Conclusions

High and medium voltage transformers are probably the most complex and easily the most expensive pieces of equipment in a transmission and distribution system.

Th ey can range anywhere from 750,000 volts down to 4160 volts primary voltage, from a few hundred VA up to 1000MVA, and be either liquid fi lled, gas fi lled, or dry type in confi guration.

The Core

Th e core is the heart of a transformer and surprisingly has not changed much since the beginning of ac power;

thin, fl at laminations of soft iron. Early on core materials changed to sheet steel, and then to silicone steel, but the basic confi guration of the core has not signifi cantly changed.

Th in laminations are normally around .30 millimeters thick and are stacked to a size and height determined by design.

After the core is assembled it is clamped to ensure the laminations are tight.

An improperly clamped core will vibrate excessively, in-creasing the “hum” of the unit and eventually contributing to a premature failure. (and you thought units “hummed”

because they didn’t know the words!)

Figure 1 — Th ree-Phase LTC Core and Coil Assembly

The Windings

Th e windings are assembled around the core and are of two types of materials; copper and aluminum. Copper has the advantage of having a greater mechanical strength and better electrical conductivity, while aluminum is lighter, costs less, and can be better at heat dissipation. Most large distribution and transmission units are copper, while small distribution and dry types are increasingly aluminum.

Kraft paper or pressboard paper insulates the windings.

For coil winding construction Kraft paper is tightly wound around the copper coils, the number of turns of paper be-ing determined by the voltage and kVA ratbe-ing of the unit.

Sheet windings can use either Kraft paper or pressboard paper between layers. After assembly of the windings the entire unit is tightened, or “clamped” down. Th e unit is then baked and vacuum impressed, hot liquid fl ushed for liquid units or epoxy impregnated for dry and gas units, and then tightened again. Th e unit is then installed in its tank, ac-ceptance tested, and prepared for shipment.

The Liquid

Th e most common type of transformers in a transmission and distribution system use insulating oil as a dielectric and cooling medium. Some, depending on their size, have oil-circulating systems for enhanced cooling. Th is is important because heat is the main enemy of any transformer. Steady state operation of a transformer at only 10^o Celsius above its nameplate rating can reduce its life by up to 50%. Heat can breakdown the winding insulation and, under the right conditions, degrade the insulating oil. Th erefore, determin-ing the insulation integrity and oil condition is of primary importance.

Oil is the lifeblood of an oil fi lled transformer. Oil tests can reveal many problems internal to a transformer well before the transformer would fail. Th e advantage of oil testing is that it doesn’t require the transformer to be taken off line. All oil samples can be drawn with the transformer on line, even at 100% load. Oil tests fall into two classifi cations - Oil Screens and Dissolved Gases.

Oil Screens

Historically, the Dielectric Test has been used to determine the condition of transformer oil under the assumption that if it had a high dielectric withstand voltage it had to be OK.

Unfortunately, having a high withstand doesn’t guarantee a soundly operating transformer, as the dielectric test is only aff ected by free water and/or other contaminates in the oil.

As a result, other tests are necessary in order to better evaluate the oil. Standard oil screen tests performed on transformers include:

Karl Fisher, ASTM D-1533-88, tests for water in insulating fl uids. Th is test reveals total water content in oil, both dis-solved and free. High readings could indicate a leak in the equipment housing or insulation breakdown.

Dielectric Breakdown Strength, ASTM D-877 and D-1816, tests for conductive contaminants present in the oil such as metallic cuttings, fi bers, or free water.

Neutralization Number, ASTM D-974, commonly called the acid number, this measurement shows the amount of acid in the oil. Th e acidity is a result of oxidation of the oil caused by the release of water into the oil from insulation material due to aging, overheating, or operational stresses such as internal or through faults. Th e acidity is measured as the number of milligrams of potassium hydroxide (KOH) it takes to neutralize the acid in one gram of oil. An increase in the acidity indicates a deterioration of the oil. Th is process causes the formation of sludge within the windings which in turn can result in premature failure of the unit.

Interfacial Tension(IFT), ASTM D-971, measures the ten-sion at the interface between two immiscible liquids, oil and water. It is expressed in dynes/centimeter. Th is test is extremely sensitive to oil decay products and contamination from solid insulating materials. Good oil will have an IFT of 40 to 50 dynes/cm, and will normally “fl oat” on top of water. As transformer and breaker insulation ages, contami-nates such as Oxygen and free water are released into the oil. Th e properties that allow the oil to “fl oat” on top of the oil then begin to break down and the result is a lower IFT.

Along with the neutralization number, the IFT can reveal the presence of sludge in insulating oils.

Color, ASTM D-1524, as insulating oils in electrical equip-ment age, the color of the oil tends to gradually darken. A marked color change from one year to the next indicates a problem.

Sediment, ASTM D-1698, indicates deterioration and/or contamination of the oil.

Oil Power Factor, ASTM D-924, taken at 25 degrees C, this test can reveal the presence of moisture, resins, varnishes, or other products of oxidation or foreign contaminates such as motor oil and fuel oil. Th e power factor of new oil should always be below .05%.

Visual Examination, ASTM D-1524, good oil is clear and sparkling, not cloudy and dull. Cloudiness indicates the presence of moisture or other contaminates. Th is is a good

“quick look” fi eld test; however a Karl Fisher or Dielectric Breakdown test will be much more defi nitive.

Of all the above tests, the Karl Fischer, Interfacial Tension, Neutralization Number, Dielectric Breakdown, and Oil Power Factor are the most important. Th ese are the oil screen tests that not only need to be looked at, but, unlike traditional analysis, they need to be trended, and when the trends are getting worse the rate of change needs to be examined. (It should be noted that as of today the Dielectric Breakdown test has not been shown to be as eff ective in trending as the other four tests; however its value for determining the voltage withstand capability of insulating fl uid is unquestioned)

> 40 dynes/cm for new oil

Power factor < .5% at 25 degrees C for in-service oil

< .05% at 25 degrees C for new oil Acid number < .15 for in-service oil.

< .05mg KOH/gm for new

Traditional analysis says that as long as the test values do not exceed the standards the transformer is OK. However, lets look at a unit that, while still testing good raises some signifi cant questions.

Th e unit is a 3000kVA, 6.9kV to 480V unit, 10 years old, good operating history. Here is a chart of the last 5 oil screens:

Date Karl Fischer NN IFT Power Factor

2/3/1998 12 0.03 48 0.08%

1/15/1999 18 0.03 44 0.10%

2/4/2000 16 0.05 42 0.22%

1/29/2001 19 0.05 39 0.29%

2/1/2002 24 0.07 31 0.35%

Notice that all four tests are within the standards, and if the only comparison is with the standards then this unit would be classed as good. However, all of the trends are going in a negative direction. Th e graphs show this very well:

From a percentage standpoint, the Karl Fischer has in-creased by 100%, the NN has inin-creased by 133%, the IFT has decreased by 35%, and the Power Factor has increased by 330% Clearly, something is going on inside the trans-former. But what?

Unfortunately, one set or type of test usually can not determine a specifi c problem. Transformer analysis requires looking at multiple tests, and using all the results to reach a conclusion. So let’s look at the next test - dissolved gas analysis, sometimes called Gas-in-Oil analysis or abbrevi-ated as dgio.

Dissolved Gas

Th is test can show many problems internal to a transformer before the problem becomes terminal. As events occur inside a transformer, gasses are liberated into the oil. Th e primary causes of these gases are thermal, mechanical, and electrical stresses in the windings. Some examples are corona discharge (a spark due to ionization), general overheating (overload conditions), arcing, and through-faults (which cause large mechanical stresses).

We are concerned with 9 gasses in this analysis. Th ey are: - Nitrogen(N2)

- Oxygen(O2)

- Carbon Dioxide(CO2) - Carbon Monoxide(CO) - Methane(CH4)

- Ethane(C2H6) - Ethylene(C2H4) - Hydrogen(H2) - Acetylene(C2H2)

Diff erent combinations of these gasses reveal diff erent problems. Large amounts of CO and CO2 indicates over-heating in the windings, CO, CO2, and CH4 show the possibility of hot spots in the insulation, H2, C2H6, and CH4 are indicative of corona discharge, and C2H2 is a sign of internal arcing. After the concentration of each gas (in PPM) has been determined, various industry publications may be used to help determine the potential problem.