0% found this document useful (0 votes)

41 views90 pages

Asme PTC 4.4

The document outlines the ASME Performance Test Code PTC 4.4 for Gas Turbine Heat Recovery Steam Generators, which was established to provide standardized testing methods for these systems. It includes sections on the purpose, scope, definitions, guiding principles, measurement methods, and computation of results. The code was approved as an American National Standard in 1981 and emphasizes the importance of public input and participation in its development.

Uploaded by

Rajendra

We take content rights seriously. If you suspect this is your content, claim it here.

Available Formats

Download as PDF, TXT or read online on Scribd

0% found this document useful (0 votes)

41 views90 pages

Asme PTC 4.4

Uploaded by

Rajendra

We take content rights seriously. If you suspect this is your content, claim it here.

Available Formats

Download as PDF, TXT or read online on Scribd

You are on page 1/ 90

Gas Turbine

Heat
Recovery
Steam
Generators

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Gas Turbine
Heat PERFORMANCE
Recovery TEST
Steam
CODES
Generators
ANSI/ASME PTC 4.4 1981 -

THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS

United Engineering Center
345 East 47th Street New York, N.V. 10017

This code or standard was developed under procedures accredited as meeting the criteria for
American National Standards. The Consensus Committee that approved the code or standard was bal-
anced to assure that individuals from competent and concerned interests have had an opportunity
to participate. The proposed code or standard was made available for public review and comment which
provides an opportunity for additional public input from industry, academia, regulatory agencies, and
the public-at-large.
ASME does not "approve," "rate," or "endorse" any item, construction, proprietary device, or
activity.
ASME does not take any position with respect for the validity of any patent rights asserted in con-
nection with any items mentioned in this document, and does not undertake t o ensure anyone utilizing
a standard against liability for infringement of any applicable Letters Patent, nor assume any such
liability. Users of a code or standard are expressly advised that determination of the validity of any
such patent rights, and the risk of infringement of such rights, i s entirely their own responsibility.

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
Participation by federal agency representative(s.1 or personk) affiliated with industry is not to be
interpreted as government or industry endorsement of this code or standard.

Date of Issuance: August 31, 1981

No part of this document may be reproduced in any form,

in an electronic retrieval system or otherwise,
without the prior written permission of the publisher.

FOREWORD

PTC 4.4, Gas Turbine Heat Recovery Steam Generators, was originally formed as a reorganized
PTC 4.1, Steam Generating Units, in September 1973 to prepare an Appendix 10 to PTC 4.1
to cover Heat Recovery Steam Generators for Combined Cycles. During the early meetings
(May 11-12, 1976 and May 3-4, 1977) it was decided that the scope was beyond the capacity
of an Appendix. A t this point a charter was approved by the PTC Supervisory Committee to
prepare a separate code entitled PTC 4.4, Gas Turbine Heat Recovery Steam Generators. The
draft of PTC 4.4 was presented to the Supervisory Committee in February 1980 with final
approval on January 26, 1981. This Performance Test Code has been approved as an American
National Standard by the ANSI Board of Standards Review on February 3,1981.

iii

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

PERSONNEL OF PERFORMANCE TEST CODE COMMITTEE NO. 4.4

ON GAS TURBINE HEAT RECOVERY STEAM GENERATORS

R. J. Peyton, Chairman
P. F. Sokolowski, Secretary

A. K. Bakshi, Senior Mechanical Engineer, Brown & Root, Incorporated, U.K., 125 High Street,
Colliers Wood, London, S.W. 19.2 J R, England
F. R. Berg, Manager, Steam Projects, Brown Boveri Turbomachinery, Inc., 711 Anderson Avenue
North, St. Cloud, Minnesota 56301
G. W. Bush, Mechanical Engineer, EI Paso Natural Gas Company, P.O. Box 1492, EI Paso, Texas
79978
D. Campbell, Chief, Mechanical Division, Public Service Electric & Gas Company, 200 Boyden
Avenue, Maplewood, New Jersey 07040
R. J . Casey, Head, Systems& Components, Development Section, Naval Ship Systems Engineer-
ing Station, Philadelphia Naval Base, Philadelphia, Pennsylvania 19112
R. W. Foster-Pegg, Consultant, Westinghouse Electric Corporation, Combustion Turbine Systems
Division, P.O. Box 251, Concordville, Pennsylvania 19331
J. W. Godbey, Technical Director, Heat Transfer Division, Henry Vogt Machine Company,
P.O. Box 1918, Louisville, Kentucky 40201
H. R. Hazard, Staff Consultant, Battelle Columbus Laboratories, 505 King Avenue, Columbus,
Ohio 43201
S. W. Lovejoy, Supervisor, Electric Production Results, Long Island Lighting Company, 175 East
Old Country Road, Hicksville, New York 11801
S. L. Morse, Retired, Assistant Manager, Field Engineering, Babcock & Wilcox Company,
20 South Van Buren Avenue, Barberton, Ohio 44203
S. P. Nuspl, Development Engineer, Babcock & Wilcox Company, 20 South Van Buren Avenue,
Barberton, Ohio 44203
C. E. Oliver, Mechanical Engineer, Chas. T. Main, Incorporated, 101 Huntington Avenue,
Boston, Massachusetts 02199
R. J. Peyton, Engineering Manager, Gaithersburg Power Division, Bechtel Power Corporation,
15740 Shady Grove Road, Gaithersburg, Maryland 20760
W. O. Printup, Manager, Thermodynamic Engineering, General EIectricCompany, Medium Steam
Turbine Department, 1100 Western Avenue, Building 26462, Lynn, Massachusetts O191O
T. J. Radkevich, Manager of Plant Engineering, Westinghouse Electric Corporation, P.O. Box 251,
Concordville, Pennsylvania 19331
R. W. Robinson, Manager, Field Testing and Performance Results, Combustion Engineering,
Incorporated, 1O00 Prospect Hill Road, Windsor, Connecticut 06095
P. F. Sokolowski, (Deceased), Fellow Engineer, Westinghouse Electric Corporation, Steam
Turbine Division, N-206, P.O. Box 9175, Lester, Pennsylvania 19213
J . C. Stewart, Group Manager, Heat Transfer, The Lummus Company, 3000 South Post Oak
Road, Houston, Texas 77056
E. J. Sundstrom, Energy Specialist, Dow Chemical U.S.A., Texas Division, Freeport, Texas 77541

Copyright ASME International Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
Provided by IHS under license with ASME 23:56:18 MST Questions or comments about this message: please call the Document
Policy Group at 303-397-2295.
L. Tomlinson, Manager, Combined Cycle Application Engineering, General Electric Company,
Gas Turbine Division, 1 River Road, Building 500, Room 122, Schenectady, New York
12345
F. Vona, Group Manager o f Performance, Erie City Energy Division, Zurn Industries, 1422 East
Avenue, Erie, Pennsylvania 16501
J .J.Zeller, Senior Engineer, Southern California Edison Company, 2244 Walnut Grove Avenue,
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

P.O. Box 800, Rosemead, California 91770

Copyright ASME International Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
Provided by IHS under license with ASME 23:56:18 MST Questions or comments about this message: please call the Document
Policy Group at 303-397-2295.
Personnel of the Performance Test Codes Supervisory Committee
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

J . H. Fernandes, Chairman
C.B. Scharp, Vice-chairman

D. W. Anacki A. S. Grimes S. W. Lovejoy

R. P. Benedict K. G. Grothues W. G. McLean
K. C.Cotton R. Jorgensen J . W. Murdock
W. A. Crandall E. L. Knoedler L. C. Neale
R. C. Dannettel W. C. Krutzsch, I r . R. J . Peyton
J . S. Davis C.A. Larson W. A. Pollock
V. F. Estcourt A. Lechner J. F. Sebald
W. L. Garvin P. Leung J. C. Westcott
F. H. Light

vi i

Section 1 Object and Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1.1 Purpose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.2 Object . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.3 Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.4 Applicable Test Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.5 Reference Codes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Section 2 Definitions and Description o f Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2.1 Definition of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
2.2 Symbols and Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Section 3 GuidingPrinciples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
3.1 Agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
3.2 Preparation for Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
3.3 Method of Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Section 4 Instruments and Methods of Measurement ............................ 13

4.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
4.2 Flow Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
4.3 Steam and Water Temperature Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . 15
4.4 Gas and Air Temperature Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
4.5 Other Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
4.6 Alternative Methods o f Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Section 5 Computation of Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

51 . Efficiency by Input-Output Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
5.2 Efficiency by Thermal-Loss Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
5.3 Performance by Effectiveness Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
5.4 Calculation Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Section 6 Report of Results ............................................ 43

Section 7 Appendix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
7.1 Guidance in Selection of Test Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
7.2 Gas Flow Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
7.3 Computer Program for Calculating Exhaust Gas Enthalpy . . . . . . . . . . . . . . . . .65
7.4 Discussion of Effectiveness ...................................... 79
7.5 Discussion of Heats of Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

ix
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ASME PERFORMANCE TEST CODES

Code on
GASTURBINE HEAT RECOVERY
STEAM GENERATORS

SECTION 1 - OBJECT AND SCOPE

1.1 PURPOSE individual parts or sections of the HRSG unit; (e) compar-
ing performance when firing different fuels; (f) determin-
1.1.1 The purpose of this Code i s to establish procedures ing the effects of changes to equipment.
for the conduct and report of tests of heat recovery steam
generators (HRSG) employed in combined cycle installa-
tions. Combined cycle, as used herein, shall be interpreted 1.3 SCOPE
v
%G a gas turbine exhausting into an HRSG, which may or
may not be arranged for supplemental firing. This Code 1.3.1 The rules and instructions given in this Code apply
provides standard t e s t procedures which will yield results to HRSG units employed in combined cycle installations.
having the highest level of accuracy consistent with current Units operating with more than approximately 40 percent
engineering knowledge and practice, excess air shall be tested in accordance with the require-
ments of this Code. Units operating with less than approx-
imately 20 percent excess air shall be tested in accordance
1.2 OBJECT with Performance Test Code PTC-4.1, Steam Generating
Units. For units operating between 20 percent and 40 per-
1.2.1 The purposes of testingunder this Code are the deter- cent excess air, guidance as to the preferred test method
mination of (a) efficiency, or effectiveness, a t specified can be obtained in Appendix 7.1. Orsat analysis i s not re-
operating conditions; (b) capacity at specified operating quired for tests performed under this Code. Testing of
conditions; (c) other related operating characteristics such auxiliary equipment shall be governed by the Performance
as steam temperature and control range, inlet gas flow and Test Code applying specifically to the auxiliary in ques-
temperature; pressure drops in combustion air, gas, steam tion. This Code i s not applicable to solid fuel fired units.
and water circuits; quality and/or purity of steam; and air The HRSG covered by this Code i s encompassed by the
.and bypass stack gas leakage. envelope boundary shown in Fig. 1.1

1.2,2 A determination of any or all o f the performance

items listed in 1.2.1 may be necessary for other purposes, 1.4 APPLICABLE TEST METHODS
such as: (a) checking the actual performance against
guarantee; (b) comparing these items with a standard of 1.4.1 Instructions are given for three acceptable methods
operation; (c) comparing different conditions or methods o f testing HRSG ünits; two to determine efficiency and
o f operation; (d) determining the specific performance of one for determining effectiveness as a measure of unit per-

l
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Copyright ASME International Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
Provided by IHS under license with ASME 23:56:18 MST Questions or comments about this message: please call the Document
Policy Group at 303-397-2295.
L
a
z
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ASME P T C * 4 * L I 43
~
~
0757b70 0054325 O E

ANSI/ASME PTC 4.4 - 1981 SECTION 1

2
L

-VI . a,

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Copyright ASME International Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
Provided by IHS under license with ASME 23:56:18 MST Questions or comments about this message: please call the Document
Policy Group at 303-397-2295.
SECTION 1 ANSI/ASME PTC 4.4 - 1981
formance. Of the two methods of determining efficiency, 1.4.7 The adjustment of test results to include the effect
one i s the direct measurement of input and output, here- of equivalent heat in auxiliary power to determine Ilnet
inafter referred to as the input-output method and the efficiency” is not a requirement of this Code.
other i s the direct measurement o f heat losses, hereinafter
referred to as the thermal-loss method, The effectiveness 1.4.8 This Code will apply to tests conducted when firing
method measures performance by comparing actual the same or different fuels simultaneously in the gas tur-
enthalpy drop o f the gas to the maximum theoretically bine and in the HRSG supplemental burner(s).
possible (MTP) enthalpy drop. The method to be followed
in conducting the tests shall be a matter for agreement 1.4.9 The determination of data of a research nature or
among all parties and the points of measurement shall be other special data is not covered by this Code.
clearly defined in the report.
1.4.10 A report shall be prepared for each test, giving
1.4.2 The input-output method requires the accurate complete details of the conditions under which the test
measurement of those factors necessary for calculating the was conducted, including a record of test procedures
total heat input t o the HRSG and the heat absorbed b y and all data in form suitable for demonstrating that the
the working fluid or fluids, agreed-upon objectives of the test were in fact attained.

1.4.3 The thermal-loss method requires the accurate meas-

urement of HRSG inlet and outlet temperatures plus the
determination of other heat losses and credits occurring
a t the test point.

1.4.4 The effectiveness method requires the accurate meas- 1.5 REFERENCE CODES
urement of HRSG gas temperature at appropriatelocations.
PTC 1 - General Instructions
1.4.5 An acceptablealternativemethod of determining the 2 - Definitions and Values
heat input to the HRSG, the gas turbine exhaust gas tem- 3 - Fuels
perature, or the gas turbine exhaust gas flow in lieu o f 4.1 - Steam Generating Units
direct measurements i s the resolution of a heat balance 19 - Instruments and Apparatus
around the gas turbine. Refer to the procedure set forth 22 - Gas Turbine Power Plants
in Section 4.6. 6 - Report- Guidance for Evaluation of
Measurement Uncertainty in
1.4.6 Guidelines for the proper selection and application Performance Tests of Steam
of an appropriate test method are given in Appendix 7.1, Turbines

4
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 2 - DEFINITIONS AND DESCRIPTION OFTERMS

2.1 DEFINITION OF TERMS Heat absorbed by working fluids

- Heat in gas turbine exhaust gas $. heat in
ooo/o
2.1.1 The following terms areeither not elsewhere defined supplementary fuel + heat credits
in this Code or are provided for clarification.
For derivation see paragraph 5.4.2.
2.7.1.1 Total Net Heat Input. Total net heat input i s
defined as the sensible heat in the gas turbine exhaust gas Thermal-LossMethod
flow, the chemical heat in any supplementary fuel (lower Efficiency (percent)
heating value of the fuel under constant pressure), plus any
supplemental heat credits added to the working fluid(s),

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
air, gas and other circuits which cross the envelope boundary Heat losses
=(loo- Heat in gas turbine exhaust gas + heat in
)x 100%
as shown in Fig. 1 .l. This total net heat input does not
include the latent heat of the moisture in the gas turbine supplementary fuel + heat credits
exhaust gas flow or from combustionof supplemental fuel.
Heat input and output that cross the envelope boundary For derivation see paragraph 5.4.3.
are involved in the efficiency calculations. Apparatus is 2.1.1.5 Effectiveness. Effectiveness of H RSG equip-
outside the envelope boundary when it requires an outside ment determined within the scope of this Code is defined
source of heat or where the heat exchanged i s not returned as the ratio in percent of the actually measured enthalpy
to the HRSG. drop of the HRSG gas across the section being evaluated
2.1 .I .2 Heat Credits, Heat credits are defined as those relative to the maximum theoretically possible (MTP)
amounts of heat added to the envelope o f the HRSG other enthalpy drop o f the gas as defined in paragraphs 2.1.1.6
than the sensible heat in the gas turbine exhaust and the and 2.1.1.7.
chemical heat in supplementaryfuel. These heat credits in- 2.1 .I S.1 Effectiveness is expressed by the following
clude quantities such as sensible heat in the supplementary equation:
fuel, in entering air, and in atomizingsteam, and heat from
energy conversion in circulating pump and primary air Effectiveness (percent)
and/or recirculating fans. Enthalpy drop of the HRSG gas
-
2.1.1.3 Capacity. Capacity of HRSG units is defined as MTP enthalpy drop of the HRSG gas
either actual evaporation in terms of mass flow of steam For derivation see paragraph 5.4.4.
per unit time or heat absorbed by the working fluids per
unit time. 2.1.1.6 Measured Enthalpy Drop. The measured en-
2.1 -1.4 Efficiency. The efficiency of HRSG equipment thalpy drop of the HRSG gas i s defined as the difference
determined within the scope of this Code i s defined as the between enthalpies as derived by methods detailed in this
ratio of heat absorbed by the working fluids to the total Code o f HRSG gas a t temperatures measured at the points
net heat input as defined in paragraph 2.1.1 .I, This definí- of entering and leaving the section being evaluated.
tion excludes the equivalent heat in the power required by 2.1 .I .7 Maximum Theoretically Possible (MTP) En-
auxiliary apparatus external to the envelope (Fig. 1.i). thalpy Drop. The MTP enthalpy drop of the HRSG gas i s
2.1.1.4.1 Efficiency for the two methods is ex- defined as the difference between the enthalpy of the gas
pressed by the following equations: entering and leaving the section being evaluated such as
would occur if thesection had infinite heat transfer surface
Input-Output Method with the result that the HRSG gas temperature would
Efficiency (percent) = -
Output x 100% equal the water/steam temperature(s) a t one or more
Input

points in the section. Refer to paragraph 5.4.4 for amplifi- 2.1.1.10 Heating Value. The lower heating value i s
cation of the relationship between measured and MTP utilized in this Code as this Code is intended to be utilized
enthalpy drops o f the HRSG gas. for gas turbine heat recovery steam generators. The lower
heating value is utilized as a standard in the gas turbine
2.1.1.8 Pinch Point. The pinch point is defined as the industry. Further discussion o f the relationship between
minimum temperature difference between the H RSG gas lower heating value and higher heating value is found in
and the working fluid. Section 7.5. Higher heating value may be utilized if agreed
2.1.1.9 For conversions to S I units refer to PTC 2, to by the parties to the test.
Definitions and Values.

2.2 SYMBOLS AND DESCRIPTION

Symbol Description Units

B Total sensible heat credits added to the-envelope Btu per hr
Bf Sensible heat in supplementary fuel Btu per hr
BGR Sensible heat in HRSG gas recirculated Btu per hr
BGT Sensible heat in HRSG gas Btu per hr
BmA Sensible heat in moist augmenting air for supplementary firing Btu per hr
Bx Sensible heat from auxiliary drives within the envelope Btu per hr
Bz Sensible heat in atomizing steam for supplementary firing Btu per hr
Mean specific heat o f supplementary fuel Btu per Ib-"F
CPf
CpfG Mean specific heat o f gas turbine fuel Btu per Ib-"F
EF Effectiveness ratio o f enthalpy change -

FGA Gas turbine fuel - inlet air ratio Ib fuel per Ib

moist air
Supplementary fuel - HRSG gas ratio Ib fuel per Ib gas
Heat recovery steam generator -
Enthalpy o f dry air component Btu per Ib gas
Enthalpy o f gas turbine overboard air or gas leakage Btu per Ib
Enthalpy of gas turbine overboard air or gas leakage at reference temperature Btu per Ib
Enthalpy o f carbon component Btu per Ib gas
Enthalpy o f gas turbine cooling fluid Btu per Ib
Enthalpy o f carbon dioxide component Btu per Ib gas
Lower heating value o f supplementary fuel Btu per Ib
Lower heating value o f gas turbine fuel Btu per Ib
Enthalpy o f HRSG gas at given temperature Btu per Ib
Enthalpy o f gas turbine exhaust gas at reference temperature Btu per Ib
Enthalpy o f H RSG gas at a temperature equal to the saturated steam temperature Btu per Ib

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
Enthalpy o f hydrogen component Btu per Ib gas
Ideal gas enthalpy o f dry air Btu per Ib
Incremental enthalpy o f carbon Btu per Ib
Ideal gas enthalpy o f carbon dioxide Btu per Ib
Incremental enthalpy o f hydrogen Btu per Ib
Ideal gas enthalpy o f carbon monoxide Btu per Ib
Ideal gas enthalpy o f moisture Btu per Ib
Ideal gas enthalpy o f nitrogen Btu per Ib
Ideal gas enthalpy o f oxygen Btu per Ib
Incremental enthalpy o f sulfur Btu per Ib
Ideal gas enthalpy of sulfur dioxide Btu per Ib
Enthalpy o f steam to auxiliaries at exhaust pressure and initial entropy Btu per Ib
Enthalpy o f carbon monoxide component Btu per Ib gas
Enthalpy of moisture component Btu per Ib gas .

ANSI/ASME PTC 4.4 - 1981 SECTION 2

SYMBOLS A N D DESCRIPTION (Cont'd)

Description Units
Enthalpy of moist air a t given temperature Btu per Ib
Enthalpy of water injected Btu per Ib
Enthalpy of water injection a t reference temperature Btu per Ib
Enthalpy of nitrogen component Btu per Ib gas
Enthalpy o f oxygen component Btu per Ib gas
Enthalpy of gas turbine lubricating oil Btu per Ib
Enthalpy of HRSG gas at reference temperature Btu per Ib
Enthalpy of moist air a t reference temperature Btu per Ib
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Enthalpy of sulfur component Btu per Ib gas

Enthalpy of steam Btu per Ib
Enthalpy of steam injected Btu per Ib
Enthalpy of steam injected a t reference temperature Btu per Ib
Enthalpy of steam to auxiliaries Btu per Ib
Enthalpy of sulfur dioxide component Btu per Ib gas
Enthalpy of water at given temperature Btu per Ib
Enthalpy of water vapor at atomizing steam temperature Btu per Ib
Enthalpy of atomizing steam a t reference temperature Btu per Ib
Total of heat losses from steam generator Btu per hr
Convective heat loss Btu per ft2-hr
Heat loss in moist H RSG gas Btu per hr
Heat equivalent of gas turbine auxiliaries and miscellaneous losses Btu per hr
Radiant heat loss Btu per ft2-hr
Heat loss in circulating pump systems Btu per hr
Heat loss due to surface radiation Btu per hr
Max ¡mum theoretically pOssi ble -
Weight of carbon in fuel percent
Weight of carbon dioxide in fuel percent
Weight o f hydrogen in fuel percent
Weight of carbon monoxide in fuel percent
Weight o f nitrogen in fuel percent
Weight of oxygen in fuel percent
Weight of sulfur in fuel percent
Weight of sulfur dioxide in fuel percent
Sensible heat in gas turbine exhaust gas Btu per hr
Heat equivalent of gas turbine power output Btu per hr
Heat radiation loss from gas turbine Btu per hr
Heat loss surface area ft2
Temperature of ambient air O F .

Temperature of supplementary fuel O F

Temperature of exhaust gas O F

Temperature of moist air O F

Reference temperature (see paragraph 5.4.2.3.1) O F

Temperature of steam "F

Temperature of water O F

Temperature of atomizing steam "F

Volume of gaseous supplementary fuel ft3 per hr
Overboard air or gas Leakage flow from gas turbine Ib per hr
Gas turbine exhaust gas bypass flow Ib per hr
Gas turbine cooling liquid flow Ib per hr
Supplementary fuel flow Ib per hr

ANSIIASME PTC 4.4 - 1981

SYMBOLS A N D DESCRIPTION (Cont’d)

Description Units

Gas turbine fuel flow Ib per hr

Recirculated HRSG gas flow Ib per hr
Gas turbine exhaust gas flow Ib per hr
Moist augmenting air flow for supplementary firing Ib per hr
Gas turbine water injection flow Ib per hr
Gas turbine lubricating oil flow Ib per hr
Steam flow Ib per hr
Gas turbine steam injection flow Ib per hr
Steam flow to auxiliaries Ib per hr
Water flow Ib per hr
Atomizing steam flow Ib per hr
Weight ratio of dry air component Ib per Ib gas
Weight ratio o f carbon component Ib per Ib gas
Weight ratio o f carbon dioxide component I b per Ib gas
Weight ratio o f dry air Ib per Ib dry air
.Weight ratio of total fuel Ib per Ib gas
Weight ratio of supplementary fuel component Ib per Ib gas
Weight ratio of gas turbine fuel Ib per Ib air
Weight ratio o f hydrogen component Ib per Ib gas
Weight ratio o f carbon monoxide component Ib per Ib gas
Weight ratio o f moisture component Ib per I b gas
Weight ratio o f moisture in air Ib per Ib gas
Weight ratio o f injection water or steam, atomizing steam for supplementary
burners, or moisture from evaporative coolers Ib per Ib dry air
Weight ratio o f nitrogen component I b per I b gas
Weight ratio of oxygen component Ib per I b gas
Weight ratio o f sulfur component Ib per Ib gas
Total weight ratio of HRSG gas mixture Ib per Ib dry air
Weight ratio of sulfur dioxide component Ib per Ib gas
Gas turbine burner efficiency percent
Steam generator efficiency percent
Efficiency of auxiliary drives percent
Supplementary fuel gas specific weight Ib per ft3

*All references in 2.2 to Ib (pounds) are Ibm (pounds mass).

8
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 3 - GUIDING PRINCIPLES

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
3.1 AGREEMENTS 3.1.1.8 Organization and qualifications of test person-
nel, arrangements for their direction, and arrangements for
3.1.1 Items on Which Agreement Shall Be Reached. Defi- recordingthe readingsand observations, and calculatingthe
nite agreement shall be reached as to the specific object test results.
and scope of the test and to the method of operation. Any
3.1.1.9 Establishment of acceptable operational condi-
specified operating condition or performance that is per-
tions, number of load points, duration of runs, basis of
tinent to the object of the test shall be ascertained. Any
rejection of runs and procedures to be followed during the
omissions or ambiguities as to any of the conditions are to
test.
be eliminated or their values or intent agreed upon before
the test i s started. Agreements shall be reached prior to 3.1.1.10 Cleanliness of unit initially and how t h i s i s to
the tests, upon such items as the following: be maintained during the test.
3.1.1.1 1 The fuel to be fired, themethod and frequency
3.1.1.1 Object of test and methods o f operation.
of obtaining fuel samples and the laboratory to make the
3.1.1.2 The intent of any contract or specification as analysis.
to operating conditions and guarantees.
3.1.1.12 Observations and readings to be taken.
3.1 .I .3 Meansfor maintainingconstant test conditions. 3.1.1.13 Corrections to be made for deviations from
3.1.1.4 Location, type, and calibration of instruments. specified operating conditions and their numerical value.
3.1.1.5 If efficiency determination i s to be made: 3.1.1.14 Limits of error in measurement and sampling.
(a) Thermal-loss or input-output method;
3.1.1.15 Allowable leakage.
(b) Method of HRSG gas flow determination;
(c) Heat credits and losses to be measured; 3.1.1.16 Use of computerized data logging and com-
(d) Heat credits and losses to be assigned where not puter programs for calculations.
measured;
(e) Acceptable deviation in efficiency between du-
plicate runs.
3.2 PREPARATION FOR JESTS
3.1.1.6 If effectiveness determination is to be made:
(a) Point a t which inlet HRSG gas temperature i s 3.2.1 General. Every precaution shall be employed in mak-
measured;
ing preparations for conducting any test. Indisputable
(b) Point at which outlet HRSG gas temperature i s records shall be made to identify the equipment to be
measured; tested and the exact method of testing selected.
(c) Method of establishing location of pinch point
within the HRSG envelope boundary;
3.2.1.1 The entire HRSG shall be checked for leakage.
(d) Establishing the value o f the MTP enthalpy drop;
(e) Acceptable deviation in effectiveness between 3.2.1.2 It shall be determined if the fuel to be fired
duplicate runs. during the t e s t is substantially as intended.

3.1.1.7 If capacity determination is to be made: 3.2.1.3 Any departures from standard or previously
(a) Method of measuring steam flow; specified conditions in physical state of equipment, clean-
(b) Acceptable deviation in capacity between du- liness of heating surfaces, fuel characteristics or stability
plicate runs. of load, shall be described clearly in the report of the test.

SECTION 3 ANSI/ASME PTC 4.4 - 1981

3.2.2 Preliminary Tests. A preliminary run shall be made TABLE 3.1

for the purpose of: Suggested Maximum Permissible Variations
in Test Conditions
3.2.2.1 determining whether the equipment is in suit-
able condition for the conduct of the test; Variation of Any Station
3.2.2.2 Making minor adjustments, the needs for which Observation from Re-
were not evident during the preparation for test; ported Average Test Con-
Variable dition During a Test Run
3.2.2.3 Checking the operation o f all instruments;
3.2.2.4 Training the observers and other t e s t personnel. (a) Water flow to economizer 12%
(b) Economizer recirculation flow +3%
(c) Desuperheatingwater flow +4%
(d) Blowdown flow +4%
(e) Fuel flow to gas turbine +2%
3.3. METHOD OF OPERATION (f) Supplemental fuel flow 12%
(g) Gas turbine power output e2%
3.3.1 General. The HRSG and associated equipment shall (h) Gas temperature to boiler i71 0°F
be in normal operation during the test. No special adjust- (i) Stack gas temperature +IOOF
ments shall be made to the HRSG, fuel burningequipment, (i) Water temperature to economizer I1 O" F
dampers, etc., that are inappropriate for normal and con- (k) Steam temperature leaving
tinuous operation. superheater +IO"F
(I) Ambient temperature So F
3.3.2 Performance Tests. A performance test shall be (m) Barometric pressure I 1%
undertaken only when the parties to the test agree that the (n) Steam pressure +2%
HRSG i s operating to their satisfaction and is, therefore, (o) Flow
ready for test. The performance test should be started as Air +2%
soon as the HRSG i s in satisfactory condition, provided H RSG gas +2%
the load and other governing factors are suitable. Gas turbine exhaust I2%
3.3.2.1 The parties to the test may designate a person
to direct the test and serve as mediator in the event of dis-
putes as to the accuracy of observations, conditions, or
methods of operation. 3.3.3.1 Each observation of an operating condition
during a test run shall not vary from the reported average
3.3.2.2 All heat transfer surfaces, both internal and
for that operating condition during the complete run by
external, should be commercially clean (normal operating
more than the amount shown in Table 3.1, except by
cleanliness) before starting the test. During the test, only
mutual agreement between the parties to the test. If operat-
the amount of cleaning shall be permitted as is necessary
ing conditions vary during any test run beyond the limits
to maintain normal operating cleanliness.
prescribed in Table 3.1, and if these variations are not
3.3.2.3 After a preliminary run has been made, it may covered by mutual agreements, the test run shall be dis-
be declared an acceptance run if agreed to and provided carded.
that all the requirements of an acceptance run have been
met. 3.3.4 Frequency of Observations. A sufficient number o f
readings shall be taken a t suitably spaced intervals to show
3.3.3 Stability of Test Conditions. Preparatory to any test the range of fluctuations, to show that stable test condi-
run, the equipment shall be operated for a sufficient time tionsexist during the test, and to provide a suitable average
to establish steady stateconditions. Steady state is achieved for the test run. When differential pressure measurement
when the key parameters, associated with the test objec- devices are used with venturi tubes, flow nozzles, or orifice
tives have been stabilized, Stability will be achieved when plates for subsequentlydetermining quantity measurements,
continuous monitoring indicates the readings have been the flow indicating element shall be read a t five-minute
within the suggested maximum permissible variation shown intervals or more frequently when deemed necessary. Other
in Table 3.1 for a period o f time that i s agreed upon by primary measurements should be made a t no more than
the parties to the test. ten-minute intervals.

10
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ANSI/ASME PTC 4.4 - 1981 SECTION 5

3.3.5 Duration of Test Runs. When determining the per- The observations shall include the date and time of day.
formance of the HRCG, the test run shall be of not less They shall be the actual readings without application of any
than two hours steady duration. instrument corrections. The log sheets and any recorded
charts should constitute a complete record. It is recom-
3.3.5.1 The actual duration of all runs from which the mended that sufficient space be l e f t a t the bottom of each
final test data are derived shall be clearly stated in the t e s t log sheet to record average reading, correction for instru-
report. ment calibration, and translation to desired units for calcu-
lations. Computer data logging is acceptable provided all
3.3.6 Starting and Stopping Procedures. Combustion con- required data points are recorded.
ditions, rates of flow, and all controllable temperatures
and pressures shall be as nearly as possible the same a t the 3.3.10.1 Records made during tests shall show the ex-
end of the run as at the beginning. There must be reason- tent of fluctuations (¡.e., minimum and maximum values
able assurance that the temperature of the refractoriesand of instrument readings) of the instruments in order that
all other parts of the equipment have reached equilibrium data may be available for determining influence of such
before the run is started. fluctuations on the accuracy of calculated results.
3.3.10.2 Every event connected with the progress of a
3.3.7 Operating Conditions. Every effort shall be made to
test, however unimportant it may appear at the time, shall
run the tests under the specified conditions such as type
be recorded on the test log sheets together with the time
of fuel, flows, pressures and temperatures, or as close to
of occurrence and the name of the observer. Particular
the specified conditions as possible in order to avoid the
care should be taken to record any adjustments made to
application of correctionsto the test results, or to minimize
any equipment under test, whether made during a run or
the magnitude of the corrections.
between runs. The reason for each adjustment shall be
3.3.7.1 During each test, all quantitiesshall be recorded stated in the test record.
as actually observed. Corrections and corrected values shall
be entered separately in the report o f the test.
3.3.1 1 Instruments and Methods of Measurement. The
3.3.8 Corrections to Test Results. Corrections shall be necessary instruments and proceduresfor making measure-
applied to the test results for any deviations of the test ments shall be accurate and reliableand shall be as required
conditions from those specified. Correction factors may in Section 4, so that accurate observations may be made.
be in the form of curves or numerical values. The method 3.3.1 1.1 Section 4 presents the essential mandatory re-
of applying corrections shall be carried out as required in quirements for instruments, methods, and precautions
Section 5.4. which shall be employed, unless the parties to the test
3.3.8.1 Auxiliary tests may be run for the purpose of mutually agree to the contrary. The Supplements on In-
verifying the value of selected corrections factors. Any struments and Apparatus (PTC 19 series) provide general
such special tests shall be completely described in the test and authoritative information concerning instruments and
report, including the methods employed and the results their use and shall be consulted if sufficient information is
obtained. not included in this Code.

3.3.9 Rejection o f Tests. Should serious inconsistencies in 3.3.12 Thermodynamic Properties. Except with written
the observed data be detected during a run or during the
agreement to the contrary, the properties o f steam shall be
calculation of the results which affects the validity of the
obtained from the “1977 ACME Steam Tables” and the
results, the run shall be rejected completely, or in part if
enthalpy of gas shall be calculated as shown in paragraph
the affected part i s a t the beginning or at the end of the
5.4.2.4. If steam and water properties are obtained from
run. A run that has been rejected shall be repeated, if neces-
calculations using a computer, the computer program shall
sary, to attain the objectives of the test. be the IFC Formulations for Industrial Use.
3.3.10 Records and Test Reports. The test observations
shall be entered on previously prepared forms which con- 3.3.13 Tolerancesand Limits o f Error. This Code does not
stitute original log streets to be authenticated by the ob- include consideration of overall tolerances or margins on
servers’ signatures. For the tests, a complete set of un- performance guarantees. The test results shall be reported
altered log sheets and recorded charts or facsimiles thereof as calculated from the test observations with such correc-
shall become the property of each party to the test. tions as are provided in this Code.

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

--- -
ASME P T C m L I . 4
~~
81 0 7 5 9 b 7 0 0054334 1

SECTION 3 ANSI/ASME PTC 4.4 - 1981

3.3.13.1 Allowances for errors o f measurement and tion, the reported test results shall be qualified by the
sampling are permissible provided they are agreed upon statement that the error in the results may be considered
in advance by the parties to the test and clearly stated in not t o exceed a given plus or minus percentage, this value
the test report. The limits o f probable error on calculated having been determined in accordance with the foregoing
efficiency, effectiveness, or capacity shall be taken as the method for calculating limits o f probable error. For guid-
square root of the sum of the squares of the individual ance refer to ACME PTC 6 Report-1969, “Guidance for
effects on efficiency, effectiveness or capacity. Evaluation of Measurement Uncertainty in Performance
Tests o f Steam Turbines.”

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
3.3.13.2 Whenever allowances for probable errors o f 3.3.13.3 Guidance as to the selection o f the most ap-
measurement and sampling are t o be taken into considera- propriate test method is given in Section 7, Appendix 7.1.

SECTION 4 - INSTRUMENTS AND METHODS OF MEASUREMENT

4.1 GENERAL 4.2.2 Liquid Fuel Quantity Measurement. Positive dis-

placement meters may be used if calibrated under condi-
4.1.I This section describes the instruments, methods, and tions simulating those existing during the test in regard
precautions that should be employed in testing HRSG to grade of fuel, temperature, pressure, rate of flow and
units under this Code. For procedures to obtain some of meter location. If greater accuracy is required for this
the supplementary information, other authoritative codes measurement, it i s best obtained by means of weigh tanks,
and standards are cited and shall be considered as part of The next most accurate method is by means of volumetric
this Code. For probable measurement error see Appen- tanks. Measuring devices shall be calibrated prior to and
dix 7.1. after the test such that liquid fuel flow can be measured
to an accuracy within 50.5 percent in the range of loads
4.1.2 The instruments generally required for a code test measured.
are presented in the following list for checking purposes.
Only those instruments necessary for attainment of the 4.2.2.1 Leakage of fuel between point of measurement
desired objective need be used. In some cases it may be and point of firing shall be measured and accounted for
necessary to use instruments not included in the list. in the flow calibration. Branch connections on the fuel
piping shall be either blanked off or provided with double
4.1.2.1 Quantity Measurements. Scales, weigh tanks, valves and suitable telltale drains for detecting leakage.
volumetric tanks, or flow meters to measure fuel, steam Leakage from valve stuffing boxes shall be prevented. Any
and water flows. Dynamic meters, Pitot and Fechheimer unavoidable leakage from pump stuffing boxes, or else-
probes to measure gas and air flows. where, shall be collected and accounted for. Where an oil
return system from the burners is used, both supply and
4.1.2.2Temperature Measurements. Mercury thermom- return flows shall be measured by calibrated meters.
eters, thermocouples, and resistance temperature de-
tectors. 4.2.2.2 If fluctuations in meter readings are present,
the variation of the indicated maximum or minimum
4.1.2.3 Pressure Measurements. Bourdon gauge, dead- reading shall be minimized and must be made to be less
weight gauges, manometers, and electronic pressure trans- than 5 5.0 percent by the introduction of a cushion cham-
mitters. ber, surge chamber, or other means of absorbing the pul-
sations between the source of pulsation and the primary
4.1.3 The PTC 19 series generally describes the most device before measurement i s considered acceptable. For
accurate means for determining the required parameters. further discussion of pulsating flow measurement see
For typical measurement accuracies and their effect on ASME Research Publication, “Fluid Meters -Their Theo-
overall test results refer to Appendix 7.1. ry and Application,” paragraphs 106 to 109, inclusive.

4.2.3 Gaseous Fuel Quantity Measurement. Measurement

4.2 FLOW MEASUREMENTS of gaseous fuel used in testing HRSG units requires the
use of the orifice, flow nozzle or venturi. Measuring de-
4.2.1 General. Accurate measurement of flow i s vital in vices shall be calibrated prior to and after the test such
determining overall plant performance. The several tech- that gaseous fuel flow can be measured to an accuracy
niques available each have limitations as to accuracy and within 50.35 percent in the range of loads measured.
magnitude of flow for which they can conveniently be
used. The most accurate method of measuring fluid flows 4.2.4 Water Flow Measurement, The measurement of
is by weighing, but this i s usually limited to shop tests water flow into the HRSG requires the use of the venturi,
and/or small quantities. nozzle, orifice, weigh tank, or volumetric tank.

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 4 ANSIIASME PTC 4.4 - 1981

4.2.4.1 Venturi, Nozzle, or Orifice. Water quantity 4.2.5.5 Differential pressures at the primary metering
may be measured by venturi, nozzle, or orifice. Measuring element shall be measured by a direct reading manometer,
devices shall be calibrated prior to and after test such that differential pressure gauge, or pressure transducer.
water flow can be measured to an accuracy within k0.75
percent ih the range of loads measured, 4.2.5.6 Precautions and Corrections Relating to Out-
put Quantity Measurements. All leakage which may affect
4.2.4.1.1 The recommendations o f ASME Research t e s t results shall be eliminated; otherwise it must be meas-
Publication, “Fluid Meters - Their Theory and Applica- ured and accounted for. Errors due to steam or water
tion,” shall be followed with reference not only to the entering or leaving the equipment under test, through con-
design, construction, calibration and Lise of flow measur- necting piping, shall be prevented by blanking off such
ing elements, but’also to their location and installation in connections or by providing open telltale drains between
the pipelines and the installation of the connecting piping double valves to give visible assurance that no flow exists.
system between the primary element and manometer. All Leakage tests shall be made in accordance with I & A ,
calculations of flow rate from the observed differentials, Leakage Measurement, PTC 19.21.
pressures and temperatures shall be made in accordance
with the provisions of the above reference. 4.2.5.6.1 Blowing down during a run shall be avoid-
ed. If this is not possible, the amount of heat can be de-
4.2.4.1.2 The venturi, nozzle or orifice selected termined by heat balance around the blowdown heat
shall be such that the differential pressure a t any test out- recovery system.
put as shown by the manometer is at least five inches of
manometric liquid. 4.2.5.6.2 Soot blower operation during a run shall
be avoided.
4.2.4.1.3 If fluctuations in flow are present refer to
paragraph 4.2.3.1. 4.2.6 Augmenting Air and HRSG Gas Flows. Augmenting
air and HRSG gas flows can be determined as shown in
4.2.5 Steam Flow Measurement. Output steam flow this section.
should preferably be obtained from measurement of water
flow as described in paragraph 4.2.4, corrected for any 4.2.6.1 Flow Determination by Flow Meter. Methods
addition or withdrawal of fluid beyond the measuring of measurement available for HRSG gas and augmenting
element, such as continuous blowdown, desuperheating flow for testing purposes are covered in ASME Research
spray water, boiler circulating pump injection water, etc. Publication, “Fluid Meters - Their Theory and Applica-
tion.” Where continuous monitoring of such flows is re-
4.2.5.1 For determining capacity or other related quired, nozzles, venturis, or orifices can be installed fol-
operating characteristics, the output quantity of main lowing procedures outlined in foregoing reference.
and reheat steam may be determined by means of venturi,
nozzle, or thin plate sharp edged orifice. 4.2.6.2 Flow Determination by Velocity Traverse.
Since flows are not usually uniform in the duct cross sec-
4.2.5.2 Reheat steam flow, if not measured, can be tions, a suitable means o f averaging velocity head readings
computed by a material balance calculation. must be used. One satisfactory method divides the trav-
ersed plane into multiple equal area sections with the re-
4.2.5.3 Measuring devices shall be calibrated prior to sultant average velocity pressure being taken as the square
and after the test such that steam flow can be measured of the average of the square roots of the individual veloci-
to an accuracy of rt0.75 percent in the range of loads ty pressures. This method is described in detail in Appen-
measured. dix 7.2.

4.2.5.4 The recommendations of ASME Research Pub- 4.2.6.2.1 Where the gas flow direction i s not normal
lication, “Fluid Meters - Their Theory and Applkation,” to the plane of traverse, it is recommended that a direc-
shall be followed with reference not only to the design, tional probe, such as the Fechheimer probe, be used to de-
construction, calibration and use of nozzles and orifices, termine the velocity and direction of flow. By using the
but also to their location and installation in the pipeline yaw angle correction it is possible to measure the magni-
and the arrangement of the connecting piping system be- tude of the velocity vector in the direction of flow in one
tween the primary element and the differential pressure plane. Section 7.2 provides detailed information on the
measuring instrument. procedure for making the probe insertion.

14
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ANSI/ASME PTC 4.4 - 1981 SECTION 4

4.3 STEAM AND WATER TEMPERATURE MEAS- at the same number of points as are used for HRSG gas
UREMENT velocity measurements, paragraph 4.2.6.2.

4.3.1 Saturated steam temperature shall be determined 4.4.1.2 If a preliminary survey of HRSG gas flow indi-
by the pressure in the steam drum. The temperature of cates severe stratification, it i s recommended that the
superheated steam shall be measured as close to the super- temperature measurements at individual locations in the
heater and/or reheater outlets to minimize error from duct cross section be weighted in proportion to the HRSG
heat loss. Feedwater temperatures shall be measured as gas velocity at the corresponding locations and an average
close to the economizer inlet and boiler inlet as possible. of the weighted temperature be used to represent the
Steam and water temperatures, considered to be of pri- HRSG gas temperature a t that cross section.
mary importance, shall each be taken at two different
points as close together as practical and the mean of the 4.4.1.3 Choice of temperature measuring instruments
two readings after corrections to each shall be the tem- depends upon the conditions of the individual case. The
perature of the fluid. Discrepancies between the two cor- selection, design, construction, calibration, installation
rected readings which exceed 0.25 percent for steam and and operation of temperature measuring instruments shall
0.50 percent for water shall be investigated. be in accordance with I & A, Temperature Measurement,
PTC 19.3.
4.3.1.I Mercury-in-glass thermometers, resistancetem-
perature detectors, or thermocouples are acceptable for 4.4.1.4 If the requirement of a test necessitates meas-
temperature up to 760°F. Above 760°F resistance tem- uring HRSG gas temperatures in a zone that prevents accu-
perature detectors or thermocouples shall be used. rate determination by bare thermocouples, that is, when-
ever a thermocouple can radiate to or from a surface
4.3.1.2 All temperature measuring üevices shall be (surfaces or sky outside the stack included) at a tempera-
calibrated before and after tests. When employing mer- ture different from that o f the gas being measured, special
cury-in-glass thermometers, proper allowance shall be probes using a high velocity thermocouple principle shall
made for differences between thermometer stem tem- be employed, As a guide, the aspirating rate should be in-
perature during calibration and test. See I & A, Tempera- creased until temperature readings level out.
ture Measurement, PTC 19.3.All temperature measuring
instruments and wells shall be constructed, installed, and
the instruments calibrated and operated in accordance 4.5 OTHER MEASUREMENTS
with I & A Temperature Measurement, PTC 19.3,except
that where the fluid stream Reynolds number exceeds 4.5.1 Steam and Water Pressures. Pressure gauges shall be
3.5 x IO5, appropriate allowances are required in well de- located where they will not be affected by any disturbing
sign to account for the increase in Strouhal number, Tem- influences such as extremes of heat, cold, and vibration
perature measuring devices shall be installed so that ad- and shall be located in convenient positions for reading
verse effects of radiation and/or conduction will be While calibrated Bourdon tube test gauges or deadweight
minimal. gauges may be used, the use of the latter i s preferred.

4.3.1.3 The temperature sensing element and/or well 4.5.1.1 Gauge connections shall be as short and direct
shall be located such that it i s subjected to the velocity of as possible. Gauges shall be protected with syphons or
the measured fluid and not in a dead fluid pocket. their equivalent. Convolutions of syphons shall be as few
in number as possible, consistent with the gauge remain-
ing cool, because of their tendency to introduce errors
4.4 GAS AND AIR TEMPERATURE MEASUREMENT due to unbalanced water columns in the convolutions. All
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

gauge connections shall be tight.

4.4.1 Inlet and Outlet HRSG Gas Temperature. HRSG
gas temperature measurement at the entrance and exit of 4.5.1.2 Pressure connections shall be located and in-
the HRSG i s required. This may in certain instances be stalled with extreme care in order to avoid errors due to
measured at other points such as the inlet and discharge impact and eddies. Pressure gauge pulsations shall not be
of augmenting air or HRSG gas recirculating fans. dampened by throttling the connection to the gauge or by
the use of commercial gauge dampers, but a volume cham-
4.4.1.1 To minimize the effect of HRSG gas tempera- ber may be employed, The arrangement may be consid-
ture stratification, HRSG gas temperatures must be taken ered satisfactory if the maximum and minimum values of

SECTION 4 ANSIIASME PTC 4.4 - 1981

the instantaneous pressure do not differ by more than spectrum and half-life used to identify the specific nuclide.
2.0 percent from the mean value. Bourdon tube test gauges Steam quality can be calculated as follows:
shall be calibrated, installed and used in accordance with
x ( % ) = l O O - ( Activity in steam x
I & A, Pressure Measurement, PTC 19.2. These gauges
Activity in HRSG water
shall be calibrated before and after the test and a t inter-
vals of not more than one week if the test is extended
beyond that period. Radioactive tracers have been used for determining
steam quality with excellent results. The method had not
4.5.2 Quality and Purity of Steam. Steam quality is the been sufficiently developed at the time PTC 19.11-1970
percent by weight of dry steam in a mixture of saturated was published, to include them in that supplement, how-
steam and suspended droplets of water at the same tem- ever, PTC 6-1976 has a complete description of methods.
perature. Steam purity is the solids content in a sample of 4.5.2.4 Calorimeter Method. Observations by means
condensed steam. of a properly constructed calorimeter will provide the
means for accurately calculating the percentage moisture
4.5.2.1 Measurement of Steam Quality. The following present in a given sample. The difficulty is that there can
methods listed below in the order of preference, may be never be assurance that the sample is representative of the
used to determine steam quality: (1) Continuous Deter- average condition of the steam flowing in the pipe. Tech-
mination of Sodium, ASTM D 2791; (2) Radioactive niques for sampling are described in PTC 19.11, which
Tracer Method; (3) Calorimeter for Direct Determination should be consulted whenever any of the above test
of Quality; and (4) Additional Methods if Mutually Agreed methods are used and particularly when the calorimeter
Upon. Selection of one of these methods for determining is used.
steam quality must be based upon the conditions peculiar
to a particular steam supply system, since each method 4.5.2.5 Sodium Ion Electrode, ASTM D-2791, Meth-
has limitations which govern i t s use. od A. This method employs an electrode and instrument
similar to those used for the measurement of the hydro-
4.5.2.2 Flame Photometry Method for Sodium. The gen-ion concentration in aqueous solutions (pH), except
sodium flame photometry method is based upon the accu- that the electrode i s specific for measuring the sodium
rate determination of sodium concentrations in condensed ion concentration. This device is an alternative to the
steam samples and is, therefore, contingent upon the pres- flame spectrophotometer as described in paragraph 4.5.2.2.
ence of sodium salts in the HRSG water of the steam sup- 4.5.2.6 Determination of Steam Purity. The following
ply system. It is not recommended where a large percen- methods may be used to determine steam purity: (1) Elec-
tage of the solids present do not contain sodium. Sodium tric Conductivity; (2) Sodium Ion Determination of Steam
analysis shall be performed in accordance with ASTM D Purity; (3) Dry Residue (Gravimetric) Test; and (4) Silica
2791, Method B; ASTM D 1428, Method B; or ASTM D and Metal Oxides.
2186, Method C. Solids in the steam may be calculated as The above analysis shall be performed in accordance
follows: with PTC 19.1 1.
Total solids in steam (mg/l) =
4.5.3 Moisture in Augmenting Air. The moisture carried
Sodium in steam (mg/l) Total solids in HRSG by augmenting air must be taken into consideration when
X
Sodium in HRSG water (mg/l) water (mg/l) calculating the efficiency. This moisture may be deter-
Steam quality may be calculated as follows: mined with the aid of a sling-type psychrometer or similar
device. From the dry- and wet-bulb thermometer readings

x (%) = 100 -(Sodium in steam (mg/l) x 100

Sodium in HRSG water (mg/i)
taken from the psychrometer at the observed barometric
pressure, the absolute or specific humidity (pounds of
moisture per pound of dry air) can be determined either
The accuracy of this method for determining quality is from the chart published in I & A, Humidity Determina-
impaired when volatile salts are present in the steam. tions, PTC 19.1 8, or from psychrometric tables published
in U. S. Weather Bulletin No. 235.
4.5.2.3 Radioactive Tracer Method. This method is
based upon the accurate measurement of radioactive 4.5.3.1 The dry-' and wet-bulb temperatures may be
nuclides, such as sodium-24, in condensed steam and determined at the atmospheric air inlet to the system.
HRSG water samples. The activity of the samples can be This is possible since the desired quantity i s pounds of
determined by using a multichannel analyzer with energy moisture per pound of dry air for combustion. Since the

16
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ANSI/ASME PTC 4.4 - 1981 SECTION 4

Radiant heat loss, Btu/sq ft, hr

1 2 3 4 5 6 7 8 9 1 0 20 30 40 50 60 70 80 100

.-
lo 20 30 40 50 60 70 80 100 200 300 400 600 800 1000
Ambient temperature, i,,O F

Q/A = 0.1 74e

where
y-([ - 1-(1
Q/A = heat loss, Btu/sq ft, hr
E = emissivity
T, = surface temperature,OF
To = ambient temperature,OF
FIG. 4.1

17
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 4 ANSIIASME PTC 4.4 - 1981

1O0
7-
90

z
70

60
8
/

50
L
r
i--
Y-
U
P
3 40
m’
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

c
al
9
,-
i-
30

2
o

10
10 20 30 40
- t 90 1
Temperature difference ( A t ) , O F

Free Convection Forced Convection

Q/A = 0.296(A.t)1*25
where where
J-
Q/A = 0 , 2 9 6 ( A t ) 1 * * 5 ___

QIA = heat loss, Btu/sq ft, hr Q/A = heat loss, Btu/sq ft, hr
A t = temperature difference between wall and A t = temperature difference between wall and
surrounding air “F surrounding air “F
FIG. 4.2
Source: “Thermal Insulation,” John F. Malloy, Van Nostrand Reinhold Co., 1969, pp. 33-35.

ANSI/ASME 4.4 - 1981 SECTION 4

TABLE 4.1

Radiation emittance table

Surface" Total Normal Surface Total Normal

Metals Temp., F Emittance, E Metals Temp.,"F Emittance, E
Al u minu m Lead
Highly polished 440-1070 0.039-0.057 Pure 260440 0.06-0.08
Polished 100-1O00 0.04-0.06 Gray, oxidized 75 0.28
Rough plate 78 0.055-0.070 Oxidized @ 390°F 390 0.63
Oxidized @ 111O" F 390-111O 0.1 1-0.1 9
Roofing surface 0.21 6 Magnesium
Oxide 530-1520 0.63-0.26 Polished 100-1000 0.07-0.22
Foil 212 0.087
Monel metal
Bismuth 175
Washed, abrasive soap 75 0.1 7
0.34
Repeated heating 450-1610 0.46-0.65
Brass Nickel and alloys
Highly polished 497-71O 0.03-0.04 Electrolytic, polished 74 0.05
Polished 1O0 0.05 Electroplated, not
Rolled plate, natural 72 0.06 polished 68 0.1 1
Rolled, coarse emerald 72 0.20 Wire 368-1 844 0.1 0-0.1 9
Oxidized @ 1110°F 390-111O 0.61-0.59 Oxidized @ 1110" F 390-11TO 0.37-0.48
Dull plate 120-660 0.22 Oxide 1200-2290 0.59-0.86
Nickel copper, polished 212 0.06
Chromium 100-1O00 0.08-0.26 Nickel silver, polished 212 0.14
Polished 100-500 0.06-0.08 Nickelin, gray oxide 70 0.26
Polished Solar 0.50 Nichrome wire, bright 120-1830 0.65-0.79
Nichrome wire, oxidized 120-930 0.95-0.98
Copper Chrome-nickel .36-.97
Electrolytic, polished 176 0.02
CommJl plate, polished 66 0.030
Heated @ 1110' F 390-111O 0.57-0.57 Platinum, polished 440-2960 0.05-0.1 7
Thick oxide coating 77 0.78
Cuprous oxide 1470-201O 0.66-0.54 Silver, pure, polished 440-1 160 0.02-0.03

Everdur, dull 200 0.1 1 Stainless steels

Type 316, cleaned 75 0.28
Gold 316,repeated heating 450-1 600 0.57-0.66
Highly polished 440-1 160 0.02-0.40 304,42 hr @ 980°F 42 0-980 0.62-0.73
Polished 1O0 0.06 310, furnace service 420-980 0.90-0.97
Iron and Steel Tin, bright 76 0.04-0.06
Pure iron, polished 350-1800 0.05-0.37
Wrought Iron, polished 100-480 0.28 Tungsten
Cast iron, polished 0.21 Filament 100-1000 0.03-0.08
Smooth oxidized iron 260-980 0.78-0.82 Filament 2000-5000 0.19-0.34
Strongly oxidized iron 100-480 0.95
Steel, polished 100-1O00 0.07-0.1 4 Zinc
Steel, polished Solar 0.045 Pure, polished -
4 40 620 0.05
Steel, rolled sheet 70 0.657 Galv. iron, bright 82 0.23
Steel, rough plate 100-700 0.94-0.97 Galv. gray oxidized 75 0.28
Smooth sheet iron 1650-1900 0.55-0.60 Galv. iron, dirty 2500 0.90
Plate steel, rusted 67 0.69 Galv. iron, dirty Solar 0.90
Steel, oxidized 100-1O00 0.79-0.79 Galv. iron Solar 0.54

Source: "Thermal Insulation," John F. Malloy, Van Nostrand Relnhold Co., 1969, Appendix B, p. 525.

19
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 4 ANCI/ASME PTC 4.4 - 1981

specific humidity does not change with heat addition un- the gas flow at one third of the HRSG’s height, from the
less there i s moisture addition, the air moisture crossing heat input measurement plane to the outlet plane. When
the envelope, Fig. 1, i s the same as that measured at the temperature gradients transverse to gas flow exist, then
air inlet, number of temperature measurementsshould be dou bled,
¡.e., measurement should be taken a t one third and two
4.5.4 Surface Radiation and Convection. The radiation thirds the HRSG’s height.
and convection loss of an HRSG is generally the smallest
4.5.4.3.2 Ambient air temperature must be meas-
of all heat losses. This loss may be assigned by agreement
ured.
of the parties to the test using the Radiation Loss Curve
in PTC 4.1, Figs. 8 and 9. The curve’s values were checked 4.5.4.3.3 Surface air velocity should be measured
against the actual measured losses on several large boilers with a commercial grade anemometer of the proper range
and the curve values were found to be normally greater after a smoke generator or yarn tuft has been used to de-
than the actual radiation loss. It must further be noted termine air flow direction across the HRSG exterior,
that the radiation loss curve is based on fully fired boilers
4.5.4.3.4 Calculations. When it has been determined
which have large furnaces, whereas the usual HRSG does
that the average side-to-side velocities and skin tempera-
not. Because of this difference, the HRSG radiation-con-
tures are within 10 fpm and 10°F of each other, respec-
vection heat loss area per heat input rate (sq ft of outside
tively, an overall average of these two quantities should
area/Btu input rate) will be a smaller value than for a fully
be used to obtain unit area heat losses as determined by
fired installation and therefore, PTC 4.1, Fig. 8, will be
graphs, Figs. 4.1 and 4.2, and using appropriate emissivity
even more conservative in terms of radiation-convection
values as shown on Table 4.1. The sum of the unit area
loss for HRSG units.
radiation and convection heat losses are multiplied by the
Although it may be desirable to treat this loss like all
total area over which the measurements were taken to de-
others, Le., to take test readings and compute the loss,
termine the total unit heat loss. When either or both of
the test installation is quite extensive and may be an un-
the above conditions do not exist, the heat loss from each
warranted requisite. In conducting such tests, the follow-
side or surface should be determined on an area-weighted
ing methods are suggested for obtaining test data and
basis. Radiation-convection heat loss expressed as a per-
computing the loss.
centage of total heat input becomes:
4.5.4.1 Heat Loss Bolin&ry. A boundary or bounding Total heat loss
Loss as percentage of input = x 100%
surface must be established through which heat losses Total heat input
occur. It shall include the total flat projected external
surface area between the plane at which the heat input to 4.5.5 Gaseous Fuel Sampling. The gas shall be sampled
the HRSG i s measured and the last plane (outlet plane) a t in accordance with the Test Code for Gaseous Fuels,
which heat is removed from the gas. PTC 3.3.
4.5.4.2 Conduction Method. Heat loss through ex- 4.5.6 Gaseous Fuel Analysis and Higher Heating Value.
posed surface can be determined by installing at the cen- Fuel analysis and higher heating value determination shall
ter of every 100 sq ft of area a pair of thermocouples in a
be made in accordance with the Test Code for.Gaseous
block of insulation of known conductivity. With the tem-
Fuels, PTC 3.3.
perature gradient measured by the thermocouples, the
known distance between thermocouples and the conduc-
4.5.6.1 The lower heating value is calculated from
tivity of the insulation compute the radiation and con-
higher heating value by the following formula: LHV =
vection loss for each 100 sq ft divided by the HRSG heat
HHV - 9384 H, where H is the weight fraction of hydro-
input rate will be the radiation and convection loss for gen in the fuel gas. For explanation of the conversion see
the unit.
Appendix 7.5.
4.5.4.3 Surface and Ambient Air Temperature-Veloci-
ty Method 4.5.7 Liquid Fuel Sampling, Representative samples of
fuel shall be obtained in accordance with the Test Code
4.5.4.3.1 Lagging surface temperature should be for Diesel and Burner Fuels, PTC 3.1,
measured with a contact pyrometer. If there is no tem-
perature gradient transverse to the gas flow path, a series 4.5.8 Liquid Fuel Analysis and Higher Heating Value.
of at least ten equally spaced skin (lagging) temperature Fuel analysis, density, and viscosity determination shall
measurements should be made along each side, parallel to be made in accordance with the Test Code for Diesel and

20
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ANSI/ASME PTC 4.4 - 1981 SECTION 4

Burner Fuels, PTC 3.1 ; Density Determinations, PTC this method. The following procedures and calculation
19.16; and Determination of the Viscosity of Liquids, methods are presented for application with the input-
PTC 19.17. Higher heating value shall be determined in output method (Section 5.1) for determining the effici-
accordance with ASTM D 2382, Heat of Combustion of ency of an HRSG. If agreed upon between the parties,
Hydrocarbon Fuels by Bomb Calorimeter (High Precision these methods may be applied as the primary method of
Method). ‘ determining sensible heat, gas enthalpy, or gas flow.
Alternatively, these methods may be applied as secondary
4.5.8.1 Lower Heating Value. The higher heating value methods for checking the magnitude of these parameters
of liquid fuels i s determined in a constant volume. For when using the methods presented in Section 5.1 as the
applications in this Code it is necessary to convert to con- primary method of determining the value of these param-
ditions of constant pressure and lower heating value. The eters.
conversion from higher in a constant volume to lower
under constant pressure i s made according to the follow-
ing formula: 4.6.2.1.1 The gas turbine heat balance method may
- also be utilized for determination of gas turbine exhaust
LHV(constant pressure) - flow or temperature using the calculation procedure in
- 9120 H, 4.6.2.1.4 and 4.6.2.1.5.
(constant volume)
where H is the weight fraction of hydrogen in the fuel.
For explanation of the conversion see Appendix 7.5. 4.6.2.1.2 Sensible Heat in Exhaust Gas. Fuel fired
in a gas turbine i s converted to shaft power, sensible heat
4.6 ALTERNATIVE METHODS OF MEASUREMENT in the exhaust gas, and miscellaneous losses. The sensible
heat in the exhaust gas above the reference temperature*
4.6.1 Discussion i s determined as the net heat in the fuel fired plus energy
in water or steam injection less the shaft power and the
4.6.1.1 Determination of gas turbine exhaust total miscellaneous losses. The miscellaneous losses are usually
sensible heat flow or temperature are important param- a small fraction of the energy in the fuel fired and they
eters for calculating efficiency or effectiveness. Due to include heat rejection from the lubricating oil system,
the usual geometry of gas turbine exhaust systems and heat rejection from the turbine cooling system, heat radi-
associated duct systems connecting to the HRSG, the fore- ated from casings, overboard air or gas leakage, and energy
going parameters are difficult to measure directly with input to accessories driven from the turbine shaft. Heat
the required accuracy. There are alternative methods to de- radiated from casings and energy input to shaft driven
rive these parameters with the required accuracy: the gas accessories shall be determinedfrom the gas turbine manu-
turbine heat balance method and gas turbine inlet scroll facturer’s information. Heat rejection from the lubrica-
method, tion and turbine cooling shall be determined by the lubri-
cant or turbine cooling fluid enthalpy drop and flow or
4.6.2 Gas Turbine Heat Balance Method coolant enthalpy rise and flow. If overboard air or gas
leakage flow and temperature can be measured, this heat
4.6.2.1 The gas turbine heat balance enables deter- loss shall be determined from the flow and temperature.
mination of the sensible heat in the gas turbine exhaust Since the total miscellaneous losses are a small fraction of
gas without the requirement for determination of exhaust the energy in the fuel fired, the gas turbine manufacturer’s
gas flow and exhaust gas temperature by measurement. curves and information may be employed for determina-
The major parameters employed in this method are heat tion of miscellaneous losses if agreed upon by the parties
consumption and power output, which can be determined to the test. To preserve the accuracy o f the test, the mis-
by methods presented in PTC 22 Gas Turbine Power cellaneous losses estimated from manufacturer’s curves and
Plants. Secondary parameters, which complete the heat information must not exceed two percent of the energy in
balance, are steam or water injection and the miscel- the fuel fired.
laneous losses which include auxiliaries, radiation, lubri-
cating oil cooling, and turbine cooling. The accuracy of
this method requires precise determination of power out-
put and heat consumption. The small magnitude of the * Reference temperature, t R , is the base temperature at a given
pressure to which sensible heat losses and credits are compared
miscellaneous losses reduces the influence of this param- for efficiency calculations. In 4.6.2.1.3 the reference tempera,
eter upon accuracy of determination of sensible heat by ture is the compressor inlet temperature.

21
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 4 ANSI/ASME PTC 4.4 - 1981

4.6.2.1.3 The sensible heat in the exhaust gas above -

LHg6 - QR96' wa96(hu96-huR)
the reference temperature is computed by the following
equation: + ' o 9 6 (ho96-1 - ho96-2)
' c 9 6 (hc96-1 - hc96-2)
where
- Btu
Q ~ 9 6- hr = Heat radiated from turbine and gear
casings and accessories.
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

- Ib = Overboard air or gas leakage flow from

'a96 -h;
gas turbine.

where - Btu
hu96 -% = Enthalpy of overboard air or gas leakage.
- Btu
QGTI -F = Sensible heat in exhaust gas above refer-
ence temperature. - Btu
= Enthalpy of overboard air or gas leakage
- -Ib
- Ib = Flow of fuel to the gas turbine. at compressor inlet temperature.
'fG32 -h;
- Ib
Btu
hfG32=lbfuel = Lower heating value of fuel to the gas
Y 'o96 -hr = Lubricating oil flow.

turbine (see paragraph 5.4.2.3.9). - Btu

ho96-1 - = Enthalpy of lubricating oil entering
vB = percent = Gas turbine burner efficiency. cooler.

Btu - Mean specific heat of gas turbine fuel ho96-2 = Btu = Enthalpy of lubricating oil leavingcooler.
'PfG32= Ib"F - (see paragraph 5.4.2.3.4).
--Btu
tf35,37= "F = Fuel temperature to supplementary = Enthalpy of steam injection a t the tem-
hsJ - Ib
burners. perature entering the gas turbine.

tR = "F = Reference temperature. - Btu = Enthalpy of water injection at reference

hmR -T
= -Ib
temperature.
= Flow of water injection entering the gas
'mJ hr
turbine. - Btu = Enthalpy of steam injection a t reference
hsR --
- Ib Ib temperature.
= Flow of steam injection entering the gas
/s' -
turbine. 'c96 Ib = Turbine cooling fluid flow
- Btu = Enthalpy of water injection at the tem-
hmJ -% - Btu - Enthalpy of turbine cooling fluid a t
perature entering the gas turbine.
hc96-1 - - point of extraction from turbine.
QP91 hr
= Btu = Heat equivalent of gas turbine shaft
- Btu = Enthalpy of turbine cooling fluid at
power output (kW x 3412.14 or hc96-2 -
hp x 2544.43). point of reinjection into turbine after
being cooled.
- -Btu = Heat equivalent of input to shaft driven
LH92 - hr
accessories, from gas turbine manu-
facturer (hp x 2544.43). 4.6.2.1.4 Exhaust Gas Flow Determination. The
exhaust gas flow can be calculated from the sensible heat
- Btu determined from the gas turbine heat balance if the ex-
LH96 -hr = Heat equivalent of loss from lubricating haust gas temperature is determined by measurement,
oil system, turbine cooling system,
overboard air or gas leakage, and heat employing equation:
radiated from casings, from gas tur-
QGTI
bine manufacturer or the following WGTI =
equation: ~ G GR
I

ANCI/ASME PTC 4.4 - 1981 SECTION 4

where The absolute enthalpy of the exhaust gas may be de-

termined as follows:
- Ib = Exhaust flow from the gas turbine.
WGTI -h;

QGTI -- -Btu
hr = Rate of sensible heat in exhaust gas.
Gas turbine exhaust temperature i s the temperature at
which the enthalpy of the exhaust composition has the
- Btu = Enthalpy of exhaust gas at gas turbine above value.
hGl -
outlet temperature (determined by
paragraph 5.4.2.4 in conjunction with 4.6.3 Gas Turbine Inlet Scroll Method
Table 54.1 )
4.6.3.1 This method of exhaust flow measurement
- Btu = Enthalpy of exhaust may be utilized for gas turbines with calibrated inlet
GR -.--Ib
gas at reference scrolís provided there is agreement of the parties to the
temperature (determined by para- test.
graph 5.4.2.4 in conjunction with
Table 5.4.1) 4.6.3.1.1 The parties to the test shall be mutually
satisfied with the calibration procedure and facilities
utilized by the gas turbine manufacturer. They must fur-
4.6.2.1.5 Exhaust Gas Temperature Determination.
ther be satisfied that the gas turbine is in a state of clean-
The absolute enthalpy and the temperature of the gas tur-
liness which is acceptable for test purposes.
bine exhaust gas can be calculated from the gas turbine
heat balance of 4.6.2.1.3 if the exhaust gas flow is deter- 4.6.3.1.2 The exhaust flow is the sum of the inlet
mined by measurement. flow, fuel flow, and steam and/or water injection flows.
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 5 - COMPUTATION OF RESULTS

5.1 EFFICIENCY BY INPUT-OUTPUTMETHOD ment techniques and instrumentation are discussed in

further detail in Section 4.
5.1 .I Determination of Efficiency by Input-Output 5.1.3.1.1 Total Heat Input. The total heat available
Method. HRSG efficiency is defined by this method as a t the outlet of the gas turbine may be determined by means
the ratio of the heat output to the heat input. The heat
of a heat balance around the gas turbine. This method and
output i s the heat absorbed by the HRSG working fluids
the measurement methods to be employed are described
(steam and water). The total heat input is the sum of the
in Sections 4.6 and 4, respectively.
individual heat inputs (sensibleheat supplied by the exhaust
flow from the gas turbine, heat from the combustion of 5.1.3.1.2 Exhaust Flow and Temperature. The ex-
supplementary fuel, and total of heat credits). This method haust flow or temperature may be measured directly by a
requires accurate measurement of the heat input and traverse of the gas turbine exhaust duct (see Appendix 7.2
output quantities. Data resulting from these measurements for discussion), or indirectly by performing a heat balance
are used in the calculation procedure given in Section 5.4.2. around the gas turbine. The gas turbine heat balance may
be used to obtain the total exhaust heat available at the
5.1.2 Input Data inlet to the HRSG or may be used to determine exhaust
temperature (knowing exhaust flow), or exhaust flow
5.1.2.1 Accurate determination of the following data (knowing exhaust temperature). The gas turbine heat
is essential. balance method may also be used as a check of direct
5.1.2.1.1 Gas turbine exhaust flow and temperature measurement of exhaust temperature and/or flow. The
or total heat available from the gas turbine, measurement techniques for these methods are discussed
in Section 4 and the calculation procedures are discussed
5.1.2.1.2 Exhaust gas bypass flow. in Section 4.6. The exhaust flow may also be determined
5.1.2.1.3 Enthalpy of exhaust gas (including injec- indirectly by measuring the fuel and the inlet air flow to a
tion steam or water) a t HRSG inlet temperature and at gas turbine equipped with a calibrated inlet air scroll.
reference temperature, as determined by the incremental Further information concerning this method is given in
enthalpy calculation method for combustion products Section 4.6.
(see paragraph 5.4.2.4 for calculation procedure and data 5.1.3.1.3 Exhaust Bypass Flow. The exhaust gas
required). bypass flow shall be directly measured or an allowance
5.1.2.1.4 Gas turbine and supplementary fuel analy- made by agreement of the parties to the test.
ses and flow rates.
5.1.3.1.4 Fuel Inputs. Measurement methods for
5.1.2.1.5 Supplementary fuel lower heating value fuel input data including flow, analysis, and heating value
as obtained by laboratory analysis. of liquid and gaseous fuel are given in Section 4.
5.1.2.1.6 Heat credits for augmenting air, sensible 5.1 .3.1.5 Heat Credits. Heat credits are sensible
heat of supplementary fuel, externally supplied atomizing heat quantities added to the HRSG envelope, Fig. 1.1.
steam, HRSG gas recirculation, and auxiliary drives. The quantities of each are determined by a flow quantity
multiplied by an enthalpy difference, or by the conversion
5.1.2.1.7 Ambient conditions including tempera-
t o thermal units of an electrical energy measurement.
tures, relative humidity and barometric pressure.
5.1.4 Output Data
5.1.3 Input Measurement
5.1.3.1 The following paragraphs generally describe 5.1.4.1 Data Required. Accurate determinationof data
the methods of determining the HRSG input. Measure- i s essential. For an HRSG operating a t a single pressure

24
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

level with a reheat section and an extraction stage of super- calculation method for combustion products (see paragraph
heated or saturated steam for auxiliary service the required 5.4.2.4 for calculation procedure and data required).
data includes: flow rate, temperature and pressure o f
5.2.2.1.5 Supplementary fuel flow rate and lower
superheater outlet steam, reheat steam, saturated steam,
heating value.
desuperheating water, economizer output bypass, and
boiler blowdown. Other data may be required depending 5.2.2.2 Exhaust Flow and Temperature. The exhaust
on the HRSG configuration, additional pressure levels, flow or temperature may be measured directly by a traverse
auxiliary heating services, etc. of the gas turbine exhaust duct (see Appendix 7.2 for
discussion), or indirectly by performing a heat balance
5.1.5 Output Measurement around the gas turbine. The gas turbine heat balance may
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

be used to determine exhaust flow (knowing exhaust

5.1.5.1 Section 4 generally describes the measure- temperature). The gas turbine heat balance method may
ment for determining the HRSG output. The method of also be used as a check of direct measurements of exhaust
measuring output flow i s to measure each water flow into temperature and/or flow, The measurement techniques
the unit as outlined in paragraph 4.2.4. Output data deter- for these methods are discussed in Section 4 and the calcu-
mined by the methodsof Section 4 are used in the calcula- lation proceduresare discussed in Section 4.6. The exhaust
tion procedures given in Section 5.4. flow may also be determined indirectly by measuring the
fuel and the inlet air flow to a gas turbine equipped with a
calibrated inlet air scroll. Further information concerning
5.2 EFFICIENCY BY THERMAL-LOSS METHOD this method i s given in Section 4.6.

5.2.1 Determination of Efficiency by Thermal-Loss 5.3 PERFORMANCE BY EFFECTIVENESS METHOD

Method. The thermal loss method defines the steam
generator efficiency as 1O0 percent minus a quotient ex- 5.3.1 Determination of Performance by Effectiveness
pressed in percent. The quotient consists of the sum of all Method. This method defines HRSG performance as a
accountable losses as the numerator, and heat inputs as ratio of the actual enthalpy drop of gas through the HRSG
the denominator.This method requiresaccurate determina- (or sections of a multi-pressure HRSG) t o the maximum
tion of the exhaust gas enthalpy at the HRSG inlet and theoretically possible (MTP) enthalpy drop of the gas
stack, energy from supplementary fuel, heat credits, and through the corresponding section(s). The ratio isexpressed
heat losses. The influence of exhaust gas flow measure- as a percent. This method requires the accurate determina-
ment accuracy on the accuracy of efficiency determined tion of gas temperature a t the inlet to and outlet from the
by this method i s small because it appears in the largest HRSG or sections thereof, the temperature of the water
term in the numerator, stack gas loss, and the largest term and steam, and the water flow to and steam flow from the
in the denominator, sensible heat in the gas turbine ex- steam generator. The calculation procedure is given in
haust gas, which results in cancellation of i t s effect on the Section 5.4.4.
most significant terms. The calculation procedure i s
presented in Section 5.4.3. 5.3.2 Data Required for Unfired HRSG
The operating point a t which the HRSG i s to be
5.3.2.1 Accurate determination of the following data
tested should be based on output steam pressure and either
i s required for each applicable section:
water flow measurement or steam flow measurement in
accordance with Section 4. 5.3.2.1.I Gas turbine exhaust temperature and
enthalpy. (Calculation procedure for determining enthalpy
5.2.2 Data Required and Measurement Methods i s given in paragraph 5.4.2.4.)
5.3.2.1.2 HRSG outlet gas temperature and en-
5.2.2.1 Accurate determination or control of the
thalpy.
following data are required.
*5.3.2.1.3 Steam flow and enthalpy a t outlet of
5.2.2.1.I Gas turbine exhaust temperature.
HRSG.
5.2.2.1.2 HRSG gas temperature leaving unit.
"5.3.2.1.4 Water flow and enthalpy at HRSG inlet.
5.2.2.1.3 Exhaust gas bypass flow rate.
5.3.2.1.5 Steam pressure.
5.2,2.1.4 Enthalpy of gas a t HRSG inlet and outlet *Not required when section water flow equalssection steam flow.
temperatures, as determined by the incremental enthalpy For discussion see Appendix 7.4.

SECTION 5 ANSI/ASME PTC 4.4 - 1981

5.3.3 Data Required for Supplementary Fired HRSG HRSG and that ratio applied to the total temperature drop
in the H RSG.
5.3.3.1 In addition to the data required by Section
5.3.2, accurate determination of the following additional 5.3.4.3 Output Measurement. Paragraph 4.2.5 gener-
data i s required. ally describes the measurement for determining the HRCG
output. The method of measuring output flow i s to meas-
5.3.3.1.1 Supplementary fuel flow to the steam
ure each water flow into the unit. Output data determined
generator and lower heatingvalue as obtained by laboratory
by the methods of Section 4 are used in the calculation
analysis.
procedures given in Section 5.4.
5.3.4 Method of Measurement
5.4 CALCULATION PROCEDURES
5.3.4.1 Gas Turbine Exhaust Temperature. The gas
turbine exhaust temperature may be measured directly by
5.4.1 The following calculation procedures are for deter-
a traverse of the gas turbine exhaust duct or calculated by
mining the efficiency o f a gas turbine heat recovery steam
performing a heat balance around the gas turbine. The tur-
generating unit by both the Input-Output Method and the
bine heat balance method may also be used as a check of
Thermal-Loss Method for the actual operating conditions
direct measurementof exhaust temperature. The measure-
of the tests. Where a comparison is to be made between
ment techniques for these methodsare discussed in Section
test efficiency and a standard or guaranteed efficiency, ad-
4 and the calculation procedure is discussed in Section 4.6.
justments should be made in computations for deviation of
5.3.4.2 HRSG Gas Temperature. H RSG temperatures test conditions from the standard or guaranteed conditions
which cannot be accurately measured may be determined for certain heat credits and heat losses. The procedure for
by ratioing the heat absorbed by the working fluid of the such adjustments is as described under “Corrections to
section being tested to the total heat absorbed by the Guarantee Conditions,” paragraphs 5.4.5 to 5.4.8 inclusive.

EFFICIENCY BY INPUT-OUTPUT METHOD

5.4.2.1 7 7 =~ Percent
~ = Efficiency.

5.4.2.2 Output i s defined as the heat absorbed by the working fluid, or

Note 7: The preceding equation applies to a steam generator a t a single pressure level. Similar terms
should be added if the steam generator contains additional steam pressure levels such as intermediate
and low pressure boilers and low level economizers.
Note 2: For forced circulation steam generators, the following terms must be added for cooling water,
seal or injection water and leak-off flows for each circulating pump.

Note 3: Refer to Fig. 1.I and Table 1.1 for listing of numerical subscripts.
Where
5.4.2-2.1ws1OOi W s l O l , ws106 - Ib steam -- Superheater, auxiliary, and reheater steam flow rates.
~

wsl04 - Ib steam = Saturated steam (drum) flow rate.

26
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

- Economizer
- Ib water ~ - outlet bypass and boiler blowdown flow
Ww70, Ww71 hr rates.
- Ib water = Desuperheating water flow rate.
ww681 ww69 I-

-_
Ib _ _ = Coolant flow rate to circulating pump, injection flow rate
water
Ww41, Ww43 hr
ww441 WW57 to circulating pump, leak-off flow rate from circulating
pump, and miscellaneous coolant flow rate.

5.4.2.2.2 h s 1 0 0 , h s í 0 1 , -- Btu = Enthalpies of superheater, auxiliary, and reheater steam.

Ib steam
hsl06ihsl07

hsl04
- Btu
Ib steam
= Enthalpy of saturated steam at drum pressure.

hiv 6 8 t hiv6 9 --
c Btu = Enthalpies of desuperheating water.
Ib water

=-- Btu - Enthalpies of water at economizer outlet and inlet.

h i V 7 û ~h w 7 2 Ib water

hwlO4, hw41 I h 4 2 , = ~-Btu - Enthalpies of saturated water a t drum pressure, coolant

l b water
h w 4 3 , hrv441hrv571 into and from circulating pump, injection water to and
hrv5 8 leak-off from circulating pump, and miscellaneous cool-
ant into and from envelope.
Note: Enthalpies of steam and water are to be taken from the ASME Steam Tables, 1967 Edition.
5.4.2.3 Input is defined as the sensible heat in the exhaust gas supplied to the heat recovery steam generator
plus the chemical heat in the supplemental fuel, if applicable, plus the heat credits added to the working fluid, air,
gas and other fluid circuits which cross the envelope boundary. Refer to Fig. 1.1,
InPut=BGTó+B+ (Wf35,37 X h f 3 5 , 3 7 )
=F-
5.4.2.3.1 B G T ~ Btu - Sensible heat supplied by the external exhaust gas source above the reference tem-
perature, r ~ .

= (wGT1 - W B P 2 + W f 3 5 , 3 7 + W m F 3 3 + W z 3 6 ) ( h G 6 - h R G )
Where
lb = Exhaust gas flow rate at gas turbine outlet.
WGT~=

Note; See Section 4.6 for a method of determining gas turbine exhaust flow.

- Ib = Exhaust gas bypass flow rate.

WBP2 -

Ib
Wf35,37 = = Supplementary fuel flow rate.

Ib
WmF33 = = Augmenting air flow rate.

- Ib = Atomizing steam flow rate.

wz36 -

b ~ 6 -
- -Btu
- - Enthalpy of entering exhaust gas at inlet temperature tG6.
Ib

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Note: See paragraph 5.4.2.4 for the method o f calculating exhaust gas enthalpies based upon the
incremental enthalpy of combust¡on products.
Btu -
hRG -- -- Enthalpy of exhaust gas a t reference temperature t R (determined by paragraph
Ib
5.4.2.4 in conjunction with Table 5.4.1).
Where

tR = OF = Reference temperature. This i s the base temperature at a given pressure to

which sensible heat losses and credits are compared for efficiency calcula-
tions.
5.4.2.3.2 -
Btu - Total o f heat credits determined from the summation of the amounts of heat
hr
added to the envelope of the steam generator other than the chemical heat
in supplementary fired fuel.
B BmA33 +Bf35,37 +Bz36 ' B G R 2 2 +Bx

- Btu
5.4.2.3.3 B m ~ 3 3 - -= Heat credit supplied by moist augmenting air for supplementary firing.
hr

= WmA33 (hmA33 - h R m A )
Where
Ib
W m 3~3 = E = Augmenting air flow rate.

- Btu - Enthalpy of moist air

hmA33 - TIb at inlet temperature t m A 3 3 (determined by paragraph
5.4.2.4 in conjunction with Table 5.4.1).

hRmA
- Btu
- r-Enthalpy
- of moist air at reference temperature
5.4.2.4 in conjunction with Table 5.4.1).
tR (determined by paragraph

Btu
5.4.2.3.4 Bf35,37 = T= Heat credit supplied by sensible heat in supplementary fuel.

= wf35,37 x cpf ( t f 3 5 , 3 7 - t R )
Where
Ib
Wf35,37 = = Supplementary fuel flow rate.

---=Btu
Cpf Mean specific heat of fuel. See Fig. 4 for fuel oil, Fig. 5 for gas as published in
IbO F
P I C 4.1. It i s determined from the instantaneous values over the range be-
tween fuel inlet temperature and the reference temperature. (Refer to PTC
3.3, Gaseous Fuels, for alternate method of determining enthalpy of gaseous
fuels.)
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

If liquid fuel is heated by a source external to the unit being tested, the inlet temperature shall be
measured downstream of this heater. If oil is heated directly from the unit being tested, tempera-
ture shall be measured upstream of the heater.
tf35,37 = OF = Supplementary fuel inlet temperature.

tR = OF = Reference temperature.

5.4.2.3.5 Bz36
- -
- Btu - Heat credit supplied by atomizing steam for supplementary firing when source
hr
is external to the unit being tested.

ANSI/ASME PTC 4.4 - 1981 SECTION 5

= Wz36 (hz36 -hi'/?)

Where

Wz36
-- hr
Ib
= Atomizing steam flow rate.

hz36
-- Btu
-- - Enthalpy of atomizing steam at temperature, t z 3 6 .
Ib

hzR -- -Btu
--
Ib
Enthalpy of atomizing steam at reference temperature, t R .
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

5.4.2.3.6 B G R =~ ~ = Heat credit supplied by gas recirculation.

= WGR22 (hG22 - h R G )

Where
Ib
" ~ 2 h
~ = r2 = Recirculated gas flow rate.

h ~ 2 2
-- Btu
-= Enthalpy of exhaust gas at recirculation temperature, t G 2 2 (determined by
Ib
paragraph 5.4.2.4 in conjunction with Table 5.4.1).

hRG
-- -Btu- - Enthalpy of exhaust gas a t reference temperature, t R (determined by para-
Ib
graph 5.4.2.4 in conjunction with Table 5.4.1).

5.4.2.3.7Bx - Btu
i-= Heat credit supplied by auxiliary drives within the envelope.
hr
= Wsx (hsx - h j x ) 77x1100%
Where

-- -Ib - Steam flow rate.

WSX hr

hsx -
--Btu - Enthalpy of the steam supplied to drive the auxiliaries.
Ib

Btu
= -= Enthalpy a t the exhaust pressure and initial entropy of steam supplied to
hix Ib
drive the auxiliaries.

7)X
= Percent = Overall drive efficiency; includes turbine and gear efficiency.
For electric auxiliaries, the heat supplied i s as follows:

BX = 3412.1 4 (kWh) v X / 100%

7)X = Percent = Overall drive efficiency; includes such items as motor efficiency, electric
and hydraulic coupling efficiency and gear efficiency.
Ib
5.4.2.3.8 W f 3 5 , 3 7 = h; = Supplementary fuel flow rate.

If solid or liquid fuels are used, the flow rate is determined by direct measurement.

If gaseous fuel is used, the measured volumetric flow rate must be converted to a weight basis as
follows:

A S I E P T C * q - 4 83 = 0759b70
~ 0054352 3 ~~ ~ -
ANSIIASME PTC 4.4 - 1981

Wf35 = Vf35 x Yf
Where

- ft3 = Volumetric flow rate of gaseous fuel fired.

Vf35 - -hr

= - Ib = Fuel gas specific weight a t the primary measuring element and fuel inlet tem-
Yf
ft3
perature.
Btu
5.4.2.3.9 hf35,37 = -= Lower heating value of supplementary fuel as obtained by laboratory
Ibfuel
analysis and adjusted to an “as fired” basis from laboratory determina-
tion of moisture in the fuel.
Note: Additional heat credits may be added if necessary for special or unusual t e s t conditions.
These could include such factors as sensible heat in the flue dust and unburned carbon, hydrogen,
hydrocarbons and carbon monoxide in the exhaust gas entering the steam generator.

5.4.2.4 Incremental enthalpy method for determining the enthalpy of combustion products, dry air and moist air.

Where
Ib = Weight ratio of dry air component.
WA =
Ib exhaust gas
Ib = Weight ratio of carbon in fuel components.
wc =
Ib exhaust gas

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Ib = Weight ratio of carbon dioxide in fuel components.

WD =
Ib exhaust gas
- Ib
= Weight ratio of dry air (base = 1.O Ib) = 1.O.
WdA - Ib dry air
lb = Weight ratio of total fuel.
WF =
Ib exhaust gas
Ib
Wf = = Weight ratio of supplementary fuel component.
Ib dry air
Ib
WfG = Ib dry air = Weight ratio of gas turbine fuel.

Ib = Weight ratio of hydrogen in fuel components.

WH =
Ib exhaust gas

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
Ib
WM = = Weight ratio of carbon monoxide in fuel components.
Ib exhaust gas
Ib = Weight ratio of moisture in fuel components.
Wm =
Ib exhaust gas

- lb
= Weight ratio of moisture in ambient air as determined from a psychro-
Wm
A -ibdryr
metric chart for the test conditions of ambient dry bulb temperature
and relative humidity. Excluded is moisture addition from evaporative
coolers, if utilized.
Ib = Weight ratio of steam or water injection, atomizing steam and moisture
wmJe = v r
from evaporative coolers, if utilized, for supplemental burner(s).
lb = Weight ratio of nitrogen in fuel components.
WN =
lb exhaust gas
Ib
wo = = Weight ratio of oxygen in fuel components.
Ib exhaust gas
Ib
ws = = Weight ratio of sulfur in fuel components.
Ib exhaust gas
Ib exhaust gas
rvy = = Total weight ratio of exhaust gasmixture (includingsupplementaryfiring).
Ib dry air
Ib
wu = = Weight ratio of sulfur dioxide in fuel components,
Ib exhaust gas
Ibfuel
FGA - Ib moist air
= Gas turbine fuel-to-inlet air ratio (air entering evaporative coolers, if
utilized).

- Ib fuel
FSG = Supplementary firing fuel-to-exhaustgas (gas turbine outlet) ratio.
Ib exhaust gas
PC = Percent Weight ratio of carbon in fuel.
PD = Percent Weight ratio of carbon dioxide in fuel.
PH = Percent Weight ratio of hydrogen in fuel.
PM = Percent Weight ratio of carbon monoxide in fuel.
PN = Percent Weight ratio of nitrogen in fuel.
PO = Percent Weight ratio of oxygen in fuel.
Ps = Percent Weight ratio of sulfur in fuel.
Pu = Percent Weight ratio of sulfur dioxide in fuel.

SECTION 5 ANSIIASME PTC 4.4 - 1981

Btu
- = Enthalpy of dry air component.
hA - Ib exhaust gas
Btu
hc
-- Ib exhaust gas
= Enthalpy of carbon component.

- Btu = Enthalpy of carbon dioxide component.

hD - Ib exhaust gas
- Btu
= Summation of components for turbine total exhaust gas enthalpy.
hG - Ib exhaust gas
Btu
hH = = Enthalpy of hydrogen component.
Ib exhaust gas
Btu
hm -- = Enthalpy of moisture component.
Ib exhaust gas
Btu
- = Enthalpy of carbon monoxide component.
hM - Ib exhaust gas
Btu
hN -- I b exhaust gas = Enthalpy of nitrogen component.
Btu
ho -- = Enthalpy of oxygen component.
Ib exhaust gas
- Btu
= Enthalpy of sulfur component.
hs - Ib exhaust gas
Btu
hU -- Ib exhaust gas = Enthalpy of sulfur dioxide component.

- Btu = Ideal gas enthalpy of dry air from Table 5.4.1.

AIA - -Ib
- Btu = Incremental enthalpy of carbon from Table 5.4.1.
hlC - -
Ib
- Btu = Ideal gas enthalpy o f carbon dioxide from Table 5.4.1.
hlD --Ib
- Btu = Incremental enthatpy of hydrogen from Table 5.4.1.
hlH --Ib
- Btu = Ideal gas enthalpy of carbon monoxide from Table 5.4.1.
hlM - -
Ib
- Btu = Ideal gas enthalpy of moisture from Table 5.4.1.
him - -
Ib
- Btu = Ideal gas enthalpy of nitrogen from Table 5.4.1.
hlN - Ib
- Btu = Ideal gas enthalpy of oxygen from Table 5.4.1,
hl0 - -
Ib
- Btu
hlS - Ib - = Incremental enthalpy of sulfur from Table 5.4.1.

Btu
hlu =
Ib
- = Ideal gas enthalpy of sulfur dioxide from Table 5.4.1.

A computer program to determine gas turbine exhaust gas enthalpy i s described in the Appendix.
Note: For cases when different fuels are utilized for gas turbine and supplementary firing, the incre-
mental enthalpies for both fuels must be determined and applied.
If other components are present in the fuel, the incremental enthalpies for these components must be
determined and applied.

32
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ANSIIASME PTC 4.4 - 1981 SECTION 5

EFFICIENCY BY THERMAL-LOSS METHOD

5.4.3

Derivation of equation is as follows:

VSG
- -Output x 100%
Input
Where

VSG = Percent = efficiency.

output = input- Losses ( L )

x hf35,37)

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
Input = B G T 6 + B + (wF35,37
Thus,

QSG

5.4.3.1 L - -Btu
- - Total heat losses from the steam generator.
hr

= LG19 +Lß+Lw41,43 'Lw57,58

5.4.3.1 .I L G19 --
- Btu = Heat loss in moist exhaust gas
hr

LGî 9 = (wGT1 4- wf35,37 wmF33 + wz36 - w B P 2 ) (hG19 - h R G )

Where

WGTI - -Ib
I = Rate of gas turbine exhaust gas flow.
hr
N o t e : See Section 4.6 for a method of determining gas turbine exhaust flow rate.

Wf35,37 = -
Ib = Supplementary fuel flow rate.
hr

WmF33 = -
Ib = Augmenting air flow rate.
hr

- -Ib = Atomizing steam flow rate.

wz36 hr

- -Ib = HRSG gas bypass flow rate.

wBP2 hr
- -Btu = Enthalpy of HRSG gas a t stack temperature] f G 1 9 .
hG19 Ib
Note: See paragraph 5.4.2.4 for the method of calculating enthalpy based on the incremental
enthalpy o f combustion products.

- -Btu = Enthalpy of exhaust gas at reference temperature] t R (determined by

~ R G Ib
paragraph 5.4.2.4 in conjunction with Table 5.4.1).

SECTION 5 ANCIIACME PTC 4.4 - 1981

5.4.3.1.2 Lp - -Btu = Heat loss due to surface radiation and convection.

= SB ( L R + Lc)
Where

SB = ft2 = Area of surface through which heat loss occurs.

LR
=--
ft2-hr
- Radiant heat loss as determined from Fig. 4.1 and Table 4.1 as func-
tion of ambient temperature, surface temperature and surface emis-
sivity.

Lc
= - - Btu - Convective heat loss as determined from Fig. 4.2 as a function of tem-
ft2-hr
perature difference and air velocity.
Btu
-- - = Heat loss in the circulating pump cooling water and seal water leaving
5.4.3.1.3 Lw41,43
hr
the envelope.
= ww41 (hw42 - h w 4 1 ) +- w w 4 4 (hw44 - h w 4 3 )
where
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

- -Ib = Cooling water flow rate.

ww41 hr
---Ib = Seal water leak-off flow rate.
w w 44 hr

hw41 t o 4 4 = Btu = Enthalpies of water at the corresponding temperatures tw41 t o 44.

5.4.3.1.4 L,u57,58 = Btu/hr = Heat loss in miscellaneous coolant.

= w w 5 7 (hw58 - h r v 5 7 )
Where

-_ - Ib = Cooling water flow rate.

ww57 hr
- Btu
hw57,58 - -Ib = Enthalpies of water corresponding to temperatures, t,v57 and t w 5 8 .

Note 1: The preceding equation applies to a single pressure levet steam generator. Similar terms
should be added if the steam generator contains additional pressure levels and circulating pumps.
Note 2: Additional heat losses may be added if necessary for special or unusual test conditions.
These could include, but are not limited to, sensible heat in the flue dust and unburned carbon,
hydrogen, hydrocarbons and carbon monoxide in the exhaust gas leaving the steam generator.

5.4.3.2 BGT6
_ - Btu
-
hr = Sensible heat supplied by the exhaust gas source (see paragraph
5.4.2.3.1 ).

5.4.3.2.1 B = -Btu = Total heat credits from the summation of heat added to the envelope
hr
other than the chemical heat in supplementary fired fuel.

= B ~ 33A+ Bf35,37 + B I 3 6 + BGR22 + B x

(Refer to paragraphs 5.4.2.3.2 to 5.4.2.3.7 for derivation of these terms.)

5.4.3.2.2 Wf35,37 = h
Ib ; = Supplementary fuel flow rate. (See paragraph 5.4.2.3.8.)

5.4.3.2.3 hf35,37 -
= Btu = Lower heating value of supplementary fuel. (See paragraph 5.4.2.3.9.)
Ib

Note: Additional heat credits may be added if necessary for special or unusual test conditions.
These could include but are not limited to such factors as sensible heat in the flue dust and un-
burned carbon, hydrogen, hydrocarbons and carbon monoxide in the exhaust gas entering the
steam generator.

EFFECTIVENESS METHOD

5.4.4 Effectiveness may be used to evaluate complete boilers or sections of boilers, For example, the effective-
ness of different pressure levels of multiple pressure boilers may be evaluated separately.
Cases need to be considered when the temperature pinch occurs where gas leaves the evaporator (evaporator
pinch) and where the gas leaves the economizer (economizer pinch).
Unfired HRSG will generally have an evaporator pinch and boilers fired to more than 30 percent of the heat
input will generally have an economizer pinch. When the pinch location is in doubt effectiveness should be calcu-
lated for both evaporator and economizer pinches. The correct expression will yield the higher effectiveness value.
Actual enthalpy change of the exhaust gas
EF =
MTP enthalpy change of the exhaust gas
x 100%

Where
EF = Effectiveness, percent.
MTP = Maximum theoretically possible.

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
5.4.4.1 HRSG Temperature Profile - Evaporator Pinch

temperature line

SECTION 5 ANSI/ASME PTC 4.4 - 1981

5.4.4.2 HRSG Temperature Profile - Economizer Pinch

1 2

E
4-
2 s temperature line

f
E
Pinch
-O point
+ww

5.4.4.3 Effectiveness Expression - Evaporator Pinch

Where possible a test for effectiveness should be performed with W s l = W w 3 when the expression simplifies to:

5.4.4.4 Effectiveness Expression - Economizer Pinch

5.4.4.5 Definitions of Terms for 5.4.4.3and 5.4.4.4

wsl = -Ib- - Steam flow rate.

ww3
= - Ib - Water flow rate.
hr
-
hG1 Btu - Enthalpy
- -- of HRSG gas at inlet temperature, t ~ (determined
1 by paragraph
Ib
5.4.2.4 and Table 5.4.1).

h ~ 4
-- --
Btu - Enthalpy of HRSG gas at outlet temperature, t G 4 (determined by paragraph
Ib
5.4.2.4 and Table 5.4.1).

36
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

= 3Ib = Enthalpy of HRSG gas at a temperature equal to the saturated steam temper-
h ~ ~
ature, ts2 in the boiler drum (determined by paragraph 5.4.2.4 and Table
5.4.1 ).
hGw4 = --
Ib
- Enthalpy of HRSG gas at temperature of the water entering the economizer,
tw4.

hsl = E=
Ib
Enthalpy of superheated steam at outlet temperature] t,l.

hw2 -- * Ib
= Enthalpy o f water a t saturated steam temperature, t s 2 .

hw4 = -Btu
- - Enthalpy of water at inlet temperature] t w 4 .
Ib

5.4.5 Gas turbine performance and exhaust conditions vary *significantly with changes in ambient conditions.
Variations resulting from small manufacturing differences between substantially identical turbines is also possible.
Consequently, testing an HRSG at the exact turbine exhaust conditions upon which the boiler guarantees were
developed may not be possible.

5.4.6 Correction to guarantee conditions shall be made using performance data or curves prepared and furnished
by the HRSG manufacturer prior t o any test. Correction curves or data shall define the variation of all parameters
pertinent to the test as a function o f gas turbine exhaust mass flow, temperature and exhaust gas enthalpy (or
percent moisture content). Parameters pertinent to the test would include steam flows, enthalpies, stack tempera-
ture, boiler efficiency, etc.

5.4.7 A step-by-step method of correcting test data shall be prepared by the HRSG manufacturer. The user shall
review this procedure and any questions shall be resolved prior to the start o f the tests.

Copyright ASME International

Provided by IHS under license with ASME
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

,y--
-
Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
23:56:18 MST Questions or comments about this message: please call the Document
Policy Group at 303-397-2295.
SECTION 5
ANSI/ASME PTC 4.4 - 1981
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Copyright ASME International Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
Provided by IHS under license with ASME 23:56:18 MST Questions or comments about this message: please call the Document
Policy Group at 303-397-2295.
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
ANSIIASME PTC 4.4 - 1981 SECTION 5

SECTION 5 ANCIIASME PTC 4.4 - 1981

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

- 1981
ASME PTCm4.4 A3
~
- 0757670 0054363 B - SECTION 5

t m c v w m m m o w o m - t w m wo00 o w m o m m t c u m ~ w -m r-- w c v m T I - ~ - W W N W r - W Nb m r -
q q t ? qc;O m w w m m - m r - t m a r - t o r - t o w mm m t m t m m r - 7 ~ 1C
---
- t0 t~w m m o -
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

- O r -
W N W o t m :=vid & & : = & & & G c i & &rl.a',&d o ; & d ci&d o & < O & < d & & 8 4 < ò & G ci&d
m m t t m m m w w wr-r- r-mm m m m o00
r-woo m m m o 0 0 - - r i ~ c l m NNN mmm m v t
mmm mmm www www www www www www www www www r-r-r- r-r-r- r-r-r- r-r-r- r-r-r-

P
er
8
U
v

7
2
w
-I
m
U
I-

w r - r - r-r-r- m m m m m m m m m m o o o 0 0
N N N FINN N N N N N N N N N
---
8 8 8 80'8 8 8 8 8 0 0 0 8 8 0'88 8 8 8 O 8 8 0 8 0 8 8 8 8 8 0 9 8 0 0 8 6 8 8 8 d 0 8 8 8 ó
W O N t w w O N 9 w m o N t W W O N t w m O N * w m o N t W W O N t w m O N 9 w w o N t W W O N
--ci N N N c r m m m m m t t t t a m m m m m w w
mm m m m m m m m m m m m m m m m m m m m m m m m m m m m m m m

SECTION 5 ANSI/ASME PTC 4.4 - 1981

I N N N N - om03
cicim c i m o vir-w
. r - m r - m r - -vio w a - m w m m v i - r-
-
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

O W - -r-m a w m v i m m N ~ C tr I--mmm co
-vim O W N mmm N W c i~ w w

SECTION 6 - REPORT OF RESULTS

6.1 The report shall be a document prepared in suit- 6.1.4.6 Summary of measurements and observations.
able form to present formally and clearly the observed
6.1.4.7 Methods of calculation from observed data
data and calculations. Sufficient information shall be
and agreements as to precision and accuracy.
presented to demonstrate that all objectives of the test
have been met. The test report should include in the 6.1.4.8 Correction factors to be applied because of
order given the distinctive parts outlined in the follow- deviations of test conditions from those specified.
ing paragraphs.

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
6.1.4.9 Specified or agreed allowances for possible
error, including method of application.
6.1.1 The title page should present the following in-
formation: report number (optional); date(s) of test;
6.1.4.10 Test performance reported under the follow-
t i t l e of test; location of test; owner or purchaser; manu-
facturers name; H RSG designation and identification; ing headings :
principals conducting and witnessing the test; principals 6.1.4.10.1 Test results computed on the basis of
preparing and approving the test report; and the date of the test operating conditions.
the report.
6.1.4.1 0.2 Test results corrected to specified
6.1.2 The table of contents should l i s t the major sub- conditions if test operation conditions have deviated
divisions of the report. from those specified.
6.1.4.10.3 Statement that foregoing results are
6.1.3 A brief summary should present the objects, believed correct within a stated tolerance.
results and conclusions of the test.
6.1.4.1 1 Tabular and graphical presentation of the
test results.
6.1.4 The detailed report should include the following:
6.1.4.12 Discussion of the tests, results and conclu-
6.1.4.1 Authorization for the test, its objects, guar-
sions.
antees, stipulated agreements, by whom the test was
directed, the representative parties to the test. 6.1.4.13 Log and data sheets.
6.1.4.2 Description including nameplate data of the 6.1.4.14 Observers and their affiliations.
equipment being tested and any other auxiliary apparatus,
the Operation of which may influence the test.
6.1.4.3 A line diagram indicating the cycle mechanical 6.1.5 Appendices and illustrations to clarify descrip-
and thermal arrangements. tion of the equipment and method and circumstance of
test, description of methods of calibration of instruments,
6.1.4.4 A brief history of the operation of the HRSG outline of details of calculations, descriptions and state-
since initial start-up,
ments as to special testing apparatus, result of preliminary
6.1.4.5 Method of test, giving arrangement o f testing inspections and trials and any other supporting informa-
equipment, instruments used and their location, operat- tion shall be included as required to make the report a
ing conditions and complete description of methods of complete self-contained document of the entire under-
measurement not prescribed by this Code. taking.

SECTION 7 - APPENDIX

7.1 GUIDANCE IN SELECTION OF TEST METHOD 7.1.2 General. Figure 7.1.1 compares the Overall Test
Uncertainty associated with the three t e s t methods in this
7.1.1 Evaluation Procedure, In order to compare test Code. This comparison is shown in curve form for all com-
methods and/or the various designs for a given method, a binations o f heat input from waste heat gas (sensible
unique value of merit for a t e s t is required. The value o f energy) and fuel fired in the HRCG (chemical energy). All
merit selected for this analysis is the “Overall Test Uncer- HRSGs considered in this analysis have an identical quan-
tainty.” The definition o f uncertainty and the procedure tity of energy supplied from the gas turbine exhaust. Ox-
for combining individual measurement uncertainties, used ygen required for fuel firing in the HRSG is supplied in
in this code, is given in ASME PTC 6 REPORT - 1969. the gas turbine exhaust.

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

O 20 40 60 80 1 O0

Heat input from supplemental fuel

firing, % of maximum

I I I I I
16 12 8 4 O

Stackgac oxygen content, %by weight

FIG. 7.1.1 COMPARATIVE TEST UNCERTAINTY FOR EFFICIENCY

AND EFFECTIVENESS DETERMINATION

TABLE 7.1 .I
Individual Measurement
Uncertainties and Resulting Overall Test Uncertainty

Input-Output Method
~~

Measurement Overall Test Uncertainty

Measurement Uncertainty for HRSG Efficiency (k %)
(+I
Energy input from HRSG firing (% of max) 0.0 6.0 18.0 36.4 69.8 100.0
Oxygen content in HRSG stack gas (% wt) 16 15 13 IO 5 O
1. HRSG fuel flow 0.55% - 0.1 1 0,23 0.33 0.40 0.44
2. Fuel heatlng value-LHV 0.47% - 0.09 0.20 0.28 0.35 0.38
3. Feedwater flow 0.55% 0.55 0.55 0.55 0.55 0.55 0.55
4. Feedwater temperature 0.50% 0.1 o 0.1 o 0.1 o 0.1 o 0.10 0.10
5. Superheater outlet temperature 0.50% 0.1 9 0.1 9 0.1 9 0.1 9 0.19 0.19
6. Superheater outlet pressure 0.50% 0.01 0.01 0.01 0.01 0.01 0.01
7. Gas turbine exhaust temperature 1OoF 1.20 0.97 0.70 0.49 0.32 0.24
8. Gas turbine exhaust flow L

Code meter 1 .OO%

Gas turbine heat balance 3.00% 2.91 2.36 1.70 1.20 0.78 0.59
Duct traverse 5.00%
Overall test uncertainty -+ 3.20 2.62 1.95 1.49 1.16 1 .O5

TABLE 7.1.2
Individual Measurement
Uncertainties and Resulting Overall Test uncertainty

Thermal-Loss Method

Measurement Overall Test Uncertainty

Measurement Uncertainty for H RSG Efficiency (c %)
(+I
Energy input from HRSG firing (%of max) 0.0 6.0 18.0 36.4 69.8 100.0
Oxygen content i n HRSG stack gas (% wt) 16 15 13 10 5 O
1. Ambient air temperature 3' F 0.55 0.43 0.29 0.1 9 0.1 1 0.08
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

2. HRSG fuel flow 0.55% 0.00 0.07 0.1 2 0.1 3 0.1o 0.05
3. Fuel heating value-LHV 0.47% 0.00 0.06 0.1 o 0.1 1 0.08 0.04
4. HRSG exit gas temperature IO'F 1.95 1.51 1 .O4 0.70 0.41 0.28
5. Radiation and convection losses 20.0% 0.20 0.1 6 0.1 1 0.07 0.04 0.03
6. Gas turbine exhaust temperature 10°F 0.80 0.60 0.36 0.20 0.07 0.03
7. Gas turbine exhaust flow -
Code meter 1 .O%
Gas turbine heat balance 3.0% 0.03 0.33 0.63 0.71 0.51 0.26
Duct traverse 5.0%
Overall test uncertainty t. 2.1 9 1.72 1.31 1 .O5 0.68 0.40

SECTION 7 ANSIIASME PTC 4.4 - 1981

TABLE 7.1.3
Individual Measurement
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Uncertainties and Resulting Overall Test Uncertainty

Effectiveness

Measurement Overall Test Uncertainty

Measurement Uncertainty for HRSG Efficiency (*%)
(It)
Energy input from HRSG firing ( % o f max) 0.0 6.0 18.0 36.4 69.8 100.0
Oxygen content in H RSG stack gas (% wt) 16 15 13 10 5 O

1. Feedwater flow 0.55% 0.00 0.00 0.00 0.00 0.00 0.00

2. Feedwater temperature 0.50% 0.1 o 0.1 o 0.1 o 0.1 o 0.10 0.10
3. Superheater outlet pressure 0.50% 0.00 0.00 0.00 0.00 0.00 0.00
4. Superheater outlet temperature 0.50% 0.06 0.06 0.00 0.00 0.00 0.00
5. Drum pressure 0.50% 0.05 0.02 0.00 0.00 0.00 0.00
6. HRSG entering gas temperature 1.00% 0.39 0.07 0.1 2 0.1 8 0.09 0.07
7. HRSG exist gas temperature 1O" F 1.93 1.51 1 .o5 0.73 0.43 0.31
8. Gas turbine exhaust flow -
Code meter 1.OO%
Gas turbine heat balance 3.00% 0.00 0.00 0.00 0.00 0.00 0.00
Duct traverse 5.00%
Overall test uncertainty It 1.97 1.52 1.O6 0.76 0.46 0.33

TABLE 7.1.4
Sensitive Individual Measurements Required for Each Test Method
Tables 7.1 .I, 7.1.2, and 7.1.3 display the sensitivity of Method
Measurement
the Overall Test Uncertainty to the individual measure-
Efficiency Efficiency
ment uncertainties for the three t e s t methods in this Code. by Input- by Thermal-
The individual measurement uncertainties shown are not output Loss Effectiveness
intended to be authoritative but conform approximately
Flows
with experience for the best available measurement pro- Feedwater e
cedures. For more intricate HRSGs than the example Steam
chosen, additional measurements will be required and Turbine exhaust e O
Fuel to H RSG O O
their uncertainties included in the overall analysis.
Temperatures
Table 7.1.4 tabulates all the measurements required to e e e
Gas entering tubes
use any or all o f the test methods covered in this Code for Gas leaving tubes e e
the example chosen. For each test method the individual Feedwater e O

measurements that affect the Overall Test Uncertainty by Superheated steam

outlet e O
more than 0.02 percent for a 1 percent uncertainty in the Ambient air O O
individual measurement are marked with the symbol 0. Pressures
Table 7.1.5 contains the HRSG design data used for Drum e
Economizer inlet O O
calculating the uncertainty sensitivities in this appendix.
Superheater outlet O O
Others
7.1.3 Corrections for Off Design Site Conditions. Gas tur- O
Fuel heating value O
bine flow and exhaust temperature vary substantially Radiation and con-
with ambient conditions. Since it may not be possible to vection losses O

closely duplicate design operating conditions (primarily

Notes
due to ambient) during the test period corrections for off- 1. Used 5.98 percent supplemental HRSG firing for above
design conditions are required. The magnitude o f the cor- calculations.
rection varies with the t e s t method used. In general the 2. Table is for the simple example shown in Table 7.1.5 with
no blowdown or other energy streams entering or leaving
Input-Output method requires the largest performance cor- the HRSG boundaries.
rection factors for off design conditions and the Effective- 3. The symbol oindicates the values that must be measured to
ness method the smallest corrections. The Thermal-Loss use the particular fest method.
4. The symbol *indicates that the Overall Test Uncertainty is
method requires corrections for off-design conditions only affected by more than 0.02 percent for a 1 percent uncer-
slightly larger than the Effectiveness method. tainty in the individual measurement.

TABLE 7.1.5
Heat Recoverv Steam Generator Designs

superheated steam flow Ib/hr 184666 233931 342608 502449 893083 1,275,420
Economizer outlet water temp. OF 480 480 470 460 450 450
Gas flow through HRSG Ib/hr 1,668,125 1,672,947 1,682,676 1,697,482 1,724,423 1,748,776
Fuel energy fired in HRSG-LHV 1 O6 Btu/hr 0.00 90.1 2 271.93 548.64 1052.1 2 1507.20
f‘uel energy - 9ó of maximum % 0.00 5.98 18.04 36.40 69.81 100.00
Gas temp. entering superheater OF 925 1112 1464 1949 2720 3283
Gas temp. entering evaporator O F 835 1 O00 1309 1699 2371 281 3
Gas temp entering economizer OF 522 61 3 758 920 1069 1046
Gas temp. entering stack O F 41 1 474 569 667 658 466
HRSG Exhaust Gas Analysis
Oxygen %wt 16.00 15.00 13.00 10.00 5 .O0 0.00
Carbon dioxide %wt 5.89 6.81 8.65 1 1.42 16.01 20.62
Nitrogen %wt 71.81 71.66 71.34 70.87 70.1 1 69.32
Water vapor %wt 5.O4 5.27 5.74 6.44 7.61 8.78
Sulfur dioxide %wt 0.01 0.01 0.02 0.02 0.03 0.04
Other inerts %wt 1.25 1.25 1.25 1.25 1.24 1.24

Notes
1. HRSG Efficiency was assumed to vary linearly from 60 percent to 90 percent with firing rate from unfired (16 percent O,) to
fully fired (O percent O z ) ,
2. The following parameters were held constant for all designs:
(a) Ambient temperature 59OF (9) Casing surface area 24000 ft2
(b) Compressor inlet temperature 59’ F (h) Surface temperature 134’F
(c) Superheater outlet temperature 825OF (i) Ambient air velocity 10 fps
(d) Superheater outlet pressure 600 psig (i) Emissivity 0.9
(e) Feedwater temperature 240’ F (k) No. 2 oil fuel-LHV 18688 Btu/lb
(f) H.P. drum pressure 660 psig (I) Water injection to turbine Yes

7.2 GAS FLOW MEASUREMENT

erse plane shall be free of internal obstructions, a t least
7.2.1 Guiding Principles for Flow Measurement. Many eight equivalent diameters* downstream, and a t least
situations arise in which gas flow measurements must be two equivalent diameters upstream of any bends, cross-
made under field conditions. Of the many problems test- sectional changes, or tees (branches). A t least 75 per-
ing in place introduces is the fact that it is often not pos- cent o f the traverse points shall indicate a velocity pres-
sible to find a test plane where the flow i s closely uniform sure a t or above 1.O in H 2 0 in order to minimize observer
and parallel to the duct walls nor to provide methods of averaging errors due to fluctuation. It i s recognized that
“conditioning” the flow to such a state. Seldom is one seldom can such a traverse plane be found in field
able to find an undisturbed run o f several equivalent installations,
diameters or to insert flow straighteners. Lacking these
7.2.2.2 Non-permissible Traverse Plane. Traverse
options, measurements must be made in regions of non-
planes which exhibit any of the following shall not be
uniform flow,
used: (1) Planes less than one equivalent diameter down-
For large ducts, the most practical and indeed often
stream of major obstructions, (2) Planes exhibiting re-
the only method i s the velocity traverse method. In this
verse flow, (3) Planes exhibiting vena contracta or separ-
method, a suitable probe i s inserted into the duct and the
ated flow.
velocity is measured a t a number of points. The (volume)
rate of gas flow is the integral o f the product of an ele- 7.2.2.3 Guidelines for Selection of Non-optimum
mental area and the velocity normal to this area over the Traverse Planes. In general, a traverse should be made
duct cross section. In practice, it i s customary to calcu- where the flow velocities are as large as practicable, The
late the integral as the product of an “average” velocity probe types specified in this Code shall be capable of
and the total cross-sectional area. The average velocity indicating the flow misalignment in a plane; therefore care
must represent only that component normal to the duct shall be taken to insure that the major angle of misalign-
cross section.
*Equivalent diameter = 4 x Hydraulic radius
7.2.2 Selection of Traverse Plane
Cross-sectional area
7.2.2.1 Optimum Traverse Plane. The optimum trav- =4x
Wetted perimeter

47
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Choose probe orientation with respect to flow stream such that e >> $,
and 0 lies in the xy-plane which i s perpendicular t o the probe axis.
V = Total velocity vector
V, = Velocity vector in xdirection and normal to traverse plane
= Velocity vector in ydirection and parallel to traverse plane
Vy
Vz = Velocity vector in zdirection and parallel to traverse plane
e = Yawangle
$ = Pitch angle

FIG. 7.2.1

Preferred traverse

'I
-
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
ports when A = B

Flow
q3f
L
Flow

1' Preferred traverse

ports when B > A
f Preferred traverse
ports when A > B

- Flow

Preferred traverse
ports
FIG. 7.2.2 PREFERRED TRAVERSE PORTS

ment lies in a plane perpendicular to the probe (Fig. Then the corresponding centroidal axis diameter i s
7.2.1). The following are suggestions for selecting a trav-
erse plane in certain instances.
7.2.2.3.1 Reducing Transitions. Velocity measure-
And the distance of the centroidal axis of the cir-
ments should be taken a t the outlet of area-reducing
cular ring from the duct wall (interior) i s then
transitions. Flow direction will be more uniform and have
a higher velocity due to the reduction of cross-sectional
area. Note that care must be taken to avoid regions of
vena contracta or flow separation. See Fig. 7.2.2.
7.2.2.3.2 Diffusing Transitions. Measurements are
to be avoided within these regions because of the poten-
tial for reverse flow.
7.2.2.3.3 Bends. When ducts have a rectangular
cross section, the sample ports should be located on either
of the long sides to permit traversing across the short
dimension.
When square cross sections are traversed, the sample
taps should be located in a manner such that a line drawn
across the sample ports is perpendicular to the tangent
line of the radius of curvature. Measurements should be
made on the upstream side of the bend in all cases. See
Fig. 7.2.2.
7.2.2.4 Internal Inspection and Measurement of Cross
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

Section. An internal inspection of the ductwork a t the If D < 7.8 ft

proposed traverse plane shall be conducted by the parties
to the t e s t to insure that no obstruction will affect the Then 24 = Number of points, minimum
measurements. The cross-sectional area shall be based on _
24 - Number of points/radial line
the average of four equally spaced measurements across 8
each duct dimension for rectangular ducts, and on the Therefore i= 3
basis of the average of four diametric measurements made
45 degrees to each other for circular ducts. From equation (2)

7.2.3 Determination of Sampling Grid

7.2.3.1 Circular Ducts D = 7.8 ft n an, ft
- -
(1) Measurements shall be taken a t the centroids of 1 0.34
equal areas. 2 1.14
(2) Minimum o f eight equally spaced radial traverse 3 2.31
lines.
(3) 0.5 ft minimum distance between adjacent points
on radial line common to both points. If D > 7.8,
(4) The number of test points shall be the larger of Say D = 1 2 f t
the following:
(a) 24 points nD2
Area=-- =113.1 ft2
(b) Not less than 1 pointl2 sq ft 4
Example: ft2
Number of points = = 56-55
2 ft2/ point
Let D = Internal duct diameter
i = Number of circular rings into which If 56 i s used as the total number o f sample points,
profile i s divided the elemental areas will be approximately 1 percent
n = Ordinal number of the ring larger than the recommended maximuin o f 2 sq ft.

Therefore to meet sampling criteria 1 through 4, let: Consider the following duct dimensions:

No. o f points = 60
No, o f rays = 1O

Then:
11 3.1 ft2
= 1.86-
ft2 Sampling
point 7
I I
60 points point
~

60 points / 10 rays = 6 points I ray

Therefore: i =6
n = 1,2, 6...
y=0.8ft
1 I'b I

D =I2 t l lk x = 1 . 6 f t
Then: n an,ft
_ -
1 0.26
2 0.80 X
Since-= 2
3 1.42 Y
4 2.13
5 3.00 Then S =-X/Y
2
6 4.27
Limits on aspect ratio of x / y
7.2.3.2 Rectangular Ducts
(1) Measurements must be taken at centroids of
equal areas.

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
(2) Let: 4 x 8
-<-<-
3 Y 3
S = Aspect parameter
or
Aspect ratio o f elemental area
S=
Aspect ratio of duct cross section 1.33
Y
< 2.67
Limits on S: 2/3 < S < 413 2.67 - 1.33
0ptimum:x = 1.33 -t =
(3) Long dimension o f elemental area must align with Y
long dimension of cross section.
Minimum number o f points 24
(4) Then the number of test points shall be the
larger o f the following:
(a) 24 points Elemental
Area
(b) Not less than 1 point/2 sq ft Dimensions
Example:
Let X = Long dimension o f duct cross section
II
Sampl'g Total
Grid No. of
Pattern Points = Across
Point Array
x
Long Short
Side Side
Down (4 (Y)
Aspect
Ratio
XlY
x = Long dimension o f elemental area
1 24 8 3 2.33 1.375 1.69
Y = Short dimension of duct cross section 2 24 3 8 2.67 0.5 5.3
y = Short dimension of elemental area 3 24 6 4 1.83 1.75 1 .O5
4 24 4 6 2.75 1.17 2.35
5 25 5 5 1.6 0.8 2.0
Then S =-'Iy = Aspect parameter
XI y
If X Y < 48 sq ft Sampling grid No. 5 best meets aspect parameter
criterion.
Then 24 = Minimum number o f points required
Elemental area = (1.6)(0.8) = 1.28 sq ft
Let X = 8
Y = 4

(8)(4) -
Elemental area = - - 1.33 sq ft
24 Let X Y > 48 sq ft

ANSIIASME PTC 4.4 - 1981 SECTION 7

Then one sample point cannot represent more x/Y = '83)(1 *O)
Aspect parameter: S = - = 1.16
than 2 sq ft of area. X/ Y (11.O) (7 .O)
Assume X = 11 ft
Y = 7ft 7.2.4 Velocity Traverse

1)(7) = 38.5 points 7.2.4.1 Pitot Static Tubes. Pitot tubes are permitted
Number of points = for those test situations where it can be shown that a t
2 sq ft/point
least 75 percent of the measured velocity heads approach
Round up to next convenient number, e.g., 40 the stagnation pressure hole a t a yaw angle o f less than 5
degrees.
Area/point = -
(' 1)(7) = î .93 sq ft/ point
40 7.2.4.2 Directional Probe. Directional probes must be
used for those situations which do not comply with the
.-7ft= Y-)( criterion o f 7.2.4.1.
y = 1 .o ft
4 7.2.5 Probes
A
x = 1.83 ft
General Requirements. Probes used for velocity meas-
urements must be capable of surviving the environment in

Sampling point 7 which they will be used. They shall be adequately stif-
fened and supported to minimize whipping in the gas
stream. Whenever such probes are inserted horizontally
in a horizontally flowing gas stream, rigid support and
adequate probe stiffness shall be provided to limit vertical
displacement (droop) to not more than 12.5 percent o f
the height o f an elemental area,
7.2.5.1 Pitot Static Tube. A standard Pitot static tube
has the dimensions shown on Fig. 7.2.3.
7.2.5.2 Directional Probes. A directional probe as re-
-<-
2 XlY <-4 ferred to in this Code shall be capable of simultaneously
3 1.57 3 measuring the velocity pressure and sensing the included
1.O5 <x/y < 2.09 angle between the direction of the velocity and the nomi-
nal direction of flow. Two typical probes of this type are
Optimum x/y = 1.O5 +0.,1;0.5) = 1*57 shown on Fig. 7.2.4.

7.2.6 Probe Calibration

Sample Points Dimensions 7.2.6.1 Pitot-static. Pitot-static tubes having the

Sampl'g Total \spect proportions shown on Fig. 7.2.3 are considered primary
Grid No. of Long Short Ratio instruments and need not be calibrated provided they are
Pattern Points = Across x Down Side - Side XlY maintained in the specified condition.
-
1 40 8 5 2.2 0.875 2,51 7.2.6.2 Other Probes. Calibration is required of all
2 40 5 8 1.4 1.375 1 .o2
3 40 4 10 1.75 1.1 1.59 other probes, Probe calibration shall be performed a t a
4 40 10 4 2.75 0.7 3.93 minimum of eight equally spaced points within the Rey-
5 42 6 7 1.57 1.167 1.35 nolds number range in which it will be used.
6 42 7 6 1.83 1.0 1.83
A free stream nozzle jet i s the preferred method o f
probe calibration. Calibration may also be performed in a
Sampling grid pattern No. 3 best f i t s the aspect wind tunnel.
parameter criterion, however, it does not meet Free / e t Nozzle Method, The nozzle must conform
criterion 3. Grid pattern 5 or 6 are equally ac- to the configuration shown in Fig. 7.2.5. A standard
ceptable. Grid pattern 6 would be the logical choice Pitot-static tube shall be used as the calibration reference,
in terms of round number (1 .O ft) sample intervals. The probe and the reference may be mounted symmetric-
Sampling area: xy = (1.83)(1.0) = 1.83 sq ft ally about the flow axis or may be arranged such that the

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

r""" I 0.4 û d i a .

+
"9 1 (1
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

rad.

90 deg. * 0.1 deg.

Section A-A

Head shall be free from nicks and burrs

---- t All dimensions shall be within '2%.
8 holes - 0.13 D, not to exceed 0.04 in. dia. equally spaced and free
Static pressure from burrs. Hole depth shall not be less than the hole diameter.

Note
Surface finish shall be 32 micro-in. or better. The static orifices may
not exceed 0.04 in. in diameter. The minimum Pitot tube stemdiam-
eter recognized under this Standard shall be 0.10 in. In no case shall
the stem diameter exceed 1/30 of the t e s t duct diameter.

PITOT-STATIC TUBE WITH SPHERICAL HEAD

X V
All other dimensions are the same as for spherical head Pitot-static
tubes. 0.000 0.314
0.237 0.295
0.336 0.279
0.474 0.487 1.730 0.266
0.622 0.477 0.250

0.741 0.468 1.796 0.231

0.936 0.449 1.830 0.211
1.025 0.436 1.858 0.192
1.1 34 0,420 1.875 0.176
1.228 0.404 1.888 0.163

1.31 3 0.388 1,900 0.147

1.390 0.371 1.910 0.131
1.442 0.357 1,918 0.1 18
Note 1.506 0.343 1.920 0.109
For dimensions of the ellipsoidal head. Multiply X and V by D to 1.538 0.333 1.921 0.100
obtain contour dimensions. 1.570 0.323

ALTERNATE PITOT-STATIC TUBE WITH ELLIPSOIDAL HEAD

FIG. 7.2.3 PITOT-STATIC TUBES

ANSI/ASME PTC 4.4 - 1981 SECTION 7

Cylinder

cb I-

Wedge

FIG. 7.2.4 TYPICAL DIRECTIONAL PROBES

probes each occupy the same point in the flow alternately. and
In the first case, care must be taken to insure that flow
conditions are constant in time, In either case, total -1096.84E
blockage o f the flow stream shall not exceed 5 percent. 60
See Fig. 7.2.6. Where
Wind Tunnel Method, A standard Pitot-static tube shall
be used as the calibration reference. Flow conditions in NR = Probe Reynolds number
the wind tunnel shall be sufficiently uniform to permit I/ = Velocity, ft/sec
the insertion of both the probe and the reference simul- D = Probe frontal width, ft
taneously, Care shall be taken to eliminate interference p = Density of calibrating medium, lbm/ft3
between the probes,’ The total blockage of the two probes I.( = Absolute viscosity of calibrating medium,
shall not exceed 5 percent o f the tunnel cross section. The I bmlft-sec
blockage of the probes shall not differ by more than 25 Pv = Indicated velocity head of probe being
percent. calibrated, in, H 2 0
A probe factor shall be determined for each flow
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
Combining equations (1) and (2):
condition as follows:
Velocity pressure of reference probe NR = 18.28 0
c1
K = Velocity pressure of probe being calibrated
It should be noted that this approach provides a
The probe factor (K) shall be plotted as the coordinate calibration factor which i s independent of the calibrating
value of the probe Reynolds number which shall be plotted medium.
on the abscissa, The probe Reynolds number i s derived as Once a probe has been calibrated, it should be han-
follows: dled with care since large scratches and/or nicks on
the upstream side near the pressure taps will alter i t s
calibration.

Copyright ASME International Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
Provided by IHS under license with ASME 7 about this message: please call the Document
23:56:18 MST Questions or comments
Policy Group at 303-397-2295.
SECTION 7 ANSIIASME PTC 4.4 - 1981

I I t;lH 'i
ä

fi --R
im

I It VI
W
J

s
-f
N
N
O
z

o
IIV
@L

-aNl
O
Z
4
.
3
3
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ANSI/ASME PTC 4.4 - 1981 SECTION 7

Variable speed fan

Nozzle temperature

---I

L Not greater than -

D”
20
Approximately 0.23 D,,+
r-
FIG, 7.2.6 FREE STREAM J E T CALIBRATION

7.2.7 Differential Pressure Measurement Instrumentation (b) Directional Probes. The static pressure shall be
derived in accordance with the following procedure.
7.2.7.1 Accuracy. The specifications for instruments
and methods of measurement which follow include ac- Ps = PT - K P1, or Ps = KP;
curacy requirements. The specified requirements cor- where
respond to two standard deviations and are based on an
Ps = Static pressure
assumed normal distribution o f the errors involved. The
calibration procedures which are specified shall be em- PT = Total pressure (I)when probe i s nulled
ployed to minimize systematic errors. Random errors can
K = Probe coefficient
Pi, = Indicated velocity pressure when probe
be established only from an adequate statistical sample.
i s aligned with flow velocity
It i s anticipated that calibration data will be accumulated
on the various instruments prior to their selection for use
Pi = Indicated static pressure when probe i s
in a particular test. aligned with flow velocity

7.2.7.2 Probe Pressure Readings. Probe pressure read- 7.2.7.4 Manometers and Other Differential Pressure
ings shall be taken when the total pressure hole of the Indicating Instruments. Differential pressure shall be
probe i s aligned with the flow velocity. The probe shall measured with manometers of the liquid column type
be capable of indicating both the total pressure and a using inclined or vertical legs or other instruments which
second pressure indicative of the static pressure. The dif- provide a maximum error of 1 percent of the maximum
ference between these pressures is indicative of the observed reading.
velocity pressure. This pressure differential shall be meas- 7.2.7.5 Calibration. Each differential pressure indi-
ured on an indicator, such as a manometer or equivalent cating instrument shall be calibrated a t both ends of the
differential pressure measuring device, with one leg con- scale and a t least nine equally spaced intermediate points
nected to the total pressure tap of the applicable probe, in accordance with the following:
and the other leg connected to a “static” pressure tap of (a) When the differential pressure to be indicated
the same probe. The total pressure shall be measured on a falls in the range of O to 10 in. HzO, calibration shall be
similar device, with one leg open to atmosphere. against a water-filled hook gauge of the micrometer type
7.2.7.3 Static Pressure. The static pressure shall be or a precision micromanometer.
determined a t each point of velocity measurement and (b) When the pressure to be indicated i s above 10 in.
shall be recorded as positive values for a duct pressure H 2 0 , calibration shall be against a water-filled hook gauge
above the local barometric pressure and negative values of the micrometer type, a precision micromanometer, or
for a duct pressure below the local barometric pressure. a water-filled U-tube.
(a) Pitot Tubes, The static pressure leg shall be used 7.2.7.6 Averaging. Since the flow pressures are never
as the source of static pressure measurements. strictly steady, the differential pressure indicated on any

55
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 7 ANSI/ASME PTC 4.4 - 1981

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
O 200 400 600 800 1O00 1200 1400

Temperature, O F

O 200 400 600 800 1O00 1200 1400

Temoerature. O F

FIG, 7.2.7 CURVES DRAWN USING DATA T A K E N FROM FIGS. 7.2.8 AND 7.2.9

ANSl/ASME PTC 4.4 - 1981 SECTION 7

instrument will fluctuate with time. In order to obtain a Example:

reading, either the instrument must be damped or the
readings must be averaged in a suitable manner. Averaging -
Gas -
% b y Vol. MW MW Fraction
can sometimes be accomplished mentally, particularly if CO, 13.5 x 44.01/100 5.94
O, 5.2 x 32.00/100 1.66
the fluctuations are small and regular.
When differential pressure measurements are taken for
N, 81.3 x 28.02/100 22.76
30.36 Avg. MW o f
the purpose of measuring flow rate, it must be realized dry flue gas
that the average differential pressure does not correspond
The dry gas density, pdgJ i s found by dividing the flue
to average flow rate, due to the square law between
gas MW by the volume occupied by one mole of gas a t
velocity and velocity pressure. To obtain true average flow
the condition desired. One pound-mole will occupy
rate it i s necessary to obtain a graphic record o f velocity
359.05 CU. ft at 32°F and 29.92 in. mercury.
pressure with a high-frequency-response instrument, de-
rive from this a curve of the square root of velocity pres- 30*36 Ib/lb-mole Ib
Density = = 0.0846 - @ 32"F,
sure and use the average of this square root curve to 359.05 ft3/lb-mole ft3
calculate velocity. It i s possible to carry out this process
automatically by electronic methods when an electric 29.92 in. Hg
pressure transducer is the primary element. To adjust the density to any other temperature, T, and
7.2.7.7 Corrections. Manometer readings shall be cor- pressure, P, the previously calculated density i s multiplied
rected for any difference in specific weight of gauge fluid by the absolute pressure and temperature ratios.
from standard, any difference in gas column balancing ef- Density a t desired conditions equals density a t standard
fect from standard, or any change in length of the gradu- conditions, multiplied by the temperature and pressure
correction factors below.

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
ated scale due to temperature. However, corrections may
be omitted for temperatures between 58°F and 78"F, (32°F + 459.76"F) P in. Hg
latitudes between 30" and 60" and elevations up to and
( T +459.76"F) 29.92 in. Hg
5000 ft.
7.2.8.1.2 Moisture in Flue Gas. The moisture con-
7.2.7.8 Other Differential Pressure Measuring Systems. tent of flue gas can be calculated from the fuel analysis
Differential pressure measuring systems consisting of in- and combustion air moisture content, hygrometer wet-
dicators other than manometers may be used if the com- bulb and dry-bulb temperatures, or condensation of vapor
bined error o f the system does not exceed the combined from a known gas volume. Refer to PTC 4.1, Section 7,
error for an appropriate combination of manometers. For for the combustion method of moisture determination
systems used to determine flow rate, the combined error and I&A, PTC 19.18, for the hygrometer method of
shall not exceed that corresponding to 1 percent of the moisture determination.
maximum observed velocity pressure or pressure differ-
ential reading during a test (indicator tolerance) plus 1 7.2.8.1.3 Density of Wet Flue Gas. When the
percent of the actual reading (averaging tolerance). moisture in the flue gas has been determined, the per-
cent COz, Oz, and Nz on a dry basis i s adjusted to a wet
basis. This is done by multiplying (1 - -
%,Dio)times
7.2.8 Computation of Results the dry gas percentage of COz, 02, and Nz. Assume that
7.2.8.1 Physical Properties of Gas Being Measured moisture content is 8.8 percent water vapor by volume.

7.2.8.1.1 Density of Dry Gas. The density will be % by % by

Vol. Vol. MW
required in converting gas velocity head to feet per min- Dry
Gas - Wet MW Fraction
- - --
ute and cfm to pounds per minute or vice versa. The
density o f dry flue gas can be determined from the con-
stituents in the flue gas. These constituents are normally
CO, 13.5 x (1) : ,
- 12.3 X- 44.01
1 O0
5.41

O, 5.2 x 0.912 4.7 x- 32'00 1.50

carbon dioxide, COz, oxygen, Oz, and nitrogen, Nz. The 1O0
nitrogen content is determined by difference, and all N, 81.3 x 0.912 74.2 X- 28'02 20.78
I O0
constituents are determined on a dry, volumetric, per-
centage basis. The volume fraction o f each gas is multi- H,O 0.0 8.8 X
- 18*oo 1.58
I O0
plied by i t s respective molecular weight (MW) to deter-
- -
100.0 100.0 29.27 Avg.
mine the molecular weight fraction. The sum o f the MW MW of
fractions i s equal to the dry flue gas MW. wet gas

SECTION 7 ANSI/ASME PTC 4.4 - 1981

VISCOSITY OF GASES

Gas or Vapor
Teomp.,
viscosity
Micro- Gas or Vapor
Team P., viscosity
Micro-
C C
poises poises

Air - i 94.2 55.1 Carbon dioxide -97.8 89.6

-1 83.1 62.7 -78.2 97.2
-104.0 113.0 -60.0 106.1
-69.4 133.3 -40.2 115.5
-31.6 153.9 -21 126.0
O 170.8 -19.4 129.4
18 182.7 O 139.0
40 190.4 15 145.7
54 195.8 19 148.0
74 21 0.2 20 149.9
229 263.8 30 153
334 312.3 32 155
35 156
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

357 317.5
409 341.3 40 157
466 350. I 99.1 186.1
481 358.3 104 188.9
537 368.6 182.4 222.1
565 375.0 235 241.5
620 391.6 302.0 268.2
638 401.4 490 330.0
750 426.3 685 380.0
81O 441.9 850 435.8
923 464.3 1052 478.6

1034 490.6 Oxygen O 189

1134 520.6 19.1 201.8

Nitrogen -21.5 156.3 127.7 256.8

10.9 170.7 227.0 301.7
27.4 178.1 283 323.3
127.2 219.1 402 369.3
226.7 255.9 496 401.3
299 279.7 608 437.0
490 337.4 690 461.2
825 41 9.2 829 501.2

" F = ("C x 9/5) + 32

Ibm
viscosity: - = micropoises x 6.72 x 1O-'
ft-sec

Source: Handbook of Chemistry and Physics,

57th Edition (1976-1977),
pp. F-50, F-58, F-60.

FIG. 7.2.8

ANSIIASME PTC 4.4 - 1981 SECTION 7

The wet flue gas density, Pwg, i s found by dividing 7.2.8.2 Computation of Average Gas Velocity
the MW by the volume of one pound-mole at the condi- 7.2.8.2.1 Pitot Static Tube. When velocity pres-
tions desired. sure measurements are made with this probe, the aver-
29.27 Ib/lb-mole Ibm age velocity head shall be computed as follows:
pWg =
359.05 ft3/Ib-mole
= o,o81
ft3
-
@ 32"F, 29.92 in. Hg
7.2.8.1.4 Viscosity of Wet Flue Gas. The com- = Average velocity pressure, in. H 2 0
posite viscosity of the gas mixture i s calculated using N = Total number of traverse points
the following equation:
The average velocity shall be computed as follows:

Where

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
Where
&n = Gas viscosity of mixture, Ibmlft-sec
yj = Mole fraction of gas constituent Vavg = Average gas velocity, ft/min
MWj = Molecular weight of gas constituent Pv(avg) = Derived as above
pi = Gas viscosity of individual constituent, = Density of gas mixture a t traverse plane,
Ibm/ft-sec Pwg Ibm/ft3, see paragraph 7.2.8.1.3
7.2.8.2.2 Directional Probe. When velocity pressure
Constituent MW Fraction Mole-Fraction MW measurements are made with this probe, the average veloc-
CO, 5.41 + 29.27 0.185 44.01 ity head must account for both the yaw angle and probe
0 2 1.5 + 29.27 0.051 32.00 calibration factor.
N2 20.78 + 29.27 0.710 28.02 (a) Yaw angle i s measured as shown by the following
HZ0 -1.58 + 29.27 0.054
- 18.00
diagram :

ticample:
29.27 1.o00
r Reference line on
probe

Assume gas temperature = 300°F

Mole-Frac. 9 =yaw
-
Const.
-y p,@300°F* ---
X W Y ~ PW Y ~
CO, 0.1 85 13.75 x 1O-6 6.63 1.227 16.87 x 1O-6
0, 0.051 18.0 x lo-' 5.66 0.289 5.20 x I O - ~
N,
H,O
0.710
-
0.054
15.5 x
9.5 x lo-'
5.29
4.24
3.756 58.22x10-'
0.229 2.18 x \ Flow
iL

1.o00 CYjm=5.501

ZCciyi = 82.47 x 1O-'

I
Ïraverse plane

psi = ps2 When probe nulled

*See Fig. 7.2.7
e = $ Angle which probe must be
rotated to obtain null -
Then: yaw angle, degrees
Py = Pr-PSi Indicated velocity pressure
(b) The applicable probe factor (K) shall be selected,
from the calibration curve, as the dependent variable o f
14.99 x loe6 Ibm/ft-sec the average probe Reynolds number which shall be cal-
culated as follows:
D
*Perry's Chemical Engineer's Handbook, 5th Edition, p. 3-249,
equation 3-135.
NRe(avg) = 18-28 d Pv(avg) Pwg

SECTION 7 ANSI/ASME PTC 4.4 - 1981

Where: At test conditions 7.2.8.3.2 Mass Flow. The total mass flow i s deter-
mined as follows:
NRe(avg) = Average probe Reynolds number, dimen-
sionless M = A Vavg Pwg = Q Pwg
pwg = Average gas density at traverse plane,
Ibm/ft3. See para. 7.2.8.1.3 where
D = Probe diameter, ft M = Mass flow, Ibm/min
Pm = Composite viscosity of gas mixture, pwg = Gas density at test conditions, Ibm/ft3
Ibm/ft-sec. See para. 7.2.8.1.4
Sample Problem:
and
Figure 7.2.1 1 is a sample data sheet showing the results
of a 24-point transverse.
Column Explanation

Where A Sample point identification

B Identifies a term w!thin summation
= Indicated velocity head, in. H20, at each point i C Gas temperatures, F
PVi D Total pressure! in. H,û, ¡.e., velocity + static
Note: Yaw angle correction is not required for this step. E Velocity pressure, in. H,O
F Yaw angle, degrees
The average yaw angle corrected velocity head shall be G Yaw angle corrected velocity head, in. H,O

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
derived as follows: The appropriate average values of each measurement
are shown at the bottoms of Columns C through G.
The first step is to calculate the composite gas vis-
cosity, /.l.
Where
% by % by
= Indicated velocity head, in. H 2 0 at each point I Vol. Vol. MW
Pvi -
Const. Dry Wet
- -
MW -
Fract.
ûi = Yaw angle, degrees, at each point i
CO, 12.5 x (1 -E) 11.75 x 44.011 5.17

(1 - E )
1 O0
The average velocity i s calculated as follows: 0, 3.0 x 2.82 x 32.00/ 0.90
1O0
N, 84.5 x (1 -#) 79.43 x 28.021 22.26
1O0
HZO 0.0 6.00 x 18.001 1.08
1O0
Where 100.0 100.00 29.41
Vavg = Average gas velocity, ft/min
Mole-Fract.
K = Probe factor, dimensionless. See para. Const. MW Fraction Y
7.2.8.2.2 (b) 5.1 7 -. . 29.41 0.1 8
CO,
P'v(avg) = Average velocity head corrected for yaw, 0, 0.90 - 29.41 0.03
in. H 2 0 Na 22.26 + 29.41 0.76
H2O 1.80 - 29.41 -
0.04
pwg = Gas density a t traverse plane, Ibm/ft3
29.41 1 .o

Mole-
Fract.
7.2.8.3 Calculation of Total Flow
-
Const, - y p@275'F* -
MW -
y m p y m
7.2.8.3.1 Volumetric Flow. The total volumetric CO, 0.18 13.5~10" 44.01 1.19 16.12~10~
O, 0.03 17.5 x lo-' 32.00 0.17 2.97 x lou6
flow i s determined as follows: N, 0.76 15.0 x lo-' 28.02 4.02 6 0 . 3 4 ~IO-'
H,O 0.04 95x10" 18.00 M
!J 1.61 XIO-'
-
1.o 2 = 5.55 C =81 .O4 x IOb6
Where
fi = viscosity o f gas mixture =
Zpy m-81 .O4 x 1O-' -
Q = Volumetric flow at test conditions, acfm 2 y J - w - 5 . 5 5 -
A = Total area traversed, ft2 Ibm
Vavg = Average velocity, ftlmin *Values taken from Fig. 7.2.7.
14.6~10-' -
ft-sec

Probe Reynolds number = N R e = 18.27

Where
Probe is 1.O in. Ø = 1.Oll 2 = 0.083 ft Ø
~

Pv= Average velocity pressure from Column E = 2.24

--
ASME PTC*9.4 81
~~ ~

D
E.C
m 075'7670 0059183 3

nolds number, equation (1).

Hence:

NRe = 1.56 x 1O5

or
J (550 - 3K)l
SECTION 7

(3)
in. H2Q Nue =1.56x103 dBÖ?U¿
NRe =
18.28 x 0.083 x m x 6 The trial and error solution proceeds by choosing
14.6 x
(11 values for N R e and the corresponding K-value. Suc-
cessive substitutions are made into equation (3) until
equality is achieved.
Wet flue gas density at the traverse plane i s calculated
Assume:
as follows:
NRe = 3.0 x lo4, then K = 1.195 from calibration
29.41 Ib/lb-mole 460t32 curve, Fig. 7.2,1 O
P= x- 3 . 0 ~ 1 0 ~= 1 . 5 6 ~ 1 0d550-3(1.195)
~
359.05 ft3/lb-mole 460+T
3 . 0 ~lo4 < 3 . 6 2 ~l o 4

29.92
P-9
29.92 + 13.6 13.6 Assume:
NRe = 3.6 x lo4, then K = 1.19 from Fig. 7.2.9
Where 3 . 6 ~ 1 0 ~= 1 . 5 6 ~ 1 04550-3(1.19)
~
3 . 6 ~l o 4 = 3 . 6 l~o 4
T = 275'F - average temperature from Column C
PT = 4.28 in. H 2 0 - average total pressure from Col- Note; If a Pitot tube was used to measure velocity head,
umn D this step would be unnecessary since K would equal 1.O.
K = Probe coefficient, dimensionless
PV = 2.28 in. H 2 0 - average velocity pressure from Substituting for K into equation (2) thc wet gas den-
Column E. sity becomes:
Note: Since we need average pressure this value is a -
p = 0.055 0.0003 x 1.19
straight arithmetic mean instead of the squared value of
the mean of the square roots of velocity pressure.
ft3
-
= 0.055 Ibm @ test conditions

Substituting the appropriate values:

Gas velocity:

=
29.41
359.05 x-
460t32
460+275 29.92
(G8
29.92 + 13.6
-KE)
9 V=1096.84 E
where
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

I bm/ft3 (2)
p = 0,082 x 0.669 x (1 i-
0.01 1 0,006 K ) - P v = 1.86 in. H 2 0 - The average yaw corrected velocity
head from Column G
p = 0.055 -0.0003 K .. . p = wet gas density, Ibm/ft3
Note that the probe factor, K, depends on the probe Hence:
Reynolds number; however, the Reynolds number i s a
function of gas density which is dependent on K as well. V = 1096.84 = 6378 fpm
This is so because of the method used to determine the
average static pressure in the gas stream, ¡.e., Pstatic = Volume flow:
-
Ptotal K Pvelocity head. SinCe K Cannot be explicitly
determined, a trial and error method of solution i s Q = A V = 150 x 6378 = 956,775 acfm
required. Mass flow:
This is accomplished by substituting the expression
for p, equation (2), in the expression for the probe Rey- m = Q x p = 150 x 6378 x 0.055 = 52,623 Ibmlmin

Copyright ASME International Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
Provided by IHS under license with ASME f- 23:56:18 MST Questions or comments about this message: please call the Document
-=---.
Policy Group at 303-397-2295.
1
43
SECTION 7 ANSI/ASME PTC 4.4 - 1981

A
C
t-

32
J

1:
62
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`--- ANSI/ASME PTC 4.4 - 1981 SECTION 7

Velocity, fprn

O 1 O00 2000 3000 4000 5000

2.0

1.8

1.6

1.30 1.4

o,
I
1.25 1.2 .E
i
o>
r
z
1.20 1.0 5
sc -O
+-ô
s
e 1.15 0.8
2
o,
n

1.10 0.6

1 .O5 0.4

1 .o0 0.2

O
O 1 .o 2.o 3 .O 5.0 I 04
Probe Reynolds Number

FIG. 7.2.10 SAMPLE CALIBRATION CURVE BASED O N A I R A T 7OoF, 29.92 in. Hg

D E F
A B C PT-in. Pyi n . Yaw-
Point i
- Temp., O F H2O H20 -deg

AI 1 275 3.30 1.30 -40

2 2 270 3.75 1.75 -45
3 3 276 4.00 2.00 -45
4 4 274 4.1 1 2.1 1 -45
5 5 278 4.64 2.64 O
6 6 273 3.91 1.91 -30
BI 7 280 4.1 2 2.1 2 -30
2 8 271 4.1 7 2.1 7 -32
3 9 273 4.45 2.45 +I o
4 10 275 5.63 3.63 -38
5 11 277 4.41 2.41 -30
6 12 279 5.43 3.43 -1 5
CI 13 274 4.99 2.99 -1 o
2 14 272 5.1 1 3.1 1 -5
3 15 273 4.65 2.65 -16
4 16 277 4.74 2.74 -1 5
5 17 278 4.30 2.30 -8
6 18 280 4.21 2.21 -5
DI 19 273 3.67 1.69 -9
2 20 280 3.44 1.44 -14
3 21 281 3.20 1.20 - 20
4 22 276 3.72 1.72 - 20
5 23 275 4.41 2.41 -5
6 24 - 272 4.40 2.40 O

(& ..)' 24
= 2.24

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ANSI/ASME PTC 4.4 - 1981 SECTION 7

7.3 COMPUTER PROGRAM FOR CALCULATING EXHAUST GAS ENTHALPY

7.3.1 Program Scope

This section gives details of a computer program that will calculate exhaust gas enthalpy
based upon a method combining the incremental enthalpies of the products of combustion.
This program can be used to calculate a specific enthalpy or a table of enthalpies for a range of
given conditions. The program has five routines, controlled by an input index (IPO) as follows:

lndex 7. Calculates for a given fuel, a table of exhaust gas enthalpies

for a range of gas temperatures from 100°F to 2000°F in 5OoF incre-
ments and for a range of fuel-air ratios from 0.01 5 to 0.060 in 0.005 in-
crements, This fuel-air ratio range is equivalent to an approximate ex-
cess air range of 1O percent to 400 percent.
lndex 2. Calculates for a given fuel, a table of gas temperatures for a
range of exhaust gas enthalpies from 130 Btu/lb to 500 Btullb in 10
Btu/lb increments and for the same fuel-air ratio range as Index 1.
lndex3. Calculates for a given fuel, the individual exhaust gas en-
thalpy at one gas temperature and fuel-air ratio,
lndex 4. Calculates for a given fuel, the individual gas temperature at
one exhaust gas enthalpy and fuel-air ratio.
lndex 5, Calculates for a given fuel, the incremental and total en-
thalpies of combustion products.

The range of properties stated above for routines and 2 can be altered in the program
by changing the limits in lines 35,36,44,48,49, and 59 see program listing in paragraph 7.3.3).
The increments can be altered by changing the constant in lines 39, 43, 52, 55, 61, and 63.

7.3.2 Nomenclature for Variables

Symbol Description -
Units

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
GASENT Program name Gas enthalpy
ENTHAL Subroutine name Enthal py
FG R Gas turbine fuel-air ratio Decimal
FL fuel type description Alpha numeric
FSR Supplementary firing fuel-gas ratio Decimal
HAD Component enthalpy of dry air Btullb
HCB Component enthalpy of carbon Btu/lb
HCD Component enthalpy of carbon dioxide Btu/l b
HCM Component enthalpy of carbon monoxide Btu/lb
HCO Enthalpy of carbon a t a given temperature Btu/lb
HGF Initial exhaust gas enthalpy Btullb
HGT Calculated exhaust gas enthalpy Btu/lb
HHY Component enthalpy of hydrogen Btu/lb
HIA Enthalpy of air a t a given temperature Btu/lb
HIC Incremental enthalpy of carbon Btu/l b
HIH Incremental enthalpy of hydrogen Btu/lb
HIM Enthalpy of moisture at a given temperature Btu/lb
HIS Incremental enthalpy of sulfur Btu/lb
HMO Component enthalpy of moisture Btu/lb

SECTION 7 ANSIIASME PTC 4.4 - 1981

Symbol Description Units

-
HNC Total component enthalpies of noncombustibles Btu/lb
HNI Component enthalpy of nitrogen Btullb
HNO Enthalpy of nitrogen at a given temperature Bt~i/lb
HOM Enthalpy of carbon monoxide a t a given temperature Btu/lb
HOX Enthalpy of oxygen a t a given temperature Btu/lb
HOY Component enthalpy of oxygen Btu/lb
HCD Component enthalpy of sulfur dioxide Btu/lb
HSO Enthalpy of sulfur a t a given temperature Btu/lb
HS U Component enthalpy of sulfur Btu/lb
I PO Program printout index
Program loop index
N Program loop index
PCF Percent carbon in fuel percent
PDF Percent carbon dioxide in fuel percent
PHF Percent hydrogen in fuel percent
PIA Barometric pressure psia
PIH Barometric pressure in. Hg
PM F Percent carbon monoxide in fuel percent
PNC Percent noncombustibles in fuel percent
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

PNF Percent nitrogen in fuel percent

POF Percent oxygen in fuel percent
PS F Percent sulfur in fuel percent
PUF Percent sulfur dioxide in fuel percent
RAK Absolute temperature Deg. R
RHY Relative humidity percent
RIG Initial exhaust gas temperature Deg. F
TAD Ambient dry bulb temperature Deg. F
TAW Ambient wet bulb temperature Deg. F
TG F Exhaust gas temperature Deg. F
TGT Initial exhaust gas temperature Deg. F
VAP Function for vapor pressure of water a t a given
temperature* in. Hg
VPD Vapor pressure of water at dry ambient in. Hg
VPV Vapor pressure of water (corrected) in. Hg
VPW Vapor pressure of water a t wet ambient in. Hg
WAG Component weight of dry air Ib/l b exhaust gas
WCG Component weight of carbon Ib/lb exhaust gas
WDA Weight of dry air (base = 1.O) Ib
WDF Component weight of carbon dioxide Ib/lb exhaust gas
WFE Component weight of fuel Ib/lb exhaust gas
WFG Weight of gas turbine fuel Ib/lb air
WFS Weight of supplementary fuel Ib/lb exhaust gas
WHG Component weight of hydrogen Ib/lb exhaust gas
WMA Weight of ambient moisture Ib/lb air
WMF Component weight of carbon monoxide Ib/lb exhaust gas
WMG Component weight of moisture Ib/l b exhaust gas
WMJ Weight of injection moisture Ib/lb air
WNC Total component weights of noncombustibles Ib/lb exhaust gas
WNF Component weight of nitrogen Ib/lb exhaust gas
WOF Component weight of oxygen Ib/lb exhaust gas

*Mark?s Standard Handbook for Mechanical Engineers, Seventh Edition, p. 4-81,

Symbol Description Units

-
wsu Component weight of sulfur Ib/lb exhaust gas
WTG Weight of exhaust products Ib
WTP Total of exhaust component weights Ib
WUF Component weight of sulfur dioxide Ib/lb exhaust gas
XA Project description Alpha numeric
XB Description of run Alpha numeric

7.3.3 Input Data

The input consists of five lines of data entered in fixed format as follows:

XA (11, I= I r 10
XB (I), I= I 10r
F L (11, I= I 2r
TAD, TAW, P I A , P I H r RHYr I P O
TGT ( l ) r HGF (11, FGR (111 FSR ( l ) r WMJ

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
PCFr PHFr PSFr POFr PNFr PDF, PMFr PUF

Definition of the variable names is given in paragraph 7.3.2.

Example:

TEST RUN FOR ASME PTC Lt-9 JJZ

EXHAUST GAS ENTHALPY = I S 0 CONDITIONSr IPO=1
N0.2 O I L
59-0 0-0 19-696 0 - 0 60-00 1
100- 0-0 0,01500 0 - 0 0-0.
87.50 12-00 0-50 0-0 o -0 0-0 0-0 0.0

PROGRAM LISTING (FORTRAN I V )

C PROGRAM GASENT(INPUTrOUTPUTrTAPE5)
C CALCULATES EXHAUST GAS ENTHALPY OR TEMPERATURE
C GIVEN AMBIENT CONDITIONS AND FUEL-AIR RATIO
O001 COMMON X A ~ ~ ~ ~ ~ X B ~ ~ ~ ~ ~ F L ~ ~ ~ ~ T G T ~ ~ ~ ~ ~ F G R
lHSPiTGF(vSrl0)rWFGrWMAiWTGiWDArWAGrWMGrWFEiWCGiPCFrPHFiHIAiRAKr
~HCOIHIM~HOX~HIC~HIHIHADIHMOIHCBIHHY~WTP~N~J~WHG~IPOIWOC~WOHIWOSI
~WPO~WCX~FSR~~~~~WFS~WMJ~WSUIPSF~HIS~HSU~HSO~WSXIWHXIWPHIWPTIHOPI
~HCPIHMP,PDF~PMF~PNFIPOFIPUFIPNCIWOF,WNF~WDFIWUFIWNCIHNC
C CALL PFUR(3HRETrSiTAPES)
0002 VAP~XX~~3~770~E-02+1,63297E-O3*~XX~+8-87809E-O5*~XX~**2
1-Y.92591E-07*(XX)**3+1,33683E-08*(XX)**~
0003 READ(Sr2) ( X A ( I ) r I = l r l S )
ooov READ(5r2) ( X B ( I ) i 1 = 1 1 1 5 )
0005 READ(Sr3) ( F L ( I ) i I = l i S )
0006 READ(5r't) TAD, TAWIPIAIPIH~RHYIIPO
0007 READ(Sr6) T G T ( l ) r H G F ( l ) r F G R ( l ) r F S R ( l ) r W M J
0008 READ(5r7) PCFIPHFIPSF~POF~PNF~PDF~PMFIPUF
0009 WRITE(br2) ( X A ( I ) r I = l r l S )
O010 WRITE(br2) ( X B ( 1 ) 1 1 = 1 1 1 5 )
0011 WRITE(br3) ( F L ( I ) r I = l r 5 )
0012 WRITE(6rY) T A D I T A W ~ P I A ~ P I H I R H Y ~ I P O
0013 WRITE(br6) T G T ( l ) v H G F ( l ) r F G R ( l ) , F S R ( l ) t W M J
0019 WRITE(br7) PCFiPHFiPSFrPOFrPNFiPDF,PMF,PUF
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

0015 PNC=PDF+PMF+POF+PUF+PNF
0016 WRITE(br9)
0017 IF(IP0-GE-3) W R I T E ~ ~ ~ ~ ~ ~ X A ~ I ~ ~ I ~ ~ , ~ S ) , ~ X B
1 iPCFiPSFtPHFrPNC
0018 I F ( I P 0 - E Q - 3 ) WRITE(br10)
0019 IF(IP0-EQ-Y) WRITE(brl2)
O020 IF(IPO.EQ-1) WRITE(bi1Y) (FL(I)rI=lrS)iPCFrTADrPHFrRHYrPSFtPIArPNC
O021 IF(IP0-EQ-2) WRITE(brl6) ( F L ( I ) I I = ~ ~ ~ ) ~ P C F ~ T A D I P H F I R H Y ~ P S F ~ P I A ~ P N C
O022 90 IF(PIA.GT.0.) PIH=PIA*2.03b
0023 VPD=VAP(TAD)
0029 IF(RHY.GT-O.) GO TO 20
0025 VPW=VAP(TAW)
O026 VPV=VPW-(PIH*(TAD-TAW)/2700-)
0027 RHY=VPV/VPD
0028 GO TO 22
DO29 20 VPV=RHY*VPD/lOO.
0030 22 WMA=VPV/(l-bl*(PIH-VPV))
0031 WDA=1-0
0032 RTG=TGT(l)
0033 I F (IPO-EQ.5) GO TO 9 1
0039 IF(IPO-EQ.2-0R-IPO.EQ.~) GO TO 50
0035 DO 30 N = l r 3 9
0036 DO 32 J = l r 1 0
0037 CALL ENTHAL
0038 I F ( I P 0 - E Q - 3 ) GO TO bO
0039 FGR(J+l)=FGR(J)+-OOC
oovo IF(J.EQ-10) GO TO 6 6
0091 GO TO 32

68
Copyright ASME International Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
Provided by IHS under license with ASME 23:56:18 MST Questions or comments about this message: please call the Document
Policy Group at 303-397-2295.
ANSIIASME PTC 4.4 - 1981 SECTION 7

OOY2 bb WRITE(b180) TGT(N)t(HGT(K),K=1,10)

OOY3 TGTíN+l)=TGT(N)+SO-
OOYY IF(N.EQ-39) GO TO 99
OOY5 GO TO 30
OOYb 32 CONTINUE
ooLt7 30 CONTINUE
OOY8 50 DO Y2 J = l i l O
0099 DO Y O N = l r 3 9
O050 112 CALL ENTHAL
0051 IF(HGF(N)-LT-HGT(N)) GO TO 110
0052 TGT(N)=TGT(N)+-5
0053 GO TO 112
005Y 110 IF(ABS(HGF(N)-HGT(N))-LT-O-5) GO TO Il+
0055 TGT(N)=TGT(N)--2
0056 GO TO 112
0057 11Y TGF(N,J)=TGT(N)
0058 I F ( I P 0 - E Q - Y ) GO TO 70
0059 I F ( N - E Q - 3 9 ) GO TO 1 1 6
0060 TGT(N+l)=TGT(N)
OOb1 HGF(N+l)=HGF(N)+LO-
0062 GO TO YO
0063 l l b FGR(J+l)=FGR(J)+-O05
OObY TGT(l)=RTG
0065 GO TO 'ti2
OObb YO CONTINUE
00b7 Y2 CONTINUE
OOb8 DO 1 1 8 N = l r 3 9
0069 WRITE(br82) HGF(N),(TGF(N,J).J=lr10)
O070 I F ( N - E Q - 9 8 ) GO TO 99
0071 118 CONTINUE
O072 bo WRITE(bJb2) TGT(l),WAG,HIA~HAD~WMGI"MtHMOIWCGI"C~HCB~WHG~HIH~
~HHYIWSU~HISIHSU~WTPI"T(J)
0073 79 READ(Si*,END=99) T G T ( l I r H G F ( 1 )
007Y I F ( T G T ( l ) - E Q - O - ) GO TO 99

' 0075
007b
0077
GO TO 90
7 0 WRITE(bt72) HGF(N)rTGF(N,J)rFGR(J)
GO TO 7Y
I 0078 91 J = l
I 0079 N=l
0080 CALL ENTHAL
0081 WRITE(bi92) WAGIWAGIWMGIWMGIWCGIWOC,WCX,WHGIWOH~WHX,WSU,~~OS,WSX,
1WNC,WTP,WAG,WPO~WCX~WSX,WPHtWNC~HIAI"X~HCO~HSO~HIMtHPT,HAD~HOP~
2HCPtHSPrHMPrHNC
0082 GO TO 79
0083 i FORMAT(15AY)
O089 3 FORMAT(5AY)
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

OR85 Y FORMAT(~F~,LIF~-~~F~.~,F~.~~I~)
0086 9 FORMAT(?C('-'))
0087 b FORMATtFb-0tF7-lr3F8-5)
0088 7 FORMAT(8Fï-2)
0089 8 FORMAT(//// 15AY/15AY/SAY//' CARBON = ' r F b - 2 i 1 PERC-'rYX
1 SULFUR = ' i F b - 2 , ' PERC-'/' HYDROGEN = ' r F b - i , ' PERC-'rYX
2'NON-COMB- = ' i F b - 2 r 1 PERC-'1

0090 10 FORMAT(//' COMPONENT',SXr'PRODUCT'r9Xr'INCRl"PRODUCT'/

~ ~ ~ X ~ ' W E I G H T ' I ~ X ~ ' E N T H A L P Y ' , ~ X ~ ' E N T H A L P Y ' / ~LOBX' I~ ' P E R
210x1 'BTU/LB'p9Xr'BTU/LB'/)
0091 12 FORMAT ( / / r 5 X r 'ENTHALPY TEMPERATURE FUEL-AIR'/
l b X i ' B T U / L B ' r f X r 'DEG-F1r8Xr'RATIO'/)
0092 llt FORMAT(//' GAS TURBINE EXHAUST ENTHALPY'rlOXt 'CONSTANTS'/
15Xt'FUEL = ' r S A Y r 9Xr 'TEMPERATURE DATUM = O - DEG.R-'/
2bXt'CARBON ='rF5-2r'PERCl'rlbXr'DRY BULB (AMBIENT) = ' i F 3 - 0 1
3 ' DEG-F-'/bXr'HYDROGEN = ' r F 5 - 2 , ' PERC-'rl3Xr'REL- HUMIDITY'rbXr
l t ' = ' i F 3 - 0 r 1 PEPC-'/bXr'SULFUR = ' , F 5 - 2 r 1 PERC-'rlSXt
S'BAROMETRIC PRESS- = ' r F 7 . 3 r ' P S I A . ' / b X r ' N O N - C O M B . ='rFb-Zr
6 ' PERC-'//' EXHAUST'rlOXr'ENTHALPY ABOVE ABSOLUTE ZERO',
7' - BTU/LB'/' TEMP.'rlSXi'GAS TURBINE FUEL-AIR RATIO'/
8 ' DEG-F. -015 .O20 ,025 -030 ,035 -040 -045 -050'r
9' -055 -ObO'/)
0093 l b FORMAT(//'GAS TURBINE EXHAUST TEMPERATUREft7Xr'CONSTANTS'/
15X''FUEL = 'r3Altr17Xr'TEMPERATURE DATUM = O - DEG-R-'/
2bXr'CARBON = ' r F 5 - 2 r ' PERC-'rlbXr'DRY BULB (AMBIENT) = ' r F 3 - 0 1
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

3 ' DEG-F-'/bXr'HYDROGEN = ' , F 5 - 2 r 1 PERC.'rlltXr'REL- HUMIDITY'tbXr

Y ' = ' t F 3 - 0 , ' PERC1'/bXr'SULFUR='rF5-Zr'PERC-'r17Xt
5 ' BAROMETRIC PRESS- =',F7-3r'PSIA.'/bX,'NON-COMB- ='rFb-2,
6 ' PERC-I//' EXHAUST'tlbXt'TEMPERATURE - DEG-F'/
7'ENTHALPY1r13Xr'GAS TURBINE FUEL-AIR RATIO'/'BTU/LB -015'r
8' -020 -025 -030 -035 -0YO -0Y5'r
9' -050 -055 -ObO'/)
009lt 62 FORMAT(' TEMPERATURE' r 5 X i F 9 . l r ' DEG-FI//
1' DRY AIRfr9XrF9-5,2F15-2/' MOISTURE',8XrF9-5r2Fl5-2/
2 ' CARBON I N FUEL ' r F 9 - 5 r 2 F 1 5 - 2 / ' HYDROGEN I N FUELtiF9-5r2F15-2/
3 ' SULFUR I N FUEL 'rF9,5,2F15-2/' NON-COMB. I N FUEL'rF8-5r15Xr
YF15-2/'TOTALS'rlOXrF9-5r15X1FL5-2//)
0095 32 FORMAT(1XrFlO,1rF13-lrFl2-4/)
0096 80 FORMAT(1XvFb-OrlOF7-1)
0097 82 FORMAT(lXrFb.l,F8-lt9F7-1)
0098 92 F O R M A T ( / / t 1 9 X r ' T O T A L ' r 8 X r t C O M Be P R O D U C T S'r9Xr
l'NON-'/lSXr' IN DRY A I R ' r 3 X r ' 0 2 ' r b X r ' C 0 2 ' r 5 X t ' S O ~ ' ~ 5 X r ' " r 9 X ~
2'COMB-'//' DRY A I R t r 8 X r 2 F 8 - 4 / ' MOISTURE'r7XtF8.'tr32XrF8-'t/
3' FUEL CARBON ' r F 8 - 4 - 8 X t ' ( ' t F 5 - 3 r 1 ) ' r F 8 - l t / ' FUEL HYDROGEN ' I
YF8-'tr8X,' ( ' r F 5 - 3 r ' ) ' i l b X r F 8 . l t / ' FUEL SULFUR ' tF8-lt19Xr ' ( ' r
C F 5 - 3 r ' ) ' r 8 X r F 8 - l t / ' FUEL NON-COMB- ' r F 8 - ' t / ' WEIGHT - LB ' r

b2F8.9,' ('rF5-3r')rYF8.Y/
7 ' INCR- ENTHALPY ' r 8 X r 5 F 8 - 2 / ' TOTAL ENTHALPY ' r i F 8 - 2 , ' ( ' t F 5 - 2 ,
8')'rltF8.2)
0099 99 STOP
0100 END
O001 SUBROUTINE ENTHAL
0002 COMMON X A ( ~ ~ ) , X B ( ~ ~ > ~ F L ( ~ ) ~ T G T ( ~ ~ ~ ) ~ F G R ( ~ ~ ) ~ H G T ( ~ ~ ~ ) ' H G F ( ~
lHPTrHSPrTGF(ltS,lO>rWFGrWMArWTGiWDArWAGrWMGrWFErWCGtPCFrPHF~HIA~
~RAK,HCOrHIMrHOX,HIC,HIH,HAD,HMOrHCB~HHY,WTP~N~J~WHG~IPO~WOC~WOH~
3WOSrWPOrWCXtFSR(11)rWFStWMJ~WSUrPSFtHISrHSUrHSO~WSXrWHX~WPH~WPT~
ltHOPiHCPtHMP,PDFrPMFrPNFrPOF,PUF,PNC,WOF,WNFrWDF~WUFrWNC~HNC
0003 WFG=(WDA+WMA)*FGR(J)
0009 WFS=(WDA+WMA+WMJ+WFG)*FSR(J)
0005 WTG=WDA+WMA+WFG+WFS+WMJ

0006 WAG=WDA/ WTG

O007 WMG=(WMA+WMJ)/WTG
0008 WFE=(WFG+WFS)/WTG
0009 WCG=PCF*WFE/lOO-
O010 WHG=PHF*WFE/lOO-
O011 WSU=PSF*WFE/100-
0012 WOF=POF*WFE/100.
0013 WNF=PNF*WFE/lOO-
0019 WDF=PDF*WFE/lOO-
O015 WMF=PMF WFE / 1O O * -
0016 WUF=PUF*WFE/lOO-
0017 WNC=WOF+WNF+WDF+WMF+WUF
0018 WTP=WAG+WMG+WCG+WHG+WSU+WNC
0019 RAK=TGT(N)+959-7
0020 HIA=-1-15203+2-97795E-Ol*RAK-2~335b8E-O5*RAK**2+
12~38185E-08*RAK**3-b~793b9E-l2*RAK**9+b~82532E-lb*RAK**5
0021 HC0~19~00137*RAK/100~+~67027*~RAK/100-~**~-~87505E-02*
l(RAK/100-)**3-8-573b9*(10O-/RAK)
0022 HIM~90~83193*RAK/100~+-3b7lO*~RAK/lOO-~**2+-OblbOE-O2*
1(RAK/100~)**3+39~9235b*lOO-/RAK
0023 HOX~19~75583*RAK/100~+~29852*~RAK/lOO-~**2--27109E-O2*
1(RAK/100~)**3+18~86205*10O-/RAK
0029 HS0=11~10611*(RAK/100-)+-92328*(RAK/100~~**2
1-.b0599E-2*(RAK/100~)**3+-b7880*(lOO~/RAK)
0025 HIC=(3-659Y*HCO)-(2-bbY9*HOX)
0026 HIH=(8-937*HIM)-(7-937*HOX)
0027 HIS=(1-998*HSO)-(-998*HOX)
0028 HOM~23~39bLC3*RAK/100~+~l3898*~RAK/lOO~~**2-~OlbYE-2*~RAK/lOO~~
1**3+18-89712*(100-/RAK)
0029 HN0~23~69959*RAK/100~+-09769*~RAK/100~~**2+-05999E-2*~RAK/100-~
1**3+15~60296*(100~/RAK)
0030 HAD=WAG*HIA
0031 HMO=WMG*HIM
0032 HCB=WCG*HIC
0033 HHY=WHG*HIH
0039 HSU=WSU * H I S
0035 HOY=WOF*HOX
003b HNI=WNF*HNO
0037 HCD=WDF*HCO
0038 HCM=WMF*HOM
0039 HSD=WUF*HSO
OOYO HNC=HOY +HNI+HCD+HCM+HSD
0091 I F ( I P 0 - E Q - 5 ) GO TO 9 8
0092 IF(IP0-EQ-2-OR-IPO-EQ-9)GO TO Yb
0093 HGT(J)=HAD+HMO+HCB+HHY+HSU+HNC
OOYLC GO TO Lc7
0095 96 HGT(N)=HAD+HMO+HCB+HHY+HSU+HNC
0096 GO TO 97
0097 98 WOC=2.b699*WCG
0098 WCX= 3. b 699 WCG *
0099 WOH=7-937*WHG
0050 WHX=8-937*WHG
0051 WOS=-998*WSU

71
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ASME PTCm4.4 A3 W 0757b70 0 0 5 4 3 9 4 ô

~ ~

SECTION 7 ANSIIASME PTC 4.4 - 1981

0052 WSX=1,998*WSU
0053 WPO=WOC+WOH+WOS
005Lt. WPH=WMG+WHX
0055 WPT=WAG+WCX+WSX+WPH+WNC-WPO
0056 HOP=WPO*HOX
0057 HCP=WCX*HCO
0058 HSP=WSX*HSO
0059 HMP=WPH*HIM
O060 HPT=HAD+HCP+HSP+HMP+HNC-HOP
0061 97 RETURN
0062 END

72
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ASME P T C 8 q . q
~~ BL 9 0759670 005YL75 T 9

ANSI/ASME PTC 4.4 - 1981 SECTION 7

PROGRAM OUTPUT
PRINTOUT INDEX I P O = 1

TEST RUN FOR ASME PTC 9-9 J J Z

EXHAUST GAS ENTHALPY = I S 0 CONDITIONS, IPO=1
NO-2 O I L
59.0 0-0 19-696 0-0 60.00 1
100 0-0 0~015000-0 0-0
87-50 12-00 0.50 0-0 0-0 0-0 0-0 0-0

GAS TURBINE EXHAUST ENTHALPY CONSTANTS

FUEL = N0.2 O I L TEMPERATURE DATUM = 0- DEG-F
CARBON = 87-50 PERC- DRY BULB (AMBIENT) = 5 9 - DEG-F
HYDROGEN = 12-00 PERC- RELI HUMIDITY = 60- PERC-
SULFUR = 0-50 PERC- BAROMETRIC PRESS- = 19-696 P S I A -
NON-COMB. = O - O PERC-

EXHAUST ENTHALPY ABOVE ABSOLUTE ZERO BTU/LB -

TEMP . GAS TURBINE FUEL-AIR RATIO
DEG-F- -015 -020 -025 ,030 ,035 -090 -095 -050 -055 -060

100- 135.1 135-3 135.5 135-7 135.8 136-0 136-2 136-9 136-6 136-8
150- 197-3
200 -
159 5 - 197.5
159 8 -- 197 8
160-1
- 198.0
160.9
198 2- 198 5
l b 0 - 7 161-0
- 198-7
161.2
198-9
161-5
llt9-2
161-8
199 -9
-
162 1
250, 171-8 172 2 172 5 - 172 8 - 173-2 173-5 -
300- 18Y 2
350. 196-6
- 189 b
197.0
- 185 -0
197.5
185 9 185 -8 186-1
198 -9 198 8 -
173-8
186-5
179 2
186-9
179-5
187-3
179-8
167-6

YO0
Y50
--
209-1
221-6
209-6
222-2
210.1
222-8
197-9
210-6
223 - 3
211.1
223-9
211-6
229-5
199 - 3
212-1
199-7
212-6
225-0 225-6
200-1
213-1
22b-1
200-6
-
213 b
226-6
500- 239.2 23Y 9 - 235-5 236.2 236-8 237-9
550
600
296-9
-
259 7
- - 297-6
260-5
298-3 299.1
261.3 262-0
299 7
262-8
-263-6
250-9
238.0 238-6
251-1 251-8
269-3 265-0
239-2 239- 8
252-5 253-1
265-8 266-5
b50, 272-6 273-9 279-3 275 1 275-9 276-8 277-6 278-9 279.2 280-0
700- 285.5 286-9 287-9 288 3 289-2 290 1 291 -0 - 291-8 292-7 293-6
750. 298-5 299 5 - 300.5 301-5 302-5 303-5 309 - 9 305-9 306, 3307-3
800 311-6 312.7 313 8 319-9 315-9 317-0 318-0 319-0 320-1 321-1
850 329.8 326-0 327.2 328.3 329-9 330-6 331-7 332-8 333-9 335-0
900.
950.
338.1
351.5
339-9 390.6 391.8 393 1 399 3
0 - 395 5 - 396-6 397-8 399-0
352.8 359-1 355.5 3 5 6 - 8 358- 0 359-3 360-6 361-8 363-1
1000 -
369.9 366-3 367.8 369.2 370-5 371-9 373-3 379-6 375-9 377-3
1050. 378.5
1100 392.1
380.0 381-5
-
393 7 395 3 - 383.0 389-9 385-9 387-3 388-7 390-2 391 b -
396.8 398-9 399-9 901-5 903 -0 909-5 906-0
1150. 905-8
1 2 0 0 - 919-5
907-5 909-1
921-3 Y23.1
910-8
929 9 - 912-9 919-1
926-6 9 2 8 - 3
915 7
930-0
- 917-3
931-7
918-9 9 2 0 - 5
933-9 935-0
1250. Y33.9 935-3 937-1
1300
1350
--
997.3
961-3
Y99.3 951.3
963-9 965-9
939-0
953-2
967-5
990-8 992-6
955-1 Y57 o
969-5 971-5
- 999-9
958-9
973.5
996-2
960-8
975-9
998 -0 999-7
962-6
977.9
969-5
979-3
lY00. 975-9
1950. Y89 -5
977.5 979.7
991-8 999-0 996.3
981.8 989.0 986-1 988 1 - Y90 -i? 992-2 999-2
998-5 500 -7 502 - 9
1500
1550, 518. O
-
503-7 506-1
520-9
508-9
522 9 - 510-8
525 3 -
513-1 515-9
527.8 530 1 -
517-7
532-5
505- 0
519-9
539.9
507-1 509-3
522 1 529 3
-
537 2 539 5
-

73
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

EXHAUST ENTHALPY ABOVE ABSOLUTE ZERO BTU/LB -

TEMP - GAS TURBINE FUEL-AIR RATIO
DEG.F- ,015 .O20 .O25 -030 .O35 -090 ,095 -050 .o55 - Ob0
1600. 532-3 539-9 537-9 590-0 592-5 595.0 597.9 599 9 - 552 3 - 559-7
1650- 596-6 -
599 3 552.0 559-7 557-3 559-9 562-9 565-0 567-5 570.0
566- 7 569-9 572.1 579-8 577-5 580-1 582 8 585-9
1700-
1750.
1800.
561,1
575-6
590.1
563.9
578-5 581-9
593-1 596.1
589-2 587.0 589-8
599-1 602-0 609.9
592.6
607-8 610-6
595 9 - 598.1
613 5 -
600- 8
616 -3
1850. 609.7 607-8 610.9 bllc-O 617-0 620-0 623-0 626-0 628-9 631-8
1900- 619-3 -
622 5 625.7 628.9 632-1 635-2 638-3 691-3 699-9 697-9
1950. 639 O - 637-3 690-6 693-9 697-2 650.9 6 5 3 - 6 656-8 659-9 663-0
2000- 698 7 - 652-1 655-6 659-0 662-3 665.7 669-0 672-2 675-5 678-7

74
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

PRINTOUT INDEX I P O = 2

TEST RUN FOR ASME PTC 9-9 JJZ

EXHAUST GAS TEMPERATURE = I S 0 CONDITIONSI IPO = 2
NO-2 O I L
59-0 0.0 19-696 0-0 60-00 2
0- 130.0 0.01500 0.0 o -0
87.50 12-00 0-50 0.0 0-0 0-0 0-0 0-0

GAS TURBINE EXHAUST TEMPERATURE CONSTANTS

FUEL = NO-2 O I L TEMPERATURE DATUM = O- DEG-F
CARBON = 87-50 PERC- DRY BULB (AMBIENT) = 59- DEG-F
HYDROGEN = 12-00 PERC- REL- HUMIDITY = 6 0 - PERC-
SULFUR = 0-50 PERC- BAROMETRIC PRESS- = 19.696 P S I A -
NON-COMB- = O - O PERC-

EXHAUST TEMPERATURE DEG-F-

ENTHALPY GAS TURBINE FUEL-AIR RATIO
BTU/LB -015 ,020 -025 -030 -035 -090 -095 -050 -055 -060

130-0 79-5 78-5 78-0 77-5 76-5 76-0 75-5 79-51 79-0 73-5
190 *o 120-5 119.5 118-5 118-0 117-0 116-0 115-5 llY-5 119-0 113-0
150-0 161-5 160-5 159-5 158.5 157-5 156-5 155-5 159-5 153-5 152-5
160.0 202.0 201-0 200-0 198 5 - 197-5 196-5 195-5 199-5 193-0 192-0
170-0 2 9 3 - 0 291-5 290-0 239- O 237-5 236-5 235-0 239-0 232-5 231-5
180-0 283-5 282-0 280-5 279-0 277 5- 276-0 2 7 9 - 5 273-0 272-0 270-5
309-5
190-0 329-0 322-0 320-5 318-5 317-0 315-5 319-0 312.5 311-0
200 -0 369-0 362-0 360-0 358.5 356-5 355-0 353-0 351-5 350-0 398-0
210-0 909-0 902.0 900-0 398 -0396.0 399-0 392-0 390-5 388-5 386-5
220-0 999-0 991-5 939-5 937-0 935-0 933-0 ‘131-0 929-0 927-0 925-0
230-0 983-5 981-0 978-5 976-5 979-0 971-5 9 6 9 - 5 967-5 965-0 963-0
290 o 523.0 520.5 518-0 515-0 512-5 510-5 508-0 505-5 503-0 501-0
250-0 562-5 559-5 556-5 559-0 551 -0 598.5 596-0 593-5 591-0 538-5
260.0 601-5 598-5 595-5 592-5 589-5 587-0 589-0 581-5 578-5 576-0
270.0 690-5 637-0 639-0 631-0 627-5 629-5 622-0 619-0 616-0 613-5
280.0 679-0 675-5 672-0 669-0 665-5 662-5 659-5 656-5 653-5 650-5
290-0 717-5 719-0 710-5 707-0 703-5 700-0 696-5 693-5 690-5 687.0
300-O 756-0 752-0 -
798-5 799 5 791-0 737-5 739-0 ‘230-5 727-0 729-0
310-0 799-0 790-0 786.0 782-0 778-5 779-5 771.0 767-5 763-5 760-5
320 -0
330-O
832.0
870.0
827-5
865.5
823-5 819-5 815 5
861-0 856-5 852-5
- 811-5 807-5
898-0 899-0
809-0 800-0
890-0 836-5
796.5
832-5
390-0 907-5 902-5 898-0 893-5 889 -0 885-0 880.5 876-5 872-5 868-5
350 -0 995.0 990.0 935.0 930-5 925 5 - 921-0 917-0 912-5 908-0 909-0
3b0-0 982-0 977-0 972-0 967-0 962-0 957-5 953-0 998-5 S99-O 934-5
370-0 1019-0 1013.5 1008-5 1003-5 998.5 993-5 988-5 989-0 979-5 975-0
380-0 1056-0 1050-5 1095-0 1039 5- 1039-5 1029-5 1029-5 1019-5 1019-5 1010-0
390-0 1092-5 1087-0 1081-5 1075-5 1070 - 5 1065-0 1060-0 1055.0 1050-0 1095-0
900 -0 1129.5 1123.5 1117-5 1111-5 1106-0 1100-5 1095-0 1090-0 1085-0 1079-5
910-0 1165-5 1159-5 1153-5 1197-5 1191-5 1136-0 1130-5 1125-0 1119-5 1119-5
9 2 0 - 0 1202.0 1195.5 1189.5 1183-0 1177-0 1171-0 1165-5 1160-0 1159-5 1199-0
930-0 1238-0 1231.5 1225-0 1218-5 1212-5 1206.5 1200-5 1199-5 1189-0 1183-0

75
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 7 ANSI/ASME PTC 4.4 - 1981

EXHAUST ENTHALPY ABOVE ABSOLUTE ZERO BTU/LB -

TEMP. GAS TURBINE FUEL-AIR RATIO
DEG.F. -015 -020 -025 -030 -035 -090 -095 -050 -055 -060

990-o 1279.0 1259-0 12Y7.5 12Y1-O 1235.0 1229-0 1223-0

U b i - 0 12b0.5 1217-5
Y50-O 1310-0 1303-0 1296-0 1289-0 1282-5 1276-0 1269-5 12b3-5 1257-5 1251.5
YbO-O 1395.5 1338-5 1331-0 1329-0 1317-5 1310-5 1309.0 1297.5 1291-5 1285-5
970-0 1381-5 1373.5 1366-5 1359-0 1352.0 1395-0 1338-5 1332-0 1325.5 1319-0
Y80 -0 1916-5 1909-0 1901.5 1399.0 1386-5 1379-5 1372-5 1366-0 1359.0 1352-5
990-0 1952-0 1999-0 193G-5 1928.5 1921-0 1919-0 1906-5 1900-0 1393-0 1386-0
500 - 0 1987-5 1979-O 1971-0 1963-0 1955-5 1998.0 1990-5 1933-5 1926-5 1919.5
510-0 1522-5 1519-0 1506-0 1997-5 1990-0 1982-0 1979-5 1967-0 1960.0 1953-0

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

PRINTOUT INDEX I P O = 3

TEST RUN FOR ASME PTC 9-9 JJZ

EXHAUST GAS ENTHALPY = I S 0 CONDITIONSi IPO=3
NATURAL GAS
59-0 0-0 1 9 - 6 9 6 0-0 6 0 - 0 0 3
500- 0.0 0,02500 0-0 0-0
75-00 2 2 - 5 0 0-50 0-0 0-50 0-50 0-50 0-50

TEST RUN FOR ASME PTC 9-9 JJZ

EXHAUST GAS ENTHALPY = I S 0 CONDITIONSi IP0=3
NATURAL GAS

CARBON = 75-00 PERC, SULFUR = 0.50 PERC-

HYDROGEN = 2 2 - 5 0 PERC- NON-COMB- = 12-00 PERC-

COMPONENT PRODUCT INCR - PRODUCT

WEIGHT ENTHALPY ENTHALPY
PER LB BTU/LB BTU/LB

TEMPERATURE 500-0 DEG-F

DRY A I R
M O ISTURE
-
O 96996
0-00615
-
230 99
929-81
223 99
2-69
-
CARBON I N FUEL 0-01829 -
1 2 1 99 2.23
HYDROGEN I N FUEL 0-00599 2158-09 11 8 9 -
SULFUR I N FUEL 0,00012 68-66 0.01
NON-COMB- I N FUEL 0,00099 o. o5
TOTALS 1-00000 290-72

TEMPERATURE 1 0 0 0 - 0 DEG-F

DRY AIR -
O 96996 358-55 397 60 -
MOISTURE 0-00615 678 - 5 2 9-17
CARBON I N FUEL 0-01829 279-96 5-12
HYDROGEN I N FUEL 0-00599 3Ltll-YLt 1 8 -72
SULFUR I N FUEL 0-00012 -
133 02 0-02
NON-COMB- I N FUEL 0-00099 0-07
TOTALS 1-00000 375 -72

TEMPERATURE 1 5 0 0 - 0 DEG-F

DRY A I R 0-96996 993 -59 9 7 8 -97

MOISTURE 0- O0615 997-56 5-82
CARBON I N FUEL 0,01829 971-75 8-63
HYDROGEN N
I FUEL o-aostq 9792-29 26-30
SULFUR I N FUEL 0-00012 206.37 0-03
NON-COMB- I N FUEL O-OOOLt9 0-10
TOTALS 1-00000 519-37

77
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

SECTION 7 ANSI/ASME PTC 4.4 - 1981

PRINTOUT I N D E X I P O = 9

TEST RUN FOR ASME PTC 9.9 JJZ

EXHAUST GAS TEMPERATURE = I S 0 CONDITIONSI IPO=9
NATURAL GAS
59-0 0 - 0 19-696 0-0 60-00 9
50- 200.0 0,02500 0 - 0 0-0
75-00 2 2 - 5 0 0-50 0.0 0-50 0-50 0.50 0-50

TEST RUN FOR ASME PTC 9-9 JJZ

EXHAUST GAS TEMPERATURE I S 0 CONDITIONSI - IPO= 9
NATURAL GAS

CARBON = 75.00 PERC- SULFUR = 0 - 5 0 PERC-

HYDROGEN = 22-50 PERC- NON-COMB- = 2 - 0 0 PERC-

ENTHALPY TEMPERATURE FUEL-AIR

BTU/LB DEG- F RATIO

200-0 393-0 0-0250

300.0 729-0 0-0250
900-0 1087-0 0,0250
500-0 -
1939 5 0-0250

PRINTOUT I N D E X I P O = 5

TEST RUN FOR ASME PTC 9 - 9 JJZ

EXHAUST GAS ENTHALPY I S 0 CONDITIONSI IP0=5-
NATURAL GAS
59.0 0.0 19-696 0 - 0 60.00 5
1000- 0 - 0 0,02500 0 - 0 0.0
75.00 22-50 0 - 5 0 0.0 0-50 0.50 0-50 0-50

CARBON = 75.00 PERC- SULFUR = 0 - 5 0 PERC-

HYDROGEN = 22.50 PERC- NON-COMB- = 2-00 PERC-

TOTAL C O M B - P R O D U C T S NON-
I N DRY A I R 02 c02 502 H20 COMB.

DRY A I R 0-9695 0-9695

MOISTURE 0-0061 0.0061
FUEL CARBON O - 0183 (0-099) 0-0670
FUEL HYDROGEN 0,0055 (0-099) 0-0990
FUEL SULFUR o. O001 (0-000) o- 0002
FUEL NON-COMB- 0-0005
WEIGHT LB - 1 ~ 0 0 0 0 0,9695 (0-092) 0-0670 0-0002 0-0552 0.0005
I N C R - ENTHALPY 358.55 3 3 - 1 7 319-39 233-51 678-52
TOTAL ENTHALPY 375-70 397.60 (30-88) 21.91 0-06 37-95 0-07

78
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ANSI/ASME PTC 4.4 - 1981 SECTION 7

7.4 Discussion of Effectiveness temperature leaving the evaporator would be reduced to

the temperature of the saturated water in the evaporator.
7.4.1 General Discussion With infinite economizer surface area the temperature
Effectiveness quantifies the heat transfer performance of the water leaving the economizer and entering the
of a heat recovery device and i s the ratio of the enthalpy evaporator would be raised to gas temperature leaving the
drop of the gas to the maximum enthalpy drop of the gas evaporator and would equal drum saturation temperature.
which i s theoretically possible. In the MTP case with an evaporator pinch the gas and
EF = A hG f A hG MTP water temperatures a t the evaporator economizer junction
are known to be equal to evaporator saturation tempera-
The maximum enthalpy drop and transfer of heat ture from which their enthalpies can be found.
theoretically possible would occur with infinite heat Knowing the gas enthalpy drop from superheat inlet
transfer surface when the gas and water temperatures to the temperature of the drum saturated water and the
would coincide at one or more points (pinch points) in water side duties above saturation and the total water
the boiler. In heat recovery boilers the temperature pinch side duty, the gas enthalpy drop from inlet to the super-
may occur wherc the gas leaves the evaporator (evapora- heater to the outlet of the economizer is calculated by
tor pinch) or the economizer (economizer pinch). Un-

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
proportionality.
fired HRSG will generally have an evaporator pinch and
boilers fired to more than 30 percent of the heat input AhG MTP = AhG above saturation x Q total
will generally have an economizer pinch. Qabove saturation
In the case o f an evaporator pinch MTP enthalpy drop where
requires infinite heat transfer surface area in evaporator
AhG MTP = maximum theoretically possible (MTP)
and economizer so the temperatures of the gas leaving the enthalpy drop of the gas
evaporator and the water leaving the economizer both are
Q = water side duty
equal to the saturated water steam temperature in the
evaporator. In the case of an economizer pinch MTP en- Without blowdown, extraction or induction of water
thalpy drop requires infinite h e a t transfer surface in the (which is the preferred test condition) the water flow in
economizer so the temperature of the gas would be cooled economizer, evaporator and superheater are equal and
to the temperature of the water entering the economizer. the MTP gas enthalpy leaving the economizer can be
Temperature profiles of heat recovery boilers with found by proportionality of H 2 0 enthalpy rise above
evaporator and economizer pinches are shown in para- and below saturation.
graphs 5.4.4.1 and 5.4.4.2. Using terms as defined in paragraph 5.4.4.5 and
Calculations of effectiveness requires different expres- where inlet and outlet H 2 0 flows are equal
sions for evaporator and economizer pinches. When the
location of the pinch is in doubt effectiveness should be
calculated both for evaporator and economizer pinches.
The expression which is appropriate will yield the higher
EF -- Enthalpy change of the exhaust gas
effectiveness value. The expression for an evaporator MTP enthalpy change of the exhaust gas
pinch i s found in 5.4.4.3.1 and for economizer pinch in x 100%
5.4.4.4.1.

7.4.2 Derivation of Effectiveness Equations

An evaporator pinch will occur when the proportion
of heat in the gas above saturation temperature relative
to the heat in the gas above economizer water inlet
temperature is less than the proportion of heat required Where water and steam flows are not equal the expres-
by the HzO above saturation relative to the total beat sion for AhG MTP and effectiveness with evaporator pinch
required by the HzO with equal water and steam flows. are expanded to include terms for water and steam flow.
An evaporator pinch will occur when

7.4.3 Derivation of Evaporator Pinch Effectiveness

With infinite evaporator heat transfer area the gas

x 100% 7.5.1 Introduction

Heats of combustion of solid and liquid fuels are
7.4,4 Derivation of Effectiveness Equation - Economizer measured in the fixed volume of an oxygen bomb
Pinch calorimeter.
With an economizer pinch infinite surface area would Heat of combustion of a gaseous fuel is meas-
reduce the gas temperature to equal the water inlet ured in the constant pressure of a continuous flow
temperature calorimeter.
AhG MTP = hGi - hGw4 In the calorimeters the water produced by combus-
tion of the hydrogen in the fuel is condensed to liquid
Effectiveness economizer pinch releasing the latent-heat of condensation which is in-
cluded in the measured heat of combustion, Heat of
combustion including the latent heat of the water pro-
duced is the higher heating value (HHV) of combustion.
Effectiveness is influenced by extraction, blowdown, This i s synonymous with the gross heat of combustion.
etc. A test for effectiveness should preferably be con- The water of combustion in commercial equipment
ducted without extraction or blowdown or should be is not condensed so the latent heat i s not usable. The
conducted with the design proportion of such flows. lower heating value (LHV) of combustion is calculated
from gross heating value omitting the latent heat and is
7.4,5 Other Considerations of Test Method used throughout this code. The lower heating value is
The gas inlet temperature of low fired heat recovery synonymous with net heat of combustion.
boilers produces a temperature pinch which prevents
a low stack temperature. Because of the temperature 7.5.2 Terminology
pinch the highest boiler efficiency theoretically possible Heat of combustion is also called heating value or HV,
may be 70 percent. A boiler with 60 percent efficiency Gross when referred to heat of combustion is also called
is then 86 percent as efficient as possible (100 x 60 f higher and net is called lower.
70). The effectiveness of the same boiler would be 86 per- Thus:
cent truly reflecting the merit of the boiler, which i s not
properly expressed by efficiency. Gross heat of combustion = Higher Heating Value
Efficiency calculated by input-output is strongly in- = H.H.V.
fluenced by the accuracy of gas flow measurement. Ef- Net heat of combustion = Lower Heating Value
ficiency calculated by the loss method i s not materially = L.H.V.
influenced by gas flow measurement and effectiveness is
not affected at all. The heat of combustion of solid and liquid fuels
The performance criteria less influenced by gas flow measured in the bomb calorimeter must be converted
measurement require less elaborate gas flow measure- from the constant volume conditions in the bomb to
ment equipment and avoid the need to precisely adjust the constant pressure condition of the practical applica-
performance to the design flow or to perform the test tions covered by this Code.
precisely at design conditions. The hydrogen in fuel and the water produced there-
Precise establishment of the gas flow during a per- from i s solely responsible for differences between higher
formance test for efficiency by the loss method is not heating value, lower heating value, constant volume and
very important and for effectiveness is unnecessary. constant pressure heats of combustion.
Effectiveness is less sensitive to boiler gas inlet tem- On the basis of the hydrogen fraction of the dry fuel
perature than is efficiency. Adjustments to effective- the conversions are depicted on Fig. 7.5.1.
ness for off design gas inlet temperature i s less critical Use of the Fig. 7.5.1 is demonstrated by conversion
with effectiveness. of higher heating value of combustion for a No. 2 type
Radiation and convection losses will improve meas- oil measured in a bomb calorimeter to other bases in
ured effectiveness. Radiation and convection normally the following example.
are of small relative magnitude and do not materially
affect effectiveness or efficiency. When evaluating by 7.5.3 Example
effectiveness, radiation and convection may separately Oil with 12.06 percent H yields 19300 Btu per Ib when
be quantified by methods in paragraph 4.5.4. tested in a bomb calorimeter.

80
--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---

ANSI/ASME PTC 4.4 - 1981 SECTION 7

given in the 1967 ASME steam tables for 77°F (1050.1)

has been used herein, Confusion may also arise because
of failure to adequately define heat of combustion. For
example it may not be stated whether higher heating
value i s a constant volume or constant pressure value.
Confusion may also occur with lower heating value but
lower heating value can usually be taken as being a con-
stant pressure value.
The particular conditions which apply to the pre-
sented values can usually be ascertained by use of the
correlations herein, For gaseous fuels values for con-

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
stant pressure usually are given. For liquids and solids
the higher heating value of combustion is usually de-
rived from a bomb test in a constant volume.

7.5.4 Gaseous Fuels

The conversions between higher and lower heating
values for gaseous fuels are the same as for liquid and
solid fuels. Conversions from constant volume to con-
stant pressure for gaseous fuels are different from liquid
Example of Use of Diagram or solid fuels because the fuel being gaseous before com-
Gross heat of combustion a t constant pressure bustion results in a different interchange of heat and PV
= Net heat of combustion a t constant volume energy.
plus Ib HJlb fuel x 9120
Heating values of gaseous fuels are determined in
constant pressure calorimeters so the constant volume
FIG. 7.5.1. to constant pressure conversion is a theoretical value only
and is not required in practice. For gaseous fuels the
conversion of importance is from higher to lower heat-
Higher heating value of combustion in a const. vol. ing value at constant pressure equal to a deduction of
= 19300 Btu/lb 9384 Btu per pound of hydrogen.
Lower heating value const. vol. = 19300 - 0.1 206 x
8856 = 18232 Btu/lb 7.5.5 Adjustment for Calorimeter Test Base Temperature
Higher heating talue const. press. = 19300 + 0.1 206 x
The higher heating value of combustion includes the
264 = 19332 Btullb latent heat of condensation of the water of combustion
Lower heating value const. press. = 19300 - 0.1 206 x
which varies by about 0.56 Btu per "F per ib of water
91 20 = 18200 Btu/lb
adjacent to the standard temperature for calorimeter
ASTM D 2382, Heat of Combustion of Hydrocarbon tests. This converts to 5 Btu/"F per Ib H2 in the fuel.
Fuels by Bomb Calorimeter (High Precision Method), Higher heating values of combustion may be adjusted
requires that all results be quoted for a base temperature to different base temperatures by this factor.
of 25°C (77°F) as used in this Code.
Other codes and tabulations quote heating values at 7.5.6 Accuracy and Consistency of Heats of Combustion
temperatures of 60 and 68°F (20°C) at which the con- Tests for heat of combustion are subject to unavoid-
versions are different. able inconsistencies, Discrepancies of 50 Btu per Ib are
Many tables of heats of combustion will be found to regarded as normal by ASTM.
differ by small amounts from the conversions found Recognizing the possible discrepancies in determina-
herein. Differences may be due to use of different values tion of heat of combustion small differences between
for the latent heat of vaporization of water. The value sources o f information are within the accuracy of tests.

PERFORMANCE TEST CODES NOW AVAILABLE

PTC41 .Air Heaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1968)

PTC 23 - Atmospheric Water Cooling Equipment . . . . . . . . . . . . . . . . .(1958)
PTC 8.2 - CentrifugalPumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1965)
PTC 12.1 - Closed Feedwater Heaters . . . . . . . . . . . . . . . . . . . . . . . . . (1978)
PTC 4.2 - Coal Pulverizers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1969)
PTC 10 - Compressors and Exhausters . . . . . . . . . . . . . . . . . . . . . . . (1965)
PTC 39.1 - Condensate Removal Devices for Steam Systems . . . . . . . . . . . .(1983)
PTC 2 - Definitionsand Values . . . . . . . . . . . . . . . . . . . . . . . . . . . (1980)
PTC 9 - DisplacementCompressors,Vacuum Pumps and Blowers . . . . . . .(1970)
PTC 7.1 - Displacement Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1962)
PTC 12.3 - Deaerators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1977)
PTC 27 - Determining Dust Concentration in a Gas Stream . . . . . . . . . . . .(1957)
PTC 38 - Determining the Concentration of Particulate Matter in a
Gas Stream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1980)
PTC 28 - Determining the Properties of Fine Particulate Matter . . . . . . . . .(1965)
PTC 3.1 - Diesel and Burner Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . (1958)

--`````,,,,`,`````,```,``,,`,,,-`-`,,`,,`,`,,`---
PTC 21 - Dust Separating Apparatus . . . . . . . . . . . . . . . . . . . . . . . . . (1941)
PTC 24 - Ejectors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1976)
PTC 14 - Evaporating Apparatus . . . . . . . . . . . . . . . . . . . . . . . . . . . (1970)
PTC 16 - Gas Producers and Continuous Gas Generators . . . . . . . . . . . . .(1958)
PTC 4.4 - Gas Turbine Heat Recovery Steam Generators . . . . . . . . . . . . .(1981)
PTC 22 - Gas Turbine Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . (1966)
PTC 3.3 - GaseousFuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (196.91
PTC 1 - General Instructions . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1980)
PTC 18 - Hydraulic Prime Movers . . . . . . . . . . . . . . . . . . . . . . . . . .(i 949)
PTC 31 - Ion Exchange Equipment . . . . . . . . . . . . . . . . . . . . . . . . A19731
PTC 33 - Large Incinerators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (197B)
PTC 32.1 - Nuclear Steam Supply Systems . . . . . . . . . . . . . . . . . . . . . . (1969)
PTC 20.2 - Overspeed Trip Systems for Steam Turbine-Generator Units . . . . .(1965)
PTC 20.3 - Pressure Control Systems Used on Steam Turbine Generator
Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . í 1970)
PTC 18.1 -Pum ing Modeof Pump/Turbines . . . . . . . . . . . . . . . . . . . . . (1978)
9
PTC 17 - Reciprocating Internal-Combustion Engines . . . . . . . . . . . . . . .(1973)
PTC 7 - Reciprocating Steam-Driven Displacement Pumps . . . . . . . . . . .(1949)
PTC 5 - Reciprocating Steam Engines . . . . . . . . . . . . . . . . . . . . . . . (194'3)
PTC 25.3 - Safety and Relief Valves . . . . . . . . . . . . . . . . . . . . . . . . . . (19715)
PTC 3.2 - Solid Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1954)
PTC 20.1 - Speed and Load Governing Systems for Steam Turbine-
Generator Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1977)
PTC 29 - Speed-Governing Systems for Hydraulic Turbine-Generator
Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . í 1965)
PTC 26 - Speed-Governing Systems for Internal Combustion Engine-
Generator Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1962)
PTC 12.2 - Steam Condensing Apparatus . . . . . . . . . . . . . . . . . . . . . . . (1955)
PTC 4.1 - Steam-GeneratingUnits . . . . . . . . . . . . . . . . . . . . . . . . . .(1964 ) .
PTC 6 - Steam Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1976)
PTC 6A - Appendix A to Test Code for Steam Turbines . . . . . . . . . . . . . .(1964)
PTC 6 Report - Guidance for Evaluation of Measurement
Uncertainty in Performance Tests of Steam Turbines . . . . .(1969)
PTC 6s Report - Simplified Procedures for Routine Performance Tests
os Steam Turbines . . . . . . . . . . . . . . . . . . . . . . . . . (1970)
PTC 32.2 Report - Methods of Measuring the Performance of Nuclear
Reactor Fuel in Light Water Reactors . . . . . . . . . . . . . .(1978)

Copyright ASME International

Provided by IHS under license with ASME
Document provided by IHS Licensee=foster wheeler /5956413001, 02/20/2005
23:56:18 MST Questions or comments about this message: please call the Document
DO0043
Policy Group at 303-397-2295.

ASME PTC 4.4-1981 Gas Turbine Heat Recovery Steam Generators
No ratings yet
ASME PTC 4.4-1981 Gas Turbine Heat Recovery Steam Generators
90 pages
Asme PTC 4.4. - 1981
No ratings yet
Asme PTC 4.4. - 1981
90 pages
Field Testing The Performance of Gas Turbine Exhaust Heat Recovery Steam Generators (PDFDrive)
No ratings yet
Field Testing The Performance of Gas Turbine Exhaust Heat Recovery Steam Generators (PDFDrive)
15 pages
Fired Steam Generators: ASME PTC 4 - 2013
No ratings yet
Fired Steam Generators: ASME PTC 4 - 2013
2 pages
Appendix C Asme Performance Test Code List
No ratings yet
Appendix C Asme Performance Test Code List
4 pages
47636
No ratings yet
47636
3 pages
ASME PTC 4.2-1969 - Coal Pulverizers (Note Reaffirmed)
No ratings yet
ASME PTC 4.2-1969 - Coal Pulverizers (Note Reaffirmed)
27 pages
ASME
0% (3)
ASME
3 pages
ASME PTC 4.2 - (1997) Coal Pulverizers
No ratings yet
ASME PTC 4.2 - (1997) Coal Pulverizers
31 pages
PTC - The List of Codes
No ratings yet
PTC - The List of Codes
4 pages
ASME-PTC-6S Report (1988) + ERR 1
No ratings yet
ASME-PTC-6S Report (1988) + ERR 1
150 pages
2011 ASME GT Inlet Air Cond Equip
100% (1)
2011 ASME GT Inlet Air Cond Equip
138 pages
PTC-Performance Test Codes List
No ratings yet
PTC-Performance Test Codes List
6 pages
ASME PTC 6S Reporte 1988 Revisión de ASME PTC 6S Report 1970 R 1985
100% (2)
ASME PTC 6S Reporte 1988 Revisión de ASME PTC 6S Report 1970 R 1985
48 pages
ASME1
No ratings yet
ASME1
3 pages
Asme PTC 12.2-1998 PDF
100% (1)
Asme PTC 12.2-1998 PDF
86 pages
Asme PTC 22 2014
100% (2)
Asme PTC 22 2014
83 pages
Pulverizers: Supplement To Performance Test Code For Steam Generating Units
100% (1)
Pulverizers: Supplement To Performance Test Code For Steam Generating Units
27 pages
Asme, Ansi PTC 22 - 1997
No ratings yet
Asme, Ansi PTC 22 - 1997
46 pages
Asme PTC 4.2 - 1969
No ratings yet
Asme PTC 4.2 - 1969
27 pages
Asme PTC 4.3 - 1968
No ratings yet
Asme PTC 4.3 - 1968
31 pages
ANSI-ASME PTC 11-1984.ventiladores PDF
100% (1)
ANSI-ASME PTC 11-1984.ventiladores PDF
138 pages
ANSI-ASME PTC 11-1984.ventiladores PDF
No ratings yet
ANSI-ASME PTC 11-1984.ventiladores PDF
138 pages
Large Heavy-Duty Gas Turbines For Base-Load Power Generation and Heat Cogeneration
No ratings yet
Large Heavy-Duty Gas Turbines For Base-Load Power Generation and Heat Cogeneration
11 pages
Gas Turbine HRSG Performance Codes
No ratings yet
Gas Turbine HRSG Performance Codes
3 pages
ASME - Performance Test Codes
No ratings yet
ASME - Performance Test Codes
1 page
Asme PTC 22-2014 Gas Turbines
100% (4)
Asme PTC 22-2014 Gas Turbines
112 pages
PTC11
No ratings yet
PTC11
138 pages
Asme PTC 4
No ratings yet
Asme PTC 4
273 pages
8406 Steam Turbines
No ratings yet
8406 Steam Turbines
5 pages
Asme PTC
No ratings yet
Asme PTC
3 pages
ASME PTC 51 - Gas Turbine Inlet Air-Conditioning Equipment PDF
100% (1)
ASME PTC 51 - Gas Turbine Inlet Air-Conditioning Equipment PDF
138 pages
Steam Turbine Standards & Guidelines
No ratings yet
Steam Turbine Standards & Guidelines
5 pages
ASME Performance Test Codes: or Contact Steve Weinman, Director, Standardazation & Testing, ASME
No ratings yet
ASME Performance Test Codes: or Contact Steve Weinman, Director, Standardazation & Testing, ASME
5 pages
Waste Heat Boiler Deskbook PDF
100% (1)
Waste Heat Boiler Deskbook PDF
423 pages
List of ASME PTC Codes and Their Respective Titles
100% (1)
List of ASME PTC Codes and Their Respective Titles
2 pages
Industry Standards & Regulations: ASME - Performance Test Codes Collection
No ratings yet
Industry Standards & Regulations: ASME - Performance Test Codes Collection
2 pages
List of ASME PTC Codes and Their Respective Titles
100% (3)
List of ASME PTC Codes and Their Respective Titles
2 pages
Combined Cycle Power Efficiency
No ratings yet
Combined Cycle Power Efficiency
17 pages
L24 - Rankine Cycle
No ratings yet
L24 - Rankine Cycle
29 pages
ASME PTC 22 Gas Turbine Test Code PDF
100% (1)
ASME PTC 22 Gas Turbine Test Code PDF
46 pages
ASME PTC 22 (Gas Turbine Test Code)
100% (6)
ASME PTC 22 (Gas Turbine Test Code)
46 pages
Asme PTC 6 - 1996
No ratings yet
Asme PTC 6 - 1996
124 pages
PTC40
No ratings yet
PTC40
70 pages
Waste Heat Recovery Project
No ratings yet
Waste Heat Recovery Project
9 pages
Meherwan P Boyce - Gas Turbine Engineering Handbook-Elsevier Butterworth-Heinemann (2012) 2
No ratings yet
Meherwan P Boyce - Gas Turbine Engineering Handbook-Elsevier Butterworth-Heinemann (2012) 2
5 pages
ASME PTC-30-1991 - Air Cooled Heat Exchanger
No ratings yet
ASME PTC-30-1991 - Air Cooled Heat Exchanger
92 pages
12 2 58 Feg PG 6203 031 1 1
No ratings yet
12 2 58 Feg PG 6203 031 1 1
1 page
Combustion Turbine Innovations
100% (2)
Combustion Turbine Innovations
22 pages
136-Heat Recovery Steam Generator Technology Vernon L. Eriksen 9780081019405 Woodhead Publishing 2017 424 $235
100% (8)
136-Heat Recovery Steam Generator Technology Vernon L. Eriksen 9780081019405 Woodhead Publishing 2017 424 $235
425 pages
ASME Test Codes for Inspectors
No ratings yet
ASME Test Codes for Inspectors
2 pages
ASME PTC 46 Performance Test Code On Overall Plant Performance
No ratings yet
ASME PTC 46 Performance Test Code On Overall Plant Performance
191 pages
ASME Performance Test Codes Guide
100% (1)
ASME Performance Test Codes Guide
3 pages
ASME PTC 2-1980 Definitions and Values
No ratings yet
ASME PTC 2-1980 Definitions and Values
30 pages
ASME PTC 42-1988 R2004 Wind Turbines
No ratings yet
ASME PTC 42-1988 R2004 Wind Turbines
52 pages
Power Generation Market Insights
No ratings yet
Power Generation Market Insights
5 pages
Comparison of Is 2062 & Sa 36 Criteria IS 2062 SA 36
No ratings yet
Comparison of Is 2062 & Sa 36 Criteria IS 2062 SA 36
2 pages
Linceed Oil - VpCI - 422 Method Application
No ratings yet
Linceed Oil - VpCI - 422 Method Application
2 pages
Comp SA36, IS 2062, SA516 GR 60
No ratings yet
Comp SA36, IS 2062, SA516 GR 60
2 pages
ABMA Boiler 402 PDF
67% (3)
ABMA Boiler 402 PDF
74 pages
Water Wash Procedure For Economizer
100% (1)
Water Wash Procedure For Economizer
3 pages
NEMA & IEC Standards Guide
No ratings yet
NEMA & IEC Standards Guide
1 page
Fire Tube Boiler Design
100% (2)
Fire Tube Boiler Design
3 pages
Heating and Cooling Curve
No ratings yet
Heating and Cooling Curve
7 pages
HW10
No ratings yet
HW10
2 pages
Optimum Angle for NACA 632-215 Airfoil
No ratings yet
Optimum Angle for NACA 632-215 Airfoil
6 pages
Welded Joint Design Guide
No ratings yet
Welded Joint Design Guide
21 pages
Clausius Clapeyron Equation
100% (1)
Clausius Clapeyron Equation
3 pages
Automotive Hydrogen Storage System Using Cryo-Adsorption On Activated Carbon
No ratings yet
Automotive Hydrogen Storage System Using Cryo-Adsorption On Activated Carbon
12 pages
Fluid Power Ebook - Fluid Power Circuits Explained
No ratings yet
Fluid Power Ebook - Fluid Power Circuits Explained
474 pages
MSPU Training: By:-Brijesh Patel
No ratings yet
MSPU Training: By:-Brijesh Patel
19 pages
Heater
No ratings yet
Heater
29 pages
Retaining Wall Design Guide
No ratings yet
Retaining Wall Design Guide
8 pages
Effect of Dislocation Distribution On The Yield Stress in Ferritic Steel
No ratings yet
Effect of Dislocation Distribution On The Yield Stress in Ferritic Steel
5 pages
Pressure and Fluids Worksheet-1
No ratings yet
Pressure and Fluids Worksheet-1
4 pages
Whitepaper - Mechanical Testing of DMLS Parts
No ratings yet
Whitepaper - Mechanical Testing of DMLS Parts
10 pages
Reservoir Fliud Phase Behavoir
No ratings yet
Reservoir Fliud Phase Behavoir
50 pages
Analysis of The Thermal Environment in A Mushroom House Using Sensible Heat Balance and 3D CFD
No ratings yet
Analysis of The Thermal Environment in A Mushroom House Using Sensible Heat Balance and 3D CFD
8 pages
Site Investigation Final
0% (1)
Site Investigation Final
5 pages
Materials & Welding: Toughness
No ratings yet
Materials & Welding: Toughness
8 pages
Circular Water Tank (Rigid Joint)
No ratings yet
Circular Water Tank (Rigid Joint)
28 pages
Molar Enthalpy of A Chemical Change
100% (2)
Molar Enthalpy of A Chemical Change
2 pages
Part 8
No ratings yet
Part 8
4 pages
Converting Steel Weldments To Ductile Iron Castings
No ratings yet
Converting Steel Weldments To Ductile Iron Castings
5 pages
Anexo B Felder 4taed
No ratings yet
Anexo B Felder 4taed
27 pages
Design Considerations Orifice Plate 1590507843 PDF
100% (1)
Design Considerations Orifice Plate 1590507843 PDF
5 pages
Food Industry Dryers Overview
No ratings yet
Food Industry Dryers Overview
9 pages
Ahsanullah University of Science and Technology
No ratings yet
Ahsanullah University of Science and Technology
6 pages
Design and Fabrication of 3 Roller Sheet
No ratings yet
Design and Fabrication of 3 Roller Sheet
7 pages
CS Load Cases PDF
No ratings yet
CS Load Cases PDF
3 pages
Coke Drum Repair Techniques
No ratings yet
Coke Drum Repair Techniques
30 pages
GATE 700 Formula FAA Links and Other Links
No ratings yet
GATE 700 Formula FAA Links and Other Links
6 pages
Maritime CFD Software for Researchers
No ratings yet
Maritime CFD Software for Researchers
2 pages