TM 5-811-6

CHAPTER 3

STEAM TURBINE POWER PLANT DESIGN

Section 1. TYPICAL PLANTS AND CYCLES

3-1. Introductiona. Definition. The cycle of a steam power plant is

the group of interconnected major equipment com-ponents selected for optimum thermodynamic char-acteristics, including pressure, temperatures and ca-pacities, and integrated into a practical arrange-ment to serve the electrical (and sometimes by-prod-uct steam) requirements of a particular project. Se-lection of the optimum cycle depends upon plantsize, cost of money, fuel costs, non-fuel operatingcosts, and maintenance costs.

b. Steam conditions. Typical cycles for the prob-able size and type of steam power plants at Army es-tablishments will be supplied by superheated steamgenerated at pressures and temperatures between600 psig (at 750 to 850°F) and 1450 psig (at 850 to950º F). Reheat is never offered for turbine genera-tors of less than 50 MW and, hence, is not applicablein this manual.

c. Steam turbine prime movers. The steam tur-bine prime mover, for rated capacity limits of 5000kW to 30,000 kW, will be a multi-stage, multi-valveunit, either back pressure or condensing. Smallerturbines, especially under 1000 kW rated capacity,may be single stage units because of lower first costand simplicity. Single stage turbines, either backpressure or condensing, are not equipped with ex-traction openings.

d. Back pressure turbines. Back pressure turbineunits usually exhaust at pressures between 250 psigand 15 psig with one or two controlled or uncon-trolled extractions. However, there is a significantprice difference between controlled and uncontrolledextraction turbines, the former being more expen-sive. Controlled extraction is normally appliedwhere the bleed steam is exported to process or dis-trict heat users.

e. Condensing turbines. Condensing units ex-haust at pressures between 1 inch of mercury abso-lute (Hga) and 5 inches Hga, with up to two con-trolled, or up to five uncontrolled, extractions.

3-2. Plant function and purposea. Integration into general planning. General

plant design parameters will be in accordance withoverall criteria established in the feasibility study or

planning criteria on which the technical and econom-ic feasibility is based. The sizes and characteristicsof the loads to be supplied by the power plant, in-cluding peak loads, load factors, allowances for fu-ture growth, the requirements for reliability, andthe criteria for fuel, energy, and general economy,will be determined or verified by the designer andapproved by appropriate authority in advance of thefinal design for the project.

b. Selection of cycle conditions. Choice of steamconditions, types and sizes of steam generators andturbine prime movers, and extraction pressures de-pend on the function or purpose for which the plantis intended. Generally, these basic criteria shouldhave already been established in the technical andeconomic feasibility studies, but if all such criteriahave not been so established, the designer will selectthe parameters to suit the intended use.

c. Coeneration plants. Back pressure and con-trolled extraction/condensing cycles are attractiveand applicable to a cogeneration plant, which is de-fined as a power plant simultaneously supplyingeither electric power or mechanical energy and heatenergy (para. 3-4).

d. Simple condensing cycles. Straight condensingcycles, or condensing units with uncontrolled ex-tractions are applicable to plants or situationswhere security or isolation from public utility powersupply is more important than lowest power cost.Because of their higher heat rates and operatingcosts per unit output, it is not likely that simple con-densing cycles will be economically justified for amilitary power plant application as compared withthat associated with public utility ‘purchased powercosts. A schematic diagram of a simple condensingcycle is shown on Figure 3-1.

3-3. Steam power cycle economya. Introduction. Maximum overall efficiency and

economy of a steam power cycle are the principal de-sign criteria for plant selection and design. In gener-al, better efficiency, or lower heat rate, is accom-panied by higher costs for initial investment, opera-tion and maintenance. However, more efficientcycles are more complex and may be less reliable perunit of capacity or investment cost than simpler and

3-1

TM 5-611-6

N A V F A C D M 3

Figure 3-1. Typical straight condensing cycle.

less efficient cycles. Efficiency characteristics canbe listed as follows:

(1) Higher steam pressures and temperaturescontribute to better, or lower, heat rates.

(2) For condensing cycles, lower back pressuresincrease efficiency except that for each particularturbine unit there is a crossover point where lower-ing back pressure further will commence to decreaseefficiency because the incremental exhaust loss ef-fect is greater than the incremental increase in avail-able energy.

(3) The use of stage or regenerative feedwatercycles improves heat rates, with greater improve-ment corresponding to larger numbers of such heat-ers. In a regenerative cycle, there is also a thermody-namic crossover point where lowering of an extrac-tion pressure causes less steam to flow through theextraction piping to the feedwater heaters, reducingthe feedwater temperature. There is also a limit tothe number of stages of extraction/feedwater heat-ing which may be economically added to the cycle.This occurs when additional cycle efficiency no long-er justifies the increased capital cost.

(4) Larger turbine generator units are generallymore efficient that smaller units.

(5) Multi-stage and multi-valve turbines aremore economical than single stage or single valvemachines.

(6) Steam generators of more elaborate design,or with heat saving accessory equipment are moreefficient.

b. Heat rate units and definitions. The economyor efficiency of a steam power plant cycle is ex-

3-2

pressed in terms of heat rate, which is total thermalinput to the cycle divided by the electrical output ofthe units. Units are Btu/kWh.

(1) Conversion to cycle efficiency, as the ratio ofoutput to input energy, may be made by dividingthe heat content of one kWh, equivalent to 3412.14Btu by the heat rate, as defined. Efficiencies are sel- dom used to express overall plant or cycle perform-ance, although efficiencies of individual compo-nents, such as pumps or steam generators, are com-monly used.

(2) Power cycle economy for particular plants orstations is sometimes expressed in terms of poundsof steam per kilowatt hour, but such a parameter isnot readily comparable to other plants or cycles andomits steam generator efficiency.

(3) For mechanical drive turbines, heat ratesare sometimes expressed in Btu per hp-hour, exclud-ing losses for the driven machine. One horsepowerhour is equivalent to 2544.43 Btu.

c. Heat rate applications. In relation to steampower plant cycles, several types or definitions ofheat rates are used:

(1) The turbine heat rate for a regenerative tur-bine is defined as the heat consumption of the tur-bine in terms of “heat energy in steam” supplied bythe steam generator, minus the “heat in the feedwa-ter” as warmed by turbine extraction, divided bythe electrical output at the generator terminals.This definition includes mechanical and electricallosses of the generator and turbine auxiliary sys-tems, but excludes boiler inefficiencies and pumpinglosses and loads. The turbine heat rate is useful for

TM 5-811-6

performing engineering and economic comparisonsof various turbine designs. Table 3-1 provides theo-retical turbine steam rates for typical steam throttle

conditions. Actual steam rates are obtained by di-viding the theoretical steam rate by the turbine effi-ciency. Typical turbine efficiencies are provided onFigure 3-2.

ASR =where: ASR = actual steam rate (lb/kWh)

TSR = theoretical steam rate (l/kWh)nt = turbine efficiency

Turbine heat rate can be obtained by multiplyingthe actual steam rate by the enthalpy change acrossthe turbine (throttle enthalpy - extraction or ex-haust enthalpy).

Ct = ASR(hl – h2)where = turbine heat rate (Btu/kWh)

ASR = actual steam rate lb/kWh)h1 = throttle enthalpyh1 = extraction or exhaust enthalpy

TSR

’

FROM STANDARD HANDBOOK FOR MECHANICALENGINEERS BY MARKS. COPYRIGHT © 1967,

. MCGRAW-HILL BOOK CO. USED WITH THEPERMISSION OF MCGRAW- HILL BOOK COMPANY.

Figure 3-2. Turbine efficiencies vs. capacity.m

(2) Plant heat rates include inefficiencies andlosses external to the turbine generator, principally

the inefficiencies of the steam generator and pipingsystems; cycle auxiliary losses inherent in power re-quired for pumps and fans; and related energy usessuch as for soot blowing, air compression, and simi-lar services.

(3) Both turbine and plant heat rates, as above,are usually based on calculations of cycle perform-ance at specified steady state loads and well defined,optimum operating conditions. Such heat rates areseldom achieved in practice except under controlledor test conditions.

(4) Plant operating heat rates are long termaverage actual heat rates and include other suchlosses and energy uses as non-cycle auxiliaries,

plant lighting, air conditioning and heating, generalwater supply, startup and shutdown losses, fuel de-terioration losses, and related items. The gradualand inevitable deterioration of equipment, and fail-ure to operate at optimum conditions, are reflectedin plant operating heat rate data.

d. Plant economy calculations. Calculations, esti-mates, and predictions of steam plant performancewill allow for all normal and expected losses andloads and should, therefore, reflect predictions ofmonthly or annual net operating heat rates andcosts. Electric and district heating distributionlosses are not usually charged to the power plantbut should be recognized and allowed for in capacityand cost analyses. The designer is required to devel-op and optimize a cycle heat balance during the con-ceptual or preliminary design phase of the project.The heat balance depicts, on a simplified flow dia-gram of the cycle, all significant fluid mass flowrates, fluid pressures and temperatures, fluid en-thalpies, electric power output, and calculated cycleheat rates based on these factors. A heat balance isusually developed for various increments of plantload (i.e., 25%, 50%, 75%, 100% and VWO (valveswide open)). Computer programs have been devel-oped which can quickly optimize a particular cycleheat rate using iterative heat balance calculations.Use of such a program should be considered.

e. Cogeneration performance. There is no gener-ally accepted method of defining the energy effi-ciency or heat rates of cogeneration cycles. Variousmethods are used, and any rational method is valid.The difference in value (per Btu) between prime en-ergy (i.e., electric power) and secondary or low levelenergy (heating steam) should be recognized. Referto discussion of cogeneration cycles below.

3-4. Cogeneration cyclesa. Definition. In steam power plant practice, co-

generation normally describes an arrangementwhereby high pressure steam is passed through aturbine prime mover to produce electrical power,and thence from the turbine exhaust (or extraction)opening to a lower pressure steam (or heat) distribu-tion system for general heating, refrigeration, orprocess use.

b. Common medium. Steam power cycles are par-ticularly applicable to cogeneration situations be-cause the actual cycle medium, steam, is also a con-venient medium for area distribution of heat.

(1) The choice of the steam distribution pres-sure will be a balance between the costs of distribu-tion which are slightly lower at high pressure, andthe gain in electrical power output by selection of alower turbine exhaust or extraction pressure.

(2) Often the early selection of a relatively low

3-3

TM 5-811-6

3-4

steam distribution pressure is easily accommodatedin the design of distribution and utilization systems,whereas the hasty selection of a relatively highsteam distribution pressure may not be recognizedas a distinct economic penalty on the steam powerplant cycle.

(3) Hot water heat distribution may also be ap-plicable as a district heating medium with the hotwater being cooled in the utilization equipment andreturned to the power plant for reheating in a heatexchange with exhaust (or extraction) steam.

c. Relative economy. When the exhaust (or ex-traction) steam from a cogeneration plant can beutilized for heating, refrigeration, or process pur-poses in reasonable phase with the required electricpower load, there is a marked economy of fuel ener-gy because the major condensing loss of the conven-tional steam power plant (Rankine) cycle is avoided.If a good balance can be attained, up to 75 percent ofthe total fuel energy can be utilized as comparedwith about 40 percent for the best and largest Ran-kine cycle plants and about 25 to 30 percent forsmall Rankine cycle systems.

d. Cycle types. The two major steam power cogen-eration cycles, which may be combined in the sameplant or establishment, are:

TM 5-811-6

(1) Back pressure cycle. In this type of plant,the entire flow to the turbine is exhausted (or ex-tracted) for heating steam use. This cycle is themore effective for heat economy and for relativelylower cost of turbine equipment, because the primemover is smaller and simpler and requires no con-denser and circulating water system. Back pressureturbine generators are limited in electrical output bythe amount of exhaust steam required by the heatload and are often governed by the exhaust steamload. They, therefore, usually operate in electricalparallel with other generators.

(2) Extraction-condensing cycles. Where theelectrical demand does not correspond to the heatdemand, or where the electrical load must be carriedat times of very low (or zero) heat demand, then con-densing-controlled extraction steam turbine primemovers as shown in Figure 3-3 may be applicable.Such a turbine is arranged to carry a specified elec-trical capacity either by a simple condensing cycleor a combination of extraction and condensing.While very flexible, the extraction machine is rela-tively complicated, requires complete condensingand heat rejection equipment, and must always passa critical minimum flow of steam to its condenser tocool the low pressure buckets.

.

.

N A V F A C D M 3 Figure 3-3. Typical condensing-controlled extinction cycle.

3-5

TM 5-811-6

e. Criteria for cogeneration. For minimum eco-nomic feasibility, cogeneration cycles will meet thefollowing criteria:

(1) Load balance. There should be a reasonablybalanced relationship between the peak and normalrequirements for electric power and heat. Thepeak/normal ratio should not exceed 2:1.

(2) Load coincidence. There should be a fairlyhigh coincidence, not less than 70%, of time andquantity demands for electrical power and heat.

(3) Size. While there is no absolute minimumsize of steam power plant which can be built for co-generation, a conventional steam (cogeneration)plant will be practical and economical only abovesome minimum size or capacity, below which othertypes of cogeneration, diesel or gas turbine becomemore economical and convenient.

(4) Distribution medium. Any cogenerationplant will be more effective and economical if theheat distribution medium is chosen at the lowestpossible steam pressure or lowest possible hot watertemperature. The power energy delivered by the tur-bine is highest when the exhaust steam pressure islowest. Substantial cycle improvement can be madeby selecting an exhaust steam pressure of 40 psigrather than 125 psig, for example. Hot water heatdistribution will also be considered where practicalor convenient, because hot water temperatures of200 to 240º F can be delivered with exhaust steampressure as low as 20 to 50 psig. The balance be-tween distribution system and heat exchangercosts, and power cycle effectiveness will be opti-mized.

3-5. Selection of cycle steam conditionsa. Balanced costs and economy. For a new or iso-

lated plant, the choice of initial steam conditionsshould be a balance between enhanced operatingeconomy at higher pressures and temperatures, andgenerally lower first costs and less difficult opera-tion at lower pressures and temperatures. Realisticprojections of future fuel costs may tend to justifyhigher pressures and temperatures, but such factorsas lower availability y, higher maintenance costs,more difficult operation, and more elaborate watertreatment will also be considered.

b. Extension of existing plant. Where a newsteam power plant is to be installed near an existingsteam power or steam generation plant, careful con-sideration will be given to extending or parallelingthe existing initial steam generating conditions. Ifexisting steam generators are simply not usable inthe new plant cycle, it may be appropriate to retirethem or to retain them for emergency or standbyservice only. If boilers are retained for standby serv-ice only, steps will be taken in the project design for

protection against internal corrosion.c. Special considerations. Where the special cir-

cumstances of the establishment to be served aresignificant factors in power cycle selection, the fol- lowing considerations may apply:

(1) Electrical isolation. Where the proposedplant is not to be interconnected with any local elec-tric utility service, the selection of a simpler, lowerpressure plant may be indicated for easier operationand better reliability y.

(2) Geographic isolation. Plants to be installedat great distances from sources of spare parts, main-tenance services, and operating supplies may re- quire special consideration of simplified cycles, re-dundant capacity and equipment, and highest prac-tical reliability. Special maintenance tools and facil- ities may be required, the cost of which would be af-fected by the basic cycle design.

(3) Weather conditions. Plants to be installedunder extreme weather conditions will require spe-cial consideration of weather protection, reliability,and redundancy. Heat rejection requires special de-sign consideration in either very hot or very coldweather conditions. For arctic weather conditions,circulating hot water for the heat distribution medi-um has many advantages over steam, and the use ofan antifreeze solution in lieu of pure water as a dis- tribution medium should receive consideration.

3-6. Cycle equipmenta. General requirements. In addition to the prime

movers, alternators, and steam generators, a com-plete power plant cycle includes a number of second-ary elements which affect the economy and perform-ance of the plant.

b. Major equipment. Refer to other parts of this manual for detailed information on steam turbinedriven electric generators and steam generators.

c. Secondary cycle elements. Other equipmentitems affecting cycle performance, but subordinateto the steam generators and turbine generators, arealso described in other parts of this chapter.

3-7. Steam power plant arrangementa. General. Small units utilize the transverse ar-

rangement in the turbine generator bay while thelarger utility units are very long and require end-to-end arrangement of the turbine generators.

b. Typical small plants. Figures 3-4 and 3-6 showtypical transverse small plant arrangements. Smallunits less than 5000 kW may have the condensers atthe same level as the turbine generator for economyas shown in Figure 3-4. Figure 3-6 indicates thecritical turbine room bay dimensions and the basicoverall dimensions for the small power plants shownin Figure 3-5.

TM 5-811-6

U. S. Army Corps of Engineers

Figure 3-4. Typical small 2-unit powerplant “A”.

3-7

TM 5-811-6

a

3-8

TM 5-811-6

Section Il. STEAM GENERATORS AND AUXILIARY SYSTEMS.

tors for a steam power plant can be classified bytype of fuel, by unit size, and by final steam condi-tion. Units can also be classified by type of draft, bymethod of assembly, by degree of weather protec-tion and by load factor application.

(1) Fuel, general. Type of fuel has a major im-pact on the general plant design in addition to thesteam generator. Fuel selection may be dictated byconsiderations of policy and external circumstances

3-8. Steam generator conventionaltypes and characteristics

a. Introduction. Number, size, and outlet steam-ing conditions of the steam generators will be as de-termined in planning studies and confirmed in the fi-nal project criteria prior to plant design activities.Note general criteria given in Section I of this chapter under discussion of typical plants and cycles.

b. Types and classes. Conventional steam genera-.!

.

AND CONDENSER SUPPLIERS SELECTED.

36433116611.37 . 53 . 71.25 . 5517.55811

NOTE:

U S .

DIMENSIONS IN TABLE ARE APPLICABLE TO FIG. 3-5

Army Corps of Engineers

Figure 3-6. Critical turbine room bay and power plant “B” dimensions.

3-9

TM 5-811-6

unrelated to plant costs, convenience, or location.Units designed for solid fuels (coal, lignite, or solidwaste) or designed for combinations of solid, liquid,and gaseous fuel are larger and more complex thanunits designed for fuel oil or fuel gas only.

(2) Fuel coal. The qualities or characteristics ofparticular coal fuels having significant impact onsteam generator design and arrangement are: heat-ing value, ash content, ash fusion temperature, fri-ability, grindability, moisture, and volatile contentas shown in Table 3-2. For spreader stoker firing,the size, gradation, or mixture of particle sizes affect

Table 3-2.Characteristic

stoker and grate selection, performance, and main-tenance. For pulverized coal firing, grindability is amajor consideration, and moisture content before and after local preparation must be considered. Coalburning equipment and related parts of the steamgenerator will be specified to match the specificcharacteristics of a preselected coal fuel as well asthey can be determined at the time of design.

(3) Unit sizes. Larger numbers of smaller steamgenerators will tend to improve plant reliability andflexibility for maintenance. Smaller numbers of larg-er steam generators will result in lower first costs

Fuel Characteristcs.Effects

Coal

Heat balance.

Handling and efficiency loss.Ignition and theoretical air.Freight, storage, handling, air pollution.Slagging, allowable heat release,allowable furnace exit gas temperature.Heat balance, fuel cost.Handling and storage.Crushing and pulverizing.Crushing , segregation, and spreadingover fuel bed.Allowable temp. of metal contactingflue gas; removal from flue gas.

Oil

Heat balance.Fuel cost.Preheating, pumping, firing.Pumping and metering.Vapor locking of pump suction.Heat balance, fuel cost.Allowable temp. of metal contactingflue gas; removal from flue gas.

Gas

Heat balance.Pressure, f ir ing, fuel cost .Metering.Heat balance, fuel cost.Insignificant.

NAVFAC DM3

3-10

TM 5-811-6

per unit of capacity and may permit the use of de-sign features and arrangements not available onsmaller units. Larger units are inherently more effi-cient, and will normally have more efficient draftfans, better steam temperature control, and bettercontrol of steam solids.

(4) Final steam conditions. Desired pressureand temperature of the superheater outlet steam(and to a lesser extent feedwater temperature) willhave a marked effect on the design and cost of asteam generator. The higher the pressure the heav-ier the pressure parts, and the higher the steam tem-perature the greater the superheater surface areaand the more costly the tube material. In addition tothis, however, boiler natural circulation problems in-crease with higher pressures because the densitiesof the saturated water and steam approach each oth-er. In consequence, higher pressure boilers requiremore height and generally are of different designthan boilers of 200 psig and less as used for generalspace heating and process application.

(5) Type of draft.(a) Balanced draft. Steam generators for elec-

tric generating stations are usually of the so called“balanced draft” type with both forced and induceddraft fans. This type of draft system uses one ormore forced draft fans to supply combustion air un-

der pressure to the burners (or under the grate) andone or more induced draft fans to carry the hot com-bustion gases from the furnace to the atmosphere; aslightly negative pressure is maintained in the fur-nace by the induced draft fans so that any gas leak-age will be into rather than out of the furnace. Nat-ural draft will be utilized to take care of the chimneyor stack resistance while the remainder of the draftfriction from the furnace to the chimney entrance ishandled by the induced draft fans.

(b) Choice of draft. Except for special casessuch as for an overseas power plant in low cost fuelareas, balanced draft, steam generators will be spec-ified for steam electric generating stations.

(6) Method of assembly. A major division ofsteam generators is made between packaged or fac-tory assembled units and larger field erected units.Factory assembled units are usually designed forconvenient shipment by railroad or motor truck,complete with pressure parts, supporting structure,and enclosure in one or a few assemblies. Theseunits are characteristically bottom supported, whilethe larger and more complex power steam gener-ators are field erected, usually top supported.

(7) Degree of weather protection. For all typesand sizes of steam generators, a choice must bemade between indoor, outdoor and semi-outdoor in-stallation. An outdoor installation is usually less ex-pensive in first cost which permits a reduced general

building construction costs. Aesthetic, environmen-tal, or weather conditions may require indoor instal-lation, although outdoors units have been used SUC- cessfully in a variety of cold or otherwise hostile cli-mates. In climates subject to cold weather, 30 “F. for7 continuous days, outdoor units will require electri-cally or steam traced piping and appurtenances toprevent freezing. The firing aisle will be enclosedeither as part of the main power plant building or asa separate weather protected enclosure; and theends of the steam drum and retractable soot blowerswill be enclosed and heated for operator convenienceand maintenance.

(8) Load factor application. As with all parts ofthe plant cycle, the load factor on which the steamgenerator is to be operated affects design and costfactors. Units with load factors exceeding 50% willbe selected and designed for relatively higher effi-ciencies, and more conservative parameters for fur-nace volume, heat transfer surface, and numbersand types of auxiliaries. Plants with load factorsless than 50% will be served by relatively less ex-pensive, smaller and less durable equipment.

3-9. Other steam generator characteris-tics

a. Water tube and waterwell design. Power plantboilers will be of the water welled or water cooledfurnace types, in which the entire interior surface ofthe furnace is lined with steam generating heatingsurface in the form of closely spaced tubes usuallyall welded together in a gas tight enclosure.

b. Superheated steam. Depending on manufac-turer’s design some power boilers are designed todeliver superheated steam because of the require-ments of the steam power cycle. A certain portion ofthe total boiler heating surface is arranged to addsuperheat energy to the steam flow. In superheaterdesign, a balance of radiant and convective super-heat surfaces will provide a reasonable superheatcharacteristic. With high ‘pressure - high temper-ature turbine generators, it is usually desirable toprovide superheat controls to obtain a flat charac-teristic down to at least 50 to 60 percent of load.This is done by installing excess superheat surfaceand then attemperating by means of spray water atthe higher loads. In some instances, boilers are de-signed to obtain superheat control by means of tilt-ing burners which change the heat absorption pat-tern in the steam generator, although supplemen-tary attemperation is also provided with such a con-trol system.

c. Balanced heating surface and volumetric de-sign parameters. Steam generator design requiresadequate and reasonable amounts of heating surface

3-11

TM 5-811-6

and furnace volume for acceptable performance andlongevity.

(1) Evaporative heating surface. For its ratedcapacity output, an adequate total of evaporative orsteam generating heat transfer surface is required,which is usually a combination of furnace wall ra-diant surface and boiler convection surface. Bal-anced design will provide adequate but not exces-sive heat flux through such surfaces to insure effec-tive circulation, steam generation and efficiency.

(2) Superheater surface. For the required heattransfer, temperature control and protection of met-al parts, the superheater must be designed for a bal-ance between total surface, total steam flow area,and relative exposure to radiant convection heatsources. Superheaters may be of the drainable ornon-drainable types. Non-drainable types offer cer-tain advantages of cost, simplicity, and arrange-ment, but are vulnerable to damage on startup.Therefore, units requiring frequent cycles of shut-down and startup operations should be consideredfor fully drainable superheaters. With some boilerdesigns this may not be possible.

(3) Furnace volume. For a given steam gener-ator capacity rating, a larger furnace provides lowerfurnace temperatures, less probability of hot spots,and a lower heat flux through the larger furnace wallsurface. Flame impingement and slagging, partic-ularly with pulverized coal fuel, can be controlled orprevented with increased furnace size.

(4) General criteria. Steam generator designwill specify conservative lower limits of total heat-ing surface, furnace wall surface and furnace vol-ume, as well as the limits of superheat temperaturecontrol range. Furnace volume and surfaces will besized to insure trouble free operation.

(5) Specific criteria. Steam generator specifica-tions set minimum requirements for Btu heat re-lease per cubic foot of furnace volume, for Btu heatrelease per square foot of effective radiant heatingsurface and, in the case of spreader stokers, for Btuper square foot of grate. Such parameters are not setforth in this manual, however, because of the widerange of fuels which can affect these equipment de-sign considerations. The establishment of arbitrarylimitations which may handicap the geometry offurnace designs is inappropriate. Prior to settingfurnace geometry parameters, and after the typeand grade of fuel are established and the particularservice conditions are determined, the power plantdesigner will consult boiler manufacturers to insurethat steam generator specifications are capable ofbeing met.

d. Single unit versus steam header system. Forcogeneration plants, especially in isolated locationsor for units of 10,000 kW and less, a parallel boiler or

steam header system may be more reliable and moreeconomical than unit operation. Where a group ofsteam turbine prime movers of different types; i.e., one back pressure unit plus one condensing/extrac-tion unit are installed together, overall economy canbe enhanced by a header (or parallel) boiler arrange-ment.

3-10. Steam generator special typesa. Circulation. Water tube boilers will be specified

to be of natural circulation. The exception to thisrule is for wasteheat boilers which frequently are a . .special type of extended surface heat exchanger de-signed for forced circulation.

b. Fludized bed combustion. The fluidized bed boiler has the ability to produce steam in an environ-mentally accepted manner in controlling the stackemission of sulfur oxides by absorption of sulfur inthe fuel bed as well as nitrogen oxides because of itsrelatively low fire box temperature. The fluidizedbed boiler is a viable alternative to a spreader stokerunit. A fluidized bed steam generator consists of afluidized bed combustor with a more or less conven-tional steam generator which includes radiant andconvection boiler heat transfer surfaces plus heat re-covery equipment, draft fans, and the usual array ofsteam generator auxiliaries. A typical fluidized bed boiler is shown in Figure 3-7.

3-11. Major auxiliary systems.a. Burners.

(1) Oil burners. Fuel oil is introduced throughoil burners, which deliver finely divided or atomizedliquid fuel in a suitable pattern for mixing with com-bustion air at the burner opening. Atomizing meth-ods are classified as pressure or mechanical type, airatomizing and steam atomizing type. Pressureatomization is usually more economical but is alsomore complex and presents problems of control,poor turndown, operation and maintenance. Therange of fuel flows obtainable is more limited withpressure atomization. Steam atomization is simpleto operate, reliable, and has a wide range, but con-sumes a portion of the boiler steam output and addsmoisture to the furnace gases. Generally, steamatomization will be used when makeup water is rela-tively inexpensive, and for smaller, lower pressureplants. Air atomization will be used for plants burn-ing light liquid fuels, or when steam reacts ad-versely with the fuel, i.e., high sulfur oils.

(2) Gas and coal burners. Natural gas or pulver-ized coal will be delivered to the burner for mixingwith combustion air supply at the burner opening.Pulverized coal will be delivered by heated, pressur- ized primary air.

(3) Burner accessories. Oil, gas and pulverized

3-12

coal burners will be equipped with adjustable airguide registers designed to control and shape the airflow into the furnace, Some burner designs also pro-vide for automatic insertion and withdrawal of vary-ing size oil burner nozzles as load and operating con-ditions require.

(4) Number of burners. The number of burnersrequired is a function both of load requirements andboiler manufacturer design. For the former, the indi-vidual burner turndown ratios per burner are pro-vided in Table 3-3. Turndown ratios in excess ofthose listed can be achieved through the use of mul-tiple burners. Manufacturer design limits capacityof each burner to that compatible with furnace flameand gas flow patterns, exposure and damage to

STEAM OUTLET TOSUPERHEATER IN BED

TM 5-811-6

heating surfaces, and convenience of operation andcontrol.

(5) Burner managerment systems. Plant safetypractices require power plant fuel burners to beequipped with comprehensive burner control andsafety systems to prevent unsafe or dangerous con-ditions which may lead to furnace explosions. Theprimary purpose of a burner management system issafety which is provided by interlocks, furnacepurge cycles and fail safe devices.

b. Pulverizes. The pulverizers (mills) are an essen-tial part of powdered coal burning equipment, andare usually located adjacent to the steam generatorand burners, but in a position to receive coal bygravity from the coal silo. The coal pulverizers grind

k 1111111 rlu-SPREAOER

U.S. Army Corps of Engineers

Figure 3-7. Fluidized bed combustion boiler.

3-13

TM 5-811-6

and classify the coal fuel to specific particle sizes forrapid and efficient burning. Reliable and safe pulver-izing equipment is essential for steam generator op-eration. Pulverized coal burning will not be specifiedfor boilers smaller than 150,000 lb/hour.

c. Stokers and grates. For small and mediumsized coal burning steam generators, less than150,000 lb/hour, coal stokers or fluidized bed unitswill be used. For power boilers, spreader stokerswith traveling grates are used. Other types ofstokers (retort, underfeed, or overfeed types) aregenerally obsolete for power plant use except per-haps for special fuels such as anthracite.

(1) Spreader stokers typically deliver sized coal,with some proportion of fines, by throwing it intothe furnace where part of the fuel burns in suspen-sion and the balance falls to the traveling grate forburnout. Stoker fired units will have two or morespreader feeder units, each delivering fuel to its ownseparate grate area. Stoker fired units are less re-sponsive to load changes because a large proportionof the fuel burns on the grate for long time periods(minutes). Where the plant demand is expected to in-

clude sudden load changes, pulverized coal feedersare to be used.

(2) Grate operation requires close and skillfuloperator attention, and overall plant performance is sensitive to fuel sizing and operator experience.Grates for stoker fired units occupy a large part ofthe furnace floor and must be integrated with ash re-moval and handling systems. A high proportion ofstoker ash must be removed from the grates in awide range of particle sizes and characteristics al-though some unburned carbon and fly ash is carriedout of the furnace by the flue gas. In contrast, alarger proportion of pulverized coal ash leaves the .furnace with the gas flow as finely divided particu-late,

(3) Discharged ash is allowed to COOl in the ash hopper at the end of the grate and is then sometimesput through a clinker grinder prior to removal in thevacuum ash handling system described elsewhere inthis manual.

d. Draft fans, ducts and flues.(1) Draft fans.

(a) Air delivery to the furnace and flue gas re-

Table 3-3. Individual Burner Turndown Ratios.

Burner Type Turndown Ratio

NATURAL GM

Spud or Ring Type

HEAVY FUEL OIL

Steam Atomizing

Mechanical Atomizing

COAL

Pulverized

Spreader-Stoker

Fluidized Bed (single bed)

5:1 to 10:1

5:1 to 10:1

3:1 to 10:1

3:1

2 :1 to 3 :1

2 :1 to 3 :1

U.S. Army Corps of Engineers

3-14

II

.

.

moval will be provided by power driven draft fansdesigned for adequate volumes and pressures of airand gas flow. Typical theoretical air requirementsare shown in Figure 3-8 to which must be added ex-cess air which varies with type of firing, plus fanmargins on both volumetric and pressure capacityfor reliable full load operation. Oxygen and carbondioxide in products of combustion for variousamounts of excess air are also shown in Figure 3-8.

(b) Calculations of air and gas quantities andpressure drops are necessary. Since fans are heavypower consumers, for larger fans considerationshould be given to the use of back pressure steamturbine drives for economy, reliability and their abil-it y to provide speed variation. Multiple fans on eachboiler unit will add to first costs but will providemore flexibility and reliability . Type of fan drivesand number of fans will be considered for cost effec-tiveness. Fan speed will be conservatively selected,and silencers will be provided in those cases wherenoise by fans exceeds 80 decibels.

(c) Power plant steam generator units de-signed for coal or oil will use balanced draft designwith both forced and induced draft fans arranged forclosely controlled negative furnace pressure.

(2) Ducts and flues. Air ducts and gas flues willbe adequate in size and structural strength and de-signed with provision for expansion, support, corro-

TM 5-811-6

sion resistance and overall gas tightness. Adequatespace and weight capacity will be allowed in overallplant arrangement to avoid awkward, noisy or mar-ginal fan, duct and flue systems. Final steam gener-ator design will insure that fan capacities (especiallypressure) are matched properly to realistic air andgas path losses considering operation with dirtyboilers and under abnormal operating conditions.Damper durability and control characteristics willbe carefully designed; dampers used for control pur-poses will be of opposed blade construction.

e. Heat recovery. Overall design criteria requirehighest fuel efficiency for a power boiler; therefore,steam generators will be provided with heat recov-ery equipment of two principal types: air pre-heater and economizers.

(1) Efficiency effects. Both principal types ofheat recovery equipment remove relatively low levelheat from the flue gases prior to flue gas dischargeto the atmosphere, using boiler fluid media (air orwater) which can effectively absorb such low levelenergy. Such equipment adds to the cost, complex-ity and operational skills required, which will be bal-anced by the plant designer against the life cyclefuel savings.

(2) Air preheater. Simple tubular surfaceheaters will be specified for smaller units and the re-generative type heater for larger boilers. To mini-

3-15

TM 5-811-6

mize corrosion and acid/moisture damage, especiallywith dirty and high sulphur fuels, special alloy steelwill be used in the low temperature heat transfersurface (replaceable tubes or “baskets”) of air pre-heater. Steam coil air heaters will be installed tomaintain certain minimum inlet air (and metal) tem-peratures and thus protect the main preheater fromcorrosion at low loads or low ambient air tempera-tures. Figure 3-9 illustrates the usual range of mini-mum metal temperatures for heat recovery equip-ment.

(3) Economizers. Either an economizer or an airheater or a balanced selection of both as is usual in apower boiler will be provided, allowing also for tur-bine cycle feedwater stage heating.

f. Stacks.(1) Delivery of flue gases to the atmosphere

through a flue gas stack or chimney will be pro-vided.

(2) Stacks and chimneys will be designed to dis-charge their gases without adverse local effects. Dis-persion patterns and considerations will be treatedduring design.

(3) Stacks and chimneys will be sized with dueregard to natural draft and stack friction with

290

NAVFAC DM3

Figure 3-9. Minimum metal temperatures for boiler heatrecovery equipment.

height sometimes limited by aesthetic or other non-economic considerations. Draft is a function of den-sit y difference between the hot stack gases and am- bient air, and a number of formulas are available forcalculating draft and friction. Utilize draft of thestack or chimney only to overcome friction withinthe chimney with the induced draft fan(s) supplyingstack or chimney entrance. Maintain relatively highgas exit velocities (50 to 60 feet per second) to ejectgases as high above ground level as possible. Reheat(usually by steam) will be provided if the gases aretreated (and cooled) in a flue gas desulfurization scrubber prior to entering the stack to add buoy-ancy and prevent their settling to the ground afterejection to the atmosphere. Insure that downwashdue to wind and building effects does not drive the flue gas to the ground.

g. Flue gas cleanup. The requirements for flue gascleanup will be determined during design.

(1) Design considerations. The extent and na-ture of the air pollution problem will be analyzedprior to specifying the environmental control sys-tem for the steam generator. The system will meetall applicable requirements, and the application willbe the most economically feasible method of accom-plishment. All alternative solutions to the problemwill be considered which will satisfy the given loadand which will produce the least objectionablewastes. Plant design will be such as to accommodate future additions or modifications at minimum cost.Questions concerning unusual problems, unique ap-placations or marginal and future requirements willbe directed to the design agency having jurisdictionover the project. Table 3-4 shows the emission lev-els allowable under the National Ambient AirQuality Standards.

(2) Particulate control. Removal of flue gas par- ticulate material is broadly divided into mechanicaldust collectors, electrostatic precipitators, bag fil-ters, and gas scrubbing systems. For power plantsof the size range here considered estimated uncon-trolled emission levels of various pollutants areshown in Table 3-5. Environmental regulations re-quire control of particulate, sulfur oxides and nitro-gen oxides. For reference purposes in this manual,typical control equipment performance is shown inTable 3-6, 3-7, 3-8, 3-9, 3-10 and 3-11. These onlyprovide general guidance. The designer will refer toTM 5-815-l/AFR 19-6/NAVFAC DM-3.15 for de-tails of this equipment and related computationalrequirements and design criteria.

(a) Mechanical collectors. For oil fired steam generators with output steaming capacities lessthan 200,000 pounds per hour, mechanical (centrifu- gal) type dust collectors may be effective and eco-nomical depending on the applicable emission stand-

3-16

ards. For a coal fired boiler with a spreader stoker, amechanical collector in series with an electrostaticprecipitator or baghouse also might be considered.Performance requirements and technical environ-mental standards must be carefully matched, andultimate performance warranties and tests requirecareful and explicit definitions. Collected dust froma mechanical collector containing a large proportionof combustibles may be reinfected into the furnacefor final burnout; this will increase steam generator

TM 5-811-6

efficiency slightly but also will increase collectordust loading and carryover. Ultimate collecteddust material must be handled and disposed of sys-tematically to avoid objectionable environmental ef-fects.

(b) Electrostatic precipitators. For pulverizedcoal firing, adequate particulate control will requireelectrostatic precipitators (ESP). ESP systems arewell developed and effective, but add substantialcapital and maintenance costs. Very high percent-

3-17

Pollutant

Part i cu la te

Sulfur Oxides

Nitrogen Oxides

COAL FIRED(Lb of Pollutant/Ton

Table3-5. Uncontrolled Emissions.

OIL FIREDof Coal) (Lb of Pollutant/1000 Gal)

Pulverized Stokers or

NATURAL GAS( L b o f P o l l u t a n t / 1 06 F t3 )

1. The letter A indicates that the weight percentage of ash in the coal should be multiplied bythe value given. Example: If the factor is 16 and the ash content is 10 percent, the particulateemissions before the control equipment would be 10 times 16, or 160 pounds of particulate per tonof coal.

2. Without fly ash reinfection. With fly ash reinfection use 20A.

3. S equals the sulfur content, use like the factor A (see Note 1 above) for estimate emissions.

U.S. Environmental Protection Agency

2-6

50-70

50

90-95 Industrial a n d

util i ty boilerParticulate control.

U.S. Army Corps of Engineers

Table 3-2! Characteristics of Scrubbers for Particulate Control.

Partic leCollection Water UsageEff ic iency Per 1000 Gal/Min

80 3-5

InternalVelocity

Ft/SecPressure Drop

In. H O

3-8

Gas FlowFt /MinScrubber Type Energy Type

Low EnergyCentrifugalScrubber

1,000-20,000

50-150

Impingement &Entrainment

Low Energy 4-20 500-50,000

50-150 60-90 10-40

Venturi High Energy 4-200 200-150,000

200-600 95-99 5-7

Ejector Venturi High Energy 10-50 500- 200-500 90-98 70-14510,000

U.S. Army Corps of Engineers

T y p e

Hot ESP

Cold ESP

Wet ESP

Table 3-8. Characteristics of Electrostatic Precipitators (ESP) for Particulate Control.

Operating , R e s i s t i v i t yTemperature at 300º F

°F ohm-cm

600+ Greater Than1 01 2

300 Less Than1 01 0

3 0 0 - Greater Than1 01 2 b e l o w1 04

U.S. Army Corps of Engineers

P r e s s u r eGas DropFlow I n . o f

F t / M i n Water

100,000+ Less Than1"

Table 3-9. Characteristics of Baghouses for Particulate Control.

Pressure Loss Filter Ratio(Inches of (cfm/ft

System Type Water) Eff ic iency Cloth Type Cloth Area) Recommended Application

Shaker 3-6 99+% Woven 1-5 Dust with good filtercleaning properties,intermittent collection.

Reverse Flow 3-6 99+% Woven 1-5 Dust with good filter cleaningproperties, high temperaturecollection (incinerator fly-ash) with glass bags.

Pulse Jet

Reverse Jet

Envelope

3-6

3-8

3-6

U.S. Army Corps of Engineers

99+% Felted

99+% Felted

99+% Woven

4-20

10-30

1-5

Efficient for coal and oil flyash collection.

Collection of fine dusts andfumes.

Collection of highly abrasivedust .

Table 3-10. Characteristics of Flue-Gas Desulfurization Systems for Particulate Control.

Retrofit toExisting

Installations

Yea

Pressure Drop(Inches of Water)

SO Removal Recovery andRegeneration

No Recoveryof Limestone

No Recoveryof Lime

No Recoveryof Lime

Recovery of MgOand Sulfuric Acid

Recovery of NaS03

OperationalReliabilityEfficiency (%)

30-40%

System Type

High

High

Low

Low

Unknown

Unknown

Unknown

Unknown

1) Limestone BoilerInjection Type

Less Than 6“

Greater Than 6“

Greater Than 6“

Greater Than 6“

Greater Than 6“

Yea2) Limestone, SrubberInjection Type

30-40%

Yea3) Lime, Scrubber,Injection Type

90%+

Yea4) Magnesium Oxide

90%+5) Wellman-Lordand Elemental Sulfur

6) Catalyticoxidation

Recovery of 80%H2S04

No85% May be as high as 24”

Tray Tower PressureDrop 1.6-2.0 in.H2O/tray, w/Venturiadd 10-14 in. H2O

Little Recoveryof Sodium Carbonate

Yea7) Single AlkaliSystems

90%+

Yea8) Dual Alkali 90-95%+ Regeneration ofSodium Hydroxideand Sodium Sulfites

U.S. Army Corps of Engineers

g

Tabble 3-11. Techniques for Nitrogen Oxide Control.

Technique

Load Reduction

Low Excess Air Firing

Two Stage Conbustion

Coal

Oil

Gas

Potential

Off-Stoichiometric Combustion

Coal

Reduced Combustion AirPreheat

NO Reduction (%)

Flue Gas Recirculation

15 to 40

30

40

50

45

10-50

20-50

U.S. Army Corps of Engineers

Advantages Disadvantages

Easily implemented; no additional Reduction in generating capacity;equipment required; reduced particu- possible reduction in boiler thermallate and SOX emissions. thermal efficiency.

Increased boiler thermal efficiency; A combustion control system whichpossible reduction in particulate closely monitors and controls fuel/emissions may be combined with a load air ratios is required.reduction to obtain additional NOx

emission decrease; reduction in hightemperature corrosion and ash deposition.

- - - Boiler windboxes must be designed forthis application.

- --

- - -

- - -

Possible improvement in combustionefficiency end reduction in particu-late emissions.

Furnace corrosion and particulateemissions may increase.

Control of alternate fuel rich/andfuel lean burners may be a problemduring transient load conditions.

Not applicable to coal or oil firedunits; reduction in boiler thermalefficiency; increase in exit gasvolume and temperature; reduction inboiler load.

Boiler windbox must be modified tohandle the additional gas volume;ductwork, fans and Controls required.

TM 5-811-6

ages of particulate removal can be attained (99 per-cent, plus) but precipitators are sensitive to ashcomposition, fuel additives, flue gas temperaturesand moisture content, and even weather conditions.ESP’s are frequently used with and ahead of fluegas washing and desulfurization systems. They maybe either hot precipitators ahead of the air preheaterin the gas path or cold precipitators after the air pre-heater. Hot precipitators are more expensive be-cause of the larger volume of gas to be handled andtemperature influence on materials. But they aresometimes necessary for low sulfur fuels where coldprecipitators are relatively inefficient.

(c) Bag filters. Effective particulate removalmay be obtained with bag filter systems or baghouses, which mechanically filter the gas by passagethrough specially designed filter fabric surfaces.Bag filters are especially effective on very fine parti-cles, and at relatively low flue gas temperatures.They may be used to improve or upgrade other par-ticulate collection systems such as centrifugal col-lectors. Also they are probably the most economicchoice for most medium and small size coal firedsteam generators.

(d) Flue gas desulfurization. While variousgaseous pollutants are subject to environmentalcontrol and limitation, the pollutants which must beremoved from the power plant flue gases are the ox-

ides of sulfur (SO2 and SO3). Many flue gas desulfuri-ztion (FGD) scrubbing systems to control SO2 andSO3stack emission have been installed and oper-ated, with wide variations in effectiveness, reliabil-ity, longevity and cost. For small or medium sizedpower plants, FGD systems should be avoided ifpossible by the use of low sulfur fuel. If the parame-ters of the project indicate that a FGD system is re-quired, adequate allowances for redundancy, capitalcost, operating costs, space, and environmental im-pact will be made. Alternatively, a fluidized bedboiler (para. 3-10 c) may be a better economic choicefor such a project.

(1) Wet scrubbers utilize either limestone,lime, or a combination of lime and soda ash as sor-bents for the SO2 and SO3 in the boiler flue gasstream. A mixed slurry of the sorbent material issprayed into the flue gas duct where it mixes withand wets the particulate in the gas stream. The S02

and S09 reacts with the calcium hydroxide of theslurry to form calcium sulfate. The gas then contin-ues to a separator tower where the solids and excesssolution settle and separate from the water vaporsaturated gas stream which vents to the atmospherethrough the boiler stack. Wet scrubbers permit theuse of coal with a sulfur content as high as 5 percent.

(2) Dry scrubbers generally utilize a dilutedsolution of slaked lime slurry which is atomized by

compressed air and injected into the boiler flue gasstream. SO2 and SO3 in the flue gas is absorbed bythe slurry droplets and reacts with the calcium hy-droxide of the slurry to form calcium sulfite. Evapo-ration of the water in the slurry droplets occurs si-multaneously with the reaction. The dry flue gasthen travels to a bag filter system and then to theboiler stack. The bag filter system collects the boilerexit solid particles and the dried reaction products.Additional remaining SO2 and SO3 are removed bythe flue gas filtering through the accumulation onthe surface of the bag filters, Dry scrubbers permitthe use of coal with a sulfur content as high as 3 per-cent.

(3) Induced draft fan requirements. Induceddraft fans will be designed with sufficient capacityto produce the required flow while overcoming thestatic pressure losses associated with the ductwork,economizer, air preheater, and air pollution controlequipment under all operating (clean and dirt y) con-ditions.

(4) Waste removal. Flue gas cleanup systemsusually produce substantial quantities of wasteproducts, often much greater in mass than the sub-stances actually removed from the exit gases. De-sign and arrangement must allow for dewateringand stabilization of FGD sludge, removal, storageand disposal of waste products with due regard forenvironmental impacts.

3-12. Minor auxiliary systemsVarious minor auxiliary systems and componentsare vital parts of the steam generator.

a. Piping and valves. Various piping systems aredefined as parts of the complete boiler (refer to theASME Boiler Code), and must be designed for safeand effective service; this includes steam and feed-water piping, fuel piping, blowdown piping, safetyand control valve piping, isolation valves, drips,drains and instrument connections.

b. Controls and instruments. Superheater and‘burner management controls are best purchasedalong with the steam generator so that there will beintegrated steam temperature and burner systems.

c. Soot blowers. Continuous or frequent on linecleaning of furnace, boiler economizer, and air pre-heater heating surfaces is required to maintain per-formance and efficiency. Soot blower systems,steam or air operated, will be provided for this pur-pose. The selection of steam or air for soot blowingis an economic choice and will be evaluated in termsof steam and makeup water vs. compressed air costswith due allowance for capital and operating costcomponents.

3-25

k

TM 5-811-6

Section Ill. FUEL HANDLING AND STORAGE SYSTEMS

3-13. Introductiona. Purpose. Figure 3-10 is a block diagram illus-

trating the various steps and equipment requiredfor a solid fuel storage and handling system.

b. Fuels for consideration. Equipment requiredfor a system depends on the type of fuel or fuelsburned. The three major types of fuels utilized forsteam raising are gaseous, liquid and solid.

3-14. Typical fuel oil storage and han-dling system

The usual power plant fuel oil storage and handlingsystem includes:

a. Unloading and storage.(1) Unloading pumps will be supplied, as re-

quired for the type of delivery system used, as part

of the power plant facilities. Time for unloading willbe analyzed and unloading pump(s) optimized for the circumstances and oil quantities involved.Heavier fuel oils are loaded into transport tanks hotand cool during delivery. Steam supply for tank carheaters will be provided at the plant if it is expectedthat the temperature of the oil delivered will be be-low the 120 to 150ºF. range.

(2) Storage of the fuel oil will be in two tanks soas to provide more versatility for tank cleanout in-spection and repair. A minimum of 30 days storagecapacity at maximum expected power plant load(maximum steaming capacity of all boilers withmaximum expected turbine generator output andmaximum export steam, if any) will be provided.Factors such as reliability of supply and whether

Figure 3-10. Coal handling system diagram.

3-26

backup power is available from other sources mayresult in additional storage requirements. Space forfuture tanks will be allocated where additional boil-ers are planned, but storage capacity will not be pro-vided initially.

(3) Storage tank(s) for heavy oils will be heatedwith a suction type heater, a continuous coil extend-ing over the bottom of the tank, or a combination ofboth types of surfaces. Steam is usually the mosteconomical heating medium although hot water canbe considered depending on the temperatures atwhich low level heat is available in the power plant.Tank exterior insulation will be provided.

b. Fuelpumps and heaters.(1) Fuel oil forwarding pumps to transfer oil

from bulk storage to the burner pumps will be pro-vided. Both forwarding and burner pumps should beselected with at least 10 percent excess capacityover maximum burning rate in the boilers. Sizingwill consider additional pumps for future boilers andpressure requirements will be selected for pipe fric-tion, control valves, heater pressure drops, andburners. A reasonable selection would be one pumpper boiler with a common spare if the system is de-signed for a common supply to all boilers. For highpressure mechanical atomizing burners, each boilermay also have its own metering pump with spare.

(2) Pumps may be either centrifugal or positivedisplacement. Positive displacement pumps will bespecified for the heavier fuel oils. Centrifugal pumpswill be specified for crude oils. Where absolute relia-ability is required, a spare pump driven by a steamturbine with gear reducer will be used. For “blackstarts, ” or where a steam turbine may be inconven-ient, a dc motor driver may be selected for use forrelatively short periods.

(3) At least two fuel oil heaters will be used forreliability and to facilitate maintenance. Typicalheater design for Bunker C! fuel oil will provide fortemperature increases from 100 to 230° F usingsteam or hot water for heating medium.

c. Piping system.(1) The piping system will be designed to main-

tain pressure by recirculating excess oil to the bulkstorage tank. The burner pumps also will circulateback to the storage tank. A recirculation connectionwill be provided at each burner for startup. It will bemanually valved and shut off after burner is suc-cessfully lit off and operating smoothly.

(2) Piping systems will be adapted to the typeof burner utilized. Steam atomizing burners willhave “blowback” connections to cleanse burners offuel with steam on shutdown. Mechanical atomizingburner piping will be designed to suit the require-ments of the burner.

d. Instruments and control. Instruments and

TM 5-811-6

controls include combustion controls, burner man-agement system, control valves and shut off valves.

3-15. Coal handling and storage systemsa. Available systems. The following principal sys-

tems will be used as appropriate for handling, stor-ing and reclaiming coal:

(1) Relatively small to intermediate system;coal purchases sized and washed. A system with atrack or truck (or combined track/truck) hopper,bucket elevator with feeder, coal silo, spouts andchutes, and a dust collecting system will be used.Elevator will be arranged to discharge via closedchute into one or two silos, or spouted to a groundpile for moving into dead storage by bulldozer. Re-claim from dead storage will be by means of bulldoz-er to track/truck hopper.

(2) Intermediate system; coal purchased sizedand washed. This will be similar to the system de-scribed in (1) above but will use an enclosed skiphoist instead of a bucket elevator for conveying coalto top of silo.

(3) Intermediate system alternatives. For morethan two boilers, an overbunker flight or belt con-veyor will be used. If mine run, uncrushed coalproves economical, a crusher with feeder will be in-stalled in association with the track/truck hopper.

(4) Larger systems, usually with mine run coal.A larger system will include track or truck (or com-bined track/truck) unloading hopper, separate deadstorage reclaim hoppers, inclined belt conveyorswith appropriate feeders, transfer towers, vibratingscreens, magnetic separators, crusher(s), overbunk-er conveyor(s) with automatic tripper, weighingequipment, sampling equipment, silos, dust collect-ing system(s), fire protection, and like items. Wheretwo or more types of coal are burned (e.g., high andlow sulphur), blending facilities will be required.

(5) For cold climates. All systems, regardless ofsize, which receive coal by railroad will require carthawing facilities and car shakeouts for looseningfrozen coal. These facilities will not be provided fortruck unloading because truck runs are usuallyshort.

b. Selection of handling capacity. Coal handlingsystem capacity will be selected so that ultimateplanned 24-hour coal consumption of the plant atmaximum expected power plant load can be unload-ed or reclaimed in not more than 7-1/2 hours, or withinthe time span of one shift after allowance of a 1/2-hourmargin for preparation and cleanup time. The hand-ling capacity should be calculated using the worst(lowest heating value) coal which may be burned inthe future and a maximum steam capacity boiler ef-ficiency at least 3 percent less than guaranteed byboiler manufacturer.

3-27

TM 5-811-6

c. Outdoor storage pile. The size of the outdoorstorage pile will be based on not less than 90 days ofthe ultimate planned 24-hour coal consumption ofthe plant at maximum expected power plant load.Some power plants, particularly existing plantswhich are being rehabilitated or expanded, will haveoutdoor space limitations or are situated so that it isenvironmentally inadvisable to have a substantialoutdoor coal pile.

d. Plant Storage.(1) For small or medium sized spreader stoker

fired plants, grade mounted silo storage will be spe-cified with a live storage shelf above and a reservestorage space below. Usually arranged with one siloper boiler and the silo located on the outside of thefiring aisle opposite the boiler, the live storage shelfwill be placed high enough so that the spout to thestoker hopper or coal scale above the hopperemerges at a point high enough for the spout angleto be not less than 60 degrees from the horizontal.The reserve storage below the live storage shelf willbe arranged to recirculate back to the loading pointof the elevator so that coal can be raised to the top ofthe live storage shelf as needed. Figure 3-11 shows a

typical bucket elevator grade mounted silo arrange-ment for a small or medium sized steam generatingfacility.

(2) For large sized spreader stoker fired plants,silo type overhead construction will be specified. Itwill be fabricated of structural steel or reinforcedconcrete with stainless steel lined conical bottoms.

(3) For small or medium sized plants combinedlive and reserve storage in the silo will be not lessthan 3 days at 60 percent of maximum expectedload of the boiler(s) being supplied from the silo sothat reserves from the outside storage pile need notbe drawn upon during weekends when operatingstaff is reduced. For large sized plants this storagerequirement will be 1 day.

e. Equipment and systems.(1) Bucket elevators. Bucket elevators will be

chain and bucket type. For relatively small installa-tions the belt and bucket type is feasible althoughnot as rugged as the chain and bucket type. Typicalbucket elevator system is shown in Figure 3-11.

(2) Skip hoists. Because of the requirement fordust suppression and equipment closure dictated by

environmental considerations, skip hoists will notbe specified.

(3) Belt conveyors. Belt conveyors will be se- lected for speeds not in excess of 500 to 550 feet per

minute. They will be specified with roller bearingsfor pulleys and idlers, with heavy duty belts, andwith rugged helical or herringbone gear drive units.

(4) Feeders. Feeders are required to transfercoal at a uniform rate from each unloading and inter-mediate hopper to the conveyor. Such feeders will beof the reciprocating plate or vibrating pan type withsingle or variable speed drive. Reciprocating typefeeders will be used for smaller installations; the vi-brating type will be used for larger systems.

(5) Miscellaneous. The following items are re-quired as noted

(a) Magnetic separators for removal of trampiron from mine run coal.

(b) Weigh scale at each boiler and, for largerinstallations, for weighing in coal as received. Scaleswill be of the belt type with temperature compensat-ed load cell. For very small installations, a low costdisplacement type scale for each boiler will be used.

(c) Coal crusher for mine run coal; for large in-stallations the crusher will be preceded by vibrating(scalping) screens for separating out and by-passingfines around the crusher.

(d) Traveling tripper for overbunker conveyor serving a number of bunkers in series.

(e) One or more coal samplers to check “as re-

TM 5-811-6

ceived” and’ ‘as fired” samples for large systems.(f) Chutes, hoppers and skirts, as required,

fabricated of continuously welded steel for dusttightness and with wearing surfaces lined withstainless steel. Vibrators and poke holes will be pro-vided at all points subject to coal stoppage or hang-up.

(g) Car shakeout and a thaw shed for loosen-ing frozen coal from railroad cars.

(h) Dust control systems as required through-out the coal handling areas. All handling equip-ment—hoppers, conveyors and galleries-will be en-closed in dust tight casings or building shells andprovided with negative pressure ventilation com-plete with heated air supply, exhaust blowers, sepa-rators, and bag filters for removing dust from ex-hausted air. In addition, high dust concentrationareas located outside which cannot be enclosed, suchas unloading and reclaim hoppers, will be providedwith spray type dust suppression equipment.

(i) Fire protection system of the sprinklertype.

(j) Freeze protection for any water piping lo-cated outdoors or in unheated closures as providedfor dust suppression or fire protection systems.

(k) A vacuum cleaning system for mainte-nance of coal handling systems having galleries andequipment enclosures.

(l) System of controls for sequencing andmonitoring entire coal handling system.

Section IV. ASH HANDLING SYSTEMS3-16. Introduction

a. Background.(1) Most gaseous fuels burn cleanly, and the

amount of incombustible material is so small that itcan be safely ignored. When liquid or solid fuel isfired in a boiler, however, the incombustible materi-al, or ash, together with a small amount of unburnedcarbon chiefly in the form of soot or cinders, collectsin the bottom of the furnace or is carried out in alightweight, finely divided form usually knownloosely as “fly ash.” Collection of the bottom ashfrom combustion of coal has never been a problem asthe ash is heavy and easily directed into hopperswhich may be dry or filled with water,

(2) Current ash collection technology is capableof removing up to 99 percent or more of all fly ashfrom the furnace gases by utilizing a precipitator orbaghouse, often in combination with a mechanicalcollector. Heavier fly ash particles collected fromthe boiler gas passages and mechanical collectors of-ten have a high percentage of unburned carbon con-

tent, particularly in the case of spreader stoker firedboilers; this heavier material may be reinfected intothe furnace to reduce unburned carbon losses and in-

crease efficiency, although this procedure does in-crease the dust loading on the collection equipmentdownstream of the last hopper from which such ma-terial is reinfected.

(3) It is mandatory to install precipitators orbaghouses on all new coal fired boilers for finalcleanup of the flue gases prior to their ejection to at-mosphere. But in most regions of the United States,mechanical collectors alone are adequate for heavyoil fired boilers because of the conventionally lowash content of this type of fuel. An investigation isrequired, however, for each particular oil fired unitbeing considered.

b. Purpose. It is the purpose of the ash handlingsystem to:

(1) Collect the bottom ash from coal-firedspreader stoker or AFBC boilers and to convey itdry by vacuum or hydraulically by liquid pressureto a temporary or permanent storage terminal. Thelatter may be a storage bin or silo for ultimate trans-fer to rail or truck for transport to a remote disposalarea, or it maybe an on-site fill area or storage pondfor the larger systems where the power plant site is

3-29

TM 5-811-6

adequate and environmentally acceptable for thispurpose.

(2) Collect fly ash and to convey it dry to tem-porary or permanent storage as described above forbottom ash. Fly ash, being very light, will be wettedand is mixed with bottom ash prior to disposal toprevent a severe dust problem.

3-17. Description of major componentsa. Typical oil fired system. Oil fired boilers do not

require any bottom ash removal facilities, since ashand unburned carbon are light and carried out withthe furnace exit gas. A mechanical collector may berequired for small or intermediate sized boilers hav-ing steaming rates of 200,000 pounds per hour orless. The fly ash from the gas passage and mechani-cal collector hoppers can usually be handled manu-ally because of the small amount of fly ash (soot) col-lected. The soot from the fuel oil is greasy and cancoagulate at atmospheric temperatures making itdifficult to handle. To overcome this, hoppersshould be heated with steam, hot water, or electricpower. Hoppers will be equipped with an outletvalve having an air lock and a means of attachingdisposable paper bags sized to permit manual hand-ling. Each hopper will be selected so that it need notbe evacuated more than once every few days. If boil-er size and estimated soot/ash loading is such thatmanual handling becomes burdensome, a vacuum orhydraulic system as described below should be con-sidered.

b. Typical ash handling system for small or intermediate sized coal fired boilers;

(1) Plant fuel burning rates and ash content ofcoal are critical in sizing the ash handling system.Sizing criteria will provide for selecting hoppers andhandling equipment so that ash does not have to beremoved more frequently than once each 8-hourshift using the highest ash content coal anticipatedand with boiler at maximum continuous steamingcapacity. For the smaller, non-automatic system itmay be cost effective to select hoppers and equipment which will permit operating at 60 percent ofmaximum steam capacity for 3 days without remov-ing ash to facilitate operating with a minimumweekend crew.

(2) For a typical military power plant, the mosteconomical selection for both bottom and fly ash dis-posal is a vacuum type dry system with a steam jet

or mechanical(Figure 3-12).

exhauster for creating the vacuumThis typical plant would probably

have a traveling grate spreader stoker, a mechanical collector, and a baghouse; in all likelihood, no on-siteash disposal area would be available.

(3) The ash system for the typical plant will in-clude the following for each boiler:

(a) A refractory lined bottom ash hopper toreceive the discharge from the traveling grate. Aclinker grinder is not required for a spreader stokeralthough adequate poke holes should be incorpor-ated into the outlet sections of the hopper.

(b) Gas passage fly ash hoppers as required by the boiler design for boiler proper, economizer,and air heater.

(c) Collector fly ash hoppers for the mechani- cal collector and baghouse.

(d) Air lock valves, one at each hopper outlet,manually or automatically operated as selected bythe design engineer.

(4) And the following items are common to allboilers in the plant:

(a) Ash collecting piping fabricated of specialhardened ferro-alloy to transfer bottom and fly ashto Storage.

(b) Vacuum producing equipment, steam ormechanical exhauster as may prove economical. Forplants with substantial export steam and with lowquality, relatively inexpensive makeup require- ments, steam will be the choice. For plants withhigh quality, expensive makeup requirements,consideration should be given to the higher cost me-chanical exhauster.

(c) Primary and secondary mechanical (centri-fugal) separators and baghouse filter are used toclean the dust out of the ash handling system ex-haust prior to discharge to the atmosphere. This equipment is mounted on top of the silo.

(d) Reinforced concrete or vitrified tile over-head silo with separator and air lock for loading silo with a “dustless” unloader designed to dampenashes as they are unloaded into a truck or railroadcar for transport to remote disposal.

(e) Automatic control system for sequencingoperation of the system. Usually the manual initia-tion of such a system starts the exhauster and thenremoves bottom and fly ash from each separator col-lection point in a predetermined sequence. Ash un-loading to vehicles is separately controlled.

Section V. TURBINES AND AUXILIARY SYSTEMS

3-18. Turbine prime movers generator and its associated electrical accessories,The following paragraphs on turbine generators dis- refer to Chapter 4.cuss size and other overall characteristics of the tur- a. Size and type ranges. Steam turbine gener-bine generator set. For detailed discussion of the ators for military installations will fall into the fol-

3-30

Figure 3-12. Pneumatic ash handling systems—variations.

TM 5-811-6

lowing size ranges:(1) Small turbine generators. From 500 to about

2500 kW rated capacity, turbine generators willusually be single stage, geared units without extrac-tion openings for either back pressure or condensingservice. Rated condensing pressures for single stageturbines range from 3 to 6 inches Hga. Exhaustpressures for back pressure units in cogenerationservice typically range from 15 psig to 250 psig.

(2) Intermediate turbine generators. Fromabout 2500 to 10,000 kW rated capacity, turbinegenerators will be either multi-stage, multi-valvemachines with two pole direct drive generators turn-ing at 3600 rpm, or high speed turbines with gear re-ducers may also be used in this size range. Units areequipped with either uncontrolled or controlled (au-tomatic) extraction openings. Below 4000 kW, therewill be one or two openings with steam pressures upto 600 psig and 750°F. From 4000 kW to 10,000kW, turbines will be provided with two to four un-controlled extraction openings, or one or two auto-matic extraction openings. These turbines wouldhave initial steam conditions from 600 psig to 1250psig, and 750°F to 900°F. Typical initial steam con-ditions would be 600 psig, 825º For 850 psig, 900°F.

(3) Large turbine generators. In the capacityrange 10,000 to 30,000 kW, turbine generators willbe direct drive, multi-stage, multi-valve units. Forelectric power generator applications, from two tofive uncontrolled extraction openings will be re-quired for feedwater heating. In cogeneration appli-cations which include the provision of process orheating steam along with power generation, one au-tomatic extraction opening will be required for eachlevel of processor heating steam pressure specified,along with uncontrolled extraction openings forfeedwater heating. Initial steam conditions range upto 1450 psig and 950 “F with condensing pressuresfrom 1 1/2 to 4 inches Hga.

b. Turbine features and accessories. In all sizeranges, turbine generator sets are supplied by themanufacturer with basic accessories as follows:

(1) Generator with cooling system, excitationand voltage regulator, coupling, and speed reduc-tion gear, if used.

(2) Turbine and generator (and gear) lubricationsystem including tank, pumps, piping, and controls.

(3) Load speed governor, emergency overspeedgovernor, and emergency inlet steam trip valve withrelated hydraulic piping.

(4) Full rigid base plate in small sizes or sepa-rate mounting sole plates for installation in concretepedestal for larger units.

(5) Insulation and jacketing, instruments, turn-ing gear and special tools.

3-19. GeneratorsFor purposes of this section, it is noted that the gen-erator must be mechanically compatible with the driving turbine, coupling, lubrication system, andvibration characteristics (see Chapter 4 for gener-ator details).

3-20. Turbine featuresa. General. Turbine construction may be general-

ly classified as high or low pressure, single or multi-stage, back pressure on condensing, direct drive orgear reducer drive, and for electric generator or formechanical drive service.

(1) Shell pressures. High or low pressure con-struction refers generally to the internal pressuresto be contained by the main shell or casing parts.

(2) Single us. multi-stage. Single or multi-stagedesigns are selected to suit the general size,enthalpy drops and performance requirements ofthe turbine. Multi-stage machines are much moreexpensive but are also considerably more efficient.Single stage machines are always less expensive,simpler and less efficient. They may have up tothree velocity wheels of blading with reentry sta-tionary vanes between wheels to improve efficiency.As casing pressure of single stage turbines are equalto exhaust pressures, the design of seals and bear-ings is relatively simple.

(3) Back pressure vs. condensing. Selection of a back pressure or a condensing turbine is dependenton the plant function and cycle parameters. (SeeChapter 3, Section I for discussion of cycles.) Con-densing machines are larger and more complex withhigh pressure and vacuum sealing provisions, steamcondensers, stage feedwater heating, extensive lubeoil systems and valve gear, and related auxiliary fea-tures.

(4) Direct drive vs. geared sets. Direct drive tur-bines generators turn the turbine shaft at generatorspeed. Units 2500 kW and larger are normally directconnected. Small, and especially single stage, tur-bines may be gear driven for compactness and forsingle stage economy. Gear reducers add complex-ity and energy losses to the turbine and should beused only after careful consideration of overall econ-omy and reliability.

(5) Mechanical drive. Main turbine units inpower plants drive electrical generators, althoughlarge pumps or air compressors may also be drivenby large turbines. In this event, the turbines arecalled “mechanical drive” turbines. Mechanicaldrive turbines are usually variable speed units withspecial governing equipment to adapt to best econ-omy balance between driver (turbine) and driven ma-chine. Small auxiliary turbines for cycle pumps,

3-32

fans, or air compressor drives are usually singlestage, back pressure, direct drive type designed formechanical simplicity and reliability. Both constantspeed and variable speed governors are used de-pending on the application.

b. Arrangement. Turbine generators are horizon-tal shaft type with horizontally split casings. Rela-tively small mechanical drive turbines may be builtwith vertical shafts. Turbine rotor shaft is usuallysupported in two sleeve type, self aligning bearings,sealed and protected from internal casing steamconditions. Output shaft is coupled to the shaft ofthe generator which is provided with its own enclo-sure but is always mounted on the same foundationas the turbine.

(1) Balance. Balanced and integrated design ofthe turbine, coupling and generator moving parts isimportant to successful operation, and freedomfrom torsional or lateral vibrations as well as pre-vention of expansion damage are essential.

(2) Foundations. Foundations and pedestals forturbine generators will be carefully designed to ac-commodate and protect the turbine generator, con-denser, and associated equipment. Strength, mass,stiffness, and vibration characteristics must be con-sidered. Most turbine generator pedestals in theUnited States are constructed of massive concrete.

3-21. Governing and controla. Turbine generators speed/load control. Electri-

cal generator output is in the form of synchronizedac electrical power, causing the generator and driv-ing turbine to rotate at exactly the same speed (orfrequency) as other synchronized generators con-nected into the common network. Basic speed/loadgoverning equipment is designed to allow each unitto hold its own load steady at constant frequency, orto accept its share of load variations, as the commonfrequency rises and falls. Very small machines mayuse direct mechanical governors, but the bulk of theunits will use either mechanical-hydraulic governingsystems or electrohydraulic systems. Non-reheatcondensing units 5000 kW and larger and back pres-sure units without automatic extraction will beequipped with mechanical-hydraulic governing. Forautomatic extraction units larger than 20,000 kW,governing will be specified either with a mechanical-hydraulic or an electro-hydraulic system.

b. Overspeed governors. All turbines require sep-arate safety or overspeed governing systems to in-sure inlet steam interruption if the machine exceedsa safe speed for any reason. The emergency gover-nor closes a specially designed stop valve which notonly shuts off steam flow but also trips various safe-ty devices to prevent overspeed by flash steam in-

TM 5-811-6

duction through the turbine bleed (extraction)points.

c. Single and multi-valve arrangements. What-ever type of governor is used, it will modulate theturbine inlet valves to regulate steam flow and tur-bine output. For machines expected to operate ex-tensively at low or partial loads, multi-valve ar-rangements improve economy. Single valve tur-bines, in general, have equal economy and efficiencyat rated load, but lower part load efficiencies.

3-22. Turning geara. General. For turbines sized 10,000 kW and

larger, a motor operated turning gear is required toprevent the bowing of the turbine rotor created bythe temperature differential existing between theupper and lower turbine casings during the long pe-riod after shutdown in which the turbine cools down.The turbine cannot be restarted until it has com-pletely cooled down without risk of damage to inter-state packing and decrease of turbine efficiency,causing delays in restarting. The turning gear ismounted at the exhaust end of the turbine and isused to turn the rotor at a speed of 1 to 4 rpm whenthe turbine is shut down in order to permit uniformcooling of the rotor. Turning gear is also used duringstartup to evenly warm up the rotor before rollingthe turbine with steam and as a jacking device forturning the rotor as required for inspection andmaintenance when the turbine is shut down.

b. Arrangement and controls. The turning gearwill consist of a horizontal electric motor with a setof gear chains and a clutching arrangement whichengages a gear ring on the shaft of the turbine. Itscontrols are arranged for local and/or remote start-ing and to automatically disengage when the tur-bine reaches a predetermined speed during startupwith steam. It is also arranged to automatically en-gage when the turbine has been shut down and de-celerated to a sufficiently slow speed. Indicatinglights will be provided to indicate the disengaged orengaged status of the turning gear and an interlockprovided to prevent the operation of the turning gear if the pressure in the turbine lubrication oil sys-tem is below a predetermined safe setting.

3-23. Lubrication systemsa. General. Every turbine and its driven machine

or generator requires adequate lubricating oil supply including pressurization, filtration, oil cooling,and emergency provisions to insure lubrication inthe event of a failure of main oil supply. For a typ-ical turbine generator, an integrated lube oil storagetank with built in normal and emergency pumps isusually provided. Oil cooling may be by means of an

3-33

TM 5-811-6

external or internal water cooled heat exchanger. Oiltemperatures should be monitored and controlled,and heating may be required for startup.

b. Oil Pumps. Two full capacity main lube oilpumps will be provided. One will be directly drivenfrom the turbine shaft for multi-stage machines.The second full size pump will be ac electric motordriven. An emergency dc motor driven or turbine-driven backup pump will be specified to allow or-derly shutdown during normal startup and shut-down when the shaft driven pump cannot maintainpressure, or after main pump failure, or in the eventof failure of the power supply to the ac electric mo-tor driven pumps.

c. Filtration. Strainers and filters are necessaryfor the protection and longevity of lubricated parts.Filters and strainers should be arranged in pairs foron line cleaning, inspection, and maintenance. Larg-er turbine generator units are sometimes equippedwith special off base lubrication systems to provideseparate, high quality filtering.

3-24. Extraction featuresa. Uncontrolled extraction systems. Uncontrolled

bleed or extraction openings are merely nozzles inthe turbine shell between stages through which rela-tively limited amounts of steam may be extractedfor stage feedwater heating. Such openings addlittle to the turbine cost as compared with the costof feedwater heaters, piping, and controls. Turbinesso equipped are usually rated and will have efficien-cies and performance based on normal extractionpressures and regenerative feedwater heating calcu-lations. Uncontrolled extraction opening pressureswill vary in proportion to turbine steam flow, and

extracted steam will not be used or routed to anysubstantial uses except for feedwater heating.

b. Automatic extraction. Controlled or automaticextraction turbines are more elaborate and equipped with variable internal orifices or valves to modulateinternal steam flows so as to maintain extractionpressures within specified ranges. Automatic ex-traction machine governors provide automatic self-contained modulation of the internal flow orifices orvalves, using hydraulic operators. Automatic ex-traction governing systems can also be adapted torespond to external controls or cycle parameters topermit extraction pressures to adjust to changingcycle conditions.

c. Extraction turbine selection. Any automaticextraction turbine is more expensive than itsstraight uncontrolled extraction counterpart of sim-ilar size, capacity and type; its selection and use re-quire comprehensive planning studies and economicanalysis for justification. Sometimes the same ob-jective can be achieved by selecting two units, one ofwhich is an uncontrolled extraction-condensing ma-chine and the other a back pressure machine.

3-25. Instruments and special toolsa. Operating instruments. Each turbine will be

equipped with appropriate instruments and alarmsto monitor normal and abnormal operating condi-tions including speed, vibration, shell and rotor ex-pansions, steam and metal temperatures, rotorstraightness, turning gear operation, and varioussteam, oil and hydraulic system pressures.

b. Special took. Particularly for larger machines,complete sets of special tools, lifting bars, and re-lated special items are required for organized and ef-fective erection and maintenance.

Section VI. CONDENSER AND CIRCULATING WATERSYSTEM

3-26. Introductiona. Purpose.

(1) The primary purpose of a condenser and cir-culating water system is to remove the latent heatfrom the steam exhausted from the exhaust end ofthe steam turbine prime mover, and to transfer thelatent heat so removed to the circulating waterwhich is the medium for dissipating this heat to theatmosphere. A secondary purpose is to recover thecondensate resulting from the phase change in theexhaust steam and to recirculate it as the workingfluid in the cycle.

(2) Practically, these purposes are accom-plished in two steps. In the first step, the condenseris supplied with circulating water which serves as amedium for absorbing the latent heat in the con-densing exhaust steam. The source of this circulat-

ing water can be a natural body of water such as anocean, a river, or a lake, or it can be from a recircu-lated source such as a cooling tower or cooling pond.In the second step, the heated circulating water isrejected to the natural body of water or recirculatedsource which, in turn, transfers the heat to the at-mosphere, principally by evaporative cooling effect.

b. Equipment required—general. Equipment re-quired for a system depends on the type of systemutilized. There are two basic types of con-densers: surface and direct contact.

There are also two basic types of cooling sys-tems:

Once through; andRecirculating type, including cooling ponds, me-

chanical draft cooling towers, natural draft coolingtowers, or a combination of a pond and tower.

3-34

TM 5-811-6

3-27. Description of major componentsa. Surface condensers.

(1) General description. These units are de-signed as shell and tube heat exchangers. A surfacecondenser consists of a casing or shell with a cham-ber at each end called a “water box. ” Tube sheetsseparate the two water boxes from the center steamspace. Banks of tubes connect the water boxes bypiercing the tube sheets; the tubes essentially fillthe shell or steam space. Circulating water pumpsforce the cooling (circulating] water through the wa-ter boxes and the connecting tubes. Uncontami-.nated condensate is recovered in surface condenserssince the cooling water does not mix with the con-densing steam. Steam pressure in a condenser (or

* vacuum) depends mainly on the flow rate and tem-perature of the cooling water and on the effective-ness of air removal equipment.

(2) Passes and water boxes.(a) Tubing and water boxes may be arranged

for single pass or two pass flow of water through theshell. In single pass units, water enters the waterbox at one end of the tubes, flows once through allthe tubes in parallel, and leaves through the outletwater box at the opposite end of the tubes. In twopass units, water flows through the bottom half ofthe tubes (sometimes the top half) in one direction,

Lreverses in the far end water box, and returnsthrough the upper or lower half of the tubes to thenear water box. Water enters and leaves through thenear water box which is divided into two chambersby a horizontal plate. The far end water box is undi-vided to permit reversal of flow.

(b) For a relatively large cooling water sourceand low circulating water pump heads (hence lowunit pumping energy costs), single pass units will be.used. For limited cooling water supplies and highcirculating water pump heads (hence high unitpumping energy costs), two pass condensers will be

< specified. In all cases, the overall condenser-circulat-ing water system must be optimized by the designerto arrive at the best combination of condenser sur-face, temperature, vacuum, circulating waterpumps, piping, and ultimate heat rejection equip-ment.

(c) Most large condensers, in addition to theinlet waterbox horizontal division, have vertical par-titions to give two separate parallel flow pathsthrough the shell. This permits taking half the con-densing surface our of service for cleaning while wa-ter flows through the other half to keep the unit run-ning at reduced load.

(3) Hot well. The hot well stores the condensate‘L and keeps a net positive suction head on the conden-

sate pumps. Hot well will have a capacity of at least3 minutes maximum condensing load for surges and

to permit variations in level for the condensate con-trol system.

(4) Air removal offtakes. One or more air off-takes in the steam space lead accumulating air tothe air removal pump.

(5) Tubes.(a) The tubes provide the heat transfer sur-

face in the condenser are fastened into tube sheets,usually made of Muntz metal. Modern designs havetubes rolled into both tube sheets; for ultra-tight-ness, alloy steel tubes may be welded into tubesheets of appropriate material. Admiralty is themost common tube material and frequently is satis-factory for once through systems using fresh waterand for recirculating systems. Tube material in the“off gas” section of the condenser should be stain-less steel because of the highly corrosive effects ofcarbon dioxide and ammonia in the presence ofmoisture and oxygen. These gases are most concen-trated in this section. Other typical condenser tubematerials include:

(1) Cupronickel(2) Aluminum bronze(3) Aluminim brass(4) Various grades of stainless steel

(b) Condenser tube water velocities rangefrom 6 to 9 feet per second (Table 3- 12). Higher flowrates raise pumping power requirements and erodetubes at their entrances, thus shortening their lifeexpectancy. Lower velocities are inefficient from aheat transfer point of view. Tubes are generally in-stalled with an upwardly bowed arc. This providesfor thermal expansion, aids drainage in a shutdowncondenser, and helps prevent tube vibration.

b. Direct contact condensers. Direct contact con-densers will not be specified.

c. Condenser auxiliaries.(1) General. A condenser needs equipment and

conduits to move cooling water through the tubes,remove air from the steam space, and extract con-densate from the hotwell. Such equipment and con-duits will include:

(a) Circulating water pumps.(b) Condensate or hotwell pumps.(c) Air removal equipment and piping.(d) Priming ejectors.(e) Atmospheric relief valve.(f) Inlet water tunnel, piping, canal, or com-

bination of these conduits.(g) Discharge water tunnel, piping or canal,

or combination of these conduits.(2) Circulating water pumps. A condenser uses

75 to 100 pounds of circulating water per pound ofsteam condensed. Hence, large units need substan-tial water flows; to keep pump work to a minimum,top of condenser water boxes in a closed system will

3-35

TM 5-811-6

Table 3-12. Condenser Tube Design Velocities.

Material Design Velocities fps

Fresh Water Brackish Water Salt Water

Admiralty Metal 7.0 (1) (1)

Aluminum Brass(2) 8.0 7.0 7.0

Copper-Nickel Alloys:

90-10 8.0 8.0 7.0 to 7.5

80-20 8.0 8.0 7.0 to 7.5

70-30 9.0 9.0 8.0 to 8.5

Stainless Steel 9.0 to 9.5 8 . 0( 3 ) 8 . 0( 3 )

Aluminum (4) 8.0 7.0 6.8

NOTES :

(1) Not normally used, but if used, velocity shall not exceed 6.0 fps.

(2) For salt and brackish water , velocities in excess of 6.8 fps arenot recommended.

(3) Minimum velocity of 5.5 fps to prevent chloride attack.

(4) Not recommended for circulating water containing high concentrationof heavy metal salts.

U.S. Army Corps of Engineers

not be higher than approximately 27 feet above min-imum water source level which permits siphon oper-ation without imposing static head. With a siphonsystem, air bubbles tend to migrate to the top of thesystem and must be removed with vacuum-produc-ing equipment. The circulating pumps then need todevelop only enough head to overcome the flow re-sistance of the circulating water circuit. Circulatingpumps for condensers are generally of the centrif-ugal type for horizontal pumps, and either mixedflow or propeller type for vertical pumps. Verticalpumps will be specified because of their adaptabilityfor intake structures and their ability to handle highcapacities at relatively low heads. Pump materialwill be selected for long life.

(3) Condensate pumps. Condensate (or hotwell)

pumps handle much smaller flows than the circulat-ing water pumps. They must develop heads to pushwater through atmospheric pressure, pipe and con-trol valve friction, closed heater water circuit fric-tion, and the elevation of the deaerator storage tank.These pumps take suction at low pressure of twoinches Hg absolute or less and handle water at sat-uration temperature; to prevent flashing of the con-densate, they are mounted below the hotwell to re-ceive a net positive suction head. Modern vertical“can” type pumps will be used. Specially designedpump glands prevent air leakage into the conden-sate, and vents from the pump connecting to the va-por space in the condenser prevent vapor binding.

(4) Spare pumps. Two 100 percent pumps for both circulating water and condensate service will

be specified. If the circulating water system servesmore than one condenser, there will be one circulat-

ing pump per condenser with an extra pump as acommon spare. Condensate pump capacity will besized to handle the maximum condenser load underany condition of operation (e.g., with automatic ex-traction to heating or process shutoff and includingall feedwater heater drains and miscellaneous dripsreceived by the condenser.)

(5) Air removal.(a) Non-condensable gases such as air, carbon

dioxide, and hydrogen migrate continuously intothe steam space of a condenser inasmuch as it is thelowest pressure region in the cycle. These gases mayenter through leakage at glands, valve bonnets, por-ous walls, or may be in the throttle steam. Thosegases not dissolved by the condensate diffusethroughout the steam space of the condenser. Asthese gases accumulate, their partial pressure raisesthe condenser total pressure and hence decreases ef-ficiency of the turbine because of loss of availableenergy. The total condenser pressure is:

Pc = PS+ Pa

where Ps = steam saturation pressure cor-responding to steam tempera-ture

Pa = air pressure (moisture free)

LThis equation shows that air leakage must be re-moved constantly to maintain lowest possible vac-uum for the equipment selected and the particularexhaust steam loading. In removing this air, it willalways have some entrained vapor. Because of itssubatmospheric pressure, the mixture must be com-pressed for discharge to atmosphere.

(b) Although the mass of air leakage to thecondenser may be relatively small because of its.very low pressure, its removal requires handling of alarge volume by the air removal equipment. The airofftakes withdraw the air-vapor moisture from the. steam space over a cold section of the condensertubes or through an external cooler, which con-denses part of the moisture and increases the air-to-steam ratio. Steam jets or mechanical vacuumpumps receive the mixture and compress it to at-mosphere pressure.

(6) Condenser cleanliness. Surface condenserperformance depends greatly on the cleanliness ofthe tube water side heat transfer surface. Whendirty fresh water or sea water is used in the circulat-ing water system, automatic backflush or mechan-ical cleaning systems will be specified for on linecleaning of the interior condenser tube surfaces.

d. Circulating water system–once through(1) System components. A typical once through

circulating water system, shown in figure 3-13, con-sists of the following components:

(a)(b)(c)(d)(e)(f)

TM 5-811-6

Intake structure.Discharge, or outfall.Trash racks.Traveling screens.Circulating water pumps.Circulating water pump structure (indoor

or outdoor).(g) Circulating water canals, tunnels, and

pipework.(2) System operation.

(a) The circulating water system functions asfollows. Water from an ocean, river, lake, or pondflows either directly from the source to the circulat-ing water structure or through conduits which bringwater from offshore; the inlet conduits dischargeinto a common plenum which is part of the circulat-ing water pump structure. Water flows through bartrash racks which protect the traveling screens fromdamage by heavy debris and then through travelingscreens where smaller debris is removed. For largesystems, a motor operated trash rake can be in-stalled to clear the bar trash racks of heavy debris.In case the traveling screens become clogged, or toprevent clogging, they are periodically backwashesby a high pressure water jet system. The backwashis returned to the ocean or other body of water. Eachseparate screen well is provided with stop logs andsluice gates to allow dewatering for maintenancepurposes.

(b) The water for each screen flows to the suc-tion of the circulating water pumps. For small sys-tems, two 100-percent capacity pumps will be se-lected while for larger systems, three 50-percentpumps will be used. At least one pump is requiredfor standby. Each pump will be equipped with a mo-torized butterfly valve for isolation purposes. Thepumps discharge into a common circulating watertunnel or supply pipe which may feed one or morecondensers. Also, a branch line delivers water to thebooster pumps serving the closed cooling water ex-changers.

(c) Both inlet and outlet water boxes of themain condensers will be equipped with butterflyvalves for isolation purposes and expansion joints.As mentioned above, the system may have the capa-bility to reverse flow in each of the condenser halvesfor cleaning the tubes. The frequency and durationof the condenser reverse flow or back wash opera-tion is dictated by operating experience.

(d) The warmed circulating water from thecondensers and closed cooling water exchangers isdischarged to the ocean, river, lake, or pond via acommon discharge tunnel.

(3) Circulating water pump setting. The circu-lating water pumps are designed to remain operablewith the water level at the lowest anticipated eleva-

3-37

TM 5-811-6I

NAVFAC DM3

Figure 3-13. Types of circulating water systems.

tion of the selected source. This level is a function ofthe neap tide for an ocean source and seasonal levelvariations for a natural lake or river. Cooling pondsare usually man-made with the level controlled with-in modest limits. The pump motors and valve motoroperators will be located so that no electrical partswill be immersed in water at the highest anticipatedelevation of the water source.

(4) System pressure control. On shutdown of acirculating water pump, water hammer is avoidedby ensuring that the pumps coast down as the pumpisolation valves close. System hydraulics, circulat-ing pump coastdown times, and system isolationvalve closing times must be analyzed to precludedamage to the system due to water hammer. Thecondenser tubes and water boxes are to be designedfor a pressure of approximately 25 psig which is wellabove the ordinary maximum discharge pressure ofthe circulating water pumps, but all equipmentmust be protected against surge pressures causedby sudden collapse of system pressure.

(5) Inspection and testing. All active compo-nents of the circulating water system will be accessi-ble for inspection during station operation.

e. Circulating water system—recirculating type(1) General discussion.

(a) With a once-through system, the evapora-tive losses responsible for rejecting heat to the at-mosphere occur in the natural body of water as thewarmed circulating water is mixed with the residualwater and is cooled over a period of time by evapora-tion and conduction heat transfer. With a recircula-tion system, the same water constantly circulates;evaporative losses responsible for rejecting heat tothe atmosphere occur in the cooling equipment andmust be replenished at the power plant site. Recircu-lating systems can utilize one of the following forheat rejection:

(1) A natural draft, hyperbolic cooling tow-er.

(2) A mechanical draft cooling tower, us-ually induced draft.

(3) A spray pond with a network of pipingserving banks of spray nozzles.

(b) Very large, man-made ponds which takeadvantage of natural evaporative cooling may beconsidered as “recirculating” systems, although fordesign purposes of the circulating water system

3-38

TM 5-811-6

they are once through and hence considered as suchin paragraph d above.

(c) To avoid fogging and plumes which arecharacteristic of cooling towers under certain at-mospheric conditions in humid climates, so calledwet-dry cooling towers may be used. These towersuse a combination of finned heat transfer surfaceand evaporative cooling to eliminate the fog and vis-ible plume. The wet-dry types of towers are expen-sive and not considered in this manual. Hyperbolictowers also are expensive and are not applicable tounits less than 300-500 M W; while spray pondshave limited application (for smaller units) becauseof the large ground area required and the problem ofexcessive drift. Therefore, the following descriptivematerial applies only to conventional induced draftcooling towers which, except for very special cir-cumstances, will be the choice for a military powerplant requiring a recirculating type system.

(2) System components. A typical recirculatingsystem with a mechanical draft cooling tower con-sists of the following components:

(a) Intake structure which is usually an ex-tension of the cooling tower basin.

(b) Circulating water pumps.(c) Circulating water piping or tunnels to con-

densers and from condensers to top of cooling tower.(d) Cooling tower with makeup and blowdown

systems.(3) System operation.

(a) The recirculating system functions as fol-lows. Cooled water from the tower basin is directedto the circulating water pump pit. The pit is similarto the intake structure for a once through system ex-cept it is much simpler because trash racks or trav-eling screens are not required, and the pit settingcan be designed without reference to levels of a nat-ural body of water. The circulating water pumpspressure the water and direct it to the condensersthrough the circulating water discharge piping. Astream of circulating water is taken off from themain condenser supply and by means of boosterpumps further pressurized as required for bearingcooling, generator cooling, and turbine generator oilcooling. From the outlet of the condensers and mis-cellaneous cooling services, the warmed circulatingwater is directed to the top of the cooling tower forrejection of heat to the atmosphere.

(b) Circulating water pump and condenservalving is similar to that described for a typicalonce-through system, but no automatic back flush-ing or mechanical cleaning system is required forthe condenser. Also, due to the higher pumping

heads commonly required for elevating water to thetop of the tower and the break in water pressure atthat point which precludes a siphon, higher pressure

ratings for the pumps and condensers will be speci-fied.

(4) Cooling tower design.(a) In an induced draft mechanical cooling

tower, atmospheric air enters the louvers at the bot-tom perimeter of the tower, flows up through thefill, usually counterflow to the falling water droplets, and is ejected to the atmosphere in saturatedcondition thus carrying off the operating load ofheat picked up in the condenser. Placement and ar-rangement of the tower or towers on the power sta-tion site will be carefully planned to avoid recircula-tion of saturated air back into the tower intake andto prevent drift from the tower depositing on elec-trical buses and equipment in the switchyard, road-ways and other areas where the drift could be detri-mental.

(b) Hot circulating water from the condenserenters the distribution header at the top of the tow-er. In conventional towers about 75 percent of thecooling takes place be evaporation and the re-mainder by heat conduction; the ratio depends onthe humidity of the entering air and various factors.

(5) Cooling tower performance. The principalperformance factor of a cooling tower is its approachto the wet bulb temperature; this is the differencebetween the cold water temperature leaving the tow-er and the wet bulb temperature of the entering air.The smaller the approach, the more efficient and ex-pensive the tower. Another critical factor is the cool-ing range. This is the difference between the hot wa-ter temperature entering the tower and the cold wa-ter temperature leaving it is essentially the same asthe circulating water temperature rise in the conden-ser. Practically, tower approaches are 8 to 15°F withranges of 18 to 22°F. Selection of approach andrange for a tower is the subject for an economic opti-mization which should include simultaneous selec-tion of the condensers as these two major items ofequipment are interdependent.

(6) Cooling tower makeup.(a) Makeup must be continuously added to

the tower collecting basin to replace water lost byevaporation and drift. In many cases, the makeupwater must be softened to prevent scaling of heattransfer surfaces; this will be accomplished bymeans of cold lime softening. Also the circulatingwater must be treated with bioxides and inhibitorswhile in use to kill algae, preserve the fill, and pre-vent metal corrosion and fouling. Algae control isaccomplished by means of chlorine injection; acidand phosphate feeds are used for pH control and tokeep heat surfaces clean.

(b) The circulating water system must beblown down periodically to remove the accumulatedsolid concentrated by evaporation.

3-39

TM 5-811-6

3-28. Environmental concernsa. Possible problems. Some of the environmental

concerns which have an impact on various types ofpower plant waste heat rejection systems are as fol-lows:

(1) Compatibility of circulating water systemwith type of land use allocated to the surroundingarea of the power plant.

(2) Atmospheric ground level fogging fromcooling tower.

(3) Cooling tower plumes.(4) Ice formation on adjacent roads, buildings

and structures in the winter.(5) Noise from cooling tower fans and circulat-

ing water pumps.(6) Salts deposition on the contiguous country-

side as the evaporated water from the tower is ab-sorbed in the atmosphere and the entrained chemi-cals injected in the circulating water system fallout.

(7) Effect on aquatic life for once though sys-tems:

(a) Entrapment or fish kill.(b) Migration of aquatic life.(c) Thermal discharge.(d) Chemical discharge.(e) Effect of plankton.

(8) Effect on animal and bird life.(9) Possible obstruction to aircraft (usually only

a problem for tall hyperbolic towers).(10) Obstruction to ship and boat navigation

(for once through system intakes or navigablestreams or bodies of water).

b. Solutions to problems. Judicious selection of the type of circulating water system and optimumorientation of the power plant at the site can mini-mize these problems. However, many military proj-ects will involve cogeneration facilities which mayrequire use of existing areas where construction ofcooling towers may present serious on base prob-lems and, hence, will require innovative design solu-tions.

Section VII. FEEDWATER SYSTEM

3-29. Feedwater heatersa. Open type—deaerators.

(1) Purpose. Open type feedwater heaters areused primarily to reduce feedwater oxygen and oth-er noncondensable gases to essentially zero and thusdecrease corrosion in the boiler and boiler feed sys-tem. Secondarily, they are used to increase thermalefficiency as part of the regenerative feedwater heat-ing cycle.

(2) Types.(a) There are two basic types of open deaerat-

ing heaters used in steam power plants—tray typeand spray type. The tray or combination spray/traytype unit will be used. In plants where heater traymaintenance could be a problem, or where the feed-water has a high solids content or is corrosive, aspray type deaerator will be considered.

(b) All types of deaerators will have internalor external vent condensers, the internal parts ofwhich will be protected from corrosive gases andoxidation by chloride stress resistant stainless steel.

(c) In cogeneration plants where largeamounts of raw water makeup are required, a deaer-ating hot process softener will be selected dependingon the steam conditions and the type of raw waterbeing treated (Section IX, paragraph 3-38 and3-39).

(3) Location. The deaerating heater should belocated to maintain a pressure higher than theNPSH required by the boiler feed pumps under allconditions of operation. This means providing amargin of static head to compensate for sudden fall

off in deaerator pressure under an upset condition.Access will be provided for heater maintenance andfor reading and maintaining heater instrumenta-tion.

(4) Design criteria.(a) Deaerating heaters and storage tanks will

comply with the latest revisions of the followingstandards:

(1) ASME Unified Pressure Vessel Code.(2) ASME Power Test Code for Deaerators.(3) Heat Exchanger Institute (HE I).(4) American National Standards Institute

(ANSI).(b) Steam pressure to the deaerating heater

will not be less than three psig.(c) Feedwater leaving the deaerator will con-

tain no more than 0.005 cc/liter of oxygen and zeroresidual carbon dioxide. Residual content of the dis-solved gases will be consistent with their relativevolubility and ionization.

(d) Deaerator storage capacity will be not lessthan ten minutes in terms of maximum design flowthrough the unit.

(e) Deaerator will have an internal or externaloil separator if the steam supply may contain oil,such as from a reciprocating steam engine.

(f) Deaerating heater will be provided withthe following minimum instrumentation: reliefvalve, thermometer, thermocouple and test well atfeedwater inlet and outlet, and steam inlet; pressure gauge at feedwater and steam inlets; and a level con-trol system (paragraph c).

3-40

TM 5-811-6

b. Closed type.(1) Purpose. along with the deaerating heater,

closed feedwater heaters are used in a regenerativefeedwater cycle to increase thermal efficiency andthus provide fuel savings. An economic evaluationwill be made to determine the number of stages offeedwater heating to be incorporated into the cycle.Condensing type steam turbine units often haveboth low pressure heaters (suction side of the boilerfeed pumps) and high pressure heaters (on the dis-charge side of the feed pumps). The economic anal-ysis of the heaters should consider a desuperheatersection when there is a high degree of superheat inthe steam to the heater and an internal or externaldrain cooler (using entering condensate or boilerfeedwater) to reduce drains below steam saturationtemperature.

(2) Type. The feedwater heaters will be of the U-tube type.

(3) Location. Heaters will be located to alloweasy access for reading and maintaining heater in-strumentation and for pulling the tube bundle orheater shell. High pressure heaters will be located toprovide the best economic balance of high pressurefeedwater piping, steam piping and heater drain piping.

(4) Design criteria(a) Heaters will comply with the latest revi-

sions of the following standards:(1) ASME Unfired Pressure Vessel Code.(2) ASME Power Test Code for Feedwater

Heaters.(3) Tubular Exchanger Manufacturers As-

sociation (TEMA).(4) Heat Exchanger Institute (HE I).(5) American National Standards Institute

(ANSI).(b) Each feedwater heater will be provided

with the following minimum instrumentation: shelland tube relief valves; thermometer, thermocoupleand test well at feedwater inlet and outlet; steam in-let and drain outlet; pressure gauge at feedwater in-let and outlet, and steam inlet; and level control sys-tem.

c. Level control systems.(1) Purpose. Level control systems are required

for all open and closed feedwater heaters to assureefficient operation of each heater and provide forprotection of other related power plant equipment.The level control system for the feedwater heaters isan integrated part of a plant cycle level control sys-tem which includes the condenser hotwell and theboiler level controls, and must be designed with thisin mind. This paragraph sets forth design criteriawhich are essential to a feedwater heater level con-trol system. Modifications may be required to fit the

actual plant cycle.(2) Closed feedwater heaters.

(a) Closed feedwater heater drains are usuallycascaded to the next lowest stage feedwater heateror to the condenser, A normal and emergency drainline from each heater will be provided. At high loadswith high extraction steam pressure, the normalheater drain valve cascades drain to the next loweststage heater to control its own heater level. At lowloads with lower extraction steam pressure and low-er pressure differential between successive heaters,sufficient pressure may not be available to allow thedrains to flow to the next lowest stage heater. Inthis case, an emergency drain valve will be providedto cascade to a lower stage heater or to the conden-ser to hold the predetermined level.

(b) The following minimum instrumentationwill be supplied to provide adequate level control ateach heater: gauge glass; level controller to modu-late normal drain line control valve (if emergencydrain line control valve is used, controller musthave a split range); and high water level alarmswitch.

(3) Open feedwater heaters-deaerators. The fol-lowing minimum instrumentation will be suppliedto provide adequate level control at theheater: gauge glass, level controller to control feed-water inlet control waive (if more than one feedwaterinlet source, controller must have a split range); lowwater level alarm switch; “low-low” water levelalarm switch to sound alarm and trip boiler feedpumps, or other pumps taking suction from heater;high water level alarm switch; and “high-high” wa-ter level controller to remove water from the deaer-ator to the condenser or flash tank, or to divert feed-water away from the deaerator by opening a divert-ing valve to dump water from the feedwater line tothe condenser or condensate storage tank.

(4) Reference. The following papers should beconsulted in designing feedwater level control sys-tems, particularly in regard to the prevention of wa-ter induction through extraction piping

(a) ASMD Standard TWDPS-1, July 1972,“Recommended Practices for the Prevention of Wa-ter Damage to Steam Turbines Used for ElectricPower Generation (Part 1- Fossil Fueled Plants).”

(b) General Electric Company StandardGEK-25504, Revision D, “Design and OperatingRecommendations to Minimize Water Induction inLarge Steam Turbines.”

(c) Westinghouse Standard, “Recommenda-tion to Minimize Water Damage to Steam Tur-bines.”

3-30. Boiler feed pumps.a. General. Boiler feed pumps are used to pressur-

3-41

TM 5-811-6

ize water from the deaerating feedwater heater ordeaerating hot process softener and feed it throughany high pressure closed feedwater heaters to theboiler inlet. Discharge from the boiler superheatedsteam in order to maintain proper main steam tern-perature to the steam turbine generator.

b. Types. There are two types of centrifugalmulti-stage boiler feed pumps commonly used insteam power plants—horizontally split case and bar-rel type with horizontal or vertical (segmented) splitinner case. The horizontal split case type will beused on boilers with rated outlet pressures up to 900psig. Barrel type pumps will be used on boilers withrated outlet pressure in excess of 900 psig.

c. Number of pumps. In all cases, at least onespare feed pump will be provided.

(1) For power plants where one battery of boilerfeed pumps feeds one boiler.

(a) If the boiler is base loaded most of thetime at a high load factor, then use two pumps eachat 110-125 percent of boiler maximum steaming ca-pacity.

(b) If the boiler is subject to daily wide rangeload swings, use three pumps at 55-62.5 percent ofboiler maximum steaming capacity. With this ar-

rangement, two pumps are operated in parallel be-tween 50 and 100 percent boiler output, but only onepump is operated below 50 percent capacity. This ar-rangement allows for pump operation in its most ef-ficient range and also permits a greater degree offlexibility.

(2) For power plants where one battery of pumpfeeds more than one boiler through a header system,the number of pumps and rating will be chosen toprovide optimum operating efficiency and capitalcosts. At least three 55-62.5 percent pumps shouldbe selected based on maximum steaming capacity ofall boilers served by the battery to provide the flexi-bility required for a wide range of total feedwaterflows.

d. Location. The boiler feed pumps will be locatedat the lowest plant level with the deaerating heateror softener elevated sufficiently to maintain pumpsuction pressure higher than the required NPSH ofthe pump under all operating conditions. Thismeans a substantial margin over the theoreticallycalculated requirements to provide for pressures col-lapses in the dearator under abnormal operatingconditions. Deaerator level will never be decreasedfor structural or aesthetic reasons, and suction pipeconnecting deaerator to boiler feed pumps should besized so that friction loss is negligible.

e. Recirculation control system.(1) To prevent overheating and pump damage,

each boiler feed pump will have its own recirculationcontrol system to maintain minimum pump flow

whenever the pump is in operation. The control sys-tem will consist off

(a) Flow element to be installed in the pump suction line.

(b) Flow controller.(c) Flow control valve.(d) Breakdown orifice.

(2) Whenever the pump flow decreases to mini-mum required flow, as measured by the flow ele-ment in the suction line, the flow controller will bedesigned to open the flow control valve to maintainminimum pump flow. The recirculation line will be discharge to the deaerator. A breakdown orifice willbe installed in the recirculation line just before it en-ters the deaerator to reduce the pressure from boilerfeed pump discharge level to deaerator operatingpressure.

f. Design criteria.(1) Boiler feed pumps will comply with the lat-

est revisions of the following standards:(a) Hydraulics Institute (HI).(b) American National Standards Institute

(ANSI).(2) Pump head characteristics will be maximum

at zero flow with continuously decreasing head asflow increases to insure stable operation of onepump, or multiple pumps in parallel, at all loads.

(3) Pumps will operate quietly at all loads with-out internal flashing and operate continuously with- out overheating or objectionable noises at minimumrecirculation flow.

(4) Provision will be made in pump design forexpansion of

(a) Casing and rotor relative to one another.(b) Casing relative to the base.(c) Pump rotor relative to the shaft of the

driver.(d) Inner and outer casing for double casing

pumps.(5) All rotating parts will be balanced statically -

and dynamically for all speeds.(6) Pump design will provide axial as well as ra-

dial balance of the rotor at all outputs.(7) One end of the pump shaft will be accessible

for portable tachometer measurements.(8) Each pump will be provided with a pump

warmup system so that when it is used as a standbyit can be hot, ready for quick startup. This is doneby connecting a small bleed line and orifice from thecommon discharge header to the pump discharge in-side of the stop and check valve. Hot water can thenflow back through the pump and open suction valveto the common suction header, thus keeping thepump at operating temperature.

(9) Pump will be designed so that it will startsafely from a cold start to full load in 60 seconds in

TM 5-811-6

an emergency, although it will normally be warmedbefore starting as described above.

(10) Other design criteria should be as forth inMilitary Specification MIL-P-17552D.

g. Pump drives. For military plants, one steamturbine driven pump may be justified under certainconditions; e.g., if the plant is isolated, or if it is a co-generation plant or there is otherwise a need for sub-stantial quantities of exhaust steam. Usually, how-ever, adequate reliability can be incorporated intothe feed pumps by other means, and from a plant ef-ficiency point of view it is always better to bleedsteam ‘from the prime mover(s) rather than to usesteam from an inefficient mechanical drive turbine.

3-31. Feedwater supplya. General description.

(1) In general terms, the feedwater supply in-cludes the condensate system as well as the boilerfeed system.

(2) The condensate system includes the conden-sate pumps, condensate piping, low pressure closedheaters, deaerator, and condensate system level andmakeup controls. Cycle makeup may be introducedeither into the condenser hotwell or the deaerator.For large quantities of makeup as in cogenerationplants, the deaerator maybe preferred as it containsa larger surge volume. The condenser, however, isbetter for this purpose when makeup is of high pur-ity and corrosive (demineralized and undeaerated).With this arrangement, corrosive demineralized wa-ter can be deaerated in the condenser hotwell; theexcess not immediately required for cycle makeup isextracted and pumped to an atmospheric storagetank where it will be passive in its deaerated state.As hotwell condensate is at a much lower tempera-ture than deaerator condensate, the heat loss in theatmospheric storage tank is much less with this ar-rangement.

(3) The feedwater system includes the boilerfeed pumps, high pressure closed heaters, boiler feedsuction and discharge piping, feedwater level con-trols for the boiler, and boiler desuperheater watersupply with its piping and controls.

b. Unit vs. common system. Multiple unit cogen-eration plants producing export steam as well aselectric will always have ties for the high pressure

Section Vlll. SERVICE WATER

3-32. Introduction

a. Definitions and purposes. Service water supplysystems and subsystems can be categorized as fol-lows:

(1) For stations with salt circulating water or

steam, the extraction steam, and the high pressurefeedwater system. If there are low pressure closedheaters incorporated into the prime movers, the con-densate system usually remains independent foreach such prime mover; however, the deaerator andboiler feed pumps are frequently common for allboilers although paralleling of independent highpressure heater trains (if part of the cycle) on thefeedwater side maybe incorporated if high pressurebleeds on the primer movers are uncontrolled. Eachcogeneration feedwater system must carefully be de-signed to suit the basic parameters of the cycle. Lev-el control problems can become complex, particu-larly if the cycle includes multiple deaerators operat-ing in parallel.

c. Feedwater controls. Condensate pumps, boilerfeed pumps, deaerator, and closed feedwater heatersare described as equipment items under other head-ings in this manual. Feedwater system controls willconsist of the following

(1) Condenser hotwell level controls which con-trol hotwell level by recirculating condensate fromthe condensate pump discharge to the hotwell, byextracting excess fluid from the cycle and pumpingit to atmospheric condensate storage (surge) tanks,and by introducing makeup (usually from the samecondensate storage tanks) into the hotwell to replen-ish cycle fluid.

(2) Condensate pump minimum flow controls torecirculate sufficient condensate back to the con-denser hotwell to prevent condensate pumps fromoverheating.

(3) Deaerator level controls to regulate amountof condensate transferred from condenser hotwell todeaerator and, in an emergency, to overflow excesswater in the deaerator storage tank to the conden-sate storage tank(s).

(4) Numerous different control systems are pos-sible for all three of the above categories. Regardlessof the method selected, the hotwell and the deaer-ator level controls must be closely coordinated andintegrated because the hotwell and deaerator tankare both surge vessels in the same fluid system.

(5) Other details on instruments and controlsfor the feedwater supply are described under Section1 of Chapter 5, Instruments and Controls.

heavily contaminated or sedimented fresh circulat-ing water.

(a) Most power stations, other than thosewith cooling towers, fall into this category. Circulat-ing water booster pumps increase the pressure of a(small) part of the circulating water to a level ade-

3-43

TM 5-811-6

quate to circulate through closed cooling water ex-changers. If the source is fresh water, these pumpsmay also supply water to the water treating system.Supplementary sources of water such as the areapublic water supply or well water may be used forpotable use and/or as a supply to the water treatingsystem. In some cases, particularly for larger sta-tions, the service water system may have its pumpsdivorced from the circulating water pumps to pro-vide more flexibility y and reliability.

(b) The closed cooling water exchangerstransfer rejected heat from the turbine generatorlube oil and generator air (or hydrogen) coolers, bear-ings and incidental use to the circulating water side-stream pressurized by the booster pumps. The medi-um used for this transfer is cycle condensate whichrecirculates between the closed cooling exchangersand the ultimate equipment where heat is removed.This closed cooling cycle has its own circulating(closed cooling water) pumps, expansion tank andtemperature controls.

(2) For stations with cooling towers. Circulat-ing water booster pumps (or separate service waterpumps). may also be used for this type of powerplant. In the case of cooling tower systems, how-ever, the treated cooling tower circulating water canbe used directly in the turbine generator lube oil andgenerator air (or hydrogen) coolers and various otherservices where a condensate quality cooling mediumis unnecessary. This substantially reduces the sizeof a closed cooling system because the turbine gen-erator auxiliary cooling requirements are the largestheat rejection load other than that required for themain condenser. If a closed cooling system is usedfor a station with a cooling tower, it should be de-signed to serve equipment such as air compressorcylinder jackets and after coolers, excitation systemcoolers, hydraulic system fluid coolers, boiler TVcameras, and other similar more or less delicateservice. If available, city water, high quality wellwater, or other clean water source might be used forthis delicate equipment cooling service and thuseliminate the closed cooling water system.

b. Equipment required—general. Equipment re-quired for each system is as follows:

(1) Service water system(a) Circulating water booster pumps (or sepa-

rate service water pumps).(b) Piping components, valves, specialities

and instrumentation.(2) Closed cooling water system.

(a) Cosed cooling water circulating pumps.(b) Closed cooling water heat exchangers.(c) Expansion tank.(d) Piping components, valves, specialities

and instrumentation. Adequate instrumentation

(thermometers, pressure gages, and flow indicators)should be incorporated into the system to allowmonitoring of equipment cooling.

3-33. Description of major componentsa. Service water systerm.

(1) Circulating water booster (or service water)pumps. These pumps are motor driven, horizontal(or vertical) centrifugal type. Either two 100-per-cent or three 50-percent pumps will be selected forthis duty. Three pumps provide more flexibility; de-pending upon heat rejection load and desired watertemperature, one pump or two pumps can be oper-

.

ated with the third pump standing by as a spare. Apressure switch on the common discharge linealarms high pressure, and in the case of the boosterpumps a pressure switch on the suction header or in-terlocks with the circulating water pumps providespermissive to prevent starting the pumps unlessthe circulating water system is in operation.

(2) Temperature control. In the event the sys-tem serves heat rejection loads directly, temper-ature control for each equipment where heat is re-moved will be by means of either automatic or man-ually controlled valves installed on the cooling wa-ter discharge line from each piece of equiment, or byusing a by-pass arrangement to pass variableamounts of water through the equipment withoutupsetting system hydraulic balance.

b. Closed cooling water system.(1) Closed cooling water pumps. The closed

cooling water pumps will be motor driven, horizon-tal, end suction, centrifugal type with two 100-per-cent or three 50-percent pumps as recommended forthe pumps described in a above.

(2) Closed cooling water heat exchangers. Theclosed cooling water exchangers will be horizontalshell and tube test exchangers with the treatedplant cycle condensate on the shell side and circulat-ing (service) water on the tube side. Two 100-per-cent capacity exchangers will be selected for thisservice, although three 50-percent units may be se-lected for large systems.

(3) Temperature control. Temperature controlfor each equipment item rejecting heat will be simi-lar to that described above for the service water sys-tem.

3-34. Description of systemsa. Service water system.

(1) The service water system heat load is thesum of the heat loads for the closed cooling watersystem and any other station auxiliary systemswhich may be included. The system is designed to maintain the closed cooling water system supplytemperature at 950 For less during normal operation

TM 5-811-6

with maximum heat rejection load. The system willalso be capable of being controlled or manually ad-

justed so that a minimum closed cooling water supply temperature of approximately 55 ‘F can bemaintained with the ultimate heat sink at its lowesttemperature and minimum head load on the closedcooling water system. The service water system willbe designed with adequate backup and other reli-ability features to provide the required cooling tocomponents as necessary for emergency shutdownof the plant. In the case of a system with circulatingwater booster pumps, this may mean a crossoverfrom a city or well water system or a special smallcirculating water pump.

(2) Where cooling towers are utilized, meanswill be provided at the cooling tower basin to permitthe service water system to remain in operationwhile the cooling tower is down for maintenance orrepairs.

(3) The system will be designed such that opera-tional transients (e.g., pump startup or water ham-mer due to power failure) do not cause adverse ef-fects in the system. Where necessary, suitable valv-ing or surge control devices will be provided.

b. Closed cooling water system.(1) The closed cooling water coolant tempera-

ture is maintained at a constant value by automaticcontrol of the service water flow through the heatexchanger. This is achieved by control valve modu-lation of the heat exchanger by-pass flow. All equip-ment cooled by the cooling system is individuallytemperature controlled by either manual or auto-matic valves on the coolant discharge from, or byby-pass control around each piece of equipment. Thequantity of coolant in the system is automaticallymaintained at a predetermined level in the expan-sion tank by means of a level controller which oper-ates a control valve supplying makeup from thecycle condensate system. The head tank is providedwith an emergency overflow. On a failure of a run-ning closed cooling water pump, it is usual to pro-

vide means to start a standby pump automatically.(2) The system will be designed to ensure ade-

quate heat removal based on the assumption that allservice equipment will be operating at maximum de-sign conditions.

3-35. Arrangementa. Service water system. The circulating water

booster pumps will be located as close as possible tothe cooling load center which generally will be nearthe turbine generator units. All service water pipinglocated in the yard will be buried below the frostline.

b. Closed cooling water system. The closed cool-ing water system exchangers will be located nearthe turbine generators.

3-36. Reliability of systemsIt is of utmost importance that the service andclosed cooling water systems be maintained in serv-ice during emergency conditions. In the event powerfrom the normal auxiliary source is lost, the motordriven pumps and electrically actuated devices willbe automatically supplied by the emergency powersource (Chapter 4, Section VII). Each standby pumpwill be designed for manual or automatic startupupon loss of an operating pump with suitable alarmsincorporated to warn operators of loss of pressure ineither system.

3-37. TestingThe systems will be designed to allow appropriateinitial and periodic testing to:

u. Permit initial hydrostatic testing as required inthe ASME Boiler and Pressure Vessel Code.

b. Assure the operability and the performance ofthe active components of the system.

c. Permit testing of individual components orsubsystems such that plant safety is not impairedand that undesirable transients are not present.

Section IX. WATER CONDITIONING SYSTEMS

3-38. Water Conditioning Selection sure boiler used in power generation.a. Purpose. (2) The purpose of the water conditioning sys-

(1) All naturally occuring waters, whether sur- tems is to purify or condition raw water to the re-face water or well water, contain dissolved and pos- quired quality for all phases of power plant opera-sibly suspended impurities (solids) which may be in- tion. Today, most high pressure boilers (600 psig orjurious to steam boiler operation and cooling water above) require high quality makeup water which isservice. Fresh water makeup to a cooling tower, de- usually produced by ion exchange techniques. Tore-pending on its quality, usually requires little or no duce the undesirable concentrations of turbidity andpretreatment. Fresh water makeup to a boiler sys-

tem ranges from possibly no pretreatment (in theorganic matter found in most surface waters, theraw water will normally be clarifed by coagulation

case of soft well water used in low pressure boiler) to and filtration for pretreatment prior to passing toultra-purification required for a typical high pres- the ion exchangers (demineralizers). Such pretreat-

3-45

TM 5-811-6

ment, which may also include some degree of soften-ing, will normally be adequate without further treat-ment for cooling tower makeup and other generalplant use.

b. Methods of conditioning.(1) Water conditioning can be generally cate-

gorized as’ ‘external” treatment or’ ‘internal” treat-ment. External treatment clarifies, softens, or puri-fies raw water prior to introducing it into the powerplant fluid streams (the boiler feed water, coolingtower system, and process water) or prior to utiliz-ing it for potable or general washup purposes. Inter-nal treatment methods introduce chemicals directlyinto the power plant fluid stream where they coun-teract or moderate the undesirable effects of waterimpurities. Blowdown is used in the evaporativeprocesses to control the increased concentration ofdissolved and suspended solids at manageable lev-els.

(2) Some of the methods of water conditioningare as follows:

(a) Removal of suspended matter by sedimen-tation, coagulation, and filtration (clarification).

(b)of gases.

(c)(d)(f)(g)(h)

Deaeration and degasification for removal

Cold or hot lime softening.Sodium zeolite ion exchange.Choride cycle dealkalization.Demineralization (ultimate ion exchange).Internal chemical treatment.

(i) Blowdown to remove sludge and concen-tration buildups.

c. Treatment Selection. Tables 3-13, 3-14, and3-15 provide general guidelines for selection oftreatment methodologies. The choice among these isan economic one depending vitally on the actual con-stituents of the incoming water. The designer willmake a thorough life cycle of these techniques inconjunction with the plant data. Water treatmentexperts and manufacturer experience data willcalled upon.

Section X. COMPRESSED AIR SYSTEMS

3-39. Introductiona. Purpose. The purpose of the compressed air

systems is to provide all the compressed air require-ments throughout the power plant. The compressedair systems will include service air and instrumentair systems.

b. Equipment required-general. Equipment re-quired for a compressed air system is shown in Fig-ures 3-14 and 3-15. Each system will include

(1) Air compressors. (2) Air aftercoolers.

(3) Air receiver.(4) Air dryer (usually for instrument air system

only).(5) Piping, valves and instrumentation.c. Equipment served by the compressed air sys-

tems.(1) Service (or plant) air system for operation of

tools, blowing and cleaning.(2) Instrument air system for instrument and

control purposes.(3) Soot blower air system for boiler soot blow-

ing operations.

3-40. Description of major componentsa. Air compressors. Typical service and instru-

ment air compressor? for power plant service aresingle or two stage, reciprocating piston type withelectric motor drive, usually rated for 90 to 125 psigdischarge pressure. They may be vertical or horizon-tal and, for instrument air service, always have oil-less pistons and cylinders to eliminate oil carryover.

3-46

Non-lubricated design for service air as well as in-strument air will be specified so that when the for-mer is used for backup of the latter, oil carryoverwill not be a problem. Slow speed horizontal unitsfor service and instrument air will be used. Soot blower service requirements call for pressures whichrequire multi-stage design. The inlet air filter-silenc-er will be a replaceable dry felt cartridge type. Eachcompressor will have completely separate and inde-pendent controls. The compressor controls will per-mit either constant speed-unloaded cylinder controlor automatic start-stop control. Means will be pro-vided in a multi-compressor system for selection ofthe’ ‘lead” compressor.

b. Air aftercooler. The air aftercooler for eachcompressor will be of the shell and tube type, de-signed to handle the maximum rated output of thecompressor. Water cooling is provided except forrelatively small units which may be air cooled.Water for cooling is condensate from the closed cool-ing system which is routed counter-flow to the airthrough the aftercooler, and then through the cylin-der jackets. Standard aftercoolers are rated for95 “F. maximum inlet cooling water. Permissivecan be installed to prevent compressor startup un-less cooling water is available and to shut compress-or down or sound an alarm (or both) on failure ofwater when unit is in operation.

c. Air receiver. Each compressor will have its ownreceiver equipped with an automatic drainer for re-moval of water.

d. Instrument air dryer. The instrument air dryer

TM5-811-6

Table 3-13. General Guide for Raw Water Treatment of BoilerMakeup

St earnPressure Sil ica Alkalinity- (ps ig ) reg./l. reg./l. (as CaCO3) Water Treatment

up to 450 Under 15 Under 50 Sodium ion exchange.Over 50 Hot lime-hot zeolite,

or cold lime zeolite,or hot lime soda, orsodium ion exchange pluschloride anion exchange.

Over 15

450 t o 600 Under 5

Over 50

Under 50

Over 50

Hot lime-hot zeolite,or cold lime-zeolite,or hot lime soda.

Sodium ion exchange pluschloride anion exchange,or hot lime-hot zeolite.

Sodium plus hydrogen ionexchange, or cold lime-zeolite or hot lime-hotzeol i te .

Above 5 Demineralizer, or hotlime-hot zeolite.

600 to 1000 ------- ‘Any Water - - - - - - - Demineralizer.

1000 & Higher ------- Any Water - - - - - - - Demineralizer.

NOTES : (1) Guide is based on boiler water concentrations recommended in the

American Boiler and Affiliated Industries “Manual of IndustryStandards and Engineering Information.”

(2) Add filters when turbidity exceeds 10mg./l.(3) See Table 3-15 for effectiveness of treatments.(4) reg./l. = p.p.m.

Source: Adapted from NAVFAC DM3

3-47

TM 5-811-6

Table 3-14. Internal Chemical Treatment.

Corrosive Treatment Required

Maintenance of feedwater pH and boiler wateralkalinity for scale and corrosion control.

.

Prevention of boiler scale by internal softeningof the boiler water.

Conditioning of boiler sludge to prevent adherenceto internal boiler surfaces.

Prevention of scale from hot water in pipelines,stage heaters, and economizers.

Prevention of oxygen corrosion by chemicaldeaeration of boiler feedwater.

Prevention of corrosion by protective filmformation.

Prevention of corrosion by condensate.

Prevention of foam in boiler water.

Inhibition of caustic embrittlement.

U.S. Army Corps of Engineers

Chemical

Caustic SodaSoda AshSulfuric Acid

PhosphatesSoda AshSodium AluminateAlginatesSodium Silicate

TanninsLignin DerivativesStarchGlucose Derivatives

PolyphosphatesTanninsLignin DerivativesGlucose Derivatives

Sulf itesTanninsFerrus hydroxideGlucose DerivativesHydrazineAmmonia

TanninsLignin DerivativesGlucose Derivatives

Amine CompoundsAmmonia

PolyamidesPolyalkylene Glycols

Sodium SulfatePhosphatesTanninsNitrates

3-48

Treatment

Cold Lime-Zeolite

TM 5-811-6

Table 3-15. Effectiveness of Water Treatment

Average Analysis of EffluentHardness Alkalinity co Dissolved

(as CaCO )

Hot Lime Soda

Hot Lime-Hot Zeolite

Sodium Zeolite

Sodium PlusHydrogen Zeolite

Sodium ZeolitePlus ChlorideAnion Exchanger

Demineralizer

Evaporator

o to 2

17 to 25

o to 2

o to 2

o to 2

o to 2

o to 2

o to 2

(as CaCO )mg./1.

75

35 to 50

20 to 25

Unchanged

10 to 30

15 to 35

o to 2

o to 2

Medium High

Low

Low to High

Low

Low

o to 5

o to 5

Solids

Reduced

Reduced

Reduced

Unchanged

Reduced

Unchanged

o t o 5

o t o 5

Sil ica

8

3

3

Unchanged

Unchanged

Unchanged

Below 0.15

Below 0.15

NOTE : (1) reg./l. = p.p.m.

Source: NAWFAC DM3

3-49

WET AIR

ENTRAINMENTSEPARATOR

Courtesy of Pope, Evans and Robbins (Non-Copyrighted)

Figure 3-14. Typical compressed airsystem.

will be of the automatic heat reactivating, dualchamber, chemical desiccant, downflow type. It willcontain a prefilter and afterfilter to limit particulatesize in the outlet dried air. Reactivating heat will beprovided by steam heaters.

3-41. Description of systemsa. General. The service (or plant) air and the in-

strument air systems may have separate or commoncompressors. Regardless of compressor arrange-ment, service and instrument air systems will eachhave their own air receivers. There will be isolationin the piping system to prevent upsets in the serviceair system from carrying over into the vital instru-ment air system.

b. Service air system. The service air systemcapacity will meet normal system usage with onecompressor out of service. System capacity will in-clude emergency instrument air requirements aswell as service air requirements for maintenanceduring plant operation. Service air supply will in-

3-50

elude work shops, laboratory, air hose stations formaintenance use, and like items. Air hose stationsshould be spaced so that air is available at eachpiece of equipment by using an air hose no longerthan 75 feet. Exceptions to this will be as follows:

(1) The turbine operating floor will have serviceair stations every 50 feet to handle air wrenchesused to tension the turbine hood bolts.

(2) No service air stations are required in thecontrol room and in areas devoted solely to switch-gear and motor control centers.

(3) Service air stations will be provided insidebuildings at doors where equipment or supplies maybe brought in or out.

c. Instrument air sys tern. A detailed analysis willbe performed to determine system requirements.The analysis will be based on:

(1) The number of air operated valves anddampers included in the mechanical systems.

(2) The number of air transmitters, controllersand converters.

TM 5-811-6

Courtesy of Pope, Evans and Robbins (Non-Copyrighted)

Figure 3-15. Typical arrangement of air compressor and accessories.

(3) A list of another estimated air usage not in- (2) Instrument air reserve. In instances whereeluded in the above items. short term, large volume air flow is required, local

d. Piping system. air receivers can be considered to meet such needs(1) Headers. Each separate system will have a and thereby eliminate installation of excessive com-

looped header to distribute the compressed air, and pressor capacity. However, compressor must befor large stations a looped header will be provided at sized to recharge the receivers while continuing toeach of the floor levels. supply normal air demands.

3-51

. ”