Steam turbines are used extensively in the power generation industry as prime movers for generators.They are also used for mechanical drive application in petrochemical and other industries where theypower centrifugal pumps, compressors, blowers, and other machines. In addition, they continue to beused for shipboard propulsion. Sizes range from as low as 0.75 kW for some mechanical drive applicationsto as high as 1,500 MW for electric generator drives in large nuclear power plants [1]. Steam turbinesare particularly well suited for continuous operation, and in many cases are operated for years withoutshutting down.
Steam turbines operate by taking high-pressure steam and converting it into useful mechanical workthrough expansion. The steam is fed into an inlet casing then throttled through a set of inlet valves, whichcontrol the rate of steam admission into the turbine. The steam is then allowed to expand and acceleratethrough stationary blades or nozzles, which directs the flow onto the rotating blades. The rotating bladesconvert the steam’s kinetic energy into torque, which results in rotation of the turbine shaft along with aloss of pressure and temperature in the steam. The rotating shaft is used to drive machinery coupled tothe exhaust end of the turbine shaft.
Absence of lubrication from the steam path is an important feature. Since the exhaust steam is notcontaminated with oil vapor, this allows the steam to be condensed and returned directly to the boilersfor reheat, or extracted and used for direct heating or other purposes. The lack of internal lubrication alsoresults in a relatively low rate of lubricating oil consumption [2].
8.2.1 Classification
Steam turbines have numerous configurations and means of classification. A steam turbine is generallyclassified as being either high-pressure or low-pressure, condensing or noncondensing, single-stage ormulti-stage, single-valve or multi-valve, extraction or nonextraction, direct drive or gear drive, and foreither electric generator, mechanical drive, or propulsion service [3]. In addition, steam turbines areclassified in accordance with recognized engineering standards, which govern various aspects of turbinedesign and construction. Some of these classifications are discussed further.
High-pressure designs refer to the internal pressure to be contained by the main shell and casingparts. High pressure generally refers to pressures in excess of 13,800 kPa (2,000 psig) where doubleshell construction is often used. The pressure and temperature of steam are interrelated. Higher inletsteam pressure is often accompanied by higher steam temperature. Temperatures can range from 200 ◦Cto over 600 ◦C. High temperature generally refers to applications with inlet temperatures in excess of540◦C (1,000◦F).
Condensing turbines exhaust steam at less than atmospheric pressure, whereas noncondensing (backpressure) turbines exhaust steam at higher than atmospheric pressure. Condensing machines tend to belarger and more complex than noncondensing designs due to the increased volume expansion of the steamat the exhaust end as well as the additional hardware required to drop the exhaust end pressure belowatmospheric.
In direct drive arrangements, the turbine is directly coupled to the driven machine; whereas geardrive applications have either a speed increasing or speed reducing gear between the turbine and drivenequipment. The use of a speed increasing or reducing gear creates added complexity, cost, and power lossesalong with additional requirements of the lube oil system. However, the use of gears greatly increases theapplication range whether the need is for high torque as in marine propulsion or high-speed requirementssuch as integrally geared compressors. Gear drives also enable the efficient use of small turbines, whichcan operate at higher speeds when a reduction gear is used.
Generator drive turbines operate at single speeds to synchronize the generators with the electric grid.Typically, the synchronization speed is either 1,800 or 3,600 rpm in regions with 60 Hz power, or 1,500or 3,000 rpm in regions with 50 Hz power. On the other hand, mechanical drive turbines are variablespeed with shaft speeds as low as 1,000 rpm or as high as 20,000 rpm depending on the turbine and theapplication.
A number of different engineering standards have been developed for the design and procurementof steam turbines as shown in Table 8.1. American Petroleum Institute (API) standards pertain todesign, manufacture, and testing of mechanical drive turbines for petrochemical application [4,5].National Electrical Manufacturers Association (NEMA) standards pertain to design and applicationof mechanical drive turbines and turbine generator sets for electric utility application [6,7]. Mil-itary standards generally apply to steam turbines for shipboard use [8–10]. Other international
TABLE 8.1 Steam Turbine Design and Procurement Standards
Standard designation Standard title
API 611 General-purpose steam turbines for refinery serviceAPI 612 / ISO 10437 Special-purpose steam turbines for refinery serviceIEC 60045-1 Steam turbines — part 1: specificationsNEMA SM-23 Steam turbines for mechanical drive serviceNEMA SM-24 Land-based steam turbine generator sets 0 to 33,000 kWMIL-T-17286D Turbines and gears, shipboard propulsion, and auxiliary steam; packaging ofMIL-T-17600D Turbines, steam, propulsion naval shipboardMIL-T-17523 Turbine, steam, auxiliary (and reduction gear) mechanical drive
recognized standards such as IEC 60045-1 are also used to assist in steam turbine specification andprocurement [11].
Figure 8.1 shows a general-purpose (API 611) turbine. These turbines are either horizontal or verticalunits used to drive equipment that is usually spared, is relatively small in size (power), or is in noncriticalservice. General-purpose steam turbines for refinery service are intended for applications where the inletgauge pressure does not exceed 4,800 kPa (700 psi), the inlet temperature does not exceed 400◦C (750◦F),and the speed does not exceed 6,000 rpm [4]. The turbine shown in Figure 8.1 has lubrication consistingof sumps at each journal bearing with oil ring-lubricated bearings. An isolated mechanical–hydraulicgovernor with oil sump is used to control speed.
Figure 8.2 shows a special-purpose turbine for refinery application that meets API 612/ISO 10437specifications. Such units are usually not spared and are used in uninterrupted continuous operationin critical service. They are not limited by steam conditions, power, or turbine speed. The equipment(including auxiliaries) covered by these standards are designed and constructed for a minimum servicelife of 20 yr and at least 5 yr of uninterrupted operation [5]. The turbine shown in Figure 8.2 has lubricationprovided by a circulating oil system console (not shown) providing oil at high volumes to the bearingsand to the servo valve actuator.
8.3 Turbine Design and Construction
The parts of a steam turbine may be thought of as being in four groupings (1) the rotor, or spindle,(2) stationary parts, (3) the governing and trip systems and valves, and (4) auxiliary systems consisting ofthe lubrication system and other components such as the condition monitoring system.
The rotor, depending on turbine type, may consist of wheels mounted on a shaft or may be machinedfrom a solid forging or a forging made up of welded sections. In each case, the rotor carries securelyfastened radial blades or buckets. Principle stationary parts consist of the steam-tight casing, nozzles,shaft seals, and bearings. Turbine governors control speed by controlling steam-admission valves throughmechanical, pneumatic, or hydraulic actuators.
Those parts of the turbine requiring lubrication consist of the bearings supporting the rotor, hydraulicactuators and governor components, and the trip system; and in some cases, a turning gear, gearedcouplings, and front standard. Lubricated parts reside external to the steam path, and when properlyisolated will not contaminate the steam or become contaminated by the external environment. Thelubrication system may be simple reservoirs in the pedestals of ring-oiled bearings, or elaborate circulationsystems, having pumps, coolers, filters, and monitoring devices [12]. Figure 8.3 shows a typical unit of anoil-piping diagram for a turbine, gear, and generator string. Lubricating oil is supplied at two pressuresby an oil console (not shown). Lube oil is supplied at low pressure of 100 to 125 kPa (15 to 18 psig) tothe bearings. High-pressure oil of 1,000 kPa (150 psig) is supplied to the trip and throttle valve, to thevalve actuator, and, if needed, to the governor mechanism. Bearing and coupling housings are part of thelube oil circuit and act to return oil to the reservoir.
FIGURE 8.4 Tilt pad journal bearing. (From Elliott Company. With Permission.)
8.3.1 Bearings
Proper rotor position is maintained by journal and thrust bearings. Journal bearings are used in pairs forradial positioning of the turbine shaft supporting the gravitational load of the shaft. Thrust bearings areused for axial positioning and support thrust loads that arise from steam forces within the turbine case.Thrust bearings are located at the steam end of the turbine opposite the coupling, and are used in pairs toaccept thrust loading in either direction along the axis of the rotor. Steam turbine bearings can be eitherhydrodynamic, rolling element, or magnetic. Hydrodynamic bearings are the most prevalent.
8.3.1.1 Hydrodynamic Bearings
Hydrodynamic bearings are highly advantageous because they suffer little or no wear and have exception-ally long life thereby enabling long periods of continuous operation, often in excess of 5 yr. In addition,the bearings possess dynamic characteristics that allow for vibration control thereby enabling high-speedoperation, and traverse of rotor critical speeds. For this reason, hydrodynamic bearings are the mostcommon type of bearing applied to steam turbines.
Journal bearings are most often of the plain cylindrical, elliptical, multilobed, pressure dam, or tiltpad design. Figure 8.4 shows a schematic of a tilt pad journal bearing. Tilt pad journal bearing designsconsist of several pads arranged in a ring around the shaft with the pads free to tilt about their respectivepivots. Tilt pad journal bearings may include several design variations such as self-aligning features tocompensate for misalignment, and special oil feed and drain configurations for temperature and powerloss control [13,14]. One particular advantage of tilt pad journal bearings is their dynamic characteristicsand inherent resistance to rotordynamic instability, which allows for control of vibration even at highspeeds.
Thrust bearings are usually of the tapered land or tilt pad design. Figure 8.5 shows a six shoe self-equalizing tilt pad thrust bearing. Tilt pad thrust bearings may also have features to compensate formisalignment, as well as special oil feed and drain configurations for temperature and power loss control[15,16].
Hydrodynamic bearings are lubricated with turbine grade oil either by a low-pressure circulating supplysystem or by ring lubrication where appropriate. In low-pressure supply systems, the oil flow is meteredto each bearing by an orifice or other flow-controlling device. The oil flows into the clearance spacingof the bearing where it forms a wedge separating the bearing and shaft surfaces. The oil exits axiallyout the sides of journal bearings; and exits radially and tangentially from thrust bearings. Observationof drain oil flow through sight boxes can be taken as an indication of at least partial flow through thebearing and is often used as a quick indication that the oil pump is running and that the oil supplyis probably sufficient. Oil supplied to the bearings functions as both a lubricant and as a coolant to
FIGURE 8.5 Self-equalizing tilt pad thrust bearing. (From A General Guide to the Principles, Operation andTroubleshooting of Hydronamic Bearings, Publication HB, Kingsbury, Inc., Philadelphia, PA, 1997. With Permission.)
counteract the heat generated by shearing of the oil during operation and conduction from the hotrotor.
Hydrodynamic bearings are limited with respect to minimum film thickness, maximum bearing tem-perature, and peak oil film pressure. These restrictions are inherently related to the load, speed of operation,and design of the bearing [17]. The bearings may be boundary lubricated during startup and turning gearoperation, developing a full film shortly after startup. Operational film thickness is typically 25 to 75 µm(0.001 to 0.003 in.). Bearing metal temperature at the instrumented location may range from less than55◦C (130◦F) for an unloaded inactive thrust bearing up to 130◦C (265◦F) for a bearing operating nearits design limits. Peak oil film pressure is typically 2.5 to 3 times the specific load defined as
P = W
A(8.1)
such that P is the specific load (N/mm2), W is the load (N), and A is the projected area (mm2) [17]. Forjournal bearings, the area is the product of the diameter and length. For thrust bearings, the area is thearea of the loaded surface.
Bearing surfaces consist of a soft metal bonded to a hard metal backing. For North American operation,the soft metal surface is most often an ASTM B23 grade 2 babbitt comprised of 89% tin alloyed withantimony, lead, copper, iron, and trace amounts of other metals. Equivalent specifications can be foundin ISO 4381 as SnSb8Cu4 [18], and Federal Spec Q-T-390 Grade 2. In some cases, an ASTM B23 grade 3babbitt is used. Babbitt bearing surfaces generally cause the least damage to steel shafts when operatedwith inadequate lubrication or with contaminants. Babbitts are good for embedding hard contaminantparticles and for resistance to seizure and galling [19]. In addition, tin-based babbitt is highly resist-ant to corrosion from organic acids and can provide satisfactory operation in the presence of oxidizedand contaminated oils. A disadvantage of babbitt bearing materials is their relatively low compressive,tensile, and fatigue strengths especially at high temperature. To provide additional strength, the bab-bitt surface is cast and bonded as a thin layer to a hard metal backing, which may be steel, bronze, orchromium copper. Steel is the most prevalent and least expensive backing material. Chromium copperis used for its superior thermal conductivity enabling reduced bearing metal temperature. A good bab-bitt bond is critical, and can be inspected by nondestructive ultrasonic testing as described in ISO 4386Part 1 [20].
The journal or thrust collar/disk is usually polished steel with surface finishes not exceeding 0.8 µm(32 µin.) Ra . The rotating element is either an integral part of the turbine shaft or else attached mech-anically to the shaft. Bearing surface materials are normally steel containing less than 2.5% Cr, to prevent
a type of failure known as wire wool [20]. In those cases where 12-Cr shaft material is required due toerosion concerns, a sleeve may be used as the bearing journal or the rotor may be inlaid with an acceptablesteel material.
To supervise the satisfactory and safe operation of turbine bearings, one or more of the followingquantities may be monitored: inlet and drain temperature of oil, bearing metal temperature, drain flowof oil, shaft position, vibration amplitude, oil film pressure, and lift oil pressure.
Bearing metal temperatures are measured using temperature sensors embedded in the bearing backingmetal near the babbitt bond line and bearing surface [21]. High bearing metal temperature can beindicative of potential bearing failure. Bearing metal temperature that rises in an upward trend withoutcorresponding change to load or speed is also indicative of potential bearing failure. There is varyingopinion with respect to metal temperature limitation. In general, the manufacturer’s recommendationshould be followed especially for new equipment lacking in historical data.
Drain temperatures are also useful for identifying problems. Drain temperature of oil is an indicatorof bearing power loss if measured separately for each bearing. It is also an indirect indication of bearinghealth, but not as reliable as bearing metal temperature. For this reason, drain oil temperature is not reliedupon as an indication of safe operation unless the bearings are not instrumented.
Radial and axial shaft position and vibration are measured with noncontacting eddy-current probes.Drastic shaft movement is an indication of bearing distress that occurs with wiping of babbitted sur-faces [22]. Excessively high radial vibration is another sign of potential bearing distress and needs to bemonitored as it may cause babbitt surfaces to fatigue or internal rubs to occur.
Depending on the bearings, hydrodynamic bearing maintenance can consist of inspection, repair, orreplacement. After installation, a lift check should be performed on each journal bearing, and the thrustbearing endplay and rotor axial position should be checked and recorded. These same checks shouldalso be performed prior to bearing removal especially if abnormal bearing conditions were observedprior to shutdown such as high metal temperature or vibration. During visual inspection, the bearingsare examined for signs of wear or distress such as scoring, cracks, pivot fretting or brinelling, heatdiscoloration, electrostatic discharge machining, corrosion, flaking, signs of overheated or contaminatedoil such as varnish deposits, and loss of babbitt bond. The rotor journal and thrust areas also need to beexamined for signs of distress such as scoring. Causes of bearing distress and failure include overloading,insufficient oil flow, insufficient bearing clearance or endplay, excessive overspeed, excessive vibration,and too high inlet oil temperature.
Corrosion failures for tin babbitt bearings are fairly uncommon, but can occur in certain cases. Theformation of hard deposits of tin oxide on tin rich white metal has been a problem with bearings in steamturbines caused by electrolytic action in certain environments such as when the oil contains free waterwith salt in solution [20]. Oil contamination from process gases that originate from the seal oil systems ofdriven units such as compressors can be particularly corrosive and may attack the components found inbabbitt.
8.3.1.1.1 Hydrostatic JackingHydrodynamic bearings may include additional features such as an externally pressurized hydrostaticjacking system. The purpose of hydrostatic jacking is first to reduce the required breakaway torqueduring either start-up or turning gear operation and second to reduce bearing wear during turning gearoperation. Hydrostatic jacking is effective by simply reducing the loading on the bearing surface suchthat it is within acceptable ranges. One manufacturer recommends consideration of hydrostatic jackingwhen the specific load on startup exceeds 1,300 kPa (190 psi) for plain journal bearings, 1,200 kPa(175 psi) for tilt pad journal bearings, and 60% of the maximum load for thrust bearings [23–25]. Theneed for hydrostatic jacking depends on the frequency of start-ups, duration of any baring condition,and available starting torque. Hydrostatic jacking systems are typically designed to lift the rotor off thebearings; however, this is not always practical. Hydrostatic jacking is effective so long as the frictiontorque is acceptable, the loading on the babbitt surface is reduced, and associated wear is negligible.Bearings with hydrostatic lift features require a high-pressure oil system, which typically supplies oil
at 7,000 to 14,000 kPa (1,000 to 2,000 psig). The high-pressure oil is turned off shortly after start-up andturned on during coast down. Lift oil pressure may be indicated by reading the pressure supplied to thelift pocket.
8.3.1.2 Rolling Element Bearings
Rolling element bearings (also known as antifriction bearings) are used where service is not critical or thesteam turbine is spared. These bearings can be used as a complete set to accommodate both radial andaxial loads or are used as a thrust bearing in conjunction with ring-lubricated bearings. Rolling elementbearings are generally less reliable than pressure fed hydrodynamic bearings and are only applied when theymeet specific criteria with respect to their speed and life, which are designated by dN and L10 parameters,respectively. The dN parameter is the product of d , the journal diameter (mm) and N , the rated speed inrevolutions per minute. Operation of dN in excess of 300,000 generally requires oil lubrication. The L10
parameter describes the basic rating life expressed in number of operating hours, or millions of revolutionswith 90% reliability. The latest revised and updated L10 equation considers the bearing design, dynamicload, reliability factor, and life adjustment factor that involves the complex interaction of lubricationconditions, contamination, bearing material properties and other factors [26]. Rolling element bearingsare generally designed and retained in accordance with American Bearing Manufacturers Association(ABMA) standards. The Conrad type or deep groove ball bearing is a typical design. The bearings arelubricated either by grease with protection against overgreasing, or by oil supplied by bath, mist, orjet lubrication. Grease fittings are required to extend outside the machine to permit regreasing duringoperation. Venting is provided to prevent pressure buildup in the housing. One particular disadvantage ofrolling element bearings is that they cannot be horizontally split without reducing their life and degradingtheir performance. As a result, most rolling element bearings cannot be replaced without removing therotor and coupling. Presence of water in oil is particularly detrimental to the life of a rolling elementbearing [27].
8.3.2 Bearing Housings and Bearing Housing End Seals
Bearing housings support and position the bearings such that the rotor is centered in its respect-ive packing bores. These housings are also used to mount vibration monitoring and other conditionmonitoring devices. The steam end bearing housing further encases the overspeed trip assembly;as well as the governor speed sensor, which may consist of a notched wheel and speed pickup, orit may consist of flyweights or other devices. At times, a turning gear is also present. Groundingbrushes may be mounted to the outboard end of the bearing housing to prevent the buildup ofhigh voltage between the shaft and the case, which can damage the bearings through electrostaticdischarge.
Bearing housings also function as a part of the lube oil circuit, keeping oil in while keeping con-taminants, such as steam out. In the case of pressure-lubricated hydrodynamic bearings, the housingsare arranged to minimize foaming through proper design of the drain and vent system to main-tain oil and foam levels below shaft end seals. Proper sizing of drains is important to minimizefoaming.
Bearing housings are equipped with replaceable labyrinth end seals and deflectors where the shaftpasses through the housing to minimize contamination and leakage. Bearing housings and gland seals arespaced to help prevent leaking oil from entering the glands and gland steam from entering the bearings.For ring-oiled bearings, the housings further act as oil sumps and may contain water jackets for coolingthe oil.
Bearings housing oil seals may suffer from oil carburization, contaminant leakage into the seal or oilleakage from the seal. Contaminant leakage into the bearing housing can be a problem when using a vaporextractor on the main oil tank, which creates a slight vacuum in the bearing housings through the oildrain lines. Pressurizing the annulus in the oil seal with a gas purge such as nitrogen or air can assist with
seal leakage. This may also cool the oil seal to prevent carburization. Overheating of the oil seal may alsobe prevented by improvements to the heat guards [28].
8.3.3 Steam Control Valves, Governors, and Control Systems
As shown in Figure 8.6, steam is directed into the turbine steam chest through either a trip or trip andthrottle (T&T) valve. Trip valves are opened by fluid pressure and mechanically closed by spring force.The trip system is controlled by an overspeed governor. A trip due to overspeed or other unsafe operatingcondition causes the solenoid valve to open thereby causing system depressurization and immediateclosure of the trip valve, which shuts off the steam thereby bringing the turbine to an eventual stop.
After passing through the trip valve, the steam is directed through the steam chest, and then throughcontrol valves (also called governor valves). The control valves throttle the steam into a nozzle ringmatching the turbine power to the load thereby controlling speed. The control valves may be operated bymechanical linkage, by bar-lift arrangement (Figure 8.6), by cams, or by individual hydraulic cylinders.Mechanical and pneumatic actuators can be found on the smallest turbines whereas hydraulic actuatorsare required on most other units. Extraction turbines have additional valves located at an intermediatestage in the turbine. Extraction valves may be of poppet or spool type for higher pressure, or of grid typefor controlling large volumes of steam at lower pressure. In each case, the valve actuators are controlledby the main governor.
The main governor operates independently from the overspeed governor. The main governor can beeither a relatively simple system that acts directly upon a steam-admission valve; or a complex system thatmay control speed, extracted steam, and devices separate from the turbine such as a compressor or theboiler. Figure 8.7 shows a mechanical–hydraulic governor with hydraulic actuator. In this case, hydraulicaccumulators are used to supply the high volume of fluid that is required for rapid control action duringsudden changes in load. To achieve the high force levels required in multivalve applications, the governortypically controls a servo (prepilot or slave) to a master pilot that controls the flow of high pressure oil toa large piston as shown in Figure 8.7. The assembly of servo, pilot valve, and piston is called a servomotor.In such a control system, a few ounces in governor force can be multiplied through a hydraulic mechanicaladvantage to generate the thousands of pounds of force that may be required to operate the turbinegovernor valves [29].
Required hydraulic oil pressures typically range from 350 kPa (50 psi) on small turbines to 18,000 kPa(2,600 psi) on very large turbines [30,31]. Turbine oils are typically employed at pressures below 2,000 kPa(290 psi) whereas fire-resistant fluids are often used at pressures exceeding 2,000 kPa and in installationswhere steam pipe temperatures exceed the auto-ignition temperature of turbine oil, particularly in powerplant applications [30].
The governor and actuator control system may be supplied from the same lube system as the bearings ormay be fed independently from a separate system. In small turbines, hydraulic and mechanical–hydraulicgovernors are often self-contained units featuring a shaft driven oil pump, and an oil sump with sightglass for determining the oil level. In medium sized turbines, typical of process industry applications, thecontrol system is normally fed off the same lube system as the bearings. In large power plant turbines, twoseparate circulating systems are usually employed: one for the bearings using turbine oil and one for thecontrol system using a fire-resistant phosphate ester fluid.
Control systems have long had high visibility due to reliability and maintenance shortcomings. Largequantities of mechanical components such as pins, links, levers, rod end bearings, hydraulic relays, springs,gearing, and flyball governor assemblies are present and subject to wear. The use of electronic speed sensorsand electronic governor controls has enabled the elimination of some wearing mechanical parts, and hasimproved control and flexibility through use of noncontacting pick-ups and nonmechanical feedbackcircuits. Actuators have remained primarily hydraulic due to the large forces and quick response timerequired.
Governor maintenance depends considerably on the type of governor in use, and the manufacturer’srecommendations should be followed. The proper oil must be selected, and it must be kept clean, dry, and at
the proper level and temperature. Water contamination, even in trace amounts, contributes significantlyto early failure as well as forming oxides that also contribute to failures. As noted by one governormanufacturer, dirty oil causes most governor/actuator troubles [32]. Oil contamination and degradationis particularly problematic on self-contained sump units that do not have oil conditioners.
Other parts of the governing system must also be maintained. Governor valves and linkages must befree from binding or sticking. Valve sticking may be related to steam impurity, which may lead to depositson the valve stem [33], or it may be related to oil contamination causing deposits or corrosion in tightclearance hydraulic components [34], which may have clearance as small as 5 µm. Hydraulic actuatorsmay operate on the valves through a linkage. Loose or worn linkage components can cause unacceptablegovernor control. Linkage bearings are usually hand-oiled or greased. Some, however, are made fromlow-friction materials, which may require little or no lubrication.
8.3.4 Turning Gear
High-temperature steam turbines are sometimes equipped with a turning gear to prevent bowing of therotor when at rest, especially after shutdown. The need for a turning gear depends upon the probability ofrotor bow, which is related to the steam temperature, shaft diameter, and bearing span. Turning gears areprimarily found on large turbines with long bearing spans, though they are sometimes needed for smallturbines as well to allow for oil circulation through the bearings during cool down. The turning gear isoperated prior to turbine run-up and immediately after shutdown. Turning gears are electric motor drivenwith a means for disengagement such as a clutch or retractable gear. The turning gear motor is typicallygrease lubricated whereas the actual turning gear and bearings are lubricated with oil supplied from themain circulation system. A separate, relatively small, motor-driven oil pump is generally provided tosupply oil to the bearings of the turning gear system. The auxiliary oil pump, which backs up the main oilpump, may also be used for this service. During turning gear operation, oil inlet temperature may be keptcool to increase oil viscosity thereby maintaining a thick oil film in the turbine bearings during low-speedoperation.
8.3.5 Couplings
Couplings are used to connect the steam turbine to the driven equipment. They are made from corrosion-resistant or coated materials. Couplings can be either rigid or flexible. Rigid couplings are essentially twoflanges bolted together. Such couplings require no lubrication, but do not readily accommodate changes tomachine position, which can be caused by thermal expansion of the equipment, foundation settling, andstrain due to loading. Flexible couplings accommodate some misalignment; however, their use does notpreclude the need for proper machine alignment of both the turbine and driven equipment [6]. Flexiblecouplings are described by a number of standards such as API 671, ISO 10441, and MIL-C-23233A.
For turbine applications, special attention may be required with respect to machinery alignment due tothermal expansion. Quill shafts, membrane couplings, and contoured disc couplings run dry and withoutlubrication and are often preferred for their low maintenance. Gear couplings must be lubricated.
8.3.5.1 Gear Couplings
Gear couplings can be advantageous because of their light weight and minimal required overhang, andbecause they allow for maximum axial movement between turbine and driven equipment shaft ends ascaused by expansion of various parts under hot conditions [35]. In general, however, the need for lubric-ation and maintenance means that geared couplings are seldom used in new turbine applications thoughthere is still a considerable population of geared couplings that must be maintained. The life of a gearedcoupling is primarily dependent on alignment and lubrication. The majority of geared tooth couplingfailures are due to improper or insufficient lubrication [36]. Gear coupling lubrication is complicatedby the centrifugal effect that a spinning coupling has on lubricants. Packed lubrication with grease canonly be applied at relatively low speeds since the thickener tends to separate out of the grease under high
centrifugal force [37]. Packed lubrication with either grease or oil may require lubricant replenishmentat 6 to 12 month intervals [38]. Typical grease used for high-speed geared coupling is NLGI #1 or #2grade with R&O inhibitors. Greases that are specifically formulated for high-speed coupling applicationuse thickeners, which have a density closer to that of oil [39]. These formulations resist separation due tocentrifugal effects. Special grease formulations can also extend replenishment intervals beyond the 6 to12 months typically cited. A test method for evaluating grease separation is ASTM D4425. In this test, thegrease is subjected to 36,000 G centrifugal acceleration at 50◦C for a period of at least 6 h. Results fromthe test are presented as
K 36 = V /H (8.2)
where V is the oil separation in volume percent, and H is the accumulated time of testing in hours.High speeds and low maintenance in gear couplings require the use of continuous lubricant feed at
each hub that is provided by either oil spray or jet using filtered oil piped from the system bearing oilsupply. Coupling teeth for such applications are often hardened usually by nitriding [39].
Lubricants must be carefully selected with additives that resist separation from centrifugal force. Oiladditives, in particular silicone antifoam compounds, can separate out of the lubricating oil and formsludge [40]. The coupling lubricant must also resist reaction with metal particles that may exist in thecoupling due to wear [41]. Such measures are unnecessary when using dry couplings.
The coupling housings provide safe enclosure of the coupling. Coupling housings may also act as partof the lube oil system. The housings are oil tight and include provision for coupling lube oil supply ifneeded and drainage back to the reservoir. The drains also handle any oil that may be carried over fromthe coupled equipment and are consequently featured on housings for both dry and lubricated couplings.A filter breather is attached to the coupling housing to allow proper drainage or the housing is connectedto the bearing oil vent system of the equipment train. Regardless of the type of coupling used, properdesign of coupling housings is important due to windage losses, heat generation, and potential for oilleakage from the joined equipment [42].
8.3.6 Additional Tribological Components and Issues
Several components outside of the lubricating oil circuit require batch lubrication and special materialconsideration to limit wear and corrosion. Among these components is the turbine casing and steampatch components. Gland seals may also be subject to wear and have considerable effect upon watercontamination of the lubrication system.
8.3.6.1 Casings
Steam casings expand and contract due to changes in casing temperature caused by the use of hightemperature steam. Thermal movement is typically accommodated at the steam end by either a flexiblesupport or sliding pedestals. Sliding pedestals are most common on large turbines and rarely used onsmall and medium sized units. Sliding pedestals may operate dry, or they may be lubricated by eithergrease or oil depending on the load, temperature, and expansion. The use of lubrication reduces frictionthereby allowing casing thermal expansion without binding. Binding of the casing can cause distor-tion, misalignment, and vibration. Grease lubricated casing supports are often used for large centralstation steam turbines. Grease may be supplied by either a common system or grease gun. The typeand application should follow the manufacturer’s recommendation. NLGI number 1 or 2 grease ofsodium, lithium, or sodium–calcium soap base have been used for lubricating sliding pedestals; in addi-tion a mixture of graphite and cylinder or turbine oil mixed to a paste consistency has also been used[43]. Problems associated with grease separation have been noted on high temperature, heavy turbinesused in central station applications due to the high temperature and heavy loads associated with theseapplications [44].
Parts that are located in the steam path consist of the steam chest, rotating blades, stationary nozzles,diaphragms’, seals, valves, and valve guides. These parts have tribological issues that must be solvedwithout lubrication, which would contaminate the steam. Stationary nozzles and rotating blades aredamaged by erosion and corrosion mechanisms. Turbine blades in particular suffer the most damage inturbines resulting in loss of power, efficiency, or operation. There exist many causes for wear throughthe steam path; however, three mechanisms are prevalent. These are (1) moisture impingement erosion,(2) erosion–corrosion, and (3) solid particle erosion.
Moisture impingement erosion is caused by the presence of water droplets in the steam. When turbineblades operate in wet steam, the moist steam may cause blade erosion. Erosion is dependent on speedof the rotating blade, wetness of the steam, and blade design. Blade velocities can exceed 250 m/sec(825 ft/sec) at the tip. Moisture impingement erosion has been noted to be particularly problematic in thefinal stage of long multi-stage low-pressure turbines due to condensation. Allowable wetness is related tosteam conditions, blade velocities, and design. In some cases, there is no need for a moisture limit. In othercases, 8% [45], 12% [46], or other moisture limit is used depending on the application. Moisture erosionalso effects seals and can lead to degradation of performance and changes to the thrust loading [47].
Erosion–corrosion problems are caused by reactive steam chemistry. Steam of insufficient purity maycause deposits on the casing, nozzles, blades, seals, and sealing surfaces. These deposits may containcorrosive agents such as chlorine, which can attack the material used on these components. This resultsin eventual pitting and stress corrosion cracking [48]. Geothermal steam applications are known to haveparticularly corrosive steam with constituents of silica, sodium, ammonia, calcium, and sulfate. Theacidity of geothermal waters can be very high with pH as low as 1.8 [49].
Solid particle erosion (SPE) is caused by entrainment of erosive materials in the steam. Solid particleerosion is traceable to exfoliated material coming from the boiler tubes, and in some cases, the steam leads.This type of erosion appears to be related to both the size of the unit and the pressure being employed.The solid particle erosive mechanism is most prevalent on large central station utility turbines; and it israrely observed on small turbines operating under 540◦C (1000◦F) [50].
An important factor in each of these erosive wear mechanisms is the condition of the steam. For thisreason, steam conditioning may be used for ensuring reliable operation. Monitors have been developedto quantify the particle loadings from the boiler [46]. Various separators and moisture removal devicesmay be employed upstream and inside of the turbine. Strainers are used to remove the largest particlesand trap foreign objects. Some recommendations for steam purity are specified by NEMA for low-pressure turbines relating to the amount of dissolved solids, alkalinity, conductivity, and content ofsilicon oxide, iron, copper, sodium, and potassium [6]. Original equipment manufacturers also providesteam purity recommendations. Design methods for combating erosive wear include the use of eitherhardened materials or hard coatings such as Stellite on turbine blades. Stainless steels such as 12%chromium steel are also used. For turbine nozzles and internals, chromium steel cladding may be used[50]. Corrosion-resistant coatings have also been developed for this service.
Other forms of wear and degradation internal to the steam path also exist. Turbines that are not inoperation can experience a form of corrosion known as stand-by corrosion [45,49]. The corrosion is dueto steam leaking into the turbine past a valve, which is not tight. Once the steam has leaked into theunit, it can condense and corrode the unit. This type of corrosion may cause severe pitting on stainlesssteel buckets. Brown specs (known as tubercles or scabs) form on carbon steel parts, such as discs anddiaphragms [46]. It is therefore important that idle turbines have the inlet valve tightly seated and that allthe casing drains be open [49]. Additional measures such as an additional drain between the turbine andsteam inlet valve, and blanketing turbine internals with a positive flow of dry gas along with running thelubrication system and rotating the journals have also been performed [43].
8.3.6.3 Seals and Gland System
In order to maintain efficiency and performance, seals are required to limit steam leakage from the turbinecase and between each stage. Casing end seals, also referred to as packing seals, are provided where the
shaft ends pass through the casings. They are used to seal against the leakage of steam to atmosphere, andto seal against air suction into the low-pressure condensing case of condensing turbines. The seals may becarbon ring, labyrinth, or noncontacting mechanical design.
Properly functioning gland seals are important for maintaining turbine performance. Improperlyfunctioning gland seals can cause excessive steam leakage, which may ingress into the bearing housingleading to oil contamination. Likewise, a loss of vacuum on condensing turbines can also cause excessivesteam leakage past the gland seals. Gland leakage does not have to be visible to cause a problem.
8.3.7 Driven Units
Driven units such as gears, compressors, and generators create additional complexity to a lube oil system.Many of these units will have similar requirements to the turbine with respect to journal and thrust bearinglubrication. The oil selected for a common lube oil system must be suitable to all the pieces of equipmentto be supplied. Low-viscosity rust and oxidation inhibited (R&O) oils, commonly called turbine oils,are used in many high-speed gear units where the gear tooth loads are relatively low [51] and the highentraining velocity of the gear develops thick elasto-hydrodynamic (EHD) oil films. Slower speed gears,as used for propulsion, tend to be more heavily loaded. These gears generally require higher viscositylubricants with antiscuff additives [51]. High-pressure oil seals, as used in compressors; and hydrogenseals, as used in generators, can cause contamination of the seal oil by gas such that natural or vacuumdegassing is required [31]. In some cases, a separate, isolated, lube oil system is used to provide seal oildue to potential contamination of the lubricating oil [52].
8.4 Lube Oil Systems
Lube oil systems may be classified as either nonpressurized or pressurized systems. Nonpressurized lubesystems consist of ring lubrication and are common on very small steam turbines. Larger turbines usepressurized lubrication.
8.4.1 Nonpressurized Oil Ring Lubrication
Ring-lubricated hydrodynamic bearings are used where service is not critical or the steam turbine isspared. These bearings have the advantage of not requiring an external lube oil system thereby enablingsteam turbine application where initial cost is a primary concern.
Figure 8.8 shows an oil ring-lubricated journal bearing. The oil ring lubrication system employs metalrings to deliver oil to the turbine bearings. The rings are rotated by the journals carrying oil from asump below the bearings to the top half bearing liners where it is fed into the clearance between thebearing liners and the shaft journals. Oil is drained from the ends of each bearing liner and returnedto the bearing housing reservoirs to be cooled. Some of the supplied oil may be used to feed a rollingelement bearing that is normally required in conjunction with ring-lubricated journal bearings for thrustpositioning. The use of ring-lubricated bearings is limited with respect to load capacity, journal rotationalspeed, and by the need for cooling.
Bearing housings may be double walled to allow water circulation to remove heat from the oil bath.Under conditions of high inlet steam temperature, the bearings can be damaged after shutdown becausethere is no longer oil circulation to carry heat away from the shaft, and a turning gear is sometimes usedto continue the rotation of the shaft and subsequent oil ring lubrication.
Ring-lubricated bearing housings are equipped with constant-level sight-feed oilers that maintain aconstant reservoir oil level. A permanent indication of the proper oil level is clearly marked on the outsideof the bearing housing. Low oil level in the housing will cause inadequate bearing lubrication. Excessivelyhigh oil levels can also be detrimental as it may restrict oil ring rotation also causing inadequate bearinglubrication. Housings for ring-lubricated bearings are provided with plugged ports positioned to allowvisual inspection of the oil rings while the turbine is running.
FIGURE 8.8 Ring-lubricated journal bearings. (From Installation, Operation, and Maintenance Instructions for YRTurbines, Elliott Company, Jeannette, PA, 2003. With permission.)
TABLE 8.2 Lube System Design and Procurement Standards
Standard designation Standard title
API 614 Lubrication, shaft-sealing, and control-oil systems and auxiliaries for petroleum, chemical,and gas industry services
ASTM D4248 Design of steam turbine generator oil systemsASTM D6439 Standard guide for cleaning, flushing, and purification of steam, gas, and hydroelectric turbine
lubrication systems
8.4.1.1 Ring Lubrication System Maintenance
Proper oil level should be maintained at all times. Since oil ring lubrication systems have no means offiltering solids from the oil or removing water, periodic sampling and frequent oil changes are necessary toensure a clean oil supply. The range of cooling water temperature must also be controlled to ensure goodheat transfer without promoting condensation in the oil sump. To avoid condensation, the minimuminlet water temperature to the bearing housings should preferably be above the ambient air temperature.
8.4.2 Pressurized Lubrication Systems
The pressurized lubrication system is essentially a closed loop system designed to provide an uninterruptedsupply of cooled and filtered oil at the proper pressure to the bearings, control-oil system, shutdown system,and other components such as continuously lubricated couplings, as well as gears and seals on adjoiningequipment.
Oil consoles vary widely depending on the make, size, type, and purpose of the turbine and its adjoiningequipment. Lubrication systems are designed according to the application, which may require the use ofdesign standards such as those shown in Table 8.2. Proper lube system design is vital to machine reliability.
A typical system is shown in Figure 8.9 and Figure 8.10. The oil is taken from the reservoir and passedthrough a cooler then filtered. The flow is split into two legs. One leg delivers high-pressure oil to a
FIGURE 8.9 API 614 lube oil console. (From Elliott Company, Jeannette, PA. With permission.)
common header for the governing and control mechanisms. A second leg delivers reduced pressure oilto a common header for the bearings. Bearing oil pressure is typically 100 to 125 kPa (15 to 18 psi), butmay range from as low as 55 kPa (8 psi) in some systems to 345 kPa (50 psi) in others. Oil from thebearings and governor mechanisms will drain back to the reservoir. Figure 8.10 shows the following majorcomponents:
• Oil reservoir• Pumps and drivers• Filters• Coolers• Control valves• Piping
Additional accessories may include relief valves, transfer valves, accumulators, and instrumentationas shown in Figure 8.10. Not shown is the oil conditioning hardware. Each of the major components isdescribed briefly along with instrumentation, commissioning, and system maintenance.
8.4.2.1 Oil Reservoir
The reservoir is usually of rectangular shape, carbon steel construction with an interior coating of rustproofing paint. Solid stainless steel or stainless steel clad construction is also used. Normally the reservoirwill have a sloping bottom to drain, clean out manways, gasketed openings, fill opening with strainer, oillevel sight gage, and vent with weatherproof breather.
The various oil levels as defined in the reservoir are shown in Figure 8.10. Depending on designrequirements, the reservoir is sized to contain an amount of oil for anywhere from 3 to 5 min workingcapacity as measured from the minimum operating level. Large reservoir capacity enables disengagementof entrained air or gas and the settling of water and solid contaminants. A high and low oil-level indicatorand alarm are usually provided. A free oil surface in the reservoir of at least 0.37 m2/lps (0.25 ft2/gpm) ofoil is required to enhance air disengagement from the oil [53]. In addition, the oil reservoir is designedwith a sloping bottom (1 unit in 24) such that supplementary water and dirt can accumulate at the areaof the low point drain, and thus be drawn off during operation.
Most pressurized lubrication systems are constructed with some provision for ventilation althoughsome systems enjoy satisfactory operation with no such provision. Effective ventilation of the lubricationsystem enables the reduction of moist air that affects the service life of the turbine oil. The provision ofadequate ventilation is also helpful in reducing foaming where trouble from this source is encountered[54]. The following methods of ventilation are commonly used: Natural ventilation, vacuum ventilation,or dehumidifier system [54]. Figure 8.10 shows a system equipped with a vapor extractor. The extractorpulls a slight negative pressure that should result in no more than −0.5 kPa (−0.07 psi) in the bearinghousing to keep oil vapors from escaping, but without pulling in atmospheric contaminants.
Reservoirs normally have a connection for an oil conditioning system. Such oil conditioners can providefurther purification by removing water, acids, and other contaminants not removed by the filters. Theseare discussed in more detail under oil maintenance.
8.4.2.2 Pumps and Drivers
Two or more oil pumps are normally supplied with the lube oil system. One pump is considered the mainoil pump and the other, the auxiliary. The pumps are sized with additional flow capacity to provide apositive flow of oil under all normal operating conditions and most abnormal conditions to the turbineand the driven equipment. Additional smaller pumps may be used to supply oil for special purposes suchas turning gear operation; hydrostatic lift oil for highly loaded bearings; seal oil for hydrogen-cooledgenerators; or oil transfer through filters [28]. Positive displacement pumps have relief valves located ateach pump discharge line to protect the pumps and system against excessive pressure.
The main oil pump can be driven off the main turbine shaft, by an electric motor, or by a small steamturbine. Most often, the auxiliary oil pump is driven from a different source of power than the main oilpump. The auxiliary pump driver is selected to reflect availability of power or steam under emergencyconditions. Should the main pump fail, the auxiliary pump will automatically start. If the pressurecontinues to drop, the turbine and driven equipment will shut down. Emergency situations where bothpumps fail are handled by either an emergency oil pump sized to provide last-resort lubrication forcoastdown or a rundown tank that provides lube oil by gravity flow. Rundown tanks are common inmarine applications.
On lube systems where the auxiliary oil pump is driven by a small steam turbine, an accumulatoris incorporated into the system. The accumulator will maintain the required oil flow while the turbine(auxiliary pump driver) is accelerating to speed preventing a system shutdown in case of main pumpfailure.
8.4.2.3 Filters
Twin filters with multiple cartridge filtering elements are normally used in the lubricating oil system.Filters are operated in the full-flow mode such that all oil being circulated to the turbine passes throughthe filter. Using two filters permits filtering element changes while the equipment is in operation. Filtrationratings should be a minimum of 25 µm, and filtration of 10 µm is typically required. Filters are sizedfor a maximum pressure drop of 35 kPa (5 psid) when clean and passing oil at the design temperature.Filtering elements are typically replaced when pressure drop reaches approximately 100 kPa (15 psid)above original clean value [55].
The effect of water on the filter must be considered. Water and corrosion-resistant filter cartridge mater-ials are preferred. Such water-resistant filter cartridges should not deteriorate even if water contaminationreaches 5% by volume and an operating temperature as high as 70◦C (160◦F).
Depth type elements (e.g., cotton and nylon) can suffer from a phenomenon termed“cartridge erosion,”where oil velocity enlarges or erodes the filter passages over time, which effectively invalidates the filtrationrating of the element [55]. Cartridge erosion problems are eliminated by conservatively replacing filterelements every 6 months. Filters are also replaced if the pressure drop from clean increases by 100 kPa(15 psid). Recommendations of the filter element manufacturer should be considered.
Oil coolers are usually conventional shell and tube heat exchangers with removable tube bundles. Normally,water flows through the tube bundle thus allowing for easy waterside cleaning. Oil flows through the shellside in a single pass. Coolers are usually operated so that the oil is at a higher pressure than the water,thus, reducing the severity of water contamination caused by tube failure. Typical cooling requirement isto cool oil to 120◦F. Where conditions do not lend themselves to water-cooled heat exchangers, such asdesert or subzero installations, air blast oil coolers must be considered. Coolers may be used for heatingduring initial oil system installation and cleansing and it is important that the system be designed for suchuse if desired [56].
Problems with maintaining oil temperature could be caused by improper venting, malfunctioningtemperature regulators, incorrect water pressure, or badly fouled coolers [28]. Tube failure may be causedby fatigue and erosion. Excessive water flow can cause flow-induced vibration of the cooling tubes, butmaintaining proper flow will reduce fatigue related problems. Water treatments and sacrificial anodesare used to retard corrosion failure of the cooler [56]. Cooler failures are responsible for the worst watercontamination of the turbine oil.
8.4.2.5 Control Valves
The backpressure regulator is designed to maintain a constant header pressure for all operating conditions.Normally, it is a self-operated valve, but where wide control ranges are required, pneumatic regulatorscomplete with valve positioners are used.
In addition to the backpressure regulator, pressure-reducing valves are required for all pressure levelsbelow main header pressure. These valves are normally self-operated reducing valves but where widecontrol range is required, pneumatic operators complete with valve positioners may be furnished.
8.4.2.6 Piping
Lubrication system components are joined together by the necessary piping to make the system func-tional. This includes provisions for the mounting of control instrumentation, such as pressure gauges,temperature gauges, switches, and monitoring and safety devices. Piping may be either carbon or stainlesssteel. Stainless steel is preferred due to superior corrosion resistance and is used extensively in refineryapplications.
The header piping connects the lube oil console to the various components being lubricated, such asbearings and seals. Used oil is returned to the reservoir through drain piping. Oil drains are sized to runno more than half full when flowing at a velocity of 0.3 m/sec (1 ft/sec) and are arranged to ensure gooddrainage. Horizontal runs slope continuously, at least 40 mm/m (1/2 in./ft), toward the reservoir [57].
8.4.2.7 Safety and Monitoring Devices
Lubrication system instrumentation is located throughout the system as shown on the schematic oil flowdiagram. Monitoring devices, such as pressure gauges, safety devices, and alarm and trip switches aregenerally mounted on header piping close to the components being lubricated. A low-pressure start-upswitch signals the auxiliary pump to start if pressure is too low. Temperature indicators are provided atbearing and seal outlets and at the inlet and outlet of coolers. Pressure indicators are generally provided ateach pressure level. A sight-flow indicator is provided at the outlet of each turbine shaft bearing and eachturbine thrust bearing.
8.4.2.8 Cleaning and Flushing
All reasonable effort must be made to limit the introduction of contaminants into the lube oil systemduring construction. Proper cleaning and preservation of lube system components must be performedprior to system shipment. Different preservatives are used depending on the environment and expectedstorage time [58].
All units employing forced-feed oiling systems should have the entire lubrication system thoroughlyflushed before operation. The importance of this step cannot be overemphasized. All dirt, rust scale, weld
slag, or other contaminants that have been introduced into the oil system during storage, transportation,and fabrication at the jobsite must be removed by a continuous flushing operation or in extreme cases thatdo not involve stainless steel pipe, by pickling and cleaning. In addition to flushing during the commis-sioning, the system should also be flushed if left idle for a long time. Most turbine manufacturers providespecial instructions for the oil flush. In the absence of such instructions, industry recommendationsshould be consulted such as those detailed in ASTM D6439 [59] or API RP 686 [58]. Flushing the systemmay require the use of external pump and such preparations should be made in advance. The bearingsand bearing area should be bypassed until the system is proven to be clean. The flushing should continueuntil the required cleanliness is achieved based on inspection of the flushing filters or strainers, patch test,particle counters, or ISO 4406 cleanliness level.
Flush oils, operating oils, and preservative oils must be compatible to preclude foaming, formation ofemulsions, or breakdown of oil additives. Compatibilities and limitations may generally be obtained fromthe oil supplier. A system that is to use phosphate ester fluids must be flushed with phosphate ester fluidsince such fluid is incompatible with mineral oil. The same may apply to other synthetic oils.
8.4.2.9 Lube System Maintenance
Lube systems must be periodically inspected and maintained to ensure their proper operation. As aminimum, the following regular checks should be performed:
• Check filter pressure drop and replace elements as recommended.• Check the oil reservoir level and add oil as required.• Periodically check operation of auxiliary oil pump by operating pump and returning to
auxiliary duty.
In addition, turnaround maintenance of the lube oil system should be performed at 1 to 3 yr intervals, asnormal plant maintenance permits. Care must be taken to keep contaminants out of the lube oil circuitduring bearing changes, filter changes, top up, and other maintenance activities.
8.5 Turbine Oil
Equipment vendors often have turbine oil standards detailing the minimum characteristics required forsuccessful turbine operation. In the absence of such standards, an internationally recognized turbines oilspecification such as shown in Table 8.3 should be used.
8.5.1 Physical Properties
Turbine oil performs four functions (1) Lubricate bearings and gears; (2) cool lubricated parts, carryingheat away from hot surfaces such as bearings and shafts; (3) act as a hydraulic fluid for governor, controlvalves, and safety devices; and (4) act as a sealant for gas seals such as hydrogen shaft seals in generatorsor gas seals on compressors. Each of these functions require an oil that is suitable with respect to severalphysical, chemical, and performance properties. Some physical properties frequently used to character-ize turbine oils with corresponding American Society for Testing and Materials (ASTM) test methods
TABLE 8.3 Standards for Turbine Oils and Hydraulic Fluids
Standard designation Standard title
ASTM D4293 Standard specification for phosphate ester-based fluids for turbine lubricationASTM D4304 Standard specification for mineral lubricating oil used in steam or gas turbinesISO 8068 Petroleum products and lubricants — petroleum lubricating oils for turbines (categories
ISO-L-TSA and ISO-L-TGA)MIL-PRF-17672D Performance specification: hydraulic fluid, petroleum, inhibitedMIL-PRF-17331H Performance specification: lubricating oil, steam turbine and gear, moderate service
Physical or ASTM ISOchemical property designation designation Purpose
ISO viscosity grade D2422 ISO 3448 Overall viscosity classificationKinematic viscosity at 40◦C, 100◦C D445 ISO 3104 Relates to viscosity at normal operating conditionsViscosity index D2270 ISO 2909 Empirical comparison of viscosity and temperature
characteristicsPour point D97 ISO 3016 Measures low temperature flow propertiesFlash point D92 ISO 2592 Low value indicates volatile componentsTotal acid number (TAN) D974 ISO 6618 Determination of acidity of new and used oils by
titration with KOHFoaming characteristics D892 ISO 6247 Foaming characteristics of lubricating oilsAir release D3427 DIN 51 381 The oil’s capacity to separate entrained air over a
period of timeWater separability (Demulsibility) D1401 ISO 6614 Emulsion characteristics of oilRust prevention D665 ISO 7120 Ability of oil to prevent rusting of steel surfaces in
presence of waterCorrosiveness to copper D130 ISO 2160 Indicates tendency of oil to corrode copper and
copper alloysOxidation stability (TOST) D943 ISO 4263 Oxidation stability of mineral oilsRotating pressure vessel oxidation
test (RPVOT)D2272 Tests remaining oxidation life of in-service oils
Acid number D664 ISO 6619 Indicates acid levelKarl Fischer titration D1744 ISO 6296 Measures the water content of oilColor D1500 ISO 2049 Measures colorISO cleanliness code ISO 4406 Measures oil cleanliness
are summarized in Table 8.4. Detailed descriptions of the ASTM methods are available in the ASTMHandbook [59].
The most important physical property is viscosity. Table 8.5 gives the viscosity ranges for typical minerallubricating oils used in steam turbines. Typical viscosity grade numbers are ISO-VG-32, VG-46, VG-68,VG-78, and VG-100 such that the viscosity grade numbers indicate the average oil viscosity in centiStokeunits at 40◦C (104◦F). In order to reduce the power losses at the bearings and improve the responsivenessof hydraulic components, the lowest acceptable lubricant viscosity is normally selected. As a result, theusual lubricant employed in a common oil system is ISO VG-32 turbine oil cooled to a supply temperatureof 120◦F after the cooler. Other viscosity grades are also used. ISO VG-46 turbine oil cooled to a supplytemperature of 140◦F after the cooler is commonly used in desert, arid, and offshore applications whereair blast coolers are utilized, or where the ambient temperature is quite high [56]. Oils used for ring-oiled turbine bearings tend to be higher viscosity such as ISO VG-68 or VG-100. Oils used for shipboardpropulsion may be ISO VG-68 to VG-100 and may have mild antiscuff additives. It is important to notethat the lube oil system and the turbine rotordynamics are designed considering a specific oil viscosity.Turbine lube systems must be maintained with lubricants of the recommended viscosity, and the viscosityspecification should not be changed without proper engineering review.
8.5.2 Formulation
To achieve the desired physical, chemical, and performance properties, turbine oil is formulated with abase fluid and additive package consisting of rust and oxidation (R&O) inhibitors. Steam turbine oilsare essentially special grades of R&O oils, formulated to give better oxidation resistance and longer lifein a steam turbine [60]. While industry standard lube oil bench tests can provide great insight intothe performance and life expectancy of turbine oils, both turbine original equipment manufacturers(OEMs) and oil suppliers generally agree that past successful performance of a particular oil under similarconditions is the best overall representation of quality and performance [61].
Foaming characteristics D892Sequence 1, mL max. 65/0 65/0 65/0 65/0Sequence 2, mL max. 65/0 65/0 65/0 65/0Sequence 3, mL max. 65/0 65/0 65/0 65/0Air release 20 D3427Water separability 40/40/3 40/40/3 40/40/3 40/—/3 D1401Oxidation stability, min. 1000 h 1000 h 1000 h 1000 h D943
8.5.2.1 Base Oil
The base oil stock of a turbine oil comprises more than 98% of the formulation. The base oil is categorizedas either conventional solvent refined mineral-based (API Group I), or hydroprocessed mineral-based(API Group II) oil. Group II base oils contain fewer heteroatoms (sulfur, nitrogen, oxygen), and haveless aromatic content than Group I base oils. When properly formulated, Group II turbine oils willhave longer oxidation life, less deposit forming tendencies, improved water shedding ability, and overallhigher performance than do Group I turbine oils [60]. One advantage of the conventional mineral-based(Group I) turbine oils is better innate solvency than the hydroprocessed (Group II) oils. The better solvencyof the Group I turbine oils provides better additive package retention and increased ability to dissolveoxidation products that could otherwise potentially lead to varnish and sludge. While Group I and Group IIbase stocks are compatible with each other, the additive packages used to formulate the respective turbineoils may be incompatible with the overall mixture. Mixing oils can therefore cause sludge formation andadditive dropout [62]. For this reason, compatibility between products is an important considerationwhen mixing two oils.
8.5.2.2 Additives
Additives are used to improve the performance of the oil. Although additives are to some extent con-sumed in performing their functions, they can be replenished through normal lubricant make-up therebyenabling suitable performance for longer periods. Note that newer machine designs offer less oil loss andtherefore do not benefit as much from this effect as did older machines exhibiting greater oil loss. Themain types of additives include oxidation inhibitors, rust inhibitors, foam inhibitors, and demulsifiers.
8.5.2.2.1 Oxidation InhibitorsAntioxidants are the additives, which have the strongest influence on the useful life of turbine oils. Theygenerally function either by free radical inhibition, by hydroperoxide decomposition, or by deactivationof metal catalysts. The two major types of antioxidants used in turbine oils are arylamines and hinderedphenols [63], and they work as free radical inhibitors. A mixed phenol-amine has certain advantages overthe use of a single antioxidant system. Other additives and combinations of additives are also used tosuppress oxidation. In particular, metal deactivators are used to suppress oxidation by reacting with metalions and surfaces to inhibit their catalytic activity [64].
8.5.2.2.2 Corrosion InhibitorsHighly refined oils lose their metal-wetting ability and are easily displaced by water. For this reason,corrosion inhibitors are necessary to prevent corrosion. New turbine oils contain a rust-inhibitor additiveand must meet ASTM Test Method D 665. These corrosion inhibitors typically work based on the physicaladsorption principle. In action, the corrosion inhibitor “plates out” on surfaces, forming a film that resistsdisplacement by water and, therefore, protects the surfaces from contact with water [65]. Corrosioninhibitors used in turbine oils are polar and thus susceptible to water washout. Alkenyl succinic acids aretherefore widely used due to their resistance to water washout [66].
8.5.2.2.3 Foam InhibitorsFoam additives must be carefully selected in order to prevent excessive foam formation, but still retainshort air release times [67]. Highly refined hydrotreated base oils have lower foaming tendencies thanconventionally refined base oils. Foam inhibitors work by decreasing the gas-lubricant interfacial ten-sion. Liquid silicones are an effective antifoamant, but also act as an air-emulsion stabilizer, negativelyinfluencing the air release properties of the turbine oil as it resides in the stilling portion of the equipment.
8.5.2.2.4 DemulsifiersDemulsifiers destabilize oil–water emulsions by changing the interfacial tension of oil and water therebyallowing their separation [64]. Conventional mineral-based (Group I) turbine oils usually contain demul-sifying additives whereas hydroprocessed (Group II) turbine oils have good demulsibility without anadditional additive.
8.6 Performance Features of Turbine Oils
The following oil performance features must be retained to ensure safe and continuous operation ofthe turbine (1) viscosity; (2) oxidation stability; (3) freedom from sludge; (4) anticorrosion protection;(5) water separability [68]; and (6) air separability and resistance to foaming.
8.6.1 Viscosity
Viscosity is measured by ASTM Test Method D 445. Viscosity is the most important characteristic ofturbine oil, as the oil film thickness under hydrodynamic lubrication conditions is critically dependent onthe oil’s viscosity characteristics. Viscosity also affects journal bearing stiffness and damping properties,which determine the vibration characteristics of the turbine. Viscosity of most new oils may vary by±10%. A change in viscosity up to 10% is not in itself likely to cause trouble; however, a change inviscosity of 5% from its original value should be investigated for the cause. A change in viscosity is usuallycaused by contamination or top off with the wrong lubricant rather than by degradation of the oil. Dropin oil viscosity is a particular concern where turbine driven compressors are used in the compressionof hydrocarbon gases because the viscosity change may be caused by contamination of the oil from thelighter hydrocarbons [56].
During steam turbine operation, the lubricating oil is subjected to relatively severe oxidizing conditions.These are due primarily to the influence of heat, the presence of water and entrained air, and the catalyticaction of substances in contact with the oil, particularly copper and ferrous metals [69]. Under theseinfluences, the antioxidants are gradually used up and the oxidation stability decreases.
ASTM D943 Turbine Oil Stability Test (TOST) is used to evaluate the oxidation characteristics of newinhibited steam turbine oils. This is an accelerated oxidation test; actual service should be much longerthan test report hours [61]. Since TOST testing can take longer than a year, it is impractical as an in-serviceoil test.
8.6.3 Freedom from Sludge and Deposits
Deposits are generally formed due to oxidation of the turbine oil, soap formation, microbiological growth,contamination by water containing salts, and solid particulate contamination [66]. Process gases can alsoreact with the oil and its additives to form deposits. One such example is a turbine driven ammoniacompressor in which the oil became contaminated with ammonia. The acidic rust inhibitor used in theturbine oil reacted with ammonia to form an insoluble resinous product [70]. Filtration and centrifugationcan remove sludge and other products from oil as they are formed, but if oil deterioration is allowed toproceed too far, sludge will deposit in parts of the equipment and system flushing and an oil change maybe required [71].
8.6.4 Corrosion Protection
Protection against rusting is very important due to the common presence of water in turbine oils and watervapor in the ambient air. Rusting may occur below the oil surface, at the oil surface, or in the vapor spacesabove the oil surface. Rusting requires oxygen, water, a corrodible surface, and time. Effective corrosionprotection requires the elimination of any one of these items. Oil acts to protect against corrosion bycoating structural surfaces with corrosion inhibitor thereby denying access of water to corrodible surfaces.
ASTM D665 is used to evaluate the rust-preventing characteristics of steam-turbine oil in the presenceof water. Procedure A is used for land turbines where condensed steam or humidity from air is the watersource. Procedure B is used for marine-service ocean-going vessels where salt water can be a water source.
Present additive technology has been found to be highly effective at preventing rusting problems belowthe oil surface in full flow conditions. When rusting occurs below the oil surface, it is frequently causedby galvanic corrosion, and it is noticed in areas where there is little oil movement and where free watercollects, such as the bottom of the oil reservoir. Galvanic corrosion is caused by contaminant particlessettling out of the oil and the presence of water. Particulate matter can create galvanic cells and act asnuclei for air bubbles [34]. Factors that influence galvanic corrosion are impurity concentrations, the pHof the water, and temperature [66]. Galvanic corrosion shows up as black rust. Rusting at the oil surfaceis typically caused by liquid water standing on the surface [72].
Most rust problems occur above the oil in what is known as the vapor space. Vapor spaces are present insteam turbine bearing pedestals, oil return lines, sumps, and gear cases. The air in these vapor spaces willcontain water vapor from the relative humidity of the air drawn into the system and from the evaporationof water entrained in the oil. In addition, salt particles that can act as corrosion-sponsoring nuclei alsomay be present [73]. Water vapor tends to condense on the cooler parts of the circulation system, suchas the underside of the reservoir top, inside return-oil piping above oil level, in bearing pedestals, andaround governor parts [74]. Corrosion in the vapor space results in formation of scaly red rust.
8.6.5 Water Separability (Demulsibility)
A lubricant’s ability to separate readily from water is one of the most important requirements of a turbineoil. Water must readily separate from oil in the drain tank so that it is dry when pumped to the system.
Demulsibility is influenced by oxidation and contamination from dirt or metallic particles. Resistanceto oxidation helps preserve the demulsibility characteristics of the oil. Normally, if the oil is in goodcondition, water will settle to the bottom of the storage tank, where it should be drained off as a routineoperating procedure [71]. Water may also be removed by purification systems. If turbine oil develops poordemulsibility, significant amounts of water will stay in the system and create problems such as increasedoxidation, additive depletion, and corrosion. ASTM D1401 is used to test the demulsibility characteristicsof oil.
8.6.6 Air Separability and Resistance to Foaming
All oils will foam in some degree. Foaming of the present day turbine oils should not, however, occurunless the oil is contaminated or subjected to abnormal aeration.
Antifoam additives suppress foam, but in doing so may also slow down air release leading to air entrain-ment. Air entrainment in the oil has been known to cause pressure surge in oil systems, interruptionsin oil supply, excessive formation of foam [75], and reduced hydraulic control. Care must be taken suchthat improving the antifoam characteristics of turbine oil does not lead to unacceptable air separabilitycharacteristics.
Turbine circulation systems have been constructed to eliminate conditions that have been found tocause foaming such as leaky pump suctions, excessive splashing of oil returning to the reservoir, oil-returnlines of insufficient size or capacity, and insufficient venting. Wide differences in temperature between thefresh oil (as added) and the oil in the system may contribute to foaming [76]. Serious cases of excessivefoaming may be due either to mechanical faults of the type listed or to oil contamination [77]. Problemswith excessive foaming may also be due to mixing of incompatible lubricants [63] or the use of excessiveantifoam inhibitor.
Air entrainment issues are also affected by system design. In particular, the stilling period of the lube oilsystem can affect the air entrainment characteristics of oil. Machines that provide short stilling periods forthe oil have displayed air entrainment/release characteristics that seem to counter those displayed duringstandard air release testing (ASTM D3427). Such machines with very short stilling periods have displayedincreased air entrainment when nonsilicone antifoamants have been used and it is suspected that thesilicone antifoams discourage the initial air entrainment during the agitation period [78].
8.7 Degradation of Turbine Oils in Service
Factors responsible for oil degradation in service include contamination, additive depletion, oxidation,and bacteriological deterioration.
8.7.1 Contamination
Contaminants will unavoidably find their way into the lubricating oil. The following types are mostcommon: water, oil soluble contaminants, and solid particles.
8.7.1.1 Water
Water is always present in oil in solution and may also be present in free or emulsified form. The solubilityof water in oil is temperature dependent. Water in solution has no adverse effect on lubricating propertiesand will not cause corrosion; however, when hot oil subsequently cools, some water may come out ofsolution as very fine droplets dispersed throughout the oil [28]. This water is very likely to cause corrosionof steel parts and may also cause other problems, (e.g., foaming, sludge formation, and change of viscosity).In addition, water can also lead to oxidation, additive removal, bacteriological contamination, as well asreducing filter element life.
Water enters the oil system from the condensation of humid air by system temperature fluctuation;from steam through the turbine gland seals; or from leaking oil coolers [73]. Leaking gland seals is the
most common source of water. Leaking oil coolers is the most detrimental particularly since cooling waterleaks will have moderate to high concentrations of dissolved solids. In extreme cases, a rupture of the heatexchanger can cause massive amounts of water to enter the machine compartment [79].
Free water generally exists above a saturation level of around 120 to 150 ppm, and oil becomes cloudyin the range of 200 to 500 ppm [80]. A centrifuge is effective in removing free water down to about 30 ppmabove the saturation level.
Different methods for the testing of water exist. The simplest is visual inspection followed by “crackle”or hot-plate test, which can indicate the presence of water in oil due to boil off. Another test is the FourierTransform Infra-Red (FTIR) spectrometry. The Karl Fischer Titration, ASTM Test Method D 1744, is themost accurate method for water testing.
Differing limitations for water are noted by different manufacturers. In general, the water content shouldnever be allowed to exceed 2500 ppm (0.25%). ASTM D4378 cites 1000 ppm (0.1%) as a warning limit.Depending on the design and application, some manufacturers will require a limit of 500 ppm (0.05%).
8.7.1.2 Soluble Contaminants
Oil soluble contaminants may include gases, solvents, other lubricants, flushing oils, preservatives, andsealants. Gases and some light solvents can be removed by vacuum dehydration methods. Other contam-inants cannot be removed. The presence of such contaminants requires the consultation of the oil supplierand the turbine manufacturer. A common source of dissolved gases is the oil seals used in some generatorsand compressors.
8.7.1.3 Solid Particles
Abrasive contaminants can damage bearings, journals, and control mechanisms. Improved practices suchas better preservation of the turbine and its components when not in operation, high velocity systemflushing during commissioning, and use of full flow filtration during operation have led to a significantreduction in failures due to abrasive contaminants [81].
Cleanliness of the system oil can be determined by gravimetric means by ASTM F 311 or F 312 or byparticle counting. Allowable contamination level is dependent upon the individual turbine application andcomponents in the system. ISO 4406 cleanliness levels ranging from 18/16/13 to 16/14/11 are commonlyapplied to steam turbine service. The three digits of the ISO 4406 code refer to the number of particlesper milliliter greater than 4-, 6-, and 14-µm respectively. It should be noted that further reductions incontamination beyond manufacturer recommendations might lead to improvements in reliability thatcan be cost justified [82].
8.7.2 Additive Depletion
Additives are used up in the performance of their function. In other cases, the additives are removed dueto reaction with contaminants or drop out due to problems of compatibility. Oil suppliers are often ableto replenish additives by sweetening the oil.
8.7.3 Thermal and Oxidative Degradation
The oil acts as a heat transfer fluid with the overall system design determining the heat load on theoil. Factors such as smaller oil reservoirs, higher shaft surface velocity, and higher shaft and bearingtemperatures all contribute to environmental conditions that degrade the oil by thermal stress leading tooxidation. Oxidation occurs by chemical reaction of the oil with oxygen. The first step in the oxidationreaction is the formation of hydroperoxides. Subsequently, a chain reaction is started and other compoundssuch as acid, resins, varnishes, sludge, and carbonaceous deposits are formed [71]. Oxidation productsmay further lead to rust and corrosion, and promotion of foaming and poor demulsibility. The oxidationrate is influenced by the presence of water, contaminants, entrapped air, and temperature. The oxidationrate of a fully inhibited mineral oil is quite low at temperatures less than 60◦C and will double for every10◦C rise in temperature [83].
For in-service oil testing, the oxidation stability reserve is best determined by the rotating pressurevessel oxidation test (RPVOT), ASTM test Method D 2272, and by total acid number (TAN), ASTM TestMethod D 974.
8.7.4 Biological Deterioration
Lubricating oils are susceptible to biological deterioration if the proper growing conditions are present.Procedures for preventing and coping with biological contamination include cleaning and sterilizing,addition of biocides, frequent draining of moisture from the system, and avoidance of dead-legs inpipes [71].
Sustained high water content can lead to bacterial and fungal growth in the system. This can causefilter blocking and formation of deposits. The most effective antimicrobial measure is the establishmentof preventative procedures such as frequent draining of free water from the oil reservoir. Biocides are usedto prevent microorganism growth. Sterilization by heat is also effective.
8.7.5 Turbine Oil Severity
The expected service life of a turbine lubricant depends considerably on the severity of the application.Many low severity steam turbines have a history of requiring a full lubricant changeout only every 10to 20 yr or longer, with periodic top-up with fresh oil [67]. Certain environmental conditions, however,can result in or accelerate lubricant degradation and reduce life. As noted, factors responsible for oildegradation in service include contamination, additive depletion, and thermal, oxidative, or physicalbreakdown.
Other important factors affecting service life are (1) type and design of lubrication system, (2) conditionof the system after construction, and (3) oil makeup rate. These factors vary from unit to unit so thatservice life is difficult to predict solely on original oil properties [84]. One method for determining theservice conditions for each operating unit is to use a property called the turbine severity level (B), whichis defined as the percent of fresh oil oxidation resistance or oxidation inhibitor lost per year due to oilreactions [85]. The equation for turbine severity is
B = M · (1 − X /100)/(1 − e −M ·t /100 ) (8.3)
where B is turbine severity, % of fresh oil oxidation resistance lost per year due to oil reactions in theturbine, M is fresh oil makeup, % per year, t is years of oil use, and X is used oil oxidation resistance byASTM D2272, % of fresh oil.
A lubrication system with a high severity level requires frequent makeup or completely new charges,whereas one with a low severity level may have no problems with routine makeup [86]. The methodrequires periodic testing of the lubricating oil. Large steam turbines should have their turbine severitydetermined. The severity constant is different for each turbine, and varies widely between 5 and 30 forlarge turbines [87]. Figure 8.11 shows the importance of makeup rate for maintaining oil quality in ahigh-severity turbine where B = 25%/yr [85].
8.8 Lubricant Maintenance
Small turbines with ring-lubricated bearings, and governors with sumps require periodic changes inlubricant. The quantities of oil are small, and it is often more economical to change the oil rather thanto maintain it. Change periods of 1 yr are not uncommon and are set by regular change intervals, bymonitoring the acid number or by more sophisticated monitoring.
In larger turbine systems that employ circulating oil systems using more than 200 l (roughly 50 gal) ofoil that require long periods of continuous operation, oil analysis generally proves more profitable than aroutine time/dump program [88]. A life of up to 30 yr is desirable because of the outage and oil change
FIGURE 8.11 Effect of makeup rate on oil degradation for turbine severity, B = 25%/yr. (From DenHerder, M.J.,Vienna, P.C., Lubrication Engineering, 37, 67, 1981. With permission.)
TABLE 8.6 Standards for Turbine Oil Maintenance
Standard designation Standard title
ASTM D4378 Standard practice for in-service monitoring of mineral turbine oils for steam and gas turbinesASTM D4057 Standard practice for manual sampling of petroleum and petroleum productsASTM D6224 Standard practice for in-service monitoring of lubricating oil for auxiliary power plant
equipmentASTM D6439 Standard guide for cleaning, flushing, and purification of steam, gas, and hydroelectric turbine
lubrication systemsIEC 60962 Maintenance and use guide for petroleum lubricating oils for steam turbinesIEC 60978 Maintenance and use guide for petroleum lubricating oils for triaryl phosphate ester turbine
control fluids
costs involved. In such systems, regular sampling and testing can indicate the need for oil conditioning.Many oil suppliers offer programs to meet specific lubrication maintenance requirements. Standardsfor turbine oil maintenance are listed in Table 8.6. Such standards offer a guideline for oil-monitoringand maintenance. Other methods may be applied depending on the application. One such standard,ASTM D4378, Standard Practice for In-Service Monitoring of Mineral Turbine Oils for Steam and GasTurbines is used in the power generation industry [89]. As with any oil monitoring program, propersampling is important. In-service oil should be tested at sufficient intervals to detect contamination,oxidation, and additive depletion. Key tests include appearance and color, water content, viscosity, totalacid number, rust test, cleanliness, and RPVOT [89]. Systems that are exposed to volatile gases or liquids
may also benefit from flash-point testing. Maintaining the lubricant may require new oil makeup, lube oilconditioning, and refortification.
8.8.1 New Oil Makeup
Oil is lost due to leakage and to system maintenance such as draining off impurities, and filter changes.There is considerable variation with respect to the amount of makeup oil required for a steam turbine.Makeup rates can range from less than 5%/yr to more than 30%/yr in extreme cases. The average makeuprate in the United States is 7 to 10%/yr [89].
The compatibility of the system oil and the makeup oil are of critical importance. Compatibility isdescribed as a lubricant’s ability to be mixed with another lubricant without detriment to the propertiesand the characteristics of either lubricant. The introduction of Group II oils has caused some concernswith respect to compatibility with Group I oils. In particular, the different additives and the solubilityof those additives is a concern when mixing different oils especially those involving different base stocks.Problems involving excessive air entrainment, varnish particle build up, development of sludge, sticking ofgovernor proportional valves, and plugging of governor filters has been noted on hydroturbines operatingon turbine lubricants [90]. In some cases, a complete system flush may be required to introduce a newoil. The use of makeup oil that is the same oil as is already in the system is preferred for the eliminationof compatibility issues.
8.8.2 Lube Oil Purification
All circulating lube oil systems use filters to remove particle contaminants and purify the oil. Devices forremoving liquid contaminants such as water will also improve system reliability. The most common devicesfor removing liquid contamination are settling tank, centrifuge, coalescing filter, and vacuum dehydrator.The settling tank works best on a batch basis. The centrifuge, coalescing filter, and vacuum dehydrator areapplied continuously with 10 to 20% of the volume of oil in the turbine system every hour. Systems ofthis type tend to remove impurities as fast as they enter the oil, thereby avoiding accumulations.
Settling tank — Oil contaminants that are heavier than oil can be separated by gravity alone. Suchsettling is best accomplished in a settling tank that is separate from the main oil tank. Settling times canbe very long and the results are often less adequate than the onstream methods.
Centrifuge — In a centrifugal purifier, or centrifuge, centrifugal force is used to accomplish the sep-aration of contaminants heavier than oil. A separating force several thousand times that of gravity isproduced by rotating the liquid at 7,000 to 15,000 rpm. The centrifuge is particularly effective in removingwater and larger, heavier particles of solid impurities. The extent to which extremely fine solid particlesare removed depends on the rate of throughput and other factors. Centrifuges are capable of removingfree water and solids.
Coalescing filter — A coalescing filter system uses special cartridges to combine small, dispersed waterdroplets into larger ones. The larger water drops are retained within a separator screen and fall to thebottom of the filter while the dry oil passes through the screen. Coalescers are capable of removing freewater and solids.
Vacuum dehydrator — A vacuum dehydration system removes water from oil through the applicationof heat and vacuum. The contaminated oil is exposed to a vacuum and heat. The water is removed asvapor. The vacuum dehydrator removes not only the free water, but also the dissolved and suspendedwater well below the solubility point (down to 10 ppm). In addition, vacuum dehydrators also deaerateand degasify the oil [91].
8.8.3 Refortification
Refortification refers to the act of adding a predetermined amount of additive to a clean, dry, used lubricantto replenish some of the depleted additives [92]. In most cases, refortification and purification are usedtogether.
Fire-resistant fluids are used in the hydraulic actuators of large steam turbines operating at very hightemperatures in excess of the auto-ignition temperature of turbine oil. Since the early 1970s, phosphateesters have been the only fire-resistant fluids approved by the turbine builders for use as a turbine controlfluid although small amounts of more flammable carboxylate or synthetic esters have been used inrefurbished systems [93].
8.9.1 Properties
The main advantage of phosphate esters is their fire-resistance. Phosphate esters tend to have higherflash and fire points, higher auto-ignition temperatures and perform better in spray flammability andwick-type fire propagation tests [94]. Auto-ignition temperatures are in the region of 550–590◦C. Thetriaryl version of the phosphate ester possesses inherent self-extinguishing properties because the fluiddoes not create enough energy to support its own combustion. Triaryl phosphates, in addition to their fire-resistant properties, have good thermal stability, excellent boundary lubrication properties, low volatility,fair hydrolytic stability [94], adequate air release, and low-foaming properties. The density of phosphateesters is roughly 30% higher than mineral oils necessitating some additional consideration with respectto lube oil system design. Phosphate ester-based fluids are described in ASTM D4293. Viscosity gradesare either ISO VG-32 or ISO VG-46. Phosphate ester fluids can be incompatible with some seal andinsulative materials as well as certain paints thus making the pressurization system design and maintenancecritical.
8.9.2 Degradation
In service, phosphate esters are subject to deterioration as a result of hydrolysis, oxidation, and contamin-ation. In the case of triaryl phosphate ester hydraulic fluids, contamination may be by water, particulates,mineral oil, and chlorine or chlorinated materials [95].
The principle degradation pathway for phosphate esters in steam turbine-generator lubrication systemsis hydrolysis. While water is inevitably present in the fluids, its continued high concentration can betolerated if fluid acidity is controlled [96]. As the solubility of water in phosphates is very much higherthan in oil (reaching about 2500 ppm at 25◦C), free water is not usually a problem and the level of fluidacidity will normally determine the suitability of the fluid for continued use.
Many of the problems with the use of phosphate esters in turbine applications are associated with thedevelopment of acidity due to hydrolysis or oxidation. Since acidity development can cause corrosion,further accelerate the rate of hydrolysis, and is probably an early stage in the process of deposit formation,the maintenance of acidity levels of less than 0.5 mg KOH/g and preferably less than 0.2 mg KOH/g isstrongly recommended [97].
Contamination by mineral oils can impair fire resistance, as well as being incompatible with variousseals. High chlorine content can cause servo valve electrokinetic wear [95].
8.9.3 Condition Monitoring
The following properties are considered necessary for the in-service testing of phosphate esters; appear-ance, chlorine content, color, mineral oil content, total acid number or neutralization number, fluidcleanliness, particle size, resistivity, viscosity, water content, and air release. The parameters that are ofmost concern are the increase in acidity, water content, and particulate contamination level. When triarylphosphates degrade the most common result is an increase in acidity with little effect on viscosity change.Triaryl phosphate ester fluids are condemned if the acid number exceeds 0.2 over the original value (typ-ically 0.03) [98]. Water should be kept below 2000 ppm. Alternate guidelines for maintenance and use oftriaryl phosphate ester turbine control fluids can be found in IEC 60978.
The key to the cost-effective use of phosphate esters is the use of conditioning media to remove aciddegradation products. Fuller’s earth and activated alumina have provided years of acceptable service;however, new adsorbents based on ion-exchange resins, may allow the fluid to be kept in the system formany years. Vacuum dehydration is required to remove the displaced water [93].
Phosphate ester hydraulic fluids require additional consideration of the lube oil system. Their use inhigh-pressure (1000 psi) systems requires fine filtration (0.5 to 5µm) to protect more closely fitted pumpsand control valves [99]. In addition, adsorbent filtration of phosphate ester hydraulic fluids using fullers’earth, activated alumina, or ion exchange resin is needed to control fluid acidity. Adsorbent filters removedissolved contaminants, such as acids, that are not removed economically or at all by other processes[100]. There is a tendency for these types of filters to remove additive materials. For this reason, adsorbentclay filters are typically not used on turbine oils, but are used for purifying fire-resistant phosphate esterhydraulic fluids as used in turbine control systems. The filters are most often used in a continuous bypassmode with 1–3% treatment ratio or they are used intermittently in accordance with changes in the acidnumber [97]. A fine particulate filter must be placed in series and downstream of the fuller’s earth filterto control particulates.
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