Conductors

By Carl R. Tamm

If you have a line with two or more sub-conductors per phase, and during an infrared inspection, a scenario is found where one of the sub-conductors has a fitting that is hotter than the one next to it, the natural tendency is to assume it is a high resistance connection.  Were it a single conductor and we find a “hot fitting” it is a “no brainer” to understand that it is high resistance.

However, when we have two or more sub-conductors, and one fitting is hot and the other is not, it is not such a simple matter, as more often than not, the problem is elsewhere!

While this phenomenon applies to any multiple of sub-conductors, for simplicity, we will use the scenario of only two, or “twin sub-conductors” for the rest of this article.

To gain an appreciation of what happens, it may be easier to think of the old analogy of comparing electrical energy flow through conductors to water flowing though pipes.

If we think about having a specific flow rate of water, say 100 gallons per minute, and instead of having that flow through one pipe, we provide two pipes of equal size and equal levels (for simplicity, we’ll ignore number of fittings and other restrictions) we can expect the flow of water to be divided in half, with 50 gallons per minute flowing through each pipe.

When we design a transmission line with twin sub-conductors, care is taken to assure both conductors are of equal length, with the same number of fittings so that if measured, they would have the same “electrical resistance” measured in ohms.  And, if this is the case, we will achieve an equal voltage division, and therefore an equal current division, with each conductor carrying 50% of the entire electrical load (or flow).

If we go back to the pipes, and we put a restriction in one of them, possibly partially closing a valve, or some other mechanical restriction….

….now we expect more water to flow through the open pipe, such as 40 gallons through the restricted pipe, and 60 gallons through the open pipe!

With electricity, it works the same way.  IF both sub-conductors are exactly the same, they will carry equal current.

However, if one has more resistance than the other, such as having a high resistance connector in the circuit, MORE current flows through the conductor that has less resistance!  Now – MORE CURRENT results in HIGHER OPERATING TEMPERATURES!

A transmission line has many connectors, and while they may be close, there will inevitably be some difference in electrical resistance, but with reasonably good craftsmanship, the normal result is so close it is of no concern.

However, when one or more of those connectors begin to increase in resistance with age, rarely will that degradation be equal, and the result will be an imbalance of current between the two sub-conductors.

Because the current is always trying to find equilibrium, the current will try to find other paths in order to maintain that balance.  Oftentimes, this is through a yoke plate or other mechanical connection, which may be miles from the location where the hot connector was originally found!

While the hot connector may be bad, or going bad, it is very likely not the ONLY bad connection on the line.  When using a ClampStar® to shunt that hot connector, it will behave as one would expect, it WILL cool down, simply because the ClampStar® has increased its ampacity by a factor of 3 or more, so it would take 3 times as much current to cause it to heat.  But the story does not end there.

It becomes necessary to look for that current imbalance.  Begin by doing a much more thorough inspection of the circuit, using a much more narrow range of bandwidths on your IR equipment, and look at all hardware that joins the sub-conductors in any manner, including spacers and yoke plates.  It would be advisable to look for high resistance fittings using an Ohmstik (SensorLink®) which allows the measurement of resistance by measuring micro-voltage drop across a connector.

It may be advisable, while you are out on the line, up close and personal, to consider covering any critical connections with ClampStar®, even if they are not really bad today.  If the line is aged, and you are finding some bad connectors today, you will find more next year, and more the year after that.  A great portion of your expense is mobilization, and while you are there, it only takes minutes to correct a potentially bad situation.

Connections over roadways, waterways, or places frequented by pedestrian traffic should be given serious consideration.  One failed connector and a dropped line will cost more than covering every connector on the line while you are there.

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Surge Arrester Lead Length Revisited

By Waymon P. Goch

Surge arrester manufacturers always recommend that line and ground leads be as short and straight as possible in all surge arrester applications. Why?

The primary reason is inductive surge impedance. The selection of the best surge arrester for a given application can be negated by poor installation practices. The length and configuration of the line and ground leads connecting the arrester to the apparatus being protected is critical in the determination of the arrester protective levels and margins.

Modern surge arresters are designed to protect insulation from impulse over voltages that could cause flashover or damage to the insulation that is in parallel with the arrester. For distribution class arresters the primary impulse overvoltage is lightning whereas for station class arresters the primary impulse overvoltage is switching. As the class name suggests, Intermediate class arresters fall in between. The consequence of failure to protect is a function of the nature of the insulation and whether it is self-restoring (air) or non-self-restoring (solid, liquid, or composite) insulation.

Internally, the critical components of surge arresters are non-linear resistance elements; either in combination with series multi gaps or more modern gapless metal-oxide varistors (MOV). Internal gaps were necessary in older silicon-carbide arresters to limit grading current through the silicon-carbide resistance elements and to interrupt the flow of system follow current through the arrester following discharge. The composition of MOV (primarily zinc-oxide) resistance elements results in a very highly non-linear voltage / current relationship and allows the construction of gapless surge arresters.

When an overvoltage surge is impressed across the arrester terminals, the arrester begins to conduct the resulting discharge current to ground. The flow of discharge current through the arrester causes a discharge voltage to appear across the terminals of the arrester. If the arrester line and ground leads are also installed in parallel with the insulation being protected, the combined lead inductive voltage drop is additive to the arrester discharge voltage.

The inductive voltage drop in the line and ground leads is a function of the lead inductance, current rate of rise and time according to the formula: V = L di/dt .

For a straight lead wire, the inductance (L) can be assumed to be 0.4 µH/foot. If the lead wires are coiled the inductance will be significantly greater.

Arrester manufacturers’ catalogs, drawings, and data will usually provide protective characteristics of their arresters, including maximum discharge voltages for several discharge currents and voltage times to crest from steep wave through switching surge. Those arrester discharge voltages plus lead inductive voltage (if appropriate) are usually plotted and  compared to the corresponding insulation characteristics to determine the protective margins on insulation coordination curves similar to Fig 1. Fig 1 also illustrates the typical volt-time characteristic of most insulation. That is, the shorter the time the greater the insulation or dielectric strength.

Published arrester IR discharge voltages are normally based on a standard 8/20 impulse current wave (8 µs to crest/20µs to half crest on the tail) however, the highest voltages to which the insulation is subjected are rapidly rising steep wave impulses due to lightning. It is now known that rapidly rising impulse currents are far more common that previously thought. More accurate measurements have shown that about half have rates of rise of 13 kA/µs with a maximum value of approximately 60 kA/µs.

Consistent with this rate of rise, a lead wire voltage drop of 6 kV/ft is often used in calculating the protective levels for installations exposed to rapidly rising fast front surges.

Let’s look at an example to illustrate the effect of arrester line and ground leads connected to a surge arrester and connected in parallel with insulation.

Assuming an 8.4 kV MCOV gapless distribution arrester protecting a 95 kV BIL transformer, a typical gapless heavy duty distribution class arrester might have a 0.5 µs 10 kA IR of around 36.5 kV.

Assuming line and ground lead impedance of 0.4 µH/ft, the resulting inductive voltage developed across the leads = 0.4 x 10‾⁶ x (10 x 103 A / 0.5 x 10‾⁶ sec) = 8 kV/ft. Thus, for every foot of line and ground lead, 8 kV must be added to the arrester IR discharge voltage when calculating the overvoltage protective margins provided by the arrester and its connections. This could be particularly important for the protection of underground cable and aged or degraded equipment.

Fig. 1 Insulation Volt-Time Coordination Curve

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Avoiding Splice Failures

By Lisa Nelson, EDM International, Inc.

One of the primary root causes for splicing failures is poor cleaning of aluminum strands prior to compression.   The Electric Power Research Institute has developed technology that enables line crews to properly prepare conductors quickly, efficiently and affordably.  Improper cleaning of conductor strands can result in higher resistance terminations and splices that cause fittings to operate at higher temperatures leading to premature failure. To alleviate this concern, EPRI developers have come up with a system for cleaning the ends of overhead conductors prior to installing compression terminations and splices.

Prior to EPRI’s conductor cleaning research, the predominant method to clean conductors before splice assembly was wire brushing.  However, for complete and thorough cleaning, the conductor must be unstranded. This unstranding is an impractical requirement in most field conditions. Thus EPRI has initiated a multi-phase initiative to develop a method or tool for cleaning aluminum conductors.

The technology involves the agitation of a specialized solution to remove oxidation and grime from conductor strands, and can be adjusted for various cleaning cycle time, depending on the condition of the conductor. This methodology allows line crews to thoroughly clean conductors in much less time than traditional hand-cleaning methods. The technology was designed to be compact and portable to allow linemen to operate wherever the splice is most efficiently made – whether on the ground or up in a bucket.

Not long ago, Southern Company ran a beta test with the conductor cleaning tool. The Southern Company team put the tool to use during a restoration effort at Plant Bowen in Cartersville, GA, where three 500 kV feeders comprised of six structures were destroyed due to a tornado. The team completed 80 to 90 conductor cleanings over a two-week period. “With this new tool, Southern Company was able to do a single cleaning in about six minutes,” according to Andrew Phillips, Director of Trans­mission Increased Power Flow at EPRI. “Using manufacturer conductor cleaning recommenda­tions, which involves cleaning each strand, it would have taken 30–45 minutes to clean each one. A conservative, rough estimate of the time savings would be in the neighborhood of 1,920 minutes, or 32 hours saved.”

For the first-time users at Southern Company, the tool proved to be a device you could learn quickly and put to work immediately with basic expert advisement. “The team saw the tool for the first time and adapted quickly to it,” Phillips commented. “This was really a good situation to test the effectiveness of the device. They were experiencing an outage and in a worst case scenario they were prepared to spend 30 or more minutes to clean each conductor using the manufacturer’s suggested cleaning method. If the first few did not go well, they would have gone back to the recommended method and nothing substantial would have been lost. There was only an upside in choosing to use the device.” Alan Holloman from Southern Company shared this perspective, “The crew was amazed at how well and thoroughly the tool cleaned each conductor. It did a superb job. We would have missed an opportunity if we had not used it.”

There were a number of benefits from using the conductor cleaner. The device enabled crews to be timely and efficient in the splice making process and the splice that was made was more efficient than if they had used the traditional method. The cleaning process was also much faster, saving significant man-hours. Southern Company was also able to make its 500 kV lines available much earlier. Since the conductor is cleaned to the core, the finished product is also of better quality and this could help limit sleeve failures in the future.

A total of seven utilities were part of the project to develop the conductor cleaner. The group of utilities included American Transmission Company, Tennessee Valley Authority, Oncor Electric Delivery, Public Service Electric & Gas Company, CenterPoint Energy, East Kentucky Power Cooperative and Southern Company. Southern Company was the first to use it in scale.  Heat-cycle testing of compression connectors by EPRI shows that connectors installed using this technology consistently outperform connectors installed using wire brushing as evidenced by lower operating temperatures and longer life.

For additional information on proper splice methodology, or for information on other topics related to effectively managing electric utility assets, please contact EDM International, Inc. (970-204-4001).

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Corrosion and Splices

By Waymon P. Goch

Worldwide, the annual cost of corrosion is $2.2 trillion (US); and is currently estimated to be $429 billion (US) annually in the United States.(1) Corrosion that results in failure of aircraft, pipelines, bridges and other critical structures receives a lot of publicity and attention but other failures that are primarily due to corrosion do not receive that kind of scrutiny.

Corrosion can be defined as the destruction of metals by chemical and electrochemical processes. The corrosion products are oxides, hydroxides, sulfides, sulfates, and carbonates in most cases. This represents a return to a natural state in which most common metals occur as ores. There are several types of corrosion. Atmospheric corrosion, such as rust on the surface of ferrous metals, is an example of direct chemical attack. Oxidation is a direct chemical attack that requires only oxygen. Moisture is not required for oxidation to occur. Oxides form immediately on copper and aluminum upon exposure to the air. Copper surface oxides tend to be soft and electrically conductive in contrast to the hard, almost impervious surface oxide that forms on aluminum alloys. The aluminum oxide is electrically non-conductive and the oxide thickness increases with time and temperature.

Additional accelerants present in the atmosphere are carbon dioxide, water vapor, sulfur, sodium and chlorine compounds and the severity of the attack is directly related to the amount of those compounds in the service environment.

Although splices and other connectors and hardware on overhead transmission and distribution lines are subject to direct corrosion with pitting and other outside surface changes, it usually does not result in mechanical or electrical failure, with one exception and that is the oxidation of internal aluminum splice components and conductor. That oxidation contributes to increased contact resistance, heating, and subsequent failure of splices and, to a lesser degree, dead ends and other current-carrying compression connectors.

The more significant corrosion type that affects splice life and performance is galvanic. Almost everyone is at least casually familiar with galvanic corrosion but may not be aware of some of its causes and characteristics. Galvanic corrosion is an electrochemical process that involves metal in the presence of an electrolyte. It normally requires two dissimilar metals of different electrical potential in the presence of an electrolyte.

All metals have a specific relative electrical potential as shown in the galvanic series chart of Fig 1. When metals of different electrical potential are in contact in the presence of moisture (electrolyte) a low energy electric current flows from the metal having the higher potential (anode) to the one having the lower (cathode). This galvanic action is shown graphically in Fig 2.

The actual process involves an anode reaction, the conduction of electrons through the metal from anode to cathode, and the conduction of ions through the electrolyte solution. Corrosion occurs in the anode area (less noble) while the cathode area (more noble) is protected. The corrosion deposit is analogous to ash from burning wood.

This process is intentionally employed in cathodic protection systems to prevent corrosion of underground pipelines and other structures and equipment (including hot water heaters in which the anode is normally magnesium).

Concentration cell, crevice, stress, deposit, impingement, intergranular and fatigue corrosion are all forms of galvanic corrosion.

It was mentioned earlier that galvanic corrosion normally involves dissimilar metals but it is possible to experience galvanic corrosion in a single metal under certain conditions. If a deep crack or fissure develops and can contain stagnant moisture, it is possible to create galvanic corrosion in one metal.

It is important to recognize that the one element required for galvanic corrosion to occur in any form is moisture. If there is no moisture, there is no electrolyte and therefore no galvanic corrosion.

I’d like to call attention to an interesting characteristic in Fig 1. That is the difference in potential of active and passive types 304 and 316 stainless steel. Exposure to stagnant or poorly aerated water causes passive stainless steels to become much more active. This same characteristic can be seen in other metals in the galvanic series.

Within a line splice galvanic cells are created by the ingress of moisture, salts, and other surface and airborne contaminants. Evaporation is retarded and an electrolytic cell is created. This is the primary cause of internal corrosion, accelerated aging, and higher contact resistance resulting in shifting of the dynamic current path. This also emphasizes the importance of proper conductor cleaning and preparation to remove the non-conductive aluminum oxides immediately before splice installation and the use of the proper inhibitors to seal the contact area and conductor strand interstices.

Galvanic corrosion is not a concern with ClampStar® Connector Correctors because a galvanic cell cannot be established. There are no pockets in which stagnant moisture can accumulate and the conductor grooves and interfaces are permanently sealed with CC², a proprietary high temperature inhibitor compound that will not wash out under any service condition.

(1)    U.S. Congress, Federal Highway Administration, and NACE.

Figure 1
Figure 2

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Inner Workings of an Automatic Splice and Using ClampStar as a Safety Tool

By, Carl R. Tamm

ClampStar is used as a tool by several utilities as a “safety” when performing line work on a conductor that contains an automatic splice in the span.

As a work method precaution, many utilities require the crew to install a “safety” over an automatic splice if any work is to be done on a live line, including changing insulators or crossarms, or any work during which the subject span containing an automatic might be disturbed.  Properly installed, automatic splices are predominantly reliable.  However, due to the number of incidents that have occurred, many times it is found that the conductor was not properly inserted.  The most prominent “improper insertion” is known as “partial insertion.”  In this case, for various reasons, usually because the installer failed to properly mark the conductor before starting, the conductor is not inserted to a sufficient depth to push the pilot cup completely through the jaws.

The problem then becomes that the jaws cannot close completely on the conductor, and obviously, it has a propensity to slip.

To state our position once again, “Properly installed, automatic splices are predominantly reliable.”  Some people have thought that CCI is pushing for the “ban” of automatic splices – but that is not the case.  We have also stated that automatic splices are “a must – for storm restoration.”  They are, without question, the most economical, and certainly the fastest means of reliably splicing a conductor.  Do other methods, such as compression connectors, offer a higher integrity connection?  I think that the manufacturers of automatics would agree that is the case – as they also offer the compression option – but nobody would argue against the importance of the “quick” means afforded by the automatic splice.

Because so many people ask, it seemed appropriate to share some of the inner workings of automatics.  While most people who use them know what is inside, perhaps it will assist them when installing these connectors, to understand the purpose of the components, and possibly give them a bit more appreciation for the manufacturer’s instructions!

The following is a picture of the “guts” of one side of an automatic – the other side is the same.

Beginning at the upper left and moving clockwise, we have (a) the spring, which provides a forward thrust to the jaw assembly during installation, (b) two jaws which interlock and make up the “jaw assembly”, (c) the pilot cup, which captures the ends of the conductor strands, and maintains their position (keeps them together) during the installation, and at the bottom, the yellow component is the “funnel guide” which serves to hold the pilot cup inside the assembly and guide the stranded ends of the conductor into the pilot cup – all within the tapered body of the splice.

To illustrate the action of the pilot cup, the following photo shows how the conductor, once inserted through the funnel guide, fits within the confines of the pilot cup.

Prior to insertion, having this side cut out from the splice, one can see the position of the jaws, urged forward by the force of the spring, awaiting insertion of the conductor.

Upon insertion of the conductor, having picked up the pilot cup as it passes through the funnel guide, the “resistance” that is felt during installation is the force required to push the jaw assembly backward against the spring.

As can be seen, the pilot cup serves to maintain the conductor’s position, centered within the jaws as it is pushed toward the center of the splice.

Properly installed, the conductor will carry the pilot cup completely throughthe jaws, to the center of the splice.  Because the pilot cup must contain the entire conductor, it is obviously of larger diameter than the conductor, and as can be seen in the following photo, upon passing the pilot cup completely through the jaws, the jaw assembly will “spring” forward, and the taper of the body will force the jaws into intimate contact with the conductor!  Additional tension on the device will serve to further “seat the jaws” and urge them into increased forced contact with the conductor.

Without question, 75-80% of the problems with automatic splices occur due to installation error, and about 80% of those are “partial insertion” errors, where the conductor is simply not inserted to its full intended depth such that the pilot cup has not “cleared” the jaws!

The result is that of the following photos. In the instance of the first photo, insufficient force was provided to drive the pilot cups into the jaws, and the conductor was simply not gripped.  If this occurs, the lineman will immediately recognize there is a problem, and take action to correct that, by installing another splice.

However, in the instance that follows, the pilot cup has passed almost to the end of the jaws, which is the most dangerous situation, as the tips of the jaws may capture the conductor, leading the installer to believe that the splice is made adequately, and the conductor may withstand the initial tension of the line, but the jaws are prevented from closing completely on the conductor by the invading pilot cup!  In such instances, the splice may be left in service for days, weeks, or even years, before some event jostles the line sufficiently or components of corrosion allow the conductor to slip out!  This condition may be impossible to detect with infrared techniques, depending on the current load on the line.

A second type of insertion error occurs from time to time, when upon inserting the conductor, the lineman pulls it back a bit (possibly to get a better grip because it was obvious that the conductor did not go it far enough – such as the condition in the previous photo and the pilot cup does not come back, as it is held in the jaws.  The purpose of the pilot cup is to keep the ends of the strands together, and assure that they all pass completely through the end.  In the scenario where the conductor is retracted as much as ½ inch, the strands can escape from the pilot cup, and one may erroneously slip through the side between the jaws.  In this instance, although the conductor may be fully inserted, the errant strand between the jaws prevents them from closing completely, and because it is not within the bundle, the overall diameter is reduced and again, the conductor can slip from the grasp of the jaws.

The critical concern is that neither of these situations are visible or otherwise readily detectable, and while the splice may hold the line under the stringing tension of a few hundred pounds, additional tension or other disturbance during work on the line may be enough to allow it to slip.

The old method of putting a set of grips and come-a-long on the line, could in its own movement, cause the line to slip before it is secure.  If that occurs, there is an arc flash hazard, along with the fallen conductor.  If one puts the MAC cable (ground set used as a jumper cable) on first, it can eliminate the arc flash, but may in itself drop the line.

Placing a ClampStar on the line in a gentle fashion allows both the electrical and mechanical safety to be applied at the same time, and is faster and safer to install.  If the splice appears bad, i.e., has burnt funnel guides or has evidence of obvious expulsion of contaminants (looks like black grease) running out of it, perhaps it would be wise to simply leave the ClampStar in place!

However, if there is sufficient confidence concerning the integrity of the splice, the ClampStar can be removed, and used again.

Have you ever looked up as you were driving, and noting a splice in the conductor passing over the road, wondered if that splice was one of many that, although it is there today, may have been improperly installed, and could “let go” at any moment with no warning?  Perhaps one might sleep a little better if they saw a ClampStar covering that splice, knowing that one connector had been “corrected”!

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DO YOU KNOW THE CONDITION OF YOUR SPLICES?

Joe Renowden, Consulting Engineer
(Article provided by SensorLink)

Why would that question be important when industry wide there have been relatively few failures? The answer is: The risk of failure can’t be managed until the splice’s condition is assessed and characterized. Managing the risk means planned replacement, as opposed to “Uh Oh! Get a crew out there and put it back up!”

At a splice reliability workshop in September of 1999 an EPRI survey reported a trend toward increasing transmission line splice failures. Transmission line reliability has an Achilles heel! These aging fittings are deteriorating at a time when load currents and fault currents are increasing!

Note: time is not an “aging factor” for fittings. Deterioration is due to increases in resistance of the connection. The increased resistance is produced in part by peaks of load and fault current that can heat the interface even if only temporarily or for a few cycles. (Also in part by oxidation of the interfaces during thermal expansion and cooling, and by corrosion accelerated by moisture and chemicals in very small quantities that get in between the strands.) Every splice has at least one “uphill” side for water, etc. to run to. The reason we tend to hear that fewer “deadends” fail; may be that most of them are pointed “downhill”.

All these influences accelerate the deterioration of fittings that are not installed properly. Cleaning and roughening the conductor always was important in making a “good fitting”, and with today’s shorter, harder alloy tube fittings, we have found it critically important, even with the new conductor. Proper dispersion of inhibitor will help keep the interfaces from oxidizing. All major manufacturers have frequently found missing or inadequately dispersed inhibitor when examining failed fittings. Proper die closure is very important, especially with the newer (last 20 years or so) alloy tube “single die” type compression fittings. There is generally less conductor inserted in the fitting than in the older “hex die” type of fitting, so it is less forgiving of installation error. These consequences of installation lead to incremental increases in resistance during the service life of the fitting. Resistance measurements of newly made alloy tube fittings indicate they are more likely to start service at the higher end of the normal range than the lower end.

All that has been learned about fitting reliability lately indicates that there will be more problems with unexpected failures than we have in the past. This comes at a time when we need just the opposite. We need to repair or replace on a planned basis before failure occurs.

There are two practical methods of doing condition assessment of splices and other connectors while they are energized and carrying load current. They have very different thresholds of detection and consequently different impacts on reliability.

The first method provides definitive actionable early warning of a deteriorating fitting. It is to directly measure the resistance of the connection with an Ohmstik™. The resistance is the electrical condition of the splice! If it is outside the normal range, the connection is deteriorating!

A connection with resistance above the normal range is in a failure process where the time to failure depends on how high the resistance is. The appropriate planned actions for ranges of resistance above normal are shown in the following Table. The resistance ratio is calculated by comparing the resistance of the fitting over the resistance of the conductor.

The Ohmstik™ is a microhmeter mounted on a hot stick. It measures the resistance of the conductor and the connection, at any level of line loading above 5 amps, on energized lines up to 500 kV.

Splice Inspection on 220 kv Line

Actions required based on resistance ratios (R fitting / R conductor)

Category

Resistance ratio

Condition of fitting Action

1

0.3 to 1.0

Normal connection
New Connections are expected to be in the 0.3 to 0.8 range
None

2

1.01 to 1.2

Serviceable, shows deterioration
Overloads & faults may deteriorate the connection.
Re-inspect in one year, or after next fault

3

1.21 to 1.5

Serviceable, poor
Overloads & faults may deteriorate the connection.
Re-inspect in 6 months, or after next fault

4

1.51 to 2.0

Serviceable, very poor
High loads, over loads, or faults may dete­riorate the connection.
Schedule repair or replacement in less than 3 months

5

2.01 to 3.0

Bad, deterioration rate is increasing
High loads, overloads, or faults may fail the connection.  High tensions from cold weather or wind may initiate failure under normal loading.
Schedule repair or replacement  very soon

6

> 3.0

Failing
Normal loads, overloads, or faults may fail the connection. High tensions from cold weather or wind are likely to initiate failure under normal loading.
Repair or replace As Soon As Possible

Note: This information was developed from field measurements, manufacturer data, lab tests, failure analysis, and understanding of deterioration mechanisms. This guideline may be modified as field & test data accumulates.

The second method is the somewhat familiar Infrared inspection technique (IR for short), used extensively to find thermally “hot” connections, switchblades, and other overheated power equipment.

IR can find “hot” splices in the last stages of failure, IF:

A. The line has enough electrical load during the inspection to overcome the cooling effects of the wind on the splices. (They are larger in crossection than the conductor and cool more effectively.) Even light winds of 3 to 5 mph have a major cooling effect (read masking effect) on splices. Daytime winds at conductor elevations are rarely less than this.

B. The splices are not shinier than the adjacent conductor. If their emissivity is low (i.e., shinier) they will emit less heat than the conductor and can appear to the IR to be cooler than the conductor, even though the actual temperature is higher (1.) {Improving the Results of Thermographic Inspections of Electrical Transmission & Distribution Lines, John Snell, Joe Renowden. ESMO 2000 paper 28C-TPC-17}

C. The Sun heating of the fitting or conductor doesn’t mask the internal heat from the connection.

D. The distance of the IR camera from the fitting doesn’t reduce the “object size” so much that the heat source is “dimmed”. This effect always reduces the indicated temperature, thereby “masking” the actual temperature.

These effects can, individually or in combination, keep many splices in the earlier stages of failure from being detected. The early stages of failure are in the form of internal resistance increases, detectable by resistance measurement. The IR masking effects can and do conceal badly deteriorated fittings. This is known to have resulted in a failure, after several IR inspection cycles, where a new (shiny) fitting was improperly installed on a weathered conductor.

First, IR does indeed find “hot” fittings! What has not been fully understood is that these fittings are in the last stages of failure and could have failed from a combination of loading and weather conditions before they were IR inspected!

Second, there have been failures of fittings after IR inspections did not detect the deteriorated fittings!

It is only the later stages of failure that produce fittings hot enough to be detected by IR. (See the following table.) Experience bears this out with several well-known facts:

The following table indicates the likelihood of an Infrared survey finding fittings in the various categories where the resistance ratios indicate action for deteriorated fittings.

Action Category

Resistance Ratio

Action Needed (based on resistance ratio)

Likelihood of Infrared detection

(Notes 1. & 2.)

1

0.3 – 1.0

None None - splice will be cooler than conductor

2

1.01 – 1.2

Re-inspect in 12 months, or after next fault None - splice will appear to be cooler than conductor

3

1.21 – 1.5

Re-inspect in 6 months, or after next fault Unlikely - Splice may appear to be cooler than conductor

4

1.51 – 2.0

Schedule replacement in less than 3 months Unlikely - Splice may appear to be cooler than conductor

5

2.0 – 3.0

Schedule replacement very soon Possible - Splice may be close to or the same as conductor temperature

6

> 3.0

Replace ASAP Somewhat likely – Splice may still be masked at this load level
Notes:
1)     Estimates of likelihood of detection are based on IEEE ESMO 2000 paper 28C-TPC 17 by J. Snell & J. Renowden
2)     Conductor is 795 ACSR 26/7 and has 25% of rated load current. Wind is 3 mph (day time air is rarely this slow!) cooling the splice more than the conductor due to its larger surface area, and thereby further masking the splice. Emissivity on conductor & splice is set at 0.7. The splice emissivity can be lower than the conductor, further masking it.

SensorLink Corporation
1360 Stonegate Way
Ferndale, WA 98248 USA
Phone: 360-595-1000
Fax: 360-595-1001
www.sensorlink.com

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Do You Change the Tires on the Family Auto?

By, Carl Tamm

Most of us gray haired guys well remember the advent of radial belted tires!  There was significant skepticism initially, as some of the early models wound up with bulging “pump knots” on the sidewalls, but eventually the problems were ironed out, and the radial tire, along with the non-continuous tread design evolved into our tire of choice today.  And with that, most of us are glad to get more than 15,000 miles from a set of tires.  We are pleased to commonly get an excess of 40,000 miles with proper maintenance.

Now, the question of the day.  How many of you operate your tire replacement plan on a “run-to-fail” basis?  Just run ‘em till they pop!  Does this sound absurd to you?  It works for socks doesn’t it?  Wear ‘em till they get a hole in them!  What’s the difference?  Well, it is highly unlikely that a hole in your sock is going to endanger your life, nor the lives of anyone else.  But those tires could kill you, your family or passengers, or, if loss of control occurs at high speed, possibly endanger the lives of other “innocent” people on the road or sidewalk.

The dilemma has come up a few times with some utilities, and the concern is, “If I start using ClampStar, I am admitting I have an unsuitable connector in the air.”  Engineers worry that they have specified the use of an unsuitable product.  C’mon folks – nothing lasts forever.  We know the bridge is going to fail, so we repair it.  Roads, pipelines, cars, tires, even anvils will eventually wear out with enough use or abuse.

None of the connectors made by reputable manufacturers, which have been tested and approved, are unsuitable for their intended purpose.  They work quite well within their intended operating parameters and useful lifetime.  Some may be better than others, some may operate in certain environments better than others, and some may exhibit longer useful lives than others.  But of one thing you can be certain: ALL of them will eventually FAIL - NONE of them will last FOREVER.  Forever and ever is a nice phrase in fairly tales, but it is an awfully long time!  You can write this down in your little book, and you can put my name beside of it with a little asterisk, (Carl Tamm*) said, “The only electrical connection that will last as long as the parent material, is a thermal fusion weld.”  With all other designs, there exists an “electrical interface” that NEVER goes away, and WILL DEGRADE over TIME!”  We have ample empirical data to back up that statement.

OK, so we started the discussion with tires.  Tires have “wear indicators” molded in the tread.  There are means of measuring tread depth, and visual inspections will serve to indicate a suitable time to change the tires.  Unfortunately, electrical connectors are a little less forthcoming with such obvious indicators.  We utilize inline resistance measuring devices.  We utilize Infrared Thermography, and one additional effort that is being advanced is a thermo-chromatic paint.  One of our major issues is going out and checking the condition of our splice / connector population.  It is a bit less expensive to check the inflation pressure in the tires, or to make occasional observations of their condition when we stop for fuel.

The “remaining life” indicators for connectors are not nearly as black and white as those for tires, but that does not relieve us of the responsibility of doing what we can to make these decisions, and in certain instances, perhaps it is not worth the risk, waiting until we have a clear indication of an imminent failure, because we might not catch it in time (before the next scheduled inspection).

Identify Critical Connectors, and prioritize them, based on the potential damage should they fail.  Those in the business of designing door knobs do not have much concern.  If a door knob fails, the major injury one might suffer is a bruised toe – although it is not without risk, as it could impede someone from escaping a burning building.  Aerial electrical connectors are ALWAYS a danger.

(A)   1 st Priority are those that are suspended above areas accessed by the general public, such as sidewalks, parking lots, or any area that is subject to high traffic by pedestrians, where, should a conductor fall due to a connector failure, innocent people are likely to be killed or injured.  Aged connectors over such areas should be addressed immediately.

(B)    2nd Priority are those that are suspended over roadways, waterways, railroads, where the situation of an overhead conductor falling into these areas due to a connector failure could result in not only direct contact, but also could contribute to secondary fatalities such as automobile wrecks or electrification of remote objects.

(C)    3rd Priority are those connectors on lines that serve “critical facilities” such as those structures from which essential services and functions for victim survival, continuation of public safety actions, and disaster recovery are performed or provided.  Shelters, emergency operation centers, including fire stations and EMS facilities; public health facilities or hospitals; pumping stations for public drinking water, sewer and wastewater facilities are examples of critical facilities.

(D)   4th Priority would include public facilities where a power outage could result in potential harm and certainly major inconvenience, such as malls or shopping centers, or public event arenas or stadiums, an example being the outage at Candlestick Park last December discussed in a previous article.  Included in this category would be areas where fire would be imminent from a downed power line.

From a “maintenance” perspective, these “priority” applications could well warrant the enhancement of the connector be made without waiting for the opportunity or undergoing the expense to conduct inspections.  Utility personnel should be aware if they have lines with “critical location” connectors that are beyond their normal useful life.  The design criteria 30+ years ago for compression connectors was 30 years!  Today, we have found that those designers did a good job, and we can expect 40 – 70 years of useful life from those connectors operated within their design parameters.  The most important parameter is temperature of the conductor, which, per those 30+ year old parameters, was/is 70°C (158°F).  If you have “critical location” connectors that are beyond their normal useful life based on either of these parameters, it should become a high priority to address them.

Have you kicked your tires lately?  “Run-to-Fail” is NOT an acceptable policy for overhead electrical connectors.

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Fault Current versus Distance

Background: A major utility noted that they were having far more splice failures on their 34.5 kV distribution lines within a few miles of the substation than they were toward the end of their circuits. The primary reason is the available system fault current diminishes with distance from the sources.

In an attempt to quantify this, representative fault current calculations were made on a “typical” 34.5 kV circuit. I’ll call it “typical” because no circuit details or transformer nameplate data were available. We do know that the utility uses both 336.4 kcmil (Linnet) and 636 kcmil (Grosbeak) ACSR conductors on their 34.5 kV circuits and it is assumed that both are loaded to their 75°C maximum operating temperatures. The transformer used for these calculations was arbitrarily selected as 34.5 kV, 95.0 MVA, X/R=5.0, 5%Z (which may or may not be representative of the actual transformer).

Short circuit studies normally begin with a line diagram showing all loads and potential sources of fault current. (During a symmetrical fault, induction motors will contribute only during the asymmetric portion of fault current but synchronous motors may contribute 4 – 6 times their full load current to all fault locations). Capacitors may also be a factor under some conditions. Protective devices are not normally included in the line diagram.

Worst case short circuits are normally based on bolted 3 phase fault conditions in which all three phases are “bolted” together to obtain a zero impedance fault. This results in maximum thermal and mechanical stress in the system and typically assumes infinitely available fault current from the primary source.

In this case, we are only interested in the available short circuit current at the location of a line splice versus distance from the transformer, based entirely on the conductor resistance, reactance, and voltage at the fault (splice) location. Following are the graphical results of point-to-point analysis of both conductors from 1/8 mile to 10 miles from the transformer.

Conclusions: While this exercise may or may not be truly representative of a particular utility system, it does illustrate fault current magnitude relative to distance from a transformer source, regardless of the transformer type and location. In this case, fault currents are higher on the larger Grosbeak conductor because its total impedance is less than that of Linnet.

Although the slopes and magnitudes would change for other source and conductor combinations, the results would be similar.

Degraded, high resistance splices, connectors, damaged conductors, etc. would be less able to withstand the higher fault currents both electrically and mechanically so it would be expected that failure rates would also reduce with distance.

Waymon P. Goch
March 14, 2012

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