ASME_PTC_46_(1996)

AN AMERICAN NATIONAL STANDARD8

ASMEPIC 46-1996

KEMA Documentatlecentrum

D . '1' 4 HUg12002

ARNHEM

~PerformanceTestCodeonOverall PlantPerformance

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Date of Issuance: October 15, 1997

This document will be r~vi~~dwhen toe Sqciety approves the issuance of the nextedition. There will be no addenda issued to ASME pic 46-1996.

Please Note: ASME issues written replies to inquiries concerning interpretation oftechnical aspects of this document. The interpretations are not part of the document.PTC 46-1996 is being issued with an automatic subscription service to the interpreta-tions that will be issued to it up to the publication of the next edition.

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ASME is the registered trademijrk of Th~ American Society of Mecllijnical Engin~ers.

This code or standard was developed under procedures accredited as meeting the criteria for AmericanNational Standards. The Consensus Committee that approved the code or standard was balanced to assure

that individuals from competent and concern~d interests have hijd an opportunity to pijrticipate. Theproposed code or standard WijS made ijvijilable for public review and comment which provides an

opportunity for additional public input from industry, acijd~mia, regulatory agenci~s, and the public-at-large.

ASME does not "approve," "rate," or "~ndorse" any item, construction, proprietary device, or activity.

ASME does not take ijny position with r~spect to the vijlidity of any patent rights ass~rted in connection

with any items mention~d il1 this document, and does not undertake to insure anYOne utilizing a standardagainst liability for infringement of ijny applicable Letters Pijtent, nor assume any such liability. Users ofa code or standard are expressly advised, that determination of the validity of any such patent rights, andthe risk of infringement of such rights, is entirely their own responsibility.

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ASME accepts responsibility for only those int~rpretations issued in accordance with governing ASMEprocedures and policies which preclude the issuance of interpretations by individual volunteers.

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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.

8

The American Society of Mechanical Engineers345 East 47th Street, New York, NY 10017

Copyright I!:>1997 byTHE AMERICAN SOCIETY OF MECHANICAL ENGINEERS

All Rights ReservedPrinted in U.S.A.

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",FOREWORD

(This Forward is nol a part of ASME PTC 46-1996.1

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C()de Origins

ASME Performance Test Codes (PTCs) have been developed and have long existed fordetermining the performance of most major components used in electric power productionfacilities. A Performance Test Code has heretofore not existed to determine the overall

performance of a power production facility. Changes in the electric power generationindustry have increased the need for a code addressing overall power plant performancetesting. In response to thes~needs, the ASMEBoardon PerformanceTestCodes approvedthe formation of a committee (PTC 46) in June 1991 with the charter of developing a codefor the determination of overall power plant performance. The organizational meeting ofthis Committee was held in September 1991. The resulting Committee included experi-enced and qualified users, manufacturers, and general interest category personnel fromboth the regulated and non-regulated electric power generating industry.

In developing this Code, the Committee reviewed common industry practices withregard to overall power plant and cogeneration facility testing. The Committee was notable to identify any general consensus testing methods, and discovered many conflictingphilosophies. The Committee has strived to develop an objective code which addressesthe multiple needs for explicit testing,methods and procedures, while attempting to providemaximum flexibility in recognition of the wide range of plant designs and the multipleneeds for this Code.

This Code was approved by the PIC 46 Committee on May 10, 1996. It was thenapproved and adopted by the Council as a Standard practice of the Society by action ofthe Board on Performance Test Codes on October 14, 1996. It was also approved as anAmerican National Standard by the ANSI Board of Standards Review on November 27,1996.

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8PERSONNEL OF PERFORMANCE TEST CODE COMMITTEE 46

OVERAll PLANT PERFORMANCE

(The following is the roster of the Committee at the time of approval of this Code.!

OffiCERS

-J. G, Yost, Chair

J. R. Friedman, Vice ChairJ. H. Karian, Secretary

COMMITTEE PERSONNEl

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P. G. Albert,General Electric Co.K.S. Brooks,JacobsSirrine EngineeringN. E. Cowden, Southern Electric InternationalM. J. Dooley, ABB CE ServicesH. W. Faire, Jr., Destec Energy, Ine.J. C. Stewart, Alternate, Destec Energy, Ine. (retired)J. R. Friedman, WestinghouseElectricCorp.M. C. Godden, Babcock & WilcoxS. J. Hand, Zurn/NepcoD. A. Horazak,ParsonsPowerGroup, Ine.T. S. Jonas, Black & VeatchJ. H. Karian,AmericanSociety of Mechanical EngineersW. C. Kettenacker, Performance Engineering, Ine.J. D. loney, Fluor Daniel, tne.P. M. McHale, McHale & Associates, Ine.J. D. McNeilly, Enron Engineering & Construction Co.R. R. Priestley,Power Technologies, Ine.W. C. Wood, Duke/Fluor Daniel

J. G. Yost, Resource Management International, Ine.

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CONTENTS

Foreword ......................................................Standards Committee Roster ........................................

tSection0123456

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Figures3.13.23.33.44.14.24.34.44.54.64.74.85.1

5.2

8 5.3

5.45.5

It

Tables1.13.13.23.33.4

Introduction '....................................Object and Scope........................................Definitions and Description of Terms... """""GuidingPrinciples........................................Instruments and Methods of Measurement. . . . . . . . . . . . . . . . . . . . . .CalculationsilndResults ...................................Report of Results .

Generic Test Boundary ....................................Typical Steam Plant Test Boundary ...........................Typical Combined Cycle Plant Test Boundary. . . . . . . . . . . . . . . . . . .Three Post-TestCases .....................................Five-WayManifold .......................................Four-WireRTDs .........................................Three-WireRTDs.........................................Flow-ThroughWell.......................................Duct Measurement Points ..................................Three-Wire Open Delta Connected Metering System. . . . . . . . . . . . . .Four-WireMeteringSystem.................................TypicaICorrectionCurve...................................Typical Test Boundaryfor a Power Plant RequiringApplicationof Heat

SinkCorrectionfactor~SAorcusA""""""""""""".Typical Test Boundaryfor a Power Plant RequiringApplicationof Heat

SinkCorrectionFactor~sBorcusB"""'""""""""""Typical Test Boundaryfor a Power Plant or Thermal Island Requiring

Application of Heat Sink Correction Factor ~sc or (Usc. . . . . . . . . . .Output Versus Throttle Steam Flow .................SteamTurbinePlantTestBoundary ................

Largest ExpectedTest Uncertainties...........................Design, Construction, and Stilrt-upConsiderations. . . . . . . . . . . . . . . .Guidance for EstablishingPermissibleDeviations FromDesign. . . . . . .TypicaIPretestStabilizationPeriods...........................Recommended Minimum Test Run Durations. . . . . . . . . . . . . . . . . . . .

vii

iiiv

1357

234765

889

202830303233404144

54

55

566263

412171919

Nonmandatory AppendicesA Sample Calculations

Combined Cycle Cogeneration Plant Without Duct FiringHeat Sink: Completely Internal to Test the BoundaryTest Goal: SpecifiedMeasurement Power ~ Fire to Desired Power

LevelbyDuctFiring """""'"

Sample CalculationsCombined Cycle Cogeneration Plant With Duct FiringHeat Sink: External to the Test BoundaryTest Goal: SpecifiedMeasurement Power ~ Fireto Desired Power

LevelbyDuctFiring.....................................Sample CalculationsCombined Cycle Cogeneration Plant Without Duct FiringHeat Sink: Cooling Tower External to th~ Test BoundaryTest Goal: Specified Disposition is Gas Turbine Base Loaded (Power

Floats) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Representation of Correction for Different Heat Sink Temperature than

Gas Turbine Air Inlet Temperature (As or (.<.Is)if Necessary, fQr aTypicaICombinedCyciePlant.............................

Sample CalculationsSteam Power Cogeneration PlantHeat Sink: River CQoling Water Flow within Test BQundaryTest Goal: Two Test Runs are Made with Different GoalsTest Run 1: Specified Corrected Power ~ Fireto Desired Corrected

PowerTest Run 2: Specified Disposition by Firing to Desired Throttle Flow

(PowerFIQats) ,....Uncertainty Analysis '".,

Ent~ringAirConeJitions ,.EnergyBalanceMethoeJ....................................Solid Fuel and Ash Sampling """""'".

5.1

5.2

5.3

5.4

5.5

B

C

Summary of Additive Correction Factors in Fundamental PerformanceEquations.............................................

Summary of Multiplicative Correction Factors in FundamentalPerformance Equations...................................

Examplesof Typical Cycles and Test Objectives ~ CorrespondingSpecific Performance Equations ............................

Change in Compressor Inlet Temperature over a 30% Range inEvaporator Cooler Effectiveness on a 80°F Day, with 80% RelativeHumidity.............................................

Required Test Series for Phased Construction Combined Cycle Plants. .

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viii

488

49

51

5961

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67

81

101 f\

121

125177181183185

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OVERALL PLANT PERFORMANCE ASME PTC 46-1996

SECTION 0 - INTRODUCTION

0.1 APPLICATIONS AND LIMITATIONS

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Power plants which produce secondary energyoutputs (j.e., cogeneration facilities) are includedwithin the scope of this Code. For cogenerationfacilities, there is no requirement for a minimumpercentage of the facility output to be in the formof electricity; however, the guiding principles, mea-surement methods, and calculation procedures arepredicated on electricity being the primary output.As a result, a test of a facility with a low proportionof electric output may not be capable of meetingthe expected test uncertainties of this Code.

This Code provides explicit procedures for thedetermination of power plant thermal performanceand electrical output. Test results provide a measureof the performance of a power plant or thermalisland at a specified cycle configuration, operatingdisposition and/or fixed power level, and at a uniqueset of base reference conditions. Test results can

then be used as defined by a contract for the basis. of determination of fulfillment of contract guarantees.Test results can also be used by a plant owner, foreither comparison to a design number, or to trendperformance changes over time of the overall plant.The results of a test conducted in accordance with

this Code will not provide a basis for comparingthe thermoeconomic effectiveness of different plantdesigns.

Power plants are comprised of many equipmentcomponents. Test data required by this Code mayalso provide limited performance information forsome of this equipment; however, this Code wasnot designed to facilitate simultaneous code level.testing of individual equipment. ASME PTCs whichaddress testing of major power plant equipmentprovide a determination of the individual equipmentisolated from the rest of the system. PTC 46 hasbeen designed to determine the performance of theentire heat-cycle as an integrated system. Wherethe performance of individual equipment operatingwithin the constraints of their design-specified condi-tions are of interest, ASME PTCs developed forthe testing of specific components should be used.likewise, determining overall thermal performanceby combining the results of ASME code tests con-

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ducted on each plant component is not an acceptablealternative to a PTC 46 test.

0.2 GUIDANCE IN USING THIS CODE

As with all PTCs, PTC 46 was developed primarilyto address the needs of contract acceptance orcompliance testing. This is not intended, however,to limit or prevent the use of this Code for othertypes of testing where the accurate determinationof overall power plant performance is required.

This Code is not a tutorial. It is intended for use

by persons experienced in performance testing. Aworking knowledge of power plant operations, ther-modynamic analysis, test measurement methods, andthe use, control, and calibration of measuring andtest equipment are presumed prerequisites. Properuse and interpretation of this Code also requires aworking knowledge of ASME Performance TestCodes. At a minimum, users of this Code shouldbe familiar and knowledgeable with the following:

. PTC 1, Genera/Instructions

. PTC 19.1, Measurement Uncertainty

Other PTC 19 Instrument and Apparatus Supple-ment series codes and the applicable PTC 3 serieson fuel sampling and analysis may need to beconsulted during the planning and preparationphases of a test. In addition, some measurementmethods specified in PTC 46 refer to PTCs for testingof specific equipment.

Use of PTC 46 is recommended whenever the

performance of a heat-cycle power plant must bedetermined with minimum uncertainty. It is suitablefor incorporation into commercial agreements asthe means of determining fulfillment of contractobligations. However, incorporation of PTC 46 intoa contract does not eliminate the need for test

planning. PTC 46 provides the protocol, or frame-work, for a test. As defined in Section 3, the useof PTC 46 requires the development of a detailedtest plan that must be approved by all parties to thetest. This test plan must be reviewed and approved byall parties prior to the start of testing.

OVERAll PLANT PERFORMANCE ASME PTC 46-1996

SECTION 1 - OBJECT AND SCOPE

1.1 OBJECT

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The objective of this Code is to provide uniformtest methods and procedures for the determinationof the thermal performance and electrical output ofheat-cycle electric power plants and cogenerationfacilities.

This Code provides explicit procedures for thedetermination of the following performance results:

. corrected net power

. corrected heat rate

. corrected heat input

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Tests may be designed to satisfy different goals,including:

. specifieq disposition

. spe~ified net corre~ted power

.. specified net power

1.2 SCOPE

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This Code applies to any plant size. It can beused to measure the performance of a plant in itsnormal operating ~ondition, with all equipment ina ~Iean and fully-functional condition. This Codeprovides explicit methods and procedures for com-bined-cycle power plants and for most gas, liquid,and solid fueled Rankine cycle plants. There is nointent to restrict the use of this Code for other typesof heat-cycle power plants, providing the explicitprocedures can be met. It does not, however, applyto simple-cycle gas turbine power plants (see ASMEPTC 22 instead). The scope of this Code begins fora gas turbine-based power generating unit when aheat-recovery steam generator is included within thetest boundary.

To test a particular power plant or cogenerationfacility, the following ~onditions must be met.

(a) a means mu5t be available to determine,through either direct or indirect measurements, all ofthe heat inputs entering the test boundary and all ofthe electrical power and secondary outputs leavingthe test boundary;It

(b) a means must be available to determine,

through either direct or indirect measurements, all ofthe parameters to correct the results from the test tothe basereference condition; .

(c) the test result uncertainties are expected to belessthan or equal to the uncertainties given in Subsec-tion 1.3 for the applicable plant type; and

(d) the working fluid for vapor cycles must besteam. This restriction is imposed only to the extentthat other fluids may require measurements or mea-surement methods different from those provided bythis Code for steam cycles. In addition, this Code doesnot provide specific references for the properties ofworking fluids other than steam.

Tests addressing other power plant performance-related issues are outside the scope of this Code.These include the following:

emissions tests: testing to verify compliance with regu-latory emissions levels (e.g., airborne gaseous and par-ticulate, solid and wastewater, noise, etc.), or requiredfor calibration and certification of emission-monitor-

ing systems.

operational demonstration tests: the various standard

power plant tests typi~ally conducted during start-up, or periodically thereafter, to demonstrate specifiedoperating capabilities (e.g., minimum load operation,automatic load control and load ramp rate, fuelswitching capability, etc.).

reliability tests: tests conducted over an extended pe-riod of days or weeks to demonstrate the capabilityof the power plant to produce a specified minimumoutput level or availability. The measurement meth-ods, calculations, and corrections to design conditionsincluded herein may be of use in designing tests ofthis type; however, this Code does not address thistype of testing in terms of providing explicit testingprocedures or acceptance criteria.

1.3 TEST UNCERTAINTY

The explicit measurement methods and procedureshave been developed to provide a test of the highest

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ASME PIC 46-1996 OVERALL PLANT PERFORMANCE

TABLE1.1LARGESTEXPECTEDTESTUNCERTAINTIES t

CorrectedH,at Rate

(%)

CorrectedNet Power

(OJ.)

1.0Type of Plant

Simple cycle with steam generation

Pescription

Gas turbine with exhaust heat used for

steam generation

1.S

CQmbineQ cycles Combined gas turbine and steam turbinecycles with or without supplementalfiring to a steam generator

1.5 1.0

1.5 1.0

Steam cycle

Direct steam input (e.g. geothermal)

1.5 1.0

Steam cycle

Steam cycle Consistent solid fuel

Consistent liquid or gas fuel

3.0 1.0t'

level of accuracy consistent with practical limita-tions. Any departure from Code requirements couldintroduce additional uncertainty beyond that consid-ered acceptable to meet the objectives of the Code.

It is recognized there is a diverse range of powerplant designs which can be generally categorizedfor purposes of establishing testing methods anduncertainties. The uncertainty levels achievable fromtesting in accordam::e with this Code are dependenton the plant type, spe(:ific design complexity, andconsistency of operation during a test. The largestexpected test uncertainties are given in Table 1. Ifa plant design does not clearly fall under one ofthe categories included in Table 1, the parties mustreach agreement on the most appropriate category.

The Table 1 values are not targets. A primary

philosophy underlying this Code is that the lowest

achievable uncertainty is in the best interest of allparties to the test. Deviations from the methodsrecommended in this Code are acceptableonly ifit can be demonstratedthey provide equal or loweruncertainty.

A pretest uncertainty analysis shall be performedto establish the expected level of uncertainties forthe test. Most tests conducted in accordance withthis Code will result in uncertainties that are lowerthan those shown in Table 1. If the pretestuncertaintyanalysis indicates that the test uncertainty is greaterthan that listed in Table 1, the test mustbe redesignedso as to lower the test uncertainty or the parties tothe test may agree, in writing, to higher uncertainty.A post-test uncertainty analysis is also required tovalidate the test. If the post-test uncertainty is higherthan the agreed IJpon maximum expected uncer-tainty, then the test is not valid. .

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SECTION 2 - DEFINITIONS AND DESCRIPTION OFTERMS

2.1 SYMBOLS

CUl,~l:additive correction factors to thermal heat in-put and power, respectively, to correct to base refer-ence thermal efflux

CU2t~2:additive correction factors to thermal heat in-put and power, respectively, to correct to base refer-ence generator power factor

CU3,~3:additive correction factors to thermal heat in-put and power, respectively, to correct to base refer-ence steam generator blowdown

CU4,~4:additive correction factors to thermal heat in-put and power, respectively, to correct to base refer-ence secondary heat inputs

CUSA'~SA:additive correction factors to thermal heatinput and power, respectively, to correct to base refer-ence air heat sink conditions

CUSB'~SB:additive correction factors to thermal heatinput and power, respectively,to correct to base refer-ence circulation water temperature

cusc,~sc: additive correction factors to thermal heatinput and power, respectively, to correct to base refer-ence condenser pressure

CU6'~6:ildditive correction filctors to thermal heat in-put and power, respectively, to correct to base refer-ence auxiliary loads

CU7'~7:additive correction factors to thermal heat in-put and power, respectively, to correct for measuredpower different from specified if test goal is to operateat a predetermined power. Can also be used if requiredunit operating disposition is not as required.

f31,al,~: multiplicative correction factors to thermalheat input, power, and heat rate, respectively, to cor-rect to base reference inlet temperature

f32,a2,f2: multiplicative correction factors to thermalheat input, power, and heat rate, respectively, to cor-rect to base reference inJet pressure

f33,a3,f3: multiplicative correction factors to thermalheat input, power, and heat rate, respectively, to cor-rect to base reference inlet humidity

f34,a4,f4: multiplicative correction factors to thermalheat input, power, and heat rate, respectively, to cor-rect to base reference fuel supply temperature

f3s,asJs: multiplicative correction factors to thermalheat input, power, and heat rate, respectively, to cor-rect to base reference fuel composition

fn:multiplicative correction factors to measured plantheat rate, dimensionless

HR: heat rate, Btu/kW-hr

HV: heating value, Btu/lbm

P: power, kW or MW

Q: subscripted with "meas" or "corr," Q is thermalheat input from fuel, Btu/hr. Otherwise refers to othersources of heat in the same units.

qm or m: mass flow, Ibm/hr

an: multiplicative correction factors to measured plantpower, dimensionless

f3n:multiplicative correction factors to measured plantthermal heat input, dimensionless

~n: additive correction factors to measured plantpower, kW

An: multiplicative correction factors to auxiliary loads

CUn:additive correction factors to measured plantheat input

2.1.1 Abbreviations Used in Subscripts

corr: corrected result to base reference conditions

CT: gas turbine

meas: measured or determined result prior to correct-ing to base reference conditions

Sf: steam turbine

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ASME PTC46-1996

2.2 TERMS

base reference conditions: the values of all the exter-

nal parameters, Le., parameters outside the testboundary to which the test results are corrected. Also,the specified secondary heat inputs and outputs arebase reference conditions.

bias (systematic) uncertainty: refer to PIC 19.1 fordefinition

consistent liquid or gas fuels: fuels with a heatingvalue that varies less than one percent over the courseof a performance test

consistent solid fuels: fuels with a heating value thatvaries less than two percent over the course of a per-formance test

cogeneration plant: any cycle which produces bothelectric power and at least one secondary output foruse in a process external to the test boundary

corrected heat input: the primary heat input enteringthe test boundary corrected to base reference condi-tions

corrected heat rate: the test calculated heat rate cor-rected to specified base reference and secondary out-put conditions

corrected net power: the net power leaving the testboundary at the test-specified operating conditionsand corrected to the specified base and secondaryoutput conditions

coverage: refer to PIC 19.1 for definition

error (measurement, elemental, random, sampling,bias, precision): refer to PIC 19.1 for definition

net power: the net plant electrical power leaving thetest boundary

heat sink: the reservoir to which the heat rejected tothe steam turbine condenser is transferred. For a cool-

ing pond, river, lake, or ocean cooling system, thereservoir is the body of water. For an evaporative ordry air cooled heat exchanger system, the reservoir isthe ambient air.

OVERALL PLANT PERFORMANCE

precision (random) uncertainty: refer to PIC 19.1 fordefinition

primary heat input: energy supplied to the cycle fromfuel or other source (such as steam) available for con-version to net power plus secondary outputs

primary variables: those used in calculations of testresults. They are further classified as:

Class 1: primary variables are those which have arelative sensitivity coefficient of 0.2 or greater

Class 2: primary variables are those which have arelative sensitivity coefficient of less than 0.2

secondary heat inputs: the additional heat inputs tothe test boundary which must be accounted for, suchas cycle make-up and process condensate return

secondary outputs: any useful nonelectrical energyoutput stream which is used by an external process

secondary variables: variables that are measured butdo not enter into the calculation of the results

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sensitivitycoefficient, absolute or relative: refer to PIC19.1 for definition

specified corrected net power test: a test run at aspecified corrected net power that is near to the designvalue of interest, for example, an acceptance test ofa stearn cycle plant where heat rate is guaranteed ata specificload, and partial-loadtests for developmentof heat rate curve conditions

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specifieddispositiontest:a test run at a specifiedplantdisposition with both load and heat rate determinedby the test. Examples of this test goal are valve-pointtesting on a steam cycle plant (including maximumcapability testing) and base-load testing on a com-bined cycle plant with or without duct firing.

specified net power test: a test run at a specified netpower regardless of ambient or other external condi-tions. An example of this test goal is acceptance teston a duct fired combined cycle plant with an outputguarantee over a range of ambient temperatures

testboundary: identifiesthe energy streams requiredto calculate corrected results

uncertainty: an estimate of the error. Refer to PIC19.1.

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QvERAU. PLANT PERFQRMANq

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ASME PTC 46-1996

SECTION 3 - GUIDING PRINCIPLES

3.1 INTRODUCTION

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This Section provides guidance on the conductof overall plant testing, and outlines the steps re-quired to plan, conduct, and evilluate a Code testof overall plant performance. The Subsections discussthe following:

. test plan (Subsection3.2)

. test preparations (Subsection3.3)

. conduct of test (Subsection3.4)

. calculation andreporting of results(Subsection3.5)

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The Code recognizes that different types of plantsand even different types of tests will have a uniquetest goal and operating mode. The following illustratethe different test goals considered by the Code andincludes examples.

(a) The test can be run at a specified dispositionwith both load and heat rate determined by the test.

. An example of this test goal would be valve-pointtesting on a steam cycle plant (including maximumcapability testing) or base-load testing on a combinedcycle plant with or without duct firing.

(b) The test can be run at a specified corrected netpower that is near to the design value of interest.Examples of this test would be an acceptance test ofa steam cycle plClnt where heat rate is guaranteed ata specific load, or partial-load tests for developmentof heat rate curves.

(c) The test can be run at a specified net powerregardless of ambient or other externill conditions. Anexample of this testgoill is an ilcceptilnce tast on a.duct-fired combined cycle plant with iln output guar-antee over a range of ambient temperatures.

Regardless of the test goal, the results of a Codetest will be corrected net power and either correctedheat rate or corrected heat input. The test must bedesigned with the appropri;1te goal in mind to ensureproper procedures are developed, the appropriateoperating mode during the test is followed, and thecorrect performance equations are applied. Section5 provides information on the general performanceequiltion and variations of the equation to supportspecific test goals.

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3.1.1 Test Boundary and Required Measurements.The test boundary identifies the energy streams whichmust be measured to calculate corrected results.

The test boundary is an accounting concept usedto define the streams that must be measured to

determine performance. All input and output energystreams required for test calculations must be deter-mined with reference to the point at which theycross the boundary. Energy streams within the bound-ary need not be determined unless they verify baseoperating conditions or unless they relate function-ally to conditions outside the boundary.

The methods and procedures of this Code have

been developed to provide flexibility in defining thetest boundary for a test. In most cases, the testboundary encompasses all equipment and systemson the plant site. However, specific test objectivesmay mandate a different test boundary. For example,an acceptance test may be required for a bottomingcycle that is added in the repowering portion of anupgrade.

For this Code to apply, the test boundary mustencompass a discrete electric-power-producing heatcycle. This meansthat the followingenergystreamsmust cross the boundary:

. all heat inputs

. net electrical output and any secondary outputs

For a particular test, the specific test boundarymust be established by the parties to the test. Someor all of the typical streams required for commonplant cycles are shown in Fig. 3.1.

Solid lines indicate some or all of mass flow rate,thermodynamic conditions, and chemical analysisof streamscrossing the test boundary,which haveto be determined to calculate the resultsof an overallplant performance test.

The properties of streams indicated by dashedlines may be req ired for an energy and massbalance, but may not have to be determined tocalculate test results.

Typical test boundariesfor the two mostcommonapplications - steam power plants and combinedcycle power plants - are shown in Figs. 3.2 and3.3, respectively.If these plants were cogeneration

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ASME PTC46-1996 OVERALLPLANT PERFORMANCE

- --,Test boundry

Fuel (heat)input Net

electricaloutput

Secondaryheat output(such asprocess return

Plant

Secondaryheat output(such asprocess steam)

Inlet air

Ultimate

I heat sink

i-+ Wa... haa'

L L--r -; -.Em;..'o..-_oj

Sotbent

. Required to be determinedfor test calculation

- - Notrequired to be determinedfor test calculation

FIG. 3.1 GENERIC TEST BOUNDARY

,---I

Stackgas

~ .. Ash residue. .

-t-; ,: I I. /

Stearn turbine Power

Fuel

Inlet air Boiler

I

I.. . . -~ Test boundary Heat sink

FIG. 3.2 TYPICAL STEAM PLANT TEST BOUNDARY

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Fuel

,--I

Inletair

I

I .-~

'= T.~ bound.~

ASME PTC 46-1996

Power

Steam turbine

1

t- - ~ SIa,""I

I

Heat sink

FIG. 3.3 TYPICALCOMBINED CYCLE PLANT TEST BOUNDARY

plants, secondary process input and output streamswould also be shown crossing the test boundary.

More definitive test boundaries for specific repre-sentative cycles are shown in Figs. 5.1, 5.2, 5.3, andin the appendices describing sample calculations.

3.1.2 Required Measurements. Some flexibility isrequired by this Code in defining the test boundary,since it is someWhatdependent on a particular plantdesign. In general, measurements or determinationsare required for the following streams.

3.1.2.1 Primary Heat Input. Measure or calcu-late fuel mass flow and heating value at the pointat which they cross the test boundary. The testboundary would typically be where the fuel entersthe plant equipment; however, the actual measure-ment may be upstream or downstream of that pointif a better measuring location is available and if theflow and fuel constituents at the metering point areequivalent to or can be accurately corrected to theconditions at the test boundary.

For gas and liquid fuels, the method of primaryheat input determination depends On the particularfuel and plant type. In most cases, it is determinedby the product of the measured fuel flow and theaverage fuel heating value. If the plant is a steamturbine plant fired by gas or liquid fuels, primaryheat input is sometimes determined by the productof the heat input to the steam and the inverse ofthe steam generator efficiency determined by the

energy balance method (also called the heat lossmethod).

For solid fuels of consistent constituency, theenergy balance method is required.

The use of higher heating value is preferred, butlower heating value may also be used. For solidfuel plants, the use of higher heating value requiresthat latent heat lossesbe accounted for in the energybalance method of evaluating plant thermal input.

The equations in Section 5 are applicable for eitherhigheror lowerheatingvalue.Equations utilized inthe calculations of results should be reviewed toverifythat all references to heating value are consist-ent (either all lower or all higher) and that allcorrection curves and heat balance programs arebased on the same definition of heating value.

3.1.2.2 Secondary Heat Inputs. Secondary heatinputs to the cycle may include process energyreturn; make-up, and low energy external heat recov-ery. Measurements to determine the mass flow andenergy level are required for correction to the basereference conditions.

3.1.2.3 Inlet Air For Combustion. The total pres-sure, the dry bulb temperature, and the specifichumidity are required for combustion air where theair enters the plant equipment. Measurement of inletair conditions is discussed in Appendix G.

3.1.2.4 Sorbents. The quality, analysis, andquantity of sulfursorbent or other chemical additives

9

ASME PTC 46-1996

which affect the corrected heat rate or corrected

net power must be measured for correction to thedesign conditions. Corrections for sorbent injectionrate are limited to variations attributable to differ-

ences between test and design fuel or sorbent charac-teristics, or due to variations attributable to ambientconditions.

3.1.2.5 Electric Power. The electric power out~

put from the plant is the net plant output at thetest boundary, which is generally on the load sideof a step-up transformer. The specific point of mea-surement may be at that location, or may be madeby measuring the generator outputs and the auxiliaryloads with corrections for step-up transformer lossesbased on transformer efficiency tests. The criteriafor selection of the specific measurement points isbased on a determination of the lowest achievable

uncertainty.

3.1.2.6 Secondary Outputs. Nonelectrical en-ergy outputs must be determined to calculate theresults.

3.1.2.7 Emissions. Emissions are any dischargeacross the test boundary which must be limited tomeet regulatory or other licensing requirements.These may include gaseous, particulate, thermal, ornoise discharges to the ambient air, waterways, orthe ground. Determinations of emissions are outsidethe scope of this Code, and as such, no emissionlimitations or required measurements are specified.However, since emissions limits may have an effecton results, the test plan must specify emission levelsor limits, as required operation conditions for the test.

3.1.2.8 Heat Sink Conditions. Corrections to the

plant output are required for differences betweenthe design and testheatsink conditions. The parame-ters of interest depend on the type of heat sinkused. For open tyde cooling, it is the temperatureof the circulating water where it crOSsesthe testboundary. For an evaporative cooling tower, it isthe barometric pressure and the ambient air wet-bulb temperature. For a dry air cooling system, itis the ambient air barometric pressureand dry~bulbtemperature. When the test boundary excludes theheat rejection system, the correction is based onthe steam turbine exhaust pressure.

3.1.2.9 Criteria for Selection of MeasurementLocations. Measurement locations are selected to

provide the lowest level of measurementuncertainty.the preferredlocation is at the test boundary, but

~


only if the measurementlocation is the best locationfor determining required parameters.

3.1.2.10 Specific Required Measurements. Thespecific measurements required for a test dependon the particular plant designarid the test boundaryrequired to meet the specific test intent.

3.1.3 Application of Corrections. The calculationof results for any plant or thermal island describedby this Code requires adjusting the test-determinedvaluesof thermal input and power by the applicationof additive and multiplicative correction factors.Thegeneral forms of these equations are:

.

Peorr = (Pmeas+ additive "P" corrections) x (multiplica-tive "P" corrections)

HR = Qmeas + additive "Q" correctionscarr Pmeas+ additive" P" correctionsx (multiplicative "HR" corrections)

An alternate definition of corrected heat rate is:

HReorr = Qeortl Peorr

where

Qeorr = (Qmeas+ additive "Q" corrections)

x (multiplicative "Q" correttiOhS)

The format of the geheral equations identify andrepresent the various corrections to measured per-formance and to mathematitally decouple them sothat they can be applied separately. The correctionfactors are also identified as being necessary dueto operational effects for whith corrections are allow-able, such as those caused by changes in cogenera-tion plant process flows, and as those necessary dueto uncontrollable external effects, such as inlet air

temperature to the equipment.Also, Section 5 permits the Code user to utilize

a heat balance computer program with the appro-priate test data input following a test run, so thatthe corrected performance can be calculated ftomdata with only one heat balance run necessary.

While these correction factors are intended toaccount for all variations from base reference condi-

tions, it is possible that plant performance could beaffected by processes or conditions that were. notforeseen at the time this Code was written. In thiscase, additional correction factors, either additive

or multiplicative, would be required.

10


t

All correction factors must result in a zero correc-tion if all test conditions are equal to the basereference conditions.

3.1.4 Design, Construction, and Start-up Consider-ations. During the design phase of the plant, consid-eration should be given to accurately conductingacceptance testing for overall performance for thespecific type of plant.

Consideration should also be given to the require-ments of instrumentation accuracy, calibration, re-calibration documentation requirements, and loca-tion of permanent plant instrumentation to be usedfor testing. Adequate provisions for installation oftemporary instrumentation where plant instrumenta-tion is not adequate to meet the requirements ofthis Code must also be considered during the designstages. For example, all potential transformers (PTs)and current transformers (CIs) used for power mea-surement should be calibrated.

If the steam or electrical hosts are unable to acceptelectricity or process steam, make other provisionsto maintain the test values within the appropriate"Permissible Deviati.ons from Design" values in Ta-ble 3.2.

Table 3.1 lists the items to consider during thespeWic plant design, construction, and start-up.It3.2 TEST PLAN

A detailed test plan must be prepared prior toconducting a Code test. It will document agreementson all issues affecting the conduct of the test andprovide detailed procedures for performing the test.The test plan should be approved, prior to thetesting, by authorized signatures of all parties to thetest. It must reflect any contract requirements thatpertain to the test objectives and performance guar-antees and provide any needed clarifications ofcontract issues.

In addition to documenting all prior agreements,the test plan should include the schedule of testactivities, responsibilities of the parties to the test,test procedures, and report of results.

3.2.1 Schedule of Test Activities. A test schedule

should be prepared which should include the se-quence of events and anticipated time of test, notifi-cation of the parties to the test, test plan preparations,test preparation and conduct, and preparation ofthe report of results.

3.2.2 R~sponsibiliti~ of Parties. The parties to

the test should agree on individual responsibilities

ASME PTC 46-1996

required to prepare, conduct, analyze, and reportthe test in accordancewith this Code. This includesagreement On the organization of test personneland designation of a test coordinator who will beresponsible for the execution of the test in accord-ance with the test requirementsand will coordinatethe setting of required operating conditions with theplant operations staff.

Representativesfrom each of the parties to thetest should be designatedwho will observe the testand confirm that it was conducted in accordancewith the test requirements. They should also havethe authority, if necessary,to approve any agreedupon revisions to the test requirements during thetest.

3.2.3 Test Procedures. The test plan should includetest procedures that provide details for the conductof the test. The following are included in the testprocedures:

(il) objective of test and method of operation(b) test acceptance criteria for test completion(c) base reference conditions

(d) defined test boundaries identifying inputs andoutputs and measurements locations

(e) the intent of any contract or specification asto operating conditions, performance guarantees, andenvironmental compliance .

(f) complete pretestuncertainty analysis;with biasuncertainties established for each measurement

(g) specific type, location, and Calibration require-ments for all instrumentation and measurement sys-tems and frequency of data acquisition

(h) measurement requirements for applicable emis-sions, including measurement location, instrumenta-

tion, and frequency and method of recording(j) sample, collection, handling, and analysis

method and frequency for fuel, sorbent, ash, etc.(j) method of plant operation(k) identification of testing laborCitories to be used

for fuel, sorbent, and ash analyses(/) required operating disposition or accounting for

all internal thermal energy and auxiliCiry power con-sumers having ci material effect on test results

(m) required levels of equipment cleanliness andinspection procedures

(n) procedures to Ciccount for performance degrCi-dation, if applicable

(0) valve line-up requirements(p) preliminary testing requirements(q) pretest stabilization criteria(r) required steadiness criteria and methods of

maintaining operating conditions within these limits

11

ASME PTC 46-1996 OVERALL PLANT PERFORMANCE

TABLE3.1DESIGN, CONSTRUCTION, AND START-UP CONSIDERATIONS

NOTES:(1) Permanent Plant Instrumentation Used for Test Measurements. It must be considered in the plant design if it is desired t!>use s!>me

permi'ment plant instrumentali!>n for primilry meilsurements. Such permanent plant instrumentation must meet the Class 1 requirementsof Secti!>n4 if it myst becopsidered <;oqe ql,lalityClass 1 instrumentation, or the Class 2 requirements of Section 4 if lesser accuracyis acceptable. This includes obtaining appropriate laboratory calibrations and submitting all laboratory calibration reports, certificationsor calibration results for all permanent plant instrumentation used for the test, as applicable. The ability to do post-test recalibrationsor verificiltions is required as described in this Coqe. Many times, after considering such requirements, it may be decided to usetemporary instrumentiltion in some areils where permanent instrumentation was initially desired to be used. Similarly, it might alsobe determined to use ahernilte permanent instrymentation. These decisions are best Iilken care of in the design stilges.

(2) Connections and spoo! sections req\Jired for tempolilry test instrumentation which will be \JSedfor primary meilsurements. Pressureconnections, thermowells, spool sections for flow meters, ilnd electrical metering tie-ins for temporary test instrumentation needed tomeet the Class 1 requirements of Section4 sho~ldbe incorporatedinto the plant design.

(3) Ch;:mges in Lociltion. Documentiltion thilt records the relocation of items in the process vilriilble loop routing during the design and!or the construction phase of the plant. Any impilct on test uncertilinty should be identified ilnd reviewed with consideriltion tocontrilctuill ilnd code limitations. An example is the relOciition of a flow meter within a process line.

(4) Changes in loop Ro\Jting. An example is the rerouting of condensate legs.(51 Applicability. The proximity to the desired test process value measured. Note whether the recorded value is an instantaneous or average

value. Note also the historical logging capabilities necessary for the testing.(6) Access is reqyired for inspection, calibration, ilnd any temporary instrument installation and removal.(7) Minimize EMF effects, vibration and plJlsiltion tq in?truments, and instr\Jment 19ops. Ensure prqper grounding for instr\Jment cirCuits

ilnd digital systems.(8) Quantity of devices and instrument ports available at pne IOCiltipntq reduce uncertainty and provide contingency data acquisition.

An example i.susing twq (2) or quill element thermocouples to meaSure criticill temperatureS.(9) layqut qf instrument loops to minimize meilsurernent error. Precautipns are listed in Section 4 of this Code. If instrument transfprmers

ilre used, adequate wire size should be used to redyce voltage drops and a neutral cable should be PrQvided to enilble accurate 3-phase watt metering.

(10) Ability to duplicilte measurements. This allows a validation of process value ilng includes iI cpntingency plan for test measurements.A separilte device should be identified to cpllaborilte ;ilndback\Jp a test meilsurement.

(11) Timing of flow elements installationwith respectto acid cleilningilnd/or steamblows. Forinstance,a calibratedflow measuringdeviceshould npt be installed priqr to acid cleaning or steilm blows.

(12) Up ilnd do\Vn stream straight lengths fpr flow elements to minimize I.jncertainty. The upstre;tm ilnd dpwnstreilm lengths impilct theflow measurement uncertainty, and therefore shoulg be maximized.

(13) Water leg correction necessary fQraccurate process variable measurement. A difference in flow measurement tap elevation will alterthe differential pressure meilsured at a Zero flqw condition. Flow measurement devices should be installed in horizontal pipe runs.

(14) Ability to inspect w;tter legs tq validate wilter leg height.(15) Accessible condensate pots to check or refill condensate lines to transmitter.(16) Validate the installation of heat tracing. A check sho\Jld be milde tP validate that heilt trilcing done on water legs is in accord;tnce

with manufacturer's instructiqns to prevent boiling pf condensate.

12

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No. Item Elect Flow Press. Temp.

Permanent plant instrumentationused for test measyrements X X X X

2 Connections and spool sections X X X X3 Changes in location X X X4 Changes in loop routing X X X5 Applicability X X X X6 Access X X X X7 Environmenteffects X X X X8 Quantity X X9 layout X X X

10 Abilityto duplicate measurement X X X X11 Installationtiming X12 Up & down stream straightlengths X13 Water leg correction X X14 Water leg inspection X X15 Condensate pots X X16 Heat tracing X X


(5) allowable variations from basereferencecondi-tions and methods of setting and maintaining op-erating conditions within thes~ limits

(t) number of t~st runSand durations of ~ach run(u) test start and stop requirements(v) dataacceptanceandrejectioncriteria(w) allowabl~rangeof fuel conditions,including

constituents and heating value(x) cor.r~.ctioncurv~s pr algorithms(y) sample calculations or detail~d procedures

specifying testr\.lndata reduction and calculation andcorrection of test resultsto basereferencecondition

(I;) the method for combining test runs to calculatethe final test results

(pp) requirementsfpr datastorage,document reten-tion, and test report distribution

(pb) test report format, contents, inclusions, andindex

3.3 TEST PREPARATIONS

All parties to the test shall be given timely notifica-tion, as defined by prior agreement, to allow them thenecessary time to respond and to prepare personnel,equipment, or documentation. Updated informationshould be provided as it becomes known.

A test log must be maintained during the test torecord any occurrences affecting the test, the timeof the occurrence, and the observed resultant effect.

This Ipg will be part of the permilnent record ofthe test .

Personneland instrumentation involved in the testshould be cQnsidered. For example, provision ofsafe ac;cessto test point locations, availability ofsuitable utilities and silfe work areas for personnelas well ilS potential damage to instrumentation orcalibration shifting becauseof extreme ambient con-ditions .. such as temperat\.lre or vibration.

Dpc\.lmentation mlJst be developed or be madeavili.lable for calculated or adjusted data to provideindependent verificiltion of algorithms, constants,scaling, calibration corrections, offsets,base points,and..conversions.

The remainder of this Subsectiondescribesprepa-riltions relating to:

. testapparatus(3.3.1)

. testpersonnel (3..3.2)

. equipmentinspectionand cleanliness(3.3.3)

. preliminarytesting(3.3.4)

3.3.1 Test Apparatus. Test instruments are classi-fiedas described in para. 4.1.2.1. Instrumentation

ASME PTC 46-1996

used for data collection must be at least as accurateas instrumentation identified in the pretest uncer-tainty analysis. This instrumentation can either bepermanent plant instrumentation or temporary testinstrumentation.

Multiple instruments should be used as neededto reduce overall test uncertainty. The frequencyof data collection is dependent on the particularmeasurement and the duration of the test. To theextent practical, at least 30 readings should becollected to minimize the random error impact onthe post-test uncertainty analysis. The use of auto-mated data acquisition systems is recommended tofacilitate acquiring sufficient data. .

Calibration or adequate checksof all instrumentsprior to and after the test must be carried out, andthose records and calibration reports must be madeavailable. Following the test, recatibrationor ade.quate reconfirmation or verification is required.

The continuous emissions monitoring systemsho\.lld be in normal operation throughout the testtime frame unless the parties to the test mutuallyagree to the contrary.

3.3.2 Test Personnel. Test personnel are requiredin sufficient number and expertise to support theexecution of the test. (See para. 3.2.2, "Responsibili-ties of Parties.") Operations personnel must be famil-iar with the test operating requirements in order tooperate the equipment accordingly.

3.3.3 Equipment Inspection and Cleanliness. Sincea PTC 46 test is not intended to provide detailedinformation on individual components, this Codedoes not provide corrections for the effect of anyequipment that is not in a clean and functional state.

Prior to conducting a test, the cleanliness, condi-tion, and age of the equipment should be determinedby inspection of equipment or review of operiltionalrecords, or both. Cleaning should be completedprior to the test and equipment cleanliness agreedupon.

All parties to the test shall have reasonable oppor-tunity to examine the plant and agree that it is readyto test. The plant should be checked to enS\.lrethat eq\..!ipment and subsystems are installed andoperating in accordance with their design param-eters.

3.3.4 Prelimi"~ry Testing. Preliminary testing canand should be conducted sufficiently in advance ofthe start of the overall performance test to allowtime to calculate preliminary results, make finaladjustments,and modify the test requirementsand/or

13

ASME PTC 46-1996

t~$t equipment. Results from the preliminary testingshould b~ cakulated and reviewed to identify anyproblems with the quantity and quality of measureddata. The parties shall mutually agree before thetest to any test modifications 50 det~rmined.

Some reasons for a preliminary run are:(a) to determine whether the plant equipment is in

suitable condition for the conduct of the test(b) to make adjustments, the needs of which wer~

not evident during the preparation of the test(c) to check the operation of all instruments, con-

trols, and data acquisition systems(d) to ensure that the target uncertainty can be ob-

tained by checking the complete system(e) to ensure that the facilities operation can be

maintained in a steady state performance(f) to ensure that the fuel characteristics, analysis,

and heating value are within permissible limits, andthat sufficient quantity is on hand to avoid interruptingthe test

(8) to ensure that process boundary inputs and out-puts are not constrained other than those identifiedin the test requirements

(h) to familiarit:e test personnel with their assign-ments

(i) to retrieve enough data to fine tune the controlsyst~m if nec~ssary

3.4 CONDUCT OF TEST

This Subsection provides guidelin~s on the actualconduct of the performance test and addresses thefollowing areas:

. starting and stopping tests and test runs (3.4.1)

. methods of operation prior to and during tests(3.4.2)

. adjustments prior to and during tests (3.43)

. duration and number of tests and number of read-ings (3.4.4)

. constancy of test conditions (3.4.5)

In addition, this Subsection contains the followingtables:

. Table 3.2 Guidance for EstablishingPermissibleDeviations from Design

. Table33 TypicalPretestStabilizationPeriods

. Table3.4 MinimumTestDurations

3.4.1 Starting and Stopping Tests' and Test Runs.The test coordinator is responsible for ensuring thatall data collection begins at the agreed-upon start


of the test, and that all parties to the test are informedof the starting time.

3.4.1.1 Starting Criteria. Prior to starting eachperformance test, the following conditions must besatisfied:

(a) operation, configuration, and disposition fortesting has been reached in accordance with theagreed upon test requirements, including:

(1) equipment operation and method of control(2) unit configuration, including required pro-

cess effluxflow(3) valve line-up(4) availabilityof consistentfuel anMuel supple-

ments within the allowable limitsof the fuel analysisfor the test (byanalysisas soon as practicable preced-ing the test)

(5) plant operation within the bounds ofthe per-formance correction curves, algorithms or programs

(6) equipment operation within allowable limits(7) fora seriesof test runs, completion of internal

adjustments required for repeatability(b) Stabilit:ation.Priorto startingtest, the plant must

be operated for a sufficientperiod of time at test loadto demonstrate i'lndverifystabilityin accordance withpara. 3.4.2 criteria.

(cJ Data Collection. Data acquisition system(s)functioning, i'lndtest personnel in place and ready tocollect samples or re~ord data.

3.4.1.2 Stopping Criteria. Tests are normallystopped when the test coordinator is satisfied thatrequirements for a complete test run have beensi'ltisfied.(Seepi'lras.3.4.4 and 3.4.5.) The test coordi-nator should verifythat methods of operation duringtest, specified in para. 3.3.2, have been satisfied.The test coordinator may extend or terminate thetest if the requirements are not met.

Data logging should be checked to ensure com-pleteness and quality. After all test runs are com-pleted, secure equipment operating for purposes oftest only (such as vent steam). Return operationcontrol to normal dispatch functions, if appropriate.

3.4.2 Methods of Operation Prior To and DuringTests. All equipment necessary for normal and sus-tained operi'ltion at the test conditions must beoperated during the test or accounted for in thecorrections. Intermittent operation of equipmentwithin the test boundary should be accounted forin a manner agreeable to all parties.

Typical but nonexhaustive examples of operatingequipment for consideration include fuel handlingequipment, soot blowers, ash handling systems, gas

14


turbine compressor inl~t chillers or evaporative cool-ers, gas compressors, water treatment equipment,and blowdown. Any environmental control systemmust be operating and within normal rC!nges,includ-ing percent solids, gas flow, inlet and outlet emissionconcentrations, pH, and solid and liquid concentra-tions.

3.4.2.1 Operating Mode. The operating modeof the plant during the test should be consistentwith the goal of the test. The correctionsutilizedin the general performance equation and the devel-opment of correction curves will be affected by theoperqting mode of the plant, If a specified correctedor measured load is desired, the plant control systemshould be configured to maintain the load duringthe t~st. If a specified disposition is required, thecontrol system should maintain the disposition andnot make changesto the parameterswhich shouldbe fixed, such as valve position.

The plant equipment should be operated in amann~r consistentwith the basisof designor gu<'!ran-

tee, C!nd in a manner that will permit correctionfrom test operating conditions to base referenceconditions.

Proc~ss energy (process st~am and condensate)must be controlled in th~ most stable manner possi-ble. This may require operation in manual mode orventing to the atmosph~re if th~ host is unable tos<'!tisfystability or quantity crit~ria,

3.4,2.2 Valve Line-up/Cycle Isolation. A cycleisolation checklist should be developed to the satis-faction of all parties to the test. The checklist shouldbe divided into three categ~ries: manual valve isola-tion checklist, automatic valve isolation checklist,and test valve isolation checklist.

(a) The manual valve isolation checklist should bean ~xhaustive list of all the valves that should be closed

during normal op~ratiOn. Thes~ are the valves thataffect the i;\c<;uracy or results of the test if they arenot secured. These valve positions should be checkedbefore and after the teSt.

(b) The automatic valve isolation checklist is a list

of valves that should be clos~d during normal opera-tion but may from time to time cycle open (such asfeedwater heater emergency dump valves). As in (a),these are the valves that affect the accuracy or resultsof the test if they are not secured. These valve positionsshould be checked prior to the preliminary test andmonitored during subsequent testing. (To the extentavailable from the plant control system, these valvepositions should be continually monitored duringthe test.)

ASME PTC 46-1996

(e) The test valve isolation checklist is a list of those

valves that should be closed during the performancetest. These valves should be limited to valves that must

be closed to accurately measure the plant perform-ance during the test. For example, the boiler blow-down may need to be closed during all or part of thetest to accurately measure boiler steam production.The blowdown valve position should be addressed in

the test plan.No valves normally open should be closed for

the sole purpose of changing the maximum perform-ance of the plant.

The valves on the test valve isolation checklist

should be closed prior to the preliminary test. Thevalves may need to be opened between test runs.

Effortshould be made to confirm zero flow throughvalves that are required to be closed during the test.

3.4.2.3 Equipment Operation. Plant equipmentrequired for normal plant operation should be op-erating as defined by the respective equipment sup-pliers' instructions (to support the overall objectivesof the plant test), unless otherwise agreed to by theparties to the test. Equipment that is necessary forplant operation or that would normally be requiredfor the plant to operate at base reference conditionsmust be operating or accounted for in determiningauxiliary power loads.

At least 99.9% of nonelectric internal energy con-sumption should be accounted for and specifiedoperating disposition tabulated. At least 99% ofelectrical auxiliaries should be accounted for andspecified operating disposition tC!bulated. Anychanges in equipment operation that affect plantcorrected heat rate or corrected performance bymore than 0.25 (or mutually agreed) percent willinvalidate a test run. A switch-over to redundantequipment, such as a standby pump, is permissible.Intermittent nonelectrical internal energy consump-tion and electrical auxiliary loads, such as prorating,or proportioning, must be accounted for in an equita-ble manner and applied to the power consumptionof a complete equipment operating cycle over thetest period. Examples of intermittent loads includewater treatment regeneration, well pump, materialhandling, soot blowing, blowdown, heat tracing,and air preheating.

3.4.2.4 Proximity to Design Conditions. It isdesirable to operate the plant during the test asclosely as possibl~ to the base reference performanceconditions, and within the allowable design rangeof the plant and its equipment so as to limit themagnitude of corrections to net electrical output

15

ASME PIC 46-1996

ilnd heilt rilte. Table 3.2 was developed based onqchieving the overall test uncertainties described inTqblel.1. Excessivecorrectionsto plant performancepilrilmeters can adversely affect overall test uncer-tilinty. To maintain compliance with test code re-quirements, the ilctual test should be conductedwithin the criteria given in Tables 3.2 and 3.3 orother mutually agreed operating criteria that resultin overall test uncertaintycompatible with Table 1.1.

3.4.:l.5 Stabilization. Agreement must bereilched on the necesSilrYstilble conditions beforestilrtingthe test. The length of operilting time neces-SqrYto ilchievethe required steqdy stiltewill dependon previous operations, using Table ,3.2 as a guide.

3.4.2.6 Plant Output. A test may be conductedat any load condition, as required to satisfy thegoals of the test. For those t~sts which require aspecified corrected or meilsured loild, the test runelectrical output should be set so thilt the estimatedtest result of net electrical power is within one (1)percent of the ilpplicable design vilh..le.For thosetests which require a specified disposition of theplant, the test electricill output will be dependenton the performance of the plant itself and will notbe controlled. At no time should the actual testconditions exceed any equipment ratings providedby the manufacturer.

3.4.2.7 Plant Thermal Energy. Cogenerationplant thermill energy export shall be set at levelsspecified or ilS mutually agreed by parties to thetest. If automiltic control of export energy does notprovide sufficient stability and proximity to designconditions, manuill control or venting of exportenergy may be required.

3.4.2.8 fuel and Fuel Supplements. Consump-tion and properties of fuel and fuel supplements(such as limestone)should be milintilinedas constantas practicable for the duration of the preliminarytest qnd actual test. Permissible deviations in fuelproperties for various fuels and components arespecified in Table 3.2.

3,4.2.9 Emissions.Throughoutthe tests, the plantshall be operated in accordance with the emissionslimits outlined in the test plan. Emissionsshould bemonitored with approved equipment. However, thisCode does not require that emissions tests be con-ducted as part of the overall performance test. Emis-sions can be monitored with normal monitoringequipment, not necessarily compliance testingequipment.


3.4.2.10 On-line Cleaning. On-line cleaning ofboiler heat transfer surfacesand gas turbine compres-sors should be addressed.

3.4.3 Adjustments Prior to and During Tests. ThisSubsection describes the following three types ofadjustments related to the test:

. permissible adjustments during stabilization peri-ods or between test runs

. permissible adjustments during test runs

. non-permissible qdjustments

3.4.3.1 Permissible Adjustments During Stabili-zation Periods Between Test Runs." Agreementshould be reached before the test on acceptableadjustments prior to the test. Basically, any adjust-ments may be made to the equipment and/or op-erating conditions, but the requirements for determi-nation of stable operation (see para. 3.4.2.5) stillapply. For example, if the fuel distribution on astoker is altered, sufficientstable operating time mustbe allowed for a complete change of the ash onthe grates. Similarly, a change in fluidized bedcombustor ash reinjection must permit restabilizationof the bed. Changes in nonprimary measurements,such as steam temperature, may be made so long asthe requirement for stabilityof primarymeasurementsstill hold.

Typical adjustments prior to tests are those re-quired to correct malfunctioning controls or instru-mentation or to optimize plant performance forcurrent operating conditions. Recalibration of SIJS-pected instrumentation or measurement loops arepermissible. TIJningand/or optimization of compo-nent or plant performance is permissible. Adjust-ments to avoid corrections or to minimizethe magni-tude of performance corrections are permissible.

3.4.3.2 Permissible Adjustments During TestRuns. Permissible adjustments during tests are thoserequired to correct malfunctioningcontrols, maintainequipment in safe operation, or to maintain plantstability. Switching from automatic to manIJal con-trol, and adjusting operating limits or set points ofinstruments or equipment should be avoided duringa test.

3.4.3.3 Nonpermissible Adjustments. Any ad-justments that would result in equipment being oper-ated beyond manufacturer's operating, design, orsafety limits and/or specified operating limits arenot permitted. Adjustments or recalibrations whichwould adversely affect the stability of a primarymeasurement during a test are also not permitted.

16

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eam

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erat

ion

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neC

ycle

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imar

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tly

25°F

(14°

0w

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30°F

(17°

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the

air-

cool

edhe

atsi

nk

(coo

ling

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cool

edco

nden

ser)

isin

clud

edin

test

boun

dary

.

Gas

turb

ine

max

imum

allo

wab

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ion

inre

quir

edm

ode,

such

asba

se

load

ed.

Var

ies

byga

stu

rbin

e.

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ine

max

imum

allo

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ion

in

requ

ired

mod

e,su

chas

base

load

ed.

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ies

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ival

ent

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ense

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re.

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ies

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eam

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ine.

N/A

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ense

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re.

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ies

byst

eam

turb

ine.

IfR

bis

0.30

orle

ss:

[(m

;n)

=0.

30x

Fb

x(P

ps/P

ms)

IfR

bex

ceed

s0.

30:

F(m

;n)

=R

bx

Fb

x(P

ps/P

ms)

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e(1

)1

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ss:

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;n)

=0.

30x

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x(P

ps/P

ms)

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ceed

s0.

30:

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;n)

=R

bx

Fb

x

(Pps

/Pm

s)[N

otes

(1)

and

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ss:

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=0.

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x(P

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ms)

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ceed

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30:

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;n)

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+(R

b-

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)/0.

70x

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Fb

x(P

ps/P

ms)

(Not

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d(2

)1

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ival

ent

to10

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le.

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tion,

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le.

Allo

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ion

perm

itted

for

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ine.

Var

ies

with

turb

ine.

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ion

perm

itted

for

the

gas

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ine.

Var

ies

with

turb

ine.

Con

trac

tfu

elsp

ecif

icat

ion

limits

.

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mT

urbi

neC

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red

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ithpr

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atin

put

mea

sure

ddi

rect

ly,

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boile

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t

air

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ture

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ir"

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ival

ent

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ine

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re.

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ies

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ine.

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ss:

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;n)

=0.

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Pm

s)If

Rb

exce

eds

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:F

(m;n

)=

(0.7

5+

(Rb

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30)/

0.70

x0.

251

xF

bx

(Pps

/Pm

s)[N

otes

(1)

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ival

ent

to10

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eam

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pera

tion,

ifap

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able

.

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trac

tfu

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ecif

icat

ion

limits

.

0 < m ;Ie

» r- r- "'C

rr- » z --

j" m ;I

e'T

I0 ;I

e5: » z (') m » VI

5: m " ~ ~ ~ \,0 \,0 0-.

TA

BL

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ON

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)

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DF

UE

L:

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ysis

(hea

ting

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ts)

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ific

atio

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its.

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el

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atio

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its.

Con

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act

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ific

atio

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EL

EC

TR

ICA

lP

AR

AM

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RS:

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ctor

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freq

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y

Allo

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rers

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ific

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neq

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ture

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ies

with

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ific

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ines

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TE

(1)

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=ba

sere

fere

nce

proc

ess

'eff

lux,

Ibm

/h,

kg/h

,8t

u/h,

orkW

(t)

[(m

inI

=m

inim

umpr

oces

sef

flux

flow

duri

ngte

st,u

nits

cons

iste

ntw

ithF

bN

P=

plan

tne

t:p

ower

outp

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omba

sehe

atba

lanc

e,kW

(e)

PE=

mec

hani

cale

quiv

alen

toft

hepr

oces

seff

luxf

rom

base

heat

bala

nce,

kW{t

)P

InS

=m

ain

stea

mpr

essu

re,p

sia

orkP

aP

ps=

proc

esss

team

pres

sure

,psi

aor

kPa

Rb

=ra

tioof

PE/(

NP+

:PE

),dim

ensi

onle

ssSm

alle

rval

uesm

aybe

'use

dfo

rthe

min

imum

requ

ired

proc

esse

fflu

xonl

yif

stea

mcy

cle

char

acte

rist

ics(

such

asst

eam

turb

ine

flow

fact

ors)

need

edfo

rhea

tba

lanc

eca

lcul

atio

nsca

nbe

conf

irm

edw

ithda

ta.

(2)

():)

» l1'> 3: ,.,.,

~ -'I n ~ ! \0 \0 '" ~ m ~ .....

.....

"0 s: Z -'I ." m ::10

"II

0 ~ Z n m


" TABLE 3.3TYPICAL PRETESTSTABILIZATION PERIODS

Type of Plant

Gas fired boilerOil fired boiler

Pulverized coal-fired boilerFluidized bed combustor

Simple cycle with heat recoveryCombined cycleReciprocating enginesStoker and cyclone

Stabilization

1 hr1 hr1 hr24 hr (1)1 hr1 hr1 hr4 hr

NOTE:11) If chemical stability has been satisfied, then testing may commence one (1) hour following

achievement.

I»

TABLE 3.4RECOMMENDED MINIMUM TEST RUN DURATIONS

"

Type of Plant

Gas fired boiler

Oil fired boilerPulverized coal-fired boiler

Fluidized bed comb!Jstor

Simple cycle with heat recoveryCombined cycleStoker and cyclone

Test Run

2 hr2 hr2 hr4 hr1 hr1 hr4 hr

I

3.4.4 Duratipn of Runs,Number of Test Runs,and Number of Readings

3.4.4.1. Duration of Runs. The duration of a testrun'shall be of sufficient length that the data reflectsthe average efficiency and/or performance of theplant. This includes consideration for deviations inthe measurable parameters due to controls, fuel,and typicalplant operatingcharacteristics.The rec-ommended test durations are tabulated in Table 3.4.

The test coordinator and the parties to the testmay determine that a longer test period is required.The recommended times shown in Table 3.4 aregeneriilly based upon continuous data acquisition.Depending upon the personnel available and themethod of diita acquisition, it miiy be necessary toincrei:\se the length of a test in order to obtaina sufficient number of samples of the measuredparameters to attain the required test uncertainty.When point-by-point traverses are required, the testrun should be long enough to complete two fulltraverses. Test runs using blended or Wiiste fuelsmay also require longer durations if variations inrt

the fuel are significant. Test run duration shouldconsider transit times of samples.

3.4.4.2 Number of Test Runs. A run is a com-plete set of observations with the unit at stableoperating conditions. A test is a single run or theaverage of a series of runs.

While not requiring multiple runs, the advantagesof multiple runs should be recognized. Conductingmore than One run will:

. provide a valid method of rejecting bad test runs

. allowthe partiesto the test to examine the validityof the results

. verifythe repeatabilityof the results. Results maynot be repeatable due to variations in either testmethodology(testvariations)or the actual perform-ance of the equipment being tested (process varia-tions)

After completing the first test run that meets. thecriteria for an acceptable test run (which may bethe preliminarytest run), the data should be consoli-dated and preliminary results calculated and exam-

19

!If~

~~- ._-

ASMEPIC 46-1996 OVERAll PLANT PERFORMANCE

Case INo 9Vtlrlap

Case IICompleteoverlap

Case 1\1

Partial overlap

! I f~u,

1

X1

f%u,

1

f%U2

1

X2

f%u,

i f%U2

1

t%U2

lox,

X1

X2

FIG. 3.4 THREE POST-TEST CASES

ii,

ined to ensure that the results are reasonable. If the

p;uties to the test agree, the test may be concludedat the end of any test run.

3.4.4.3 Evaluation of Test Runs. When compar-ing results from two test runs (XI and X2)and theiryncertainty intervals, the three cases illustrated inFig. 3.4 should be considered.

Case I: A problem clearly exists when there is nooverlap between uncertainty intervals. Either uncer-tainty intervals have been grossly underestimated, anerror exists in the measurements, or the true value isnot constant. Investigation to identify bad readings,pverlpoked or underestimated systematic uncertainty,etc., is necessary to resolve this discrepancy.

Case II: When the uncertainty intervals completelyoverlap, as in this case, one can be confidentthat therehas been il proper accounting of all melioruncertaintycomponents. The smellIer uncertainty interval, X2 :tV2, is wholly contained in the interval, X2 :t VI,

Case III: This CilSe, where a partial overlap of theuncertainty exists, is the most difficult to analyze. Forboth test run results ilnd both uncertainty intervals tobe correct, the true value lies in the region where the

uncertainty intervalsoverlap.Consequently the largerthe overlap the more confidencethere is in the validityof the measurements ilnd the estimate of the uncer-tainty intervals. As the difference between the twomeasurements increases, the overlap region shrinks.

Should a run or set of runs fall under case 1 orcase 3, the results from all of the runs should bereviewed in an attempt to explain the reason forexcessive variation. Should no reason become obvi-ous, the parties to the test can either increase theuncertainty band to encompass the runs and there-fore make them repeatable, or they can conductmore runs, which will allow them to calculate theprecision component of uncertainty directly fromthe test results.

The results of multiple runs shall be averaged todetermine the mean result. The uncertainty of resultis calculated in accordance with PTC 19.1.

3.4.4.4 Number of Readings. Sufficient readingsmust be taken within the test duration to yield totaluncertainty consistent with Table 1. Ideally at least30 sets of data should be recorded for all noninte-grated measurements of primaryvariables. There areno specific requirements for the number of integrated

20

""


readings or for measurements of secondary variablesfor each test run.

3.4.5 CQn$teJnc;:yQf Test Conditions. The primarycriterii'l for steady sti'lte test conditions is that theaverage of the data reflects equilibrium betweenenergy input from fuel and energy output to thermaland/or electrical generation. The primary uncontrol-lable parameters affecting the steady state conditionsof a test are typically the ambient conditions. Testingdurations and schedules must be such that changesin ambient conditions are minimized. See para.3.4.2.5.

3.5 CALCULATION AND REPORTING OFRESULTS

The data taken during the test should be reviewedand rejected in part or in whole if not in compliancewith the requirements for the constancy of testconditions. See para. 3.4.5.

Each code test shall include pretest and post-testuncertainty analyses and the results of these analysesshall fall within code requirements for the type ofplant being tested.

3.5.1 Causes for Rejection of Readings. Upon com-pletion of test or during the test itself, the test datashall be reviewed to determine if data from certaintime periods should be rejected prior to the calcula-tion of test results. Refer to PTC 19-1 and ANSI/ASME MFC-2M (Appendix C) for data rejectioncriteria. A test log should be kept. Any plant upsetswhich cause test data to violate the requirementsof Table 3.2 shall be rejected. A minimum of 10minutes following the recovery of these criteria shallalso be rejected to allow for restabilization.

Should serious inconsistencies which affect theresults be detected during a test run or during thecalculation of the results, the run shall be invalidatedcompletely, or it may be invalidated only in part ifthe affected part is at the beginning or at the endof the run. A run that has been invalidated shallbe repeated, if necessary, to attain the test objectives.The decision to reject a run shall be the responsibilityof the designated representatives of the parties tothe test.

During the test, should any control system setpoints be modified that effects stability of operationbeyond code allowable limits as defined in Table3.2, test data shall be considered for rejection fromthe calculations of test results. The period rejectedshall start immediately prior to the change and end

ASMEPTC 46-1996

no less than 10 minutes following the recovery ofthe criteria found in Table 3.2.

An outlier analysis of spurious data should alsobe performed in accordance with PTC 19.1 on allprimary measurements after the test has ended. Thisanalysis will highlight any other time periods whichshould be rejected prior to calculating the test results.

3.5.~ UncerteJinty.Test uncertainty and test toler-ance are not interchangeable terms. This Code doesnot address test tolerance, which is a contractual~m. ~

Procedures relating to test uncertainty are basedon concepts and methods described in PTC 19.1,"Measurement Uncertainty." PTC 19.1 specifies pro-cedures for evaluating measurement uncertaintiesfrom both random and fixed errors, and the effectsof these errors on the uncertainty of a test result.

This Code addresses test uncertainty in the follow-ing four sections.

. Section 1 defines expected test uncertainties.

. Section 3 defines the requirements for pretest andpost-test uncertainty analyses, and how they areused in the test. These uncertainty analyses andlimits of error are defined and discussed in para.3.5.2.1.

. Section 4 describes the bias uncertainty requiredfor each test measurement.

. Section 5 and Appendix Fprovide applicable guid-ance for determining pretest and post-test uncer-tainty analysis results.

3.5.2.1 Pretest and Post-Test UncertaintyAnalyses .

(a) A pretest uncertainty analysis shall be per-formed so that the test can be designed to meet coderequirements. Estimates of bias and precision error foreach of the proposed test measurements should beused to help determine the number and quality oftest instruments required for compliance with codeor contract specifications.

The pretest uncertainty analysis must include ananalysis of precision uncertainties to establish per-missible fluctuations of key parameters in order toattain expected uncertainties.

In addition, a pretest uncertainty analysis can beused to determine the correction factors which aresignificant to the corrected test. For simplicity, thisCode allows elimination of those corrections whichdo not change the test results by 0.05 percent.Also, pretest uncertainty analysis should be used todetermine the level of accuracy required for each

21

ASMEPTC46-1996OVERALL PLANT PERFORMANCE

measurement to maintain overall Code standards forthe test.

(b) A posHest uncertainty analysis shall also beperformed as part of a Code test. The post-testuncer-tainty analysiswill reveal the actual qualityof the testto determine whether the expected test uncertaintydescribed in Section 1 has been reali;!:ed.

3,5.3 Data Distribution and Test Report. Partiesto the test h;:lVethe right to have copies of all data

at the conclusion of the test. Data will be distributedby the test coordinator and approved in a manneragreed to prior to testing.

A test report is written in accordance with Section6 of this Code by the test coordinator and distributedwithin a time frame agreed to by all parties. Apreliminary report incorporating calculations andresults may be required before the final test reportis submitted for approval.

4

22


SECTION 4 -- INSTRUMENTS AND METHODS OFMEASUREMENT

4.1 GENERAL REQUIREMENTS

4.1.1 Introduction. This Code presents the manda-tory requirements for instrumentation employed andthe use of such devices. The instrumentation recom-mended herein may be replaced by new technologyas it becomes available. The Instruments and Appara-tus supplement (ASME PTC 19 Series) outlines thegoverning requirements for all ASME performancetesting. If the instrumentation n;quirements in theInstrument and Apparatus supplement become morerigorous as they are updated, due to advances inthe state gf the art, their requirements will supersedethgse set forth in this Cgde.

U.S. Customary units are shown in all equationsin this Sectign. However, any other consistent setof units may be used.

4.1.2 Instrumentation Classification. The instru-

mentation employed to measure a variable will havedifferent required type, accuracy, redundancy, andhandling depending upon the use of the measuredvariable and depending on how the measured vari-able affects the final result. For purposes of thisdiscussion, variables at a given location are tempera-ture, pressure, flow, velocity, voltage, current, streamconstituency, and humidity. Measurements are clas-sified as either primary or secondary variables.

4.1.~.1 Primary Variables. Variables that areused in calculatigns of test results are consideredprimary variables. Primary variables are further clas-sified as <:;:Iass1 primary variables or Class 2 primaryvariables. Class 1 primary varipbles are those whichhave a relative sensitivity coefficient of 0.2 percent orgreater. These variables will require higher-accuracyinstruments with mgre redundancy than Class 2primary vpripbles which have a relative sensitivitycoefficient of less than 0.2 percent.

4.1.2.2 Secondary Variables. Variables that aremeasured but do not enter into the calculation ofthe results are secondary variables. These variablesare measured throughout a test period to ensurethat the required test condition was not violated.

An example of these variables are gas turbine exhausttemperature or steam turbine inlet pressure andtemperature. These example variables verify that theunit was not over- or under-"fired" during the testperiod.

This Code does not require high accuracy instru-mentation for secondary variables. The instrumentsthat measure these variables may be permanentlyinstalled plant instrumentation. The code does re-quire verification of instrument output prior to thetest period. This verification can be by calibrationor by comparison against two or more independentmeasurements of the variable referenced to the samelocation. The instruments should also have redundant

or other independent instruments that can verify theintegrity during the test period.

4.1.3 h'!str\.lmentCalibration

4.1.3.1 Definition of Calibration. Calibration of

an instrument is the act of applying process condi-tions to the candidate instrument and to a referencestandard in parallel. Readings are taken from boththe candidate instrument and the reference standard.The output of the instrument then may be adjusted tothe standard reading. As an alternative, the differencebetween the instrument and the reference standard

may be recorded and applied to the instrumentreading. This alternative method is mandatory inthe case of thermocouple or Resistance TemperatureDevices (RTDs)because their output cannot be easilyaltered.

4.1.3.2 Reference Standards. In generaI all testinstrumentation used to measure primary (Class 1and Class 2) variables should be calibrated againstreferencestandards traceable to the National Instituteof Standards and Technology (NIST),other recog-nized international standard organization, or recog-nized physical constants. All reference standardsshould be calibrated as specifiedby the manufactureror other frequency i!s the user has di!ta to supportextension of the calibration period. Supporting datais historical calibration data that demonstrates a

23

-= ~~,,~

ASME PTC 46-1996

calibration drift less than the accuracy of the refer-ence sti3ndard for the desired calibration period.

The reference standards should have an uncer-tairHyat .Ieast4 times. less thi3n the test instn.lmentto be ci3fibrated.A reference standard with a loweruncertainty may be employed if the uncerti3intyofthe sti3ndardcombined with the precision uncertaintyof the instrument being ci3librated is less thi3n thei3ccuracy reqllirement of the instrument.

Instrumentation used to measure secondary vari-ables need not be calibrated against a referencestandard. These instruments may be calibratedagainst a calibrated instrument.

4.1.3.3 Ambient Conditions. Calibration of in-struments used to mei3sureprimary variables (Class1 or CIi3ss2) should be performed in a mi3nnerthi3treplicates the condition under which the instr\Jmentwill be \.Isedto make the test measurements. Consid-eration must be given to all process i3nd ambientconditions which may i3ffectthe measurement in-cluding temperatyre, pressure, hymidity, electromag-netic interference, ri3dii3tion,or etc.

4.1.3.4 Instrument Ranges and CalibrationPoints. The number of calibration points dependsupon the classification of the variable the instrumentwill measure. The classificatitms are discussed inpara. 4.1.2. The calibration should bracket the ex-pected measurement range as closely as possible.

(a) Class 1 PrimaryVariablesThe instruments measuring Class 1 primary vari-

ables should be calibrated i3t two (2) points morethan the order of the calibration curve fit.

Ei3chinstrument should also be calibrated suchthat the measuring point is approi3chedin an increas-ing i3nddecreasing manner. This exercise minimilesany hysteresis effects.

Some instruments are built with a mechanism toalter the range once the instrument is installed. Inthis case, the instrument must be calibrated at eachrange to be used during the test period.

Some devices cannot practically be calibrated overthe entire operating range. An example of this isthe calibration of a flow measuring device. Thesedevices are calibrated often at flows lower than theoperating range and the calibration data is extrapo-lated. This extrapolation is described in Subsec-tion 4.4.

(b) Class 2 PrimaryVariablesInstruments measuring Class 2 primary variables

should be calibrated at the number of points equalto the order of the calibration curve fit. If theinstrument can be shown to typically have a hystere-

I

- i


sis of less than the required accuracy, the measuringpoint need only be approached from one direction(either increasing or decreasing to the point).

(c) SecondaryVariablesInstrumentsused to measure secondary variables

can be checked in place with two or more instru-ments measuring the variable with respect to thesame location or Ci3nbe calibrated against i3 pre-vioysly calibrated instrument.

Should the instrument be calibrated, it need onlybe calibrated at one point in the expected operi3tingrange.

~

4.1.~.5 Timingof Calibration. Alltest instrumen-tation used to measure primi3ry(Class 1 i3ndClass2) variableswill be calibrated prior to and calibratedor checked following the tests. No mandate is mi3deregardingqui3ntityof time between the initialcalibra-tion, the test period, and the reci3libration.Thequantity of time between initial i3nd recalibrationshould however be kept to a minimum to obti3ini3nacceptable calibri3tiondrift.

Flow measuringdevices and current i3ndpotentialtri3nsformersby nature are not conducive to post~test ci3libri3tion.Inthe case of flow mei3suringdevicesused to measure Class 1 primary variables, theelement may be inspected following the test ratherthan recalibrating the device. Flow elements usedto measure Class 2 primary variables need not beinspected following the test if the devices have notexperienced steam blow or chemical cIei3ning.

Post-testcalibration of current and potential trans-formers is not required.

4

4

4.1.3.6 Calibration Drift. Calibration drift is de-fined as the difference in the calibration correction asa percent of reading. When the post-test calibrationindicates the drift is less than the instrument biasuncerti3inty,the drift is considered accepti3ble andthe prete~tCi3librationis used as the biasfor determi",-ing the test results. Occasionally the instrumentcalibration drift is unacceptable. Should the calibra-tion drift, combined with the reference standardaccuracy as the squi3reroot of the sum of the squares,exceed the required i3ccuracyof the in~trument, itis unaccepti3ble.

Ci3libri3tiondriftc:an result from instrument mal-function, transportation, insti3l1ation,or removal ofthe test instrumentation. Should unaccepti3blecali-bration drift occur, engineering judgment must beused to determine whether the initialor recalibrationis correct. Below are some practices thi3t lead tothe application of good engineering judgment. -

24

~


(a) When instrumentation is transported to the testsite between the calibration and the test period, asingle point check prior to and following the test pe-riod can isolate when the drift may have occurred.An example of this check is vented pressure transmit-ters, no load on watt meters, and ice point temperatureinstrument check.

(b) In locations where redundant instrumentationis employed, calibration drift should be analyzed todetermine which calibration data (the initial or recali-bration) produces better agreement between redun-dant instruments.

4.1.3.7 Loop Calibration. All instruments usedto measure primary variables (Class 1 or Class 2)should be loop-calibrated. Loop calibration involvesthe calibration of the instrument through the signalconditioning equipment. This may be accomplishedby calibrating instrumentation employing the testsignal conditioning equipment either in a laboratoryor on site during test setup before the instrumentis connected to process. Alternatively, the signalconditioning device may be calibrated separatelyfrom the instrument by applying a known signal toeach channel using a precision signal generator.

Where loop calibration is not practical, an uncer-tainty analysis must be performed to ensure that thecombined uncertainty of the measurement systemmeets the accuracy requirements described herein.

4.1.3.8 Quality Assurance Program. Each cali-bration laboratory must have in place a qualityi;!ssurance program. This progri'lm is a method ofdocumentation where the following information canbe found:

(a) calibration procedures(b) calibration technicii'ln training(c) standi;!rd calibration records(d) standard calibration schedule(e) instrument calibration historiesThe quality assurance program should be designed

to ensure that the laboratory standards are calibratedas required. The program also ensures that properlytrained technicians calibrate the equipment in thecorrect manner.

All parties to the test should be allowed accessto the calibration facility as the instruments arecalibrated. The quality assurance program shouldalso be made available during such a visit.

4.1.4 Plant Instrumentation. It is acceptable to useplant instrumentationfor primaryvi'lriablesonly iftheplant instrumentation (including signal conditioning

ASME PTC 46-1996

equipment) can be demonstrated to meet the overalluncertainty requirements. Many times this is not thecase. In the case of flow measurement all instrumentmeasurements (process pressure, temperature, differ-ential pressure, or pulses from metering device) mustbe made available as plant conversions to flow areoften not rigorousenough for the required accuracy.

4.1.5 Redundant Instrumentation. Redundant in-struments are two or more devices measuring thesame pari'lmeterwith respect to the same location,Redundant instruments should be used to measureall primary (Class 1 or Class 2) variables with thefollowing exceptions. Redundant flow elements andredundant electrical metering devices !:Irenot re-quired because of the large increase in costs, butshould be considered when developing a test plan.

Other independent instruments in separate loca-tions can also monitor instrument integrity.A samplecase would be a const,mt enthalpy process wherepressure and temperature in a steam line at onepoint verifythe pressure and temperature of anotherlocation in the line by comparing enth!:llpies.

4.2 PRESSUREMEASUREMENT

4.2.1 Introduction. This Subsection presents re-quirements and guidance regardingthe measurementof pressure. Due to the state of the art and generalpractice, it is recommended that for primary mea~surements electronic pressure measurement equip-ment be used. Dead weight gages, manometers, andother measurement devices may in some caseS beas accurate !:Indmay be used.

All signal cables must have a grounded shield todrain any indlJced currents from ne!:lrbyelectricalequipment. All signal cables should be installedaway from EMFproducing devices such as motors,generators, electrical conduit, and electrical servicepanels.

Prior t9 calibration, the pressure transducer rangemay be altered to match the process better. However,the sensitivity to ambient temperature fluctuationmay increase as the range is altered.

Additional points will increa!!e the accuracy butare not required. During calibration the measuringpoint should be approached from an increasing anddecreasing manner to minimi4ethe hysteresiseffects.

Some pressure transducers have the capability ofchanging the range once the transmitter is in!!talled.The transmitters must be c!:llibratedat each rangeto be used during the test period.

25

-

i - ASME PTC 46-1996

4.2.2 Pressure Transmitter Accuracy

4.2.2.1 Introduction. The required pressuretr~nsmiU~r ~ccur~cy will depend upon the type ofvariables being measured. Refer to p~ra. 4.1.2 fordiscussion on primary and second~ry variables.

4.2.2.2 Accuracy Requirements. Class 1 primaryvariables should be measuredwith 0.1% accuracyclass pressure transmiUersthat have a total uncer-tainty of 0.3% or beuer of calibrated span. Thesepressuretransmittersshould be temperature compen-sated. If temperature compensation is not available,the ambient temperatureat the measurementlocationduring the test period must be compared to thetemperature during calibration to determine if thedecrease in accuracy is acceptable.

Class 2 primary v~riables should be measuredwith 0.25% accuracy classpressuretransmittersthathave a total uncertainty of 0.50% or better of c~li-brated span. ThesepreSsuretransmittersdo not needto be temperature compensated.

Secondary variables can be measured with anytype of pressure transmitter.

4.2.3 Pressure Triinsmitter TypesThree types of pressuretransmiUersare described

below.

. absolute pressuretransmitters. . gagepressuretransmitters

. differential pressuretransmitters

4.2.3.1 Absolute Pressure Transmitters

Application: Absolute pressure transmitters measurepressurereferencedto absolute zero pressure.Abso-lute pressure transmitters should be used on all mea-surementlocationswith a pressure equal to or lessthan atmospheric.Absolute pressure transmittersmayalsobeusedto measure pressures above atmosphericpressure.

Calibration: Absolute pressuretransmitterscan be cal-ibrated using one of two methods. The first methodinvolves connecting the test instrument to a devicethat develops an accurate vacuum at desired levels.Such a device Can be a dead weight gage in a belljar referenced to zero pressure or a divider pistonmechanism with the low side referenced to zeropressure.

The second method calibrates by developing andholding a constant vacuum in a chamber usinga suction and bleed control mechanism. The testinstrument and the calibration standard are bothconnected to the chamber. The chamber must be

i

!

Ii

; I

; I

!iI

, i

, i

jj

'1


maintained at constant vacuum during the calibrationof the instrument.

4.2.3.2 Gage Pressure Triinsmitters

Application: Gage pressure transmitters measure pres-sure referenced to ~tmospheric pressure. To obtainabsolute pressure, the test site atmospheric pressuremust be added to the g~ge pressure. This test siteatmospheric pressure should be measured by an abso-lute pressure transmitter. Gage pressure transmittersmay only be used on measurement locations withpressures higher than atmospheric. Gage pressuretransmitters are preferred over absolute pressure trans-mitters in measurement locations above atmosphericpressure because they are easier to calibrate.

Calibration: Gage pressure transmiUers can be cali.br~ted by an ~ccurate deadweight gage. The pressuregenerated by the dead weight gage must be correctedfor local gravity, air buoyancy, piston surface tension,piston area deflection, ~ctual mass of weights, actualpiston are~, ~nd working medium temperature. If theabove corrections ~re not used, the pressure generatedby the dead weight gage may be inaccurate. The ~c-tual piston area and mass of weights is determinedeach time the dead weight gage is calibrated.

4.2.3.3 Differential Pressure Transmitters

Application: Differenti~1 pressure tr~nsmiUers areusedwhere flow is determined by a differential pres-sure meter.

Calibration: Differential pressuretransducersused tomeasureClass1 primary vari~blesmustbe calibratedat line staticpressure unlessdata is available showingth~t the effect of high line static pressure is withinthe instrument accuracy. C~librationsat line staticpressureare performed by applying the actual ex-pectedprocesspressureto the instrumentasit is beingcalibrated.

Calibrations at line static pressure can be accom-plished by one of three methods:

(a) two highly accuratedeadweight gages;(b) adeadweight gageanddivider combination; or(cJ one de~dweight gageandone differential pres-

sure standard.

Differential pressure transmitters used to measureClass 2 primary variables or secondaryvariables donot require calibration at line static pressure andcan be calibrated using one accurate dead weightgageconnected to the "high" side of the instrument.If line static pressure is not used, the span must becorrected for high line static pressure shift unless

26

~


-the instrument is internally compensated for theeffect.

Once the instrument is installed in the field, thedifferential pressure from the source should be equal-ized and a zero value read. This zero bias mustbe subtracted from the test-measured differential

pressure.

4.2.4 Vacuum Measurements

4.2.4.1 Introduction. Vacuum measurementsarepressure measurements that are below atmosphericpressure. Absolute pressure transmitters are recpm-mended for these measurements. Differentialpres-sure transmittersmay be used with the "low" side ofthe transmitterconnected to the source to effectivelyresult in a negative gage that is subtracted fromatmospheric pressure to obtain an absolute value.This latter method may be used but is not reCom-mended for Class 1 primary variables since thesemeasurements are typically small and the differenceof two larger nllmbers may result in error.

Atmosphericpressure measurements must be mea-sured with absolute pressure transmitters.

4.2.4.2 Installation. All vacuum measurementsensing lines must slope upward from the sourceto the instrument.All sensing lines in steam or waterservice must be purged with a minute amount ofair or nitrogen to deter water legs from forming.The Code recommends that a purge system be usedthat isolates the purge gas during measurement ofthe process. A continuolls purge system may beused; however it must be regulated to have noinfluence on the reading. Prior to the test period,readings from all pllrged instrumentation should betaken successively with the purge on and with thepurge offto prove that the pllrge air has no influence.

Once transmitters Me connected to process, aleak check must be conducted. The leak check isperformed by isolating first the pllrge system andthen the ~OllrCe.If the sensing line has no leaks,the instrument reading will not change.

Atmospheric pressure transmitters should be in-stalled in the same general are<;1and elevation ofthe gage pressure transmitters and shpuld be prq-tected from air currents that could influence themeasurements.

4.2.5 Gage Pressure Measurements

4.2.5.1 Introd\.lction. Gage press!Jre measure-ment variables are those at Or <;1boveatmosphericpressure. These me;:lsurementsmay be made withgage OrabsOlutepreSsuretransmitters.G<;1gepressure

ASME PTC 46-1996

transmitters are recommended since they are easierto c<;1librateand to check once on site.

Caution must be used with low pressure variablesbecause they may enter the vacuum region at partload operation.

4.2.5.2 Installation. Gage pressure transmittersused in gas service should be installed with thesensing line sloping continuously upward to theinstrument. This method alleviates inaccuracies from

possible condensed liquid in the sensing line.Pressure transmitters used in steam or water service

should be installed with the sensing line slopingcontinuously downward to the instrument. This en-sures that the sensing line will be full of water. Insteam service, the sensing line should extend atleast two feet horizontally from the source beforethe downward slope begins. This horizontal lengthwill <;1l1owcondensation to form completely so thedownward slope will be completely full of liquid.

The water leg is the condensed liquid or waterin the sensing line. This liquid causes a static pressurehead to develop in the sensing line. This static headmust be subtracted from the pressure measurement.The static head is calculated by multiplying thesensing line vertical height by gravity and the densityof the liquid in the sensing line.

Each pressure transmitter should be installed withan isolation valve at the end of the sensing lineupstream of the instrument. The instrument sensingline should be vented to cle<;1rW<;1teror steam (insteam service) before the instrument is installed. Thiswill clear the sensing line of sediment or debris.After the instrument is installed, allpw sufficient timefor Iiq!Jid to form in the sensing line so th~ readingwill be correct.

4.2.6 Differential Pressure Measurements

4.2.6.1 Introduction. Differential pressure mea-surements are used to meaSure flow of a gas orliquid over or throllgh <;1flow element. The fluidflow over or through this type of devi~e produces adrop in pressur~.The differentialpresS!Jretransmittermeasures this pressllre difference or pressure dropth<;1tis u~ed to c<;1lculat~the fluid flow.

4.2.6.2 Installation. Differential pressure trans-mittersshould be installed utilizing a five-waymani-fold shown in Fig. 4.1. This manifold is requiredrather than a three-way manifold bec<;1usethe five-way eliminates the possibility of leakage past theequalizing valve.

Ifth~ inWument is us~d in ga~service, the sensinglines should slope upward to the instrument. This

27

~

ASMEPTC46-1996 OVERALL PLANT PERFORMANCE

Process

Vent

Instrument

FIG. 4.1 FIVE-WAY MANIFOLD

eliminates the possibility of error due to moisturecondensing in the sensing lines.

Differential preSsure transmitters used in steam,wpter, or other liquid service should be installedwith the sensing lines sloping downward to theinstrument.The sensing lines for differentialtransmit-ters in steam service should extend two feet horizon-tally before the downward slope begins. This willensure thpt the vertical length .ofsensing line is fullof liquid.

When a differential pressure meter is installed ona flow element that is .located in p vertical steamor water line, the measurement must be correctedfor the difference in sensing line height pnd fluidhead change unless the upper sensing line is installedagainst a steam or water line inside the insulationdown to where the lower sensing line protrudesfrom the insulation. The correction for the noninsu-lated case is as follows:

Ht( 1 1)hwc= hw+ 62.32 sg Vsen- Viluid

where:

hwc=:;:corrected differential pressure, in. H2Ohw=:;:measured differential pressure, in. H2OHt=:;:sensing line height difference, in.

62.32 =conversion factor

Vsen= specific volume of sensing line, ft3/lbmVf\ui~=specific volume of process, ft3/lbm

4.3 TEMPERATUREMEASUREMENT

4.3.1 Introduction. This Section presents require-ments and guidance regarding the measurement oftemperature. It also discusses applicable temperaturemeasl.lrement devices, calibration of temperaturemeasurement devices, and application of tempera-ture devices.

Since temperature measurement technology willchange over time, this Code does not limit theuse of other temperpture measurement devices notcurrently available or not currently reliable. If sucha device becomes available and is shown to be ofthe reql.liredaccuracy and reliability it may be used.

All temperature instrumentation signal wiresshould have a grounded shield to drain any induced

28


currents from nearby electrical equipment. All signalcables should be installed away from EMF-produdngdevices such as motors, generators, electrical con-duit, and electrical service panels.

4.3.2 Required Un(:ertainty. All instruments usedto measure Class 1 primary variables must have abias uncertainty of no more than O.50°Ffor tempera-tures less than 200°F and no more than 1°F fortemperatures more than 200°F. Instruments used tomeasure Class 2 primary variables must have a biasunl;;ertaintyof no more than 3°F. Instruments usedto measure secondary variables shall have a biasuncertainty of no more than 5°F. Primary and sec-ondary variables are described in para. 4.1.2

4.3.3 Acceptable Temperature Measurement De-vices

4.3.3.1 Mercury in Glass Thermometers. Mer-cury in glassthermometers are typil;;allyused wherethe number of readings required for a measurementpoint are limited and the measurement frequencyis low because the measurements are taken andrecorded manually. Mercury in glass thermometersare a good candidate for remote location bel;;auseno electrical cables are needed.

The mercury in glass thermometers need to havegrClduationswithin the necessary meClsurementaccu-

. racy. These devil;;esare typicallyvery sensitivetothe distance the device is immersed into the workingfluid (immersiondepth). They should be used ,.t thesame immersion depth experienced during calibra-tion or an immersion correction should be appliedper PTC 19.3.

4.3.3.2 Thermocouples. Thermocouples may beused to measure temperature of any fluid above200°F. The maximum temperature is dependent onthe type pf thermocouple Clndsheath mClterialused.

Thermocouples may be used for measurementsbelow 200°F if extreme I;;autionis used. The thermo-couple is a differential-typedevice. The thermocou-ple measures the difference between the measure-ment location in question and a referencetemperature. The greClterthis difference, the higherthe EMFsignal from the thermocouple. Therefore,below 200°F the EMF signal becomes low andsubject to induced noise causing inaccuracy.

The temperature cCllculatedfrom the EMFvoltagegenerated by the thermocouple should be in accord-ance with NIST monograph 175, 1993.

This Code recommends that the highest EMFperdegree be used in all cases. This can be accom-plished by type "E" (Chromel Constantan) thermo-

ASME PTC 46-1996

couples for measurements from 200°F to 1400°F.Type "E" thermocouples have the highest EMF perdegree in this range.

For temperatures above 1400°F to 2450°F type"K" (Chrome I Alumel) thermocouples have the high-est EMF per degree.

Thermocouples used to measure Class 1 primaryvariables must be continuous lead from the measure-ment's tip to the connection on the cold junction.These high accuracy thermocouples must have acold junction reference of 32°F or ambient if thejunction is well-insulated and reference measuringdevice is calibrated. The ice point reference caneither be a stirred ice bath or a calibrated electronicice bath.

This Code recommends that thermocouples usedfor high accuracy measurements have a suitablecalibration history (three or four sets of calibrationdata). This calibration history should include thetemperature level the thermocouple experienced be-tween CCllibrations. A thermocouple that is stableafter being used at lower temperatures may not bestable at higher temperatures.

Thermocouples are susceptible to drift after cy-cling. Cycling is the act of exposing the thermocoupleto process temperature and removing to ambientconditions. The number of times a thermocouple iscycled should be kept to a minimum.

Thermol;;ouples used to measure Class 2 primaryvariables can have junctions in the sensing wire.The junction of the two sensing wires must bemaintained at the same temperature. The cold junc-tion may be at ambient temperature for these lessaccurClte thermocouples provided that the ambientis measured and the measurement is compensatedfor changes in cold junction temperature.

Thermocouples should be constructed accordingto PTC 19.3, Temperature Measurement.

Thermocouples can effectively be used in highvibration areas such as main or high pressure inletsteam to the steam turbine. High vibrCltionmeasure-ment locations may not be conducive to othermeasurement devices.

4.3,3.3 Resistance Temperature Devices (RTD).The Resistance Temperature Device (RTD)may beused in testing from any low temperature to thehighest temperature recommended by the RTDman-ufacturer. Typically RTDscan measure in excess of1200°F.

Temperature measurements of Class 1 primaryvariables are best meClsuredby a four-wire type andmade of platinum as presented in Fig. 4.2. Three-

29


Mllasurement

_loop ---/' "

/ "/ \

FIG. 4.2 FOUR-WIRE RTDs

CQmpensation or leadresistance loop

FIG. 4.3 THREE-WIRE RTDs

wire Inps as shown in Fig. 4.3 and described inthe following paragraph may be used for Class 1primary vari!lples if they c!ln be shown to have theacc\)racy as required herein. They must however bemade of platinum.

Temperature measurements of Class 2 primaryvariables can be made accurately with either four-wire or three-wire devices and do not necessarilyneed to be made of platinum.

The c!llcl.llationof temperatl.lrefrom the resistanceshould be done according to equations in IPTS68as given in NISTmonograph 126, section 6.1. RTDsshould be constructed in accordance with PTC19.3.

4.3.3.4 Thermistors. Thermistors are constructedwith ceramic-like semiconducting material that acts

as a thermally sensitive variable resistor. However,unlike RTDs,the resistanceincreases with decreasingtemperature so that this device is useful at lowtemperatures.

This device may be used on any meas\)rementbelow 300°f. Above this temperature, the signal islow !lnd susceptible to error from current-inducednoise.

4.3.4 Calibration of Primary Variables Tempera,.ture Measurement Devices. The calibration of tem-perature measurement devices is accomplished byinserting the candidate temperature measurementdevice into a calibration medium along with atemperature standard.Thetemperature of the calibra-tion medium is then set to the calibration temperature

30


setpoint. The temperature of the calibration mediumis allowed to stabilize until the temperature of thestandard is fluctuating less than the accuracy of thestandard. The signal or reading from the standardand the candidate temperature device are sampledto determine the bias of the candidate temperaturedevice. See PTC 19.3 for a more detailed discussionof calibration methods.

4.3.5 Typical Applications

4.3.5.1 Temperature Measurement of Fluid in <tPipe or Vessel. Temperature measurement of a fluidin a pipe or vessel is accomplished by installing athermowell. A thermowell is a pressure-tight devicethat protrudes from the pipe or vessel wall into thefluid. The thermowell has a bore extending to nearthe tip to facilitate the immersion of a temperaturemeasurement device.

The bore should be sized to allow adequateclearance between the measurement device and thewell. Often the temperature measurement devicebecomes bent causing difficulty in the insertion ofthe device.

The bottom of the bore of the thermowell should

be the same sh;;\pe as the tip of the temperaturemeasurement device. The bore should be cleanedwith high-pressure air prior to insertion of the device.

The thermowell should be installed so that thetip protrudes through the boundary layer of the fluidto be measured. The thermowell should be locatedin an 'area where the fluid is well-mixed and hasno potential gradients. If the location is near thedischarge of a boiler, turbine, condenser, or otherpower plant component, the thermowell should bedpwnstre'am of an elbow in the pipe.

If more than one thermowell is installed in agiven pipe location it should be installed on theopposite side of the pipe and not directly downstreamof another thermowell.

Whert 'the temperature measurement device isinstalled it should be '!spring loaded!' to ensure thatthe tip of the device remains against the bottom ofthe thermowell.

For high-accuracy measurements the Code recom-mends thanhe portion of the thermowell protrudingoutside the pipe or vessel be insulated along withthe device itself to minimize conduction losses.

For measuring the temperature of desuperheatedste;;\m, the thermowelliocation relative to the desup-erheating spray injection must be carefully chosen.The thermowell must be located where the desuper-heating water has thoroughly mixed with the steam.This can be accomplished by placing the thermowell

ASME PTC 46-1996

downstream of two elbows in the steam line pastthe desuperheat injection point.

4.3.5.2 Temperature Measurement of low Pres-sure Fluid in a Pipe or Vessel. As an alternate toinstalling a thermowell in a pipe, if the fluid is atlow pressure, the temperature measurement devicecan either be installed directly into the pipe orvessel or "flow-through wells" may be used.

The temperature measurement device can be in-stalled directly into the fluid using a bored-through-type compression fitting. The fitting should be ofproper size to clamp onto the device. A plastic orTeflon-type ferrule is recommended so that the de-vice can be removed easily and used elsewhere.The device must protrude through the boundarylayer of the fluid. Care must be used so that thedevice does not protrude into the fluid enough tocause vibration of the device from the flowing fluid.If the fluid is a hazardous gas such as natural gasor propane the fitting should be checked for leaks.

A "flow-through well" is shown in Fig. 4.4. Thisarrangement is only applicable for water in a coolingsystem where the fluid is not hazardous and the fluidcan be disposed without great cost. The principle isto allow the fluid to flow out of the pipe or vessel,over the tip of the temperature measurement device.

4.3.5.3 Temperature Measuremeot of Productsof Combustion in a Duct. Measurement of the fluidtemperature in ;;\duct requires several measurementpoints to minimizethe uncertainty effectsof tempera-ture gradients. Typically, the duct pressures are lowor negative so that thermowells are not needed.A long sheathed thermocouple or an unsheathedthermqcouple attached to a rod will suffice.

The number of measurement points ne<;:essarytobe used is determined experimentally or by experi-ence from the magnitude of the temperature varia-tions at the desired measurement cross-section andthe required maximum yncertainty of the value ofthe average temperatyre. The total yncertainty ofthe averagetemperature is affectedby the uncertaintyof the individualmeasurements, the number of pointsused in the averagingprocess, the temperature gradi-ents, and the time variation of the readings. Theparties to the test should locate the measurementplane at a point of uniform temperatures and veloci-ties to the extent practical. The recommended num-ber of points are:

. lo<;:atedevery nine (9) ft2

. a minimum of four (4) points

. a maximum of 36 points

31

ASME PTC 46-1996

Fluid to bemeasured


Measurementdevice

~Fluid

FIG.4.4 flOW-THROUGH WELL

PTC 19.1 describes the method of calculating theuncertainty of the average of multiple measurementsthat vary with time.

For round ducts the points may be installed intwo (2) diameters 90 deg. from each other as shownin Fig.4.5, which also shows the method of calculat-ing the measurement point spacing. The point spac-ing is based on locating the measurement points atthe centroids of equal areas.

For square or rectangular ducts, the same conceptof locating the measurement points at chondrites ofequal areas should be used. The measurement pointsshould be laid out in a rectangular pattern that takesinto account the horizontal and vertical temperaturegradients at the me;:!surementcross-section. The di-rection with the highest temperature gradient shouldhave the closer point sp;:!cing.

4.3.$.4 Inlet Dry 8ulb Air Temperature. The drybulb temper;:!ture is the static temperature at theinlet to the plant equipment. The temperature sensormust be shielded frQm sp!;:!rand other sourCeSofradiation and must have a constant air flow acrossthe sensing element. Althpugh not required, a me-chanically aspired psychrometer, as described be-low, may be used. If a psychrometer is used, a wickshould not be placed over the sensor (as is requiredfor measurement of wet bulb temperature). If theair velocity across the sensing element is greater

~

than 1,500 feet per minute, shielding of the sensingelement is required to minimize stagnation effects.

4.3.5.5 Inlet Air Moisture Content. The moisturecontent of the ambient air may be determined bythe measurement of adiabatic wet-bulb, dew pointtemperature, or relative humidity. Measurements todetermine moisturecontent must be made in proxim-ity with measurements of ambient dry bulb tempera-ture to provide the basis for determination of airproperties. Descriptions of acceptable devices formeasurement of moisture content are discussedbelow.

(a) Wet Bulb Temperature. The thermodynamicwet bulbtemperature isthe air temperature that resultswhen air is adiabatically cooled to saturation. Wetbulb temperature can be inferred by a properly de-signed mechanically aspired psychrometer. The pro-cess by which a psychrometer operates is not adia-batic saturation, but one of simultaneous heat andmass transferfromthe wet bulb sensing element. Theresultingtemperature achieved by a psychrometer issufficientlyclose to the thermodynamic wet bulb tem-perature over most range of .conditions. However, apsychrometer should not be used for temperaturesbelow 40°F or when the relativehumidity is less than15 percent.Withinthe allowable range of use, a prop-erly designedpsychrometer can provide a determina-tion of wet bulb temperature with an uncertainty of

32


Cross $ec;tioo of Circ;"I"rG"s P"sAge

ASME PTC 46-1996

NOTE: indic;"tes location of samplepoint

j2Na'1'(1 = R -;::r;-'n = distance fromsampling

point to center of pipeR = r"dius of pipe

N, = no. of samplingpoints countedfromcenter as /:erO

NT = total no. of samplingpointson Adiameter

0.550

1.0

Duct Diameters Upstream From Flow Disturbance (Dist;mce AI

2.01.5 2.5

TA

tB

L

~ 5 9 10I> 7

0

3 4 8

Duct Diameters Downstream From Flow Disturbance (Distance B)

FIG. 4.5 DUCT MEASUREMENTPOINTS

33

.. 40C'0g.

Ii;><II 30.='0

jE:::I?e 20:::IE'c

10

ASME PIC 46-1996

iIIi II

approximately j: 0.25°F (based on a temperature sen-sor uncertainty of j: 0.15°F).

The mechanically aspirated psychrometer shouldincorporate the following features:

(1) The sensing element is shielded from directsunlight and any other surface that is at a temperatureother than the dry bulb temperature. Ifthe measure- .

ment is to be made in direct sunlight, the sensor mustbe enclosed by a double-wall shield that permits theair to be drawn across the sensor and between thewalls.

(2) The sensing element is suspended in the airstream and is not in contact with the shield walls.

(3) The sensing element is snugly covered by aclean, cotton wick that is kept wetted from a reservoirof distilled water.

(4) The air velocity across the sensing elementis maintained constant in the range of 800 to 1,200feet per minute.

(5) Air is drawn across the sensing element insuch a manner that it is not heated by the fan motoror other sources of heat.

The psychrometer should be located at least five(5) feet above ground level and should not be locatedwithin five (5) feet of vegetation or surface water.

(b) Cooled Mirror (Jew Point Hygrometer. The dewpoint temperature is the temperature of moist air whenit is saturated at the same ambient pressure and withthe same specific humidity. A cooled mirror dew pointhygrometer uses a cooled mirror to detect the dewpoint. Air is drawn across a mirror which is cooledto the temperature at which vapor begins to form onthe mirror. A temperature sensor mounted in the mir-ror measures the surface temperature. Manual devicesare available. There are also commercially availableinstruments that automatically control the mirror tem-perature, detect the inception of condensation, andprovide a temperature readout. Commercially avail-able cooled mirror dew point hygrometers measurethe d~w PRint t~I'T1P~raturewith an uncertainty of ap-proximately 0.5°F.

The advantages of using dew point hygrometersinclude:

(1) Calibration can be verified by using samplegases prepared with known concentrations ofmoisture.

(2) Dew point can be measured over the fullrange of ambient conditions, including belowfreezing.

(c) Relative Humidity Hygrometers.Thin film ca-pacitance and polymer resistance sensors provide adirect measurement of relative humidity. Measure-ment uncertainties vary with sensor type and design.

-~


Their usual range is from j: 1 to j: 2 percent of rangefrom relative humidities between 0 and 90 percent.Measurement uncertainties for relative humiditiesabove 90 percent are usually higher. Accuracies ofthese types of instruments are dependent on propercalibration.

The advantages of relative humidity hygrometersinclude:

(1) Calibration can be verified by using samplegases prepared with known concentrations ofmoisture.

(2) Relativehumidity can be measured over thefull range of ambient conditions, including belowfreezing. .

4.4 FLOW MEASUREMENT

4.4.1 Water and Steam

4.4.1.1 Water flows can be measured more accu-rately than steam flows. Whenever possible it is bestto configure the tests so that water flows are mea-sured and used to calculate steam flows. The usualmethod of determining flow is with a differentialpressure meter, using two independent differentialpressure instruments.

4.4.1.2 The flow section with a throat tap nozzledescribed in PTC 6 is recommended for the Class1 primary flow measurements when the test Reynoldsnumbers are greater than the maximum calibratedReynolds number.

4.4.1.3 Other Flow Measuring Devices. Informa-tion relative to the construction, calibration, andinstallation of other flow measuring devices appearsin ASMEMFC-3M.These devices can be used forClass 2 flow measurements and for secondary flowmeasurements.They can also be used for Class 1primary flow measurement when Reynolds numberextrapolation is not required.

. The beta-ratio should be limited to the range of0.25 to 0.50 for wall-tap nozzles and venturis and0.30 to 0.60 for orifices.

. Class 1 primary flow measurement requires cali-bration.

. For Class 2 primary and secondary flows, the ap-propriate referencecoefficientfor the actual devicegiven in ASMEMFC-3Mmay be used.

4.4.1.4 Water Flow Characteristics. Flow mea-surements shall not be undertaken unless the flowis steady or fluctuatesonly slightlywith time. Fluctua-tions in the flow shall be suppressed before the

34

~,.- -

'"-'"


beginning of a test by very careful adjustment of flowand level controls or by introducing a combinationof conductance, such as pump recirculation, andresistance, such as throttling the pump discharge,in the line between the pulsation sources and theflow measuring device. Hydraulic damping deviceson instruments do not eliminate errors due to pulsa-tions and, therefore, should not be used.

In passing through the flow measuring device, thewater should not flash into steam. The minimum

throat static pressure shall be higher than the satura-tion pressure corresponding to the temperature ofthe flowing water by at least 20 percent of thethroat velocity head, as required per para. 4.5.1.7to avoid cavitation.

4.4.1.5 Steam Flow Characteristics. In passingthrough the flow measuring device, the steam mustremain superheated. For steam lines with desuper-heaters, the flow sec:tion should be installed aheadof desuperheaters and the total flow is determinedfrom the sum of steam flow and the desuperheaterwater flow.

Secondary Measurements. The calculation ofsteam flow through a nollie, an orifice, or a venturishould be based on upstream conditions of pressure,temperature, and viscosity. In order to avoid thedisturbing influence of a thermowell located up-stream of a primary element, downstream measure-m.ents of pressure and temperature are used to deter-mine the enthalpy of the steam, which is assumedto be constant throughout a well-insulated flowmeasurement section. Based on this enthalpy andthe upstream pressure, the desired upstream proper-ties can be computed from the steam tables.

4.4.1.6 Enthalpy Drop Method For Steam FlowDetermination. The enthalpy drop method may be

employed for the determination of steam flow butis applicable only to nQncondensing or back pressureturbine having a superheated exhaust. Separate gen-erator tests must be available from which electrical

losses can be computed or their design value mustbe agreed \.Jpon. The parties to the test must assignand agree upon values for the mechanical losses ofthe turbine. The steam flow is calculated from an

energy balance based on measurements of pressureand temperature of all steam entering and leavingthe turbine, including consideration of leak-ofts, gen-erator output, and the agreed-upon mechanical andelectrical losses.

ASME PTC 46-1996

4.4.1.7 Additional flow Measurements(a) Feedwater Heater Extraction Flows. If the ex-

traction steam is superheated, the extraction flow canbe determined by heat balance calculation. The un-certainty of the result increases asthe temperature riseacross the heater diminishes. It should be noted that

errors in temperature measurement will be translatedinto extraction flow error. For instance, an error of

1°F (0.5 K) in the temperature rise of a heater with anincrease of 30°F (17 K) will result in an expecteduncertainty in extraction flow of approximately 3.3percent.

(b) Two-Phase Steam- Water Mixtures. There are in-stances when it is desirable to measure the flow rate

of a two-phase mixture. PTC 12.4 describes methodsfor measurement of two-phase flow.

4.4.2 Liquid Fuel. Liquid fuel flows shall be mea-sured using flow meters that are calibrated throughouttheir Reynolds number r;mge expected during thetest using the actual flow. For volume flow metersthe temperature of the fuel also must be accuratelymeasured to correctly calculate the flow. Other flowmeters are permitted if a measurement error of 0.7%or less can be achieved.

4.4.2.1 Positive Displacement Oil Flow Meter.Use of oil flow metersis recommendedwithouttemperaturecompensation.The effectsof tempera-ture on fluid density <::an be accounted for by calcu-lating the mass flow based on the specific gravityat the flowing temperature.

qmh = (8.337) (60) qy (5g) (4.4.1)

whereqmh= massflow, Ibm/h

qy= volume flow, gal/msg= specific gravity at flowing temperature, di-

mensionless8.337 = density of water at 60°F, Ib/gal

60= minutes per hour, m/h

Fuel analyses should be completed on samplestakenduringtesting. The lower and higher heatingval~e of the fuel and the specific gravity of the fuelshould be determined from these fuel analyses.Thespecific gravity should be evaluatedat three tempera-tures covering the range of temperatures measuredduring testing.The specific gravity at flowing temper-atures should then be determined by interpolatingbetween the measuredvalues to the correct temper-ature.

35

ASME PTC 46-1996

I'Iii

i;IiIi

4.4.3 Gas Fuel. Gas fuel flows may be measuredusing orifices or turbine type flow meters. The fuelmass flow must be determined with a total uncer-tainty of no greater than 0.8%. Measurements usedto determine the mass flow rate such as fuel analysisto determine density, the static and differential pres-sures, temperature, and frequency, if a turbine meter,must be within an uncertainty range to meet thisrequirement. Other flow meters are permitted if itcan be demonstrated that the total uncertainty ofmass flow rate is 0.8% or less.

ASME MFC-3M-1989 details the calculation ofthe uncertainty of an orifice metering run manufac-tured and installed correctly. The manufacturer re-quirement is to demonstrate that the meter wasmanufactured in accordance with the appropriatereferences, shown in para. 4.4.3.1.

Uncertainty of turbine meters is usually by state-ment of the manufacturer as calibrated in atmo-

spheric air or water, with formulationsfor calculatingthe increased uncertainty when used in gas flow athigher temperatures and pressures. Sometimes, aturbine meter is calibrated in pressurized air. Theturbine meter calibration report must be examinedto confirmthe uncertainty as calibrated in the calibra-tion medium.

jI

i

IIIIII:1

.,,[

II

ili

III

,IId

I

- II

4.4.3.1 Calculation of Natural Gas Fuel Flow. Usingan Orifice.Thefollowingprocedureis shownfor c~lculation of natural gas fuel flow using measure-ments from a flange-tapped orifice meter. The orificemetering run must meet the straight length require-ments of 150-5167, and the manufacturing and otherinstallation requirements of ASME MFC-3M-1989.These include circularityand diameter determinationof orifice and pipe, pipe surface smoothness, orificeedge sh;npness, plate and edge thickness, and otherrequirements,detailed in ASMEMFC-3M-1989.Thecalculations are also done in strict accordance withASME MFC 3M-1989, with an example shownbelow.

MassFuel FlowThe following equation is used to develop the

mass fuel flow, in Ibis.

2

f3Pfl

qms = 0.09970190 C YI d ~ (4.4.2)1 - /3

whereqms= gas mass flow, Ib/~

0.09970190= units conversion constantC =discharge coefficient, dimensionlessYl =expansionfactor,dimensionless

Ii

OVERALLPLANT PERFORMANCE

d =diameter of orifice, in.D = inside diameter of pipe, in.

hw ;:::differentialpressure,in. of H2Oat 60°Fpn = density of flowing gas upstream of

orifice, Ibm/ft3 .

f3 ;::: beta ratio (diD), dimensionless

f

Note: Any other consistent set of units is acceptable with theuse of the appropriate units conversion constant.

Orifice and Pipe Dimension Correction to FlowingTemperature

The dimesions of the orifice and pipe may bemeasured at conditions that vary from their in-serviceconditions. The following eql,Jations compensate forthe dimensional changes to the components due totemperature variations.

d = [1 + apE (If - Imeas)) dmeas (4.4.3)

0 = [1 + ap (If - Imeas)) Dmeas (4.4.4)

wheredmeas = measureddiameterof orifice, in.Dmeas= measured diameter of pipe, in.

apE = coefficient of thermal expansion for orifice,in./in./°F

ap = coefficient of thermal expansion for pipein./in./°F

tf = temperature of flowing fluid, OFfo,l!as= metal temperature when components were

measurt:d, OF

Calculation of Flow DensityCalculation of the density of the flowing gas (Pn)

can be derived from the ideal gas laws.

Pf Mrair sg,

Pn;:: ZfRT((4.4.5)

where

Pf =pressure of gas, PSIAMrair =molecl,Jlarweight of standard air, 28.9625

Ib/lbmoleSgi =gas ideal specific gravity, dimensionlessZf = natl,Jralgas compressibility factor, dimen-

sionless (developed from AGATransmissionMeasurement Committee Report No.8)

R = Universal Gas Constant, 10.7316PSIA ft3

Ib mole "'R

Tf = absolute temperature of gas, OR

36


Expansion FactorThe expansion factor compensates for the change

in gas density due to the increase in pressure whenflowing through the orifice.

4 hwY1 ::;:: 1 - (0.41+ 0.3513 ) . (4.4.6)

27.73 K P,

where

K = isentropic coefficient, 1.327.73 =units conversion factor, in. H2O/PSI

Coefficitmt of DischargeThe coefficient of discharge relates actual test data

to theoretically determined flows.For D ~ 2.3 in.

C::;:: 0.5959 + 0.0312132.1- 0.1840138 + 0.09p-l 134(1 - 134t1- 0.03370-1133 + 91.71132.5 Ro-0.75

(4.4.7)

ASME PTC 46-1996

P, Mrai' Sgi

PI::;:: Z,RT,(4.4.10)

for 2 in. < D < 2.3 in., see MFC-3M-1989Ro = Reynolds number with respect to the pipe

diameter, dimensionless

Reynolds Number

22738 qms

R 0 ::;:: ;0 (4.4.8)

where

P, = pressure of gas, PSIAMrai'= molecular weight of standard air, 28.9625

Ib/lb molesg; = gas ideal specific gravity, dimensionlessZ{= natural gas compressibility factor, dimen-

sionless(developed from AGATransmissionMeasurement Committee Report No.8)

R = Universal Gas Constant, 10.7316PSIAft3 .

Ib mole oR

T{ = absolute temperature of gas, OR

4.4.3.3 Digital Computation of Fuel Flow Rate.Mass flow rate as shown by computer print-out orflow computer is not acceptable without showingintermediateresultsand the data used for the calcula-tions. Intermediate results for an orifice would in-clude the discharge coefficient, corrected diameterfor thermal expansion, expansion factor, etc. Rawdata includes static and differential pressures, andtemperature. Fora turbine meter, intermediate resultsinclude the turbine meter constant(s) used in thecalculation, and how it is determined from thecalibration curve of the meter. Data includes fre-quency, temperature, and pressure. Forboth devices,fuel analysis and the intermediate results used inthe calculation of density is required.

4.5 PRIMARYHEATINPUT MEASUREMENT

4.5.1 Cpnsistent Splid Fuels. Consistent solid fuelsare defined as those with a heating value that variesless than 2.0% over the course of a performancetest. The heat input to the plant by consistent solidfuel flow must be measured and calculated by indi-rect methods since solid fuel flow cannot be accu-rately measured using direct methods. The approachrequires dividingthe heat added to the workingfluid by the boiler fuel efficiency as follows:

facility heat input =

where

facility heat input =

boiler energy outputb.e.

the energy added to thefacility by the consistentfuel, Btu/lb

where

qms ::;:: mass gas flow, Ib/secJL ::;::absolute viscosity of the fluid, 6.9 x 106

Ibm/ft sec

4.4.3.2 T\.Irbine Meters for Natural Gas FuelFlow Measurement. Use of turbine meters is onealternative to orifice gas flow measurement. Theturbine meter measures actual volume flow. Theturbine meter rotates a shaft connected to a display.Through a Series of gears the rotational shaft speedis adjusted so that the counter displays in actualvolume units per unit time, e.g., actual cubic feetper minute. This value must be adjusted to massflow units, Ib/h.

qms ::;::60 qv PI (4.4.9)

37

where

qms ::;::mass flow, Ib/hqv = actual volumeflow,acf/mp{ = density at flowing conditions,

60 = minutes per hour, m/hIb/ad

ASME PTC 46-1996

I~

boiler energy output = heat added to the workingfluid (including blowdown)by the boiler, Btu/lb

b.e. = boiler fuel efficiencyI lo~ses+ I credits= 1 ~ -.

heating value

The boiler fuel efficiency (b.e.) ~hallbe (:akulatedy~ing the energy balanc:e method per PTC 4, FiredSteam Generator~.l

The boiler energy output i~ the energy added tothe boiler feedwatera~ it become~~uperheated~teamand as ~team i~ reheated if appliqble. The boilerenergy output i~ calculated by drawing a mass andenergy control volume arownd the boiler. Then theprodwctof the flow and.enthalpy of each water andsteam ~tream crossing the volume are summed.Flow~ entering the vplwme are negative and theflows leaving are po~itive.All steam or water flowsinto or out of the boiler will be included. Theseflow~inclwdefeedwater, ~yperheat spray,blowdown,~ootblower ~team, and steam flows.

The following is ~ome guid;mce as to when flow~hol..lldbe included and how to make measwrements.Swperheat ~pray/attemperator flow generally origi~nate~ at the boiler feedpump discharge. However,otca~ionally it originates from the feedwater linedbwnWeam pfany feedwater heaters and down-stream of theJfeedwater measurement. Should thelatter..be the case, do not include the superheat~pray flow in the calculation.

Boilerblowdown most often leaves the cycle and~howldbe counted as one of the leaving streams.The enthalpy of this stream is saturated liquid atthe boiler drwm pressure. This Code recommendsthat the boiler blowdown be isolated since it isdifficult to mea~l!fe a saturated liquid flow.

SQotblpwing~team~houldbe counted as a leavingflow We~mifir originates within the boiler. Oftenthi~steal11origirlate~upstream of one of the superheat~ection?. If ~99tblowing steam cannot be measuredit ~h04'dbe i$oJ*ed during the test. Ifthe sootblow-ing ~tealTloriginates downstream of the main steamit ~hould not be inclwded in the calculation.

The main stearn flow j~ typically cal!:ulated bysubtracting blowdowrl and other po~sibleextraneousflow like sootblowing ~team from the feedwater flow.

1 PTC 4 is scheQiJl!:kJfpr piJblicMion in 1998, and will replacePTC 4.1, "Steam Generating Units." Until then, the parties tothe test miJstagree pn a methPQologyfpr calculating the boilerfuel efficiency. NonmanQ~tory giJiQi'lncefqr the determini'ltion ofboiler fiJel efficiency is prpvided in Appendix H, which can beused by mutual agreement pf the parties to a test until PTC 4is available.


The reheat steamflowto the boileris determinedby subtractingfromthe main steam flowany leakagesand extractions that leave the main steam before itreturns to the boiler as reheat steam. leakages shallbe either measured directly, calculated using vendorpressure for flow relationships, or determined bymethods acceptable to all parties. Extraction flowsshall either be measured directly or calculated byheat balance around the heater if the extraction isserving a heater.

Reheat ~pray flow m!,lstalso be included as oneof the flow streams into the boiler. The reheat returnflow is the summationof the reheat steam flow tothe boiler and the cold reheat spray.

4.5.2 Consistent liquid or Gaseous Fuels. Consist-ent liquid or gaseous fuels are those with heatingvalues that vary les~than 1.0% over the course ofa performance te~t. Since liquid and ga~ flows and~eating values can be determined with high accu-racy, the heat input from these type fuels is usuallydetermined by direct measurement of fuel flow andthe laboratoryor on-line c;:hromatograph-determinedheating value. Consistent liquid or gaseous fuelsheat input can also be determined by calculationas with solid fuels.

Homogenous gas and liquid fuel flows are usuallymeasured directlyfor gas turbine based power plants.For steam turbine plants, the lowest uncertaintymethod should be employed depending on the spe-cific site.

Subsection 4.4 include~ a di~cu~sionof the mea-surement of liquid and gaseo4s fuel flpw. Shouldthe direct method be employed, the flow i~multipliedby the heating value of the stream to obtain thefacility heatinpwt to the cycle. The heating valuec;:anbe measured by an on-line chromatograph orby sampling the ~tream Periodically (at least threesamples per te~t) andanalyzingeach sampleindivid-ually for heatingvalue. The analy~i~of gas, eitherby po-line chrpmatography or from laboratory sam-ple~, in acc;:prdance with ASTM D 01945 results inthe amount and kind pf ga~ con~titl..lent~,from whichheating vall..leis c;:alculated. liql..lidfuel heating Val4emay be determined by calorimeter in ac<::ordancewith ASTM 04809.

4.5.3 Solid Fuel and Ash Sampling. Refer to PTC4, Fired Steam Generators, for sampling requirementsand procedures.2

2 PTC 4 is scheduled for publicption in 199/1, i1nd will replacePTC 4.1, "Steam C;en~ri'lting \.Jnits." Until then, the parties tothe test must agree on a methodology for calculating solid fueland ash sampling. Nonmandatory guidi'lnce for solid fuel and

38


4.6 elECTRICAL GENERATION MEASUREMENT

4.6.1 Introduction. This Subsection presents re-quirements and guidance regarding the measurementof electrical generation. The scope of this Subsectionincludes the measurement of polyphase (three phase)real and reactive power measurements. Typicallythe polyphase measurement will be net or overallplant generation, the direct measurement of genera-tor output (gross generation), or power consumptionof large plant auxiliary equipment (such as a boilerfeedpump drives).

ANSI/IEEE Standard 120-1989i "IEEE Master TestGuide for Electrical Measurements in Power Circuits"is referenced for measurement requirements not in-cluded in this Subsection or for any additionallyrequired instruction.

4.6.2 Electrical Measurement System Connections.Polyphase power systems will be three-wire or four-wire type systems. Below is a description of whereeach of these systems are found and how the mea-surements are made.

4.6.2.1 Three Wire Power Systems. Three wirepower systems are used for several types of powersystems as shown in Fig. 4.6. Descriptions of variousthree wire power systems are as follow:

(a) Where generator output (gross generation) is de-siredJrom an "Open Delti'l"q:mnected generator. Inthis case no neutral or fourth wire is available.

(b) Where generator output is desired from a "wye"connected generator with a high impedance neutralgrounding device. In this case the generator is con-

. nected directly toa transformer with a delta primarywinding and load distribution is made on the second-ary, grounded-wye, side of the transformer. Any loadunbalance on the load distribution side of the genera-tor transformer are seen as neutral current in the

grounded wye connection. On the generator side ofthe transformer, the neutral current is effectively fil-tered out due to the delta winding, and a neutralconductor is not required.

(c) Where generator output is desired from a wyeconnected generator with a low impedance neutralgrounding resistor. In this case the generator is con-nected to a three-wire load distribution bus and theloads are connected either phase to phase, !iinglephase, or three phase delta. The grounding resistor issized to carry 400 to 2000 amperes of fault current.

ash sampling is provided in Appendix \, which can be used bymutual agreement of the parties to a test until PTC4 is available.

ASME PTC 46-1996

(d) A less common fourth example of a three-wirepower system is where generator output is desiredfrom an ungrounded wye generator used with a delta-wye grounded transformer.

Three-wire power systems can be measured usingtwo "Open Deltc\ Connected" potential transformers(PTs) and two current transformers (CTs). The OpenDelta metering system is shown in Fig. 4.6. Theseinstrument transformers are connected to either twowatt meters, two watt-hour meters, or a two-elementwatt-hour meter. A var type meter is the recom-mended method to measure reactive power to estab-lish the power factor. Power factor is then determinedas follows:

WattsrPF =

[Watts/ + Vars/JO.5

where

PF= power factorWattsr= total watts

Varsr= total vars

Alternatively, for balanced three-phase sinusoidalcircuits, power factor may be calculated from thephase-to-phase power meC\surement as follows:

PF =

(1 + 3 [(Wattsl-2 - Watts3-2)

]

2)(Wattsl-2 + Watts3-2)

wherePF= power factor

Wattsl-2 = real power phase 1 to 2Watts3-2=real power phase 3 to 2

4.6.2.2 Four-Wire Power Systems. There are twotypes of four-wire p6wer systems as shown in Fig.4.7. Descriptions of various three-wire power systemsare as follow:

(a) Where generator output is desired from a wyeconnected generator with a solid or impedanceground where current can flow through this fourthwire.

(b) Where net plcmt generation is measured some-where other than at the generator such as the highside of the step-up transformer. In this case the neutralis simulated by a ground.

In addition, with the exception of the "OpenDelta" generator connection, all of the three-wiresystems described in para. 4.6.2.1 can also be mea-

39

ASME PTC 46-1996OVERAll PLANT PERFORMANCE

CTPhase 1

Deltagenerator

Phase 2

Phase 3

nPT

'\Two wattmeters or

one two-element watt-hour meter.

Connects here.

CTPhase 1

II Phase 2

nPT"

Phase 3

Two wattmeters orone two-element watt-hour meter.

/Connects here.

FIG. 4.6 THREE-WIREOPEN DELTA CONNECTED METERING SYSTEM

.""""-'

40

-- ~~

OVERALL. PLANT PERFORMANCEASME PTC 46-1996. CT

Phase 1

II"-.

Phase 2

Phase 3

Neutral

IPTn"

ri

/'Three wattmeters or

one three-element watt-hour meter.

Connects here.

CTPhase 1

ICT

Phase 2 .

CT Phase 3

PTn'I

\t .

t

Neutralor ground

II

8 PT

nt\'v

t

PT

n,V

tThree wattmeters or

one three-element watt-hour meter.

Connects here.

a", FIG. 4.7 FOUR-WIRE METERING SYSTEM

41

~ ~~~~-~~- --~u_-

ASME PTC 46-1996

I'I

I!'I,

sured using the f()\.!r-wire measurement system de-scribed in this Section.

The measurement of a four-wire power systemsmade using three PTs and three CTs as shown inFig. 4.7. These instrument transformers are connectedto either three watt/var meters, three watt-hour/var-hour meters, or a three element watt-hour/var-hourmeter. The var meters are necessary to establish thepower factor as follows:

Watts,PF ::;

..JWatis,2 ~\I;Jf~,iII

where

PF= power factorWatts,= total watts for three phases

Vars,= total vars for three phases

Alternatively, power factor may be determined bymeasuring each phase current and voltage, with thefollowing equation:

II i""

Watts,

PF = 2 Vi ,;I

dlII

:1

,

1

I,ii;{

wherePF= power factorVi= phase voltage for each of the three phases1;= phase current for each of the three phases

4.6.3 Electrical Metering Equipment. There arefour types of electrical metering equipment that maybe usedto measureelectricalenergy:1)wattmeters,2) watt-hour meters, 3) var meters, and 4) var-hourmeters.Single or polyphase meteringequipment maybe used.However,if polyphase equipment is usedthe output from each phase must be ilvailable orthe meter must be calibrated three phase. Thesemeters are described below.

4.6.3.1 Watt Meters. Watt meters measure in-stantaneous ilctive power. The instantaneous activepower must be measuredfrequently during a test runand averaged over the test run period to determineaverage power (kilowatts)during the test. Shouldthe total active electrical energy (kilowatt-hours)bedesired, the average power must be multiplied bythe test duration in hours.

Watt meters measuring a Class 1 primary variablesuch as net or gross active generation must have abias uncertainty equal to or less than 0.2 percentof reading.Meteringwith an uncertaintyequal toor less than 0.5 percent of reading may be used

II'I'


for the measurement of Class 2 primary variables.There is no metering accuracy requirements formeasurement of secondary variables. The outputfromthe watt meters mustbe sampled with a fre-quency high enough to attain an acceptable preci-sion. This is a function of the variation of the powermeasured. A general guideline is a frequency of notless than once each minute.

4.6.3.2 Watt-hour Meters. Watt-hour metersmeasure active energy (kilowatt-hours)during a testperiod, The measurementof watt-hours must bedividedby the test durationin hours to determineaverage active power (kilowatts) during the testperiod.

Watt-hour meters measuring a Class 1 primaryvariable such as net or gross active generation musthave an uncertainty equal to or less than 0.2 percentof reading. Metering with an uncertainty equal toor less than 0.5 percent of reading may be usedfor measurementof Class 2 primary variables. Thereare no meteringaccuracy requirements for measure-ment of secondaryvariables.

The resolution of watt-hour meter output is oftenso low that high inaccuraciescan occur over atypical test period. Often watt-hour meters will havean analog or digital output with a higher resolutionthat may be used to increase the resolution. Somewatt-hour meters will often also have a pulse typeoutP\.ltthilt maybesummedover time to determinean ilccurate total energy during the test period. Fordisk type watt-hour meters with no external output,the disk revolutions can be counted during a testto increase resolution.

4.6.3.3 Var Meters. var meters measure instanta-neous reactive power. The var measurements aretypically used on four wire systems to calculatepower factor as discussed in para. 4.6.2.2. Theinstantaneous reactive power must be measured fre-quently during a test run and averaged over the tes'run period to determine average reactive powe!(kilovars) during the test. Should the total reactivlelectrical energy (kilovar-hours)be desired, the average power must be multiplied by the test duratiolin hours.

var meters measuring a Class 1 or Class 2 primarvariable must have an uncertainty equal to or le~than 0.5 percent of reading. There is no meterinaccuracy requirements for measurement of seconcary variables. The output from the var meters mube sampled with a frequency high enough to attaian acceptable precision. This is a function of t~

42

-


variation of the power measured. A general guidelineis a frequency of not less than once each minute.

4.6.3.4 Var-hour Meters. Var-hour meters mea-

sure reactive energy (kilovar-hours) during a testperiod. The measurement of var-hours. must be di-vided by the test duration in hours to determineaverage active power (kilovars) during the test period.

Var-hour meters measuring a Class 1 or Class 2primary variable must have an uncertainty equal toor less than 0.5 percent of reading. There is nometering accuracy requirements for measurement ofsecondary variables.

The resolution of var-hour meter output is oftenso low that high inaccuracies can. occur over atypical test period. Often var-hour meters will havean analog or digital output with a higher resolutionthat may be used to increase the resolution. Some

var-hour meters will often also have a pulse typeoutput that may be summed over time to determinean accurate total energy during the test period. Fordisk type var-hour meters with no external output,the disk revolutions can be counted during a testto increase resolution.

4.6.3.5 Watt and Watt-hour Meter Calibration.Watt and wiltt-hour meters, cQllectively referred toas PQwermeters, are calibrated by applying powerthrough the test power meter and a watt meteror watt-hour meter standard simultaneously. Thiscomparison should be conducted at several powerlevels.(at leastfive) acrossthe expected power range.The difference between the test and standard instru-ments for each PQwer level should be calculatedand applied to the power measurement data fromthe test. For test points between the calibrationpower levels, a curve fit or linear interpolationshould be used. The selected pQwer levels shouldbe approached in an increasing and decreasingmanner. The calibration data at each power levelshould be averagedto minimize any hysteresiseffect.

Should polyphase metering equipment be used,the output of each phase must be available orthe meter mustbe calibratedwith all threephasessimyltaneously.

When calibrating watt-hour meters, the outputfrom the watt meter standard should be measuredwith frequencyhighenoughto reduce the precisionerror during calibration so the total uncertainty of thecalibration processthe required level. The averageoutput can be multiplied by the calibration timeinterval to compare against the watt-hour meteroutput.

ASME PTC 46-1996

Watt meters should be calibrated at the electricalline frequency of the equipment under test, Le.,donot calibrate meters at 60 Hz and use on 50 Hzequipment.

Watt meter standards should be allowed to havepower flow through them prior to calibration toensure the device is adequately"warm." The stan-dard should be checked for zero reading each dayprior to calibration.

4.6.3.6 Var and Var-hour Meter Calibration. In

order to calibrate a var or var-h9ur meter, one must

either have a var standard or a tatt meter standardand an accurate phase angle measuring device. Alsothe device used to supply power through the standardand test instruments must have the capability ofshifting phase to create several different stable powerfactors. These different power factors create reactivepower over the calibration range of the instrument.

Should a var meter standard be employed, theprocedure for calibration outlined above for wattmeters should be used. Should a watt meter standard

and philse angle meter be used, simultaneous mea-surements from the standard, phase angle meter,and test instrument should be taken. The var levelwill be calculated from the average watts and theaverage phase angle.

Watt meters should be calibrated at the electrical

line frequency of the equipment under test, i.e., donot calibrate meters at 60 Hz and use on 50 Hz

equipment.

When calibrating var-hour meters, the output fromthe var meter standard or watt meter/phase anglemeter combination should be measured with fre-

quency high enough to reduce the precision errorduring calibration so the total uncertainty of thecillibration process the required level. The averageoutput can be multiplied by the calibration timeinterval to compare against the watt-hour meteroutput.

Should polyphase metering equipment be used,the output of each phase must be available or

the meter must be cillibrated with all three phClsessimultaneously.

4.6.4 Instrument Transformers. Instrument trans-formers include potential transformers and currenttransformers. The potential transformers meilsurevoltage from a conductor to a reference Clnd thecurrent transformer~ measure current in a conductor.

4.6.4.1 Potential Transformers. Potential trans-formers measure either phase to phase voltage orphase to neutral voltage. The potential transformers

43

ASMEPTC 46-1996OVERALL PLANT PERFORMANCE

CT Ratio Correction Curve

0'0'"U.I:.2'0I!!isu.91;;a:

-

$econdary Currllnt

FIG. 4.8 TYPICAL CORRECTION CURVE

serve to convert the line or primary voltage (typicallyvery high in voltage) to a lower or secondary voltagesafe for metering (typically 120 volts for phase tophase systems and 69 volts for phase to neutral~ystems). For this rea~on the secondary voltage mea-~ured by the potential transformer must be multipliedby a turns ratio to calculate the primary voltage.

Potential tnmsfprmers are available in severalme-tering accuracy classes. For the measurement pfClass 1 pr CI!'Iss2 primary variables .or secondaryvariables,Q.~percent bias uncertainty class potentialtransformeJ~shall be used. In the Case pf Class 1primary variable measurement, potential transform-ers must be calipratf:d for turns ratio and phaseangle and operated within their rated burden range.

4.6.4.2 Current Transformers. Current transform-ers measure current in a given phase. Current trans-formers serve to cqr1Vertline or primary current(typically very high) to lower or secondary me!eringcurrent. For this reaspn the secondary current mea-sured by the current transfprmer must Pe multipliedby a turns ratio to calculate the primary current.

Current transformers are available in several meter-

ing accuracy classes. For the measurement of Class1 or Class 2 primary variables or secondary variables,0.3 percent bias uncertainty class current transform-

ers shall be used. In the case of Class 1 primaryvariable measurement, current transformers must becalibrated fpr turns ratip and phase angle and oper-ated within their rated burden range.

4.6.5 Calc\.llationof Corrected Average Power orCorrected Total Energy.The calculation method foraverage power or total energy should be performedin accordance with ANSI/IEEEStandard 120 for thespecific type of measuring system used. For Class1 primaryvariable,power measurementsmust becorrE!ctedfor actual instrumenttransformer ratio andfor phase-angle errors in accordance with the proce-dures of ANSI/IEEEStandard 120.

4.7 DATACOllECTION AND HANDLING

4.7.1 Data <:ollection and <:alc\.IlationSystems

4.7.1.1 Data Collection Systems. A data collec-tion system should be designed to accept multipleinstrument inputs and be able to sample data fromall of the instruments within two to three minutesto obtain all necessary data with the plant at thesame condition. The systemshould be able to collectdata and store data and resultswithin three minutes.

44


4.7.1.2 Data Calculation Systems. The data ca1-culation system should have the ability to averageeach input collected during the test and calculatethe test results based on the averaged values. Thesystem should also calculate standard deviation andcoefficient of variance of each instrument. The sys-tem should have the ability to locate and eliminatespurious data from the average. The system shouldalso have the ability to plot the test data and eachinstrument reading over time to look for trends ando\.ltlyingdata.

4.7.2 Data Management

4.7.2.1 Storage of Data. Signal inputs from theinstruments should be stored to permit post testdata correction for application of new calibrationcorrections. The engineering units for each instru-ment along with the calculated results should bestored if developed on site. Prior to leaving the testsite all test data should be stored in removablemedium to secure against equipment damage duringtransport.

4.7.2.2 Manually Collected Data. Most test pro-grams will require some data to be taken manually.The data sheets should each identify the data point,test site location, date, time, data collect or, collec-tion times and data collected.

4.7.2.3 Distribution of Data. The averaged datairi engineering units should be available to all partiesto the test prior to leaving the test site. All manuallycollected data should be made available to all partiesto the test prior to leaving the test site.

4.7.3 Construction of Data Collection Systems

4.7.3.1 Design of Data Collection System Hard-ware. With advances in computer technology, datacollection system configurations have a great dealof flexibility.They can consist of a centralized pro-cessing unit or distributed processing to multiplelocations in the plant.

Each measurement loop must be designed withthe ability to be loop calibrated separately. Eachmeasurement loop should be designed so that itCanindividuallybe checked for continuity and powersupply ifapplicable to locate problems during equip-ment setup.

ASME PTC 46-1996

Each instrument signal cable should be designedwith a shield around the conductor and the shield

should be grounded on one end to drain any strayinduced currents.

4.7.3.2 Calibration of Data Collection Systems.When considering the accuracy of a measurement,the accuracy of the entire measurement loop mustbe considered. This includes the instrument and the

signal conditioning loop or process. Ideally, whenan instrument is calibrated it should be connectedto the position on the data collection system thatwill be employed during the test. Should this beimpractical, each piece of equipment in the measure-ment loop should be individually calibrated. Separatepieces of equipment include current sources, voltmeters, electronic ice baths, and resistors in themeasurement loop.

If the system is not loop calibrated prior to thetest, parties to a test should be allowed to spotcheck the measurement loop using a signal generatorto satisfy that the combined inaccuracy of the mea-surement loop is within the expected value.

4.7.3.3 Usage of Existing Plant Measurementand Control System. The Code does not prohibitthe use of the plant measurement and control systemfor code testing. However, this system must meetthe requirements of this Section. Below are somecaution areas.

Typically plant measurement and control systemsdo not calculate flows in a rigorous manner. Oftenthe flow is based on a ratio relationship with com-pensation factors. Calculation of flow should followSubsection 4.4.

Often the plant systems do not have the abilityto apply calibration corrections electronically. Theoutput of some instrumentation like thermocouplescannot be modified so electronic calibration is nec-essary.

Some plant systems do not allow the instrumentsignal prior to conditioning to be displayed or stored.The signal must be available to check the signalconditioning calculation for error.

Distributed control systems typically only reportchanges in a variable which exceed a set thresholdvalue. The threshold value must be low enough sothat all data signals sent to the distributed controlsystem during a test are reported and stored.

45


SECTION 5 - CALCULATIONS AND RESULTS

5.1 FUNDAMENTAL EQUATIONS

,The fundamental performance Eqs.,(5.1.1), (5.1.2),

and (5.1.3a,b) are applicable to any of the types ofpower plants covered by this Code.

Corrected net power is expressed as:

7 5.

Peorr = (Pmeas + .~A; )n £rj1=1 j=1

(5.1.1)

Corrected heat input is expressed as:

7 5

Qeorr = (Qmeas + i~ Wi) j~Pj(5.1.2)

Corrected heat rate is expressed as:

t7 5

(Qmeas+ ;~lCUi)j~PjHReorr = 7 5

(Pmeas + i~ Ai) j~ £rj

(5.1.3a)

or

7

(Qmeas + ~ CUi) 5HReorr = ';1 n 0

(Pmeas + ~ Ai );=1

1=1

(5.1.3b)

~

Additive corrections factors Ai and Wi, and multipli-cative correction factors aj,/3j and ~, are used tocorrect measured results back to the design-uniqueset of base reference conditions. Tables 5.1 and5.2 summarize the correction factors used in thefundamental performance equations.

The correction factorswhich are not applicableto the specific type of plant being tested, or to thetest objectives, are simply set equal to unity orzero, depending on whether they are multiplicativecorrection factors or additive correction factors, re-spectively.

Some correction factors may be significant onlyfor unusually large deviationsfrom design conditions,or not at all, in which case they can also be ignored.An example of this is some secondary heat inputs,t

such as process return temperature in a cogenerator.If the pre-test uncertainty analysis shows a correctionto be insignificant, these corrections can be ignored,or may be measured.

The fundamental performance equations, whichare generalized, can then be simplified to be specificto the particular plant type and test program objec-tives.

5.2 MEASURED NET PLANT POWER ANDHEAT INPUT TERMS IN THEFUNDAMENTAL EQUATIONS

Measured net plant power for a power plant withmultiple prime movers is expressed as:

Pmeas = (i Pmeasured' )- Pmeasured,n=1 genera torn aux

- Plransformer - Plin.losses losses

(5.2.1)

where

n= an individual generator

k= the total number of generators

Equation (5.2.1) represents net plant power asmeasured in the switchyard. Line losses may benegligible or outside of the test boundary, but areincluded in Eq. (5.2.1) for those cases when it isnecessary to consider them.

Any of the loss terms can be excluded from Eq.(5.2.1) if the test boundary dictates.

Heat input which can be calculated from measuredfuel flow and heating value is expressed as:

Qmeas = [(HV)(qm)]fuel (5.2.2)

If the fuel flow cannot be directly measured, Qmeas

is determined from results of heat input computationsbased on heat output and steam generator correctedfuel energy efficiency. Steam generator correctedfuel energy efficiency would be determined by theenergy balance method per ASME PIC 4. Heat

47

~ "0/--,.,


AI

Operating CQnditiQn QrUncQntrQllable EXternal CQnditiIJn

Requiring Correction

Thermal efflux

(Operating)

TABLE 5.1

SUMMARY OF ADDITIVE CORRECTION FACTORS IN FUNDAMENTAL PERFORMANCE EQUATIONS

AdditiveCorrectionto ThermalHeat Input

AdditiveCorrection to

Power[Notes (1) and (2)] Comments

WI Calculated from efflux flow rate and energylevel, such as process steam flow andenthalpy

4'2 Az Generator(s) power factor(s)(Operating)

Corrected for each generator and combined

Wj Aj Steilm generator(s) blowdowndifferent thiln design(Operating)

80 is sometimes isolated so that

performance may then be exactly correctedto design 80 flow rate

!II

!I

W4 A4 Secondary heilt inputs(External)

Process return or make-up temperature istypical

WSA AsA Ambient conditions, cooling toweror air-cooled heat exchanger ilir inlet(Extern iI I)

For some combined cycles, m.ay be based. onthe conditions at the combustion turbineinlets

I

IiI

WSB ASB Circ water temperature different thandesign(External)

To be used if there is no cooling tower orair-cooled condenser in the test boundary

Wsc ASC Condenser Pressure(External)

If the entire heat rejection system is outsidethe test boundary

Wb Ab Auxiliary Loilds, thermal andelectrical

(Operating)

(a) To account for auxiliary loads when themultiplicative corrections are based on grossgeneration, usually only for steam turbineplants(b) To compensate for irregular or off designauxiliary loads .

W7 A7 Measured power different thanspecified if test goal is to operate ata predetermined power, or operatingdisposition slightly different thanrequired if a specified dispositiontest

(Operating)

To account for (a) the small difference in

meilsured versus desired power for a .test runto be conducted at a specified measured orcorrected power level, or (b) smalldifferences between required and actual unitoperating disposition such as valve pointoperation of a stearn turbine plant .

NOTES:(1) For additive corrections 1-6, for a given correction i, us!.lallyeither Wior Ai will be used for combined cycle plants, b!.ltnot both. Use

of both usually means that a correction is being made twice for a given condition. For stearn turbine plants, it is sometimes necessaryto use Wi and Ai corrections with the same subscript, as shown in the sample calculations.

(2) Additive correction factors with subscript 7 must always be used together. The correction W7 is the correction to heat input thatcorresponds to A7-

48

""-~1!!"" "'i!!t'


TABLE5.2SUMMARYOF MULTIPLICATIVECORRECTIONFACTORSIN FUNDAMENTALPERFORMANCE

EQUATIONS

M,.dtip!iC;:i'tivf!Correc::tion toThermal Heat

Input

MultiplicativeCorrection to

Heat Rate

f. = !!.iI OIj

Operi'ting Condition orUncontrollable E"ternal

Condition RequiringCorrection Comments

MultiplicativeCorrection to

Power

/31 III f1

/3~ f~

Inlet temperaturecorrection (external)

Ambient pressurecorrection (external)

Ambient humidity(external)

Fuel s\Jpply temperaturecorrection (external)Correction due to fuel

analysis different thandesign (external)

Measured at the test boundary atthe inlet to the equipmentAs per /31- Ill, ~

As per /31- al, ~

Il~

/33 f]

GENERAL NOTE:

Inlet ambients and fuel/sorbent chemical analysis deviations from base reference conditions are part of the corrections for the heat loss

method for coal or solid fuel plant when that method is used to determine thermal heat input. In those circumstances, they are not part ofthe overall plant performance test corrections per se.

correction. For a combined cycle plant, Eqs. (5.1.1)and (5.1.3b) reduce to:

Pcrm = (Pmeas + A1 + A2 + . . . A6)0I1012£r3£r401s (5.3.1)

a3

/34 1l4 f4

H R - .. (Qmeas)(f,(2f3f4fs). torr - (pmeas + Al + A2 + . . . A6)(5.3.2)

/3s fs

From the format of Eq. (5.3.2), it is seen that once thesteam turbine cycle output is corrected to referenceconditions by use of the additive correction factors,and the other additive corrections are incorporated,then the more global corrections for inlet conditionsand fuel analysis are applied.

Examples of applications of Eqs. (5.3.1) and (5.3.2)are shown in Appendix 1 and Appendix 3.

(b) Steam Turbine Plants - Specified Unit Dispo-sition

For steam turbine plants, if the test goal is tiedto a specified disposition, it is usually based dneither a valve point operating mode, or on thethrottle flow rate. For a steam turbine plant, thesteam generator calculations are first done separatelyfrom the overall plant calculations in order to calcu-late PTC 46-measured thermal input. As such, thetwo additive corrections to overall plant referenceconditions which always relate to steam flows affectthe corrected thermal input as well as the corrected

as

output is determined by steam generator water/steamside measurements.

5.3 PARTICULARIZING FUNDAMENTALPERFORMANCE EQUATIONS TO SPECIFICCYCLES AND TEST OBJECTIVES

5.3.1 General. The applicable corrections to usein the fundamental performance equations for aparticular test depend on the type of plant or cyclebeing tested, and the goal of the test.

5.3.2 Specified Disposition Test Goal. If the goalQf the test is to determine net plant power and heatrate under a specified unit oper;:!ting disPQsitionwithout setting output to a predetermined numericalpower, then Eqs. (5.1.1) and (5.1.3) are simplifieddifferently depending on the type of power pl;:!nt.

(a) Combined Cycle Plants - Specified Unit Dis-position

For combined cycle plants without 'duct firing, orduct firing out of service, and the specified operatingdisposition being the base loading of the gas turbines,the 6. correction factors are the only additive correc-tions which ;:!reused. Use of both types of additivecQrrections WQuidbe dQuble-a(:counting fQrthe samecQrrection. Note that all the 6. corrections thml.lghsubscript 5 are steam turbine cycle power relatedexcept for the gas turbine generator power factor

49

'T' ~';P""",'1c~ ~~~---.

ASME PTC 46-1996

power of the plant. These are the additive correctionwith subscripts /11/1 and "3," for blowdown andprocess steam.

The multiplicative correction factors for inlet airconditions and fuel analysis and conditions are em-bedded in the steam generator data ~nalysis. Qme~sfor the overall plant test is the corrected thermalinput as determined from an ASME PTC 4 test.

Hence, the correction factors for the air inlet

conditions and the other multiplicative correctionfactors are all unity in the overall plant performanceequations, and some of the additive correction factorswith the same subscript are used.

The fundamental performance equation for power,Eq. (5.1.1) becomes:

Peort = (Pmeas+ A, + A2 + . . . A7) (5.3.3)

For heat rate, Eq. (5.1.3a) then becomes

HR - (Qmeas + CUI + CU3+ CU7)carr - ( C>rmeas + Al + A2 + . . . A7)

(5.3.4)

iII

'I

In Eq. (5.3.4), Qmeas is thus equal to the steamgenerator tested output as defined in ASME PTC 4,

, including blowdown energy if applicable, divided bythe steam generator corrected fuel energy efficiencycalculated per ASMEPTC 4 (see Subsection 5.2).

The 6J factors are then used to correct the thuscalculated measuredthermal input to the plant refer-ence conditions, such as reference process efflux,blowdown, and required operating disposition.

The 6Jcorrection curves are calculated by heatbalance using base reference steam generator cor-rected fuel energy efficiency. If the tested correctedefficiency deviatessignificantly from reference, thenrecalculation of the 6Jcorrections simply by multi-plying each one by the ratio of base reference fuelenergy efficiency to the test corrected efficiencycan be done if the difference affects the resultssignificantly.

An example of application of Eqs. (5.3.3) and(5.3.4) are in Appendix E for the unit requireddisposition of fixed throttle flow. Req\.Jiredunit dispo-sition at valve point operation would be similarlycalculated.

Note that Eq. (5.3.4) is in the format:

Qeorr

HReorr = Peort(5.3.5)


5.3.3 Specified Corrected Net PowerSpecified corrected net power tests are conducted

for steam turbine plants. I

For a steam turbine plaint for which a test is runwith the goal that heat I rate is determined at aspecific corrected net power, the unit operating netpower, after being corrected to the base referenceconditions, is adjusted for the test, to be as closeas possible to the design 'value of interest. 1:17 and6J7 are applied to adjust: for the small differencebetween the actual adjusted power and the desiredadjusted power.

As shown in Appendix E, the applicable equationsare identical to a steam power plant when the goalis to test at a fixed operating disposition.

I

5.3.4 Specified Measure,d Net PowerThe other test whose required unit operating dispo-

sition dictates adjustment of power to a predeter-mined value for testing is a specified measured netpower test. This test is conducted for a combinedcycle power plant with duct firing or other form ofpower augmentation, such as steam or water injec-tion when used for that purpose.

For this test, the net power is set as closely aspossible to a specified amount regardless of air inletconditions.

The 6Jadditive corrections are applicable (but notthe 1:1corrections except 1:17)'

1:17and 6J7 are applied to adjust for the smalldifference between the actual adjusted power andthe desired adjusted power. .

In this case, the fundamental performance equa-tion for corrected net power simplifies to:

'i;"I1

tI,

if~'I,1I

Peort = Pbasereference = (Pme.s + A7) (5.3.6)

The fundamental equation for corrected heat ratesimplifies to:

HReort =

(Qme.s + CUI + CU2+ CU3+ CU4+ CU5+ CU6+ CU7)«(, (2(3(4(5)

(Pmeas + A7)(5.3])

Note that Eq. (5.3.7) is also in the format of Eq.(5.3.5). Because aj = 2, then Pj = ~.

Table 5.3 summarizes the format of the generalperformance equations to use for various types ofpower plants or thermal islands, and test objectivesdiscussed in this Section. There may be other applica-tions for which different combinations of the correc-

50

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0 < m ;c > r- r- " r- > Z -I " m ;c .." 0 ;c ~ > Z () m > VI

~ m " -I () ~ 9' - 1.1)

1.1)

'"

ASME PTC 46-1996

I

I

I'.,iI;

tion factors are used, but the general performanceequations should always apply.

5.3.5 Alternate to d7 and W7 Correction Factors.During a test run for which the test objective requiressetting the power level, power will not be preciselyat the required level because (1) adjustments aremade utilizing readings of most operating conditionsfrom the control room, (2) there are normal fluctua-tions during the test run aher the unit is set for testing,and (3) desired power level might be dependent onfinal fuel analysis, which has to be assumed forthe test.

Similarly, during a specified disposition test of asteam turbine plant, the unit m..y be found to havebeen operating in a slightly different disposition thanrequired for the same reasons.

There are two ways to handle these situations.The preferred method is to incorporate the A7 andW7 correction factors.

The second and alternate technique is to interpo-late through the results of several test runs to deter-mine where the results are at the desired powerlevel or desired disposition. If the alternate methodis used, then 6.7 and W7 are not applicable andcan be eliminated from the performance equations.However, the measured power levels or dispositionof the test runs should have enough of a spreadgiven the test uncertainty for reasonable results tobe achieved this way.

This is shown in the example in Appendix E fora fixed corrected power test. In lieu of the additivecorrections 6.7 and W7, three tests were conductedand the result was interpolated.

Usually power levels can be set close enough todesired such that the alternate method is not neces-sary. And for steam turbine plants in particular, heatrate versus power at full loads is a relatively flatcurve.

5,3.6 Different Test Goals for the Same Cycle.Tests with different objectives can be conducted atthe same power plant, in which case care must betaken to ensure that appropriate sets of correctionfactors are calculated based on the test goal. Inmost cases, a single test objective is selected for aparticular site.

5.4 DISCUSSION OF APPLICATION OFCORRECTION FACTORS

The format of the fundamental equations allowsdecoupling of the appropriate correction effects (pro-

'1F


cess efflux, ambient conditions, ete.) relative to themeasured prime parameters of heat rate and power,so that measured performance can be corrected tothe reference conditions. Corrections are calculated

for parameters at the test boundary different thanbase reference conditions which affect measured

performance results. Tables 5.1 and 5.2 indicatewhether each correction isconsidered due to uncon-trollable external conditions, or to operating condi-tions.

Correction curves applied to measured perform-ance are calculated by a heat balance model of thethermally integrated systems contained within thetest boundary. The heat balance model representsthe mathematical definition of the expected perform-ance of the energy conversion facility. Each correc-tion factor is calculated by running the heat balancemodel with a variance in only the parameter to becorrected for over the possible range of deviationfrom the reference condition. Correction curves are

thus developed to be incorporated into the specificplant test procedure document. The model is final-ized following purchase of all major equipment andreceipt of performance information from all vendors.

Some of the correction factors are summations of

smaller corrections or require a family of curves.For example, the correction for power factor is thesummation of power factor corrections for eachgenerator.

It is noted that for convenience, identical subscriptsfor all additive correction factors, and similarly forall multiplicative correction factors, represent thesame variable to be corrected for, but the symbolsare different depending on the result being corrected.

In lieu of application of the equations in Subsection5.3, a heat balance computer model may be appliedafter the test using the appropriate test data andboundary conditions so that all the corrections forthe particular test run are calculated simultaneously.Heat balance studies of different cycles using theperformance equations in the above format havedemonstrated that interactivity between correctionfactors usually results in differences of less than0.2% compared to calculation of the complete heatbalance post-test with the test data. An advantageof this post-test heat balance calculation is a reduc-tion or elimination in required heat balance calcula-tions required to generate all the heat balance correc-tion curves.

4

5.4.1 Additive Correction Factors - d and w.The additive corrections are discussed below inparas. 5.4.1.1-5.4.1.7.

52

OVERAll PlANT PERFORMANCE

5.4.1.1 Correction Due to Thermal EffluxDiffer~ent Than Des~gn- ~, or Cd,. For a cogenerationpower plant, the design net power and heat rate isspecified at a design thermal efflux, or second<lryoutput. These are the corrections for deviations fromdesign reference therm<llefflux during the perform-ance test run, when applicable.

If thermal efflux is in the form of process steam,which is the most common, then the design netthermal effluxfor each process may be defined as:

Qthermal efflux, = [(mh)process - (mh)processdesign sleam relurn

- (mprocess - mprocess )hmake ].

lIeam relurn up design

(5.4.1)

If the design process return flow is equal to designprocess steam flow, and Eq. (5.4.1) simplifies to:

Qlher.

malefilux,= [( mprocess )( hprocessdeSIgn Sleam sleam

- hprocess )]relllrn design(5.4.2)

-

Test results are corrected for deviations from designvalues of each term in Eq. (5.4.2); The sum of thecorrections equals ~I (or iLll).

It is also permissible to include the process returnenergy correction as part of the correction A4, (oriLl4)' which is for secondary heat inputs into thecycle (see below), if more convenient. If that optionis selected, then process return is not consideredas part of the ~I (or iLll)correction.

5.4.1.2 Generator Power Factor Correction -~2 or Cd2'The output of each generator is correctedto its design power factor rating from measurementsof MVARS and MW. The sum of all the correctionsto each generator comprise ~2 (or lU2L

~

5.4.1.3 Steam Generator Blowdown Correc~

tion - ~J or CdJ.To compare test results to designreference heat balance values, it is recommendedto isolate blowdown if possible and to correct tothe design blowdown flow rate. This simplifies thetest because of the difficulty in determining actualblowdown flow rates.

5.4.1.4 Secondary Heat Input - ~4 or Cd4'

Secondary heat inputs are all heat inputs to the testboundary other than primary fuel. Examples aremake-up water and low level external heat recovery.The process steam return portion for a cogeneration

ASMEpre 46-1996

unit can be considered in this correction term, oras part of ~I (or lUI);

Effects of differences in make-up temperature orflow from design should be considered for thosecases where it has impact. The same holds true forprocess steam returned as water.

If any of the return is stored in a tank and thenadded to the cycle, as opposed to direct return tothe cycle, the conditions prior to entering the cycleare corrected to reference conditions.

5.4.1.5 Heat Sink - As Factors. Only one ofthe correction factors ASA,ASB,or ~sc (or lUSA,iLlSB,or lUsd is applied, depending on the cycle testboundary, or cycle configuration of the plant orthermal island. Figures 5.1, 5.2, and 5.3 show con-figurations where these corrections are respectivelyapplicable for a combined cycle power plant.

(a) Ambient conditions at the cooling tower air in-let - ASA,or iLlSA

If cooling tower(s) or air-cooled condenser(s) existwithin the test boundary, then a correction is madefor cooling tower/air-cooled condenser atmosphericinlet conditions. For <Iwet cooling tower, applicableambients are wet bulb temperature and barometricpressure. Humidity and dry bulb temperature maybe used in lieu of wet bulb temperature. Typically,for a dry cooling tower, or air cooled condenser,dry bulb temperature and barometric pressure arethe required applic<lble ambient conditions. Thebarometric pressure component of this correctioncan be incorporated into the subscripted "2" multipli-cative correction factors.

It may be acceptable to assume that cooling towerinlet conditions are identical to those measured at

the combustion turbine inlets in a combined cycle,if they are measured at the combustion turbineinlet(s};

(b) Circulating water temperature - ~SB, or iLlSBIf there is no cooling tower(s) or air-cooled con-

denser(s) within the test boundary, then the heatsink correction is made bas~d on measured circulat-ing water conditions.

(e) Condenser pressure - Asc, or iLlSCIf the condenser is not part of the test boundary,

a correction is made to the steam turbine cyclebased on the measured condenser pressure.

5.4.1.6 Thermal and Electrical AuxiliaryLoads - 4.6 or Cd6'These corrections are for off-design auxiliary load line-up at the tested conditions.Care must be taken to assure that no overlap existsbetween corrections taken here as well as for inlettemperature and other external condition corrections

53

PROCESS

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in which normal auxiliary load variations with vary-ing external conditions have already been con-sidered.

5.4.1.7 Small Difference in Measured Power

from Target Power, or Actual Unit Disposition fromOperating Disposition - 1:17or (1)7' For specifiedmeasured net power and specified corrected netpower tests, in which the power during the test isset, these are used to correct for the fact thatmeasured power will never equal precisely the de-sired power for the practical reasons tabulated inpara. 5.3.5. These corrections must always both beused together. Once measured power is correctedto the precise value it should have been exactly setto, then the concomitant change in thermal heatinput must be considered.

For the same reasons, these corrections are usedwhen the required unit operating disposition isslightly different than required for a steam turbineplant.

-

5.4.2 Multiplicative Correction factors - a, f,and 11. For a steam turbine cycle, multiplicativecorrections usually do not apply.

For combined cycles, once the steam turbineportion of the cycle has been corrected to designreference conditions by the additive corrections, thenthe plant performance can be corrected based onambients and other external quantities using themultiplicative correction factors as described below.

a multiplicative corrective factors are used tocorrect measured net power, and either ( or 13 isused to correct heat rate or measured thermal heat

input, respectively. It is preferred to use (.The multiplicative correction factors are discussed

below in paras. 5.4.2.1-5.4.2.4.

- 5.4.2.1 Inlet Temperature, Pressure, and Humid-ity Corrections a" a2, a3 and f" f2, and f3, or 11"112' and 113' Correction is made to plant performancebased on the inlet temperature (a1 and (1, or 131)'inlet pressure (a2 and (2, or 132),and inlet humidity(a3 and (31or 133)'

Inlet temperature of the air crossing the test bound-ary at gas turbine compressor inlet(s) is preferablymeasured inside the air inlet duct because of better

mixing to attain true bulk ambient temperature.Inlet pressure and humidity of air crossing the test

boundary at gas turbine compressor jnlet(s) should bemeasured in the vicinity of the gas turbine COmpres-sor inlet ducts, but can be measured outdoors.,

ASME PTC 46-1996

5.4.2.2 fuel Supply Temperature Correction -a4 and (4' or 114' F\.Jelsupply temperature upstreamof any conditioning device such as preheating whichis different than base reference affect performance.Provision is made for correction in the performance

equations for this.

5.4.2.3 Fuel Analysis Correction - as and fs,or 135'Differences in fuel properties between thedesignfuel and the performance test fuel can leadto variance from design performance. This correctsfor difference in fuel properties.

5.5 SPECIALCONSIDERATIONS OFPERFORMANCE EQUATIONS AS APPLIEDTO COMBINED CYCLES

5.5.1 Multiple Locations of Air Inlet. Correctedperformance by utilizing the fundamental perform-ance equations in the formats for combined cyclesshown in Subsection 5.3 assumes that the air at

each gas turbine inlet is equivalent. The equationsalso allow for accommodating the combined cyclecalculations if significantly different air inlet condi-tions exist at the cooling tower(s) or air-cooledcondenser(s) than at the gas turbine(s).

For facilities with more than one gas turbine, itis almost always acceptable to average the ambientmeasurements at all gas turbine compressor inletsand use the average for the determination of inletcorrections, provided the gas turbines are identicalmodels, which is usually the Case. Slight differencesbetween conditions at each inlet will not impactthe calculated results if the machines are all theSame model and fulfill the base loading requirementof unit disposition.

A correction for inlet conditions at the coolingtowers different than at the compressor inlets c;mbe developed and used (4sA or (USA).

Ambient pressure and humidity can be assumeduniform for the entire site if measured in the vicinityof the gas turbine compressor inlets.

If necessary, expansion of Eq. (5.3.1) for a cydemandating a test goal of constant unit dispositionis written as

57

ASME PTC 46-1996

Total # ofgas turbines

[5

]Peorr = L (Pmeas,grOSScT+ ~2CT ) n anCTm=CTl m m n=1 m

TOlal # ofsleam

IUrbines

[

5 5

]+ L (Pmeas.grosSST.+ L ~kST) n anST./=1 / k=l / n=1 )

5

- faux n An - Plransformer-P,inen= 1 loss loss

(5.5.1 )

if it is more prudent not to ilverage conditions ateach gas turbine inlet.

The subscripts for the new multipliciltive correc-tion factors, Ant refer to the same parameters to becorrected for as in the other multiplicative correc-tions. Care is taken in calculating heat balances todetermine correction factors for the format of Eq.(5.5.1) to base the an correction factors on grosspower. Heat balance calculations to determine cor-rections to ambients utilizingthe format of Eq.(5.2.3)include auxiliary load effects in that equation's re-spective a's.

Note that the a corrections for the steam turbinesin Eq. (5.5.1) will not be unity even if the coolingtowerisoutsidethe test boundary,due to the ambienteffect at the combustion turbine inlet on steamproduction.

Similarly, for the test goal of a specified unitdisposition without setting output to a predeterminedlevel(para.5.3.2), the corrected heat rate equationmay be expanded into the following format if Eq.(5.5.1) is used in lieu of Eq, (5.3.1):

10Iai # offuel inputs

[5

]~1 .. (Qmeas) lJ.1 13nm

HReorr = P Per Eq, (5.5.1)eorr(5.5.2)

Similar formulations can be developed for speci-fied measured net power tests for combined cyclesin which there is duct firing, if necessary.

It is also usually valid, in combined cycles, ifthere is no inlet cooling during the test, or inletchilling, to assume that the air inlet temperature isequivalent at the gas turbine compressor inlet{s) andthe cooling tower air inlet(s), provided it is measuredat the point of greatest influence, which is over-

whelmingly the gas turbine compressor(s). Duringthe test planning stilges, calculations are performedto determine sensitivity coefficients for cycle affectsdue to deviation of inlet conditions from design at


the compressor inlet{s)and the cooling tower(s) toverify the validity of this assumption. Effectsof realtemperature differences between cooling tower andcombustion turbine compressor inlets, arecompared.(When doing the sensitivity studies, note that mea-surement of inlet temperature at the cooling towerinlets is a high uncertainty measurement, whereasthe mixing of air inside the gas turbine compressorinlet ducts improves the i3ccuraCYof bulk ambienttemperatureme;:lsurement.) ~SA(or (USA)is calculatedif measureabledifferences affect the resultsby morethan 0.1%.

5.5.2 Special Case of Inlet Air Evaporative Cool-er(s). Experienceshowsthat testing with evaporativecoolers in-service can lead to erroneous, non-repeat-able results. The major reason why testing with thecooler(s) in service and using upstream air inletconditions to determine the appropriate correctionsto plant performance can lead to unacceptably largeerrors is because the thermal performance of theplant variesstronglywith the temperature conditionat the compressor inlet. It is, in fact, the steepestcorrection to the plant output. If the evaporativecooler producesa downstreamtemperature whichis - or is measured as - slightly greater than 1°Fdifferent than the design number, resultscan typicallybe affected by 0.5%.

An alternate and more practical approach. is totest the unit performance with the evaporative cool-er(s) out of service, if possible, correct performanceto a base condition, and then correct the calculatedbase condition performance basedon the verificationof evaporative cooler performance from a sepa-rate test.

A further complication is that large changes inevaporator cooler performance, as measured by ef-fectiveness, produce only relatively small changesin downstream temperature. Precise determinationof effectivenesswithin a meaningful uncertainty rela-tive to the effect on plant performance is almostalways not possible. .

The effectiveness of the evaporative cooler isdefined by:

eff = Ti.db- Te.dbTi.db - T;,wb

(5.5.3)

1!

~

,i~.

where

T:::: temperature

Subscripts:db: dry bulbe: exit, or downstream (0/5)

58

OVERALL PLANT PERFORMANCE. ASME PTC 46-1996

TABLE 5.4CHANGE IN COMPRESSOR INLET TEMPERATUREOVER A 30% RANGE IN EVAPORATOR COOLER

EFFECTIVENESSON AN 80°F DAY, WITH 80% RELATIVEHUMIDITY

t

~.

i: inlet, or upstream (U/S)wb: wet bulb

Very small errors in temperature measurementcause large variations in the calculation of effective-ness, as shown in Table SA. Table SA assumes an80°F day at 80% relative humidity.

Note that a 30% change in effectiveness corres-ponds to only a change of 1.5°F downstream temper-ature.

New correction factors are developed for thespecial case of a plant with evaporative air cooler(s).

The plant is tested with the evaporative cooler{s}out of service. Then, for comparison with the designheat balance plant performance:

Peart. = Peorr. X KPeva (5.5.4)evap cooler I/S evap cooler o/s eoofer

-

Where Peorr. is the corrected power as deter-evap cooler OIS

mined by Eqs. (5.1.1) or (5.5.1), with the correctionsbeing performed to the base reference cooler(s) inlettemperature and humidity. Kpevap is the power cor-cooler

rection factor used to correct the tested plant per-formance with the evaporative cooler{s}out of serviceto the performance it would have been with thecooler{s) in service at the base reference inlet temper-ature and humidity.

Similarly,

HRcorr. = HRcorr.evap cooler lIS evap cooler o/s

X KHRevapcooler

(5.5.S)

or

)Qeorr. = Qeorr. X KQeva (5.S.G)

evapcoolerI/S evaPcoolero/s eoofer

where the left hand terms represent the corrected

heat rate and corrected heat input, respectively, towhat they would have been with the evaporativecooler{s} in service during the plant test. The firstterms on the right side of the equations representcorrected heat rate or corrected thermal input withthe evaporator cooler out of service per the appro-priate equations in Subsection (5.3), and correctedto base reference conditions at the inlet of the

cooler{s). The K terms are the correction factors

to correct the tested plant performance with theevaporative cooler{s) out of service to the perform-ance it would have been with the coolers in service.

Because measurement error will probably be largerthan the requirements to determine effectivenesswithin a small range of performance, experiencedictates that the best that can be achieved is to

assume that performance of the evaporator has beenverified if the design effectiveness is calculated fromthe test data within test uncertainty, and to use the.corrections to plant performance based on the basereference effectiveness.

5.5.3 Staged Testing of Combined Cycle Plantsfor Phased Construction Situations. This subsection

details the methodology to test for new and cleannet power and heat rate of a combined cycle plantwhen it is constructed in phases. The gas turbinesof the plant usually operate tor several months insimple cycle mode while the steam portion of thecombined cycle plant is being constructed.

In order to determine the combined cycle newand clean performance, it is necessary to test thegas turbines when they are new and clean (Phase1 test series), and combine those results with new

and clean steam turbine cycle performance data(Phase 2 test series).

59

Upstream Upstream Downstream Downstream Downstream

Dry Bulb Relative pry Bulb Relative Hu- Wet BulbEffectiveness Temp. Humidity Temp. midity Temp.

0.70 80°F 80% 76.6 94% 75.1°F0.75 80°F 80% 76.3°F 95% 75.1°F0.85 80°F 80% 75.8°F 97% 75.1°F0.95 80°F 80% 75.4DF 99% 75.1°F1.00 80°F 80% 75.1°F 100% 75.1°F

ASME PTC 46-1996

,j

ij

This protocol requires corrections in addition tothe standard corrections tabulated in Tables 5.1 and5.2. These are:

(a) air flow rate deterioration of the gas turbines(b) the change in gas turbine exhaust gas pressure

drop to atmosphere based on the different back endgeometry of the ductwork and equ ipment downstreamof the combustion turbines

(c) combined cycle mode fuel heating not availablein simple cycle mode

Determination of the first two items requires gasturbine test data taken with the steam cycle by-

. passed during the Phase 2 test series. If the plantdoes not include a by-pass, the simple cycle Phase2 test must be conducted just prior to shut downfor the HRSG tie-in.

The simple cycle tests during Phase 2 are calledPhase 2A tests, while the final combined cycleoperation tests are considered as Phase 28 tests.

Nomenclature for the unique correction factorsto this protocol are:

Corrections due to physical changes betweenPhase7 and Phase2;Cr; Correction to steam cycle gross power outputat design reference conditions to new and clean airflow rate of the gas turbinesCx: Correction to phase (2A) gas turbine "i" grosspower output at design reference conditions to ac-count for exhaust gas pressure change between testphasesCh; Correction to Phase (1) simple cycle thermalheat input at design reference conditions to accountif fuel preheating is available during Phase (26) andnot during Phase (1)

Table 5.5 summarizes the reasons for each testseries.

Note that there is usually an air flow reductionand back pressure change in the simple cycle modeafter extended operation, which is why the secondphase of testing must be done in two parts.

5.5.3.1 Special Performance EquationsPhased Construction. The corrected total grosspower output of the gas turbines used for the com-bined cycle plant performance evaluation is:

numberof numberoigas turbines

.

gas tu

.

rbones

{ [ ( )2: PeorrCT= 1: PeorrCT +;=1 ; ;=1 . j PHASE 1

(Peorr ) (Cx - 1)]}CT; PHASE 2A. '

(5.5.7)


Equation (5.5.7) expresses the total gross poweroutput of the gas turbines as corrected to referenceconditions, and in new and clean condition, bymeans of application of the Phase 1 simple cycletest results. It also corrects new and clean gas turbinepower output at reference conditions for op~rationin combined cycle mode for the change in exhaustpressure between simple cycle and combined cycleoperation. Note that the corrected gas turbine power,identified by subscript "corr," is based on ASMEPTC 22 tests and corrections.

The corrected total gross output of the steamturbine used for the combined cycle plant perform-ance evaluation is:

Total ~ ofsleam

turbines

[ (PeorrST= :1: . Pmeas,grossST.+}=1 J

:i ilkST. )n c:rnST.]<C;)

k=1 } n=1 }(5.5.8)

Equation (5.5.8) corrects the measured steam tur-bine cycle power output to design reference condi-tions, and also to combustion turbine new and cleancondition by application of Cr.

Cr is determined by comparison of the Phase 1and the Phase 2A simple cycle test series resultsby ratio of the airflow references measured duringthose respective test series for each gas turbine. Thereferences are based on the total pressure drop acrossthe compressor scroll corrected to base referenceoperating conditions. .

The tot;31plant gross power in combined cyclemode at reference conditions, and at new and cleanconditions, is therefore expressed as:

Peorr, =gross

numberofgas lurbines

2: Peorr CT1=1 j

number ojsteam

turbines

+ .2: PeorrST.1=1 1

(5.5.9)

The corrected thermal heat input from the fuelused for the combined cycle plant performanceevaluation is:

QpHASE28 = (QpHASE 1) (Ch), (5.5.10)

where QpHASE1 is calculated from the power andheat results of Phase 1 tests by:

60

'"


TABLE5.5

REQUIRED TEST SERIESFOR PHASED CONSTRUCTION COMBINED CYCLEPLANTS

Test Ph;ilse

Phase 1

Reasons for Tests Operating Mode

Simple cycle operationafter initial simplecycle start-upSimple cycle operation(see par<l. 5.5.3)

New and clean gas turbine performance

Gas turbine performance to determinedegradation effect on exhaust gas flow rate,and gas turbine back pressure changesSte<lmcycle performance for determinationof combined cycle plant performance innew and clean condition. This is

accomplished by combining gas turbinedata from Phase 1 with the steam cycleperformance data, with appropriatecorrections based on Phase 2A tests.

Phase 2A

Phase 28 Full combined cycleoper<ltion

;=number ofgas turbines

QpHASE1 = 2: (PCT.) * HRpHASE 1;=1 'PHASE1 (5.5.11)

~

Equation (5.5.10) expresses the total thermal heatinput from the fuel as corrected to reference condi-tions, and in new and clean condition, by meansof application of the corrected power and correctedefficiency Phase 1 test results from equation (5.5.11).It also corrects new and clean total thermal heat

input at reference conditions for operation in com-bined cycle mode due to the operation of fuel pre-heating by application of Ch.

The total plant gross heat rate in new and cleanconditions, combined cycle mode, and at contractoperating conditions, is therefore expressed as:

-HR = QpHASE 28

Peorr gross(5.5.12)

Net power and heat rate is found by subtractingcorrected auxiliary loads from the plant gross power,and subtracting transformer losses, if applicable, andline losses, if applicable.

5.6 SPECIAL CONSIDERATIONS AS APPLIEDTO STEAM TURBINE PLANTS

.~

Steam turbine based power plants do not usuallyhave a defined base load rating as do gas turbineor combined cycle power plants. There are twopossible equivalent definitions of base load rating

for a steam plant. The first is defined at a specifiedamount of main steam flow from the steam generatorat rated steam conditions such as maximum continu-OUsrating, provided other plant components do nothave to be operated above their continuous designratings. The other possible required disposition ofa steam turbine plant during a test might be withoperation at a particular control valve operatingpoint.

Performance correction to a reference conditionrequires knowledge or estimation of how the cor-rected plant net electrical output v;:lries with cor-rectE)dfuE)lenergy input. Figure 5.4 illustrates howgross output of a ste;:lm turbine based plant varieswith steam turbine throttle flow.

The scallops in the output vs throttle flow curveare due to the control action of the steam turbine

throttle valves. The straight line curve labeled valvebest point performance shows how the plant outputwould vary if calculated on a valve best point basis.This performance is not realizable but is synthesizedby passing a straight line through the steam turbinevalve points. In practice, the actual performancevaries from the valve best point performance by amaximum of about 0.35% for a six valve reheatmachine to 0.7% or more for a non-reheat machine.

A steam turbine plant for which required operatingdisposition is based on operation at valve point mustbe tested at that valve point.

If the specified disposition is a throttle flow rate,refer to para. 5.3.5. The plant may be tested overa range of steam turbine throttle flows sufficientto encompass the corrected performance point of

61

ASME PTC 41>-1991> OVERALL PLANT PERFORMANCE

1.6 x 105

1.5 X 105

~~ 1.4x 105..::I0

1.3 X 1PS

1.2x1050.85 P.90 0.95 1.00 1.05

Thrpttl~ Steam Flow. million Ib/h

FIG. 5.4 OUTPUT VERSUS THROTTLESTEAMFLOW

interest. The applicable performance equations inthis scenario are thus for a fixed unit disposition,with the corrected power floating. A corrected outputversus corrected input curve is developed from thetest data. The curve is entered at the net correctedoutput to determine the net corrected fuel energyinput. Another procedure for this specified disposi-tion, which is preferred, would simply be to applythe 6.7 and W7 corrections.

The performance characteristics of a steam turbineoperating in a combined cycle plant is normallydifferent than shown. here. What is discussed hereis not applicable to such a plant, or to a largesliding pressure mode steam turbine plant.

Figure 5.5 shows a typical test boundary for anon-reheat steam cycle that may be used in straightpower generation or cogener;:ltionapplications.

62

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(]'o


SECTION 6 - REPORT OF RESULTS

6.1 GENERAL REQUIREMENTS of test boundary diagrams for specific plant type ortest goal)

(b) a listing of the representatives of the parties tothe test

(c) any pre-test agreements which were not tabu-lated in the executive summary

(d) the organization of the test personnel(e) test goal per Sections 3 and 5 of this Code

6.4 CALCULATIONS AND RESULTS

The following should be included in detail:(a) the format of the general performance equation

that is used, based on the test goal and the applicablecorrections (This is repeated from the test requirementsfor convenience.)

(b) tabulation of the reduced data necessary to cal-culate the results, summary of additional operatingconditions not part of such reduced data

(e) step-by-step calculation of test results from thereduced data (Refer to the appendices for examplesof step-by-step calculations for each plant type andtest goal.)

(d) detailed calculation of primary flow rates fromapplicable data, including intermediate results, if re-quired (Primary flow rates are fuel flow rates, and, ifcogeneration, process flow rates.)

(e) detailed calculations of heat input from fuelfrom a coal-fired power plant utilizing PTC 4 andwater/steam side measurements

(f) detailed calculations of fuel properties - den-sity, heating value (Values of constituent properties,used in the detailed calculations shall be shown.)

Heating value must be identified as either high or lowheating value.

(g) any calculations showing elimination of datafor outlier reason, of for any other reason

(h) comparison of repeatability of test runs(j) clarity as to whether reported heat rate is base

on HHV or LHV

65

The test report for a performance test shouldincorporate the following general requirements

(a) Executive Summary, described in Subsection6.2

(b) Introduction, described in Subsection 6.3(e) Calculation and Results, described in Subsec-

tion 6.4(d) Instrumentation, described in Subsection 6.5(e) Conclusions, described in Subsection 6.6(f) Appendices, described in Subsection 6.7This outline is a recommended report format.

Other formats are acceptable, however, a report ofan overall plant performance test should contain allthe information described in Subsections 6.2 through6.7 in a suitable location.

6.2 EXECUTIVESUMMARY

The executive summary is brief and contains thefollowing.

(a) general information about the plant and the test,such as the plant type and operating configuration,and the test objective

(b) date and time of the test(c) summary of the results of the test including un-

certainty(d) comparison with the contract guarantee(e) any agreements among the parties to the test to

allow any major deviations from the test requirements,e.g., if the test requirements called for three test runs,and all parties agreed that two were sufficient

6.3 INTRODUCTION

This section of the test report includes the fol-lowing.

(a) any additional general information about theplant and the test not included in the executive sum-mary, such as:

(1) an historical perspective, if appropriate(2) a cycle diagram showing the test boundary

(refer to the figures in the appendices for examples

ASME PTC 46-1996

6.5 INSTRUMENTATION

(a) tabulation of instrumentation used for the pri-mary and secondary measurements, including makemodel number, etc.

(b) description of the instrumentation location(c) means of data collection for each data point,

such as temporary data acquisition system print-out,plant control computer print-out, or manual datasheet, and any identifying tag number and/or addressof each

(d) identification of the instrument which was usedas back-up

(e) description of data acquisition system(s) used(f) summary of pretest and post-test calibration

6.6 CONCLUSIONS

(a) if a more detailed discussion of the test resultsis required


(b) any recommended changes to future test proce-dures due "lessons learned"

6.7 APPENDIXES

Appendixes to the test report should include:(a) the test requirements(b) copies of original data sheets and/or data acqui-

sition system(s) print-outs(c) copies of operator logs or other recording of

operating activity during each test(d) copies of signed valve line-up sheets, and other

documents indicating operation in the required con-figuration and disposition

(e) results of laboratory fuel analysis(f) instrumentation calibration results from labora-

tories, certification from manufacturers

66

APPENDIX A - SAMPLECALCULATIONSCOMBINED CYCLE COGENERATION PLANT

WITHOUT DUCT FIRINGHEAT SINK: COMPLETELY INTERNAL TO THE TEST

BOUNDARYTEST GOAL: SPECIFIED MEASUREMENT POWER - FIRE

TO DESIRED POWER LEVELBY DUCT FIRING

(This Appendix is not a part of ASME PTC 46-1996.)

Cycle DescriptionThe plant to be tested is a non-reheat combined

cycle cogeneration plant that is powered by twonominal 85 MW gas turbines with inlet evaporativecoolers and steam injection for NOx control andpower augmentation.

The gas turbine exhausts produce steam in twotriple-pressure heat recovery steam generators. Thehigh pressure, 1280 psig/900°F (89.27 bar{a)/482°C),steam feeds the throttle of an 88 MW condensingsteam turbine that has an intermediate pressureextraction port at 350 psig [25.1 bar{a)] to supplythermal efflux steam and make up for shortages ofgas turbine injection steam. The exhaust steam fromthe steam turbine is fed to an Ciir-cooled condenser.The low pressure, 30 psig [3.1 bar(a)J saturated,steam is used only for boiler feed water deaeration.There is no sllpplemental firing capability in theHRSGs.

Thermal efflux is in the form of export steam,primarily extracted from the steam turbine with steamconditions controlled at 300 Psig/550°F (21.7 bar(a)/288°C).

Test Boundary DescriptionBasically, the entire plant is included within the

test boundary, as is indicated on the process flowdiagram. Air crosses the boundary at the inlets ofthe gas turbines and the inlet to the condenser.

Net plant electrical output is determined frommeasurements of the output of each generator with

an allowance made for the losses of each step-uptransformer. Plant auxiliary loads are supplied fromthe utility high voltage supply during the test.

Fuel flow rate and heating value are measuredin the plant fuel supply line near where the fuelcrosses the test boundary.

Export steam is measured in the steam export linewhere it crosses the test boundary.

Reference and Measured ConditionsReference MeasuredCondition Condition

250 (31.5) 218 (27.5)0.85 0.97570 (21) 59 (lS)

Parameter

Steam ExportPower FactorAmbient

TemperatureAmbient

PressureRelative

HumidityMeasured Results

Plant Net PowerNet Heat Rate

Fuel Input

k Lb/hr (kg/s)

OF (OC)

Psia [bar(a)]14.433(0.99512)

60

14.595(1.0063)

77 %

MWBtu/kWh HHV

1,977 mm Btu/hr HHV579.4 M]/s HHV87.0 MW87.5 MW49.5 MW4.5 MW

Gas Turbine 1 PowerGas Turbine 2 PowerSteam Turbine Power

Auxiliary Load

Fundamental Equations

Pearr =(

pmeas +i l:1i)

n aj,: 1 j: 1

67

Qeorr

HReorr = Peorl

Qeorr =(

Qmeas +i Wi)n l3i

1=1 j=1

Table of Required Corrections and CorrectionFactors

Correction/FactorAdditivecorrectionsTherm<!1 Efflux

G<!s Turbine Power F<!ctor

Ste<!m Turbine Power F<!ctor

Multiplicative Correction Factors

Ambient Temper<!tureAmbient Pressure

Rel<!tive Humidity

Corrections Not RequiredThe following corrections and correction factors

are not required for this specific test:A3= HRSG blow-down was closed for test and

the guarantee was based on no blow-downA4= there were no secondary heat inputs

ASA=inlet air conditions were acceptably closeto those at the inlets to the gas turbines,so an average temperature was used for thecalculations

ASB= does not apply to this condensing systemAsc= does not apply to this condensingsystemA6=there were no irregular or off-designauxil-

iary loads during the testA7= the test was a constant disposition test and

therefore A7 was zeroa4,/34= fuel supply conditions were the same as

for designas,/3s= fuel analysis matched the design fuel

Power FIJel fnergy

A,A2AA2B

a1

a2

a]

/31/32/3]

The above corrections may be required for calcula-tions of an actual test of a similar plant. The fact

I

II

ill!

that they were neglected in this example does notmean that they should always be neglected.

Correction Curves and Fitted EquationsThese curves and equations are linear and non-

linear regressions of calculated performance devia-tions based on a model of a specific plant, andshouldnot be usedgenerically for any PTC46 Test.

A1= -22,180 + 88.8 . (k lb/hr)A2A=MW . 1000 . 0.987 . (0.01597) . (pf -

0.85) - 0.012104. (pf2- 0.852)- 0.021571. (pf - 0.85) . MW/13S)

4\2B==MW . 1000 . 0.9825 . (0.01597 . (pf -0.85) - 0.012104 . (pf2- 0.852)- 0.021571. (pf - 0.85) . MW/88) .

a1 = 0.844902 + 0.00146818(OF)0.000010612(OF)2

a2= 2.134403 - 0.07858(Psia)a3= 0.957444 + 0.078668 . (%RH/100) -

0.01301(%RH/100)2/31=0.852007 + 0.001696891(OF)+ 5.9254E-

06(OF)2/32= 2.045731 - 0.07245(Psia)/33= 0.958413 + 0.078079 . (%RH/100) -

0.01474(%RH/1 00)2

4

+

Discussion

Corrections are for factors affecting plant perform-ance that are outside the control of the party runningthe test.

Steam export flow rate has been corrected toguarantee temperature and pressure conditions inthe measurement process.

Corrections for fuel energy input have been usedinstead of those for heat rate based on a personalpreference for this particular method of correction.

The ambient temperature used for corrections isthe average dry bulb temperature at the inlets ofthe gas turbines. The relative humidity is the averageof the inlets to the gas turbines.

To simplify the calculations, the power factors ofthe three generators are assumed equal during themeasurement period. This is not always true.

68

u.s. Customary 51Type Description Component Value Units Value Units

basis steam eport 250 k Ib/hr 31.5 kg/s

basis power factor 0.85 0.85

basis ambient temperature 70 of 21 °C

basis atmospheric pressure 14.433 psia 0.99512 bara

basis relative humidity 60% 60%

test gas turbine 1 power 87,000 kw 87,000 kw


test steam turbine power 49,500 kw 49,500 kw

test auxiliary load 4,500 kw 4,500 kw

test fuel input-HHV 1,977.0 mm btu/hr 579.40 mils

test steam export 218 k Ib/hr 27.5 kg/s

test power factor 0.975 0.975

test ambient temperature 59 of 15 °C

test atmospheric pressure 14.595 psia 1.0063 bara

test relative humidity 77% 77%

test transformer losses 0.5% 0.5%

test gross power 224,000 kw 224,000 kw

test auxiliary load 4,500 kw 4,500 kw

test transformer losses 1,120 kw 1,120 kw

test net power 219,500 kw 219,500 kw

Delta 1 Thermal Effluxtest steam export 218 k Ib/hr 27.5 kg/s

curve correction delta 1 (2,822) kw (2,822) kw

Delta 2A Gas Turbine Power Factortest power factor 0.975 0.975


curve GT 1 corr delta 2A (215) kw (215) kw


curve GT 2 corr delta 2A (217) kw (217) kw

add total corr delta 2A (432) kw (432) kw

Delta 28 Steam Turbine Power Factortest power factor 0.975 0.975

test steam turbine power 49,500 kw 49,500 kw

curve corr delta 28 (111) kw (111) kw

Alpha 1 Ambient Temperature- Powertest ambient temperature 59 OF 15 °C

69

70

U.S. Customary 51

Type Description Component Value Units Value Units

curve corr alpha 10.96846 0.96846

Alpha 2 Atmospheric Pressure- Powertest atmospheric pressure

14.595 psia 1.0063 bara

curve corr ;llpha 20.98756 0.98756

Alpha 3 Relative Humidity - Power

test relative humidity77.0% 77.0%

curve corr alpha 31.01030 1.01030

Beta 1 Ambient Temperature- Fueltest ambient temperature

59 of 15 °C

curve corr beta 10.97275 0.97275

Bet!) 2 Atmospheric Pressure - Fueltest atmospheric pressure

14.595 psia 1 .0063 bara

curve corr beta 20.98831 0.98831

Beta 3 Relative Humidity - Fuel

test relative humidity77.0% 77.0%

curve carr beta 31.00980 1.00980

Corrected Power

test net power219,500 kw 219,500 kw

curve delta 1(2,822) kw (2,822) kw

curve total delta 2A(432) kw (432) kw

curve delta 2B(111) kw (111) kw

curve alpha 10.96846 0.96846

curve alpha 20.98756 0.98756

curve alpha 31.01030 1.01030

calc corrected net power208.845 kw 208,845 kw

CorrectedFuel

test fuel input - HHV1,977.0 mm btu/hr 579 mj/s

curve beta 10.97275 0.97275

curve beta 20.98831 0.98831

curve beta 31.00980 1.00980

calc corrected fuelinput - HHV

1,919.3 mm btu/hr 562.48 mils

CorrectedHeat Rate

calc corrected fuel input1,919.3 mm btu/hr 562.48 mils

calc corrected net power208,845 kw 208,845 kw

calc corrected heat rate 9,190 btu/kwh 9,696 kj/kwh

:::J

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APPENDIX B - SAMPLE CALCULATIONSCOMBINED CYCLE COGENERATION PLANT WITH

DUCT FIRINGHEAT SINK: EXTERNALTO TEST BOUNDARY

TEST GOAL: SPECIFIED MEASUREMENT POWER - FIRETO DESIRED POWER LEVELBY DUCT FIRING


B.1 CYCLE DESCRIPTION AND UNITDISPOSITION

B.2 TEST BOUNDARY DESCRIPTION

The test boundary is also shown on Fig. B.1. Notethat the condenser is outside the test boundary.

The streams with energy entering the system whichneed to be determined are:

(a) air for the gas turbine(b) fuel to both gas turbine and the duct burner(c) make-up flow(d) saturated condensate from the condenser to the

condensate systemThe streams with energy leaving the system which

need to be determined are:(a) electrical power(b) process steam(c) steam turbine exhaust to condenser(d) blowdown from the HRSG

B.3 TABLE OF REFERENCECONDITIONS

The parameters requiring correction, and theirdesign values, are given in Table B.1.

B.4 REQUIREDCORRECTION FACTORS

For the test, the plant is operated by adjustingthe amount of duct firing until the design powerlevel is reached. Since it is desired to minimize

corrections to power, additive corrections are madeto heat input using the (J)corrections. Multiplicativecorrections are made to heat rate using the f correc-tion factors. There is one additive correction to

81

This cycle consists of a gas turbine that exhauststo a two pressure level heat recovery steam generatorwith duct firing, plus a single case steam turbinethat exhausts to a water cooled condenser. (Referto the cycle diagram in Fig. B.1). HP steam fromthe HRSG goes to the steam turbine throttle valve.An extraction port on the steam turbine providessteam for gas turbine NOx control. The steam turbinealso has an LP induction/extraction port. When littleor no process steam is required, LP steam from theHRSG is inducted into the turbine. When designquantities of process steam are required, LP steamis extracted from the turbine and combined withLPsteam from the HRSG.The cycle also includes afuel preheater, a deaerator, and a chemical cleaningsystem.

The operating disposition of this plant is such thatit allows adjustment to plant power by adjustingthe rate of fuel to the duct burner. The gas turbineis base loaded and its power output is a functionof ambient conditions. The steam turbine must pro-vide the difference between the design power leveland the gas turbine power output. By varying ductburner fuel flow, the necessary amount of steam. inthe HRSG is produced to meet the required steamturbine power output and process steam flow require-ments.

Thus, the performance test goal is to duct fireuntil design power is reached. The unit was designedto meet this power level on a 365 day per yearbasis in a temperate climate zone.

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TABLE B.1REFERENCECONDITIONS

Reference Condition Description

Gross plant power output

Reference Value

81,380 kW

Ambient temperature 30°FH.1Oe)

Ambient pressure 14.68 psia. (101.2 kPa)

Ambient relative humidity 60%

Gas turbine fuel temperature 350°F(177°C)

Fuel heating value, HHV 21,826 Btu/lbm

(50767 kJ/kg)

3.06Fuel carbon to hydrogen ratio

Gas turbine generator power factor 0.85

Steam turbine generator power factor 0.85

HRSG HP drum blowdown 1% Steam Flow

HRSG LP drum blowdown 1% Steam Flow

Make-up water temperature 60°F(16°C)

Excess make-up water flow* 0 Ib/hr

(0 kg/s)

Condenser pressure 1.50 Inches HgA(5.08 kPa)

Process steam flow 50,000 Ib/hr

(6.2999 kg/s)

Process steam enthalpy 1240.5 Btu/lbm

(2885.4 kJ/kg)

*This is the flow in excess of that required for make-up due to NOxsteam, process steam, etc. that enters the cycle.

power, A7, which is used in combination with (z)7to correct from measured power to design power.

Therefore, from the overall general heat rateequation,

HR - (Qmeas + ~ (z)j)II Ill.

corr - 1-'(Pmeas+ ~ Ai) II exJ

and the relationship

~=:!JPj

the test equation for this specific plant and testbecomes

HRcorr

- (Qmeas + Cd! + CdZ + Cd3 + Cd4 +_iLlS + iLI7)" fzf3f4fs

- (Pmeas + A7)

The individual corrections in this equation aredescribed in Table B.2.

8.5 CORRECTION CURVES AND FITTED

EQUATIONS

A series of heat balances were run in order todetermine the performance test corrections. The cor-rections are first presented in equation form followedby a series of curves.

Correction to. heat input to account for processefflux (i.e., process steam) different than design

iLl!= 55082885 - 78.4074405F+ 6.7583*10-7Fz - 25310.41H+ 9.66613371 Hz - 0.41827648FH- 1.0758*10-9FzH - 0.00011342FHz

+ 4.2804*10-13FzHz

where

F= process steam flow (lb/hr)H= process steam enthalpy (Btu/lb)

Correction to heat input to account for gas turbinegenerator power factor different than design.

Cd2A = 76855305.67 - 154591165PF+ 75497833.33PF2 - 3387.76765kW+ 0.034160678kW2 + 6736.6085PFkW- 3236.47PFzkW - 0.06782565PFkW2+ 0.032513667PFzkW2

where

PF= gas turbine generator power factorkW = gross power output measured at gas turbine

generator terminals (kW)

83

TABLE B.2REQUIRED CORRECTION FACTORS

Symbol

"'1

"'2

"'3

"'4

"'sc

"'7

A7

DescriptiOfl

Correction to heat input to account for process ef-flux (j.e., process steam) different than design.

Correction to heat input to account for generatorpower factor different than design. This is brokendown to "'2Afor the GT generator and "'28 for the5T generator.

Correction to heat input to account for blowdowndifferent than design.

Correction to heat input to account for secondaryheat inputs (ie., make-up) different than design.

Correction to heat input to account for condenserpressure different than design. (The correctionwould be "'SAfor cooling tower air inlet tempera-ture different than design. The correction would be"'S8 for circulating water temperature different thandesign.)

Correction to heat inpUt to atcount for differencebetween measured power and design power.

Difference between design power and measuredpower.

~ Correction factor to plant heat rate to account forambient temperature different than design.

f2 Correction factor to plant heat rate to account forambient pressure different than design.

~ Correction factor to plant heat rate to account for

relative humidity different than design.

f. Correction factor to plant heat rate to account for

fuel temperature different than design.

f5 Correction factor to plant heat rate to account for

fuel heating value different than design.

Correction to heat input to account for steamturbine generator power factor different than design

CIJ28= 6286157 - 12273205PF+ 5738500PF2 - 443.8303kw+ O.OO4955327kW2 + 914.5335714PFkW- 461.6238095PF2kW - O.O12295PFkW2+ O.OO7606122PF2kW2

where

PF= steam turbine generator power factor

TABLE B.3MEASURED DATA

Description

Gross gas turbine power outputGross steam turbine outputGas turbine generator power factorSteam turbine generator power factorAmbient temperature

Ambient pressure

Ambient relative humidityGas turbine fuel temperature (OF)

Fuel heating value, HHV

Fuel carbon to hydrogen ratioHR5G HP drum blowdownHRSG lP drum blowdown

Make-up water temperature

Condenser pressure

Process steam pressure

Process steam temperature

The data below is calculated from othermeasurements:

Gas turbine fuel flow

Duct burner fuel flow

Process steam flow

NOx steam flow

Make-up flow

Process steam enthalpy (Btu/lb)

Measured Value

54921 kW27244 kW

0.950.95

47.3°F(8.50°0

14.76 psia001.8 kPa)

30%356°F

080"C)22850 Btu/lbm

(53149 kJlkg)3.05

IsolatedIsolated64.2"F

(17.9°C)

1.20 Inches HgA(4.06 kPa)188.4 psia(1299 kPa)

463.3°F(239.6°C)

25,906 Ibm/hr(3.2641 kgls)5448 Ibm/hr(0.6864 kg/s)

46,626 Ibm/hr(5.8748 kg/s)

45,552 Ibm/hr(5.7395 kg/s)

92,303 Ibm/hr(11.630 kgls)

1249.8 Btu/lbm

(2907.0 kJ/kg)

kW =gross power output measured at steam tur-bine generatorterminals(kW)

Correction to heat input to account for blowdowndifferent than design.

Correction from isolated to 1% HP blowdown.LP blowdown. is insignificant.

Cr1)=592390.1 - 672.4T+ 100.0485T2

Where

T= ambient temperature (OF)

84

~

t

,Correction to heat input to account for secondary

heat inputs (i.e., make-up) different than design

"-'4 = -571800 -1300.38F+ 5.9631*10-19F2+ 9440T + 1.572 + 0.17475FT+ 6.7763*10-2IF2T+ 0.0002125FT2- 5.294*10-23F2T2

where

F= excess make-up flow (lb/hr)7= make-up temperature (OF)

Correction to heat input to account for condenserpressure different than design

"-'sc = 11986296.56 - 8308140.313P+ 344850.625p2 + 68357.175T- 393.718125 T2 - 52424.275PT+ 4568.55p2T + 282.085625PT2- 13.07125p2 T2

where

P= condenser pressure (inches Hg absolute)7=ambient temperature (OF)

Correction to thermal heat input to account fordifference between measured power and designpower

UJ7 = -2.61186*10-12 + 7260.752844.1.7- 0.537355297.1./ + 4.27425*10-14T- 2.24607*10-1sT2 + 26.6786625.1.7T+ 0.018662119.1./ T - 0.222322188.1.7T2- 0.000155518.1./T2

where

117= difference between design power and mea-sured power, Pdesign- Pmeas,(kW)


Difference between design power and measuredpower

117= 81380 - Pmeas

Correction factor to heat input to account forambient temperature different than design

fl = 1.012975085- 0.0004378037T+ 1.766957*10-7T2

where


Correction factor to heat input to account forambient pressure different than design

(2 = 1.617199959 - 0.08191305P + 0.002715903p2

where

P= ambient pressure (psia)

Correction factor to heat input to account forrelative humidity different than design

(3= 1.0 (correction is insignificant)

Correction factor to heat input to account for gasturbine fuel temperature different than design

(4= 0.99301814 + 0.000019948177

where

T= fuel temperature (OF)

Correction factor to heat input to account for fuelheating value different than design

fs = 2.66107573 - 0.00010133 V+ 3.3266*10-13V2- 1.06344696R+ 0.17852287 R2 + 6.5632*10-5 VR-2.1534*10-13V2R-l.l011*10-sVR2+ 3.4844*10-14V2R2

where

V= fuel higher heating value (Btu/lb)R= fuel carbon to hydrogen ratio (no units)

B.6 SAMPLECALCULATIONSAND RESULTS

The "Corrected Value" entries of Table 8.4 are

calculated as described below. The plant specifictest equation is repeated for convenience.

85

HRcorr

- (Qmeas + Ui1 + w2 + Ui3 + w4 + w5 + w7) f1f2f3f4/5- (Pmeas+ d7)

= 755,592,753 kJlhr)

The multiplicative corrections are

The additive correction to power isto.9926623)(0.9998435)(1.000000)(1.0001197)(0.9964189) =

0.989071059

82,165 kW - 785 kW = 81,380 kW The complete equation is then

The additive corrections to heat input are HR - (716, 171,950)(0.989071059)rou - 81380

716,438,900 + 2,289,194 + 328,100 + 137,016+ 784,423 - 120,605 + 2,616,334 - 6,301,412

= 716,171,950 Btu/hr

HRcOtf = 8704 Btu/kW-hr

HR - (755,592,753 kJ/hr)(0.989(j71)corr - 81380 kW

(755,874,400 + 2,415,228 + 346,164 + 144,560+ 827,610- 127,245 + 2,760,379 - 6,648,343 HRcorr == 9183 kJ/kW-hr

86

~

TABLE 8.4PERFORMANCE CORRECTIONS

Gross Plant Design Power

Description

GT generator gross power

81,380 kW

Measured Value Correction Corrected Value

54,921 kW

5T generator gross power 27,244 kW

Gross plant power 82,165 kW

Difference from design power /::.7= -785 kW

Correded gross plant power 81,380 kW

Gas turbine gas flow 25,906 Ibm/hr

Cr.2641 kg/s)

.5448 Ibm/hr

(0.6864 kg/s)Duct burner gas flow

Total gas flow 31,354 Ibm/hr

0.9505 kg/s)

Fuel heating value, HHV 22,850 Btu/lbm

(53149 kJ/kg)

Measured heat input 716,438,900Btu/hr

(755,874,400 kJ/hr)

Process steam flow 46,626 Ibm/hr

(5.8748 kg/s)

Process steam enthalpy 1249.8 Btu/lbm

(2907.0 kJ/kg)

Process efflux correction w1 = 2,289,194 Btu/hr(w1 = 2,415,228 kJ/hr)

GT generator power factor 0.95

GT generator power factor correction w2A = 328,100 Btu/hr(w2A = 346,164 kJ/hr)

5T generator power fador 0.95

5T generator power factor correction w2B = 137.016 Btu/hr

(w2B = 144,560 kJ/hr)

HP and lP blowdown Isolated

Blowdown correction w3 = 784,423 Btu/hr(w3 = 827,610 kJ/hr)

Excess make-up flow 125 Ibm/hr

(0.0157 kg/s)

Make-up temperature 64.2°F (17.9°e)

87

TABLE B.4

PERFORMANCE CORRECTIONS (CONT'D)

Gross plant Design Power 81,380 kW

Description

Make-up correction

Measured ValueCorrection

Corrected Value

w4 = -120,605 Btu/hr(w4 = -127,245 kj/hr)

Condenser pressure 1.20 inches HgA(4.06 kPa)

Condenser pressure correction CL/5C= 2,616,334 Btu/hr

( 5C = 2,760,379 kJ/hr)

Power difference (A7) -785 kW

Power difference correction 7 = -6,301,412 Btu/hr(w7 = -6,648,343 kJ/hr)

Ambient temperature 47.3°F (8.50°C)

Ambient temperature correction f1 = 0.9926623

Ambient pressure 14.76 psia (101.8kPa)

Ambient pressure corredion f2 = 0.9998435

Ambient relative humidity 30%

Ambient relative humidity correction f3 = 1.000000

GT fuel temperature 356°F (180°C)

GT fuel temperature correction (4 = 1.0001197

Fuel heating value, HHV 22850 Btu/lbm

(53149 kJ/kg)

Fuel carbon to hydrogen ratio 3.05

Fuel analysis correction f5 = 0.9964189

Plant heat input after additivecorrections, HHV

716,171,950Btu/hr

(755,592,753 kJ/hr)

Corrected plant heat rate, HHV 8704 Btu/kW-hr

(9183 kJ/kW-hr)

88

CORRECTION TO HEAT INPUTFOR THERMAL EFFLUX

Plant GrossOutput 81 380 kW Gas Turbine Base LoadedNaturalGas Fuel Duct BurnerFiring

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PROCESS STEAM FLOW, F (Ib/hr)

FIG. 8.2 CORRECTION TO THERMAL HEAT INPUT FOR THERMAL EFflUX

89

-.,... 50000008-z0-I- 00wa:a:0 -50000000

CORRECTION TO HEAT INPUTFOR GAS TURBINE GENERATOR POWER FACTOR

Plant GrossOutput81380 kW Duct BurnerFiringNaturalGas Fuel Gas TurbineBase Loaded

600000__J..JuL_L_J__LL_L_T_TL_: .L IT1: i--- , ,~ - GrossGT Power = 40000 kW r f--f-- 1--

= .- - - -- - GrossGT Power=50000 kW ---

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GT GENERATOR POWER FACTOR, PF

FIG. B.3 CORRECTION TO THERMAL HEAT INPUT FOR COMBUSTIONTURBINE GENERATOR POWER FACTOR

90

400000

oJ

- 300000CCN8-z 2000000-I-0w 100000a:a:00

0

")CORRECTION TO HEAT INPUT

FOR STEAM TURBINE GENERATOR POWER FACTOR

PlantGrossOutput81380 kW Duct BurnerFiringNaturalGas Fuel Gas TurbineBase loaded

400000 HL:-~;;i;~;~;~~i~i ~=I;~ Gross5T Power=35000 kW oz:

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ST POWER FACTOR, PF

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FIG. B.4 CORRECTION TO THERMAL HEAT INPUT FOR STEAM TURBINEGENERATOR POWER FACTOR

-

91

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('IIe-z0-I-

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0

CORRECTION TO HEAT INPUTFOR HP BLOWDOWN

Correction from Isolated to 1% HP Blowdown

Plant Gross Output81380 kW Gas TurbineBase loadedNaturalGas Fuel Duct BurnerFiring

50000 Ib/hrProcess Steam

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AMBIENT TEMPERATURE e F)

( FIG. 8.5 CORRECTION TO THERMAL HEAT INPUT FOR HP BlOWDOWN

c92

CORRECTION TO HEAT INPUTFOR CYCLE MAKE..UP

Plant Gross Output81380kW Gas TurbineBase LoadedNatural Gas Fuel Duct BurnerFiring50000 Ib/hr Process Steam

0 ..L..L-1._.J.J. I J I._J...I..L..1.1' !:\.' . I" ..- - - - - 40 F Make-upTemp f ;-" . , I

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EXCESS MAKE-UP FLOW, F (Ib/hr)

FIG. 8.6 CORRECTION TO THERMAL HEAT INPUT FOR CYCLEMAKE-UP

93

CORRECTION TO HEAT INPUTFOR STEAM TURBINE CONDENSER PRESSURE

Plant Gross Output 81380 kW Gas Turbine Base Loaded50000 Ib/hr Process Steam Natural Gas FuelDuct Burner Firing

6000000

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CONDENSERPRESSURE,P (In. Hg)

FIG. 8.7 CORRECTION TO THERMAL HEAT INPUT FOR STEAM TUR81NECONDENSER PRESSURE

94

0-()It)8- -2000000z0-to-0 -4000000wa:a:0

-60000000

-8000000

)CORRECTION TO HEAT INPUT

FOR MEASURED POWER DIFFERENT THAN DESIGN

Natural Gas Fuel50000 Ib/hr Process Steam

Gas Turbine Base Loaded

Duct Burner Firing

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-1 -1- !-20000000 I

-2000 -1000 0 1000 2000

DIFFERENCE IN POWER 6.7(kW)

FIG. B.8 CORRECTION TO THERMAL HEAT INPUT FOR MEASUREDPOWER DIFFERENT THAN DESIGN

95

-- ""~

.-~-~-~ '"

CORRECTION TO PLANT HEAT RATEFOR AMBIENT TEMPERATURE

Plant Gross Output81380 kW Duct BurnerFiring309 F Guarantee Conditions 50000 Ib/hr ProcessSteamNatural Gas Fuel Gas TurbineBase Loaded

1.005

0.975

1+ n -1

.

'-- -- ~- --I. j -. Hi.f

I .._-

! ! I !+:-1'- __njum '--

1

.1

I-I 1.

11

' ,T,

! ---', 1 "'1H1 i. IiI I ii' n_!

...)

'I\: ,'1 " .-.

'\ I --.+L-L-_L- - I i I !

, ~ i i- +,1 - ..-

\ - -' L i

I

.

I I' T - - -:- r' .. - i" I ,,---+....---N I Ii I, I' I . !:

n_.n 4- I I ---

i 1-- -_u-r n- ___n_-

.- I I , t... --I t l--f +--- ,-----.

\ i . _..._..i " I '

I I i'\!_n - -l- '\

I n.__[_._m --.-

I ,.. . -.- -I-un \ '

.-- -'-",'-' - --,-- nu- -"u'- -- _1_---

I If--+ --; f-'-- : - - "

I I \; -- H- 1 1-- - .\0'I

, I \ I---tn -- I un T nun +'\- .--!

- - , I I I' I '\

, I -,' . .-- - - . . -. I ' 'ii' I I

' ' ' - '\ I

~-+ .' I , '. I I I

Ii I I , + t--",! I

1 \, !-,

i .' ".~~- .. -i - ' -~ I" "

1.000

0.97030 40 50 60 70 80 90

AMBIENT TEMPERATURE, T (O F)

100

FIG. B.9 CORRECTIONTO PlANT HEAT RATEFOR AMBIENTTEMPERATURE

96

- 0.995....--a:0t-0 0.990c(u.Z0-t- 0.9850wa:a:00 0.980

)CORRECTION TO PLANT HEAT RATE

FOR AMBIENT PRESSURE

Plant Gross Output81380 kW DuctBurnerFiring30° F Guarantee Conditions 50000 Ib/hr ProcessSteamNaturalGas Fuel Gas TurbineBase Loaded

1 .001 0

1.0008

)1.0006-('II--

",,),.--

a:0t-O~u..Z0i=0wa:a:00

1.0000

1.0004

1.0002

0.9998

0.9996

')

i

m

I

1

: ; i 1 'l !.

1

'l! 1\1 ' - '-'-- - li, , ,-,j 1

1'

u -',1-- -. -t-- .-t---!--I\)- , I' i .

I I i\ ! +-=+:' ,: I '\.; :! -J--, . [\ , ' . ' I' , -, . -. " i, .

1

. ~'-"- ',.,. - ,-/. "..., i-, 1 I 'i' ': .'f-r.' m.i'r'~- -",. Iii!

" ! I' 1-; I L ~--~-

~t_l ' I . I +-!- -- ,u- - ~

.

+- --+-

~~ r- - : t-++H- -.r- :. -_U- ~~<JJ.l-l-=Ir- I I' 'll.L~!, ; j

,I ! I' 1 i i.1 y-

, I I , - ., u-r-r-i!, I I I ,I III ~Il I I

-- -+j, uO ,+-L. --~_r-~. I. ;.-0.9994 ; I

14.4 14.5 14.6 14.7 14.8 14.9

AMBIENT PRESSURE, P (psia)

--,---

15.0

FIG. 8.10 CORRECTION TO PLANT HEAT RATE FOR AMBIENT PRESSURE

)

97

CORRECTION TO PLANT HEAT RATEFOR FUEL TEMPERATURE

Plant Gross Output 81380 kW Duct Burner Firing30QF Guarantee Conditions 50000 Ib/hr Process SteamNatural Gas Fuel Gas Turbine Base Loaded

i!I I

i-. -- ~ - -T-. -

1

I71-

i

-_.'-'--1- - - ---- .- !+ ,u..> - pl.-

f--j_+~m I I TIIi

-+-"' +-+-1 -+ -~ -- -.:t-I

i--tlTT f- -I I. --p-_u

I (- t 1 --- - --

--~ +-

-¥~_w.

i r-

~-

11++I¥f:Iii.. --+-+--J--+-~--~,_..

'7

T!-i

t+ITI T

320 340 360 380

FUEL TEMPERATURE e F)

FIG. 8.11 CORRECTION TO PLANT HEAT RATE FOR FUEl TEMPERATURE

98

-.-

-

400

1.0010

1.0008

1.0006-'I;t1 .0004--

a:0I- 1.00020<CLA.Z 1.00000-t-0 0.9998wa:a:0 0.99960

0.9994

0.9992

0.9990L1

300

CORRECTION TO PLANT HEAT RATEFOR FUEL ANALYSIS

PlantGross Output 81380 kW Duct BurnerFiring30° F Guarantee Conditions 50000 Ib/hr Process SteamNatural Gas Fuel Gas TurbineBase Loaded

1.002

)1.000

1

- r-

UTIII'

W. i i

l- +- .. --'---Jl-L- 2.98 Fuel C/H Ratio h-

3.06FuelC/H Ratio H-3.12 Fuel C/H Ratio i I .

'!, , . -- -j--j--

1 ,

,

a::0I-CJca:u.Z0i=CJwa::a::0CJ

--I-.-+ '_'.~---

'I, Il~"

II

_m'n_~__+-++ I ,

I-1

+i

.1

-II)-- 0.998

0.996.I

I

0.994H---! -+,.. +---

ITIi.,.J- -1' .

L-ll,

+,I

--,-_.,- +-+

j-

'~ I

l

'

j"

~+f\. -,t,+ ~,-+

t- "

---+-- I1-

~l-L I

.

1

'.1

i

I j

0.992

J - -_.~-

,

II I - -

0.990 I . I21500 22000 22500 23000 23500

FUEL HIGHER HEATING VALUE (Btu/lb)

FIG. 8.12 CORRECTION TO PLANT HEAT RATE FOR FUEL ANALYSIS

t99

)

APPENDIXC - SAMPLE CALCULATIONSCOMBINED CYCLE COGENERATION PLANT WITHOUT

. DUCT FIRINGHEAT SINK: COOLING TOWER EXTERNALTO THE TEST

BOUNDARY

TEST GOAL: SPECIFIED DISPOSITION IS GAS TURBINEBASELOADED (POWER FLOATS)

(This Appendix is not a part of A5ME PTC 46-1996.)

C1 Introduction

t

The combined cycle/cogeneration plant for thesample calculation that follows is generally shownon Fig. Cl. The major equipment items are asfollows:

. gas turbine: 115 MW at 150 conditions (S9°F OsoC),60% RH, and sea level} with 4 inwg (12.0 mbar)inlet and 12 inwg (36 mbar) exhaust pressure dropand steam injection for NOx control to 25 ppmheat recovery steam generator: three steam pressurelevels one of which is used with an integral deaerator.The design conditions at the outlet of the HR5Gare 1280 psig (88.3 barg) and 900°F (482.2°C) forthe HP steam, 330 psig (22.8 barg) and 500°F(260°C) for the IP steam, and saturated 15 psig (1.03barg) steam for the integral deaerator.steam turbine: condensing type, 40 MW nominalrating, with an exit pressure of 2.0 in Hg (67.5mbar) with two extraction ports at 315 psig (21.7barg) and 16S psig (11.4 barg)condenser: shell and tube with a cooling water inlettemperature of 80°F(26.rC) and a 20°F (11.1°C)risedeaerator: integral with LP drum with pegging steamfrom IP steam line if needed

)

C2 Test Boundary

The test boundary is typically shown as Fig. Cl.The measurement points for this calculation are asfollows:

(a) combined net power output from the gas andsteam turbine generator excluding in-plant auxiliarypower

(b) fuel input to the gas turbine (specified as LHVfor reference)

(c) cogeneration steam flow to the user(d) condensate return flow from the user(e) ambient air conditions at the gas turbine filter

house inlet

(f) condenser cooling water inlet(g) blowdown from the HR5G(h) make-up feedwater

C3 Test Reference Conditions

For the sample calculation that follows, the designreference conditions are:Ambient temperatureRelative humidityPlant site elevation

Process steam flow

Process steam pressureProcess steam temperatureBlowdown flowCondensate return flow

Cooling water inlet temperatureFuel heating value, LHV

60°F (1 5.6°C)

60%

0 ft/14.696 psia[0 m/l.013 bar (al]

150,000 Ib/hr 08.9 kg/s)150 psig (10.3 bargl373°F (189°C)

14,405 Ib/hr (1.81 kg/sl75% at 180°F (82.2°C)60°F (15.6°e)21515 Btu/lb (50044 kJlkg)145,540 kW7966 Btu/kWh {8404.6kJ/kWhl

Net plant power outputNet plant heat rate, LHV (without

credit for process energy)

101

--

-

-PA

~~

ik~

Y-;

IE

!I

1I

PO

WE

RI

TO

TA

LF

UE

L

INLE

TA

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-UP

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TA

IRC

OO

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LW

AT

ER

TR

EA

Th4

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--

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finI

CW

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r"S

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I

DE

SU

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~ .« ~ (f)

Cl.

:I:

LPS

TE

AM

PE

SU

P.

ST

EA

MT

OP

RO

CE

SS

I-IE

ALE

EG

ffilE

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Jilll

LE

R

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UM

PC

ON

DE

NS

AT

ER

ET

UR

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FIG

.c.1

TE

STB

OU

ND

AR

YO

FT

YP

ICA

LCO

MB

INE

OC

YC

LE

/CO

GE

NE

RA

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NPL

AN

TW

ITH

EX

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RN

AL

CO

ND

EN

SE

RCO

OL

ING

"'*'

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j

c.4 Correction Factors

The genera I equation tor corrected power tromSection 5 is

Peorr = (Pmeas + ~.:l;) na;

The overall general heat rate equation trom Section5 is

- (Qmeas + ~lUi)n~HReorr - (Pmeas + ~.:l;)

The test requirements are based on fixed unitdisposition based on base loaded gas turbines withno duct burning. For this test configuration the lUlthrough lU7 and ;).7 alt become o.

ether specific simplifying assumptions tor thisconfiguration are with regard to the variables foundin the above equation and in Tables 5.1 and 5.2:

(a) The generator power factor is specified as aconstant of 0.9 lead and will not vary, thus ;).2 be-comes o.

(b) The auxiliary laad and transformer jasses arenot expected to vary tor design and off design condi-tions, and since net power is measured, ;).6 be-comes zero.

(c) For this fixed unit disposition test, the a4 andas terms become 1.

The fs term in the above heat rate equation isused to correct the fuel healing value thai wasassumed at the time of the test to thai of the tested

fuel sample analysis recieved after completion ofthe test. It is defined as

~ - Fuel Analysis Value (LHV)s- 21515 (LHV)

The complete list of additive and multiplicativecorrections trom Tables 5.1.1 and 5.1.2 thai are

applicable tor the boundary conditions describedabove are listed as:

Changing Boundary Value Parameter Correct ion Variable(s}

Ambient tempAmbient pressureAmbient relative humidityFuel healing valueChange in steam salesHRSG blowdown flow

Make-up water tempCondens er cooling water tempCondensate return

a" f,a2, (2

a3, (3

(s

ll,

ll3

ll4

llSB

Insignificant

Reducing the general equation with these correc-tions the new power equation is

Peorr= (Pmeas+ .:ll + .:lJ + .:l4 + .:lSB) a,a2aJ

and the new heat rate equation is

HR - (Qmeas) f,f2fJfseorr - (Pmeas + .:l] + .:lJ + .:l4 + .:lsB)

The correction factors listed above are best deter-

mined using a computer model of the completeplant. The following pages list data sheets thai displaythe resulting correction variables from the plantmodel calculations tor different ranges of the parame-ters. For each parameter the power correction vari-able and/or the heat rate correction variables were

curve fit (signified by a ' symbol) using a third-orderpolynomial fit. Foltowing each data sheet, a graphshowing the data points and the curve fits are alsopresented.

103

Performance Test Code Data SheetParameter: Ambient TemperatureDesign Point: 60 0 F

Design Point:

Regression AnalysisOrder: 3rd

Regression Results

where:a,' = Intercept +

f,' = Intercept +

C, (T) +C, (T) +

C,(T)2 +C2 (T)2 +

C3 (T)3

C3 (T)3

104

Ambient Net Plant Net Plant Power Corr. Heat Rate Corr. Power Corr. Heat Rate Corr.Temperature Power Heat Rate Variabie Variabie Curve Fit Curve Fit

uF kW Btu I kWh - - - -T P HR a, t, a,' f,'

30 153,010.0 8035.9 0.951180 0.995035 0.952378 0.99058136 151,660.0 8016.4 0.959647 0.997455 0.959045 0.99399142 150,170.0 8004.3 0.969168 0.998963 0.967437 0.99636648 148,650.0 7992.1 0.979078 1.000488 0.977602 0.99777154 147,220.0 7973.4 0.988589 1.002834 0.989586 0.99826860 145,540.0 7996.0 1.00000o 1.000000 1.003435 0.99792166 142.880.0 7988.4 1.018617 1.000951 1.019196 0.99679572 140,190.0 8012.8 1.038162 0.997903 1.036916 0.99495278 137.500.0 8036.9 1.058473 0.994911 1.056641 0.99245684 134,900.0 8052.6 1.078873 0.992971 1.078417 0.98937190 132,170.0 8075.7 1.101158 0.990131 1.102292 0.985759

T T2 T3 a, t,30 900 27000 0.951180 0.99503536 1296 46656 0.959647 0.99745542 1764 74088 0.969168 0.99896348 2304 110592 0.979078 1.00048854 2916 157464 0.988589 1.00283460 3600 216000 1.000000 1.00000066 4356 287496 1.018617 1.00095172 5184 373248 1.038162 0.99790378 6084 474552 1.058473 0.99491184 7056 592704 1.078873 0.99297190 8100 729000 1.101158 0.990131

Intercept C, C2 C) R2I (x,' 0.943300812 -0.000332432 2.00891E-05 3.59239E-O8 0.998954255I f,' 0.955794514 0.001705298 -1.96625E-05 4.90452E-O8 0.938588992

PTC CORRECTIONS FACTORSWITH CURVE FITS

111 U1

A f1

- Curve Fit of «1. al'Curve Fit of f1o11'

1.150000

1.100000

AI

.. ':::"" 00..."/-001

" -=::r-"/ ""'OOOO"'_"""".I""-""""""'~"'I~.............

1.050000

..::

J

1.00000o

0.950000

0.90000020 30 40 50 60 70

Ambient Temperature, oF

80 90 100

105

Perforrrnlnce T..t Code Data SheetParameter: AmbientPressureDesign Point: 14.696 psia

Design HRDesign Power

7.966.0 Btu I kWh145.540.0 kW

Regression Analy.i.Order: 3rd

Regres.ion Ruults

where:I1z'. Intercept +

fz' . .lntercept +

C, (P) +Ct (P) +

Cz(P)z +Cz(P)z +

c,(pic,(P)'

106

~ '" ~

'*

Ambient Net Plant Net Plant Power Co". Heat Rate Con. Power Con. Heat Rata Con.Pressure Power Heat Rate VariabIe VariabIe Curve Fit Curve Fit

osia kW Btu I kWh . - . .P PWR HR (1z 1z (1z' 1z'

13262 128,530.0 8140.0 1.132343 0.978624 1.132317 0.97862513.409 1,280.0 8120.1 1.117132 0.981022 1.117180 0.98101813.557 132,030.0 8100.7 1.102325 0.983372 1.102335 0.98337613.704 133.770.0 8081.8 1.087987 0.985672 1.087972 0.98566813.852 135 520.0 8063.4 1.073937 0.987921 1.073882 0.98792913.999 137,270.0 8045.4 1.060246 0990131 1.060245 0.99012814.146 139.020.0 8027.9 1.046S00 0.992289 1.046950 0.99228314.294 140.770.0 8010.8 1.033885 0.994408 1.033899 0.99441014.441 142,510.0 7994.1 1.021262 0.996485 1.021256 0.99648214.589 144,260.0 7977.8 1.008873 0.998521 1.008837 0.99852914.736 146,010.0 7961.8 0.996781 1.000528 0.996798 1.000524

P p2 p> lXz 1z13262 175.880644 2332.529101 1.132343 0.97862413.409 179.801281 2410.955377 1.117132 0.98102213.557 183.792249 2491.67152 1.102325 0.98337213.704 187.799616 2573.605938 1.087987 0.98567213.852 191.877904 2657.892726 1.073937 0.98792113.999 195.972001 2743.412042 1.060246 0.99013114.146 200.109316 2830.746384 1.046900 0.99228914.294 204.318436 2920.527724 1.03388S 0.99440814.441 208.542481 3011.561968 1.021262 0.99648514.589 212.838921 3105.107018 1.008873 0.99852114.736 217.149696 3199.91792 0.996781 1.000528

Interçept C, C, R2I (1z' 5.641320426 -0.687385781 0.19369 -O.000E135263 0.999999479I 1z' 0.342759195 0.094852034 -0.004698993 8.76304E-05 0.999999532

»PTC CORRECTION FACTORS

WlTH CURVE FITS

.

...a2f2

Curve Fit of a2, a2'

Curve Fit of f2, f2'

1.140000

1.120000

.....

1.100000

1.080000

1.060000

..:'..a

1.040000

1.020000

1.00000o

0.980000

0.96000013 13.2 13.4 13.6 13.8 14 14.2 14.4 14.6 14.8 15

Ambient Pressure, psia

107

-----

Parameter:Design Point

Relative Humidity6O')L

J

(1"'-~

Design Point:

;"$

~


iI

a.,'. Interçept +f; . Interc;apt+

Cl (Per) +C,( Per) +

Cz(Per)2 +C2(Per)2 +

~(Per)3C3(Per)3

Regression R.su1t8

where:~

"

""-.1>'

'"

-,

1;

108

Alnbient Net Plant Net Plant Power Corr. tRateCorr. Corr. Heat Rate Corr.Relative Humiditv Power Heat Rate VariabIe VariabIe Curve Fit Curve Fit

'!Io IiM/ Btu/liM/h - - - -Per P HR a., f3 a.,' fs

10 145,619.9 7950.9 0.999451 1.001901 0.999441 1.00189920 145,609.9 7954.0 0.999520 1.001510 0.999544 1.00151730 145,589.9 7956.9 0.999657 1.001145 0.999653 1.00113740 145,570.0 7960.0 0.99979<1 1.000754 0.999767 1.00075750 145,560.0 7963.0 0.999863 1.000377 0.999884 1.00037860 145,540.0 7966.0 1.00000o 1:00000o 1.000001 1.00000o70 145,520.0 7969.0 1.000137 0:999623 1.000117 0.99962380 145,510:0 7972:0 1.000206 0.999247 1.000229 0.99924690 145,490.1 7975:0 1.000343 0.998870 1.000335 0.998871

Per Per Per' a., f,10 100 1000 0.999451 1.00190120 400 8000 0.999520 1.00151030 900 27000 -0.999657 1.00114540 1600 64000 0.999794 1.00075450 2500 125000 0.999863 1.00037760 3600 216000 1.00000o 1:00000o70 4900 343000 1.000137 0.99962380 6400 512000 1.000206 0.99924790 8100 729000 1.000343 0.998870

Intercept Cl CzI G4' 0.999346728 8.89891E-06 5.42992E-08 -3.46311E-10 0.9964!78563

I f; 1.002281715 -3 .83348E.()5 5.78617E-09 -1.08789E-11 0.999985041

»PTC CORRECTIONS FACTORS

WITH CURVE FITS

. 0.3

.t. f3

- Curve Fit of 0.3, 0.3'Curve Fit of f3, f3',...,...........

1.002000

1.001500

~,

1.001000

1.000500

)-='

{;

1.00000o

0.999500

.)0.999000

0,99850020 30 40 50 60 70

AmbientRelative Humidity,%

80 90 100

~

109

--

"

':""

"'"

"

"

"

"

À,., I"

'"

.-----""'"

I

"

"""

"

"

"',

"

"0"

""

"

""

.

Performance Test Cod4!Data SheetParameter: Ste;IImSales AowDesign FIow: 150,000 lbJhr

\I

[)esignHRDesign Power

7,966.0 Btu I kWh145,540.0 kW ()


;1,î

Regression Results

110

--"

""- - - - - "'-= -'- -

Ste;IImSales Net Plant PowerCorr. PowerCorr.Aow Power Variable CuM! FitIbJhr kW kW kWSS PWR t 't

112,500 148,600.0 -3060.0 -3060.139860120,000 147,990.0 -2450.0 -2450.699301127,500 147,380.0 -1840.0 -1839.533800135,000 146,770.0 -1230.0 -1226:923077142500 146,150.0 -610.0 -613.146853150,000 145.540.0 0.0 1.515152157,500 144,920.0 620.0 616.783217165.000 144.310.0 1230.0 1232.377622172.500 143,690.0 1850.0 1848.018648180,000 143,080.0 2460.0 2463.426573187,500 142,460.0 3080.0 3078.321678

ss SS' SS' At112.500 1.26563E+10 1.42383E+15 -3060.00000o120.000 1.44000E+10 1.72800E+15 -2450.00000o127,500 1.62563E+10 2.07267E+15 -1840.00000o135.000 1.8225OE+10 2.46038E+15 .1230.00000o142,500 2.03063E+10 2.89364E+15 -610.00000o150.000 2.25000E+10 3.375OOE+15 0.00000o157.500 2.48063E+10 3.90698E+15 620.00000o165,000 2.7225OE+10 4.49213E+15 1230.00000o172.500 2.97563E+10 5.13295E+15 1850.00000o180.000 3.24000E+10 5.83200E+15 2460.00000o187.500 3.51563E+10 6.59180E+15 3080.00000o

Intercept Ct c:,t.'t -11804.54545 0.072926185 5.51153E-oa -1.10507E-13

where:'t. Interçept + Ct (SS) + {SS)2 + c:, (SS)3

-PTC CORRECTION FACTORS

WITH CURVE FITS

. À1

-Curve Fit tor À1. À'1

4000.0

-..; 0.0

1101000 1201000 1301000 1401000 1601000 1701000 1801000 1901000

3000.0

)2000.0

1000.0

-1000.0

-2000.0

~

-3000.0

-4000.0

Steam Sales FIow,IbIhr

111

---- -~-----------

Performanc:e Teat Code Data SheetParameter. 8IowdownAowDesign Point: 14.405 1bIhr

~nHRDesign Power

7.966.0 Btu, kWh145.5040.0 W<I

..1

Regr..sion AnalysisOrder: 3rd

Regression Resulta

.11"

fJ~,

~~;iI~~JI"~

~1.'~

112

~

'" '"

BIowdown Net Plant Power CorT. Power Con.Aow Power VariabIe CUrveFitIbIhr W<I W<I W<IBD PWR A. f.'3

0 145,970.0 -430.0 -432.5174832.400.8 145.910.0 -370.0 -363.9160844,801.7 145,830.0 -290.0 -293.2867137.202.5 145.760.0 -220.0 -221.0839169,603.3 145690.0 :150.0 . :f47.762238

12,0042 145,610.0 -70.0 -73.77622414.405.0 145,5040.0 0.0 0.41958016,805.8 145.470.0 70.0 74.37062919.206.7 145 390.0 150.0 147.62237821,607.5 145,320.0 220.0 219.72028024.008.3 145 250.0 290.0 290.209790

I Inten:ept I Cl I

C2 C3

I 6', -432.5174825 0.028088538 2.15347E.o7 ..sA7444E-12

where:6',. lnterc:ept+ Cl (BD) + (BD)2 + C3(BD)'

BD BD' BO' A.0 0 0 -430.00000o

2.400.8 5764000.694 1383840500 1 -370.00000o4,801.7 23056002.78 f.10707E+11 -290:00000o7.202.5 5187600625 3.73637E+11 -220.00000o9,603.3 92224011.11 8.85658E+11 -150.00000o

12.004.2 144100017.41 1.7298E+12 -70:00000o14,405.0 207504025 2.9891E+12 . 0.00000o16,805.8 282436034 4.74657E+12 70.00000o19.206.7 368896044.4 7.08526E+12 150.00000o21.607.5 466884056.3 1.00882E+13 220.00000o24.008.3 576400069.4 1.38384E+13 290.00000o

~

It . A3

PTC CORRECTJON FACTORSWITH CURVE FITS - Curve Fit tor A3.A'3

It

Ij

300.0

0.0

200.0

100.0

.os -100.0

-200.0

-300.0

-400.0

.soo.0HRSG Blowdown FIow, Iblhr

113

~

Performanc:e Test Code Data Sheet

Parameter: Make-up Water Temperatl.lreDesign Point: 60 0 F

~gnHRDesign Power

7,966.0 Btu I kWh145,540.0 't(N

~

.,~,

(tRegression AnalysisOrder: 3rd

Regression Reaults

~

~' !f ' -

1

'"-~

.-- i

,~c~ ~ '" 11

~ : if; .:"" .1

114

,

"" ~'

f "

Mak.up Net PI8nt Power ColT. Poww ColT.Temgerature Power VariabIe Curve Fit

UF 't(N 't(N 't(NMU PWR 8c A'

40 145,500.0 40.0 41.04895143 145,500.0 40.0 37)18251746 145,510.0 30.0 32.72727349 145,510.0 30.0 27.02797252 145,520.0 20.0 20:62$37155 145.530.0 10.0 13:77622458 145,530.0 10.0 6.71328761 145,540.0 0.0 -0.31468564 145.550.0 -10.0 -7.06293767 145,550.0 -10.0 -13.28671370 145,560.0 -20.0 -18.741259

MU MU" Mlf40 1600 64000 40.00000o43 1849 79507 40.00000o46 2116 97336 30.00000o49 2401 117649 30.00000o52 2704 140608 20.00000o55 3025 166375 10.00000o58 3364 195112 10.00000o61 3721 226981 0.00000o64 4096 262144 -10.00000o67 4489 300763 -10.00000o70 4900 343000 -20.00000o

InwrçePt Ct/).. -144.5333679 12.65993266 -0.260942761 0.001510835

where:/).'4. IntercePt + Ct(MU) + Cz(MU)z + (MU)

lilÀ4

PTC CORRECTION FACTORS

WITHCURVEFITS - Curve Fit tor .6.t. 1:1'4

60.0

0.'

50.0

~ 40.0

30.0

20.0

-d

10.0

-10

-20

-30.0

Make~p Water Temperature. 0 F

115

::-...

-

\.\

\ -

\\..

5 '<0 '<5 r;o 5 E

'\10 15

- --

i

Perfonnanc:e Test Code Data Sheet

Parameter: CondenserCoormg~ Temp.DesignPoint 60 0 F

o.sign HRo.sïgn Power

7,966.0 Btu/kWh145,540.0 W/

Regression AnalysisOrder. 3rd

Regres.ion Results

6'saIntercePt

267i741432C1

-131.6835017

c:;1.579254079

C3-0.002805836

where:6'.. . Intefcept + C1 (CCT) + ~(CCT)2 + C3(CCT)3'

116

Cond. CooIing Net Plant Power ColT. Power Corr.

Temperature Power VariabIe Curve Fit"F W/ W/ W/

CCT .P'NR 1I6a l!:u.

50 145,850.0 -310.0 -312.02797253 145,830.0 -290.0 -286083916se 145,780.0 -240.0 -239.74359059 145,710.0 .170.0 :173:46153862 145,630.0 :sa.O .$7.69230865 145,520.0 20.0 17.10955768 145 400.0 140.0 140:48951071 145,260.0 280.0 281.99300774 145.100.0 440.0 441:16550177 144,920.0 620.0 617.55244880 144 730.0 810.0 810.699301

CCT CCT' CCT' 1I6a50 2500 125000 -310:00000o53 2809 148877 -290:00000ose 3136 175616 .240:00000o59 3481 205379 ':170.00000o62 3844 238328 -9O00000065 4225 274625 20.00000o68 4624 314432 140:00000o71 5041 357911 280.00000o74 5476 405224 440.00000o77 5929 456533 620:00000o80 6400 512000 810.00000o

PTC CORRECTION FACTORSWITH CURVE FITS

11 À5B

Curve Fit tor À5B.À'sa

1000.0

0.0

800.0

600.0

400.0

-IQ

.(j

200.0

.

-200.0

-400.0

Condenser Cooling Water Temperature, 0 f

117

CS Sample Calculation Data

The measured test data foT the sample calcula-tien is:

Ambient air temperatureRelative humidity

Ambient site pressure

Net power outputGross gas turbine power (for

checking)Gross steilm turbine power (for

checking)Plant auxiliary power (tor

checking)Transformer 1055(estimated)

Fuel consumption

Steam flow to process

Steam conditions to process

Condensate return flow

Feedwater make-up temperature

80°F (26.7°C)70%

13.8 psia (0.95 bara)125,910 kW

100,715 kW

29,329 kW

3,692 kW442 kW47,974 Ib/hr (6.04

kg/sj165,000 Ib/hr (20.8

kg/sj150 psig/373°F

(10.34 barg/189°C)123,750 Ib/hr (15.6

kg/sj70°F (21.1°C)

Cooling water inlet temperatureHRSG blowdown setting

70°F (21.1°C)

0 Ib/hr (0 kg/sj

Fuel sample analysis shows fuel to have 21,496Btu/lb (50,000 kj/kg) LHV and 23,839 Btu/lb (55450

kj/kg) HHV. For reference, fue! energy consumedand heat rate value cao be multiplied by the HHV /LHV ration and the correction factor using the above

equation to convert to HHV values associated withthe test conditions. Finally, using the values fromthe sample test data above, the resulting additiveand multiplicative correction values are calculatedbased on the curve fit equations presented previouslyin the data sheets. These correction values are theninserted into the appropriate equations to correctthe power and the heat rate to the design values.The boundary value inputs, the resulting correctionvalues, the corrected power, the corrected heat rate,and the variance of the corrected power and heatrate from the design point are all presented in the

spreadsheet below.

118

PTC PERFORMANCE TEST SPREADSHEET

Equation tor Corrected Net Plant PowerPTC Section 5

p- =(P- + IS, + 6'3 + IS. + 6'sa) a', a'2a'3

Equation tor Corrected Net Plant Heat RatePTC Section 5

HR- = 0_(r,r2f3f5)(P- + 6', + 6'3 + 6'. + 6'sa)

Design Plant Power:Design Plant Heat ~e:

145,540.0 WI7,966.0 Btu/Wlh

119

Boundarv Value InDuts (measured) Units ValueAmbientTemoerature oF 80.0AmbientPressure DSia 13.800AmbientRelativeHumiditv % 70.0Steam Sales Flow Iblhr 165,000Blowdown Flow Iblhr 0.0Make-UDWater Temoerature oF 70.0Condenser CoolinaWater Temperature oF 70.0Measured Net Plant Power: INJ 125,910Measured FueIFlow IbIhr 47,974Assumed FuellHV Value Btul1b 21,515FuelAnalvsis lHV Value Btul1b 21,496

Curve Fit Eauation Constants Curve Fit Eq.Power ConectJon Vatiables Intercept C, C2 ResuIt

a,' 0.943300812 -0.000332432 2.00891 E-05 3.59239E-08 1.063669

a2' 5.641320426 -0.687385781 0.034619369 -0.000635263 1.078791

a; 0.999346728 8.89891 E-06 5.42992E-08 -3.46311E-10 1.000117

IS, -11804.54545 0.072926185 5.51153E-08 -1.10507E-13 1232.377622

6'3 -432.5174825 0.028088538 2.15347E-O7 -5.47444E-12 -432.517483

IS. -144.5333679 12.65993266 -0.260942761 0.001510835 -18.741259

6'58 2674.741432 -131.6835017 1.579254079 -0.002805836 232.839506

Curve fit EQvation Constants Curve Fit Eq.Heat Rate ConectJon Variables Intercept C, Resuit

f,' 0.955794514 0.001705298 -1.96625E-05 4.90452E-08 0.991490

'2' 0.342759195 0.094852034 -O.00469a993 8.763O4E-05 0.987140

'3' 1.002281715 -3.83348E-05 5.78617E-09 -1.08789E-11 0.999623

f5' 0.00000o 0.99912 0.00000o 0.00000o 0.999117

Comacted OutDut Units VaJueCorrected Net Plant Power. INJ 145,659.4Corrected Net Plant Heat Rate: BtuIlNJh 7949.2Guarantee Net Plant Power IMf 145,540.0Guarantee Net Plant Heat Rate BtuI kWh 7966.0Net Plant PowerVariance: INJ 119.4Net Plant Heat Rate Variance: BtuI kWh -16.8

CG Discussion of Results

The corrected power and heat rate are better thandesign.

120

APPENDIX D - REPRESENTATIONOF CORRECTIONFOR DIFFERENT HEAT SINK TEMPERATURETHAN GAS

TURBINE AIR INLET TEMPERATURE(4.s or ldS) IFNECESSARY,FOR A TYPICAL COMBINED CYCLE PLANT


The calculation of Appendix A assumed that theinlet air conditions at the gas turbine(s) compressorinlet(s) were identical to those at the cooling tower(s)air inlet(s), which is allowable per Section 5. Seepara. 5.5.1.

For a combined cycle power plant, for whichdifferences in dry bulb temperatures at each locationshould be considered, Figs. 0.1 and 0.2 showtypical correction curves (Xi and ~5A, respectively.The intent is to show how ~5A can be represented.

Figure 0.1 is based on the temperature measuredat the inlet to the gas turbine compressor. Figure 0.2is the ~5A correction for the difference in temperaturebetween the compressor inlet and the coolingtower inlet.

The plant is a typicailSO MW combined cycle.Note that, at 59°F gas turbine compressor inlettemperature, the correction to plant power is approxi-mately 20 kW per degree difference between thegas turbine compressor inlet and the cooling towerinlet - a rather small amount considering the buiIt-in errors in measurement of cooling tower air inlet.

121

l'

tf

POWER CORRECTION - CT/COOL TWR W.B. TEMP DIFFNATURAL GAS OPERATION

APPLICABLE FOR: Natural Gas FuelGas Turbine Base Loaded

-1000-10 -8 -6 -4 -2 0 2 4 6 8

COOL. TWR W.B.- CT W.B.,WB (OF)

1000

-600

-800

iI..f

t10

FIG. 0.1 POWER CORRECTION - CT/COOL TWR W.B. TEMPERATUREOIFFERENCE

122

800

600

- 4003:-cc 200U)<Ia::"w 03:0Q.Cl: -200I-..JWQ

-400

LLLU- -LJ..Li-- LLLJ..J _LU_,L LL LLLJ_,.JL1. i

t I1-- --. ,;

I-.--

59 oF CT Dry Bulb Temperature-" _m ,..

--"-1-...... 35 oFCTDryBulbTemperature ,

'1-.-.-. 105 oFCTDryBulbTemperature .:''r- --- -.--.

i_". ;- - -'T -- -, -- -

,I I

. II

,: JI I -- -- - -- -. .-- -- -- -- - ,-- h...:

..I !I, : I

I

-Wo<

--...- - -..- ,- u --..-- -,--, - ,--II

i .J,..., I' 11-- -- - - .- - - ,- - - --

; -.Ou-

;;.10'... I :I I- II I

I- :, I;... i'" '. ,I.

i,II I ;" ' ,-

+-i-! i 1--" , I!I

.. I

i

- , --.., lor' ._"hl

-- -, --,--. 'h _u, -- --- ---1---'T" i -'-j- -

-, I

---f-- --, - .. - --

-I-.- -- - - -- , .. - i - -- - _u,

! ! ,i;

-Ii __.L -u--

i-t- ,T-

" - - - u, -- - - -, -- u -hI I i

POWER CORRECTION - AMBIENT TEMPERATURENATURAL GAS OPERATION

1.20

1.16

-;:- 1.12(:3-

a::0J-O 1.08<CU-

Z0-t; 1.04wa::a::00 <;1 .00

0.96

APPUCABLE FOR: Gas TurbineBase Loaded

Natural Gas Fuel

Ii ! I I! iI! I +- i i

I .! 'i, I ti-I T,' +---1--1

I '! I ' '! 11- II1 1 I i I '7 T

! I I ' I I i ' '

-1-+ 11: 111 T i' yr;-t,

I I I I I I /ll '

i I I 1 1 --'--, ,: 1 I i I

"

I! ,I 1/

I I T /'- ---L

i I I ' I

I !' i I IJ ' 'i ! I ! v; 1 I

I I : i1 ' /', 1 I I '

, / 1

i

I '

--t.- - '" .. - -'- i -+- - -. - - - /~ -- -- -- m_- .--- -'

j

-- -- i' /

,

-t,

' I

n

,

_- .,

_-n - I - ---f- I

-- +--+-i-cl [71--+- ~=I I I / I I

" I

i I / II /

I

, II /,: I,I I,I/! ' ! : ,-: IY I ' I I

, ,' YI

"

/:j' "I I

'I I.--

" ' " I ." I I

i' ' - ' 1,--; ,I I i I 1

I

I

1 ' i' I I I' I

1-- - ' I I

, I I I I :

// I I ! I I II

l7 ,I '/ I ! I

, ,-I I I

! I i ', iI 'I0.92

35 45 55 65 75 85 95 105

GAS TURBINE COMPRESSOR INLET AIR TEMP (OF)

FIG. D.2 POWER CORRECTION - AMBIENT TEMPERATURf

123

APPENDIX E - SAMPLE CALCULATIONSSTEAM POWER COGENERATION PLANT

HEAT SINK: RIVER COOLING WATER FLOW WITHINTEST BOUNDARY

TEST GOAL: TWO TEST RUNS ARE MADE WITHDIFfERENT GOALS

TESTRUN 1: SPEClflEDCORRECTEDPOWER - flRE)

TO DESIRED CORRECTED POWERTEST RUN 2: SPEClflED DISPOSITION BY FIRING TO

DESIRED THROTTLE FlOW (POWER FLOATS)


CYCLE DESCRIPTION

The PTC 46 Example Steam Plant is a simptenon-reheat condensing steam turbine-based plantwith three feedwater heaters and an uncontrolledextraction tor process steam. Process steam conden-sate is returned at low temperature to the plantwater treatment system. The steam generator is acirculating fluidized bed unit burning medium sulfureastern coat with sulfur emissions controlled bylimestone fed to the fluidized bed. The steam genera-tor is equipped with a tubular air heater to pre-heat bath primary and secondary air. The plant isequipped with a bag house to control particulateemissions. The condenser is cooled with circulatingwater drawn trom a river. Figure E.1 is a diagramof this plant.

Nominal throttle conditions tor the steam turbine

are 885.0 psig and 900.0°F (6203 kPa and 482.2°C).The steam turbine is rated tor continuous operationat 5% over pressure. The generator is rated at101.2 MW to enable turbine operation at nominalconditions with no extractions. Nominal steam gen-erator exit conditions are 931.0 psig, 903.00F (6520kPa and 483.9°C) and 800,000 Ib/hr (100.798 kgf

sec) steam flow. Maximum continuous rating of thesteam generator is 975.0 psig (6824 kPa), 910.0°F(487.8°C) and 840,000 Ib/hr (105.838 kg/sec). Mainsteam temperature to the steam turbine throttle iscontrolled by mixing spray flow with steam exitingthe steam generator.

TESTBOUNDARY DESCRIPTIONThe entire plant is located within the test boundary.

Air enters the steam generators at the forced draftfan inlet. Cooling water trom the river crosses theboundary. Net electrical power is delivered tromthe high side of the step-up transfarmer. Net powermeasurement is taken on the low side of the step-up transformer with allowance tor transformer losses.Gross steam turbine power is measured at the genera-tor terminals. Plant auxiliary power is calculatedtrom the diffenmce between the measured gross andnet power. Process steam is measured at the plantboundary with a calibrated flow measuring section.

There are two sets of sample calculations thatwil! be demonstrated with this example system. Thefirst one, Test 1, is tor unit heat rate at specifiedcorrected net output. (13,115 Btu/kWh (13,837 kJ/kWh) at 83,500 kW net corrected output at the

125

TABlE E.1

ReferenceSI UnitsPlant Parameter

Ambient air temperatureRelative humidityRiver water temperatureSteam generator blowdownMakeup water temperature .

Process condensate temperatureProcess steam flow

Process steam pressureProcess steam temperatureProcess condensate return

Net plant outputNet plant heat fale

U.s. Customary Units

80.0°F60%75.0°F

1%75.0°F75.0°F

100,000 lh/hf150.0 psig350.0°F100%83.5 MW

13,115 Btu/kWh

26.7°C60%23.9°C

23.9°C23.9°C

12.5998 kg/sec1136 kPa

176.7°C

83.5 MW13,837 kJ/kWh

TABlE E.2

Conditional Auxiliary Power Budget

Coal unloadingAsh transferWater treatment

Air compressorHVAC

Lighting

Connected Load(kW)

300100430600300300

Duty Factor

0.1

0.2

0.7

0.5

0.5

0.6

Reference(kW)

3020301300150180

conditions listedbelow.}The second sample calcula-tion, Test 2, is tor the plant tested in a fixed disposi-tion; that is with the steam generator at maximumcontinuous rating of 840,000 lh/hf (105.838 kgfsec). The other reference conditions are listed inTable E.2. The net plant output and heat fale basereference conditions tor Test 2 are 88,000 kW and13,040 BW/kWh(13,758 kj/kWh).

Table E.2 gives an auxiliary power budget torequipment that is required to support continuousplant operation, but may not be operating at thelong term expected duty factor during the perform-ance test. These auxiliaries are to be monitoredduring the test and corrected to reference tor pur-poses of comparing to guarantee.

The step-up transformer 1055is 0.99% of plant netoutput delivered to the low side of the transformer.Atthe reference condition of 83500 kW net plantoutput (high tension side) the transformer 1055is835 kW.

The reference coal and sorbent analysis and as-tested analysis is given in Table E.3: Forconveniencein demonstrating the sample calculation and correc-

tion procedure, it wiJl be assumed that the steamgenerator as-tested coal analysis, sorbent analysisand residue split and residue analysis are the sametor each test run.

TEST1 SAMPLECALCULATIONsThetest strategyto demonstrate plant performance

at the base reference condition of 83,500 kW cor-rected is to perform three test runs thai span theguarantee condition. The corrected heat fale fromthese test runs is plotted versus corrected output orcurve fit with and the test corrected heat fale readoft the curve entered at the reference correctedoutput.

The correction procedure is designed to fit theabove strategy in plant performance determination.The correction procedure produces a corrected plantoperating Ijne of heat rate versus output at theplant base reference conditions; thai is the correctedoperating Hne characterizes plant performance atreference conditions of 100,000 lh/hf (12.5998 kgfsec) of process steam, 1% boiler blowdown, 0.85power factor, 80.0°F (26.7°C) ambient temperatureand 75.0°F (23.9°C) river water temperature while

126

TABlE E.3

Coal Ultimate AnalysisReference As Tested

70.91%1.23%4.40%7.3%1.34%4.61%

10.23%12,561 (29,217)

CarbonSulfur

HydrogenMoisture

NitrogenOxygenAsh

Higher healing value, Btu/lb (kj/kg)

Sorbent Analysis

69.7%1.49%4.31%5.43%1.38%4.05%

13.64%12,310 (28,633)

Reference As Tested

CaCOjCa(OHhMgCOj

Coal Ultimate Analysis

95%0%4%

94%0%4.2%

Reference As Tested

Mg(OHhH2OInerts

0%0.03%0.97%

0%0.03%1.77%

burning the reference coat and utilizing the referencesorbent.

The following correction curves are required tocorrect plant performance:

. Fig E-2,Output Correction tor ProcessSteamFlow

. Fig E-3,Output Correction tor Power Factor

. Fig E-4,Output Correction tor Blowdown Flow

. Fig.E-5,Output Correctiontor Cooling WaterTem-perature

. Fig E-6,Heat Consumption Correction tor ProcessSteamFlow

. Fig E.7, Heat Consumption Correction tor Blow-down Flow

The as-tested andcorrected steam generator fuelenergy efficiency is to be calculated according toPTC 4 using the energy balance method. The cor-rected energy supplied by the steam generator tothe werking fluid is divided by corrected efficiencyto determine the corrected tue! energy input.

Table E.4 summarizes the averaged measured dataof the th ree test runs.

Corrected OutputCorrected output tor each test run is calculated

using Eq. 5.3.3, repeated below. Terms in the equa-tion are described in Section 5 of this Code.

Pcorr = (Pmeas + .:11 + .:12 + i .:17)

A summary of the corrections tor the test runs isgiven in Table E.5.

The Lll term (output additive correction tor thermalefflux) is found by entering Fig. E.2 at process steamflow and determining the percentage difference inoutput. The percentage difference in output ismultiplied by the measured gross output to give thevalue of Ll1 in kW.

The Llz term (output additive correction tor powerfactor) is found by entering Fig. E.3 at the as-tested power factor and reading off the percentagedifference in output. The percentage difference inoutput is multiplied by the as-tested gross output togive the value of Llz.

The Ll3 term (output additive correction tor blow-down) is found by entering Fig. E.4 at the as-testedpercent blowdown and reading off the percentagedifference in output. The percentage difference inoutput is multiplied by the as-measured gross outputto give the value of Ll3'

The LlSBterm (output additive correction tor cool-ing water temperature) is found by entering Fig. E.5at the as-tested coating water temperature and steamturbine throttle flow and reading off the percentagedifference in output. The percentage difference in

127

TABlE E.4

Test Run 18 Test Run 1CTest Run 1A

Turbine generator gross output, kWPower factor

Net plant output, kW (low side SU trans)Feedwater flow, Ib/hr (kg/sec)Feedwater enthalpy, 8tu/lb (kj/kg)Steam generator blowdown, %810wdown enthalpy, Btu/lb (kj/kg)Main steam flow, Ib/hr (kg/sec)Main steam enthalpy, SG exit Btu/lb (kj/kg)Ambient temperature, OF(OC)River w<!tertemperature, oF (OC)Process steam flow, Ib/hr (kg/sec)

92,2770.95

83,540786,290 (99.0709)

256.3 (596.2)0.80%

538.1 (1,252)780,000 (98,2784)

1,452.16 (3,777.72)70.0 (21.1)65.0 (18.3)

90,000 (11.340)

93,6130.94

84,526803,823 (101.280)

257.1 (598.0)0.006

538.1 (1,252)799,000 (100.672)

1,452.16 (3,377.72)74.0 (23.3)6a.o (20.0)

102,000 (12.8518)

94,6200.9

85,391

817,356 (102.985)257.9 (599.9)

0.009

538.1 (1,252)

810,000 (102.058)

1,452.16 (3,377.72)80.0 (26.7)70.0 (21.1)

105,000 (13.2298)

Conditional Auxiliary Power Usage (kW), Test Run Averages

Coal unloadingAsh transferWater treatment

Air compressorHVAC

Lighting

080

200200

5010

Total 540

TABlE E.S

Output Corrections, kW

Al, Process steam

A2, Power factor

A3, Blowdown

Ase, Cooling water temperatureAb, Conditiona) auxili<!ry power correction

Step up tr<!nsformerNet corrected output, kW

output is multiplied by the as-measured gross outputto give the value of ÀSB'

The À6 term is determined by subtracting the as-tested power usage of the conditional auxiliariestrom the conditional auxiliary budget allowance.

Corrected Fuel Energy Input and CorrectedHeat Rate

The corrected fuel energy (Qcorr) is calculatedaccording to the numerator of eq. 5.3.4, where

Qcorr = Qmeas + ûll + ûl3 + ûl7

Qmeas is the steam generator tested output (Qro)

as defined in PTC 4, including blowdown energy,divided by corrected fuel energy efficiency calcu-lated per PTC 4. Qmeas in this sense represents the

30010

300100

70120

3020

0600200200

900 1050

Test lA Test 18

144.1-172.9

23.2-77.3-81

-836.883525.3

Test lC

-530.1-187.6

11.7-87.2

-441-827

81478.8

256.0-100.5

6.3-74.8

69-845.4

84701.6

test fuel energy consumption corrected to referencefuel and reference ambient temperature tor the steamgenerator. The terms w" W3, and W7 correct thefuel energy consumed to reference thermal efflux,reference blowdown and reference operating condi-tions if required. The w terms are described in Table5.1 in Section 5 of this Code.

Using relationships and terms discussed above,

Qmeas = Qro/17fuel correcled

where

Qro= steam generator tested output as de-fined in PTC 4, including blowdownenergy

128

t

)

~,i!,,I

f~I,I

(t)

i

TABLEE.G

Test Run 1B Test Run.1CTest Run lA

956.18 (1008.83) 969.36 (1022.7~)

As-tested heat added to water-steam, 10&Btu/hr (10&kJ/h) 934.52 (985.97)

WI, Process steam, 10& Btu/hr (10& kJ/h)

W], Blowdown, 10& Btu/hr (10& kJ/h)

Corrected heat added by steam generator,10& Btu/hr (10& kJ/h)

0.526 (0.555)

0.021 (0.022)

935.07 (986.55) 956.87 (1009.56) 969.25 (1022.62)

17fuelcorrected= steam generator corrected fuel energyefficiency calculated per PTC 4

The {.r}terms in this sample calculations procedureare based on a steam generator base referenceefficiency of 100%. The {.r}corrections terms usedhere need to be multiplied by the ratio of referencesteam generator efficiency to corrected steam genera-tor fuel energy efficiency, i.e., 1/ 17fuelCorrected.

For this example correction calculation the numer-ator of Eq. 5.3.4 can be expressed as

Q - (Qro + (.r)1+ (.r)3+ "'7)con -17iuel eorrecred

Corrected heat rare is calculated trom Eq. 5.3.4

HR - (Qmeas+ (.r)1+ (.r)3+ "'7) - Qeoneorr- (Pmeas+ 6.1+ 6.3+ f 6.7) - Peorr

The as-tested energy added to the steam-water bythe steam generator (steam generator output) is equalto the main steam flow times the enthalpy at steamgenerator exit plus the blowdown flow times theenthalpy of saturated water at steam generator drumpressure less feedwater flow times feedwater en-thalpy. The values tor the three test runs and thecorrections are given in Table E.G.

The {.r}1term (heat added by steam generatoradditive correction tor thermalefflux) is found byentering Fig. E.6 at process steam flow and determin-ing the percentage difference in energy added. Thepercentage difference in energy added is multipliedby the as-tested heat added by the steam generatorto give the value of {.r}1in 106 Btu/hr.

The {.r}3term (heat added by steam generatoradditive correct ion tor blowdown) is found by enter-ing Fig. E.7 at the as-tested percent blowdown andreading off the percentage difference in energyadded. The percentage difference in energy added

~

-0.180 (-0.19)0.864 (0.912)

-0.300 (-0.32)0.193 (0.203)

is multiplied by the as-tested heat added by thesteam generator to give the value of {.r}3in 106 Btu/hr.

The design air split between primary and second-ary air heater is 50% to each.

The as-tested measured parameters and analysisinformation is entered in the appropriate inputs ofthe PTC 4 spreadsheet. The as-tested steam generatorfuel energy efficiency is calculated as 87.27%. (ThePTC 4 calculations we re modified to include blow-down steam energy as an output trom the steamgenerator 50 that the modified steam generator outputcan be divided by fuel energy efficiency to determinefuel energy input.) The inputs and results tor theas-tested steam generator efficiency are given inpages 130-132.

The ground rules tor determining corrected steamgenerator efficiency must be agreed to by the partjesto the test. For this test, since the coal and limestoneanalysis was not far trom design, it was agreed thatcorrected steam generator efficiency be determined.trom PTC 4 calculations using:

. referencecoalanalysis

. reference sorbent analysis

. as-testedpercent excess air

. as-testedcalcium/sulfurmolarratio .

. as-testedfan temperature rise for primaryair, sec-ondary air, and blower

. as-testedpercent carbon hum-up

. as-testedash spiit

. as-testedbed and baghouse COz percentage

. as-tested primary and secondary air heater effec~tiveness

. as-testedsulfurcapture

In addition to the as-tested fuel energy efficiency,the as-tested parameters in Table E.7 were deter-mined. They are to be used in translating the as-tested results to corrected results.

129

_/

TABlE E.7

Percent excess airPercent carbon bum-upCalcium-sulfur molar ratioCalcination fraction of sorbentAir heater effectiveness

PrimarySecondary

Fan temperature rise tor primary andsecondary airPrimarySecondary

21.92%97.81%

2.878.92

48.23%51.84%

24.0°F (13.3°C)

20.0°F (11 .1 °C)

TABlE E.8

Ambient temperatureAir heater primary air inter temperatureAir heater secondary air inter temperatureAir heater fluegas inlet temperature

Primary air heater flue gas exittemperature

Secondary air heater flue gas exittemperature

70.0°F (21.1 °C)

94.0°F (34.4°C)

90.0°F (32.2°C)559.3°F (292.9°C)

360.0°F (182.2°C)

316.0°F (157.8°C)

The as-tested ash split and ash analysis is asfollows:

Ash split Bed Ash 41.9%Baghouse Ash 58.1 %

Bed Ash 1%

Baghouse Ash 2%

Bed Ash 0%

Baghouse Ash 12.41 %Ambient temperature and airheater temperatures

are given in Table E.8. .

The as-tested primary air heater effectiveness(11p) is:

CO2 in

% Carbon in

559.3 - 360 x 100 = 42.83%TIp = 559.3 - 94

The as-tested secondary air heater effectiveness(11s) is:

559.3 - 316 =51.84Tls = 559.3 - 90

There was no leakage around the air heater. Theflue gas exit temperature from thè primary (TGPcorr)and secondary (TGScorr) air heaters, at referencecondition, is calculated as follows:

TGPeorr = 559.3 - lriO . (559.3 - 104)= 364.3°F (184.6°C)

TGSeorr= 559.3 - 1~~ . (559.3 - 100)= 321.2°F (160.7°C)

Since the as-tested flow split between the primaryand secondary was 50~50, the corrected flue gasexit temperature (TGcorr)is the average of the primaryand secondary air heater flue gas exit temperature.

TGeorr = 342.BoF (l72.7°C)

The appropriate inputs are made to the PTC 4spreadsheet and corrected steam generator efficiencyis calculated to be 87.37%. The inputs and outputsof the PTC 4 spreadsheet are given on page 00-00. The corrected heat added by the steam generatoris divided by the corrected efficiency divided by100 and the resulting fue! energy use of each testrun is given in Table E.9. The corrected output andcorrected heat rate results of each test run are alsogiven.

Corrected heat rate is plotted in Fig. E.8. Thecorrected heat rate at 83,500 kW corrected, per Fig.L8 is 13,112 Btu/kWh (13,834 kj/kWh).

TESTRUN 2, OEFINEODISPOSITION TESTSample Ca/culations

The purpose of this test is to determine net plàntoutput and heat rate at a defined disposition - inthis case at steam generator MCR output of 840,000lh/hf (105.838 kg/sj steam.

The reference condition is given in Table E.10.It is required that this test be run at over-pressure

rating of the steam turbine to pass the throttle flowat a throttle valve position that wilt still give goodregulation. The correction curves presented foT Test1 are not valid since this test is run at over-pressure.However, tor this example, the curves will be usedhere to demonstrate the correction required. Also,additional correction curves are required in thisinstance since it may not be possible to conductthe test at the exact steam generator steam flow,pressure, and temperature conditions of reference.The additional correction curves required would bethose that correct tor steam generator exit conditionsdifferent trom reference, namely correction tor steamflow, pressure, and temperatures different trom refer-ence. These correction curves are given in Figs. E.ethrough E.14. These correction curves would only

130

)TABLE E.9

Test Run lCTest Run lA Test Run 18

Corrected fuel energy, 106 Btu/hr (106 kj/hl

Corrected output, kWCorrected heat rate, Btu/kWh

(kJ/kWh)

1,070.25 (1129.18)

81,478.813,135.3 (13,858.5)

1,095.19 (1155.49)

83,525.313,112.1 (13,834.1)

1,109.37 (11?0.45)

84,701.613,097.3 (13,818.4)

~

TABlE E.10TEST2 REFERENCECONDITIONS

Defined Disposition TestPlant Parameter Reference

Ambient air temperatureRelativehumidityRiver water temperatureSteam generator blowdownMakeup water temperatureProcess condensate temperature oF (OC)Process steam flow, Ib/hr (kg/s)Process steam pressure, psig' (kPa)Process steam temperature OF (OC)Process condensate return

Steam generator

Sieam flow Ib/hr (kg/s)Temperature oF (OC)Pressure psig (kPa)

Net plant output, kW

Net plant heat fale, Btu/kWh (kJ/kWh)

80.0°F (26.7°C)60%

75.0°F (23.9°C)1%

7S.00F (23.9°C)

75.0°F (23.9°C)

100,000 (12.5998)

150.0 (1,136)350.0°F (176.7°C)100%

840,000 (105.838)903.2°F (484.0°C)

975.0 (6,824)

88,00013,040 (13,758)

be u!ied tor smal! deviations trom the reference pointand upward corrections would not be taken if theunit could not demonstrate capability of achievingand maintaining thaI level of performance.

Table E.11 lists the as-tested average data.The conditional auxiliary power usage for this test

is given in Table E.12.Note thaI the as-tested steam generator exit pres-

sure, temperature, and flow were below the referencevalues. In this case, the unit had previously demon-strated its capability to achieve and/or maintain thedesired conditions. The local utility purchasing theplant power could not take enough output to loadthe plant higher. There was not enough time in thewindow of test opportunity to adjust the controlsettings to achieve the desired steam generator exitconditions, so the plant supplies and plant owneragreed to correct the steam generator test values toreference. The correction tor temperature and pres-

TABlE E.11Test 2

Turbine generator grossoutput (kW)Power fador

Net plant output (kW)Feedwaterflow, Ib/hr (kg/s)Feedwaterenthalpy, Btu/lb (kj/kg)Steamgeneratorexit flow, Ib/hr (kg/s)Pressurepsig (kPa)TemperatureOF(OC)EnthalpyBtu/lb (kJ/kg)SteamgeneratorblowdownBlowdown enthalpy Btu/lb (kJ/kg)Ambient temperature°F(OC)Riverwater temperature°F(OC)Processsteamflow Ib/hr (kg/s)

98,400.85

88,050846,465 (106.653)261.01 (607.11)

838,000 (105.586)972.5 (6807)902.0 (483.3)

1450.1913,373.14)1%

540.6 (1,257)80.0°F (OC)80.0°F (OC)

102,000 (12.8518)

TABlE E.12

Conditional Auxiliary Power UsageCoal unloadingAsh transferWater treatment

Air compressorHVAC

LightingTotal

kW30200

600200200

1050

sure would not normally be allowed according toSection 3 of this Code.

Corrected OutputCorrected output tor this test is calculated using

Eq. 5.3.3. Terms of the equation are described inTable 5.1.1 of this Code.

Peerr = (Pmeas + A1 + Al + f A7)

A summary of the corrections is given in TableE.13.

131

The corrections Al, Az, A3, AsB' and A6 are foundin the same manner as in Test 1. A7A'A7B'and A7ecome from correction curves Figs. E.9, E.11, andE.13, respectively.

The corrected steam energy supplied by the steamgenerator is computed as was done foT Test 1with additional corrections foTsteam generator flow,temperature, and pressure.

Corrected Fuel Energy Input and CorrectedHeat Rate

The eorrected fuel energy input is ealculated aswas done in Test 1, but with additional correctionsfoT steam generator flow pressure and temperature.

Again, following the development of the equationsto determineQcorr foTthe fiTsttest,

Q - Qro + CtJ, + CtJ3+ CtJ7A+ CtJ7B+ CtJ7Ceorr -

17fuel correeted

Qcorr

HRçorr = Peorr

Corrected heat fale is ealculated from Eq. 5.3.4:

HReorr = Qeorr/ Peorr

For purposes of this example, it is assumed thatthe corrected steam generator efficiency is as wascalculated for Test 1, namely 87.37%. The netcorrected plant heat consumption is then:

1002.19 = 1147.1 106 Btu/hr (1210.3 106 kJ/h).8737

The net corrected heat fale is then:

TABU E.13

Measured net plant output, kW

t1, process steam, kW

t12 power factor, kWt1] blowdown, kW

t1S8 cooling water temperature, kW

t16 conditional auxiliary power correction, kW

t17A steam generator steam flow, kWt178 steam generator steam exit temperature, kW

t17c steam generator steam exit pressure, kW

Step-up transformer, kW

Net corrected output, kW

88,050151

00

19769

3456927

-87188,037

TABU: E.14

As tested heat s\,!pplif;d by steam generator,106 Btu/hr (106 kJ/h)

"", process steam, Btu/hr (106 kJ/h)"'] blowdown, Btu/hr (106 kJ/h)

"'7A steam generator steam flow, Btu/hr (106kJ/h)

"'78 steam generator steam temperature, Btu/hr (106 kJ/h)

"'7C steam generator steam pressure, Btu/hr(106 kJ/h)

corrected heat added by steam generator, 106Btu/hr (106 kJ/h)

998.9 (1053.9)

-0.30 (-0.32)0

2.25 (2.37)

.57 (0.60)

.77 (0.81)

1002.19 (1057.37)

1147.1 X 106 Btu/hr88037 kW

= 13,030 Btu/kWh (13,747 kj/kWh)

The values foT this test run and the correctionsare given in Table E.14.

The terms W7A,W7B,and W7Cwe re determinedfrom correction curves, Figs. E.10, E.12, and E.14,respectively.

132

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INPUT DATA SHEET 1

147

COMBUSTION CAlCULATIONS - FORM CMBSTNa1 HHV- Higher Heating Value of Fuel, Btu/lbm as fired 12561.0

4 a. Measured Fuel Flow 85.0

6 FuelEfficiency, % (estimate initially) B7.27

8 Barometric Pressure, in Hg 29.9

9 Dry Bulb Temperature, F 70.0

10 Wet Bulb Temperature, F 0.0

11 Relative Humidity, % 67.0

15 Gas Temp Lvg AH, F Primary/Secondary or Main I 15B I 360.00 I 15A 316.00

16 Air Temp Ent AH, F Primary/Secondary or Main I 16B I 94.00 I 16A 90.00

20 Sorbent Rate, Klbm/hr 10.00

COMBUSTION CAlCULATIONS - FORM CMBSTNb30 Fuel Ultimate Analysis, % Mass

A Carbon 70.91

B Unburned Carbon in Ash 1.55

D Sulfur 1.23

E Hydrogen 4.40

F Moisture 7.30

G Moisture (Vapor tor gaseous tue!) 0.00

H Nitrogen 1.34

I Oxygen 4.61

J Ash 10.23

K Volatile Matter 0.00

50 Flue Gas 02, % Entering Air Heater 3.60

Leaving Air Heater 3.60

NAME OF PLANT PTC 46 Plant 1 UNIT NO.

TEST NO. Test lA DATE LaAD

TIME START: END CALC BY

DATE 4-28-95

SHEET OF

INPUT DATA SHEET 2

148

COMBUSTION CAlCUlATIONS - FORM CMBSTNc

83 Flue Gas TemperatureEnteringAir Heater, F 559.3

84 Air TemperatureLeavingAir Heater, F 379.2

UNBURNED CARBON & RESIDUE CAlCUlATIONS - FORM RES

5 ResidueMassFlow 18.2 Klbm/hr Split, %

A Furnace 0.0 41.9

B Economizer 0.0 0.0

C Bag House 0.0 58.1

D 0.0 0.0

E 0.0 0.0

6 Carbon in Residue,%

A Furnace 0.00

B Economizer 0.00

C Bag House12.41

D

E

7 Carbon Dioxide in Residue,%

A Furnace 1.04

B Economizer 0.00

C Bag House 2.10

D

E

24 Temperature of Residue,F

A Furnace 1540.0

B Economizer 336.0

C Bag House 336.0

p

E

-c-

NAME OF PLANT PTC 46 Plant 1 UNIT NO.


TIME START: END CALC BY

DATE 4-28-95

SHEET OF

JtIItII

~,

INPUT DATA SHEET3

149

SORBENT CALCULATION SHEETMEASURED C AND CO2 IN RESIDUE - FORM SRBa

7A 502 in Flue Gas, ppm 928 02 in Flue Gas at location where 502 is measured, % 3.609 502 & 02 Basis, Wet (0) or Dry [1] 1

20 Sorbent Products, % MassA CaC03 94.00B Ca(OH)2 0.00C MgC03 4.200 Mg(OH)2 0.00E H20 0.03F Inert 0.00

23A Calcination Fraction 0.93

SORBENT CALCULATION SHEETMEASURED C AND CO2 IN RESIDUE - FORM SRBb

II

SORBENTCALCULATIONSHEETEFFICIENCY- FORM SRBc

61 Sorbent Temperature,F 77.0I

EFFICIENCY CALCULATIONS DATA REQUIRED - FORM EFFa5 Gas Temperature Entering Hot Air Quality Control Eq\.!ipment, F 0.06 Gas Temperature Leaving Hot Air Quality Control Equipment, F 0.0

EFFICIENCY CAlCULATIONS - FORMEFFb55 ISurface Radiation and Convection, MKBtu/hr 6.4

EFFICIENCY CALCULATIONS OTHER lOSSES AND CREDITS - FORM EFFcLosses, %

85A CO in Flue Gas 0.00858 Pulverizer Rejects 0.0085C Air Infiltration 0.0085D Unburned Hydrogen in Flue Gas 0.0085E Unburned Hydrogen in Residue 0.0085F Unburned Hydrocarbons in Flue Gas 0.0085G

Losses, MKBtu/hr86A Wet Ash Pit 0.000868 Sensible Heat in Recycle Streams - Solid 0.00086C Sensible Heat in Recycle Streams - Gas 0.000860 Addilional Moisture 0.00086E Cooling Water 0.000

86f Air Preheat Coil (Supplied by Unit) 0.00086G Boiler Circulating Pumps 0.00086H

Credits, %87A I 0.00

Credits, MKBtu/hr88A Heat in Additional Moisture (External to Envelope) I 0.000NAME OF PLANT PTC 46 Plant 1 UNIT NO.TEST NO. Test 1A DATE LOAOTIME START: END CALC BY

DATE 4-28-1995SHEET OF

nt--~~Ji .

INPUT DATA SHEET4

150

W T PFLOW TEMPERATURE, PRESSURE

PARAMETER Klbm/hr F PSIG

1 FEEDWATER 786290 285.1 1100.0

2 SH SPRAYWATER 0 260.0 1180.0

3 EntSH-1 Attemp 0 0.0 0.0

4 Lvg SH-1 Attemp 0 0.0 0.0

6 EntSH-2 Attemp 0 0.0 0.0

7 Lvg SH-2 Attemp 0 0.0 0.0

.-INTERNAl EXTRACTION FlOWS

9 Blowdown 6290 947.0

10 SarSteilm Extraction 0 0.0

11 Sootblowing Steam 0 0.0 0.0

12 SH SteamExtraction 1 0 0.0 0.0

13 SH SteamExtraction 2 0 0.0 0.0

14

AUXILIARY EXTRACTION FlOWS

15 Aux Steam1 0 0.0 0.0

16 Aux Steam2 0 0.0 0.0

17

18 MAIN STEAM 903.0 931.0

REHEAT UNITS

20 REHEATOUTLET 0.0 0.0

;;!1 COW REHEATENT ATTEMPERATOR 0.0 0.0

22 RH SPRAYWATER 0 0.0 0.0

23 COLO REHEAT EXTRACTION 0

24 TURB SEALFlOW & SHAFT L 0

FW HEATER NO. 1

25 FW Entering 0 0.0 0.0

2ft FW LeilVinl! 0.0 0.0

27 Extraction Steam 0.0 0.0

28 Drain 0.0 0.0

FW HEATER NO. 2

30 FW Entering 0 0.0 0.0

31 FW Leaving 0.0 0.0

32 Extraction Steilm 0.0 0.0

33 Drilin 0.0 0.0

NAME OF PLANT PTC46 Plilnt UNIT NO.

TESTNO. Test lA LaAD

TIME START: END: CALC BY

DATE 4-28-95

SHEET OF

t

t

COMBUSTION CALCULATIONS

151

DATA REQUIRED1 HHV - Higher Healing Value of Fuel, Blu/lbm as fired 12561.0

2 uac - Unburned Carbon, Ibm/l 00 Ibm fuel trom RESor SRBb FaRM 1.55

3 Fuel Flow, Klbm/hr [4b] 85.24

4 a. Measured Fuel Flow 85.00

4 b. Calculated Fuel Flow 100,000 x [5]/[61/11) 85.24

5 OutPut, MKBtu/hr trom OUTPUT Item 137] 934.41

6 Fuel Efficiency, % (estimate inilially) 87.27

7 Moisture in air, Ibm/Ibm Dry Air 0.0105

8 Barometric Pressure, in Hg pw\ #VALUE! 29.92

9 Dry Bulb Temperature, F psw\ 0.3629 70.0

10 Wet Bulb Temperature, F psw\ 0.0000 0.0

11 Relative Humidity, % pw\ 0.2432 67.0

Additional Moisture (Measured) Klbm/hr

Atomizing Steam trom OUTPUT Item (15] 0.0

Sootblowing Steam trom OUTPUT Item [12] 0.0

Other 0.0

12 Summalion Additional Moisture 0.0

13 Additional Moislure, Ibm/100 Ibm Fuel 100 x (121/[3J 0.0

14 Additional Moisture, Ibm/lO KBtu [131/«(1)/100) 0.0

If Air Heater (Exel SIm/WIr Cai!) Enter following

15 Gas Temp Lvg AH, F Primary/Secondary or Main 15B I 360.00 15AI 316.00

16 Air Temp Ent AH, F Primary/Secondary or Main 16B I 94.00 16AI 90.00

Fuel Analysis,% Mass as fired - Enter in Col [30)

02 in Flue Gas, % Volume - Enler in Column [50] each location

19 Mass Ash, Ibm/] 0 KBtu 100 x (30J)/[1) 0.081

If mass of ash (llem [19)) exceeds 0.15 Ibm/10 KBtu or Sorbent

ulilized, EnterMass FraClionof Refusein Col [79)tor each location

SORBENT DATA (Enter 0 if Sorbent not Used)

20 Sorbent Rate, Klbm/hr 10.00

21 C02 trom Sorbent, Ibm/lOO Ibm Sorb trom SRBa Item [251] 40.63

22 H20 trom Sorbent, Ibm/l00 Ibm Sorb trom SRBa Item (261) 0.03

23 5ulfur Capture, Ibm/Ibm Sulfur trom SRBb Item (451 0.899

24 Spent Sorbent, Ibm/100 Ibm fuel fromSRBb Item [48] 9.72

25 Sorb/Fuel Ratio, Ibm Sorb/lbm Fuel (20]/[3] 0.117

NAME OF PLANT ASMEPTC 46 UNIT NO 1



DATE 4-28-95

SHEET 1 OF 8

COMBUSTION CAlCUlATIONSCOMBUSTION PRODUCTS

30 Ultimate 31 Theo Air F

Analysis Ibm/l 00 Ibm Fuel% Mass [30J x K

AB

CD

EF

GH

I

LK

l

M

C

uac

Cb

5H2

H20

H20vN2

02ASHVM

l1II Dry Prod FMol/lOO Ibm Fuel

[30]/K

~ Wet Prod FMol/100 Ibm Fuel

(30]/K70.91

1.551

69.36 11.5

4.3234.3

798.325.31

150.88

12.01

32.06

5.775

0.038

~ H20 FuelIbm/lOKB

[30)xK/([1]/100)

8.94

1.01.0

0.3130.058

0.000

TOTAl

1.23

4.40

7.300.00

1.344.61

10.23

0.00

2.016 2.183

18.016 0.40518.016 0.000

28.02 0.048

0.371

7.58

4.77

0.004

0.0345.978.56

936.9932.35

7.460.694

0.0 0.0

-4.3 -19.92

100.02 31 I 2.588134 T

0.02 0.02

934.60 I 32 T 5.861 [ 33 T

35 Total Theo Air fuel Check, Ib/10 KB I([31M] + [30B] x 11.51)/([1]/100)

404142

4344

CORRECTIONS FOK SORSENT REACTIONS AND SUlFUR CAPTURE

een trom Sorb, Ib/100 Ib tuel [21] x 125]H20 trom Sorb, Ib/100 tb tuel [22] x [25]502 Reduction, Mol/lOO Ib tuel [320] x [23]

Dry Prod Comt, Mol/100 Ib tuel [32MJ + [40]/44.01 - (42]Wet Prod Comt, Mol/100 Ib tuel [33M] + [41]/18.016 + [43]

4647

4849

Theo Air Corr, Ib/lOO Ib tue! [31M] + 2.16 x [300] x (23JTheo Air Corr, Mol/100 Ib tuel [46]/28.966Theo Air CQrr, Ib/l OKBtu [46]/((1 ]/1 00)

Wet Gas trom Fuel, Ib/lOKBtu (100 - [30j] - [30B) - [30DJ x [23])/([lJ/100)

.. LÖCATION

50

5152

02,% Below m = Measured 1 = LocationAH IN

3.60AH OUT3.60

0.000.00

0.000.000.00

0.00

0.000.000.000.00

53FLI,JEGAS ANM YS!S, M9J/l 00 Jb Fyel

Moisture in Air 0.02DJl..0

Wet(7] x 1.608 0.02

Dry/Wet ProduC1S Comb

Additional Moisture

0.00 0.00

54

55

56

57

58

Summation

[43)0

[44J

113]/18.016

8.56

0.00

25.57

34.13

17.29

8.56

0.00

26.12

34.67

17.29

1

8

60 Excess Air, %

NAME OF PLANT

TEST NO. Test lA

TIME START:

[74] x (0.7905 + [53])

[54J + 155] + [56]

20.95 - [50] x (1 + (53])

100 x 150] x [571/[47]/[58) 21.97 22.32

ASME PTC 46

DATE

END:

UNIT NO.

LOAD

CAlC BYDATE 4-28-95

SHEET 2 OF

152

GENERAL COMBUSTION CALCULATIONSlOCATION

60=:] Excess Air, %02, C02, 502 WHEN EXCESSAIR KNOWN

61

626364

65

AH IN21.97

AH OUT22.32 I 0.00

Dry [471 x (0.7905 + (601/100)Wet [47) x (0.7905 + 153] + (1 + (53]) x 160]/100)

Dry Gas, Mol/100 Ib Fuel 143) + 162]Wet Gas, Mol/100 Ib Fuel [441 + 163]

32.6833.3438'.6541.90

32.7933.4638.7642.01

3.6014.00

0.009

9.120.694

0.0380.0950.0000.0009.950.467

9.48

4.690.581

0.1710.010

0.266

338.0092.0063.63

3.640.2513

338.6

r=J]}~

UNIT NO.LOADCALC BY

DATE 4-28-95SHEET 3 OF

0.000.005.978.56

0.00

0.000.000

0.00

0.0000.0000.0000.0000.0000.000.0000.00

0.000.0000.0000.000

0.000 I

0.000.000.000.000.00000.0

Tü:Oro:o

0.00

0.00

0.005.978.56

0.000.000.000

0.00

0.0000.0000.0000.0000.0000.000.0000.00

0.000.0000.0000.000

0.000

0.000.000.000.000.00000.0

1070.785.20.00.0

22.31855424

987.2

8

666768

~164](64)[64]

3.55

14.040.009

Wet

(65](651165]

02, % 160] x 147] x 0.2095/C02, % ([30C)/1l201 + 140)/.440l)f502, % (1 - [23]) x 130DI/.32064/

FLUE GAS PRODUCTS, Ibm/l0 KBtuDry Air (1 + [60]/100) x 148JWet Gas trom Fuel 1491 .C02 trom Sorbent [40\/«(1)/100)Moisture in Air (7) x (69]Waterfrom Sorbent [41)/([1)/100)Additional Moisture 114]Tata 1Wet Gas [69) + [70) + [711 + [72] + [73] + [74)H20 in Wet Gas (34M)+ 1721+ 173) + (74)Dry Gas . [75J - [76]

69707172

7374757677

9.100.6940.038

0.0950.0000.0009.920.4669.46

787980

81

H20 in Wet Gas, % Mass 100 x (761/(751Residue, Ib/lb Total Retuse at each location

Residue, Ib/1 0 KBtu I([30J) + 12)+ [24])/([11/100)Residue in Wet Gas, Ib/lb Wet Gas (79] x 1801/175)

4.700.5810.1710.010

82 I-eilkage, % Gas Entering 100 x «(75LJ - (75E])/[75E] 0.000

8384

85868788

GAS TEMPERATURE CORRECT ION FOR INFILTRATION

Gas Temp Lvg UNCL LKG),F 115]Air Tem Ent, F [16)H Air Lv , But/Ibm T = 183]. H20 = (7]

H Air Ent, Btu/lbm T = [84]. H20 = [7]

C ,Btu/lbm F T = 183]. H20 = 178E]. RES = (81EI

Corrected AH Gas Oudet Temperature[831 + «(82)/1 00 x (185) - (86])/[87))

559.30379.20118.69

73.790.2540

559.3

909192

93

AIR, GAS, FUEL & RESIDUE MASS FLOW RAUS, Klbm/hrIn ut trom Fuel trom Efficienc Farm, Million Btu/hrFuelRate, Klb/hr 1000 x (901/[1]

ResiQue Rate, Klb/hr 180] x (901/10Wet Flue Gas, Klb/hr 175) x [901/10

~TlO62J

9596

Excess Air Lvg Blr, %

Total Air to Blr, Klbm/hr

As A licable trom (60]

(1 + [95)/100) x (1 + 17])x [48) x (901/10

NAME OF PLANT

TEST NO. Test lA

TIME START:

ASME PTC 46DATEEND:

153

lJNBlJRNED CARBON & RESIDUECALClJLATIONS

154

DATA REQUIRED FOR RESIDUE SPLIT

1 Ash in Fuel,% trom Form CMBSTNbI 10.23 21 HHV Fuel, Btu/lb 'as fired' 12561.0

3 Fuel Mass Flow Rate, Klbm/hr trom Form CMBSTNar 8S.24 41 trom Form CMBSTNa [1]

A Item (3) - Use measured or estimated value initially.(5ee CMBSTNa)Recillculateafter boiler efficiencyhas been calculated until estimatedvalue is within 1% of calculated value

B Residuesplits estimated- Entervalue in Col [8]pnd calculate Col [5)Residue rillemeasured- Entermeasuredmasstlowratesin Col(5].Whenresiduenotmeasuredat alilocations,estimatesplitpnd flow tor measured locations.Reiterateuntil estimatedtotal residue is within 2% ot calculated.

C Enterthe % tree carbon in Col [6] (total carbon correcter tor CO2). Unitswith sorbent - Enterthe % CO2 in Col [7].

W ResidueMass FloLU C W CO2 W ResidueSplit% [IJ C CO2

Location Input Calculated In Residue In Residue Input Calculated Md Ave % WTD Ave %Klbm/hr Klbm/hr % % 100x[SI/ISFI [6]x[8]/100 [7]x[8J!100

A Furnace 0.00 7.68 0.00 1.0 41.9 0.00 0.000 0.435

B Econ 0.00 0.00 0.00 0.0 0.0 0.00 0.000 0.000

C Ba House 0.00 10.66 12.41 2.1 58.1 0.00 7.214 1.221

0 0.00 0.00 0.00 0.0 0.0 0.00 0.000 0.000

E 0.00 0.00 0.00 0.0 0.0 0.00 0.000 0.000

F TOTAL 5 I 0.00 18.33 8 I 100.0 0.00 9 7.214 10 I 1.656

UNITS WITHOUT SORBENT

11 TUnburnedCaibon,--

Ibm/100 Ibm Fuel 1[1) x [9F]/(l00 - [9F]) 0.795

20 ITotal Resldue, Ibmll00 Ibm Fuel I (lJ + [l1J 11.03-.

UNITS WITH SORBENT0 Enteraverage C and CO2 in residue, (9F]& [lOF]above or SRBa(Items[4] & [5])and comolete Soment Calculation11 IUnburned Carbon, Ibml100 Ibm Fuel I trom Form 5RBb Item [491 1.551

20 Tot;ll Residue, Ibm/lOO Ibm Fuel I trom Form 5RBb Item [50] 21.50..

21 TotillResidue, Klbm/hr r (20) x [3)/100 18.33

EWhen all residuecollection locationsare measuredresidue sflit is used tor calculations. If a portion of the residue mass isestimated, recept calculation above until Col [SF] & Item [21 agree within 2%.

22 Tot;ll Residue, Ibm/10KBtu 100 x [201/[2] 0.171

23 SENSIBLEHEATRESIDUE LOSS, %

Temp [8] x [22) Residue 11000 Loss

Location Residue % Ibm/10KBtu Btu/lbm %A Furnace 1540 41.87 x 0.171 x 388.12 /10000 0.278

B Econ 336.0 0.00 x 0.171 x 52.04 11OOÓO 0.000C BaRHouse 336.0 58.13 x 0.171 x 52.04 110000 0.0520

--0.0 - 12.950.00 x 0.171 x 110000 0.000

E 0.0 0.00 x 0.171 x -12.95 110000 0.000. Totall 25 0.330

.

H residue = 0.16 x T + 1.09E-4 x TA2- 2.843E-8 x TA3- 12.95

. -

NAMEOF PLANT ASMEPTC 46 UNIT NO.TEST NO. Test lA DATE LOADTIME START: END: CALC BY

DATE 4-28-95

SHEET 4 OF

~

SORBENT CALCULATION SHEETMEASURED C AND CO2 IN RESIDUE

155

DATAREQUIRED1 Fuel Rate, Klbm/hr trom CMBSTN . 85.24 4 Carbon in Residue, c trom Form RES [9F] 7.212 Sorbent Rate, Klbm/from CMBSTNa 12] 10;00 5 C02 in Residue, trom Form RES[lOF! 1.663 Sorb/Fuel Ratio [2)/11) + 0.117 6 Moisture in Air, lh/lh Dry trom CMBSTNa [7J 0.0107 S02 Flue Gas, ppm 7A I 92.0 [7A)/10,000 % PB 0.0098 02 Flue Gas @ Loc 502 % 3.6 9 IS02 & 02 Basis Wet (1) or Dry (0) 1

10 Additiona! Moisture, Ibll 00 Ib Fuel (CMBSTNa, Item [13]) 0.00

Item (1) - Use measured or estimated value initially. Recalculate after boiler efficiency has been calculated untilestimated value is within 1% of cale.Enter fuel analysis in Col [1S]Enter sorbent ",nalysis in Col (20). Estimate Unburned Carbon [15BI. anc Calcination (23A) initially.Reiterate until estimated value is within 2% of calculated value.

+ Items thaI must be recalculated tor each iteration.COMBUSTION PRODUCTS

Ultimate Analysis J TheoAirF ]2J DryProdF -.!!J Wet Prod F% Mass Ibm/100 Ibm Fuel Moill 00 Ibm Fuel Mol/lOOIbm Fuel

trom CMBSTNb [30! [15] x K . (15]/K . [15J!KA C 70.91B UBC . 1.551C Cb + 69.36 11.51 + 798.3 12.01 + 5.78D S 1.23 4.32 5.3 32.064 0.04E H2 ,4.40 34.29 150.9 2.016 2.183F H20 7.30 18.02 0.405G H20v 0.00 18.02 0.000H N2 1.34 28.016 0.05I 02 4.61 -4.32 (-) -19.9

J ASH 10.23KLM TOTAL 170.93 16 I + 934.6 17 + 5.86 18 2.588

SORBENT PRODUCTSCaEJ C02 H20

Mol/lOO Ib Calcination Ib/1001b Sorb Ib/100lb Sorb% Mass MW [20]/(21) Fraction MW [22] x[231 x [241 [22] x (23J x [24J

A CaC03 94.00 100.09 0.939 . 0.930 44.01 + 38.44B. Ca{OH)2 0.00 74.096. 0.000 1.0 18.016 0.00C MC03 4.20 84.321 1.0 44.01 2.19D Mg{OH)2 0.00 58.328 1.0 18.016 0.00.E H20 0.03 18.016 1.0 18.016 0.03F INERT 0.00

G .

HI TOTAL Ca, Mol/lOO Ib Sorb 0.939 TOTAl + 40.63 0.03

NAME OF PLANT UNIT NO.TEST NO. Test lA DATE LOADTIME START: END: CALC BY

DATE 4-28-95

SHEET OF

SORBENT CAlCUlA TION SHEETMEASUREDC AND CO2 IN RESIDUE

SUlFUR CAPTURE BASED ON GAS ANAl YSIS

Select Column per Item [9]30 Moisture in Air Mols/Mol DA

31 Additional Moisture

3~ Products Combustion Fuel33 H20 Sorb (3] x [26IJ/18.01634 C02 Sorb [3] x 1251)/44.0135 (0.7905 + [30]) x [16MJ/28.96636 Summation [31] thru.[35]

37 1.0 - (1.0 + [30]) x [8]/20.9538 (0.7905 + [30]) x 2.387 - 1.039 [7B] x [36]/1170J/[37]40 [38J x [7B]/[371

Dry Wet

[6] x 1.608[10]/18.016

[17M] + [18M]Cale

+

0.00.0

117M]0.0

+++

+

45 ISulfur Capture. Ib/lb SLllfur 1+(100 - [39])/(100 + [40])

UNBURNED CARBON, CALCINATION AND OTHER SORBENT/RESIDUE CAlCULATIONS47 S03 Formed. Ib/IOO Ib Fuel [45] x [170] x 80.064 +48 Spent Sorbenl. Ib/1O0 Ib Fuel [47] + (100 - [251) - [261])x [3] +49 Unburned Carbon. Ib/1O0 Ib Fuel ([48J + [15J]) x [4]/(100 - [4]) +50 ResidLle R.:tte. Ib/100 Ib Fuel [49J + [48] + [15)] +51 Caleination. Ib/lb CaC03 1 - [Solx [SJ x 0.0227mOA]/[3] +52 Ca/S Molar Ratio, Mols Ca/Mol S [3J x [221)x 32.064/[150]

Compare the following, reiterate if initial estimate not within 2% caleulated

00.0170.000

8.4490.0000.108

26.04934.606

0.825

0.92710.0570.010

0.899

2.7629.723

1.55121.505

0.927

2.872

Unburned Carbon,Calein~tion,

[15B][23AJ

Initial Est Caleulated

1.551 [491 1.5510.930 [51] 0.927

Ib/100 tb FLlel

Mols C02/Mol CaC03

Enter result of Item 150J on Form RES, Item [20J.

If residue mass now rate not measured at aillocations, recalculale.

RES and SRBa & SRBb until convergence on refuse rate of 2%.

NAME OF P'LANT

TEST NO. Test lA

TIME START:

OÀtEEND:

UNITNO.LaADCALCBYDATESHEET

156

4-28-95

OF

)SORBENT CAlCULATION SHEET

EFFICIENCY

157

DATA REQUIRED60 ReferenceTemperature,F 77.0 60A EnthalpyWater (32 F Ref) 4561 5orbent Temperature,F 77.0 61A EnthalpySorbent (77 F Ref) 0.0062 Ave Exit Gas Temp (ExciLkg) 338.6 62A EnthalpySteam @ 1 PSlA 1213.3363 HHV Fuel, Btu/lbm 'as fired' 12561.0

lOSSES MKBtu/hrWater trom Sorbent [2] x [261]x ([62A]- [60A])/1O0000

x x ( - )/100000 0.035

Calcination/Dehydration71 CaCO3 [20AI x [nA] x [2J x 0.0077 = 94.00 x 0.93 x 10.00 x 0.00766 6.69672 Ca(OH) [20B] x 1.0 x [2] x 0.0064 = 0.00 x 1.0 x 10.00 x 0.00636 0.00073 MgCO3 [20C] x 1.0 x [2] x 0.0065 = 4.20 x 1.0 x 10.00 x 0.00652 0.27474 Mg(OH) [200] x 1.0 x [2] x 0.0063 = 0.00 x 1.0 x 10.00 x 0.00625 0.000757677 Summation of Losses Due to Calcination/Dehydration SUM [71]-[76] 6.970

CREDITS, %Sulfation 6733 x [451 x [150)/[63]

6733 x x 1 0.593.

CREDITS, MKBtu/hrSensible Heat trom Sorbent [2] x [61A]/1000

x /1000 0.000

Enthalpy of Limestone See text tor other sorbentsHCACO3 = (61] x (0.179 + 0.1128E-3 x (61]) - 14.45 .

x (0.179 + 0.1128E-3 x ) - 14.45 0.002[61A) = (1 - [20E]/100)x HCACO3 + (20E] x ([61) - 77)/100

=(1- /100) x + x ( - 77)/100 0.002

NAME OF PLANT UNIT NO.TESTNO. Test lA DATE WADTIME START: END: CALC BY


EFFICIENCY CALCULA TIONSDATA REQUIRED

.~

I1"

158

TEMPERATURES, F11 ReferenceTemperature 77 lA I-EnthalpyWater (32 F Ref) 45

Ave EnteringAir Temp 92.0 2A IEnthalpy Dry Air 3.60trom CMBSTNa Item ([16A] + [16B))/2 28 IEnthalpyWater Vapor 6.69

-2J Ave Exit Gas T (Exel Lkg) 338.6 3A Enthalpy Dry Gas 62.69

trom CM8STNa Item ([ISA] + [158))/2 38 Enthalpy Steam@ 1 PSlA 1213.333C EnthalpyWater Vapor 119.86

4 Fuel Temperature 77.0 4A IEnthalpy Fuel 0.01

HOT AIR QUALITY ÇONTROl EQUIPMENT5 EnterinJ1,Gas Temperature 0.0 SA EnthalpyWet Gas 0.00

-.!.J Leaving Gas Temperature 0.0 GA Enthalpyof Wet Gas 0.0068 Enthalpyof Wet Air 0.006C Enthalpyof Wet Air @T = [3) 0.00

RESULTS FROM COMBUSTION CALCULATION FORM CMBSTN10 Dry Gas WeiJ1,ht 177J 9.46 18 Unburned Carbon, % [2) 1.55111 Dry Air Weight [691 9.10 19 HHV Btu/lbm 'as.fired' [1) 12561.012 Water from H2 Fuel 134EI 0.313 HOT AQC EQUIPMENT13 Water trom H20 Fuel [34F] 0.058 20 Wet Gas EmerinJ1, (75E] 0.00

14 Water trom H2Ov Fuel [34G) 0.000 21 H20 in Wet Gas, % [76E] 0.0015 Moisture in Air Ib/lb DA [7) 0.010 22 Wet Gas LeavinJ1, [75L) 0.0016 Moisture in Air Ib/10K8 [72) 0.095 23 Refuse in Wet Gas, % [81E) 0.0017 Fuel Rate Est.Klb/hr [3] 85.00

MISCELLANEOUS30 Unit Output, MKBtu/hr 934.41 31 Aux Equip Power, MK8tu/hr 1.0

32 FeedwaterTemperature, F 0.00 32A Enthalpy Feedwater,Btu/lbm 0.033 Feeciwater Pressure, psiJ1, 0.00 34 DrIJm Pressure, psiJ1, 0.0035 Blowdown Flow, Klb/hr 0.00 35A Enthalpy Blowdown, Btu/lbm 0.0036 SB Stm Flow (Unit), Klb/hr 0.00

NAME OF PLANT ASME PTC 46 UNIT NO.TESTNO. DATE LOADTIME START: END: CALC BY

DATESHEET 5 OF 8

159

"'.

LOSSES, % Enter Calculated Result in % Column A I MKB B I %

40 IDry Gas [10) x [3A) /100x /100 5.930

41 IWater trom H20 Fuel [12J x ([3B] - [lA))/lOOx ( - 45) /100 3.658

42 IWater trom H20 Fuel [13J x ([3B] - [lA])/lOOx ( - 45 )/100 0.679

43 IWater trom H20v Fuel 1141x ([Je)) /100x /100 0.000

44 IMoisture in Air [16) x [Je) /100x /100 0.114

45 Unburned Carbon in Ref (18) x 14500/[19] = x 14500/ 1.791

46 Sensible Heat of Refuse - trom Form RES 0.33047 Hot AQC Equip ([20] x (lSA] - 16A)) - (122] - 120)) x ([6B) - [GC)))/100

( x ( - ) - ( -= ) x ( - ))/100 0.0048 lOther Losses,% Basis - trom Ferm EFFeItem 185] 0.0054 ISumation of Losses.% Basis 12.501

LOSSES, MKBtu/hr Enter in MKB.Column [A]55 SurfaeeRadiation and Convection 6.40056575'8 Sorbent Calcination/Dehydration - trom Ferm SRBe Item 177] 6.97059 Water trom Sorbent - trom Ferm SRBe Item (65] 0.03560 Other Losses,MKBtu/hr Basis - trom Ferm EFFeItem 186] 0.00062 Summation of Losses,MKBtu/hr Basis 13.405

CREDITS, % Enter Calculation Result in % Column [B]

EnteringDry Air [11] x [2A) /100x /100 0.328

Moisture in Air [161x [2B] /100x /100 0.006

SensibleHeat in Fuel 100 x 14AI /[19)100 x / 0.000

66 Sulfation - trom Form SRBeItem [80J 0.59367 OtherCredits,% Basis - trom Form EFFeItem 187J 0.00071 Summationof Credits,% Basis 0.927

CREDITS, MKBtu/hr Enter Caleulated Result in MKB Column [A]72 Auxili,uy Equipment Power [31J 1.020

73 Sensible Heat trom Sorbent - trom Ferm SRBeItem [/351 0.00074 Other Credits, MKBtu/hr Basis - trom Form EFFeItem [88J 0.0075 Summation of Credits, MKBtu/hr Basis 1.020

Fuel Eff,% (100- [54] + [71)) x [30]/([301 + [62] -175))(100- + )x /( - + ) 87.27

81 IInput trom Fuel,MKB 100 x [30)/(80J = 100 x / 1070.7

82 IFuel Rate, Klbm/hr 1000 x [/31I/(19J = 1000 x / /35.24

NAME OF PLANT ASME PTC46 UNIT NO.TESTNO. DATE LOADTIME START: END: CALC BY

DATE 4-28-95SHEET 6 OF 8

QW T P H ABSORPTION

FLOW TEMPERATURE PRESSURE ENTHALPY MKBtu/hrPARAMETER Klbm/hr F PSIG Btu/lbm Wx(H-Hl)/lOOO

1 FEEDWATER(ExcludingSH 5) 786.290 285.1 1100.0 256.502 SH SPRAYWATER 0.000 260.0 1180.0 230.73 0.003 Ent SH-l Attemp 0.000 0.0 0.0 0.004 LvI!SH-l Attemp 0.000 0.0 0.0 0.05 SH-l Spray Water Flow 0.000 W3 x (H3-H4)/(H4-H2) or W4 x (H3-H4)/H=(H3-H2)6 Ent SH-2 Attemp 0.000 0.0 0.0 0.00 I7 LvI!SH-2 Attemp 0.000 0.0 0.0 0.001

8 SH-2 Spray Water Flow 0.000 W6 x (H6-H7)/(H7-H2) or W7 x (H6-H7)/(H6-H2)INTERNAL EXTRACTION fLOWS

9 Blowdown 6.290 947.0 538.93 1.7810 Sat Steam Extraction 0.000 0.0 0.00 0.0011 Sootblowing Steam 0.000 0.0 0.0 0.00 0.0012 SH Steam Extraction 1 0.000 0.0 0.0 0.00 0.0013 SH Steam Extraction 2 0.000 0.0 0.0 0.00 0.0014

AUXILIARY EXTRACT ION fLOWS15 Aux Steam 1 0.000 0.0 0.0 0.00 0.0016 Aux Steam 2 0.000 0.0 0.0 0.00 0.0017 0.00018 MAIN STEAM 780.000 903.0 931.0 1452.19 932.6319 HIGH PRESSSTREAMOUTPUT Q18 Q2 +0T5 + 016 + Q17 932.63

. . ..

REHEAT UNITS20 REHEAT OÜ-rLET 0.0 0.0 0.0021 COLD REHEATENT ATTEMPERATOR 0.0 0.0 0.022 RH SPRAYWATER 0.000 0.0 0.0 0.0023 COLD REHEAT EXTRACTION 0.00024 TURB SEALFLOW & SHAFT L 0.000

FW HEATER NO. 125 FW Entering 0.000 0.0 0.0 0.00

26FW~rng 0.0 0.0 0.0027 Extraction Steam 0.0 0.0 0.0028 Drain 0.0 0.0 0.0029 FW HEATERNO. 1 FLOW 0.000 W25 x (H26-H25)/(H27-H28)

fW HEATER NO. 230 FW Entering 0.000 0.0 0.0 0.0031 FW Leaving 0.0 0.0 0.0032 Extraction Steam 0.0 0.0 0.0033 Drain 0.0 0.0 0.0034 FW HEATERNO. 2 FLOW 0.000 W30 x [(H31-H30) -W29 x (H28-H33)]/(H32-H33)35 COi.DREHEÄ-r Fl..OW 780.000 W18 - W23 - W24 - W29 - W3436 REHEATOUTPUT W35 x (H20-H21) + W22 x (H20-H22) I 0.0037 TOTAL OUTPUT inc. Blowdown Q19 + Q36 + Q9 I 934.41

NAME6F' PLANT UNIT NO.TEST NO. DATE LaADTIME START: END: CALC BY

DATESHEET OF

OUTPUTDATA REQUIRED

160

-

t

INPUT DATA SHEET 1

161

?

COMBUSTION CALCULATIONS - FORM CMBSTNa1 HHV - Higher Heating Value of Fuel, Btu/lbm as fired 12310.0

4 a. Measured Fuel Flow 85.06 Fuel Efficiency, % (estimate initially) 87.378 Barometric Pressure,in Hg 29.9

9 Dry Bulb Temperature, F 80.0

10 Wet Bulb Temperature, F 0.011 Relative Humidity, % 60.015 Gas Temp Lvg AH, F Primary/Secondary or Main 115B 364.30 I 15A 321.1916 Air Temp Ent AH, F Primary/Secondary or Main 116B 104.00 I 16A 100.0020 Sorbent Rate, Klbm/hr 12.2

COMBUSTION CALCULATIONS - FORM CMBSTNb30 Fuel Ultimate Analysis, % Mass

A Carbon 69.70B Unburned Carbon in Ash 1.520 Sulfur 1.49E Hydrogen 4.31F Moisture 5.43G Moisture (Vapor tor gaseousfue!) 0.00H Nitrogen 1.38J Oxygen 4.05

J Ash 13.64K Volatile Matter 0.00

50 Flue Gas 02, % EnteringAir Heater 3.61Leaving Air Heater 3.61

NAME OF PLANT PTC 46 Plant 1 UNIT NO.TESTNO. Test 1ACOF DATE LaADTIME START: = END: CALC BY

DATE 4-28-95

SHEET OF

1

INPUT DATASHEET2

i"~~..

.

1.

1

~

I

t

162

COMBUSTION CAlCUlATIONS - FORM CMBSTNc83 Flue Gas Temperature Entering Air Heater, F 559.3

84 Air Temperature Leaving Air Heater, F 389.2

UNBURNED CARBON & RESIDUE CALCULATIONS - FORM RES5 Residue Mass Flow 23.34 Kbm/hr Split, %

A Furnace 0.0 41.9B Economizer 0.0 0.0C Bag House 0.0 58.1

D 0.0 0.0E 0.0 0.0

6 Carbon in Residue, %A Furnace 0.00

B Economizer 0.00

C Bag House 9.75

DE

7 Carbon Dioxide in Residue, %A Furnace 1.04

B Economizer 0.00C Bag House 2.10DE

24 Temperature of Residue, FA Furnace 1540.0B Economizer 342.0C Bag House 342.7DE

NAME OF PLANT PTC 46 Plant 1 UNIT NO.TEST NO. Test lACOR DATE LOADTIME START: END: CALC BY


INPUT DATA SHEET3SORBENT CAlCUlATION SHEETMEASUREDC AND CO2 IN RESIDUE- FORM SRBa

7A 502 in Flue Gas, ppm

8 02 in Flue Gas at location where 502 is measured, %

9 S02 & 02 Basis, Wet [Ol or Dry [1]

20 Sorbent Products, % MassA CaC03

B Ca(OH)2

C MCm

D M (OH)2

E H20

F Inert

Calcination Fraction

112

3.60

1

9S.00

0.00

4.00

0.00

0.03

0.00

0.9223A

SORBENT CAlCULATION SHEETMEASUREDC AND C02 IN RESIDUE- FORM SRBb

SORBENT CALCUlATION SHEETEFFICIENCY- FORM SRBe61 ISorbent TemfJerature, F 77.0

0.0

0.0

EFFICIENCY CALCULATIONS- FORM EFFb

~ Surface Radiation and Convedion, MKBtu/hrEFFICIENCYCAlCUlATIONS OTHER lOSSES AND CREDITS- FORM EFFe

6.4

Losses,%85A CO in Flue Gas858 Pulverizer Re"ects8SC Air Infiltration8SD Unburned H dra en in Flue Gas85E Unburned H dra en in Residue

85F Unburned Hydrocarbons in Flue Gas8SGLosses,MKBtu/hr86A Wet Ash Pit86B Sensible Heat in Rec cleStreams - Solid

86C Sensible Heat in Recycle Streams - Gas860 Additional Moisture86E Coolin Water86F Air PreheatCoil (Su lied b Unit)86G BoilerCirculatin Pumps86HCredits, %

0.000.000.000.000.000.00

0.0000.0000.0000.0000.0000.0000.000

87A

Credits, MKBtu/hr

~ Heat in Additional Moisture (External to Envelope)NAME OF PLANT PTC 46 Plant 1TEST NO. Test lAC DATETIME START: END:

0.00

0.000UNIT NO.LOADCALC BYDATE 4-28-95SHEET OF

163

INPUT DATA SHEET 4

4

t,

iI!

164

W T PFlOW TEMPERATURE PRESSURE

PARAMETER Klbm/hr F PSIG

1 FEEDWATER 786290 285.1 1100.0

2 SH SPRAYWATER 0 260.0 1180.0

3 Ent SH-1 Attemp 0 0.0 0.0

4 lvg SH-1 Attemp 0 0.0 0.0

6 Ent SH-2 Attemp 0 0.01 0.07 lvg SH-2 Attemp 0 0.0 0.0

INTERNAl EXTRACTION FlOWS9 Blowdown 6290 947.0

10 SarSteamExtraction 0 0.011 Sootblowing Steam 0 0.0 0.0

12 SH Steilm çxtraction 1 0 0.0 0.0

13 SH StearnExtr;lc!ion 2 0 0.0 0.0

14

AUXILIARY EXTRACTION FlOWS15 Aux Steam 1 0 0.0 0.016 Aux Steam 2 0 0.0 0.0

1718 MAIN STEAM 903.0 931.0

REHEAT UNITS20 REHEAT OUTLET 0.0 0.021 COlD REHEAT ENT ATTEMPERA TOR 0.0 0.022 RH SPRAYWATER 0 0.0 0.023 COlD REHEATEXTRACTION 0

24 TURB SEAl FlOW& SHAFT l 0

FW HEATER NO. 125 FW Entering 0 0.0 0.0

26 FW leaving 0.0 0.0

27 Extraction 5team 0.0 0.0

28 Drain 0.0 0.0

FW HEATER NO. 230 FW Entering 0 0.0 0.031 FW leaving 0.0 0.032 Extraction Steam 0.0 0.033 Drain 0.0 0.0

NAME OF PlANT PTC 46 Plant UNIT NO.

TEST NO. Test 1ACOR LOADTIME START: END: CAlC BY


t

COMBUSTION CALCULATIONS

165

DATA REQUIRED1 HHV - Higher Heating Value of Fuel, Btu/lbm as fired 12310:02 uac - Unburned Carbon, Ibm/100 Ibm fuel trom RESor SRBb FORM 1.523 Fuel Flow, Klbm/hr [4b] 86.884 a. Measured Fuel Flow 85.004 b. Calculated Fuel Flow 100,000 x [51/[61/[1) 86.88s Output, MKBtu/hr trom OUTPUT Item [37J 934.416 Fuel Efficiency, % (estimate initially) 87.377 Moisture in air, Ibm/Ibm Dry Air 0.01318 Barometric Pressure, in Hg pv #VAlUE! 29.929 Dry Bulb Temperature, F psv 0.5068 80.010 Wet Bulb Temperature, F psv 0.0000 0.011 Relative Humidity, % pv 0.3041 60.0

Additional Moisture (Measured) Klbm/hr

Atomizing Steam trom OUTPUT Item [15] 0.0

Sootblowing Steam trom OUTPUT Item [12] 0.0Other 0.0

12 Summation Addition Moisture 0.013 Additional Moisture, Ibm/100 Ibm Fuel 100 x [121/[3] 0.014 Additional Moisture, Ibm/1 OKBtu [131/([11/100) 0.0

If Air Heater (Exel SIm/WIr COl!) Enter following15 Gas Temp lvg AH; F Primary/Secondary or Main 158 I 364.30 I 15A I 321.1916 Air Temp Ent AH, F Primary/Secondary or Main 168 I 104.00 I 16A I 100.00

Fuel Analysis,% Mass as fired - Enter in Col [30]

02 in Flue Gas, % Volume - Enter in Column [50] each location

19 Mass Ash, Ibm/10KBtu 100 x (30]]/[1] I 0.111

If mass of ash (Item [19)) exceeds 0.15 Ibm/l0KBtu or Sorbentutilized, Enter Mass Fraction of Refuse in Col [79] tor each location

SORBENT DATA (En1er 0 if SQrbent not U$ed)20 Sorbent Rilte, Klbm/hr 12.20

21 C02 trom Sorbent, Ibm/1O0 Ibm 50 trom SRBiI Item [251) 40.5222 H20 trom Sorbent, Ibm/1O0 Ibm 50 trom SRBaItem [2611 0.0323 Sulfur Capture, Ibm/Ibm Sulfur trom SRBb Item [45) 0.900

24 Spent Sorbent, Ibm/l00 Ibm tuel trom SRBb Item (48] 11.70

2S Sorb/Fuel Ratio, Ibm Sorb/lbm Fuel !20J/[3) 0.140

NAME OF PLANT ASME PTC 46 UNIT NO. 1

TEST NO. Test 1ACOR DATE lOADTIME START: END: CAlC BY


COMBUSTION CAlCUlA TIONS

166

COMBUSTION PRODUCTS

UQJ Ultimate . TheoAir F .EJ Dry ProdF .2U Wet ProdF . 2!J H20 Fuel

Analysis Ibm/100 Ibm Fuel Moll100 Ibm Fuel Molll00 Ibm Fuel Ibm/10KB% Mass 130JxK !30J!K !30J/K [30jxK!([1])/lOOJ

A C 69.70

B UBC 1.524

C Cb 68.18 11.5 784.71 12.01 5.677D 5 1.49 4.32 6.44 32.06 0.046

E H2 4.31 34.3 147.79 2.016 2.138 8.94 0.313F H20 5.43 18.016 0.301 1.0 0.044

C H20v 0.00 18.016 0.000 1.0 0.000H N2 1.38 28.02 0.049

J 02 4.05 -4.3 -17.50

J ASH 13.64

K VM 0.00

l

M TOT AL 100.00 31 I 921.44 I 32 I 5.772 33 I 2.439 34 I 0.357

35 Total Theo Air Fuel éheck, Ib/10KB T((31MJ + [30B] x 11.51)/((1]/100) I 7.63

CORRECTIONS FOR SORBENT REACTIONS AND SUlFUR CAPTURE

40 C02 trom Sorb . Ib/100lbfuel [21] x 125J 5.6941 H20 trom Sorb Ibll 00 Ib fuel [22) x [25J 0.00442 502 Reduction Mol/l 00 Ib fuel [32DJ x [23) 0.04243 Dry Prod Comt Mol/100 Ib fuel [32M] + [40J/44.01 - [42J 5.9044 Wet Prod Comt Mol/100 Ib fuel [33MJ + 141J/18.016 + [43] 8.34

46 Theo Air Carr, Ib/100 Ib tue! [31 M] + 2.16 x [30DJ x 123J 924.3347 Theo Air Corr, Mol/l00 Ib fuel [471128.966 31.9148 Theo Air Corr, Ib/10KBtu [46J/([l)/100) 7.5149 Wet Gas trom Fuel, Ib/10KBtu (100 - [30j] - [30B) - 130DJ x 1231)/([1]/100) 0.678

lOCA TION AH IN AH OUT..Below m = Measured 1 = location50 02, % 3.61 3.61 0.0 0.0

5152

FlUE CAS ANAl YSJS, Mol/10O Ib Fuel Dry Wet53 Moisture in Air 0 [7)x 1.608 0.02 0.02 0.02 0.02

I54 Dry/Wet Produets Comb [43J [44) 8.34 8.34 0.00 0.0055 Additional Moisture 0 [13J/18.016 0.00 0.00 0.00 0.0056 [47] x (0.7905 + [53]) 25.23 25.90 0.00 0.0057 5ummation !54J + [55J + [56J 33.57 34.24 0.00 0.0058 20.95 - [50] x (1 + [531) 17.26 17.26 0.00 0.00

60 Excess Air, % I 100 x ISo] x [57]/[47]/[58] 22.00 22.44 0.00 0.00

NAME OF PLANT A5ME prc 46 UNIT NO. 1TEST NO. Test 1ACOR DATE LOADTIME 5TART: END: CALC BY

DATE 4-28-95

SHEET 2 OF 8

GENERAL COMBUSTION CAlCUlATIONS

167

lOCA TION AH IN AH OUT60 Excess Air, % I 22.00 22.44 0.00 0.00

0.2, C02, 502 WHEN EXCESSAIR KNOWN6162 Dry [471 x (0.7905 + [60])/100) 32.24 32.39 0.00 0.0063 Wet [47] x (0.7905 + [53) + (1 + 153]) x [60)/100) 33.07 33.21 0.00 0.00

64 Dry Gas, Mol/l00 Ib Fuel 143] + [62] 38.15 38.29 5.90 5.9065 Wet Gas, Mol/l00 Ib Fuel [441 + [63] 41.41 41.55 8.34 8.34

.

Dry Wet

66 02,% [60] x [47] x 0.2095/ 164J [65] 3.55 3.61 0.00 0.0067 C02, % ([30C)/.1201 + (401/.4401)/ [64J (65) 14.02 13.97 0.00 0.0068 502,% (1 - [23]) x [30D]I.32064/ [64] (65] 0.011 0.011 0.000 0.000

FLUE GAS PRODUCTS, Ibm/l0KBtu69 Dry Air (1 + [60)/100) x [48] 9.16 9.19 0.00 0.0070 Wet Gas trom Fuel [49J 0.678 0.678 0.000 0.00071 C02 trom Sorbent 140]/([1)/100) 0.046 0.046 0.000 0.00072 Moisture in Air [7] x (69) 0.120 0.121 0.000 0.000

73 Water trom Sorbent [41]/«(1]1100) 0.000 0.000 0.000 0.000

74 Additional Moisture [14] 0.000 0.000 0.000 0.00075 Total Wet Gas (69) + [70] + [71] + [72) + [73] + 174) 10.01 10.04 0.00 0.0076 H20 in Wet Gas (34M] + 172] + (73) + [74J 0.477 0.478 0.000 0.00077 Dry Gas (75) - [76] 9.53 9.56 0.00 0.00

78 H20 in Wet Gas, % Mass 100 x [761/[75] 4.77 4.76 0.00 0.0079 Residue, lh/lh Total Refuse at each location 0.581 0.581 0.000 0.00080 Residue, Ib/l0KBtu 1<13011+ [2] + [24])/([1]/100) 0.218 0.218 0.000 0.00081 Residue in Wet Gas, lh/lh Wet Gas [79J x [80)/[75) 0.013 0.013 0.000 0.000

.

82 ILeakage, % Gas Entering 100 x ((75L] - [75E))/[75EJ 0.000 0.336 I 0.000 I 0.000

. GAS TEMPERATURE CORRECT ION FOR JNFJLTRATION83 Gas Temp Lvg (lNCL LKG), F [15] 559.30 342.75 0.00 0.0084 Air Temp Ent, F [16] 389.20 102.00 0.00 0.0085 H Air Lvg, Btu/lbm T = [83), H20 = (7] 118.98 64.95 0.00 0.0086 H Air Ent, Btu/lbm T = [84), H20 = [7) 76.44 6.08 0.00 0.0087 Cpg, Btu/lbm F T = [83), H20 = [78E), RES = [81EI 0.2541 0.2514 0.0000 0.0000

88 Correction AH Gas Outlet Temperaturer--- 183] + ([82)/100 x <185]-(86])/[87]) 559.3 343.5 0.0 0.0

AIR, GAS, FUEl &RESIDUE MASS FlOW RATES, I<lbm/hr90 Input trom Fuel trom Efficiency Form, Million Btu/hr 1069.591 Fuel Rate, Klb/hr 1000 x [90J/[IJ 86.992 Residue Rate, Klb/hr [80] x [90]/10 23.3 23.3 0.0 0.093 Wet Flue Gas, Klb/hr [75) x [90]/10 1070.1 1073.7 0.0 0.0

95 Excess Air Lvg Blr, % As Applicable trom [60] 22.4378616696 Total Air to Blr, Klbm/hr (1 + (95)/100) x (1 + [7]) x [48) x 190]/10 996.2

NAME OF PLANT ASME PTC 46 UNIT NO.TEST NO. Test lACOR DATE LOADTIME START: END: CALC BY


UNBURNEO CARBON & RESIOUE CAlCULATIONSDATA REQUIRED fOR RESIDUE SPLIT

1 Ash in Fuel, % trom Form CMBSTNb 113.6412 IHHVFuel,Btu/lb'asfired'1

12310.0

I I I trom Form CMBSTNa [1]3 Fuel MassFlow Rate,Klbm/hr trom Form CMBSTNa 86.88 4

A Item [3J - Use measuredor estimatedvalue initially. (SeeCMBSTNa)Recalculate after boiler efficiency hiJSbeen calculated until estimatedvalue is within 1% of calculated value

B Residuesplits estimated - Entervalue in Col [81and calculate Col [SIResiduerare measured- Entermeasuredmassflow riJlesin Col [SJ.When residue not measuredat all locations, estimate splitand flow for measured locations. Reiterateuntil estimated total residue is within 2% of calculated.

CEnter the % tree carbon in Col [6] (lotal carbon correcter for C02). Units with sorbent - Enterthe % C02 in Col [7].

WResidue Mass Flow~. .ij W Residue Split % -2J C ~C C02 Calculated Md Ave % C02

Input Calculated in Residue in Residue 100 x [5]/ [6] x (S]/ Wtd Ave %Location Klbm/hr Klbm/hr % % Input [SF] 100 [71 x [8]/100

A Furnace 0.00 9.77 0.00 1.0 41.9 0.00 0.000 0.435

B Econ 0.00 0.00 0.00 0.0 0.0 0.00 0.000 0.000

C Bag House 0.00 13.56' 9.75 2.1 58.1 0.00 5.668 1.2210 0.00 0.00 0.00 0.0 0.0 0.00 0.000 0.000

E 0.00 0.00 0.00 0.0 0.0 0.00 0.000 0.000

F TOTAL 510.00 23.34 81100.0 0.00 91 5.668 101 1.656

UNITS WITHOUT SORBENT

11 IUnburned Carbon, Ibm/100 Ibm Fuel I [1] x [9F] / (100:'" [9F]) I 0.820

20 Tot<ll Residue, Ibm/WO Ibm Fuel 1[1] + [11] 114.46

UNITS WITH SORBENT

0 Enter averiJge C and C02 in residue, (9F] & [10FJabove or 5RBa(Items [4] & [5]) and complete Sorbent Calculation11 Unburned Carbon, Ibm/WO Ibm Fuel Ifrom Form SRBb Item [49] I 1.522

20 ITotal Residue, Ibm/WO Ibm Fuel Itrom Form SRBb Item [50J I 26.86

211 Total Residue, Klbm/hr 1[20] x [3] / 100 123.34

E When all residue collection locations are measured,the measuredresidue split is usedtor calculations. If a port ion of the residuemass is estimated, repeat calculation above until Col [SF] & Item [21] agreewithin 2%.

22 1 Total Residue, Ibm/l0KBtu 100 x [20] 1[2] 1 0.218

23 1 SENSIBlE HEAT RESIDUE tOSS, %

Location ~ Temp 181 x [22] Residue /1000 LossResidue % Ibm/10KBtuBtu/lbm %

A Furnace 1540 41.87 x 0.218 x 388.12 /10000 0.355B Eçon 342.0 0.00 x 0.218 x 53.38 /10000 0.000

C Bag House 342.7 58.13 x 0.218 x 53.54 /10000 0.0680 0.0 0.00 x 0.218 x -12.95 /10000 0.000

E 0.0 0.00 x 0.218 x -12.95 /10000 0.000Total 125 0.422

H residue = 0.16 x T + 1.09E-4x TA2- 2.843E-8 x TA3- 12.95

NAME OF PLANT ASME PTC 46 UNIT NO.

TEST NO. Test lACOR DATE LOAD

TIME START: END: CALC BYDATE 4-28-95

SHEET 4 OF

168

SORBENT CAlCUlA TION SHEETMEASURED C AND CO2 IN RESIDUE

169

?~

DATAREQUIRED1 Fuel Rate, Klbm/hr from CMB5TN . 86.88 4 Carbon in Residue, 0 trom Form RE519F] 5.672 Sorbent Rate, Klbm/1 trom CMB5TNa [2J 12.20 5 C02 in Residue, trom Form RE5[10FJ 1.663 Sorb/Fuel Ratio [2J/[lJ + 0.140 6 Moisture in Air, lh/lh Dry from CMB5TNa(71 0.0137 502 Flue Gas, ppm 7A 1112.0 [7AI/l 0,000 % 7B 0.0118 02 Flue Gas @ Loc 502% 3.6 9 502 & 02 Basis Wet (1) or Dry (0) 110 Additional MoistureIb/1()0Ib Fuel . (CMB5TNa, Item (13]) 0.00

Item [1] Use measured or estimated value initially. Recalculate after boiler efficiency has beencalculated until estimated value iswithin 1% ot cale.Enter fuel analysis in Col [15JEnter sorbent analysis in Col [20J.Estimate Unburned Carbon [15B], and Calcination [23A] initially.Reiterate until estimated value is within 2% of caleulated value.

+ Items thai must be recalculated tor each iteration.

COMBUSTION PRODUCTS

.J..U Ultimate Analysis Theo Air F Dry Prod F -2!J Wet Prod F

% Mass Ibm/100 Ibm Fuel Molll00 Ibm Fuel Mol/lOO Ibm Fuelfrom CMB5TNb [30] [15J x K [151/K [15J/K

A C 69.70 -B uac . 1.524 -C Cb + 68.18 11.51 + 784.7 12.01 :1" 5.68D 5 1.49 4.32 6.4 32.064 - 0.05E H2 4.31 34.29 147.8 - 2.016 2.138F H20 5.43 - 18.02 0.301

G H20v 0.00 - 18.02 0.000

H N2 1.38 28.016 - 0.05I 02 4.05 -4.32 (-) -17.5 -J A5H 13.64 -K -l -M TOTAL 169.70 16 1+ 921.4 17 + 5.77 18 2.439

SORRENT PRODUCTS

2!J .EJ Ca C02 H20

Moll100 Ib Caleination Ib/1OOlb50rb Ib/1001b Sorb

% Mass MW [201l[21! Fraction MW [22Jx[23]x(24J [22]x(23Jx[24]

A CaC03 95.00 100.09 0.949 . 0.920 44.01 :r 38.43B Ca(OH)2 0.00 74.096 0.000 1.0 18.016 - 0.00

C MgC03 4.00 84.321 1.0 44.01 - 2.09D Mg(OH)2 0.00 58.328 1.0 18.016 - 0.00

E H20 0.03 18.016 1.0 18.016 - 0.03

F INERT 0.00 -G -H -I TOTAL Ca, Mol/lOO tb Sorb 0.949 TOTAL + 40.52 0.03

NAME OF PLANT UNIT NO.

TEST NO. Test 1ACOR DATE LOAD


SHEET OF

c"

':I i'! I

I

30

313233

343536373839

40

SORBENT CAlCULATION SHEETMEASURED C AND CO2 IN RESIDUE

SUlfUR CAPTURE BASEDON GAS ANAl YSIS

SelectColumn per Item [9)Moisture in AirAdditional Moisture

ProductsCombustion FuelH20 SorbC02 Sorb +

+

0

0.021

0.0008.212

0.0000.129

25.81934.160

0.8250.9379.9850.013

0.900

3.34911.697

1.52226.859

0.9242.868

Unburned Carbon,

Calcination,

'b/100 Ib FuelMols C02/Mol CaC03

[15BJ(23A]

Calculated

1.524 149J 1.5220.920 [51] 0.924

Mols/Mol DADry0.0

0.0

(17M)

0.0

Wet

[6]x1.608

[10]/18.016

[17M] + [18M)

Calc

+

[3J x [2611/18.016

. [3] x [2511/44.01

(0.7905 + [30]) x [16M]/28.966Summation [31) thru [35]

1.0 - (1.0 + [30]) x [8]/20.95(0.7905 + [30]) x 2.387 - 1.0(7BJx 1361/ [17DJ / [37J[38J x [7BI / [37!

+

+

45 Sulfur Capture, lh/lh Sulfur (100 - [39])/(100 + [40]) +

4748495051

52

UNBURNED CARBON, CAlCINATION AND OTHER SORBENT/RESIDUE CALCULATIONS

503 Formed, Ib/l00 Ib Fuel [45) x [170] x 80.064 +

Spent Sorbent, Ibll 00 tb Fuel [471+ (100-125IJ-[261])x [3] +Unburned Carbon: Ib/1O0Ib Fuel ((48] + [15J]) x [4) / (100-(4]) +ResidueRate, Ib/100 Ib Fuel [49) + (48J + [15J! +

Calcination, lh/lh CaC03 1 - [50] x [5] x 0.0227/ !20A] / 131 +Ca/S Molar Ratio, Mols Ca/MolS [3] x (221] x 32.064/ [150]

Compare the following, reiterate if initial estimate not within 2% calculatedInitia I Est

Enter result of Item (50] on Form RES, Item [201.rf residue mass flow rare not measured at aH locations, recalculate.

RES and SRBa &SRBb until convergenceori refuse rare of 2%.

NAME OF PLANTTE5TNO. Test 1ACORTIME START:

DATEEND:

UNIT NO.LaADCALC BY

DATESHEET

4-28-95OF

170

, SORBENT CAlCULATION SHEETEFFICIENCY

171

DATA REQUIRED60 Reference Temperalure, F 77 60A Enlhalpy Water (32 F Ref) 45

61 Sorbent Temperature, F 77.0 61A Enthalpy Sorbent (77 F Ref) 0.0062 Ave Exit Gas Temp (Exel Lkg) 343.5 62A Enthalpy Steam @ 1 PSIA 1215.59

63 HHV Fuel, Btu/lbm 'as fired' 12310.0

LOSSES MKBtu/hrWater trom Sorbent (2] x [261) x ([62A] - [60A])/100000

x x ( - )/100000 0.043

Calcination/Oehydralion71 CaCO3 [20A) x (23A] x (2! x 0.008 = 95.00 x 0.92 x 12.20 x 0.00766 8.168

72 Ca(OH) [20B] x 1.0 x (2] x 0.006 = 0.00 x 1.0 x 12.20 x 0.00636 0.000

73 MgC03 [20C) x 1.0 .x [2] x 0.007 = 4.00 x 1.0 x 12.20 x 0.00652 0.318

74 Mg(OH) [200) x 1.0 x [21 x 0.006 = 0.00 x 1.0 x 12.20 x 0.00625 0.000

75

76

77 5ummation of Losses Due to Calcination/Oehydration SUM [71] - (76) 8.486

CREDITS, %Sulfalion 6733 x [45) x [150] / 1631

6733 x x / 0.733

CREDITS, MKBtu/hrSensible Heat trom Sorbent [2J x (61A] / 1000

x / 1000 0.000

Enthalpy of limeslone - See lext tor other sorbentsHCAC03 = [61) x (0.179 + 0.1128E-3 x [61)) - 14.45

x (0.179 + 0.1128E-3 x ) - 14.45 0.002

(61AJ = (1 - [20E) / 100) x HCACO3 + [20EJ x ([61] - 77) / 100= (1 - / 100) x + x ( - 77) / 100 0.002

NAME OF PLANT UNIT NO.

TEST NO. Test 1ACOR DATE LOAD


DATE 4-28-95

SHEET OF

~T

EFFICIENCY CALCULA TIONSDATA REQUIRED

'72

TEMPERATURES,F1 ReterenceTemperature 77 lA EnthalpyWater(32 F Ref) 45

2..JAve EnteringAir Temp 102.0 2A Enthalpy Dry Air 6.01trom CMBSTNaItem ([16AI + [16B]) / 2 28 Enthalpy Water Vapor 11.15

2J Ave Exit Gas T (Exel lkg) .343.5 3A Enthalpy Dry Gas 63.89

trom CMBSTNaItem ([15A] + (1SB])/ 2 38 Enthalpy Steam@ 1 PSIA 1215.59

3C Enthalpy Water Vapor 122.16

4 Fuel Temperature I 77.0 4A Enthalpy Fuel I 0.02

HOT AIR QUALITY CONTROL EQUIPMENT

5 IEntering Gas Temperature 0.0 5A Enthalpy Wet Gas 0.00

leaving Gas Temperature 0.0 6A Enthalpy ot Wet Gas 0.00

68 Enthalpy ot Wet Air 0.00

6C Enthalpy ot Wet Air @ T = (3] 0.00

RESULTS' FROM COMBUSTION CAlCUlATION FORM CMBSTN

10 Dry Gas Weight 1771 9.53 18 Unburned Carbon, % [2] 1.522

11 Dry Air Weight 1691 9.16 19 HHV Btu/lbm 'as-tired' [lJ 112310.0

12 Water trom H2 Fuel 134E] 0.313 HOT AQC EQUIPMENT

13 Water trom H20 Fuel 134F] 0.044 20 Wet Gas Entering [75E] 0.00

14 Water trom H20v Fuel [34GI 0.000 21 H20 in Wet Gas, % [76E] 0.00

15 Moisture in Air Ib/lb DA [7J 0.013 22 Wet Gas leaving [75l] 0.00

16 Moisture in Air Ib/l0KB 172] 0.120 23 Retuse in Wet Gas, % [81 E] 0.00

17 Fuel Rate Est. Klb/hr 13] 85.00

MISCEllANEOUS

30 Unit Output, MKBtu/hr 934.41 31 Aux Equip Power, MKBtu/hr 1.0

32 Feedwater Temperature, F 0.00 32A Enthalpy Feedwater, Btu/lbm 0.0

33 Feedwater Presure, psig 0.00 34 Drum Pressure, psig 0.00.

35 Blowdown Flow, Klb/hr 0.00 35A Enthalpy Blowdown, Btu/lbm 0.00

36 SB Slm Flow (Unit), Klb/hr 0.00

NAME OF PLANT A5ME PTC 46 UNIT NO.

TEST NO. DATE lOAD

TIME START: END: CAlC BY

DATE

SHEET 5 OF 8

~

~

~

~

-

EFFICIENCYCAlCUlATIONS

173

LOSSES, % Enter Calculated Result in % Column A I MKB B I %

Dry Gas [10] x [3A] /100x /100 6.087

Water trom H2 Fuel [12) x ([3B]-[lA]) /100x ( - 45)/100 3.663

Water trom H20 Fuel [13] x (l3BJ- [lA]) /100x ( - 45)/100 0.516

Water trom H20v Fuel [14] x ([K] /100x /100 0.000

Moisture in Air [16] x [K] /100x /100 0.147

45 Unburned Carbon in Ref [18Jx 14500/[19] == x 14500/ 1.79346 Sensible Heat of Refuse - trom Farm RES 0.422

47 Hot AQC Equip ((20! x <l5A] - (6A]) - ([22J - [20]) x ([6B] - [6C!))/100- ( x( - )-( - )x( - ))/100 0.000

48 IOther losses, % Basis - trom Farm EFFeItem [85J 0.000

54 ISummation of losses, % Basis 12.629

LOSSES, MK8tu/hr Enter in MKB Column [A]55 Surfaee Radiation and Conveetion 6.40056

5758 Sorbent Calcination/qehydration - trom Farm SRBeItem [771 8.48659 Water trom Sorbent - trom Farm SRBeItem [65] 0.043

60 Other losses, MKBtu/hr Basis - trom Farm EFFeItem [86] 0.000

62 Summation of losses, MKBtu/hr Basis 14.929

CREDITS, % Enter Calculation Result in % Column [8]

Entering Dry Air [11] x [2AI /100x /100 0.550

Moisture in Air [16] x [2B) /100x /100 0.013

Sensible Heat in Fuel 100 x [4A] /[19J100 x / 0.000

66 Sulfation - trom Form SRBeItem [80) 0.733

67 Other Credits,% Basis - trom Farm EFFeItem [87J 0.000

71 SummaIIon of Credits, % Basis 1.297

CREDITS, MKBtu/hr Enter Calculated Rsult in MKBColumn [A]72 Auxiliary Equipment Power [31] 1.020

73 Sensible Heat trom Sarbent .,.trom Farm SRBeItem [85J 0.000

74 Other Credits, MKBtu/hr Basis - trom Form EFFeItem [88J 0.000

75 Summationof Credits, MKBtu/hr Basis 1.020

Fuel Eff, % (100 - [54) + 171])x [30]/(1301 + [62J - [75])(100 - + )x /( - + ) 87.37

81 Input trom Fuel, MKB 100 x 130]/[80J = 100 x / 1069.5

82 Fuel Rate, Klbm/hr 1000 x 181J/[19] = 1000 x / 86.88

NAME OF PLANT ASME PTC 46 UNIT NO.

TESTNO. DATE LOADTIME START: END: CAlC BY

DATE 4-28-95

SHEET 6 OF 8

EFFICIENCY CALCULATIONSOTHER LOSSES AND CREDITS

174

The jasses and credits listed on this sheet are not universally applicable toal! fossil fired steam generators and are usually minor. Losses/credits thaIhave not been specifically identified by th is Code but are applicable inaccordance with the intent of the Code should also be recorded on thissheet.

Partjes to the test may agree to estimale the jasses or credits in lieu oftesting. Enter a 'T' tor tested or 'E' tor estimated in the second column, andthe result in the appropriate column.Enter the sum of each group on Farm EFFb.Refer to the text of PTC 4 for the calculation method.

Itm Tor E LOSSES,% Enter Calculated Resultin % Column [8] A I MKB B I %

85A CO in Flue Gas 0.000

858 Pulverized Rejects 0.000

85C Air Infiltration 0.000

85D Unburned Hydrogen in Flue Gas 0.000

85E Unburned Hydrogen in Refuse 0.000

85F Unburned Hydrocarbons in Flue Gas 0.000

85G85 SulJlmationof Other Losses,% Basis 0.000

LOSSES, MKBtu/hr Enter in MK8 Column [A]86A Wet Ash Pit 0.000

868 Sensible Heat in Recycle Streams- Solid 0.000

86C Sensible Heat in Recycle Streams- Gas 0.000

86D Additional Moisture 0.000

86E Cooling Water 0.000

86F Air PreheaterCoil (supplied by unit) 0.00086G 0.00086 Summation of Other Losses,MKBtu/hr Basis 0.000

CREDITS, % Enter Calculatión Result in % Column [8]87A 0.00087 Summation of Credits, % Basis I 0.000

CREDITS, MKBtu/hr Enter Result in MKB Column [A]8SA Heat in Additional Moisture (externallo envelope) 0.000888 0.00088 Summation of Credits, MKBtu/hr Basis 0.000

NAME OF PLANT ASME PTC46 UNIT NO

TESTNO DATE LOAD


SHEET 7 OF 8

e,

.

.

"

OUTPUT

175

QW T P H ABSORPTION

FlOW TEMPERATURE PRESSURE ENTHALPY MKBtu/hrPARAMETER Klbm/hr F PSIG Btu/lbm Wx(H-Hl)/1000

1 FEEDWATER(excluding SH Sp) 786.290 285.1 1100.0 256.50

2 SH SPRAYWATER 0.000 260.0 1180.0 230.73 0.003 Ent SH-1 Attemp 0.000 0.0 0.0 0.00

4 Lvg SH-1 Attemp 0.000 0.0 0.0 0.00

5 SH-1 SprayWater Flow 0.000 W3 x (H3-H4)/(H4-H2) or W4 x (H3-H4)/(H3-H2)6 Ent SH-2 Attemp

. 0.000 0.0 0.01 0.00

7 Lvg SH-2 Attemp 0.000 0.0 0.01 0.00

8 SH-2 Spray Water Flow 0.000 W6 x (H6-H7)/(H7-H2) or W7 x (H6-H7)/(H6-H2)

INTERNAL EXTRACTION FLOWS9 Blowdown 6.290 947.0 538.93 1.78

10 Sat Steam Extraction 0.000 0.0 0.00 0.0011 Sootblowing Steam 0.000 0.0 0.0 0.00 0.00

12 SH Steam Extraction 1 0.000 0.0 0.0 0.00 0.0013 SH Steam Extraction 2 0.000 0.0 0.0 0.00 0.0014

AUXILIARY EXTRACTION FlOWS15 Aux Steam 1 0.000 0.0 0.0 0.00 0.0016 Aux Steam 2. 0.000 0.0 0.0 0.00 0.00

17 0.00018 MAIN STEAM 780.000 903.0 931.0 1452.19 932.6319 HIGH PRESSSTEAM OUTPUT Q18 - Q2 + Q1S + Q16 + Q17 932.63

REHEAT UNITS20 REHEAT OUTLET 0.0 0.0 0.0021 COLD REHEATENT ATTEMPERATOR 0.0 0.0 0.0022 RH SPRAYWATER 0.000 0.0 0.0 0.0023 COLD REHEATEXTRACTION 0.00024 TURB SEALFLOW & SHAFT L 0.000

FW HEATER NO. 125 FW Entering 0.000 0.0 0.0 0.0026 FW Leaving 0.0 0.0 0.0027 Extraction Steam 0.0 0.0 0.0028 Drain 0.0 0.0 0.00

29 FW HEATERNO. 1 FLOW 0.000 W25 x (H26-H25)/(H27-H28)

FW HEATER NO. 230 FW Entering 0.000 0.0 0.0 0.0031 FW Leaving 0.0 0.0 0.0032 Extraction Steam 0.0 0.0 0.0033 Drain 0.0 0.0 0.0034 FW HEATER NO. 2 FLOW 0.000 W30 x !(H31-H30) - W29 x (H28-H33)]/(H32-H33)35 COLD REHEAT FLOW 780.000 W18 - W23 - W24 - W29 - W3436 REHEATOUTPUT W3S x (H20-H21) + W22 x (H20.H22) I 0.0037 TOTAL OUTPUT Ine. Blowdown Q19 :t Q36 + Q9 934.41NAME OF PLANT UNIT NO.TEST NO. DATE LOADTIME START: END: CAlC BY

DATESHEET OF

APPENDIX F - UNCERTAINTY ANAL YSIS(This Appendix is not a part of ASME PTC 46-1996.)

F.l INTROOUCTION F.2 CORRECTEDPOWER

The following variables are measured to determinecorrected power.

Pmeas = measured power= Pcn + Pcn + PST- PAux

where

PGTl = gas turbine generator power corrected fortransformer losses

PGT2= gas turbine generator power corrected fortransformer losses

PST= steamturbine generatorpower corrected fortransformer losses

PAux= auxiliarypowermthenn = steam export mass flow

pf= generator power factor

T;nl = inlet air temperaturePamb = ambient barometric pressure

%RH= ambient relative humidity

F.3 CORRECTEDHEAT RATE

In addition to the variables measured to determinecorrected power, the following variables are alsomeasured to determine corrected heat rate.

Qmeas = measured thermal input (Qmeas = qm HV)

where

qm = fuel mass flowHV= fuel healing value

F.4 DERIVATION OF UNCERTAINTYEQUA TIONS

This Appendix gives the derivation of the uncer-tainty of corrected power and corrected heat rateusing the test described in Appendix A as the basis.This derivation is done accordi.ng to PTC 19.1,Measurement Uncertainty. Sample calculations ofuncertainty for corrected power output and correctedheat rate are given. The sample calculations arebased on a specific plant and test procedure. Donot apply the sample uncertainties to any otherperformance test. Evaluate the uncertainty of eachtest taking into account the test objective, the calcula-tion method and the uncertainty of the specificmeasurement methods used for that particular testThe sample calculations are given only to show themethodology by which the uncertainty is calculated.

Fundamental EquationsFrom Section 5:

Peorr =(

Pmeas + .i lli

JTI aj

1=' j= 1(5.1.1)

F.4.1 Uncertainty in Corrected Power

(Go... + ,i, ~,) j~' PjHReorr=

)(Pm J, A, I~' al

(S.1.3a)

Peerr = (Pmeas + 111+ 1l2a + 1l2b) a,a2a3 (F.4.1)

177

Specific EquationsThese are the equations specific to the test de-

scribed in Appendix A.

Peorr = (Pmeas + 111+ 1l2a + 1l2b) a1a2a3 (F.1.1)

(Qmeas) /3d32/h (F.l.2)HReorr= (P + 11, + 1l2a + 1l2b) a,a2a3meas

UPcorr =[ UPmeaS2( apcorr)

2

Pcorr P 2 aPmeascorr

+ Umlherm2 ( apcorr )2 + U~( (apcorr)2

P 2 am1herm P 2 aprwrr wrr

UT;n/2

(aPcorr )2 UPamb\ apcorr)2

+-- + -P 2 aT;nl P 2 aPambcorr corr

U 2 2

]

V,%RH

(apcorr )+ P 2 a%RHcorr

(FA.2)

F.4.2 Uncertainty in Corrected Heat Rate

. (Qmeas)fJlfJ2/hHRcorr = (D + Al + A2a + A2b)al1X21X3'meas

(FA.3)

UHR

[

UQ 2

(':\ HR

)2 Up 2

("I

HR)

2corr meas u . corr meas u corr

HRcorr = HR~orr aQmeas + HR~orr aPmeas

+ Umlherm2(aHRcorr)2 + -.

Up?(aHRcorr)

2

HR 2 amtherm HRcorr2 aprcorr

UT. 2 ':\HR 2 Up 2 "IHR

)2

mi u corr . amb u corr

+ HRcorr2(~) + HRcorr2( aPamb

U 2 2

]

'11%RH aHRcorr

+ HRcorA a%RH ) (FAA)

F.5 SAMPLE CAlCUlATJONS

Sample calculations of uncertainty tor correctedpower output and corrected heat fale are givenusing the test described in Appendix A as the basis.The plant is a combined cycle cogeneration plantwith two natural gas fueled gas turbine generators.Each gas turbine generator exhausts to an unfired

heat recovery steam generator. The single steamturbine generator has an air-cooled condenser. Steamis extracted trom the steam turbine generator andexported trom the plant. The variables measured todetermine corrected power output and correctedheat rille are: individual turbine generator output,power factor, auxiliary load, steam export, ambienttemperature, ambient pressure, relative humidity,fuel flow, and fuel healing value.

The sample calculations are based on a specificplant and test procedure. Do not apply the sampleuncertainties to any other performance test. Evaluatethe uncertainty of each test taking into accountthe test procedure, the calculation method and theuncertainty of the specific measurement methodsused tor thai particular test. The sample calculationsare given only to show the methodology by whichuncertainty is calculated.

The instrumentation uncertainty of the measure-ment method was estimated tor each variabie. PTC

6 Report can be used as a resource tor estimatingmeasurement uncertainties. The systematic uncer-tainty and random uncertainty used in these samplecalculations are typical tor primary instrumentation.The sensitivity tor each variabie was determined bychanging the variabie then calculating the changein the corrected power output or corrected heatrille. The sensitivity is expressed as the percentchange in the corrected power output or correctedheat fale per unit change in the variabie.

The measured power output is the sum of theindividual generator outputs less the auxiliary powerand the step-up transformer losses. The generatorsare three phase and have three-wire corinections.The power output trom each generator is measuredusing the two single-element metering method, anelectron ic watthour meter with high accuracy digitalreadout and uncalibrated current and potential trans-formers of the 0.3% accuracy class. The generatoroutputs are corrected tor step-up transformer lossesusing the transformer calibration curves.

The component systematic uncertainties of powermeasurement are:

Component SystematicUncertaintymeteringmethod zerowatthour meter :!:0.15%potential transformers :!:0.30%current transformers :!:0.30%

The uncertainty in determining step-up transformerlosses is negligible.

Combining the systematic uncertainties of thecomponents gives:

178

Up :::p (0)2+ (0.15)2+ (0;J2 + (0;J2 + (0)2

::: 0.34 ,

The systematic uncertainty of power output foreach generator is 0.34%.

The power factor for each generator is determinedfrom the power measurements. The systematic uncer-tainty of power factor is 0.2%.

The auxiliary power is measured using the threesingle-element metering method, an"electronic watt-hour meter with high accuracy digital readout anduncalibrated current and potential transformers ofthe 0.3% accuracy class. The systematic uncertaintyof auxiliary power is 0.5%.

The steam export is measured using a venturi meter-ing run. The Reynolds number is 3 x 106.The flow sec-tien is uncalibrated and inspected before and after thetest to assure no changes in the flow element. The meterhas no flow straightener. The pressure differentialacross the venturi and steam pressure are measured us-ing laboratory calibrated pressure transducers of the0.1 % accuracy class. Steam temperature is measuredwith a calibrated RTO. The systematic uncertainty ofsteam export is 1.2%.

Inlet temperature is measured with calibratedRTOs. There are four RTOs in the inlet air stream

of each gas turbine. Incorporating spatial variationsamong the RTOs and the assumption of no differencebetween the inlet temperature of the air-cooledcondenser and the average gas turbine inlet tempera-ture gives a systematic uncertainty of 2.0°F (1.1°c).

Ambient pressure is measured using a laboratorycalibrated pressure transducer. The systematic uncer-tainty is 0.01 psi.

Relative humidity is determined using a capaci~tance based humidity sensor. The systematic uncer-tainty is 1% relative humidity.

Fuel flow is measured usingan orifice meter witha f3 ratio of 0.6. The Reynolds number is 3 x 106.The meter is inspected before and after the test toassure no changes in the flow element. The meterhas no flow straightener. The pressure differentialacross the orifice and fuel pressure are measuredusing laboratory calibrated pressure transducers ofthe 0.1 % accuracy class. Fuel temperature is mea-sured with a calibrated RTO. The systematic uncer-tainty of fuel flow is 0.75%

Fuel heating value is determined from multiplegrab samples sent to a laboratory and analyzed witha gas chromatograph. The systematic uncertainty is0.5%.

The sensitivity of each variabie represents thechange in corrected output or corrected heat rateper unit change in the measured variabie. The sensi-tivity for each measured variabie was determinedby creating a spreadsheet containing the calculationmethodology for corrected output and corrected heatrate. The measured variables were then varied and

the change in corrected power and corrected heatrate are the sensitivity with respect to the correspond-ing variabie. The sensitivities could have been simi-larly determined using a model of the plant createdwith thermal cycle modelling software.

The random uncertainty for each variabie wasestimated as the standard deviation of the mean of

previous test data.The combination of sensitivities, systematic uncer-

tainties and random uncertainties into the total uncer-

tainty is shown in Table F.l.

UPcorr :::

Pcorr (B

)2

(Sp

)2

Pcorr corr

Pcorr + t Pcorr

UHRcorr :::HRcorr (

BHR

)2

(SHR

)2

corr corr

HRcorr + t HRcorr

UPcorr-p ::: --'/0.7322 + (2 x 0.160)2 ::: 0.799%

corr

UHRcorr . (

~ ::: ,\,1.0882 + (2 x 0.321)2 ::: 1.264%corr

The total uncertainty of corrected power is 0.80%.The total uncertainty of corrected heat rate is 1.26%.

It is assumed that test procedure is designed suchthat the degrees of freedom are at least 30. Therefore,the student's t is 2.0. If the degrees of freedom areless than 30, the student's t must be calculated andused in the calculation of total uncertainty.

179

TABLE F.1

SAMPLE UNCERTAINTY CALCULATION ,Uncertaintyof Corrected PowerOutput

Variabie Sensitivity

0.39% per %0.39% per %0.22% per %0.021% per %0.110% per %0.015% per %0.34% per oF0.61 % per oe1.15% per %0.038% per %

Gas turbine 1 powerGas turbine 2 powerSteam turbine powerAuxiliary loadSteam exportPower factor

Ambient temperature(SI units)

Ambient pressureRelative humidity

Systematic uncertainty (B)

Random uncertainty (S):Tota! uncertainty of corrected

power:

Uncertainty of Corrected Heat Rate

Variabie Sensitivity

0.39% per %0.39% per %0.22% per %0.021 % per %0.11% per %0.015% per %1.00% per %1.00% per %0.28% per OF0.50% per oe0.09% per %0.003% per %

Gas turbine 1 powerGas turbine 2 powerSteam turbine powerAuxiliary loadSteam exportPower factorFuel flow rare

Fuel healing valueAmbient temperature

(SI units)Ambient pressureRelative humidity

Systematic uncertainty (B)Random uncertainty (5):

Total uncertainty of correctedheat rare:

180

Systematic Standard Random

Systematic Uncertainty Deviation UncertaintyUncertainty Contribution of the Mean Contribution

0.34% 0.133% 0.17% 0.0663%0.34% 0.133% 0.18% 0.0702%0.34% 0.075% 0.21% 0.0462%0.5% 0.011% 0.05% 0.0011%1.2% 0.132% 0.25% 0.0275%0.2% 0.003% 0.02% 0.0003%2 0.680% 0.34 0.1156%1.110.1% 0.115% 0.01% 00115%1% 0.038% 0.10% 0.0038%

0.732%0.160%0.799%

Systematic Standard Random

Systematic Uncertainty Deviation UncertaintyUncertainty Contribution of the Mean Contribution

0.34% 0.133% 0.17% 0.066%0.34% 0.133% 0.18% 0.070%0.34% 0.075% 0.21% 0.046%0.5% 0.011% 0.05% 0.001 %1.2% 0.132% 0.25% 0.028%0.2% 0.003% 0.02% 0.000%0.75% 0.750% 0.23% 0.230%0.5% 0.500% 0.17% 0.170%2 0.560% 0.34 0.095%1.110.1% 0.009% 0.01% 0.001%1% 0.003% 0.10% 0.000%

1.088%0.321 %1.264%

itI1

APPENDIX G - ENTERING AIR CONDITIONS

(This Appendix is not a part of ASME PTC 46-1996,)

PTC 46 requires measurements to determine theconditions of air (i.e., dry bulb temperature, specifichumidity, and barometric pressure) at the planeat which it enters combustion or heat rejectionequipment. The purpose of this. Appendix is toexplain why entering conditions have been specified,and the potential ramifications of this designationin assessing the performance of a plant.

The performance of plant combustion and heatrejection equipment are functionally related to thecondition of air entering the equipment. Heat faleand net power must be corrected for differencesbetween the design and test ambient air conditions.The test boundary, as discussed in Section 3 of thisCode, requires that the test boundary be drawn sothat the inputs crossing the test boundary are notinfluenced by conditions within the test boundary.This is not necessarily true, however, with air atthe inlet to plant equipment. Depending on plantdesign, component orientation, sight conditions, andwind speed, and wind direction at the time of thetest, the temperature or humidity of the air enteringplant equipment may be affected by plant heatlosses. Steam vents, cooling tower exhaust plumes,and other heat Jasses may be entrained into theambient air as it is drawn into combustion or heat

rejection equipment.The magnitude or frequency of entrainment or

heat jasses into the air entering plant equipment ishighly dependent on plant design and layout. As aresult, it would seem more appropriate to measurethe ambient air conditions at a temperature locationupwind of the plant. Although this may be preferabie,it is generally not practica!. Air temperature andhumidity vary with elevation and with upwindground conditions. The air entering the combustionand heat rejection equipment is drawn in from all

directions. As aresuit, the average conditions of airdrawn into the equipment cao vary significantlyfrom the conditions measured at any single upwindlocation. In addition, variations will occur over time

with changes in ambient lapse fale (changes intemperature with elevation), wind conditions, andthe ground-effects upwind of the plant.

As previously stated, plant performance is a func-tion of the condition of the air entering the equip-ment. A performance test is of little value if it caonot provide repeatable results that cao be comparedto design values at a specified set of conditions.Since there is no practical war of correlating ambientair to the air which enters the equipment, multipletests based on measurements of ambient air will

indicate widely scattered results due the effects ofvariations in wind speed, wind direction, and ambi-ent lapse rate. The only alternative would be tospecify and measure ambient lapse rate, wind speed,and wind direction at base reference conditions.

However, this would significantly increase the com-plexity and expense of testing, and would restricttesting to times wh en these ambient conditions wereall within specified limits of their respective basereference values. As a consequence, tests couldbe delayed indefinitely while waiting for ambientconditions to change.

Even though entering air has been specified itmust be recognized that entrainment of heat jassesinto the air entering equipment is a potential problemthat could have significant detrimental effect on theactual output and performance of the plant. Becausea PTC 46 test will not reveal the effect of heat

losseson plant performance, it is especially importantfor these potential effects to be carefully reviewedand considered during plant design and equipmentspecification and in the development of the overallplant performance test plan.

181

APPENDIX H - ENERGY BALANCEMETHOD


The energy balance method combines the energybalance equation

input + credits = output + jasses

with the efficiency definition

(output. 100)input

to arrive at

ff ' ,

[input - Jasses + creditS ] 100e Iclency = ' t.

InpU

= [1 - losse~ - creditS ] . 100Input

Efficiency determination by the energy balancemethod requires the identification and measurement

(or estimation) of al! losses. Figure H.l illustratesthese losses. The primary measurements for effi-ciency determination by the energy balance methodare chemica I analysis of thefuel, sorbent, residue,and fJue gas; the higher healing value of the fuel;and air and flue gas temperatures.

Many ether measurements are required to deter-mine values for al! of the losses; however, severalof them usually have a minor effect on the results.

In many cases, partjes to the test may agree toestimate values for certain Josses,rather than measur-ing them; however, the uncertainties of estimatedvalues are usually greater than if the values weremeasured. Losses are sometimes determined on a"percent input" basis rather than an absolute basis.

183

TI

II,

Input laRF)Energy in tuellchemical) fi,

tEnergy in ei'ltering dry lIir

Energy in moisture in entering air

OpBDA

OpBWA

OpBF

OpBSlf

OrBx

Sensible heat in fuel

Energy gain due to sulfation

Energy trom auxiliary equipment power

Sensible heat in sorbent

Credits(OpB)

OrBSb

QrBWAd Energy in IIdditionlll moi$ture

I--III,,IIIIIIIII1_____-

Envelope ,Boundary r - - - - - r - - - - .-Energy in primarysteam

~- - - - ~ - - - - -~Energy in auxiliary steam and blowdownI II ...~ - - - - Energyindesuperheaterand'-- <'" I circulationpumpinjectionwater...I

...~ - - - - Energy in feedwater

r - - - - - L - - -- .-Energy in reheat steam outI I, ...II~ - - - - Energyin desuperheaterwater~-~...

, , r.- - - - - Energyin reheat steam in

Output(DrO)

losseslapt)

Energy balance: output = input - losses + credits

orO = OrF - OrL + OrB

OrL OrBOpL =100 x OrF' % OpB = 100 x OrF' %

Fuel efficiency (percent) =EF 1%) = 100 x ~utputInput= 100-OpL + OpB

FIG. H.l STEAM GENERATOR ENERGY BALANCE

184

-----------------

OpLDFg Energyin .-QpLWF Water infuel

OpLH2F Water trom burning hydrogen

OpLWA Moisture in air

OpLSmUb Unburned carbon and other combustibles

OpLRi $en!;ible heat in residue

OpLAq Hot air quality control equipment

OpLALg Air infihration

OpLNQx NOx formation

OrLSrc Surface radiation and convection

OrLWAd Energy in additional moi$ture

OrLClh Calculation and dehydration ofsorbent

OrLWSb Water in sorbent

aftAp Radiation to wet ashpit

OrLRy Energy loss trom recycled solids and gas

OrLCw Ener!!y in coolin!! water

OrLAc Air preheater coi!

APPENDIX I - SOLID FUEL AND ASH SAMPLING


1.1 GENERAl

The methods of sampling shall be agreed uponby pIl partjes to the test pnd must be described inthe test report. An appropriate uncertainty must beassigned tor the method of sampling used tor a test.

The sampling program conducted during the per-formance test has a significant effect on the steamgenerator efficiency result. Of all the data CQllectedduring a test, the higher healing value (HHV) of thesolid fuel is the variabie having the most influenceon steam generator efficiency. Further, on somaunits, unburned combustibles lost in the residue(based on carbon concentration) are a major energylasso If samples are not representative of the respec-live solid streams, the steam generator efficiencyresult is questionable. In addition, the variation inthe composition of solids directly affects the uncer-tainty of the steam generator efficiency. In thisAppendix, the methods used to determine variances,standard deviations, and precision indices tor thesamples obtained during the test are discussed. Theestimation of bias limits is also addressed.

1.2 METHODS OF SOLID SAMPLING

Fuel, sorbent Of applicable), and residue solidsshall be sampled trom a flowing stream as naar tothe steam generator as practical to ensure that sam-ples are representative. If it is not possible or practicalto sample naar the steam generator, a time lag maybe incurred between when the sample is taken andwhen it is actually injected or removed trom thesteam generator. This time lag must be determinedbased on estimated flow rates between the samplelocation and the steam generator. It is importantthat the time-Iagged sample be representative of theactual material injected or removed trom the steamgenerator. "Thief" sampling or taking a partial cutsample trom silos or hoppers has large associatedbias errors. One possible exception to this is sorbent,which in most cases is homogenous. Parallel streams,

such as coal feed with belt feeders, have the potentialtor variation trom stream to stream because of differ-

ent flow rates, particle sizes, pnd chemical composi-tion. Therefore, unless the chemical constituents of

the samples cao be shown to be uniform, the samplesmust be taken trom each of the parallel streamsand combi ned. If the flows tor the parallel streamsare unequal, the amount of samples of each parallelstream must be flow weighted tor the compositasample. The flow tor each of the parallel streamsmust be continuous throughout the test.

Depending on the casts associated with laboratoryanalyses and the availability of a historical database, different options may be selected tor differentsample constituents (i.e., coat, sorbent, residue).

Fuel or sorbent samples collected upstream tromsilos, tanks, pnd hoppers typically have larger biasesthan samples collected downstream trom silos, tanks,pnd hoppers. Samplings trom upstream of silos, tanks,pnd hoppers are classified as alternate proceduresbecause of the possibility of samples not beingrepresentative of fuel fired during the test. Alternateprocedures should not be used tor acceptance tests.For other test purposes, if altemate procedures areused, the partjes to the test shall assign appropriatebiases.

1.2.1 Sampl~ Size. As stated previously, it is ex-tremely important that any sample be as representa-live of the cQmposition of the actual stream aspossible. In addition, since there is a direct correla-tion between individual sample weight and variance,sufficient weight of individual samples is requiredto minimize the variance.

Generally, a complete cross section of the flowingstream is the most representative. This criterion,however, cao meao different sample size require-ments tor different types of solid streams. For exam-ple, the fiV ash residue stream sample should beobtained trom isokinetic particulate sampl ing. Thissample is typically very smal!. However, since it istaken trom a complete pnd controlled traverse ofthe flue gas duct, the sample is representative. In

185

this case, the small quantity is a minor factor in

regard to the reliability of the sample.Another example of the acceptability of a smal!

quantity of sample is sorbent sampling. The size ofsorbent may vary, but it is likely that the chemicalcomposition does not vary across the size range oramong different lots of sorbent. Therefore, a smallsample can be representative of the entire sorbentfeed during the test. .

In summary, the actual sample size must be basedon several factors, including size distribution, chemi-cal composition variability, feed methods, flow ca-pacities, and number of samples. In genera!, largersize samples result in lower variances. However, assample size increases, so do sample preparationcasts for reducing to a size for laboratory analysis.For manual sampling of coal or sorbent, samplestypically weighing from 2 to 8 Ib are collected. Forautomatic silmpling devices, much larger samplescan be collected.

The weight of the individual test sample must beequal to or greater than the weight of the samplesused from a historical database. Otherwise, the vari-ance of the test database could be greater than thevariance of the historical data.

The factors previously noted, combined with goodengineering judgment, casts, agreement betweenpartjes, and desired accuracy of sample analyses,should be used by the testing participants to deter-mine the proper sample size. Table 2 of ASTMStandard D 2234 provides more information aboutsample size.

1.2.2 Sample Collection. ASTM D 2234 providesguidance on sample collection. The I/stopped belt"technique is the preferred or reference method. Zerosampling bias should be assigned if the "stoppedbelt" technique is used. Using this method, a loadedconveyor is stopped, and a full cross-section cutnormal to the flow stream is taken. The width ofthis cut should not be less than three times the topside of the solid. In many cases, however, stoppedbelt sampling is not practical; therefore, full-cutsampling should be used. Using full-cut sampling,the sample is taken from a full diverted cut of amoving stream. Figure 1.1 shows a typical "full-cut"sampling method. A "thief" probe, as shown in Fig.1.2 may be used for taking a sample from a flowingstream if a full-cut sampling device is not available. Apretest run is recommended to identify and alleviatepotential problems in the sampling techniques.

1.2.3 Handling Samples. Sampling must be cilrriedout only under the supervision of qualified personnel.

The procedure used must be developed and carefullyimplemented to ensure that representative samplesare obtained and to prevent contamination in sam-

pling devices and storage containers. Samples col-lected outdoors must be protected from externalenvironmental influences during collection. Airtight,noncorrosive storage containers prevent degradationof the sample until it is analyzed. Each sampleshould be sealed immediately after being taken.Samples should not be mixed in open air prior toanalysis for moisture because of the potential formoisture lasso

Samples must be properly labeled and describedin terms of their significance to the test. The labelshould include, as a minimum, the date, time, loca-tion, and type of sample taken.

ASTM Standards D 2013 and D 3302 should befollowed in the preparation of coal samples. Sorbentanalysis procedures are addressed by ASTM D 25.

1.3 BIAS FOR SOllD FUEl AND SORBENTSAMPLING

When the bias of a sampling procedure is esti-mated, the test engineer should consider the follow-ing potential sources. There may be other sources,and not all sources listed are applicable to allmeasurements.

. sampling location/geometry

. probe design

. stratificationof f'owing stream

. number and Iocation of sample points

. ambient conditions at sample Iocation

. fuel/sorbent viability

. fuel/sorbent size

. sample handlinglstorage0 duration of test. quantityof sampleobtained

An estimate of the bias from a sample is a combi-nation of bias limits from sample acquisition, loca-tion, and stream consistency.

Sampling methods other than those recommendedmust be assigned higher biilses.

Before conducting a performance test, it is manda-tory that partjes to the test make a pretest inspectionof the sampling locations, identify the samplingmethodology, and make the sampling probes avail-able. Careful attention should be paid to areas where

samples might not be representative. Sampling ofcoal and other solid materials from a moving streamcan result in more of one size range of particles

186

Solids storage bin

Solids conveyor

ry Solenoid valve

QAir cylinder

actuator

Limit switch in

closed position

Sampling bladeSample chute'

Main chute

Pipa withpipa cap

tTo process ~

To sample collection container

Methods tor obtaining sample:1. Close isolation gate on dust suppression system. This wil! eliminate tinas removal.2. Initiate samplediverter gate to sample position. This is do ne pneumatically with a duration set by a timer.3. Adjust timer to obtain a proper sample size.4. Throw away the tirst sample.S. Collect 5 gallon bucket and seal container. Prepare tor riffling, crush. and size.

FIG. 1.1

187

ConveyorTypical ~hief probe sampling location.

Care must be taken to get a

representative silmple.

A A

Section A-A

Design:Consists of two concentric pipes with the same sample hole configuration. The probe is inserted jnto a flowing solids streamwith the sample ports cios ed. (The inner tube rotates 180. relative to the outer tube from the sample position.) The inner tubeis rotated to align the sample holes and is rotated back with the inner tube now full of material.

FIG. 1.2

188

during collection. If systematic (bias) errors are pres-ent in the sampling system, the errors must becorrected, or the parties must assign conservative(higher) bias limits.

1.4 TYPEOF SAMPLES

Coat or sorbent samples may be individual, partial-composite, or full-composite samples. Residue sam-ples other than tor fly ash should be individualsamples.

1.4.1 Individual Samples. Separate analysis samplesare prepared trom individual samples, referred toas "increments" in the terminology of ASTM 02234,Standard Methods tor Collectión of a Cross Sampleof Coal. The analysis samples are individually ana-Iyzed tor the applicable constituents, healing value,carbon content, moisture, etc. The average valueand precision index of each constituent are calcu-lated using the following equations.

XA VE = l/n(xl + X2 + X3 + . . . + xn)n

= l/n 2:Xii=1

(1.4-1)

where

XA VE = arithmetic average value of a mea-sured parameter

Xi = value of measured parameter i at anypoint in time

n = number of times parameter X is mea-sured

m

XAVE = l/m 2:XAVEkk = 1

(1.4-2)

where

XA VEk = average value tor set k given by Eq.(1.4-1) with the addition of a subscriptto denote the set

This procedure would be used when there areno historica! data available to estimate the precisionindex of the samples.

1.4.2 Partially-Composited Samples. This is an al-ternative to analyzing individual samples, predicatedon the availability of valid historical data. The objec-live is to reduce laboratory costs. The constituentsare grouped into "composite" (e.g., carbon, hydro-gen, and nitrogen) and "variable" (e.g., water, ash,and possible sulfur) constituents. The precision indi-ces of the "composite" constituents are taken trom

historical data. The precision indices of the "variable"constituents are based on individual analysis madetor the specific test.

The underlying premise tor this alternative is that"composite" constituents tor both the historical andtest data are trom the same statistica I population.As the constituents are trom the same population,a precision index derived trom historical data maybe used tor the test uncertainty analysis.

T0 simplify this discussion, coal constituents andterminology are used; sorbent constituents and termi-nology cao be substituted as appropriate.

As coat is typically stored outdoors, the moisturecontent of as-fired coal may have greater variabilitythan as-received coal. This increased variability mayinvalidate the premise that the historical as-receiveddata and the test data are trom the same statisticalpopulation. However, changes in moisture contentdo not affect constituents on a dry-and-ash-free basis.Where sulfur retention is an important considerationin the test, sulfur content should be included in thevariabie constituents. The variability of sulfur contentis often relatively large.

This alternative is not suitable tor residue samples.The composition of residue is affected by operatingconditions within the steam generator. There is nosimple war to ensure that historical and test datator residue would be trom the same statistica I popu-Iation.

Historical data should satisfy the following criteriato be valid tor sampling.

. The historical and test coat (sorbent) are trom thesame mine/quarry and seam.

. Historical data are the analyses of individual (notmixed) sample increments tor the coal {sorbent}.

. The historical and test samples are collected andprepared in accordance with ASTM Standards 02234, Standard Methods tor Collection of a CrossSample of Coat, and 02013, Standard Method ofPreparing Coat Samples tor Analysis.

. The types of increments of the historica! data andthe test data are ASTM 0 2234 Type 1, ConditionA (Stopped-Belt Cut) or Condition B (Full-SteamCut), with systematic spacing.

. The size of the historical samples is the same asthe size of the samples collected during the test.

If the historical samples were taken at a differentlocation, an additional bias likely has been intro-duced.

Two sets of individual analysis samples are pre-pared. One set is individually analyzed tor thevariabie constituents, such as ash and moisture. The

189

average value and precision index of each variabieconstituent are calculated using Eqs. (104-1) and(1.4-3).

PI = STDDEVMN (1.4-3)

where

PI = precision index for a measuredparameter .

STDDEVMN = standard deviation of the meanfor a measured parameter

The second set of individual analysis samples isthoroughly mixed and analyzed for the compositeconstituents. The average value of each variabieconstituent is the measured value .of the mixed

analysis sample.The historical analyses are converted to the dry-

and-ash-free (daf) basis by multiplying the as-re-ceived percentages (other than the variabie constit-uents, ash and moistu.re) by

100

100 - MpH20Fj - MpAsF;(1.4-4)

where

MpH20F; = moisture content, in percent, of histori-cal sample increment, i

MpAsF; = ash content, in percent, of historicalsample increment, i

For carbon content, the convers ion equation is

MpCFdaF,

]100 (1.4-5)= MpCFj [100 - MpH20F; - MpAsF;

where

MpCFj = carbon content of the fuel in percent,as-fired basis

MpCFda~ = carbon content of the fuel in percent,dry-and-ash-free basis

MpH20Fj = moisture content of the fuel in percent,as-fired basis (average of test analysis)

MpAsFj = ash content of the fuel in percent, as-fired basis (average of test analysis)

The convers ion equations for heating value, hydro-gen, nitrogen, sulfur, and oxygen are similar. ASTM0 3180 addresses the convers ion of analysis tromone basis to another and should be used.

Using the dry-and-ash-free values of the individualhistorical samples, estimate the maximum probablestandard deviation Soj'of each composite constituent.

Use Appendix A2, Method of Estimating the OverallVariance for Increments, of ASTM 0 2234 to deter-

mine Soj'The use of this Appendix requires for each compos-

ite constituent twenty or more analyses of individualincrements. If fewer than twenty are available, calcu-late the standard deviation, STDDEVj, of each com-posite constituent using the following equation:

STDDEVMN = [STO~EV2] V,

[1 n

= n(n - 1) ;~1 (Xl - XA VE)2] !ll(1.4-6)

where

pt = precision index for a measuredparameter

STDDEVMN = standard deviation of the meanfor a measured parameter

STDDEV = standard deviation estimate from

the sample measurementsPSTDDEV = population standard deviation for

a measured parametern = number of times parameter is

measured

X; = value of measured parameter iat any point in time

XAVE = arithmetic average value of a

measured parameter

The precision index for each composite constit-uent, PIj, is for twenty or more analyses:

Soj

PI = .~) 'JN

(1.4-7)

or tor less than twenty use:

[

F.n-l." x ST

..DDEV/

]

v,

Pij = N(1.4-8)

where

Fn-l.'"= upper jive percent point of the Fdistri-bution tor n - 1 and ex degrees offreedom. Table 1-1 provides selectedvalues of the distribution.

n = number of sample increments in thehistorical data

N = number of sample increments takenduring the test

The degrees of freedom of this precision indexare infinite.

190

tTABlE 1-1

F DISTRIBUTION

t

t1.4.3 Full-Composite Samples. This is also an alter-native to analyzing individual samples. For full-composite samples, none of the constituents areclassified as variabie constituents. This alternativemay be applicable for sorbents and coal whenhistorical data are available and changes in moistureor ash content are either very smal I or of minorconcern.

A composite analysis sample is prepared from thesamples taken during the test and analyzed for allconstituents. The average value of each constituentis the measured value of the mixed analysis sample.

The criteria and calculations given above for par-tial-composite samples are applicable to full-com-posite samples except thai the convers ion factor Eqs.(1.4-4) and (1.4-5) are excluded.

1.4.4 Systematic Sampling. With one exception, thesamples shall be collected at uniform, not random,intervals. The exception is when it is known thaithe collection sequence corresponds with IIhighs"or "Iows" in the fines content. In thai instance,random time intervals should be used. Each sampleshould be of the same weight. The elapsed time to

collect al! coal samples must equal the duration ofthe test run.

1.4.5 Number of Samples. The number of samplesto take during a test cao be set by trial and errorusing the precision indices of the constituents. Thepreferred method uses a complete pretest uncertaintyanalysis. See PTC 19.1. The number of samples isvaried parametrically. A number of samples areselected such thai the target test uncertainty caobe met.

An alternative method is to examine the directeffect of changing the number of samples on theprecision index of a resultant. The result may besteam generator efficiency, a heat credit or loss, orthe value of the constituent. A heat credit or lossis a war of highlighting the effect of a constituent.For example, the carbon content of residue has aprimary effect on the unburned carbon loss andrelatively lower effect on efficiency. The contributionof constituent j to the precision index of a resultantPIRj, is

PIRj = RBj x Pij (1.4-9)

where

R(Jj = absolute sensitivitycoefficientof constituenti on resultant R

The absolute sensitivity coefficients are obtainedfrom a sensitivity analysis. See PTC 19.1.

When the test samples are to be individuallyanalyzed, the standard deviation used to set thenumber of samples is estimated. Several possiblesources of data for estimating the standard deviationare the following:

. Prior individual analysis.

. The maximum and minimum values of the constit-uent. If the data are trom analysis of sample incre-ments, an approximation of the standard deviationis to divide the range by six.

. If the data for the ranges are trom composite sam-ples, an approximation of the standard deviationis to divide the range by three.

Wh en composite samples are to be analyzedtor the test, the precision indices described aboveare used.

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n-1 Fn-1

1 3.8415

2 2.9957

3 2.6049

4 2.3719

5 2.2141

6 2.0896

7 2.0096

8 1.9384

9 1.8799

10 1.8307

12 1.7522

15 1.6664

20 1.5705

40 1.3940

120 1.2214

infinity 1.0000

Documents

ASME_PTC_46_(1996)