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Troubleshooting Turbine Systems Introduction

Turbines are rotating machines with unique construction and very efficient

operation. The operating principle is simple; when a forcing agent such as wind, water,

steam or gas is directed at the curved blades of the rotor mounted on a shaft, the forcing

agent changes speed and direction and the kinetic energy produced, spins the rotor.

The shaft upon which the rotor is mounted, in turn produces mechanical power

that can be used to operate motors, generators, hydraulic systems, compressors, gear

drives, or any number of machines used for many applications.

While the principle of operation is simple, turbines themselves can be very

complex in design and construction and each type offers its own challenges to the

operator with regard to lubrication, maintenance, troubleshooting and overall reliability.

Wind Turbines

Depending upon their design, these turbines have two or three large blades

ranging in length from 72 feet (22 meters) to 295 feet (90 meters). These blades rotate at

relatively slow speeds depending upon the natural speed and force of the wind. The

blades are connected through a gear drive to a high speed output generator. High gear

ratios, often up to 50:1, are used in order to convert the low speed and high torque of the

rotor to the low torque and high speed requirements of the generator. (SEE FIGURE 1.)

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FIGURE 1. Wind turbines can be found on both land and sea all over the world.

They require unique lubricants and pose special maintenance challenges.

The use of longer blades provides for more torque generation, but this requires

higher gear ratios which create gear contact forces of up to 4 million Newton-Meters. (A

4MW turbine exerts a mechanical force or torque, needed to lift 408,000 kg. through 1

meter each second). This requirement for extremely high gear ratios is necessary in order

to provide the high speeds required to generate electricity by wind power.

Gear and bearing lubrication have created special reliability challenges for

operators of these machines. In addition, hydraulic oil is required to operate the blade

pitch and rotor brakes, while greases are required for the generator bearings.

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Without question, the biggest challenge for wind turbine operators is the

reliability of the gear box. In recent years, improvements in gear tooth finish, lubricants,

technology, oil cleanliness requirements, seal effectiveness and compatibility,

contamination control and the elimination of the causes of sludge and varnish have made

wind turbine gear boxes much more reliable.

Wind Turbine Lubrication

Original equipment turbine manufacturers, such as Hansen Transmission, Bosch

Rexroth, Winergy and Eickhoff, have developed high performance lubricant

requirements for their gear boxes. These performance standards demand gear lubricants

in an ISO viscosity grade of 320, with extremely high load carrying capacities, excellent

wear and corrosion protection and viscosity indices of over 150. The hydraulic oils used

must have VI’s of at least 140 and pour points of -30ºC. Greases where used, must be

capable of operating over a wide temperature range of -55ºC to +140ºC or more.

Mineral base lubricants can not always meet these requirements and synthetic

lubricants using polyalphaolefins (PAOs) or polyalkylene glycols (PAGs) are those

usually recommended by wind turbine manufacturers.

In addition, where wind turbine gear boxes contain cooling systems, large

diameter flexible hoses are a requirement that must be pre-cleaned prior to installation to

ensure that rubber dust does not contaminate the gear oil, or affect filterability. FAG and

SKF bearing manufacturers have also developed lubricant standards to prevent premature

bearing failures due to insufficient lubrication, excessive loads, or contamination caused

by dirt, water or wear metals.

These rolling element bearing manufacturers have published specifications for

gear oil requirements in gear boxes wherever their bearings are used. These

specifications include; oil operating time of five (5) years, no sludge or varnish

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formation, corrosion resistance, good filterability, oxidation stability and resistance to

wear, scuffing and micro-pitting.

Wind Turbine Maintenance Recommendations

Contamination by water, airborne dust and wear metals are a particular concern

for wind turbines. Gear oils in turbine service must never exceed contamination levels of

18/16/13 per ISO cleanliness standard 4406:99.

Oil used for gear box refills or top ups should not exceed 16/14/11 and all oils

should be pre-filtered to 3 microns absolute, before being installed. Only oil filters and

seals recommended by the gearbox manufacturer (or meeting the manufacturer’s

specifications) should be used. The gearbox breather should contain a 3 micron filter and

water absorbing desiccant to prevent the ingress of dust, dirt, water, (or salt water if the

wind turbine is an offshore installation).

Lubricant analysis should include spectroscopy and ferrography to monitor wear

rates and any source and type of wear respectively. Contamination should be monitored

using particle counts and the oil must be tested for viscosity, acidity and water content,

all on a regularly scheduled basis. All used oil filter elements should be cut open and

carefully examined for wear particles and contaminants. It is advisable to obtain

AGMA/AWEA Standard 6006. This is an industrial standard written to provide

guidelines for the proper operation and maintenance of wind turbine gear boxes.

Wind Turbine Troubleshooting

Some of the more common problems associated with wind turbines are related to

gear oil oxidation and bearing and gear failure. (SEE FIGURES 2., 3., 4., 5., 6., 7., 8.)

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FIGURE 2. The sludge shown here is typical of extremely oxidized gear oil. Sludge forms as a result of many factors, common among them; high operating temperature, air bubbles entrained in the lubricant, water and oil emulsions, solid contaminants and/or bacterial growth.

FIGURE 3. Premature oil thickening, a darkening in oil color and yellow or brown varnish forming on the surfaces of bearings or other

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components are sure signs of oil oxidation beginning to occur in recirculating systems such as gear boxes.

FIGURE 4. A potential problem associated with wind turbines is false brinelling of bearings or gears while the turbine rotor is parked. This illustration shows a severe false brinelling condition. Small gusts of wind caused the rotor to vibrate slightly while the bearing was supporting the weight of the rotor.

FIGURE 5. Fretting corrosion occurs during operation when the outer raceway of

a bearing moves slightly in its housing (or when the inner raceway moves slightly on its shaft mounting position). Fretting results from

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poor bearing fits, poor installation practices, differing load intensity, or vibration. Fretting corrosion generates metal particles that may be subsequently picked up in the oil flow causing further damage.

FIGURE 6. Typical scoring of the gear set caused by abrasive particles in

the oil or localized overheating resulting from a break down of the oil film.

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FIGURE 7. Spalling of the gear tooth surface is now severe. Note the embedded contaminant as shown by the arrow.

FIGURE 8. Corrosive pitting will occur when moisture, particularly salt

water, is allowed to enter the wind turbine gear boxes on offshore installations.

Hydraulic (Hydro Electric) Turbines

The primary use of hydraulic turbines is to drive generators which produce

electrical power. These plants are built in conjunction with dams to ensure a sufficient

head of water that in turn, provides flow through the penstock to rotate the turbine blades.

The turbine main shaft is usually coupled directly to the generator shaft with one

set of bearings supporting both. The electrical power produced is received by the main

substation transformer where it then flows through main transmission lines to supply

various customers. (SEE FIGURE 9.)

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FIGURE 9.

Like all turbines, the blading design is either of “impulse” or “reaction” (pressure)

type construction. (SEE FIGURE 10.)

FIGURE 10. A. Impulse turbine design. B. Reaction turbine design.

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There are three fundamental hydraulic turbine designs. The Pelton impulse

turbine, is used in applications where water pressure heads are in the range of about 500

to 3,900 feet (150–1,200 meters). These turbines may be constructed with either a

vertical or horizontal shaft design. (SEE FIGURE 11.)

FIGURE 11. Pelton impulse turbine with a vertical shaft design.

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The Francis reaction turbine is the most widely used machine. These turbines are

primarily of vertical shaft design and are used where water heads are in the range of 65 to

1,650 feet (20–500 meters). (SEE FIGURE 12.)

FIGURE 12. Francis reaction turbine with vertical shaft.

The Kaplan reaction turbine may be of horizontal or vertical shaft design. It is a

propeller type machine used where the water head is about 16 to 250 feet (5–75 meters).

(SEE FIGURE 13.)

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FIGURE 13. Kaplan propeller type reaction turbine. The operation of these turbines is quite simple. In an impulse or Pelton machine,

jets of water are directed into bucket shaped runners attached to the turbine shaft. The

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velocity of the water is controlled by hydraulically controlling the nozzle tip position,

which in turn maintains speed in relation to variations in the load.

In reaction turbines, such as the Francis and Kaplan types, the water is directed

into adjustable turbine wicket gates or guide vanes to maintain constant speed as the load

varies. The gates or guide vanes are operated by either single or multiple hydraulic servo

motors, depending upon the manufacturer’s design.

Where a single servo motor is used, the guide vanes are connected to a regulating

ring by shear pins. (SEE FIGURE 14.)

FIGURE 14. Typical guide vane adjustment using individual hydraulic servo

motors. This set up can be found on Francis or Kaplan reaction turbines.

Speed regulation is achieved through the operation of a hydraulically controlled

governor, while some newer turbine designs use electronic speed controls.

Lubrication of Hydraulic Turbine Systems

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Hydraulic turbines require lubrication of the main shaft thrust, support and guide

bearings, the guide vane or gate bearings, the governor control system and hydraulic

components, such as the servo motors and accumulator system. In addition the generator

bearings and the air compressor, where used, must be lubricated.

1. Turbine and Generator Bearings;

Machines with horizontal shafts require journal bearings of the fluid film, spit-

shell type to support the rotating components, including the generator armature.

Thrust bearings are also used to absorb the thrust of the water acting upon the

turbine runner.

Vertical shaft machines will be equipped with a main thrust bearing to support the

load. Depending on the length of the shaft, there may be four or five segmented

split-shell guide bearings mounted strategically to allow ease of access for shaft

alignment and bearing clearance adjustments.

Thrust bearings may be either fixed pad or tilting pad type and on large, heavy

machines, both journal and thrust bearings may be designed for hydraulic pressure

oil lift to eliminate and bearing wear during shaft starting procedures. (SEE

FIGURES 15., 16.)

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FIGURE 15. Tilting pad thrust bearing of the spring supported type. Each pad has

a slot for oil film supply and oil lift as shown by the arrow.

FIGURE 16. Journal bearings used on horizontal shafts with shallow pockets for

hydrostatic lift.

Turbine shaft guide bearings on older machines may still be equipped with water

lubricated rubber or composition bearings. However, most new machines are

equipped with a stuffing box at the top of the turbine containing adjustable carbon

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ring or gland packing, combined with split-shell journal guide bearings which

may or may not contain chamfers, slots or grooves to provide lubrication. (SEE

FIGURES 17., 18., 19., 20.)

FIGURE 17. Journal bearing with a radial oil groove and chamfer on both halves.

FIGURE 18. Split journal bearing with double chamfers on both halves.

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FIGURE 19. Split journal bearing with a wide diagonal and axial groove with

chamfer to permit a large oil flow for cooling purposes.

FIGURE 20. Vertical shaft split journal bearings with radial and spiral grooves.

The radial groove on the left is located at the upper end of the bearing to allow oil to run down the bearing. The circular spiral groove on the right is designed to pump oil upward as the shaft rotates.

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The lubricant used for both hydraulic turbine journal and thrust bearings is most

often a premium rust and oxidation inhibited recirculating oil with excellent water

separating characteristics. If oil lifts are not used for startup, some systems use oil

with anti-wear capability to provide additional protection during starting. Various

oil viscosity grades are used depending upon bearing design, shaft speeds and

operating temperature. ISO viscosity grades range from 32, 46, 68 and 100.

Depending on design, the lubricant is supplied by self lubrication, where the oil is

contained in a reservoir surrounding each bearing, or may be supplied by a

centralized lubrication system. For cooling purposes, a series of cooling pipes or

a cooling jacket may be located in the oil reservoir or around each bearing.

2. Governor and Hydraulic Control Systems;

On older hydroelectric turbines, the speed controls were equipped with a

mechanical speed sensitive device and a hydraulic system to activate the guide

vanes, wicket gates or runner blades, depending upon the manufacturer’s design.

These hydraulic systems are still in wide use and most use the same oil types and

viscosities as the bearing systems.

On new machines, the speed controls are electrical or electronic, but may include a

hydraulic system to actuate the guide vanes or runner blades.

1. Compressor Lubrication;

In many hydroelectric plants, compressed air is required to maintain pressure in

the accumulators although some accumulators now utilize hydraulic oil under

pressure. Compressed air is also required in some installations to ensure tail

water does not accumulate in the turbine and to keep water out of the turbine

systems during maintenance or other activities. The compressor may be driven by

an electric motor or from the generator system itself. Depending upon the design

of the air compressor, recommended lubricants may include premium rust and

oxidation inhibited compressor oils with ISO viscosities of 32, 48, 68 or 100.

Many systems use the same lubricants as those used for the hydraulic system and

turbine bearings.

2. Guide Vane, Control Valve and Motor Bearings;

These components usually require grease lubrication, often from a centralized

lubrication system. The greases used are NLGI grades 1 or 2, depending on

pumpability requirements and temperature and both lithium and calcium are most

often used due to their good water resistance and rust prevention.

Hydraulic Turbine Maintenance Recommendations

Proactive preventive maintenance of hydraulic turbine systems is very similar to

any maintenance program to ensure machine reliability. Regular inspections, re-

lubrication, applicable air or oil filter replacements, timely adjustments to mechanical or

electrical components and maintaining machine cleanliness are all critically important.

Depending upon turbine type, the following maintenance activities are typical.

1. Turbine Assembly should be inspected regularly for worn, pitted or misadjusted

runner blades, gates, guide vanes, or propellers. Wicket gate and guide vane

bearings where used, must be periodically inspected for worn bearings, damaged

shear pins and re-lubricated if applicable. Where used, water shut off control

valves must be inspected for proper operation. Turbine shaft bearings should be

inspected for excessive wear when possible and bearing lubricant should be

topped up or replaced as necessary. Determining lubricant replacement intervals

may be guided through the regular use of appropriate oil analysis testing.

On turbines where gland packings are used on the main shaft, these must be

adjusted periodically and when leakage is severe, the packing gland seal assembly

must be replaced. Water quality, flow rate and velocity must be considered on an

ongoing basis and action taken to control or prevent high levels of silt or debris

entering the turbine runner. (SEE FIGURE 21.)

FIGURE 21. Courtesy of TransAlta Utilities. Francis Hydraulic Turbine Assembly.

2. Hydraulic System and Governor Assembly must be maintained in the same

manner as any industrial hydraulic system. Regular inspections and periodic

adjustment of the mechanical speed sensitive device may be required, depending

upon the design of the governor. The hydraulic oil must be maintained in

extremely clean condition to prevent the erratic operation of guide vane or wicket

gate servo motors caused by contaminated oil. Air filters in accumulators (where

used) and hydraulic oil filters must be of top quality and should be rated at the

very least, to 10 microns absolute.

Hydraulic pumps, relief valves and electric drive motors must not be allowed to

accumulate dust or debris to cover them and the operating temperature of these

devices must be monitored on a regular basis. Electric motor bearings should be

re-lubricated periodically and monitored for temperature and vibration. The

temperature of the exterior of these components, including the exterior of the

reservoir, should not exceed 160ºF (71ºC) in order to prevent oxidation of the oil,

which may result in the formation of varnish and sludge in the hydraulic system.

(SEE FIGURE 22.)

FIGURE 22. Courtesy of TransAlta Utilities.

Hydraulic System and Governor Assembly used to control the speed of the Francis Turbine.

3. Generator Assembly and Electrical Control Devices must be inspected

periodically and monitored for proper operation. Brush assemblies, slip rings,

switches, insulation and all control mechanisms must be inspected or tested

periodically to ensure reliable operation. Air gap between the stator and rotor

should be periodically inspected and the generator itself must be maintained in a

clean and dry condition. Premature darkening or oxidation of generator bearing

lubricant, or slight pitting of the bearings themselves might be an indication of

generator leakage currents through the bearings or may be caused by electrostatic

discharge occurring in the lubricant itself.

Generator shaft bearings must be re-lubricated periodically (if not lubricated by

the main bearing central lubrication system) and the bearing assemblies should be

monitored regularly for increases in temperature or vibration conditions which

may indicate that wear or misalignment is occurring. (SEE FIGURES 23. AND 24.)

FIGURE 23. Courtesy of TransAlta Utilities Typical generator assembly used in a hydroelectric plant.

FIGURE 24. Courtesy of TransAlta Utilities

Generator Control Panel used with the generating system shown in Figure 23.

4. Compressor Assembly (where used) must be inspected periodically and all oil or

air leaks repaired as necessary. Air quality must be maintained by ensuring that

water is removed via air line water traps or filters. Air and oil filters must be

replaced as required and the compressor lubricant topped off or replaced as

required. Replacement of the lubricant should be completed as a result of

recommendations made via a regularly scheduled oil analysis program.

Compressor drive belts or drive couplings should be inspected regularly for wear

or misalignment and the compressor must be kept clean and monitored for

temperature and vibration.

Troubleshooting Hydroelectric (Hydraulic) Turbines

Hydraulic turbines operate at relatively slow speeds of 50–150 RPM depending

upon the water head flow and the penstock design. As a result, these systems are subject

to unique operating conditions for mechanical and electrical generating components

respectively.

1. Conditions Affecting Mechanical Components; include, but may not be limited

to water hammer, cavitation, debris-filled water, contaminated or oxidized

lubricants, worn or broken wicket gate shear pins or bearings, sticking or leaking

servo motors and misaligned, worn or damaged shaft bearings.

a) Water hammer is a series of pressure waves in the penstock water supply

caused by small wicket gate or guide vane movements. If these components

are damaged or badly worn, water hammer can become severe.

b) Cavitation occurs when the pressure at any point in the flowing water

drops below the vapor pressure of the water, which ranges from .5 to 1.40 ft.

absolute depending upon the temperature. Cavitation may cause mild or

deep pitting depending upon the pressure of the cavity. When the cavitation

becomes severe and pitting spreads over wide areas of the wicket gates,

runner blades or propellers, turbine instability, vibration, imbalance and

noise may result.

Cavitation is directly affected by the elevation of the turbine with respect to

the penstock and draft tube and the velocity of the water in much the same

way as when an industrial hydraulic system is “flooded” to eliminate

cavitation.

Depending upon the design, many new turbines today are manufactured with

stainless steel propeller runners, vanes, gates, or buckets to prevent pitting

and to reduce or eliminate wear caused by the development of rust.

c) Debris-filled dirty water, is a problem for some hydraulic turbines. The

debris will get caught up in runners, guide vanes, or wicket gates and can

cause severe damage, vibration and imbalance conditions.

d) Degraded bearing or hydraulic lubricants can result in unexpected

lubrication problems. Varnish or sludge caused by excessive water

contamination or high operating temperatures will cause worn bearings,

sticking hydraulic governor controls and servo motors which in turn can

cause erratic operation of wicket gates, guide vanes or adjustable propeller

blades, again depending upon the design of the turbine.

e) Worn or damaged mechanical components will obviously result in

improper or unsatisfactory turbine operation. All adjustable wicket gates,

guide vanes, needle valve controls (Pelton turbines) and propeller runners

must be securely mounted with no worn bearings, broken or damaged shear

pins or other loose fittings or hardware. On turbines fitted with packing

glands, these must be properly adjusted periodically.

2. Conditions Affecting Electrical Generation Components; include, but may not

be limited, to problems associated with incorrect air gap, partial discharge, stator

faults, leakage currents and magnetic field problems, as well as thermal

conditions causing insulation failure or loose rotor rims where the shrink fit

between the rotor rim and main shaft spider mounts are relaxing. This last

problem has occurred on some Westinghouse hydro generators.

Damp and dusty conditions will affect the efficiency of the generator and all

components must be maintained in dry, dust free conditions.

3. Condition Monitoring Recommendations; condition monitoring includes, but

may not be limited to, oil analysis, temperature monitoring using thermography,

vibration analysis and the periodic electrical testing of the generator.

a) Vibration analysis may include proximity probes at each bearing to

monitor shaft position and radial dynamic motion. There might also be a

requirement to measure axial vibration using a probe to measure thrust. In

addition, low frequency signal condition circuitry may be necessary due to

the low operating speed of hydraulic turbines. There are vibration analysis

programs currently available specifically designed for hydraulic turbines

which are designed to monitor conditions such as shear pin failures, sources

of imbalance, debris in wicket gates and bearing problems.

b) Oil analysis should include testing for acid number, viscosity, water

content, particle count analysis and wear metals for both the hydraulic

system and bearing lubricants.

c) Monitoring Hydro Generator Conditions can be done using various

electrical testing and thermography, however a vibration analysis program

developed recently by Bently Nevada Corporation is now capable of

determining generator thermal conditions, rotor to stator air gap, partial

discharge and magnetic field condition. In addition, this program is also

capable of monitoring “rotor rim to main shaft spider” looseness. Certain

Westinghouse generators have experienced a problem where the shrink fit of

the rotor rim to the shaft mounting spider has relaxed. (SEE FIGURE 25.)

FIGURE 25. Courtesy Bently Nevada Corporation.

Shows the rotor rim and spider interface. Using displacement sensors, the Bently Nevada program found relative motion between the spider and rotor rim.

Steam Turbines

A steam turbine consists of a stationary set of blades, often called nozzles and a

moving set of blades called buckets, or rotor blades. In a steam turbine, hot steam at a

pressure above atmosphere is produced by a boiler, then, expanded in the nozzle where

the heat energy is converted to kinetic energy. (SEE FIGURE 26.)

FIGURE 26. A typical steam turbine operating system, in this case driving an

electric generator. This kinetic energy is then converted into mechanical energy in the turbine. If the

nozzles are fixed and the jets directed at the movable blades, the impulse from the force

of the jets pushes the blades. If the nozzles are free to move, reaction of the jets pushes

against the nozzles forcing them to move in the opposite direction.

The stationary and rotating blade components act together to provide torque to the

rotor assembly, which is transmitted through the shaft to the load (FIGURE 10. illustrates

the typical arrangement of impulse and reaction turbine blade designs).

Steam turbines are built in a number of different configurations to suit the needs

of industrial process, compression, or power plant electrical generation installations.

They may be of double (compound), or single cylinder design. Turbines with single

cylinder design are either a condensing or a back pressure (non-condensing) machine.

(SEE FIGURE 27.)

FIGURE 27. The back pressure design where exhaust steam is used for

heating or process purposes and the condensing design used for continuous or standby power exhausting to a condenser.

Steam Turbine Lubrication The primary lubricated components of steam turbines are the journal and thrust

bearings and depending upon the design and application of the turbine, a hydraulic

governor control system, seals, accessory gear drive, flexible coupling and turning gear

may also require lubrication.

A main oil pump is usually driven by an auxiliary gear on the governor end of the

turbine and an auxiliary oil pump is often used for oil lift systems to ensure bearing

lubrication is assured during startup or coast down.

Standard shell and tube heat exchangers are used as oil coolers and typical oil

temperatures are 140ºF (60ºC) entering the cooler and 120ºF (49ºC) exiting the cooler.

Where a generator, compressor or other device is driven by the turbine, the central

lubrication system usually lubricates the bearings and auxiliary components of the driven

machinery.

Since about 1980, stainless steel oil reservoirs and piping have become the

industry standard and where required, oil heaters have been available mounted in the

reservoirs.

Full flow oil filters are used and are rated in the 5 to 10 micron absolute ranges.

On some systems, a “side stream” or “kidney” filter is installed as a return line filter to

the reservoir to maintain the oil in extremely clean condition and to remove water which

may have entered past steam seals in systems with high back pressure, or high first stage

pressure. (SEE FIGURE 28.)

FIGURE 28. Typical Steam Turbine Lubrication System. The lubricant used in steam turbines must be a premium quality recirculating oil

with excellent thermal and oxidation stability, in order to prevent varnish and sludge

formation at bearing oil temperatures that may occasionally reach 200ºF (94ºC).

In addition, the lubricant must have high quality rust and corrosion prevention

characteristics and must readily shed the water that may enter steam turbine systems.

Lubricants used in these systems are either mineral oil or polyalphaolefin synthetic base

in ISO viscosity grades of 32, 46, or 68. Lubricants containing these qualities have

served in many well maintained steam turbine systems for thirty (30) years without

change out.

In many smaller, medium speed steam turbines, bearing lubrication is provided by

a ring oiling design, where a ring rotates over the journal, or through a slot in the journal

bearing. The ring picks up oil as it rotates and distributes the oil to the bearing and shaft.

(SEE FIGURE 29.)

FIGURE 29. Oil rings rotate with the journal to pick up and provide lubricant.

The inspection plug in the cap shown by the arrow can be removed to inspect oil level which is critical. Too little oil results in inadequate lubrication. Too high oil level allows the ring to drag causing flat spots on the ring reducing the ring’s action also reducing lubrication.

All steam turbines are equipped with two independent governors, the first to shut

off steam supply in emergencies and a second to maintain speed. Speed control governor

systems include centrifugal mechanical, hydraulic pilot valve and electronic (or

electrical) speed sensitive devices.

Electrohydraulic speed control governors are particularly susceptible to contaminated oil

and the lubricants in these systems must be kept contamination free to protect the servo

valves.

Radial journal bearings are of the split shell, three lobe, or tilting pad anti-whip

type, depending upon turbine design, speed or application. (SEE FIGURES 30., 31.)

FIGURE 30. On the left is the three lobe bearing, which tends to keep the shaft

centralized by the hydrodynamic oil film, while the tilting pad bearing on the right provides for multiple oil films to ensure stability of the journal.

FIGURE 31. The wide groove in the upper half of this split shell ends with a

machined oil dam. As the insert shows, the dam provides a downward pressure to stabilize the journal and prevent oil whirl or whip.

1. On-Line Monitoring; should include steam consumption, inlet, intermediate and

final steam pressure and temperature measurements. Turbine stage pressures

should be monitored in order to obtain information as to blade condition, such as

deformation, damage, or deposit formation.

Bearing oil pressure and temperature monitoring is recommended. A reduction in

pressure may indicate increased bearing clearance, while an increase in

temperature might indicate a change in bearing geometry or condition. These

practices should be done in conjunction with an on-going oil and vibration

analysis program.

2. Scheduled Maintenance and Inspection Activities should include periodic

inspections for oil leaks in piping, at bearing seals, or hydraulic lines. Inspect

joints and valve mechanism for steam leaks. Inspect governor and throttle valves

and/or linkage to ensure proper operation. Inspect and operate emergency or

auxiliary oil pumps to ensure they start when main oil pump pressure drops.

Inspect the governor to ensure that it holds the speed in all conditions. Inspect the

overspeed trip valve for proper operation. Inspect turbine rotor sealing glands for

leakage. Measure and maintain alignment, inspect base plate, grouting, piping

and piping anchors for damage or looseness.

If changes in turbine stage pressures have occurred, carry out a borescope

inspection if the turbine manufacturer has provided borescope access points. If no

access points have been provided by the manufacturer, it is sometimes possible to

remove accessories or covers, which will allow at least partial borescope

inspection and where modifications for access are possible, these maintainability

improvements should be carried out.

If changes in thrust or journal bearing temperature or oil pressure indicate

possible problems, bearing radial and thrust clearance should be determined.

Above all, establish and maintain accurate and detailed maintenance records that

include reports, drawings, specifications, photos and all related information

associated with operational changes, process improvements, repairs,

modifications and failure analysis documentation.

Troubleshooting Steam Turbines

Steam turbines are prone to problems requiring the initiation of

maintenance. These problems include conditions affecting lubrication, alignment

problems, imbalance conditions, vibration, bearing problems, operational errors,

steam contamination and problems affecting the efficiency of the turbine blades

themselves, such as stress cracking, corrosion, pitting and erosion. In addition,

erratic governor operation or worn governor parts will cause poor turbine

performance.

1. Factors Affecting Lubrication.

a) Entrained Air in the lubricant will increase the internal temperature of

the oil causing oxidation. Oxidation in turn will result in the formation of

varnish and sludge that settles on governor components, cooling coils, in

bearing passages and on other components, in turn causing sluggish oil flow,

further raising the temperature and more rapid oil oxidation. Unless approved

by the turbine manufacturer, oil temperature should never exceed 180ºF

(83ºC) and only intermittently at that temperature.

b) Water Contamination can be a serious problem in steam turbines. Water

will form from condensation in the oil reservoir, particularly if turbine

operation is intermittent and/or if the oil temperature is higher than it should

be. Water can enter the lubrication system through leaks in oil coolers and if

steam bypasses the steam seals.

This particular condition can be minimized by providing a dry nitrogen gas or

air purge system connected to the carbon ring glands or labyrinth steam seals

used on most steam turbines.

Water combined with air will cause the formation of rust, in turn forming

emulsions and foam that will act as catalysts increasing oxidation. (SEE

FIGURE 33.)

FIGURE 33.This shows the damage to journal bearings that will result if

unacceptable quantities of water mixed with air are allowed to remain in the lubricant. Operators must determine what amount of water is acceptable. Most experts suggest that water content should be less than 250 PPM.

c) Solid Contaminants such as dust, dirt and wear metals also contribute to

deposit and sludge formation. Some contaminant is abrasive and will be the

direct cause of scoring and excessive wear on bearing surfaces. Some

contaminants are of such size and structure that electrohydraulic servo control

valves used in many governor designs will become slow, sluggish or cause

erratic operation.

d) Applied Oil Analysis is absolutely necessary when troubleshooting steam

turbine problems. First of all, the analysis of the lubricant must be done on a

regularly, scheduled basis, usually once every 300 hours or thirty (30) days.

Trending records of all lubricant conditions such as viscosity, acid number,

solid contaminant levels, water content and the rate of component wear must

be maintained accurately and meticulously.

The recommended minimum lubricant analysis testing program for steam

turbine oils includes kinematic viscosity, spectroscopic wear metals, acid

number, water content (using the Karl Fischer test to provide accuracy), rate

of oxidation and ISO particle count for solid contaminants (larger than 5

micrometers).

If wear rates appear to be increasing, or if solid contaminant levels are higher

than normal, a ferrographic oil analysis should be carried out to determine if a

more severe wear condition is developing.

2. Factors Affecting Vibration.

a) Bearing problems in steam turbines are related to such conditions as

wear, incorrect clearances or the internal frictional qualities of the lubricant.

Radial journal bearings have high starting friction and low running friction.

At low RPM, the friction is relatively high due to boundary lubrication. This

friction decreases as the shaft moves into the rotating position where there is a

full film of lubricant between the shaft and the bearing’s inner surface.

Journal bearing to shaft clearance should not be less than two (2) mils and

should be at least 1 to 1.5 mils for every inch of shaft diameter. This

clearance affects the system’s vibration, because damping increases as

clearance decreases.

Another potential vibration problem with journal bearings is the possibility of

hydraulic instability of the shaft inside the bearing. This is a vibration caused

by “oil whirl” or “oil whip.” These conditions are the result of a wedge of

lubricant forced to rotate as the shaft rotates. This uneven oil film moves the

shaft in an eccentric motion as the shaft rotates, causing a vibration.

The vibration frequency will run somewhere between 35–49% of the shaft’s

rotational frequency. The vibration can create a condition where the shaft

ruptures the oil film and will impact or rub the bearing.

Solutions to oil whirl or whip include; reducing the load, reducing the bearing

clearance, increasing oil pressure, reducing lubricant viscosity, increasing

operating temperature, changing the journal bearing design or applying tilting

pad or three lobe bearings. (REFER TO FIGURES 30., 31.)

b) Alignment problems can be caused by cracked or damaged foundation

mounting pads, bent or deformed base plates, damaged or worn drive

couplings, loose, missing or damaged hold down bolts and brackets. In short,

any condition that may change the normal position of the steam turbine

with respect to drive or driven equipment or accessories.

c) Imbalance problems may be created by damage to turbine blades caused

by such conditions as erosion, pitting or corrosion. The build up of deposits

can block turbine buckets or settle on blades not only creating imbalance, but

increasing the axial load on thrust bearings. (Any increase in the temperature

of thrust bearings may be an indication of increased axial thrust that could be

the result of deposits).

Another potential cause of imbalance is incomplete or inadequate water

washing or chemical cleaning procedures of steam turbines. If all deposits are

not completely and thoroughly removed, imbalance may result.

d) Applied Vibration Analysis is a necessary component of steam turbine

condition monitoring. A typical large industrial steam turbine consists of a

high pressure case, an intermediate pressure case and a low pressure case

containing a series of rotors securely coupled together, supported by journal

and thrust bearings and the entire turbine shaft is rigidly coupled to the driven

machine, usually a generator or compressor.

A typical vibration analysis condition monitoring system will consist of

transducers mounted near both the journal and thrust bearings. Depending

upon the system design or monitoring requirements, these transducers may be

designed to measure the velocity or acceleration of the rotating components.

In high speed steam turbine applications, displacement transducers are always

used to monitor shaft and bearing stress and clearances. Vibration frequencies

can be either “synchronous” (such as misalignment or imbalance), “sub-

synchronous” (such as oil whirl or whip) or “non-synchronous” (such as an

electrical fault frequency).

An important consideration is that the probes containing the transducers must

be positioned correctly to “pick up” the various frequencies which will

indicate a problem. Transducers must be mounted in positions that will

monitor the most stressful conditions in the direction of rotation of the rotor

and shaft.

Equipment operators may use hand held vibration monitoring equipment or

permanently mounted vibration monitoring systems may be applied, however,

the best results are obtained when the transducers are mounted at vertical,

horizontal and axial positions (where possible). (SEE FIGURE 34.)

FIGURE 34. A typical steam turbine generator train showing the recommended

vibration transducer positions to monitor axial, vertical and horizontal frequencies on bearings A, B, C and D.

3. Factors Affecting Steam Turbine Efficiency.

a) Steam contamination can cause stress-corrosion cracking, corrosion

pitting, erosion, and can leave deposits in the turbine. It is recommended that

the feed water system be properly filtered to remove contaminants and that the

system is accurately and continuously monitored to control steam chemistry.

Any deposits on components in the steam path will have a direct effect on

capacity, efficiency and reliability.

Deposits may be detected by monitoring operating parameters such as

temperature, pressures, flow rates and valve opening. If water washing is

carried out as part of the preventive maintenance program, it is important to

remember that deposit solubilities may vary considerably between washes on

the same machine, making proper procedures an absolute necessity.

b) Erratic Governor Operation.

Steam turbine governor and control mechanisms range from relatively simple

mechanical speed governors used for small turbines, to very sophisticated and

complex pressure compensated governors. (SEE FIGURES 35., 36.)

FIGURE 35. Courtesy, Dresser Rand Corporation.

A small steam turbine used in many applications. The section shown in green is a mechanical speed governor. The red arrows show the location of various types of seals used in these machines.

FIGURE 36. Courtesy Woodward Governor Company.

Pressure compensated governor used for many turbine applications. High temperatures may cause bellow “A” to fail. Worn shaft spines “B” can occur. These are common conditions that will cause loss of turbine speed control.

Extraction, mixed pressure and back pressure type turbines are equipped with

governors that control steam flow in response to a combination of speed and

various pressures.

Large, high speed turbine governors are also equipped with hydraulic systems

used to further increase the force of the centrifugal governor mechanism and

to increase the speed with which the system responds to speed changes.

New turbines are equipped with electrical or electronic speed sensitive devices

also designed to control speed and steam valve operation.

Regardless of governor design, application or steam turbine type, the

operation of the governor may depend upon pneumatic, hydraulic, electrical or

electronic mechanisms to control speed, steam pressure and flow.

It is extremely important that the operator be aware of how an erratic governor

operation or worn governor components, can affect steam turbine efficiency.

Gas Turbines

Gas turbines used for land and marine based industrial applications have been

developed and/or converted from steam turbine or aero-engine configurations. Thus the

gas turbines used today are referred to as heavy industrial or aero-derivative types.

Typical of the steam turbine derived heavy industrial gas turbines are the General

Electric Model Series 5000 and the Solar Mars industrial gas turbine. Aero-engine

turbines that have been converted successfully to industrial applications include models

from Pratt and Whitney, General Electric and Rolls Royce. Of these aero-derivative

engines, the General Electric LM2500 and LM6000 gas turbines have been very

successfully used in industrial applications. Heavy industrial gas turbines operate at

speeds in the 3,000 to 12,000 RPM range. Aero-derivatives run at speeds ranging from

9,000 to 20,000 RPM. (Many new small “micro-turbines” will operate at speeds of up to

100,000 RPM). (SEE FIGURE 37.)

FIGURE 37. General Electric LM2500 gas turbine illustrating the compressor,

combustion and six stage power turbine sections. All gas turbines operate on the principle of the Brayton cycle; compression,

combustion and expansion. (SEE FIGURE 38.)

FIGURE 38. A gas turbine illustrating the Brayton cycle, open system, single shaft

design. (Note that this industrial turbine shaft is supported by journal bearings).

The compressor draws in atmospheric air where both pressure and temperature

are increased and the air is forced into the combustor. The fuel nozzles supply fuel to the

combustor, where the air fuel mixture ignites once again increasing temperature and heat

energy levels.

The hot compressed mixture travels to the turbine section where the air fuel

mixture expands, developing mechanical energy to rotate a shaft, which in turn, drives an

output turbine to provide power to, a generator, a pipeline transmission compressor or

many other devices. (SEE FIGURE 39.)

FIGURE 39. The GE LM2500 gas turbine showing air intake and air flow through

the combustion process.

1. Gas turbine design configurations are many and varied. They may be classified

by turbine type such as “open,” “closed” or “semi-closed.” They may also be

classified by the type of drive used, such as “hot” or “cold” end drive, or by their

output shaft configuration relative to the power turbine. This classification may

be “single spool-split shaft” or “dual spool-split shaft.”

a) Open, closed or semi-closed; an “open” turbine is one in which the air

and combustion process expansion gases pass through the turbine only once

from intake to exhaust a “closed” (sometimes referred to as “regenerative”)

turbine is one in which the heated exhaust is returned to the compressor to

improve the thermal efficiency of the new air entering the system. These

systems often use a pre-cooler to cool the hot exhaust air before

recompression. In a “semi-closed” system about two thirds of the exhaust air

is re-circulated to the compressor.

b) Hot or cold end drive; when the output shaft is an extension of the

turbine shaft, it is referred to as a “hot end drive.” When the output shaft is at

the compressor end of the turbine, it is referred to as a “cold end drive.”

Hot end drives can reach temperatures of up to 1,000ºF (538ºC) and these

temperatures can affect bearing operation and lubricant effectiveness.

Cold end drives are easier to maintain, but this configuration requires a special

design that can accommodate the output shaft and the equipment it drives.

c) Single or dual spool; a single spool split output shaft turbine is a single

shafted gas turbine unit driving a free power (or separate) turbine, without

being directly coupled to it. The drive is accomplished aerodynamically. The

dual spool split output shaft is similar to the single spool, in that it is not

connected directly to the free power turbine output shaft. However, there are

two independent shafts (a shaft within a shaft) that operate low and high

pressure compressors and turbines which generate the hot gases that operate

the free output turbine. These are used primarily for higher horsepower

applications.

2. Industrial or aero-derivative. There are several major differences in both

construction and operation between heavy frame industrial and aero-derivative

turbines. Shaft speeds are slower in the industrial type and journal bearings are

used to support the shaft, while rolling element bearings are used in the aero-

derivatives. Air flow and fuel consumption are higher in the industrials than the

aero-derivatives.

A major disadvantage to heavy industrial turbines is the time required for major

maintenance activities. This is primarily due to the modular design of aero-

derivatives. For example, inspection of the compressor on a heavy industrial

turbine may require up to 750 man hours, while the same inspection on an aero-

derivative may only require about 15 to 20 man hours. These requirements

obviously depend upon turbine design and maintainability improvements which

operators should consider, such as designing and installing borescope access

points on industrials.

From an operational point of view, aero-derivatives take much less time for

starting, acceleration, cool down and stopping than do the heavy frame industrial

turbines, however due to the very high temperatures that the aero-derivatives run

at, “hot spots” and bearing temperatures may exceed 400ºF (204ºC). While these

temperatures may be intermittent, synthetic oil is required and the potential for

varnish and sludge formation is always present.

Another major difference between heavy industrial and aero-derivative gas

turbines is the design and size of the vanes and blades. The larger, short, thick,

cross-sectional area of blades and vanes in the industrials does not resist

sulfidation corrosion, but can resist much more corrosion than the long, thin aero-

derivative turbine blades.

3. Component comparisons; the primary components of gas turbines are the

compressor, turbine, combustor, accessory drive and support bearings.

Compressors are axial design, up to nineteen (19) stages or centrifugal, with one

(1) or two (2) impellers.

Compressor pressure ratios of aero-derivatives are 30:1 or greater, while the

compressor pressure ratios of industrials are in the 12:1 range. (SEE FIGURE 40.)

FIGURE 40. Courtesy, TransCanada Turbines.

Typical General Electric aero-derivative compressor rotor assembly.

Currently all gas turbines use an impulse–reaction turbine design. Over the past

quarter century, turbine inlet temperatures have increased as much as 500ºF

(260ºC) with some as high as 2,640ºF (1,450ºC).

New technology in casting and the use of improved materials have almost

eliminated premature cracking of turbine blades and nozzles. Each advancement

in manufacturing technology has increased high temperature strength of these

components by over 80ºF (27ºC). (SEE FIGURE 41.)

FIGURE 41. Courtesy TransCanada Turbines.

Typical General Electric aero-derivative six stage turbine rotor assembly.

Combustor design continues to be improved as well, where the reverse flow

combustor used in heavy industrials uses a regenerator which improves thermal

efficiency.

Other designs utilize either single or multiple fuel nozzles and the air fuel ignition

flame can reach 3,000ºF (1,649ºC) at the combustor center depending upon the design of

the turbine.

Another major difference between heavy industrial and aero-derivative gas

turbines is the lubrication system. The industrials may require a reservoir as large as

2,000 gallons or more to lubricate and cool the system, including the hydrodynamic

sleeve type or tilting pad journal and thrust bearings used in these machines, as well as

the geared accessory drive. (SEE FIGURES 30, 31, 32.)

On the other hand, aero-derivative gas turbines usually only require a 100 to 150

gallon reservoir to lubricate and cool the system, including the anti-friction roller and ball

bearings used. The use of rolling element bearings on these units is possible because of

the reduced weight of the aero-derivatives. (SEE FIGURE 42.)

FIGURE 42. The General Electric aero-derivative LM6000 illustrating compressor

air flow, combustion chamber configuration, turbine arrangement and the location of the anti-friction roller and ball bearings which support the rotor.

4. Turbine control systems; The gas turbine is a highly responsive, high speed

machine. Without a proper control system, the compressor can begin to surge in

milliseconds, the turbine can exceed safe operating temperatures in less than one

(1) second and the power turbine can begin overspeed in less than two (2)

seconds.

The control system manages output shaft horsepower by sensing parameters such

as fuel flow, compressor inlet air temperature, compressor inlet and discharge

pressures, shaft speed and turbine inlet and exhaust temperatures. There are many

variations in turbine control mechanisms and they can be divided into the

following groups, hydro-mechanical (either pneumatic or hydraulic), electrical

relay logic, or programmable logic controller (computer micro processor).

Gas Turbine Lubrication

Almost without exception, bearings in gas turbines, whether anti-friction,

hydrodynamic journal or thrust bearings, are pressure lubricated. These systems consist

of a reservoir, primary pump, pressure regulator or relief valve, a filter (or filters) and a

cooler.

Many critical systems also utilize a secondary or standby pump to ensure positive

lubricant flow if the primary is shut down or fails. Some systems use secondary, depth

type filters to remove water or contaminants that the primary filter may not remove.

These filters are usually mounted in a bypass or side stream circuit, parallel to the low

pressure return line to the reservoir.

The primary full flow oil filters on most turbines are 3 microns, while the bypass

or side stream filters are frequently rated at 1 micron absolute. (SEE FIGURE 43.)

FIGURE 43. Typical aero-derivative lubrication system and turbine control panel.

The reservoir, tubing and hardware are of stainless steel manufacture and all of the lubrication system components are installed for relative ease of maintenance.

It is important to note that the oil operating conditions for aero-derivative turbines

are considerably more severe than the oil operating conditions for heavy industrial

machines. The thermal conditions of aero-derivative turbines include intermittent “hot

spots” at component surfaces in the 400–600ºF (204–316ºC) range, depending upon

speed and load. Hot gases can also leak into rolling element bearing housings mixing

with the lubricating oil causing increases in temperature. Bulk oil temperatures in the

reservoir may be in the 160–250ºF (71–121ºC) range.

These severe operating conditions require lubricants with superior anti-oxidation

and thermal resistance, in addition to high viscosity indices in the range of 120–150.

These conditions almost always call for the use of synthetic lubricants with

polyalphaolefin, diester, or polyol ester base stocks in the ISO viscosity ranges of 32 or

46 centistokes.

If fire resistant fluids are called for, phosphate esters are often recommended. Oil

operating conditions for industrial gas turbines on the other hand, are far less severe than

those of aero-derivatives. Temperatures of the oil entering the journal and thrust bearings

of these turbines range from 130–160ºF (54–71ºC) and leave the bearings at temperatures

in the range of 150–210ºF (66–99ºC). Bulk oil temperatures in the reservoir should range

from 120–140ºF (50–60º).

Lubricants recommended for heavy industrial turbines are most often premium

quality paraffinic base, rust and oxidation inhibited mineral oils, with viscosity indices in

the 120 range. The ISO viscosities used are 32, 46 or 68 centistokes, depending upon

ambient temperature and manufacturers’ recommendations.

Gas Turbine Maintenance Recommendations

The objective of gas turbine maintenance is to maximize performance, improve

maintainability, reduce downtime and improve reliability. This can only be achieved by

preventing turbine systems deterioration. Therefore, to prevent deterioration, the

operators of turbines must (or should) monitor and/or inspect important turbine systems

on a continuing basis.

This condition monitoring and maintenance program must pay particular attention

to five specific gas turbine operational considerations. These operational and

maintenance considerations are:

The thermodynamic gas path.

Turbine vibration and instability.

The lubricant and lubrication system condition.

Parameters for on-line condition monitoring.

Scheduled inspection and proactive maintenance activities.

The five operational considerations affect each other and the components related

to each system must all be in excellent condition to ensure optimum performance of

the turbine. Maintenance considerations for these systems are described briefly

below.

1. Thermodynamic gas path, includes the condition and cleanliness of the

compression intake air, fuel quality and the integrity and quality of the

combustion process and turbine exhaust.

a) Inlet air, must be free of contaminants, such as dust, sand, salt,

agricultural air borne chemicals, snow, ice and air borne pollen, all of which

will contribute to turbine erosion, corrosion, fouling and sulphidation which

attacks turbine blade and nozzle materials and can render the turbine useless

in a year or less, if proper air filtration is not provided and maintained.

High efficiency filters capable of capturing more than 95% of the problematic

contaminants down to one (1) micron in size must be used. Some filter

systems have a “self clean” feature that uses high pressure air to reverse flow

through the filters and blow excess contaminants from the filter elements.

This feature is highly recommended.

A decrease in turbine power output, a decrease in compressor efficiency, or an

increase in the frequency of cleaning the compressor, are indications that the

filter system is not functioning satisfactorily.

b) Fuel quality and the combustion and exhaust process. There are many

fuel types used in gas turbines. Fuels range from liquids such as distillate and

residual oils to various fuel gases, such as propane, natural gas, methane, or

gas produced from biomass processes.

Pollutants such as hydrocarbons, carbon monoxide, sulphur oxides and

nitrogen oxides (NOX) are all products of the gas turbine combustion process

and these pollutants can be reduced or eliminated by using properly designed

combustors, reducing combustion temperature with water or steam injection

into the combustion process, or by using a selective catalytic converter in the

turbine exhaust. In addition, turbine exhaust temperature is a critical

condition that should be monitored continually.

2. Turbine vibration and instability, of rotors, bearings and gear box components

can directly affect the efficiency and reliability of the process. Specifically,

resonance, rotor imbalance, misalignment, mechanical looseness, oil whirl in

hydrodynamic bearings, gear problems and defects in ball and roller bearings

should be regarded as potential problems and continuously monitored with an on-

line vibration analysis program. Hand held vibration monitoring devices should

also be used when or if, a specific problem is suspected or indicated.

3. Lubricant and lubrication system condition, includes the condition of the

lubricant itself and the condition and reliable operation of the lubrication system.

The lubrication system must be periodically inspected for oil leaks at connections,

piping and fittings. Oil levels should be monitored on a daily basis and oil

pressure and temperature must be part of the condition monitoring program.

Oil pressure is indicative of the pressure drop across filters and can indicate

internal leaks if external leaks are not present, but the oil level is dropping.

Internal leaks are difficult to detect and can result in oil leaking into the hot gas

path. This may or may not be indicated by either a gradual or sudden appearance

of exhaust smoke. If internal leaks are suspected, an inspection of the combustor,

the exhaust duct, the compressor discharge, or air bleed discharge may be possible

using a borescope or other method to look for traces of burned oil in these

components.

Monitoring oil temperature can be carried out using one (or more) of three

methods; measure the temperature of the oil leaving the bearings, measure the

actual oil temperature at the return line to the reservoir, or measure the bearing

metal temperature using contact thermocouples or resistance temperature

detectors (RTDs). An increase in oil temperature can occur quickly if leaking

seals allow hot gases to leak into the oil. Oil temperature will also increase if the

cooler is inefficient or plugged, or if the cooler doesn’t have the correct capacity

for the system.

4. Parameters for on-line condition monitoring of gas turbines should include, but

are not limited to the following list: (Some manufacturers may recommend

specific additional requirements).

a) Ambient air temperature and barometric pressure.

b) Inlet air pressure at the compressor.

c) Low pressure compressor “out” pressure.

d) High pressure compressor “out” pressure.

e) RPM, single shaft.

f) RPM, dual shaft.

g) RPM, free power turbine.

h) Fuel flow and pressure.

i) Exhaust total pressure and exhaust gas temperature.

j) Overall vibration levels.

k) Lubricant oxidation and contaminant levels.

5. Scheduled inspections and proactive maintenance activities should include,

but may not be limited, to annual fuel nozzle inspection and/or replacement,

governor control system inspection and testing, water or chemical washing

procedures and borescope inspections.

When used in conjunction with gas path, vibration, lubricant and trending analysis

techniques, borescope inspections usually provide the final step in the

identification of an internal turbine problem.

Borescope inspections can be carried out with flexible or rigid borescope

equipment. This inspection equipment is limited by the turbine design, borescope

accessibility locations and the inspector’s knowledge and capability.

Borescope ports are provided by many aero-derivative turbine manufacturers, but

may not be provided by the makers of heavy industrials. In these cases, the

inspector must use every available access point, such as removing fuel nozzles,

pressure or temperature probes. If accessible, the borescope can be used to view

the combustion liner, turbine nozzles and blades and compressor vanes and

blades.

If a borescope inspection reveals a problem, such as compressor fouling, water or

chemical washing may be carried out.

Washing procedures and access instructions are available from the various turbine

manufacturers, whose maintenance procedures include detailed internal washing.

Inadequate or incomplete washing however, may actually cause additional

problems or increase existing problems, such as moving the debris deposits to a

more critical component. This is a particular concern when cleaning compressors

of salt contamination. The cleaning process may simply move the salt into the

turbine area where sulphidation corrosion may be accelerated. Operators must be

fully knowledgeable of their turbine designs and the washing procedures

recommended.

Troubleshooting Gas Turbines

Gas turbines are susceptible to damaged turbine, compressor or combustor

components, contamination buildup, fouling, erosion, corrosion, sulphidation,

lubricant oxidation causing sludge and varnish, water emulsions, worn bearings

and seals, plugged or damaged fuel or turbine nozzles, or broken blades or vanes.

(SEE FIGURE 44.)

FIGURE 44. This General Electric LM6000 gas turbine is a complex and

sophisticated machine. The factors that affect troubleshooting of gas turbines include lubrication conditions, vibration, turbine efficiency and the air/fuel combustion and governor control processes.

1. Factors Affecting Lubrication.

a) Varnish and sludge are caused by oxidation and thermal degradation of

the oil, primarily caused by high temperatures, but also promoted by

contaminant catalysts like water and air. Specifically, oxidation is a chemical

reaction when oil is mixed with oxygen, while thermal degradation occurs at

higher temperatures around 400ºF (205ºC) or higher or when trapped air

bubbles travel from low to high pressure areas. The hot air bubbles implode

and the high concentration of heat raises the oil temperature degrading the

lubricant. Symptoms of oil oxidation include an increase in viscosity, an

increase in acid number and a darkening in color, all of which indicate the

beginning of thermal degradation that will result in black, tar like deposits on

mechanical seals, hard brownish or gold colored films on valves or bearings,

thick gooey deposits trapped in oil filters and premature plugging of oil

coolers.

It should be noted that some of today’s Group II and Group III base oils have

lower solvency than Group I base stocks. As a result, lubricants with reduced

solvency may have a lower tolerance for degradation by-products that form

sludge and varnish. (SEE FIGURES 45., 46.)

Figure 45. Note the brown/black varnish deposits on the journal bearing. These

deposits “may” have formed at these bearing areas because these particular areas experienced the highest temperatures and/or the lowest oil flow.

FIGURE 46. Excessive varnish can clearly be seen on this gas turbine inlet guide

vane valve. This resin like material can become so hard it will cure to a glossy coating like lacquer.

In addition to these quite common causes of varnish and sludge, a

phenomenon known as fluid electrification is also a contributor to varnish and

sludge formation in turbines.

Electrostatic discharge occurs in lubricants as a result of internal molecular friction

and differences in electrical potential between the fluid and machine component

surfaces. Static electrical discharge has been known to occur at servo valve

surfaces, in filters and in reservoirs and spark discharges can reach temperatures of

20,000ºC, promoting thermal degradation instantly.

b) Water contamination can not only promote oxidation in turbine lubrication

systems, but can also promote foaming, emulsions and bacterial growth. Water

content of 500 PPM in the lubricant is sufficient to cause these conditions. While

bacterial growth is primarily found in steam turbine lubrication systems, due to the

high potential for water, bacterial growth can also occur in gas turbines if water

content is high and stagnant or low oil flow conditions exist in cooler parts of the

lubrication system, particularly in the presence of light. (See Figures 47., 48.)

Figure 47. The interior of a steam turbine filtration unit showing heavy

concentrations of bacterial growth and rusty emulsions. While these conditions are found predominantly in steam turbine lubrication systems, they can also occur in gas turbine or hydraulic (hydroelectric) turbine lubrication systems.

FIGURE 48. Oil sight glasses will often show foaming, emulsified oil and/or free

water content. If bacterial growth is occurring, a perfect place for a bacteria colony may be near the bottom of the inside of the sight glass, at the point of the arrow.

c) Solid contaminants, such as salt, sand, dust, dirt and wear metals, particularly

wear metals like copper, can also contribute to varnish and sludge formation.

These contaminants will also cause scoring and wear on components like bearings

and hydraulic servo control valves in governor systems. (SEE FIGURE 49.)

FIGURE 49. This ball bearing failure in a GE LM6000 gas turbine was initiated by

a hard metal particle that came loose from a poor weld during a component repair. The bearing was replaced twice before the root cause of the problem was located and corrected.

Other contaminants may include water/glycol mixtures where it is used in

coolers. (To prevent contamination of the oil, it is recommended that the oil

side operating pressure of the cooler should be higher than the water side

pressure).

d) Applied oil analysis is a condition monitoring technology that must be

carried out on gas turbines on a regularly, scheduled basis, usually every 200

to 300 hours or thirty (30) days and more frequently if conditions warrant.

A recommended minimum lubricant analysis program for gas turbine

oils includes viscosity at both 40 and 100ºC, spectroscopic wear metals, acid

number, Fourier Transform infrared spectroscopy to monitor oxidation levels,

water content and a particle count to measure contaminant levels.

If wear rate or contaminant level trends increase, a ferrographic analysis is

recommended. Where acid number increase or FTIR analysis suggest that

oxidation rates are increasing too rapidly, an RPVOT (rotating pressure vessel

oxidation test) should be considered.

2. Factors Affecting Vibration.

a) Bearing problems in gas turbines are related to lubricant quality,

contaminants, wear, temperature and vibration. While the rotational speeds of

steam turbines is relatively low, gas turbines run at high speed, particularly

aero-derivatives which run at speeds that range from 9,000 to 20,000 RPM,

while heavy industrials operate at lower speeds in the 3,000 to 12,000 RPM

range.

Some industrials use hydrodynamic journal bearings, but all of the new aero-

derivatives and many industrials now use rolling element bearings to support

the rotors and shafts.

Anti-friction bearings inherently have low starting friction, but high running

friction, as opposed to the frictional conditions that affect journal bearings.

Most rolling element bearing vibration fault frequencies are caused by fatigue

and running wear, incorrect or insufficient lubrication, bearing misalignment

and manufacturing flaws within the bearings themselves.

Often, improper internal clearances (too loose or too tight) and improper

installation can cause premature failure and vibration frequencies may be

related to these conditions.

The four fundamental vibration frequencies related to anti-friction bearings

are:

Fundamental train (cage) frequency, often referred to as the FTF.

Ball pass frequency of the inner raceway (BPFI).

Ball pass frequency of the outer race (BPFO).

Ball spin frequency (BSF).

These defect frequencies depend upon the shaft speed and bearing geometry.

Troubleshooters must therefore know the name and part numbers of gas

turbine rolling element bearings. This information is necessary in order to

obtain the manufacturers bearing geometry data and thus know the

frequencies of the bearings.

The bearing geometry data required to accurately determine the vibration fault

frequencies are:

The ball or roller diameter,

The pitch diameter,

The number of rolling elements,

The contact angle.

If the bearing frequencies are not known, or cannot be obtained from the

manufacturer, the following calculations can be used to obtain the

approximate frequencies of the bearings inner and outer raceways.

Inner Race Frequency # of Rolling Elements X Shaft RPM X 65%

Outer Race Frequency # of Rolling Elements X Shaft RPM X 45%

b) Resonant or natural frequencies are found in every piece of equipment

and gas turbines are no exception. If the resonant frequency is below the

operating frequency or speed, the turbine (or any piece of equipment) is said

to have a stiff shaft. Almost all gas turbines on the other hand are said to have

a flexible shaft, because the normal operating speed and corresponding

frequency is above the resonant frequency.

As in all rotating equipment, resonant frequencies which may affect turbine

operation can be found in rotors, base plates, mounting pads, piping and

bearing or bearing supports, to name a few. Troubleshooters should be aware

of these potential sources of turbine vibration.

c) Other sources of vibration include rotor imbalance, seen at 1 X running

speed in the radial direction, while looseness and misalignment are usually

seen at 2 X running speed. In order to obtain as much data as possible, it is

wise to measure displacement (distance or movement), velocity (speed) and

acceleration (force) of the vibrations.

Proximity transducers are used to measure displacement and are located at

each radial bearing. Accelerometers are used to measure high frequencies of

compressor or turbine blade vibration, while the most uniform measurement

of vibration data is velocity, because overall velocity is frequently used to

detect a wide range of vibration data occurring at low, mid and high

frequencies. As was the case with steam turbines (or any piece of rotating

machinery), data should be collected in the vertical, horizontal and axial

positions. (SEE FIGURE 50.)

FIGURE 50. This spalled rolling element turbine bearing would have displayed vibration frequencies that would have clearly indicated failure. (Note the brownish coloration on the cage between the rolling elements that also indicates evidence of varnishing).

d) Applied vibration analysis is an essential component of trouble shooting

and condition monitoring of gas turbines. All of the vibration analysis

recommendations made for steam turbines apply for gas turbines and indeed

may even be more important due to the high speeds under which these

complex machines operate.

3. Factors Affecting Gas Turbine Efficiency.

Problems related to gas turbine efficiency can be detected by concentrating on

troubleshooting four general areas. Previously discussed were vibration and

lubrication. The remaining areas of troubleshooting are gas patch analysis and

turbine control systems.

a) Gas path analysis includes monitoring the parameters associated with

compressor fouling, such as compressor discharge pressure. Compressor

fouling occurs due to foreign deposits on the blades. Another area to be

investigated is the possibility of plugged or damaged fuel nozzles and

damaged combustor liners. Fuel flow and pressure parameters would provide

the necessary troubleshooting data.

A third condition that directly affects turbine efficiency is turbine assembly

blade erosion, corrosion, oxidation, or impact damage. Statistically, 25% of

gas turbine failures are due to blade failure. Parameters that need to be

considered by the troubleshooter are increases in fuel flow, changes in exhaust

gas temperature and/or compressor discharge pressure.

As pointed out earlier, many oxidation, corrosion, erosion or damage caused

by foreign objects, can be verified by a borescope inspection.

A final item not to be overlooked is the possibility of hot air or gas leaking

into the lubrication system past leaking labyrinth or mechanical seals. This

condition can cause an increase in oil temperature and possibly foaming or

frothy oil. (SEE FIGURE 51.)

FIGURE 51. This cutaway of a GE LM6000 gas turbine provides graphic evidence

of the complexity of these machines. The compressor, turbine and bearing supported rotor assemblies are well designed and carefully balanced to provide years of high speed reliable service.

b) Fuel and governor control problems are most often associated with gas

turbine starting problems, such as “hot” or “hung” starts. Hot starts are

usually caused by a too rich fuel schedule, while hung starts may be the result

of a too lean fuel schedule.

Running problems such as an inability to accelerate, or a too rapid

acceleration, are usually the result of a governor problem.

The troubleshooter must keep in mind that pneumatic and hydraulic governor

controls are extremely susceptible to leaks, contamination and wear.

Pneumatic systems can also be very erratic if moisture is in the air lines. The

troubleshooter must know how the control systems work and how to

recognize and correct malfunctions.

A Word About Micro-turbines

Micro-turbines are small, compact combustion turbines with high rotor speeds of

up to 100,000 RPM with outputs from a low of 20 kw, to a high of 500 kw when used to

generate electricity. These machines evolved from truck turbocharger designs and

typically consist of a single shaft mounted centrifugal compressor and radial turbine, a

combustor and a recuperator. The recuperator is used to return a portion of the exhaust

heat to heat compressor discharge air. Heating the compressor discharge air reduces fuel

consumption and reduces NOx formation. In some designs, a separate power turbine

wheel is provided.

Micro-turbines are coupled to inductive or synchronous generators, in mechanical

drive applications to a gear box, refrigeration compressor, or a pumping service. (SEE

FIGURE 52.)

FIGURE 52. A micro-turbine with a free power turbine driving a gear box. Many micro-turbines are now being built by such manufacturers as Capstone,

Ingersoll Rand and Allied Signal, some weighing no more than 165 pounds. Micro-

turbines are complex, sophisticated machines with unique bearing and lubrication

systems. Some use hydrodynamic journal bearings to support the turbine rotor, while

most new designs use rolling element bearings, some of which use ceramic balls

requiring synthetic lubricants.

Newer designs use magnetic, water vapor, air, gas or foil bearings, none of

which require lubricants. An “air” bearing uses a thin film of pressurized air to support

the shaft. In a “gas” bearing, the gas is pressurized. A “foil” bearing has a small preload

between shaft and bearing surface. As the shaft begins to rotate, hydrodynamic pressure

pushes the foil away from the shaft and the shaft becomes airborne.

The “water vapor” bearing design uses water pressure at higher than atmospheric

pressure. At rest, the clearance between the shaft and bearing surface is filled with liquid

water. As speed increases, the heat transfer turns the water to vapor. Evaporation from

the bearing surface elevates local pressure and stabilization occurs due to hydrostatic

pressure superimposed on the hydrodynamic requirements.

In a “magnetic” bearing design, a magnetic field maintains a stabilized shaft

position within the surfaces of the support bearings. Currently, there is work underway to

produce micro-turbines for use in generating electrical power for truck and automotive

service. A hybrid electric automobile application for micro-turbines is on the drawing

board. This application should be possible and practical when the high production and

maintenance costs can be overcome.

Conclusion

Successfully troubleshooting turbine system, whether they are operated by wind,

water, steam or gas, can only be done if the troubleshooter has an intimate knowledge of

the turbine’s design and application and how operating conditions, effective maintenance

practices and condition monitoring techniques will affect their reliable operation.

The condition monitoring techniques that should be used carefully and correctly

by the troubleshooter include, oil and vibration analysis, thermography (to monitor hot

spots) and ultrasonic testing (to locate pneumatic control leaks and internal hydraulic

leaks at governor or servo-control valves).

In addition, the appropriate non-destructive testing techniques must be well

understood, all of which will then make troubleshooting relatively easy and effective.

R e f e r e n c e s

1. The Practical Handbook of Machinery Lubrication, 3rd Edition, L. Leugner, Maintenance Technology International Inc., PP. 94–99, 116–130.

2. Gas Turbine Handbook, Principles and Practices, 3rd Edition, Tony

Giampaolo, Dekker/CRC Press.

3. Mark’s Mechanical Engineers Handbook, 6th Edition, McGraw-Hill, Chapter 9, PP. 68–90, 173–182, 207–227.

4. Practical Machinery Management For Process Plants, Volume 4, Heinz

Bloch, Fred Geitner, Gulf Publishing, PP. 335–492, 628–633.

5. Practical Machinery Management For Process Plants, Volume 2, 2nd Edition, Heinz Bloch and Fred Geitner, Gulf Publishing, PP. 274–287, 437–444, 461–472.

6. Handbook of Lubrication, Volume 1, Application and Maintenance,

STLE, CRC Press, PP. 91–133.

7. Practical Lubrication For Industrial Facilities, Heinz Bloch, Dekker Publishing, PP. 441–481.

8. Machinery Oil Analysis, 2nd Edition, Larry Toms, Coastal, PP. 243–

246.

9. Lubricants and Related Products, Dieter Klamann, Verlag Chemie, (Federal Republic of Germany), PP. 256–260.

10. Formulating Advanced 4 Centistoke Gas Turbine Oils–A Feasibility

Study, SAE Paper # 851833, Q.E. Thompson and R.E. Zielinski, Monsanto Industrial Chemicals Co.

11. Reliability Centered Maintenance, 2nd Edition, John Moubray, Industrial

Press, PP. 44, 52, 89, 161, 162, 348–411.