CHAPTER 34UTILITIES

Steam-electric power generating plants are the largest industrial users of water inthe United States. The Federal Power Commission 1970 National Power Surveyreported that utilities cooling water constituted 80% of all such water usage, orapproximately one-third of the nation's total water withdrawals. About 70% ofthe water withdrawals by utilities is fresh water. The balance is saline water usedby generating stations in coastal regions.

The laws of thermodynamics limit the amount of the energy in fuel that canbe converted to work by a steam turbine. More than 50% of the initially availableheat remains in the exhaust steam leaving the turbine, and most of this is rejectedto cooling water and then lost to the surrounding environment. Cooling waterrequired for condensing the turbine exhaust steam in a 1000 MW (1,000,000 kW)plant is about 400,000 gal/min (1500 m3/min).

By comparison, other water requirements for steam-electric plants are small.These include replacement of blowdown and other losses from the steam cycle,ash transport (in fossil-fueled plants), equipment cleaning, and domestic uses.

A high percentage of the cooling water is returned directly to its source,because once-through cooling is used in plants having about 70% of the currentlyinstalled generating capacity in the United States. Because the condenser outletwater is typically 5 to 250F (3 to 140C) warmer than the inlet, heat is the principalconcern in discharges of utility cooling water. The goal of U.S. environmentalpolicy to eliminate environmentally harmful thermal discharges to receivingwaters by utilities has generally been achieved, with some exceptions.

The difference between total water withdrawal and wastewater discharge ismostly evaporation. Evaporation occurs principally from ponds and cooling tow-ers used in recirculating cooling water systems; there is also some from the sur-faces of ash settling ponds. Minor water losses can also occur by seepage into theground from unlined ponds and in wet ash or water treatment sludges hauledfrom the plant.

Utility wastewater contaminants include suspended solids, metals such as ironand copper, acids and alkalies from water treating and metal cleaning operations,oil, and grease. Less likely to become a water contaminant, but of special envi-ronmental concern, are polychlorinated biphenyl compounds (PCBs) used astransformer fluids, now being replaced by safer materials.

THE PROCESS: ENERGY CONVERSION

In steam-electric power production (Figure 34.1), the chemical energy of fossilfuels or the nuclear energy of fissionable materials is converted to heat for gen-

FIG. 34.1 This utility system incorporates both a nuclear unit (left) and a coal-fired unit (right)at the same site. (Courtesy of Carolina Power & Light Company.)

eration of steam that is then converted to mechanical energy in a turbine coupledto an electric generator. Exhaust steam is condensed and returned to the boiler.

Within the fluid (water-steam) cycle of a steam-electric plant, the theoreticalefficiency at which heat in the steam can be converted in a turbine to work isshown by:

y 1Y

Percent theoretical efficiency = -^-—- X 100J \

where T1 is the absolute temperature of the turbine inlet steam, and T2 is theabsolute temperature of the turbine exhaust steam.

Thus, the greatest efficiency is achieved by providing the highest inlet steamtemperature (T1) and lowest exhaust temperature (T2) practical for a given boiler-turbine-condenser system.

In practice, upper temperatures are limited by the strength of metals availablefor boiler and superheater construction; strength falls off rapidly as temperatureexceeds 90O0F (48O0C, 136O0R). Upper temperatures are generally limited to amaximum of about 110O0F (59O0C, 156O0R). A significant temperature differenceis required to cause heat to flow from the exhaust steam to the cooling mediumcirculated through the condenser. The practical effect is that lower steam temper-atures (T2) on condensing turbines typically range 80 to 12O0F (27 to 490C, 540 to58O0R), even with cooling water at 4O0F (40C) in the winter. Within these upperand lower temperatures, then, the best theoretical efficiency would be calculatedas:

Theoretical efficiency = 156^ ~ 54° X 100 = 65.4%1560

Achievable efficiencies are considerably lower than theoretical both for thefluid cycle and for the generating plant as a whole. Significant energy is lost inovercoming fluid and mechanical friction. Sizable amounts of energy are con-sumed in the operation of the plant's feed water pumps, boiler draft fans, andother auxiliaries. A power plant's pollution control equipment, required to meet

air emission and water discharge standards, can consume as much as 10% of theelectrical output. Actual steam-electric plant overall efficiencies range from 32 to39%.

POWER CYCLE

The energy flow through the water-steam phase changes in a steam-electric plantis called the Rankine cycle, having four basic stages: boiler, turbine, condenser,and feed water pump.

The Rankine cycle may be illustrated by several kinds of diagrams. Figure 34.2shows that cycle, relating the change in temperature of the fluid to its entropy ateach stage in the cycle. Entropy is a measure of that portion of the heat receivedby a cycle that cannot be converted into work because of the random motion ofgas (steam) molecules. Entropy is expressed mathematically as the ratio of heatcontent to temperature.

To achieve the highest possible thermodynamic efficiency, modern fossil-fuelpower cycles use steam superheaters and reheaters to raise average temperatures(T1) of steam flowing through the turbine. Condensers operating at high vacuumpermit expansion of steam to the lowest possible exhaust temperature (T2). And

a to b: Liquid heating and compression (feedwater pump).

b to e: Reversible heat addition in feedwater heaters Ib toe) , boiler ( c tod ) and superheater ( d t o e ) .e to f ; Steam expansion and conversion of heat energy to work.f to a: Reversible rejection of unavailable heat to cooling water "sink".

FIG. 34.2 Steps in the Rankine cycle from the introduction of water as a liquid into thesystem, through its phase change to steam which produces work in a turbine, to the condensingof the exhaust vapor to water again for return to the boiler.

Entropy,SFeedwater pump

Deaerator

Boiler

Superheater

Coolingwater

Turbine Condenser

Unavailable

heat

Tem

pera

ture

,0R

High-pressure bleed heaters Low-pressure bleed heaters

Single reheat, 8 -s tage regenerat ive teed heating, 3515 ps ia , 1000°F/1000°F s team

FIG. 34.3 The addition of steam reheat and regenerative feed water heating to increaseefficiency.

to further recover as much heat as possible, partially expanded steam is extractedfrom the turbine at various points for heating feed water (called "regenerativeheating"). Figure 34.3 illustrates a cycle having these components, and Figure34.4 illustrates their effect on a temperature-entropy diagram of the cycle.

Nuclear steam-electric plants of the light water reactor types, typical in U.S.commercial service, cannot deliver steam at the temperatures achieved in fossil-fueled units. Nuclear pressurized water reactors (PWR) (Figure 34.5) employingonce-through steam generators achieve only a relatively small degree of steamsuperheat [30 to 6O0F (17 to 340C)]. But in PWR cycles employing recirculatingU-tube steam generators, and in boiling water reactor (BWR) cycles (Figure 34.6)there is no superheat. For this reason, nuclear power cycles are limited to efficien-cies of about 32%, compared to 36 to 39% for fossil-fueled cycles, since less heatis supplied to the turbine (at T1).

In fossil-fueled units, further improvements in thermodynamic efficiency areachieved by economizers and air heaters installed in the path of the exit flue gasbetween the boiler and stack. Economizers transfer heat from the exit gases to thefeed water; air heaters transfer some of the residual stack gas heat to the boilercombustion air supply.

For still higher efficiencies, where suitable fuels are available, some steam-elec-tric plants combine the operation of a combustion gas driven turbine with that ofa steam turbine. In such combined cycle generating plants (Figure 34.7), the hot

Feed water pump

Feed waterdrive turbine

Reheatturbine

High-pressure"turbine

Low-pressureturbine

Condenser

Deaer.htr.

Supe

rhea

ter

Rehe

ater

Boile

rEc

onom

izer

Entropy S1 Btu/ lb

(0F -- 32) X 5/9= 0C

psi X 0.069 = bars

Btu/lb X 0.555 = kcal/kg

FIG. 34.4 The modified Rankine cycle showing the effect of reheating steamand adding feed water heaters to the cycle. (Adapted from Steam/Its Genera-tion and Use, Babcock & Wilcox Company, 1972.)

The heat energy equivalent of one electrical kilowatt hour is 3413 Btu (860kcal). At 32% overall thermodynamic efficiency, the heat rate for a generating sta-tion would be:

^l = 10,700 Btu/kWh or, ~j- = 2690 kcal/kWh

If an efficiency of 40% could be achieved, the station heat rate would be only 8533Btu/kWh (2150 kcal/kWh)—requiring about 20% less fuel for a given output.

gases of combustion, such as from a jet aircraft engine, are first utilized for spin-ning the gas-driven turbine; and the turbine exhaust gas, still containing consid-erable heat, is then used in a boiler-superheater unit to produce steam to drive asteam turbine.

Low-pressure heaters

Boiler feed pump

High-pressure heaters

SuperheatReheat

540psia3515 psia

t (T

empe

ratu

re),

0F

Stage heaters with cascaded drips

(0F -- 32) X 5/9 = 0C

psi X 0.069 = bars

FIG. 34.6 Diagram of a BWR nuclear power cycle showing major components and typical pres-sures and temperatures. (Adapted from the Effects of Water Quality on the Performance of Mod-ern Power Plants, Klein and Goldstein, NACE 1968 Conference.)

(0F -- 32) X 5/9 = 0C

psi X 0.069 = barsFIG. 34.5 PWR nuclear power cycle showing major components and typical pressures and tem-peratures. (Adapted from the Effects of Water Quality on the Performance of Modern PowerPlants, Klein and Goldstein, NACE 1968 Conference.)

Reactor

P r imary coolant pump

Bypasspur i f i ca t ion

Pressur izer

Steam generator

Reheater

Condenser2 " H g a b s ,

10O0F

L.P. e x t r a c t i o ns team

2100 psi,6050F

735 ps i , 5090F Moistureseparator

H.P. ex t rac t ionsteam

Feedpump

Drip pump

Reactor

Circulatingpump

Shielding

Feedpump

Condensatepump

Condenser

LP. turbine

Stage heaters wi th cascaded drips

H.P. turbine

425ps i ,450°F

165 psi,3650F

Reheater 2" Hg abs,10O0F Hot

well

965 psi,54O0F

40O0F 34O0F 29O0F 23O 0 F 17O0F

Drip pump

Pressure, psio

Ib/ft3 X 16.02 = kg/m3

psi X 0.069 = bars

FIG. 34.8 As boiler pressure increases, steam den-sity and water density, which are greatly different atatmospheric pressure, approach each other, becom-ing equal at 3208 lb/in2, the critical pressure.

FIG. 34.7 Combined cycle gas turbine-steam plant. (From Power Special Report, Gas Tur-bines, December 1963.)

WATER: THE WORKING FLUID

In steam-electric power cycles, water is subjected to wide variations in tempera-ture and pressure in the cyclic sequences of compression, heating, expansion, andheat rejection. Temperatures may range from 70 to 120O0F (21 to 65O0C), withpressures from 0.5 to 5000 psia (0.035 to 345 bars).

As shown by the diagram in Figure 34.8, steam density approaches that ofwater as pressure increases, until the critical pressure is reached at 3208 lb/in2 abs

Cr i t i ca lpressure3208 psi

Liquid

Vapor

Compressor

Combustors

Gas turbine

Condenser

Airintake

Exhaust to stack

L.P. was te -hea t boilerH.P. was te -hea t boiler

CondenserSteam turbine

Generator

L.P. steam

L.P economizerand evaporator

Gasout

Load

Airin

H.P.economizerL

evaporator andsuperheater

Fuel in

Den

sity

, Ib/

ft3

FIG. 34.9 The basic differences between (a) drum-type and, (b)once-through steam generators.

leaves most of the undesirable solids behind in the boiler water. And becauseboiler internal recirculation rates are about four times the rate of steam flow fromthe boiler, the fluid rising to the steam drum from the generating tubes will beabout 75% water. This means that superheated steam, in which some boiler waterimpurities would become soluble, cannot exist in the boiler drum. Secondly, sincethe recirculating mixture in the boiler tubes is primarily water, more efficient heattransfer and tube metal cooling occurs than when steam alone flows through thetubes.

In subcritical once-through boilers, a complete phase change occurs with waterentering at one end and superheated steam leaving at the other. There is no recir-culation within the unit, nor is there a drum for mechanical steam-water separa-tion. Boiler blowdown is impossible, so to prevent deposition of solids in the sys-tem beyond the point of water-steam phase change requires stringent feed waterquality requirements—considerably higher than for drum-type boilers.

For cycles operating above critical pressure, no phase change occurs, so nosteam-water separation is possible. Thus, at supercritical pressures, all steam gen-erators are once-through. Universal pressure boilers are once-through boilers suit-able for use at pressures above or below critical. From the standpoint of tubemetal alloy and thickness requirements, they are economically most practical foroperation in the range of about 2000 to 3000 lb/in2 (138 to 207 bars).

In higher subcritical pressure cycles [2750 to 2850 lb/in2 abs (190 to 197 bars)],the margin between feed water quality requirements of drum and once-throughboilers is somewhat lessened. At such pressures, effective mechanical steam-water

(220 bars). Above this pressure exists a supercritical fluid which cannot be con-sidered either steam or water. Boilers operating over 3208 lb/in2 abs are calledsupercritical units.

In cycles operating at pressures below critical where steam density is less thanthat of water, phase changes occur from water to steam and then from steam backto water. While there are advantages favoring drum-type boilers (Figure 34.9) formost subcritical pressure cycles, once-through boilers are sometimes used becauseof lower initial costs.

Drum-type boilers have two major advantages in subcritical steam generation.First, they can produce high-purity steam with less stringent feed water qualityrequirements. Mechanical disengagement of steam from the recirculating water

Feedwaterflow = Q

Steamf l o w = Q

Steamflow = Q

C i r cu la t i onf l o w = Q

Feedwaterf l o w = Q

Circulat ion f low - 4 Q

separation is an advantage provided by drum-type boilers. But the advantage islimited by the increase in the solubility of water contaminants in the steam, asthe densities of steam and water approach each other (Figure 34.8). The solidsdissolved in steam cannot be removed by mechanical separation devices in aboiler drum. For high-pressure utility boilers, therefore, the concentration of sol-ids in steam is determined to an important extent by their steam-water solubilityratios at the operating pressure. Silica is a notable example (Figure 34.10).

PRESSURE-PSl

1 psi X 0.069 = bars

FIG. 34.10 Distribution of silica between boiler water andsteam.

If solids concentrations in the steam were to avarage 30 ppb (Mg/L), for exam-ple, a 200-MW turbine would receive more than 200 Ib/yr (91 kg/yr) of potentialdepositing solids. The portion that would deposit in the turbine and the portionthat would remain in the steam to recycle to the boiler is not accurately predict-able. But, to avoid excessive turbine fouling, experience has shown the necessityof keeping total salt concentrations in the steam below 50 ppb (^g/L) with silicanot to exceed 10 ppb (^g/L)- Further, to minimize any potential for stress corro-sion cracking of turbine members, the steam solids should be free of sodiumhydroxide. The average steam contaminant levels shown in Table 34.1 were col-lated from a survey of a number of utility plants.

In nuclear power cycles, water purity is important for a different reason.

SIL

ICA

IN

S

TE

AM

- P

PM

CR

ITIC

AL

P

RE

SS

UR

E

* The significance of pH in this system is not clear; in pure water at pH 7, [OH] =[H]+ and as the dissociation constant for water is 10~14, this calculates to 5 ppb H+ and5 ppb OH ~ as CaCO3. Therefore, at pH 9.0, the OH~ calculates to 500 ppb as CaCO3,or 170 ppb OH ~, which doesn't check with reported anions. The anions must be balancedby the cations, the most prominent of which may be ammonia, morpholine, or hydrazine,none of which was reported.

f After a cation exchange column, the ionic matter should be present as mineral acids,and the conversion factor for them is approximately 8 ̂ S/cm per ppm acidity as CaCO3.Therefore it may be assumed that the 30 ppb is made up of the acids of chloride, sulfate,nitrate, and phosphate.

Source: "Control of Turbine-Steam Chemistry," S. D. Strauss (ed.), Power, March1981.

Although the required degree of purity varies for different cycles, relativelyhigh-purity water is required for all modern power cycles. Many water constitu-ents today must be measured and controlled at parts per billion (ppb, or jig/L)concentration levels compared to their measurement and control at parts per mil-lion (mg/L) concentrations in the lower pressure cycles that were once common.

However, make-up water of the purity required can be produced reliably andat reasonable cost by ion exchange, evaporation, and other pretreatment methods.But, because make-up water volumes are usually only 1% or less of total feedwater in typical power cycles, the major problem has become keeping the waterpure after it has entered the cycle.

Although H2O becomes only slightly radioactive under neutron flux, producingonly short-lived isotopes, the response of materials in the water under flux is ofconcern. Naturally occurring cobalt, for example, would be an extremely undesir-able constituent of primary coolant water passing through the reactor core ineither BWR or PWR cycles. The product would be highly radioactive, emittinghigh-energy gamma rays during subsequent decay. So cobalt must be avoided insuch systems. Since most other metals also produce radioactive isotopes underneutron flux, the tolerance of water corrosion products is limited in nuclear cyclesfor operating and maintenance safety.

TABLE 34.1 Typical Contaminant Levels in Utility Plant Steam

Crud constitutentsIron, as FeCopper, as CuSilica, as SiO2

Cations reportedSodium, as NaPotassium, as K

Anions reportedFree OHPhosphate, as PO4

pHOH corresponding to pH 9.0*

Cation conductivityAnions corresponding to cation conductivity!

17.4ppb5.0 ppb

17.4ppb39.8 ppb

6.5 ppb1.5 ppb

0.1 ppb7.0 ppb8.55-9.26

500 ppb as CaCO3

0.24 MS30 ppb

The two main sources for contamination of high-purity water are corrosionand inleakage. Corrosion represents not only metal damage, but also contami-nation of the system water with corrosion products. Low-purity water enters thecycle at points of high vacuum (e.g., the surface condenser), and this inleakage isa second major source of contamination. Careful design and selection of materialsof construction minimize the occurrence of these problems.

WA TER CHEMISTRY IN FOSSIL-FUELED PLANTS—LIQUID PHASE

Apart from steam quality considerations, a major goal of cycle water chemistryand treatment control is the prevention of tube metal failures in high-pressuresteam generators.

Because make-up water is deionized and essentially free of measurable hard-ness and other solids, tube failure due to water side scale and deposits is far lesslikely to occur in utility plants than in lower pressure industrial boilers. Instead,in power plant drum-type boilers, tube metal failures are more commonly due toa highly localized "crater" or "ductile gouging" form of water side corrosion, andto water side hydrogen penetration and embrittlement of carbon steel.

The ductile gouging form of corrosion is a chemical attack characterized byirregular craters in the tube wall. The tube fails when wall thickness at the pointof wastage is insufficient to withstand the internal pressures (Figure 34.11). Themost common chemical agent in this form of attack is sodium hydroxide. Evenwith a bulk boiler water free of NaOH as determined by usual methods of testing,

FIG. 34.11 Typical chemical-concentrate(ductile gouging)-type attack located down-stream of a weld with backing ring.

a porous deposit on the tube wall provides a mechanism for concentrating chem-ical in contact with the tube surface to several thousand milligrams per liter.Sodium hydroxide concentrates in this manner and reacts first with the magnetitetube surface and then with the elemental iron of the tube to form soluble sodium-iron complexes:

4NaOH + Fe3O4 — 2NaFeO2 + Na2FeO2 + H2O (1)

Fe + NaOh + H2O - NaFeO2 + 3H (2)

The parent tube metal is thus exposed to react with water to reform protectivemagnetite,

3Fe + 4H2O — Fe3O4 + 8H (3)

In either case, localized wastage of tube metal occurs and hydrogen is producedas a reaction product. The atomic hydrogen thus produced is capable of inter-granular penetration of steel and of reaction with carbon in the steel to form meth-ane gas:

4H + C — CH4 (4)

Not only is the steel thus weakened by decarburization along its grain boundaries(Figure 34.12), but the formation of methane develops pressure between grains inthe steel microstructure, producing discontinuous intergranular cracks. The endresult is failure of the tube wall when such intergranular decarburization andmicrofissuring have sufficiently reduced its strength. Although some water sidewastage of metal may have occurred in the corrosion reaction that produced thehydrogen, hydrogen damage normally results in thick-edged fracture before thewall thickness is reduced to the point that stress rupture would have occurred. Insuch thick-edged or "brittle" fracture failures, it is not uncommon for an entireirregularly shaped "window" to be blown out of an affected tube.

FIG. 34.12 Attack of boiler steel caused by hydrogen generation, leading to decarburization andfissure formation. (Left) Typical microstructure of pearlite colonies in a ferrite matrix. Etchant:picral. (50OX) (Right) Intergranular microcracks and decarburization near fracture surface ofactual hydrogen damage failure. Etchant: picral. (500 X)

In summary, the major causes of ductile gouging and hydrogen damage of car-bon steel tubes are (1) a chemical agent that will be corrosive if sufficiently con-centrated and (2) a concentrating mechanism.

There are several mechanisms capable of producing high localized salt concen-trations. Any condition of heat input in excess of the cooling capacity of the flowof fluid circulating through a tube can result in film boiling on the metal surface,with evaporative concentration of salts occurring. Localized pressure differentials,as created by high velocity through a tube restriction such as a welding back-upring, can result in small pockets of "flashing" water, concentrating salts on thedownstream side of the restriction. The most common mechanism is preboilercorrosion, with pickup of metals and their subsequent deposition on heated boilertube surfaces, where they function as porous membranes. Evaporation beneaththe deposit draws in boiler water to replace evaporation loss, but prevents solidsfrom leaving the area.

To prevent such corrosion and hydrogen damage, either all concentrationmechanisms must be eliminated or potentially corrosive chemical agents must beexcluded from the boiler water. Since porous deposits of preboiler corrosion prod-ucts create the most common mechanism for chemical concentration, strict atten-tion to protection of preboiler metal surfaces is critical.

A significant characteristic of modern utility cycles is the high ratio of preboilersurface area to that in the boiler itself. While a ratio of about 0.3 would be typicalin a 750 lb/in2 (52 bars) system, a ratio of about 1.3 would be typical at 2800 Ib/in2 (93 bars). This is a reflection of the multiple stages of regenerative feed waterheating commonly employed to increase cycle efficiency. To the water engineer,the higher ratio means that the area from which metals can be picked up is largerthan the area on which they are likely to deposit.

Metals used in fabrication of condensers, low-pressure heaters, and high-pres-sure heaters are commonly cast iron, stainless steels, and alloys of copper, suchas brass and monel. Thus, iron and copper are the principal contaminants likelyto be acquired by feed water enroute to the steam generator.

Feed water pH is an important factor in minimizing preboiler corrosion ofmetals. For iron and its alloys, although a minimum pH of 8.5 might be accept-able, feed water pH values in the range of 9.2 to 9.6 are considered optimum. Forcopper and its alloys, feed water pH values generally should be in the range of 8.5to 9.2. A compromise feed water pH control range of 8.8 to 9.2 is usually estab-lished where both metals are present. Volatile alkalies such as ammonia andamines that will not contribute dissolved solids are commonly used for pH con-trol in this portion of the cycle.

Feed water oxygen also has a great bearing on preboiler corrosion and contam-ination; an oxygen level of 5 ppb or less is usually specified. The largest potentialfor oxygen admission occurs in the high vacuum portions of the cycle. Oxygencan be reduced to low levels mechanically, either in deaerating-type surface con-densers or in separate deaerators located ahead of high-pressure feed waterpumps. For removal of residual oxygen, organic reducing agents like hydrazinemay be injected continuously immediately downstream of the condenser. Hydra-zine is a chemical oxygen scavenger that introduces no solids to the cycle. Itsconcentration is controlled in the range of 10 to 20 ppb in the feed water, usuallymeasured at the economizer inlet. Because of the potential risks to personnel inhandling hydrazine, a suspected carcinogen, proprietary substitutes have beendeveloped that react very much as hydrazine. The most widely used substitutescontain carbohydrazide and isoascorbic acid.

Ammonia, an important factor in preboiler pickup of copper, is generally pres-

ent in power cycles, either due to direct addition or decomposition of chemicalssuch as hydrazine or amines that have been added to the system. It can also resultfrom thermal decomposition of organic matter in cooling water entering the cyclethrough condenser leaks.

In sufficient concentrations, ammonia reacts directly with copper to form sol-uble complexes or it can contribute to stress corrosion cracking of copper alloytubes. Even at lower concentrations, ammonia can react with protective copperoxides on the water side of condenser and heater tube surfaces, exposing parentmetal to wastage by reaction with oxygen in the feed water. To minimize copperattack, most operators limit cycle ammonia concentrations to about 0.1 to 0.3mg/L. These limits can be met by carefully controlling chemical additions to thecycle and by proper regeneration of condensate polishers. Where ammonia con-centrations build up beyond the desired maximum, deconcentration may requiretemporarily dumping the normally recycled aftercooler drains (Figure 34.13)where ammonia concentrates.

FIG. 34.13 Noncondensible gases, including air from inleakage and NH3 fromsteam cycle, are removed by ejection and inter- and after-condensers. Final dripsmay be reclaimed or discarded if contamination levels are too high. Air discharge(vent) should be limited to 1 ft3/min (standard) (0.0283 m3/min) per 100-MWcapacity.

Good design calls for careful selection of materials of construction to with-stand the environment of the preboiler systems. Condenser tubes in freshwatercoolant service are commonly brass and stainless steel. These materials are alsocommon in low-pressure stage heaters, except for supercritical pressure cycleswhere even minute concentrations of copper can cause serious turbine foulingproblems, and the use of carbon steel is required. High-pressure stage heaters arefabricated of copper-nickel alloys, thin-wall stainless steel, and carbon steel.

It is now standard practice to reduce metallic "crud" in utility feed water bypolishing the condensate through a filter of mixed cation and anion exchange res-ins. Filtration removes the insoluble crud and ion exchange removes any dis-solved contaminants that have entered the cycle by inleakage.

Steam at150-200 psi 2d stage

ejector

Vent- noncondensiblegases to atmosphere

Condensateto deaerator

Af te r coolerdrips to drainor to recovery

1 psi X 0.069 = barsCondensate as coolingwater to intercondenser

Hotwell

Maincondenser

Airremovalsection

Intercondenserdr ips

Noncondensiblegases

1st stageejector

FIG. 34.14 Power cycle with full-flow condensate polishing.

For best cost performance, regenerable mixed bed polishers are commonlyoperated at service flow rates over 50 gal/min/ft2 (2 m3/rnin/m2), about 10 timesthe rate employed in raw water demineralization. To avoid any possibility of con-taminating cycle water with regenerant chemicals, resins are removed from thepolisher for external regeneration and periodic cleaning.

Nonregenerable, powdered resin polishers have found wide acceptance in util-ity systems. The finely ground resin particles provide good nitration and excellentkinetics for ion exchange. This type of condensate polisher is typically operatedat service flow rates of about 4 gal/min/ft2 (0.16 m3/rnin/m2). During cyclecleanup, such as during start-up, an inexpensive cellulosic filter aid may beincluded in the powdered resin mixture. In any case, when the resins becomefouled or exhausted, they are discarded, usually every 3 or 4 weeks.

For either regenerable or nonregenerable polishers, the cation exchange resincan be used in ammoniated form to prevent removal of ammonia from the cycle.Anion resins are in the hydroxide form.

Virtually all once-through boilers, because of their especially high water purityrequirements, employ polishing of feed water. Many plants polish the total feedwater flow; some polish as little as 20% at full load with increasingly higher por-tions as load is reduced.

Heater dr ips cascade downward >•Boi lerfeedpump

Polisher

Superheater

Boiler Turbine

Deaerator

As shown in Figure 34.14, polishers are generally located between the con-denser and the first feed water stage heater, since a large part of the vulnerablepreboiler metal surface area is in the condenser and on the steam side of stageheaters cascading drips back to the condenser. This placement protects high-tem-perature feed water heaters, the steam generator, and the turbine from deposit-forming contaminants. Temperature limitations on ion exchange resin controllocation of polishers in the cycle: regenerable polishers can withstand only about12O0F (480C), so must be confined to the condenser; powdered resin units may beplaced in higher temperature locations, but still in the lower pressure stage heatertrain.

In drum-type boiler systems where water purity is less critical, condensate pol-ishing may not be economically justifiable for normal day-to-day operations. Buteven in these systems, condensate polishing may be worthwhile to protect theboiler and turbine from the high levels of crud and silica common during initialstart-up and subsequent restarts. A polisher can greatly shorten the precirculationtime and often pay for itself in the cost of purchased power that would otherwisebe necessary during the start-up period.

Condensate polishing eliminates most deposit-forming materials that createchemical concentration mechanisms in steam generator tubes, but such measuresare never completely effective. Long-term accumulations of such deposits, prin-cipally iron and copper oxides, on boiler tube surfaces are removed by periodiccleaning. Utility boilers are generally considered "clean" with deposit weights lessthan 15 g/ft2 (1.5 g/m2) of tube area. Subcritical pressure boilers are considereddirty when accumulations exceed 40 g/ft.2 Supercritical boilers are consideredvery dirty at accumulations over 25 g/ft.2 Power boilers with normal feed waterconditions may be routinely chemically cleaned every 4 years. Longer intervalsmay allow otherwise soft deposits to harden and become tenacious and difficultto remove.

Corrosion and hydrogen damage of boiler tubes are not likely to occur whererigorous control of preboiler chemistry, condensate polishing, and periodic clean-ing keeps boiler surfaces clean. But because clean tube surfaces cannot be assuredat all times and conditions other than water side deposits can create chemicalconcentration mechanisms, it is general utility practice also to exclude sources ofpotentially aggressive free sodium hydroxide from the boiler water.

Corrosion of boiler steel is also a function of pH (Figure 34.15), and pH valuesideally should fall within a general range of 9.0 to 11.0. But a safe value must beachieved without producing measurable residuals of sodium hydroxide. In utility

FIG. 34.15 Attack on steel at 59O0F (31O0C) by water of varying pH.

Mineral ac id i ty H y d r o x y l a l ka l n i t y

Rel

ativ

e ra

te o

f at

tack

pH value at 25 0C

FIG. 34.16 The distribution of different ionic spe-cies of phosphate at various pH values.

Where the sodium (Na) to phosphate PO4) mole ratio in pure water is 3 to 1,for Na3PO4, the relationship of pH to phosphate ion concentration will be asshown on the so-called coordinated phosphate curve (Figure 34.17).

Controlling pH solely by sodium phosphate hydrolysis, bulk boiler water pHshould never accidently increase to levels aggressive to boiler steel. Reaction (6)shows that the hydrolysis reaction of trisodium phosphate is self-limiting; as pHrises above 10.0, generation of hydroxide ions by hydrolysis decreases. It is the-oretically impossible for a solution OfNa3PO4 to reach a pH much above 12.0. Ifthe Na3PO4 solution were to concentrate to 10,000 mg/L, the pH would be 12.

practice, this is accomplished either with a selection of sodium phosphate salts orwith a "zero solids" treatment using all-volatile chemicals.

Sodium phosphates provide the desired pH in boiler water, while controllingthe presence of free sodium hydroxide, as shown by these hydrolysis reactions:

Na3PO4 ^ 3Na+ + PO43' ...

trisodium phosphate) \3)

Na3PO4 + H2O ̂ Na2HPO4 H- NaOH (6)

Na2HPO4 ^ 2Na+ + HPO42"

disodium phosphate It /"7\

H+ + PO43-

Na2HPO4 + H2O — NaH2PO4 + NaOH (8)

NaH2PO4 ^ Na+ + H2PO4Vmonosodium phosphate Jt (Q\

H+ + HPO42-

The phosphates used are blends of disodium and trisodium salts of phosphoricacid. The species of phosphate present will depend upon pH, as shown in Figure34.16. This plot shows that phosphates exist almost entirely in the dibasic ionform (HPO4

2") within the pH range of 9.0 to 11.0 considered optimum for boilersteel. Note that pH is measured on a cooled sample, and equilibrium pH valuesin the boiler are somewhat different.

Mol

e% o

f sp

ecifi

c io

n

mg/1 PO4

FIG. 34.17 Equilibrium between PO4 and pH denning the coor-dinated phosphate boundary. (Adapted from Combustion, pp.45-52, October 1962.)

In reaction (6), if water were to be removed by evaporation, the equilibriumwould be forced to the left. Upon evaporation to complete dryness, the residuewould contain Na3PO4, free of NaOH. But incomplete evaporation, the morelikely condition beneath a porous deposit, produces a liquid beneath the depositrich in sodium hydroxide, especially if incipient localized corrosion were alreadyoccurring. Thus, maintaining a 3:1 sodium'.phosphate ratio in the boiler watermay not provide positive protection against caustic-concentrate-type corrosiondamage.

Many utility operators have adopted a modified form of coordinated phos-phate control calling for maintenance of a Na: PO4 ratio not over 2.6, correspond-ing to a 3:2 blend of trisodium and disodium phosphate. The control diagramshown in Figure 34.18 shows the differing hydrolysis effects of different sodiumphosphates in selectively adjusting pH, PO4, or both to keep coordinates withinthe desired range.

The all-volatile treatment (AVT) method uses only nitrogen-hydrogen com-pounds such as ammonia and hydrazine, so no solids are added. This is manda-tory in once-through steam generators. Even in drum-type boilers, volatile treat-ment offers protection against superheater and turbine deposits that mightotherwise occur with carryover of boiler water containing dissolved solids.

A disadvantage of AVT for drum-type boilers is that the boiler water is unbuf-fered and thus subject to extensive and rapid pH excursions in the event of feedwater contamination. There is no tolerance for condenser coolant inleakageunless condensate polishing is provided.

Contaminant salts entering the cycle from other sources may produce acids(H+) or alkalies OH ~) capable of being concentrated locally to corrosive levels.Typical contaminant sources are (1) condenser leakage; (2) treated make-up water

Sodium hydroxide generated solely by this hydrolysis reaction is sometimescalled "captive"; it will be "taken back" and revert to Na3PO4 at any sites of local-ized evaporative concentration, so high concentrations of NaOH in a confinedarea where solids might form is avoided, preventing caustic-gouging-type ofmetal attack.

Equ

ilibr

ium

pH

valu

e at

250

C

P O 4 , T o t a l phospha te , m g / l

FIG. 34.18 Suggested coordinated phosphate control target for high-pressure boilers.

contamination by evaporator carryover or demineralizer leakage; (3) regenerantcontamination from ion exchange units; or (4) incomplete removal of chemicalcleaning solvents or alkalies. Of these, condenser leakage is the most significant.

Boiler tube hydrogen damage that results from condenser leakage is particu-larly likely to occur where the cooling water is brackish. The reactions of contam-inants such as calcium chloride and magnesium chloride in boiler water, afterdepletion of any soluble phosphates, are:

MgCl2 + 2HOH - Mg(OH)2 + 2HCl (10)

CaCl2 + 2HOH — Ca(OH)2 + 2HCl (11)

In high-purity, unbuffered boiler water, very small cooling water leaks canreduce pH to 4.0 or less. Where the acid is then concentrated locally within adeposit at a tube surface, corrosion and hydrogen damage proceed rapidly.

While protection is afforded by condensate polishers, strict surveillance of con-denser leakage is prudent for drum-type boiler cycles without polishers. As a gen-eral rule, leaks causing 0.5 mg/L feed water concentrations can usually be accom-modated in normal operation without serious difficulty: feed water concentrationsof 2.0 mg/L may be tolerated for short periods; but immediate boiler shutdownis usual when a condenser leak produces concentrations greater than 2.0 mg/L.Immediate boiler shutdown is always indicated where acceptable boiler water pHcannot be maintained.

The necessary continuous surveillance of condenser leaks usually relies on so-called cation conductivity monitoring, which effectively senses concentrationchanges as small as 20 ppb (^g/L). In this method, a condensate sample passesthrough a column of acid-form cation resin to convert sulfate, chloride, and

Ratio refers to molecularrat io of Na to PO4

Control vectorsNaOH

Slowdown

pH a

t 250

C

(780

F)

Note:Exper imenta l pH vs. PO4 va lues per Rosemer.Dole.Mesmer, and Feldman

nitrate salts to more electrically conductive sulfuric, hydrochloric, and nitric acid.The conductivity is then measured in the resin-treated sample.

Monitors for silica and sodium are alternative devices for detection of con-denser leaks. Against background concentrations commonly encountered in tur-bine condensates, available monitoring equipment can reliably detect changes of5 ppb or less in either of these contaminants.

STEAM PHASE PROBLEMS

In the 1950s, it became apparent that the silica in steam that was causing depositson the low-pressure stages of utility turbines was not carried out of the boiler indroplets of the boiler salines, but rather it was a gaseous fraction of the high-tem-perature vapor. (This was a contribution to water chemistry from the field of geol-ogy.) Previously, it had been long recognized that carbonates would break downto yield CO2 in steam, but now there was growing evidence that minerals mightactually volatilize and leave the boiler in the gas phase. With development of theonce-through boiler, it was apparent that any minerals in the feed water, volatileor not, would be passed along to the turbine and the condenser. This led to thedevelopment of polishing demineralizers for the condensate stream to prevent abuildup of minerals in the cycle that would lead to deposits. It also led to devel-opment of AVT, or the use of volatile chemicals, such as ammonia and hydrazine,as the only chemical treatment applied to the cycle.

The quality of makeup improved greatly in the succeeding years, demineral-izers replacing evaporators not only on the basis of economics, but also on qual-ity; evaporators (as then designed) were unable to produce the low silica levelsneeded to avoid turbine deposits.

The newer systems began to experience turbine blade cracking, generallyoccurring on the next-to-last wheel, and it was found that the cracking was causedby caustic. Furthermore, ammonia concentrations and pH were difficult to con-trol, because the polishing demineralizer removed ammonia (usually causing anincrease in sodium); and erratic control often led to attack of copper alloy heatertubes.

Because of these problems, it became necessary to study steam-phase condi-tions throughout the cycle. This required the development of sophisticated andreliable isokinetic sampling systems capable of handling both superheated andwet steam, at high pressure and under vacuum. Analyses were made of the natureand causes of system deposits, and basic research was undertaken in the physicalchemistry of the elements and compounds found. One of the surprising conclu-sions was that NaCl present in superheated steam hydrolyzed, yielding NaOH indry deposits and HCl in the condensed steam. Because of this, limits were placedon sodium levels because sodium seems to be the major cause of embrittlement-type attacks on turbine blading, a problem more common to AVT systems thanto drum-type boilers using phosphate treatment.

There is still more to be learned about vapor-phase chemistry, but present stateof the art calls for extensive sampling and continuous analysis of makeup, con-denser hotwell water, deaerated water, feed water at the economizer inlet, boilerwater, superheated steam, and selected stage heater drains. The analyses includecontinuous measurement of conductivity, pH, dissolved oxygen, sodium, and sil-ica (on demineralized makeup); Fe, Cu, and Ni on feed water, heater drains, andcondensate; these metals plus ammonia before and after condensate polishers;

hydrazine on feed water; and boiler testing (with drum-type boilers). With thistype of monitoring, conditions can be continuously scrutinized both duringsteady load and during shutdown and start-up, so that corrective adjustments canbe made in chemical treatment, or operating problems (demineralizer regenera-tion, control of air inleakage, control of condenser leakage) can be corrected.

The steam-phase chemistry relative to geothermal plants is completely differ-ent from conventional plants, as the vapor often contains additional contami-nants (e.g., boron and sulfur compounds) at parts per million rather than partsper billion levels. This is a completely new field.

WA TER CHEMISTRY IN NUCLEAR FUELED PLANTS

The nuclear pressurized water reactor (PWR) (Figure 34.5) has two major watersystems:

1. The primary loop, or reactor coolant system2. The secondary loop, or steam generator-turbine cycle

Components of the primary loop are the reactor vessel, a pressurizer, steamgenerators (heat exchangers), and circulating pump. In the primary loop, watertemperature is allowed to rise only about 5O0F (280C) passing through the reactor,so recirculation rates are quite high to absorb the amount of heat generated. Pres-sure of the recirculating water is kept high enough to keep the water from boiling.The pressurizer maintains this pressure and absorbs changes in volume producedby changes in temperature. For maximum corrosion resistance, wetted surfacesin the primary loop are usually stainless steel or nickel-based alloys.

High purity must be maintained in the primary loop water to minimize foulingof reactor and exchanger heat transfer surfaces and to avoid contaminants thatcould form undesirable radioactive isotopes under neutron flux. Controlled addi-tions and removals of boric acid in the primary loop water provide the correctconcentration of neutron-absorbing boron needed to control neutron flux andenergy transfer. Chemicals such as lithium hydroxide, forming relatively saferadioisotopes under neutron flux, are used for pH control in the primary loop.

Under nuclear radiation in passage through the reactor, some of the primaryloop water is decomposed into hydrogen and oxygen as follows:

H 2 O-H 2 + X2O2 (12)

To suppress oxygen generation and to scavenge oxygen entering the system,hydrogen gas is commonly added. Primary loop water purity is usually main-tained by continuously passing a portion of the circulating water through a mixedbed demineralizer. These generally utilize anion resins in the borate form, toavoid removal of boron from the water. As impurities accumulate, these resinstend to become radioactive and regeneration becomes impractical. Consequently,the resins are eventually disposed of as a solid radwaste.

Two basic heat exchanger designs are employed as secondary loop steam gen-erators in PWR systems. The recirculating U-tube-type (Figure 34.19), is analo-gous to a drum-type boiler in a fossil-fueled system. Having an internal recircu-lation rate of 3 to 4 times the steam flow, the unit provides mechanical steam-water separation and continuous blowdown. But it differs from fossil-fueled boil-ers in that there is no provision for superheating the steam.

FIG. 34.19 PWR vertical U-tube recirculating-type steam generator withintegral feed water preheater.

The other PWR heat exchanger design (Figure 34.20) provides once-through-type steam generation. The heat exchanger is baffled so that incoming feed waterfirst flows down through an outer annulus in which it is heated to saturation tem-perature, and then it is converted totally to steam and is slightly superheated in asingle upward shellside pass through the tube bundle. Depending on load, up toabout 6O0F (340C) superheat can be achieved.

Either type steam generator requires maximum corrosion resistance on the pri-mary side, so tube materials are commonly a special nickel-iron-chromium alloy.Carbon steel shells are generally used, although those parts of the shell surfaceconstituting the primary coolant inlet and outlet plenums are clad on the coolantwater side.

For recirculating U-tube-type PWR steam generators, the AVT method is pre-ferred to coordinated phosphate treatment. In once-through-type PWR steamgenerators, of course, AVT is automatically required.

In the nuclear boiling water reactor (BWR) (Figure 34.21), boiling occurs inthe reactor itself. The same water serves as the cycle working fluid, the reactorcoolant, and the nuclear reaction moderator. Boiling water reactors are compa-rable to drum-type boilers. A portion of the water passing through the core isconverted to steam. The steam-water mixture is then separated, with the steamgoing to the turbine and boiler water returning through circulating pumps to thecore inlet.

An important aspect of BWR operation is the effect on the working fluid ofdirect exposure to nuclear radiation. Some of the water is decomposed into hydro-gen and oxygen. It is not possible to inject hydrogen as in the PWR because of

Steam outlet

Secondary separator

Primary separator

Downcomer area

U tubes

Annular wrapper (downcomer)

Feedwater inlet

Preheater

Primary coolant nozzle

Coolant inlet from core

Recirculated water

Water level

Steaming area

Divider plates

Coolant chamber

Coolant outlet return to core

FIG. 34.20 PWR once-through-type steam generator. (Adapted fromSteam/Its Generation and Use, Babcock & Wilcox Company, 1972.)

the heed for continuous removal of all noncondensible gases at the condenser tomaintain the vacuum required for turbine efficiency. Thus, steam produced by aBWR reactor contains high concentrations of oxygen, an important factor incorrosion.

Nitrogen entering the cycle by air inleakage or decomposition of nitrogenouscompounds can react to form nitric acid:

5O2 + 2N2 + 2H2O - 4HNO3 (13)

Additives for pH control and oxygen scavenging, such as amines and hydra-zine, are not usable in BWR cycles because they are subject to nuclear decom-

Reoctor coolant inlet

Manway

TubesheetCoolant f lowsthrough tubes

Tube support plates

Divider

Feedwater inlet

Annular space forfeedwater preheating

Steaming areabetween tubes

Manway

Tubesheet

Manway

Inspection portDrain

Return to core

Reactor coolant outlet

Lower annular baf f le

Steam outlet

Upper annular baf f le

Auxi l iary feedwater inlet.

FIG. 34.21 In the BWR nuclear plant, steam is generated in thesame vessel that contains the fuel elements, as shown in this sim-plified diagram.

orifices of the core water distributor. Make-up water is demineralized to less than1.0 juS/cm specific conductivity and 10 ppb (^g/L) silica. Full flow condensatedemineralization is then employed to maintain cycle water purity at limits estab-lished by the reactor manufacturer. Typical limits are: 30 ppb total metals, 2 ppbCu, 2 ppb Cl, and 0.1 /iS/cm at 250C. Resultant feed water is essentially neutral,with pH equal to 7.

Where deep bed demineralizers are used in BWR condensate polishing, resinsare usually sluiced to external vessels for scrubbing and regeneration. Theregenerant wastes generally contain low-level radioactivity which requires pro-cessing in the liquid radwaste system. Where nonregenerable powdered resinunits are used for polishing, the spent, sluiced resin must be processed.

CONDENSER COOLING WATER

As previously discussed, the thermal efficiency of modern fossil-fueled steam elec-tric plants averages about 34%. The largest part of the loss, equal to about 50% ofthe heat released by the fuel, is rejected at the condenser. Nuclear-fueled plants,averaging about 32% efficiency, lose even more heat at the condenser. Heatrejected at the condenser is transferred to cooling water, which subsequentlyreleases this heat to the environment.

Although water circulating through the tubes of a surface condenser is calledcooling water, it is important to recognize that there is no cooling of the vapor or

position. Thus, corrosion control relies primarily on the corrosion resistant mate-rials used throughout the cycle.

Metallic contaminants in the cycle water, either from condenser leakage orfrom corrosion of system metals, are subject to stringent limitations to avoid for-mation of hazardous isotopes and to avoid deposition of crud on the core heattransfer surfaces. Copper is specifically limited because of its tendency to foul the

Feed pump

Condenser

Turbine

Steam

Feedwater

Steamseparators

Steamgenerationinfuelelement area

Recirculation

condensate. The circulating water simply absorbs the heat of vaporization ofsteam leaving the turbine, converting it to liquid at the same temperature. Forthis reason, the term "condenser water" is sometimes preferred to "coolingwater."

The primary function of a surface condenser is to maximize cycle efficiency byallowing steam to expand through the turbine to the lowest possible exhaust tem-perature. Just as in a boiler drum, the temperature of steam and water in a con-denser is directly related to pressure. At 1020F (390C), for example, the corre-sponding saturated steam pressure is about 1.0 lb/in2 abs (51.7 mmHg); this isalso expressed as a vacuum of about 27.89 in of mercury (705 mmHg). At thisvacuum, 1 Ib of steam occupies 331.1 ft3 (20.6 m3/kg); when condensed it occupiesonly 0.016 ft3 (0.001 m3/kg), about 0.005% of the original steam volume.

Noncondensible gases (air, ammonia) in the condenser reduce the vacuumachievable, so such gases are continuously removed by mechanical vacuumpumps or steam jet eductors (Figure 34.22).

The ability of a surface condenser to provide the lowest possible backpressurefor a given load and cooling water temperature is adversely affected by such thingsas:

1. Waterside scaling and fouling of condenser tube surfaces2. Partial blockage of cooling water flow through the tubes3. Inadequate removal of noncondensible gases4. Faulty distribution of exhaust steam

Waterside scaling and fouling are probably the most common causes of impairedcondenser performance.

The effect of a 1.0 in Hg (25.4 mm) rise in backpressure in a 500-MW plant isillustrated in Figure 34.23. At constant steam rate, electrical output would bereduced by about 13 MW, a loss of 2.5%. This 13 MW represents about $1.25

FIG. 34.22 Two-pass surface condenser with provision for reversing water flow for backwashingtubes and waterbox. Inter- and after-condenser drips normally return to the hotwell.

Circulatingpump

Drips

Drips

Aftercondenser

Air out

Condensate

Second-stageejector

First-stageejector

'Steam

-Inter-condenser

Atmospheric relief

Airofftake

Turbineexhaust

Priming ejector

Water box

Revers ingvalve

500-MW Generation—Coal Fired(where unit rating permits fixed load maintenance)

Backpressure,in mm Hg Gross turbine

(abs) unit Heat rates, total

1.5 7600 Btu/kWh 3.8 X 109 Btu/h2.5 7800 Btu/kWh 3.9 X IQ9 Btu/h

A. Rise 1.0 200 Btu/kWh 0.1 X l O 9 Btu/hB. Additional fuel Btu (at 90% boiler efficiency) = 0.11 X 109 Btu/hC. Additional fuel cost (at $1.75/million Btu = $193/h

$4620/day

Plus additional fuel cost caused by increased load on auxiliaries.1 Btu = 0.252 kcal

FIG. 34.23 The effect of turbine backpressure increase on plant efficiency.

million in plant investment. Effective condenser water treatment is a very impor-tant factor in preventing such losses.

Five basic types of condenser water systems are used in utility stations (Note:There are also some all-dry condensing systems, but these are quite rare.):

1. Once-through cooling2. Cooling lake and cooling pond systems3. Spray ponds4. Wet cooling tower systems5. Wet-dry combination cooling tower systems

In once-through cooling, water passes once through the condenser and returns toits source at a higher temperature. Because residence time and temperature arelow, scaling is usually not a problem. The principal fouling problems are usuallyrelated to microbial activity and silt deposition. Regularly scheduled biocide con-trol usually achieves a moderate increase in condenser cleanliness for severalhours. Application of a biodispersant with each application of chlorine or bro-mine can increase both the magnitude and duration of this improvement (Figure34.24). By increasing the effectiveness of chlorine or bromine, such biodispersantsalso can reduce the dosage of biocide, helping the plant meet dischargeregulations.

Corrosion inhibitors are rarely required in freshwater once-through systems.But for protection of copper alloy tubes (e.g., aluminum-brass) in seawater once-through systems, low dosages of ferrous sulfate are sometimes applied intermit-tently to the condenser inlet water to provide a protective film of iron oxide onthe tube internal surfaces. The cost effect of the film in reducing heat transfer mustbe balanced against the benefit of reduced corrosion.

With the advent of environmental regulations restricting thermal discharges,some once-through systems have been modified so that the condenser outlet waterpasses over a "helper" cooling tower or through a tempering canal with floatingspray modules to dissipate heat before discharge. Since such "helper" additionsfollow the condenser, biocide-dispersant treatment of the water is the same as forconventional once-through systems.

C.F. improvement

Treatment* Highest percent Duration

0.05 mg/l Cl2 residual plus15 mg/l biodispersant 7.24% 6.5 hours

12.12 mg/l Cl2 residual plus5 mg/l biodispersant 2.61% 6.0 hours

12.40 mg/l Cl2 residual aloneno biodispersant 0.55% 2.0 hours

* Short duration treatment applications with system blowdown closed off untilchlorine residual gone.

FIG. 34.24 Condenser tube cleanliness factor improvement through the use of a biodisper-sant. (Source: Nalco Research Report Serial No. 1642, June 1977, re: Field evaluation dataobtained at Duane Arnold Nuclear Center of Iowa Electric Light & Power Company.)

Cooling water may be discharged to cooling lakes, artificial impoundments cre-ated by damming a stream. Condenser water is recirculated through the lake, andheat is dissipated primarily by surface evaporation. The lake receives make-upfrom rainfall and runoff from its drainage area. Cooling lakes make possible highcooling water withdrawal from streams too small to provide such cooling capacityon a once-through basis. Water treatment practices and discharge limitations aregenerally the same for these cooling lakes as for once-through cooling.

By contrast, cooling ponds are defined as impoundments that do not impedethe flow of a navigable stream. They are usually constructed along a stream fromwhich make-up water may be pumped to meet evaporative losses not replaced byrainfall or runoff from surrounding drainage areas. Cooling ponds containedwithin earthen levees at levels above the surface water are said to be "perched."The area required for natural evaporation is typically on the order of 1.0 to 1.5acres (0.4 to 0.6 ha) per megawatt of capacity. A pond typically provides detentionof about 5 to 15 days to produce the necessary heat dissipation.

Blowdown from cooling ponds is composed of bottom seepage and controlledoverflow to the source stream. Because of the large rainfall-receiving surface areas,concentration ratios are typically quite low, up to about 1.5 times source concen-tration. But even such low concentration increases may be significant in terms ofreduced CaCO3 solubilities, so condenser tubes are more likely to scale on pondsystems than on once-through cooling systems. Sulfuric acid may be fed to main-tain pH below saturation values (pHs). Scale inhibitors and dispersants are some-times required in conjunction with acid feed for complete scale prevention.

A significant aspect of cooling ponds is that they promote "homes" for a vari-ety of aquatic organisms. They often support large fish populations. Specific bio-dispersants in conjunction with periodic feed for chlorine or bromine may beneeded to keep condenser tubes free of biological slimes initiated by the micro-organisms of the food chain supported by the pond.

Spray ponds promote evaporation by mechanically dispersing water intosheets and droplets, dissipating heat effectively so that less pond area is required.Evaporation is mechanically promoted, so it is less dependent on climatologicalconditions. Recirculating water treatment requirements generally correspondmore closely to those of evaporative (wet) cooling towers than to cooling pondsor lakes.

Where large cooling ponds or spray ponds are impractical, cooling towers are

installed to reduce thermal pollution of receiving waterways. To comply withrestrictions on thermal discharge, blowdown is taken from the tower basin, hav-ing the lowest temperature of the recirculating system.

An important advantage of wet cooling towers is their ability to significantlyreduce raw water withdrawal and wastewater discharge (Table 34.2).

TABLE 34.2 Water Flows for 1000-MW Plant Cooling System

[Based on 2O0F (U0C) temperature rise]

Once-through Wet cooling towercooling system recirculating system

Condenser flow, gal/min* 400,000 400,000Evaporative cone, ratio 1X 5 XMake-up water, gal/min 400,000 10,000Discharge water, gal/min 400,000 2,000

*gpm X 3.785 X ICT3 = m3/min

Because drift (entrainment of fine mist) from a cooling tower is part of blow-down, the net discharge to the receiving stream in this example would be about10 to 200 gal/min (0.038 to 0.76 m3/min) less than the 2000 gal/min (7.6 m3/min)shown.

With the constraints of environmental limitations on concentrations of chlo-rine and other chemicals that may be discharged in blowdown, cooling towerrecirculating water treatment practices for stream-electric plants are generally asdescribed elsewhere in this text for industrial plants.

With the increased planning for maximum water conservation, coal-firedplants may substitute cooling tower blowdown for raw water for ash sluicing.Some sluice water is evaporated by the heat of bottom ash, and a small amountis retained by the ash, so the final volume of wastewater for disposal is furtherreduced.

Zero discharge of tower blowdown may be impractical and unnecessary envi-ronmentally in most parts of the country, but strategies for approaching this goalhave been devised for arid regions where adequate land is available. In such cases,tower blowdown may be routed to on-site solar evaporation ponds.

FIG. 34.25 Simplified schematic of process to recover cooling water by side-stream treatment and desalination to yield only a concentrated brine.

Recovery

MakeupCool ing

Condenser

Evaporation

Hot return

Desal t ing

Brine tosolarevaporation

Side streamprecipitation

FIG. 34.26 Dry cooling towers can be used in water-short areas, but users usually pay a penaltyin energy loss where air temperatures are high. (From Power Special Report, "Cooling Towers,"March 1973.)

Various processes for side stream treatment of cooling water and for blowdownconcentration reduce discharge volume and required evaporation pond areas.One such conceptual system is illustrated in Figure 34.25. Although side streamprocessing can control concentrations of potentially scale-forming ions, highsalinity in the recirculating water is characteristic of these treatment schemes. Theeffects of high dissolved solids in cooling tower drift and on surounding vegeta-tion and structures must be considered. Also, the significantly greater impact ofcondenser leaks on the chemistry of the boiler water cycle must be provided for.

Moisture "plumes" emanate from cooling tower stacks like clouds under manyweather conditions, literally dominating the atmosphere in the immediate vicin-ity. One means of eliminating plumes is to use nonevaporative dry cooling tow-ers. In dry cooling towers (Figure 34.26), heat is transferred from the recirculatingwater to the air by convection rather than by evaporation.

Since dry cooling tower performance is controlled by ambient air dry bulb tem-perature, rather than by lower wet bulb temperatures, turbine backpressures arehigher for dry tower systems than for wet towers, so cycle efficiencies are poorer.

But combinations of wet and dry cooling towers may be used to advantage(Figure 34.27) to alleviate plume problems with minimum loss of cycle efficiency.And, since dry towers handle their part of the heat load without evaporation,overall make-up and blowdown volumes are less for wet-dry cooling tower com-binations. Systems may be set up with the recirculating water flowing either inseries or parallel through the wet and dry towers. Designs usually provide for ameans of totally or partially bypassing either air flow or recirculating water flowselectively around either the wet or dry tower, as may be required to optimizeplant efficiency for varying plume abatement and water conservation require-ments. Figure 34.28 diagrams a system with provision for water bypass. Figure34.29 illustrates an integral wet-cooling tower unit with provision for adjustingthe balance of air flows through the wet and dry sections. Recirculating watertreatment practices for wet-dry cooling tower systems are essentially the same asfor straight wet cooling tower systems. As load is shifted from wet to dry cooling,less dirt is washed out of the air to contaminate the recirculating water.

Closed recirculating water systems handle a variety of cooling requirements in

Design condenser pressure.in. Hg abs

(With 10O0F design air temperature)

Operating condenser pressure,in. of Hg abs

Shuttercontrol

Plenum

FinsShutters

Headers

Fan motor

Belt drive

Fan

Ambi

ent a

ir te

mpe

ratu

re,°

F

FIG. 34.28 Bypass permits optimum use of wet and dry cooling towers. (FromCombustion, pp. 23-27, October J 9 76.)

utility stations, avoiding introduction of outside contaminants that might foulheat exchanger surfaces. Systems of this type are sometimes used for cooling thehydrogen circulated for electric generator cooling. They also may be used for after-cooling of compressed air, jacket cooling for standby diesel engines, and for cer-tain lube oil cooling requirements. In nuclear plants, closed recirculating cooling

FIG. 34.27 At this utility station a large combination wet-dry tower is used tocool condenser water. (Courtesy of the Public Service Company of New Mexico.)

Dry tower Wet tower

Pumpstation

Sur face condenser

FIG. 34.29 Integral wet/dry cooling tower with damper control(D.E.s—drift eliminators). (From Reisman, J. I., and Ovard, J. D.:"Cooling Towers and the Environment—An Overview," Proceedings ofthe American Power Conference, vol. 35, 1973.)

water systems are commonly used to handle heat loads from the reactor vesselshielding, primary coolant pump seal housings, and other heat loads within thereactor building.

MISCELLANEOUS WATER USES

Another major water use in coal-fired power plants, and to a lesser extent in oil-fired plants, is for ash transport. The solids that fall to the bottom of the boilerfurnace (bottom ash) are invariably cooled and conveyed from the boiler bywater. The solid products of combustion (fly ash) in the flue gas that do notdeposit in the boiler convection passes or air heater, are subsequently removedby electrostatic precipitators, bag filters, and wet scrubbers. Fly ash accumulationsare removed from these devices either by water or by mechanical or pneumaticmeans.

The quantity of water required for ash sluicing varies with design factors suchas method of firing and nature of the coal. For a typical 1000-MW coal-fired plant,it amounts to about 10 mgd (26.2 m3/min).

For molten slag tap or "wet bottom" boiler, where water is used to quenchmolten ash, heat pick up can be in the range of 106 Btu per ton of bottom ash.Suspended solids in bottom ash water are of concern if they are difficult to settle.

DAMPERS

D.E.'S

HEATEXCHANGER

FILL

COLD WATER

INTAKELOUVERS

WARM DRYEFFLUENT

FAN

HOTWATER

FIG. 34.30 The suspension firing of coal produces slag in a variety of forms, including thesemicrospheres, which float to the surface of wet ash collection ponds. (Left) Random spheres;(right) broken shell.

Coagulants may be needed to reduce supernatant turbidity. Dissolved solids con-tribution to the sluice water from the ash is relatively small.

By contrast, fly ash is much more leachable and may contribute on the orderof 50 to 800 mg/L dissolved solids to its transport water. Fly ash often containshollow microspheres (Figure 34.30), which are difficult to separate from sluicewater by sedimentation. So, dry transport systems are often used to handle it.

In oil-fired plants, ash is produced in comparatively small quantities. Bottomash removal from the boiler by fireside washing and sluicing may be needed onlyoccasionally. Oil ash generally does not settle in ponds as well as coal ash. Whileash pond overflow waters have many of the same characteristics as in coal-firedplants, high concentrations of vanadium may be present, originating as an ashconstituent of some fuel oils. Bottom ash in some oil-fired plants is removed bydry collection rather than by water sluicing.

Where there is a market for the bottom ash, or where insufficient land is avail-able for settling, dewatering bins can be used and the dewatered ash trucked away.Water drainage from dewatering bins or the supernatant from ash ponds can berecycled to the sluice pumps. Make-up to such recycle systems is required forreplacement of evaporative losses and moisture that leaves with the dewateredash. Because of the poor liquids/solids separation of the buoyant fly ash, however,recycle systems are generally not suitable where fly ash is sluiced to the samedewatering point as bottom ash. Chemical coagulants and flocculants are usefulin the treatment of ash transport waters, to reduce suspended solids to acceptablelevels for recycle or final discharge.

In some utility plants firing high-sulfur coal, water is also used in wet-scrub-ber-type flue gas desulfurization (FGD) systems. Most FGD systems in U.S.power plants use a wet scrubbing process in which the reactive component of thesorbent is not regenerated. Most commonly, sulfur dioxide in the flue gas isreacted with slurries of lime or limestone to form calcium sulfites and sulfates.Sludge from the process, consisting of fly ash and water in addition to the calciumprecipitates, is usually piped to large settling ponds. Supernatant water from theponds is reclaimed and recycled to the process. The ponded sludge retains aquicksandlike character, limiting any future use of the pond land area. Make-upwater requirements for such systems may be in the range of 0.75 to 1.0 gal/min(2.8 to 3.8 1/min) per megawatt of generation rate.

FIG. 34.31 Flow diagram of the double-alkali process for removal of SO2 from flue gas toproduce a disposable sludge cake and recycle soluble alkali.

A smaller number of nonregenerable FGD systems are of the double-alkalitype. In this process, flue gas is scrubbed with a solution of sodium hydroxide toform sodium sulfite and sodium bisulfite. The scrubbing solution is then reactedwith lime, precipitating sludges similar to those with lime as the primary sorbent,restoring the sodium hydroxide for reuse in the process. Although the absorbingmedium is thus "regenerated," this process is still categorized as nonregenerablebecause the sulfur scrubbed from the flue gas is not recovered (Figure 34.31).

TABLE 34.3 Major Wastewater Sources and Contaminants in Fossil-fueled Steam-Electric Generating Plants

Source

Ash sluicing systemLow- volume wastes^Metal-cleaning wastes§Boiler blowdownMain condensers, once-through coolingMain condensers, recirculating-water

blowdownArea runofffIntake water traveling screens and

strainers

Principal contaminants

TSS,* TDS,t heat, oilTSS, TDS, pH, oilTSS, TDS, pH, iron, copper, other metals, oilTSS, iron, copper, oilHeat, residual chlorineResidual chlorine, Zn, Cr, P and other

corrosion inhibitorsTSS, TDS, pH, oilSolids (debris)

* TSS, total suspended solids.t TDS, total dissolved solids.$ Low volume wastes, collectively including wastes from ion exchange systems regeneration, evap-

orator blowdown, flue-gas wet scrubbers, floor drainage, cooling-tower basin cleaning, blowdown fromrecirculating house service water systems.

§ Metal cleaning wastes, including waterborne wastes from boiler tube cleaning, boiler fireside clean-ing, air preheater cleaning.

f Area runoff, including rainfall runoff from storage of coal, ash and other materials.

Outlet duct

Fromprecipitdtor

System B

Lime(CaO)

Usebin

Water

SlakerCa(OH)2

Thickener System E

System C

Filter cakeSodium regeneration2NaHSO3 4-Ca(OH)2 —

Ca SO 3 «1/2 H2O + Na2SO3-I-11/2H20

Sulfur dioxide absorptionNa2S03+S02 + H2O-

2NaHSO3

System A

Boosterfan

Stack

Limereactor

Surgetank

Na2CO3

Soda ashstorage

System D

Steam-electric power plants are subject to federal, state, and local water pol-lution control regulations. Where these regulatory bodies differ on specific limi-tations for a given pollutant, the more stringent regulations generally apply. Somestate and local regulations limit certain pollutants not limited by federalguidelines.

A significant feature of pollution control regulations for steam-electric plantsis that specific discharge limitations relate to individual processes and sourceswithin the plant rather than to the combined discharge. Thus, no credits accruefrom combining or diluting one in-plant waste stream with another. For example,the total weight discharge per day of iron originating in boiler blowdown may notexceed the actual daily flow of boiler blowdown times the permissible concentra-tion limit of iron.

A simplified tabulation of steam-electric plant wastewaters and their contam-inant characteristics, by source categories, is shown in Table 34.3.

FIG. 34.32 Water reuse and effluent treatment scheme for a coal-fired steamelectric plant.

Makeup

Arearunof f

Metalcleaning

Ion exch.regen.

Ashsluice

Hold. Hold. Neuf.Hydrobins

orash pond

Surgefank

Oil to sprayon coal pile E q u a l i z a t i o n

Recyclepit

Oilpump

C l a r i f i e r s

Clear we l l

Drumf i l te r

N/C r e c y c l e

O u t f a l l

Solidshaul-out

Intake

Trashhaul-out

Intaketravel l ingscreenbackwash

Small meshscreen dev ice

Servicewaterstrainerbackwash

Once- th roughcooling water \

discharge <

To e i t he r :

1. Cool ing pond2. Separate outfal l

Ashhaul-out

Sani tarywas tes

iTo e i t he r ;

1. C i t y sewer2. On-s i te t reatment

and discharge

'Boilerblowdown

.*To e i t h e r :1. DI water recovery

2. Equal izat ion basin3. Separate outfal l

Source: Development Document for Proposed Effluent Limita-tions Guidelines and New Source Performance Standards for SteamElectric Powerplants, EPA 440-1-73/029, March 1974.

Principles of water recycle, reuse, and effluent treatment for steam-electricplants are generally the same as for other process industries. Figure 34.32 illus-trates one reuse and effluent treatment scheme for a coal-fired plant. In this illus-tration, bottom ash transport water is recycled. Fly ash is separately handled in adry system. One of the difficult problems is proper handling of coal pile runoffwithout interfering with coal handling procedures in the large area used for coalinventory. The runoff is often high in heavy metals, alumina, and crud, and mayrequire recycle or direct treatment (Table 34.4).

For nuclear power plants, a principle of special importance is the segregationof dissimilar wastes. High-purity (low-conductivity) wastewaters are kept separatefrom low-purity (higher conductivity) waters to facilitate reclamation and recycleof the high-purity waters. Chemical wastes, including ion exchange regenerantsand chemical cleaning wastes, should be segregated from detergent wastes becauseof their differing requirements for final treatment before discharge or reuse.

SUGGESTED READINGS (SEE "ENERGY PRIMER/'CHAPTER 46)

Auerswald, D. C., and Cutler, F. M.: "Two-Year Study on Condensate Polisher Performanceat Southern California Edison," Proceedings 43rd Internation Water Conference, October1982.

TABLE 34.4 Typical Characteristics of Coal Pile Runoff

Parameter

Total solidsTotal dissolved solidsTotal suspended solidsTotal hardness (CaCO3)Alkalinity (CaCO3)Acidity (CaCO3)ManganeseCopperSodiumZincAluminumSulfatePhosphorusIronChlorideNitrateAmmoniaBODCODTurbidity (in JTU)pH (in units)

Concentration, mg/L

1500-45000700-4400020-3300

130-185015-8010-2780090-1801.6-3.9

160-1260006-23.0825-1200130-200000.2-1.20.4-2.020-4800.3-2.30.4-1.8

3-10100-1000

6-6052.8-7.8

Austin, S. M., et al.: "Know Your Condenser," Power Eng., reprint of papers, 1961.Babcock & Wilcox Company: Steam/Its Generation and Use, 1972.Federal Power Commission: Steam-Electric Plant Air and Water Quality Control Data,FPC-S-229, February 1973.

Federal Power Commission: Steam-Electric Plant Air and Water Quality Control Data,FPC-S-253, January 1976.

Federal Register: Steam-Electric Power Generating Point Source Category, Effluent Guide-lines and Standards, 39 Num (196) (October 8, 1974).

Jacklin, C., and Brower, J. R.: Correlation of Silica Carryover and Solubility Studies,"ASME Paper No. 51-A-9L

Kennedy, George C.: "A Portion of the System Silica-Water," Econ. Geoi, 45 (7), 629-52(1950).

Klein, H. A.: "Use of Coordinated Phosphate Treatment to Prevent Caustic Corrosion inHigh Pressure Boilers," Combustion, October 1962.

Landon, R. D., and Houx, J. R. Jr.: "Plume Abatement And Water Conservation with theWet-Dry Cooling Tower," Proc. American Power Conf., 35 (1973).

deLorenzi, O. (ed.): Combustion Engineering, Riverside, Cambridge, Mass., 1947.Skrotzky, B. G. A.: Basic Thermodynamics, Elements of Energy, McGraw-Hill, New York,

1963.Strauss, S. D., (ed.): "Control of Turbine-Steam Chemistry," Power, 125 (3) March 1981.U.S. Environmental Protection Agency: Development Document for Steam Electric Power

Generating, EPA-440/l-74-029a, October 1974.U.S. Environmental Protection Agency: Economic Report for Steam Electric, NTIS-PB-239315/AS.

Van Meter, J. A., Durkin, T. H., Legatski, L. K., and Petkus, R. O.: "Making FGD Workat Sigeco," Pollut. Eng., 29-33 (March 1981).