Reference

NBS

PUBLICATIONS

mdSIR 85-3205

Chemical Thermodynamics in

Steam Power Cycles Data

Requirements

Proceedings of a Workshop held at The National Bureau of Standards,

Gaithersburg, Maryland

February 8-9, 1 983

Otakar Jonas and Howard J. White, Jr.

U.S. DEPARTMENT OF COMMERCE

National Bureau of Standards

Office of Standard Reference Data

Gaithersburg, MD 20899

July 1985

’ ^

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i Sponsored by;

The ASME Research Committee on the Properties of Steam

The ASME Research Committee on Water in Thermal Power Systems

r The Electric Power Research Institute

^l)C — The National Bureau of Standards

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ITATIONAL BUREAU

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NBSIR 85-3205

> 9 9 CHEMICAL THERMODYNAMICS IN

STEAM POWER CYCLES DATA

REQUIREMENTS

Proceedings of a Workshop held at The National Bureau of Standards

Gaithersburg, Maryland

February 8-9, 1 983

Otakar Jonas and Howard J. White, Jr.

U.S. DEPARTMENT OF COMMERCE

National Bureau of Standards

Office of Standard Reference Data

Gaithersburg, MD 20899

July 1985

Sponsored by:

The ASME Research Committee on the Properties of Steam

The ASME Research Committee on Water in Thermal Power Systems

The Electric Power Research Institute

The National Bureau of Standards

U.S. DEPARTMENT OF COMMERCE. Malcolm Baldrige, Secretary

NATIONAL BUREAU OF STANDARDS, Ernest Ambler, Director
I*
FOREWORD

A workshop on the needs for chemical thermodynamic data in steam

power cycles was held at the National Bureau of Standards in

Gaithersburg, Maryland, February 8-9, 1983. In these proceedings

the purpose of the workshop is presented and the principal conclusions

and recommendations are stated.

The texts or extended abstracts of most of the papers presented are also given.

i
SPONSORSHIP AND CREDITS

The workshop was sponsored by the ASME Research Committee on

the Properties of Steam, the ASME Research Committee on Water

in Thermal Power Systems, the Office of Standard Reference

Data of the National Bureau of Standards, and the Electric Power

Research Institute and was organized by Mr. Otakar Jonas,

Westinghouse Electric, and Dr. Howard J. White, Jr., Office of

Standard Reference Data.

ii
CONTENTS

Foreword i

Sponsorship and Credits ii

Contents iii

Introduction 1

Background 1 Current Status 1 Objectives of the Workshop 2

Scope

Format

Related Activities 3

Conclusions and Recommendations 4

Summary 4 Conclusions and Recommendations of Working Groups 6 Group I Reactors 6 Group II PWR Steam Generators and Fossil Boilers 9

Group III Turbines 11 Group IV The Pre-Boiler Cycle 15

Presentations 17

Introduction R. Spencer 18

Power System Chemical

Transport 0. Jonas 21 Waterside Corrosion and • Its Control in Fossil

Utility Steam Generators F. Pocock 38

Water Quality in Boiling

Water Reactor Cycles M. Maddagiri 103

Turbine Steam Chemistry W. T. Lindsay, Jr. 110

Reactor Chemistry P. Cohen 159

Basic Aqueous Chemistry at

High Temperatures and

Pressures at ORNL R. E. Mesmer 167

Aqueous Solutions at High

Temperatures R. Wood 179

Distribution of Chemical

Species Between Water

and Steam P. Cohen 195

Thermodynamics and Electrochemistry of Corrosion G. Theus 203

Correlation of Data for

Electrolytes in Water

and Steam J, Pei per 224

iii

rj

ro
Evaluated Data and Data

Bases; Chemical Thermodynamics in the Steam

Power Cycle D. Garvin 239

EPRI and ASME Research Committee on Water in Thermal

Power Cycles 0. Jonas 269

lAPS and ASME Research Committee on the Properties

of Steam

and

H. J. White, Jr. 277

Appendix I Agenda 278

Appendix II Attendance List 280

iv
INTRODUCTION

Background

It is estimated that corrosion in U.S. power systems costs about $1.5

billion annually. A large proportion of the 15 percent loss in capacity

of the 560,000 MW U.S. electric power system has been caused by corrosion

of boilers, turbines, condensers, and other components of the steamwater cycle. Similar problems occur in steam power systems used for ship

propulsion or industrial purposes.

Most of these corrosion problems result from the interaction of waterborne impurities, which may be acids, bases, salts, or oxides, organic

or inorganic in nature, with the materials of construction of the systems,

which are primarily metalSo Feedwater is pretreated before use, but the

fact that impurities may be concentrated at specific locations within the

system makes possible the presence locally of even concentrated solutions

of materials that enter the system in a very dilute state.

Corrosion is controlled through purification of water and addition of

water-treatment chemicals. The concentrations and thermodynamic properties of the impurities change throughout the power cycle with the temperature,

pressure, phase of the solvent (water or steam), and reactions of the

impurities with one another and with water-treatment chemicals. A necessary

step toward obtaining better corrosion control is an understanding of the

chemical -thermodynamic behavior of the substances in question over the

range of parameters met in the power cycle. Reference data are needed on substances, which may be present in the power cycle as impurities, watertreatment chemicals, corrosion products, and their mixtures over the temperature and pressure ranges found in power cycles.

Current Status

Many data relevant to this need exist in the literature. More are being

produced from projects being carried out under sponsorship of industrial

organizations such as EPRI. The International Association for the Properties

of Steam, through its Working Group IV, Chemical Thermodynamics in Power

Cycles, has been collecting and reviewing data on the systems Na0H/H20,

NaCl/H20, Si02/H20, and magneti te/H20. However, the comprehensive

authoritative tables that power engineers and scientists need in their work

are not available.

Provision of such tables in a timely fashion will require an extensive

coordinated effort. Experimental data must be compiled and evaluated.

Possible equations for correlating, interpolating, and extrapolating data

must be obtained and tested. A comprehensive, coordinated, thermodynamically

consistent set of reference data of tested reliability must be prepared and

1
made available. Groups that carry out such tasks in a systematic way

are often referred to as data centers. A data center assigned the task

of providing such tables would be expected to coordinate its efforts

with the ongoing activities mentioned above and to provide a focal point

for information on the thermodynamics of power cycles.

Objective of the Workshop

The participants in the workshop were asked to review the needs of the

U.S. power industry for reference data for the solution of corrosion problems in steam power systems, with particular emphasis on the thermodynamic

data discussed above. They were also asked to consider the desirability

of establishing a data center to meet these needs. Finally, they were

asked to establish the chemical substances, ranges of parameters, and

types of data that should be involved.

Scope

The scope of the workshop was limited to data on chemical compounds, pertinent to steam cycles, found in fossil and nuclear power plants including

the primary nuclear cycle. To the extent practicable, cycles found in

industrial, ship-propulsion, and geothermal uses were considered. Analytical

techniques and sensor development were not covered.

Format

The workshop took place over a two-day period. On the first day, plenary

lectures defining the current status of the field were given. These were

of two kinds. In one session observations of the presence and effects of

various substances in major components of power systems were discussed.

These included studies of operating systems and special tests on industrial

equipment. In the other session, the current status of the thermodynamics

of aqueous systems was discussed. Presentations covered the available

experimental data and the current capability to correlate and predict data

for relevant systems.

Working groups were formed on the following topics:

Working Group I Working Group II Working Group III

Working Group IV

Reactors

PWR Steam Generators and Fossil Boilers

Turbines

The Pre-Boiler Cycle

2
The working groups were asked to consider the needs for chemical thermodynamic data in general and the following specific items:

What would an ideal thermodynamic data base for your topic

contain? Substances, properties, reaction, ranges of temperature and pressure, other parameters such as pH, p02, emf?

Are treatment of complex ions, hydrolysis of ions, complex

mixtures involved? What are the most important cases? How

would you suggest that they be treated?

To what extent can these needs be met with existing measurements and correlation techniques, and what new measurements

must be made and what new correlation and prediction techniques

developed?

Are there any special data requirements introduced when interfacial phenomena and corrosion are considered?

What kinds of data products would you find most useful? Tables?

Figures, e.g., Pourbaix Diagrams? Computer tapes? "How to

calculate it" data books? Would you expect the reliability of

the data to be evaluated?

Do you think that a group devoted to preparing such data

products (a data center) is necessary or highly desirable?

• After the meetings of the working groups, the chairmen reported in a plenary session to allow discussion involving members of different working groups.

Related Activities

Each of the sponsors of the workshop is involved in obtaining or evaluating

data of the type considered here. In addition, the International Association for the Properties of Steam is also concerned with such data. For a variety of reasons, none of these organizations can be expected to carry

out the activities considered here independently, although each would be

expected to cooperate with any program that might be established.

3
CONCLUSIONS AND RECOMMENDATIONS

Summary

The following are the conclusions and recommendations of the workshop

drawn from the conclusions of the individual working groups and the

joint discussion. The recommendations of each working group are also

given separately:

1. The users of steam for power generation, propulsion, and industrial purposes urgently need chemical thermodynamic data pertinent to

their systems. The principal stimulus is provided by corrosion problems

for the solution of which such data provide a necessary base. Other types

of data, principally kinetic data, are also important. A data center

should be established to collect, evaluate, correlate, predict, and disseminate reference data and recommend research in areas where suitable

data are not available.

2. A temperature range from room temperature to 650°C (1200°F) and

a pressure range from 0 to 41 MPa (6000 psia) should be covered. Both the

liquid (water) and the vapor (steam) phases are important over the entire

range of concentration of solute achievable, and the systems may be multicomponent solutions. Furthermore, many of the substances of interest contain

ions which can be hydrolyzed, oxidized, or involved in complex formation

so that these internal equilibria must be taken into account and the properties of a solution depend on its pH and pO as well as the concentration of

solute. Finally, the solutions are in contact with solid surfaces with

which they* can interact.

Data needed include:

° Activity coefficients

° Redox, hydrolysis, hydration and other equilibrium constants

involving dissolved ions

° Phase equilibria, especially solubilities and liquid-vapor

distribution coefficients

° Af G°(T), Af H°(T), S° (T), C° (T), V (Tx P)

° Adsorption

° Ion-solid interactions

° Possibly surface tensions and colloidal properties in some caseso

4
3 . The chemical systems for which data are needed involve many

common cations and anions, gases (O2 H2 N2 H2S . . . ) and water treatment additives (ammonia, hydrazine, cyclohexylamine,morphol ine,

chelants, phosphates, polyphosphates . . .)

Specific chemical systems for which properties are most needed include

water and steam solutions of:

° NaOH, silica, chlorides, sulfates and other sulphur compounds,

carbonates, fluorides, borates, iodides

° Volatile and nonvolatile pH control additives, oxygen scavengers,

and H2O2

° Ions of structural metals (Fe, Cr, Ni , Co, Mo, Mn, Cu, Zr, Zn)

such as Fe'’"^, Fe+^, HFeO-^ and other hydrate species, Cr+ 2

, Cr04 " 2

, HCrO"^, Ni+^, NiO"^, cobalt species obtained from radioactive transport, etc.

° Metal oxides, mixed oxides, and hydroxides

In addition, mention was made of chemical cleaning agents, colloids, and

some organic substances. The following cations and anions were identified

as of importance by one or more working groups:

Cations Anions

Aluminum Borates

Ammonium Carbonates

Cal ci urn Carboxyl ates

Chromium Chi orides

Cobal

FI uorides

Copper Hydroxides

Hydrogen Iodides

Hydrazinium Ni trates

Iron Other Organics

Lithium Oxides

Magnesium Phosphates

Manganese Polythionates

Molybdenum Sil i cates

Nickel Sul fates

Potassium Sul fides

Sodi urn Zi nc Zirconium

5
4. Equations should be developed to provide detailed thermodynamic

data under conditions found throughout the power cycle. Ideally, this

would include not only the fluid phases but the surface phases on structural materials, although the latter would represent a longer-term goal.

A variety of output mechanisms should be considered including tables,

graphs, formulations, handbooks, and automated outputs such as tapes and

possibly on-line services.

Conclusions and Recommendations of the Working Groups

Working Group I, Reactors

Chairman: D. Cubicciotti, EPRI

Secretary: V. Parker, NBS

Participants: Do Garvin, NBS

Do Schl uderberg , Babcock and Wilcox

Jo Hicks, Babcock and Wilcox

After a general discussion by Hicks and Schluderberg on the types of

problems encountered in the various components of the PWR's and BWR's, we decided to concern outselves primarily with the problems associated with

the presently operated PWR's. The data needs and uses are in the areas

of:

1. Deposition of solids (more important in the secondary circuits)

2o Vapor transport • 3. Corrosion redox reactions

4. Chemical cleaning

The specific important components for each category are detailed in this

report.

The types of thermodynamic data needed are those that define the chemical

stability of the various components presently known to exist or those

possible by virtue of the conditions present. The A^G°(T), solubilities,

equilibrium constants, and the activity coefficients, AfH°(T), S°(T),

C°(T,P), V(T,P) in the range room temperature to 700°F, and P range up to

2§00 psi are needed.

A strong comment was made by the Chairman that useful data need not just

be "hard" good accurate NBS-type data, but estimated "rough" ballpark

engineering estimates that will indicate limits, i.e., the importance of

the species or the potential reaction that might be occurring.

6
In addition, methods are needed for estimating the above-mentioned

thermodynamic properties for immediate use by the engineer.

Specifically, data on the following species and their derivatives are needed:

1 . a) For the input system, dissolved in H 20 (ji), LiOH(aq),

0H“(aq), H

2

B 02 (aq), and BO^ ion, and other B ions or species.

b) In the steam phase, solubility of H2> O2, N2, H2O2, I species

are needed.

2 . In solution, information is needed on the ions of the struc-

+2 +3

tural metals, Fe, Cr, Co, Ni , such as Fe , Fe , HFeO^, and

+2 -2 -

^ other hydrated species, Cr ’ CrO^ , HCrO^, etc. Cobalt species

obtained from radioactive transport, Ni , and other oxygenated

_2 species such as Ni 02 , as well as Mn and Mo species.

In addition, properties for SO^, SOZ, S2O2, S.Og, HS~, S , H2S, and other

possible S species in solution^are needed.

Of secondary importance, information is needed on complexes formed with

the structural metals by Cl", OH", F", or the additives such as EDTA,

citric acid, picric acid, resins, CCK, as well as on the I species in

solution (I", lO^).

3 . In the solid phase, information is needed on the colloids transported, the passive films formed, as well as the corrosive films

and tfie nature, structure, and thermodynamic differences of these

films from the crystalline material.

The mixed oxides, spinel type of Fe-Ni, Fe-Cr, Li-Zr, Mo, Mn are a particular concern. Mixed chloride oxides of the structural metals are important, as well as the sulfides of the structural metals. (Is it

possible that MoS2(c) + ^ 20(1 or g) forms H2S(g) under operating conditions?)

Of secondary importance, information on the following compounds is needed:

AI2O2, AHOH)^, Si 02 » CaSO^, CaCO^, MgSO. , a and y FeOOH, CrOOH, and FeOCl

,

which are involved in the corrosion films.

The thermodynamic properties of the various colloidal material are needed,

as well as those resins formed containing and NH2 groups.

7
The direct emphatic answer to question 6: Is a data center for chemical

thermodynamics in steam power cycles necessary or highly desirable: YES,

All five participants agreed.

As has been indicated, this data center should include estimates as well

as "firm" values.

The output (question 5) from this data center should be tables of data

and/or equations. The output should be compatible (units, conventions,

reference states, etc.) with other well-known thermo-data centers' output.

Estimation procedures (a how-to manual) should be another output. Some

interest was also expressed for computer tapes. Pourbaix diagrams were

not considered to be a primary output but to be something to be derived

from the evaluated data giving the thermodynamic properties, e.g.,

C , A^H°, K^, etc., cited earlier.

8
Working Group II, Steam Generators and Boilers

Chairman: P. Bryant, Combustion Engineering

Secretary: J. Oscarson, BYU

ParticipantsM. J. Angwin, EPRI

J. W. Cobble, San Diego University

P. Colombo, Nalco

P. Cohen

J. Cooper, Naval Research Laboratory

F. Gabriel li, Combustion Engineering

J. Kruger, NBS

J. Leibovitz, NWT Corp.

R. Mesmer, Oak Ridge National Laboratories

G. J. Theus, Babcock and Wilcox

R. Wood, University of Delaware

1. We focused almost entirely on concentrated solutions because the

consensus was that corrosion problems in PWR steam generators and

fossil boilers are primarily associated with heated crevices: viz,

evaporation and concentration of salts.

After considerable discussion, the following parameters were considered

to be of greatest importance: pH, solubility, and redox potential.

The practical product therefrom is generation of Pourbaix diagrams

which can provide a predictive capability for corrosion of steam

generator or boiler materials in concentrated salt solutions prevalent

in heated crevices.

2. Salts of chlorides and sulfates as well as pH control additives in

concert with the oxides of the metals of construction were considered

the constituents of prime importance.

The following were chloride compounds identified as most important to

put in the data base (some may already exist and need to be reviewed,

whilst others may need to be measured): FeCl-, CuCK, MgCl^, NaCl

,

HCl, NH^Cl, NiCl^. ^

Other chlorides of less import but worthy of evaluation include:

CuCl , CrCl

2

» and CaCl

2

.

Similarly, most important sulfur compounds were identified as follows:

Na2S0^, FeSO^. J2S0^, Na2S202, MgSO^, and (NH^)2S0^.

Alkali pH control additives were as follows: NaOH, Na^CO^, Ca(OH)-,

and

9
Complex mixtures were considered and judged important because they

represent reality. Three complex systems were recommended on which

to initiate studies:

a) Na2S0^, H2S0^, NaCl mixture

b) FeCl

2

» HCl , Na2S0^ mixture

c) HaOH, H^PO^ mixture

Solids in contact with the saturated solutions need to be considered;

of prime importance are the oxides of the materials of construction

plus copper-copper oxides and the following salts: CaSO^, CaCOo,

and Mg( 0 H)

2

.

Solids which should be considered include oxychlorides and oxysulphates

of the transition metals plus precipitated solids.

In the steam phase, solubilities of the following hydrated species

need to be addressed: NaCl, Na2S0^, NH^, H2S0^, HCl, Si02>

and copper compounds.

These needs cannot be real istical ly met with existing measurements and

correlation techniques. New measurements by and large must be initiated.

4. Colloidal interactions and ion exchange characteristics of the oxides

on the materials of construction represent special data requirements.

5. Tables, as well as computer tapes, of the standard free energies of

all species (in solution) and the free energies as a function of ionic

strength plus free energies of the solids at P^n-r recommended.

Free energies of gaseous species as a function^of pressure are necessary.

Finally, all data are needed from 25 to 550°C.

6. The answer to this question is "yes;" although not discussed in the

context of this meeting, it is my personal opinion that resources allocated to quantification of the above thermodynamic properties

need to be put in perspective with resources required to understand more fully operative corrosion mechanisms in nuclear steam generators

and fossil boilers.

10
Working Group III: Turbines

Chairman: W. T. Lindsay, Jr., Westinghouse

Secretary: G. C. Gould, GE

Participants: J. Has tie, NBS

0. Jonas, Westinghouse

T. Passell, EPRI

J. C. Pei per, Arizona State U.

R. C. Spencer, GE

B. Staples, NBS

Answers to questions given to chairmen:

1. What would an ideal thermodynamic data base for your topic contain?

Substances, properties, reaction, ranges of temperature and pressure,

other parameters such as pH, p02> emf?

la. Substances One problem is to narrow down the list

Lithium

Sodi urn Potassium

Ammonium

Magnesium

Cal cium

Chromium

Manganese

Iron

Nickel

Copper

Zinc

A1 umi num

Etc.

Borates

Carbonates

Silicates

Nitrates

Oxides

Hydroxides

Phosphates

Sul fates

Sul f ides

Chlorides

Carboxyl ates

Other Organics

Etc.

And mixtures too!

lb. Properties

1) Chem. Potential of pure substances and their

Activities mixtures in all phases

2) Phase Equilibria

Liquid-sol id-vapor

Phase diagram

Table of K's

11
3) Physical Properties

Surface tension

Density

Ic. Parameters

5500 Psig 400 Bars

O-IO" Hg .03 Bars

T: 1200°F 600°C

30°F o°C

12
2. Is treatment of complex ions, hydrolysis of ions, complex mixtures

involved? What are the most important cases? How would you suggest

that they be treated?

Hydrolysis in aqueous phase

Mixtures are very important

Important Cases: Si02 - CuO - CU2O - Na20 - Fe^"'’ SO3 - NH3 - FeO - PO4 - CO2 - Cl - O2

H2O system

How to Treat: Start single (binary) and build (complex)

Use interactive model (Pitzer)

Questions of speciation need to be addressed

(Sol ution Model

)

Important Complexes: Chloride, hydroxyl , and others from the list

above.

3 . To what extent can these needs be met with existing measurements

and correlation techniques, and what new measurements must be made

and what new correlation and prediction techniques developed?

NaCl and NaOH are probably the best explored but still only 60 percent

of data.

What new is needed?

° Low pressure solubility

° Hydrolytic dissociation NaClg + H20g 3: HClg + NaOHg

Techniques: Modern spectroscopic technique

(Raman, laser, etc.)

Flow micro-calorimetry

Development of more reliable

predictive techniques.

13
4. Are there any special data requirements introduced when interfacial

phenomena and corrosion are considered?

° Surface energy

° Ion-solid interactions

° Adsorption

Corrosion is the main problem

Need: Redox potential

pH

(Pourbaix diagrams)

5. What kinds of data products would you find most useful? Tables?

Figures, e.g., Pourbaix diagrams? Computer tapes? "How to calculate

it" data books? Would you expect the reliability of the data to be

evaluated?

° On-line, interactive, computer access

° Figures (Pourbaix diagrams, etc.)

° Tables and equations

° Access to the original data

° Books

° Computer tapes

6. Do you think that a group devoted to preparing such data products

(a data center) is necessary or highly desirable?

YES!

14
Working Group IV: The Pre-Boiler Cycle

Chairman: E. E. Coulter, Babcock and Wilcox

Secretary: R. N. Goldberg, NBS

Participants: 0. Jonas, Westinghouse

J. Kelly, Nalco

K. Lehner, Wisconsin Electric Power

M. Maddagiri, Bechtel Power

W. Marshall, Oak Ridge National Laboratories

F. Pocock, Babcock and Wilcox

Conclusions

1. Erosion and/or corrosion and tfie contaminants thus formed are the most

important problems in the pre-boiler system.

2. The prevention or minimization of corrosion products must be addressed

during fabrication, storage, outages as well as during the operation

of the boiler. These problems must also be addressed by the system

designerso

3. A wealth of data exists on the rates of corrosion of various materials

under various conditions. Some of the pertinent knowledge is important,

but has not or perhaps cannot be easily quantified. Examples include

exfoliation and erosion by moisture.

Recommendations

1. That a retrievable information base be established which consists of

both quantitative and qualitative data. The qualitative types of

data include:

(a) the behavior of additives

(b) the characteristics of alloys (e.g., the degree of exfoliation

and erosion by moisture droplets in high-velocity steam.

(c) specific failures and operating characteristics of various types

of boiler systems.

(d) economic, health, and ecological aspects of boiler technology.

15
The quantitative data should have as its aim the ability to predict the

chemistry (i.e., the amounts of species present in a given system) likely

to be found under various types of boiler operation. The physical quantities of concern to such a data base include both kinetic and equilibrium

data. There is also a need for interpretive programs which can be used

with the data base to calculate amounts of species under a wide variety

of temperatures , pressures, and compositions (i.e., the data need to be

made as useful as possible).

2. That a number of power plants be "fingerprinted" as to composition of

boiler water at various locations in the plant so that one can understand

for such a system of plants how the materials interact with the environment and how the contaminants migrate through the system.

16
PRESENTATIONS

Introduction R. Spencer

Water and Steam Chemistry Seesion

Power System Chemical

Transport

Waterside Corrosion and

Its Control in Fossil

Utility Steam Generators

Water Quality in Boiling

Water Reactor Cycles

Turbine Steam Chemistry

Reactor Chemistry

Chemical Thermodynamics Session

Basic Aqueous Chemistry at

High Temperatures and

Pressures at ORNL

Aqueous Solutions at High

Temperatures

Distribution of Chemical

Species Between Water

and Steam

Thermodynamics and Electrochemistry of Corrosion

Correlation of Data for

Electrolytes in Water

and Steam

Evaluated Data and Data

Bases: Chemical Thermodynamics in the Steam

Power Cycle

Collateral Activities

C. Jonas

F. Pocock

G. Gould and M. Maddagiri

W. T. Lindsay, Jr.

P. Cohen

R. E. Mesmer and W. L. Marshall

R. Wood

P. Cohen

G. The us

J. Peiper

D. Garvin

EPRI and ASME Research Committee on Water in Thermal

Power Cycles C. Jonas

lAPS and ASME Research Committee on the Properties

of Steam H. J. White, Jr.

17
Introduction

Robert C. Spencer

General Electric Company

Schenectady, New York

At the end of World War II - in the mid 1940's - typical utility steam power

plant units were rated in the 30 to 50 MW size range with steam conditions of

850 pounds, 900 degrees - nonreheat with perhaps four heaters in the feedwater

cycle. Partly as a result of wartime developments, materials technology was at

a point where many advances in steam conditions and power plant equipment were

possible. Thus, the first postwar decade saw rapid advances in steam conditions

and an almost complete adoption of the reheat cycle. By the time the 1960's

rolled around, double reheat units at 3500 pounds 1 050/1 050/1 050F were in service

with several units at even higher conditions. The period also saw steam turbine

efficiency undergo rapid advancement with the introduction of the tremendous

calculating ability of the computer and advanced manufacturing capability to

make complex twisted airfoil shapes.

However, by the 60 's steam conditions and cycles had been pushed about as far as materials technology and economics then allowed. In searching for new ways

to reduce the cost of electricity, the industry turned to reducing the pounds of

material to produce a KW - the so called economy of scale. This led to larger

unit ratings - first of the cross compound or two shaft type primarily because of

generator size limitations. However, by the late 1960's larger generator ratings

became available and the introduction of longer last stage vanes/or buckets as some of us call them, permitted a rapid increase in single shaft unit ratings.

Problems with units using 1050F steam temperature became evident in the mid 1960's.

The industry backed away from 1050F and more frequently selected lOOO/lOOOF steam

temperature.

To recapture the heat rate loss due to temperature reduction, initial pressure was frequently increased to the supercritical 3500 pound level. Thus, the period

from the middle 1960's to the mid 70's saw rapid growth in single shaft unit ratings

coupled with a swing to 3500 pound throttle pressure. But by the mid 1970's,

the industry realized the reliability and availability of many of the large 3500

pound plants were not meeting expectations. With 20/20 hindsight, it is apparent

that the equipment troubles were primarily associated with the rapid increase in

unit ratings rather than the 3500 pound steam conditions. However, the more complex operating requirements of 3500 pound conditions contributed to the industry

rapidly backing away from supercritical steam conditions.

Now let me briefly step back again to the mid 1950's when research and development

into nuclear power had progressed to the point where orders for commercial

units were possible. The low pressure and temperature steam from light water

reactors provides a relatively short expansion energy range and expands almost

entirely in the moisture region of the mollier chart. The relatively large

ratings of nuclear units, the low throttle pressure and short expansion energy

range leads to large steam mass flows and even larger volume flows at both

turbine inlet and exhaust. These conditions naturally lead to the use of low

18
speed, 1800 RPM turbine generators. The high moisture content of the wet

steam expansion caused turbine designers concern about water droplet erosion

(similar to the impact type erosion of the last stage buckets of fossil

turbines) and the erosion-corrosion that could result on internal surfaces

(^washing erosion) and erosion in leakage paths (wire drawing). Also, the

magnitude of the efficiency losses associated with the high moisture levels was

a further uncertainty. Additional concerns stemmed from the rel atively unknown

effects of oxygenated steam and radioactivity upon materials. While initial

units utilized a non-reheat cycle, steam reheat was selected for many later

plants. As with fossil plants, pressures of economy of scale led to larger

units with ratings of over 1100 MW in service by the mid 1970's.

So we see that from world war II we had a brief period of rebuilding and

reorganizing manufacturing capability followed by a decade of rapid advances

in plant efficiency through the application of higher steam conditions, the

universal use of the reheat cycle and strides in turbine efficiency; that

period was followed by a decade where the cost of power generation was reduced

thru economy-of-scal e or fewer pounds of material per KW.

These advances leading to lower cost power generation were a major contributor

to the growth of the U.S. economy during this period. It would not have been

possible without the application of the most advanced knowledge of materials

behavior, the application of sophisticated computer calculated stress analysis

methods and the use of higher alloy steels and modern steel-making technology.

Together these factors permitted designs which utilized not only stronger

materials but also applied them at stresses much nearer to their ultimate

capability.

While during this period there had been periodic problems eventually

attributed to what we might collectively call water or steam chemistry - adequate and workable. Solutions were found despite the fact that in many

instances a real fundamental understanding of the problem was lacking.

However, by the mid 1970's, industry's attention was focused on the reliability

and availability of plant equipment while it simultaneously coped with

the energy crisis; air, water, and land environmental concerns; nuclear

licensing and other problems; and the increasingly difficult economic

environment.

An increasingly larger portion of reliability and availability problems seemed

to be associated with steam and water chemistry - failure of last stage buckets

pitting of components, instances of massive deposits in turbine steam paths,

nuclear steam generator problems, MSR's and now a major industry problem with

the shafts and wheels of nuclear low pressure turbines.

In attempting to understand these problems and develop solutions, it became

increasingly apparent that the state of knowledge was grossly inadequate.

Therefore, programs were put in place in this country and overseas by individual

companies, industry associations, universities, and governments. Each program

was directed to obtaining the basic data for a selected chemical solution

believed to be associated with a particular problem. In many cases, the data

gathered covered only a narrow range of parameters, was of questionable

19
quality, and all too frequently not generally available to the industry

as a whole.

The magnitude and urgency of the problem no longer will permit this

approach. Experimental data must be collected, compiled, and evaluated

on a more organized and industry wide basis. The data must not only be

evaluated but equations for correlating, interpolating, and extrapolating

the data must be developed. Those of us who have been involved in the much

simpler but similar task for pure water know that this is an effort that

will not likely be accomplished in a timely manner by any one existing

organization.

The challenge to this workshop is to develop a detailed statement of the

scope of the problem, the current state of knowledge, and a specification

of a proposed solution, which may require the establishment of a data

center to carry out these tasks.

Gentlemen - let's get on with finding a solution to this important industry

wide problem.

20
POWER SYSTEM CHEMICAL TRANSPORT

Otakar Jonas

1113 Faun Rd., Wilmington, DE. 19803

Results of field measurements of chemical transport of ionic impurities

and some theoretical considerations are presented and a comprehensive list

of chemicals found in steam systems is attached. The report gives typical

concentrations of measured species in water and steam and points to

differences between the established views and measured chemical transport

characteristics of different power systems.

The chemical transport studies, in combination with chemical thermodynamics, should provide a link between the impurity source and

local chemistry on steam cycle component surfaces which in turn could be

used to evaluate corrosion.

21

Transport of Ionic Impurities In Fossil and PWR Cycles New Observations

By Otakar Jonas, Westinghouse Electric Corporation, Philadelphia, Pennsylvania IWC-81-40

INTRODUCTION

In order to minimize corrosion of steam power system

components, sources, concentrations, chemical transport,

and local reactions and concentration processes for impurities as well as water treatment chemicals have to be known

and controlled. Over 150 chemicals have been already identified through

surveys of turbine and boiler deposits, water treatment

practices and analysis of water and steam (1 to 1 ll^Sources

of impurities and the system chemical transport have been

discussed and cycle chemistry described (12 to 22). By now, we have analyzed cycle chemistry in forty-four

fossil and PWR utility units. Eleven units were monitored

for extended periods of time, rest of the units were sampled

once at high steady load only. Steady load chemistry of

twenty units was measured as a part of the EPRI project

RP912 (11). Using advanced chemical instrumentation and liquid ion

chromatographic analytical techniques capable to analyze

low ppb ( 10“®) concentrations of impurities, we were able to measure chemical transport characteristics such as total carry-over of important ions, impurity separation in Moisture Separator Reheaters (MSRs), ionic balances, fluctuation of concentrations, effectiveness of condensate polishing, resin rinse, some transient effects, etc. Results of the above work with emphasis on new observations, together

with some related laboratory experiments are discussed in

this paper. The new observations include formation of volatile species and high vaporous carry-over of chlorides and sulfates,

hydrolysis of sodium chloride, acidification of turbine

steam, low carry-over of PO^, very low equilibrium solubility of NaOH and NaCl in superheated steam, high solubility of NH4 CI, adsorption of NaOH on dry surfaces, verifi- cation of “salt zone” and a periodic destruction of Wilson

line by an oscillating shock wave. The data suggest that some traditional views on chemical

transport need to be reviewed and that attention should be

given not only to concentrations of impunties and local concentrating mechanisms, but to the ionic balances as

well. Discussion of local transport and concentration processes and effects of system design on chemicaf transport can be found elsewhere (4, 5, 10, 1 1, 13, 14, 15, 19, 21 to 27)

and is not included in this paper. More comprehensive report with data from individual

units, including an update on deposit chemistry, chemical

thermodynamics, and sampling and analysis methods is being prepared as an EPRI Topical Report, RP912-1 (11).

WATER AND STEAM CHEMISTRY

Impurity concentrations were determined in low pres- sure (LP) turbine steam, boiler water or feedwater (feed- water in the case of once-through boilers and PWR steam

generators, and drum water or blowdown in the case of

drum boilers and recirculating PWR-steam generators). In some cases, samples from additional sources in the water/

steam cycle, such as the main steam, condensate pump dis- charge, and reheat steam were analyzed.

Due to the complex effects of transient operation on the chemistry of water and steam, the steam and water were sampled during a steady normal operation only. The results, therefore, represent typical chemistries under steady

conditions. They include Na"^. K“, NH^“. Cl". SO^-“.

P04^“, dissolved oxygen, silica, and pH data. The units selected for the sampling program were chosen

to cover different types of steam supply systems, water

treatment, condensate polishing, and condensate cooling.

Forty-two units were sampled between July 1978 and February 1980. A matrix showing distribution of the sampled

units is given in Table 1. Steam and water sampling was from the existing sample

lines. Low pressure turbine steam was sampled from a sur- face tap at the LP inlet or with a Westinghouse developed

nozzle. Liquid ion chromatography was used to analyze

sodium, ammomium, chloride, sulfate and phosphate,

silica was determined photometrically per ASTM D859.

dissolved oxygen was measured by the indigo-carmine

method, pH was measured on site with a portable meter. Chemistries of individual units are included in the Topical Report (11). Summary of the data (averages, maxima,

minima, LP steam to blowdown ratios and sodium to anion

molar ratios) are listed in Table 2. A distribution of the average concentrations of chloride, sulfate, and sodium for major unit types and for all the 42 sampled units is given in Table 3 and Figure 1. Because of the inherent scatter of

individual data points, unit averages were chosen as more

meaningful for this statistic. Sulfate distributions are added

for comparison and because a sulfate limit may be intro- duced in the future. Results of sampling around the cycle

of a 480 MW, 3500 psi, once-through supercritical fossil unit with Powdex condensate polishing and salt water con- denser cooling are shown in Table 4. The high levels of

chloride and sodium indicate a presence of cooling water

impurities and unsatisfactory performance of the condensate polishers. Hotwell cation conductivity of 0.35 ^S cm

supports this observation. The polishers apparently remove some NH4 but add sodium and chloride. Repeated samples

of feedwater show small chemistry variations, but the

TABLE 1 Plant Distribution Matrix

Uatar Treatment Condensate Cool ino

Salt

i Cool Ini Bolltr Typ« AVT Sracltlsn Fresn Tower

Orun 14 3 6 6 5 Fossil Onca-Ctirough ” 14 6 7 1

Raci rculating S.S. 9 S 3 1 PVR Onca-throuqh S.G. 2 . 1 1 Total 14 28 17 17 8 Reprinted from the I’roreedings or the

42nd Lntern.i t Lena 1 Water ton t c rence , Pittsburg, PA 1*^81 with permission

C International Water Conference

)*Appendix A

22

TAIJLE

2

Siimiiiiiiy

of

Analytical

Kcsiills:

Steam,

I'cedwatcr

ami

Iluiler

Ulnwdowii

CNfcO O & — &

S

tn o

o o o O

o o o

e o

o ir>

CM O «n o V «M

to CM «*>

P«> 91 to

o o o csj m M

to

8 “ 2

o u

«« <1 c o >

> « « ^ o

e e o

V

o o o

to O O to

to o a « to Cl ^

«i« to CM

I ^ M OJ

• • W o

( e o > M ^ o

to O CM A 91 O

S 3 S

e o o ^ O r«* CM lO

09 to «-• e CM o

<nM

o o CM ««

O CM to

tn mm (O O

9» M e «

> m t < X X ^

o e o ^ 91 — V CM

to91 O

A dO « to V

e o CM

CM O ^ lO tO 00 ^ ^

•• o o M CM

V* > 882 91 to CM

to <n

91 91 O

toV to O

< * • . 91 M e

^ <o « 91 to

S O CM

tO —

eto CM CM

23

*Averi 9

c

of

unit

<ver«ges

**Hcil4r

Rillo
3 =

- J ^ J 100-

90»- 60K

•*0 r

2or

0

*-

N«

<3 <5 <10

Concentration, ppo

<20

All Units PWR-Hec

Drum - PO4

Once Through

- AVT

FIGURE 1 Statistical Distribution of Unit Averages with Respect to Con'

centrations in Steam

Steam samples show typical fluctuations. The unit has

known condenser tube corrosion problems (copper alloy),

high air inleakage, turbine corrosion and erosion problems

and high levels of suspended oxides. To keep oxygen and

pH under control, high dosing of hydrazine and ammonia

is used. This tends to decrease the exchange efficiency

of the condensate polishers and adds to condenser tube corrosion. The results of a more extensive sampling program in one

fossil drum boiler unit (KA6) are given in Table 5. The unit

IS a 626 MWc, 1900 psi, drum boiler unit with condensate

polishers and a cooling tower. It uses phosphate boiler

TABLE 3 Number and (Percent) of Steam Chemistrv’ Averages Within

Range

Sanqe (poB) Unit No. of

Ion Type <3 <5 <10 <20 Units

Cl ORUM/PO46 (43) 10 (71) 13 (93) 14 ( 100 ) 14 DRUM/AVT 2 3 3 3 3 PUR. Rec. 4 (44) 5 (55) 9 ( 100 ) 9 ( 100 ) 3 PUR, OT 1 1 2 2 2 OT/AVT 5 (36) 7 (50) 12 (36) 14 ( 100 ) 14 ALL IS (43) 26 (62) 39 (93) 42 ( 100 ) 42

SO4 DRU«/P0i 5 (43) 3 (57) 11 (79) 12 (36) 14 DRUM/AVT 2 2 3 3 3 PUR, Rec. 3 (.33) 3 (.38) 6 (.75) 3 ( 100 ) 3 PUR. OT 1 1 2 2 2 OT/AVT 3 (57) 9 (64) 12 (36) 13 (93) 14 ALL 20 (49) 23 (56) 34 (33) 33 (93) 41 PO4 ORUM/PO4 4 (57) 6 (36) 6 (36) 7 ( 100 ) 7 ORUM/AVT 0 1 2 2 2 PUR, Rec. 5 (63) 7 (38) 8 ( 100 ) 3 ( 100 ) 3 PUR, OT 1 1 2 2 OT/AVT 5 (71) 6 (36) 6 (36) 6 (36) ALL IS (53) 21 (31) 24 (92) 23 (38) 26 Na DRUM PO4

6 (46) 7 (54) 10 (77) 11 (85) 13 ORUM/AVT 2 3 3 3 3 PMt, Rec. 4 (50) 7 (38) 7 ( 88 ) 3 ( 100 ) 3 PW. OT 0 0 1 2 2 OT/AVT 4 (29) 7 (50) 12 ( 86 ) 14 ( 100 ) 14 ALL 16 (40) 24 (60) 33 (33) 38 (95) 40

TABLE 4 Chemistry of the 480 MW Supercritical Once-Through Unit

Source Time pH Spec. Cond. (uS/ca)

<^2 (ppP)

Na*

(ppb)

NH,

(ppn) cr

(ppb)

soj-

(ppb) P0^‘

(ppp)

NO3

(poh)

SiO,

(ppb)

LP Steam 13:05 32 1.68 42 <1 <1 <l <10 13:14 7.5* 1.60* 10.5* 3.5* <1* <1* 13:ia 3 1.65 2 <1 <1 <1 (4th e»tract1on 13:22 4 1.74 5 <1 <1 <1 point) 13:25 8.7 (23*C) 13:30 9.6 14:30 <1

Feeilwater 11:15 9.5 9.S (26*0

11:10 7 2.1 SO <1 <1 <1 <10 11:15 7 2.5 so <1 <1 <1 11:20 4 2.6 55 <1 <1 <1 11:25 4 2,3 60 <1 <l <1 13:45 <l

Main Steoa 12:00 18 1.7 31 <1 <1 <1 <10 12:04 9.4 9.8 (26*0

Condensate 11:55 9.5 Pump Discharge 12:00 9.0 (26*0

12:12 12 l.S 9 <1 <l <1

Polisher Out 11:35

11:40 9.2 5.9 (26*0 14 0.8 IS <1 <1 <1

Deaerator Out 11:30

11:35 9.2 9.7 (28*0 5 2.1 9 <1 <1 <1 •Average of 4 determinations

24
TABLE 5

Chemistr>' of the 626 MW, 1900 PSIG, Drum Boiler Unit (KA4)

Spec. Cond. ®2 SIO7 (ppb) cr soj- poj* Ha* HH4* Source Tleie pH* (uS/cm) (pp6) (ppb) (ppb) (ppb) (ppb) (p(*») Remarks

L. P. StCM 13:30 <5 14:33 M 3.9 <S <10 3 <1 <1 10 O.Sl Duplicate analysis from

4 <1 <1 10 0.50 sane sample container

1S:11 7.0 10 4 <1 s 0.63

IS: 18 7.2 7 2 <1 s 0.61

Ha In Sten 15:0S 7.0 <10 7 3 <1 s 0.48

Orui Stean IS: 04 6.9 4 2 <1 s 0.50

Orui Hater 13:30

14:40 0.9 26.S

<S 100 40 131 2.9 pp« 2.9 PPM <5 ppb Duplicate anilysls froM

38 134 3.0 PPM 2.9 PPM <S ppb sane sample container

1S:03 8.4 100 34 132 3.1 PPM 2.9 PPM <S ppb

1S:2S 8.6 100 34 13S 3.0 ppa 2.9 ppa <S ppb

Feeduater (Econonlzer Inlet) 1S:00 7.2 4 <1 <1 12 0.50

Condensate

(Fwep Discharge) 1S:0S 6.6 <10 3 <1 <1 0 0.S5

NOTE: Concentrations are given In ppb unless specified otherwise. Other Ions of Interest, Including K^, F*, NOj, NO3

, nere belon the detection Halt, I.e., <1 ppb.

water treatment and hydrazine for oxygen scavenging. It is interesting that the total carry-over (ratio of steam to drum

water chemistry) is different for each ionic species. If we

combine the main plus LP steam data and all drum water

data, the total average carry-overs, K, are: Kq = 16%,

Kso, = 1-7%. Kpo^ <0.03%, = 0.2%, Kgio, < 10%.

Carry-over of phosphate is very low, and carry-over of

chlorides is very high. Similar carry-overs are observed in other units. Steam and water pH seem to be lower than

what corresponds to the concentrations of phosphate and

ammonia. This could be due to COo or an analytical error. Results of around the cycle sampling of a 835 MW PWR

unit (SI) with recirculating steam generators are in Table 6. The sampling was performed during an experimental boric

acid addition period and immediately following recovery from a major condenser tube leakage incident. The data

provide information on the distribution of boric acid

around the cycle. The unit has almost continual condenser

leakage and uses brackish water for condenser cooling.

With no polishers, the chemistry is controlled by blowdown. It is noted that some of the sodium, chloride, and

boron are separated between the HP steam and LP turbine

by the MSRs. This is a recorded feature of the PWR cycle

design (21). The main observations derived from the steam, blowdown and feedwater chemistry data representing a “one

moment” chemistry of a unit operating at a steady high

load are:

1 . Average concentration {group averages) of chlorides, sulfates, phosphates and sodium in LP steam is less than 10 ppb in all types of unit sampled. Chloride average is highest in once-through fossil turbines (5.1 ppb), sulfate average is highest in PWR turbines (9 ppb), sodium av- erage in drum boiler, PO, turbines (8.5 ppb). Average

ammonia concentration is highest in the fossil OT units

( 1 100 ppb), average silica is about the same for all units,

average oxygen is highest in PWR—recirculating units (12.8 ppb) but more oxygen data is needed for better confidence. Average pH is lowest in the drum, PO^ units

(7.6) and highest in the fossil OT units (9.3), consistent

with the ammonia concentration.

2. Frequency distribution of unit averages for chloride, sulfate, phosphate and sodium in low pressure turbine

steam is in Table 3 and Figure 1. The averages are dis- tributed into four groups (<3, <5, < 10, and <20) cor- responding to different steam purity limits (<3 is for information only) for sodium and chloride (5). 71% of

drum boiler PO4 units meet the chloride limit of <5

ppb, 54% meet the sodium limit of <5 ppb. Only 50% of

TABLE 6 Water and Steam Chemistry of the SI PWR Recirculating Unit

During a Boric Acid Addition E.xperiment

Sampling Point

Ha (ppb)Cl (ppb) SO*

(ppb) SlOj(ppb)

B*

(ppm) pH

Steam Generator A Blowdown770 1220 159 120 5.85 3.25

Steam Generator A

)f> Steam Condensate

32 28 4 <30 0.21 3.95

H? Drain Tank** 30 14 8 <30 0.32 3.75

LP Steam Condensate 16 9 7 <30 0.C4 9.15

Condenser Hot Well 4 10 5 <30 0.04 9.00

•determination of H38O3 as boron. ••Collects MSR drain In addition to condensate from HP turbine extraction steam used In reheater and certain feed water beaters.

25
oncc-lhrough fossil and 55% of PWR recirculating units meet the <5 ppb chloride limit. For all units together,

about 60% meet the chloride and sodium <5 ppb limit and more than 80% meet < 10 ppb limit. This shows that the <5 ppb limit for normal operation can be met but that a significant number of units need to improve the purity of steam.

3. Blowdown concentrations in drum boiler and PWR re- circulating units reflect the typical 3 to 10 ppm level phosphate treatment in most fossil units and AVT treat- ment in few fossil and all sampled PWR units.

4. Feedwater concentrations in fossil once-through units are similar to the steam concentrations, with ammonia

and pH higher in steam due to the decomposition of

hydrazine.

5. Carry-over from a boiler drum or a PWR recirculating

steam generators is indicated as the ratio of LP steam to blowdown in Table 2. In many units (but not all), the carry-over of chlorides and sulfates is much higher (up

to 6*0%) than e.xpected from the ’‘classical” considerations of mechanical and vaporous carry-over. It seems to increase with ammonia concentration. Carry-over of

sodium is low, indicating low mechanical carry-over. It

is interesting to note that a drum boiler AVT unit using

morpholine, which had an average 1 150 ppb of chloride

and 1435 ppb of sodium in the blowdown had also low

carry-over (0.21%) of chloride. This is consistent with

the distribution coefficient of NaCl. Other units, with

much lower concentrations of chloride, even those bal- anced in the blowdown by sodium, have a much higher

carry-over of chloride. The difference between the carry-over of sodium

(low) and anions (high) causes a change in the chemical

balance from drum water to steam and acidification of

turbine moisture and deposits. Similar effects were observed during chemical monitoring at the Arkansas

Power & Light, ANO-1, PWR once-through unit (8, 18). where more sodium was separated in the MSRs and a higher proportion of chlorides and sulfates was carried

into the LP turbine. The above observations are significant. They indicate

that the reduction of drum water impurities does not always reduce their concentration in the steam. While

ammonia may be sufficient to prevent corrosion in the

single phase liquid environments, it may not always be

adequate for turbine protection when corrosive anions

are present.

6. Inherent scatter of concentrations of ionic species can be

observed in many units. It is observed in both methods

of sampling (cartridges, bottles) in steam, feedwater,

and blowdown samples. As the multiple analyses of some samples show, the scatter is not due to a poor analytical accuracy. We don’t know what causes the scatter.

It could be an effect of sampling where plated out impurities break loose and make the sample nonhomogenous,

adsorption of ionic species on oxide particles, erosion of

deposits on blades and boiler and MSR tubes, or oscilla- tion of the wet-dry transition somewhere in the system

causing periodic washing and drying.

Due to this inherent scatter, collection of a single sample may not prove to be a meaningful representation of

the average chemistry. More detailed study of this scatter and a microscopic analysis of deposits and sus- pended particles is needed to evaluate whether the chemical -transport by particulates is significant.

7. Sodium to anion molar ratios were calculated for some

units for steam, feedwater and blowdown. The LP steam

ratios in drum boiler and PWR recirculating units are much lower than the blowdown ratios, indicating acidi- fication of the steam. Most of the steam ratios are less than one, some are extremely low. This is consistent

with the observation of higher carry-over of anions than

of sodium. In the turbines with low sodium to anion

ratio (assuming the absence of cations other than ammonia), the protection of metal surfaces against acid

corrosion is dependent upon the concentration of ammonia at the surface.

8. Sodium to phosphate molar ratio in the drum, PO^ units varies in blowdown and steam over a wide range. In steam, it is often higher than in the blowdown (for ex- ample, unit KA4, 4.0 in blowdown to >27.5 in steam),

sometimes lower.

9. Boric acid distribution in one PWR recirculating unit follows the following ratios; blowdown: HP steam: LP steam = 5.81 : 0.21 : 0.04

SOURCES OF IMPURITIES

This brief discussion is included for completeness of the chemical transport picture, to describe some of our field observations and to attract attention to some neglected

sources of impurity ingress.

Major sources of impurities are shown in Figure 2. Good

progress has been made in the control some of these, particularly in PWR units. In many units, condensers have been

retubed with better tube materials and more sensitive leak

26
detection methods are being used. The operation of condensate polishers is improving, but leakage of chlorides, sul- fates and sodium is still marginal in too many units. Quality control programs for regeneration and water treatment chemicals is being implemented to limit (mostly) chloride

contamination.

Condenser leaks are the most frequent source of impurities in the U.S. utility units (28-29). Depending upon the chemistry of the cooling water, they can result in either acid or caustic contamination of the steam system. Good treat- ment of the effects of condenser leakage on boUer water

chemistry is in (15 and 30). We have observed changes of

system chemistry during condenser leaks. In one case, in a once-through subcritical fossil unit with condensate polishers in NH4-OH form, chlorides and sulfates in all streams

increased about tenfold for 24 hours during power operation with coincident condenser inleakage.

A typical effluent chemistry of a deep bed condensate polisher is shown in Figure 3. This is for a polisher in H-OH

form with resins regenerated by sulphuric acid (cation) and

sodium hydroxide (anion). After introduction into service,

insufficiently rinsed polisher resin releases excess regenerants (usually sulphuric acid), and cation conductivity and

sulfate are high. Towards the end of a service cycle, silica increases, and when the cation resin becomes converted to the ammonia form, sodium increases. Fouled resins have

poorer rinsing characteristics. Anion Leakage from ammonium form polishers in- creases with increase of the influent pH (31-33). Mixed bed

polishers in the H-OH form which are operated beyond

ammonia break-through can unload much of the ex- changed anions when the influent pH is high. Another

source of the anions can be a contaminated caustic regenerant (See Figure 4 from Ref 33). Condensate polishers, both powder and mixed bed

types, can leak resin fines which decompose to yield sul- phuric and organic acids capable of causing corrosion. Up

to ppm concentrations of fines have been found, resulting

in pH drop and cation conductivity increase.

8

«/»

FIGURE 3 A Typical Deep Bed Polisher ElUuent Chemistry

PPB

pH9.S

?H9.2

pHS.a

PPM

FIGURE 4

Chloride Concentration in the Ammonia Form Deep Bed Polisher

Effluent vs. Chloride in the Cau.stic Regenerant and pH (33)

Our recent survey of air inleakage revealed excessive levels of air ingress at most of the surveyed units. In different

units, the air inleakage varied from 1 to 160 SCFM. West- inghouse recommendation is 1 SCFM per 100 MW electric capacity. In 36 U.S. units, 29 experienced gland seal sys- tem leaks, 20 leaks between condensers and UP turbines

(boot), 17 flanges, hood and expansion joints leaks, and 12 leaks through manways. Air inleakage is harmful because

of the copper oxide formation before the oxygen scavenging by hydrazine, and their subsequent contribution to steam generator and turbine corrosion, the formation of

carbonic acid and carbonates which can cause stress corro- sion of low alloy steels, and condensate polisher exhaustion

by carbonates and subsequent release of some of the ex- changed anions of lower«selectivity.

Makeup water can bring not only the impurities not re- moved or added by the makeup system, but it periodically,

during makeup additions, introduces dissolved oxygen (up

to several ppm) and carbon dioxide. We have also wit- nessed the introduction of chlorine from chlorinated con- densate storage tanks and organic inpurities where organic

growth in the storage tank was present.

Organic impurities are often poorly controlled and their

effects on corrosion underestimated (7. 34). In high pressure, 1000° F. utility systems, all organic materials eventually decompose, forming organic and/or inorganic acids

and COo. Dichloroethane. C.jH^Cl.,. (used in insecticides)

and carbon tetrachloride. CCI4

. start to decompose in water at '-150°C (300° F) and 14 ppm concentration in water can change pH from neutral to 3.5 (34). We have

found up to 8 ppm of total organic carbon in some units. Identified organic compounds include: oils, insecticides,

acetic, formic, propionic, and butyric acids, and carbon tet- rachloride. We have, however just started a more systematic monitoring of organics.

CHEMICAL TRANSPORT

How impurities and additives concentrate from ppb or ppm average levels, how they are transported from their sources through a power system, and how they react with

27
system metals are factors that govern the system corrosion,

erosion, thermodynamic efficiency, performance of con- densate polishers, and other parameters.

Chemical transport can be divided into system transport

and local transport processes. The system transport is gov- erned by the flow of water and steam, chemical reactions in the bulk water, separation of chemicals in the boiler (mechanical and vaporous carryover), blowdown, separation of

gases in condensers, and condensate polishing. Local processes are governed by local flow conditions, temperature

gradients, geometry (such as crevices), state of oxidation,

solubility, volatility, water chemistry, corrosion, etc. The new observations discussed in the section on Water

and Steam Chemistry' effect both, the system transport, and

the local processes.

Ideally, ingress of impurities from their sources should

be in balance with their removal by the impurity removal

systems such as condensate polishers and boiler blowdown

system. Otherwise, impurities will accumulate and concentrate which usualy leads to problems. However, most of the

time, system components and the whole power system are

in a transient mode with time periods of transients varying

from years (chemical cleaning), to months or weeks (startups)

to days (load changes, polisher exhaustion) to hours (superheat and reheat temperature fluctuations) to fraction of a second (dynamic flow processes, evaporation, condensation. shock wave). Some of these transients can result in short term local concentration of impurities and should

therefore also be controlled.

In this section, we will review the transport of ionic impurities. combining new observations based on the field and laboratory data with some previous descriptions.

A schematic description of a drum boiler unit chemical

transport is shown in Figure 5, and a once-through PWR

unit in Figure 6. Important processes governing chemical transport in- clude; Solubihty in water

Deposition of salts and oxides from water

Deposition from steam

FIGURE 5 Chemical Transport in a Drum Boiler Unit

FIGURE 6 Chemical Transport in a Once-Through PWR Unit

•Separation from water to steam (mechanical and va- porous carry-over)

•Volatility

•Chemical reactions in water, steam and in concentrating solutions

•Chemical reactions in oxides

•Ionization, dissociation, hydrolysis, and hydration

Adsorption and absorption by oxides and other surfaces Capillary condensation and boiling in oxides

Corrosion

Ion exchange (resins and oxides)

Drying and washing

Evaporation and condensation

Deaeration

Based on the recent data, some traditional views of the transport processes should be reviewed: in particular the processes marked by an asterisk in the above list.

SEPARATION FROM BOILER WATER TO STEAM

The presence of impurities in steam is mainly due to the mechanical and vaporous carry-over. Mechanical carry- over is the entrainment of water droplets with the steam

leaving a boiler drum or a steam generator. It is controlled by moisture separating devices, water level, separation velocity and other design features of steam generators. It also depends upon water chemistry and is sensitive to impurities causing foaming, such as oils and other organics. Prior

to about 1940, it was not believed that high pressure steam may act as a solvent for inorganic compounds with very low vapor pressure, such as salts and hydroxides (35. 37). This belief was dispelled by the experiments of O. Fuchs

(35-36) and others, and by problems with turbine deposits.

Data on volatile carry-over (distribution ratio, constant, or

coefficient, partition coefficient, etc.) have been measured

by now for a number of compounds.

For constant concentrations and without reactions

28
changing chemical species, the distribution ratios (apparent, molecular, and ionic) depend only on the ratio of water

and steam densities p (see Figure 7): = •'

n is a constant for each chemical compound.

According to the accepted theory (22, 38) the apparent

distribution ratio for salts, K^pp = Cj/c,^, is variable

and depends not only on the densities but also on concentration. It includes molecular (k^j) and ionic (k^) distribu- tion ratios and is a function of the degree of dissociation

of the electrolyte in steam water (a^, a^), dissociation constants (k^, K^), mean activity coefficients of the ions in steam and water (fg, f,„), and concentrations (Cg, c^):

j. ^ ^s) ^ 2 "c^(l -a^)”‘

1^ _ ^

^d.s ^ Ki.

^

= k„(> - + ki “I

Due to their hydration, ions pass from water to steam

less than weakly hydrated molecules. If the solubility of the

ionic form in steam is negligible (Og — 0), we get the true

distribution ratio = Cg/c„ (undissociated). Chemical

compounds in a mixture with salts which can react with, or, alter salt dissociation or hydration will also alter the distri- bution ratios. The dependence of apparent molecular and ionic distri-

.2 o

<0 CM Q. CO ooooo OOOOO oo_ _ o_ co^o-n’o oo o CMCMCMi-1- o-v CM

oaeg >

FIGURE 7 Steam-Water Distribution Ratios

bution ratios on the concentration of NaCl in boiler water

is theoretically treated in (38). The lower the concentration,

the lower the apparent molecular distribution ratio. .At 2350 psia (160 ata) pressure, both ratios are equal at concentration in water of 10 ppm. From 1000 ppm to 0.1 ppm,

the total distribution ratio drops about two orders of magnitude (see Figure 8). This is because at low concentrations, the degree of dis- sociation in water is high and the distribution ratio of ions low. At high concentrations, the degree of dissociation is low and molecular carryover prevails. This is similar to the behavior of weak electrolytes such as AI0O3 and SiO,.

In most power stations we have monitored, the measured

separation or distribution of chloride and sulfate anions

between water and steam (Table 2) has been found to be

orders of magnitude higher than estimated from the distri- bution coefficients for sodium and calcium salts reported in the literature (5, 22, 39 to 41), (see Figure 7). This may be due to sampling or analytical errors, formation of volatile chloride and sulfate compounds such as ammonium salts and acids, and/or systematic errors in the

literature data. Mechanical carry-over was not the cause. Low ratio of sodium in steam to sodium in blowdown indi- cates that it is low. Our sampling and analysis could have added scatter to the data, but it is unlikely that errors were introduced

which would change the overall conclusions. Similar observations were made in units sampled once, and in those

sampled several times over a period of several months with

samples continuously flowing. The analysis for sodium is very reliable and even with a possible systematic error in

FIGURE 8 Dependence of Molecular and Ionic Distribution Ratios on NaCI

Concentration in Water.

I — 195 ata

I — 160 ata 3— % ata

29
the analysis of low level chlorides and sulfates, their distri- bution ratios would still be high.

Formation of Volatile chloride and sulfate compounds is the most likely reason for the high distribution coefficients observed. Volatile compounds can form in makeup and

condensate polishing systems as a result of unequal re- moval of cations vs. anions, changing sodium to anion

ratio, on metal surfaces, in crevices, in oxide deposits, in low pH regions by dissociation of neutral salts, by changing

balances of reactions in water and in concentrating salt mixtures (precipitation of magnesium hydroxide from a concentrated sea salt) (15), and by hydrolysis of magnesium and sodium salts in high temperature water and solid

salt deposits in superheated regions (42-43). For instance, the conditions leading to low pH and a generation of hydrochloric acid are discussed by Turner (15) and Gamsey

(26) and illustrated in Figure 9. Hydrolysis of sodium salts, such as NaCl hydrolysis observed by Dr. Rogers (EPRI

RP968- 1 ) may be a major contributor to the high carryover even when the impurities enter system as neutral salts (for

example, seawater inleakage). In the experiments of Dr. Rogers, superheated steam was carried through solid NaCl,

condensed and analyzed. A highly alkaline deposit was

found in the precondenser tubing and the final condensate was acidic. This was observed at temperatures as low as 250“C. Similar observations were made during tests of a

boiler loop at 19.4 MPa (2813 psia), where hydrolysis of

NaCl and deposition of NaOH occurred on a dry wall of an

experimental loop (42). Hydrolysis, combined with periFIGURE 9

Solution pH vs. iNaCl Concentration and Different NaOH;NaCI

Ratios for Solutions Containing .Vlagnesium and Sodium Chlorides (15)

odic washing and drying of salt, such as may occur in su- perheater tubes, can lead to a periodic release of hydrochloric acid, followed by washing of sodium hydroxide.

Salts deposited in turbines can also hydrolize. In fossil tur- bines, the inlet temperature is typically 1000’ F (538°C)

and according to the above data, hydrolysis is still possible

at 480° F (250°C) which is well within the low pressure

turbine. In nuclear turbines, hydrolysis is possible in the high pressure turbines of once-through PWR units and in the reheater and inlet stages of low pressure PWR turbines,

where the temperature is about 500° F (260°C). Sodium

chloride is frequently found in turbine deposits throughout

the superheated regions.

Review of the literature on vaporous carryover and dis- cussions with some investigators leads to the following

speculations about possible reasons for the differences be- tween the field and laboratory data:

1 . Actual boiler water composition is so different from the

single compound solutions used in the laboratory work

that the laboratory data do not apply. We are mainly

referring to the presence of volatile amines, carbon di- oxide, nitrogen (from air inleakage and decomposition

of hydrazine) and volatile organic impurities. 2. The experimental setup did not represent boiler conditions such as local concentrations on heat transfer surfaces, crevices, sludge, oxidized surfaces, etc. 3. The experiments were performed at much higher concentrations than those currently encountered and there

is an undiscovered increase of the distribution ratio at ppb concentrations.

4. Because much of the previous data was based on so- dium analysis only, there could have been higher carry- over of anions but it was not detected. We have found two references where analysis of both,

sodium and anions is reported. Rebright (44) found in lab- oratory tests that vaporous carry-over of sodium chloride at concentrations in water over 3000 ppm is stochiometric and

Martynova and Samoilov (45) found a stochiometric trans- port into steam of salts and some mixtures (NaOH -i- NaCl. LiCl -I- NaCl, NaCl + NaoSO^). This was also measured at high concentrations of salts in water. They

limited their conclusions to the pressure and temperature

region where hydrolysis is insignificant and where the salts behave as weak electrolytes in their vapor solutions, and to substances which do not react or displace the system equilibrium.

TRANSPORT OF IMPURITIES IN TURBINES

Transport processes in turbines have been described before (1-7. 19, 27. 37, 46). They include:

• Precipitation and deposition due to the decreasing solubility in superheated steam.

• Direct deposition of mechanical carry-over and oxides.

• Evaporation and drying on superheated surfaces.

• Hydrolysis.

• Changing volatility and distribution between steam and

moisture.

• Separation of soluble impurities with moisture in moisture separators and turbine extractions.

30
In addition to the new field observations described in

this paper, the following laboratory data and our field measurements of conductance within the turbine salt zone

are of importance:

• Static (equilibrium) solubility of sodium hydroxide and

sodium chloride under low pressure turbine steam conditions (47) is several orders of magnitude lower (10“^ to 10“' ppb) than the estimated dynamic solubility (few

ppb), and is not therefore applicable to the control of

steam chemistry.

• Ammonium chloride solubility under the above steam

conditions is about 100 ppm as chloride which indicates

high volatility of this salt (48). It is estimated that this

salt would not concentrate on LP turbine surfaces by

precipitation in superheated steam and deposition be- cause its concentration would not reach such high levels.

• Presence of crystalline sodium hydroxide on autoclave

surfaces and stress corrosion of some stainless steel trans- ducer casings during a steady state exposure to a satu- rated solution of NaOH in superheated steam (49) indi- cates that an unknown impurity concentration

mechanism can be active.

• Existence of liigher concentrations of salts within the predicted LP turbine salt concentration zone in the su- perheat region above saturation line has been confirmed

by surface conductance measurements in four operating

turbines (46). A lack of conductance response to the time

of exposure and to the increase of the average concentration of salts remains to be explained.

• Periodic destruction of the Wilson line by an oscillating

shock wave has been obser\’ed in a 1-D nozzle at tran- sonic steam flow conditions. This could mean that high

frequency (about 50 Hz) transients such as this exist in LP turbines (19). SUMMARY AND CONCLUSIONS

The development of new analytical techniques, such as

liquid ion chromatography and ion specific electrodes is making it possible to monitor the chemical transport characteristics of steam power systems. The sensitivity of the analytical methods to low ppb concentrations is needed

because of the water and steam purity requirements of

modem power systems.

By field monitoring of more than forty power stations, we have established typical levels of major chemical species in water and steam and found:

• Very high vaporous carry-over of chlorides and sulfates (up to 60%) and its dependence on ammonia concentration.

• Carry-over of sodium to be about what is expected for sodium salts.

• Acidification of steam due to the lower sodium/anion

ratio in steam than in drum boiler water.

• Very low carry-over of PO4 in units with PO^ treatment.

• Inherent scatter of impurity concentrations in steam and

water.

• Distribution of boric acid in PWR systems.

The most important observation is that the vaporous

carry-over of chlorides and sulfates is orders of magnitude

higher than calculated for sodium salts using laboratory

data. This has an impact upon the system, and particularly

steam and local chemistry control. Not only concentration,

but also ionic ratios must be considered when evaluating

chemistry control and corrosion effects. New observations related to impurity transport and concentration mechanisms in turbines include:

• Very low equilibrium solubility of NaOH and NaCl. not

applicable to the dynamic situation in turbines.

• High solubility of arnmonium chloride.

• New deposition mechanism (from equilibrated vapor)

for NaOH.

• Confirmation of higher salt concentration in the “salt zone” near the saturation line.

• Periodic destruction of the Wilson line by an oscillating

shock wave in a one-dimensional model of a transonic

flow. The above observations indicate that much basic data

applicable to turbines needs to be ascertained and refined. Panicularly dynamic data, data on effects of metal surfaces, and data related to local processes and transients. The system transient chemistry discussion is limited

since the amount of experimental data is small. It is possi- ble that most of the system chemical and corrosion problems may be caused by high concentration transients. The

dynamics of concentration processes in crevices and by- deposition, washing, dissolution, and hideout needs to be

better understood to improve possible control during transients. This is particularly needed for peaking units. There is a gap between the field and laboratory data and some laboratory research projects, even some currently active, do not appear to represent real life conditions (nonrepresentative chemical conditions in thermodynamic and

corrosion testing, no dynamic considerations). Published

thermodynamic data are scattered through many different journals, many are not readily available and are in foreign

languages. These data need to be collected, critically evaluated, statistically correlated, made available, and applied.

Slow progress is being made through the International Association for Properties of Steam *IAPS), Working Group

IV on Chemical Thermodynamics in Steam Power Cycles.

RECOMMENDATIONS

1 . Since the total carry-over, particularly of chlorides and

sulfates and some other chemical transport processes are not predictable, the chemical characteristics of every power system should be experimentally established.

This should be done shortly after commissioning of new

units and periodically about every five years of service.

2. Distribution between water and steam for important

chemical mixtures and compounds should be deter- mined. All ions should be analyzed in both phases and

the effects of concentration. pH. ammonia, hydrazine,

oxygen, hydrogen, hydroxide, oxides and crevices, es- tablished.

3. Due to the acidification of steam, other possible changes

in ionic balances from water to steam, and hydrolisis of

salts, turbine steam should be sampled and analyzed. .At least sodium, cation conductivity and pH should be

monitored continuously to describe transient chemistrv

4. In control of sources of impurities, more attention

31
should be given to the operation of condensate polishers, resin fines, air inleakage, organic impurities, and

purity of water treatment and regeneration chemicals.

5. The relationship between deposition and turbine steam

chemistry should be studied in an actual or a model

turbine under ty'pical power station steam conditions

representing phosphate, ammonia, morpholine and cy- clohexylamine water treatments. In-situ surface chemistry should be also measured.

6. Laboratory steam solubility programs should include’

mixtures of chemicals, including volatile amines, carbon

dioxide, and sodium phosphates. In addition to dissolution measurements, precipitation, deposition, and adsorption measurements should be performed and hydrolysis of frequently present salts should be

investigated. The deposited surfaces should be chemically and microscopically characterized. All investigators should measure solubility and deposition under two

or three “standard” conditions of pressure and temperature. Stressed specimens of several materials susceptible

to stress corrosion cracking (U-bends) should be placed

in the superheated steam space of the autoclaves in which salts are dissolving to determine whether the adsorbed corrodents can cause cracking.

7. A compilation, review, and statistical correlation of all available chemical thermodynamic data, such as solubility in steam and water, dissociation, ionization, distri- bution coefficients and chemical activities, of major

impurities, oxides and water treatment chemicals is needed for theoretical evaluation of power system envi- ronments.

8. Research on chemical thermodynamics under transient conditions, panicularly applicable to peaking units should be initiated and field experience monitored and

analyzed. Water and steam chemistry specifications for peaking operation need to be formulated.

ACKNOWLEDGMENTS

The author is grateful to the utilities who let us monitor

their chemistry, and to the Westinghouse engineers and

technicians who helped to collect and analyze the samples.

Dr. A. Pebler participated in the development of steam

sampling and in the station chemistry monitoring program.

REFERENCES

1. Jonas. O., Survey of Steam Turbine Deposits. Proc. 34th In- ternational Water Conference (Pittsburgh). 73-81 (1973).

2. Jonas. O.. Indentification and Behavior of Turbine Steam

Impurities. Corrosion 77. NACE (San Francisco). Paper No.

124 (1977).

3. Kirsch. H.. and Pollann. S.. Depo.sition of Corrosion Products in the Water Steam Cycle of Steam Generating Plants. Chemie-Ingenieur Technik. 40. 897-903 (1968).

4. Martynova. O. 1., and Rogatskin. B. S., Deposition of Salts and Corrosion Products in Supercritical Turbine Flow Sections. Teploenergetika. 17, 50-54 ( 1970).

5. Jonas. O.. Turbine Steam Purity. .Southeastern Electric E.x- change. Washington. D. C.. April. 1978. Also Combustion.

50. No. 6. 11-27. (1978).

6. Straub. F. B.. Cause and Prevention of Turbine-Blade Deposits. Transactions of the ASME, 57. 447-454 ( 1935).

7. Bodmer. M., .Acid Corrosion in Steam Turbine.s. Combustion. March 1978. p. 35. reprinted from Brown Boveri Rev.. 5. (1977).

8. Rice, J. K.. Characterization of Impurities in the Feedwater. Steam and Condensate Cycle of a Once-Through Steam

Generating Plant. Paper No. IWC-80-16. 41st International Water Conference. Pittsburgh. October 20-22. ( 1980).

9. Jonas, O., A Critical Overview of Power Station Sampling

and Analysis of W'ater and Steam. Panel Presentation. .ASTM

D-19, ASME Symposium on Power Plant Instrument for Measurement of High Purity W'ater Quality. Milwaukee.

June 9-10, 1980, will be published as ASTM—STP.

10. Jonas. O.. Turbine Steam Impurities. Paper Presented at a Seminar on Water Chemistry and Corrosion in the Steam- Water Loops of Nuclear Power Stations. .ADERP. Electncite de France. Seillac, March 17 to 21. 1980.

11. Jonas, O.. Pebler, A.. Characterization of Steam Turbine

Environment. Westinghouse-EPRI RP912-2. Topical Report,

to be published.

12. Jonas, O., Control of Turbine-Steam Chemistry. Power 125. 33-42 (1981), S. O. Strauss, editor.

13. Jonas, O.. Transfer of Chemicals in Steam Power Systems.

lEEE-ASME Joint Power Generation Conference. (Buffalo. New York), Paper No. 76-JPGC-Pwr-12. (1976) also Combustion, March 1977, p. 33.

14. Jonas. O., Transfer of Chemicals in PWR Systems: Secondary Side. BNES Conf. on Water Chemistry of Nuclear Reactor Systems, 1977, (Bournemouth), Paper No. 50.

15. Turner, D. J.. A Study of the Solution Chemistry of Boiler Water During a Condenser Leak. High Temperature. High

Pressure Electrochemistry in Ag. Solns.. NACE p. 188 ( 1977).

16. Hicks, J. H.. Mravich. N. J.. Pocock, F. J.. "Nuclear Steam

Supply System Water Chemistry Research”. Proceeding of

the American Power Conference. 33. 790 (1971).

17. CEGB. Chemical Control of Boiler Feedwater. Boiler Water

and Saturated Steam for Drum-type and Once-Through

Boilers. General Operation Memorandum 72. (1975).

18. Jonas, O., Arkansas Power & Light Turbine Chemical Monitoring. Westinghouse Electric-EPRI RP-1 124-2, Final Report, to be published.

19. Jonas, O.. Lindsay, W. T. Jr., Evans, N. A., Turbine Steam

Purity—1979 update. Paper presented at the 9th ICPS. Munich. September 1979.

20. Peterson. S. H.. Bellows. J. C.. Pensenstadler. D. F.. and

Hickam. W. M.. Steam Purity Monitoring for Turbine Corrosion Control: A Total Plant Survey. Presented at the 40th Annual Meeting of the International Water Conference.

Pittsburgh. Pennsylvania October 30-November 1. 1979.

21. Jonas. O.. Increase of Impurities Concentration in Once- Through Units with Forward Pumped Moisture Drains

Combustion, p. 20. August. 1977.

22. Cohen. P.. Water Coolant Technology of Power Reactors, Amer. Nucl. Soc.. (1980).

23. Cohen. P.. Chemical Thermohydraulics of Steam Generating

Systems Paper Presented at a Seminar on Water Chemistry

and Corrosion in the Steam- Water Loops of Nuclear Power

Stations, ADERP, Electricite de France. Seillac. March 17 to 21. 1980.

24. Mann. G. .M.. Distribution of Sodium Chloride and Sodium

Hydroxide between Steam and Water at Dry out in an E.xper- imental Once-Through Boiler. Chem. Eng. Science. 30 249- 260 ( 1979).

25. Styrikovich, M. A., and Khaibuilin. I.. Kh. Physical and

Chemical Processes in Boilers p. 11-28. Moscow. .Acad, of

Sciences ( 1957).

26. Garnsey. R., The Chemistry of Setam Generator Corrosion. Combustion. 36-44, August. 1980.

27. Lindsay. W. T., Jr.. Behavior of Impurities in Steam Turbines. Power Engineering, 68-72, .May 1979.

32
28. Nuclear and Large Fossil Unit Operating E.xperiences, EPRl

NP-1191, Project 771-4, Final Report, September, 1979.

29. EPRI Steam Plant Surface Condenser Leakage Study,

NP481, March, 1977.

30. Liebowitz. J.. Sawochka. S. G.. .Modeling the Effects of Condenser Leakage on PWR Chemistry, Paper No. IWC-80-33,

41st International Water Conference, Pittsburgh (1980).

31. Khodyrev, B. N., Shchapov, G. A., Rudnitskii, E. V., Through Removal of Chlorides From Condensate,

Teploenergetika, 17, 27-30 (1970).

32. Abrams, I. M., New Requirements for Ion Exchange in Condensate Polishing, 37th International Water Conference,

Pittsburgh ( 1976).

33. Bacon, G. W., Burgess. P. 0., Anion Leakage from Ammonium from Condensate Polishers. Stone & Webster paper

presented at ASME-Res. Committee on Water in Thermal

Power Systems, April 24. 1978. Chicago.

34. Koravin, V. A., et al. Thermal Decomposition of Organic

Impurities in Boiler Condensates. Energetik, No. 5, 24-25

( 1980).

35. Rudorff. D. W., Solvent Properties of High-Pressure Steam,

Engineering and Boiler House Review, 2-6 (Jan., 1945).

36. Fuchs, O., Action of High Pressure Steam as a Solvent,

Zeitschr. F. Elektrochemie, 47, p. 101 (1941).

37. Straus, F. G., “Steam Turbine Blade Deposits”, University of

Illinois Bulletin No. 59, June 1, 1946.

38. Styrikhovick, M. A., Martynova, O. I., Belova. Z. S., Some

Features of the Carryover of Sodium Chloride From Boiling Water into Steam, Teploenergetika, J2, No. 9, 86-89 ( 1965).

39. Styrikovich, M. A., et al. An Investigation of Salt Solubility

in High Pressure Steam, Doklady of USSR Sci. Academy 100 (6)1125-1126 (1955).

40. Martynova. O. 1.. Solubility of Inorganic Compounds in Subcritical and Supercritical Water. ‘Reprint Number: C-2. NACE Conf. on High Temperature High Pressure Electro- chemistry in Aqueous Solutions. (1973).

41. Goodstine. S. L.. Vaporous Carryover of Sodium Salts in High Pressure Steam, Proc. Amer. Power Conf.. 36 784-9

(1974).

42. Pritchard. A. M., Peakall. K. A.. Smart. E.. .A. Minature Water Loop for Boiler Corrosion and Deposition Studies Proc Int. Conf. on Water Chemistry of Nuclear Reactor Systems.

BNES, Bournemouth, October 24-27 (1977).

43. Rogers. L. B., Communications to the EPRl on R0969-1 Solubility of Corrosion Salts in Dry Steam (1980-81).

44. Rubright, M. M.. “The Stoichiometry of the Vaporous

Carry-Over of Sodium Chloride From High-Pressure Boiler Water,:” Proc. ASTM, 61. 1370-82 (1961).

45. Martynova, O. I., and Samoilov. Yu F.. The Formation of

Solutions of Inorganic Substances in Water Vapour. Russian

J. of Inorg. Chem. 7 (4), 372-375 ( 1962).

46. Steltz, W. G., Lee. P. K.. Lindsay. W. T. Jr., The Verification of Concentrated Impurities in Low Pressure Steam Turbines

Westinghouse Steam Turbine-Generator Symposium. Charlotte, October 21-23, 1980.

47. Allmon, W. E., et al. Deposition of Salts from Steam. Paper No. IWC-80-15, 4lst International Water Conference, Pitts- burgh, October 20-22, 1980.

48. Allmon, W. E., et al. Deposition of Salts from Steam, EPRl

Contract RP 1068-1 Status Report. November 1 —December

31, 1980.

49. Jonas. O., Prepared Discussion—Deposition of Salts from

Steam (Ref. 47), 41st Int. Water Conf.. Pittsburah. October

1980.

33
0. Jonas

APPENDIX A

CHEMICALS FOUND IN STEAM POWER SYSTEMS

Oxi des

*F6304

*F6203

FeO

FeO(OH)

Fe Cu O2

FeCr204

( Cr , Fe )203

*CuO

*Cu 20

CugFeaOy

CuAl O2

oAl oO-D CP203

Co Fe204

NaFe 02

Nd2Fe204

Ca (

A

1 02)2

MgFe204

*PbO

PbFe40y

Ti02

Fe2(Ti 03)3

Ca Ti O3

Na 2^

*Si02

FeAl Cr 04

*^0304

Mg0+2(Si02*H20)

Si li cates

*Na 2 Si 03

Na2Si O3 • 5H2O

Na 2 Si 03 . 9 H

2 O

3Na 2

Si 2^5

Na 4

Si 3

AI ^ 02^ 2

^^ NaAl Si O4

Na[]Al Si *H20

Iron Oxide

Iron oxide (a, y, e)

Iron (II) oxide

Iron oxide hydrate (a, 3 s y)

Copper Iron (II) oxide

Iron chromium oxide

Chromium, iron oxide

Cupric oxide

Cuprous oxide

Copper Iron oxide

Copper aluminum oxide

Alpha aluminum oxide

Chromium oxide

Cobalt iron oxide

Alpha sodium iron oxide

Sodium iron oxide

Calcium aluminum oxide

Magnesium iron oxide

Lead oxide

Lead iron oxide

Titanium oxide

Iron titanium oxide

Calcium titanium oxide

Sodium oxide

Silica (hex.-rhd., rh., tetr., amorphous)

Iron Aluminum Chronium Oxide

Manganase Oxide

Molybdenum Oxide

Serpenti ne

Sodium metasilicate

Sodium metasilicate pentahydrate

Sodium metasilicate nanohydrate

Sodium disi licate

Sodal i te

Sodium aluminum silicate

Sodium aluminum silicate hydrate

34
Nd^Al 2Si ‘ZHoO

Na 4Al 3Si 30 ^ 2 ( 0^^ Na8Al6S04(Si 04)0

Na FeSi oOg

Nag[Cl (A 1 Si 04)5]

NaAlSigOg

NagCa2l-( Si 04)g]

A 1 2Si O3

KAl Si 2^3

KNa3 Si ^4)4

KNa3(AlSi04)5

*^0 33^^0

MgiL(0H)2Si50i5.2H20+4H20

Mg6[(0H)8Si40^Q]

Ca2Si 2^4

Ca 3 Si 2^7

Ca2Al 2Si 30]^q( 0H )2

Ca2Si O4 »H20

6^17^

Ca (1 2Si 4O 2

)

*6H20

Ca2NaH[Si30g]

Ca2Al 2Si 3^]^o^ ^2

CaMg(Si205)

Ca2Mg5(0HSi 4O11 )2

3A 1 2034Na 20 *6Si O2 *S 03

Fe2Si O4

(Fe,Mg)7Sig022(0H)2

^^8^^ 6^^ 5024^°^4

MgSiO(OH)

Mg3[(0H)Si40^Q]

Zri2Si O4

ZrSi O4

Amorphous silicon compounds

Sodium aluminum silicate hydrate

Sodium aluminum silicate hydroxide

Sodium aluminum sulfate silicate

Sodium iron silicate

Sodium chloro hexa-al umi num silicate

Sodium aluminum silicate

Sodium calcium carbonate aluminum silicate

Aluminum silicate

Potassium aluminum silicate

Potassium sodium aluminum silicate

Potassium tri -sodium aluminum silicate

Nephel i ne

Sepi ol ite

Magnesium octa-hydride silicate

Calcium silicate

Calcium si licate

Calcium aluminum silicate hydroxide

Calcium silicate hydrate

Calcium silicate hydroxide (Xonotlite)

Calcium aluminum silicate hydrate

Sodium calcium silicate hydroxide (Pectolite)

Calcium aluminum silicate hydroxide

Calcium magnesium silicate

Calcium magnesium hydroxide silicate

Nosel ite

Iron silicate

Iron magnesium hydroxide silicate

Sodium aluminum molybdenum oxide silicate

Magnesium Silicate Hydroxide

Magnesium hydroxide silicate

Zinc silicate

Zi rconi urn Si licate

Sulfates

*Na2S04

Na 2^ 2 ^6 * 2 ^

2 ^ FeS04

FeS04 »H20

Na Fe(S 04)2 -IZHgO

CaNa 2 (S 04)2

Cu4S0^( OH

)g

Na2Cu ( SO4 )2

Cu Fe(0H)2S04

AI2SO4

Sodium sulfate

Sodium sulfate di hydrate

Iron (II) sulfate

Iron (II) sulfate hydrate

Sodium iron sulfate dodeci hydrate

Calcium sodium sulfate

Copper sulfate hydrate

Sodium copper sulfate

Copper iron sulfate hydrate

Aluminum sulfate

35
Al4S04(0H)^Q.5H20

CaS04 -2H20

Cd SO4

( ^^4 )?

^38^16(51 04)5504

*(NH4)2S04

Phosphates

*Na

3

P 04

Na3P04.12H20

*Na 2

HP 04

NaH 2

P 04

NaP 03

(NaP 03)3 *^^ 2 ^ Na2^2P 2^7*^^2^

Na3HP20y.9H20

FeP 04

Fe(P 03)3

Na Fe 3 (P 04 ) 2 ( 0H) 4

« 2 H 20

(Fe,Mn)2[(0H)(P04)]

Na2(Fe,Mn)5[P04J4

Ca4P20g

0^10 (^^)2^ ^^3 ^6

Ca5[(0H)(P04)3]

Mgx(OH) (P 04 )^

(Na ,Ca ,Te,Cu ,Ni

)

Carbonates

Aluminum sulfate hydroxide pentahydrate

Calcium sulfate dihydrate

Calcium sulfate

Sodium carbonate sulfate

Sodium aluminum silicate sulfate

Ammonium sulfate

Tri sodium phosphate

Tri sodi urn phosphate-dodecahydrate

Di sodium hydrogen phosphate

Sodium di hydrogen phosphate

Sodium metaphosphate

Tri sodi urn metaphosphate hexahydrate

Sodium di hydrogen pyrophosphate

Sodium hydrogen pyrophosphate

Iron (III) orthophosphate

Iron phosphate

Sodium iron phosphate hydroxide di hydrate

Iron manganese phosphate hydroxide (Wolfeite)

Sodium iron manganese phosphate

Calcium phosphate

Hydroxy-apatite

Calcium phosphate hydroxide

Magnesium hydroxide phosphate

Mixed phosphate

*Na2C03

Na 2 *H 20

Na2C03*10H20

*NaHC03

Na 3H ( CO3

) 2

*H20

Na3H(C03)2‘2H20

5Na20-8C03 *3H20

3NaAlSi04 «Na2C03

CaC03

CaNa2(C03)2 *2H20

CUCO3 Cu(0H)2

*(NH4)2C03

Sodium carbonate

Sodium carbonate monohydrate

Sodium carbonate decahydrate

Sodium bicarbonate

Sodium hydrogen carbonate monohydrate

Sodium hydrogen carbonate di hydrate

Sodium carbonate trihydrate

Sodium aluminum silicate sodium carbonate

Calcium carbonate

Calcium sodium carbonate di hydrate

Copper carbonate, basic

Ammonium carbonate

36
Chlorides

*NaCl

KCl

FeCl^

FeCl

3 CrCl

2

CrCl 3

*NH 4

C1 Cu 2(0H)3 Cl

Acids

Sodium chloride

Potassium chloride

Iron (II) chloride

Iron (III) chloride

Chromium (II) chloride (possible)

Chromium (III) chloride (possible)

Ammonium chloride

Copper (II) oxychloride

*H2S04

*HC1

*CH3C00H

*CH3CH2C02H

*CHoCHpCHpCOpH

*HC00H

H

2 Si 02

H2BO3

^2^x^6’

^ ^ 3, 4, or 5

Gases

Sul phuri

Hydrochloric

Aceti

Propionic (propanoic)

Butyric (Butanoic)

Formi

Silicic

Bori c Polythionic

*C02,N2,*02,*H2,C1 ,H2S

Uncompounded Elements

aFe Alpha iron

C Graphite (carbon)

*Cu Copper

Cr Chromium

S Sulphur

Other Additives

*NH40H Ammonium hydroxide

*C4HgN0 Morphol i ne *C6 HiiNH2 Cyclohexyl amine

*N2H4 Hydrazi ne

H

2 O

2 Hydrogen peroxide

Na 2

S 03 Sodium sulfite

Other

*NaOH

Li OH

AlOOH nH20

*NaF

N0‘

Sodium hydroxide

Lithium hydroxide

Aluminum oxide hydroxide

Sodium fluoride

Nitrite

Oits and oil decomposition products

Unknown cobalt compounds

CCI 4 Carbon tetrachl oride

MoS Molybdenum disulfide

EPA Organics

Methoxychl or Toxaphene

2,4,5-TP (Silvex)

Traces of Endrin, Lindane, 2-4-D

C

2 H

4

CI 2

Di chi orethane

*Compounds and elements preceded by an asterisk are recommended for corrosion

testing.

37
Waterside Corrosion and its Control

in Fossil Utility Steam Generators

F. J. Pocock, Sr. Scientist

Babcock & Wilcox Co. - A McDermott Company

Alliance Research Center

Cycle Heat Transfer Equipment

Figures 1, 2 and 3 show typical diagrams of fossil utility and high

pressure Industrial power plant cycle arrangements including water chemistry

control equipment.

Condenser

The condenser (Figure 4) is a shell and tube heat exchanger with a carbon

steel shell, usually copper alloy tubing with tubesheets constructed of

materials compatible with the tubing alloy and designed to avoid galvanic

corrosion. It is quite common to install sacrificial anodes in the water box

of the condenser to prevent the latter. The use of coatings is also common. Among the tubing alloys utilized are admiralty metal (aluminum-brass), copper

nickel alloys 90-10, 70-30, stainless steels and titanium. Titanium is rapidly

coming into use in nuclear power stations in response to internal boiler

corrosion problems associated with copper bearing deposits and in a further

effort to simplify and optimize water conditioning.

Feedwater Heater

Feedwater heaters (Figure 5) are shell and tube arrangements that utilize

bleed steam to preheat the feedwater before it reaches the steam generator

(boiler). In the past, these were commonly tubed with copper alloys of similar

alloy composition to condenser tubing. More recently, in large utility

installations, these units are tubed with carbon steel and/or stainless steel.

38
HVORAZIWe MCASURIMG

FIGURE 1. A FOSSIL UTILITY STEAM GENERATING SYSTEM VTETH RECIRCULATING STEAM

GENERATOR

39

Ref 1
FIGURE 2. ONCE-THROUGH STEAM GENERATING SYSTEM

40
HIGH PMESSUMC STEAM TO AAOCESS

41 Ref 18
42 Ref 23
TUBE SUPPORT

TUBESHEET

FIGURE 5. FEEDWATER HEATER

42a Ref. 23

Deaerators (Figures 6 and 7) are usually open heaters containing either

tray systems or spray systems whereby the incoming feedwater can be

counter-currently scrubbed with steam to reduce its dissolved gas content.

Well designed deaerators commonly have exiting water essentially free of

dissolved gases. Dissolved oxygen is usually at a concentration of less than

ten parts per billion. Deaeration is also accomplished in the condenser.

Figure 8 shows the efficiency of deaerating condensers as a function of

air removal capacity.

Cycle Purification Equipment

There are many devices designed to purify returned condensate. The two

basic principles used are ion-exchange and filtration.

Condensate Polishing

The ion exchange method is called condensate polishing when ionexchange resins are applied and used in this way. In utility deep bed

condensate polishing practice (Figure 9) the ion-exchange resins are moved

hydraulically from the cycle for regeneration by acids and bases, the reason being concern for contaminating the cycle equipment, piping and

steam generators with material damaging regenerant chemicals. The cation

resin in these systems can be employed in either the hydrogen form or a cycle chemical additive form such as ammonium hydroxide or morpholine.

The removal of dissolved cations (metal ions) is less effective in the

latter forms and much additional care with regeneration methods must be

employed. The anion resin is always operated in the hydroxide form.

Powdered Resin Systems (Figure 10) are widely utilized. These

systems using a ground resin mixture (<400 mesh) of varying amounts of

cation and anion materials are excellent filters. They are usually

operated in the cycle pH correctant additive form and new resins are always used. These are in a highly degenerated form as shipped by the

manufacturer.

43
DIRECT CONTACT VENT

CONDEN8INQ t PRE-HEATINO

SECTION

ON END PLATE FIGURE 6. TRAY TYPE DEAERATOR

44
VENT »RAV NOZZLES

IMPINGEMENT WATER DISTRIBUTORS ve^t CONCENTRATOR PLATE

RELIEF VALVE CONN SECTION

LEGEND

STEARI WATER

TO STORAGE TANK

DIRECT CONTACT VENT

CONDENSING B

FIGURE 7. SPRAY TYPE DEAERATOR

45
Ossoived Oxygen in Condensate (ppb)

FIGURE 8. INFLUENCE OF AIR INLEAKAGE & INSTALLED AIR REMOVAL CAPACITY ON

ACHIEVABLE DISSOLVED OXYGEN LEVELS IN THE CONDENSATE

46

Ref. 23
CONDENSATE

FIGURE 9. CONDENSATE POLISHING SYSTEM

47
FIGURE 10.

48
Filtration

Condensate filtration (Figure 11) is normally carried out by either

cellulose cartridge, cellulose precoat or more recently electromagnetic

filters (Figure 12). In industrial plants, cation resins have also been

used in the sodium form to remove corrosion product particulates.

Cellulose precoat filter systems are employed alone to filter

suspended solids (usually corrosion products) or in combination with

ion-exchange condensate polishers. The cellulose precoat material is

called Sulka-Floc and is pure cellulose. It is precoated onto filter

system substrates that can be made of either plastic or stainless steel,

although stainless steel filter systems are usually employed. The

cellulose cartridge filters have been less popular in utility service

because of the need to disassemble equipment to install new filters.

A newer development has been the electromagnetic filter first widely

applied in Europe where preboiler systems contain very little copper other

than in the surface condenser. These have been introduced into the United

States in the past ten years as the tendency to remove copper from utility

cycles has increased. They are capable of very effective removal of iron

oxide corrosion (magnetite) particles in the size range encountered in

utility systems. They have the additional capability of effective use at

high temperatures (below the Curie point) which ion-exchange condensate

polishers do not. Resin ion exchangers are limited by the thermal

degradation of the plastic resin beads and/or exchange site groups.

Recent experimentation with thermally treated resins has shown some promise for moisture separator drain purification at high temperatures.

49
50
i 1 y.

IMPROVEMENT OF EXISTING FEEDWATER CYCLE . OUTLET

FLUSH

0 OUTLET —^ ^

BYPASS Y

0 o o o

o c o o

o o o o

o c o o

o o o o

o o o o

0 o oo

o o o o

ELECTROMAGNETIC

FILTER

POWER/CONTROL UNIT ACTUATES

ALL VALVES SHOWN IN THE PROPER SEQUENCE T"1(AINLET

(ALL CXINDITIONSI

Electromagnetic Filter Electromagnetic Filter Installation FIGURE 12

51
Monitoring Instrumentation

There are many kinds of monitoring instrumentation available to

automatically assess the quality of the feedwater. Principal among these are those that monitor dissolved gases (chiefly dissolved oxygen and hydrogen),

monitor conductivity (measure of dissolved solids and dissolved ionized gases

[CO^, NH^, etc.]), monitor pH (measure of acidity and basicity) and monitor

specific cations (metals) and anion (radicals, SO^ = Cl” etc.) known to be

damaging to component structural materials.

Dissolved Gases

The dissolved gases of principal interest to the corrosion processes

in utility cycles are oxygen and carbon dioxide. A gas of interest to the

monitoring of ongoing corrosion processes is hydrogen.

Instrumentation for dissolved oxygen and dissolved hydrogen are readily available. Usually, dissolved oxygen instrumentation depends on electrochemical cell action (current generated by redox processes) while

dissolved hydrogen is monitored by measuring the very high thermal

conductance of hydrogen gas after it is scrubbed from the sample stream.

Reliable monitoring instrumentation for carbon dioxide is not available

although several devices have been designed to scrub this gas from the

water and measure the resulting differential conductivity.

Conductivity Measurement

Electrical conductance is a quantitative measure of the dissolved

ionized solids and gases in water when properly applied. Two types of

instrumentation are utilized in utility plants. One, specific

conductance, measures the gross ionized solids and gas content of the

water and is especially useful in power plants for controlling the

injection of pH additives like ammonium hydroxide and morpholine. Cation

conductance depends on acid conductivity after cationic ion-exchange.

This is a sensitive measure of condenser leakage through the conversion of

sulfates and chlorides to their corresponding acids. This acid conversion

52
of the anions enhances the conductivity measurement because of the greater

conductance of acids as compared with neutral salts and/or bases. It does

not measure cation hydroxides (sodium hydroxide, etc.) and therefore

cannot indicate the leakage of sodium hydroxide into the cyle.

pH is a measure of acidity or basicity of the water and is equivalent

to the negative log of the activity of the hydrogen ion. Important to the

utilization of this monitoring equipment (and a common mistake) is the

knowledge that the instrumentation whether manually or automatically

compensated measures pH at sample temperatures. If evaluation of

corrosion potential to standard conditions (25°C, 77°F) is desired, proper

calculation and/or nomographs must be used to convert the measured pH to

reference values at 25°C, 77°F for the type of volatile condensate

treatment additive utilized. The same is true for solid alkaline

additives used in boiler water treatment.

Anion and Cation Measurement

Anion measurement has long been a problem except for gross measure by

cation conductivity. Recently developed process ion-chromatographs hold

promise for the physical measurement of these on-line at least in a semi-continuous monitoring mode. Cations are now commonly measured by

selective ion electrodes. A common and well developed monitor is the

sodium ion electrode and is widely applied for assessing moisture

carryover in steam. A chloride specific electrode is also coming rapidly

into use in power plants. Currently, the only available method of

monitoring low concentrations of sulfate ion is the ion-chromatograph.

Corrosion Behavior of Cycle Components

This discussion will be principally concerned with the corrosion

protection of the preboiler system and to a lesser extent, the condenser as these surfaces are the source of porous waterside deposits in steam generator

tubing.

53
Steel Feedwater Preheaters

Currently carbon steel or stainless steel preheaters are being employed in

nuclear and fossil once-through boiler cycles. They are also being retrofitted

to nuclear recirculating systems. Carbon steel tubed heaters were first widely

applied during World War II (copper shortage) and then designers returned to

the traditional copper alloy heat exchangers when material shortages were alleviated. Problems with copper transport in supercritical cycles twenty

years ago and more currently with recirculating nuclear steam generator

localized support plate corrosion problems have led to a prol i feration of steel

tubed heaters both here and abroad. Both vertical and horizontal shell and

tube exchangers are employed in various cycles. Concerns for carbon steel are corrosion product pick-up on both the shell and tube side and inlet corrosionerosion problems. For stainless stell tubed heaters, there is a concern for

stress corrosion cracking by either dissolved oxygen, chorides and/or

hydroxides. There is also a concern for reduced sulfur species intergranul ar attack in sensitized weld heat affected zones. These latter can be a catastrophic corrosion problem. Because of the better corrosion resistance

afforded by the higher alloy material, corrosion product pick-up is

significantly reduced by their application. More recently, ferritic stainless

steel alloys are being utilized for this purpose in Europe.

Copper alloy tubed feedwater heaters have been constructed of a full range

of alloys that include 90-10 and 70-30 copper nickel. Monel and aluminum

brasses. Copper has been an attractive alloy because of its good thermal . conductance. Discussions about its use have included the desirability of

utilizing a single (steel) alloy in the water/steam cycle for simplified water

treatment, cost, and additional complications in boiler chemical cleaning

caused by copper bearing deposits etc.

54
Copper alloy condensers have involved similar discussions, although it can be shown that improved alloy conductance for this application is not a major

part of total heat conductance. Some have shown this factor to be on the order

of 10% of the total temperature drop through the wall. Fouling, surface

oxidation, and condensing film coefficients are more important. For nuclear

service, titanium is becoming the alloy of choice although because of required

thinner sections for proper heat transfer, vibration concerns are enhanced.

There are three general reference pH ranges used to reduce corrosion

product pick-up and these are dependent on pre-boiler component alloy material

choice. All are stated at a reference pH of 25°C (77°F). For copper alloy

tubed heaters, the pH range most accepted is 8. 8-9. 2. For carbon steel tubed

heaters, the most accepted pH range is 9. 3-9. 6. Where stainless steel tubing

is employed (even with copper condensers) a pH as low as 8.5 is acceptable.

The pH chosen sets the concentration of volatile additive and has significant

impact on the unit process - condensate polishing - if employed. Figures 13

and 14 illustrate the effect of pH on corrosion (metal ion pick-up) of these

materi al s.

55
FIGURE 13. IRON PICK-UP AT ECONOMIZER INLET - CARBON STEEL FEEDWATER

HEATER TRAIN

56

Ref. 4, 24
I/Brf

FIGURE 14. DEPENDENCE OF CORROSION OF BRASS ON pH VALUE WHEN

ALKALIZING WITH AMMONIUM HYDROXIDE

57

Ref. 21
Once-Through Steam Generators

Figure 15 is an illustration of a 3,500 psig (24.1 MPa), 1050°F (565. 6°C)

reheat Universal Pressure Boiler. The required feedwater conditions. Table 1, are the same for both sub and supercritical once-through steam generators. The

allowable contaminant limits in the feedwater must be less than their

solubility in the exiting steam to avoid deposition in the steam generator.

This is possible for the dissolved solids but is not possible for

balance-of-plant corrosion products. Therefore, these latter are limited to

concentration levels acceptable for periodic chemical cleaning. The

concentration levels acceptable for this objective are controlled by careful

balance-of-plant material, design choices and water conditioning along with the

utilization of condensate purification equipment.

Figure 16 shows a typical rippled magnetite deposit in a supercritical

once-through steam generator tube. Figure 17 shows the effect of this deposit

on heat transfer at various heat absorption rates.

Because of the dissolution of dissolved solids in the exiting steam,

"under-deposit" concentrated chemical attack corrosion failures are not

experienced in these types of steam generators. Tube metal overheat type

failures can and do occur, therefore the accumulation of deposition must be

controlled to an acceptable level by periodic chemical cleaning that will

prevent these insulating deposit induced tubing failures. An additional reason

for chemical cleaning is the characteristic "rippled deposit" formation. This

latter deposition pattern leads, to increased steam generator pressure drop and

related requirements for additional feedpump capacity if system load reduction

is to be avoided. The source of these oxydic deposits can be both internal and

external. The current belief is that 'v 50% of the tube deposit accumulations

have their source as corrosion products from the preboiler system while the

remainder is due to solubilization and redepositing of the magnetite protective

oxide longer. The solubility of magnetite as a function of pH is shown in

Figure 18.

58
FIGURE 15. BABCOCK & WILCOX UNIVERSAL PRESSURE BOILER

59
TABLE 1. FEEDWATER SPECIFICATION FOR UNIVERSAL PRESSURE BOILERS

Carbon Steel

Heaters

Copper A1 loy

Heaters

pH B 25°C (77°F) 9. 3-9.

5

8.8-9.

2

Total Solids, PPB, yg/1 <50 <50

Cation Cond., S, MHO/CM 25°C <0.5* <0.5*

Fe, PPB, ug/1 10 10

Cu, PPB, ug/1 2 2

SiO^. PPB, ug/1 <20 <20

0,, PPB, ug/1 <7 <7

Normal Maximum
Typical internal fluid side surface

appearance of the magnetite layer in a once>through boiler furnace tube.

Nickel plating

Porous overlay

Protective oxide layer

Base metal

().() 1 ini t' —H

Transverse section through internal

Magnetite layer in a once-through

boiler furnace tube.

FIGURE 16.

61

Ref. 1
DEPOSIT

TEMPERATURE

DROP,

138.9

^ in.i

u.d

83.3 -DVw3

15w

0> 55.6 £

0)

’55 a0) 27.8 ^

0.0

Deposit weight, g/ft.^

Deposit temperature drop

Bulk fluid temperature , 700 F ( 371 . 1 °C)

Pressure 3800 psia (26.2 MP/^)

Porosity 0.65

FIGURE 17

62

Ref. 1
100

80 -

60 -

9

Jt m

a. 40 —

20

0.1 mg NH3

/kg

0.2 mg NH3

/kg

O 0.3 mg NH3

/kg • 0.45 mg NH3/kg

If 1.0 mg NH3

/kg

A 2.0 mg NH3

/kg

T

50 100 150 200 250 300 350

FIGURE 18. MAGNETITE SOLUBILITY AS A FUNCTION OF TEMPERATURE

AT VARIOUS AMMONIA CONCENTRATIONS

63 Ref. 21
Recirculating Boilers

Figures 19 and 20 show typical high recirculating pressure boilers of the

Industrial and utility types. Since some industrial boilers approach utility

boiler high pressures, they are treated similarly from a water conditioning

standpoint. Heat absorption (transfer) rates are probably the largest single

factor related to waterside deposition. Figure 21 illustrates the general heat

absorption pattern in high duty recirculating boilers.

ABMA and B&W Water Quality Guidelines

Tables 2 and 3 contain typical B&W high pressure utility feedwater and

boiler water quality limits for drum-type units. Table 4 contains the current

ABMA* guidelines. Table 5 contains typical turbine supplier steam purity

1 imi ts.

Boiler Water Treatment

Figure 22 shows the trend in boiler water internal treatment for

recirculating drum type boilers in a 1971 ASME survey.

It is obvious that the favored internal treatment in the absence of

condensate polishing is the addition of sodium phosphate. The method of

addition is by congruent control.

Congruent control refers to the ratio of sodium to phosphate in the bulk

water. The intention is that this ratio shall always result in the formation

of phosphate chemicals rather than sodium hydroxide when concentrated to near

dryness (Figure 23).

Figure 24 shows the reason that sodium phosphates are employed rather than

other alkaline phosphates. It is based on the relative corrosion rates of

mild steel when the salts are concentrated in high quality regions under

deposits.

*ABMA American Boiler Manufacturers Association

64
f stack

CHILE EXPLORATION COMPANY

TOCOPILLA POWER PLANT

TOCOPILLA, CHILE saw CONTRACT NO S- 102 14 FIGURE 19. TWO-DRUM STIRLING BOILER

65
ALABAMA POWER COMPANY

MILLER STEAM PLANT-UNITS NO 1.2.3 AND 4

WEST JEFFERSON . ALABAMA

B a W CONTRACT NOS RB-520.521,522 AND 523

38 - 0

' -

R6-5a0,52;,52::,525-50u-2-.

FIGURE 20. EL PASO-TYPE RADIANT BOILER FOR NATURAL-GAS AND OIL FIRING.

SUPERHEATER OUTLET PRESSURE 2625 PS I; PRIMARY AND REHEAT

STEAM TEMPERATURES 1005°F; CAPACITY 3,770,000 LB. STEAM/HR.

66
Steam

Risers

FIGURE 21. THE CIRCULATION LOOP Ref. 25

67
TABLE 2

BaW RECOMMENDED WATER QUALITY LIMITS

FOR HIGH PRESSURE-DRUM TYPE BOILERS

(ABOVE 2,000 PSI DESIGN)

FEEDWATER BOILER WATER

MAX. LIMIT MAX. LIMIT

OXYGEN .007 PPM (mg/1

)

TOTAL SOLIDS 15 PPM (mg/1)

IRON .010 PPM (mg/1

)

NaaP 04 3-10 PPM (mg/1)

COPPER .005 PPM (mg/1

)

HYDROXIDE 1 PPM (mg/1)

HARDNESS 0 PPM pH 9.0-10.0

CARBON DIOXIDE 0 PPM SILICA AS DETERMINED*

BY DRUM

ORGANIC 0 PPM PRESSURE

pH 8. 5-9.2

SODIUM

*As determined by Turbine Manufacturer Limits
TABLE 3

BaW Feedwater Quality Limits

Drum Type Boilers Less Than 2,000 psi

DISS. OXYGEN AS ppm (mg/1 ) 0^

IRON AS ppm (mg/1 ) FE

COPPER AS ppm (mg/1 ) CU

HARDNESS, ppm (mg/1)

ORGANIC, ppm (mg/1)

pH 25°C (77°F)

Below 600 to

600 psi 1000 psi

0.007 .007

0.1 0.05

0.05 0.03

0* 0*

0 0

8.0 - 9.5 8.0 - 9.5

*Temporary maximum of 1.0 ppm (mg/1) permitted.

69 Ref. 6
TABLE 4

WATERTUBE BOILERS*

RECOMMENDED BOILER WATER LIMITS AND ASSOCIATED STEAM PURITY

At Scndy-Stm. Full-Load Oparttion

Drun Pressure

psig

Range

Total Dissolved

Solids^ Boiler

Water ppn (MAX)

Range j Total AUal1nTty‘

Boiler Water

ppn

Suspended Solids Boiler Water

ppn (MAX)

Range

, ^ Total Dissolved SoMds ’ Stean

ppn (MAX expected value'-

Dnim-TYPa Boilan

0 - 300 700 - 3500 140 - 700 15 0.2 - 1.0

301 - 450 600 - 3000 120 - 600 10 0.2 - 1.0

451 - 600 500 - 2500 100 - 500 8 0.2 - 1.0 601 - 750 200 - 1600 40 - 200 5 0.1 - 0.5

751 - 900 150 - 1200 30 - 150 3 0.1 - 0.5

901 - 1000 125 - 625 25 - 125 1 0.1 - 0.5

1001 - 1800 100 NOTE (3) 1 0.1 1801 - 2350 50 N/A 0.1 2351 - 2600 25 N/A 0.05

2601 - 2900 15 N/A 0.05

Onca-Throuen Boilvn

1400 and Above 0.05 N/A N/A 0.05

NOTES;

1. Actual values within the range reflect the TDS in the feed water. Higher values are for high solids, lower values are for low solids In the feed water.

2. Actual values within the range are directly proportional to the actual value of TDS of boiler

water. Higher values are for the high solids, lower values are for low solids In the boiler water.

3. Dictated by boiler water treatment.

4. These values are exclusive of silica.

* Draft - 3rd Edition. 1M2

•Published by The American Boiler Manufacturers Association - Draft 3rd Addition, 1982

70
TABLE 5

TURBINE MANUFACTURERS' STEAM PURITY LIMITS

Constituent General Electric Uestinchouse All is-Chalmers

Normal 100 hrs. 24 hrs. Normal 2 wks. 24 hrs. Normal

Cation Conductivity (umhos) <0.2 0.5 1 <0.3 0.3-0.

0. 5-1.1 <0.1

Sodium (ppb) 3 6 10 <5 5-10 10-20 <10

Chlorides (ppb) <5 5-10 10-20

Silica (ppb) <10 10-20 20-50 <10

Iron (ppb) <20 <5

Copper (ppb) <2 <1

Oxygen (ppb) <10 10-30 30-100 <5

71

Ref. 4
%

OF

TOTAL

FIGURE 22. TRENDS IN BOILER WATER TREATMENT (1955-1970)

72 Ref. 3
pH

VALUE

@

25°C

PPM PO4

FIGURE 23. LOW LEVEL COORDINATED PHOSPHATE CURVE

73 Ref. 24
CORROSION

RATE

(MG/DM^

MONTH)

ALKALI CONCENTRATION

FIGURE 24. RELATIVE CORROSION BEHAVIOR OF ADDITIVES

VOL/L)

74 Ref. 7
Measurement of the dissolved solids in the boiler water is made in the

blowdown water. Preferably this blowdown sample tap will be located under the

steam separators at a location where the highest boiler water concentrations

occur.

Another approach to internal boiler water conditioning employs chelating

agents. Two of the most common employed are Ethylene Diamene Tetra Aceta Acid

(ETDA) or its salts and Nitrillo Triacetic Acid (NTA). Both chemicals combine

with calcium and magnesium hardness materials to prevent their precipitation.

Commonly, those materials are applied at pressures under 1200 psi for this

purpose. However, in the Soviet Union, EDTA has also been applied in

supercritical once-through cycles to help with iron transport problems. The

principal problem with chelate chemical additives is control. Overfeed can

lead to severe boiler tube corrosion while underfeed allows hardness salt

deposition. With available analysis techniques, precision control is

difficult.

More recently organic polymers are becoming widely used as additives in

industrial boilers. Sometimes these are in combination with chelating agents.

Recent data suggest that these treatment compositions overcome some of the

possible chelating corrosion problems and improve the transport of suspended

corrosion products (iron oxides) by maintaining them in suspension for

bl owdown.

In Europe, a new treatment method has evolved over the past decade. This

was called neutral water treatment and employs the addition of 200-300 ppb of

dissolved oxygen either in the gaseous form or by hydrogen peroxide. More

recently, this has been modified by the addition of a small amount of ammonia

to elevate pH slightly (the latter is called the Combined Neutral Water

Treatment). It is employed with once-through steam generators having all steel

preboiler systems with the exception of condensers. Full flow condensate

polishing is required to assure a feedwater purity before additives equivalent

to a conductance of less than O.lu mhos/cm (us).

This technique is widely applied in Germany with some utilization in the

Soviet Union and other eastern block countries. It is dependent on the low

75
corrosion rates of carbon steel in high purity water with small amounts of

dissolved oxygen. It is a type of anodic inhibition and, again, very strict

water purity controls are required .

Chemical additives are utilized to remove the last traces of dissolved

oxygen from the power plant cycle. The common additives that have been applied

in the past are hydrazine (N^H^) and sodium sulfite (Na^SO^). Tables 6 and 7 contain the advantages and disadvantages of these chemicals.

Above pressures of 1500 psig, only hydrazine is applied as the thermal

decomposition products of sodium sulfite are considered inimical to turbine

materials. Another limitation to the use of sodium sulfite is the addition of

dissolved solids to the boiler water through reaction with dissolved oxygen.

The reaction products of dissolved oxygen and hydrazine are nitrogen and

water while the thermal degradation products are hydrogen and

ammonia - dissolved gases commonly found in power plant cycles.

In 1978, NiOSH (the research arm of OSHA) issued a document suggesting

that hydrazine had carcinogous effects. This has not been promulgated into law

by OSHA but has led water treatment companies to investigate replacement

additives. Many of these are being field tested at present. Among the

chemical formulations being investigated for their usefulness as dissolved

oxygen scavengers are hydroquinone, isomers of ascorbic acid, restructured urea compounds, etc.

These are currently being researched for their effectiveness during cycle

equipment wet storage (cold condition) as well as the characteristics and

impact on corrosion processes of various cycle materials by their thermal

degradation products.

Chemical additives are commonly applied to the remainder of the cycle to

protect surfaces exposed to returned steam condensate. Two types of additives

are employed. They are neutralizing amines (morpholine and cyclohexyl amine)

and filming amines (Octadecyl amine and ethoxylated soya amine). The former

76
TABLE 6

SODIUM SULFITE/CATALYZED SODIUM SULFITE

Advantages Pi sadvantaqes

Reacts at Room Temperature Quickly

Catalyzed Form Reacts Quicker

Than Catalyzed Hydrazine

Handling Requirements Simple

Not as Toxic as Hydrazine

Adds Dissolved Solids to Boiler Water

Cannot Use Feedwater Downstream of

Addition Point for Attemperators

Cobalt Catalyst or Other Transition

Metal Catalysts can be Precipitated

in Boiler Water

Excess Sulfite can Decompose at 254°C

(490°F) to Produce Acid Gases

Upper Limit of Use is 1500-1800 psig

Cannot Reduce Higher Oxides of Iron

and Copper at Normal Condensate and

Deaerator Temperatures

Requires More Sulfite Than Hydrazine

to React with Dissolved Oxygen

77

Ref. 18
TABLE 7

HYDRAZINE/CATALYZED HYDRAZINE

Advantages Disadvantages

Adds No Dissolved Solids to Boiler

Water

Very Slow Reaction at Deaerator Outlet

Temperature for Uncatalyzed Version

Can be used in Attemperator Water Starts Decomposing at 204®C (400®F) to

Form Ammonia

Organic - Cobalt Catalyzed Version

can be Used With Chelating Agents

Hydrazine is Toxic Inflammable Material

Suspected of Being a Carcinogen

Can Neutralize CO^ When Carried

Over With Steam ^

Can Reduce Ferric Oxide at

Deaerator Effluent Temperatures

Reacts with Dissolved Oxygen Mole

for Mole

Can Be Used Above 1500 psig

Can Be Injected in After Boiler

Steam Lines to Reduce Iron and

Copper Pick-Up

As a Reducing Agent, It can Increase

Solubility of Protective Oxide Film

78 Ref. 18
neutralizes traces of acid by elevating pH while the latter deposit a non-wetable protective film on surfaces in the return piping and associated

components to protect against corrosion by oxygen and carbon dioxide. The

resulting balance-of-plant component and piping protection reduces the

corrosion products available for transport to the steam generator. Filming

amines are usually employed only in industrial plants. In condensate polished

return cycles, they could foul ion exchange resins.

Boiler Tube Damage

Figures 25, 26, 27, and 28 show "under deposit" corrosion which may reveal

itself only by tube thinning under the porous deposit due to concentrated

boiler water contaminant and/or treatment chemical attack or associated with

"hydrogen damage" (decarborization) of the steel. The latter causes dramatic

failures in which pieces of steel are blown out of the boiler tubes. Figure 29

shows how that boiler water "under deposit" concentration may occur. Figure 30

shows how boiler salts may distribute themselves between the tube wall and the

bulk fluid.

Effects of Soluble Salt Concentration

Trace soluble (and corrosive) constituents in the boiler water can be

concentrated by such a method to very high concentrations adjacent to the

tube wall. This results in rapid attack of the tube metal and subsequent

failure. The exchange and distribution of chemicals between steam and

water film in the deposits and the bulk boiler water would most likely be

similar to that reported by Martynova (Figure 30). Another commonly

discussed mechanism of concentration is the "concentrating film" theory as shown in Figure 31 for sodium hydroxide. The latter theory preceded more

finite data on the distribution of salts between steam and water, but both

mechanisms are probably involved.

79
FIGURE 25. "UNDERDEPOSIT” HYDROGEN DAMAGE - CYCLONE BARREL TUBE

80 Ref. 22
81

Ref. 22
FIGURE 27. SECTIONS OF FURNACE WALL TUBING EXHIBITING "UNDERDEPOSIT"

BULK CORROSION ATTACK (GOUGING)

Ref. 22

82
FIGURE 28. A SECTION SHOWING BULGING OF THE TUBE AS A RESULT OF THINNING

BY CORROSION (lOX)

83 Ref. 22
STEAM ESCAPING FROM MOUTH OF

STEAM CHIMNEY BY SUCCESSIVE

84 Ref. 10
MARTYNVA, O. I. (MOSCOW POWER INSTITUTE) AND

AKOLZIN, P. A. (ALL UNION INSTITUTE, INDUSTRIAL

WATER ENGINEERING, P. 29, DECEMeER 1969)

FIGURE 30

85

Ref. n
86

Ref. 12

SODIUM

HYDROXIDE

CONCENTRATION,

PPM
Corrosion Fatigue

Figures 32 and 33 are pictures of a damaged studded furnace floor

tube caused by inadequate circulation in a high heat input zone. The

cyclic heating and cooling caused "corrosion fatigue" of the tube metal.

Causes of such damage may relate to the thickness of the external

slag layer (radiant heat input shield) and condition of the "chrome ore"

coatings on the studs (additional protection against localized heat input)

on the fire side of the tube as well as contributions of accumulated

deposits formed by feedwater contaminants or a combination of these as shown.

Stress Corrosion Cracking

Austenitic stainless steel superheater tubes sometimes are damaged by

stress corrosion cracking in either chi oride-or-hydroxide-contai ning

environments.

Figures 34 and 35 show examples of "caustic" stress corrosion caused

by the inadvertent introduction of a "caustic" containing boiler "boil

out" cleaning solutions into a superheater. The boiler had been fired for

only a few hours. Replacement of the superheater was required. This is

not an uncommon type of tubing damage and further emphasizes the need for care and thought in chemical cleaning of fossil boilers.

The damage was primarily located at the stressed support locations

and ring welds (heat affected zones).

87
FIGURE 32. A SECTION OF STUDDED FURNACE FLOOR TUBING SHOWING

WATERSIDE CORROSION FATIGUE DAMAGE AND EXTERNAL

THERMAL STRESS NOTCHES

88

Ref. 22
FIGURE 33. INTERIJAL SURFACE CORROSION FATIGUE NOTCHES (lOOX)

89

Ref. 22
FIGURE 34. A FAILED STAINLESS STEEL (SS 304) SECONDARY SUPERHEATER

TUBE (CAUSTIC STRESS CORROSION) (IX)

90

Ref. 22
FIGURE 35. CRACK MORPHOLOGY SHOWING TRANSGRANULAR PENETRATION

OF THE TUBE WALL (lOX)

91

Ref. 22
steam Blanketing

"Steam blanketing" or departure from nucleate boiling (DNB) can lead

to failures of the type shown in Figure 36. The problem is due to

improper mass flow in boiler tubes in relation to heat input and pressure.

This limit is also affected by tube inclination. One example of the

latter is insufficient velocity in inclined "slag screen" tubes in a "high

heat input" region. The observed damage would be at the top of the tube

in such a case and is characteristically a narrow corroded region

(sometimes referred to as "ghost lines").

Failures of this type usually exhibit themselves by "ghostline"

corrosive attack on the tube wall which, if it proceeds far enough, will

result in the type of damage shown. In this case, the tube was locally

thinned and a pressure rupture occurred. This type of attack is sometimes

accompanied by gross accumulation of corrosion product oxides on the

waterside due to severe localized tube metal attack. We have demonstrated

this type of failure by penetrating a steam generator tube in as little as 24 hours with the addition of 10-15 ppm caustic in high purity water under

controlled DNB conditions in the laboratory. Again, this type of tube

damage is not one of the most common types. It must involve a corrosive

substance in the boiler water. Subcritical once-through boilers

constantly operate under these same physical conditions without corrosion

in a high-purity water environment.

Industrial Boiler Corrosion

Modern industrial boilers are subject to the same kinds of problems

that plague utility units. There are, however, some differences due

mainly to lower feedwater qualities and less rigid control of feedwater

and internal boiler water treatment practices. The following are some

typical examples.

92
1 FIGURE 36. APPEARANCE OF "STEAM BLANKETING" ATTACK ON

A FURNACE WALL TUBE

93

Ref. 22
Caustic Embrittlement

The caustic embrittlement type failure as shown in Figure 37 is

seldom encountered in modern boilers. With increasing pressure, higher

duty units, better water conditioning, etc., "hydrogen damage" problems

and usually associated with utility boilers and as depicted in Figures 24

and 25, are becoming more common. "Caustic embrittlement" was an important consideration in riveted drums with their many crevices but is

much less of a problem in modern "all -welded" boiler construction.

However, this tube failure confirms the necessity to be careful -- even now -- with crevice areas and high concenrations of "free caustic" in the

boiler water. In modern boilers, caustic embrittlement usually occurs as

a result of leaking tube seats. The corrosion attack usually takes place

in a few inches beyond the drum or header and progresses from the external

tube surface inward.

Oxygen Attack

"Dissolved oxygen" attack takes several forms. It contributes to the

amount of "preboiler corrosion products" transported to the boiler which,

in turn, contributes to "underdeposit" pitting type damage in economizer

tubes, boiler drums, and steam generating tubes during operation.

It is the common denominator of corrosive attack under the

out-of-service conditions such as shipment and field storage and also

during equipment maintenance outages. A particular problem that is not

given the attention it deserves is the storage (layup) of superheater

loops under out-of-service conditions. Figure 38 is typical of the

metal lographic structures of dissolved oxygen pitting attack. The proper

utilization of modern deaerating equipment, the judicious use of oxygen

scavengers, and proper control methods can avoid this problem.

Chelants are, of course, effective in reducing boiler water sludge by

sequestering the residual feedwater hardness salts (magnesium and calcium)

and thereby contributing to the boiler tube cleanliness.

94
FIGURE 37. CAUSTIC EMBRITTLEMENT - GENERATING TUBE

95

Ref. 22
FIGURE 38. OXYGEN PITTING - ECONOMIZER TUBE (lOX)

Ref.

96

22
The corrosive damage caused by chelant overfeed (Figure 39) is

usually more prevalent in areas of high steam quality and high velocities

in the boiler or areas of high turbulence in the economizer.

Low Temperature Acid Attack

There is another all too common and unnecessary form of corrosive

tube damage. Low temperature acid attack can result from improperly

inhibited cleaning solvents or by not completely neutralizing chemical

cleaning solvents and rinsing them from the boiler after chemical

cleaning.

The corrosive attack is usually preferential to highly stressed

pressure parts and its appearance is not unlike the attack (Figure 38)

attributed to chelants. Metal 1 ographical ly, it can be differentiated from

pitting corrosion by the obvious dissolution of inclusion "stringers" in

the boiler steel. Pitting by dissolved oxygen or bulk transcrystal 1 ine

"under-deposit" corrosion does not usually result in this.

Summary and Conclusions

These are typical of the pressure part damage experienced by utility

and industrial recirculating steam generators. Corrective actions for

these are adequate. The equipment, in most cases, must be cleaned, water

treatment methods and feedwater purification improved, and better

long-term water technology management employed.

The requirements for system modifications (design changes) to correct

for such things as improper mass flow in tubes are very infrequent and the

appropriate action is usually apparent. More important are careful

considerations regarding the choice of materials in system components in

the bal ance-of-pl ant (feedwater heaters, condensers, heat exchangers,

etc.) to insure compatibility with the best possible water treatment

additive system program without compromises and tradeoffs in the corrosion

97
FIGURE 39. CHELANT ATTACK - GENERATING TUBE

98

Ref. 22
rate of one part of the system as opposed to another. This results in

cleaner boilers—and clean boilers with good circulation have fewer

problems and higher availabilities.

Chemical Cleaning

No water treatment process or component design arrangement can assure

steam generator (boiler) cleanliness over its entire design life.

Therefore, viable chemical cleaning methodology has been developed for

cleaning both modern high pressure industrial and utility steam

generators.

Preboiler Cycle

One of the very important things to do is degreasing by alkaline

cleaning and flushing of the preboiler cycle after construction to remove construction lubricants and other dirt and debris before start-up. Beyond

that, if there has been any significant rusting and oxidation of component

surfaces during storage, erection, and hydrotesting, it may be desirable

to also acid clean these surfaces. It is important that competent,

experienced contractors do this work or almost irreparable damage to the

system components can occur. Proper post cleaning storage under

controlled conditions is equally important so that the surfaces remain

clean and free from rust.

Steam Generator

Steam generator cleaning is carried out in a similar manner with

approved and inhibited cleaning solvents by one of the established

processes. This may be repeated several times during the life of the

equipment to insure clean heat transfer surfaces for reliable, trouble

free operation. Recirculating steam generators (boilers) are normally

cleaned by properly inhibited mineral acids (hydrochloric) by either the

circulation or soaking methods. Once-through steam generators are cleaned

by organic (chloride free) chemical cleaning chemicals. (Usually either

inhibited hydroxy-acetic formic acid mixtures of formulations consisting

99
of ethylene diamine tetra acetic acid (ETDA). The once-through steam

generator usually contains austenitic steel which is subject to stress

corrosion cracking in hydrochloric acid.

More recently, because of exfoliation of oxides from superheater/

reheater steam-side surfaces after long periods of operation, these

surfaces are being chemically cleaned. Properly inhibited organic

cleaning materials are employed for this purpose. Because of the low

pressure drop through the superheater/ reheater banks, it is doubly

important that the steam generator manufacturer as well as competent

chemical cleaning contractors be involved in such a cleaning process.

100
REFERENCES

1. K. H. Haller, N. J. Mravich, and J. W. Seifert, "The Nature and Behavior

of Corrosion Products in Once-Through Boilers", Paper No. 9, NACE

CORROSION/71.

2. K. H. Haller, R. A. Lee, and J. S. Slotnik, "Heat Transfer and Friction

Characteristics of Porous Magnetite Layers in Once-Through Boilers",

ASME Paper 71-WA/HT-45.

3. H. A. Klein, et. al., "A Field Survey of Internal Boiler Tube Corrosion in

High Pressure Utility Boilers", in Proceedings of the American Power

Conferen ce , Vol. 33, 1971, pp. 702-709.

4. F. J. Pocock, "Waterside Corrosion and Contaminant Transport Control for

Modern Central Station Steam Supply Systems", NACE Corrosion in the Power

Industry Conference, Montreal, Canada, September 27-29, 1977.

5. B. W. Bussert, R. M. Corran, and G. C. Gould, "The Effect of Water

Chemistry on the Reliability of Modern Large Steam Turbines", ASME Paper

78-JPGC-PWR-9.

6. Water Treatment for High Pressure Drum Type Boilers , Technical Brochure,

The Babcock & Wilcox Company, Barberton, Ohio.

7. Private Communication.

8. E. P. Partridge, "Hydrogen Damage in Power Boilers", Paper No. 63 PWR-9,

The National Power Conference, Cincinnati, Ohio, September 23-26, 1963.

9. W. C. Ames and J. A. Lux, "An Experimental Investigation of Hydrogen

Damage in Boiler Tubing", The American Power Conference, April 25-27,

1967.

10. R. V. Macbeth, R. Trenberth, and R. W. Wood, "An Investigation into the

Effect of 'Crud' Deposits on Surface Temperature, Dry-Out, and Pressure

Drop with Forced Convection Boiling of Water at 69 Bar in an Annular

Test Section". UKEA Report No. AEEW-R705, Winfrith, Dorchester, UK, 1971.

11. P. A. Akolzin and 0. I. Martynova, "High Purity Steam Research in the

U.S.S.R.", Industrial Water Engineering , December, 1969, p. 29.

12. H. M. Rivers, "Concentrating Films - Their Role in Boiler Scale and

Corrosion Problems", in Proceedings of the Twelfth Annual Water Conference , Pittsburgh, Pennsylvania, October 22-24, 1951, pp. 131-137.

13. F. Gabrielli, W. R. Sylvester, and G. W. Thimot, "Contamination Prevention

of Superheaters and Reheaters During Initial Startup and Operation",

American Power Conference, Chicago, Illinois, April 20-22, 1976.

14. Babcock & Wilcox Company Internal Research Report.

101
15. K. W. Herman, "Causes and Cures of Waterside Problems in Industrial

Boiler Systems", Combustion , August, 1978.

16. J. Dawson, Jr., and T. J. Tvedt, "Fifteen Years of Operating Experience

with ETDA in High Pressure Industrial Boilers," American Power Conference,

Chicago, Illinois, April 25, 1978.

17. J. S. Beecher, I. B. Dick, R. W. Lane, and L. H. Vaughn, "How to Determine

When a Boiler Requires Chemical Cleaning", Task Force Report, ASME

Research Committee on Water in Thermal Power Systems.

18. J. S. Beecher, J. Moulds, "Corrosion Control in Steam Generating Systems,

The Role of Sulfite, Hydrazine, Neutralizing Amines and Ammonia", Water

Chemistry and Corrosion Problems in Power and Industrial Plants , PECS,

Hungary, August 27, 28, and 29, 1981.

19. "Consensus on Operating Practices for the Control of Feedwater and Boiler

Water Quality in Modern Industrial Boilers," published by the American

Society of Mechanical Engineers, 1979.

20. "Occupational Exposure to Hydrazines", DHEW (NIOSH) Publication No. 78-172,

U.S. Dept, of Health, Education and Welfare, National Institute for

Occupational Safety and Health pp. 1-168 (1978).

21. P. H. Effertz, et al, "Combined Oxygen/Ammonia Conditioning Process of

Water-Steam Loops in Power Stations with Once-Through Boilers,"

Allianz Technical Information, D-8000 Munich 44, P. 0. Box 24, W. Germany.

22. Pocock, F. J., Lux, J. A., "Waterside Corrosion in Fossil Fired Steam

Generators," HIA Symposium on the Effect of Water Chemistry on CorrosionInduced Failures in Power Systems," National Association of Corrosion

Engineers, Atlanta, Georgia, March 12-16, 1979.

23. Coit, R. L., "Design Trends in United States Utility Feedwater Heaters

and Condensers," Paper No. 2, International Nickel Power Conference,

Lausanne, Switzerland, 1972.

24. Pocock, F. J., et al , "Control of Iron Pick-Up in Cycles Utilizing Steel

Feedwater Heaters," Proceedings of the American Power Conference,

Chicago, Illinois, 1966.

25. Pocock, F. J,, Banweg, A., "Current Waterside Concerns in Fossil Utility

Steam Generators," Paper NO. 100, 162nd Annual Meeting, The Electrochemical

Society, Detroit, Michigan, October 17-21, 1982.

102
WATER QUALITY IN BOILING WATER

REACTOR CYCLES

M. MADDAGIRI

MOISTURE SEPARATOR

AND REHEATER

Direct cycle power system. Stenm generated in the reactor vessel is used directly to drive the turbine-generator.

103
F.1.1 WATER QUALITY

The quality of water is controlled by installing appropriate

system ma,terials, by operating with high purity water and, or

installing and operating with industrial type, utility starion

water ’treatment equipment.

Reactor Water - Operation in Excess of 1% of Rated

Steam Flow

The quality of reactor water shall not exceed the follcwinc

limits

Conduc tivi ty o

t1— umho/c.m

Chloride (as Cl) 0.2 ppm

pH 5.6 to 8.6 a

Reactor water may exceed these limits but exceeding the

following maximum time or quality limits shall be cause fcr

shutdown and cooldown to the depressurized condition until

the water is within the quality limits specified for startup

and operation up to 1% of rated steam flow.

Conductivity

Time above 1 umho/cm

Chloride (as Cl)

Time above 0.2 ppm (Cl )

10 umho/cm at 25°C

2 wk per 12 mo period

0 . 5 ppm

2 wk per 12 mo period

If the above maximum time and quality limits are reached , the

pK can range between 4 and 10, depending on impurities present.

When the reactor is operating at a conductivity greater than

1.0 umho/cm at 25 °C, pH shall be measured and, if found to

be out of the 5.6 to 8.6 range, shall be brought within such

range w’ithin 24 hours using installed Unit water treatm.ent

equipment. If the pH cannot be corrected or exceeds the 4 to 10 range, the reactor shall be shut down and cooled down.

104

i
cleaning or testing, the quality of the water shall be

monitored and shall meet the water quality requirements

specified for reactor water with the reactor vessel in a

depressurized condition (see above)

.

Any time prior to fuel loading, when the reactor vessel is

heated above 200°F (93°C) for cleaning or testing, the quality

of water shall be monitored and shall not exceed the following

limits

Conductivity

Chloride (as Cl)'

pH

2 umho/cm at 25°C

0 . 2 ppm

5.6 to 8.6 at 25“C

Feedwater

The Unit design shall include the features specified herein

to minimize and/or control the reactor feedwater input of

materials specified below.

During normal operation the quality of feedwater to the

reactor vessel (measured before the outboard isolation valve

except as noted) shall not exceed the following limits:

Conductivity

Metallic impurity

Oxygen

Chlorides (Cl)

<0.1 umho/cm at 25*C

Tmeasured after the condensate treatment system)

£15 ppb of which no more

than 2 ppb may be copper

200 ppb maximum; 20 ppb

minimum (measured after

the condensate treatment

system)

Feedwater chloride concentrations shall be maintained within limits such

that chloride concentration

limits in reactor water

specified for operation up

to and in excess of of

rated steam flow are maintained

105
I

I

!

I h' “ i'vA, •,/ ~\i'- .. !A.T I .

iz

£--£:TIVE fuel POV/E!^ YEA!EL EF:M ; lUW PADIATICN F_/UnTc

'..';l/-,TlON F'iE_0 iE Ul L!>- 'P 0'\ TnEEIPI —LT lE\ "IP \E-

'RE FEB APPENDIX ?l Fl C- Z~ FIG 2 106
I c

c

C

.3

S"i A.vjis A.!v i Ai " O STAGNANT AlR

SAT’JAATz.T v'vAT”~ ici SATURATED WATEK (5. ISE °F

ITT SCRRCSiCN

107
(2) Corrosion Product Control

(a) Performance of Condensate Purification System

Corrosion

Product

Tyoe

Deep-Bed

(D/B)

Deep-Bed

wi th

URC***

FilterDemi nerali zer

(F/D)

Dual

(D/B + F/D)

Insol uble* 'v.lO ppb 5-6 ppb 2-3 ppb n.0.3 ppb

Soluble** _<2 ppb <2 ppb 3-4 ppb 0. 1-0.2 ppb

Total 'V'12 ppb 5-7 ppb 'vS ppb 'v.0.5 ppb

Insoluble = Corrosion Products retained on 0.45 micron

Mi Hi pore

^

fi Iter membrane.

Soluble = Corrosion Products penetrating a 0.45 micron

Cp) Mi llipore^ filter membrane.

Deeo-5ed system with effective use of ultrasonic resin cleaners

(URC).

(b) Corrosion product concentration in forward-pumped drain stream is

21 ppb, steady state, and 31 ppb average.

(c) Forward- pumped drain flow is 30 percent of total feedwacer flow.

3. 1.1.1 Plants with Fully Cascading Feedwater Heater Drains . Select a fi Iterdemine ralTzeFrTr^a^aiip^^D^G^vTTirrTnnjrErai'orTTFTeril^^ if the chloride

concentration in the condenser cooling water is less than 40 ppm. If chloride

concentration is greater than 40 ppm, select a deep-bed demineralizer with an ultrasonic resin cleaner. For additional margin, select a dual treatment system.

3. 1.1. 2 Plants with Forward- Pumped Feedv/ater Heater Drains . Select a filterdemine ralT2irnT”crrrorTae~concerrt7iTron~TfPEni'Tondens^^ water is less

than 40 ppm. If chloride is greater than 40 ppm, select a dual treaL-.ent system.

A deep-bed demineralizer with an ultrasonic resin cleaner may be adequate, if

the forward-pump drain system is designed to minimize corrosion/erosion effects.

108
TURBINE

c/1 O

u

n (/I I I

109

FIGURE 1

NON-REMEAT,

CASCADE

FEEDWATER

HEATER

DRAINS
TURBINE STEAM CHEMISTRY

W. T. Lindsay, Jr.

Westinghouse R&D Center

Pittsburgh, PA 15235

ABSTRACT

This presentation is intended to introduce the subject, summarize problems

and progress, and give the author’s view of the role chemical thermodynamics has or could have in this area. Topics discussed are: the

turbine part of the steam cycle; chemical composition of steam; sources of

impurities; effects of impurities; the condensation process and its

consequences; fluid composition modeling for turbine steam; shortcomings

in the data base; and recommended priorities for expansion of the data

base

.

The main topics discussed in this presentation are covered by the

following papers, which are reproduced here in lieu of a written summary:

1. Behavior of Impurities in Steam Turbines.” W. T. Lindsay, Jr., Power

Engineering ^ (No. 5), 68-72 (1979).

Reprinted with permission (c) Copyright Technical Publishing a Dun

and Bradstreet Company.

2. ’’Turbine Steam Purity - 19179 Update.” 0. Jonas, W. T. Lindsay, Jr.

and N. A. Evans, pages 595-607 in ’’Water and Steam. Their Properties

and Industrial Applications,” J. Straub and K. Scheffer, eds.

(Pergamon Press, Oxford, 1980).

Reprints with permission (c) Copyright Pergamon Press Inc.

3. ’’Steam Purity Analysis Instrumentation for Turbines and Power

Plants.” W. M. Hickam, S. H. Peterson, D. F. Pensenstadler , and

J. C. Bellows. Advances in Instrumentation Vol. 36, Part 2, 1981.

Reprinted with permission (c) Copyright Instrument Society of America

4. ’’The Verification of Concentrated Impurities in Low-Pressure Steam

Turbines.” W. G. Steltz, P. K. Lee, and W. T. Lindsay, Jr., J. of

Engineering for Power 105 , 1923-198 (1983).

Requested with permission (c) Copyright American Society of Mechanical

Engineers

110
Behavior of impurities in steam turbines

Dissolved impurities carried over to the turbine in steam-eiectric

plants can damage blades. Knowledge of their concentrations and effects

can help in proper material selection and improved plant operation

By W. T. LINDSAY, JR., Westinghouse R&D Center

In studying the behavior of impurities in steam turbines, the overall objective is to understand, quantify,

and predict this behavior. Average

concentrations of the minor constituents, which exist at levels from parts per million (ppm) down to parts per

billion (ppb), are transformed into higher local concentrations. Knowledge of these concentrations is helpful in guiding materials evaluations

programs, in turbine design, and for plant operations.

Detailed calculations of the equilibrium fluid composition involving some important volatile substances

such as ammonia, amines, boric

acid, or carbonic acid can be per- formed because most of the data that

is needed for this purpose is avail- able. These substances are important because ammonia and amines

are used for control of pH, and the

volatile boric and carbonic acids are often unavoidably present. Fluid

composition modeling for these volatiles is discussed in the first part of

this article. A general picture of the behavior of two other important contaminants, sodium hydroxide and

sodium chloride, will be covered in the second part.

Fluid composition modeling

The objective of fluid composition

modeling for the volatiles is to calculate the equilibrium composition of both steam and moisture in a turbine

system in a particular plant. Thermodynamic data are needed on liq- uid-vapor distribution coefficients. High-temperature ionization constants are needed for all of the

possible dissolved species that can

form in the moisture of steam. For

the particular machine and plant

combination that is under study, the

flows, enthalpies, temperatures,

moisture contents, and so on must

be determined as a function of load. With this information as background,

modeling calculations can be per- formed that explore the effects of parameters such as load, the composition of the inlet stream, the

performance of components (e.g., the moisture separators in the moisture separator-reheaters (MSRs) of nuclear plants), and other operating

options, such as reheat or no reheat.

Basic Molller diagram

A Mollier diagram (Figure 1) is a plot of enthalpy vs entropy for steam and

steam-water mixtures. The curved

line across the middle of the plot is the saturation line for water. Above

this line is the region of dry or superheated steam, and below it is the region of wet steam or a mixture

of steam and water. Also on this plot are the expansion lines for steam as

it passes through a PWR nuclear

turbine system. Inlet steam starts near saturation conditions and ex- pands into the wet region as it goes

through the high pressure (HP) tur- bine. It then goes through the MSR.

first bringing the steam quality back

to saturation conditions, followed by

the addition of superheat to the

Figure 1. Mollier diagram for steam and steam-water

mixtures, showing condition of steam through various stages of a PWR plant turbine.

1

A. Expansion through high-pressure turbine

B. Passage through moisture separator-reheater

C. Expansion through low-pressure turbine D To low-pressure turbine exhaust

Figure 2. Concentration of ammonia in moisture carried by steam passing through a PWR plant turbine.

2

Turbine High-pressure Low-pressure

location section 5^5 section

111
saturated steam. Finally, the steam

expands through the low pressure

(LP) turbine, passing into the wet

region where the steam again contains high moisture, until it reaches

the turbine exhaust pressure. The conditions are constantly

changing as the steam passes

through the system, so calculations

have been performed at a number of locations along the expansion path.

These locations are indicated by the

stroke marks along the expansion

curve.

Volatile contaminants

Figure 2 shows the concentration of ammonia in moisture decreasing as

the steam expands through the sys- tem, from the HP turbine inlet at the

left through to the LP turbine outlet

at the right. Each of the dots along

the expansion lines on the plot

corresponds to one of the calculation locations shown in Figure 1. The

breaks in the curve indicate places

where extractions of steam and

moisture occur. For this case, the

inlet steam to the HP turbine was

assumed to contain an average concentration of about 0.25 ppm of ammonia, which would give a pH 9

(alkaline) condensate at room temperature.

Ammonia is quite volatile, which means that most of it will appear in

the vapor phase. Consequently, the

calculation shows that the concentration of ammonia in the moisture at the HP inlet is only 0.09 ppm, and

decreases further as the steam continues through the system. Morpholine is much less volatile than ammonia; consequently, it is a more

effective alkalizer for the moisture in steam. The concentration of mor- pholine increases as one goes

through the system, starting from

about 4 ppm and increasing to nearly

18 ppm, as shown in Figure 3. This

calculation is for the case of the inlet steam containing 3.8 ppm of morpholine, which is equivalent to nor- mal ammonia, in that it also gives a pH 9 condensate. Comparing these

two plots shows how differently ammonia and morpholine behave.

pH changes

The pH can be calculated at the

temperatures that exist throughout

the turbine to determine alkalizing effects of the concentrations of ammonia and morpholine that will exist

in the moisture. The pH itself is not too useful, because the pH of neutral water changes with temperature.

Consequently, the results are shown

as pH units above neutral, i.e., the

alkalinity of the moisture.

Figure 4 shows how the alkalinity of moisture changes with normal ammonia, and Figure 5 shows how the

alkalinity changes in going through

the system with the equivalent

amount of morpholine.

these two plots look very muc^>^ke,

it can be seen by the battofw scales

that morpholine gives substantially more alkalinity. At the outlet of the LP turbine, morpholine drives moisture 2.2 pH units above neutral,

whereas ammonia provides moisture

with only a little over 1 pH unit above

neutral. Boric acid is a steam contaminant of current interest because of its possible use in PWR steam generators,

where borates tend to act as inhibi- tors of corrosion in crevices. With 1.8 ppm boron as the average concentration in the inlet steam, the boric

acid in the moisture starts from a peak of about 50 ppm at the inlet of the HP turbines and decreases

sharply. Then it rises slightly when it passes through the dryout point in the reheater, where all of the boric

acid volatilizes. A second peak of about 50 ppm occurs when the moisture begins to form in the LP turbine,

and it decreases to a very low level near the outlet of the LP turbine. This

is shown in Figure 6.

It must now be determined how

effective ammonia or amines are in offsetting the acidity that these concentrations of boric acid would proFlgure 3. Concentration of morpholine in moisture Figure 4. Degree of alkalinity of turbine steam due to carried by steam passing through a PWR plant turbine. ammonia in carried-over moisture.

£a

a

XI5

o

E

c

03co

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r urbine ocation section separator section reheater

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Turbine

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High-pressure

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Low-pressure

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POWER ENGINEERING/MAV 1979 112
IMPURITIES IN STEAM TURBINES

Figur* 5. Degree of alkalinity of turbine steam due to morpholine in carried-over moisture.

Figure 6. Concentration of boric acid in turbine steam

oexiorl miior moisture.

Figure 7. Change in pH above neutral with several concentrations of acid and alkali in moisture caa0n4m‘f( in turbine steam.

0 2.400 PSI drum boiler

Figure 8. Mollier diagram of the expansion characteristics of steam passing through three sections of a turbine system for a fossil-fueled boiler. A portion of the 50% load line is shown for part of the LP turbine expansion process.

Figure 9. Mollier diagram of the expansion of steam in a turbine system for a fossil-fueled boiler. Added lines show sodium

hydroxide liquid phase concentrations and approximate solubility of NaOH in the steam in parts per billion.

Figure 10. (below) Low-pressure turbine from a fossil-fueled plant contaminated and damaged by an excess of NaOH in the steam. The white deposit is sodium carbonate

113 POWER ENQINEERING/MAY 1979
duce in moisture. The center line in Figure 7 shows the relative alkalinity

when normal ammonia is present.

The lower curve shows that boric

acid depresses the pH of normal

ammonia by about 0.3 pH unit where

moisture begins to form in the LP

turbine and 0.4 pH unit at its outlet. The upper line shows that an amine,

at the amount equivalent to normal

ammonia, gives a higher pH. even

with boric acid, than would happen

with normal ammonia alone. In this example the amine is cyclohexylamine. but very much the same result

is obtained when morpholine is used

in the calculation at the amount that

is equivalent to normal ammonia.

In other words, the use of either of these amines, morpholine or cyclohexylamine, more than compensates

for the pH depression that boric acid

would cause. This is desirable be- cause a higher pH (additional alkalinity) in moisture is better for tur- bine materials with respect to many

possible corrosion effects. The uses of fluid composition modeling can be expanded to accommodate other situations. Application

may be useful in cases where nonvolatiies. such as sodium hydroxide

and sodium chloride, are present

with volatile acids and bases. A

desirabie application is the inclusion

of the effects of oxidation-reduction

reactions, since chemicals that participate in these kinds of reactions

have an effect on the corrosivity of turbine moisture. These calculations

could be modified to include nonequilibrium effects, as well.

Non-volatile contaminants

The non-volatile contaminants mentioned above are quite different from

the volatiles. The first is sodium

hydroxide, and it is important for two

reasons. First, caustic contamination

of steam can happen a number of

different ways, and it seems to happen with distressing regularity. It can

be caused by improper regeneration

of condensate poiishers; it can be

caused by chemistry upsets in phosphate-treated boilers; or it can be

caused by poor steam separation in drum boilers that are being deliber- ately treated with low-level free

caustic. Second, no practical turbine

POWER ENGINEERING/MAY 1979

materiais can stand up under the

corrosive or stress corrosion effects

of concentrated caustic. Sodium hydroxide has probably damaged more

turbines than any other single contaminant.

It is useful to describe the behavior

of sodium hydroxide in connection

with a Mollier chart. Plotted on the

Mollier chart of Figure 8 are expansion lines for steam passing through

a turbine system for a fossil fuel unit with a 2400-psi drum boiler. After evaporation, the steam passes

through the superheater, expands

through the HP turbine, is reheated

and expands again through the inter- mediate pressure (IP) turbine, and

passes through most of the LP tur- bine before it enters the wet region.

A part of the LP expansion line for 50% load is shown to the right, where

it can be seen how the dry-to-wet

transition shifts to a different location in the turbine at reduced load. Solutions of sodium hydroxide can be very concentrated: these concentrated solutions have elevated boil- ing points so they can exist in the

region of superheated steam. Lines

showing sodium hydroxide concentrations of 25% to 90% are shown in the Mollier diagram of Figure 9. These concentrated solutions cover almost all the region traversed by the

steam expansion line. It is only in the wet region, near the outlet of the LP

turbine, where the sodium hydroxide

concentration becomes so dilute as

to be non-corrosive.

The solubility of sodium hydroxide

in steam must be found so a deter- mination can be made of how contamination level affects the location

of damage. Some lines have been

added to Figure 9 indicating the

approximate values of sodium hydroxide solubility in steam. Information from measurements made so far

is incomplete, but EPRI-sponsored

research projects now underway

may provide better results. By combining these two sets of lines on a Mollier chart, it can be seen how

a caustic contamination incident that would put a quantity (say 100 ppb)

of sodium hydroxide in the steam

could produce a 90% concentrate of sodium hydroxide as a liquid some- llA

where in the IP turbine, as indicated

by the intersection of the 100 pbb

solubility limit and the IP steam

expansion line. Damage could also occur in the LP turbine, but caustic

contamination effects are not limited to the interiors of turbines. For ex- ample, crossover piping has suffered from caustic damage.

Figure 10 is a photograph of an LP

turbine that was damaged by caustic

contamination when used with a

fossil-fueled unit. A heavy white

encrustation of sodium carbonate is visibie on two of the rows of blades on both halves of the turbine. Sodium carbonate is formed when

parts coated with concentrated so- dium hydroxide are exposed to air. In this incident, the caustic contamination most probabiy resulted from

improper regeneration of condensate poiishers.

Another contaminant of great impor- tance is sodium chioride. Salt is a very common contaminant of steam,

and its concentrated solutions can cause pitting, corrosion fatigue, and

stress corrosion cracking. The ther- modynamic properties of sodium

chloride are very different from those

of sodium hydroxide, because it has

a more limited solubility. The same

Mollier chart and the same expansion lines for a 2400-psi drum boiier turbine system are shown in Figure

11. The shaded band is the oniy

region where concentrated salt solutions are stable. Above the shaded

band, only pure dry sodium chloride

is stable in the dry, superheated

steam. Below the band, in the wet

region, salt contamination becomes

so dilute as to be without much

corrosive significance.

Along the upper boundary of the

shaded region there are solutions

that are saturated with solid salt. At

the point where the LP expansion

line crosses into this region, the

concentration is 28% sodium chloride at the upper boundary and close

to 0% at the lower boundary. The

important feature is that corrosively

significant solutions of salt are ther- modynamically stable only within one stage of the LP turbine. This

location can shift slightly as the

load changes.
IMPURITIES IN STEAM TURBINES

11

HP

section expanFigure 11. Mollier diagram of the expansion of steam in a turbine system for a boiler with NaCI contained in the steam. Estimated

solubility of dry salt in superheated steam is shown in ppb.

Figure 12. Magnified portion of the Mollier diagram of Figure 11 showing expansion through the LP section of the turbine in the region of concentrated NaCI solutions.

Estimates of the solubility of sodium

chloride in steam can be made as was done before with sodium hydroxide. These estimates should not be

relied upon completely with respect

_to their absolute values, but Figure

11 shows approximately how the

solubility of salt in steam varies. A

28% solution of salt can be produced

from very low levels of steam contamination.

Localized effects

It is interesting to look more closely

at the place where the expansion line crosses the region of stable NaCI

solutions. Figure 12 shows a magnified view of the region. Expansion

through one stage of the turbine covers the region from A to C. The

region from A to B includes the expansion across the stationary

blades, and B to C represents the expansion across the rotating blades. The pressure between the stationary

blades and the rotating blades is indicated on the Mollier chart by the constant pressure line B-B'. The

pressure at the outlet of the stage,

after the rotating blades, is indicated

by the constant pressure line C-C'. There are many local effects going on inside turbines, and the expansion line represents only conditions

along the mam steam flow path.

Steam that passes through the controlled leakage seal at the tip of the

rotating blade will expand at constant enthalpy along the horizontal arrow from B to C, on the constant

pressure line C-C', because it does

no work. This steam could deposit

solid sodium chloride but not any

solution. However, with the conditions prevailing, wet steam at condition C could intermittently mix into the region where the deposit has

been formed and wet it. There could

thus be an alternating wet and dry

situation in a very local region near

the seal. Another interesting localized effect could occur near the tips or near the base of the blades, where the machine is not as efficient in extracting

work from the steam. This is illus- trated by the lower arrow from B to the point C2 , where the expansion

path lies entirely in the region of concentrated liquid solutions.

Corrosive effects due to sodium

chloride contamination can be found

wherever concentrated solutions of

sodiurji chloride persist. These are very localized within one stage of the turbine and can be formed from very Iqw levels of salt contamination.

Summary

It has been noted that different impurities behave differently For example, solutions of sodium chloride are stable only in a narrow band near the liquid-vapor saturation line,

whereas solutions of sodium hydroxide can exist over the entire range of expansion from the inlet to the high pressure turbine to the beginning of the wet region in the low pressure

turbine near the exhaust. This means

that the corrosive effects of sodium

chloride are very localized, while

those of sodium hydroxide can oc- cur anywhere, depending on the

level of contamination.

In addition, fluid composition modeling has been shown to be a useful new tool for quantifying turbine materials' environments. The use of this technique makes it possible to provide realistic predictions that are

specific and detailed enough to be

very helpful in guiding designs and

establishing operating procedures.

The technique can be expanded to have greater generality, and calculations can always be refined as new

and more reliable basic data are generated by research programs. END

To obtain an axira copy of this articia, circia 204 on Readar Sarvica Card

115

POWER ENGINEERING/MAY 1979
TURBINE STEAM PURITY — 1979 UPDATE

O. JONAS, W. T. LINDSAY. JR.* and N. A. EVANS

Westinghouse Electric Corporation, ST-G TOD, N-207, P.O. Box 9175,

PhJadeiphia, PA 19113, USA

Westinghouse R&D Center, Beulah Road, Kttsburgh, PA 15235, USA

ABSTRACT

An update of turbine corrosion statistics, chemical composition of steam, water

and deposits, relations between the low ppb average impurity concentration in? steam to high concentrations in condensed phases, and new observations of the

' nonsteady condensation near the transonic flow region, where most turbine

corrosion occurs, are given. Current steam chemistry specifications and steam chemistry resulting from boiler water and feedwater control are summarized, and

the relations between water and steam chemistry control, actual steam composition

and turbine corrosion are discussed.

KEYWORDS

Turbine steam; composition; deposits; concentration of impurities; solubility;^

condensed phases; Wilson line; sodium chloride; sodium hydroxide; corrosion.

INTRODUCTION

The high cost of turbine corrosion, particularly In the U.S.A. (Jonas, 1978;

Bussert, Curran and Gould, 1978) has brought a renewed interest in turbine steam

purity. Our estimate is that 30% of the U.S. utility units operate with high

concentrations of impurities in steam, 20% of these units with corrosive impurities. Since 1964, utilities owning Westinghouse units have experienced more than

140 stress corrosion and corrosion fatigue failures of turbine components (Fig. 1

YEAR Figure 1. Turbine corrosion failures - Westinghouse

).

116
0. Jonas, W. T. Linsday Jr. and N. A. Evans

The Edison Electric Institute's recent survey of 125 units in the U.S., representing all makes of turbines, found that corrosion-related blade failures have

been a problem in 73 units with a total generating capacity of 39,000 MW.

Since the early steam and deposit chemistry studies (summarized by Pocock, 1979

and Jonas, 1978), not only was the chemical control in some U.S. power stations

relaxed, but also larger units came on-line with higher steam flows, more turbines

with supersonic flow velocities, and more once-through boilers and units using

all volatile water tpeatment. In some geographical regions, corrosion problems

could relate to increased levels of industrial and agricultural pollutants in the

cooling and/or makeup^water . The effects of the above changes on steam chemistry,

as well as many equilibrium, and more importantly, dynamic properties of steam with impurities are little understood. Some research, in our opinion not enough,

has been initiated to improve the understanding. As indicated in recent discussions

of the ASME Research Committee on Water in Thermal Power Systems, some of which

are summarized by Rice and Passell (1978), and in conclusions and recommendations

of the Electric Power Research Institute workshops on Steam Purity for Turbine

Protection (1979), and on Corrosion Fatigue of Steam Turbine Blading Alloys

(1979), much of the current research is not directly applicable to the control of

chemistry of turbine steam with the complex mixtures of impurities and additives,

flow velocities up to supersonic, steam expansion rates 1_ ^ up to about 3000 s"s

P dt ; and the presence of metal surfaces of various roughness and degree of oxidation.

In spite of the lack of knowledge of chemical thermodynamics of steam with

impurities, impurity limits for turbine steam have been recommended (Jonas,

1978) or specified (Allis Chalmers Co., General Electric Co., 1977; VGB, 1972,

1973; CEGB, 1975; Martynova, 1972). These are based partly on limited thermodynamic data and partly on experience and analytical detection limits. Where

steam purity limits have not been specified, such as for example in the Japanese

Standard JIS B8223 (1976), boiler water limits for recycle boilers and feedwater

specifications for once-through boilers control the steam chemistry. Whether

these specifications are too conservative and force unnecessary operating costs,

or whether they are not strict and comprehensive enough and could result in turbine corrosion, will be tested by service experience.

COMPOSITION OF WATER, STEAM, AND DEPOSITS

Through surveys of deposit composition (Jonas, 1973, 1975, 1978) and monitoring of

condensed steam and water chemistry of about 200 modern utility units, and after

inclusion of data by Kirsh and Pollmann (1968) and Martynova and Rogatskin (1970),

a list of chemicals found in steam turbines (Table 1) was compiled. It contains more than 160 compounds and elements. The deposits were analyzed semiquanti tatively

,

by wet chemical methods, and by X-ray diffraction. Water and condensed steam samples were analyzed by wet methods, including liquid ion chromatography and by continuous

analyzers. EPA chemicals (pollutants) were analyzed by gas chromatography. Some

compounds, such as for example ammonium salts, were not identified directly, but were inferred from the stoichiometric balance of the liquid samples. With the

exception of acids, gases, EPA chemicals, volatile additives and ammonium salts,

all of the chemicals in Table 1 have been identified in turbine deposits, i.e., in

a concentrated form. Deposit composition only partially reflects the "in-situ“

chemistry of a running turbine. Some components may be washed away by moisture

during unit shutdown, others will react with air and metallic surfaces after shutdown, and some can volatilize. Concentrations in liquid samples were from sub-ppb

to ppm, in deposits from a fraction of a percent to almost 100%. In addition to the identification of chemicals listed in Table 1, low pressure turbine steam compositions (averages, standard deviations and maxima) are given in Table 2. The

averages and standard deviations are from fourteen turbines sampled at high steady

load, except for the case of sodium for which one unit with extremely high sodium

levels (up tq 250 ppb) was excluded. Including that unit, average Na =« 18.8 ppb,

standard deviation 50.7 ppb.

117
Oxides

Turbine Steam Purity - 1979 Update

TABLE 1 Chemicals Found in Steam Power Systems

Fe304 Iron oxide

Fe203 Iron oxide (a, y, c) FeO Iron (II) oxide

FeO(OH) Iron oxide hydrate (a, B, y)

FeCu02 Copper iron (II) oxide

FeCr 204 Iron chromiua oxide

(Cr,FeJ 203 Chromium, iron oxide

CuO Cupric oxide

Cu20 Cuprous oxide

Cu 5 Fe307 Copper iron oxide

CuA 102 Copper aluminum oxide

aAl 203 Alpha aluminum oxide

Cr203 Chromium oxide

CoFe204 Cobalt iron oxide

NaFe02 Alpha sodium iron oxide

Na2 Fe204 Sodium iron oxide

Ca(A102)2 Calcium aluminum oxide

MgFe204 Magnesium iron oxide

PbO Lead oxide

PbFe407 Lead iron oxide

Ti 02 Titanium oxide

CaTi 03 Calcium titanium oxide

Na20 Sodium oxide

Si 02 Silica (hex.-rhd., rh., tetr., amorphous)

Si 1 i cates .

Na2 Si 03 Sodium metasilicate

Na2 Si 03 * 5 H20 Sodium metasil icate pentahydrate

Na2 Si 03 ' 9 H20 Sodium metasi 1 icate nanohydrate

6 fJa 2 Si 205 Sodi urn di sil icate

NaAlSi 04 Sodium aluminum silicate

Na[AlSi 206 ] •H 2 O Sodium aluminum silicate hydrate

Na4 Al 2 Si 60 i 7

' 2 H 20 Sodium aluminum silicate hydrate

Na4 Al 3 Si 30i 2 ( 0 H) Sodium aluminum silicate hydroxide

Na8Al 5

S 04 (Si 04)6 Sodium aluminum sulfate silicate

NaFeSipOg Sodium iron silicate

N 38 [Cl(AlSi 04 )g] Sodium chloro hexa-aluminum silicate

NaAlSiiOg Sodium aluminum silicate

Na5 Ca2 L(C03 ) 2 (AlSi 04 ) 5 ] Sodium calcium carbonate aluminum silicate

Al 2 Si 05 Aluminum silicate

KAlSigOg Potassium aluminum silicate

KNa3 (AlSi 04)4 Potassium sodium aluminum silicate

KNa3(AlSi04)6 Potassium tri-sodium aluminum silicate

•^0 33^^0 67^15^04 Nepheline

Mg 4 [( 0 H) 2 Si 60 i 5 ]- 2 H 20+ 4 H20 Sepiolite

M96[ Magnesium octa-hydroxy silicate

Mg 3 Si 4 ( 0 H )2 Magnesium silicate hydrate

Ca2 Si 204 Calcium silicate

Ca2 Al 2 Si 30io(OH )2 Calcium aluminum silicate hydroxide

Ca2 Si 04 -H 20 Calcium silicate hydrate

Cag[

(

0 H) 2 Sig0 i 7 ] Calcium silicate hydroxide (Xonotlite)

Ca(Al 2 Si 40x 2

)

6 H2 O Calcium aluminum silicate hydrate

118
0. Jonas, W. T. Lindsay Jr. and N. A. Evans

Ca2 NaH[Si 309 ] Sodium calcium silicate hydroxide (Pectolite)

Ca2 Al 2 Si 30 io(OH )2 Calcium aluminum silicate hydroxide

CaMg(Si 205 ) Calcium magnesium silicate

Ca2 Mg 5 ( 0 HSi 40 ii )2 Calcium magnesium hydroxide silicate

3 Al 2034 Na20 - 6 Si 02 -S 03 Noselite

(Fe,Mg) 7 Si 3022 ( 0 H )2 Iron magnesium hydroxide silicate

NdsAl 5

S

i

5024 Mo04 Sodium aluminum molybdenum oxide silicate

^93[ (OH)Si40iol Magnesium hydroxide silicate

Zn2 Si 04 Zinc silicate

Amorphous silicon cgmpunds

Sulfates **

Na2 S 04 Sodium sulfate

FeS 04 Iron (II) sulfate

FeS0a-H20 Iron (II) sulfate hydrate

NaFe(S04 ) 2

’ 12 H 20 Sodium iron sulfate dodecihydrate

CaNa2 (S 04)2 Calcium sodium sulfate

Cu4

S 0d( 0 H )5 Copper sulfate hydrate

Na2Cu(S04)2 Sodium copper sulfate

CuFe( 0 H) 2

S 04 Copper iron sulfate hydrate

AI 2 SO4 Aluminum sulfate

Al 4

S 04 ( 0 H) 10

* 5^20 Aluminum sulfate hydroxide, pentahydrate

CaS 04 - 2 H 20 Calcium sulfate dihydrate

CaS04 Calcium sulfate

Na5

C 03 (S 04)2 Sodium carbonate sulfate

Na3

Al 5 (Si 04 ; 6

S 04 Sodium aluminum silicate sulfate

(NH4 ) 2 S04 Ammonium sulfate

Phosphates

Na3P 04 Tri sodium phosphate

Na3P 04 ' 12 H20 Trisodium phosphate-12 water

Na2 HP 04 Di sodium hydrogen phosphate

NaH 2 P 04 Sodium dihydncgen phosphate

NaP 03 Sodium metaphosphate

(NaP 03 ) 3

- 6 H 20 Tri-sodium metaphosphate hexahydrate

FeP 04 Iron (III) orthophosphate

Fe(P 03)3 Iron metaphosphate

NaFe 3 (P 04 ) 2 ( 0 H) 4

• 2 H 2 O Sodium iron phosphate hydroxide dihydrate

(Fe,Mn

)

2 L (OH) (PO4 ) ] Iron manganese phosphate hydroxide (Wolfeite)

(Fe,Me) 2 [( 0 H)(P 04 )] Wolfeite

Na2 (Fe,Mn) 5 [P 04]4 Sodium iron manganese phosphate

Ca4

P 20g Calcium phosphate

Ca5 [ (OH) (PO4 ) 3 ] Calcium phosphate hydroxide

Mgx( 0 H)y(P 04)2 Magnesium hydroxide phosphate

(Na,Ca,Fe,Cu,Ni ) Mixed phosphate

Carbonates

Na2 C 03 Sodium carbonate

N 32 C 03 -H 20 Sodium carbonate monohydrate

Na2 C 03 - 10H 20 Sodium carbonate decahydrate

NaHC03 Sodium bicarbonate

Na 3 H(C 03 ) 2 -H 20 Sodium hydrogen carbonate monohydrate

Na3 H(C 03 ) 2

’ 2 H 20 Sodium hydrogen carbonate dihydrate

5 Na20 . 8 C 03 ‘ 3 H 20 Sodium carbonate trihydrate

3NaAlS

i

04 -Na 2 C03 Sodium aluminum silicate sodium carbonate

119
Turbine Steam Purity - 1979 Update

CaC03 Calcium carbonate

CaNa2(C03)2-2H20 Calcium sodium carbonate dihydrate

CuC07Cu( 0H)2 Copper carbonate, basic

(NH4)2C03 Ammonium carbonate

Chlorides Acids

NaCl Sodium chloride

KCl Potassium chloride

PeCl2 Iron (II) chloride

FeCl3 Iron (III) chloride

CrCl2 Chromium (II) chloride (possible)

CrCl3 Chromium (III) chloride (possible)

NH4C1 Ammonium chloride

Cu2(0H)3C1 Copper (II) oxychloride

Gases

H2SO4 Sulphuric

HCl Hydrochloric

CH3COOH Acetic

CH3CH2CO2H Propionic (Propanoic)

CH3CH2CH2CO2H Butyric (Butanoic)

fcoOH ^ Formic

H2Si03 Silicic

H3BO3 Boric

^ ~ 3,4, or 5 Polythionic

C02,N2,02,H2,C1,H2S

Uncompounded Elements

Si Si 1 icon aFe Alpha iron

c Graphite (carbon)

Cu Copper

Cr Chromium

S Sulphur

Other

NaOH Sodium hydroxide ; LiOH Lithium hydroxide

A100H.nH20 Aluminum oxide hydroxide

NaF Sodium fluoride

NOt Nitrate

Oils and oil decomposition products

Other Additives EPA Organics

NH4OH Ammonium hydroxide

C4HgN0 Morpholine

C5 Hi]^NH2 Cyclohexylamine

N2H4 Hydrazine

H2O2 Hydrogen peroxide

Na2S03 Sodium sulfite

Methoxychlor

Toxaphene

2,4,5-TP (Silvex) Traces of Endrin, Lindane, 2-4-D

In many units using all volatile treatment, analyses do not give a stoichiometric

balance between Na and anions. The excess anions have to be associated with NH4

or possibly hydrogen ion. Condensate polishers were frequently the source of

SO4.

Main sources of these chemicals are: condenser and air inleakage, condensate

polishers, makeup water, system corrosion, and contaminated water treatment and

polisher resin regeneration chemicals.

How these chemicals influence system corrosion and the properties of steam and

water is only partially known. In relation to turbine corrosion, the concentration of corrosive mixtures on metallic surfaces, and their effect on local pH

and redox potential are the most important. Locally, the mixtures range from

strongly acidic to strongly basic (particularly in deposits, crevices and pits),

and from reducing to oxidizing.

120
0. Jonas, W. T. Lindsay Jr. and N. A. Evans

How these impurities and additives concentrate from ppb or ppm average levels,

how they are transported from their sources through a power system, and how they

react with system metals are factors that govern the syst&m corrosion, erosion,

thermodynamic efficiency, performance of condensate polishers, and other parameters. They may also influence system perfonriance through effects on water and

steam properties, such as evaporation and condensation kinetics, thermal

conductivity, etc.

RELATION OF AVERAGE IMPURITY CONCENTRATION TO CONCENTRATION IN CONDENSED

PHASES

It was pointed out at the 8th ICPS by Lindsay (1974), that impurites most frequently

cause troubles in power stations when they can occur as condensed phases, in which

they may be highly concentrated. It is important to understand and to quantify

the processes by which condensed-phase concentrates of corrosive substances

can develop in operating turbines from steam that contains sub-ppm average levels

of impurities.

Sodium chloride and sodium hydroxide are frequent contaminants of steam, especially

in power stations with once-through boiler systems. These compounds typify two different classes of slightly volatile impurities; namely, those that are only

moderately soluble in hot liquid water (as is sodium chloride), and those that are

so soluble as to approach complete miscibility with water at relevant temperatures.

Thermodynamic analysis of the properties of liquid solutions of these substances,

in relation to the state lines for steam expansion in turbines, (Lindsay, 1979)

shows that liquid concentrates of sodium chloride are stable in turbines only

in a very narrow pressure range immediately before the dry-to-wet transition

(Fig. 2). This transition occurs at or below 1 atm absolute pressure, in the

next-to-last stage of the low pressure turbines of fossil-fueled units. Consequently,

corrosive effects that are due to sodium chloride and other contaminants of the

same solubility class are most pronounced in a localized region near the point

where moisture just begins to develop. In contrast, hot liquid solutions of

sodium hydroxide can be so concentrated as to have boiling point elevations

sufficient for stable persistence anywhere in the superheat region of the expansion

Fig. 2. Simplified Mollier chart showing

state lines for typical 165 atm boiler

and turbine. Stability region for liquid

aqueous concentrates of NaCl is indicated

by the shaded band just above the pure water saturation line.

Fig. 3. Mollier chart similar to Fig. 2 with NaOH phase equilibria superimposed.

Liquid aqueous concentrates of NaOH are stable throughout the range of superheat

conditions in the turbines.

121
Turbine Steam Purity - 1979 Update

The steam-phase solubilities of sodium chloride, sodium hydroxide and related

impurities are still highly uncertain, especially at conditions pertinent to intermediate and low pressure turbines (from around 35 atm, 570*C down to less

than 1 atm, 130*C). Extrapolation of steam-phase solubility data from higher

pressures (Lindsay, 1978) and preliminary evaluation of results from current

research projects sponsored by the U.S. Electric Power Research Institute (RP 969,

RP 1068) indicate that corrosively significant liquid solutions of both sodium

chloride and sodiu® hydroxide can develop from steam that contains low-ppb average

levels of contamination. In the event of caustic contamination that sometimes occurs at high-ppb or even ppm levels, sodium hydroxide solutions as concentrated

as 90 to 95 weight percent can precipitate in the higher-pressure, higher superheat

stages of turbines. On the other hand, with similarly high levels of contamination

by sodium chloride and in the absence of other extremely water-soluble contaminants,

only dry solid salt can condense at superheats exceeding the boiling point elevation

of solid-saturated salt solutions.

It appears also that the mechanism of condensation can differ for these two types

of impurities. With high contamination levels, from which the condensation of

liquid solutions of sodium hydroxide is thermodynamically possible at steam temperatures around 400*C or higher, rapid homogeneous nucleation and precipitation

of the condensed-phase concentrate can occur with a degree of supersaturation that is achievable well within the superheat region as the expansjon process

proceeds. The pattern of caustic deposition that is observed in turbines that

have experienced high-contamination-level events with sodium hydroxide indicates

substantial depletion of the contaminant from the steam, a result that is most plausibly accomplished by a homogeneous nucleation mechanism.

Quite differently, the high surface energy of crystalline sodium chloride makes

homogeneous nucleation of solid salt unlikely, even at high temperatures and at contamination levels that correspond to a very high degree of supersaturation, in time periods comparable to steam transit times through the superheat region of

intermediate and low pressure turbines. Furthermore, steam transit times through

the narrow region of concentrated sodium chloride liquid-solution stability are very short, under 1 millisecond, as steam velocities approach the sonic velocity

in the next-to-last stage of low pressure turbines. Such a short transit time,

combined with the fact that temperatures are relatively low in this region, makes

the homogeneous generation of critical-sized nuclei of liquid salt-solution

droplets also unlikely, despite their lower surface energy. Consequently, salt

precipitation in the bulk steam phase is delayed until general moisture formation

begins, when the salt content of the steam will condense as a highly diluted

component of the moisture.

The preceding considerations indicate that most of the throughput of moderatelywater-soluble salt contaminants can escape deposition in the turbine and appear

in the condensate. However, only a small fraction of the total contaminant

throughput, integrated over a period of many hours, can be enough to produce a thin liquid film of salt concentrate on the limited surface area of turbine

components that experience steady state conditions within the zone of concentrated

salt solution stability. Salt solution condensation in this zone can proceed by

a mechanism of heterogeneous nucleation on the microscopically rough, machined

and oxidized metal surfaces, with condensation rates controlled by diffusion

through the boundary layer of flowing steam. Deposition and salt-induced corrosion

patterns on next-to-last stage blades appear to be consistent with the mass transport theory for impurities in steam moving at near-sonic velocities. The

thinner the boundary layer of the flow, the faster will be the diffusion of

salt, resulting in more rapid deposit buildup and corrosion (Fig. 4).

122
0. Jonas, W. T. Lindsay Jr. and N. A. Evans

Fig. 4. Interferogram of flow through a cascade of

turbine blades. The boundary line is thinnest

over the convex surfaces. Inlet Mach number

0.364, outlet Mach number 1.125.

Much additional data on both the thermodynamic and transport properties of steam impurities are needed for a completely quantitative analysis of the processes

whereby ppm to ppb average levels of contaminants are transformed to corrosively

significant concentrates in turbines. Nevertheless, preliminary considerations,

based on limited data and supplemented by both theory and field observations, have

already provided useful insights that can help materials specialists, turbine

designers, and plant operators in their efforts to reduce turbine corrosion.

CONDENSATION AND TRANSONIC FLOW

Additional effects are produced directly by the flow dynamics, since certain

kinetic processes in high speed steam flow are too slow to maintain physical and

thermodynamic equilibrium. As an example, at sonic flow speeds, with steam conditions corresponding to the low pressure turbine steam, nucleation and

droplet growth rate are so slow that there is supersaturation until condensation

avalanches at a theoretical moisture level of 3 to 4%, on the so called Wilson

line. Furthermore, at supersonic speeds, embedded shock waves will produce j'ump

increases in pressure, temperature, and density which affect not only contaminant

solution kinetics and concentration, but will also cause moisture re-evaporation.

Recent observations in a one dimensional nozzle flow indicate that under certain

circumstances such re-evaporation can result in a significant fluid mechanical

instability, with periodic destruction and re-establishment of both the shock wave and the condensation front (see sequence of shadowgraphs in Figure 5).

Steam for these experiments was generated in a recirculating boiler with moisture

separators, and was superheated by expansion through an orifice. Initially, the

boiler was filled with de-ionized water without chemical additives. During the

boiler operation with only occasional blowdown, impurities may have concentrated.

Nonuniformities in the three dimensional turbine flow may change or diminish the

above nonequilibrium phenomena. This remains to be investigated in a blade

cascade and in a turbine. Investigation of effects of nonsteady relaxation will

be included because of its importance in localized blade corrosion by sodium

chloride, which appears in a narrow region at the condensation line.

123
Turbine Steam Purity - 1979 Update

camera focal plane slit width

2.5 m/s J

Range of plane

shock wave

oscillation

Flow

Direction . ^ • a b1 b2 c d

(a) Steady condensation front (bottom), and almost steady shock wave (top),

(bl) Boundary layer-induced shock wave oscillation.

(b2) Sketch showing range of plane shock wave oscillation, as recorded by focal

plane slit shutter in (bTT^

(c) Partly destroyed shock wave in condensation interaction zone.

(d) Partly destroyed condensation front, with no remaining shock wave.

Sequence (a) to (d) repeats at frequencies of 50 to 100 Hz.

Fig. 5. Interaction of condensation and shock wave in steam nozzle flow at Mach number range 1.2 to 1.4.

STEAM PURITY SPECIFICATIONS

Although the detrimental effects of some impurities, such as sodium hydroxide, are

well known, our understanding of the properties of steam with impurities is not complete. Nevertheless, it has been deemed necessary to recommend or specify

chemical control parameters for turbine steam. Direct analysis and control of

steam chemistry is necessary because of unknown relations between feedwater and

boiler water and steam chemistry, especially during transient operation, and also

because the boiler water specifications do not always result in an acceptable

turbine steam (particularly when different vendors supply different parts of the

equipment, as in the U.S.). The turbine usually has the lowest tolerance for

impurities in the whole system because of the very low (low ppb) solubility of

most dissolved impurities in low pressure superheated steam. Where concentrations

of the impurity exceed the solubility, the impurity precipitates and concentrates

by deposition.

Steam chemistry limits from various sources are tabulated in Table 2. Included

are feedwater limits for once-through boilers (where, at steady operation,

feedwater and steam chemistry are similar), and some steam chemistry limits

recalculated from drum boiler water chemistry using the liquid-vapor distribution

coefficients from Martynova (1973) and Jonas (1978), and 0,25% mechanical carryover for PWR steam generators and 0.1% for fossil drum boilers. The 0.1% was arbitrarily selected as it is frequently observed at 100% steady operation. The

pH, conductivity and some other values from drum boilers are not recalculated

because of the variations of volatility of ammonia and different amines, reactions

on boiler surface, and other unknown distributions between water and steam.

124

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Table

2

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Turbine Steam Purity - 1979 Update

In addition to the individual steam, feedwater and recalculated recycle boiler

specifications, relevant averages and results of an experimental field steam sampling program (averages and maxima at steady load) of fourteen different LP turbines are given in Table 2. Fossil (drum and once-through ) and PWR units were

sampled, and the samples were analyzed by ion chromatography. pH was measured by

a pH electrode, silica was analyzed by colorimetry, and oxygen by the indigo-carmine

method.

w The compilation of different specifications in Table 2 shows that, for most fossil

and PWR systems, pH, cation conductivity, oxygen, sodium, silica and copper limits

are similar. There is, however, a great variation in allowable chloride and iron,

and some steam chemistries resulting from feedwater specifications may not be good enough for the turbine.

DISCUSSION

The chemical composition of industrial "pure" H 2 O can be very complex. It is not unusual to find low concentrations of more than fifteen chemicals in the water and steam of one power system. As shown in this paper, the variety of

compositions found through the power industry is almost endless. In addition to the chemical variations, there are changing thermodynamic conditions of water and steam, particularly in the turbine.

The question arises whether a "rational" control of water and steam chemistry

(based on chemical thermodynamic data), which would result in 30 to 50 year

trouble-free service of the equipment, is possible. Anyway, very little chemical

thermodynamic data are available right now to support fully "rational" control.

The other principal approaches to chemical control are:

. Operation to the best achievable purity, which md^ cost too much.

. Operation based on analysis of experience, which may take too much time

to acquire.

. Operation with chemical additives, such as low level phosphates in drum

boilers (it is not so clear what additives should be used in once-through and PWR steam systems).

. Operation by any control method, plus cleaning, plus provision of spare parts,

plus use of more corrosion resistant materials.

For the current steam chemistry control, particularly under the U.S. conditions

and practices, a mixed approach, such as in Table 3 is recommended.

TABLE 3 Recommended Mixed Approach for Steam Chemistry Control

"Rational": Concentration of chemicals below solubility in dry steam,

optimum pH and O2

.

Best Achievable: Control of condenser leaks and air inleakage, polisher

operation in H-OH form, pure water treatment chemicals.

Experience: Cation conductivity <0.2 pS/cm, O 2

< 10 ppb, Na < 5 ppb, Si 02 = 10 to 20 ppb; GOOD

Systems with Cu, AVT; NOT SO 6000 Drum boilers with low PO4 ; GOOD

Once-through systems more sensitive

126
0. Jonas, W. T. Lindsay Jr. and N. A. Evans

. Additives: PO4 , AVT additives ? Cheiants - problems in high P,T units

Need higher pH in low pressure turbines

. Turbine Washing: By wet steam immediately after contamination.

Clean the whole system

Spare Parts: Yes

*

As more relevant data become available, better steam chemistry control limits

will be formulated on the rational basis. To speed up this process, measurements

of behaviour of water and steam with impurities and additives in actual turbines,

or under closely simulated turbine conditions, are necessary. The equilibrium

data measured so far are only a background. Needed measurements include in situ

conductivity, pH, oxygen, moisture and redox potential monitoring.

CONCLUSIONS AND RECOMMENDATIONS

1. Even without any further research on chemical thermodynamics of steam with

impurities, most of the turbine corrosion problems can be eliminated by

better control of impurity ingress through condenser and air inleakage, ?- better performance of condensate polishers, and control of purity of water treatment chemicals. Designing with low stresses, proper system design, and

system materials selection would all further improve the situation. Proof

of this is the successful operation of many turbines, particularly in England, Germany and Japan.

2. Better basic understanding (currently insufficient) would allow optimization

of the water chemistry control practices, long time corrosion damage predictions, and improved design.

3. Current research, while necessary, bears little relevance to the complex

chemical and thermodynamic situation in a turbine. It should be extended to cover a study of precipitation, deposition and washing in actual turbines,

“in situ" identification of steam impurities, a study of steam and water

sampling techniques, and a three-dimensional study of condensation and

transonic flow.

4. Current steam purity specifications and recommendations, while not absolutely

accurate, are necessary for better control of turbine corrosion. They

should be improved as better data and/or experience are available.

REFERENCES

Jonas, 0., (1978). Turbine steam purity. Combustion , 50 , No. 6 , 11-27.

Bussert, B.W., R.M. Curran and G.C. Gould, ( 1978) . The effect of water chemistry

on the reliability of modern large turbines. ASME Paper No. 78-JPGC-Pwr-9,

1 - 6 . Pocock, F.J., (1979). The importance of understanding the steam environment.

9th ICPS, Munich.

Rice, J.K., and T.O. Passell, (1978). Determination of impurities in steam -

a research program. Proc. 39th Int. Water Conf. (Pittsburg h). 11-20. EPRI,

(1979). Workshop on Steam Purity For Turbine Protection (Charlotte, N.C.).

EPRI, (1979). Workshop on Corrosion Fatigue of Steam Turbine Blading Alloys

(Ismaning, DBR).

127
Turbine Steam Purity-1979 Update

V6B, (1973). Guidelines for the Feedwater and Boiler Water of Steam Water Tube

Boilers with more than 64 bars Operating Pressure (VGB-Richtlinien fur das Wasser in Kernkr aftwerken mit Leichtwasser-reaktoren) . VGB-Kraftwerks-Technik

Mitteilungen, 52(2) , 167-172.

VGB, (1973). Guidelines for Water in Nuclear Power Plants with Light-Water

Reactors, (Neue Richtlinien fur das Kessel spei swasser und das Kesselwasser von Oampferzeugern) . VGB-Kraftwerks-Technik Mittei lungen , 53(4) , 207-209.

CEGB, (1975). Chemical Control of Boiler Feedwater, Boiler Water and Saturated

Steam for Drum-type aiyl Once-through Boilers. General Operation Memorandum 72. Martynova, 0. I . , (1972). Das Verhalten von Korrosionsprodukten in Wasser-Dampfkreisl aufen

bei Hohen Temperature. VGB-Spei sewassertagung , 8.13.

Jonas, 0., (1973). Survey of steam turbine deposits. Proc. 34th Internate Water

Conf. (Pittsburgh) , 73-81.

Jonas, 0., (1977). Identification and behavior of turbine steam impurities.

Corrosion 77, NACE (San Francisco) , Paper No. 124.

Kirsch, H., and S. Pollann, (1968). Deposition of corrosion products in the water steam cycle of steam generating plants. Chemie-Ingenieur Technik, 40,

897-903.

Martynova, O.I., and B. S. Rogatskin, (1970). Deposition of salts and corrosion

products in supercritical turbine flow sections. Teploenergetika , 17 , 50-54.

Lindsay, W.T., Jr., (1974). Some examples of physical-chemical processes

occuring in the water and steam of power stations. Proc. 8th International

Conf. on Properties of Steam (Giens, France) , 713.

Lindsay, W.T., Jr. (1979). Behavior of impurities in steam turbines. Power

Engineering, 83 , (No. 5), 68-72.

Lindsay, W.T., Jr. (1978). Physical chemistry of impurities in steam turbines.

Paper presented at Westinghouse Steam Turbine-Generator Technology Symposdium

(Charlotte, N.C.).

EPRI Project RP 969, Prof. L. B. Rogers, University of Georgia, Athens, Georgia

(EPRI Project Manager, Dr. T. 0. Passell).

EPRI Project RP 1068, Babcock & Wilcox Research Center, Alliance, Ohio and General Elecric Co., Schenectady, N.Y. (EPRI Project Manager, Or. T.O. Passell).

Martynova, O.I., (1973). Solubility of Inorganic Compounds in Subcritical

and Supercritical Water. Conf. on High Temp. High Pressure Electrochemistry

in Aqueous Solutions. (Surry), Preprint C-2.

128
STEAM PURITY ANALYSIS INSTRUMENTATION FOR TURBINES AND POWER PLANTS

W. M. Hickam, S. H. Peterson, D. F. Pensenstadler , and J. C. Bellows

Westinghouse Research & Development Center

Pittsburgh, Pennsylvania 15235

ABSTRACT

Organizations responsible for the generation of the nation's

electricity recognize the necessity of steam/condensate chemistry

control in plant operation in order to minimize chemical corrosionrelated component failures. In order to better determine and control

the steam purity in operating turbines and power plants, instrumented

analysis methods and systems have been developed and applied in plant

tests. The developments include the following: (1) Ion chromatograph

for steam/condensate analysis; (2) On-line steam analyzer system for

continuous monitoring of turbine steam; and (3) Computerized systems for

data collection, analysis, graphing, and storage. Each of the instrumented systems will be described and results presented on their use in

assessing the* steam/condensate chemistry of operating power plants.

* Current address: Westinghouse Steam Turbine Generators Division,

Philadelphia, PA.

129
INTRODUCTION

Power plants continuously recycle water between the condensate

and steam phases for use as an intermediate energy transport fluid. The

condensate/steam cycle which couples the thermal energy supplied by

fossil or nuclear fuel to the generator electrical output via steam

turbines is a highly complex chemical process. In many plants this

process utilizes pressure changes greater than 2000 psi and temperature

changes greater than 900°F in the reprocessing of millions of pounds per

hour of steam/condensate—the largest volume of the highest purity

material processed today. In addition to purity control, the process

requires precise control of additive chemistry.

Failure to maintain a high purity and controlled chemical

environment within operating plants will accelerate component corrosion,

a major cause for turbine failures. It is imperative that both the

man*ifacturer and the operator of power plants J^e fully cognizant of the

steam/condensate chemical control constraints in order to achieve high

turbine reliability and availability.

This paper will describe power plant instrumentation and instrumental methods for use in power plants to analyze and monitor the

steam/condensate. It will encompass steam/condensate criteria,

instrumentation development, plant testing of instrumental analysis

systems, plant test results and conclusions, and identify

product/services deemed beneficial to operators of power plants.

STEAM PURITY CRITERIA

Corrosion related turbine component failures have increased over

the past fifteen years. (1) The turbine components experiencing chemical

attack include blades, tenons, shrouds, blade lashing, piping, expansion

bellows, and disks. However, examination of turbine operating histories

130
reveals corrosion "affected" and corrosion "unaffected" turbines, which

is indicative of varying steam corrodant levels among operating plants.

In recognition of the limited tolerance of operating turbine components

to chemically corrosive environments, all major manufacturers of turbines have issued steam purity recommended limits. Table 1 lists the

Westinghouse turbine steam purity recommended limits for normal

operation.

)

TABLE 1 TURBINE STEAM PURITf RECOMMENDATIONS

Cation Conductivity <0.3 yS/cm

Sodium <5 ppb

Oxygen <10 ppb

Chlorides <5 ppb

Sulfates <5 ppb

Silica <10 ppb

Copper <2 ppb

Iron <20 ppb

The two primary causes for operation with steam environments

inconsistent with recommendations are impurity inleakage sources and

malfunctions of impurity removal systems. Plant impurity sources

include;

Condenser leaks

Polisher Exhaustion or Malfunction

Air leaks

Makeup water

Water storage containers

Plant materials

Chemical additives

Inspection and repair contamination

131
Assurance of the functionality of impurity removal systems is

essential and includes:

Polishers

Blowdown

Moisture separators

Exhaust pumps

Deaerators

Filters

Plants operating free of impurity inleakage sources and with

fully functional Impurity removal systems maintain steam environments

consistent with the steam purity recommendations and evidence little or

no significant corrosion of turbine components over many years of

operation.

INSTRUMENTATION

Our instrumentation development program has focused on plant

monitoring and analysis needs for better defining and maintaining the

steam/condensate environment to minimize corrosion risks. Continuous

monitors were preferred but where they were not available, grab sample

analysis methods were developed. Table 2 lists typical plant chemical

control parameters analyzed by continuous monitors and by laboratory

grab sample analysis. An on-line steam analyzer system has been

developed for the control parameters designated (o) under Continuous

Analysis and ion chromatographic methods for similarly designated

parameters listed under Laboratory Analysis. Automated methods of data

recording, analysis, and graphing by computer techniques have been an integral part of the instrumentation development program.

Ion Chromatography

Small, Stevens, and Bauman^^) of the Dow Chemical Company were

the first to report the development of ion chromatography in 1975, and

132
TABLE 2 CHEMISTRY CONTROL PARAMETERS

Continuous Analysis

o pH

o Specific Conductivity

o Cation Conductivity

o Sodium

o Oxygen

o Chloride

Ammonia

Hydrazine

Silica

Air

Hydrogen

Carbon Dioxide

Laboratory Analysis

o Sodium

o Chloride

o Sulfate

Phosphate

Silica

Iron

Copper

Organics

pH

almost simultaneously Dionex introduced a commercial instrument based on

this development. Ion chromatography combines new separator ion exchange

resins with a unique suppressor column/conductivity cell detection

system to achieve cation or anion analyses. The electrical output

consists of time dependent conductivity signals, identifiable with

specific cations or anions, for which the peak, heights are a linear

function of concentration.

The early instruments made possible, for the first time, the

direct analysis of cations and anions in water at a concentration level

of one part per million. Through the combined instrumentation developments of Dionex and methodology developments of Westlnghouse , a useful

sensitivity of one part per billion was achieved for the first time in

the laboratory for sodium, chloride, and sulfate in 1977.^^^

In order to make available to power plants this newer and needed

capability for analyzing steam/condensate samples, the remote analysis

of grab samples collected from power plants and the use of the Ion

chromatograph in a power plant environment were investigated.

133
Today, the collecting of condensate samples at a domestic power

plant, their shipment by commercial carriers, and analysis at a remote

laboratory is a fully-tested and practical methodology. In addition,

its use in servicing the needs of plants around the world is under

consideration.

The first use of the ion chromatograph in a power plant environment for steam/condensate analysis was at the Commonwealth Edison

Kincaid plant in a Westinghouse-conducted test in June, 1978. Through

this and other plant tests the ion chromatograph was demonstrated to be

acceptable for use in a power plant environment and to have operator

requirements consistent with typical plant staffing capabilities.

Today, some seventy-five utilities in the United States and throughout

the world have in-house capabilities for ion chromatographic analysis of

steam/condensate samples and the usage is growing rapidly. Figure 1 is

a photograph of a Dionex ion chromatograph equipped for simultaneous

anion and cation analysis.

STEAM ANALYZER SYSTEM

A steam analyzer system has been developed for continuously

monitoring the steam entering turbines. The system consists of a steam

sampling nozzle, valve, sample condenser, and analyzer cabinet equipped

with both multipoint chart and magnetic tape cassette recorders. The

system provides continuous analysis for pH, specific and cation

conductivities, oxygen, and sodium. It also provides a record of time,

sample temperature, plant load, and turbine identification. The system

is designed to accommodate a chloride monitor which is being evaluated.

Figure 2 is a flow diagram of the steam analyzer/data reduction system.

Photographs of the sampling nozzle/steam valve, sampling condenser, and

analyzer system are shown in Figures 3, 4, and 5.

Computer software and hardware systems have been developed for

processing data logged on tape cassettes. A data processing facility

equipped with tape reader, minicomputer, video display tube, terminal

and printer has been established and is shown in Figure 6. The data are

134
sent to a Uni vac 1100 computer which provides data analysis, graphing,

reporting, and data storage.

PLANT TESTS

Both ion chromatography and the continuous steam analyzer system

have been extensively tested in analyzing power plant steam/condensate

environments. Two types of plant tests have been developed for this

purpose. One test utilizes only the continuous steam analyzer system

and the second, identified as a total plant survey, includes the use of

the steam analyzer, two ion chromatographs and existing plant chemical

instrumentation.

Steam Analyzer System Plant Test

A steam analyzer plant test, including planning, conducting

test, and reporting typically requires an elapsed time of 6-9 months.

The major steps for conducting this test are:

Plant selection criteria

Customer test proposal and acceptance

Site preparation and analyzer installation

3-6 months monitoring of turbine steam; data transfer

Data analysis and reporting

Follow-up visits

Site preparation includes nozzle Installation and requires plant shutdown. Data transfer for computerized processing is by mailed tape

cassettes.

The first steam analyzer Installation for conducting a plant

test was completed in November, 1977. Since that time, eight analyzer

systems have been used at twenty-three plant sites In the steam

monitoring of twenty-eight turbines. Table 3 lists the analyzer number,

test period, plant site, and unit number for these tests. All plants

listed are fossil plants, except for Turkey Point, Beaver Valley and

Indian Point, which are nuclear plants.

135
TABLE

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Total Plant Survey

In order to better define the chemical conditions of the

steam/condensate cycle, and, when needed, the corrective action

requirements, a Total Plant Survey Test was developed. In this test the

condensate and the steam from 6-10 sampling points are analyzed using

both grab sample analysis and continuous monitors. Some of the requirements for conducting the test are:

Staff: 10

Duration: 7 Days

Plant Operation: Base Load, Cyclic Load, Shutdown, Startup

Equipment: Steam Analyzer System

2 Ion Chromatographs

Plant Instrumentation

Information gathered during the test includes:

Steam analyzer record for turbine steam

Cation and anion analyses of 250 grab samples

Periodic readings of 25 plant instruments

The extensive information gathered under various plant load

conditions provides a basis for assessing the steam/condensate environment. In plants found to be operating outside recommended turbine steam

purity limits, analysis of the data serves to identify causes and

established corrective action requirements. Total plant surveys have

been conducted for:

Kincaid Unit IH

Decker Creek Unit

Big Stone Unit //I Takasago Unit //I Riverside Unit //I Lacygne Unit //I

137
The listing includes both drum and once-through plants and plants which

have and have not experienced turbine corrosion.

RESULTS

In order to better reduce and interpret the significance of the

large amount of data collected from steam analyzer system plant tests

and total plant surveys, it was necessary to develop computerized

methods of data analysis and graphing. Two plants tested were selected

to illustrate the steam/condensate conditions found.

Figure 7 is computer-graphed data from the steam analyzer

monitoring low pressure turbine steam of plant #1. Each of the monitored parameters are plotted for daily high, daily low, and dally average

values. The average values are connected with a solid line. The straight

solid lines displayed on the cation conductivity, sodium, and oxygen plots

are the Westinghouse recommended limits for normal operation. The daily

highs and lows of the load plot indicate that the plant is used for load

following. The large differences in the highs and lows for cation conductivity and sodium plots indicate chemical excursions, likely associated

with load changes, and suggest a large impurity deposit inventory in the

steam/condensate system.

Concurrent with steam analyzer system data collected in plant

#1, some 250 grab sample analyses were performed by ion chromatography.

Figure 8 is a computer-plotted graph of distributions found in the

sodium, chloride, and sulfate analyses of the condensate and steam

samples. The graph shows that a significant fraction of the analyzed

samples exceed 5 parts per billion of the three impurities. Turbine

corrosion problems have been experienced in this plant.

A total plant survey similar to that conducted at plant #1 was

also conducted at a second plant identified as plant #2. Figure 9 is a computer plotted graph of the steam analyzer data. The load graph shows

that this plant also is operated as a load following plant. Note the

small differences in daily highs and lows of monitored chemical

138
parameters and the magnitudes of the cation conductivity and sodium

levels found compared to the recommended steam purity limit lines.

Over two-hundred grab samples from plant #2 were analyzed by ion

chromatography for sodium, chloride, and sulfate. Figure 10 is a plot

of the analysis of samples collected from the condensate pump discharge

during the same time period as shown in Figure 9. All values are well

below the Westinghouse recommended steam purity limits for these

condensate samples as was found for all steam/condensate sampling

points. This turbine has experienced no corrosion failures over several

years of operation.

CONCLUSIONS

The steam/condensate instrumentation and analysis methods

developed and evaluated through extensive testing at operating fossil

plants have served to better define the operating environment of

individual plants and the steam/condensate environment differences in

plants. Both the steam analyzer plant tests and the total plant survey

tests have provided information, whereby recommendations and corrective

action steps for improving the steam environment could be made. Plants

incorporating into their operations the instrumentation and methodologies described, namely, ion chromatographic analysis of grab samples,

steam analyzing system, and computerized data analysis, all of which are currently available as products and services, can better maintain a steam/condensate environment consistent with good chemical plant

practices.

The information gained through the analysis of the

steam/condensate environment of nearly thirty operating plants can be

summarized as follows:

Turbine steam purity recommended limits for normal operation are achievable during plant operation at all loads.

139
Turbine steam purity recommended limits are exceeded in many

operating plants.

Operation within the steam purity recommended limits for normal

operation will reduce turbine corrosion failures.

ACKNOWLEDGMENT

The electric utilities' permission to monitor their plants and

the assistance provided by their staffs in conducting the listed plant

tests is gratefully acknowledged.

Several engineers and technicians of both the Steam Turbine

Generators Division and the R&D Center participated in the numerous

plant tests reported. Their contributions to and support of the program

described is acknowledged.

140
REFERENCES

1. Turbine Steam Purity. 0. Jonas. Southeastern Electric Exchange,

Washington, D. C. (1978).

2. Novel Ion Exchange Chromatographic Method Using Conductimetric

Detection. H. Small, T. Stevens, and W. Bauman. Anal. Chem. , 47,

1801 (1975).

3. Characterization of the Steam Turbine Chemical Environment. G. L.

Carlson. Westinghouse Steam Turbine Generator Technology Symposium,

Charlotte, N.C. (1978).

4. Steam Purity Monitoring for Turbine Corrosion Control: A Total

Plant Survey. S. H. Peterson et al. Paper No. IWC-79-26,

International Water Conference, Pittsburgh, Pa. , November, 1979.

5. Steam/Condensate Chemical Maintenance and Control in Power Plant

Operations. W. M. Hickam et al. Paper No. IWC-80-18, International

Water Conference, Pittsburgh, Pa. , October, 1980

141
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Fig. 2--F10W chart for steam analyzer and information output

systems

143
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149
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151
Reprinted from January 1983, Vol. 105, Journal of Engineering for Power

W. G. Steltz^

Advisory Engineer. Steam Turtiine-Generator Division.

P. K. Lee

Senior Research Scientist. Physical ahd Inorganic Chemistry Department. Research and Development Center.

W. T. Lindsay, Jr.

Consulting Scientist. Chemical Sciences Division. Research and Development Center. Westinghouse Electric Corporation.

I

The Verification of Concentrated

Impurities in Low-Pressure Steam

Turbines

The problem of corrosion-assisted low-pressure blade failures is discussed from the water chemistry and aerothermodynamic viewpoints. The physical chemistry of

particular steam impurities existing in low-pressure steam turbines is reviewed with

special applicability to blade path steam conditions. The interaction of the turbine expansion line with the salt solution zone has been verified by field testing which

has, for the first time, demonstrated the existence of concentrated impurities within

the low pressure turbine blade path. In addition, the existence of low levels of

moisture as measured by an optical moisture probe offers strong evidence that the expansion process in low-pressure steam, turbines takes place, on the average, in thermodynamic equilibrium, at least in the vicinity of the saturated vapor line.

Introduction

Corrosion-assisted cracking has been experienced in many

steam turbine units, varying from those used in plants with

drum type steam generators operating at less than 2000 psi

(13.8 MPa) upward through the pressure scale to plants with

supercritical once-through steam generators. As a recognized

industry-wide problem, many programs are underway to study the fundamental causes of material failures in steam

environments.

A significant problem area of turbine material corrosion

involves the transport of corrosive impurities throughout the steam turbine cycle. It is essential to determine the identity of

the corrosive species, their sources in the plant water/steam

cycle, the mechanism of their transport and deposition during

the expansion cycle, and the modes of attack on turbine

materials by the significant corrodents. These several investigative programs form a broadly based

effort spanning many disciplines. Included in this effort are

the fracture analysis of failed turbine blades, the metallurgical testing of turbine materials in corrosive en- vironments, the determination of steam and water purity in operating units, the physical and chemical characteristics of

water, water treatment additives, and corrosive substances,

and the analysis of the thermochemical mechanisms that cause deposition of corrodents on turbine parts. This paper will describe the several aspects of these programs dealing with water chemistry and the analysis of the mechanisms controlling corrodent deposition within steam

turbines. The physical chemistry of steam impurities is reviewed and particular evaluation of their interaction with

the turbine blade path expansion line is discussed. The first experimental detection of concentrated impurities in lowpressure turbine blade path steam is described in detail,

^ Currently alflliatcci wuh Power Dynamics. Inc.. Uroomall. Pa. I'XlOH Coninbuleil by ihe (<as Turbine Division and preseiiied ai the AS.Mt. Wimer

Annual Meetinii, Washiiiglon, D( . November 15-20. IVXI. Manuscnpi

received by the (/as Turbine Division, June IK, IVK2.

Table 1 Summary of ASME turbine survey Drum Oncetype through Total Number of units reviewed 64 31 95 Percent of units with cracks Percent of units

15 42

with pitting Percent of units

15 39

with fouling 29 19

Table 2 Summary of .\SME turbine survey cracks drum type units

Phosphate 4/ Volatile treatment treatment Number of units Percent of units 55 9

with cracks 14 15 “Coordinated phosphate control

further test programs are described, and finally, conclusions

are drawn.

Corrosion-Assisted Failure Experience in Field Turbines

Many interactive factors control the mechanisms of stress corrosion and corrosion fatigue. In some instances of blade cracking it is impossible to identify their separate effects. ,\s an all-inclusive descriptive term, it is usually advisable to characterize the problem as a corrosion-assisted failure. A significant factor in the occurrence of corrosion-assisted blade failures is the type of steam generator supplying the turbine system. 7 he conventional drum type boiler and the once-through supercritical steam generators ditfer fun- damentally in the type of water treatment chemicals utilized. The all-volatile treatment employed in all once-through

boilers is sometimes used in drum type boilers, but. more

usually, low-phosphate water treatment is used in drum type

/Vol. 105, JANUARY 1983

152

Transactions of the ASME
^0

it1 1

2

a

z

Iu

0 01

TURBINE

UNIT „ „

Fig. 1 Deposit analyses for Cl ~ from penultimate blades of twentyfour Westinghouse fossil low-pressure turbines. Range indicates average to maximum values.

boilers. A recent survey sponsored by the ASME Committee

on Water for Thermal Power Systems evaluated 95 boiler- turbine systems; these 95 were comprised of 31 once-through

and 64 drum type boilers [1]. These results are summarized in Tables 1 and II. Although these survey results consistently indicate that corrosion-assisted turbine failures are more prevalent in boiler systems which utilize all-volatile water treatment, other

significant factors such as the use and maintenance of

polishers and the transfer of undesirable chemical species

throughout the turbine cycle could also have a profound

influence on turbine blading distress. A substance which contributes significantly to material corrosion is sodium chloride. Figure I shows the weight

percent of chloride in deposits taken from twenty-four fossil low-pressure turbine elements, some of which have been

inspected more than once [2]. The units are classified in the lower portion of the figure into a group that has had blade

failures, and a group that has operated without blade problems.

Chloride is considered to be a primary turbine material corrodent, as is substantiated by the units which have ex- perienced failures generally having a high fraction of chloride

in their deposits.

While chloride is considered to be a primary factor in corrosion-assisted cracking, other chemical species have also been shown to contribute to turbine corrosion. These species include sulfate, caustic, and dissolved oxygen. The sodium

ion itself is not considered to be corrosive, but is usually the charge compensating cation found in deposits with the anions

mentioned above.

Physical Chemistry Aspects of Impurities in Steam

The purpose of a behavior study of impurities in steam

turbines is to develop understanding, quantification, and the prediction of their behavior in order to control and ameliorate

their undesirable effects on turbine materials. Concentrations

of the minor constituents, which exist at levels from parts per

million (ppm) down to parts per billion (ppb), are trans- formed into higher local concentrations. Detailed calculations of the equilibrium fluid composition involving some important volatile substances can now be performed [3] as most

of the data needed for this purpose is available. The characteristics of nonvolatile contaminants are quite

I I ! 1 1 I M r I M I I I M r I M I I I

ii I I

• • I..

NO

BLADE

FAILURES

FAILED BLADES

lllllLlllllLlLlLLiJ_lllllllllllll_L i_L

i/)(d CO o ^

2,400 PSl(i6.5 MPa^ORUM BOILER

Fig. 2 Simplified Mollier diagram showing turbine expansion lines at 100 and 50 percent load

Fig. 3 Simplified Mollier diagram showing turbine expansion lines and sodium hydroxide liquid phase concentrations

different from the volatiles normally used in water treatment. Two substances are of considerable concern to the turbine

designer. The first is sodium hydroxide, which has probably

damaged more turbines than any other single contaminant.

Caustic contamination of steam can occur in a number of

different ways. It can be caused by improper regeneration of condensate polishers, by chemistry upsets in phosphatetreated boilers, or by poor steam separation in drum boilers that are being deliberately treated with low-level free caustic. Plotted on the Mollier diagram of Fig. 2 are expansion lines for steam passing through a fossil fueled turbine system with

a 2400 psi (16.5 MPa) drum boiler. A part of the LP ex- pansion line for 50 percent load is shown to the right, where it can be seen how the dry-to-wet transition location (the saturated vapor line) shifts to a different location in the turbine at reduced load. Solutions of sodium hydroxide can be

very concentrated with substantially elevated boiling points, so they can exist in the superheated steam region. Lines showing sodium hydroxide concentrations of 25 to 90 percent

are shown in the Mollier diagram of Fig. 3. These concentrated solutions cover almost all the region traversed by

the steam expansion line. It is only in the wet region, near the

outlet of the low pressure turbine, where the sodium

hydroxide concentration becomes so dilute as to be noncorrosive. The second contaminant of great significance is sodium

chloride. Salt is a very common contaminant of steam, and its

Journal of Engineering for Power

153

JANUARY 1983, Vol. 105
ENTROPY

Fig. 4 Simplified Mollier diagram showing turbine expansion lines and sodium chloride liquid solution zone

FINAL STAGE ‘^PENULTIMATE —

STAGE

Fig. 6 Transverse probe locations at Encina No. 4, San Diego Gas and

Electric Company

Fig. 5 Typical conductance sensor

concentrated solutions have been shown to cause pitting,

corrosion fatigue, and stress corrosion craoicing. The ther- modynamic properties of sodium chloride are quite different from those of sodium hydroxide, as it has a more limited

solubility. The same Mollier diagram and the same expansion

lines for a 2400 psi (16.5 MPa) drum boiler turbine system are shown in Fig. 4. The shaded zone is the only region where

concentrated salt solutions are stable. Above the shaded zone, only pure dry sodium chloride is stable in superheated steam. Below the zone in the wet region, salt contamination becomes

so dilute as to be without much corrosive significance. A

similar band of salt solution stability exists for other compounds that are moderately soluble in water. The upper boundary of the shaded zone is the three-phase

boundary at which steam, solid sodium chloride, and liquid solutions saturated with sodium chloride coexist. The position of the three-phase boundary for other salts depends on the

boiling point elevation of their solid-saturated solutions. With

sodium chloride, the concentration is approximately 28 weight percent at the condition where the low-pressure fossil turbine expansion line crosses this boundary (at about 220°F

(104°C)) and is essentially 0 percent at the equilibrium

saturated vapor line. The important feature is that corrosively significant solutions of sodium chloride, and solutions of other salts with

limited maximum boiling points, are thermodynamically

stable within one stage of the low-pressure turbine.

In summary, solutions of sodium chloride and other moderately water soluble salts are stable only in a narrow band near the liquid-vapor saturation line, whereas solutions of sodium hydroxide and similarly highly soluble compounds

can exist in the entire superheated steam region, riuis, in a steam turbine, this means that the corrosive effects of sodium

Fig. 7 Encina No. 4 test plan for conductance measurements at the

inlet to L-1C

chloride are very localized, while those of sodium hydroxide

can occur anywhere, depending on the level of contamination.

Field Verification of Concentrated Impurities Within

Low-Pressure Steam Turbines

A key factor pertaining to the cause and effect of impurities

in blade path steam is the determination of the physical processes which concentrate these impurities into corrosive

solutions. Development activities led to a field test program

for verification of the existence of the “salt solution zone" phenomenon in operating turbines. A measurement device capable of immersion in the blade path steam was conceived as a “surface conductance probe"

and designed, developed, and constructed at the Research and

Development Center. A typical conductance sensor, which is attached to a long support barrel to form a complete probe, is shown in Fig. 5. The sensing element itself consists of two

parallel platinum electrodes spaced less than a millimeter

apart, held in place and separated by an insulating block oi MACOR'. The electrical signal developed by the sensor is affected by the conductance of a Hiiid film deposited on the

insulating surface between the two electrodes. The conductance, in turn, depends on the chemical species compri.sing

the lluid; in the case of pure water, very low levels of con- ductance are developed. On the other hand, ionizable dissolved impurities increase the conductance by orders of magnitude. Laboratory calibration of several probes at the

' I ratJcmiitk »l Corning (ilass Works.

Vol. 105, JANUARY 1983 154 Transactions of the ASME
100

0 38% LOAD 0 S4%

* 65%

1 77% M

r\

\ CYL

I

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320 340 360 HOT REHEAT TEMPERATURE »F

Fig. 8 Electrical conductance data taken at Encina No. 4

Research and Development Center prior to their use in field turbines verified high sensitivity to small arpounts of elec- trolytes. Figure 6 indicates the location of probe guides in the low

pressure turbine of Encina No. 4, a phosphate treated drum

boiler unit of the San Diego Gas and Electric Company. The

locations marked “NEW” supplemented existing probe

locations. In effect, three measurement planes were available: before, in the middle of, and following the penultimate stage. All three locations were fitted with conductance probes of

several designs.

The physical location yielding the pertinent results reported

herein is the L-IC inlet location. It was this location which

could be controlled in such a manner as to control movement

across the saturation line from wet to superheated steam and

vice-versa. The test plan. Fig. 7, describes the desired loads and range

of hot reheat temperature required to effect the movement of

the saturation line. The region of interest is shown as the shaded area labeled L-IC test region. This region is consistent with the predicted “salt solution” zone of Fig. 4. The test loads were limited by the pressure level existing at the plane of measurement, i.e., atmospheric pressure corresponded to ^

about 75 percent load. Actual test points, denoted by

asterisks, indicate the location of pertinent conductance data ^

collected during the test program. <

At the lowest load, specific points were initially run with o

steam conditions at their wettest state. Higher values of hot §

reheat temperature were then established. Indications from ^

the conductance probe located at the L-IC inlet appeared at a o

nominal level and increased until the probe’s environment

became superheated steam. The probe output then dramatically dropped to essentially a zero conductance in- dication. By ramping the hot reheat temperature slowly

downward, a distribution of conductance readings emerged.

These were substantiated by succeeding up and down ramps. Very careful control of the boiler (drum type) operation was

achieved by the several operators assisting in the test program. The results of the conductance probe(s) measurements are shown in Fig. 8. At each load, as a function of hot reheat temperature, distinct conductance peaks were observed; these were established, and verified, by the up and down ramping

of the hot reheat temperature. These observed changes in conductance levels with steam temperature indicate the presence of contaminated condensed water on the con- ductance probe’s surface. The conversion of the location of the conductance peaks at

CONDUCTANCE PROBE FIELD TEST RESULT / SUPERHEATED

' STEAM

ENTROPY

Fig. 9 Simplified Mollier diagram showing location of peak con- ductance measurements at Encina No. 4

Ql 1 ^ ^ ^ 1 1 ^ 870 880 890 900 910 920

(460OC) (4750C) (4900C)

HOT REHEAT TEMPERATURE °F

Fig. 10 Electrical conductance data taken at Big Brown No. 2

the four loads has been made to the Mollier diagram of Fig. 9. Heat balance calculations were made for the unit operating

conditions consistent with the individual test points. The locus of local steam conditions, compatible with these conductance

peaks, is a line of nearly constant superheat. This line is essentially parallel to the maximum concentration line defining the predicted upper limit of the sodium chloride

solution zone.

In addition to surface conductance measurements in the low

pressure turbine blade path steam, samples were taken of the

Journal of Engineering for Power

155

JANUARY 1983, Vol, 105
Table 3

PROBE

Average droplet Moisture

Blade height diameter content

07o d X 10*m 9^0

17 (near rotor blade hub) _ _

29 2.48 0.3 76 (near rotor blade tip) 0.17 0.5 CONDUCTANCE PROBE FIELD TEST RESULTS

SUPERHEATED STEAM

PREDICTED

SALT SOLL .ION

PEAK CONDUCTANCE

MEASUREMENTS

• ENCINA 4

X BIG BROWN 2

Fig. 11 Simplified Mollier diagram showing location of peak con- ductance measurements at Big Brown No. 2 and Encina No. 4

crossover steam through a sampling tube identical to that used

in a steam purity continuous analyzer program [2] in order to determine the chemical species existing in the superheated steam prior to its entry to the blade path. The samples taken from Encina No. 4 showed that phosphate and sodium were

the main contaminant species. The three-phase boundary for a sodium phosphate salt (NaiHPOj) is shown by the dotted

line in Fig. 9. The conductance peak locations are closer to

this line than they are to the sodium chloride three-phase

boundary.

The observation of conductance peaks at steam conditions

with a significant amount of superheat can result only from

coverage of the probe insulator surface with a film of a

substantially concentrated solution of an electrically conducting substance that is essentially nonvolatile. It could be

postulated that such a film could be created by condensation

of moisture on an initially contaminated surface, or by some

effect of adsorbed moisture or capillary condensation on the

properties of the insulator surface. However, the reproducibility of the observations after exposure of the probe to the washing effects of wet steam and the result of

laboratory tests of probe response to static (noncontaminating) conditions effectively rule out such ex- planations for the observations. The most probable cause of

these effects is the deposition on the probe of water soluble contaminants that were present in the turbine steam. We believe that these measurements are the first to be taken

directly from a field unit to demonstrate experimentally the existence and location of turbine operating regions where

concentrated contaminated solutions exist. During the course of these experiments, measurements were made of the moisture content and the corresponding average

droplet diameter. The locations chosen during these tests were

at the L-R exit position in Fig. 6 (the turbine blade path

exhaust) the L-IR exit, and the L-IC inlet. The results of

pertinence to the conductance probe measurements, are those obtained at the L-IC inlet location. These moisture measurements were made using a multiple wavelength optical

probe [4| developed for steam turbine applications.

Fig. 12 Conductance probe location at Turkey Point No. 4, Florida Power and Light Company

Moisture measurements were made only at the 65 percent load condition at a reheat temperature of approximately

850°F (454°C), the operating conditions coincident with the peak of the conductance probe response curve. Fig. 8. Table 3 describes the results of these moisture measurements. In the near tip region (i.e., the outer diameter) of the inlet to this stationary blade row, where the conductance probe was

situated, moisture contents on the order of 0.5 percent were

observed. As the conductance probe was situated at a larger

diameter than the 76 percent location of Table 3, the inherent blade path radial energy variation undoubtedly produced

higher local enthalpy conditions than that sensed by the moisture probe. Although precisely corresponding

measurements of moisture and conductance were not made,

extremely low levels of moisture were sensed quite close to the conductance probe’s location.

Further Field Verification Testing

Since these initial tests were run in the summer of 1979,

three other units were fitted with appropriate probe guides

and tested. Two of these units were also fossil units. Conductance peaks were observed in all fossil test programs. The second fossil unit tested was Big Brown No. 2 of the Texas Utilities Generating Company which is a once-through

unit equipped with condensate polishers. The corresponding

electrical conductance data for Big Brown No. 2 are presented

in Fig. 10. The loci of these peaks have been converted to local steam conditions and are located on the Mollier diagram of

Fig. 1 1 . Steam samples indicated the presence of low levels of

sulfates and sodium at the low pressure turbine inlet. The “\"

symbols on Fig. 1 1 are close to the three-phase boundary for sodium sulfate solutions, suggesting that a nearly saturated

solution of sodium sulfate formed on the surface conductance

probe. Data from the third fossil unit tested, Centralia No. 2 of the Pacific Power and Light Company, produced similar

characteristics but test data clarity precluded exact quantification.

Vol. 105, JANUARY 1983

156

Transactions of the ASME
20 CONDUCTANCE PROBE FIELD TEST RESULTS

PERCENT LOAD

Fig. 13 Turkey Point No. 4 test plan for conductance measurements

between disks number 1 and 2

Fig. 14 Electrical conductance and thermocouple traces at Turkey

Point No. 4

The First Nuclear Unit Verification Test The fourth test program was the first to be performed on a nuclear unit, Turkey Point No. 4 of the Florida Power and

Light Company. This is a pressurized water reactor system

operating with all volatile treatment, consisting of ammonia

and hydrazine additions to the feedwater. Two probes were

installed at different circumferential locations in the space between stages number 2 and 3 of a low pressure turbine element. Figure 12. These probes were installed during a

startup while the turbine was on turning gear. As the blade path pressure at this location is on the order of 80 psia (552

KPa) at full load, the probes were designed to be semipermanent, that is, once installed they would not be removed

until the unit came down or until load was reduced to 20

percent or lower. During the test program, an automatic recorder was employed to sense and document the signal generated by one of

the conductance probes. In effect, two signals were recorded:

(/) the signal from the conductance sensor, and (//) steam

temperature as sensed by a thermocouple adjacent to the conductance sensor. The test program for this nuclear unit required control of

the steam temperature entering the low-pressue turbine element. This was effected by control of the steam flow rate entering the reheater tube bundle of the moisture separator

reheaters (MSR’s) supplying the low pressure turbine. The

desired test region is indicated in Fig. 13 with the actual test lines superimposed.

Typical results from the surface conductance probe and its thermocouple are presented in Fig. 14 as a function of time. The lower trace is the conductance sensor’s output while the upper trace is that of the thermocouple.

In this instance, which is typical of data collected in this

SUPERHEATED STEAM

, PREDICTED • ENCINA 4 /

/salt SOLUTION BIG BROWN 2 \ t// zone (NaCi) * TURKEY POINT 4 THREE PHASE

/ BOUNDARY (NaCi) /

/ / / / ENTROPY

Fig. 15 Simplified Mollier diagram showing location of peak con- ductance measurements at Turkey Point No. 4, Big Brown No. 2, Encina

No. 4

manner, the unit was operated along a load line of Fig. 13 while the MSR outlet temperature was varied. Initially, the MSR temperature was high enough to maintain the probe’s

local temperature in the superheated region and above the

“salt solution zone.’’ As MSR temperature is reduced, the probe temperature also reduces and the conductance sensor responds to the formation of solutions of concentrated contaminants. Increases in conductance level occur within a very narrow range of temperature change. The unsteady

character of the sensor’s response is thought to be due to the variation in liquid film thickness and extent surrounding the platinum-sensing elements. As the MSR outlet temperature is further reduced, the probe output reduces to an essentially steady level typical of

the conductance of nearly pure water as the blade path steam

conditions move further into the wet steam region. A reversal of the process results in the trace on the right-hand side of the

figure - an increase of steam conditions from the wet region

through the concentrated contaminant zone and into the superheated zone. The probe responds in a similar manner

and upon becoming superheated, its response falls to a minimal level. A similar conversion of the local steam conditions compatible with these observed conductance peaks results in the additional points on the Mollier diagram of Fig. 15. In this instance, the maximum pressure level is 75 psia (517 KPa),

approximately a fourfold increase over the maximum

pressure levels encountered in the fossil unit test programs. The most likely salt contaminant of the steam during the

testing period at Turkey Point No. 4 is sodium chloride, since measurable amounts of both sodium and chloride were

present in the steam generator blowdown water. The location of the conductance peak on Fig. 15 is very close to the pure water equilibrium saturated vapor line and far removed from

the three-phase boundary for sodium chloride. This indicates

that a relatively dilute solution of the salt condensed on the surface conductance probe, corresponding to a very low

concentration in the steam.

Conclusions

In summary, this paper has dealt with the chemistry and

aerothermodynamic aspects of steam as it pertains to the general problem of corrosion-assisted blade failures. The

interaction of the steam turbine expansion line with the salt solution zone has been verified by field testing which has, for the first time, demonstrated the existence of concentrated

impurities within the low-pressure turbine blade path.

This phenomenon has been observed in each turbine tested to date including three fossil units and a single nuclear unit.

Journal of Engineering for Power

157

JANUARY 1983, Vol. 105
These units represent three different physical designs installed by four different utilities located throughout the United

States. The boiler systems delivering steam to these turbines include both once-through and drum type fossil boilers; the nuclear unit was of the pressurized water reactor type. Water

treatment techniques varied between units and included

phosphate treated subcritical drum type boilers, all volatile treated supercritical once-through boilers, and the all volatile water treatment of the nuclear steam supply system.

Regardless of these variations, the observed results and

conclusions are the same.

In the unit in which moisture measurements were obtained

in conjunction with electrical conductance measurements, a

relationship was observed between the two measurement sets. Very slight, but measurable amounts of moisture were sensed by the moisture probe when turbine operating conditions were

held in the immediate vicinity of the conductance peak. These

droplets were generally less than 2.5 x 10"* m in diameter

and the indicated moisture content less than or equal to 0.5 percent.

These findings also support the contention that steam

flowing in low-pressure steam turbines tends to approximate

equilibrium conditions. These moisture measurements made

in the vicinity of the equilibrium saturated vapor line, albeit with some experimental uncertainty, have been made under

local steam conditions ranging up to 75 psia (517 KPa) and at local Mach numbers from 0.5 to 0.8. The possibility of local supersaturation of the steam flow in expanding turbine passages cannot be dismissed, as hosts of laboratory data confirm this phenomenon. These current findings indicate

that in the flow spaces between blade rows, steam tends toward the equilibrium state, that is, “on the average,” steam

tends to follow the equilibrium characteristics defined by

many publications in this area. It is quite logical that equilibrium and nonequilibrium flow processes coexist in steam turbines. Local conditions within nozzles or rotating blade rows generally experience very high rates of expansion,

conducive to subcooling and delay in achieving equilibrium

conditions.

Some degree of uncertainty must be assigned to these test data and to their implications. For example, tests of this type

in power plant installations utilizing delicate and sophisticated

instruments and electronic systems must be coordinated with

plant operations and to some degree depend on the accuracy

of plant operational instruments. The final determination of

local steam conditions surrounding the surface conductance

probe depends on these operating parameters by way of

turbine cycle heat balance calculation procedures.

The exact chemical species responsible for the conductance

probe response were not measured and are, of course, a source of speculation. These important factors have yet to be

resolved; they have, however, prompted continued activity in this area and are significant links in the chain relating the corrosion phenomena to steam turbine reliability.

Acknowledgments

The authors wish to express their appreciation to the Westinghouse Electric Corporation for permission to publish

this paper and to certain individuals without whom these

results could not have been achieved, especially L. D. Smith,

S, Anderson, and W. Snyder,

References

1 Gabrielli, F., and Grabowski, H. A., "Steam Purity at High Pressures- System Considerations,” presented at the Joint Power Generation Conference

1979.

2 Peterson, S. H., Bellows, J. C., Pensentadler, D. F., and Hickam, VV. M., “Steam Purity Monitoring for Turbine Corrosion Control: .A Total Plant Survey,” International Water Conference, 1979, Paper No. IWC-79-26.

3 Lindsay, Jr., W. T., “Behavior of Impurities in Steam Turbines,” Power

Engineering, Vol. 83, No. 5. 1979. 4 Wyler, J. S., and Desai, K. J., "Moisture Measurements in a Low

Pressure Steam Turbine Using a Laser Light Scattering Probe," .ASME

H0OI08, 1977.

Vol. 105, JANUARY 1983 158 Transactions of the ASME

REACTOR CHEMISTRY

Paul Cohen

Water was an obvious candidate for moderator and coolant functions in

the nuclear fission reactors and was so employed in the plutonium production

reactors. For power applications two options were available for light water cooled

and moderated reactors: to allow the water to boil in the reactor to produce

steam directly (the boiling water reactor, BWR) or to use the water as a pressurized

non-boiling heat transfer agent, transferring heat through a bsirrier in a steam

generator to form steam (pressurized water reactor) PWR.

A considerable amount of radiolysis occurs in the BWR. The water in the

circuit contains about 0.2-0. 3 ppm oxygen. Despite the presence of a stoichiometric

amount of hydrogen, the environment is oxidizing. In the PWR, radiolysis is low

and can be effectively suppressed by the convenient maintenance in the non-boiling

system of about 1-2 ppm of dissolved hydrogen. The electrochemical potential

is close to that of the hydrogen electrode.

These two conditions produced a difference in material selection and behavior

in the two types of plants. For the BWR it dictated that the coolant had to be

very low in electrolytes (aside from consideration of formation of undesirable

nuclides) to control corrosion. In the PWR it permitted the optimization of pH

to control corrosion and deposit formation, for which LiOH was found to be optimum,

and the utilization of boron as boric acid to control reactivity.

159
These accomplishments were not without side effects. The corrosion of

zirconium alloy fuel cladding in the BWR environment in effect limits the temperature

and pressure of operation, to a range comparable to that obtained in the PWR

steam generator. Cracking of sensitized stainless steel in the oxidizing environment

has prompted studies of reduction of the potential by some hydrogen additions.

In the PWR, the high temperatures resulting from the necessary pressurization

and indirect cycle are close to limiting with respect to the cladding. Concentration

of lithium in deposits can lead to excessive corrosion of zirconium alloys; the

oxide appears to be particularly sensitive to the lithium ion (Fig. 1).

In both systems, corrosion products are transported to the core where they

deposit and are irradiated. The nuclides formed are released and are transported

to and deposited on or incorporated in the oxides of the various surfaces over

the entire system. Numerous studies have been undertaken to understand and

control this process. These include the solubility of corrosion products in reactor

coolant as a function of temperature, composition and coolant pH, as well as

the colloidal behavior of particulates. In addition to the radiological effects,

the deposits have had undesirable effects on fuel clad temperature and fluid friction.

Typically, in the BWR the transported corrosion product is hematite, in the PWR,

with Inconel 600 steam generators, it is a nickel substituted magnetile Ni^Fe2_j^0^,

with X up to about 0.6.

The current approach to PWR chemistry is to select conditions so that the solubility

of the corrosion products increases as the coolant traverses the reactor. In principle

this will prevent supersaturation and deposition of solubles and assure the dissolution

of deposited particulates. This requires a knowledge of the effect of coolant chemistry

on pH, and the effect of pH on corrosion product solubility.

160
Fig. 2 shows the pH of solutions of boric acid and lithium as a function of temperature.

Fig 3 shows the solubility of magnetite as a function of acid or base concentration.

Fig. 4 shows curves of the solubility of magnetite for various conditions as a

function of temperature, illustrating the principle stated earlier.

The tactic now most widely employed is to specify the chemistry according

to these principles, resulting in an operating curve, as shown in Fig. 5. Although

reasonably successful this strategy has not resolved all problems, and attention

is now being directed to the behavior of particulates in the reactor coolant system,

particle deposition on surfaces and particle-particle interaction, as a function

of chemistry and thermohydraulic conditions.

In the BWR, as noted earlier studies and trials are being undertaken of partial

suppression of radiolysis with hydrogen additions, to control pipe corrosion. A

major consideration will be the effect on deposit formation and their consequences.

161
CORROSION RATE OF ZIRCALOY-4 AT 600®F

AS A FUNCTION OF LiOH CONCENTRATION

Wtight Gain (Mg/Dm^)

10^1 —r r - r--

5

Exposure Time (Days)

162
\ FIGUfi£ 1

pH OF M4XTUHES OF BOHIC ACID

WiTH 10*^ MCX.AL BASE

pH

163
SOLUBIUTY OF FE3O4 IN SOLUTIONS

SATURATED WITH H2 AT 1 ATM. 25^

Concentratioii

oi Fe in

Solution (/fc/4

Tamparitura (*C)

164
FE SOLUBILITY VERSUS TEMPERATURE

FOR SOLUTIONS CONTAJNINQ

500 PPM AND VARYING LI CONCENTRATION

Fe Solubility /^oles/Kg

0.7

0.6

0.5

04

0.3

0.2

0.1

0.0

250 260 270 260 200 300 310 320 330 340 350

Tomperature (•€)

165
RECOMMENCED Li CONCENTRATION RANGE

AS A FUNCTION Of BORON CONCENTRATION

POm U

ppm B

166
( Basic Aqueous Chefnistry at High Temperatures and Pressures at ORNL*

R. E, Mesmar

Chemistry Division

Oak Ridge National Laboratory

Oak Ridge, Tennessee 37830

The Chemistry Division at Oak Ridge National Laboratory has had a program in

basic aqueous chemistry since the 1950' s when work was being done on the homogeneous reactor experiment (UO2 SO4 dissolved in H

2 SO4 solution) with over two

hundred publications over the years as the purposes changed. Many new techniques were developed and applied in that program to aqueous systems at temperatures up to 300° and sometimes 800°C.

The program has been devoted to precise quantitative measurements on systems

applicable in reactor coolants, steam generators, desalination, and hydrothermal

geochemistry as well as basic correlations. Most work has been in the use of

conductance, hydrogen electrode cells, isopiestic and calorimetric techniques as

well as phase equilibrium measurements. Many scientists have been involved

notably Marshall, Sweeton, Lietzke, Holmes, Busey, Baes and myself. I will

review in a very brief way some of the highlights of the program and Bill

Marshall will follow with some elaboration on phase studies and other research

with which he has been directly involved.

* Research sponsored by the Division of Chemical Sciences, Office of Basic

Energy Sciences, !J.S. Department of Energy under contract W-7405-eng-26 with

the Union Carbide Corporation.

167
BASIC AQUEOUS CHEMISTRY

TO

HIGH TEMPERATURES AND PRESSURES

(Oak Ridge National Laboratory)

Equilibrium Studies

• Phase studies (350 PsATN.)

PHOSPHATE; SILICA; OXIDES; HYDROXIDES; SULFATES

• POTENTIOMETRY (300°C^ PsATN-^

ACID-BASE IONIZATION; HYDROLYSIS; HCl ACTIVITIES

• Conductance (800°C^ 4000 bars)

1:1 AND 2:1 ASSOCIATION^ IONIZATION OF ACIDS

& bases

® Spectrophotometry

l2 solution chemistry

® Modeling

Thermodynamics of Electrolytes

® ISOPIESTIC studies (250°C^ PsATN.)

CHLORIDES^ sulfates^ HYDROXIDES^ MIXTURES

® Mixing calorimetry (500°C^ 400 bars)

HEATS OF dilution^ MIXING^ REACTION

• Modeling

168
ORNL—DWG 81-6618

r

c

50 100

t (*C)

200 400 600 1000

Log K for the Ionization of Water from 0 to 1000’

at Several Densities and at the Saturation Vapor

Pressure.

(

169
(

ORNL-DWG 81-6640

t(“C)

50 100 200 400 600 1000

1000/j(o|^)

Log K for the Protonation of Ammonia From 0 tolOOO^C.

At Several Densities and at the Saturation Vapor

Pressure.

170
log K

ORNL-OWG 77-14135ft tCC)

300 250 200 150 100 50 0

0.0017 0.0021 0.0025 0.0029 0.0033 0.0037

VrCK)

Log K vs / T for Ionization Reactions of Weok Acids and Weak Boses

from 0" to 300 "C.

171
(

ORNL-DWG 8i-6624

t CO

300 200 iOO 50 0

^000/t(ok)

Neutralization Reactions: e.g. HA-t-OR .:i^:H20 + A

172

log K
f

ORNL-DWG 81-6638

ACp for Ionization Reactions (Lower Curves) and

for Neutralization Reactions (Upper Curves) All

Measured Potentiometricly.

173
c

ISOPIESTIC STUDIES OF AQUEOUS SYSTEMS (110 - 250°C)

*j t » «• LiCl MgCl2 Li2S0i^ NoCl + KCl

•j t • KCl CQCI2 NQ2S0^ NaCl + LlCl

•j t * CsCl SrCl2 K2SO4 NaCi CsCl

* * « NiCl2 BQCI2 CS2SO4 NaCl + CaCl2

t « t

NiSO^ C0CI2 MgSO^ KCl + CaCl2

C ^Published

"^In press

174
c

m

O CD to CM O

d CD C) b

175
NqCI

ORNL-DWG 82-11486

MEAN ACTIVITY COEFFICIENT OF AQUEOUS NoCI AT

SATURATION PRESSURE (400° AT 415 bars)

176
ORNL-DWG 80-14463R

ENTHALPY OF DILUTION OF AQUEOUS NaCI

177
{

ORNL-DWG 8^-<8736

ENTHALPY OF DILUTION OF AQUEOUS CoCIa

178
Aqueous Solutions at High Temperatures

Robert H. Wood

FLOW CALORIMETRY HAS OPENED UP HIGH TEMPERATURE AQUEOUS

SOLUTIONS FOR RAPID, PRECISE INVESTIGATION.

(1) SENSITIVE TO CHANGES IN C^ OF 1 IN 10,000.

(2) RAPID-NEW DATA POINT EVERY 15 MINUTES

AT PRESSURES UP TO 177 ATM.

(3) VALUES OF Cp(T) WITH G(298) AND H(298) GIVE

G(T) AND H(T).

MEASUREMENT OF Cp(T,P) GIVES H(T,PX_ AJ©lifi(T;P)

GIVEN G(298,P), H(298,P) AND Cp(T,P) WE CALCULATE

H(T,P) = H(298,P) + /

T

C (T,P)dT

P

298

AND

T ,T

298 298

KNOWLEDGE OF G ALLOWS CALCULATION OF HIGH TEMPERATURE CHEMISTRY;

SOLUBILITY OF MINERALS, CORROSION POTENTIALS, OXIDATION-REDUCTION

REACTIONS, FORMATION OF CHLORO-COMPLEXES , ETC.
/JK

mol
K

mol

131
182
133
18A

0,5 \/t99/a/kcL 1*0

vh
/J

K

^

mol

T/K

185
TEMPERATURE. ®C

186
CORRESPONDING STATES PREDICTION OF c^/J

T/K

m 397.97 497.73 603.39

-1

mol kg

0.0996 4.185 4.483 6.289

4.180 4.470 6.263

0.4940 4.086 4.333 5.545

4.070 4.312 5.625

3.000 3.570 3.650 3.894

3.564 3.669 3.996

EXPERIMENTAL

CONCLUSIONSV

1) THIS TREATMENT WORKS AMAZINGLY WELL FOR NaCl.

2) IT NEEDS FURTHER TESTS ON OTHER SALTS.

3) NOT EXPECTED TO WORK FOR TEMPERATURES WHERE THE STATE OF IONIZATION

OF THE SALT IS NOT SIMILAR TO THAT NEAR THE CRITICAL POINT.

PREDICTIONS ;

1) MARSHALL AND JONES FIND THAT MANY SALTS (LiCl, NaCl, KCl, KBr, KI,

CSNO

3

, KHSO4 , NH4CI) HAVE VERY SIMILAR T^ AT THE SAME MOLALITY.

PRESUMABLY P^ IS ALSO SIMILAR AND CORRESPONDING STATES THEORY

PREDICTS SIMILAR C„ . RECENT EXPERIMENTAL EVIDENCE SUPPORTS THIS

(COBBLE & MURRAY, LINDSAY, CRISS)

.

2) ANY SOLUTE WILL HAVE C ^ or -«> AT THE CRITICAL POINT

P,<l> DEPENDING ON WHETHER THE CRITICAL POINT IS SHIFTED UP OR DOWN IN

TEMPERATURE BY THE SOLUTE.

QUESTION : CAN THIS EQUATION PREDICT SUPERCRITICAL HEAT CAPACITIES?

187
THE BORN EQUATION, AN EQUATION FOR THE ELECTROSTATIC FREE ENERGY

OF A CHARGED SPHERE IN AN INCOMPRESSIBLE DIELECTRIC FLUID, IS:

= -(Le^/87re^)CR"^ + r”^)(1 - 1/ D)

L = AVOGRADO'S NUMBER

e = PROTONIC CHARGE

e » VACUUM PERMITTIVITY

R_^, R = RADII OF CATION AND ANION

NaCH ys. SoKyy.

PREDICTIONS R = 3.27 A

P » 177 BAR

T/K S,<|,(EXPT.) S,«J>(CALC.)

A

300 -49 -35 14

350 -50 -50 0

400 -85 -75 10

450 -165 -119 1f46

500 -306 -215 J 91

550 -628 -534 l94

600 -3001 -2995 |L 6

AC

AT 572 K = AP

PREDICTED VALUE IS

AC

AT 320 K = AP

PREDICTED VALUE IS

"CHEMICAL EFFECTS" DOMINATE AT 320 K.

+325 J mol"-*- K~

74 BAR

+329

74

14

167

2

167

o'nei^:parameterv<predicts,-:temperaturevand'

^RESSURE'.DEPENDENCE' NEAR.CEITICAL'vPOINT..

188
COMPARISON OF C° = „ FOR NaCl VERSUS KCl (J K“^ MOL"^)

P»<P P»2

T=350 K T=600K

NaCl “48 -2168

KCl -198 -2378

RCk"^) » 0.133 NM R(Na*^) = 0.095 NM

FOR KCl, BORN WITH CRYSTAL RADIUS PREDICTS C? ^ FOR KCl SHOULD

-o +

BE 40% LESS NEGATIVE. ACTUALLY.

^ ^ FOR K + Cl" IS 10% MORE NEGATIVE

p,2

AT 600 K.

AT ALL TEMPERATURES C° „(NaCl) - C° ^(KCl) = 109 TO 210 J k"^ MOL”^.

CHEMICAL (MOLECULAR) EFFECTS ARE AT LEAST THIS LARGE'. THIS WAS ALREADY

CLEAR FROM 298 K DATA.

THE ELECTROSTATIC CONTRIBUTION MAY BE ROUGHLY CONSTANT FOR DIFFERENT

IONS. THE APPROXIMATION THAT C° ^ FOR ALL ELECTROLYTES ARE THE SAME IS

P,<l> NOT CORRECT BUT IT'S A GOOD FIRST APPROXIMATION (+10%?).

189

>

400

600

800

1000

el

AGu /kJ mol

n

o) ro

o o o

o o o o

191
/kJ

mol
O

CM

193

.• \ »
COMPRESSIBLE

FLUID

R/A
DISTRIBUTION OF CHEMICAL SPECIES BETWEEN

WATER AND STEAM

by Paul Cohen

The distribution of chemical species between two phases, water and steam

is governed by the phase rule. The extended system can consist of three phases,

liquid, vapor and solid and two components, water and solid (if there is no reaction).

W riting

P + F = C + 2. We have, for 1, v, only

F = C - P + 2

F = 2

Thus, if temperature and pressure are fixed, the compositions of both phases

are fixed. This applies only for species which do not react with water, i.e., acids

or bases. In the case of salts, which can hydrolyze, an additional degree of freedom

exists, namely the ratio of the quantities of the two phases. This follows from

the independent mobility of the hydrolysis products. Thus at equilibrium between

the phases the ratio of the cation and anion of the salt does not have to be identical

in the two phases. Only the overall ratio has to correspond to the salt composition.

Thus incongruent volatility of salts from liquid to vapor is to be expected and

has been observed.

At the saturated solution line, there are three phases

F=C+2-P=l

Thus, if either pressure or temperature are fixed, the other and the compositions

of the phases are defined.

195
In the superheated region, solid and vapor only, the composition of the solid

(hydration) and composition of the vapor are fixed, if pressure and temperature

are fixed.

Two systems have been studied extensively, Si02 - H

2

O and NaCl - H

2

O.

They represent solutions with limited or extended solubility in the liquid, and

high and low solubility in the vapor respectively (Figs. 1 and 2). Both materials

are common in the steam cycle and are technologically important. The transported

solids produce deposits in turbines (Si 02) or create potentially destructive environments

in turbines (NaCl).

For control in the boiler, the region of dilute solutions is of interest, where

the apparent distribution constant, K j^, is of the order of 10 to 10 , Fig.

3. For turbine phenomena, at lower temperatures but high superheat, the distribution

-9 -8

coefficients are very low, of the order of 10 - 10 , with high concentrations

in the liquid phase, and low concentrations in the vapor phase. Therein lies the

technical problem. Very dilute steam solutions can produce very concentrated

solutions in equilibrium. Fig. 4. These two sets of data are roughly correlated

as follows:

A. log S = yy\ logPy^+ H + B.

T

py is the steam density. T is the absolute temp, m, H, and B

are constants, S is the steam phase concentration in equilibrium

with solid salt.

B. K D

-

wherep^,pv are the densities V) the liquid and vapor phases, n is a constant,

and is an apparent distribution coefficient for dilute solutions, see

Fig. 3.

196
Given the data for the solid solubility and thermodynamic data for the liquid solutions,

the complete field should be calculable. This has been attempted by the writer

for NaCl (requiring hydrolysis) with only moderate success. Recently, Pitzer has

attempted to model the solubility of salts after the hydration of the individual

ions, as observed by mass spectrometry (Fig. 5) with moderate success.

Further understanding of this field will require studies of systems without

hydrolysis. LiOH is most suitable, for it has limited solubility in the liquid phase,

and correlation of the two fields 1, v, // s, v would be possible.

197
Fig. 1. Phase Equilibrium diagram for Si)2"^2® (Ref.

198
Fig. 2. Phase equilibrium diagrams for system NaCl-H^O (Ref. 33)

199
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201
r

lOOO/T

• «SS«

Fig. 5 The sacuraclon vapor pressure of NaCi in steam: (a) as a function of P at

450*C (723 K), points from references: 6, solid circles; 4, open circles;

9, triangles; (b) as a function of T at 50 bar, points from references:

6, circles; 8, triangles; (c) as a function of T at 1(X) bar, points from

references: 4, circles; 8, triangles. On all parts the curves are calculated from the models discussed In the text.

202
Thermodynamics and Electrochemistry of Corrosion

G. J. Theus

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(VOLT

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FIGURE ' POTENTIAL-ipH DIAGRAM FOR Fe-^-HoO SYSTEM AT'25°C

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213
POTENTIAL

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Z

AXIS

THREE DIMENSIONAL DIAGRAM FOR Fe - H2O

AT TEMPERATURE FROM 25 TO 300° C

214
215
POTENTIAL

(VOLT

VS.

SHE)

Potential — pH Diagramfor Fe-cr-H20 at 300°C

216
POTENTIAL

(VOLT

VS.

SHE)

Potential — pH Diagram for Fe - S - H2O at 300°

C

217
POTENTIAL

(VOLT

VS.

SHE)

Potential — pH Diagram of Fe > H2O with

Cr(OH)3 Stability Region on Top of it at 100°C

218
POTENTIAL

(VOLT

VS.

SHE)

Potential — pH Diagram of Fe - H2O with

Cr(OH)3 Stability Region on Top of it at BOO'^C

219
POTENTIAL

(VOLTS

vs

SHE)

|)H

FIGURE 22 POTENTIAL ()U DIAGRAM FOR N. S lUO SYSTEM AT 25'^C

fi ^lONS '^CONTAMINANT IONS

220
POTENTIAL

(VOLT

VS.

SHE)

Potential — pH Diagram for Ti - Cl” - H2O at 1 00°

C

221
POTENTIAL

(VOLT

VS.

SHE)

Potential — pH Diagram for Ti - F“ - H2O at 100°C

222
c

(CEE3

l/l

flC O

(/) a.<G<O

oc

LU

(/) D

liJ CC<

C/3 2<

QCo<QX<

OQOCDo

Q.

liJ

w CQ

2. <

UJ

-i

OQO

CC

-J<><

a. >-i zg G<

(/i lU o OC

oc

ocoo < </)

GZ<

CDz zo

1-<G Zg

OC

LUt < > (/) O o

f”

lU < G < CQ G o

CA z

Ui <

LU

OC 0C

O

OCo

Q.

lU z>

U.o o

UL i< oz G

>-O

GO2

c/3 g

(/) g z>G

H*O <

OC

oc

LU

H

lU2 X

lU

OS Q D I G OC

liJ o hX LU LU

OC o LU I

Q. < • • z H

223
Correlation of Data for Electrolytes in Water and Steam

J. Christopher Pei per*

Department of Chemistry

University of California, Berkeley

Berkeley, CA 94720

(Paper presented at the Workshop on Cycles, held at the National Bureau

8-9, 1983).

Chemical Thermodynamics in Steam Power

of Standards, Gaithersburg, MD, February

%

*Present address: Department of Chemistry

Arizona State University

Tempe, Arizona 85287

224
Introducti on

Two problems must be addressed in correlating data for use in steam power

generation and associated technologies: First, the aqueous solutions involved

are multi-component systems with overall composition ranging from extreme

dilution to solute saturation. Second, these solutions are present as liquidor gas-like fluids at temperatures to 800 K and pressures to 500 bar.

Therefore, correlative techniques must apply over a wide range of

conditions. This paper briefly describes three complementary formulations:

the ion-interaction (or virial coefficient) equations of Pitzer, the older

equations of van Laar, and an ion-hydration model.

Ion-interaction Model

The ion-interaction model is based upon a virial expansion in the solute

concentration or molality; molality is preferred since it is temperatureindependent. This approach has an excellent theoretical basis. MacMillan and

Mayer^ established for dilute solutions a treatment formally similar to that

for nonideal gases, provided intermolecular potentials are replaced with

potentials of mean force for the solvent of interest. Thus second and higher

virial coefficients may be computed from well-known statistical mechanical

formulas; for electrolytes this computation is not strai ghtforward due to the

long-range nature of the coulombic potential. But Mayer^ and others have

shown that a Debye-Huckel term accounting for electrostatic effects may be

combined with a virial expansion accounting for short-range interactions. In this case, however, virial coefficients depend upon the ionic strength as well

as temperature and pressure.

This theoretical basis was used by Pitzer^ in developing practical

equations for the thermodynamic properties of electrolyte solutions. His

basic equation is postulated for the excess Gibbs energy of the solution;

other thermodynamic quantities may be obtained by differentiation

n RT w f+Z .m.m.\..+E .. mmm u

1 .J 1 J IJ 1 ,J ,k 1 j k ^jk ( 1 )

0X Here G /n^ is the excess Gibbs energy per kilogram of solvent and m^ , mj

,

etc., are the molalities of ions or neutral species. Electrostatic

interactions lead to the Debye-Huckel term, f, which is dependent upon ionic

225
strength. Short-range forces are accounted for by binary and ternary virial

coefficients, . and These quantities are theoretically dependent upon

ionic strength, but for this dependence is neglected. Of course, (1) may

be extended to fourth and higher virial terms, but in practice this is not

necessary

Appropriate composition derivatives yield equations for osmotic and

activity coefficients, which were used to model experimental data at 298 K for

n c

a wide variety of pure and mixed aqueous electrolytes. ’ Later work

considered special groups of electrolytes®"^^ and cases complicated by

association equilibria. At temperatures significantly above 298 K,

experimental data for most systems become sparse. However, it has been

possible to determine ion-interaction parameters for NaCl (aq) to 573 and

for Na 2 S04 (aq) to 473 In all, nearly 300 pure and 70 mixed electrolyte

systems were studied and ion-interaction parameters reported. In addition,

measured enthalpies for more than 100 pure electrolytes at 298 K were correlated^® using the temperature derivative of (1), yielding temperature

coefficients of ion-interaction parameters.

The importance of the ion-interaction formulation is especially great for

mixed electrolytes. Of the needed virial parameters for a complex mixture

(e.g. seawater), most are determined from measurements on pure electrolyte

solutions. The remainder are determined from data on binary mixtures, but

these mixing terms are small and can usually be ignored for all but the most

abundant species.

Harvie and Weare^^ recently confirmed the effectiveness of the ioninteraction model. These authors accurately represented activity and

solubility information for the seawater-related system (Na'*’, K'*’, Mg^'*’, Ca^'*',

1

Cl", S0^“, H2 O) at 298 K and correctly reproduced the evaporite sequence.

There are 13 invariant points (each with four solids present) and in all 13 cases the predicted solution composition agrees with the experimental value

given by Braitsch^^ well within the error of measurement.

Not all of the and are independent for electrolyte solutions due

1 J 1 J K to electroneutrality. Thus (1) is recast into the working form

.ex -TTF = f(I) + 2z

n RT c,a

0)

m m [B (I ) + (Emz)C j

226
( 2 )

+ Z ,mm,[e. .,(!) + 1/2 Z m 4; , ]

c,c c c 1,1 a a c,c ,a

+ z , m m , [e , (I) + 1/2 Z m 4, , ],

a, a a a a, a c c c,a,a

where is the molality of cation c with charge z^, and similarly for a. Sums over c or a cover all cations or anions with z„, = Z m^z^ = z m Iz^l.

B's and 0's are measureable combinations of \'s and C's and 4<'s are combinations of

The electrostatic function f(I) must contain the Debye-Huckel limiting

law, but for correlative purposes it proves advantageous to adopt an extended

form. From a variety of alternatives, Pitzer^ selected

f(I) = ^A In (1 +

K A

1/2,

(3)

wiith b = 1.2 kg^/^ mol"^/^ for all electrolytes in water. The Debye-Huckel

parameter is a function of the properties of pure water only:

4> 2uN d 2 A = 1/3 ( o_w. 1/2 /_e_x3/2

\ ^ 1000 ’ ^DkT^ (4)

where is Avogadro's number, d^ is the density of water, e is the electronic

charge, D is the dielectric constant of water and k is Boltzmann's constant.

Bradley and Pitzer^^ give values for A for a wide range of temperatures and

pressures

.

The second virial coefficients B^ ,(I) and binary mixing terms 0. .(I) are dependent upon temperature, pressure and ionic strength. Pitzer^ selected

23‘1>

B (I) = 3^°' + {1 - (1 + exp(-ad''^) (5) C)d C)d c a I

from several theoreti cal ly plausible forms with parameters and

C 9 d C ) d determined empirically. This equation is valid for all electrolytes with at

least one univalent ion with a

= 2.0 kg^^^ niol"^/^, pgr other electrolytes

where there is a tendency to form ion pairs, an additional term is added:^’^

“l‘

227
( 6 )

23

( 2 )

+ ^^{1 - (1 exp(-a2l^^^)}.

"2^

In this case = 1.4 and = 12.0 kgl/2 ,t,q]-i/2^

The dependence of 0. .(I) on ionic strength is given in a different

' ’s manner. Following Pitzer:

0. .(I) = ^0. .(I) + ^0. . + 1^0'. . ( 7 )

The first term on the right represents higher-order electrostatic effects,

first noted by Friedman^--^ in his cluster theory for electrolyte solutions.

Notably, ^0. .(I) is computed in an a priori manner from equations given by

Q Op ' Pitzer°>‘^‘^ ; these terms do not constitute additional parameterization of the

ion-interaction model. If i or j is a neutral species, or if i and j are equi-valent, ^0. .(I) = 0. The remaining terms of (7) account for the effects

1 J J of short-range interactions and their variations with ionic strength

(^0* . = d\. ./dl). , _ the latter are so small as to be of no practical significance and are usually

neglected.^

S S 0. . and 0^I . must be determined empirically; however.

The third virial parameters , and ternary mixing parameters 4

;- • . are jd 1 , J jK

independent of ionic strength and must be evaluated from experimental data.

The third vi rials are commonly tabulated as defined by

C 9 a

C4)c,a

= 2 z z

I c a 1/2

c ,a ( 8 )

It would be difficult to present here all or even most of the known

parameters for aqueous electrolytes. As an example showing the magnitudes of

various parameters, tables 1 and 2 give virial and, mixing coefficients for the

system (Na'*’, Ca^'*’, Cl", SO^", H2 O) at 298 K. Most of these values were taken from Pitzer and Mayorga^ or Pitzer and Kim,^ but a few were revised

in later work.^^»^^ Note that the mixing coefficients are much smaller than

the corresponding virial coefficients.

228
van Laar Equations

For very concentrated solutions, a virial expansion is not

satisfactory. Presumably a nonrandom distribution of ions (with oppositely

charged species close to one another) applies from the fused salt through the

range of high solute concentration, leading to large virial coefficients of

all orders. Only in dilute solutions will the ion distribution approach

randomness. However, the properties of concentrated electrolytes are dominated by short-range forces, just as with non-electrolytes, and one expects equations developed for the latter to be appropriate.

There are two systems for which the vapor pressure of water, hence its

activity, was measured over the full compositional range from dilute solution

to fused salt.^^"^® For each system, (Ag,Tl )N 03 -H20 or (Li ,K)N 03 -H20 , the

salt is a simple eutectic mixture. The results are shown in figure 1 which

also includes data for other systems with a large but limited solubility.

Compositor in the mole fraction given on a completely ionized basis,

xi = ni/(nj_ + vn 2 ) with n^ and n

2 the moles of solvent and solute and v the

number of ions in the salt.

The similarity of these curves to those for non-electrolytes is apparent,

with Henry's law and Raoult's law regions clearly visible. The dashed line

representing ideal solution behavior neglects short-range and electrostatic

interactions. This similarity encouraged application to ionic solutions of

simple equations derived for non-electrolyte systems. One of the simplest and

most successful had its origins in the work of van Laar.^^ Prausnitz^^

discusses this equation and the contribution of Margules, Hildebrand,

Scatchard, Guggenheim and others to this topic. For the activity of either

component, referenced to the pure liquid, one has (water is component 1):

The nonideality parameter oj, occasionally written w/RT, represents the

difference in i ntermol ecul ar attraction of unlike species as compared to the mean of intermolecular attractions for pairs of like species. The second

parameter (b^/b2 ) is sometimes equated with the molar volume ratio for each

In a^ = In Xj^ + w^z^ In a^ = In x^ + .

= 0),(b /bj (9)

229
species in the liquid or with the ratio of molecular volumes. For ionic

solutions it is best to regard (bi/b2 ) as a freely adjustable parameter.

Least-squares fits of (9) to data for the two completely miscible systems

yields

= 1.02, (b^/b

2

) = 0.50 for (Ag ,T1 )N02~H20 , and

= -0.89, (b^/b

2

) = 1.2 for (Li ,K)N02-H20 .

A Debye-Huckel term was not included in either calculation; if included,

agreement is improved in the water-rich region.

Of course, the van Laar equations may be reformulated for mul ti -component

solutions

Ion Hydration Model

The behavior of an electrolyte when dissolved in steam is quite different

than when dissolved in liquid water: Gaseous ions, with or without attached

water molecules, tend to aggregate in neutral or near-neutral clusters. Under

these conditions an ion hydration model is more appropriate.

For an ion dissolved in steam, the first few hydration steps are most

important since the energy binding a water molecule to an ion-water cluster

decreases rapidly as the cluster size increases. Therefore, its seems reasonable to treat distant water molecules separately from those which are tightly bound. The "outer-shell" effects of distant water molecules are easily and accurately included via the Born model, which Professor Wood

discusses in greater detail elsewhere in these proceedings. The Born equation

for the Gibbs energy of solvation is

( 10 )

where R* is the effective radius of a spherical cavity in the dielectric

solvent (in the present case, steam) which contains the ion; s is the

dielectric constant or relative permitivity of the solvent, is the vacuum permitivity and e is the protonic charge. The dielectric constant of steam

may be taken from Quist and Marshal 1^^ or Uematsu and Frank. For the

present work, the equation given by Quist and Marshall was adopted since its

form is theoretically satisfactory for extrapol ati on to higher temperatures

230
from the range of experimental measurement. A value of 6 A was chosen for R*,

the effective size of the ion-water cluster, after a few preliminary

calculations

.

"Inner-shell" effects are best included by stepwise hydration equilibria;

for NaCl the solute:

[Na(H20)n_i]‘" + H

2 O = [Na(H20)n]‘", C

[Cl(H20)n.i]- + H

2O = [Cl (H20)n]',

NaCl(H20)n.i + H

2 O = NaCl(H20)n, (11)

Kebarle and associ ates^^ determined the K^'*' and Kp" from mass spectrometric

measurements. By measuring Kp'*’ and Kp" at several temperatures they

obtained aH and aS as well. Table 3 summarizes their results; the linear

n n equation accurately reproduce Kebarle's values to n = 6 (the limit of

measurement) and form the basis for extrapolation to slightly larger n.

There are, however, no molecular-level data for hydrates of the Na"'’Cl"

pair. Physically, one expects the first two or three water molecules to bind

to Na''' since its hydration enthalpies are much larger than those for Cl“. But

the presence of Cl" will lower the attachment to Na"'' and a value intermediate

between those of Na"^ and Cl" seems appropriate. Some additional guidance in

selecting values for the AH°p and AS®p may be obtained from the solubility of

NaCl in steam. The measurements of Martynova, Styrikovich, et a1 .

,

SourincLjan and Kennedy, and Gal obardes , et al . were considered.

Unf ortunately , these measurements are difficult and uncertainties in the final

results quite large; nevertheless, reasonable agreement was obtained with all

data, except those of Sourirdyan and Kennedy, with the values given in table

3c

.

Many thermodynamic properties may be computed from (10) and (11) with the

values of table 3. Figure 2 shows the solubility of NaCl in steam for a wide

range of conditions. At the relatively low pressures and moderate

temperatures where steam turbines are usually operated, NaCl solubility is

lO'll or less. This is smaller than the value currently obtainable by current

technology for the purification of boiler feed water. Figure 3 gives the

231
ionization constant of NaCl in steam; the experimental data are those of Quist

and Marshall. At 1073 K, the computed results fit very smoothly with

experimental values. At lower temperatures, the curves take on a distinct

S-shape with a gradually increasing slope connecting the low and high density

regions. Below the critical temperature of water this must become a discontinuity in both log p and log K.

Extension of the hydration model to other species is strai ghtforward , and

Pitzer^® has considered the hydration of H'*' and OH". Molecular-level data are required, but even crude estimates of the enthalpies and entropies of

hydration yield much-needed information on the behavior of electrolytes in

steam.

232
References

1. Macmillan, W. G. and Mayer, J. E., J. Chem. Phys,, 1945 , 13, 276.

2. Mayer, J. E., J. Chem. Phys., 1950 , 18, 1426.

3. Pitzer, K. S., J. Phys. Chem., 1973 , 77 , 268.

4. Pitzer, K. S. and Mayorga, G., J. Phys. Chem., 1973 , 77, 2300.

5. Pitzer, K. S. and Kim, J. J., J. Am. Chem. Soc., 1974 , 96, 5701 . 6. Pitzer, K. S. and Mayorga, G., J. Solution Chem., 1974 , 3, 539.

7. Pitzer, K. S. and Silvester, L. F., J. Phys. Chem., 1978 , 82, 1239.

8. Pitzer, K. S., J. Solution Chem., 1975 , 4, 249.

9. Pitzer, K. S., Peterson, J. R., and Silvester, L. F., J. Solution Chem.,

1978 , 7, 45.

10. Downes, C. J. and Pitzer K. S., J. Solution Chem., 1976 , 5, 389.

11. Pitzer, K. S., Roy, R. N., and Silvester, L. F., J. Am. Chem. Soc., 1977 , 99, 4930.

12. Pitzer, K. S. and Silvester, L. F., J. Solution Chem., 1976 , 5, 269.

13. Peiper, J. C., and Pitzer, K. S., J. Chem. Thermodynamics, 1982 , 14, 613.

14. Pitzer, K. S., Peiper, J. C., and Busey, R. H., J. Phys. Chem. Ref.

Data., submitted; see also Lasrence Berkeley Laboratory Report No. 15512,

available from Technical Information Division, Lawrence Berkeley

Laboratory, Berkeley, CA 94720.

15. Rogers, P. S. Z. and Pitzer, K. S., J. Phys. Chem., 1981 , 85, 2886 . 16. Silvester, L. F. and Pitzer, K. S., J. Solution Chem., 1978 , 7, 327.

17. Harvie, C. E. and Weare, J. H., Geochim. Cosmochim. Acta, 1980 , 44, 981 . 18. Eugster, H., Harvie, C. E., and Weare, J. H., Geochim. Cosmochim. Acta,

1980 , 44, 1335.

19. Braitsch, 0., "Salt Deposits: Their Origin and Composition,"

Spri nger-Verl ag, 1971.

20. Bradley, D. J. and Pitzer, K. S., J. Phys. Chem., 1979 , 83, 1599 . 21. Friedman, H. F., "Ionic Solution Theory," Interscience, New York, 1962.

22. Pitzer, K. S., J. Phys. Chem., submitted.

23. Rogers, P. S. Z., Report, 1981 , LBL-12356, Avail NTIS or Technical

Information Division, Lawrence Berkeley Laboratory, Berkeley, CA 94720.

24. Trudelle, M-C., Abraham, M., and Sangster, J., Can. J. Chem., 1977 , 55,

1713.

25. Tripp, T. B. and Braunstein, J., J. Am. Chem. Soc., 1954 , 73, 1984.

26. Braunstein, H. and Braunstein, J., J. Chem. Thermodynami cs , 1971 , 3, 419.

233
27. van Laar, J. J., Z. physilk. Chem., 1910 , 72, 723,

28. Prausnitz, J. M., "Molecular Thermodynamics of Fluid-Phase Equilibria,"

Prentice-Hall, Inc., Englewood Cliffs, NJ, 1969.

29. Quist, A. S. and Marshall, W. L., J. Phys. Chem., 1965 , 69, 3165.

30. Uematsu, M. and Franck, E. U., J. Phys. Chem. Ref. Data, 1980 , 9, 1291.

31. Ozldic, I. and Kebarle, P., J. Phys. Chem. 1970 , 74, 1466.

32. Anshadi , M., Yamdagni , R., and Kebarle, P., J. Phys. Chem., 1970 , 74,

1475.

33. Martynova, 0. L., Zh. Fiz. Khim. 1964 , 38, 1065; Russ. J. Phys. Chem.,

1964 , 38, 587.

34. Styrikovich, M. A., Martynova, 0. L., and Mingulina, E. I., Dokl. Akad.

Nauk. SSSR, 1966 , 171, 911; also see the English translation, 1966 , 171,

783.

35. Sourirdljan, S. and Kennedy, G. C., Am. J. Sci . , 1962 , 260, 15.

36. Galobardes, J. F., Van Hare, 0. R., and Rogers, L. B., J. Chem. Eng.

Data, 1981 , 26, 363.

37. Quist, A. S. and Marshall, W. L., J. Phys. Chem., 1968 , 72, 684.

38. Pitzer, K. S., J. Phys. Chem., 1982, 86, 4704.

234
Table 1. Parameters for virial coefficient equations at 25“C

M X TO ^MX ^MX TO

Na Cl .07650 .2264 — .00127

Na .01958 1.1130 — .005 7

K Cl .04835 .2122 — -.00084

K so,

4

.04995 .7793 — 0

Mg Cl .35235 1.6815 — .00519

Mg SO

4

.22100 3.3430 -37.23 .025

Ca Cl .31590 1.6140 — -.00034

Ca t/J 0 .20000 3.1973 -54.24 0

Table 2. Parameters for mixed electrolytes with the

virial coefficient equations (at 25°C)

i 3 k

S9.,

ij ijk

Na K Cl -.012 -.0018

SO,

4

-.010

Na Mg CZ. .07 -.012

SO,

4

-.010

Na Ca Cl .07 -.014

SO

4

-.067

K Mg C^ .0 -.022

so. -.048

K Ca Cl .032 -.025

so,

4 -

Mg Ca Cl .010 0

SO,

4

.020

Cl SO

4 Na .03 0

K -.005

Mg -.020

Ca -.027

235
Table 3. Enthalpies and Entropies of

Na"^, Cl" and Na'''Cl".

Hydration of

n T*/K cal K"^mol"^ kcal mol"^

a. (Na'*’)

1 700 21.5 24.0

2 550 22.2 19.8

3 450 21.9 15.8

4+ 350 25.0 13.8 - 1.5(n-4)

b. (Cl")

1 400 16.5 13.1

2 400 20.8 12.7

3 350 23.2 11.7

4+ 330 25.8 11.1 - 0.5(n-4)

c. (Na'^Cl")

1 500 22 17.5

2 500 22 13.5

3 500 22 9.5

4+ 500 25 9.5 - 0.8(n-4)

236
Figure 1.

Figure 2.

237
moj?

-2

loa o

238

0
Evaluated Data and Data Bases: Chemical

Thermodynamics in the Steam Power Cycle

David Garvin, Robert N. Goldberg and Bert R. Staples

Chemical Thermodynamics Division

Center for Chemical Physics

National Bureau of Standards

Washington, D.C. 20234

1 . Introduction

The subject of this paper is the thermodynamic data needed in the

solution of chemical problems that arise in steam power plants. We shall

discuss what these problems are (as interpreted by thermodynamicists)

,

what types of data are needed for solving them, how the data can be codified

effectively and what reliable codified data are now available. We shall

also consider the issue of technology transfer: how to get the data from

the laboratory to the engineer and the plant designer.

2. How to get the data

Our plan has two parts.

a. First make maximum use of the existing data: Reinterpret

them, intercompare different studies, correlate the best of them,

guided by theory.

\ b. Then make new measurements:

Fill gaps, resolve ambiguities, extend ranges and test theories.

Expanded version of a presentation at the Workshop on "Chemical

Thermodynamics in Steam Pov/er Cycles. Data Requirements,"

Gaithersburg, Maryland, February 8-9, 1983.

CONTRIBUTION OF THE NATIONAL BUREAU OF STANDARDS.

NOT SUBJECT TO COPYRIGHT.

239
The second part is easier to understand than the first. It is measurement .

It is fun. It is feasible. Many of the experts are here today, the instruments

are nearly sufficient, but measurement is costly and attacks only a small

segment of the problem at a time. We believe that, for an applied program,

there must be a clearly stated reason for each measurement project.

The first part is the evaluation of the existing data . This is a

different approach and, for many scientists and engineers, less familiar. In

it all available data are intercompared and the best of them are melded into

a thermodynamically consistent whole. This means that results from emf,

partial pressure, solubility and calorimetric studies are treated together.

The systematic errors become painfully apparent and the gaps very visible.

The method is feasible, it is rapid (compared to measurement), less costly,

covers the entire problem and points out what still needs to be done.

As an example of maximizing the use of existing data, consider Figure 1,

the relative apparent molar enthalpy of aqueous CaCl

2

solutions at 25 ®C. The

measurements span the time period 1849 to 1975. They define this property very

well, except at the highest molalities (for which the data are both old and

extrapolated from higher temperatures). Measure something else first.

This evaluation of data - reviewing the literature - is a task most

thermochemists are sure that they can do (if they only had the time). We

argue that this task is most efficiently done in a specialized data program.

\ The next section describes such a data program. Later sections of this paper

cover data needs and data sources.

240
3. Structure and Activities of a Thermodynamic Data Project

3.1 General

Solution of the problems of chemistry in power cycles will require

both measurement and evaluation of data. What the data evaluation part should

be and do is discussed in this section. Later we consider what data are available, how they should be organized and what substances should be studied.

There are two principal guidelines to follow in setting up a data project:

It should be specialized to the project at hand, and each component of it

should be limited to the treatment of one class of information.

There are two reasons for adhering to these guidelines. First, in order

to advance rapidly, a project in support of an applied program must concentrate

its effort - high temperature aqueous chemistry is a large subject. This

means building upon evaluations made by others, and extending them.

Second, data comes by discipl ine, . for the most part, and so do experts.

There is some technical gain from mixing thermochemists, kineticists, and

fluid flow specialists, but not as much as for measurement projects. On the

other hand they can share the same computer, report writing and literature

collection facilities with profit.

The organization plan given here is based on data components of larger,

successful scientific studies: rocketry - of which the JANAF Tables are a

legacy, atmospheric chemistry - the CIAP program on the SST and aerosols, and

the current CO

2

studies, and coal stack gas clean up.
3.2 Organization of a Data Project

The optimum organization scheme calls for two distinct parts:

A core group of thermodynami cists to compile and correlate data and to

prepare recomnended values, and an advisory group of experts to delineate

problems, assist with reviews on special topics and to monitor the work.

This dual structure provides breadth and knowledge of the applied problem plus

ability to actually supply the data recommended by the advisory group.

3.3 Activities

The principal things a data project should do are listed below.

a. Identify data needs.

b. Collect relevant data.

c. Evaluate existing data.

d. Promote needed measurements.

e. Distribute recommended values and information.

f. Consult for participants.

g. Develop new interpretations, correlating procedures, and

predictive schemes.

h. Provide liaison with experimental groups.

i. Hold workshops for participants - to distribute the results promptly.

This list shows that a data project can do more than provide reliable data,

it can serve as a focus for a larger program.'

In the remainder of this paper we shall address only item a, above, the

identification of data needs. This is done both to show the point from which

a data project would start and also to provide the participants with information about data sources they can use today. The other items in the list

are self-explaining.

242
4. Data Needs for High Temperature Aqueous Systems

4.1 Scope

Our consideration of data needs is restricted to thermodynamic data

needs. But more than solutions must be considered: there are many two-phase

systems involved and a good bit of chemistry.

The principal application of the data is in the prediction of the

composition of a system under conditions of equilibrium. This may mean

spatially local equilibrium or a dynamic steady state. That is, the major

+3

goal is to be able to answer questions such as: given T, p, pH, [Fe ],

[Cl’], what precipitate forms, what vapor species are there, and what are

their partial pressures?

Answers based on thermodynamics can then be extended by or compared with

kinetic studies.

The material presented below is based on two sources. These are a study

of the literature of aqueous solution thermodynamics (research and applications)

and our interpretation of the presentations made at this workshop.

4.2 Problems to be Solved

Most of the problems require the treatment of chemical and physical equilibri

The more important ones for which data are needed are

a. solubility in water, acid, base, and salt solutions;

b. vapor pressures of both solvent and solute;

c. emfs for oxidation- reduction reactions;

d. complexation, ion pairing, and chelation;

e. hydrolysis and other chemical reactions, both in solution'

and with solids;

f. chemical transport via colloidal suspensions;

Data on oxidation-reduction reactions is the most important, corrosion

is the problem. The others are ones to be solved along the way.

243
4.3 Thermodynamic Organization of the Problems and of the Data

All of the problems to be solved require a knowledge of equilibrium

constants and the activities of the species involved. This means that the

solutions of the problem and codification and correlation of the data can

be organized around the Gibbs energy of each process and its derivatives

with respect to temperature, pressure and composition, that is enthalpies,

heat capacities and molar volumes. The relationships are:

Funct ions

r T,p

0(A^GVT)3T)p =

(3A^H/3T)p =

(3A^G/3p)^

Here is a change in a process, G is Gibbs energy, H is enthalpy, Cp is

heat capacity, K is an equilibrium constant and T, p and V are temperature,

pressure and volume, respectively. These equations show that what is needed

is an equation of state:

A^G ( T, P, x)

or, as a minimum:

A^G(T°, x), a^H(T% x), A^Cp(T, x), a^V(T, x)

where T® is a reference temperature, and x is the composition variable.

Interestingly enough, both of these approaches are feasible. They can be

illustrated for the excess properties of solutions. Silvester and Pitzer (1977)

and, more recently, Pitzer, Peiper and Busey (1983) have provided equations of

state for NaCl solutions, and Phutela and Pitzer (1983) one for CaCl

2

. The "mimmum

set" approach is illustrated by our current evaluation of data on CaCl

2

* Figure 1

shows the enthalpy and figure 2 shows a Gibbs energy property, the osmotic coefficient, at 25,®C, Figure 3 shows the heat capacity at four temperatures.

-RT In K

-aH®/T^

aV

244
4.4 Thermodynamic Properties That Must be Retrievable From a Data Base

The problems of interest are listed in Section 4.2. The basic thermodynamic

functions are displayed in Section 4.3. In practice this set of functions for

a practical data base must be expanded. A fairly large number of properties

must be either correlated or made available to the user. These are shown in

Figure 4. They include both the properties of solutions (thermophysical

properties - such as the excess properties G , H , C , V which summarize

r activity coefficients and other deviations from ideality) and the properties

of the chemicals that react in all phases (thermochemical properties - A^G, a^H,

A^V, A^Cp). All of these are needed as a function of temperature and, where it

matters, of pressure.

It must be emphasized that the problems listed in Section 4.2 can be solved

if values are known for the functions given in Figure 4. Often it is easier to

extrapolate these functions than the "direct" answers to the problems.

4.5 How to Get the Data Out of the Data Base

All of the discussion so far is summarized in Figure 5 which pulls

together the evaluation process, the data base, and its outputs. High temperature

aqueous solution thermodynamics covers such a wide range of temperature, pressure

and composition, and involves such a wide selection of substances that a very

strong case can be made for letting the user specify exactly which output

data he wants. Therefore we recommend a data base coupled to powerful interpretative programs for this applied project.

The traditional method is to make up tables. This certainly will

continue. Tables are very useful for answering spot questions. We suggest,

however, that the tables be kept to skeleton form and that major use be made

of equations. The equations can give you exactly what you want; the tables

provide a check on trends and on the programming of the equations.

The big gain in efficiency comes when the equations are embedded in programs

that can solve the pertinent problems. If you want solubilities, let the proper

program calculate them for you. Furthermore, and most important, if you are

245
dealing with a complex mixture, let an equil ibrium-miniinization program determine

the speciation for you.

4.6 Substances and Systems to be Included in the Data Base

This is where the work is tailored to fit the problem of power cycle

chemistry. It is here that the collective knowledge of the participants in

this workshop can be applied. Jonas has presented at this workshop an extensive list of substances that have been identified either by analysis or

that can be deduced from a knowledge of materials added to the water cycles.

Most of these identified substances are solids from deposits and corrosion

products. A different view of the problem comes from considering the species

in solution.

Some of the soluble species that might be found in power cycle chemistry

are listed in Figure 6. This list is based on presentations made at the workshop, the list provided by Jonas and articles on applied problems in aqueous

chemistry. The list includes the simple metal ions, which usually are hydrated

in aqueous solutions, oxy-anions and a wide variety of complex ions: ion-pairs,

complexes with additives, hydrolysis products and amphoteric species. All of

these complexes will increase the apparent solubilities of the metal cations

and will also influence the effective corrosion potentials. Our criteria for

listing species in figure 6 are that they are known to exist in solution at

room temperature, there is information showing that the complexes are quite

stable and there is a reasonable presumption that they also will be stable at

higher temperatures.

We do not expect all of these species to be present in significant

concentrations throughout the power cycle solutions. Indeed, the conditions

in those solutions vary greatly - from very dilute solutions in reactor cooling

cycles to saturated hot brines on turbine blades. Many detailed modeling

studies will be needed to sort out which species are important in which parts

of the power cycle solutions. These studies should be made in the early phases

of a data program.

246
4.7 Data That Can be Used in This Program

There are many data available that can be used here. Some of them have

been evaluated. There are, however, flaws in this data set. First, the

temperature and pressure ranges do not match the power cycle chemistry problem,

second there are data missing and, third, there is no coherent source for

thermodynamic data. Instead there are many sources. A selection of compiled

data is given in Appendix I.

In general, there is good coverage of activities at 25 ®C and 1 atmosphere,

reasonably adequate thermal data for solutions of common salts, but very few

heat capacity data. There are very few data of any kind on aqueous solutions

at high temperatures. Both new measurements and theoretical extensions of the

existing data base will be needed.

The compiled thermochemical data on solids and gases are in moderately

good shape. Some of the compilations of data are, however, out of date and the

impact of new data must be considered in the present application. Even so, as

much as possible -these existing data should be used. Needs for highly accurate

data may cause all of these statements to be revised. Needs for high accuracy

will mean special, high accuracy, measurements.

4.8 Data Centers and Machine-readable Data Bases .

We have not identified any publicly available interactive data bases

that might be easily applied to this problem. On the other hand almost everybody has files of data - for local use. It is an activity of much larger magnitude to provide them for general use and to maintain them.

A few current or potential data measures may be mentioned. The tables in

NBS Technical Note 270 are now part of the Chemical Information System (CIS) and

are retrievable by customers of CIS. A magnetic tape version of these tables

also is being sold by the NBS Office of Standard Reference Data. At NBS we

are developing a data base of activity coefficients covering the approximately

400 salts mentioned earlier. It is not yet available.

247
There are several data centers and projects from which information on the

properties of solutions can be obtained. Three of them at NBS are the Electrolyte

Data Center, (B.R. Staples); the Alloy Data Center (K. Bhansali); and the

Phase Diagram for Ceramicists project (L. Cook). At the U. S. Geological Survey,

Reston, VA. , there is the National Center for The Thermodynamic Data for Minerals

(J. Haas). At the Lawrence Berkeley Laboratories , Dr. Sidney Phillips, has

available correlated data on stability constants for 20 metal species, up to

350 °C, and selected data on solubilities, density and viscosity.

Professor R.H. Wood is developing a plan to collect and distribute files of

newly measured data. These would then be available for correlation and integration

into applied projects. This plan is being developed on a grant from the NBS

Office of Standard Reference Data. It should be helpful on this project.

4.9 Cal culational Systems

One future direction of research which we consider to be of great importance

is the development of well -documented and generally available computer

programs which, when coupled with a data base, can be routinely used by both

specialist and non-specialists for the calculation of the thermodynamic

properties of aqueous solutions. (See section 4.5) Under thermodynamic properties

we include all of the excess, partial molar, and apparent molar properties and

the amounts of the various substances and aqueous species present in the solution

or in other phases in equilibrium with the solution. Pourbaix type diagrams

would also be valuable outputs.

Systems on which such calculations need to be made include strong, weak,

and hydrolyzable electrolytes and non-electrolytes and in multi -component mixtures

over a wide range of temperature and pressure. While we are aware of scattered

developments in this direction [Edwards, Newman and Prausnitz (1975, 1978)

248
Zemaitis, NPL], some of which are proprietary, we are not aware of any extensive

compatible sets of codes which are generally available for routine use on

aqueous solutions. Such codes when coupled with extensive data bases and reliable

estimation procedures are the essential thermodynamic tools needed to solve the

practical problems.

249
References

1. Barry, T.I.; Dinsdale, A.T.; Jones, G.P.' "A Databank for Metallurgical

and Thennochemical Calculations"; NPL Report DMA (B) 11, Nat. Physical

Laboratory, Teddington, UK, October 1980.

2. Edwards, T.H.; Maurer, G.; Newman, J.; Prausnitz, J.H.; A.I.Ch.E. J.: 24,

966, (1978).

3. Edwards, T.J.; Newman, J.; Prausnitz, J.H.; A. I .Ch. E. J . ; 21, 248 (1975).

4. Phutela, R.C.; Pitzer, K.S.; "Thermodynamics of Aqueous Calcium Chloride".

J. Solution Chem. (in review 1983).

5. Pitzer, K.S.; Peiper, J.C.; Busey, R.H.; J. Phys. Chem. Reference Data

(in review 1983).

6. Silvester, L.F.; Pitzer, K.S.; J. Phys. Chem. 81, 22 (1977).

7. Staples, B.R.; "Evaluation of Thermodynamic Properties of Aqueous

Electrolytes" in "Thermodynamics of Aqueous Systems with Industrial

Applications"; Newman, S.A., ed. ; ACS Symposium Series No. 133,

Am. Chem. Soc., Washington, D.C., Chap. 27.

8. Zemaitis, J.F., Jr.; "Predicting Vapor-Liquid-Solid Equilibria in

Multicomponent Aqueous Solutions of Electrolytes"; in "Thermodynamics of

Aqueous Systems with Industrial Applications," Newman, S.A., ed.;

ACS Symposium Series No. 133, Am. Chem. Soc., Washington, D.C.,

Chap. 10.

250
FIGURE CAPTIONS

Figure 1. Evaluated apparent molar enthalpy of aqueous calcium chloride at

298.15 K, versus square root of molality. Data measured

from 1849 to 1975 are included and correlated using the Pitzer equation.

X = -» 0), = 3L^/3n^ where n^ = moles

of water. Some data have been adjusted from higher and lower

temperatures.

(Prepared for the CODATA Thermodynamics Tables by V.B. Parker and

D. Garvin 1983).

Figure 2. Evaluated osmotic coefficient (0) of alkaline earth chlorides at 298.15 K

versus molality. 1 - 0 = (nyvMRT) (3G^^/3n^)^2

j p Staples (1980).

Figure 3. Evaluated apparent molar heat capacity of aqueous calcium chloride

solutions as a function of temperature and composition. At temperatures

other than 298.15 K, the correlations are largely based on the unpublished data of White, Gates and Wood. (Prepared for the CODATA

Thermodynamic Tables by B.R. Staples, 1983).

Figure 4. Thermodynamic Properties for which values are needed in aqueous

solution chemistry.

Figure 5. Evaluation and Retrieval of Data.

Figure 6. Substances of interest in the chemistry that occurs in various

stages of the power cycle.

251
—

300 0.

—

250.0

—

200.0

—

150.0

—

100.0

-

50.0

0.0

50.0

100.0

I 252
253
254 I T
Figure 4. Useful Thermodynamic Properties

Thermochemical Properties of Substances

^H“(s, 1, g)

(s. 1, g)

Uses

Calculate K

T dependence of K Heat balance

T dependence of H r P dependence of G and H

Thermophysical Properties of Solutions Uses

p X

G , 0» and "interaction parameters"

Lg. L, 4

Sa’ ‘^1’ '^2

wex

Activities of solute and

solvent

T dependence of activities,

dilution effects

ex

T dependence of H

P dependence of G, H

Mixing rules Estimates for multi -component

mixtures

255
EVALUATED

DATA

BASE

:z; o

CO

HHH

:z: o

COo

HH

-H

p:5

P3

HH

COo H ffi

KH

a.

<! Ph HH P o

O* p:: O' o W o w

COwo

:z; www

256
Figure 6.

Soluble species for power cycle chemistry

The species that may be expected to be in solution in the various parts

of the power cycle are given in the figure. They are based on known

additives and the composition of deposits. Simple (hydrated) cations are

shown at the left margin while anions and other ligands head each column.

The complex ions, ion pairs and hydrolysis products in the body of the

figure are those that would predominate in 0.01 mol kg""* of each ligand.

\

257
OH' X' HSO' HjPO- NH

3

, N

2 H^

+9

0

'^ sof HPof Other

Fe

^ FeO^I Fe(0H' FeF* FeSOJ; etc. FeHPO| Fe(NO), FeEDTA'

Fe"2 Fe( 0 H)

2

, FeF

2 FeSO^, etc. FeHPoJ FeNO^t FeHSiO^^

Fe*3 FeC^t etc. FeEDTA*, Fe(OH)!

CUO

2

T HCuO' CuF^ CuSOJ CuHPO® Cu(NH

3

)^"^, etc.

CuCl'^, etc. CUSO

3

, etc.

CuBr"^ CuEDTA^'

ZnO^, HZn 02 ZnF"^ ZnSO^, etc. ZnHPO® Zn(NH

3 )^^, etc.

ZnOH^, Zn(OH)° ZnCl"^, etc. Zn(N

2

H^)^''’, etc.

ZnOHCl 0

AlO' A1 F^^, AIF^- AlOH^^, etc.

Cr02 , CrOH^'*’, etc. CrCl

2

, etc. CrSoJ CrHPoJ

Cr(IV) CrO^' HCrO^

CoSO^, etc. CoHPOJ Co(NH

3

) 2 ^, etc.

m 2 - CoEDTA^

Ni( 0H

)3 NiSO° NiHPO^ Ni(NH

3

) 2

'*', etc.

Ni(N

2 H^)

2 ^, etc.

NiEDTA^'

Mg^'^ MgOH"^ MgSOJ MgHPOJ MgEDTA^'

CaSO| CaHPO° CaEDTA^'

other cations (which may form complexes)

TlO^t Ti(0H)^t Zr^"^, ZrOOH'^, Li"^, Na'^, k"^, H30'^, NhJ,

Other anions

HS", SO^T S20^; HSO3, CO3; HCO3, HCOO", BO3T BO2, B^O^; NO2, NO',

ethyl enedi amine tetraacetic acid

Neutral

O2. H2O2, N2, N2H^, CO2, C2H4Cl2(dichloroethane), C^H^NO (morpholine),

methoxychlor , toxaphene, 2, 4, 5-TP.

258
DATA COMPILED FOR AQUEOUS SOLUTION THERMODYNAMICS

(extracted largely from Goldberg, R.N., NBS Special Publication 454

2nd edition 1933, in preparation)

General Sources

CODATA Recommended Key Values for Thermodynamics 1977

(CODATA Bulletin No. 28 (1978) and Tentative Set of Key Values for

Thermodynamics: Parts VI, VII, and VIII, CODATA Special Reports:

No. 4 (March 1977), No. 7 (April 1978), and No. 8 (April 1980)).

Wagman, D.D., Evans, W. H. , Parker, V.B.

Halow, I., Bailey, S. M. , Schumm, R. H., Churney, K. L., and Nuttall, R. L. Selected Values of Chemical Thermodynamic Properties

National Bureau of Standards Technical Note 270 (U. S. Government Printing

Office, Viashington , DC 20402 Parts 3 (1968) to 8(1981).

Also being published as: The NBS Tables of Chemical Thermodynamic Properties,

J. Phys. Chem. Ref. Data Supplement 2 (1982) in press.

Medvedev, V. A., Bergman, G. A., Gurvich, L. V., Yungman, V. S., Vorob'ev,

A. F., Kolesov, V. P., and others (V.P. Glushko, general editor)

Thermal Constants of Substances

(Viniti, Moscow, Volume 1(1965) to 10(1981). (In Russian).

Stul 1 , D. R. , Prophet, H. JANAF Thermochemical Tables, 2nd ed.

,

National Standard Reference Data Series, NBS, Washington, DC 1971 No. 37.

Supplements: Chase, M. W.Jr., Curnutt, J. L., Hu, A. T. , Prophet, H. , Syverud, A. N. Vialker, L. C., J. Phys. Chem. Ref. Data £, 311-480; (1974), Chase, M. W. Jr.,

Curnutt, J. L., Prophet, H. , McDonald, R, A., Syverud, A, N.,

J. Phys. Chem. Ref. Data 4, 1-175 (1975), Chase, M. W. Jr., Curnutt,. J. L.,

McDonald, R. A., Syverud, A. N. J. Phys. Chem. Ref. Data 7_, 793-940 (1978). Chase, M. W. , Jr., Curnutt, J. L.,

Downey, J.R., Jr., McDonald, R. A. Syverud, A. N., and Valenzuela, E. A. , J. Phys. Chem. Ref. Data. 11 695-940 (1982).

Gurvich, L. V., Bergman, G. A., Veits, I, V., Medvedev, V. A.,

Khachkuruzov , G. A., Yungman, V. S., Eds., Glushko, V. P., Gen. Ed.,

"Thermodynamic Properties of Individual Substances" ( Izadatel ' stvo "Nauka",

Moscow, Vol. 1 (1978), Vol . 2 (1979), Vol . 3 (1981). (In Russian).

Robie, R. A., Hemingway, B. S. , and Fisher, J. R.

Thermodynarni CpProperties of Minerals and Related Substances at 298.15 K and 1 Bar (10^ Pascals) Pressure and at Higher Temperatures

.

([U.S.] Geological Survey Bulletin 1452, U. S. Government Printing Office,

Washington, DC 1978).

259
s _o r Water

L., Callaqher, J. S. and Koll, G. S.

A Tliern;odynam i c Surface for Water: Ffie formulation and Computer Procjrams

(NBSIR 81-2253, National Bureau of Standards, Wasliington, DC, 1981).

**Haar, L., Gallagher, J, S. and Kell, G. S.

NBS/MRC Steam Tables: Thermodynamic and Transpo^'t Properties and

Computer Programs for Vapor and Liquid States of Water.

(Hemisphere Publications, in press, 1983).

Hlarshall, W. L. and Franck, E. U. Ion Product of Water Substance, 0-1000 '’C, 1-10,000 bars

Nev/ International Formulation and its Background

J. Phys. Chem. Ref. Data 10_, 295 (1981 ).

Olofsson, G., and Hepler, L. G.

Thet’rnodynamics of Ionization of Water Over Wide Ranges of Temperature

and Pressure

J. Solutiori Chem. 4, 127 (1975).

*Uematsu, U., Franck, E. U.

Static Dielectric Constant of Water and Steam

d. Phys, Chem. Ref. Data ^ 1291 (1980)

*Vorgaftik, M. B., Valkov, 3. N. and Vojak, L. D.;

International Tables of Water Surface Tension

J. Phys. Criem. Ref. Data (in press, 1983).

Formulations approved by lAPS for scientific and general use.

"ic Formulation approved by lAPS.

260
Thermal and Volumetric Properties of Solutions

Parker, V. B. Thermal Properties of Aqueous Uni-univalent Electrolytes

NSRDS-NBS 2, (U. S. Government Printing Office, 1965).

Mishchenko, K. P., and Pol toratzki i , G. M,

Aspects of the Thermodynamics and Structure of Aqueous and Non-Aqueous

Electrolyte Solutions

(Izd. "Khimia", Leningrad, 1968) (In Russian).

Wagman, et al., NBS TN 270, loc. cit.

Medvedev, et al . "Thermal Constants of Substances," loc. cit.

Barrier, H. E. and Scheurman, R. V.

Handbook of Thermochemical Data for Compounds and Aqueous Species

(John Wiley and Sons, New York, 1978).

D'Ans, J., Surawski , H., Synowietz, C.

Densities of Binary, Aqueous Systems and Heat Capacities of Liquid Systems

in Landol t-Bornstein , "Numerical Data and Functional Relationships in Science

and Technology" New Series K.-H. Hellwege, editor-in-chief

(Springer-Verlag, Berlin, 1977). Group IV Volume 1, part b.

Millero, F. J.

The Molal Volumes of Electrolytes

Chemical Reviews, 7]_, 147 (1971 ).

Millero, F. J. The Partial Molal Volumes of Electrolytes in Aqueous Solutions.

Compilation of the Partial Molal Volumes of Electrolytes at Infinite

Dilution, V*^ and the Apparent Molal Volume Concentration Dependence

Constants, S* and b , at Various Temperatures , in

"Water and Aqueous Solutions," R. A. Horne (editor)

(Wi 1 ey-Interscience , New York 1972).

Millero, F. J,

Effects of Pressure and Temperature on Activity Coefficients in

"Activity Coefficients in Electrolyte Solutions," R. M. Pytkowicz (editor)

(CRC press, Boca Raton, Florida, 1979). Volume II, page 63.

261
Activities in £lcctrQiyt&_ Si^iitJ on^

Hamer, W. J., and Wu , Y.C.

Osmotic Coefficients and Mean Activity Coefficients of Uni -Uni valent

Electrolytes in Water at 25 °C.

Journal of Physical and Chemical Reference Data, 1_, 1047 (1972).

Wu , Y. C. , and Hamer, W. J.

Electrochemical Data. Part XIV. Osmotic Coefficients and Mean Activity

Coefficient of a Series of Uni-Bivalent and Bi-Univalent Electrolytes in

Aqueous Solutions at 25 ”C. Part XVI. Osmetic Coefficients and Mean

Activity Coefficients of a Number of Uni -Tri valent and Tri-Univalent

Electrolytes in Aqueous Solution at 25 °C.

(National Bureau of Standards Reports No. 10052 and 10083, U. S. Department

of Commerce, 1969).

Staples, B. R. and R. L. Nuttall

The Activity and Osmotic Coefficient of Aqueous CaCI^

J. Phys. Chem. Reference Data, 6, 385 (1977).

at 298.15 K

Staples, B. R. Ionic Equilibrium Constants of Aqueous Alkaline Earth Salts

Environ. Sci. Tech., 1_2, 339 (1978).

Goldberg, R. N., and R. L. Nuttall

Evaluated Activity and Osmotic Coefficients for Aqueous Solutions: The

Alkaline Earth Metal Halides

J. Phys. Chem. Ref. Data, 7_, 253 (1978),

Goldberg, R. N., R. L. Nuttall, and B. R. Staples

Evaluated Activity and Osmotic Coefficients for Aqueous Solutions: Iron

Chloride and the Bi-univalent Compounds of Nickel and Cobalt

J. Phys. Chem. Ref. Data, 8_, 923 (1979).

Goldber'g, R. N.

Evaluated Activity and Osmotic Coefficients for Aqueous Solutions:

Bi-univalent Compounds of Lead, Copper, Manganese, and Uranium

J. Phys. Ref. Data, 8, 1005 (1979).

Staples, B, R. and Wobbeking, T. F. A Compilation of Thermodynamic and Transport Properties of Aqueous

Sulfuric Acid

NBSIR 81-2276, (National Bureau of Standards, June 1981.)

Parker, V. B. , Staples, B. R., Jobe, T. L., Neumann, D A Report on Some Thermodynamic Data for Desulfurization Processes

NBSIR 81-2345, (National Bureau of Standards, September 1981.)

Goldberg, R. N.

Evaluated Activity and Osmotic Coefficients for Aqueous Solutions:

Bi -Univalent Compounds of Zinc, Cadmium, and Ethylene bis(tri-methylammonium)

Chloride and Iodide

J, Phys. Chem. Ref. Data 1_0, 1 (1981).

262
Goldberg, R. N. Evaluated Activity and Osmotic Coefficients for Aqueous Solutions:

Thirty-Six Uni -Bivalent Electrolytes

J. Phys. Chem. Ref. Data, 10, 671 (1981).

Staples, B. R. Activity and Osmotic Coefficients of the Alkali Metal Nitrites

J. Phys. Chem. Ref. Data, lOi, 765 (1981 ).

Staples, B. R. Activity and Osmotic Coefficient of Aqueous Sulfuric Acid at 298.15 K

J. Phys. Chem. Reference Data, 10, 779 (1981).

Joseph, R. E. and Staples, B. R.

,

A Compilation of Thermodynamic and Transport Properties of Aqueous

Potassium Hydroxide

NBSIR 81-2356, (National Bureau of Standards, January 1982.)

Smi th-Magowan , D. R. , and Goldberg, R. N.,

"A Bibliography of Sources of Experimental Data Leading to Thermal

Properties of Binary Aqueous Electrolyte Solutions,"

NBS Special Publication 537, (U. S. Government Printing Office, Washington,

DC, 1979).

Goldberg, R. N., Staples, B. R., Nuttall, R. L., and Arbuckle, R. "A Bibliography of Sources of Experimental Data Leading to Activity

or Osmotic Coefficients for Polyvalent Electrolytes in Aqueous Solution,"

NBS Special Publication 485, (U.S. Government Printing Office,

Washington, DC), July 1977.

Pitzer, K.S.

Thermodynamic Properties of Aqueous Solutions of Bivalent Sulphates

J. Chem. Soc. Faraday Trans II 6^, 101 (1972).

Pitzer, K.S. and Mayorga, G.

Thermodynamics of El ectrolytes . II. Activity and Osmotic Coefficients for

Strong Electrolytes with One or Both Ions Univalent

J. Phys. Chem. 1J_, 2300 (1973).

Pitzer, K.S. and Mayorga, G.

Thermodynami cs of Electrolytes. III. Activity and Osmotic Coefficients

for 2-2 Electrolytes

J. Solution Chem. _3, 539 (1974).

Pitzer, K.S. and Kim, J.J.

Thermodynamics of Electrolytes IV. Activity and Osmotic Coefficients for

Mixed Electrolytes

J. Amer. Chem. Soc. %, 5701 (1974).

Pitzer, K.S. and Silvester, L. F. Thermodynamics of Electrolytes. VI. Weak Electrolytes Including H,P0.

J. Solution Cliem. _5_, 269 (1976),

Pitzer, K, S., Roy, R.N., and Silvester, L. F.

I iiermodynam i cs of L 1 ec trol y tes . VII. Sulfuric Acid

J. Aiik.t. Chem. Soc. 99, 4930 (1977).

263
SilvGSi.or, 1. . F. and Pitzer, K. S. Theniiod.ynamicG of FI octroi ytos . YHI Hi gh-Teiiiperaturo Properties,

Including Fnthalpy and Heat Capacity, with Application to Sodium Chloride,

d. Phys. Chein. 8I_, 18F2 (1 977).

Pitzer, K. S. , Peterson, J.R., and Silvester, L. F. Thermodynamics of Electrolytes. IX. Rare Earth Chlorides, Nitrates and

Perchl orates

J. Solution Chem, 45 (1978).

Silvester, L. F. a!id Pitzer, K.S.

Thermodynamics of Electrolytes. X. Enthalpy and the Effect of Temperature

on the Activity Coefficients.

J. Solution Chem. 7_, 327 (1978).

Pitzer, K.S. and Silvester, L. F. Thermodynamics of Electrolytes. 11. Properties of 3:2, 4:2, and Other

High-Valence Types

J. Phys. Chem. 1239 (1978).

Pitzer, K.S. and Peiper, J. C.

Activity Coefficients of Aqueous NaHCO..

J. Phys. Chem. 84, 2396 (1980).

Peiper, J. C. and Pitzer, K.S.

Tliermodynamics of Aqueous Carbonate Solutions Including Mixtures of

Sodium Carbonate, Bicarbonate, and Chloride

J. Chem. Thermodynamics 1_4, 613 (1982).

Rogers, P.S.Z. and Pitzer, K.S.

Volumetric Properties of Aqueous Sodium Chloride Solutions

J. Phys. Chem. Ref. Data 1J_, 15 (1982)

Pitzer, K.S.

Theory: Ion Interaction Approach

in "Activity Coefficients in Electrolyte Solutions"

Pytkowicz, R. M. (editor)

(CRC Press, Boca Raton, Horida, 1979) (Volume I, page 157).

Helgeson, H. C., Kirkham, D. H. Theoretical Prediction of the Thermodynamic Behavior of Aqueous

Electrolytes at High Pressures and Temperatures . Parts I through IV (Am. J. Science, New Haven, CT). Bound reprints originally published as:

Part I. Summary of the Thermodynamic/El ectrostatic

Properties of the Solvent,

Am. J. Sci .274 , 1089 -1198 (1974)

Part II. Debye-Huckel Parameters for Activity Coefficients

and Relative Partial Molar Properties,

Am. J. Sci. 274 1199-1261 (1974)

264
Part III. Equation of State for Aqueous Species at

Infinite Dilution

Am. J. Sci. 276, 97-240 (1977)

, and Flowers, G. C.

,

Part IV. Calculation of Activity

Coefficients, Osmotic Coefficients and Apparent Molal and

Standard and Relative Partial Molal Properties to 600 °C and

5 KB,

Am. J. Sci. 1249-1516 (1981 )

Harried, H. S. , and Owen, B. B. The Physical Chemistry of Electrolytic Solutions (3rd Edition)

(Reinhold Publishing Corporation, New York, 1958).

Robinson, R. A., and Stokes, R. H. Electrolyte Solutions

(Buttervrorths Scientific Publications, London, 1959, 2nd ed.).

Lobo, V.M.M.

Electrolyte Solutions: Literature Data on Thermodynamic and Transport Properties.

(Revista de Faculdade de Ciencias da Universidade de Coimbra, 1975).

Offprint, Volume 50.

265
So 1 ubi I i t iGS

Linko, W. F. Solubilities: Inorganic and Meta 1 -Organic Compounds--A Compilation of

Solubility Data from the Periodical Licerature. (Originated by A. Seidel.)

(Volume I A-Ir; D. Van Mostrand Co., Princeton, New Jersey, 1958;

Volume II K-Z; American Chemical Society, Washington, DC, 1965).

Stephen, J., and Stephen, T. (editors, first five volumes), and

Silcock, H. (editor, 1979 - ) Solubilities of Inorganic Compounds," Transl . of "Spravochnik po

rastvorimosti

(Perqamnn Press, Oxford, 1963, 1964, and 1979).

Nyvlt, J. Solid-Liquid Phase Equilibria

(Elsevier Scientific Publishing Co., Amsterdam, 1977).

Kertes, A. S., edi tor-in-chief

Solubility Data Series

(Pergamon Press, New York 1979 to 1981).

This eighteen volume series, prepared under the auspices of IIIPAC.

The volumes which have been issued to data or are planned with their

titles and editors, are:

Volume 1 Volume 2

Volume 3

Volume 4

Volume 5 Volume 6

Volume 7 Volume 8

Volume 9

Volume 10

Volume 11

Volume 12

Volume 13

Volume 14

Volume 15

Volume 16

Volume 17

Volume 18

H. L. Clever, "Helium and Neon"

H. L. Clever, "Krypton, Xenon, and Radon"

M. Salomon, "Silver Azide, Cyanide, Cyananiides, Cyanate

Selenocyanate and Thiocyanate"

H. L. Clever, "Argon"

R. Battino, "Oxygen and Ozone"

J. W. Lorimer, "A1 kal ine-earth Metal Sulfates" • E. M. Woolley, "Silver Halides"

P. Farrell, "Mono- and Di saccharides in Water"

R. Cohen-Adad, "Alkali Metal Chlorides"

J. E. Bauman, "Alkali Metal and A1 kal ine-earth Metal Oxides and

Hyroxides in Water"

b". Scrosati and C. A. Vincent, "Alkali Metal, Alkaline-earth

Metal and Ammonium Halides. Amide Solvents"

Z. Falus and C. Guminski, "Metals in Mercury"

C. [.. Young, "Oxides of Nitrogen, Sulfur and Chlorine"

R. Battino, "Nitrogen"

H. L. Clever and W. Gerrard, "Hydrogen Ha Mdse in Non-Aqueous Solvents"

A. L. Horvath, "Halogenated Benzenes" ^ E. Wilhelm and C. L. Young, "Hydrogen, Deuterium, Fluorine and Chlorine'

0. Popovych, "Tetrapher.yl borates"

Battino, R. and Clever, H. L. The Solubility of Gases in Liquids

Chemical Reviews, 66, 395 (1966).

266
Complexation in Solution

Sillen, L. G., Martell, A. E. Stability Constants of Metal Ion Complexes, Section I; Inorganic Ligands, Section II; Organic Ligands (second edition)

Special Publication No. 17, 1964, and Supplement No. 1, Special

Publication No. 25, 1971. (The Chemical Society, London, England)

SP 17 is the 2nd edition of S.P. 6 (1957) and S.P. 7 (1958).

Critical Stability Constants

Martell, A. E., and Smith, R. M.

Smith, R. M. , and Martell, A. E. Martell, A. i. and Smith, R. M.,

Smith, R. M., and Martell, A. E. (Plenum Press, New York)

Baes, C. F., Jr., and Mesmer, R. E. The Hydrolysis of Cations

(John Wiley & Sons, New York, 1976)

Christensen, J. J., Eatough, D. J. , and Izatt, R. M.

Handbook of Metal Ligand Heats and Related Thermodynamic Quantities

(second edition)

(Marcel Dekker, Inc., New York, 1975)

Christensen, J. J., Hansen, L. D., and Izatt, R. M.

Handbook of Proton. Ionization Heats and Related Thermodynamic Quantities

(John Wiley & Sons, New York, 1976).

(1974) Vol . 1 Amino Acids

(1975) Vol. 2. Amines

(1977) Vol. 3. Other Organic Ligands

(1976) Vol. 4. Inorganic Complexes '

267
Mi seel laneous

Dymond, J. H. , and Smith, E. B.

Tlie Vi rial Coefficients of Gases

(Clarendon Press, Oxford, 1980).

Armstrong, G.T. , and Goldberg, Ri N.

An Annotated Bibliograpny of Compiled Thermodynamic Data Sources

for' Biochemical and Aqueous Systems (1930-1975). Equilibrium,

Enthalpy, Heat Capacity and Entropy Data.

National Bureau Standards Special Publication 454 (1976).

(U. S. Government Printing Office, Washington, DC) 2nd ed. in preparation 1933

Freeman, R. D. , editor

Bulletin of Chemical Thermodynamics

(Thermochemi stry , Inc., Stillwater, Oklahoma). Annual, vol . 23 (1980).

February 1933

268
COLLATERAL ACTIVITIES

0. Jonas, H. J. White, Jr.

In the U.S. many of the activities related to steam power system water

chemistry, corrosion, and chemical thermodynamics are centered around the

Electric Power Research Institute (EPRI), American Society of Mechanical

Engineers (ASME) Research Committees on Water in Thermal Power Systems and on the Properties of Steam, American Society for Testing and Materials

(ASTM) Committee D-19 on Water and the National Association of Corrosion

Engineers (NACE). In addition there are international activities of the

International Association for the Properties of Steam.

EPRI activities are concentrated in the Coal Combustion Systems Division

(see Figure 1 for objections), and in the Nuclear Power Division's

subprograms (see Figure 2a, b, c). Specific EPRI projects are listed in

Table 1.

Groups and activities of the ASME Research Committee on Water in Thermal

Power Systems are listed in Table 2.

269
Coaf Combudiion

Systama Dfvlsfon _

- ; **M

s:!^j^iz. - 7—^- ' f- Fbssfl Riel Ptw& '•

Objectives

— Steam Generators

—Steam Turbines

Fossil Plant

Performance

and Reliability

•Plant AuxiliariesReduce outages caused by metallurgical and —other boiler tube failures and ash slagging

and fouling.

_ Improve cyclic operation and control of boilers

"and thermal performance.

Improve human factors interfaces to minimize

"operator error.

_ Reduce outages caused by turbine component

"failures including metallurgy.

_ Demonstrate improved cyclic operatioxv

" controls, and thermal performance.

Develop comprehensive guidelines for inspection and maintenance.

Improve air/gas systems reliability and

" performance.

Improve reliability and performance of water

"system components. —Improve reliability of fuel/ash handling systems. —Plant Chemistry

Provide guidelines for steam and water purity

and ion exchange programs.

Conduct and monitor field tests on plant

components and systems.

Validate turbine vendor's steam purity recommendations

(1982)

Publish definitive texts on power plant component chemx^.^

cleaning and water technology (1982-83).

Develop programs for the use of microprocessor techniquespower plant chemistry operations (1983).

^—techniques, improve plant maintenance and

reduce forced outages.

Develop special incipient failure devices to "improve plant availability.

Determine applicability and develop off-line —nondestructive evaluation techniques for fossil plant equipment.

—Plant Diagnostics

Figure 1 - Fossil Plant Performance and Reliability Program Logic

270
271
Figure 2b

Subprogram

>

Steam Generator

Technology

Approach Technology — Denting and Corrosion Mechanisms — Water Chemistry and Purity Requirements

Chemistry and

Corrosion — Evaluation of Plant Data

Crevice Corrosion and Concentration

Modeling

Alternate Water Chemistry for Corrosion

Inhibition

Materials Selection

and Testing

p— On-Line Corrosion Monitor Development

_ Characterization and Improvement of

” Existing Materials

_ Examination and Qualification of Steam

Generator Components

Thermal, Hydraulic

and Structural

Testing and

Analysis

Thermal and

Hydraulic Code

Development

— Evaluation of Alternate Materials —Water Hammer — Model Steam Generator Testing

___ Steam Generator Instrumentation

Development — Vibration — Model Development — Code Comparisons — Verification With Model Boiler Data — Verification With Field Data

272
Figure 2c

Subprogram

Plant

Materials

Chemical and

Radiation

Control

Approach Technology

Definition of Plant

Corrosion

Processes

EnvironmentRelated Studies

and Remedies

— Mechanisms of Localized Corrosion — Metal-Environment Interactions — Identification of Rate Determining Steps

Effects of Environmental Variables on

Corrosion Processes — Reactor Environment Characterization — Alternative Water Chemistries and Inhibitors

Improvement of

Materials and

Processing

Field Experience

and Application

Engineering

Alternative Alloys and Composition

Optimization — Improved Alloy Processing — Improved Fabrication Methods

Examination and Analysis of Field

Experience — Transfer of Remedy Technology to the Field

Development of Improved Life-Prediction

Methods

Radiation Control

Chemical

Processing

Water and Steam

Corrosion

Operational Control

Materials Effects

Coolant Technology

Surface Treatment

Purification Technology

Decontamination

Occupational Radiation Exposure

Low-Level Waste Treatment

Low-Level Waste Storage. Containment

and Solidification

Water Conditioning

Chemical Supply and Treatment

Steam and Water Deposition Control

Steam Monitoring

Water Quality Monitoring at Operating

Conditions

Crevice Corrosion

System Design for Water Control

Corrosion Technology. Monitoring and

Control

273
Table 1

SPECIFIC EPRI PROJECTS

REACTORS ; DURING AND POST ACCIDENT ANALYSIS IN THE PWR PRIMARY CYCLE

D. CUBICCIOTTI

PROPERTIES OF COLLOIDS RP966-1 CLARKSON COLL.

MATIJEVIC'

PWR STEAM GENERATORS : CHEMICAL ASPECTS OF DENTING CEBELCOR

CHEMISTRY OF CORROSION PRODUCING SALTS IN LWR RP967-1 B&W

CHEN, THEUS

CHEMICAL THERMODYNAMIC STUDIES OF AGUEOUS TRACE COMPONENTS RP311-2

IN LWR COBBLE

OXYGEN SUPPRESSION IN BWRS

PWR CHEMISTRY FOLLOW PROGRAM RP699-1 (W)

EVALUATION OF SECONDARY SYSTEM OXYGEN CONTROL IN PWRS BURNS & ROE

PWR SECONDARY WATER CHEMISTRY GUIDELINES

MONITORING OF CREVICE CHEMISTRY BY LASER RAMAN SPECTROSCOPY

WESTINGHOUSE ELECTRIC

pH control AGENTS SAN DIEGO STATE UNIVERSITY, WESTINGHOUSE RP1571-3

OXYGEN CONTROL MEASURES T.O. PASSELL

274
Table 1 ( cont .

)

TURBINES

0 LP PWR TURBINE DISC CRACKING (INCLUDES CHEMICAL MONITORING)

0 CORROSION FATIGUE OF TURBINE BLADES RP-912 (INCLUDES SURVEY

OF CYCLE CHEMISTRY IN 42 UNITS AND DEPOSITS IN 120 UNITS)

0 EFFECTS OF PHOSPHATE ENVIRONMENTS ON TURBINE MATERIALS

RP1886-1 EPRI - GENERAL ELECTRIC CO.

0 SOLUBILITY OF NaOH IN SUPERHEATED STEAM BABCOCK &

WILCOX, GENERAL ELECTRIC, T.O. PASSEL, W. ALLMAN, G. GOULD

0 NEUTRON ACTIVATION ANALYSIS OF TURBINE DEPOSITS, RP1409.

GENERAL

0 PROGRAMS ON CHEMICAL ANALYSIS AND MONITORING AND CORROSION

TESTING.

0 SURVEY OF CONDENSATE POLISHING B&W

0 BWR RESIN INTRUSION BATTELLE, RP1653-2

0 HIGH TEMPERATURE pH,HYDROGEN, AND REDOX MONITORING SRI, RP1168-1

0 ESTIMATION OF DIFFUSION COEFF. OF ELECTROLYTES IN HOT WATER

RP5146-1

0 HIGH TEMP. BEHAVIOR OF CHEMICAL SPECIES IN WATER, RP1167-5,

CEGB

275
Table 2

ASME RESEARCH COMMITTEE ON

WATER IN THERMAL POWER SYSTEMS

UTILITY SUBCOMMITTEE

INDUSTRIAL SUBCOMMITTEE

AQUEOUS DISCHARGE SUBCOMMITTEE

HANDBOOK PROJECT

LIAISON WITH THE ASTM RESEARCH COMMITTEE ON THE PROPERTIES OF

STEAM AND I APS

EEI LIAISON

POWER DIVISION LIAISON

NACE LIAISON

ASTM U-19 LIAISON

TECHNICAL PAPERS SUBCOMMITTEE

ACTIVITIES: SURVEYS, PROPOSING RESEARCH, CONFERENCES, REGULAR _ _ INFORMATION EXCHANGE

0 UTILITY AND INDUSTRIAL TURBINE SURVEYS

0 WATER CHEMISTRY FOR INDUSTRIAL BOILERS

0 LAYUP GUIDELINES

0 ANALYTICAL ROUND ROBIN PROPOSAL (ppb)

0 SAMPLING STEAM PROPOSAL

0 AIR INLEAKAGE AND ORGANICS SURVEY

0 BIBLIOGRAPHY OF CONDENSATE POLISHING

0 CHEMICAL CLEANING

0 STEAM GENERATOR CHEMISTRY

0 SLUDGE HANDLING AND DISPOSAL

0 CONTAMINATION - DECONTAMINATION

0 AQUEOUS DISCHARGES

276
International Association for the Properties of Steam

The International Association for the Properties of Steam (lAPS) is an organization devoted to the preparation and promulgation of

internationally-agreed-upon , critically evaluated reference data on the

properties of water, steam, and aqueous solutions. The properties covered

are those of importance to the power industry.

Countries are members of lAPS and each member country pays yearly dues to

support lAPS and maintains a National Committee on the Properties of Steam

which coordinates and encourages research on the properties of steam

within the country and provides the country’s official delegates to lAPS.

The official delegates form the Executive Committee of lAPS which manages

the association's activities. The technical activities of lAPS are carried out by working groups and subcommittees. At present there are the

following;

Working Group 1, Equilibrium Properties

Working Group 2, Transport Properties

Working Group 3. Other Properties Especially Surface and Electrical

Properties

Working Group 4, Chemical Thermodynamics of Power Cycles

Subcommittee on Industrial Calculations

The best known product put out by lAPS and its predecessors is the 1967

IFC Formulation for. Industrial Use which is used in almost all industrial

calculations for specifications and which forms the basis for the various

national steam tables, such as that put out by ASME in the USA. In

addition, lAPS has issued the following releases which are current:

Release on Viscosity and Thermal Conductivity of Heavy Water Substance,

September 1982 - Revised February 14, 1984

Release on Static Dielectric Constant of Water Substance, September 1977

Release on lAPS Statement, 1983 1 of Values of Temperature, Pressure and

Density of Ordinary and Heavy Water Substances at Their Respective

Critical Points

Release on Surface Tension of Water Substance, September 1975

Release on Thermal Conductivity of Water Substance, 1977, as amended in

1982

Release on the Dynamic Viscosity of Water Substance as amended in 1982

Release on the Ion Product of Water Substance, May 1980

Currently, Working Group IV is actively engaged in evaluating data for the

four systems NaCl/H20, Na0H/H20, Si02/H20 and Fe^0y/H20. Each of these

systems is important in power-plant chemistry.

ASME Research Committee on the Properties of Steam

The ASME Research Committee on the Properties of Steam encourages and

coordinates research on the properties of steam and serves as the U.S.

National Committee on the Properties of Steam. In this latter capacity it

sends the U.S. delegates to lAPS meetings and sets U.S. policy with

respect to matters treated by lAPS.

277
Appendix I

AGENDA

Chemical Thermodynamics in Steam Power Cycles

Data Requirements

February 8, 1983

Welcome - R. G. Kammer , Deputy Director, NBS

Introduction - R. C. Spencer, Jr.

Water and Steam Chemistry Session - Chairman, 0. Jonas

Power System Chemical Transport - 0. Jonas

Fossil- Boilers - F. J. Pocock

PWR Secondary Cycle - P. E. C. Bryant

BWR Cycle - G. Gould and M. Maddagiri

Reactor Chemistry - P. Cohen

Turbine Steam Chemistry - W. T. Lindsay, Jr.

Chemical Thermodynamics Session - Chairman, H. J. White, Jr.

Current Experimental Measurements Related to Power Cycles

J. W. Cobble

R. E. Mesmer and W. L. Marshall

Aqueous Solutions at High Temperatures - R. H. Wood

Distribution of Chemical Species between Water and Steam - P. Cohen

Thermodynamics and Electrochemistry and Corrosion - G. J. Theus

Correlation of Data for Aqueous Electrolyte Systems - J. Pei per

Evaluated Data and Data Bases - D. Garvin

278
2

February 9, 1983

Collateral Activities

EPRI and ASME Research Committee on Water in Thermal Power Cycles

0. Jonas

lAPS and ASME Research Committee on the Properties of Steam

H. J. White, Jr.

Working Group I, Reactors, Lecture Room B

Chairman - D. Cubicciotti

Secretary - V. B. Parker

Working Group II, PWR Steam Generators and Fossil Boilers, Lee. Room D

Chairman - P. E. C. Bryant

Secretary - J. Oscarson

Working Group III, Turbines, Room 111

Chairman - W. T. Lindsay, Jr.

Secretary - G. Gould

Working Group IV, Pre-Boiler Cycle, Room 113

Chairman - E. Coulter

Secretary - R. N. Goldberg

Presentations of Conclusions and Recommendations of Individual Working

Groups

Working Group I

Working Group II

Working Group III

Working Group IV

Discussion - Conclusions and Recommendations of the Workshop

279
Appendix II

WORKSHOP ON CHEMICAL THERMODYNAMICS

February 8-9, 1983

Attendance List

M. Angwin

EPRI

P.O. Box 10412

Palo Alto, CA 94303

(41 5)855-2481

J. Cooper

Naval Research Laboratory (Code 5133)

4555 Overlook Avenue, S.W.

Washinoton, DC 20375

(202)767-3115

P. Ausloos

National Bureau of Standards

Chem. Bldg. Room B343

Washington, DC 20234

(301)921-2439

O. Bonnell

National Bureau of Standards

Matls. Bldg., Room A329

Washington, DC 20234

(301 )921 -2711

P. E. C. Bryant

Combustion Eng. Inc.

Combustion Div.

Dept. 9453-401

1000 Prospect Hill Road

Windsor, Connecticut 05095

(203)683-6268

J. W. Cobble

Chemistry Dept.

San Diego State University

San Diego, CA 92182-0419

(61 9)265-5139

P, Cohen

3024 Beachwood Boulevard

Pittsburgh, PA 15217

(412)521-5786

P. Col umbo

Nalco Chemical Company

1801 Diehl Road

Naperville, Illinois 60540

(312)961-9500 x204S

E. Coulter

Babcock & Wilcox

91 Stirling Avenue

Barberton, Ohio 44203

(216)860-1126

D. Cubicciotti

EPRI

P 0. Box 10412

Palo Alto, CA 94303

(415)855-2069

F. Gabrielli

Combustion Engineering Inc.

1000 Prospect Hill Road

Windsor, Connecticut 05095

(203)688-1911 x2485

D. Garvin

National Bureau of Standards

Chemistry Bldg., Room A161

Washington, DC 20234

(301 )921-2773

L. Gevantman

National Bureau of Standards

Physics Bldg., Room A318

Washington. DC 20234

(301)921-3442

R. Goldberg

National Bureau of Standards

Physics Bldg , Room A303

Washington, DC 20234

(301)921 2752

280
G. Gould

General Electric Company

Bldg. 55 - Room 233

1 River Road

Schnectady, New York 12345

(513)385-2113

J. Hastie

National Bureau of Standards

Materials Bldg,, Room A329

Washington, DC 20234

(301 )921-3618/2S59

J. Hicks

Babcock & Wilcox

Utility Power Generation Division

Old Forest Road, P.O. Box 1260

Lynchburg, Virginia 24505

(804)385-3482

O. Jonas

Westinghouse Electric Corp. N-206

P. O. Box 9175

Philadelphia, PA 17113

(215)237-2958

J. Kelly

Nalco Chemical Company

1801 Diehl Road

Naperville, Illinois 60556

(312)961-9500 x2021

J. Kruger

National Bureau of Standards

Materials Bldg., Room B254

Washington, DC 20234

(301 )921 -2094

K. Lehner

Wisconsin Electric Power Co.

231 W. Michigan Street

Milv/aukee, Wisconsin 53201

(414)277-2422

J. Leibovitz

NWT Corporation

7015 Realm Drive

San Jose, CA 95119

(408)281-1100

D. R. Lide, Jr

National Bureau of Standards

Physics Bldg., Room A323

Washington, DC 20234

(301 )921-2467

W, T, Lindsay, Jr

Westinghouse R2.D Center

1310 Beulah Road

Pittsburgh, PA 1 5235

(412)256-3696

M. Maddagiri

Bechtel Power

P.O. Box 3965

San Francisco, CA 94119

(415)768-0623

W. Marshall

Research Staff

Chemistry Division

Oak Ridge National Laboratory

P.O. Box X Oak Ridge Tennessee 27830

(615)574-4960

R. E. Mesmer

Oak Ridge National Laboratory

P.O. Sox X Oak Ridge, Tennessee 27830

(615)574-4958

R. Nuttall

National Bureau of Standards

Chemistry Bldg., Room A1 52

Washington, DC 20234

(301 )921 -21 08

J. Oscarson

350K C3 Dept, of Engr.

Brigham Young University

Provo, Utah 84602

(801 )378-6240

V. Parker

National Bureau of Standards

Chemistry Bldg., Room A1 52

Washington, DC 20234

(301 )921 -21 09

281
T. Passell

EPRI

Nuclear Eng. and Operations

P.O. Box 10412

Palo Alto, CA 94303

(415)355 2070

O. Pei per

Dept, of Chemistry

Arizona State University

Tempe, Arizona 85287

(602)965-5697

F. Pocock

Babcock & Wilcox

P. O. Box 835

Alliance, Ohio 44601

(216)821-9110 x428

D. Schluderberg

Babcock & Wilcox

Box 1260

Lynchburg, VA 24505

(703)385-3110

R. Spencer

General Electric Company

Bldg. 273 - Room 244

Schenectady, New York 12345

(518)385-31 53

B. Staples

National Bureau of Standards

Chemistry Bldg., A1 64

Washington, DC 20234

(301 )921-3632

6. Theus

Babcock i Wilcox R&D

P.O. Box 835

Alliance, Ohio 44601

(216)821-9110 x343

D. Venesky

Naval Research Laboratory

Code 6130

4555 Overlook Avenue, S.W.

VJashington, DC 20375

(202)767-3557

H. d. White, Jr.

National Bureau of Standards

Physics Bldg., Room A316

Washington, DC 20234

(301

)

921 -2531

R. Wood

University of Delaware

Chemistry Department

Newark, Delaware 19711

(302)

738-2941

282
HSS«n4A <BEV. 2*eci U.s. OEPT, OF COMM. BIBLIOGRAPHIC DATA

SHEET (See instruciions)

1. PUBLICATION OR

REPORT NO.

NBSIR 85-3205

2. Performing Organ. Report NoJ 3. Publication Date

4. TITLE and subtitle

Chemical Thermodynamics in Steam Power Cycles Data Requirements (Proceedings

of a Workshop)

5. AUTHOR(S)

Otakar Jonas and Howard J. White, Jr.

6. performing organization (If Joint or other than NBS, see instructions) 7. Contract/Grant No. NATIONAL BUREAU OF STANDARDS

DEPARTMENT OF COMMERCE 8. Type of Report 8, Period Covereo WASHINGTON, D.C. 20234

9. SPONSORING ORGANIZATION NAME AND COMPLETE ADDRESS (Street. City, State. ZIP)

10. supplementary NOTES

' ^ Document describes a computer program; SF-185, FlPS Software Summary, is attached.

11. ABSTRACT (A 200-word or less factual summary of most significant information. If document includes a significant

bibliography or literature survey, mention it here)

This report represents the proceedings of a workshop on data needs for chemical

thermodynamics in power cycles held at the National Bureau of Standards,

February 8-9, 1983. It contains a summary of the recommendations of working

groups that met during the workshop as well as the texts or abstracts of most

of the papers presented at the workshop.

12. KEY WORDS (Six to twelve entries; alphabetical order; capitalize only proper names; and separate key words by semicolon si aqueous electrolytes; aqueous solutions; chemical thermodynamic data; data

requirements; power cycles; proceedings; reference data

13. AVAILABILITY

Uni imi ted

1 1 For Official Distribution. Do Not Release to NTIS

r 1 Order From Superintendent of Documents. U.S. Government Printing Office. Washington. D.C

20402.

] Order From National Technical Information Service (NTIS). Springfield, VA. 22161

14. NO. OF

PRINTED PAGES

287

15. Price

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