TESTING POWER TRANSFORMER

High-voltage (HV) transformers are some of the most important and expensive pieces of

equipment required for operating a power system. The purchase, preparation, assembly,

operation and maintenance of the HV transformers represent a large expense to the power

system.

Power Transformer Overview

When transformers are received from the factory or reallocated from another location it is

necessary to verify the following points:

• That each transformer is dry and has sustain no damage during shipping,
• That the internal connections have not been loosened,
• That the transformer’s ratio, polarity, and impedance agree with its nameplate, 
• That its major insulation structure is intact, and
• The wiring insulation has not been bridged.

Apart from this there are certain factors affecting the amount of testing necessary to certify that a transformer is ready to be energized and placed in service:

• Physical size, voltage class, and kVA rating are the major factors that dictate the amount of preparation required to put transformers in service,
•  Size and kVA rating also dictate the kind and number of auxiliary devices a transformer will require.

Multiple number of checks and tests are performed as a transformer is being assembled

at a substation. The test engineer may not directly perform all of the tests and

inspections but must be sure that they are satisfactorily completed, so that the final decision

over transformer bank readiness for energization can be made. Some tests and procedures are performed by the specialists during the assembly phase. Special tests, other than those listed below, may also be required. Some of the tests require special equipment and expertise that construction electricians do not have and are not expected to provide. Some tests are performed by an assembly crew, while other tests are done by the personnel making the final electrical tests on the transformers.

The following are the details for performing the entire array of tests needed to prepare transformers for service:

• Nameplate Data
• Power Meggering
• Auxiliary Components and Wire Checks
• Lightning Arrestors
• Hand Meggering
• Temperature Devices
• CT Tests
• Winding Temperature and Thermal Image
• Bushing Power Factoring
• Remote Temperature Indication
• Transformer Power Factoring
• Auxiliary Power
• Voltage Ratio
• Automatic Transfer Switch
• Polarity
• Cooling System
• Transformer-Turns Ratio
• Bushing Potential Device
• Tap Changers
• Auxiliary-Equipment Protection and Alarms
• Short-Circuit Impedance
• Overall Loading
• Zero Sequence
• Trip Checks

Before proceeding with transformer measurements following rules must be followed for all the tests. Below is the approximate sequence for transformer testing:

• Inspect transformer and parts for shipping damage and moisture
• Check nameplate and prints for proper voltages and external phasing connection to the line or bus
• Check calibration of all thermal gauges and hot-spot heater, bridge RTDs and associated alarm contacts 
• Check and Megger all wiring point to point: Fans, pumps, alarms, heaters, tap changers, and all other devices on the transformer and interconnecting cables
• All banks above 150 MVA should be vacuum dried. Do not apply test voltages to the winding during the vacuum drying process. Make certain the terminals are shorted and grounded during oil circulation because of the large amount of static charge that can build up on the winding.
• After the tank has been filled with oil, confirm that an oil sample was sent to the Chemical Lab and that its results are entered in the bank test reports. Note the oil level and temperature at completion of filling.
• Power operate to verify proper rotation of pumps and fans and correct operation of the under load (UL) tap changer, when provided. Also, check heater, alarms and all other devices for proper operation.
• Winding tests
• Ratio and Polarity (Voltage Method or TTR). The preference is that all large power Transformers (>1 MVA) be tested with TTR test set.
• Impedance
• DC winding resistance
• Megger and Power Factor windings, bushing and arrestors. (Wait until 24 hours after completion of oil filling for Power Factor testing).
• Load CT circuits overall and flash for polarity
• Before energization, trip-check bank protection schemes and make sure the gas collection relay is free of gas.
• When energizing a bank or picking up load, monitor bank currents and voltages, including UL tap-changer operation.
• Check proper phasing and voltage of the bank to the system before load is picked up. When possible, large transformers (>1 MVA) should remain energized for eight hours before carrying load.
• Make in-service checks on meters and relays.
• Release to Operations and report energization information to the TNE office.
• Turn in revised prints and test reports, which should include the following:
• All test data
• Moisture and oil data
• Problems incurred
• In-service data
• Time energized and release to operation
• Any unusual problem that information will aid in future equipment testing

Detailed procedure to be continued...

Detailed Discussion on Dissolved Gas Analysis of Power Transformer Oil

Introduction
Transformer is one of the most important and complex component in any electrical establishment, therefore much attention is needed on maintenance of the transformers in order to have a fault free service and to maximize the efficiency and lifetime of the transformer.


Dissolved Gas Analysis (DGA) is the study of the dissolved gases in transformer oil and is the most accepted preventive and maintenance tool for the electrical power industry for over three decades. Even though DGA continues to be the most important component in assessing the condition of the transformer, but the demands imposed by the increasing loading of transformers and the aging of the transformer population require new tools and diagnostic approaches. It has been suggested that the 70% of the transformers condition is contained within the insulating oil and periodic checking of these conditions could provide us with the exact condition of the transformer.

Why DGA is important?

DGA is the most effective means of oil sampling and monitoring the condition of oil-filled electrical equipment such as transformers, etc. The analysis gives us detailed description of the types of dissolved gases in the oil, the amount, generation, relative proportion and the changes over time gives us information about, what is happening in the transformer?.

Every possible fault generates one or more gases arising from the subsequent increased degradation of adjacent oil or cellulosic insulation, hence DGA is considered to be comprehensive in responding to many faults. Moreover, since in the early stages these fault gases dissolve in the oil and can then be detected at later point in time when an oil sample is taken, DGA can detect intermittent faults. Also, because fault gases can be detected at very low levels, the DGA technique is very sensitive and extremely suitable for detecting faults at an early stage. Most guides for interpreting DGA results include, and concentrate on, schemes for diagnosing faults, usually by analyzing the relative concentrations of the various fault gases, so the technique can also be described as discerning and contributing to diagnosis as well as the detection of faults.

The main difficulty in making use of DGA results, which arises from its very good sensitivity, is that it is not easy to draw the line between normal and abnormal results, i.e. to be sure that a fault really exists. Most, but not all, interpretation schemes include a normal condition as one of the diagnostic outcomes, but have not been particularly effective in reliably identifying a normal condition.

Dissolved gases

For details please refer previous pages of the blog.

Diagnostic DGS - Characteristics

Diagnostic DGS - Characteristics
Fault indicator gases

CO2/CO ratio should be in the range of 1:10, if this ratio decreases to 1:3 or less, overheating of cellulose is most likely to occur.
O2/N2 this ratio should be maintained at less than 1:10, in order to prolong the life of the fluid in the transformer.

Solubilité des gaz dans l'huile de transformateur (Ref. http://www.nttworldwide.com)

Distribution typique de gaz de défaut de condition différente (Corona, pyrolyse, Arcing)
(Ref. http://www.nttworldwide.com)

Normal values of dissolved gas in oil

Dissolved gas concentration limit (ppm)

Condition 1 - TDCG below this level indicates that the transformer is operating satisfactorily
Condition 2 - TDCG within this range indicates greater than normal combustible levels & should prompt additional investigation. (any gas exceeding specified levels)
Condition 3 - TDCG within this range indicates high level of decomposition (additional investigation required)
Condition 4 - TDCG within this range indicates excessive decomposition, continued operation could result in the failure of the transformer.

Diagnostic DGA - Methods
Method of gas ratios:

• IEC 60599
• Rogers
• Dornenburg

Duval Triangle
Gas patterns (EPRA Japan)

Dornenburg Chart (Ref: http://www.nttworldwide.com)

Duval Triangle

    

Key Ratios                                                                                                

• CH4/H2                Partial discharge
• C2H4/C2H6         Oil overheating
• C2H2/C2H4         Arcing
• C2H2/C2H6         Electrical discharges

Auxiliary Ratios

• C2H2/H2             Contamination OLTC
• C2H2/C2H4        Identification of thermal defects OLTC
• CO2/CO             Cellulose overheating
• N2/O2                 Oxygen consumption, bad sealing

Gas Ratios Method (IEC 60599)

Rogers Method (IEEE)

Gas patterns

Water Content (Ref: IEC 60422)
Depending on the amount of water, the temperature of the insulating system and the status of the oil, the water content of the insulating oil influences:

• The breakdown voltage of the oil.
• The solid insulation.
• The ageing tendency of the liquid and solid insulation. 

Two main sources of water increase in transformer insulation:

• Ingress of moisture from the atmosphere.
• Degradation of cellulose and oil.

The solubility of water in oil, given in mg/kg (ppm), depends on the condition of the oil, the temperature and type of oil. Wabs (the absolute water content) is independent of the temperature type and condition of the oil and the result is given in mg/kg. Wabs can be measured according to IEC 60814.

Water solubility should be determined at the same temperature as the oil has been taken.

Sampling temperature at or above 20 °C
For the proper interpretation of moisture content, the analytical result of water content of the oil at a given sampling temperature needs to be corrected to that at a defined temperature.
For practical reasons, the defined temperature is set at 20 °C, since below 20 °C the rate of diffusion of water is too slow to achieve equilibrium in operational equipment.