Steamturbine 140203094808-phpapp01

TM 5-811-6
CHAPTER 3
STEAM TURBINE POWER PLANT DESIGN
Section 1. TYPICAL PLANTS AND CYCLES
3-1. Introduction
a. 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 plant
size, cost of money, fuel costs, non-fuel operating
costs, 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 steam
generated at pressures and temperatures between
600 psig (at 750 to 850°F) and 1450 psig (at 850 to
950º F). Reheat is never offered for turbine genera-
tors of less than 50 MW and, hence, is not applicable
in this manual.
c. Steam turbine prime movers. The steam tur-
bine prime mover, for rated capacity limits of 5000
kW to 30,000 kW, will be a multi-stage, multi-valve
unit, either back pressure or condensing. Smaller
turbines, especially under 1000 kW rated capacity,
may be single stage units because of lower first cost
and simplicity. Single stage turbines, either back
pressure or condensing, are not equipped with ex-
traction openings.
d. Back pressure turbines. Back pressure turbine
units usually exhaust at pressures between 250 psig
and 15 psig with one or two controlled or uncon-
trolled extractions. However, there is a significant
price difference between controlled and uncontrolled
extraction turbines, the former being more expen-
sive. Controlled extraction is normally applied
where 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 purpose
a. Integration into general planning. General
plant design parameters will be in accordance with
overall criteria established in the feasibility study or
planning criteria on which the technical and econom-
ic feasibility is based. The sizes and characteristics
of the loads to be supplied by the power plant, in-
cluding peak loads, load factors, allowances for fu-
ture growth, the requirements for reliability, and
the criteria for fuel, energy, and general economy,
will be determined or verified by the designer and
approved by appropriate authority in advance of the
final design for the project.
b. Selection of cycle conditions. Choice of steam
conditions, types and sizes of steam generators and
turbine prime movers, and extraction pressures de-
pend on the function or purpose for which the plant
is intended. Generally, these basic criteria should
have already been established in the technical and
economic feasibility studies, but if all such criteria
have not been so established, the designer will select
the parameters to suit the intended use.
c. Coeneration plants. Back pressure and con-
trolled extraction/condensing cycles are attractive
and applicable to a cogeneration plant, which is de-
fined as a power plant simultaneously supplying
either electric power or mechanical energy and heat
energy (para. 3-4).
d. Simple condensing cycles. Straight condensing
cycles, or condensing units with uncontrolled ex-
tractions are applicable to plants or situations
where security or isolation from public utility power
supply is more important than lowest power cost.
Because of their higher heat rates and operating
costs per unit output, it is not likely that simple con-
densing cycles will be economically justified for a
military power plant application as compared with
that associated with public utility ‘purchased power
costs. A schematic diagram of a simple condensing
cycle is shown on Figure 3-1.
3-3. Steam power cycle economy
a. 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 efficient
cycles are more complex and may be less reliable per
unit of capacity or investment cost than simpler and
3-1

TM 5-611-6
NAVFAC DM3
Figure 3-1. Typical straight condensing cycle.
less efficient cycles. Efficiency characteristics can
be listed as follows:
(1) Higher steam pressures and temperatures
contribute to better, or lower, heat rates.
(2) For condensing cycles, lower back pressures
increase efficiency except that for each particular
turbine unit there is a crossover point where lower-
ing back pressure further will commence to decrease
efficiency because the incremental exhaust loss ef-
fect is greater than the incremental increase in avail-
able energy.
(3) The use of stage or regenerative feedwater
cycles 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 the
extraction piping to the feedwater heaters, reducing
the feedwater temperature. There is also a limit to
the 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 generally
more efficient that smaller units.
(5) Multi-stage and multi-valve turbines are
more economical than single stage or single valve
machines.
(6) Steam generators of more elaborate design,
or with heat saving accessory equipment are more
efficient.
b. Heat rate units and definitions. The economy
or efficiency of a steam power plant cycle is ex-
3-2
pressed in terms of heat rate, which is total thermal
input to the cycle divided by the electrical output of
the units. Units are Btu/kWh.
(1) Conversion to cycle efficiency, as the ratio of
output to input energy, may be made by dividing
the heat content of one kWh, equivalent to 3412.14
Btu 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 or
stations is sometimes expressed in terms of pounds
of steam per kilowatt hour, but such a parameter is
not readily comparable to other plants or cycles and
omits steam generator efficiency.
(3) For mechanical drive turbines, heat rates
are sometimes expressed in Btu per hp-hour, exclud-
ing losses for the driven machine. One horsepower
hour is equivalent to 2544.43 Btu.
c. Heat rate applications. In relation to steam
power plant cycles, several types or definitions of
heat 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 by
the steam generator, minus the “heat in the feedwa-
ter” as warmed by turbine extraction, divided by
the electrical output at the generator terminals.
This definition includes mechanical and electrical
losses of the generator and turbine auxiliary sys-
tems, but excludes boiler inefficiencies and pumping
losses and loads. The turbine heat rate is useful for

TM 5-811-6
performing engineering and economic comparisons
of 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 on
Figure 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 multiplying
the actual steam rate by the enthalpy change across
the 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 enthalpy
h1 = extraction or exhaust enthalpy
TSR
’
FROM STANDARD HANDBOOK FOR MECHANICAL
ENGINEERS BY MARKS. COPYRIGHT © 1967,
. MCGRAW-HILL BOOK CO. USED WITH THE
PERMISSION OF MCGRAW- HILL BOOK COMPANY.
Figure 3-2. Turbine efficiencies vs. capacity.
m
(2) Plant heat rates include inefficiencies and
losses external to the turbine generator, principally
the inefficiencies of the steam generator and piping
systems; cycle auxiliary losses inherent in power re-
quired for pumps and fans; and related energy uses
such 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 are
seldom achieved in practice except under controlled
or test conditions.
(4) Plant operating heat rates are long term
average actual heat rates and include other such
losses and energy uses as non-cycle auxiliaries,
plant lighting, air conditioning and heating, general
water supply, startup and shutdown losses, fuel de-
terioration losses, and related items. The gradual
and inevitable deterioration of equipment, and fail-
ure to operate at optimum conditions, are reflected
in plant operating heat rate data.
d. Plant economy calculations. Calculations, esti-
mates, and predictions of steam plant performance
will allow for all normal and expected losses and
loads and should, therefore, reflect predictions of
monthly or annual net operating heat rates and
costs. Electric and district heating distribution
losses are not usually charged to the power plant
but should be recognized and allowed for in capacity
and 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 flow
rates, fluid pressures and temperatures, fluid en-
thalpies, electric power output, and calculated cycle
heat rates based on these factors. A heat balance is
usually developed for various increments of plant
load (i.e., 25%, 50%, 75%, 100% and VWO (valves
wide open)). Computer programs have been devel-
oped which can quickly optimize a particular cycle
heat 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. Various
methods 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 level
energy (heating steam) should be recognized. Refer
to discussion of cogeneration cycles below.
3-4. Cogeneration cycles
a. Definition. In steam power plant practice, co-
generation normally describes an arrangement
whereby high pressure steam is passed through a
turbine 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, or
process 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, and
the gain in electrical power output by selection of a
lower turbine exhaust or extraction pressure.
(2) Often the early selection of a relatively low
3-3

steam distribution pressure is easily accommodated
in the design of distribution and utilization systems,
whereas the hasty selection of a relatively high
steam distribution pressure may not be recognized
as a distinct economic penalty on the steam power
plant cycle.
(3) Hot water heat distribution may also be ap-
plicable as a district heating medium with the hot
water being cooled in the utilization equipment and
returned to the power plant for reheating in a heat
exchange with exhaust (or extraction) steam.
c. Relative economy. When the exhaust (or ex-
traction) steam from a cogeneration plant can be
utilized for heating, refrigeration, or process pur-
poses in reasonable phase with the required electric
power 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 of
the total fuel energy can be utilized as compared
with about 40 percent for the best and largest Ran-
kine cycle plants and about 25 to 30 percent for
small Rankine cycle systems.
d. Cycle types. The two major steam power cogen-
eration cycles, which may be combined in the same
plant 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 the
more effective for heat economy and for relatively
lower cost of turbine equipment, because the prime
mover is smaller and simpler and requires no con-
denser and circulating water system. Back pressure
turbine generators are limited in electrical output by
the amount of exhaust steam required by the heat
load and are often governed by the exhaust steam
load. They, therefore, usually operate in electrical
parallel with other generators.
(2) Extraction-condensing cycles. Where the
electrical demand does not correspond to the heat
demand, or where the electrical load must be carried
at times of very low (or zero) heat demand, then con-
densing-controlled extraction steam turbine prime
movers 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 cycle
or a combination of extraction and condensing.
While very flexible, the extraction machine is rela-
tively complicated, requires complete condensing
and heat rejection equipment, and must always pass
a critical minimum flow of steam to its condenser to
cool the low pressure buckets.
.
.
NAVFAC DM3 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 the
following criteria:
(1) Load balance. There should be a reasonably
balanced relationship between the peak and normal
requirements for electric power and heat. The
peak/normal ratio should not exceed 2:1.
(2) Load coincidence. There should be a fairly
high coincidence, not less than 70%, of time and
quantity demands for electrical power and heat.
(3) Size. While there is no absolute minimum
size of steam power plant which can be built for co-
generation, a conventional steam (cogeneration)
plant will be practical and economical only above
some minimum size or capacity, below which other
types of cogeneration, diesel or gas turbine become
more economical and convenient.
(4) Distribution medium. Any cogeneration
plant will be more effective and economical if the
heat distribution medium is chosen at the lowest
possible steam pressure or lowest possible hot water
temperature. The power energy delivered by the tur-
bine is highest when the exhaust steam pressure is
lowest. Substantial cycle improvement can be made
by selecting an exhaust steam pressure of 40 psig
rather than 125 psig, for example. Hot water heat
distribution will also be considered where practical
or convenient, because hot water temperatures of
200 to 240º F can be delivered with exhaust steam
pressure as low as 20 to 50 psig. The balance be-
tween distribution system and heat exchanger
costs, and power cycle effectiveness will be opti-
mized.
3-5. Selection of cycle steam conditions
a. Balanced costs and economy. For a new or iso-
lated plant, the choice of initial steam conditions
should be a balance between enhanced operating
economy at higher pressures and temperatures, and
generally lower first costs and less difficult opera-
tion at lower pressures and temperatures. Realistic
projections of future fuel costs may tend to justify
higher pressures and temperatures, but such factors
as lower availability y, higher maintenance costs,
more difficult operation, and more elaborate water
treatment will also be considered.
b. Extension of existing plant. Where a new
steam power plant is to be installed near an existing
steam power or steam generation plant, careful con-
sideration will be given to extending or paralleling
the existing initial steam generating conditions. If
existing steam generators are simply not usable in
the new plant cycle, it may be appropriate to retire
them or to retain them for emergency or standby
service 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 are
significant factors in power cycle selection, the fol-
lowing considerations may apply:
(1) Electrical isolation. Where the proposed
plant is not to be interconnected with any local elec-
tric utility service, the selection of a simpler, lower
pressure plant may be indicated for easier operation
and better reliability y.
(2) Geographic isolation. Plants to be installed
at 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 installed
under 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 cold
weather conditions. For arctic weather conditions,
circulating hot water for the heat distribution medi-
um has many advantages over steam, and the use of
an antifreeze solution in lieu of pure water as a dis-
tribution medium should receive consideration.
3-6. Cycle equipment
a. 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 turbine
driven electric generators and steam generators.
c. Secondary cycle elements. Other equipment
items affecting cycle performance, but subordinate
to the steam generators and turbine generators, are
also described in other parts of this chapter.
3-7. Steam power plant arrangement
a. General. Small units utilize the transverse ar-
rangement in the turbine generator bay while the
larger 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 show
typical transverse small plant arrangements. Small
units less than 5000 kW may have the condensers at
the same level as the turbine generator for economy
as shown in Figure 3-4. Figure 3-6 indicates the
critical turbine room bay dimensions and the basic
overall dimensions for the small power plants shown
in 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
Section Il. STEAM GENERATORS AND AUXILIARY SYSTEMS.
tors for a steam power plant can be classified by
type of fuel, by unit size, and by final steam condi-
tion. Units can also be classified by type of draft, by
method 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 the
steam generator. Fuel selection may be dictated by
considerations of policy and external circumstances
3-8. Steam generator conventional
types 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 chap
ter under discussion of typical plants and cycles.
b. Types and classes. Conventional steam genera-
.!
.
AND CONDENSER SUPPLIERS SELECTED.
36
43
31
16
6
11.3
7 . 5
3 . 7
1.2
5 . 5
5
17.5
5
8
11
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 solid
waste) or designed for combinations of solid, liquid,
and gaseous fuel are larger and more complex than
units designed for fuel oil or fuel gas only.
(2) Fuel coal. The qualities or characteristics of
particular coal fuels having significant impact on
steam generator design and arrangement are: heat-
ing value, ash content, ash fusion temperature, fri-
ability, grindability, moisture, and volatile content
as 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 a
major consideration, and moisture content before
and after local preparation must be considered. Coal
burning equipment and related parts of the steam
generator will be specified to match the specific
characteristics of a preselected coal fuel as well as
they can be determined at the time of design.
(3) Unit sizes. Larger numbers of smaller steam
generators will tend to improve plant reliability and
flexibility 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 spreading
over fuel bed.
Allowable temp. of metal contacting
flue gas; removal from flue gas.
Oil
Heat balance.
Fuel cost.
Preheating, pumping, firing.
Pumping and metering.
Vapor locking of pump suction.
Allowable temp. of metal contacting
flue gas; removal from flue gas.
Gas
Heat balance.
Pressure, firing, fuel cost.
Metering.
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 on
smaller units. Larger units are inherently more effi-
cient, and will normally have more efficient draft
fans, better steam temperature control, and better
control of steam solids.
(4) Final steam conditions. Desired pressure
and temperature of the superheater outlet steam
(and to a lesser extent feedwater temperature) will
have a marked effect on the design and cost of a
steam generator. The higher the pressure the heav-
ier the pressure parts, and the higher the steam tem-
perature the greater the superheater surface area
and the more costly the tube material. In addition to
this, however, boiler natural circulation problems in-
crease with higher pressures because the densities
of the saturated water and steam approach each oth-
er. In consequence, higher pressure boilers require
more height and generally are of different design
than boilers of 200 psig and less as used for general
space 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 induced
draft fans. This type of draft system uses one or
more forced draft fans to supply combustion air un-
der pressure to the burners (or under the grate) and
one or more induced draft fans to carry the hot com-
bustion gases from the furnace to the atmosphere; a
slightly 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 chimney
or stack resistance while the remainder of the draft
friction from the furnace to the chimney entrance is
handled by the induced draft fans.
(b) Choice of draft. Except for special cases
such as for an overseas power plant in low cost fuel
areas, balanced draft, steam generators will be spec-
ified for steam electric generating stations.
(6) Method of assembly. A major division of
steam generators is made between packaged or fac-
tory assembled units and larger field erected units.
Factory assembled units are usually designed for
convenient shipment by railroad or motor truck,
complete with pressure parts, supporting structure,
and enclosure in one or a few assemblies. These
units are characteristically bottom supported, while
the larger and more complex power steam gener-
ators are field erected, usually top supported.
(7) Degree of weather protection. For all types
and sizes of steam generators, a choice must be
made 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. for
7 continuous days, outdoor units will require electri-
cally or steam traced piping and appurtenances to
prevent freezing. The firing aisle will be enclosed
either as part of the main power plant building or as
a separate weather protected enclosure; and the
ends of the steam drum and retractable soot blowers
will be enclosed and heated for operator convenience
and maintenance.
(8) Load factor application. As with all parts of
the plant cycle, the load factor on which the steam
generator is to be operated affects design and cost
factors. Units with load factors exceeding 50% will
be selected and designed for relatively higher effi-
ciencies, and more conservative parameters for fur-
nace volume, heat transfer surface, and numbers
and types of auxiliaries. Plants with load factors
less 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 plant
boilers will be of the water welled or water cooled
furnace types, in which the entire interior surface of
the furnace is lined with steam generating heating
surface in the form of closely spaced tubes usually
all welded together in a gas tight enclosure.
b. Superheated steam. Depending on manufac-
turer’s design some power boilers are designed to
deliver superheated steam because of the require-
ments of the steam power cycle. A certain portion of
the total boiler heating surface is arranged to add
superheat energy to the steam flow. In superheater
design, a balance of radiant and convective super-
heat surfaces will provide a reasonable superheat
characteristic. With high ‘pressure - high temper-
ature turbine generators, it is usually desirable to
provide 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 surface
and then attemperating by means of spray water at
the 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 requires
adequate and reasonable amounts of heating surface
3-11

TM 5-811-6
and furnace volume for acceptable performance and
longevity.
(1) Evaporative heating surface. For its rated
capacity output, an adequate total of evaporative or
steam 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 heat
transfer, 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 heat
sources. Superheaters may be of the drainable or
non-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 considered
for fully drainable superheaters. With some boiler
designs this may not be possible.
(3) Furnace volume. For a given steam gener-
ator capacity rating, a larger furnace provides lower
furnace temperatures, less probability of hot spots,
and a lower heat flux through the larger furnace wall
surface. Flame impingement and slagging, partic-
ularly with pulverized coal fuel, can be controlled or
prevented with increased furnace size.
(4) General criteria. Steam generator design
will specify conservative lower limits of total heat-
ing surface, furnace wall surface and furnace vol-
ume, as well as the limits of superheat temperature
control range. Furnace volume and surfaces will be
sized 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 heat
release per square foot of effective radiant heating
surface and, in the case of spreader stokers, for Btu
per square foot of grate. Such parameters are not set
forth in this manual, however, because of the wide
range of fuels which can affect these equipment de-
sign considerations. The establishment of arbitrary
limitations which may handicap the geometry of
furnace designs is inappropriate. Prior to setting
furnace geometry parameters, and after the type
and grade of fuel are established and the particular
service conditions are determined, the power plant
designer will consult boiler manufacturers to insure
that steam generator specifications are capable of
being met.
d. Single unit versus steam header system. For
cogeneration plants, especially in isolated locations
or for units of 10,000 kW and less, a parallel boiler or
steam header system may be more reliable and more
economical than unit operation. Where a group of
steam turbine prime movers of different types; i.e.,
one back pressure unit plus one condensing/extrac-
tion unit are installed together, overall economy can
be enhanced by a header (or parallel) boiler arrange-
ment.
3-10. Steam generator special types
a. Circulation. Water tube boilers will be specified
to be of natural circulation. The exception to this
rule 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 stack
emission of sulfur oxides by absorption of sulfur in
the fuel bed as well as nitrogen oxides because of its
relatively low fire box temperature. The fluidized
bed boiler is a viable alternative to a spreader stoker
unit. A fluidized bed steam generator consists of a
fluidized bed combustor with a more or less conven-
tional steam generator which includes radiant and
convection boiler heat transfer surfaces plus heat re-
covery equipment, draft fans, and the usual array of
steam 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 through
oil burners, which deliver finely divided or atomized
liquid 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, air
atomizing and steam atomizing type. Pressure
atomization is usually more economical but is also
more complex and presents problems of control,
poor turndown, operation and maintenance. The
range of fuel flows obtainable is more limited with
pressure atomization. Steam atomization is simple
to operate, reliable, and has a wide range, but con-
sumes a portion of the boiler steam output and adds
moisture to the furnace gases. Generally, steam
atomization will be used when makeup water is rela-
tively inexpensive, and for smaller, lower pressure
plants. 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 mixing
with 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 air
guide registers designed to control and shape the air
flow 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 burners
required is a function both of load requirements and
boiler manufacturer design. For the former, the indi-
vidual burner turndown ratios per burner are pro-
vided in Table 3-3. Turndown ratios in excess of
those listed can be achieved through the use of mul-
tiple burners. Manufacturer design limits capacity
of each burner to that compatible with furnace flame
and gas flow patterns, exposure and damage to
STEAM OUTLET TO
SUPERHEATER IN BED
TM 5-811-6
heating surfaces, and convenience of operation and
control.
(5) Burner managerment systems. Plant safety
practices require power plant fuel burners to be
equipped with comprehensive burner control and
safety systems to prevent unsafe or dangerous con-
ditions which may lead to furnace explosions. The
primary purpose of a burner management system is
safety which is provided by interlocks, furnace
purge cycles and fail safe devices.
b. Pulverizes. The pulverizers (mills) are an essen-
tial part of powdered coal burning equipment, and
are usually located adjacent to the steam generator
and burners, but in a position to receive coal by
gravity 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 for
rapid and efficient burning. Reliable and safe pulver-
izing equipment is essential for steam generator op-
eration. Pulverized coal burning will not be specified
for boilers smaller than 150,000 lb/hour.
c. Stokers and grates. For small and medium
sized coal burning steam generators, less than
150,000 lb/hour, coal stokers or fluidized bed units
will be used. For power boilers, spreader stokers
with traveling grates are used. Other types of
stokers (retort, underfeed, or overfeed types) are
generally 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 into
the furnace where part of the fuel burns in suspen-
sion and the balance falls to the traveling grate for
burnout. Stoker fired units will have two or more
spreader feeder units, each delivering fuel to its own
separate grate area. Stoker fired units are less re-
sponsive to load changes because a large proportion
of 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 feeders
are to be used.
(2) Grate operation requires close and skillful
operator attention, and overall plant performance is
sensitive to fuel sizing and operator experience.
Grates for stoker fired units occupy a large part of
the furnace floor and must be integrated with ash re-
moval and handling systems. A high proportion of
stoker ash must be removed from the grates in a
wide range of particle sizes and characteristics al-
though some unburned carbon and fly ash is carried
out of the furnace by the flue gas. In contrast, a
larger 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 sometimes
put through a clinker grinder prior to removal in the
vacuum ash handling system described elsewhere in
this 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
3-14

I
I
.
.
moval will be provided by power driven draft fans
designed for adequate volumes and pressures of air
and gas flow. Typical theoretical air requirements
are shown in Figure 3-8 to which must be added ex-
cess air which varies with type of firing, plus fan
margins on both volumetric and pressure capacity
for reliable full load operation. Oxygen and carbon
dioxide in products of combustion for various
amounts of excess air are also shown in Figure 3-8.
(b) Calculations of air and gas quantities and
pressure drops are necessary. Since fans are heavy
power consumers, for larger fans consideration
should be given to the use of back pressure steam
turbine drives for economy, reliability and their abil-
it y to provide speed variation. Multiple fans on each
boiler unit will add to first costs but will provide
more flexibility and reliability . Type of fan drives
and number of fans will be considered for cost effec-
tiveness. Fan speed will be conservatively selected,
and silencers will be provided in those cases where
noise by fans exceeds 80 decibels.
(c) Power plant steam generator units de-
signed for coal or oil will use balanced draft design
with both forced and induced draft fans arranged for
closely controlled negative furnace pressure.
(2) Ducts and flues. Air ducts and gas flues will
be 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. Adequate
space and weight capacity will be allowed in overall
plant arrangement to avoid awkward, noisy or mar-
ginal fan, duct and flue systems. Final steam gener-
ator design will insure that fan capacities (especially
pressure) are matched properly to realistic air and
gas path losses considering operation with dirty
boilers and under abnormal operating conditions.
Damper durability and control characteristics will
be carefully designed; dampers used for control pur-
poses will be of opposed blade construction.
e. Heat recovery. Overall design criteria require
highest 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 of
heat recovery equipment remove relatively low level
heat from the flue gases prior to flue gas discharge
to the atmosphere, using boiler fluid media (air or
water) which can effectively absorb such low level
energy. Such equipment adds to the cost, complex-
ity and operational skills required, which will be bal-
anced by the plant designer against the life cycle
fuel savings.
(2) Air preheater. Simple tubular surface
heaters 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, especially
with dirty and high sulphur fuels, special alloy steel
will be used in the low temperature heat transfer
surface (replaceable tubes or “baskets”) of air pre-
heater. Steam coil air heaters will be installed to
maintain certain minimum inlet air (and metal) tem-
peratures and thus protect the main preheater from
corrosion 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 air
heater or a balanced selection of both as is usual in a
power 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 treated
during design.
(3) Stacks and chimneys will be sized with due
regard to natural draft and stack friction with
290
NAVFAC DM3
Figure 3-9. Minimum metal temperatures for boiler heat
recovery 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 for
calculating draft and friction. Utilize draft of the
stack or chimney only to overcome friction within
the chimney with the induced draft fan(s) supplying
stack or chimney entrance. Maintain relatively high
gas exit velocities (50 to 60 feet per second) to eject
gases as high above ground level as possible. Reheat
(usually by steam) will be provided if the gases are
treated (and cooled) in a flue gas desulfurization
scrubber prior to entering the stack to add buoy-
ancy and prevent their settling to the ground after
ejection to the atmosphere. Insure that downwash
due to wind and building effects does not drive the
flue gas to the ground.
g. Flue gas cleanup. The requirements for flue gas
cleanup will be determined during design.
(1) Design considerations. The extent and na-
ture of the air pollution problem will be analyzed
prior to specifying the environmental control sys-
tem for the steam generator. The system will meet
all applicable requirements, and the application will
be the most economically feasible method of accom-
plishment. All alternative solutions to the problem
will be considered which will satisfy the given load
and which will produce the least objectionable
wastes. 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 will
be directed to the design agency having jurisdiction
over the project. Table 3-4 shows the emission lev-
els allowable under the National Ambient Air
Quality Standards.
(2) Particulate control. Removal of flue gas par-
ticulate material is broadly divided into mechanical
dust collectors, electrostatic precipitators, bag fil-
ters, and gas scrubbing systems. For power plants
of the size range here considered estimated uncon-
trolled emission levels of various pollutants are
shown 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 in
Table 3-6, 3-7, 3-8, 3-9, 3-10 and 3-11. These only
provide general guidance. The designer will refer to
TM 5-815-l/AFR 19-6/NAVFAC DM-3.15 for de-
tails of this equipment and related computational
requirements and design criteria.
(a) Mechanical collectors. For oil fired steam
generators with output steaming capacities less
than 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, a
mechanical collector in series with an electrostatic
precipitator or baghouse also might be considered.
Performance requirements and technical environ-
mental standards must be carefully matched, and
ultimate performance warranties and tests require
careful and explicit definitions. Collected dust from
a mechanical collector containing a large proportion
of combustibles may be reinfected into the furnace
for final burnout; this will increase steam generator
TM 5-811-6
efficiency slightly but also will increase collector
dust loading and carryover. Ultimate collected
dust material must be handled and disposed of sys-
tematically to avoid objectionable environmental ef-
fects.
(b) Electrostatic precipitators. For pulverized
coal firing, adequate particulate control will require
electrostatic precipitators (ESP). ESP systems are
well developed and effective, but add substantial
capital and maintenance costs. Very high percent-
3-17

Pollutant
Particulate
Sulfur Oxides
Nitrogen Oxides
COAL FIRED
(Lb of Pollutant/Ton
Table3-5. Uncontrolled Emissions.
OIL FIRED
of 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 by
the value given. Example: If the factor is 16 and the ash content is 10 percent, the particulate
emissions before the control equipment would be 10 times 16, or 160 pounds of particulate per ton
of 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
utility boiler
Particulate control.

Table 3-2! Characteristics of Scrubbers for Particulate Control.
Particle
Collection Water Usage
Efficiency Per 1000 Gal/Min
80 3-5
Internal
Velocity
Ft/Sec
Pressure Drop
In. H O
3-8
Gas Flow
Ft /MinScrubber Type Energy Type
Low EnergyCentrifugal
Scrubber
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 70-145
10,000

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 y
Temperature at 300º F
°F ohm-cm
600+ Greater Than
1 01 2
300 Less Than
1 01 0
3 0 0 - Greater Than
1 012
b e l o w
1 04
P r e s s u r e
Gas Drop
Flow I n . o f
F t / M i n Water
100,000+ Less Than
1"

Table 3-9. Characteristics of Baghouses for Particulate Control.
Pressure Loss Filter Ratio
(Inches of (cfm/ft
System Type Water) Efficiency Cloth Type Cloth Area) Recommended Application
Shaker 3-6 99+% Woven 1-5 Dust with good filter
cleaning properties,
intermittent collection.
Reverse Flow 3-6 99+% Woven 1-5 Dust with good filter cleaning
properties, high temperature
collection (incinerator fly-
ash) with glass bags.
Pulse Jet
Reverse Jet
Envelope
3-6
3-8
3-6
99+% Felted
99+% Felted
99+% Woven
4-20
10-30
1-5
Efficient for coal and oil fly
ash collection.
Collection of fine dusts and
fumes.
Collection of highly abrasive
dust .

Table 3-10. Characteristics of Flue-Gas Desulfurization Systems for Particulate Control.
Retrofit to
Existing
Installations
Yea
Pressure Drop
(Inches of Water)
SO Removal Recovery and
Regeneration
No Recovery
of Limestone
No Recovery
of Lime
No Recovery
of Lime
Recovery of MgO
and Sulfuric Acid
Recovery of NaS03
Operational
ReliabilityEfficiency (%)
30-40%
System Type
High
High
Low
Low
Unknown
Unknown
Unknown
Unknown
1) Limestone Boiler
Injection Type
Less Than 6“
Greater Than 6“
Greater Than 6“
Greater Than 6“
Greater Than 6“
Yea2) Limestone, Srubber
Injection Type
30-40%
Yea3) Lime, Scrubber,
Injection Type
90%+
Yea4) Magnesium Oxide
90%+5) Wellman-Lord
and Elemental Sulfur
6) Catalytic
oxidation
Recovery of 80%
H2S04
No85% May be as high as 24”
Tray Tower Pressure
Drop 1.6-2.0 in.
H2O/tray, w/Venturi
add 10-14 in. H2O
Little Recovery
of Sodium Carbonate
Yea7) Single Alkali
Systems
90%+
Yea8) Dual Alkali 90-95%+ Regeneration of
Sodium Hydroxide
and Sodium Sulfites
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 Air
Preheat
NO Reduction (%)
Flue Gas Recirculation
15 to 40
30
40
50
45
10-50
20-50
Advantages Disadvantages
Easily implemented; no additional Reduction in generating capacity;
equipment required; reduced particu- possible reduction in boiler thermal
late and SOX emissions. thermal efficiency.
Increased boiler thermal efficiency; A combustion control system which
possible 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 high
temperature corrosion and ash deposition.
--- Boiler windboxes must be designed for
this application.
- --
---
---
Possible improvement in combustion
efficiency end reduction in particu-
late emissions.
Furnace corrosion and particulate
emissions may increase.
Control of alternate fuel rich/and
fuel lean burners may be a problem
during transient load conditions.
Not applicable to coal or oil fired
units; reduction in boiler thermal
efficiency; increase in exit gas
volume and temperature; reduction in
boiler load.
Boiler windbox must be modified to
handle 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 ash
composition, fuel additives, flue gas temperatures
and moisture content, and even weather conditions.
ESP’s are frequently used with and ahead of flue
gas washing and desulfurization systems. They may
be either hot precipitators ahead of the air preheater
in 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 and
temperature influence on materials. But they are
sometimes necessary for low sulfur fuels where cold
precipitators are relatively inefficient.
(c) Bag filters. Effective particulate removal
may be obtained with bag filter systems or bag
houses, which mechanically filter the gas by passage
through 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 economic
choice for most medium and small size coal fired
steam generators.
(d) Flue gas desulfurization. While various
gaseous pollutants are subject to environmental
control and limitation, the pollutants which must be
removed 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 and
SO3stack emission have been installed and oper-
ated, with wide variations in effectiveness, reliabil-
ity, longevity and cost. For small or medium sized
power plants, FGD systems should be avoided if
possible 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, capital
cost, operating costs, space, and environmental im-
pact will be made. Alternatively, a fluidized bed
boiler (para. 3-10 c) may be a better economic choice
for 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 gas
stream. A mixed slurry of the sorbent material is
sprayed into the flue gas duct where it mixes with
and wets the particulate in the gas stream. The S02
and S09 reacts with the calcium hydroxide of the
slurry to form calcium sulfate. The gas then contin-
ues to a separator tower where the solids and excess
solution settle and separate from the water vapor
saturated gas stream which vents to the atmosphere
through the boiler stack. Wet scrubbers permit the
use of coal with a sulfur content as high as 5 percent.
(2) Dry scrubbers generally utilize a diluted
solution of slaked lime slurry which is atomized by
compressed air and injected into the boiler flue gas
stream. SO2 and SO3 in the flue gas is absorbed by
the 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 gas
then travels to a bag filter system and then to the
boiler stack. The bag filter system collects the boiler
exit solid particles and the dried reaction products.
Additional remaining SO2 and SO3 are removed by
the flue gas filtering through the accumulation on
the surface of the bag filters, Dry scrubbers permit
the use of coal with a sulfur content as high as 3 per-
cent.
(3) Induced draft fan requirements. Induced
draft fans will be designed with sufficient capacity
to produce the required flow while overcoming the
static pressure losses associated with the ductwork,
economizer, air preheater, and air pollution control
equipment under all operating (clean and dirt y) con-
ditions.
(4) Waste removal. Flue gas cleanup systems
usually produce substantial quantities of waste
products, often much greater in mass than the sub-
stances actually removed from the exit gases. De-
sign and arrangement must allow for dewatering
and stabilization of FGD sludge, removal, storage
and disposal of waste products with due regard for
environmental impacts.
3-12. Minor auxiliary systems
Various minor auxiliary systems and components
are vital parts of the steam generator.
a. Piping and valves. Various piping systems are
defined as parts of the complete boiler (refer to the
ASME Boiler Code), and must be designed for safe
and effective service; this includes steam and feed-
water piping, fuel piping, blowdown piping, safety
and control valve piping, isolation valves, drips,
drains and instrument connections.
b. Controls and instruments. Superheater and
‘burner management controls are best purchased
along with the steam generator so that there will be
integrated steam temperature and burner systems.
c. Soot blowers. Continuous or frequent on line
cleaning 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 blowing
is an economic choice and will be evaluated in terms
of steam and makeup water vs. compressed air costs
with due allowance for capital and operating cost
components.
3-25
k

TM 5-811-6
Section Ill. FUEL HANDLING AND STORAGE SYSTEMS
3-13. Introduction
a. Purpose. Figure 3-10 is a block diagram illus-
trating the various steps and equipment required
for a solid fuel storage and handling system.
b. Fuels for consideration. Equipment required
for a system depends on the type of fuel or fuels
burned. The three major types of fuels utilized for
steam raising are gaseous, liquid and solid.
3-14. Typical fuel oil storage and han-
dling system
The usual power plant fuel oil storage and handling
system 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 will
be analyzed and unloading pump(s) optimized for
the circumstances and oil quantities involved.
Heavier fuel oils are loaded into transport tanks hot
and cool during delivery. Steam supply for tank car
heaters will be provided at the plant if it is expected
that 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 so
as to provide more versatility for tank cleanout in-
spection and repair. A minimum of 30 days storage
capacity at maximum expected power plant load
(maximum steaming capacity of all boilers with
maximum expected turbine generator output and
maximum 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 may
result in additional storage requirements. Space for
future 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 heated
with a suction type heater, a continuous coil extend-
ing over the bottom of the tank, or a combination of
both types of surfaces. Steam is usually the most
economical heating medium although hot water can
be considered depending on the temperatures at
which 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 be
selected with at least 10 percent excess capacity
over maximum burning rate in the boilers. Sizing
will consider additional pumps for future boilers and
pressure requirements will be selected for pipe fric-
tion, control valves, heater pressure drops, and
burners. A reasonable selection would be one pump
per boiler with a common spare if the system is de-
signed for a common supply to all boilers. For high
pressure mechanical atomizing burners, each boiler
may also have its own metering pump with spare.
(2) Pumps may be either centrifugal or positive
displacement. Positive displacement pumps will be
specified for the heavier fuel oils. Centrifugal pumps
will be specified for crude oils. Where absolute relia-
ability is required, a spare pump driven by a steam
turbine with gear reducer will be used. For “black
starts, ” or where a steam turbine may be inconven-
ient, a dc motor driver may be selected for use for
relatively short periods.
(3) At least two fuel oil heaters will be used for
reliability and to facilitate maintenance. Typical
heater design for Bunker C! fuel oil will provide for
temperature increases from 100 to 230° F using
steam 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 bulk
storage tank. The burner pumps also will circulate
back to the storage tank. A recirculation connection
will be provided at each burner for startup. It will be
manually valved and shut off after burner is suc-
cessfully lit off and operating smoothly.
(2) Piping systems will be adapted to the type
of burner utilized. Steam atomizing burners will
have “blowback” connections to cleanse burners of
fuel with steam on shutdown. Mechanical atomizing
burner 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 systems
a. 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 a
track or truck (or combined track/truck) hopper,
bucket elevator with feeder, coal silo, spouts and
chutes, and a dust collecting system will be used.
Elevator will be arranged to discharge via closed
chute into one or two silos, or spouted to a ground
pile 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 sized
and washed. This will be similar to the system de-
scribed in (1) above but will use an enclosed skip
hoist instead of a bucket elevator for conveying coal
to top of silo.
(3) Intermediate system alternatives. For more
than two boilers, an overbunker flight or belt con-
veyor will be used. If mine run, uncrushed coal
proves 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 dead
storage reclaim hoppers, inclined belt conveyors
with appropriate feeders, transfer towers, vibrating
screens, magnetic separators, crusher(s), overbunk-
er conveyor(s) with automatic tripper, weighing
equipment, sampling equipment, silos, dust collect-
ing system(s), fire protection, and like items. Where
two or more types of coal are burned (e.g., high and
low sulphur), blending facilities will be required.
(5) For cold climates. All systems, regardless of
size, which receive coal by railroad will require car
thawing facilities and car shakeouts for loosening
frozen coal. These facilities will not be provided for
truck unloading because truck runs are usually
short.
b. Selection of handling capacity. Coal handling
system capacity will be selected so that ultimate
planned 24-hour coal consumption of the plant at
maximum expected power plant load can be unload-
ed or reclaimed in not more than 7-1/2 hours, or within
the time span of one shift after allowance of a 1/2-hour
margin for preparation and cleanup time. The hand-
ling capacity should be calculated using the worst
(lowest heating value) coal which may be burned in
the future and a maximum steam capacity boiler ef-
ficiency at least 3 percent less than guaranteed by
boiler manufacturer.
3-27

TM 5-811-6
c. Outdoor storage pile. The size of the outdoor
storage pile will be based on not less than 90 days of
the ultimate planned 24-hour coal consumption of
the plant at maximum expected power plant load.
Some power plants, particularly existing plants
which are being rehabilitated or expanded, will have
outdoor space limitations or are situated so that it is
environmentally inadvisable to have a substantial
outdoor 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 reserve
storage space below. Usually arranged with one silo
per boiler and the silo located on the outside of the
firing aisle opposite the boiler, the live storage shelf
will be placed high enough so that the spout to the
stoker hopper or coal scale above the hopper
emerges at a point high enough for the spout angle
to be not less than 60 degrees from the horizontal.
The reserve storage below the live storage shelf will
be arranged to recirculate back to the loading point
of the elevator so that coal can be raised to the top of
the 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 generating
facility.
(2) For large sized spreader stoker fired plants,
silo type overhead construction will be specified. It
will be fabricated of structural steel or reinforced
concrete with stainless steel lined conical bottoms.
(3) For small or medium sized plants combined
live and reserve storage in the silo will be not less
than 3 days at 60 percent of maximum expected
load of the boiler(s) being supplied from the silo so
that reserves from the outside storage pile need not
be drawn upon during weekends when operating
staff is reduced. For large sized plants this storage
requirement 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 although
not as rugged as the chain and bucket type. Typical
bucket elevator system is shown in Figure 3-11.
(2) Skip hoists. Because of the requirement for
dust suppression and equipment closure dictated by

environmental considerations, skip hoists will not
be 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 bearings
for pulleys and idlers, with heavy duty belts, and
with rugged helical or herringbone gear drive units.
(4) Feeders. Feeders are required to transfer
coal at a uniform rate from each unloading and inter-
mediate hopper to the conveyor. Such feeders will be
of the reciprocating plate or vibrating pan type with
single or variable speed drive. Reciprocating type
feeders 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 tramp
iron from mine run coal.
(b) Weigh scale at each boiler and, for larger
installations, for weighing in coal as received. Scales
will be of the belt type with temperature compensat-
ed load cell. For very small installations, a low cost
displacement 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-passing
fines 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 dust
tightness and with wearing surfaces lined with
stainless 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 and
provided 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 concentration
areas located outside which cannot be enclosed, such
as unloading and reclaim hoppers, will be provided
with spray type dust suppression equipment.
(i) Fire protection system of the sprinkler
type.
(j) Freeze protection for any water piping lo-
cated outdoors or in unheated closures as provided
for dust suppression or fire protection systems.
(k) A vacuum cleaning system for mainte-
nance of coal handling systems having galleries and
equipment enclosures.
(l) System of controls for sequencing and
monitoring entire coal handling system.
Section IV. ASH HANDLING SYSTEMS
3-16. Introduction
a. Background.
(1) Most gaseous fuels burn cleanly, and the
amount of incombustible material is so small that it
can be safely ignored. When liquid or solid fuel is
fired in a boiler, however, the incombustible materi-
al, or ash, together with a small amount of unburned
carbon chiefly in the form of soot or cinders, collects
in the bottom of the furnace or is carried out in a
lightweight, finely divided form usually known
loosely as “fly ash.” Collection of the bottom ash
from combustion of coal has never been a problem as
the ash is heavy and easily directed into hoppers
which may be dry or filled with water,
(2) Current ash collection technology is capable
of removing up to 99 percent or more of all fly ash
from the furnace gases by utilizing a precipitator or
baghouse, often in combination with a mechanical
collector. Heavier fly ash particles collected from
the boiler gas passages and mechanical collectors of-
ten have a high percentage of unburned carbon con-
tent, particularly in the case of spreader stoker fired
boilers; this heavier material may be reinfected into
the furnace to reduce unburned carbon losses and in-
crease efficiency, although this procedure does in-
crease the dust loading on the collection equipment
downstream of the last hopper from which such ma-
terial is reinfected.
(3) It is mandatory to install precipitators or
baghouses on all new coal fired boilers for final
cleanup 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 heavy
oil fired boilers because of the conventionally low
ash content of this type of fuel. An investigation is
required, however, for each particular oil fired unit
being considered.
b. Purpose. It is the purpose of the ash handling
system to:
(1) Collect the bottom ash from coal-fired
spreader stoker or AFBC boilers and to convey it
dry by vacuum or hydraulically by liquid pressure
to a temporary or permanent storage terminal. The
latter may be a storage bin or silo for ultimate trans-
fer to rail or truck for transport to a remote disposal
area, or it maybe an on-site fill area or storage pond
for the larger systems where the power plant site is
3-29

TM 5-811-6
adequate and environmentally acceptable for this
purpose.
(2) Collect fly ash and to convey it dry to tem-
porary or permanent storage as described above for
bottom ash. Fly ash, being very light, will be wetted
and is mixed with bottom ash prior to disposal to
prevent a severe dust problem.
3-17. Description of major components
a. Typical oil fired system. Oil fired boilers do not
require any bottom ash removal facilities, since ash
and unburned carbon are light and carried out with
the furnace exit gas. A mechanical collector may be
required for small or intermediate sized boilers hav-
ing steaming rates of 200,000 pounds per hour or
less. 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 can
coagulate at atmospheric temperatures making it
difficult to handle. To overcome this, hoppers
should be heated with steam, hot water, or electric
power. Hoppers will be equipped with an outlet
valve having an air lock and a means of attaching
disposable paper bags sized to permit manual hand-
ling. Each hopper will be selected so that it need not
be evacuated more than once every few days. If boil-
er size and estimated soot/ash loading is such that
manual handling becomes burdensome, a vacuum or
hydraulic system as described below should be con-
sidered.
b. Typical ash handling system for small or inter
mediate sized coal fired boilers;
(1) Plant fuel burning rates and ash content of
coal are critical in sizing the ash handling system.
Sizing criteria will provide for selecting hoppers and
handling equipment so that ash does not have to be
removed more frequently than once each 8-hour
shift using the highest ash content coal anticipated
and with boiler at maximum continuous steaming
capacity. For the smaller, non-automatic system it
may be cost effective to select hoppers and equip
ment which will permit operating at 60 percent of
maximum steam capacity for 3 days without remov-
ing ash to facilitate operating with a minimum
weekend crew.
(2) For a typical military power plant, the most
economical 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 vacuum
This typical plant would probably
have a traveling grate spreader stoker, a mechanical
collector, and a baghouse; in all likelihood, no on-site
ash 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 to
receive the discharge from the traveling grate. A
clinker grinder is not required for a spreader stoker
although 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 by
the design engineer.
(4) And the following items are common to all
boilers in the plant:
(a) Ash collecting piping fabricated of special
hardened ferro-alloy to transfer bottom and fly ash
to Storage.
(b) Vacuum producing equipment, steam or
mechanical exhauster as may prove economical. For
plants with substantial export steam and with low
quality, relatively inexpensive makeup require-
ments, steam will be the choice. For plants with
high 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 to
clean 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 dampen
ashes as they are unloaded into a truck or railroad
car for transport to remote disposal.
(e) Automatic control system for sequencing
operation of the system. Usually the manual initia-
tion of such a system starts the exhauster and then
removes 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 will
usually be single stage, geared units without extrac-
tion openings for either back pressure or condensing
service. Rated condensing pressures for single stage
turbines range from 3 to 6 inches Hga. Exhaust
pressures for back pressure units in cogeneration
service typically range from 15 psig to 250 psig.
(2) Intermediate turbine generators. From
about 2500 to 10,000 kW rated capacity, turbine
generators will be either multi-stage, multi-valve
machines 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 are
equipped with either uncontrolled or controlled (au-
tomatic) extraction openings. Below 4000 kW, there
will be one or two openings with steam pressures up
to 600 psig and 750°F. From 4000 kW to 10,000
kW, turbines will be provided with two to four un-
controlled extraction openings, or one or two auto-
matic extraction openings. These turbines would
have initial steam conditions from 600 psig to 1250
psig, 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 capacity
range 10,000 to 30,000 kW, turbine generators will
be direct drive, multi-stage, multi-valve units. For
electric power generator applications, from two to
five uncontrolled extraction openings will be re-
quired for feedwater heating. In cogeneration appli-
cations which include the provision of process or
heating steam along with power generation, one au-
tomatic extraction opening will be required for each
level of processor heating steam pressure specified,
along with uncontrolled extraction openings for
feedwater heating. Initial steam conditions range up
to 1450 psig and 950 “F with condensing pressures
from 1 1/2 to 4 inches Hga.
b. Turbine features and accessories. In all size
ranges, turbine generator sets are supplied by the
manufacturer with basic accessories as follows:
(1) Generator with cooling system, excitation
and voltage regulator, coupling, and speed reduc-
tion gear, if used.
(2) Turbine and generator (and gear) lubrication
system including tank, pumps, piping, and controls.
(3) Load speed governor, emergency overspeed
governor, and emergency inlet steam trip valve with
related hydraulic piping.
(4) Full rigid base plate in small sizes or sepa-
rate mounting sole plates for installation in concrete
pedestal for larger units.
(5) Insulation and jacketing, instruments, turn-
ing gear and special tools.
3-19. Generators
For purposes of this section, it is noted that the gen-
erator must be mechanically compatible with the
driving turbine, coupling, lubrication system, and
vibration characteristics (see Chapter 4 for gener-
ator details).
3-20. Turbine features
a. General. Turbine construction may be general-
ly classified as high or low pressure, single or multi-
stage, back pressure on condensing, direct drive or
gear reducer drive, and for electric generator or for
mechanical drive service.
(1) Shell pressures. High or low pressure con-
struction refers generally to the internal pressures
to be contained by the main shell or casing parts.
(2) Single us. multi-stage. Single or multi-stage
designs are selected to suit the general size,
enthalpy drops and performance requirements of
the turbine. Multi-stage machines are much more
expensive but are also considerably more efficient.
Single stage machines are always less expensive,
simpler and less efficient. They may have up to
three velocity wheels of blading with reentry sta-
tionary vanes between wheels to improve efficiency.
As casing pressure of single stage turbines are equal
to 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 dependent
on the plant function and cycle parameters. (See
Chapter 3, Section I for discussion of cycles.) Con-
densing machines are larger and more complex with
high pressure and vacuum sealing provisions, steam
condensers, stage feedwater heating, extensive lube
oil 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 generator
speed. Units 2500 kW and larger are normally direct
connected. Small, and especially single stage, tur-
bines may be gear driven for compactness and for
single stage economy. Gear reducers add complex-
ity and energy losses to the turbine and should be
used only after careful consideration of overall econ-
omy and reliability.
(5) Mechanical drive. Main turbine units in
power plants drive electrical generators, although
large pumps or air compressors may also be driven
by large turbines. In this event, the turbines are
called “mechanical drive” turbines. Mechanical
drive turbines are usually variable speed units with
special 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 single
stage, back pressure, direct drive type designed for
mechanical simplicity and reliability. Both constant
speed 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 built
with vertical shafts. Turbine rotor shaft is usually
supported in two sleeve type, self aligning bearings,
sealed and protected from internal casing steam
conditions. Output shaft is coupled to the shaft of
the generator which is provided with its own enclo-
sure but is always mounted on the same foundation
as the turbine.
(1) Balance. Balanced and integrated design of
the turbine, coupling and generator moving parts is
important to successful operation, and freedom
from torsional or lateral vibrations as well as pre-
vention of expansion damage are essential.
(2) Foundations. Foundations and pedestals for
turbine 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 the
United States are constructed of massive concrete.
3-21. Governing and control
a. Turbine generators speed/load control. Electri-
cal generator output is in the form of synchronized
ac electrical power, causing the generator and driv-
ing turbine to rotate at exactly the same speed (or
frequency) as other synchronized generators con-
nected into the common network. Basic speed/load
governing equipment is designed to allow each unit
to hold its own load steady at constant frequency, or
to accept its share of load variations, as the common
frequency rises and falls. Very small machines may
use direct mechanical governors, but the bulk of the
units will use either mechanical-hydraulic governing
systems or electrohydraulic systems. Non-reheat
condensing units 5000 kW and larger and back pres-
sure units without automatic extraction will be
equipped with mechanical-hydraulic governing. For
automatic 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 exceeds
a safe speed for any reason. The emergency gover-
nor closes a specially designed stop valve which not
only 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 the
turbine 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 efficiency
at rated load, but lower part load efficiencies.
3-22. Turning gear
a. General. For turbines sized 10,000 kW and
larger, a motor operated turning gear is required to
prevent the bowing of the turbine rotor created by
the temperature differential existing between the
upper 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 is
mounted at the exhaust end of the turbine and is
used to turn the rotor at a speed of 1 to 4 rpm when
the turbine is shut down in order to permit uniform
cooling of the rotor. Turning gear is also used during
startup to evenly warm up the rotor before rolling
the turbine with steam and as a jacking device for
turning the rotor as required for inspection and
maintenance when the turbine is shut down.
b. Arrangement and controls. The turning gear
will consist of a horizontal electric motor with a set
of gear chains and a clutching arrangement which
engages a gear ring on the shaft of the turbine. Its
controls are arranged for local and/or remote start-
ing and to automatically disengage when the tur-
bine reaches a predetermined speed during startup
with steam. It is also arranged to automatically en-
gage when the turbine has been shut down and de-
celerated to a sufficiently slow speed. Indicating
lights will be provided to indicate the disengaged or
engaged status of the turning gear and an interlock
provided 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 systems
a. General. Every turbine and its driven machine
or generator requires adequate lubricating oil sup
ply including pressurization, filtration, oil cooling,
and emergency provisions to insure lubrication in
the event of a failure of main oil supply. For a typ-
ical turbine generator, an integrated lube oil storage
tank with built in normal and emergency pumps is
usually provided. Oil cooling may be by means of an
3-33

TM 5-811-6
external or internal water cooled heat exchanger. Oil
temperatures should be monitored and controlled,
and heating may be required for startup.
b. Oil Pumps. Two full capacity main lube oil
pumps will be provided. One will be directly driven
from the turbine shaft for multi-stage machines.
The second full size pump will be ac electric motor
driven. 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 maintain
pressure, or after main pump failure, or in the event
of failure of the power supply to the ac electric mo-
tor driven pumps.
c. Filtration. Strainers and filters are necessary
for the protection and longevity of lubricated parts.
Filters and strainers should be arranged in pairs for
on line cleaning, inspection, and maintenance. Larg-
er turbine generator units are sometimes equipped
with special off base lubrication systems to provide
separate, high quality filtering.
3-24. Extraction features
a. Uncontrolled extraction systems. Uncontrolled
bleed or extraction openings are merely nozzles in
the turbine shell between stages through which rela-
tively limited amounts of steam may be extracted
for stage feedwater heating. Such openings add
little to the turbine cost as compared with the cost
of feedwater heaters, piping, and controls. Turbines
so equipped are usually rated and will have efficien-
cies and performance based on normal extraction
pressures and regenerative feedwater heating calcu-
lations. Uncontrolled extraction opening pressures
will vary in proportion to turbine steam flow, and
extracted steam will not be used or routed to any
substantial uses except for feedwater heating.
b. Automatic extraction. Controlled or automatic
extraction turbines are more elaborate and equipped
with variable internal orifices or valves to modulate
internal steam flows so as to maintain extraction
pressures within specified ranges. Automatic ex-
traction machine governors provide automatic self-
contained modulation of the internal flow orifices or
valves, using hydraulic operators. Automatic ex-
traction governing systems can also be adapted to
respond to external controls or cycle parameters to
permit extraction pressures to adjust to changing
cycle conditions.
c. Extraction turbine selection. Any automatic
extraction turbine is more expensive than its
straight uncontrolled extraction counterpart of sim-
ilar size, capacity and type; its selection and use re-
quire comprehensive planning studies and economic
analysis for justification. Sometimes the same ob-
jective can be achieved by selecting two units, one of
which is an uncontrolled extraction-condensing ma-
chine and the other a back pressure machine.
3-25. Instruments and special tools
a. Operating instruments. Each turbine will be
equipped with appropriate instruments and alarms
to monitor normal and abnormal operating condi-
tions including speed, vibration, shell and rotor ex-
pansions, steam and metal temperatures, rotor
straightness, turning gear operation, and various
steam, 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. Introduction
a. Purpose.
(1) The primary purpose of a condenser and cir-
culating water system is to remove the latent heat
from the steam exhausted from the exhaust end of
the steam turbine prime mover, and to transfer the
latent heat so removed to the circulating water
which is the medium for dissipating this heat to the
atmosphere. A secondary purpose is to recover the
condensate resulting from the phase change in the
exhaust steam and to recirculate it as the working
fluid in the cycle.
(2) Practically, these purposes are accom-
plished in two steps. In the first step, the condenser
is supplied with circulating water which serves as a
medium 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 an
ocean, 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 is
rejected to the natural body of water or recirculated
source 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 system
utilized. There are two basic types of con-
densers: surface and direct contact.
There are also two basic types of cooling sys-
tems:
Once through; and
Recirculating type, including cooling ponds, me-
chanical draft cooling towers, natural draft cooling
towers, or a combination of a pond and tower.
3-34

TM 5-811-6
a. Surface condensers.
(1) General description. These units are de-
signed as shell and tube heat exchangers. A surface
condenser consists of a casing or shell with a cham-
ber at each end called a “water box. ” Tube sheets
separate the two water boxes from the center steam
space. Banks of tubes connect the water boxes by
piercing the tube sheets; the tubes essentially fill
the shell or steam space. Circulating water pumps
force the cooling (circulating] water through the wa-
ter boxes and the connecting tubes. Uncontami-.
nated condensate is recovered in surface condensers
since 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 the
shell. In single pass units, water enters the water
box at one end of the tubes, flows once through all
the tubes in parallel, and leaves through the outlet
water box at the opposite end of the tubes. In two
pass units, water flows through the bottom half of
the tubes (sometimes the top half) in one direction,
L
reverses in the far end water box, and returns
through the upper or lower half of the tubes to the
near water box. Water enters and leaves through the
near water box which is divided into two chambers
by a horizontal plate. The far end water box is undi-
vided to permit reversal of flow.
(b) For a relatively large cooling water source
and low circulating water pump heads (hence low
unit pumping energy costs), single pass units will be.
used. For limited cooling water supplies and high
circulating water pump heads (hence high unit
pumping energy costs), two pass condensers will be
< specified. In all cases, the overall condenser-circulat-
ing water system must be optimized by the designer
to arrive at the best combination of condenser sur-
face, temperature, vacuum, circulating water
pumps, piping, and ultimate heat rejection equip-
ment.
(c) Most large condensers, in addition to the
inlet waterbox horizontal division, have vertical par-
titions to give two separate parallel flow paths
through 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 least
3 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 to
the 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 have
tubes rolled into both tube sheets; for ultra-tight-
ness, alloy steel tubes may be welded into tube
sheets of appropriate material. Admiralty is the
most common tube material and frequently is satis-
factory for once through systems using fresh water
and for recirculating systems. Tube material in the
“off gas” section of the condenser should be stain-
less steel because of the highly corrosive effects of
carbon dioxide and ammonia in the presence of
moisture and oxygen. These gases are most concen-
trated in this section. Other typical condenser tube
materials include:
(1) Cupronickel
(2) Aluminum bronze
(3) Aluminim brass
(4) Various grades of stainless steel
(b) Condenser tube water velocities range
from 6 to 9 feet per second (Table 3- 12). Higher flow
rates raise pumping power requirements and erode
tubes at their entrances, thus shortening their life
expectancy. Lower velocities are inefficient from a
heat transfer point of view. Tubes are generally in-
stalled with an upwardly bowed arc. This provides
for thermal expansion, aids drainage in a shutdown
condenser, 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 of
steam 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 are
not recommended.
(3) Minimum velocity of 5.5 fps to prevent chloride attack.
(4) Not recommended for circulating water containing high concentration
of heavy metal salts.
not be higher than approximately 27 feet above min-
imum water source level which permits siphon oper-
ation without imposing static head. With a siphon
system, air bubbles tend to migrate to the top of the
system and must be removed with vacuum-produc-
ing equipment. The circulating pumps then need to
develop only enough head to overcome the flow re-
sistance of the circulating water circuit. Circulating
pumps for condensers are generally of the centrif-
ugal type for horizontal pumps, and either mixed
flow or propeller type for vertical pumps. Vertical
pumps will be specified because of their adaptability
for intake structures and their ability to handle high
capacities at relatively low heads. Pump material
will 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 push
water 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 two
inches 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 designed
pump 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 serves
more than one condenser, there will be one circulat-
ing pump per condenser with an extra pump as a
common spare. Condensate pump capacity will be
sized to handle the maximum condenser load under
any condition of operation (e.g., with automatic ex-
traction to heating or process shutoff and including
all feedwater heater drains and miscellaneous drips
received by the condenser.)
(5) Air removal.
(a) Non-condensable gases such as air, carbon
dioxide, and hydrogen migrate continuously into
the steam space of a condenser inasmuch as it is the
lowest pressure region in the cycle. These gases may
enter through leakage at glands, valve bonnets, por-
ous walls, or may be in the throttle steam. Those
gases not dissolved by the condensate diffuse
throughout the steam space of the condenser. As
these gases accumulate, their partial pressure raises
the condenser total pressure and hence decreases ef-
ficiency of the turbine because of loss of available
energy. The total condenser pressure is:
Pc = PS + Pa
where Ps = steam saturation pressure cor-
responding to steam tempera-
ture
Pa = air pressure (moisture free)
L
This equation shows that air leakage must be re-
moved constantly to maintain lowest possible vac-
uum for the equipment selected and the particular
exhaust steam loading. In removing this air, it will
always have some entrained vapor. Because of its
subatmospheric pressure, the mixture must be com-
pressed for discharge to atmosphere.
(b) Although the mass of air leakage to the
condenser may be relatively small because of its.
very low pressure, its removal requires handling of a
large volume by the air removal equipment. The air
offtakes withdraw the air-vapor moisture from the
.
steam space over a cold section of the condenser
tubes or through an external cooler, which con-
denses part of the moisture and increases the air-to-
steam ratio. Steam jets or mechanical vacuum
pumps receive the mixture and compress it to at-
mosphere pressure.
(6) Condenser cleanliness. Surface condenser
performance depends greatly on the cleanliness of
the tube water side heat transfer surface. When
dirty 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 line
cleaning 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 as
follows. Water from an ocean, river, lake, or pond
flows either directly from the source to the circulat-
ing water structure or through conduits which bring
water from offshore; the inlet conduits discharge
into a common plenum which is part of the circulat-
ing water pump structure. Water flows through bar
trash racks which protect the traveling screens from
damage by heavy debris and then through traveling
screens where smaller debris is removed. For large
systems, 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 to
prevent clogging, they are periodically backwashes
by a high pressure water jet system. The backwash
is returned to the ocean or other body of water. Each
separate screen well is provided with stop logs and
sluice gates to allow dewatering for maintenance
purposes.
(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-percent
pumps will be used. At least one pump is required
for standby. Each pump will be equipped with a mo-
torized butterfly valve for isolation purposes. The
pumps discharge into a common circulating water
tunnel or supply pipe which may feed one or more
condensers. Also, a branch line delivers water to the
booster pumps serving the closed cooling water ex-
changers.
(c) Both inlet and outlet water boxes of the
main condensers will be equipped with butterfly
valves for isolation purposes and expansion joints.
As mentioned above, the system may have the capa-
bility to reverse flow in each of the condenser halves
for cleaning the tubes. The frequency and duration
of the condenser reverse flow or back wash opera-
tion is dictated by operating experience.
(d) The warmed circulating water from the
condensers and closed cooling water exchangers is
discharged to the ocean, river, lake, or pond via a
common discharge tunnel.
(3) Circulating water pump setting. The circu-
lating water pumps are designed to remain operable
with the water level at the lowest anticipated eleva-
3-37

TM 5-811-6
I
NAVFAC DM3
Figure 3-13. Types of circulating water systems.
tion of the selected source. This level is a function of
the neap tide for an ocean source and seasonal level
variations for a natural lake or river. Cooling ponds
are usually man-made with the level controlled with-
in modest limits. The pump motors and valve motor
operators will be located so that no electrical parts
will be immersed in water at the highest anticipated
elevation of the water source.
(4) System pressure control. On shutdown of a
circulating water pump, water hammer is avoided
by ensuring that the pumps coast down as the pump
isolation valves close. System hydraulics, circulat-
ing pump coastdown times, and system isolation
valve closing times must be analyzed to preclude
damage to the system due to water hammer. The
condenser tubes and water boxes are to be designed
for a pressure of approximately 25 psig which is well
above the ordinary maximum discharge pressure of
the circulating water pumps, but all equipment
must be protected against surge pressures caused
by 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 the
warmed circulating water is mixed with the residual
water 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 to
the atmosphere occur in the cooling equipment and
must be replenished at the power plant site. Recircu-
lating systems can utilize one of the following for
heat 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 piping
serving banks of spray nozzles.
(b) Very large, man-made ponds which take
advantage of natural evaporative cooling may be
considered as “recirculating” systems, although for
design purposes of the circulating water system
3-38

TM 5-811-6
they are once through and hence considered as such
in paragraph d above.
(c) To avoid fogging and plumes which are
characteristic of cooling towers under certain at-
mospheric conditions in humid climates, so called
wet-dry cooling towers may be used. These towers
use a combination of finned heat transfer surface
and 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. Hyperbolic
towers also are expensive and are not applicable to
units less than 300-500 M W; while spray ponds
have limited application (for smaller units) because
of the large ground area required and the problem of
excessive drift. Therefore, the following descriptive
material applies only to conventional induced draft
cooling towers which, except for very special cir-
cumstances, will be the choice for a military power
plant requiring a recirculating type system.
(2) System components. A typical recirculating
system 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 directed
to the circulating water pump pit. The pit is similar
to 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 setting
can be designed without reference to levels of a nat-
ural body of water. The circulating water pumps
pressure the water and direct it to the condensers
through the circulating water discharge piping. A
stream of circulating water is taken off from the
main condenser supply and by means of booster
pumps further pressurized as required for bearing
cooling, generator cooling, and turbine generator oil
cooling. From the outlet of the condensers and mis-
cellaneous cooling services, the warmed circulating
water is directed to the top of the cooling tower for
rejection of heat to the atmosphere.
(b) Circulating water pump and condenser
valving is similar to that described for a typical
once-through system, but no automatic back flush-
ing or mechanical cleaning system is required for
the condenser. Also, due to the higher pumping
heads commonly required for elevating water to the
top of the tower and the break in water pressure at
that 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 the
fill, usually counterflow to the falling water drop
lets, and is ejected to the atmosphere in saturated
condition thus carrying off the operating load of
heat 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 and
to 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 condenser
enters the distribution header at the top of the tow-
er. In conventional towers about 75 percent of the
cooling takes place be evaporation and the re-
mainder by heat conduction; the ratio depends on
the humidity of the entering air and various factors.
(5) Cooling tower performance. The principal
performance factor of a cooling tower is its approach
to the wet bulb temperature; this is the difference
between 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 as
the circulating water temperature rise in the conden-
ser. Practically, tower approaches are 8 to 15°F with
ranges of 18 to 22°F. Selection of approach and
range 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 of
equipment are interdependent.
(6) Cooling tower makeup.
(a) Makeup must be continuously added to
the tower collecting basin to replace water lost by
evaporation and drift. In many cases, the makeup
water must be softened to prevent scaling of heat
transfer surfaces; this will be accomplished by
means of cold lime softening. Also the circulating
water must be treated with bioxides and inhibitors
while in use to kill algae, preserve the fill, and pre-
vent metal corrosion and fouling. Algae control is
accomplished by means of chlorine injection; acid
and phosphate feeds are used for pH control and to
keep heat surfaces clean.
(b) The circulating water system must be
blown down periodically to remove the accumulated
solid concentrated by evaporation.
3-39

TM 5-811-6
3-28. Environmental concerns
a. Possible problems. Some of the environmental
concerns which have an impact on various types of
power plant waste heat rejection systems are as fol-
lows:
(1) Compatibility of circulating water system
with type of land use allocated to the surrounding
area of the power plant.
(2) Atmospheric ground level fogging from
cooling 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 navigable
streams or bodies of water).
b. Solutions to problems. Judicious selection of
the type of circulating water system and optimum
orientation of the power plant at the site can mini-
mize these problems. However, many military proj-
ects will involve cogeneration facilities which may
require use of existing areas where construction of
cooling towers may present serious on base prob-
lems and, hence, will require innovative design solu-
tions.
Section VII. FEEDWATER SYSTEM
3-29. Feedwater heaters
a. Open type—deaerators.
(1) Purpose. Open type feedwater heaters are
used primarily to reduce feedwater oxygen and oth-
er noncondensable gases to essentially zero and thus
decrease corrosion in the boiler and boiler feed sys-
tem. Secondarily, they are used to increase thermal
efficiency 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 type
and spray type. The tray or combination spray/tray
type unit will be used. In plants where heater tray
maintenance could be a problem, or where the feed-
water has a high solids content or is corrosive, a
spray type deaerator will be considered.
(b) All types of deaerators will have internal
or external vent condensers, the internal parts of
which will be protected from corrosive gases and
oxidation by chloride stress resistant stainless steel.
(c) In cogeneration plants where large
amounts of raw water makeup are required, a deaer-
ating hot process softener will be selected depending
on the steam conditions and the type of raw water
being treated (Section IX, paragraph 3-38 and
3-39).
(3) Location. The deaerating heater should be
located to maintain a pressure higher than the
NPSH required by the boiler feed pumps under all
conditions of operation. This means providing a
margin of static head to compensate for sudden fall
off in deaerator pressure under an upset condition.
Access will be provided for heater maintenance and
for reading and maintaining heater instrumenta-
tion.
(4) Design criteria.
(a) Deaerating heaters and storage tanks will
comply with the latest revisions of the following
standards:
(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 zero
residual carbon dioxide. Residual content of the dis-
solved gases will be consistent with their relative
volubility and ionization.
(d) Deaerator storage capacity will be not less
than ten minutes in terms of maximum design flow
through the unit.
(e) Deaerator will have an internal or external
oil separator if the steam supply may contain oil,
such as from a reciprocating steam engine.
(f) Deaerating heater will be provided with
the following minimum instrumentation: relief
valve, thermometer, thermocouple and test well at
feedwater 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 regenerative
feedwater cycle to increase thermal efficiency and
thus provide fuel savings. An economic evaluation
will be made to determine the number of stages of
feedwater heating to be incorporated into the cycle.
Condensing type steam turbine units often have
both low pressure heaters (suction side of the boiler
feed pumps) and high pressure heaters (on the dis-
charge side of the feed pumps). The economic anal-
ysis of the heaters should consider a desuperheater
section when there is a high degree of superheat in
the steam to the heater and an internal or external
drain cooler (using entering condensate or boiler
feedwater) to reduce drains below steam saturation
temperature.
(2) Type. The feedwater heaters will be of the U-
tube type.
(3) Location. Heaters will be located to allow
easy access for reading and maintaining heater in-
strumentation and for pulling the tube bundle or
heater shell. High pressure heaters will be located to
provide the best economic balance of high pressure
feedwater piping, steam piping and heater drain pip
ing.
(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: shell
and tube relief valves; thermometer, thermocouple
and 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 assure
efficient operation of each heater and provide for
protection of other related power plant equipment.
The level control system for the feedwater heaters is
an integrated part of a plant cycle level control sys-
tem which includes the condenser hotwell and the
boiler level controls, and must be designed with this
in mind. This paragraph sets forth design criteria
which 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 usually
cascaded to the next lowest stage feedwater heater
or to the condenser, A normal and emergency drain
line from each heater will be provided. At high loads
with high extraction steam pressure, the normal
heater drain valve cascades drain to the next lowest
stage heater to control its own heater level. At low
loads with lower extraction steam pressure and low-
er pressure differential between successive heaters,
sufficient pressure may not be available to allow the
drains to flow to the next lowest stage heater. In
this case, an emergency drain valve will be provided
to cascade to a lower stage heater or to the conden-
ser to hold the predetermined level.
(b) The following minimum instrumentation
will be supplied to provide adequate level control at
each heater: gauge glass; level controller to modu-
late normal drain line control valve (if emergency
drain line control valve is used, controller must
have a split range); and high water level alarm
switch.
(3) Open feedwater heaters-deaerators. The fol-
lowing minimum instrumentation will be supplied
to provide adequate level control at the
heater: gauge glass, level controller to control feed-
water inlet control waive (if more than one feedwater
inlet source, controller must have a split range); low
water level alarm switch; “low-low” water level
alarm switch to sound alarm and trip boiler feed
pumps, 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 to
the condenser or condensate storage tank.
(4) Reference. The following papers should be
consulted 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 Electric
Power Generation (Part 1- Fossil Fueled Plants).”
(b) General Electric Company Standard
GEK-25504, Revision D, “Design and Operating
Recommendations to Minimize Water Induction in
Large 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 or
deaerating hot process softener and feed it through
any high pressure closed feedwater heaters to the
boiler inlet. Discharge from the boiler superheated
steam in order to maintain proper main steam tern-
perature to the steam turbine generator.
b. Types. There are two types of centrifugal
multi-stage boiler feed pumps commonly used in
steam power plants—horizontally split case and bar-
rel type with horizontal or vertical (segmented) split
inner case. The horizontal split case type will be
used on boilers with rated outlet pressures up to 900
psig. Barrel type pumps will be used on boilers with
rated outlet pressure in excess of 900 psig.
c. Number of pumps. In all cases, at least one
spare feed pump will be provided.
(1) For power plants where one battery of boiler
feed pumps feeds one boiler.
(a) If the boiler is base loaded most of the
time at a high load factor, then use two pumps each
at 110-125 percent of boiler maximum steaming ca-
pacity.
(b) If the boiler is subject to daily wide range
load swings, use three pumps at 55-62.5 percent of
boiler maximum steaming capacity. With this ar-
rangement, two pumps are operated in parallel be-
tween 50 and 100 percent boiler output, but only one
pump 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 of
flexibility.
(2) For power plants where one battery of pump
feeds more than one boiler through a header system,
the number of pumps and rating will be chosen to
provide optimum operating efficiency and capital
costs. At least three 55-62.5 percent pumps should
be selected based on maximum steaming capacity of
all boilers served by the battery to provide the flexi-
bility required for a wide range of total feedwater
flows.
d. Location. The boiler feed pumps will be located
at the lowest plant level with the deaerating heater
or softener elevated sufficiently to maintain pump
suction pressure higher than the required NPSH of
the pump under all operating conditions. This
means a substantial margin over the theoretically
calculated requirements to provide for pressures col-
lapses in the dearator under abnormal operating
conditions. Deaerator level will never be decreased
for structural or aesthetic reasons, and suction pipe
connecting deaerator to boiler feed pumps should be
sized 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 recirculation
control 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 be
designed to open the flow control valve to maintain
minimum pump flow. The recirculation line will be
discharge to the deaerator. A breakdown orifice will
be installed in the recirculation line just before it en-
ters the deaerator to reduce the pressure from boiler
feed pump discharge level to deaerator operating
pressure.
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 as
flow increases to insure stable operation of one
pump, 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 minimum
recirculation flow.
(4) Provision will be made in pump design for
expansion 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 standby
it can be hot, ready for quick startup. This is done
by connecting a small bleed line and orifice from the
common discharge header to the pump discharge in-
side of the stop and check valve. Hot water can then
flow back through the pump and open suction valve
to the common suction header, thus keeping the
pump at operating temperature.
(9) Pump will be designed so that it will start
safely from a cold start to full load in 60 seconds in

TM 5-811-6
an emergency, although it will normally be warmed
before starting as described above.
(10) Other design criteria should be as forth in
Military Specification MIL-P-17552D.
g. Pump drives. For military plants, one steam
turbine driven pump may be justified under certain
conditions; 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 into
the feed pumps by other means, and from a plant ef-
ficiency point of view it is always better to bleed
steam ‘from the prime mover(s) rather than to use
steam from an inefficient mechanical drive turbine.
3-31. Feedwater supply
a. General description.
(1) In general terms, the feedwater supply in-
cludes the condensate system as well as the boiler
feed system.
(2) The condensate system includes the conden-
sate pumps, condensate piping, low pressure closed
heaters, deaerator, and condensate system level and
makeup controls. Cycle makeup may be introduced
either into the condenser hotwell or the deaerator.
For large quantities of makeup as in cogeneration
plants, the deaerator maybe preferred as it contains
a larger surge volume. The condenser, however, is
better 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; the
excess not immediately required for cycle makeup is
extracted and pumped to an atmospheric storage
tank 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 the
atmospheric storage tank is much less with this ar-
rangement.
(3) The feedwater system includes the boiler
feed pumps, high pressure closed heaters, boiler feed
suction and discharge piping, feedwater level con-
trols for the boiler, and boiler desuperheater water
supply with its piping and controls.
b. Unit vs. common system. Multiple unit cogen-
eration plants producing export steam as well as
electric will always have ties for the high pressure
Section Vlll. SERVICE WATER
3-32. Introduction
a. Definitions and purposes. Service water supply
systems and subsystems can be categorized as fol-
lows:
(1) For stations with salt circulating water or
steam, the extraction steam, and the high pressure
feedwater system. If there are low pressure closed
heaters incorporated into the prime movers, the con-
densate system usually remains independent for
each such prime mover; however, the deaerator and
boiler feed pumps are frequently common for all
boilers although paralleling of independent high
pressure heater trains (if part of the cycle) on the
feedwater side maybe incorporated if high pressure
bleeds on the primer movers are uncontrolled. Each
cogeneration 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, boiler
feed pumps, deaerator, and closed feedwater heaters
are described as equipment items under other head-
ings in this manual. Feedwater system controls will
consist of the following
(1) Condenser hotwell level controls which con-
trol hotwell level by recirculating condensate from
the condensate pump discharge to the hotwell, by
extracting excess fluid from the cycle and pumping
it to atmospheric condensate storage (surge) tanks,
and by introducing makeup (usually from the same
condensate storage tanks) into the hotwell to replen-
ish cycle fluid.
(2) Condensate pump minimum flow controls to
recirculate sufficient condensate back to the con-
denser hotwell to prevent condensate pumps from
overheating.
(3) Deaerator level controls to regulate amount
of condensate transferred from condenser hotwell to
deaerator and, in an emergency, to overflow excess
water 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. Regardless
of the method selected, the hotwell and the deaer-
ator level controls must be closely coordinated and
integrated because the hotwell and deaerator tank
are both surge vessels in the same fluid system.
(5) Other details on instruments and controls
for the feedwater supply are described under Section
1 of Chapter 5, Instruments and Controls.
heavily contaminated or sedimented fresh circulat-
ing water.
(a) Most power stations, other than those
with 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 pumps
may also supply water to the water treating system.
Supplementary sources of water such as the area
public water supply or well water may be used for
potable use and/or as a supply to the water treating
system. In some cases, particularly for larger sta-
tions, the service water system may have its pumps
divorced from the circulating water pumps to pro-
vide more flexibility y and reliability.
(b) The closed cooling water exchangers
transfer rejected heat from the turbine generator
lube 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 which
recirculates between the closed cooling exchangers
and the ultimate equipment where heat is removed.
This closed cooling cycle has its own circulating
(closed cooling water) pumps, expansion tank and
temperature controls.
(2) For stations with cooling towers. Circulat-
ing water booster pumps (or separate service water
pumps). may also be used for this type of power
plant. In the case of cooling tower systems, how-
ever, the treated cooling tower circulating water can
be used directly in the turbine generator lube oil and
generator air (or hydrogen) coolers and various other
services where a condensate quality cooling medium
is unnecessary. This substantially reduces the size
of a closed cooling system because the turbine gen-
erator auxiliary cooling requirements are the largest
heat rejection load other than that required for the
main condenser. If a closed cooling system is used
for a station with a cooling tower, it should be de-
signed to serve equipment such as air compressor
cylinder jackets and after coolers, excitation system
coolers, hydraulic system fluid coolers, boiler TV
cameras, and other similar more or less delicate
service. If available, city water, high quality well
water, or other clean water source might be used for
this delicate equipment cooling service and thus
eliminate 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 allow
monitoring of equipment cooling.
a. 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 for
this duty. Three pumps provide more flexibility; de-
pending upon heat rejection load and desired water
temperature, one pump or two pumps can be oper-
.
ated with the third pump standing by as a spare. A
pressure switch on the common discharge line
alarms high pressure, and in the case of the booster
pumps a pressure switch on the suction header or in-
terlocks with the circulating water pumps provides
permissive to prevent starting the pumps unless
the 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 by
using a by-pass arrangement to pass variable
amounts of water through the equipment without
upsetting 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 for
the pumps described in a above.
(2) Closed cooling water heat exchangers. The
closed cooling water exchangers will be horizontal
shell and tube test exchangers with the treated
plant 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 this
service, although three 50-percent units may be se-
lected for large systems.
(3) Temperature control. Temperature control
for each equipment item rejecting heat will be simi-
lar to that described above for the service water sys-
tem.
3-34. Description of systems
a. Service water system.
(1) The service water system heat load is the
sum of the heat loads for the closed cooling water
system and any other station auxiliary systems
which may be included. The system is designed to
maintain the closed cooling water system supply
temperature at 950 For less during normal operation

TM 5-811-6
with maximum heat rejection load. The system will
also be capable of being controlled or manually ad-
justed so that a minimum closed cooling water sup
ply temperature of approximately 55 ‘F can be
maintained with the ultimate heat sink at its lowest
temperature and minimum head load on the closed
cooling water system. The service water system will
be designed with adequate backup and other reli-
ability features to provide the required cooling to
components as necessary for emergency shutdown
of the plant. In the case of a system with circulating
water booster pumps, this may mean a crossover
from a city or well water system or a special small
circulating water pump.
(2) Where cooling towers are utilized, means
will be provided at the cooling tower basin to permit
the service water system to remain in operation
while the cooling tower is down for maintenance or
repairs.
(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 automatic
control of the service water flow through the heat
exchanger. This is achieved by control valve modu-
lation of the heat exchanger by-pass flow. All equip-
ment cooled by the cooling system is individually
temperature controlled by either manual or auto-
matic valves on the coolant discharge from, or by
by-pass control around each piece of equipment. The
quantity of coolant in the system is automatically
maintained at a predetermined level in the expan-
sion tank by means of a level controller which oper-
ates a control valve supplying makeup from the
cycle condensate system. The head tank is provided
with 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 all
service equipment will be operating at maximum de-
sign conditions.
3-35. Arrangement
a. Service water system. The circulating water
booster pumps will be located as close as possible to
the cooling load center which generally will be near
the turbine generator units. All service water piping
located in the yard will be buried below the frost
line.
b. Closed cooling water system. The closed cool-
ing water system exchangers will be located near
the turbine generators.
3-36. Reliability of systems
It is of utmost importance that the service and
closed cooling water systems be maintained in serv-
ice during emergency conditions. In the event power
from the normal auxiliary source is lost, the motor
driven pumps and electrically actuated devices will
be automatically supplied by the emergency power
source (Chapter 4, Section VII). Each standby pump
will be designed for manual or automatic startup
upon loss of an operating pump with suitable alarms
incorporated to warn operators of loss of pressure in
either system.
3-37. Testing
The systems will be designed to allow appropriate
initial and periodic testing to:
u. Permit initial hydrostatic testing as required in
the ASME Boiler and Pressure Vessel Code.
b. Assure the operability and the performance of
the active components of the system.
c. Permit testing of individual components or
subsystems such that plant safety is not impaired
and 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 or
jurious to steam boiler operation and cooling water above) require high quality makeup water which is
service. 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 and
pretreatment. Fresh water makeup to a boiler sys-
tem ranges from possibly no pretreatment (in the
organic matter found in most surface waters, the
raw 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 to
ultra-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 general
plant 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 power
plant fluid streams (the boiler feed water, cooling
tower system, and process water) or prior to utiliz-
ing it for potable or general washup purposes. Inter-
nal treatment methods introduce chemicals directly
into the power plant fluid stream where they coun-
teract or moderate the undesirable effects of water
impurities. Blowdown is used in the evaporative
processes to control the increased concentration of
dissolved and suspended solids at manageable lev-
els.
(2) Some of the methods of water conditioning
are 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, and
3-15 provide general guidelines for selection of
treatment methodologies. The choice among these is
an economic one depending vitally on the actual con-
stituents of the incoming water. The designer will
make a thorough life cycle of these techniques in
conjunction with the plant data. Water treatment
experts and manufacturer experience data will
called upon.
Section X. COMPRESSED AIR SYSTEMS
3-39. Introduction
a. Purpose. The purpose of the compressed air
systems is to provide all the compressed air require-
ments throughout the power plant. The compressed
air systems will include service air and instrument
air 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.
a. Air compressors. Typical service and instru-
ment air compressor? for power plant service are
single or two stage, reciprocating piston type with
electric motor drive, usually rated for 90 to 125 psig
discharge 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 carryover
will not be a problem. Slow speed horizontal units
for service and instrument air will be used. Soot
blower service requirements call for pressures which
require multi-stage design. The inlet air filter-silenc-
er will be a replaceable dry felt cartridge type. Each
compressor will have completely separate and inde-
pendent controls. The compressor controls will per-
mit either constant speed-unloaded cylinder control
or automatic start-stop control. Means will be pro-
vided in a multi-compressor system for selection of
the’ ‘lead” compressor.
b. Air aftercooler. The air aftercooler for each
compressor will be of the shell and tube type, de-
signed to handle the maximum rated output of the
compressor. Water cooling is provided except for
relatively 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 air
through the aftercooler, and then through the cylin-
der jackets. Standard aftercoolers are rated for
95 “F. maximum inlet cooling water. Permissive
can 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 of
water when unit is in operation.
c. Air receiver. Each compressor will have its own
receiver 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 earn
Pressure Silica Alkalinity
-
(psig) 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, or
sodium ion exchange plus
chloride anion exchange.
Over 15
450 to 600 Under 5
Over 50
Under 50
Over 50
Hot lime-hot zeolite,
or cold lime-zeolite,
or hot lime soda.
Sodium ion exchange plus
chloride anion exchange,
or hot lime-hot zeolite.
Sodium plus hydrogen ion
exchange, or cold lime-
zeolite or hot lime-hot
zeolite.
Above 5 Demineralizer, or hot
lime-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 Industry
Standards 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 water
alkalinity for scale and corrosion control.
.
Prevention of boiler scale by internal softening
of the boiler water.
Conditioning of boiler sludge to prevent adherence
to internal boiler surfaces.
Prevention of scale from hot water in pipelines,
stage heaters, and economizers.
Prevention of oxygen corrosion by chemical
deaeration of boiler feedwater.
Prevention of corrosion by protective film
formation.
Prevention of corrosion by condensate.
Prevention of foam in boiler water.
Inhibition of caustic embrittlement.
Chemical
Caustic Soda
Soda Ash
Sulfuric Acid
Phosphates
Soda Ash
Sodium Aluminate
Alginates
Sodium Silicate
Tannins
Lignin Derivatives
Starch
Glucose Derivatives
Polyphosphates
Tannins
Lignin Derivatives
Glucose Derivatives
Sulfites
Tannins
Ferrus hydroxide
Glucose Derivatives
Hydrazine
Ammonia
Tannins
Lignin Derivatives
Glucose Derivatives
Amine Compounds
Ammonia
Polyamides
Polyalkylene Glycols
Sodium Sulfate
Phosphates
Tannins
Nitrates
3-48

Treatment
Cold Lime-
Zeolite
TM 5-811-6
Table 3-15. Effectiveness of Water Treatment
Average Analysis of Effluent
Hardness Alkalinity co Dissolved
(as CaCO )
Hot Lime Soda
Hot Lime-
Hot Zeolite
Sodium Zeolite
Sodium Plus
Hydrogen Zeolite
Sodium Zeolite
Plus Chloride
Anion 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
Silica
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
ENTRAINMENT
SEPARATOR
Courtesy of Pope, Evans and Robbins (Non-Copyrighted)
Figure 3-14. Typical compressed airsystem.
will be of the automatic heat reactivating, dual
chamber, chemical desiccant, downflow type. It will
contain a prefilter and afterfilter to limit particulate
size in the outlet dried air. Reactivating heat will be
provided by steam heaters.
3-41. Description of systems
a. General. The service (or plant) air and the in-
strument air systems may have separate or common
compressors. Regardless of compressor arrange-
ment, service and instrument air systems will each
have their own air receivers. There will be isolation
in the piping system to prevent upsets in the service
air system from carrying over into the vital instru-
ment air system.
b. Service air system. The service air system
capacity will meet normal system usage with one
compressor out of service. System capacity will in-
clude emergency instrument air requirements as
well as service air requirements for maintenance
during plant operation. Service air supply will in-
3-50
elude work shops, laboratory, air hose stations for
maintenance use, and like items. Air hose stations
should be spaced so that air is available at each
piece of equipment by using an air hose no longer
than 75 feet. Exceptions to this will be as follows:
(1) The turbine operating floor will have service
air stations every 50 feet to handle air wrenches
used to tension the turbine hood bolts.
(2) No service air stations are required in the
control room and in areas devoted solely to switch-
gear and motor control centers.
(3) Service air stations will be provided inside
buildings at doors where equipment or supplies may
be brought in or out.
c. Instrument air sys tern. A detailed analysis will
be performed to determine system requirements.
The analysis will be based on:
(1) The number of air operated valves and
dampers included in the mechanical systems.
(2) The number of air transmitters, controllers
and 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 where
eluded 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 be
for large stations a looped header will be provided at sized to recharge the receivers while continuing to
each of the floor levels. supply normal air demands.
3-51

Steamturbine 140203094808-phpapp01

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