Learning objectives

• Elements of preventive maintenance
• Benefits of EPM
• Planning an EPM
• Production economics
• Energy conservation
• Record keeping

1.1 Introduction

Preventative maintenance (PM) is a program of routine equipment inspections, maintenance tasks and repairs which are scheduled to ensure that degradation of equipment is minimized. A well planned and designed preventative maintenance program keeps equipment/facilities in satisfactory operational state by providing for systematic inspection, detection, and correction of incipient failures either prior to their occurrence or prior to their development into major failure.

Predictive maintenance is the technique of regularly monitoring selected parameters of equipment operation to detect and correct a potential problem before it causes a failure. This is done by trending measured parameters which allows a comparison of current parameters to historical data. From this approach ensures that the right maintenance activities are performed at the right time.

The main objectives of PM are to:

• enhance capital equipment productive life
• reduce critical equipment breakdowns
• allow better planning and scheduling of needed maintenance work
• minimize production losses due to equipment failures, and
• promote health and safety of maintenance personnel

If maintenance is carried out reactively, in response to interruptions, breakdowns and other unfortunate events, then this kind of approach can be severe, especially at operations such as processing plants, assembly lines and power plants, where the failure of a relatively minor component can disrupt the entire facility. The total cost of downtime and emergency around-the-clock repairs can be overwhelming. Where as a preventive maintenance program ensures continuity of operation and reduces the danger of unplanned outages. Planned shutdowns during periods of least usage, helps in detecting troubles in the early stages and corrective action taken before extensive damage is done.

Table 1.1 shows results of the survey conducted by the IEEE Industrial Commercial Power Systems Committee.

Deterioration of electrical equipment is inevitable whereas the equipment failure is not inevitable. The deterioration process can cause malfunction or an electrical failure. An effective EPM program identifies and recognizes these factors and provides measures for coping with them.

Other potential causes of equipment failure can be detected and corrected through EPM, such as load changes, voltage conditions, improperly set protective relays and changes in circuits.

1.1.1 Elements of preventive maintenance

The following are the seven elements of preventive maintenance (seen in Figure 1.1):

• Inspection: Periodically inspecting materials/items to determine their serviceability by comparing their physical, electrical, mechanical, etc., characteristics (as applicable) to expected standards.
• Servicing: Cleaning, lubricating, charging, preservation, etc., of items/ materials periodically to prevent the occurrence of incipient failures.
• Calibration: Periodically determining the value of characteristics of an item by comparison to a standard; it consists of the comparison of two instruments, one of which is certified standard with known accuracy, to detect and adjust any discrepancy in the accuracy of the material/parameter being compared to the established standard value.
• Testing: Periodically testing or checking out to determine serviceability and detect electrical/mechanical-related degradation
• Alignment: Making changes to an item’s specified variable elements for the purpose of achieving optimum performance.
• Adjustment: Periodically adjusting specified variable elements of material for the purpose of achieving the optimum system performance.
• Installation: Periodic replacement of limited-life items or the items experiencing time cycle or wear degradation, to maintain the specified system tolerance.

1.1.2 Benefits of EPM

AS per NFPA 70B (National Fire Protection Association) standard, benefits of an effective EPM program fall into two general categories:

• Direct, measurable economic benefits – derived from reduced cost of repairs and reduced equipment downtime.
• Less measurable but very real benefits – result from improved safety.

Direct, measurable economic benefits can be documented by equipment repair cost and equipment downtime records after an EPM program has been implemented.

• A well-administered EPM program reduces accidents, saves lives, and minimizes costly breakdowns and unplanned shutdowns of production equipment.
• Improved employee morale — reduces injuries and property loss. Improved employee moral, comes with employee awareness of a conscious management effort to promote safety by reducing the likelihood of electrical injuries or fatalities, electrical explosions, and fires.
• Reduced personnel injuries, better workmanship and increased productivity, reduced absenteeism, reduced interruption of production, and improved insurance considerations.
• Equipment lasts longer and performs better
• Investment in EPM is small compared with the cost of equipment repair and the production losses associated with an unexpected equipment shutdown.
• With proper planning, maintenance costs can be held to a practical minimum, while production is maintained at a practical maximum.
• An effective EPM program satisfies an important part of management’s responsibility for keeping costs down and production up.

Maintenance costs can be placed in either of two basic categories: preventive maintenance or breakdown repairs. The money spent for preventive maintenance will be reflected as less money required for breakdown repairs. An effective EPM program holds the sum of these two expenditures to a minimum. Figure 1.2 is a typical curve illustrating this principle. According to this curve, as the interval of time between EPM inspections increases, the cost of the EPM diminishes and the cost of breakdown repairs and replacement of failed equipment increases. The lowest total annual expense is realized by maintaining an inspection frequency that keeps the sum of repair/replacement and EPM costs at a minimum (Refer NFPA 70B Recommended Practice for Electrical Equipment Maintenance).

1.2 Planning an EPM

The purpose of an EPM program is to reduce hazard to life and property that can result from the failure of electrical systems and equipment. A preventive maintenance program can only be effective if it is both well planned and regularly carried out. Planning involves understanding the electrical system, identifying and prioritizing equipment maintenance requirements and then establishing a maintenance schedule.

AS per NFPA 70B standard, the following basic factors should be considered while planning an EPM program:

• Personal safety
• Equipment maintenance
• Production economics

1.3 Production economics

Maintenance costs are usually due to manhours, materials and indirect costs. Preventive maintenance should be done when production is least effected. Assessing the costs of equipment downtime is an important step in the determination of costs of preventive maintenance.

A system in general is a complex configuration of different units, which may imply that downtime of one unit, does not necessarily halt the full system. It is important to identify which unit is most vital to production, and analyze the effect of repair or replacement of the unit on the production.
The failure of one component often is an opportunity to preventively maintain other components. Especially if the failure causes the breakdown of the production system it is favorable to perform preventive maintenance on other components. In such cases, only a little or no production is lost above that resulting from the original failure.

Maintenance scheduling in line with the production can reduce the good maintenance plan, one that is integrated with the production plan, can result in considerable cost savings. This integration with production is crucial because production and maintenance have a direct relationship. Any breakdown in machine operation results in disruption of production and leads to additional costs due to downtime, loss of production, decrease in productivity and quality, and inefficient use of personnel, equipment and facilities.

Selection of quality equipment that is adequate for the present and projected load growth is a can reduce the maintenance cost. Too often, installation cost without sufficient regard for efficient and economic maintenance influences system design. Within a few years, the added cost of performing maintenance plus production loss from forced outages due to lack of maintenance will more than offset the savings in initial cost.

1.4 Energy conservation

Equipment that is well maintained operates more efficiently and utilizes less energy. Energy management incorporates engineering, design, applications, operation and maintenance of electrical power system to provide for the minimum overall use of the electrical energy. Optimized use of electrical energy involves factors such as comfort, healthful working conditions, the practical aspects of productivity, aesthetic acceptability of the space, and public relations.

Any process requires a certain minimum consumption of energy. Energy additions beyond this minimum consumption require an evaluation of the incremental cost of more efficient or techniques versus the resulting energy savings or costs. Energy conservation can be obtained by proper maintenance and operation as follows:

• Shutting off unused equipment, eliminating steam, compressed air and heat leaks, proper lubrication of equipment, proper cleaning and replacement of filters in equipment
• Equipment and process modifications should be taken into considerations during designing and planning, such as using more durable or more efficient components, more efficient design concepts or replacement of an existing process with an energy efficient process.
• Better utilization of equipment can be achieved by properly examining the production processes, schedules, and operating practices.
• Energy survey and energy balances identify energy wasting situations and differentiate between identify energy corrected by maintenance and operation actions from those that require capital expenditures.
• Power quality improvement – Energy savings can be achieved by improving the quality of the power supply to the utilization equipment.
• The I2R losses in electrical conductors can be reduced by selecting an increased wire size in cabling and by using a heavier cross section in busbars.
• Energy savings can be achieved by specifying and purchasing efficient transformers and operating the transformer efficiently.
• Provide zoning capability to shut down unused areas.

1.5 Record keeping

Records should be maintained by the management; analysis of the records should guide the breakdown repair and evaluate the results. They should contain accurate and vital information. Excessive record keeping will disrupt the EPM program. Usually records are classified into four categories:

• Maintenance work records
• Maintenance cost
• Inventory
• Maintenance files

Maintenance work records contain documentation of all the repairs and maintenance performed during the equipment service life to date. Cost records contain chronological records of profiles, labor, material costs by item. Figures should be kept to show the total cost of each breakdown. Inventory records contain information of equipment number, size and type, cost, date of manufacture or acquire, manufacturer, location of the equipment, etc. Other files include drawings, operating manuals, service manuals etc.

Record keeping is a practice and useful to determine operating performance trends, troubleshooting breakdowns, replacement or modification decisions, investigating faults, performing reliability and maintainability studies.

2.1 Introduction

The purpose of planning an EPM program is to reduce hazard to life and property that can result from the failure or malfunction of electrical systems and equipment. This chapter explains the various steps involved in planning like survey of the installation, documenting the installation modifications, data and diagrams needed to maintain the installation, procedures for maintenance and inspection.

The following four basic steps should be considered in the planning and development of an EPM program.

• Compile a listing of all equipment and systems.
• Determine which equipment and systems are most critical and most important.
• Develop a system for keeping up with what needs to be done.
• Train people for the work that needs to be done or contract the special services that are needed.

The caliber of personnel responsible for its implementation, decide the success of an EPM program. The primary responsibility for EPM program implementation and its success lies with a single individual.

This individual responsible for the EPM program should be given the authority to do the job and should have the cooperation of management, production, and other departments whose operations might affect the EPM program.

Ideally, the person designated to head the EPM program should have the following qualifications:

• Technical competence. The person should, by education, training, and experience, be well-rounded in all aspects of electrical maintenance.
• Administrative and supervisory skills. The person should be skilled in the planning and development of long-range objectives to achieve specific results and should be able to command respect and solicit the cooperation of all persons involved in the program.

The maintenance supervisor should have open lines of communication with design supervision. Frequently, an unsafe installation or one that requires excessive maintenance can be traced to improper design or construction methods or misapplication of hardware.

The work center of each maintenance work group should be conveniently located. This work center should contain the following:

• Copies of all the inspection and testing procedures for that zone
• Copies of previous reports
• Single-line diagrams
• Schematic diagrams
• Records
• Vendors’ catalogs
• Facility stores’ catalogs
• Supplies of report forms

There should be adequate storage facilities for tools and test equipment that are common to the group.

In a continuously operating facility, running inspections (inspections made with equipment operating) play a vital role in the continuity of service. The development of running inspection procedures changes with the type of operation. Running inspection procedures should be as thorough as practicable within the limits of safety and the skill of the craftsman. These procedures should be reviewed regularly in order to keep them current. Each failure of electrical equipment, be it an electrical or a mechanical failure, should be reviewed against the running inspection procedure to determine if some other inspection technique would have indicated the impending failure. If so, the procedure should be modified to reflect the findings.

Supervisors have a good scope for best motivational opportunities through handling the results of running inspections. When the electrical maintenance supervisor initiates corrective action, the craftsperson should be so informed. The craftsperson who found the condition will then feel that his or her job was worthwhile and will be motivated to try even harder. However, if nothing is done, individual motivation might be affected adversely.

Trends in failure rates are hard to change and take a long time to reverse. For this reason, the inspection should continue and resulting work orders should be written, even though the work force might have been reduced. Using the backlog of work orders as an indicator, the electrical maintenance supervisor can predict trends before they develop. With the accumulation of a sizable backlog of work orders, an increase in electrical failures and production downtime can be expected.

2.2 Survey of electrical installations

2.3 Installation modifications

The documentation of the changes that result from engineering decisions, planned revisions, and so on, should be the responsibility of the engineering group that initiates the revisions.

Periodically, changes occur as a result of an EPM program. The EPM program might also uncover undocumented practices or installations.

A responsibility of the EPM program is to highlight these changes, note them in an appropriate manner, and formally submit the revisions to the organization responsible for the maintenance of the documentation.

2.4 Forms and records

2.5 Emergency procedures

Emergency procedures should list, step by step, the action to be taken in case of emergency or for the safe shutdown or start-up of equipment or systems. To make optimum use of these procedures, they are bound for quick reference and posted in the area of the equipment or systems. Some possible items to consider for inclusion in the emergency procedures are interlock types and locations, interconnections with other systems, and tagging procedures of the equipment or systems. Accurate single-line diagrams posted in strategic places are particularly helpful in emergency situations. The production of such diagrams in anticipation of an emergency is essential to a complete EPM program. Diagrams are a particularly important training tool in developing a state of preparedness. Complete and up-to-date diagrams provide a quick review of the emergency plan. During an actual emergency, when time is at a premium, they provide a simple, quick reference guide.

In the emergency situations, properly trained electrical maintenance personnel can make an important contribution. However, most such situations will also involve other crafts and disciplines, such as operating personnel, pipe fitters, and mechanics. An overall emergency procedure for each anticipated emergency situation should be developed by the qualified personnel of each discipline involved working as a team. The procedure should include detailed steps to be followed, sequence of steps, and assignment of responsibility. Each of these emergency procedures must be run periodically as a drill to ensure that all involved personnel are familiar with the tasks they are to perform as and when the emergency arises.

2.6 Identification of critical equipment

Equipment (electric or otherwise) should be considered critical if its failure to operate normally and under complete control will cause a serious threat to people, property, or the product. Electric power, like process steam, water, and so forth, might be essential to the operation of a machine, but unless loss of one or more of these supplies causes the machine to become hazardous to people, property, or production, that machine might not be critical. The combined knowledge and experience of several people might be needed to make this determination. In a small plant, the plant engineer or master mechanic working with the operating superintendent should be able to make this determination.

A large operation should use a team comprising the following qualified people:

• The electrical foreman or superintendent
• Production personnel thoroughly familiar with the operation capabilities of the equipment and the effect its loss will have on final production
• The senior maintenance person who is generally familiar with the maintenance and repair history of the equipment or process
• A technical person knowledgeable in the theoretical fundamentals of the process and its hazards (in a chemical plant, a chemist; in a mine, a geologist; etc.)
• A safety engineer or the person responsible for the overall security of the plant and its personnel against fire and accidents of all kinds

The team should go over the entire plant or each of its operating segments in detail, considering each unit of equipment as related to the entire operation and the effect of its loss on safety and production.

There are entire systems that might be critical by their very nature. Depending on the size and complexity of the operation, a plant can contain any or all of the following examples: emergency power, emergency lighting, fire-alarm systems, fire pumps, and certain communications systems. There should be no problem in establishing whether a system is critical and in having the proper amount of emphasis placed on its maintenance.

More difficult to identify are the parts of a system that are critical because of the function of the utilization equipment and its associated hardware. Some examples are as follows:

• The agitator drive motor for a kettle-type reactor can be extremely critical in that, if it fails to run for some period of time, when the charge materials are added to the reactor, the catalyst stratifies. If the motor is then started, a rapid reaction, rather than a slow, controlled reaction, could result that might run away, over pressurize, and destroy the reactor.
• The cooling water source of an exothermic reactor might have associated with it some electrical equipment such as a drive motor, solenoid valves, controls, or the like. Failure of the cooling water might allow the exothermic reaction to go beyond the stable point and over pressurize and destroy the vessel.
• A process furnace recirculation fan drive motor or fan might fail, nullifying the effects of temperature-sensing points and thus allowing hot spots to develop, with serious side reactions.
• The failure of gas analysis equipment and interlocks in a drying oven or annealing furnace might allow the atmosphere in the drying oven or furnace to become flammable, with the possibility of an explosion.
• The failure of any of the safety combustion controls on a large firebox, such as a boiler or an incinerator, can cause a serious explosion.
• Two paralleled pump motors might be needed to provide the total requirements of a continuous process. Failure of either motor can cause a complete shutdown, rather than simply reduce production.

There are parts of the system that are critical because they reduce the widespread effect of a fault in electrical equipment. The determination of these parts should be primarily the responsibility of the electrical person on the team. Among the things that fall into this category are the following:

• Source overcurrent protective devices, such as circuit breakers or fuses, including the relays, control circuits, and coordination of trip characteristics of the devices
• Automatic bus transfer switches or other transfer switches that would supply critical loads with power from the emergency power source if the primary source failed; includes instrument power supplies as well as load power supplies

Parts of the control system are critical because they monitor the process and automatically shut down equipment or take other action to prevent catastrophe. These items are the interlocks, cutout devices, or shutdown devices installed throughout the plant or operation. Each interlock or shutdown device should be considered carefully by the entire team to establish whether it is a critical shutdown or a “convenience” shutdown. The maintenance group should thoroughly understand which shutdowns are critical and which are convenience. Critical shutdown devices are normally characterized by a sensing device separate from the normal control device. They probably have separate, final, or end devices that cause action to take place. Once the critical shutdown systems have been determined, they should be distinctly identified on drawings, on records, and on the hardware itself. Some examples of critical shutdown devices are overspeed trips; high or low temperature, pressure, flow, or level trips; low-lube-oil pressure trips; pressure-relief valves; overcurrent trips; and low-voltage trips.

There are parts of the system that are critical because they alert operating personnel to dangerous or out-of-control conditions. These are normally referred to as alarms. Like shutdown devices, alarms fall into at least three categories:

• Those that signify a true pending catastrophe,
• Those that indicate out-of-control conditions, and
• Those that indicate the end of an operation or similar condition.

The entire team should consider each alarm in the system with the same thoroughness with which they have considered the shutdown circuits. A truly critical alarm should be characterized by its separate sensing device, a separate readout device, and, preferably, separate circuitry and power source. The maintenance department should thoroughly understand the critical level of each alarm. The critical alarms and their significance should be distinctly marked on drawings, in records, and on the operating unit. For an alarm to be critical does not necessarily mean that it is complex or related to complex action. A simple valve position indicator can be one of the most critical alarms in an operating unit.

2.7 Frequency of maintenance

Frequency of maintenance cannot be fixed as the recommended frequency depends on environmental and operating conditions of an application.

2.8 Frequency of inspection

Those pieces of equipment found to be critical should require the most frequent inspections and tests. Depending on the degree of reliability required, other items can be inspected and tested much less frequently.

Manufacturers’ service manuals should have a recommended frequency of inspection. The frequency given is based on standard or usual operating conditions and environments. It would be impossible for a manufacturer to list all combinations of environmental and operating conditions. However, a manufacturer’s service manual is a good basis from which to begin considering the frequency for inspection and testing.

An annual inspection of the entire switchgear assembly, including withdrawable elements during the first 3 years of service, is usually suggested as a minimum when no other criteria can be identified.

There are several points to consider in establishing the initial frequency of inspections and tests. Electrical equipment located in a separate air-conditioned control room or inspection interval might be extended 30 percent. However, if the equipment is located near another unit or operating plant that discharges dust or corrosive vapors, this time might be reduced by as much as 50 percent.

Continuously operating units with steady loads or with less than the rated full load tend to operate much longer and more reliably than intermittently operated or standby units. For this reason, the interval between inspections might be extended 10 to 20 percent for continuously operating equipment and possibly reduced by 20 to 40 percent for standby or infrequently operated equipment.

Once the initial frequency for inspection and tests has been established, this frequency should be adhered to for at least four maintenance cycles unless undue failures occur. For equipment that has unexpected failures, the interval between inspections should be reduced by 50 percent as soon as the trouble occurs. On the other hand, after four cycles of inspections have been completed, a pattern should have developed. If equipment consistently goes through more than two inspections without requiring service, the inspection period can be extended by 50 percent. Loss of production due to an emergency shutdown is almost always more expensive than loss of production due to a planned shutdown. Accordingly, the interval between inspections should be planned to avoid the diminishing returns of either too long or too short an interval.

Adjustment in the interval between inspections should continue until the optimum interval is reached. This adjustment time can be minimized and the optimum interval approximated more closely initially by providing the person responsible for establishing the first interval with as much pertinent history and technology as possible.

Inspection frequency can be increased or decreased depending on observations and experience. It is good practice to follow specific manufacturers’ recommendations regarding inspection and maintenance until sufficient knowledge is accumulated that permits modifying these practices based on experience. It is recommended that frequent inspections be made initially; the interval can then be gradually extended as conditions warrant.

The frequency of inspection for similar equipment operating under differing conditions can differ widely. Typical examples are as follows:

• In a continuously operating plant having a good load factor and located in a favorable environment, the high voltage oil circuit breakers might need an inspection only every two years. On the other hand, an electrolytic process plant using similar oil circuit breakers for controlling furnaces might find it necessary to inspect and service them as frequently as every 7 to 10 days.
• An emergency generator to provide power for noncritical loads can be tested on a monthly basis. Yet the same generator in another plant having processes sensitive to explosion on loss of power might need to be tested during each shift.

2.9 Test and maintenance requirements

2.10 Establishment of a systematic program

The purpose of any inspection and testing program is to establish the condition of equipment to determine what work should be done and to verify that it will continue to function until the next done in conjunction with routine maintenance. In this way, many minor items that require no special tools, training, or equipment can be corrected as they are found. The inspection and testing program is probably the most important function of a maintenance department in that it establishes what should be done to keep the system in service to perform the function for which it is required.

Learning objectives

• To familiarize the reader with the purpose and application of one line and three line diagrams.
• To familiarize the reader with the purpose and application of logic and ladder diagrams.
• To familiarize the reader with the purpose and application of cabling and wiring diagrams.

3.1 Electrical diagrams

Engineers and technical personnel associated with an engineering organization use drawings to convey graphically the ideas and plan necessary for execution and completion of a project involving construction or assembly of components or systems. Drawings work as a tool for problem solving at various stages of working in an organization. The drawings are at the centre of activities taking place in an engineering organization whether a manufacturing organization or a turnkey contracting organization. Every effective troubleshooter must be able to read these drawings in order to quickly find failures in electrical controls. Technical drawings are used to convey a large amount of exact, detailed information in an abbreviated language. They consist of lines, symbols, dimensions, and notations to accurately convey an engineer’s designs to electricians/technicians who install the electrical system on a job. Some of the types of electrical drawings used for any project can be categorized as block diagrams, layout drawings, single line diagrams, wiring diagrams etc. All drawings should be prepared in line with the international standards mentioned above or any company specific standards.

3.2 What is a single line diagram?

A single line diagram (SLD), also sometimes called a one-line diagram, is a drawing that shows by single lines and symbols a simplified layout of a three-phase electrical system. It is a schematic drawing of an electrical power system that uses a concise, standard notation accepted by all power engineers. Single line or one-line diagrams get their name from the fact that only one phase of a three-phase system is shown and only one line is used to represent any number of current carrying conductors. Standard symbols are used to represent components of power systems, such as transformers, circuit breakers, generators, fuses and switches.

3.2.2 Typical examples

A typical example for single line diagrams are given below:

Figure 3.1 shows the power distribution system in a plant with 13.8 kV incomers. Voltage and current transformers are provided with relays for protection and metering. Voltage is stepped down to 480 Volts through 1000 kVA transformers through ACB of 1200 Amps. Output from the transformers is fed to the medium voltage switchgear with outgoing feeders for large motors and auxiliary transformers/ other distribution boards. Power from the MV switchboard is further step down transformers for lighting and control supply. The MV switchboard also has a bus-coupler of 1200 Amp for coupling of the two incomers.

3.3 Three-line diagrams

The 3-line diagram shows the different components of the circuit as simplified standard symbols, and the power and signal connections between the devices. Arrangement of the component interconnections on the diagram does not correspond to their physical locations in the finished device. Figure 3.2 shows a simple 3-line diagram for a motor DOL starter.

3.4 Common terms associated with electrical diagrams

Some of the common terms associated with the single line diagram are listed in Table

3.5 Protective relays

Protective relays are commonly used in single line diagrams for denoting protective devices used for generators, motors, transformers etc. Protective relays are denoted through numbers designated by IEEE/ANSI. A device could also be a combination of two relays e.g. 50/51 denotes a combination of instantaneous over current and time over current. Letters can be added to clarify application (87 T for transformer differential, 59G for ground over voltage). The list of relay numbers as per ANSI is provided below:

2 – Time Delay Starting or Closing Relay

3 – Checking or Interlocking Relay

21 – Distance Relay

24 – Over-Excitation Relay

27 – Undervoltage Relay

30 – Annunciator Relay

32 – Directional Power Relay

37 – Undercurrent or Underpower Relay

44 – Unit Sequence Starting Relay

46 – Reverse-phase or Phase-Balance Relay

47 – Phase-Sequence Voltage Relay

48 – Incomplete-Sequence Relay

49 – Machine or Transformer Thermal Relay

50 – Instantaneous Overcurrent

51 – AC Time Overcurrent Relay

53 – Exciter or DC Generator Relay

55 – Power Factor Relay

56 – Field Application Relay

58 – Power Rectifier Misfire Relay

59 – Overvoltage Relay

60 – Voltage or Current Balance Relay

62 – Time-Delay Stopping or Opening Relay

64 – Ground Detector Relay

67 – AC Directional Overcurrent Relay

68 – Blocking Relay

74 – Alarm Relay

76 – DC Overcurrent Relay

79 – AC-Reclosing Relay

81 – Frequency Relay

82 – DC-Reclosing Relay

83 – Automatic Selective Control or Transfer Relay

85 – Carrier or Pilot-Wire Receiver Relay

86 – Lockout Relay

87 – Differential Protective Relay

91 – Voltage Directional Relay

92 – Voltage and Power Directional Relay

96 – Autoloading Relay

3.6 Abbreviations

Abbreviations are frequently used in electrical diagrams. Table 3.3 identifies a few commonly used abbreviations.

3.7 Schematic Diagrams

The purpose of electric circuits is to direct and control current flow, at the correct time, to the various components in any system. A broken wire or open switch or wiring error can stop the current from flowing, thereby preventing the system, or part of the system from functioning. A schematic diagram shows an electrical circuit in detail. By clearly depicting individual current paths, it also indicates how the electrical circuit operates. Most schematic diagrams are current flow diagrams. They are arranged from top to bottom, so that we can clearly see how the current flows through the circuit. It shows the different components of the circuit as simplified standard symbols, and the power and control connections between the devices. Unlike the single line or the block diagram, the schematic diagram shows the actual connection details.

Schematic diagrams are usually spread over a number of sheets and the different sheets provide the following details:

• Title sheet
• Three line diagram
• Power distribution circuits
• Control circuits
• Terminal diagrams

An example of schematic diagram for the motor control centre for a press machine is provided in Figure 3.3. The sheet-wise details are as below:

Sheets 1 and 2: Motor power circuit

Sheet 3: Power circuit diagrams for service plugs and cabinet lamps

Sheet 4: Power circuit for transformer and bridge rectifier for getting 24 V DC from 380 volts AC and

Sheet 5: Alarm circuits for field pressure switches (low and high pressure switch contacts).

Sheet 6: Emergency circuits for press machine stopping

Sheet 7: interlock circuits for emergency stop from external panel, overload relays, tool safety position sensor contacts.

Sheets 8, 9, 10: Fault indication and interlock circuits

3.8 Logic Diagrams

Logic diagrams are easy to read graphic representations of the operation of system equipment controls using basic digital logic symbols. These symbols functionally relate manual and process input actions to the process control and operator display output actions. The logic diagram in itself does not provide the details of the hardware to be used or the details of the control signal levels but it works as a basis for other drawings such as electrical schematics or solid-state logic systems.

Before the advent of solid-state logic circuits, logical control systems were designed and built exclusively around electromechanical relays. Relays are far from obsolete in modern design, but have been replaced in many of their former roles as logic-level control devices, relegated most often to those applications demanding high current and/or high voltage switching. Solid state logic circuits are in common use now and these are based on voltage levels. These are designed to input and output only two types of signals: ‘high’ (1) and ‘low’ (0), as represented by a variable voltage: full power supply voltage for a ‘high’ state and zero voltage for a ‘low’ state.
Figure 3.4 shows the control logic for a solenoid valve which can be operated automatically in ‘Auto’ mode or manually through a hand switch with ‘OPEN’, ‘CLOSE’ and ‘AUTO’ positions. A limit switch in the field sends a signal that the valve is fully open. Only when this signal is activated, the valve remains open in the ‘AUTO’ mode. Otherwise it remains open as long as the hand switch is manually kept at the “œOPEN’ position.

3.9 Ladder Diagrams

A ladder diagram reflects a conventional wiring diagram (Figure 3.5). A wiring diagram shows the physical arrangement of the various components (switches, relays, motors, etc.) and their interconnections. The ladder diagrams are more schematic and show each branch of the control circuit on a separate horizontal row (the rungs of the ladder). They emphasize the function of each branch and the resulting sequence of operations. The base of the diagram shows two vertical “rails” one connected to a voltage source and the other to ground, and a series of horizontal “rungs” between them.

Ladder logic is widely used to program PLCs, where sequential control of a process or manufacturing operation is required. Ladder logic is useful for simple but critical control systems, or for reworking old hardwired relay circuits. As programmable logic controllers became more sophisticated it has also been used in very complex automation systems.

3.10 Plant Cabling Systems Drawing

Cabling drawings are a part of the detailed design and engineering activity of a project. These drawings are usually prepared on the basis of the single line diagram, the load schedule, equipment schedule and piping/plant layout drawings.

3.10.1 Cable/conduit/tray schedules

The intent of the conduit, cable and tray schedule is to provide all pertinent information to assist in installing, connecting, identifying, and maintaining control and power cables. Each cable and conduit should be identified with an individual designation. The cable and conduit are tagged with a designation at each end and at intermediate points as necessary to facilitate identification. The designation is also shown on equipment wiring diagrams, tray loading diagrams, on conduit plans and details, on cabinet layouts, and on junction and pull box layouts.

An example of cable schedule is provided in Figure 3.6.

3.10.2 Cable layouts

Cable layouts are prepared on the basis of the plant layout, electrical layout/ equipment layout, power distribution system layout and the load schedule. This is a diagram which shows the layout of the plant cabling system.

Cable layouts comprise of the following:

• Cable tray layouts: These provide details of the cable tray routing, support systems, cross sectional details etc(example is shown in Figure 3.7).
• Conduit and wiring layouts: These are provided mostly for lighting and utility circuits.
• Cable layout for underground cables: These provide details of duct banks, cable trenches, concrete troughs, etc.
• Pull box/junction box layout. (Pull box is an enclosure for joining conductors which also provides by its size, arrangement, and location the necessary facilities for pulling the conductors into place. This term as used here includes structures also known as ‘manhole’, ‘hand hold’, and ‘switch board pull section’.)
• Details for duct banks (A duct bank protects electrical lines that are beneath the ground from accidental breakage. They consist of electrical cables within round ducts encased in reinforced concrete in paved/unpaved areas, crossings). Details of cable trenches (Please refer to Figure 3.11 for sectional detail of a cable trench).
• Cable identifications and markings.
• Details of cable mounting on rack, cable fastening systems, conduit support systems.
• Details of cable termination and mounting diagrams (if required or can be provided separately).

Figure 3.8 is an example of a plan drawing showing layout of cable from the Motor Control Centre to the Pump Area. The tag numbers of the cables both power and control which are passing through the cable trench are mentioned in the drawing. For example P001 is the power cable and C 001 is the control cable connected to the motor 3580-NPP-001/M1 and so on.

Figure 3.9 is an example of Wiring Diagram for conduits (indoor illumination and utility power supply). The drawing provides the details of the circuit number for the conduits and their connection scheme with the lighting fixtures, power sockets etc. The legend in the drawing shows details for the fixtures and utilities.

Learning objectives

• Hazards of a general nature in industrial installations
• Electrical hazards, direct and indirect contacts
• Protective earthing and earth faults
• Dangers of static electricity and its control
• Requirements for safe working on electrical installations
• Technical , preventive and organizational measures in the work place and certification of competency
• Electric arc and arc flash protection

Note:
In this text, the term ‘earth’ has generally been used to represent the reference point of power supply system, in accordance with the practice followed in UK literature and standards. ‘Earthing’ refers to connections of exposed metallic parts to this reference point. Depending on the context, ‘earth’ may also mean soil mass and ‘earthing’ may stand for the connection of the reference point to the soil mass. The terms ‘ground’ and ‘grounding’ common in the North American practice have been avoided, but where encountered, they should be understood to have the same meaning as ‘earth’ and ‘earthing’ respectively.

4.1 Overview

It is often remarked that electricity is a good slave but a bad master. Improper use of electricity or careless handling of electrical equipment leads to a number of avoidable accidents every year, resulting in huge loss of productive man-hours and monetary compensation liability to the employer. Even more serious are the instances of fatalities due to electrocution or as a result of grievous injuries. In this text, we will take a detailed look at the electrical hazards in substations and other premises handling electricity. We will learn a little about the theory behind electrical safety as well as examining the preventive measures that need to be adopted to ensure safety while working on electrical installations.

Electrical safety is a well-legislated subject and the various Acts and Regulations enacted in most countries emphasis the responsibility of both employers and employees in ensuring safe working conditions. We will briefly trace the history of regulations on the subject of workplace safety in general, and electrical safety, in particular.

Safety is not simply a matter of taking precautions in the workplace. It has to, as a matter of course, begin at the stage of equipment design. Safety should be built into the design of electrical equipment and it is the responsibility of every manufacturer of electrical equipment to remove every possible hazard that can arise from its normal use. Another important aspect involved with safety in the workplace is the correct selection of equipment. Incorrect selection and application of even the most well designed piece of electrical machinery, can give rise to hazardous conditions. Similarly, a lot of care is required in the operation and maintenance of any electrical equipment in order to avoid accidents. Appropriate knowledge of equipment and systems is essential for each and every person who operates or maintains the equipment. This knowledge is initially acquired through structured training and thereafter by hands-on experience. The training should be comprehensive and should deal not only with the technical details of the equipment, but also with the possible hazards present in the specific working environment. This training should also teach the working personnel about the measures required in order to prevent accidents, and the skills needed to deal with accidents when they occur.

Another important factor involves the close monitoring of all electrical equipment/installations to ensure their continued safe operation. A thorough inspection during initial erection and commissioning (as well as periodic inspections and maintenance thereafter) is absolutely essential to ensure safety. Any defects brought to light during such inspections must be attended to promptly.

We will devote our attention to the use of electrical equipment in environments where hazardous materials are likely to be present. We will also discuss in detail the safety of substations, and the precautions necessary while handling DC storage battery installations. Batteries need particular attention since they contain toxic materials such as lead, as well as corrosive chemicals such as acid or alkali. These chemicals are particularly dangerous because of their electrical voltage and the risk of explosion due to the presence of the explosive mixture of hydrogen and air. Finally, we will review the organizational aspects of safety. Electrical safety is not merely a technical issue. Accidents can only be prevented if appropriate safety procedures are evolved and enforced. A mechanism should be put in place to ensure that all working personnel are aware of the hazards and are trained to carry out their duties in a safe manner.

But firstly, we will discuss in general the hazards present in any industry and more particularly, the hazards present in electrical installations.

4.2 Industrial hazards

In any industrial facility several types of hazards exist. The hazards may be due to any of the following:

• Electrical equipment
• Mechanical equipment
• Fire or flames
• Hazardous/toxic materials
• Hot liquids/gases
• Cold liquids
• Potentially explosive gas vapors and dusts
• Corrosive liquids

4.3 Electrical hazards

Hazards from electrical equipment could include any of the following:

• Electric shock and associated effects
• Internal organ damage due to passage of electricity through body
• Burns on skin at point of contact
• Injuries by electric shock combined with fall
• Temperature hazards due to high temperature during operation
• Arc flash causing external burns and injuries by explosive expansion of air due to the arc.

Electric shock is a result of the following conditions.

• Exposure to live parts (Direct contact)
• Exposure to parts that accidentally become live (Indirect contact)
• Potential difference between different points in the earth under certain conditions

The last named is similar to indirect contact except that it does not involve contact with any electrical equipment (either a live part or enclosure). Electric shock causes current flow through the body, resulting in muscular contraction. If the current flows through heart muscles, it can cause the heart to stop through a condition called fibrillation.

4.4 Protective Earthing

Electrical equipment earthing is primarily concerned with connecting conductive metallic enclosures of the equipment (which are not normally live) to the earthing system of the substation or other consumer facility through conductors known as earthing conductors. For the earthing to be effective, the fault current (in the event of a failure of insulation of live parts within the equipment) should flow through the equipment enclosure to the earth return path without the enclosure voltage exceeding the value of safe touch potential. This is also applicable to other parts that are normally dead (refer to Figure 4.1).

4.4.1 Sensing of earth faults

Earth fault protection in LV branch circuits is usually achieved using over current protective devices such as fuses or circuit breakers and no special protective relaying is used. However, main circuit feeders and the incoming circuit-breaker from the supply transformer are provided with specific protection for earth faults. Sensing of earth faults is done using one of the following approaches:

• In case the power supply source (such as the transformer) is a part of the system, a CT and relay can be provided in the earth connection of the neutral of the transformer (Figure 3.2a).
• Sensing by a single current transformer enclosing all phase and neutral conductors (called a core balance or zero sequence CT). Such a transformer detects the earth fault currents and can operate a sensitive relay (Figure 3.2b). Residual current circuit breakers use a similar scheme.
• Sensing by individual current transformers in phase and neutral conductors and providing a relay in summation circuit (Figure 3.2c).

Adding sensitive earth fault relays will enable the protection system to sense even low value of earth fault currents and trip the circuit faster. Inclusion of the neutral in Figure 4.2 cases b and c is for canceling any unbalance currents that may flow in the neutral from being sensed as earth faults.

Bonding is the practice of connecting all accessible metalwork – whether associated with the electrical installation (known as exposed-metalwork) or not (extraneous-metalwork) – to the system earth. In a building, there are typically a number of services other than electrical supply, which employ exposed metallic parts in their design. These include water piping, gas piping, HVAC ducting and so on. A building may also contain steel structures in its construction. We have seen earlier in this chapter that when an earth fault takes place in an installation, the external conducting surfaces of the installation and the earth mass in the vicinity may attain higher potential with reference to the source earth. Therefore it is possible that a dangerous potential may develop between the conducting parts of non-electrical systems including building structures and the external conducting parts of electrical installations as well as the surrounding earth. It is therefore necessary that all such parts are bonded to the electrical service earth point of the building to ensure safety of occupants. This is called equipotential bonding.

There are two aspects to equipotential bonding; the main bonding where services enter the building, and supplementary bonding within rooms, particularly kitchens and bathrooms. Main bonding should interconnect the incoming gas, water and electricity service where these are metallic, but can be omitted where the services are run in plastic, as is frequently the case nowadays. Internally, bonding should link any items, which are likely to either be at earth potential or which may become live in the event of a fault. These items are large enough to make contact with a significant part of the body or large enough to be gripped. Small parts, other than those likely to be gripped, are ignored because the instinctive reaction to a shock is muscular contraction, which will break the circuit. Refer to Figure 4.3.

In each electrical installation, main equipotential bonding conductors (earthing wires) are required to connect to the main earthing terminal for the installation of the following:

• Metal water service pipes
• Metal gas installation pipes
• Other metal service pipes and ducting
• Metal central heating and air conditioning systems
• Exposed metal structural parts of the building
• Lightning protection systems

It is important to note that the reference above is always to metal pipes. If the pipes are made of plastic, they need not be main bonded.

4.5 Dangers of static electricity buildup

The following are the dangers posed by static electricity:

• Ignition causing fire or explosion
• Damage to sensitive electronic components
• Electric shock to humans followed by accidents such as a fall
• Damage to mechanical components such as bearings due to sparking through the oil films on bearing surfaces

It is necessary to study the static buildup potential of any workplace and institute protective measures to control such buildup.

4.5.1 Control of static electricity

Earthing and bonding

Charge buildup takes place when two surfaces, which are in contact and across which electrons migrate, get suddenly separated. Connecting such surfaces together with a conducting medium prevents charge accumulation by providing a leakage path. This is called bonding, and can be achieved by using a bare or insulated conductor of adequate mechanical strength. Where electric current flows are due to charge leakage of very low magnitudes, the size of the conductor is immaterial and so is the resistance of this conductor.

For moving objects, an earth brush of metal, brass or carbon can be used to provide the required leakage path. This method is commonly used for shafts of rotating machines to prevent bearing surface damages (refer to Figure 4.4). For objects which are in contact with earth already, no separate earthing or bonding is necessary.

Earthing cannot, however, provide a solution in all cases, especially where a bulky non-conducting material is involved. In this case, the part of the substance which is a distance away from the earthed portion, can retain sufficient charge, since movement of charge will not be fast enough in an insulating material. This charge can result in a spark.

Control by humidity

Many insulating materials such as fabric, paper, etc., can absorb small quantities of water when the atmospheric humidity is sufficiently high. Even in the case of materials that do not absorb water, a thin layer of moisture gets deposited on the surface due to humidity (for example, plate glass). If the environment has a humidity reading of over 50%, moist insulating materials can leak charges as fast as they are produced. This prevents high charge buildup, thereby avoiding sparks.

Conversely, most of the materials become dry when the humidity becomes lower than 30% since they tend to lose moisture to the atmosphere. This results in increased charge accumulation, which can cause sparking. Keeping humidity levels at 60% to 70% can solve static problems in many cases such as industries handling paper and fibers where charge buildup causes unwanted adhesion. In some cases, localized humidification using steam ejectors can be useful, particularly where the large space involved makes increase of humidity in the entire space a difficult proposition.

However, this method is unsuitable where:

• The processed material can be adversely affected due to high humidity
• If the area involved is air-conditioned or humidity controlled for process reasons or human comfort
• In cases where humidity increase does not cause appreciable drop in resistivity

In all such cases, other methods of static control may have to be resorted to.

Ionization

Ionization consists of forced separation of electrons from air molecules by application of electric stress or other forms of energy. The air thus ionized becomes conductive and can drain charges from charged bodies with which it is in contact. The positive ions and electrons are also attracted by the negative and positive charges respectively, thus resulting in charge neutralization.

Ionization can be produced by high voltage electricity, by ultra violet light, or by open flames. Various devices using a step up transformer operating on mains supply and producing high electric fields are commercially available. Due care is needed however to address safety issues arising from the use of high voltage. Such devices find application in paper and fabric processing plants. They are, however, unsuitable for use in situations where the environment contains inflammable gas mixtures.

A simpler device is the static comb, which does not use electricity at all. It consists of a metallic bar with a row of sharp points projecting from it and bonded to earth. When this device is placed near the charged surface, the electric stress due to accumulation of charge near the sharp points causes ionization and helps to drain the charge from the surface. This method is commonly used in belt driven equipment near the point of separation of the belt and pulley (refer to Figure 3.5).

Another method of ionization is by using a row of small open flames. This method, however, requires caution where combustible materials are handled.

In addition to these hazards of electricity, the accumulation of static electrical charge while processing/conveying materials that are not good electrical conductors (examples: paper, wood chips and grains) also poses hazards of electric shock, ignition and explosion.

4.6 Electric arcing

An electric arc takes place when current flows through the air or through the insulation between two conductors at different potentials. The path of the current becomes conducive due to the ionization of the gas. Since arcs are associated with faults, the fault current level and the heating effect, is usually very high. Injury from arcs is usually a direct result of burning from the arc.

4.6.3 Effect and consequences of ARC flash

Arcs created by a fault do not remain stationary. The interaction between an arc and the electromagnetic field caused by the fault current flow will cause the arc to move away from the source point with the arc behaving very much like a conductor placed in a magnetic field. The arc also causes sudden heating of the air in its immediate vicinity causing a violent expansion much like an explosion. This can result in the dislocation of loose components around the fault point and their being thrown like projectiles outwards from the arc. Following are some important effects of arc flash:

• Electric arcs produce some of the highest temperatures known to occur on earth up to 35000°F. This is four times greater than of the temperature of the sun’s surface.
• The intense heat from arc causes a sudden expansion of air. This results in a blast with a very strong air pressure.
• All known materials are vaporized at this temperature. When materials vaporize they expand in volume. The air blast can spread molten metal to great distances with force.
• For a low voltage system, a 3 to 4 inch arc can become stabilized and can persist for an extended period of time.
• Energy released is a function of system voltage, fault current magnitude and fault duration.
• Arcs in enclosures, such as Motor Control Centers or switchgears, magnify the blast and energy is transmitted towards the worker as the blast is forced to the open side of the enclosure.

Figure 4.6 is a model of an arc fault and the physical consequences that can occur.

4.7 Preventive maintenance

Preventive maintenance practices exist in most companies that can boast a high reliability of supply or process continuity. Preventive maintenance also provides for a safer workplace. Procedures needed to be included that address arc flash hazards, such as the enhancement of maintenance procedures when carrying out inspections, and preventive or breakdown maintenance. This reduces the overall cost of implementing the arc flash program. Following are some recommended maintenance practices:

• Rodents and birds entering panels and switchgear are not uncommon. This can lead to a short circuit and eventually to an arc flash. Closing all open area equipment with wire nets or sealant so that rodents and birds cannot enter can prevent this risk.
• Use corrosion resistant terminals. Corrosion can lead to snapping of small wires, which in turn can create spark and fumes when the tip of the wire hits the metal enclosure or another phase conductor. Check the corroded terminals and parts regularly if the electrical equipment is at a chemical plant or near marine atmosphere. Electrical contact grease is typically used in joins and terminations. This will reduce corrosion. Check the loose connections and overhead terminals. Impurities at the terminal connectors or dust can create additional contact resistance, resulting in a heating of the terminals. A sign of such a case is discoloring of the nearby insulation.
• Heating of cable insulation can damage insulation – another cause of flash over. Infrared thermography can provide valuable data on poor connections and overheated electrical conductors or terminations.
• Insulate exposed metal parts if possible. If heat dissipation is not really needed from the exposed metal part, and insulating it with some insulating tape, sleeve or cover is not a problem, then it is better to do so; this is preferable to leaving them exposed. Insulation prevents arcing. For example, if a worker drops an insulated spanner, which then touches bare bus bars of two phases, a short circuit will occur. However this will not happen if the spanner or bus bar is insulated.
• Make sure relays and circuit breakers operate properly. Failure could lead to a prolonged exposure to arc flash, which could result in death. Routine inspection and testing of relays are carried out in companies with good maintenance practices. The frequency of the relay tests may be couple of years up to five years, depending upon the manufactures suggestions and the policies of the company. Pitting of contacts takes place when fuses are operated. Replace contacts of the fuses holder or the fuse holder itself when excessive pitting is observed.
• When fuses melt, make sure that the fault has cleared before installing new fuses. Closing on to a fault can produce a spark which could lead to an arc flash. Wire harnesses for control and instrumentation should be kept in proper condition. It is common for these wires to become bundled and messy over time. Occurrence of arc flash is possible while opening covers of such switchgear/MCC.
• Check for excessive moisture or water/ice on insulating surface of equipment. This may cause flashover, especially on high voltage equipment.

4.8 Reducing the fault level

Fault level can be reduced in following ways:

4.8.1 System configuration

• Reducing fault level depends on the existing system configuration. Double ended load centers with normally closed tie (as shown in Figure 4.8) are prime examples where fault levels can be reduced by either opening the tie or incoming breaker
• The fault current will be reduced by approximately 50% and the incident fault energy will also be reduced, although not in same proportion
• If the bus has two sources, or a source and a normally closed tie as shown in Figure.4.8, the opening of one of the sources (or tie), will reduce the fault level while maintenance is being done on the equipment
• For both the situations, the loading and relay setting should be checked to make sure that the opening of a breaker does not overload the other source

4.9 Reducing arcing time

Arcing time can be reduced in several ways. Some changes in the system of settings may be required for this purpose. Some characteristics underlined in this chapter are as follows:

• Reduce safety margin for relay and breaker operation with improved solid- state trip devices.
• Use bus differential protection to combine selectivity with instantaneous operation
• Use temporary instantaneous trip setting during work
• Retrofit time overcurrent relays with delayed instantaneous trip device if needed
• Use Optical sensor to trip breaker in the event of arc flash
• Use smaller fuse size if possible; smaller current-limiting fuses may clear faster. Fuses will generally be much faster than breakers at high fault currents; even with ignoring the current-limiting effect, this can greatly reduce arc energy
• Use Protective device coordination study to balance improving reliability with reducing arc flash hazard

4.9.3 Temporary instantaneous settings

• Replacement of low-voltage trip devices from many industries have instantaneous units that can be turned on and off. This has many advantages for the incoming breakers
• In many cases for co-ordination purposes, the instantaneous is not set and fault-clearing times are delayed for selectivity
• A main breaker clearing time with load center tie and feeder breakers could easily have a short time setting of 0.4 seconds
• If the instantaneous trip could easily be enabled while work is being performed, lower fault currents could be tripped and cleared in less than 0.04 seconds. The incident energy exposure is reduced to 10% of its previous value
• During maintenance, full selectivity of device may decrease, but reduction in arc flash exposure makes this worthwhile. The temporary instantaneous setting should be disabled and the original protective setting should be restored for normal operations after the work is completed
• Separate instantaneous trip devices with increased protection can also be added to the shunt trip or transfer trip for added protection during work procedure

Retrofit instantaneous trip devices

If bus differential relaying is not possible, then main relay can be retrofitted with an instantaneous device and safety control switch. As shown in Figure 4.9, a selector switch can be used to place the instantaneous device in service when maintenance is being done.

• Normally the instantaneous protection would not be functional due to open contact of the selector switch. However, when work is being done on energized equipment, the safety switch would be turned ‘ON’ thereby limiting the arc exposure time to the worker should an arcing fault accident occur
• The delayed fault clearing could be in range of 0.4 to 2.0 seconds on the main breaker instead of 0.1 second
• The delayed trip time greatly increases the arc exposure time and the amount of radiation a worker would receive if the arc blast pressure were not enough to propel the worker away from the fault
• The time selective protection system would be eliminated for the duration of the work in the interest of safety. The selector switch should be lockable in the maintenance position
• Ideally, positive feedback from the trip unit would be used for an indicating light associated with the switch, to confirm the setting change was in effect
• Many medium voltage multifunction relays have provisions for different protective settings for various operating modes. For example, one group of setting is used for normal operation; a second group of settings is used for the emergency mode
• Another group setting could be for maintenance where tripping and current pick-up settings are reduced and set as instantaneous. Again, these temporary settings could result in the loss of selectivity, but with a gain in human protection

Reducing the arcing current

Certain protective devices are current-limiting in design. By limiting the current available for a fault, there is a corresponding reduction in the incident energy for clearing times that are short in duration (1-3 cycles). Fault duties at these devices must be in the current limiting range for them to be effective (typically at least 10-15 times the device rating).

4.9.4 Increasing the working distance

• Since the incident energy is proportional to the square of the distance (in the open air), increasing the working distance will significantly reduce the incident energy
• Working distance can be increased by using remote racking devices, remote operating devices, and extension tools (i.e. hotsticks). Figure 4.10 demonstrates the impact of using a remote device to increase the working distance from 18 inches (Class 3, 12.62 cal/cm²) to 72 inches (Class 1, 3.28 cal /cm²)

4.9.5 Reducing the clearing time

• Lowering device settings is the cheapest solution to lowering the incident energy, but is limited by the range of available settings that will still achieve selective operation
• In medium voltage relaying, this can be achieved by changing the curve shape or lowering the time dial settings
• Low voltage protection changes are more limited due the device characteristics. Figure 4.11 shows one example of changing the settings to improve the incident energy. The incident energy was reduced from a Class 4 (38.7 cal/cm²) to Class 3 (19.8 cal/cm²)
• Zone selective interlocking (ZSI) and bus differential protection are two methods to detect bus faults and quickly clear the fault to minimize damage
• The zone selective interlocking (typically low voltage breaker only) uses a communications signal between zones of protection. For a through fault, the downstream protection sends a blocking signal to the upper level breaker, allowing normal time selective operation
• For an in zone fault, no blocking signal is sent and the time delay (usually for short time and ground fault protection only) is reduced to the minimum setting for the trip unit (typically 100 ms plus the breaker response). ZSI is not generally available as a field modification, and therefore cannot be used for installed systems
• Bus differential protection is faster than ZSI (2 cycles or less plus breaker response) and can be retrofit to existing systems. It is expensive to install due to the number of current transformers that need to be installed
• Using the example in Figure 4.12 and assuming a clearing time of 150ms for ZSI and 100ms for bus differential protection, the incident energy is reduced from 38.7cal/cm² to 9.3cal/cm² and 5.6cal /cm² respectively

4.10 Arc flash protection program

An arc flash protection program is implemented as part of the electrical safety program, which in turn, is part of the overall safety program of the company. The main objective of the program is to prevent or minimize injuries to workers from arc flash. Since arc flash hazard mitigation is a fairly new concept in the industry, it is expected that considerable efforts and allocation of resources will be required to effectively launch the program. The arc flash hazard reduction program consists of the following steps:

• Hazard assessment: A qualified person performs calculations based on the power system parameters to determine the flash protection boundary; the incident energy a worker may be subject to; and the hazard /risk category. An important step in this assessment is the collection of technical data and other necessary data.
• Documentation: It is necessary to document the results of arc flash hazard assessment in reports and drawings, and also to provide signs and labels on equipment and at hazardous areas. Documentation is also a part of the planning process before and after working on live equipment; if work changes are made to the equipment or system, documentation is also required.
• Personal protective equipment (PPE) plan: Based upon the hazard assessment the appropriate PPE must be selected and provided to the workers. Workers must wear the PPE properly as well as caring for and maintaining the quality of the PPE. They must inspect it before every use and dispose of it after its life expires.
• Development of procedures to minimize hazard: Potential hazards can be minimized by developing safer working methods, providing shields and proper work planning etc. The exposure to arc flash can also be reduced by improving system design, using current limiting devices and solid state relays, and by adjusting relay and trip devices to safer settings.
• Training for workers: Workers who are exposed to arc flash hazard should be well trained to understand what the hazard is, how it is initiated, how to read the document and warning labels, how to properly wear PPE, and how the hazard can be reduced with safer working procedures. Different tasks will require different work practices.
• Continuous improvement: Much research and development is necessary in the arc flash hazard program. New standards, PPEs and industry practices are needed for future improvements to be made. Workers’ experiences must be considered while developing the program.
• Safety audit: Safety audits should be regularly performed to evaluate various aspects of the safety program.

4.11 Electrical equipment in potentially explosive atmospheres

There are eight standardized protection principles for the safe use of electrical apparatus in potentially explosive atmospheres, in addition to some non-standardized methods. This standardized principle is commonly considered as a type of protection and for each of the principles, harmonized European standards or Euro-norms have been issued.

Hazardous areas, where potentially explosive atmospheres exist are encountered in a wide variety of industries. Thankfully, the science of how to operate safely within such areas is now well understood. However, knowing how best to comply with the requirements of this operation is something that still causes widespread confusion. Particular care has to be taken with electrical apparatus because of its potential for creating sparks and hotspots that could ignite a gas, vapour, mist or dust-laden atmosphere. Such environments are encountered in everyday life, with petrol station forecourts being an obvious example; Industry sectors that are prone to hazardous areas are mining, chemical processing, petrochemicals, and oil and gas. In addition, pharmaceutical production facilities often have areas where solvents are used; likewise, chemical plants often have hazardous areas. Flour mills, bakeries, sugar processors, timber processors, coal handling plant, paper mills and processors of metals such as aluminum and magnesium, for example, can all have areas where dust-laden atmospheres are potentially explosive. It is apparent therefore that the full spectrum of production and process plants which contain hazardous areas is extremely broad.

There are three zones for gases and vapours as shown in Table 4.1:

When on considers the size of a refinery or chemical factory and the amount of liquids and gases that circulate, as well as the various processes that occur, it is clear that there exists a certain amount of risk of leaks and other hazards. In some cases the gas, vapour or dust is present all the time or for long periods. Refineries and chemical complexes should therefore be divided into areas of risk, areas called zones, which are categorized by the various releases of gas, vapors or dust.

Safe area
A domestic domain such as a house would be classed as safe area where the only risk of a release of explosive or flammable gas would be the propellant in an aerosol spray. The only explosive or flammable liquid would be paint and brush cleaner. These are classed as very low risk.

Zone 2 area
This is a step up from the safe area. In this case it has been decided that in this zone the gas, vapour or dust would only be present under abnormal conditions (most often leaks). Unwanted substances should only be present under 10 hours/year or 0–0.1% of the time.

Zone 1 area
These areas are where special or classified electrical equipment must be used. It is expected that the gas, vapour or dust will be present or expected for long periods of time under normal running. This is defined as 10–1000 hours/year or 0.1–10% of the time. In this case there must be no sparks at all that can ignite these mediums.

Zone 0 area
This is the worst scenario as gas or vapor is present all of the time (over 1000 hours/year or >10% of the time). Although this is the worst case it is very rare that a zone 0 area will be in the open. Usually this would be the vapour space above the liquid in the top of a tank or drum.

General principles of design
With very few exceptions, the ignition of a flammable atmosphere results in a potentially destructive explosion, caused by the heat generated in a thermochemical chain reaction. In this respect, the LEL of gas/air mixture is analogous to the critical mass of a nuclear device. Hence electrical apparatus for use in potentially explosive atmospheres must be designed so that it is not capable of initiating an explosion.

If we only consider normally sparking and heated components, design will be very easy.

But we have to consider abnormal conditions such as mechanical overloads and electrical faults, which often lead to dangerous conditions. The design requirement is therefore either to prevent these faults from occurring, or to ensure in some way that they cannot cause ignition.

Circuits where safe fault levels cannot be exceeded are termed as intrinsically safe circuits. Flameproof enclosures for power equipment and intrinsic safety for light current apparatus are still the two most important and widely used concepts for electrical installations in explosion/hazardous areas.

Flameproof enclosures: The principle of flameproof protection is to place electrical equipment in an enclosure, which does not need to be sealed, but which will not ignite a surrounding explosive gas if same explosive mixture is ignited within the enclosure. A flameproof enclosure is therefore, in effect, a type of pressure vessel in which all openings and running clearances have been shown by test as reliable flame traps.

The following rules are considered while designing a flameproof enclosure:

• All face joints such as flanges to be machined and to have a land of at least 1 inch from outside to inside of the enclosure
• Flange faces may form a tight metal to metal joint; or they may be held apart to form a tight metal to metal joint; or they may be held apart to form a vented joint with maximum permissible gap of 0.02 inches
• Joining with rubber, asbestos or any other such material liable to deterioration is not permissible
• Length of bearings for shafts and spindles to be not less than 1 inch, with a maximum radial clearance of not more than 0.01 inch
• Direct entry of cables into the main flameproof enclosure is not permissible
• Nuts and bolts heads securing covers to be shrouded
• The above rules are modified but form the basis for the flameproof design.

Application and Limitation of flameproof protection
This type of protection is useful for all apparatus including switches, contactors, commutators and slip-ring motors, and incandescent lamps.

This equipment is very robust.
Limitations:

• These apparatus are not suitable for areas above atmospheric pressure
• Low temperature applications
• Cost is very high

Protection by intrinsic safety
Research has shown that the lowest current, which can cause an explosion, falls very rapidly with increase in supply voltage. If the voltage and current at the spark lie below the curve as shown in Figure 4.13, the circuit is said to be intrinsically safe.

Application of intrinsic IS system

This protection is applicable to low power and low voltage equipment. It is widely used in the protection of the electronic process control and telemetering system, where all parts of the circuit are within the hazardous area.

4.12 Hazards due to high temperature

Excessive temperatures can cause burns, start a fire, or degrade insulation within the equipment. The standards generally provide temperature limits for various internal and external parts. Installation or mounting methods are considered when evaluating the product: for example, under the counter, installed in a cabinet, etc.

Hazards due to high temperature include:

• Burns due to high surface temperature
• Fire in nearby combustible materials
• Fire originating from electrical equipment
• Arcing due to breakdown of insulation
• Mechanical failures and injury to personnel, due to arc faults

We have discussed at length arc fault prevention through proper design of insulation and enclosure in the previous sections. Arc hazard from live electrical equipment and the precautions required against this hazard were also discussed in an earlier chapter. In this section, we will confine the discussions to the temperature produced by the normal/abnormal operation of electrical equipment and electrical equipment related fires.

Adverse thermal effects are a result of high temperatures occurring during equipment operation:

• in exposed metallic enclosures
• in conducting parts

Current flowing in a conducting part produces watt losses due to the resistance of the material causing the heating of the conductors. This heat is dissipated in the form of thermal radiation and convection when the conductors are kept bare and exposed to the cooling medium. In the case of insulated conductors, the heat is first conducted through the insulation to its outer layers and then dissipated by convection and radiation. (Strange, but true; one of the requirements of an electrical insulator is that it should conduct heat adequately).

In a conductor carrying a steady load current, the temperature initially starts rising but reaches a steady state value when the heat generated and the heat dissipated are in equilibrium. The temperature, which a conductor can attain, is limited by the maximum permissible value which the insulating components in contact with it can withstand. Thus the conductor temperature of a wire with PVC insulation should not exceed the limiting temperature value applicable to PVC material (say 70 deg C). Exceeding this temperature will cause accelerated ageing and thermal failure of the insulation as discussed earlier. When abnormal conditions are encountered, the conductor temperature can go up to a much higher value compared to the temperature during normal operation. Such an increase must also be factored into the design of insulation in any electrical equipment. Abnormal conditions stated here include:

• Excessive current during overloads
• Excessive current during faults (short circuit)
• Cooling system failures

When there is a metallic enclosure around the live conductors, they too participate in the heat dissipation process and in doing so, their temperature rises beyond ambient value. Exposed and accessible parts of any electrical equipment must not attain temperatures beyond specified limits. If the part is to be held by hand for operation, the limit is the lowest. For parts which need not be held or touched during normal operation, higher limits are permissible. Though these parts are not normally handled, such requirement may occur occasionally. In addition, they can ignite any nearby flammable materials. Suitable limits must therefore be adopted. Table 4.2 below shows the typical limits for accessible parts (source: IEE wiring regulations):

Similarly, lightning flashes striking a facility can have dangerous consequences unless they are safely dissipated to the ground. We will discuss these aspects in subsequent chapters.

In some instances an electric shock may not, by itself, cause injury. However, a resulting fall from a height could. Those who are working at heights on electrical equipment (e.g. changing lamps in a high bay factory premises or on road lighting poles) must take precautions to avoid a fall as a consequence of electric shock.

Burn injuries result from an arc flash, which happens when there is a short circuit between exposed live parts. The extent of arcing and the seriousness of injury depend on the following factors:

• Fault energy as given by the fault level of the system (VA)
• Time of fault clearance

For example, the arc energy in an MV system short circuit fault is usually much higher compared to an LV mains circuit fault, which in turn has a much higher energy compared to a branch circuit fault in the same system. The longer an arc fault is allowed to persist, the higher the damage. Faults which are cleared much faster are therefore much less dangerous from the viewpoint of injury the resulting arc can inflict. High-energy faults will also cause melting of components such as copper/aluminium conductors or the steel parts of an enclosure. Copper is particularly dangerous because it can result in deposition of toxic copper salts on the skin. Direct electrical contact with a live part at the point of contact (without overt arcing) can also cause burns on the skin. Internal burn injuries and organ damage can be the result of the passage of electricity through the body (example: lightning current through a human body). Sometimes, the sudden expansion of air due to an arc fault within an enclosed space may dislodge mechanical parts (e.g. terminal covers) with a great force. Documented cases of such accidents causing injury or even death are on record. It is common practice in the design of equipment such as HV switchgear, to provide vents or flaps which open in the event of explosive arc faults, thereby avoiding damage to the enclosure. They also help to direct the arc products way from an operator who may be stationed nearby.

Another hazard arises due to the high temperature on the surface of electrical equipment enclosures and current carrying parts. As stated earlier, external surfaces of electrical equipment often attain elevated temperature: for example, the enclosure of bus ducts which can often attain surface temperatures of over 60 °C. Exposed conducting parts such as overhead line conductors can attain even higher temperatures. For example, the bus bars in switchgear often run at temperatures in excess of 100 °C. Electrical joints/mating surfaces can have temperatures exceeding the conductor temperature. This is because of increased localized resistance. Apart from causing less serious burn injuries (compared to arc flash), high surface temperature can cause ignition if flammable vapors are present in the environment.

Electrical faults can also cause fire danger as discussed in an earlier section. Special care is required when the electrical equipment itself contains flammable materials. Examples of this type of equipment include oil circuit breakers and mineral oil cooled transformers. In some cases, a fire can result because of combustible materials stored in the vicinity of electrical equipment.

Electrical equipment installed in explosive environment needs special attention. Frequently, components of electrical equipment produce arcing or sparking in the course of normal operation. Contactors, carbon brushes, push buttons, control switches are examples of such equipment. Some equipment may generate arcs during abnormal conditions such as a short circuit occurring within a motor terminal chamber. While in a normal environment such instances would be quite harmless, they may cause an explosion if hazardous substances are present in the surrounding atmosphere. Equipment intended to operate in such an environment should be designed to prevent an explosion being caused in the external environment. The nature and characteristics of the hazardous materials present in the environment play an important role in these cases. We will discuss in detail the safety measures to be taken in a hazardous environment in a subsequent chapter.

Table 4.3 identifies the safety hazards posed by electrical equipments commonly used in electrical generation and distribution systems and substations.

4.13 Electrical accidents and safety measures

We will discuss briefly in the section the reasons why electrical accidents happen and how we can avoid them. These points will be elaborated on in more detail in subsequent chapters. Electrical accidents happen mostly as a result of the following:

• Failure to isolate live parts/inadequate or insecure isolation of live parts (60%)
• Poor maintenance and faulty equipment (30%)
• Insufficient information about the system being worked on
• Carelessness and lack of safety procedures

4.14 Summary

Improper use of electricity or careless handling of electrical equipment, leads to a number of otherwise avoidable accidents. Electrical safety is a well-legislated subject and the various acts and regulations enacted in each industrialized country emphasize the responsibility of both the employer and the employee to ensure safe working conditions. However, it must also be understood that safety is not simply a matter of taking precautions in the workplace: safety must start at the stage of equipment design.

In any industrial facility, several types of hazards exist. The hazards may be due to electrical faults, mechanical faults, as well as several other causes. Electrical hazards result, in the main, from electric shock, a fall as a result of an electric shock, burns due to arc flash and injuries by explosive expansion of air due to the arc. Other safety hazards include high temperature on the surface of electrical equipment/enclosures, exposed conductors and electrical faults resulting in fire within electrical equipment or nearby combustible materials. Special attention must be given to electrical equipment installed in an explosive environment. Equipment intended to operate in such an environment should be designed to prevent an explosion being caused in the external environment.

The reason for over 60% of accidents is the result of a failure to isolate live parts, as well as inadequate or insecure isolation of live parts. The proper isolation of normally live equipment from the mains supply before commencement of work can improve safety substantially. Poor maintenance and faulty equipment, insufficient information about the system being worked on, and a lack of safety procedures are the other major reasons for electrical accidents.

The possibility of accidents can be reduced substantially by the implementation of various steps. These steps include the initial design and installation of equipment in accordance with the appropriate safety features and relevant regulations. Adoption of proper documented procedures, as well as making available adequate training to working personnel and creating safety awareness among the workforce, are examples of further steps that could be taken. In the next chapter, we will discuss the basic theory of electrical safety and shock hazards.

Learning objectives

• Objectives of inspection
• Stipulations of IEE Regulations
• Inspection of new installations
• Checklists of items/aspects to be inspected
• Periodic inspection
• Documentation of inspection
• Planned and condition-based preventive maintenance

5.1 Objectives of inspection

The quality of an electrical installation and ensuring safety of personnel who operate and maintain the installation are important issues. Carrying out the design and construction of an installation as per various applicable standards, regulations and codes of practice is crucial in ensuring the quality, safety and integrity of the installation, since standards and codes put must emphasis on matters pertaining to safety. An installation must be inspected for conformity with the applicable regulations and for safety on completion of erection and thereafter periodically.

IEE Wiring regulations stipulate various requirements to achieve these objectives. Planning, design and erection of an electrical system need extreme care in order to ensure that the installations are safe for the personnel who use, operate and maintain them. Proper planning using the methods of systematic assessment given in Chapter 3 of the Regulations will ensure that the installations function as intended and are not unduly affected by the presence of external influences. Proper design of the system and selection of equipment, which form part of the installation, ensure that the system is safe and remains safe over its entire intended life. Proper erection ensures that the equipment operates and meets the functional requirements as intended. Inspection verifies the compliance with regulations and safety requirements.

The objectives of inspection are as follows:

• To ensure that a new installation is safe to energize, operate and maintain
• To ensure that the installation remains safe during its operation without deterioration
• To ensure that additions/modifications to an existing installation do not impair its safety

Chapter 7 of the Regulations deals with the inspection of installations, prior to commissioning (called initial verification) and on an ongoing basis (periodic inspection). Initial verification ensures that there are no defects or non-compliance issues in the completed installation and it is fit to be put in service. Periodic inspection ensures that it is fit to continue in service.

Note:
IEE Wiring Regulations do not deal with high voltage equipment. However, the general principles discussed here are equally applicable for HV installations and can be extended to such installations with specific additions to suit the equipment involved.

5.2 IEE wiring regulations

In general, during inspection it should be ensured that electrical equipment is designed, manufactured and erected as per the applicable standards using good workmanship and proper materials. The characteristics of the equipment should not be impaired in the process of erection. It should also be ensured that the design temperatures are not exceeded. Measures for identification of equipment and wiring should be as per the requirements stipulated in the wiring Regulations. Joints should be of good electrical and mechanical quality.

On completion of any new electrical installation, as well as additions or modifications to an existing installation, appropriate inspection and testing should be carried out to verify that the requirements of the Regulations have been met. Similarly, periodic inspection and testing should be carried out in an operating installation to ensure that the installation quality has not deteriorated in service, due to the service conditions or other external influences. Appropriate reporting and certification should be performed by the authority carrying out the inspection/testing.

These aspects are covered in Part 7 of the Regulations in the following sections:

• CH. 71: Initial verification
• CH. 72: Alterations and additions
• CH. 73: Periodic Inspection and testing
• CH. 74: Certification and reporting

The basic objective of inspection is therefore to verify that all relevant requirements of the Regulations have been met and to make sure that the installation is safe to energize, operate and maintain. The steps involved in inspection are:

• Collection of the documents pertaining to the installation
• Assessment of general characteristics using drawings and specifications
• Disconnection of supply to the part of the installation being verified
• Inspection
• Testing
• Issue of Electrical Installation Certificate by inspecting authority with necessary documentation including inspection schedules and test schedules

5.3 Initial verification

Every installation should be inspected and tested on completion and prior to putting in service, in order to confirm that all relevant requirements of the Regulations have been met. Due precautions should be taken during inspection and testing to avoid danger to persons and property. The result of assessment of the general characteristics (as per Part 3 of the Regulations) together with the drawings and documents pertaining to the installation should be made available to the person carrying out the inspection and testing.

Inspection should precede testing and should be performed after disconnecting the supply to that part of the installation which is under inspection. The inspection should verify that all equipment forming part of the installation conforms to the appropriate standards based on markings and certification/documentation by the installer or manufacturer. The inspection should also check that the equipment is correctly selected and erected as per the Regulations and is not visibly defective or damaged. The following are the aspects that should be checked during inspection. Some of the points will require checking during erection itself (as the parts may not be accessible for external inspection once the installation is completed):

• Connection and identification of conductors
• Routing of cables in safe zones and protective measures against mechanical damage
• Connection of single pole devices used for switching or protection in the phase conductors only (a single pole switch should not be put on the neutral conductor)
• Correct connection of accessories and equipment
• Presence of fire-barriers, fire-seals and protection against thermal effects
• Protection against electric shock (to be performed in detail and all measures for protection against direct and indirect contact to be verified to ensure conformity with the Regulations)
• Preventive measures against mutual detrimental influences
• Correct location and installation of devices for isolation and switching
• Provision of under voltage protective devices
• Choice and setting of protective and monitoring devices (indirect contact/over-current)
• Protective measures against external influences
• Adequacy of access to equipment
• Presence of danger notices
• Presence of diagrams and instructions
• Erection methods

As may be noticed, the points covered by verification indicate the emphasis of the Regulations on safety against electric shock and the prevention of various other unsafe conditions as discussed in earlier chapters.

Any other aspects not specifically listed but which are appropriate to the installation may be added to this list. It would be advisable that any shortcomings observed during the above inspection are rectified before proceeding with the testing.

5.4 Testing

The following tests should be carried out and the results compared with the appropriate criteria. (The results of initial testing often form a reference for subsequent testing, particularly where no definite norms are available for acceptable values of the tests). The tests should be carried out in the order mentioned in the Regulations (713-02 to 713-09) and any non-compliance or fault revealed during a test must be rectified. The test (including any previous test whose results might have been affected by the fault) should be repeated. The installation can be energized only after successful completion of all the tests.

• Continuity of protective conductors and equipotential bonding conductors using a device whose source has a open circuit voltage between 5V and 25V and a short circuit current capability of at least 200 mA
• Continuity of all final circuit/ring final circuit conductors including the protective conductor
• Insulation resistance between live conductors and between each live conductor and Earth must be measured. In circuits having electronic devices, the insulation resistance should be measured between phase/neural conductors connected together and earth to avoid damage to sensitive electronic devices
• Voltage withstand test for site-applied insulation for protection against direct contact. (No breakdown or flashover should occur when the specified voltage is applied for the specified duration)
• Verification of degree of protection of enclosures provided for supplementary insulation and voltage withstand test for the enclosures
• Insulation resistance test for electrically separated circuits
• Verification of degree of protection for barriers provided as protection against direct contact IP XX B being the minimum acceptable degree of protection
• Measurement of insulation resistance of non-conductive locations for protection against indirect contact. (Measurement to be performed at no less than three points for each non-conductive surface between the surface and the main protective conductor of the installation)
• Polarity check to ensure that all fuses and protective devices are connected to the phase conductor and correct connection of conductors to the switches and socket outlets
• Measurement of earth resistance of earth electrodes where provided
• Measurement of earth-fault loop impedance
• Measurement/calculation of short circuit and earth fault current at the origin of the installation and at other relevant points of the installation
• Functional tests including:
  • Simulation of residual current devices
  • Tests on switchgear and control-gear assemblies to verify that they arecorrectly mounted, adjusted and installed in accordance with the requirements of the Regulations.

On completion of inspection and testing, the person conducting the inspection and testing shall give an Electrical Installation Certificate together with a schedule of inspections and a schedule of test results to the person ordering the inspection.

5.5 Alterations and additions

Verification on the lines indicated in the previous paragraphs (for initial verification and testing) will be done whenever any addition or alteration to an existing installation is carried out. This is to ensure that the work completed fulfills the requirements of the Regulations as applicable and does not impair the safety of an existing installation.

On completion of the verification, an Electrical Installation Certificate will be issued as in the case of the Initial verification.

5.6 Periodic inspection and testing

The objective of periodic inspection and testing is to determine whether an installation is in a satisfactory condition for continued service. Periodic inspection should comprise of careful scrutiny of the installation without dismantling or with partial dismantling as per scope decided by a competent person based on the availability of records and the condition of the installation. Inspection will generally be along the lines followed for the initial verification. The following aspects need to be especially examined:

• Safety of persons/livestock against electrical hazards
• Protection against damage that can arise from a defect in the installation
• Confirmation that the installation has no damage or defects which could hinder safety
• Identification of any defects/non-compliance with Regulations in the installation which may give rise to danger

No fixed periodicity is recommended in the Regulations. In the case of an installation which is under effective supervision in normal use, periodic inspection may not be necessary. Instead, a scheme of continuous monitoring and maintenance by skilled persons with appropriate documentation would be adequate. In other cases, a suitable periodicity can be determined based on the type of installation, its use and operation, as well as the type and frequency of maintenance.

The person carrying out the work should give a Periodic Inspection report together with the schedule of inspection and the schedule of tests to the person ordering inspection. The record of defects/damage/non-compliance with regulations etc. should be included in this report. The person carrying out the inspection will record the recommendation regarding the next appropriate date of inspection.

5.7 Follow up measures

The defects revealed by periodic inspection reports should be attended without delay to avoid unsafe situations. Apart from defect resolution, the following actions are also required:

A planned schedule of preventive maintenance should be drawn up based on the manufacturer’s recommendation/code of practices and implemented rigorously. This will avoid too many defects from showing up during the inspection.

Measures for condition-based preventive maintenance may be adopted to attend to incipient problems, resolving the defects in early stages. Examples: Monitoring of oil parameters (online dissolved gas monitoring) in large transformers, hot-spot detection in indoor switchgear using infrared detectors, incipient arc fault detection through photo electric sensors etc.

While planned preventive maintenance is completed according to a fixed schedule using a recommended list of maintenance works, condition-based maintenance is pro-active and relies on an early warning of problems. While this practice is well established in specific segments of mechanical machinery (such as vibration signature analysis in high speed machines), the applications in the electrical field are gradually becoming popular. The main benefit is need-based maintenance and preventing major unforeseen failures, both of which have major cost implications.

5.8 Summary

Carrying out the design and construction of an installation as per various applicable standards, regulations and codes of practice is crucial in ensuring the quality, safety and integrity of the installation. Standards and codes put much emphasis on matters concerning safety. IEE Wiring Regulations stipulate various requirements to achieve these objectives. Chapter 7 of the Regulations deals with inspection of installations prior to commissioning (called initial verification) and on an ongoing basis (periodic inspection). Initial verification ensures that there are no defects or non-compliance issues in the completed installation and it is suitable to be put into service. Periodic inspection ensures that it is fit to continue in service. Appropriate reporting and certification should be undertaken by the authority carrying out the inspection/testing. The defects revealed by periodic inspection reports should be attended to without delay to avoid unsafe situations. A planned schedule of preventive maintenance should be drawn up and implemented rigorously. Measures for condition-based preventive maintenance may also be adopted to attend to incipient problems, thereby resolving the defects in the early stages.

Learning objectives

• Planning of electrical systems
• Substation types and components
• Maintenance of approaches
• Insulation deterioration
• Switchgear diagnostic techniques
• Substation battery condition and monitoring
• Switchgear maintenance procedures
• Problems that may be found during switchgear maintenance
• Defect management
• Case studies of switchgear defects

6.1 Voltage classification and multiple voltage levels in power distribution

A number of standard voltages are used in different parts of the world both at utilization level as well as the transmission and distribution levels. For the purpose of convenience these voltages are grouped using the following classification (Ref: IEEE 141:1993).
Low voltage (LV): Systems of nominal voltage up to 1000V
Common usage: 380V, 416V, 480V
Medium voltage (MV): Systems of nominal voltage 1000V and above and less than 100000V
Common usage: 4160V, 6900V, 12000V, 13800V, 34600V, 69000V
High voltage (HV): Systems of nominal voltage 100000V and above and up to 230000V
Common usage: 116kV, 138kV, 230 kV

A majority of the plant loads are normally supplied at LV. This includes motors of up to 200 kW rating, lighting systems and so on. Unless loads of higher rating is involved, distribution at the utilization voltage is always a possibility. As such, power is usually received from MV distribution system.

Power can either directly distributed at the receiving voltage within the plant and be stepped down at different locations to the utilization levels or it can be stepped down at the incoming point and then distributed at a lower voltage to different consumers.

In large facilities, there may be a need for motors of higher ratings and these may require supply at MV. In other words, there is more than one level of utilization voltage in such plants; an LV system for the lower rated loads and an MV system for larger loads.

This may not be acceptable in some cases, because the drives at the MV utilization level may interfere with the other loads connected to the system; especially if direct-online starting of the motors is involved. Therefore there may be need to have a separate voltage level for the main distribution different from the MV utilization voltage. Taking a typical case, the following voltage levels may be used.

The incoming voltage naturally will have to be what the power supply agency can provide in the area in question.

6.2 Switchgear rating and specification

Power distribution system needs to be planned with care. In any modern industry, the power system is an essential facility that keeps the industrial process functioning. It should be planned considering the need for trouble free service under various conditions the normal and not-so-normal.

6.2.1 Selection of basic system parameters

The basic step in the design is to plan the basic system parameters of the power distribution system. The parameters to be selected are:

• Environmental or ambient specification
• Voltage level/s to be adopted in the distribution system and system frequency
• Acceptable variations in power system parameters
• Fault interrupting/withstanding capacity

6.2.2 Planning of electrical system configuration

Once the basic system parameters have been finalized, the next task is to plan the overall distribution system configuration. This is a very important step and requires the planner to consider all the aspects and arrive at an optimal configuration. The configuration once finalized is extremely difficult if not impossible to modify at a later date. At the end of this step we will have finalized the following details:

• Overall configuration
• No. of incoming feeders
• Incoming and distribution voltage level
• Ratings of major equipment
• Redundancy planning
• Type of distribution (Radial, Ring etc.)
• Type of redundancy including standby generation
• Integration of emergency/standby generation with the distribution system
• System Earthing and protective earthing (Local statutory requirements must be considered as the basis)
• Equipment for voltage/pf/harmonic control

6.2.3 Equipment ratings/sizing

Deciding the ratings of distribution equipment is the next stage in system planning. The common ratings required to be finalized at this stage are:

• Rated voltage, current and frequency
• Variations of voltage and frequency
• Fault withstand current and time
• Fault breaking capacity
• Clearance and creepage
• IP ratings of enclosures

6.2.4 Selection of appropriate equipment

While equipment sizing is the first step in finalizing the required distribution equipment, there are other factors which play an important role too:

• Cost factor
• Market reputation of the vendors who can supply such equipment
• Experience of other users (internal/external)
• Conformity to standards (national/international)
• Standardisation and variety reduction
• Maintenance requirements
• Status of technology
• Local statutory requirements being met

6.2.6 Maintainability and expandability

Planning must be done with due regard to maintainability of the equipment in service. Space for maintenance and other requirements must be integrated into the facility while the planning process is going on. Also, equipment such as switchboards may undergo additions or changes during this process. The initial assumptions must be constantly reviewed and necessary changes must be made in the layout to ensure space adequacy. Some of the aspects to be taken care of are as follows:

• Adequate space for all equipment as planned
• Access for maintenance
• Clearances for safety and maintainability
• Removal of parts
• Special tackles used at site
• Buildings to be designed considering expandability

While the requirement of space, maintenance access and clearances are usually obvious, the other points may need careful attention. These may only be known after finalizing the exact equipment as they vary from vendor to vendor. Early discussions after order placement will be required to freeze requirements arising from equipment-specific aspects.

As stated in the previous module, any distribution system equipment must be expandable to accommodate changes or additions to the plant process without major changes to the distribution system. Apart from expandability of equipment, other requirements such as space for such additions must also be planned without which equipment expandability alone will not be of much use. Important aspects to be considered as a part of expandability of distribution equipment are:

• Building design loads as a result of additions to switchgear
• Lighting and HVAC system to cater to expansion of distribution equipment.

As stated earlier, the ratings of principal equipment should be selected adequately to accommodate near-term growth of the system.

6.6.1 Asset management

In a utility, the major operating cost is that of servicing the debt created by purchasing and installing the distribution system. This cost may be regarded as fixed, or at least beyond the immediate control of the company, being largely dependent on prevailing money interest rates. However, maintaining the asset and the rate of replacement of the various components are determined by the policies adopted and can be regarded as controllable costs. Thus in recent years, maintenance and replacement have been the focus of attention and great efforts have been made to drive down these costs.

In asset management, the ‘Asset’ to be ‘Managed’ is considered to be the whole of the electricity distribution system, both active and passive components, that is, the sum total of all the historic investments that have been made, that are still in service. Some of these investments will be within the assigned lifetime over which the investment is depreciated financially (typically 40 years) whilst other assets will have been in operation for a longer period, but are still serviceable. Extending the life of these assets is critical to overall costs and therefore, in a privately owned utility, to profitability. This is because replacement before the end of an asset’s financially depreciated life is an absolute loss, whereas if life can be extended beyond the depreciated life the asset’s cost is only its continuing inspection and maintenance.

The ‘sinking fund’ formula below allows the annual cost of an asset to be calculated over a nominal service lifetime, leaving no debt at the end of the period.

The sum of money calculated by the above formula is sufficient to pay the interest on the debt and pay back the capital at the end of the period. The actual period of service lifetime varies according to the type of asset but for switchgear, transformers and cables it is usually 40 years, somewhat less for overhead lines. For example, calculate the annual cost of a circuit breaker costing $20,000 over 40 years at 6% interest rate.

For oil circuit breakers, the annual cost of initial purchase and installation has to be increased by annual sums covering after fault maintenance (typically every 3 years) and full maintenance (typically every 10 years). Although the equivalent rated Vacuum or SF6 circuit breaker could cost $26,000, its reduced maintenance nevertheless reduces the whole life cost. These factors are shown in Figure 6.2.

The annual cost of an asset is very dependent upon the service lifetime obtained. For example, the $20,000 oil circuit breaker identified in Figure 23.2 costs $1330 each year over a 40-year service life, but $1743 each year over a 20-year service life. Because of the rapid growth of load and major economic development that took place between thirty and forty years ago, many utilities and companies have switchgear assets already well into their assigned lives. This factor sets the stage for policies aimed at extending asset lifetime.

The management of these assets involves inspection, maintenance, repair and ultimately replacement, together with the installation of additional or improved specification assets to meet the needs of the system and to continuously improve network performance. The accurate formulation of these programmes of work is fundamental to the long-term management of the distribution system.

The following statements are taken from the stated Asset Management objectives of a major utility:

• To ensure that the distribution system is inspected and maintained in a condition that safeguards members of the public and company personnel, contributes to environmental improvement and provides an economic and reliable electricity supply.
• To produce an increased business benefit and a greater return on investment in the asset base, through higher levels of utilisation and a reduction of whole life costs.

Note from the second statement that a reduction in ‘whole life cost’ through more effective (that is, less but more targeted) inspection and maintenance is not the sole objective, it is also intended to increase the system ‘level of utilisation’, that is, the overall system loading. This is to be achieved by a more detailed knowledge of the condition of the system, on the understanding that a system in good condition is better able to withstand increased loading with fewer failures, compared to a system in poor condition.

6.6.2 Asset registers

A prior condition of effective Asset Management is to know what the asset is and its condition; in practice this means drawing up an Asset Register. To be fully effective, the register needs to be in computer format and should contain as much information as possible about the individual system components. Having an asset register in a computer allows for automatic production of inspection and maintenance schedules, sophisticated ‘what if’ modelling and the identification of trends in different types and classes of switchgear. The collected data for switchgear could include the items shown in Table 6.1.

The collection of all necessary data to compile a comprehensive asset register is a very large task indeed that may require several years to complete, unless a specialist contractor is brought in to undertake, or at least assist in the work. Furthermore, some of the required information may be obtainable only during outage. Circuit outage should be regarded as a resource, comparable to manpower. An outage has a cost, not only financial, but also the cost of risk to the system. This is because, where supplies are duplicated, one feeder will be inoperative during the outage and the system then relies on a single feed. Therefore outage should be used as little as possible and generally not just to collect asset data. Where data is only available through an outage, maximum use of each outage should be made both to obtain condition data and to complete all the outstanding maintenance required on the section of system taken out of service. Condition data is considered later in this chapter.

If maintenance is to be scheduled and targeted by switchgear condition rather than time, it is vital that information that can only be obtained during plant maintenance is accurately measured and securely stored for future reference. In particular, it is important that plant type-specific defects are checked for, put right if found and recorded as complete. It is this kind of information that identifies trends in plant condition and allows maintenance resources to be targeted to where they will be most effective.

In practice, Asset Registers are built up over time, starting with the most critical items of plant at the strategic, generally higher voltage, locations in the network, gradually extending to less critical plant. This policy gives the greatest and quickest benefit for the least cost.

6.6.3 Condition Based Maintenance (CBM)

The prime objective of Condition Based Maintenance (CBM) is to move towards a maintenance philosophy that directly relates ‘work done’ to ‘condition’. This represents a change in direction away from time-based maintenance where work was done at pre-determined intervals regardless of need. Overall, the total amount of maintenance can be considerably reduced compared with a time-based maintenance policy and as well as the obvious reduction in cost, it also produces the benefit of reduced risk to system security that is inherent with invasive maintenance.

The key to effective timing of preventive maintenance for each asset type is to understand the progressive nature of asset condition deterioration with time and/or use. Maximum value comes from understanding the relationship, with respect to time, between potential failure and functional failure (the P-F interval). Figure 6.3 provides a simplified model illustrating this concept. Ideally the ageing or performance characteristics should be determined such that preventative maintenance can be scheduled just before a condition indicator enters the area in which a particular asset condition indicator reaches the criteria defined as failure.

Where a condition is allowed to progress beyond the point of unacceptable risk of failure, it is likely that failure will occur and maintenance can then be regarded as remedial. This is likely to be more expensive. CBM aims to carry out maintenance no sooner but certainly no later than the time needed to prevent a failure and:

It is an absolute requirement of good maintenance that the plant asset should be in better condition after the maintenance than it was before.

Clearly, for condition based maintenance to be effective, the condition of the asset must be known; if it is not known, time based maintenance must still prevail. Knowledge of condition implies the use of diagnostic tools, of which there are two types, invasive and non-invasive. Invasive inspection describes the collection of condition data, which involves one or more of the following:

• Circuit outage to allow safe access to components for either visual inspection or the use of diagnostic equipment.
• The dismantling of an item of plant to allow access for visual or measured data to be obtained followed by the re-assembly of the plant into its original form. (This normally refers to collecting data during maintenance or repair).
• The disruptive dismantling of an item of plant or equipment to obtain visual or measured data followed by the replacement of that item because it cannot be re-assembled in its original form.

Non-invasive inspection falls into two categories:

• Diagnostic instruments or remote monitoring that allow measurement of condition directly from a safe distance, without disturbing the plant, for example partial discharge monitoring techniques.
• Measurable indicators which have a direct relationship with the asset condition, for example analysis of insulating oil or analysis of insulating gas.

Non invasive technique (a) can be difficult, because development work is still in progress and a considerable amount of data needs to be collected, analyzed and compared to actual failures of equipment, before absolute, safe limits can be established for many of the condition indicators gathered in this manner. In practice, trend data between inspections, or between inspection and first installation, are the only guides. However, over a longer period of time, it is expected that appropriate limits can eventually be set.

If asset condition can be established with confidence, maintenance requirements can then be assessed and the priorities ranked by a process that takes account of both the condition of an asset and its relative importance in the distribution system. This process is known as establishing a Condition Importance Rating with the highest priority being given to plant scoring highest (that is, ranking condition alongside the consequences of failure).

6.6.4 Reliability centered maintenance (RCM)

This technology originated in 1974 and was first utilized in the aviation industry, although it has since been extended to other industries, including the electric power industry. It differs from other techniques by focusing on the function of the equipment, rather than the equipment itself.

RCM can be described as a process used to determine the maintenance requirements of any physical equipment, based upon the operational requirements, standards of performance and in particular, failure modes and the consequences of failure. This process essentially repeats the ‘form and function’ analysis carried out by the equipment manufacturer at the design stage, which is referred to as the Failure Modes Effects Analysis (FMEA) or sometimes the Failure Modes Effects Critical Analysis (FMECA).

The only difference between the manufacturer’s FMEA worksheet and the user’s RCM worksheet is that the former summarises the manufacturer’s expectations of how the equipment may fail in the future and the latter is based upon historical knowledge of how the equipment actually fails. The RCM worksheet specifies the known failure modes and also analyses the maintenance actions required to prevent failures.

Risk can be defined as the product of the probability of an event occurring and the consequences of that event. Using a matrix diagram, risk can be quantified and ranked, as shown in Tables 6.2 and 6.3:

An RCM analysis is implemented as a seven-step process as follows:

• The objectives of maintenance with respect to any asset are defined by the functions of the asset and its associated desired performance standards.
• Inability of an asset to meet a desired standard of performance is known as functional failure. This can only be identified after the functions and performance standards of the asset have been defined.
• After identifying the functional failures, the failure modes are identified which are reasonably likely to cause loss of each function.
• Failure effects describe what will happen if any of the failure modes did occur.
• In what way does each failure matter? This refers to a quantitative measure of failure consequences, namely the criticality of failure. RCM not only recognizes the importance of the failure consequences but also classifies these into four groups: hidden failure, safety and environmental, operational and non-operational.
• The process of analyzing functions, functional failures, failure modes and criticality (FMEA/FMECA) yields opportunities for improving performance and safety.

RCM recognises three major categories of preventive tasks as follows:

• Scheduled on-condition tasks – which employ condition-based or predictive maintenance
• Scheduled restoration
• Scheduled discard tasks

6.8.1 Partial discharge

Partial discharge within and on the surface of insulating materials is one of the most reliable indicators of equipment condition and possible failure. It has been the focus of considerable research effort and is therefore well understood.

Consider Figure 6.6, showing a layer of solid insulation between two flat plate electrodes. The insulation is imperfect because it contains an air filled void. As the applied voltage rises, the voltage distribution is non-uniform, due to the different dielectric constants and the air filled void will tend to be more electrically stressed than the remainder of the solid insulation.

At some point in the AC voltage cycle, the stress across the air filled void is sufficiently great that ionisation occurs instantaneously. This causes a high frequency electrical signal that is small but detectable; it may also be detectable by sound. As the voltage falls during the second quarter cycle, ionisation ceases, followed by a further ionisation and cessation during the third and fourth quarter cycles. In the positive going half cycle, the pulse is negative and during the negative half cycle the pulse is positive, as shown in Figure 6.7.

The voltage at which ionisation commences is called the ‘inception voltage’ and the voltage at which ionisation ceases is called the ‘extinction voltage’. In practice, partial discharge is a good measure of the quality of the insulation, which ideally should be partial discharge free at the equipment’s operating voltage. However, this is seldom the case.

Because PD is voltage dependent, it will tend to increase as voltage stress increases and ever-smaller voids begin to ionise, not only within the body of the insulation but also at the interfaces between the insulation surface and the electrodes. A more typical pattern of partial discharges is shown in Figure 6.8.

In the situations shown in Figure 6.8 the inception voltage is the voltage at which the first partial discharge can be detected. The total number of PD pulses and the total PD charge (in Coulombs) can also provide useful indicators.

Partial discharge is not confined to the interior of solid insulation. Figure 6.9 shows an insulated bushing, which is internally satisfactory, but contaminated on the surface with a semi-conducting layer of dust and metallic particles. Gaps in this contamination act in exactly the same manner as the void in Figure 10.6. That is, they ionise and de-ionise in a random pattern as arcing, sparking and surface erosion re-distributes the contaminating material. Careful and expert analysis of the recorded waveforms can detect the following forms of PD:

• Inside solid insulation
• Between a conductor and solid insulation
• Between insulating material and ground
• Surface tracking
• Arcing and sparking (for example a conductor under floating potential)

Power distribution measurement can be undertaken online or off-line. When measured on line, either coupling capacitors or radio frequency antennas may be used, but accurate measurement is more difficult, because the small signals tend to be masked by general electrical noise in the supply and the metal casing of the equipment.

For off line measurement, a partial discharge free voltage source is required, preferably with the equipment and the test specimen inside an earthed metal enclosure so that the electromagnetic conditions are perfect for accurate measurement. This is seldom available outside a laboratory.

Another factor to consider is whether the equipment being monitored for PD is on or off load. When on load, the temperature will rise and any imperfections at the interfaces will tend to become more pronounced. To allow for this possibility, monitoring should preferably continue over a period of time (this can only be on line measurement). Extended PD monitoring on line can provide further useful data, over a medium to long timescale. This is called ‘time trending’ and includes:

Short term PD monitoring (1 – 2 hours). This duration of testing simply allows a more accurate measurement by removing short-term variations.

Semi-permanent monitoring (1 – 3 days). This length of monitoring allows measurement of variations of PD with load, that is, component temperature and mechanical stress. This method is useful for older installations with high levels of PD activity.

Continuous monitoring – This measures the long-term trends in PD activity and may be combined with an alarm facility. Due to cost, continuous monitoring can only be justified for critical, high value installations with high cost of failure.

In an inspection and maintenance context, it is economic and useful to carry out PD monitoring at intervals, perhaps yearly, so that a baseline level is established and long-term trends monitored.

Although it is difficult to give exact guidance on what is and what is not an acceptable level of PD, sharp rises in activity over short periods of time or a strongly rising trend should encourage a more detailed investigation. A PD analysis expert may categorise PD levels into the following categories:

• Low
• Moderate
• Elevated
• Critical

In general, air insulated switchgear will be more susceptible to PD than switchgear where the insulation surfaces are within a gas filled (SF6) enclosure. The following locations in switchgear are known to be common sources of PD:

• Internal faults in VTs
• Busbar support insulators
• Cable terminations
• Through bushings
• Internal faults in CTs
• Points where a conductor at medium or high voltage is close to earthed metal
• Surface contamination including moisture
• Conductor under floating potential
• Arcing contacts of circuit breaker
• Arcing at isolating contacts
• Loose connections including loose earthing connections

Where a company or utility has a population of switchgear of the same or very similar type, valuable information can be obtained by comparing the levels of PD occurring at the various installations and between different switch panels in the same installation. In some parts of the world, ‘user clubs’ have been established where this information can be exchanged. This is the type of information that the PD expert analyst draws upon and should have access to.

If PD in a particular installation is greater than the PD in the remainder of installations in that group, this may be taken as a warning of impending failure. At worst, if PD activity has risen to a very high value, it may be a signal that an end-of-life decision needs to be taken.

6.8.2 Partial discharge – transient earth voltage (TEV) monitoring

Developed over the last 16 years, TEV monitoring locates partial discharge activity by measuring the transient voltages occurring in the switchgear metal enclosure. It has the great advantage that it can be carried out whilst the switchgear is in service and it is also capable of locating the site of a partial discharge. Figure 6.10 shows the test method in diagrammatic form.

When a partial discharge occurs, in the example phase to earth, a small quantity of electric charge is transferred by capacitance to the earth metal cladding. The quantity of charge is extremely small, normally a few pico-coulombs and the transfer occurs very quickly, just a few nanoseconds. As the charge is transferred, electromagnetic waves propagate away from the discharge site in all directions as transient voltages. Due to skin effect, these transient voltages occurring on the inside of the enclosure cannot be detected on the outside. However, at an opening in the cladding, such as a gasketted joint, the electromagnetic wave can propagate into free space. The wave front impinges on the outside of the enclosure creating a voltage wave that may be detected, although the equipment must be very sensitive and very fast. By using two capacitive probes, the location of the discharge site may be estimated by comparing the time of arrival of the two waves.

Although TEV monitoring requires expert interpretation, TEV can locate partial discharge sites in live equipment, providing that the electrical noise is not excessive. TEV survey is usually carried out in two stages; in the first stage one probe is used to find PD sites and in the second stage both probes are used to locate them more precisely. The equipment has a 2 ns capability, equivalent to a distance of 600 mm, so in practice a PD site can be reliably attributed to a particular switch panel in a multi panel switchboard or even an individual cable box.

6.8.3 Partial discharge testing by acoustic methods

Monitoring of Partial Discharge by electrical methods has the limitations that coupling capacitors may not be available, or difficult to connect. In these circumstances, monitoring may be carried out by an acoustic method. Portable test equipment is available and has the advantages that:

Measuring can be carried out at any time, it is not necessary to take the switchgear off line.

Even where the electrical (radio frequency) signal from a Partial Discharge is suppressed by the metal enclosure, some sound signal may escape.

Figure 6.11 shows an acoustic discharge probe made by Detectaids Ltd. This unit can be fitted with different sensors suitable for detecting both airborne sound and sound conducted through structures. It is sensitive to sounds up to 40 kHz, that is, well above the human range of hearing and it can also amplify sound from a non-audible to an audible level.

Acoustic measurement has much the same advantages and disadvantages as electrical methods. It does not provide an absolute satisfactory/unsatisfactory indication, but it can alert users to developing problems and monitor trends over longer periods of time. Because the instrument and its sensor can be moved, it can provide some information on the location of a problem.

Monitoring needs to be done in a consistent manner and good records taken, so operative training is required. However, the device is cheap enough to be issued to substation inspectors.

6.8.4 Tan delta testing

Historically, Tan Delta testing is much older than Partial Discharge testing and dates back at least 60 years. Despite its age, it can still be useful in certain circumstances. Consider the cracked bushing of Figure 6.12, together with the equivalent circuit to the right. The crack, though difficult to see by eye, is nevertheless contaminated with dust and moisture and forms a high resistance path in parallel with the bushing capacitance.

In the bushing of Figure 6.12, current flows through both the capacitance and the resistance, forming the vector diagram shown in Figure 6.13. The current through the resistor is in phase with the applied voltage, but out of phase with the capacitance current by 90°.

In practice the resistive current tends to be much smaller than the capacitive current and Tan Delta (the ‘Loss Angle’) is small. This is one of the reasons that the ‘Schering’ bridge measurement method is used.

All insulating materials have a loss angle and the better the insulation quality, the smaller the loss angle. The loss angle at a low applied voltage is called the ‘material loss’. As the voltage applied to the specimen is increased, any voids in the insulation tend to ionise and discharge (that is, partial discharge). The PD current is an additional loss, called the gaseous loss and adds arithmetically to the material loss, resulting in increased Tan Delta with increasing voltage. The increase is not linear, but tends to increase sharply above a PD inception voltage (Figure 6.14).

The main limitations of Tan Delta testing are that it is strictly an off line test and that it can only be applied to single component. Tan Delta testing of an entire switch unit could not identify any single component causing a problem. Nevertheless, the graph of Tan Delta with voltage is a useful indicator of insulation quality/deterioration and finds major application in cable testing.

Thermal imaging

This technology is also several decades old and originally used solely by the military; it was too expensive for general use. However over the last 30 years it has steadily declined in cost and increased in performance. Infra red radiation, also known as thermal energy, is electromagnetic energy emitted by all objects whose temperature is greater than absolute zero. The lower the temperature, the longer the infra red wavelength, but it is always longer in wavelength than visible light. The human eye cannot see it, but special electronic sensors can detect it. Also, thermal energy does not bounce off objects like visible light does, it only comes directly from the objects emitting it. In general, dark, dull surfaces emit infra red radiation better than shiny, light colored surfaces and glass does not transmit infra red energy at all; that is, it is not transparent to infra red in the same way that it is transparent to visible light.

In the early years, infra red sensors had to be cooled to extremely low temperatures to be effective; it was the necessary refrigerating equipment that made the technology so expensive. A further disadvantage was that the early cameras were incapable of registering a steady image, the view had to be continuously moved for an image to be obtained. Later, improved sensors were introduced that did not need cooling and also provided a steady image. Mostly these uncooled systems were based upon the ‘PyroElectric Vidicon’, (PEV) a sensor similar to a television camera tube. Unfortunately, PEVs were easily ‘overloaded’ by hot objects, causing a white area on screen where the image should have been. This effect was called ‘blooming’.

Modern cameras use a solid state technology first introduced about 20 years ago, in which the heat detecting elements are grouped on a printed circuit board. ‘Blooming’ has been eliminated. This development has allowed camera size and weight to decrease to a level that is easily hand held. Cost has fallen to between $10,000 for the cheapest models up to $30,000 for a high specification unit.

Because the infra red energy cannot be seen by the human eye, the viewing screen of the camera has to translate the various temperatures it sees into either ‘false colors’ (in the more expensive models) or into a ‘grey scale’ (in the cheaper models). Figure 6.15 illustrates.

A point worth noting is that cameras are made to a performance standard that includes ‘Minimum Resolvable Temperature Difference’ (MRTD), the measure of how small a temperature difference it can detect. For example, a thermal imaging camera with an MRTD of 20° would be half as sensitive as a camera with an MRTD of 10°. In addition, the number of ‘picture elements’ in the sensor and on the viewing screen determines the smallest detail that can be seen. Thermal imaging cameras do not directly indicate an absolute value of temperature, though they sometimes have the facility of downloading the image, plus a temperature scale to a computer (Figure 6.16).

Viewing screens indicate objects hotter than those in the background very well and this is entirely suitable for locating hot spots in exposed conductors. Also, it is a monitoring technique that is non-invasive and therefore can be used at any time, either as a routine monitoring tool, or to investigate suspected problems, or both.

The main application in electrical networks is in the detection of hot spots in overhead lines and in exposed busbar systems in substations. Thermal imaging finds only a limited application for metal enclosed switchgear indoors, although it can detect hot cable boxes and would detect a switchgear enclosure that was significantly hotter than its neighbour (refer to Figure 6.17).

Typical camera specifications

• Angular resolution – 1.3 millirad (0.14 degrees)
• Thermal sensitivity – 0.08 °C
• Viewer – 640 x 480 pixels, full colour
• Sensor array – 320 x 240 pixels
• Accuracy +/- 2 °C, +/- 2 %
• Temperature range – 40 °C to + 248 °C or 0 °C to + 600 °C

Overcharging

Experience with constant voltage chargers has shown that apart from loss of charge (or undercharging) make of charger. In one type of charger a possible cause is the blowing of the sensing-circuit fuse which unbalances the differential amplifier with the resultant triggering of the main series transistor and consequent saturation of the transductor. In another type the likely cause is failure of the main control transistor.

Whatever the cause, a prolonged state of overcharge will cause gassing of the battery and gradual loss of electrolyte resulting ultimately in damage to the plates of cells. To avoid persistent overcharging, the alarm should respond to over voltage as well as under voltage. Hence in the most modern designs of alarm, separate controls are provided for both high and low settings. A third control allows the time delay to be set.

Earth fault alarms

It is entirely possible for substation batteries to suffer earth faults and monitoring devices are available to detect this condition. One type of earth fault detecting device comprises a centre-tapped potentiometer connected between the end terminals of the battery, together with a relay connected between the centre-tap of the potentiometer and earth. This is shown in Figure 6.18. The suggested design requirements for a battery earth fault detector are:

• The resistance values must be such as to limit the earth fault current for a solid earth fault on either pole of the battery (or equipment connected to it) to a value not in excess of 60 mA.
• The sensitivity should be such as to detect an earth fault on either pole of a value of 10,000 Ω or less, for a 100 V battery (and proportionately greater or less for other battery voltages).
• The continuous drain on the battery from the potentiometer shall not exceed 26 mA at the normal float voltage and should preferably be less.
• To provide a test facility, the battery charger front panel should be equipped with a double throw-and-off switch, which is biased off, but that can connect a 10,000 Ω resistance between either pole of the battery and earth. This is to facilitate routine testing. The test facility will not pass sufficient current to cause tripping of circuit breakers. This value refers to 100 V batteries and will need to be proportionately scaled up or down for other voltages.

Trip coil monitoring

The trip mechanism is second in importance only to the circuit breaker itself. It must open the circuit called upon to operate, perhaps decades. Statistics show that trip mechanisms and trip coils are responsible for a high proportion of circuit breaker faults and investigation shows the following factors as primary causes:

• Improper lubrication or lubrication that has dried out and gone solid, freezing the mechanism
• Shorted turns in the trip coil, mainly due to deteriorated winding insulation
• Faulty secondary wiring and secondary wiring contacts
• Seized bearings
• Defective latch mechanisms
• Corrosion especially rust
• Incorrect adjustment of trip latch mechanism

It follows that maintenance of the trip mechanism is vitally important and effort should be directed toward monitoring its performance. The best method of test is to measure the time interval(s) between the instant when current begins to circulate in the trip coil and the circuit breaker main contact(s) open. Alternatively and more simply, the length of time between inception of trip coil current and its interruption by the opening of the secondary contacts can be measured, as this closely approximates to the total circuit breaker opening time. Trip coil testing is an off line test undertaken during maintenance and should, of course, be undertaken before any maintenance of the mechanism is undertaken or the circuit breaker CLOSED or OPENED.

Ideally the circuit breaker should be tested on first installation so that later measurements can be compared to the original performance. IEC 66 requires that the trip coil should operate correctly at 60% of the normal battery voltage, this is to allow for the situation where several circuit breakers trip simultaneously and current demand on the battery is high, depressing the battery voltage. Hence testing should take place not only at normal battery volts, but also at lower voltages. Traditionally tapping the main battery carried out this reduced voltage testing, but newer testers have facilities to continuously vary the trip coil voltage, typically between 6 and 96% of the nominal value.

A further matter of concern is the length of time that the trip coil is energised during a circuit breaker operation. In the design of circuit breaker trip mechanisms, secondary contacts are arranged to disconnect the supply to the trip coil after the mechanism has been triggered, to prevent burn out. The time limit for an energised trip coil is 0.6 s and there are devices on the market that will automatically disconnect the supply after this period of time. The secondary contacts that interrupt the trip coil current undertake a severe duty, because the induction of the coil stores significant energy and a good deal of arcing can take place on these contacts. They should therefore be given careful attention during maintenance.

As a further refinement of protection, it is possible to fit devices that will detect a continuously energised trip circuit and, via an inter-trip link, cause another circuit breaker, the ‘backup’ circuit breaker to operate after a pre-determined time. Schemes of this type are justified where the consequences of a circuit breaker to operate are severe. For example, if a generator circuit breaker fails to operate after the generator prime mover has shut down, the generator will continue to operate as an induction motor, drawing its supply from the network. Even if the generator circuit breaker is fitted with reverse power protection, it will still not be immune to the consequences of trip mechanism failure.

Testing can be further extended to monitor and record the actual current flow through the trip coil, the movement of the circuit breaker operating lever and the opening of the contacts. The coil is of course an inductive device and the operating current will take time to rise to a level where the mechanism is released.

Figure 6.20 shows a typical trip coil graph of time against trip coil current and contact opening. Further useful measurements on the trip coil are:

• The voltage at which the circuit breaker will just trip. This measurement indicates the level of static friction (‘stiction’) and establishes the margin of safety over the normal tripping voltage. It should not be more than 66% of the nominal operating voltage.
• The D.C. resistance of the trip coil. Any reduction in this value over time indicates shorted turns.

Taken together, these measurements of trip coil parameters are called the ‘trip coil fingerprint’. They should be measured and recorded on commissioning of the circuit breaker and at every subsequent maintenance. A typical tester is shown in Figure 6.21.

Typical instrument specifications

• User settable 6 to 96% of coil input voltage
• Setting accuracy 2%
• 80 A capability
• Reversible polarity
• Overload protection
• Trip coil burnout protection (0.6 s limit)

Contact motion analysis

If the cost of the necessary test equipment can be justified, it is possible to make time-travel or motion analyzer records. Motion analyzers are portable devices that monitor the operation of the complete circuit breaker by coupling the sensors of the motion analyzer to the circuit breaker operating lever or rod. These include high-voltage and extra- high-voltage dead tank and SF6 breakers and low-voltage air and vacuum circuit breakers.

Motion analyzers can provide graphic records of close or open initiation signals, contact closing or opening time with respect to initiation signals, contact movement and velocity, and contact bounce or rebound. The records obtained not only indicated when mechanical difficulties are present but also help isolate the cause of the difficulties. Like other measurements, it is preferable to obtain a motion analyser record on a breaker when it is first installed. This will provide a master record which can be filed and used for comparison with future maintenance checks. Tripping and closing voltages should be recorded on the master record so subsequent tests can be performed under comparable conditions.

Time-travel records are taken on the pole nearest the operating mechanism to avoid the inconsistencies due to linkage vibration and slack in the remote phases

Programma Electric TM1600/MA16 Motion Analyser

• This breaker analyzer system measures a circuit breaker’s timing cycle. The timing channels record closings and openings of main contacts, resistor contacts and voltage contacts.
• Since the timing channels are not interconnected, series-connected breaker chambers without having to disconnect them.
• A built-in program unit permits easy selection of different sequences of breaker control pulses. The delay time between pulses is set on a thumb wheel. The program unit can be used to control coil currents up to 26 A (see Figure 6.22).

• The time values obtained refer to the exact instant at which voltage was applied to the coil, and a built-in printer provides you with a hardcopy printout immediately after measurement.
• The TMI 600 can be equipped with up to 24 time-measuring channels as required by the user. When more than 24 channels are needed, one or several Slave Units can be connected together to provide an unlimited number of measurement channels. Modular design also makes it easy to combine the system with the MA61 Motion Analyzer.
• The MA61 Motion Analyzer is an excellent supplement to the TM1 600. It combines the easy readability of an oscillograph with the extra accuracy ensured by computerized measurement and computer-processed readings. Menu-driven button selection via the built-in display makes operation simple and easy.
• The MA61 can be equipped with up to 6 analog channels, and it can be easily adapted to the different measurement requirements for high-voltage circuit breaker testing. It can measure and calculate contact paths and the speeds at which breaker contacts operate as well as the current in operating coils. It can also measure dynamic resistance (DRM), voltage, pressure and a number of other entities.
• After measurement, the MA61 performs the necessary calculations and prints results in both diagram and table form on a connected printer (letter-size A4 paper) or via the TM1600’s high-speed built-in printer. Moreover, parts of curves can be easily enlarged for closer study.
• The MA61 incorporates a battery-backed memory that can store up to ten measurements for subsequent processing.
• The TM 1600 also supports communication with personal computers and the CABA Win Breaker Analysis Software. The analyzer can be used for testing breakers taken out of service or for on-line testing. Fully equipped, it weighs only12 kg (2.6 lbs).

SF6 gas monitoring

The effectiveness of SF6 as an insulator and in extinguishing arcs is dependent on its purity. In service this purity may degrade due to contamination by:

• Oxygen
• Moisture
• Acidity (mainly as Hydrogen Fluoride)

To prevent contamination, a ‘molecular sieve’ is usually incorporated in each enclosure; this contains chemicals to filter out contaminants but they have a limited life. Monitoring of SF6 circuit breakers should include taking and analyzing gas samples for these contaminants; the switchgear manufacturer should be able to advise on acceptable limits.

In general user replacement of SF6 in a circuit breaker or enclosure is not practicable, either the unit should be returned to the maker (particularly if the circuit breaker is a cassette) or the manufacturer, or a specialist contractor, should be asked to replace the gas on site. SF6 is a powerful greenhouse gas and should never be allowed to escape into the atmosphere. Where an SF6 circuit breaker has faulted and arc products are exposed, great care will need to be taken. The white powder like deposits contain toxic Fluoride and they are irritant to the skin, so a specialist contractor should be employed. Typical features of analytical instruments are given below.

Oxygen

Teledyne’s 3010TAC and 3010PAC BASEEFA / CENELEC approved, intrinsically safe trace and percent oxygen analyzers are versatile, microprocessor based instruments used for detecting oxygen from 0 – 10 ppm to 100% in a variety of gases. Simple menu choices, membrane command switches, and dual displays make set-up and operation clear and quick. Three user-configurable ranges are offered with an excellent linearity precluding the need to recalibrate when changing ranges. A bi-directional RS-232 serial interface is incorporated to relay information to a host computer for remote monitoring of zero and span calibration. Applications include: Power, Air separation, Furnace, Chemical processes (see Figure 6.23).

Moisture

Model SDDLG has a range 0 – 80 °C dew point, to room air. The self-extending head allows up to 20 litres a minute flow for clearing the air supply pipe work without wetting the test chamber. Note the absence of knobs, calibrating, cooling, and servicing required by other methods. The automatic dry down measuring head accelerates the remarkably quick response from the sensor. An additional Shaw sensor can be connected to the rear of the hygrometer if desired, so that the external and internal switch can monitor two positions. Accuracy is guaranteed to better than one part in a million of moisture in very dry air or gas, and as the reading is specific to water vapour, so calibration is accurate for different gases. Flow rate has no effect on the accurate measurement.

The heart of the meter is a Shaw molecular sieve moisture sensor with a gold internal filter and gold plated exterior, a jewel of a sensor in fact with a rapid 1 s response time from dry to wet. (99%) So simple to use, blocking the outlet with a finger for a moment, raises the measurement head, and directs air or gas to the sensor (see Figure 6.24).

Acidity tester (Anachem HF-1000 acidity in SF6 analyser)

The HF-1000 enables the determination of trace levels of HF in SF6, therefore enabling the prevention of the damaging effects of this aggressive contaminant (see Figure 6.25).

Example of a generic maintenance instruction

Lighting
Portable lighting will be required to supplement the permanent substation lighting, so that the interiors of chambers can be properly examined and safe access can be gained. All power tools and portable lights must be 110 V operated and supplied from centre tapped 66 – 0 – 66 V transformers.

Safe exit from substation
Check that the emergency exists are clear and that door panic bars, if fitted, operate correctly.

Tools and equipment
Insulated tools and guards shall be provided as necessary, together with any other special equipment for operation of the switchgear (for example circuit breaker slow closing handles).

Safe working – power closing
Before work commences it is important that all power-closing devices have been rendered inoperative. This should be confirmed on the safety document. The work involved may require the restoration of the power closing supply at some stage, if so, the arrangements for this should be made clear to the fitters carrying out the work.

Environmental protection
When working on outdoor switchgear, a temporary shelter shall be erected if rain is falling or appears likely to fall.

Protection from live LV equipment
If any part of the LV distribution board is live, it is to be covered over with an Approved insulation sheet that shall be fitted before work commences and removed only when all work is complete.

Cleaning materials
Only approved cleaning materials shall be used. Under no circumstances shall steel wool be used as it will cause contamination.

Unit identification
Before maintenance work commences check that substation nameplates are in position and that all switchgear is clearly labelled with the circuit names. If the switchgear is labelled at the front and at the back, check that the labels agree. All labels must be securely fixed and legible. Any temporary labels should be replaced with permanent labels.

Cleanliness
Only lint free wipes may be used in oil filled chambers, not cloth or paper wipers that can leave fibres to contaminate the oil. All loose dust should be swept away before opening any normally closed access. After a delay to allow dust to settle the equipment should be wiped down, any rust removed and the area cleaned and spot primed. Wipe down exposed insulating surfaces with a clean, dry, dust free wiper and cover them over until maintenance is complete. When oil tanks are removed these should be covered over to prevent ingress of dust or other foreign matter. Grease and other lubricants should be applied sparingly and any spillage wiped off.

Use an Approved plastic sponge to wipe down in oil filled chambers, followed by rinsing with clean oil. After use, the sponge should be well rinsed in clean oil and stored in a clean, closed container. A polythene food container with a snap-on lid is recommended. Tanks should be refilled from a pipe reaching to the bottom of the tank to avoid entraining air. Pipes should be flushed with clean oil and the outside wiped with a clean oil soaked sponge before using them for refilling. Test bushings that enter oil must be cleaned immediately before use by wiping with a clean oil soaked sponge or by polishing with clean chamois leather. After use, paper wipers may be used to dry off excess oil. Oil sampling thieves should be treated in a similar manner. Where a tank must be entered, a plastic mat well sponged down before use should be used to stand on. Ladders and all other items that enter the tank should be well cleaned before entry to the tank. In these situations it is usually possible finally to swill down with clean oil to a drain in the tank.

Cleaning down oil filled switchgear
The preferred procedure for cleaning down oil filled switchgear is as follows:
Spray all components with clean oil, working from top to bottom. Remove all oil from the chamber using a wet/dry vacuum cleaner ensuring that the suction tube reaches the bottom of the tank. Repeat the above procedure until residual oil is clean. Take care to adjust the spray so that a mist is not created in the work area.

Avoiding the ingress of moisture
At all stages of inspection or maintenance, precautions must be taken to avoid the ingress of moisture or wind borne debris by using suitable temporary shelters over outdoor equipment. Tools, wipers, oil, etc. must be kept dry.

Any sign of moisture in equipment being maintained or inspected must be reported, to allow remedial work to be initiated. Particular attention shall be given to gaskets, tank breathers and the seals on those parts of the mechanism that pass through the sides of oil filled chambers.

Solvents
Care must be taken with the selection and use of cleaning solvents and penetrating oils with respect to fire risk and possible damage to insulation, indicator windows, moulded components, seals, gaskets, etc. Their use should be avoided wherever possible and any excess removed immediately.

Maintenance items specific to distribution switchgear

Position indicators and oil level indicator windows
Before maintenance or operation, check the semaphore windows for signs of cracking, crazing, discoloration or any signs of ingress of moisture. If damage is considered the result of vandalism or interference, ensure that this is reported for a re-assessment of the substation’s security classification. Take appropriate actions to prevent recurrence before leaving site.

Arc gaps
If arcing horns are fitted make sure that gaps are correct and that the fastenings are secure.

Earth bonding continuity
Ensure that earthing connections are tight and electrically clean, and that all contact screws are tight and full contact is maintained. Take care to tighten all bolts and nuts, together with any locking devices that may have been disturbed during maintenance. All exposed metal work should be effectively earthed.

Shutters and locking devices
Make sure that shutters and all locking devices function correctly and that where they need to prevent an action, they do so. Mechanisms should be free from corrosion and freely operating with all items such as nuts, locking devices, being secure.

Unless otherwise stated in the manufacturer’s handbook, servicing should be limited to occasional light lubrication applied to bearings, shafts and pivots. Thin machine oil should be used on actuating levers and rollers.

Interlocks

Purpose
Interlocks are incorporated to ensure safe operation of the switchgear.

Knowledge of interlocking requirements
In order to maintain interlocks correctly, an understanding of their purpose is required and a person should be designated who has the relevant knowledge and experience. The manufacturer’s handbook and any relevant plant diagrams should be available for reference.

Maintenance of interlock systems
This should include implementation of the following recommendations, depending on the types of interlock installed.

• Mechanical aspects. Moving parts should be cleaned and adequately lubricated, so that they are free to move as intended. Check for wear or excessive free play and, if found, correct it or refer it to the manufacturer. All fasteners should be secure.
• Electrical aspects. Inspect control wiring for signs of damage and check terminations for tightness. If in doubt concerning the condition of the insulation, carry out an insulation resistance test.

Ventilation
Ventilated equipment should be examined to make sure that the airflow is not restricted in any way and, in the case of forced ventilation, that any airflow interlock operates correctly. Filters, if any, should be cleaned or renewed as necessary.

Functional test
Where the relevant busbar and/or feeder circuits can be made dead, all interlocks should be functionally tested before equipment is restored to service. These checks should be carried out in both the positive and negative modes to ensure that the interlock system not only permits fulfilment of the intended operational sequence, but also prevents, when necessary, unintended and unsafe action. When an interlock is found to be defective and remedial action cannot be implemented immediately, steps need to be taken to ensure safety by other adequate means.

Equipment heating and lighting
The operation of heaters, lights, emergency lighting installations and changeover equipment for alternative low voltage (LV) supplies, where fitted, should be verified. WARNING: These circuits often remain live when the equipment is otherwise isolated.

Lifting devices
The maintenance of lifting devices should be carried out at regular intervals. In some types of equipment these form an integral part of the item and should be dealt with during the maintenance of the equipment. Some lifting devices are portable; these should be separately maintained in accordance with the manufacturer’s recommendations, and should be examined and tested In accordance with statutory requirements.

Equipment tools, spares and test instruments
Tools, spares and test instruments stored local to and associated with a particular equipment should be regularly checked against an inventory.

Tripping and closing supplies
It is particularly important that tripping and closing supplies be maintained in good order. Compressed air plant and battery installations should be regularly maintained, including associated indicators and alarms, in line with the manufacturer’s instructions.

Cable boxes, compound filled busbar chambers, band joints and endcaps

Proceed as follows:

• Check for signs of compound leaking, displaced gaskets or other damage.
• Remove the filling orifice cover or in the case of band joints, the top plate.
• Check the compound level.
• Check the compound surface for signs of unevenness, dullness or tackiness. Dullness or tackiness indicates leakage of switchgear oil into the compound.
• Check for ingress of moisture, signs of rust, corrosion or flaking paint.
• Carry out any remedial work necessary.

Test Access Covers
Test access covers are likely to be opened more frequently than any other sealed cover on switchgear. Particular attention should be paid to the fastening and compression of the gasket. During maintenance the test bushings should be inserted and all associated interlocks checked. The surface of the test bushing should be inspected and any damage repaired. Restore weather protection to all disturbed surfaces; nuts, threads etc. either by repainting or by use of grease coating.

Insulation, bushings, barriers and tank linings
Porcelain
Visually examine all porcelain components carefully for cracks, deterioration of the cement or any other defects. Do not ‘feel’ for cracks, because edges can be dangerously sharp. ‘Ring’ the porcelain component by tapping it with a pencil, the sound should be sharp not dull. This may not be effective in all situations, depending upon the mounting or enclosure.

SRBP
Visually examine all SRBP (Synthetic Resin Bonded Paper) and cast resin bushings. If the bushing is in air, wipe clean and examine for cracks, tracking, blistering, de-lamination or discoloration. In oil, wipe clean with an Approved wiper soaked in clean oil and continue as above.

Permali
Visually examine compressed densified laminated wood (Permali) drive links. Inspect them carefully for any sign of moisture absorption, swelling distortion, or de-lamination. Also check for treeing or tracking. This type of insulation is moisture absorbent if the varnish layer is broken; therefore it should be out of oil for the shortest possible period of time.

Epoxy resin & DMC
Wipe clean and visually examine Epoxy Resin and DMC (Dough Moulding Compound) components for any signs of cracking, treeing or tracking, especially those at the bottom of tanks where water can collect and promote tracking.
Insulating oil – the insulating oil filling should be changed at each maintenance.

Fuses and Fuseholders
Check fuses for distortion, discoloration or damage. Check fuse mounts for discoloration and the security of any retaining clips. Ensure that the spring clips remain resilient.

Fastenings
During the course of maintenance, check all fastenings for security, this includes lock nuts, lock washers, circlips, taper pins, split pins etc. Renew these items as necessary.

Weather protection
Whenever weather protection is disturbed, for example by the removal of filling orifice covers, access covers to switchgear compartments or cable boxes, it is essential that a weather protective coating is restored at all outdoor locations and preferably at indoor situations as well. This means the renewal of paint films or re-coating with a corrosion inhibitor, for example grease.

Test on completion of maintenance
On completion, voltage test the switchgear, 6 kV DC phase to phase and phase to earth, with the unit in the OPEN and CLOSED positions. In the OPEN position, also test between poles.

Note on polychlorinated biphenyls (PCBs)
Mineral oil used for insulation and arc extinguishing may be contaminated by PCB. Although this problem mainly concerns transformer oil, circuit breaker oil may also be contaminated. PCB is both toxic and very persistent in the environment, therefore extreme care should be taken when handling oil that may be contaminated, because PCB may be absorbed through the skin. Test kits are available for determining the amount of PCB in oil and where the level of contamination exceeds 60 parts per million, the material is classed as toxic and specialist advice should be sought.

7.1 Need for testing

The continuity of power distribution depends on the reliability of the electrical equipment in a system. While the reliability of many equipment have increased manifold during the last century, it is not recommended to connect any finished equipment to a system directly from the manufacturing place, unless its performance is proven. Earlier manufacturers had to think of many ways to prove the worthiness and reliability of their equipment. Nevertheless due to various reasons, manufacturers duplicating proven equipment also gained entry into the market. This had led to claims and counterclaims by the sellers, with consumers and end users being confused.

However the concepts have changed and bringing equipment under a common umbrella to prove their performance have slowly become the practice in every country. Each country had established committees and organizations to ensure the uniformity and performance of electrical equipment in an orderly way. This has led to the release of electrical standards in each country (for all electrical equipment). The major content of most of these cover the minimum tests that are to be conducted on any equipment in an environment that may be more severe than normal operating conditions; in terms of voltage and current levels.

With the sharing of knowledge among intellectuals from different regions and with globalization leading to the use of electrical equipment from different parts of the world, a common way to establish the capability of equipment has been accepted. This has lead to mandatory testing of electrical equipment before being put into use. The tests and the methods to be followed are covered in all electrical standards.

It can be concluded that testing on electrical equipment is needed

• To prove the performance of an equipment before being put into service
• To ensure that the equipment is assessed on a common basis with respect to their technical capabilities
• The end user is confident about the capability and performance of the equipment where it is to be used
• An assurance is established to show that the equipment will not cause any damage to property and personnel, when the equipment is put into service.

7.2 Purpose of testing

Most electrical equipments are produced by assembling various components made of different materials. The internal construction of the final equipment like transformers, circuit breakers, etc are not visible from the outside and it is not possible to visually check the performance of each and every part under a particular operating condition. Hence it is necessary to find ways to check the performance of the equipment in its full form without dismantling it. Accordingly ways and means have been drawn out to check the performance of the complete equipment in its final form which has become the basis of all electrical equipment standards. The testing helps in identifying the defects that may be inherent in particular equipment. Hence it enables the user to take a decision whether to use or not to use the equipment under known circumstances.

The purpose of electrical testing on major equipment is basically to ensure that the equipment will function as desired, when it is installed and energized within its specified voltage and load conditions. This is basically like an insurance premium to be spent before the equipment is accepted in a particular installation. The other purpose is to develop a set of base line test results of the equipment that can be compared in future to identify deterioration and therefore for taking corrective actions.

7.3 Categories of tests

Depending on the area/nature of the tests, they may be categorized as

• Factory tests
• Field/pre-commissioning tests

The factory tests are the major tests that are to be conducted by the manufacturer before declaring that the equipment suits a particular application.

These are categorized as:

• Type tests/design tests: These are normally done on identical equipment. These tests can be destructive in some cases in a sense that the type tested equipment may not be usable again. Hence it is not expected that the equipment under use is type tested but its design should have been proven by conducting tests on similarly designed equipment. All type tests are not destructive. Some times when multiple quantities of similar equipment are ordered, it is acceptable that one unit alone passes these tests.
• Routine tests: These are the necessary basic tests that are to be conducted by a manufacturer even if a customer does not specifically indicate this requirement. Any equipment which had failed in any of the routine tests is generally NOT to be used for the desired application. However under exceptional cases some routine tests may be repeated after making minor alterations to internal construction. It may be noted that all electrical equipment in service, should pass the routine tests.
• Acceptance tests: Some of the tests are to be conducted in case the operating conditions demand the same. These tests may not be applicable for all operating conditions and are mostly guided by the application of the particular equipment.
• Sample tests: When tens and hundreds of identical equipment are ordered, it is not necessary to conduct the same set of tests on each and every unit. Standards define the quantities to be considered for sample testing and the items are randomly tested to prove their capacity. The quantities to be selected are defined by a table or by some formula and samples are chosen accordingly.
• Special tests/other tests: These are defined by standards for some specific equipment at some specific ratings/capacities. These are invariably defined for tests like partial discharge tests, impulse withstand voltage tests, etc which are normally applicable for operating voltages above specified ranges like 132 kV or 220 kV.
• Field tests: As the name implies these are tests that are conducted on equipment in the field of service before being put into service. Invariably most of the pre-commissioning tests are almost same as routine tests (like megger tests, insulation tests, etc).
• Maintenance tests: These are tests conducted at regular intervals as part of maintenance checks to maintain performance. Typical tests are conducted on items like relays, etc which control the HV equipment and on oil which is the insulating medium in transformers.

7.4 Variations to test voltages and results

It is not practically possible to test the electrical equipment in ambient conditions at which they are expected to be in service. The major conditions that can affect performance and its acceptance by the end user are

• Altitude above sea levels
• Maximum and minimum ambient temperatures
• Tolerances on test results

Hence it is customary to define the performance requirements at pre-defined altitude and temperature and also to correct the test results to some basic temperature conditions; so that the equipment performance can be evaluated in a true sense.

8.1 Principles of insulation testing

The fundamental Ohm’s law is
E = I — R,

Where I is the current and R is the resistance of the equipment to which voltage is applied. The equipment function will suffer if it is not getting the required current. At the same time, the total equipment will fail if it takes more than its allowable current or voltage. In the above equation, imagine two resistances in parallel (R1 and R2, with R2 >>>R1), then it is obvious that the maximum current will flow through R1 with almost negligible current flowing through R2.

In the above clause insulation material is generally referred to be a non-conducting material, which is not 100% true. It cannot be denied that all the materials in the world are built with some integral resistance, with their values being almost zero for conducting materials and almost infinite for non-conducting materials. The insulation is basically made of some materials that offer almost infinite resistance to ground. The most common insulating material is Poly Vinyl Chloride (PVC) that covers a cable and has its external surface in contact with ground. Even if the outer surface is touched by humans, the voltage is not diverted to ground. When the insulation covers a conductor like in a cable, it basically ensures that the equipment voltage is not diverted to the ground but gets routed only through the conductor enclosed by the insulation. Hence the fundamental requirement for an insulation material is that it shall have a resistance equal to many times the conductor resistance, so that maximum current flows through it.

In a similar way air, SF6, etc that separate the terminals also have a higher resistance provided this medium separates the terminals at least for some minimum distance for a particular voltage. When the distance across the terminals is reduced, it effectively means that the molecules across the terminals are getting reduced. The resistance of the separating medium in comparison starts reducing which allows a current to flow through it. As the distance is further reduced, it may ultimately lead to a large current across the terminals in the form of an arc; referred to as short-circuit.

The insulation can be considered simply as a capacitor in parallel with a resistor as shown in Figure 8.1 below, with the phase to earth voltage applied to the insulation material.

A marginal current through the insulation material is unavoidable but its value may be in the order of micro amperes due to the high resistance it offers. The current flow that results will comprise of two components: the capacitive current (Ic) and the resistive current (Ir).

The normal currents that flow during the application of a high voltage comprise of many currents as detailed below:

8.1.2 Dielectric absorption current (Ida)

The applied insulation voltage puts a stress on the molecules of the insulation. The positive sides of the molecules are attracted to the negative conductor and the negative sides of the molecules are attracted to the positive conductor. The result is an energy that is supplied to realign the molecules much like force will realign a network of rubber bands. Like Ic, Ida usually dies off fairly quickly as the molecules realign to their maximum extent.

8.1.3 Resistive (leakage) current (Ir)

This is the electron current flow that actually passes through the insulation. In good insulation the resistive current flow will be relatively small and constant. In bad insulation the leakage current may be fairly large and it may actually increase with time.

The insulating material that is used for a particular voltage may be able to offer a maximum resistance value at that voltage, so that it does not offer a path to ground under healthy operating conditions. However in case the resistance reduces or becomes zero, the voltage will try to drive the full current to earth, which is limited only by the system impedance. Hence in the above case, the value of Ir should be very low depending on the voltage that is likely to be applied across the insulation during its life. It is also possible that the insulation will offer this high resistance only up to certain voltage levels, depending upon its properties and thickness, beyond which it is likely to fail.

Typical currents during IR test are mentioned in Figure 8.3. Ir is basically measured, which stabilizes after some time.

The basic principle of insulation testing lies with Ohm’s law and the quality of insulation is ensured by checking the following:

• Applying a high voltage (normally in the region of 500 volts to 5000 volts) to verify its integrity up to this voltage level. The resistance value from the terminal to the ground or between terminals can be directly read in units of Ohm, by measuring the current flowing. The lower this current the higher is the insulation resistance offered by the separating medium.
• The IR measuring instrument is used to measure the resistive leakage current Ir and it is necessary that the required DC voltage shall be applied at least for one minute to allow sufficient time for Ic and Ida to die out.
• It is obvious that the equipment that is designed for a particular voltage will fail at a higher voltage. The voltage of 5 kV may not be acceptable for equipment with a rated voltage of 3.3 kV. At the same time, it is enough if this voltage is applied for a period of time that is adequate to complete the measurements. Most of the insulation tests are conducted from one minute to about 5 minutes.
• In case of some insulations like oil, etc the voltage is slowly increased over a fixed gap and to check at what voltage the insulation is likely to breakdown and this is normally indicated in breakdown voltage rather than in ohms.

The insulation resistance test is very simple and non destructive because of the short duration of application.

A typical connection is is shown in Figure 8.4.

8.2 Purpose of insulation testing

It is very important that the resistance offered by the insulation, maintains a high value for achieving the purpose for which the electrical equipment is intended. This includes air or SF6 or oil or PVC, etc that separates the terminals or the conductor from one phase to another or one phase to ground. This will ensure high efficiency in power distribution at optimum cost while simultaneously offering safety to humans. It is generally observed that the insulation resistance value is very high at the time of manufacture or commissioning. But it becomes very low to such an extent that it leads to equipment failure.

The quality of insulation is linked to some basic parameters that are obtained during insulation testing. Hence the first purpose for insulation testing, (i.e. measurements done during insulation testing) is to assess how well the insulation is and whether it can withstand the continuous voltage stress during normal operation (without ‘puncture’ or ‘breakdown’).

The majority of tests performed on electrical equipment are related to the verification of the quality of the insulation, which is basically the measurement of insulation resistance. The low value of resistance means some thing is seriously wrong.

The insulation of the equipment, that had given high resistance values before being put into service, is constantly stressed over its life by a constant application of a very high voltage. In addition, there are other environmental factors like dirt, moisture, oil, corrosion, vibration, electrical spikes and surges, mechanical stresses from pulling and tugging, and many other factors that add up to deteriorate the ‘good’ insulation. This can be catastrophic, but may happen slowly and steadily even if the voltage values are within acceptable limits.

Established practice is to conduct insulation testing at various stages as noted below:

• Before an electrical equipment is approved for dispatch from a manufacturing place
• Before the same equipment is put into service
• At periodic intervals during the life of the equipment, which is generally once in a year
• When the equipment is to be put back into service after a maintenance shutdown or a repair or a prolonged shutdown.
• In all the above cases, the purpose of insulation testing is
• To verify that the assembled equipment meets the minimum quality standards required for putting into service, without breaking down.
• To ensure that it had not undergone any transit damage and will successfully resist the high voltage that is to be applied to it when it is in service.
• Environmental factors have not affected the quality of insulation and in case it is affected, make necessary corrections to bring up the value to an acceptable level.
• To monitor the quality of insulation over its life time that indirectly provides information on the possible remaining life of the insulation/equipment based on the life of similar equipment. This can be in years or in decades or it may even completely break down during the next startup if no corrections are taken.

8.3 Testing the insulation of equipment

All electrical equipment shall be able to prove their insulation characteristics before the standard rated voltage is applied. Hence all the equipment shall be subjected to insulation test, and the most common HV/MV electrical items are

• Transformers (not across phases but terminals to ground)
• Motors (not across phases but terminals to ground)
• Switchgear and circuit breakers
• Switches and switch boards
• Disconnect switches
• Insulators and bushings
• Cables

It is to be noted that the insulation test is not conducted across the terminals of the transformers and motors (unless they are physically disconnected). This is because the insulation testing will give a negligible resistance value due to a very low resistance of the windings. Similarly, some components have a very low resistance but are connected across the equipment terminals or bus bars. Application of 500V or 2000V across such low resistance will result in heavy currents through these components giving wrong results and may also lead to failure of these components. For this reason these components used between any bus bars/terminals to another bus bar/terminal or to the neutral shall be kept out of the circuit while the main bus bars are insulation tested.

Some such components are

• Fuses
• Indication lamps

Insulation tests are generally expected to be across the phase terminals or between a phase terminal-to-ground, because the insulation offered to the ground is very important from the safety point of view. As noted above even if insulation tests are avoided between phases for motors and transformers, the insulation to ground tests are very important from safety point of view. Hence the persons responsible for testing must ensure that the insulation tests to ground are conducted for all equipment. But insulation tests across phases are done only for equipment whose terminals are not internally interconnected but always maintained at a minimum distance.

8.4 Insulation resistance test voltages

The readings obtained during an insulation resistance (IR) test should give reasonable values and it is necessary that the resistance values increase with any increase in service voltages. A higher resistance may prevent flow of substantial current through the testing instrument if the voltage is not sufficient. IR test instruments are available that can produce 500 V, 1000 V, 2500 V, 5000 V and 10,000 V across their output terminals. Most common test voltages that are applied to measure the IR values are as below depending upon the system voltage (line-to-line voltage)

The 10 kV test voltage is generally adopted for motor windings above 12 kV. In the above table the two values indicate the applicability of both test voltages. Though it may be possible to verify the IR value with low test voltage like 500 V for a system of 3300 volts, it is recommended to follow the above test voltages to get consistent results with comparatively lesser errors.

IEEE 43 recommends the following test voltages for rotating machineries. The rated voltage means the line-to-line voltage for the three-phase machines and line-to-ground voltage for single phase machines and rated DC voltage of DC motors/field windings.

8.5 Types of testers

Megger® is the most common alternate name referred for IR tests. Megger is a patented brand name of the insulation resistance tester manufacturers. The tester is basically able to produce a voltage without any external means so that its output voltage is applied to the terminals under test. The most common types are

• Hand operated
• Motor operated
• Battery operated

When the testers were introduced in the market in early 20^th century, they were hand operated because of the technology prevailing in those days.

Subsequently the motor operated types entered into the market and with the advent of electronics technology, battery operated ones are gaining entry.

All these types are still most commonly used in most of the installations during manufacture and also in the field.

Due to the advancement in measuring technology, present day testers are available with analog display and digital display to show the results and accordingly they are named as analog type and digital type. We also have meters that can be used for two or more different voltages like 2.5–5 kV with output terminals marked as applicable. These are called multi range type and care should be taken to connect the correct terminal depending upon the rated voltage of the equipment under test.

8.6 Construction of a tester

The insulation resistance tester is a portable instrument that can be carried to the point of measurement and connected to the equipment being tested. Most of the types do not need external power but some operate with auxiliary single phase 110/220 V AC supply. The instrument gives direct measurement of IR values in ohms, mega-ohms, giga-ohms, etc based on the model used. It is essentially a high resistance ohm meter having built-in DC generator, generating the appropriate voltage to be applied. The DC generator is hand cranked type in case of a manual type, like a bi-cycle dynamo. A hand rotation at a good speed produces the necessary voltage.

Where a battery or AC source is used, electronic circuits produce the necessary DC voltage which can be stably maintained (unlike hand-operated ones).

8.7 Connecting a tester

In older types connecting the positive and negative terminals to the test points is critical because connecting a positive to a ground always gives low resistance values, irrespective of insulation quality. In case of three-phase (A,B,C) neutral (N) winding equipment, connections are done for the following cases separately and readings are taken separately.

• A-N, B-N, C-N, with other two phases connected to ground while measuring between one phase-to-neutral
• A-B-C-G and N-G without grounding the unconnected terminal
• A-B, B-C, C-A with the unconnected terminals grounded

In case of rotating machineries IEEE recommends that each phase is isolated and tested separately by connecting the test instrument between the reference phase and ground. This helps in identifying the condition of each winding independently. Also while conducting the tests, all external components like cables, surge arresters and surge capacitors are preferably disconnected to get better readings. Some times in the field, it is normal to conduct the IR test at motor terminals along with connecting cables. A common ground shall be used to prevent stray losses in the round circuit, which may affect the results.

Some instruments are provided with an additional terminal called the guard terminal. It should not be confused with ground and it basically shorts some external current paths that may be getting into the instruments hence giving wrong results. For example in the case of bushings, dirt and moisture produce leakage currents across the positive and negative terminals and in such cases the guard is connected to a bare wire wrapped around the bushing. Nevertheless any visible dirt and moisture is removed before applying the tester (to avoid getting low value results). Figures 8.5 and 8.6 show typically how insulation testers are connected.

Cable length does not have an influence on the time for IR measurement.

8.8 Test procedure

The steps involved during testing insulation resistance are as follows:

Figure 8.8 shows the terminal voltage of the insulation tester vs insulation resistance of the item under measurement. Since the insulation tester has a limit for the current it can deliver, the terminal voltage of the insulation tester drops with lower values of insulation resistance as shown in the figure. In the example shown, the instrument can deliver a maximum of 1mA current.

Temperature has got a significant effect on insulation resistance values. Resistance value gets lowered with increase in temperature. Each insulation material has a different rate of change of resistance with temperature. Temperature correction factor tables have been developed for the various types of electrical apparatus and can be acquired from the manufacturer. On the other hand correction factor tables can be developed by measuring and plotting the insulation resistance values of the same equipment at different temperatures. The graph is plotted with temperature in the logarithmic scale and the temperature on a linear scale. The graph is a straight line and can be extrapolated to any temperature for obtaining correction factors.

The following table shows the significance of the effect of temperature on insulation resistance values and the importance for applying the correction factors.

As can be observed, that without temperature correction factors applied, the insulation values do not give meaningful trend pattern.

The following table shows the correction factor table using multiplier factors as per the information provided by NETA (International Electrical Testing Association Inc., USA). This is shown in Table 8.4.

A general thumb rule is that for every 10 deg C increase in ambient temperature the IR value halves and hence these correction factors shall be applied to get the realistic values for comparison of previous readings.

The following are the minimum recommended values for good insulation as per NETA standards.

The recommended minimum IR values after 1 minute at 40ºC are as below based on the experience with different machines.

In the first row, kV refers to the rated line to line voltage of the machine. IEEE indicates that both IR value and PI value shall be met for machines rated 10,000 kVA and above whereas for machines below 10,000 kVA, either PI value or IR value shall meet the minimum values as per the tables. All the values are referred at 40 deg C ambient temperature.

8.9 Precautions to be taken when measuring insulation

• It is obvious that the instrument generates a high voltage which if applied to a human may cause electrocution. Though the source has limited power, it can still cause considerable damage. This is to be avoided by grounding the positive terminal to a local ground to discharge the voltage completely immediately. Use of hand gloves is recommended to avoid accidental contacts.
• Sudden application or removal of the voltage causes an abnormal dV/dt amount of stress. Whenever possible the test voltages should be gradually applied and removed to limit the stress on the insulation.
• If a large over-voltage (on the order of 2 or more times normal) is applied to some insulation systems, the small air voids in the insulation will become charged. If the insulation is then suddenly re-connected to the power system, it may fail due to the addition of the system voltage to the still charged voids. Even if the insulation does not immediately fail, it will be stressed and may lose life. To avoid this problem insulation should always be drained of DC test voltage for 1 to 5 times the length of time that the test voltage was applied before it is re-energized.
• Low quality test leads may cause undesirable leakages, which can result in wrong readings. Hence caution should be taken to avoid the leads getting into contact with each other or to ground/water during measurements.
• Effects of ambient temperature will affect the readings very much. Insulation resistance values drop considerably with increase in temperature for a specific apparatus. If possible the correction factors should be obtained from the manufacturers. As a rule of thumb every 10ºC increase halves the reading or alternatively, every 10ºC drop doubles the readings. For example 10 Mega-ohm at 20ºC may actually be 2.5 Mega-Ohm at 40ºC. These shall be ascertained at the time of taking measurements.
• Humidity and moisture also affect readings. If readings are taken above the dew point temperature, the values may not vary considerably. In electrical apparatus, we are concerned about the exposed surfaces which may lead to condensation affecting the test results.
• Good practice calls for making measurements when insulation is clean and dry whenever possible.
• Ensure proper connection of guard wires if available.

• Motors and transformers will take longer than average conductors and hence the voltage is applied for sufficient time to get a fairly stable reading.
• Equipment should be discharged (shunted or shorted out) for at least as long as the test voltage was applied in order to be absolutely safe for the person conducting the test.
• An Insulation Tester should never be used in an explosive atmosphere.
• For safety make sure all switches are blocked out and cable ends marked properly.
• It takes longer for absorption current to reach a static point as compared to the time taken by a charging current. Similarly it takes longer to bleed off. Hence on large or long cables it is important to short out the cable or ground the tested end after test to eliminate the possibility of shock to the person conducting the test.
• With modern insulating materials there is little difference in the reading obtained irrespective of which way the terminals are connected to the insulation being tested. However in older insulations, a little understood phenomenon called electro endosmosis causes a low reading to be obtained when the positive terminal is connected to the grounded side of the insulation under test. When underground cable insulation is being tested, the positive terminal of the instrument is connected to the neutral or ground of the cable and the negative terminal to the core of the cable.

8.10 Polarization index

When a motor winding insulation resistance is measured from phase-to-ground, it can be seen that the value of IR slowly increases after application of voltage for one minute. The result is basically the healthiness of the insulation. Polarization index is the ratio between IR value after 10 minutes to IR value recorded at the end of one minute. The following are the steps involved for the PI measurements.

PI value varies with the class of insulation and is applicable for all classes of insulation as per IEC 60085-01 irrespective of the application. The following are the minimum values that are recommended based on the insulation class.

PI tests are not applicable to oil insulated transformers, since the presence of oil affects the PI values. PI concept is based on the relatively rigid structures of solid insulation materials, where absorption energy is required to reconfigure the electronic structure of comparatively fixed molecules against the applied voltage field. In the case of liquid insulation materials, the flow of current causes convection currents in the oil, resulting in an unstable structure that does not support the concept on which PI testing is based. PI tests are however applicable to dry type transformers since the windings in a dry type transformer are solid and similar to that of the winding in a motor.

8.11 Step voltage test

Since a good insulation is mostly resistive and remains constant, any increase in the applied voltage will have a proportionate increase in the current flowing to provide the same resistance value for a wide range of voltages. Any deviation means some defects in the insulation exist. Normally the resistance values are observed to be almost the same at 500 and 1000 volts instilling confidence that the insulation is good. However there could be some cracks and cavities that may become prominent in ionization effects as the voltage level increases, making increased currents and lower IR values. The step voltage test is a useful tool for tests that are carried at 2.5 kV and above. Though step voltage can be an under-voltage test or an over-voltage test, it is preferred to consider under-voltage step tests (below the rated equipment voltage) to minimize catastrophic failures.

A recognized step voltage test is to increase the voltage in five equal steps at one minute intervals and record the IR value at the end of one minute before going to the next voltage level. Any considerable reduction in the IR values at any point indicates the possibility of poor insulation characteristics. The following could be the possible results and the inferences accordingly may vary.

The step voltage test is one of the most reliable tests whose results do not differ much because of ambient temperature corrections and hence do not require any corrections.

8.12 Readings and interpretation

With hand operated low voltage type testers often a reading close to infinity is seen in the meter scale and invariably the results are obtained as infinite. But as we have noted earlier, a very high value may be possible but not infinity. Still if the equipment is for low voltage application it can be concluded safely that the IR value is in the order of mega ohms and hence acceptable, without a need to decide the exact value. However it means that the value is beyond the instrument’s capability and generally does not give a chance to check the values that may be obtained later. For critical equipment, it would be preferable to use an instrument with higher ranges (in Giga ohms) so that a reasonable figure can be recorded for future reference.

The measurements taken for one machine shall not be generalized for all the machines. Relative comparisons of the same equipment will give more accurate feedback on the insulation quality. In case the IR values of machine 1 are lower than machine 2 but machine 2 values vary considerably, and reduce within a short period compared to almost a constant value for machine 1, it could mean that machine 2 needs much closer inspection and correction. Hence periodic insulation resistance measurements give a much better picture on insulation quality rather than a single measurement. Table 8.10 gives the possibilities depending upon the variations in the IR values recorded for equipment.

The readings of PI also give a good indication of insulation quality. Though the standards define some minimum values, often new equipment gives values far exceeding the minimum values. Inferences can be derived depending on the PI values as shown in Table 8.11.

Similarly an increase of more than 20% after any maintenance done compared to previous readings may also indicate trouble and would require inspection and correction.

8.13 Dryness of insulation using absorption ratio

Normally the dielectric absorption current in the insulation and its discharge takes a much longer time than the capacitive current. It is because of the dipoles randomizing their alignment within the insulation. This is equivalent to a current flowing with the discharge circuit still connected or a voltage appearing across if left open circuited. Rapidly removing the effects of leakage and capacitive currents allow a measurement relating to the moisture content in the insulation.

This test is mainly used to check the moisture absorption in the insulation. This test monitors the condition of the insulation during the discharge of the dielectric by measuring the dielectric discharge current and was developed mainly for application to large rotating machines by EDF in France. The following steps and observations are involved.

• The equipment under test is charged by applying DC voltage for a sufficient time of 10 to 30 minutes to be ‘stable’ allowing full absorption to take place.
• The applied voltage is then removed and the insulation is discharged through an internal resistance of the measuring instrument. After 1 minute any balance current still flowing is measured. At this time the charge voltage has collapsed and the current measured basically constitutes the capacitive discharge and the re-absorption current, combining to give the total ‘dielectric discharge’.
• The one minute gap is much greater than the primary time constant of the capacitive discharge, which means the resultant current is dependent on the overall capacitance, the final test voltage and the degree of polarization of the dielectric due to its moisture content.
• The Dielectric Discharge factor or absorption ratio is calculated using the formula

The dielectric discharge ratio or absorption ratio can identify absorbed moisture in the insulation as this basically decides the absorption behavior of the dielectric which is masked by its capacitive effects if we try to measure it on the charging cycle. The factor is temperature dependent.

The above test also helps to show if an internal layer is damaged. The time constant of this damaged individual layer will mismatch the other good layers, generally giving rise to a higher value of capacitive current than for a good insulation. The following inferences may be derived from the ratio.

8.14 Burn test

In a normal, insulation tester the specified high voltage is applied to measure the insulation value. In the event of a problem in the insulation, the applied voltage is tripped by the automatic Hi-Pot tester when a preset leakage current level is reached. However in a ‘Burn test’, the applied voltage is deliberately maintained to cause burning at the problem location for facilitating easy identification of the location. Burn testing is generally performed using a ‘Flash tester’. The ‘Flash tester’ provides a continuously variable A.C test voltage up to max. 4kV, having a frequency same as the supply voltage. Three modes of testing can be selected namely ‘Breakdown’, ‘Trip Level’ and ‘Burn’.

In The ‘Breakdown’ Mode, The Instrument Responds Only To The High Frequency Signals Produced By The Flashing Arc Of Breakdown And Trips The Test Voltage Only When This Occurs. In The ‘Trip Level’ Mode, The Output Voltage Is Tripped When The Preset Threshold Level Of Leakage Current Is Exceeded Or If A Breakdown Occurs. In The ‘Burn’ Mode, The Output Is Maintained Irrespective Of The Leakage Current Or Breakdown, But The Output Voltage Level Is Reduced To Limit The Level Of Current Flow. The Burning At the Fault Site Enables the Detection of the Fault

9.1 Purpose of hi-pot testing

Four basic approaches are used for testing insulation with AC.

9.2 AC and DC hi-pot tests

The high voltage in a hi-pot test can be either AC or DC. Since most of the systems are AC rated and AC generation is simpler, it is still the logical choice today. AC testing normally tries to drive a current through the insulation which is typically a resistance in parallel with a capacitance as shown in Figure 51.1. For a good insulation,

Ica >>> Ir equal to almost 100 times the Ir

Ica leads Ir by almost 90 degree due to the capacitive predominance.

In case of marginally good insulation the value of Ica may still be large but not large enough and may be around 50 times the resistive current, with the resultant power factor angle getting reduced to around 0.75 to 0.80. In AC hi-pot tests, it is generally difficult to distinguish between a good and a marginally good insulation.

When a DC voltage is applied, the capacitive current dies down after a small time if the insulation is good and hence the readings at the end of one minute are not generally related to the capacitance current unless it happens to be bad insulation.

AC testing has two significant problems

• A large percentage of the current flowing through the insulation during application of a voltage (whether good or marginal insulation) is capacitive. The resultant AC current in good insulation is almost very close to the same amount of AC current flow that flows in a marginal insulation. Hence it is not always possible to evaluate the quality of insulation by simply measuring the magnitude of the current flow alone. Nevertheless, if the insulation is really very bad, the current drawn by the insulation will be reasonably high to clearly indicate its poor quality.
• The high amount of current flow drawn by the insulation with AC voltage requires a comparatively large test instrument to supply the same. This causes the AC test sets to be generally heavier and more difficult to transport than equivalent voltage DC test sets.
• In spite of these limitations many manufacturers specify that AC be used to test their equipment, and AC testing has a large following. To overcome the above issues, DC voltages have been accepted for most insulation tests, whose test values for a particular system is slightly lower than the test voltage normally recommended for AC tests.

The principal concern while testing the insulation with DC is the possibility of damaging otherwise good insulation. Some studies have indicated that DC testing at very high voltages may cause insulation damage for one of the following two reasons:

• Sudden application or removal of the DC step voltage from zero potential causes an abnormal dV/dt amount of stress on the insulation under test. Hence it is recommended that whenever possible the test voltages should be gradually increased, applied for the specific duration and again slowly removed.
• When a large over-voltage (on the order of 2 or more times normal rated voltage) is applied to some insulation systems, the small air voids in the insulation will get charged and will remain for quite some time. If the insulation is then suddenly re-connected to the same system, it may fail due to the addition of the system voltage to the still charged voids, exceeding the normally recommended voltage. Even if the insulation does not immediately fail, it will be stressed and may have its life curtailed.

To avoid this problem insulation should always be drained of DC test voltage for 1 to 5 times the length of the duration for which the test voltage was applied before it is re-energized.

However this test is considered destructive compared to the IR test referred in the earlier chapter. The test voltages are typically as per Table 9.2. Though a higher voltage is applied at the factory, subsequent tests consider reduced voltages as given below. Though AC voltages are applied at the factory, it is normal to consider DC voltage in subsequent tests to avoid insulation getting affected.

DC Test is generally preferred after the Go-No-Go AC test at the factory due to the following specific advantages.

• Lower cost
• Lighter weight
• Smaller size
• Non- destructive
• Qualitative information

9.3 Test equipment construction and connections

The test instrument is similar to the IR test with a DC voltage being generated internally. The instrument is normally provided with ammeters and timers to enable direct readings during the tests, with the timer cutting off the voltage after the set time.

Typical instrument is shown above.

9.4 Safety precautions to be taken

• The voltages being handled can become high for high voltage equipment in tens and hundreds compared to the IR test equipment which is generally limited to 5 kV. Hence extra precautions are necessary while taking up the test.
• Generally the tests are conducted on bus bar ends, etc with the switchgear or motor kept in open condition to permit connections. The leads shall be properly insulated to avoid any inadvertent contact with any personnel in the near vicinity.
• Though the IR test is conducted with the hand operated instrument, the same is not followed for hi-pot test instruments. The leads are connected to the terminals under test and the personnel should maintain a safe distance from the equipment enclosure.
• It is necessary to caution all personnel about the test and provide warning tapes around the equipment being tested. Some instruments are provided with a beacon lamp and alarm to warn the personnel when the voltage is being applied.
• The test may be repeated for different phases by disconnecting and reconnecting the leads as needed. Hence a suitable earth rod should be kept in hand to ensure discharge of the voltage before attempting disconnection.
• All equipment under test MUST be disconnected and isolated from any other source.
• All small components shall be suitably isolated from the circuit to avoid destructive voltage being applied. It shall be ensured that all switches are blocked out and cable ends are marked properly for safety

9.5 Test voltages as per applicable standards

The following NETA table gives the test voltages recommended for the hi-pot test on different equipment based on their rated maximum voltage, depending on whether AC or DC test is adopted.

Recommended maximum are 1 minute for AC Hipot test and 5 minutes for DC Hipot test.

9.6 VLF high pot test

VLF High pot test (very low frequency AC high pot) is a test that is becoming popular for the testing of cables and electrical apparatus like transformers, motors etc. VLF stands for very low frequency sinusoidal AC voltage having generally frequency of the order of 0.1 Hz or lower. VLF is used wherever a high capacitance load needs to be tested with AC voltage, especially in applications of field testing where the large and heavy series resonant AC test systems are not practicable. The reason for using low frequency is that, use of the system frequency (60Hz) necessitates large, high capacity, heavy and expensive equipment. Usage of low frequency enables the test equipment to be of small capacity, lighter weight and less expensive.

Testing at a frequency of 0.1 Hz reduces the power requirement by approximately 600 times when compared with testing at 60Hz. Testing of long runs of shielded power cable is the most common application for VLF testing. The problems associated with DC high voltage testing namely damage to the solid dielectric insulation and inability to detect many types of cable defects are not present in VLF Hi pot testing.

VLF testing is a go/no-go type of AC stress test for verifying the integrity of cables. If the cable is able to hold the applied test voltage, the cable is deemed healthy. VLF finds application in the following three types of cable testing.

• Testing the healthiness of a repaired cable
• Condition monitoring through routine periodic testing of cables
• Burning of cable faults to identify the location of the fault

For testing the equipment, the HV output of the tester is connected to the HV terminal of the equipment and the ground terminal is connected to the ground terminal of the equipment. The test voltage is applied for the required duration and it is checked whether the equipment is able to hold the test voltage till the duration of the test.

Figure 9.2 shows the schematic setup for performing VLF High Pot test for a cable.

10.1 Need for the instrument

A ducter is basically a low resistance meter (unlike mega ohm meter) used in insulation resistance tester. Ohm’s Law dictates that for a specified energy source, operating on V AC or V DC, the amount of current drawn will be dependent upon the resistance of the circuit or the component. The satisfactory operation of the circuit or the component depends on the controlled flow of current within the design parameters for the given piece of equipment.

In this age of electronics, increased demands are placed on all aspects of electrical circuitry. In the present demanding industrial electronic environments, the engineer is now required to make measurements which show repeatability within a few micro-ohms or less to prove the reliability of the equipment.

The electrical system comprises of many interconnections and joints that introduce considerable resistance in various electrical circuits. These may be a few micro ohms at each point but their summation may introduce long term damage to existing equipment and will also waste considerable energy as heat. Any restrictions in current flow will prevent a machine from generating its full power and may also allow insufficient current to flow to activate protective devices in the case of a fault. Hence it is necessary at an early stage to test and establish resistance values and then continuously monitor any upward changes to identify unexpected changes in measured values. The trending of this data helps to forecast possible failure conditions. Excessive changes in measured values would need corrective actions to prevent a major failure.

A low resistance measurement is typically a measurement below 1 ohm. At this level it is important to use test equipment that will minimize errors introduced by the test lead resistance and/or contact resistance between the probe and the material being tested. Also, at this level, standing voltages across the item being measured (e.g. thermal emfs at junctions between different metals) may cause errors and need to be identified.

10.2 Description of instrument

The original DUCTER™ low resistance ohmmeter was developed by Ever shed & Vignoles in 1908 and employed the cross coils meter movement that was already used in insulation resistance testers. This initial design evolved into field units in the 1920s that required a leveling procedure at the time of the test due to the sensitivity of the coil. These early models did not travel well and were sensitive to shock and vibration.

To allow a measurement to compensate the errors, a four terminal measurement method had been developed with a reversible test current along with a suitable Kelvin Bridge meter which enables measuring very low resistance values. Subsequent demands required ranges up to kilo ohms, which used a Wheatstone bridge.

The low range on many resistance ohmmeters resolves 0.1 micro-ohms. This level of measurement is required to perform a number of low range resistance tests.

10.3 Working principle

10.3.1 Kelvin bridge

The Kelvin Bridge (also known as the Thomson Bridge) is used for precision measurements below the typical range of the Wheatstone bridge. Sir William Thomson (Lord Kelvin) devised this in 1854. The classic arrangement has six resistors in a rectangle, bisected by a galvanometer (see Figure 10.1), which includes an unknown resistance. A comparatively large current is passed through this unknown resistance and also through a known resistance of a comparatively low value. The galvanometer compares the voltage drops across these two resistances with the double-ratio circuit comprised of the other four resistors.

The two pairs of ratio resistors (A/B, a/b) are in parallel to each other and connected across with the galvanometer. One pair (a/b) is in series with the unknown (X) and the reference standard (R). The latter is an adjustable low-resistance, usually a manganin bar with a sliding contact.

This arrangement introduces a total resistance of A+X+a and B+R+b in parallel with the galvanometer. A connecting link (Y), sometimes called the yoke, shunts the ratio pair (a/b) that are otherwise in series with the unknown and the standard. This has minimal effect on the accuracy of the measurement so long as the two pairs of parallel ratio resistors are kept exactly equal (A to a, B to b). Lead and contact resistances are included in the value of the ratio pairs, and any effects can be nullified by keeping the resistance of the yoke extremely low. Keeping the yoke resistance low also accommodates the large test currents often used in Kelvin Bridges without causing unwanted heating effects.

When potential is balanced across the two parallel circuits, the unknown is equivalent to the parallel ratio multiplied by the adjusted reference value.

X = A/B × R

For very low measurements, the Kelvin Bridge has the advantage of nullifying extraneous resistances from leads and contacts by employing the system of double-ratio arms. The resistances of the connecting leads are in series with the high-resistance ratio arms and not with the reference or tested resistors.

10.3.2 Wheatstone bridge

A pioneering method for measuring resistance was devised in 1833 by S. H. Christie and made public by Sir Charles Wheatstone. The arrangement is a square pattern having four resistors with a galvanometer connected across one diagonal and a battery across the other (see Figure 56.2). Two of the resistors are of known appropriate values and comprise the ratio arm (A + B). A third has a known value which can be varied in small increments over a wide range, and is thus designated the rheostat arm (R). The fourth is the resistance being measured, the unknown arm (X).

The bridge is considered balanced when the rheostat arm has been adjusted so that the current is divided in such a way that there is no voltage drop across the galvanometer and it ceases to deflect (is nulled). The resistance being measured can then be calculated from the knowledge of the values of the ratio resistors and the adjusted value of the rheostat arm. The basic formula is:

X = B/A × R
Where
B and A are the ratio resistors
R is the rheostat resistance used.

The Wheatstone bridge can be constructed to a variety of ranges and is generally used for all but the highest and lowest measurements. It is suited to a range of about 1 to 100,000 ohms.

10.3.3 Four wire instrument

There are basically three ways of measuring resistance of an element viz., 2-wire, 3-wire and 4-wire instruments.

Two wire testing is the simplest method and is used to make a general assessment of a circuit element or a conductor in a circuit. The two-wire lead configuration is the most familiar one, used in multi-meters. It is generally used when the probes contact resistance, series lead resistance or parallel leakage resistances, do not degrade the quality of the measurement beyond an acceptable point.

The disadvantage with this method is that the measured value will include the test lead wire resistance and contact probe resistance values. This resistance may be equal to some tens of mille-ohms to the actual resistance, thereby introducing considerable errors when the resistance value is low. In most instances this may make little difference to the measured value, but when the measurement is below 1.000 ohm the two-wire method can easily introduce an error. This error could be several percentage of the actual resistance value. The lead resistance may be zeroed out, but that leaves the uncertainty of the contact resistances, which can change with each measurement. Contact resistance values may be in the 35 mille-ohm range at each probe and can vary with the temperature of the material under investigation.

The two-wire test method is best used for readings above 10.00 ohms up to about 10.0 megohms.

Three-wire testing is used for very high resistance and is typically used for measurements above 10.0 megohms. This is nothing but the insulation resistance tester where a third test lead is used as a guard, and allows for resistances in parallel with the test circuit to be eliminated from the measurement. This parallel resistance is usually considerably lower than the insulation resistance being measured. In fact it may, in severe cases, effectively short out the insulation resistance such that a meaningful measurement cannot be carried out without the use of a guarding circuit.

Four-wire measurement is the concept used by a Ducter. This is more suitable for accurately measuring resistances starting from mille ohms up to about 10 ohms. Out of the four wires two are called voltage leads and the other two are called current leads. A typical arrangement is as shown in Figure 56.3. The four-wire measurement compensates for usual errors that are introduced by the probe lead wire and the contact resistance values in the final reading, thus ensuring more accurate measurements.

A DC instrument should be used when trying to measure the pure resistance of a circuit or device. An AC instrument is used for applications such as ground bed testing or impedance testing.

Current is injected into the item under test via leads C1 and C2. The current that flows will be dependent upon the total resistance of this loop and the power available to push the current through that resistance. Since this current is measured, and the measured value is used in subsequent calculations, the loop resistance, including the contact resistance of the C1 and C2 contacts and the lead resistance of C1 and C2, does not have an effect on the final result.

From Ohm’s Law, if we pass a current through a resistance we will generate a voltage across the resistance. This voltage is detected by the P1 and P2 probes.

The voltmeter to which these probes are connected internally has a high impedance, which prevents current flowing in this potential loop. Since no current flows, the contact resistance of the P1 and P2 contacts produces no voltage and thus has no effect on the potential difference (voltage) detected by the probes. Furthermore, since no current flows through the P leads their resistance has no effect.

A high current output is one of the qualifying characteristics of a true low resistance ohmmeter. Generic multi-meters do not supply enough current to give a reliable indication of the current-carrying capabilities of joints, welds, bonds and the like under real operating conditions. At the same time, little voltage is required, as measurements are typically being made at the extreme low end of the resistance spectrum. Only the voltage drop across the measured resistance is critical, and it is measured at the mille-volt level.

10.4 Millie-ohmmeter Vs micro-ohmmeter

As the name implies, a mille-ohmmeter is less sensitive than a micro-ohmmeter, with measurement capability in mille-ohms rather than micro-ohms (minimum resolution of 0.01 mille-ohm). This type of instrument is normally used for general circuit and component verification. Millie-ohmmeters also tend to be less expensive than micro-ohmmeters, making them a good choice if measurement sensitivity and resolution are not critical. The maximum test current is typically less than two amperes and as low as 0.2 amperes.

In contrast, the micro-ohmmeter uses 10-amp maximum test current which provides a comfortable and suitable test current through the test sample to make the measurements. The best 10-amp micro-ohmmeters offer measurements from 0.1 micro-ohm to 2000 ohms with a best resolution of 0.1 micro-ohm at the low end of the range and accuracy of ±0.2%, ±0.2 micro-ohms. On some instruments, different measurement modes may be selected which address different types of testing conditions. Measurement modes could include manual, automatic or continuous testing, or a high power test for large windings.

The following is a selected list of key DC resistance measurement applications for 10-amp micro-ohmmeters.

• Switch and contact breaker resistance
• Bulbar and cable joints
• Small transformer and motor winding resistance
• Aircraft frame bonds and static control circuits
• Welded joint integrity
• Intercell strap connections on battery systems
• Resistive components (quality control)
• Rail and pipe bonds
• Metal alloy welds and fuse resistance
• Graphite electrodes and other composites
• Wire and cable resistance
• Transmitter aerial and lightning conductor bonding

There are different ways in which the leads are provided as shown in Figure 10.5.

10.5 Breaker contact resistance measurement

According to IEC62271-100, testing the contact resistance of high voltage AC circuit breakers calls for a test current with any convenient value between 50 A and the rated normal current. ANSI C37.09 specifies that the test current should be a minimum of 100 A. Most electrical utilities prefer to test at higher currents, as they believe this is more representative of working conditions. Field portable instruments are available that can supply anywhere from 100 A up to 600 A (subject to the load resistance and supply voltage). The best instruments have measurement resolution to 0.1 micro-ohm and offer variable test current to address a wider range of applications.

By testing at 10 Amp and then at a higher current, the operator can get a better understanding of the maintenance requirements for the circuit breaker. In addition to circuit breakers, electrical utilities and testing companies use higher current micro-ohmmeters on other high voltage apparatus, including:

• Cables
• Cable joints
• Welds
• Bus bars
• Switchgear in general

It is some times a practice to initially perform a 10 amp test and then see improved resistance readings with test currents beyond 100 amps as per standards.

However it is necessary to realize that high current meters are intended to be used at high currents. Their accuracy may reduce considerably at low currents, particularly when measuring small resistances.

Mechanical wear and tear on circuit breaker contacts reduces the area of the contact surfaces. This reduction combined with sparking and/or arcing during operations increase the resistance across the working connections. This condition will produce heat that can reduce the effectiveness of the circuit breaker. Periodic measurements will show the rate of increase of the contact resistance value. When these values are compared to the original manufacturer’s specification, a decision can be made to continue or repair. By tracking the trend of the readings, the operator gets an idea of when the circuit breaker should be pulled for service before damage is done.

10.6 Transformer resistance measurement

Some of the transformer ohmmeters include dual meters with independent range controls such that the high voltage/primary (high resistance) and low voltage/secondary (low resistance) windings of a transformer can be measured at the same time.

The transformer ohm meter is a multi current device with measurement resolution to 1 micro-ohm and is used both in factory tests and for field operating verification. Operation of the transformer ohmmeter is sometimes enhanced by connecting the test current through both windings with opposite polarity, thus providing the fastest test time (the mutual inductance between the windings is minimized by this way). This current connection operation is used on wye-to-wye, wye-to-delta and delta-to-delta transformers. The ability to measure primary and secondary windings at the same time also speeds up the testing time.

The power supply is often designed to deliver the energy to saturate the winding and then provide a stable level of test current. The test set should also be able to test the windings and contact resistance on tap-changers with make-before-break contacts and voltage regulators. Tap-changers are the most vulnerable part of the transformer and face more failures and outages than any other component. Frequent testing is required to ensure proper and reliable operation. A transformer ohmmeter is used to:

• Verify factory test readings.
• Help locate the presence of defects in transformers, such as loose connections.
• Check the make-before-break operation of on-load tap-changers.
• Perform ‘heat runs’ to determine the internal temperature changes, via the winding resistance, that occur under rated current conditions.

10.7 Precautions during measurements

The temperature of the device will have a strong influence on the measured values. For example, the resistance measured for a hot motor will be different from a measurement done in cold conditions. As the motor warms up, the resistance readings will go up. The resistance of copper windings responds to changes in temperature based on the basic nature of copper as a material. Different materials will have different temperature coefficients. As a result, the temperature correction equation will vary depending on the material being tested.

As a general safety measure, normal testing should always be performed on de-energized samples. Special training and equipment are required to perform tests on energized circuits. Internal fused input circuits are designed into a few instruments that will protect the instrument if inadvertently connected to an energized test sample. The low input impedance of the current supply internal to general instruments becomes a willing current sink when connected across a live circuit.

Safety is the responsibility of the field test engineer or technician, whoever will be in contact with the sample being tested. The majority of field tests are performed on de-energized circuits. When testing magnetic components, a state of winding saturation may occur.

The operator should connect a short circuit across the winding to neutralize the energy stored in the winding and then make a voltage test to verify the neutral state of the sample.

Battery strap testing represents a special condition, as the batteries must remain connected. The operator is required to use insulated gloves, facemask and a body apron for protection when performing these tests. This is one of the few times when electrical resistance tests are performed in the field on energized systems. Special probes, rated for 600 V operations, are available with the newer instruments to perform these tests.

When planning a test on circuit breakers, the operator must be aware of IEC62271-100 and ANSI C37.09 for test current requirements. When testing large oil circuit breakers, the best instrument is one that ramps up current slowly and steadily, holds it for a period of time to complete measurements and then ramps down in a similar fashion. This method reduces magnetizing, which would otherwise be created by the sudden switching ON and OFF of the test current. This may also result in inaccurate ‘CT’ measurements when the system is returned to normal AC operation.

Care should be taken when making a measurement across a CT as high DC currents may saturate the CT, leading to potential faults. Also, any ripple on the test current may cause circuit breakers to trip. Careful positioning of the current probes should prevent this happening, and the ripple present on the current waveform may be minimized by separating the test leads.

When connections have higher than normal resistance measurements, one should not resort to retightening the bolts, as this will over stress the soft lead connection. Over tightening does not cure the problem. The proper procedure is to disassemble the straps, clean, grease and then reconnect with the bolts tightened to the supplier’s torque level. All the three phase resistances should be balanced within a narrow tolerance of ±10 to 20%.

A common error in the field is to use a low resistance ohmmeter to sample the resistance of a ground bed. This application is incorrect, as the ground bed test method requires an instrument that toggles the test signal at a known frequency and current level.

A low resistance ohmmeter used in this application will provide an erroneous reading as the ground current will have an undue influence on the measurement. A proper ground tester performs in essentially the same way as a low resistance ohmmeter, that is, by injecting a current into the test sample and measuring the voltage drop across it. However, the earth typically carries numerous currents originating from other sources, such as the utility. These will interfere with the DC measurement being performed by a low resistance ohmmeter. The genuine ground tester, however, operates with a definitive alternating square wave of a frequency distinct from utility harmonics. In this manner, it is able to perform a discrete measurement, free of noise influence.

11.1 Other major equipment

This chapter briefly covers the tests normally done on other HV/MV equipment not covered in earlier chapters. These are

• HV/MV switchgear
• Outdoor circuit breakers
• MV motors and generators
• HV disconnectors
• MV Capacitors

11.2 HV/MV switchgear and breakers

MV switchgear are generally designed for indoor use and basically comprise of the following compartments on one vertical section. (A switchgear panel line up may consist of many such vertical sections.)

• Draw out breaker trolley or contactor assembly
• Metering/relay auxiliary compartment
• Cable compartment
• Bus bar chamber

It is necessary to have tests on integrated assembly of all the units. IEC recommends the following tests on switchgear.

11.3 MV motors

The following are the major tests conducted on medium voltage motors that are used to drive mechanical equipment like compressors, blowers, pumps, etc. The tests not only determine the losses and the efficiency but also cover procedures involved in calculating the various loss components to arrive at the efficiency figures.

• Insulation resistance test
• HV test on windings to round for 1 minute
• Over speed test
• Measurement of losses
• Measurement of stator winding resistance across every two terminals
• No load test
• Locked rotor test and measurement of copper losses
• Polarization index for each winding
• Measurement of shaft voltages
• Shaft vibration tests
• Bearing housing vibration tests
• Temperature rise test
• Insulation power factor test
• Over load test
• Noise level measurements

Some of the tests like noise level measurements and heat run test are type tests which are conducted on one motor if multiple motors of the same rating are supplied. The stator coils and insulation also go through high voltage tests before assembly of motor coils.

11.4 MV capacitors

The capacitors are mainly in the form of multiple banks and mounted either indoor or outdoor. The major tests to be conducted per IEC are as below.

11.5 Disconnectors

12.1 Need for field tests

The units are normally tested at the manufacturer’s works and transported to the site once the test results are satisfactory. Invariably there will be considerable time elapsed between the factory tests and the readiness of the site where the installation will take place. The time elapsed may vary from a month to several months depending on many factors. The installation and provision of necessary connections also takes considerable time, even if the site is waiting for the equipment. The following factors are unavoidable from the time the equipment is ready at manufacturer’s place till it is ready to get charged in the place of use.

Time for packing and arranging for the transportation after completing all the commercial formalities.

Transportation time from the manufacturer’s works to the place of installation depending upon whether the item is imported or locally available. Even in case of locally available equipment distances may make the transportation and delivery time go from a week to few weeks. Possible damages during transportation, either directly on the equipment or indirectly due to unknown reasons. Rough handling and improper packing can also lead to unknown damages. The delay in readiness of the foundation or the building may result in the equipment being kept in unfavorable climatic conditions that can affect internal insulation. Some times environmental conditions at a construction site or an existing nearby plant can also result in some deterioration to internal components and oil used in the equipment.

All the above reasons plus many other possible human errors generally delay the energizing of electrical equipment. Hence it is necessary to ensure that there are no internal damages that can affect its life and performance. For example, the oil dielectric strength might have gone down over a period of time that would require filtration before charging a transformer. If not, an internal flashover or short circuit may make the whole project wait while the transformer is repaired. Similarly in a switchgear panel, some internal links or shorting may lead to problems.

The above reasons are basically related to the delay in energizing due to unavoidable reasons. Once the equipment is energized, it is necessary to ensure periodical maintenance to maintain health. Maintenance may result in replacement of components, some adjustments in the internal mechanism, rewiring, etc. All these need to be checked for correctness before the equipment is put back into service.

Some basic tests are prescribed (especially for HV/MV equipment) that are to be conducted before restoring the service or charging the equipment for the first time. These tests are called pre-commissioning tests/checks, commissioning tests, maintenance tests, etc and since most of these tests are done in the field of service, these are referred to as field tests in this chapter.

Field tests are usually performed by independent contractors, the installation contractor or the manufacturer himself. The individuals who perform the acceptance tests should preferably be certified and/or licensed for the equipment under test. The system should be initially checked for damage, deterioration and component failures using specific component checks, inspections, and tests defined by the equipment manufacturer. Then the interconnection of the system components should be checked in a de-energized and energized state, to verify the proper interconnection and operation of components, ON/OFF control, system interlocks and protective relaying functions. It is recommended that all field tests are witnessed by a person who could be the operator of the plant or in case of shortage of skilled man power, a commissioning engineer who is not associated professionally with the agency/person performing the tests. Once the above tests are complete, the system can be energized, operational tests conducted and measurements recorded. All steps and results of the field tests should be carefully documented for review and for use in future for comparison. Considerable variation in the results of present tests compared to earlier tests is indicative of problems like deterioration of insulation, dirty environmental conditions, etc.

12.2 General safety procedures

The safety procedures given below are from IEEE Standard 510-1983 which stipulates safety practices to be followed by all personnel dealing with high voltage applications and measurements, so that any possible accidents due to the presence of electrical hazards while conducting the tests are avoided.

Safety considerations in electrical testing apply not only to personnel but to the test equipment and apparatus and or the system under test. These recommended practices generally cover the practices needed while testing in laboratories, in the field and of systems incorporating high voltage power supplies, etc. A voltage of approximately 1,000 volts has been assumed as a practical minimum for these types of tests. Individual judgment is necessary to decide if the requirements of these recommended practices are applicable in cases where lower voltages or special risks are involved.

12.3 Transformers

12.4 Switchgear

12.5 High voltage disconnectors

12.6 MV cables

12.7 MV bus ducts

12.8 Instrument transformers

12.9 Rotating machinery

12.10 Surge arresters

12.11 Outdoor bus structures

12.12 Engine generators

13.1 General

There are a number of regional standards that define the functional and testing requirements for power and distribution transformers. Universally the transformer principle is the same comprising two or three windings (mostly 2) with magnetic core and enclosure tank. For example some of the main standards available for transformers under IEC are as below:

• IEC-60076 Power Transformer
• IEC-60296 Specification for Unused Mineral Insulating Oils for Transformer & Switchgear
• IEC-60137 Insulating Bushing for Alternating Voltage above 1000 V
• IEC-60354 Loading Guide for Oil Immersed Power Transformer
• IEC-60364 Specification for Gas Operated Relays
• IEC-156 Method for the Determination of the Electric Strength of Insulating Oils

Some of the British standards for transformers are as below.

• BS 7806: Dry-type power transformers
• BS 7821-4 parts: Three phase oil-immersed distribution transformers, 50 Hz, from 50 to 2500 kVA with highest voltage for equipment not exceeding 36 kV
• BS 7844-2 parts: Three-phase dry-type distribution transformers 50 Hz, from 100 to 2500 kVA with highest voltage for equipment not exceeding 36 kV.
• In North America following IEEE/ ANSI standards are generally adopted.
• IEEE C57.12.00 – Standard General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers
• IEEE C57.12.01 – Standard General Requirements for Dry-Type Distribution and Power Transformers
• ANSI C57.12.22 – Requirements for Pad-Mounted, Compartmental-Type, Self-Cooled, Three-Phase Distribution Transformers with High Voltage Bushings; 2,500 kVA and Smaller: High Voltage, 34,500 GrdY/19,920 Volts and Below; Low Voltage, 480 Volts and Below Requirements.
• ANSI C57.12.26 – Standard for Transformers – Pad-Mounted, Compartmental-Type, Self-Cooled, Three-Phase Distribution Transformers for use with Separable Insulated High Voltage Connectors: High Voltage, 34,500 GrdY/19,920 Volts and Below; 2,500 kVA and Smaller.
• ANSI C57.12.28 – Switchgear and Transformers, Pad-Mounted Equipment – Enclosure Integrity
• ANSI C57.12.50 – Requirements for Ventilated Dry-Type Distribution Transformers, 1–500 kVA Single-Phase and 15–500 kVA Three-Phase, with High Voltage 601–34,500 Volts, Low Voltage 120–600 Volts.
• IEEE C57.12.51 – Requirements for Ventilated Dry-Type Power Transformers, 501 kVA and Larger Three-Phase, with High Voltage 601-34,500 Volts, Low Voltage 208Y/120–4,160 Volts
• IEEE C57.12.90 – Standard Test Code for Liquid-Immersed Distribution Power, and Regulating Transformers and Guide for Short-Circuit Testing of Distribution and Power Transformers (ANSI).
• IEEE C57.12.91 – Test Code for Dry-Type Distribution and Power Transformers
• ASTM D877 – Test Method for Dielectric Breakdown Voltage of Insulating Liquids Using Disk Electrodes.

These standards not just define the standard construction requirements but indicate the acceptance criterion for a transformer before putting it in service. The standards mainly relate to the testing of transformers at the manufacturer’s works or in an approved laboratory. This is done to ensure that they meet the specific needs of an application.

The tests are broadly classified as:

• Routine tests
• Type tests
• Special tests

Further, like any standard electrical equipment, transformers are tested on-site before commissioning, which may be classified as

• Pre-commissioning tests
• Periodical maintenance tests

This chapter briefly covers the requirements laid down by international standards and best practices followed in industry for transformers before accepting for an application (routine and type tests) and before putting into service (Pre-commissioning tests). Maintenance related tests are covered in a separate chapter.

13.2 Routine tests

The quality of transformers depends on successfully verifying the performance of components that go into it.

A manufacturer is expected to ensure that the following checks and tests are conducted before/during assembly.

• Quality checks and tests on all bought-out components/parts like laminations, conductors, protection devices, oil, insulation materials, bushings, etc
• Tests on individual items like tanks, windings, control panels, etc, being built at the works

The above test reports do not normally form a part of completed transformers. But in the interest of quality, it is necessary to ensure that the manufacturer is in possession of all pertinent records.

Once the transformer is fully assembled, the following routine tests are recommended. These tests are to be normally carried out in the presence of the customer at a manufacturer’s works. Hence it is expected that the manufacturer’s factory includes a well-equipped testing division.

• Visual inspection
• Measurement of winding resistance
• Measurement of voltage/turns ratio
• Verification of polarity and vector group
• Measurement of impedance voltage and load losses
• Measurement of no load losses and no load current
• Measurement of insulation resistance
• Power frequency voltage withstand test
• Induced voltage withstand test
• RIV Corona voltage test (above 132 kV)
• Partial discharge measurements (300 kV and above)Lightning impulse test (above 132 kV)
• Switching impulse voltage withstand test (above 132 kV)
• Tests on OLTC

13.3 Guarantees and tolerances

The test results are always subjected to ambient conditions and some of the figures are allowed with tolerances considering the intricacies involved in manufacture, use of different materials, etc. Following results are based on tolerances as applicable.

The temperature rise figures are normally guaranteed at an ambient of 40ºC unless other values are specified by the user. The resistance figures are normally referred at 75ºC.

13.4 Visual inspection

The visual inspection is not only to check the finish of the equipment but also to cover the following issues:

• Verification of dimensions. Critical dimensions like foundation rails, bus-duct termination level, etc, shall be as per approved drawings (for smooth and fast installation)
• Provision of all accessories as per the bill of materials and specifications, including the check on ratings of various auxiliary devices (like sudden pressure relay, etc), which need an external source for operation. To assist in achieving undisputed test results, these accessories shall be assembled at the works during testing
• Incorporation of all necessary particulars in the nameplate with serial number, etc, matching with duty requirements.

13.5 Winding resistance measurements

The purpose of this test is to establish the copper losses which are basically I2R losses in the winding varying with load. Measurement of winding resistance is done across the terminals through balanced bridge (Wheatstone Bridge or Kelvin Bridge) configurations. Sufficient time should be given to ensure that the resistance reaches a steady state value, which happens once the core saturates with a DC voltage. The time taken may be longer if the winding inductance is high. Also it is to be ensured that the windings are not unduly hot when resistance measurements are taken.

It should be noted that three-phase transformers have the terminals connected in Star or Delta and accordingly the measurements will give net parallel resistance values depending on the configuration. For example with A, B, C, N as terminals and connected in Star, the resistance across A-B will give the total resistances of AN and BN. In Delta connections two windings will be in series and parallel to the third winding across which the measurement is taken. The main point is to ensure that the values are uniform and the copper losses are within the guaranteed figures. The readings shall be taken across the two terminals of the transformer to check uniformity. In case there is discrepancy noted, it could be due to some open winding or loose connections, which should be thoroughly checked and rectified.

13.6 Turns ratio measurement

The measurement of turn’s ratio is done by applying nominal voltage across the terminals of the primary winding and measuring the open circuit secondary voltage across its terminals. The expectation is that the turn’s ratio should be the same as the voltage ratio. The ratio is measured between the primary winding to the full secondary end with tap position at 0 and also by changing to the other taps of the primary winding (which are available outside for external connections). The acceptance criterion is that the turn’s ratio should have a tolerance not exceeding 0.5% of the required voltage ratio. Generally 380/415/480 V 3-phase supply which is commonly available is applied to the HV windings of the transformer for this purpose (in case of three-phase transformers, and may be lesser voltage for single-phase ones).

A transformer turns ratio instrument with leads is shown in Figure 13.1.

13.7 Polarity and vector group check

Polarity and vector group verification is another important test required to ensure that the secondary voltage displacements are as per specifications so that the connected protective devices operate correctly. Figure 13.2 illustrates the testing connections and the method to determine the polarity of a transformer.

The connections basically require interconnecting the phase terminals of primary and secondary windings, applying voltage to one set of winding and measuring the voltage across the various terminals caused by the induction phenomenon. As is evident from the diagrams, if the voltage measured across A1–A2 is less than the voltage measured across A1–a2 then the polarity is said to be subtractive, and if it is greater, then the polarity is additive.

Figure 13.3 illustrates the test connections for a three-phase star-star connected transformer with subtractive polarity and the result verifies that the vector group matches with the requirement.

The voltage measured across C2–A2 and C2–B2 must be equal and shall be more than the measurements between C2–c2 and B2–b2. Further the voltage across C2–b2 must be more than C2–c2 and similar result is to be checked between B2–c2 and B2–b2.

13.8 Impedance voltage and load losses

The load losses in a transformer basically comprise of I²R losses in the windings and stray losses due to eddy currents in conductors, clamps and the tank. Since stray loss is frequency dependent, the test frequency should be the rated frequency. Normally the guaranteed figures are for an operating temperature of 75ºC. Corrections will be applied to the losses measured at ambient temperature in the works.

The principle is that the impedance voltage is to be applied to the primary to get the full rated current to flow in the short circuited secondary winding. Though the standards do not say that 100% secondary current is to be flown, it is recommended to get not less than 50% of rated secondary current during this test by applying a reduced voltage on the HV winding. Then,

Since the power factor during these measurements could be very low (less than 0.1), watt meters suitable for such low power factors should be considered. Further, the three watt meter method is preferred when compared to two watt meter method (to avoid a large multiplication constant).

13.9 No load losses and current measurement

The no load test not only establishes the no load losses but also indicates the soundness of insulation after HV tests. Hence normally no load losses are taken before and after the HV tests to ensure that the windings did not suffer any damage due to HV tests.

No load test is conducted by feeding the voltage to the LV winding at the rated frequency. The core loss consists of eddy current losses and hysteresis losses. The eddy current value is dependent on the rms value of supply voltage while hysteresis loss depends on the average value of voltage. Two voltmeters are used with a bridge rectifier to indicate the average value and a dynamometer type to indicate rms value. The actual losses P is given by:

Where, Pm is the measured no load loss
P1 being the fraction of hysteresis loss to the total iron loss
(0.5 for grain oriented steel and 0.7 for non-grain oriented steel)
P2 being the fraction of eddy current loss to the total iron loss
(0.5 for grain oriented steel and 0.3 for non-grain oriented steel)

13.10 Insulation resistance tests

These tests are carried out between phases-to-ground, neutral-to-ground, primary-to-secondary with 500 V/ 1000 V/ 2000 V/ 5000 V meggers depending upon the voltage ratings. The insulation resistance values shall be in hundreds of mega ohms to ensure proper insulation. These tests are conducted before and after high voltage tests to ensure integrity of the insulation after HV tests.

Though there is no standard value for these insulation resistance values, based on experience and temperature conditions some standard acceptable values are applied to verify the soundness of the insulation. If the test results give reduced values, it is preferable to take up some improvement methods like drying out, etc, before the transformer is accepted. Table 13.1 gives typical acceptable values.

13.11 Dielectric tests

The following dielectric tests are conducted on the transformers.

• Applied voltage or Dry power frequency withstand voltage
• Induced potential test

Normally, the above dielectric tests should be conducted after the lightning impulse and switching impulse tests, if they are applicable (for EHV windings) or if the customer’s specifications demand these impulse tests. Otherwise they can be conducted as a routine test.

The power frequency voltage is normally applied for one minute, where its magnitude is almost 2 times the standard voltage and depending upon the grounding method, applied to the neutral. The line terminals of the windings under test are connected together and test voltage is applied to these terminals with the other windings and tank connected to the ground. The application of test voltage is for one minute.

The power frequency withstands voltage values applicable are given in Table 13.2 and are based on the system voltage. Standard 1 values refer to effectively (solidly) earthed applications and standard 2 values are for non-effectively earthed systems.

The induced potential voltage test is basically to check the inter turn insulation and the main insulation between the windings and ground. The test voltage is twice the rated voltage of the winding with uniformly insulated windings. For graded insulation windings (generally adopted for 66 kV and above) the test voltage is about 1.5 times the nameplate voltage. For higher voltages it is usual to raise each V terminal in turn by applying single phase voltage to the LV winding. The neutral terminal may be raised to a higher potential to get at least twice the normal voltage per turn of the tested winding. The duration is 60 seconds for up to twice the rated frequency. However in order to avoid core saturation, the test frequency is chosen at higher value of around 150 to 240 Hz with the time of application reduced suitably as below.

The value of K may be 100 or 120 depending on whether it is a 50 Hz or 60 Hz rated transformer (with a minimum duration of 15 seconds).

13.12 RIV corona measurements

For transformers rated above 132 kV, the RIV corona voltage measurements are taken by applying the potential for one-hour. A rating of 1.7 times the normal voltage is applied for 2 minutes and then reduced to 1.5 times and maintained for one hour. Radio Interference Voltages (RIV) is measured 5 minutes after the voltage is reduced to 1.5 times. The readings are taken at 5 minute intervals during this one hour. The RIV readings at any moment in time and at any terminal shall not exceed 100 μV with readings not differing by more that 20 μV. If the values/differences are exceeding these values, the tests should be repeated until the transformer can match these figures.

13.13 Partial discharge measurements

For voltage ratings 220 kV and above, the partial discharge measurements are also taken during this one-hour test. The partial discharge test is basically to check the possible discharges in cavities of the solid insulation and in gas bubbles in the liquid insulation or along the dielectric surfaces. Partial discharge can result due to the following conditions.

• Improper insulation drying/process
• High stress areas caused by sharp edges in the conductors

This test requires special circuits to measure partial discharges while applying a higher voltage for a considerable duration. Typically the transformer phase and neutral is applied 1.3 times the rated phase to neutral voltage value for 5 minutes and raised to 1.5 times the rated phase to neutral voltage value for 5 seconds and again continuing with 1.3 times the voltage for 30 minutes. During this entire sequence the partial discharge should not exceed 300 pC at 1.3 times voltage and should be within 500 pC during the short 5 seconds while applying 1.5 times the voltage. These tests are normally carried out for power plant and EHV transformers rated 220 kV and above. In practice however customers require this test at much lower voltages and the new standards revision currently being debated is expected to reflect that.

13.14 Impulse tests

The lightning impulse voltage magnitudes are shown in Table 13.3 and normally conducted on EHV transformers as routine tests. The duration of the impulse is 1.2/50 μsec. One application of a reduced voltage (50 to 70% of the table values) is done after which two lightning impulses of the applicable values are applied to the terminal of the transformer.

Note:
Std 1: Non-effectively earthed systems (Resistance/Reactance grounding)
Std 2: Effectively earthed system (Solid grounding)

As a special test, chopped wave tests are often prescribed, aimed to simulate spark gaps and external flashovers across the porcelains. Dependent on the applicable standard, the value of chopped waves is 100 to 110% of the full wave values. The wave shape is similar except that the voltage is collapsed to zero after 2–8 µ seconds. The standard sequence for chopped impulse application is

• One reduced full impulse
• One 100% full impulse
• One reduced chopped impulse
• Two 100% chopped impulses
• Two 100% full impulses

The switching impulse test is similar to the lightning impulse test with one reduced full wave (75%) and two full waves of the rated impulse magnitude.

13.15 Tests on OLTC

The tests on OLTC normally consist of checking the proper operation of motors, the sequence of tap changing, manual controls, etc.

13.16 Type tests

The following are type tests which are optional and carried out on units if the client specifies the same. Normally these are conducted at additional cost.

• Temperature rise test
• Lightning impulse test (for below 132 kV)
• Switching impulse test (for below 132 kV)
• Partial Discharge test (for below 300 kV)

The temperature rise test basically comprises of allowing a full current load to be passed through the windings until the thermometer readings reach steady state values. The source is normally a low voltage, high current one. After the steady state temperature is reached the transformer will start cooling thereby changing the winding resistance value. The change in resistance value is taken to find the thermal constant of the transformer windings and to interpolate the rise in winding temperature.

The normal duration of a temperature rise test may be about 10 hours and increasing to one day for large capacity transformers. Though this is a type test, the temperature rise within the agreed limits will give a clear condition of the transformer under service conditions.

Different cooling modes are normally tested separately. On large or important transformers a test at up to 1.5 times continuous maximum rating is often specified and is then carried out for a period of some 2–10 hours to prove compliance with AS/IEC. This is done subject to a maximum hot-spot temperature of 120–1400ºC and the performance checked by analyzing the oil for dissolved gases (DGA) afterwards.

13.17 Special tests

Special tests are normally carried out only if required for checking performance. The following special tests are carried out if specified in the contract.

• Measurement of zero sequence impedance
• Short circuit test
• Sound level measurements
• Measurement of harmonics at no load
• Measurement of auxiliary power by fans and pumps

13.18 Tests on bushings

Though the transformer bushings are tested at the sub vendor’s works some of the tests may be repeated to check integrity. Normally bushing tests are repeated for EHV bushings that are condenser types.

Bushings are a critical part of the electrical system that transform and switch AC voltages ranging from a few hundred volts to several thousand volts. Bushings not only handle high electrical stress, they could be subjected to mechanical stresses, affiliated with connectors and bus support, as well. Power factor test or Tan δ test is basically carried out to check the deterioration and contamination of bushings. The voltage is applied in steps up to the rated voltage and capacitance and tan delta values are recorded for each voltage (using a Schering Bridge). Increase in capacitance and tan delta values over a period of time indicates the deterioration of the bushing.

The following are the important factors measured to decide the condition of a bushing.

• C1 Capacitance (of bushing) – this is the capacitance between the high-voltage conductor and the voltage tap or test tap.
• C2 (Tap capacitance of a capacitance graded bushing) – this is the capacitance between the voltage tap and mounting flange (ground).

Modern condenser bushings are usually equipped with test taps. Bushings rated 115 kV and above usually have voltage taps. Bushings rated below 115 kV have test taps. The availability of either a voltage tap or a test tap allows for the testing of the main insulation C1. The test tap is normally designed to withstand only about 500 volts while a voltage tap may have a normal rating of 2.5 to 5 kV. Before applying a test voltage to the tap, the maximum safe test voltage must be known and observed. Any excessive voltage may puncture the insulation and render the tap useless. If absolutely no information is available on the tap test voltage, 500 volts is the maximum test voltage recommended.

13.18.1 Main insulation (C1) test connections

• Ground points of the test set and the apparatus of the bushing under test are interconnected by ground wire.
• The HV lead from the test set to be connected to the center conductor of the bushing. If the bushing under test is in a transformer, all the bushings of the same winding shall be jumpered. The bushings of other windings should be grouped and connected to ground. The bare connector on the HV lead should extend away from the bushing under test to avoid contact with the bushing porcelain. The HV lead may be supported by another bushing or an individual wearing rubber gloves suitable for the voltage rating. The LV lead from the test set to be connected to the test tap.
• The tap housing may contain a small amount of oil or compound. Care must be taken when removing the screw cap to catch the oil. The oil is to be replaced after testing is completed.

13.18.2 Test procedure

• Power factor testing is extremely sensitive to weather conditions. Tests should be conducted in favorable conditions whenever possible.
• The main insulation test is normally performed at 10 kV in the UST test mode. If 10 kV exceeds the rating of the bushing, test at or slightly below the voltage rating.
• Actual test voltage, current, Watts, power factor and capacitance as well as ambient temperature, relative humidity, etc shall be recorded. The power factor readings shall be corrected to 20ºC.

13.18.3 Test results and inference

Changes in C1 testing are usually contamination issues caused by moisture ingress, oil contamination or breakdown and short-circuited condenser layers.
The C2 tests are similar to the above but the test voltage is to be limited as earlier indicated.

13.18.4 Hot collar test

For bushings not equipped with a test tap or a voltage tap, the only possibility is to conduct the hot collar test. The test provides a measurement of the losses in the section directly beneath the collar and is especially effective in detecting conditions such as voids in compound filled bushings or moisture penetration – since the insulation can be subjected to a higher voltage gradient than can be obtained with normal bushing tests. This method is also useful in detecting faults within condenser layers in condenser-type bushings and in checking the oil level of oil-filled bushings after a pattern of readings for a normal bushing has been established.

13.18.5 Test connections

• Ground points of the test set and the apparatus of the bushing under test should be interconnected by ground wire.
• The collar should be installed just under the top petticoat of the bushing under test and should be drawn tight around the bushing for good contact.
• The HV lead from the test set should be connected to the collar. The high voltage cable should extend away from the bushing at 90º and should not rest against the porcelain.
• The center conductor of the bushing should be grounded.

13.18.6 Test procedure

• The collar should be energized at 10 kV. If 10 kV exceeds the rating of the bushing, slightly below the rating of the bushing should be applied.
• Actual test voltage, current, and Watts are recorded. Power and dissipation factor data is not recorded. Current and Watts should be corrected to a standard test voltage such as 2.5 kV or 10 kV as necessary.
• Ambient temperature and relative humidity at the time of the test should be recorded.

13.18.7 Test results

General guidelines for evaluating the hot collar data are as follows:

• Watts-loss values less than 100 mw – bushing acceptable
• Watts-loss values of 100 mw or more – bushing unacceptable (contamination)
• Current values within 10% of similar bushings – bushing acceptable
• Current values less than 10% of similar bushings – bushing unacceptable (low level of liquid or compound)

If Watt-loss values are in the unacceptable range, cleaning may be necessary on the exposed insulation surface of the bushing. Effects of surface leakage can be substantially minimized by cleaning and drying the porcelain surface and applying a very thin coat of Dow Corning #4 insulating grease (or equal) to the entire porcelain surface.

13.18.8 Other tests on bushings

The RIV test is done basically to determine the corona discharges in bushings at the rated operating voltage (which lowers its performance and life). Oil type bushings are normally tested for moisture content similar to other transformers.

The other tests include power frequency voltage withstand test, switching impulse tests, partial discharge test, etc., to test the integrity of the bushings.

14.1 Installation of transformers

Transformers may be located indoor or outdoor. The choice is dependent on the size, space requirements, etc. Locating indoor is more common in commercial establishments, though it does not mean industries do not have indoor transformers. Indoor transformers are recommended in commercial establishments like multi-storey buildings, shopping malls, hotels, etc considering space constraints and number of common users/ outside visitors in such establishments. However in an industrial atmosphere the substations can be properly laid out to prevent access by unauthorized personnel. Cost considerations also play a role in choosing outdoor transformer installations in most of the industrial units as this avoids the cost of the building or enclosure required for an indoor location.

In locating a transformer indoors, decisions on the following are essential:

• Oil draining facilities
• Containment during oil drain
• Requirement of forced ventilation
• Approach
• Removal facilities, when required.

It is quite uncommon to have high capacity transformers mounted indoors mainly because of the space limitation, fire hazard conditions, maintainability, etc. Also the transformers with HV bushings of the order of 66 kV and above are mounted outdoor because of the simplicity in bringing the conductors by overhead lines. The insulated cable connections at these voltages are uneconomical, non-feasible and also pose a lot of limitations in routing large sized cables. Hence it can be presumed that a transformer is normally mounted outdoor if it is having EHV bushings, unless special requirements demand otherwise.

14.1.1 Ventilation

Once it is decided to have transformers indoors, whether oil filled or dry type, then adequate ventilation and physical isolation is required. Physical isolation is mainly for oil-filled ones but ventilation is a main requirement for all types of indoor transformers.

The main issue with ventilation is insufficient or non-availability of free air to cool the transformer. Hence, transformer windings reach their maximum permissible temperatures with loads as low as 50%. It is recommended that the transformer room is provided with open doors/ shutters and ventilation fans to enforce forced cooling, if the layout does not allow natural free flow of air across the transformer body.

The room in which transformers are placed must have ventilation arrangements to ensure that heated air escapes readily and can be replaced by cool air. Inlet openings should be near the flow and distributed to be most effective. The outlet opening(s) should be as high above the apparatus as the construction of the building will permit. The number and size of outlets required will depend on their distance above the transformer and on the efficiency and load cycle of the apparatus. In general, about 60 square feet of outlet opening or openings should be provided for each 1000 kVA of transformer capacity. Air inlets should be provided with the same total area as the outlets.

A typical transformer mounted indoors with such arrangements is given in Figure 14.1. It is to be noted that forced ventilation shall allow cross-flow of air from one end to other end of the transformer.

14.1.5 Unit-transformers integrated with switchgear

Oil filled transformers are normally mounted indoors in separate rooms where no other equipments are usually provided except for neutral grounding apparatus, etc. But dry type transformers are generally mounted indoors along with their primary and secondary switchgears without any partition walls because the dry type transformers are installed in steel enclosures with louvers for air circulation. Since oil is not there, the chances of spillage and associated issued do not exist.

In the case of oil filled transformers, due to their separation, the switchgears are also installed in a separate room away from the transformer. The interconnections are done by laying cables and bus ducts between transformers and the associated switchgear. This necessitates proper ear marking of space and routing for such connections. However in case of dry type transformers the interconnections can be done by extending the buses similar to a switchgear lineup. The result is a compact integrated substation with all controls and equipment located at a single place.

Dry-type transformer enclosures are larger than fluid-filled because they require air circulation to effectively insulate and cool the transformer. With air-cooled transformer designs, electrical and thermal clearances are critical. Air cooling/insulation also reduce or eliminate the flexibility to incorporate other electrical equipment into the transformer enclosure. As a result, additional air insulated switchgear must be added external to the dry-type transformer. Figure 14.2 shows the typical transformers integrated with switchgear and this type of installation is also called unit substation.

14.1.6 Dry/cast-resin designs

These transformers comprise of magnetic core and windings like any other type of transformers with the only exception being the elimination of oil for cooling/dielectric purposes. The main reason for this type is the desire of industries to reduce the maintenance and monitoring devices required in oil-filled transformers. Accordingly these transformers may also be called maintenance-free transformers.

Since the cooling medium is absent, there is a limit to transformer capacities where dry type transformers can be economically and safely used. For example all electronic gadgets and household appliances use dry type transformers mainly because of the smaller size and also the need to be maintenance free (by the common man). Typical examples are televisions, radios, tape recorders, computers, etc.

In the case of industries that use comparatively larger capacities, FRP is the most common insulation separating the windings. FRP is the short form for Fire Retardant Paper. The insulation materials are paper, pressboards, etc., and insulation up to class H is in common use. The insulation in the transformer may be epoxy encapsulated, vacuum pressure impregnated or cast resin type. There are no major differences in these types for the end user in terms of performance and guarantees, but normally the size and cost decides the type of dry transformer used. The major advantage of dry type transformers is that they can be accommodated at any location like basements, switchgear rooms, etc, provided the minimum clearances and ventilation for cooling purposes are taken care of. A typical dry type transformer internal view will be as per Figure 14.3

Cast resin transformers are used in areas where use of oil filled transformers are not preferred due to fire risks. Typical installations are for hospitals, shopping complexes, commercial complexes etc. having multi-storied buildings with considerable power requirements.

It is well known that air is not a good cooling medium. Normally air-cooled transformers without oil are thermally less efficient compared to oil filled transformers of same capacities. Extending the same logic, encapsulation of full windings by cast resin creates yet another barrier between surrounding air and the windings. Hence the cast resin transformers are still poorer in their cooling characteristics. The added disadvantage is that cast resin transformers have comparatively lower short time over load capacities compared to the oil filled ones.

The cores and frames of a cast resin transformer are identical in construction features compared to oil filled transformer core and frame. Normally foil windings are used for low voltage side in cast resin transformers and hence they are not resin encapsulated. The cast resin transformers normally use cast resin for the high voltage windings only, mainly where the secondary is less than 480V as most of the cast resin transformers do have. It is also a practice to just have cast resin coating for the secondary foil windings instead of complete encapsulation for getting uniform characteristics.

When the resin is used in the high voltage side, there are more chances for having voids in the filling and also possibilities for resin cracking. The resin has a more coefficient of thermal expansion compared to copper conductors and almost the same thermal coefficient for aluminum conductors. Hence aluminum is a preferred conductor for cast resin transformer windings.

The encapsulation process is normally carried out in full vacuum in steel moulds. To ensure that the filler materials are completely mixed, part filler is mixed with resin and the remainder fully mixed with hardener before both are mixed together in the moulds. It is necessary that the resin should penetrate fully between the winding conductors if the windings are made of wire wound conductors. In order to minimize the resin cracking, it is necessary to control the temperature of the curing process by cooling in between. Most of the resin curing processes adopts microprocessor controlled curing process to ensure reliable encapsulation. The whole transformer is normally mounted in a ventilated enclosure unless special enclosures are required as in the case of oil and gas installations.

Oil filled transformers are normally provided with off circuit tap switch with +5% to –5% variation of turns ratio. However the cast resin transformers are provided with link terminals and the desired taps are chosen by using bolted links instead of a switch which means the transformer needs to be in de-energized condition to do any change to these connections.

Since cast resin transformers are mostly used to feed a 415V switchboard, it is also a practice to have the transformer as a part of the MCC lineup and interconnected with bus. This can save some cost associated with space and cable/ bus duct requirements of an oil filled transformer mounted away from the switchboard.

14.2 Special aspects of installation of large power transformers

It is quite common to come across transformers mounted outdoors in old plants as well as in modern plants. The main reasons are basically the large size of transformers and their cooling requirements, which are difficult to get accommodated in an indoor installation. Hence it is quite an accepted practice to have the large transformers mounted outdoors with adequate clearances and following necessary precautions to avoid damages to surroundings which could be directly exposed to the transformers, unlike an indoor installation which separates the surroundings by suitable walls. The following are some of the major points to be considered while installing transformer outdoors:

• Clearances to the other equipment near the transformer
• Clearance to ground in case of open type bushings
• The exposure to rain and possible entry of water if not properly sealed
• Fencing requirements
• Fire wall requirements
• Oil Bund and Oil disposal plans (oil soak pits)

14.2.4 Firewalls

It is generally preferable to keep the large power transformers separated from the main plant, mainly in industrial areas. Separation involves locating the transformer well away from all other equipment, but this may not be convenient, as there may be space constraints. The other possibility is to segregate the transformer from other areas. Segregation basically calls for firewalls to be built around transformers such that fires, if any, would be contained within these walls. This firewall or barrier must be suitably reinforced to be capable of withstanding any explosion from the transformer. The main reason for such separation and segregation requirements is because in the event of transformer oil igniting (for whatever reason), the damage caused shall be restricted to the transformer alone and its immediate ancillary equipment, and shall not interfere with any other unit assemblies in its vicinity.

It is also a recommended practice and sometimes statutory to have firewalls between transformers, when the installation includes multiple transformers adjoining each other. This is to ensure that an oil explosion in one transformer is not carried over to the other transformers. Though it is not mandatory in some countries, it is an accepted practice to have 2 hour fire rated walls between transformers which are mounted side by side. These walls are called blast wall/ fire-wall and the main purpose of the wall is to basically prevent oil splash over to the adjacent transformer in case of severe faults leading to transformer blasts and fires. Normally installations having multiple transformers have standby transformers and in such cases it is very important to ensure that these walls are provided to minimize breakdowns in power supply. Figure 14.4 shows transformers placed on foundations separated by fire-walls.

14.2.5 Transportation and installation

Normally the transformers are dispatched with oil filled in the transformer tanks but with removable items like radiators transported separately. Hence the balance of oil to be occupied in the radiators is transported separately. Sometimes, for big transformers, the oil is transported separately with the transformer tank filled with nitrogen gas to avoid entry of moisture during transportation. Where transformers are sent along with radiators mounted to the body, the isolation valves connecting the radiator to the tank are shutoff to avoid any leakages. These valves shall be opened once transformers are received at site. The silica-gel breather is sent separately and the same shall be fitted on the transformer as soon as possible to prevent moisture absorption. All components and transformer conditions shall be verified on arrival at site and any leakage issues shall be sorted out immediately. Any delay on these could pose problems during commissioning.

Lifting of a transformer is to be done carefully and the use of cranes is recommended considering the weight and importance of the equipment. The recommended lifting arrangement is as per Figure 14.5.

Hydraulic jacks shall be employed at the jacking points provided in the transformer, when required for transferring from the truck and when fastening or turning transport rollers. During such times care must be taken to lift not more than 2 inches at every point so that no torsional strains are imposed on the transformer body.

Earthing of transformer body is a must and it shall be ensured that proper earthing connections are provided at the transformer yard.

Transformers received at site and not installed immediately are likely to absorb moisture. Hence it is desirable to erect and commission the transformer with minimum delay. However this may not always be the case. A transformer should not be stored or operated in the presence of corrosive vapors or gases, such as chlorine. Should it become necessary to store accessories for a long period of time, they should be stored in a clean, dry place or the manufacturer should be contacted for explicit instructions on the storage of individual pieces.

14.2.6 Placement of surge arresters

Overhead high-voltage power distribution lines are prone to direct lightning strikes as well as induced voltages from strikes on the protecting shield wires. While much of this lightning energy is dissipated by high voltage surge protection devices installed at the ends of a power line, a substantial part will travel further along the distribution system. This is because of the steep wave front which imparts to it the characteristics of a high frequency voltage, It thus passes through the inter winding capacitance between the HV and LV windings of power transformers into the power systems of individual buildings. Refer to Figure 14.6.

Most transformer installations are subject to surge voltages originating from lightning disturbances, switching operations, or circuit faults. Some of these transient conditions may create abnormally high voltages from turn to turn, winding to winding, and from winding to ground. The lightning arrestor is designed and positioned so as to intercept and reduce the surge voltage before it reaches the electrical system. Lightning arresters are similar to big voltage bushings in both appearance and construction.

They use a porcelain exterior shell to provide insulation and mechanical strength, and they use a dielectric filler material (oil, epoxy, or other materials) to increase the dielectric strength. Lightning arrestors, however, are called on to insulate normal operating voltages, and to conduct high level surges to ground. In its simplest form, a lightning arrester is nothing more than a controlled gap across which normal operating voltages cannot jump. When the voltages exceeds a predetermined level, it will be directed to ground, away from the various components (including the transformer) of the circuit. There are many variations to this construction. Some arrestors use a series of capacitances to achieve a controlled resistance value, while other types use a dielectric element to act as a valve material that will throttle the surge current and divert it to ground.

Considering the cost of the transformers, it is necessary to avoid flashovers near the transformer bushings due to lightning discharges, switching voltages, etc as this could affect their availability. Surge diverters are positioned at the entrance of overhead conductors connecting the exposed bushings with one number per phase to ground located close by and mounted suitably. In case of transformers which are used for frequent switching operations like arc/ furnace applications, use of surge diverters need to be carefully selected considering the operations and likely impulses. This is because the failure of surge diverters could also affect transformers if not properly coordinated with the dielectric with stand voltage requirements.

Surge diverters are sometimes placed on the transformer tank itself when the transformer design provides for the same. Many vendors will integrate this feature in their design if the same is included in the specification. The other option is to mount the surge arrestors on separate structures between the transformer and the incoming line gantry. It should be ensured that this structure does not interfere with the removal of the transformer for major repair work. The location of the structure must be as close to the transformer as feasible.

14.3 Fire protection measures for large transformer installations

Fire protection systems are those that are provided to extinguish fires caught by insulation and oil that can spread and damage the full transformer as well as the surroundings. There are many methods of avoiding or at the very least minimizing the risk of such hazards. Conventionally, it has been a general practice in many substations that employ oil filled transformers and switchgear, to provide surfaces of chipping and a drainage sump to transport away any oil spillage that could potentially fuel a fire. This method however is not foolproof. It has been found that over a period of time, these chipping collect dust and grime and this grime would provide the wick for sustained combustion. Alternatively, one could explore the possibility of providing a firewater sprinkler system around the transformer, which could be automatically triggered in the event of a fire.

The other system that can be employed for fire protection is the inert gas extinguishing system using a gas such as Nitrogen. The comprises of main storage cylinders and interconnecting pipe lines that can inject nitrogen gas once fire or internal explosion is detected, thus cutting-off oxygen supply. Figure 14.7 shows the operation of a scheme using nitrogen gas as the extinguishing medium.

The bulk sprinkler systems are employed only in large power transformer installations because of the cost and space requirements associated with such systems. For example, if the outage of a transformer can have serious financial impact (example: generator transformers), the investment definitely will make sense. In a distribution system, with redundant circuits, a fire-protection system may be difficult to justify. These systems have to be deployed when local statutory and insurance company requirements specify their use for safety and improved life of transformer installations.

The passive method of containing fires (often a mandatory requirement in installation standards) by providing adequately sized fire barriers was already discussed in an earlier section in this chapter. These barriers mainly avoid the spread of a fire from a transformer to other equipment in the vicinity.

14.4 Transformer troubleshooting

For any equipment to provide satisfactory and uninterrupted service, it is necessary that proper operating procedures are followed and recommended maintenance practices are adopted. A transformer is no exception to this rule. It is well known that transformers are the main link providing power to any type of plant and its breakdown cannot be tolerated in any installation. Transformers do not have any moving parts and hence the problems associated with rotating and moving equipment are almost eliminated, except for the accessories like OLTC and cooling fans/pumps.

It is observed that a failure of a transformer may be due to any of the following reasons:

• Continuous over loading of transformer beyond its rated capacity.
• Improper tap positions causing excessive core loss and consequently excessive heating.
• Outgoing cable faults are not cleared in specific time and transformers continue feeding them.
• Improper termination of fuses or provision of over capacity fuses which do not operate under through faults.
• Cable connections to the HT and LT bushings loosen causing arcs at contact points.
• Improper/loose earthing connection.
• Unbalanced load conditions.
• Improper maintenance/checking of oil level in conservator/transformer and not topping up oil to the required level.
• No periodical checking of the condition of silica-gel and not changing/reactivating it, if it has turned pink.
• Not checking oil level at the bottom of the breather/forming oil seal and not making up the oil level when required.
• Not periodically checking the condition of gasket joints and tightening/replacing gaskets if needed.
• Deterioration of oil characteristics and presence of moisture affecting the life of the insulation.

The above problems are mostly due to load conditions or deterioration of components over a period of time or due to poor maintenance. Accordingly the transformer problems and consequent failures can be classified into one of the following classifications:

• Overload
• Incorrect installation or use
• Faulty design or construction
• Neglect
• Wear and tear and other deterioration
• Accidents

A rigorous system of inspection and preventive maintenance will ensure long life, trouble-free service and low maintenance cost for the transformers. Maintenance consists of regular inspection, testing and reconditioning where necessary. Records should be kept of the transformer, giving details of all inspections and tests made, and of unusual occurrences if any. The principal objective of transformer maintenance is to maintain its internal insulation in good condition. Moisture, dirt and excessive heat are the main causes of insulation deterioration and avoidance of these will in general keep the insulation in good condition.

14.5 Liquid level indicator, pressure and temperature gauges

14.5.1 Liquid level indicator

These indicators are precision instruments composed of two main parts, the bezel and the body. The bezel or outer assembly includes the calibrated dial and indicating needle. The indicating needle is directly mounted on the forward end of a shaft; the other end carries a powerful actuating magnet (as shown in Figure 14.8). The bezel, when in place, covers and protects the mounting screws with which the body is attached to the flange or boss on the transformer tank or equipment.

The body is sealed against liquid leakage and encloses a second powerful magnet opposite the magnet in the bezel. The magnet in the body is mounted on a shaft coupled to the float arm. In operation, the float arm rotates the body magnet, which in turn positively displaces the bezel magnet to which the indicating needle is attached.

Liquid level indicators are usually shipped mounted on the transformer tank, or equipment, and require no maintenance. Table 14.2 gives the variations in the temperature levels for corresponding liquid levels.

Intensity	Average Liquid Temp. (ºC)	Correct Filling Level (% of Scale Above or Below 25ºC Level)
High	85 70 55 40	100 75 50 25
Normal	25 10 -5	0 -33 -67
Low	-20	-100

14.5.2 Pressure gauges

Most transformers are equipped with a pressure gauge. The gauge assembly consists of:

• a pressure sensitive element (a bulb or a diaphragm)
• an indicator attached to the element
• a dial calibrated for the required vacuum range of the tank

Maintenance of the pressure gauge should be performed if there are no changes noted during the inspection intervals (see Figure 14.9).

14.5.3 Temperature gauges

Temperature gauges are either of the hot spot or average tank temperature type. Average reading and hot spot temperature gauges can use a bulk-type detecting unit that is immersed in the oil either near the top of the oil level (Figure 14.10), or near the windings at the spot that is expected to be the hot test. A capillary tube is connected to the bulb and brought out of the tank. The temperature indication is provided either by a linear marking on the tube itself or by a dial-type indicator (Figure 14.11).

Dial type indicators have three sets of contacts to actuate any of the following devices:

• The lowest setting usually actuates external cooling fans that will turn on and off depending upon the temperature level.
• The contacts can also be set to actuate remote alarm which will alert the maintenance personnel of the transformer condition.
• Critical contact setting on the temperature gauge is connected to a relay or a circuit breaker which will trip and de-energize the transformer.

Most dial-type gauges have red indicating needle to indicate the highest temperature since it was last reset. This reading should be recorded for each inspection interval and the needle should be reset to ambient temperature for future readings.

14.6 Transformer inspections

15.1 Major tests on a CT

IEC 60044 Part 1 specifies the testing requirements for current transformers. The major tests recommended as per the standard are as below.

15.2 Test procedures

15.2.13 Polarity test

Figure 15.1 shows the simple testing arrangement for verifying the CT polarity markings at the time of commissioning electrical systems. The factory test is similar in principle except for the large power source.

Connect the battery negative terminal to the current transformer P2 primary terminal. This arrangement will cause a current to flow from P1 to P2 when +ve terminal is connected to P1 till the primary gets saturated due to the DC Voltage. If the polarities are correct, a momentary current will flow from S1 to S2.

A center zero galvanometer is connected across the secondary of the current transformer. Touch or flick the +ve battery connection to the current transformer primary terminal P1. If the polarity of the current transformer is correct the galvanometer should flick in the +ve direction.

15.2.14 Test for CT magnetizing curve

It is necessary to test the characteristics of a CT before it is put into operation, since the results produced by the relays and meters depend on how well the CT behaves under normal and fault conditions. Figure 15.2 shows a simple test connection diagram that is adopted to find the magnetic curve of a CT.

In the above circuit the current is passed through the secondary from zero to the full rated current across S1 and S2. Hence a mille-ammeter is used to measure the currents, and the corresponding voltages across S1 and S2 are measured. This basically indicates the voltage generated at the secondary terminals corresponding to the currents flowing in the winding.

The readings shall be taken until the effect of increase in the current does not generate a proportionate in the voltage. The curve is to be drawn and the exact knee point is decided where the current increase of 50% causes less than 10% change in the excitation voltage.

15.3 Safety precautions

Current transformers generally work at a low flux density. Hence the core is made of very good metal to give small magnetizing current. On open-circuit mode, secondary impedance becomes infinite and the core saturates. This induces a very high voltage in the primary – up to approximately system volts and the corresponding volts in the secondary will depend on the number of turns, multiplying up by the ratio (i.e. volts/turn × no. of turns). Since CT normally has much more turns in secondary compared to the primary, the voltage generated on the open circuited CT will be much more than the system volts, leading to Flashovers.

HENCE AS A SAFETY PRECAUTION, NEVER OPEN-CIRCUIT A CURRENT TRANSFORMER ON LOAD!!!

The general safety procedures to be followed while handling HV or MV equipment shall be applicable while testing the CT.

16.1 Tests on voltage transformers

Following are the tests recommended per IEC 60044 Part 2

16.2 Test procedures

The test procedures are mostly similar to the current transformers but are reproduced to have a review on the same.

17.1 Transformer oil – dielectric properties and uses

Till about 30 years back (around 1975) the oil used for transformers was produced by acid refining of naphtha crude. Basically, acid refining removes undesirable components from the oil by using sulphuric acid to turn the impurities to form sludge. The acidic sludge is subsequently removed by a centrifuge. The acid salts resulting in the process were removed by neutralization. Water and alcohol are removed by a steam ‘stripper’, and remaining polar contaminants are removed by an earth treatment. This process was costly, and disposal of the sludge had caused environmental concerns and criticism. Environmental pressures have forced refiners to curtail the use of the acid refining technique and develop new refining techniques. Presently, two types of refining, hydrogen and solvent, are being utilized by several refiners. These methods are less wasteful, potentially cheaper, and involve fewer environmental problems than acid refining. The oil used in today’s electrical industries is called mineral oil and all country standards clearly define the requirements of this oil.

Oil filled transformers are the most common types of transformers used for high voltage and medium voltage applications. Though dry type transformers using cast resin insulation are evoking some interest in medium voltage transformers, using oil cannot be ruled out for high voltage winding transformers above 33 kV. The main reason is that the capacity of the transformers with cast resin is limited both in terms of voltage as well as capacity. Added to this are the difficulties of having on load tap changers for these new types.

The major reason for limiting capacities of dry type cast resin transformers is the high temperature to be taken care of and generally these types of transformers are not suited for outdoor applications. Hence the chances of increased failure rates of cast resin types are also more if proper care is not taken for dissipating the heat generated by the transformers. Though these are very helpful in cutting down major maintenance needs of oil filled types, the limitations in capacities, etc make the oil filled transformers the preferred choice in many installations. This is especially so in power plants and utility industries which use voltages up to 865 kV with capacities in hundreds of MVA.

Since the mineral oil is obtained from raw petroleum crude, it is a mixture of a large number of hydrocarbons which only differ from one another in their structure and molecular weight. The oil in a transformer basically serves three purposes when a transformer is in service.

• The insulation (dielectric) properties of the oil ensure good insulation required between the windings of different phases and between the windings leading to the core.
• The oil is also acting as a coolant and the rise in oil temperature is an indication of overloading on transformers. Oil filled transformer capacity is related in reference to the maximum allowable temperature rise of the transformer oil. Radiators are provided to allow natural circulation of hot oil to travel to the top and surfaces and ensure fast heat dissipation to the atmosphere. The basic capacity of the oil filled transformer is also referred as ONAN capacity meaning the maximum loading allowed with natural oil circulation and natural air cooling.
• It also acts as an arc quenching medium like the oil in oil circuit breakers.

Transformer oil is normally a bought-out item in a transformer as far as the transformer manufacturers are concerned but their quality is vital to keep the transformers in service. The condition and safe operation of an oil filled transformer can be verified by testing the oil. This section describes the recommended tests on transformer oil and their importance, acceptable values, etc.

Typical acceptable values for transformer oil characteristics are as below and a value deviating from these values for any parameter needs immediate attention and correction as otherwise the transformer will not be able to meet its purpose and may ultimately fail during its service.

17.2 The need for testing transformer oil

During its service the oil undergoes oxidation leading to the formation of peroxides, water and organic acids along with sludge. These products lead to the deterioration of the cellulose which is the common insulation used in transformer windings. Sludge can impair the heat transfer capabilities of the oil as it forms a layer over the winding and the tank. In addition sparks and discharges inside the transformer lead to the disintegration of oil leading to the formation of gases, which mainly remain dissolved in the oil. The early detection of the deterioration of the oil will lead to considerable increase in the life of the oil and the transformer leading to improved performance.

As we have seen earlier insulation is very vital for keeping any electrical equipment in service. Naturally with transformers being major electrical equipment its oil which serves as the insulation must maintain its dielectric properties to keep the transformers in healthy operating conditions. Hence oil testing is very important to ascertain insulation properties and other properties of the transformers as discussed in the subsequent paragraphs.

It is a usual practice for the oil manufacturer to provide a test report confirming the condition of the oil meeting the above specified parameters, in line with any bought-out item. Hence a transformer manufacturer normally does not conduct oil tests to verify all the above characteristics, while supplying the transformer. But it is the responsibility of the buyer to ensure that the oil manufacturer’s test report is submitted by the transformer manufacturer and the oil is properly handled in the transformer factory. In case considerable time has elapsed between the time of tests by the oil manufacturer and the transformer testing, it is necessary to verify almost all the above parameters by testing a small sample of oil. This is done in some approved laboratory.

Nevertheless the dielectric strength is to be verified as part of a transformer’s routine tests and it is considered healthy only if the oil conditions meet the dielectric properties as per standards.

The life of the transformer oil insulation is also based on its operating temperature as noted in the following table.

A major reason for transformer failure is due to oil properties getting affected during operation. It is possible that the transformer may not be continuously loaded but still there could be occasional overloading and a temperature rise due to ambient conditions, which in turn affect’s the oil and the transformer life. Hence oil testing does not end at a manufacturer’s factory but has to be carried on during service to take proactive steps to ensure that the transformer does not suddenly fail. Oil sample test is one major critical test to ensure that the oil retains its characteristics during its operating life.

17.3 Dielectric test

The dielectric strength of the insulation is defined as the maximum voltage that can be withstood by the insulation when the voltage is applied across the conductor and the ground or the conductor and its insulation which is at ground potential. However the oil is a floating medium and hence it is difficult to verify its dielectric strength in a similar way and it is necessary to device alternate means. As we have seen earlier, air is also an insulation medium the air breaks down and allows conduction in the form of a flash arc when the distance between two different potential sources is reduced below a tested distance. This breakdown voltage also reduces in case the air properties separating the live parts or live part to the ground are affected due to climatic conditions (like higher altitude areas). The dielectric test on the oil is based on this principle where two electrodes are immersed in the oil with a voltage applied across the electrodes. The oil dielectric test measures the voltage at which the oil breaks down. In case it is below acceptable limits, it means that the insulation property of the oil has deteriorated and the oil needs to be replaced or repaired to avoid insulation breakdown within the transformer oil tank.

This test setup consists of two spherical electrodes with provisions to adjust the gap between them. A high voltage is applied across these two electrodes. This is normally increased slowly from zero, by maintaining a gap of 2.5 mm (0.1 inch) with oil in between the electrodes. The dielectric strength of the oil prevents a flashover across the electrodes up to some voltage after which it breaks down. The acceptable flashover voltage across the electrodes is around 30 kV as per standards when transformers are in service, though new oil gives a value as high as 80 kV. This voltage is termed as the break down voltage (BDV) of the oil being used. Lower values of voltage indicate the presence of contaminating agents like moisture, fibrous materials, carbon particles, sludge’s, sediments, etc in the oil and oil filtration is necessary to remove these contaminants to increase its BDV.

The test instrument is shown in Figure 17.1. The oil is collected in a small beaker and electrodes are immersed in the sample. The voltage is slowly increased from zero and a provision exists to cut off the voltage supply as soon as a flashover occurs between the electrodes. The value is displayed in the digital window. The test is normally repeated for a minimum of 3 to 6 times and the BDV recorded. The average of these readings is taken as the BDV of the main oil from which the sample is taken.

17.4 Improvement of oil by filtration

Figure 17.2 illustrates how the dielectric strength of the oil is affected by impurities and foreign matters present inside. As can be seen, the dielectric strength goes on decreasing as the impurity contents increase. The oil is likely to fail if considerable impurities are present which can bring down the dielectric strength to as low as 10 kV at 2.5 mm gap.

Moisture also plays an important role in bringing down the BDV; even below the values given in the graph. The obvious way of improving the dielectric strength is by removing the impurities and the moisture. Whether a transformer is in service or not, considerable use of paper in transformer construction makes the insulation fail due to the presence of impurities and the moisture.

The variation of dielectric strength with increasing moisture content is given in Figure 17.3. It presents a picture similar to detiriotation in the presence of impurities.

Accordingly filtration of the transformer oil is a MUST whenerver the transformer is not in srevice for a long time or if it had been under service for about one year. The filtartion unit is generally brought to the site of installation and has provisions to circulate the oil through this machine. The following graph is an indication on how the transformer oil can provde an acceptable result once impurities are removed.

It is to be noted that the impurities are not completely removed after filtration but the size of impurity particles alone is restricted. Hence filtration is not the solution for aged transformers and it is normally recommended to replace the oil every five years of service. This if of course depends on operating conditions.

17.5 Oil filtration units

These units use a combination of a high vacuum treatment and fine filtration systems. High vacuum is used for extracting water, present in the form of vapors in the oil which are then condensed. This is then followed by fine filtration of oil. Finally the oil is passed through a column of activated alumina for correction of its acidity.

These units are available as mobile units or portable units, so that they can be moved from one place to another. Naturally an industry is not ready to buy these units and hence invariably these are organized through an agency/contractor. They are normally mounted on a trailer which can be towed to any location. The system is pre-piped and pre-wired and is practically ready for use. For making the system operational, only the following things are required to be done at the place of use.

• Inlet and outlet connections by flexible hose.
• Connecting three phase electrical supply.

Typical oil filtration units are shown in Figure 17.5.

The systems are designed to remove harmful contaminants such as moisture, dissolved gases and carbon particles and hence preserve the dielectric properties of the transformer oil. The system is also capable of removing sludge and other types of suspended solids. The system is designed on a low temperature and high vacuum principle. When a high degree of vacuum is applied, the boiling point of water and vapor pressure of volatile substances comes down drastically. Water vapors and vapors of volatile substances escape from the oil, thus improving dielectric properties. By using high vacuum systems the ppm level of moisture content can be brought down to as low as 5 ppm and dissolved gas content can be brought down to 0.1% to 0.2% by volume.

The unit comprises of following main components.

• Inlet pump:

It sucks oil either from the transformer or from the transformer oil storage tank. It is a positive displacement pump.

• Heat exchanger

The inlet pump sucks oil and delivers it into a heat exchanger. Electrical heaters are flitted inside the heat exchanger. Generally, oil is heated to 60ºC to 70ºC. It contains indirect low watt density (less than 2 W/cm2) bobbin type electric heaters. Oil temperature is controlled with a thermostat. A suitable oil distribution system is provided to ensure uniform flow of oil over the heaters.

• Filter press

It is coarse filter or pre-filter for an edge filter or a membrane filter. Some parts of sludge, free water and carbon are removed in this filter press. The pre -filter is a strainer with magnet and removes magnetic and coarse suspended particles and protects inlet pump from damage due to abrasion.

• Ionic reaction column

If the oil is acidic it is passed through an ionic reaction column where the acidity is reduced by ion exchange.

• Edge filter/fine filter

Oil is then pumped into an edge filter column for fine filtration, where suspended solids are easily and effectively removed.

• Dehydrator/degassing column

A dehydrator is a highly efficient system in reducing dissolved gas and moisture content in oil. Also, it removes volatile acids which may be present. The number of stages for degassing and the type of vacuum pumping system depend upon the moisture content requirement at the outlet of the system.

The units are available as single stage and multi stage units. If requirement of dissolved gas content and moisture content is not stringent then single stage vacuum treatment plants are most suitable. For more stringent requirements multi-stage vacuum treatment plants can be used. Typical capacities of these units vary from 500 liters per hour to more than 10,000 liters per hour. The power consumption will vary from 10 kW to beyond 150 kW depending on the volume to be handled and the heating requirements.

The amount of moisture which can be dissolved in oil increases rapidly as the oil temperature increases. Therefore, insulating oil purified at too high a temperature may lose a large percentage of its dielectric strength on cooling because the dissolved moisture is then changed to an emulsion. Experience has shown that the most efficient temperature at which to filter insulating oil is between 20 and 40°C (68 and 100°F). Below 20°C the viscosity increases rapidly, while at temperatures above 40°C, the moisture is more difficult to separate from the oil.

The following factors govern whether the filtration is proper or not:

• Vacuum in the filtration machine
• The temperature of the transformer windings
• Time or number of times the oil is circulated
• The variation in the IR value of the transformer before it stabilizes
• The BDV value achieved after filtration.

A good vacuum will ensure speedy and good filtration.

17.6 Test of acidity

The oil in service gets oxidized not only because of contact with atmospheric air but also because of the large amount of copper present in the transformer. Acids formed due to these effects give rise to sludge, which precipitate out and deposit on the windings and other parts of the transformer. This affects oil circulation and transformer performance. The acids can also deteriorate the cellulose insulation.

The extent of oxidation is generally expressed as a simple number which is called Acid Neutralization Number. This number not only indicates the extent of oxidation of the oil but also identifies the extent of free organic and inorganic acids present in the oil.

The test measures the quantity of base component that is required to neutralize the acidic contents present in the oil. The test comprises of mixing the known amount of oil sample with a base compound (Potassium hydroxide – KOH) until the indicator solution turns bright pink. The neutralization number is expressed in terms of the amount of KOH in mg that takes to neutralize the acid in one gram of oil. i.e. in mg KOH/gm. Though the minimum specified is 0.03, the acceptable value under operating conditions can go up to 0.05 mg KOH/gm. However values of more than 0.1 are totally unacceptable. The difficulty in performing this test may be detecting the color change in slightly dark oil.

17.7 Other tests

17.7.1 Interfacial tension test (IFT)

The surface tension of clean pure water is strong enough to allow a carefully placed (small) needle to float without sinking. Adding detergent to the water reduces the tension and the needle sinks.

Normally oil floats on water with a surface tension between a clean oil and clean water being around 50 dynes/cm. The contaminations in the oil decrease this value and an acceptable value is around 30 dynes/cm. Values below 30 dynes/cm are unacceptable and need improvement.

This test measures the tension between the oil and water content in terms of dynes per cm or mille Newton per meter. The lower the value, the higher is the degree of sludge in the transformer oil, which needs to be filtered out or removed.

This is a laboratory test where a metal ring is mounted in a beaker parallel to the surface of the water and a sensitive balance is used to measure the force required to pull the ring from the water. The presence of acidic compounds and peroxides in the transformer oil will lower the strength of the surface film of oil on water.

The new oil should have a value of 0.04 n/m (40 dynes/cm). The values fall during service and the decrease is proportional to the concentration of oil contamination. The fall of value during the initial stage is mainly due to dissolution of varnish etc from within the equipment. Subsequent falls can then be related to the deterioration of oil. Sludge formation is possible if its value goes below 0.18 n/m.

An interesting graph as per AIEE transactions 1955 is given in Figure 17.6. It shows how the interfacial tension and acidity vary with the length of service.

It is seen that the rate of change of IFT is also a more sensitive indication of early deterioration. The IFT measurements are particularly useful in identifying (at an early stage) new oil with poor life expectancy. It permits corrective actions to be taken while it is still practical and indicating when oil should be discarded and replaced. The rate of change of acidity is often a more sensitive indication of deterioration near the sludge point. However, this is only true if the oil does not contain alkali impurities. Such impurities neutralize the acids as they are formed, resulting in a low-acidity value.

17.8 Dissolved gas analysis

17.8.4 Duval triangle method

Duval triangle method is an accurate and trustworthy method, using dissolved gas analysis for deduction of transformer problems. It is the most widely used technique for analyzing faults in transformers, with about one million DGA analyses being performed every year by more than 400 laboratories worldwide.

In Duval method, the cause of the problem is determined based on the concentration percentages of combustible gases evolved due to the problem. Table 17.5 shows the main gases analyzed by DGA.

Hydrogen	H2
Methane	CH4
Ethane	C2H6
Ethylene	C2H4
Acetylene	C2H2
Carbon monoxide	CO
Carbon dioxide	CO2
Oxygen	O2
Nitrogen	N2

The method was developed empirically by Dr. Michel Duval, by using the database belonging to thousands of transformers, spanning many years. However, it is recommended to use Duval method after confirming the existence of a problem in the transformer by the presence of hydrocarbon gases and their rates of evolution. Table 17.6 below can be used as a guide to confirm the existence of a problem in the transformer. At least one of the individual gases must be at L1 level or above and the gas generation rate at least at G2 level to indicate the presence of the problem.

Gas	L1 Limits	G1 Limits (ppm per month)	G2 Limits (ppm per month)
H2	100	10	50
CH4	75	8	38
C2H2	3	3	3
C2H4	75	8	38
C2H6	75	8	38
CO	700	70	350
CO2	7000	700	3500

Figure 17.7 below shows the Duval triangle.

PD – Partial Discharge
T1 – Thermal Fault less than 300°C
T2 – Thermal Fault between 300°C and 700°C
T3 – Thermal Fault greater than 700°C
D1 – Low Energy Discharge (Sparking)
D2 – High Energy Discharge (Arcing)
DT – Mix of Thermal and Electrical faults

The following Table 17.7 shows the faults ascribed to each of the segments shown in the Duval triangle.

Symbol	Fault	Examples
PD	Partial Discharge	Corona discharge in voids, gas bubbles with possible formation of X-wax in paper
D1	Discharges of low energy	Partial discharges of the sparking type, inducing pinholes, carbonized punctures in paper Low energy arcing inducing carbonized perforation or surface tracking of paper, or the formation of carbon particles in oil
D2	Discharges of high energy	Discharges in paper or oil, with power follow-through, resulting in extensive damage to paper or large formation of carbon particles in oil, metal fusion, tripping of equipment and gas alarms
T1	Thermal Fault T<300ºC	Evidenced by paper turning brownish (>200ºC) or carbonized (>300ºC)
T2	Thermal Fault, 300<T<700 ºC	Carbonization of paper, formation of carbon particles in oil
T3	Thermal Fault, T<700ºC	Extensive formation of carbon particles in oil, metal coloration (800ºC) or metal fusion (> 1000ºC)
DT	Electrical Fault and Thermal Fault	Development of one type of fault into another type of fault

To use the Duval triangle, the following procedure is followed. First of all, establish that a real problem exists in the transformer, using table 17.8. Once the problem has been confirmed to exist, use the Duval triangle to plot the percentages of the three gases in the triangle to diagnose the nature of the problem. The percentage of each of the key gases CH4 (methane), C2H2 (acetylene) and C2H4 (ethylene) evolved in the transformer is calculated from the individual gas quantity and the total quantity of the three gases evolved after the sudden increase in evolution of gas. Subtracting the amount of gas generated prior to the sudden increase from the present amount gives the amount of gas generated since the fault began. The percentages thus obtained are then marked on the Duval triangle against each side representing that particular gas. Lines are then drawn across the triangle for each gas, parallel to the tick marks shown on each side of the triangle as shown in sample in the figure 17.4. In majority of the cases, acetylene % would be closer to zero, since presence of acetylene indicates an abnormally high temperature condition like arcing inside the transformer.

Example below shows a case study of using the Duval triangle. Table 17.8 shows the calculation of % of the three key gases for plotting of the Duval triangle.

Name of Key Gas	Quantity of gas prior to fault	Quantity of gas after fault occurrence	Increase in gas quantity	Gas increase as % of total quantity
C2H4	82	180	98	62.8 %
CH4	140	195	55	35.2 %
C2H2	5	8	3	1.9 %
Total Quantity of gas collected	227	383	176	100 %

Figure 17.8 below shows lines drawn in the Duval triangle with the above data. These lines have been drawn parallel to the tick marks on the sides of the triangle.

As can be seen, the intersection point of the lines falls within the T3 area of the triangle, which corresponds to a thermal fault greater than 700°C. Having identified the nature and the temperature range of the fault, next we find out whether there is deterioration in the cellulose insulation material by calculating the CO2/CO ratio. Let the CO2 and CO quantities in this case be 2412 and 212 respectively which gives a ratio value of 11.38. Since the ratio is more than 7 there is no concern regarding deterioration of the paper insulation (ratio less than 7 requires further investigation).

Figure 17.9 shows a triangular graph paper, which facilitates manual plotting of the lines corresponding to the gas percentages. Such a graph paper can be obtained free of charge in electronic form by email from duvalm@ireq.ca. The graph can also be plotted automatically by using software. Kelman company in UK and Serveron US provide such software with their on-line monitors. Delta-X Research company in Canada also provides such a display.

Dual Triangle should not be used without confirming the existence of a problem in the transformer, since there may always be a percentage available for the key gases and this would erroneously indicate a problem to be present in the transformer irrespective of whether there is a real problem or not.

17.8.5 DGA case studies

Tight control of procedures and testing can prevent transformer faults occurring, whereas protection relays only operate after the event when the damage has been done. Gas analysis of samples taken form the Buchholz relay can also prove enlightening and reveal potential major problems. Tables 17.9 and 17.10 show typical DGA case studies for two different transformers.

Case 1: Transformer Rating: 250 MVA Voltage : 400/30 kV Circumstances : Buchholz trip but no obvious faults
Gas	Main Tank	Buchholz Oil
H2	13	1458
CO	4	12
CH4	3	376
CO2	51	56
C2H4	3	204
C2H6	1	7
C2H2	6	576

Diagnosis:      Findings: Discharges of high energy, arcing, sparking and overheating.

                       Flash over from dislocated connection in bushing turret.

Findings:

Case 2: Transformer Rating : 11 MVA Voltage :20/6.6 kV Circumstances : Old unit in service for + 17 years
Gas	Main Tank	Conservator
H2	219	51
CO	1791	2300
CH4	1197	731
CO2	14896	11152
C2H4	2273	1880
C2H6	663	526
C2H2	11	9

Diagnosis:      Thermal faults of high temperature. Overheated oil and cellulose.

                        Interturn flash over between winding layers.

Findings:

For dissolved gases, IEEE C-57-104-1991 (table 4) provides the basic clues, which are explained below:

Condition 1: Total dissolved combustible gas (TDCG) below this level indicates the transformer is operating satisfactorily. Any individual combustible gas exceeding specified levels in table 4 should have additional investigation.

Condition 2: TDCG within this range indicates greater than normal combustible gas level. Any individual combustible gas exceeding specified levels in table 4 should have additional investigation. A fault may be present. Take DGA samples at least often enough to calculate the amount of gas generation per day for each gas.

Condition 3: TDCG within this range indicates a high level of decomposition of cellulose insulation and/or oil. Any individual combustible gas exceeding specified levels in table 4 should have additional investigation. A fault or faults are probably present. Take DGA samples at least often enough to calculate the amount of gas generation per day for each gas.

Condition 4: TDCG within this range indicates excessive decomposition of cellulose insulation and/or oil. Continued operation could result in failure of the transformer.

If TDCG and individual gases are increasing significantly (more than 30 ppm/day), the fault is active and the transformer should be de-energized when Condition 4 levels are reached. A sudden increase in key gases and the rate of gas production is more important in evaluating a transformer than the amount of gas. One exception is acetylene (C2H2). The generation of any amount of this gas above a few ppm indicates high energy arcing. Trace amounts (a few ppm) can be generated by a very hot thermal fault (500 °C). A one-time arc caused by a nearby lightning strike or a high-voltage surge can generate acetylene. If C2H2 is found in the DGA, oil samples should be taken weekly to determine if additional acetylene is being generated. If no additional acetylene is found and the level is below the IEEE Condition 4, the transformer may continue in service. However, if acetylene continues to increase, the transformer has an active high energy. internal arc and should be taken out of service. Further operation is extremely hazardous and may result in catastrophic failure. Operating a transformer with an active high energy arc is extremely hazardous.

Above Table assumes that no previous DGA tests have been made on the transformer or that no recent history exists. If a previous DGA exists, it should be reviewed to determine if the situation is stable (gases are not increasing significantly) or unstable (gases are increasing significantly). Deciding whether gases are increasing significantly depends on your particular transformer.

Case Study 1

The types of gases normally generated based on different faults have been covered earlier and the diagnosis is in line with the gases shown in bold and italics and points 2,3 and 4 shown below.

1. Over heating of solid insulations                    CO, CO2

2. Over heating of liquid and solid insulation     CH4, C2H4, CO, CO2, H2

3. Arcing in oil                                                     CH4, C2H4, H2

4. Arcing of liquid and solid insulation               CO, CO2, H2, C2H2

Tables 17.7 and 17.8 illustrate typical readings on anonymous samples and it is important to interpret trends rather than absolute levels. There are no hard and fast rules that can be applied and even oil filtration/purification companies fight shy of interpreting results.

Case Study 1

In case 2, the diagnosis points more towards problems in solid insulation, which seems to match with the finding as shown in the points 1 and 4 below.

1. Over heating of solid insulations                    CO, CO2

2. Over heating of liquid and solid insulation     CH4, C2H4, CO, CO2, H2

3. Arcing in oil                                                     CH4, C2H4, H2

4. Arcing of liquid and solid insulation                CO, CO2, H2, C2H2

Serial No : 7324/3	Design.:	TXR3
Customer :	Rating:	10 MVA
Site :	Main Sub Voltage:	33/11 kV

SAMPLE: B M T
DATE	92-09-02	92-11-23	93-05-12	93-07-09	93-08-30	93-08-31
NEXT DATE	93-09-02	93-11-23	94-05-12	04-07-09	94-02-26	94-08-31
SAMPLE NO	1	2	3	4	5	6
REPORT NO	1346	1441	16009	1693	1718	1714
H2	0	0	5	16	55	41
02	35119	22433	20421	24759	21705	21480
N2	62326	58357	49992	59046	53134	63174
CO	19	16	17	22	2	0
CO2	459	323	469	281	133	124
CH4	5	1	1	19	0	0
C2H4	4	3	3	23	41	1
C2H6	1	0	0	8	109	5
C2H2	22	33	31	16	4	0
TCG	51	53	55	104	211	47
TGC%	9.7	8.1	7.6	8.5	7.7	8.7

Note: TCG is sum of all combustible gases (excluding O2, N2, CO2). TGC – the total gas content derived using a meter. TGC% is the content of total gas expressed in percentage from the total ppm of the gases present.

Serial No : 7324/3	Design.: TXR3
Customer :	Rating: 10 MVA
Site :	Main Sub Voltage: 33/11 kV

Sampling No: 6		Sample: B M T
Sampling Date : 93-08-31		Next date : 94-08-31
Gas Detected in Samples	Sample Values	Production Rates
Hydrogen	41 ppm	–14.00 ppm/day
…………………………………………..
H2	21480 ppm	—-
Oxygen	63174 ppm	—-
………………………………………….
O2	0 ppm	–2.00 ppm/day
Nitrogen	124 ppm	–9.00 ppm/day
………………………………………….
N2	0 ppm	0.0 ppm/day
Carbon Monoxide	1 ppm	–40.00 ppm/day
………………………………………….. C
O	5 ppm	–104.0 ppm/day
Carbon Dioxide	0 ppm	–4.00 ppm/day
………………………………………….. C	47 ppm	–164.0 ppm/day
O2
Methane	8.7 %	—-
………………………………………….. C
H4
Ethylene
………………………………………….. C
2H4
Ethane
………………………………………….. C
2H6
Acetylene
………………………………………….. C
2H2
Total Combustible Gas
………………………………………….. T
CG
Total Gas Content
………………………………………….. T
GC

A typical interpretation would be as follows:

Interpretation of historical results/trends
The high level of Ethane (C2H6) detected in sample no. 5 is a cause for concern. This is consistent with localized overheating having taken place in the transformer. The level of Ethylene (41 ppm) is also consistent with this conclusion.

Conclusion
The transformer appears to have had a localized hot spot between samples 4 & 5 but now appears to be fine. If the oil was purified between samples 5 & 6, then the results of sample 6 may not be significant and further samples should be drawn in 6 months time.

For dissolved gases, IEEE C-57-104-1991 (table 4) provides the basic clues, which are explained below:

Condition 1: Total dissolved combustible gas (TDCG) below this level indicates the transformer is operating satisfactorily. Any individual combustible gas exceeding specified levels in table 4 should have additional investigation.

Condition 2: TDCG within this range indicates greater than normal combustible gas level. Any individual combustible gas exceeding specified levels in table 4 should have additional investigation. A fault may be present. Take DGA samples at least often enough to calculate the amount of gas generation per day for each gas.

Condition 3: TDCG within this range indicates a high level of decomposition of cellulose insulation and/or oil. Any individual combustible gas exceeding specified levels in table 4 should have additional investigation. A fault or faults are probably present. Take DGA samples at least often enough to calculate the amount of gas generation per day for each gas.

Condition 4: TDCG within this range indicates excessive decomposition of cellulose insulation and/or oil. Continued operation could result in failure of the transformer

If TDCG and individual gases are increasing significantly (more than 30 ppm/day), the fault is active and the transformer should be de-energized when Condition 4 levels are reached. A sudden increase in key gases and the rate of gas production is more important in evaluating a transformer than the amount of gas. One exception is acetylene (C2H2). The generation of any amount of this gas above a few ppm indicates high energy arcing. Trace amounts (a few ppm) can be generated by a very hot thermal fault (500 °C).

A one-time arc caused by a nearby lightning strike or a high-voltage surge can generate acetylene. If C2H2 is found in the DGA, oil samples should be taken weekly to determine if additional acetylene is being generated. If no additional acetylene is found and the level is below the IEEE Condition 4, the transformer may continue in service. However, if acetylene continues to increase, the transformer has an active high energy. internal arc and should be taken out of service. Further operation is extremely hazardous and may result in catastrophic failure. Operating a transformer with an active high energy arc is extremely hazardous.

Above Table 4 assumes that no previous DGA tests have been made on the transformer or that no recent history exists. If a previous DGA exists, it should be reviewed to determine if the situation is stable (gases are not increasing significantly) or unstable (gases are increasing significantly). Deciding whether gases are increasing significantly depends on your particular transformer.

Referring to the case studies:

Case 1 : Transformer Rating : 250 MVA Voltage : 400/30 kV Circumstances : Buchholz trip but no obvious faults
Gas	Main Tank	Buchholz Oil
H2	13	1458
CO	4	12
CH4	3	376
CO2	51	56
C2H4	3	204
C2H6	1	7
C2H2	6	576

Diagnosis:      Findings: Discharges of high energy, arcing, sparking and overheating.

                       Flash over from dislocated connection in bushing turret.

Findings:

The TH manual identifies (in an earlier page), the types of gases normally generated based on different faults and the diagnosis matches with the gases shown in bold italics points 2,3,4 shown below.

1. Over heating of solid insulations                   CO, CO2

2. Over heating of liquid and solid insulation    CH4, C2H4, CO, CO2, H2

3. Arcing in oil                                                    CH4, C2H4, H2

4. Arcing of liquid and solid insulation               CO, CO2, H2, C2H2

In case 2, the diagnosis points more towards problems in solid insulation, which seems to match with the finding.

Case 2: Transformer Rating : 11 MVA Voltage :20/6.6 kV Circumstances : Old unit in service for + 17 years
Gas	Main Tank	Conservator
H2	219	51
CO	1791	2300
CH4	1197	731
CO2	14896	11152
C2H4	2273	1880
C2H6	663	526
C2H2	11	9

Diagnosis:      Thermal faults of high temperature. Overheated oil and cellulose.

                       Interturn flash over between winding layers.

Findings:

1. Over heating of solid insulations                     CO, CO2

2. Over heating of liquid and solid insulation     CH4, C2H4, CO, CO2, H2

3. Arcing in oil                                                     CH4, C2H4, H2

4. Arcing of liquid and solid insulation                CO, CO2, H2, C2H2