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CONTRACTOR REPORT

SAND84- 7000 Unlimited Release UC-63

The Effect of Photovoltaic Power Generation on Utility Operation

Arizona State University Department of Electrical and Computer Engineering Tempe, Arizona 85287

Prepared by Sandia National Laboratories Albuquerque, New Mexico 87185 and Livermore, California 94550 for the United States Department of Energy under Contract DE-AC04-76DP00789

Printed February 1984

Issued by Sandia National Laboratories, operated for the United States Department of Energy by Sandia Corporation. NOTICE: This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, nor any of their contractors, Elubcontractors, or their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed. or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise, does not necessarily_ constitute or imply its endorsement, recommendation, or favoring by the United States Government, any agency thereof or any of their contractors or subcontractors. The views and opinions expressed here~ in do not necessarily state or reflect those of the United States Government, any agency thereof or any of their contractors or subcontractors.

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SAND84-7000 Unlimited Release

Printed February 1984

The Effect of Photovoltaic Power Generation on Utility Operation

Arizona State University Department of Electrical and Computer Engineering

Tempe, Arizona 85287

Abstract

Distribution Category UC-63

The effects of photovoltaic generation on utility operations has been studied using an automatic generation control computer simulation. Generation control was evaluated in terms of "area control error," a quantity for which the utility industry has set certain performance guidelines. Results of the study show that photovoltaic penetration levels of up to 10 % can be accommodated within the generation mix. Larger penetrations can cause difficulties under "worst case" scenarios, but these cases can be totally avoided by changes in generation scheduling, control, and/or dispersion of the PV generation .

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Principal Investigator P.M. Anderson

Uti Ii ty Advisors Salt River Project: Arizona Public Service:

S.M. Chalmers M.M. Hitt J . T. Unde rhill

Project Manager M. Thomas

November 1983

. V - vi

P.L. Vogt R. Ingersoll

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TABLE OF CONTENTS

Page

1. EXECUTIVE SUMMARY. • • • • • • • . • • • • • • • • • • • • • 1-1

2. INlRODUCTION. • •

2.1 Purpose of Work

2.2 Generation Control

2.3 System Modeling

2.4 Computer Simulation

3. SIMULATION RESULTS •

3.1 Introduction

3.2 Control Performance Criteria

3.2.1 3.2.2

Deterministic PV Behavior Probabilistic PV Behavior

2-1

2-1

2-1

2-2

2-2

3-1

3-1

3-2

3.3 PV Generation on the APS System •.•.•...•.•.• 3-9

3.4

3.3.1 3.3.2 3.3.3

The APS Fall Morning Load The APS Winter Morning Load The APS Summer Peak Load

PV Generation on the SRP System

3.4.1 3.4.2 3.4.3

The SRP Fall Morning Load The SRP Winter Morning Load The SRP Summer Peak Load

. • 3-29

3 .5 Probabil i s ti e Cloud Model Simula ti ons • . • . . . . . • • 3-50

3.6 Summary of Results . • . . . . . • . • . 3-51

4. COO CLUSIOOS 4-1

4.1 Research Results 4-1

4.2 Sped fie Observations and Conclusions 4-2

4.3 General Conclusions 4-3

4.4 Utili ty Evaluation 4-4

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5.

5.1

5.2

RECOMMENDATIONS FOR FUTIJRE WORK

Simulation Studies

Simulation Program Improvements

5.2.1 5.2.2

Power Plant Modeling Network Modeling

5-1

5-1

5-1

5.3 Priori ties. . . . . • . . . • . • . • . . . • . . . . . . 5-3

6 • APPEND! CES

A.

A.I

POWER SYSTEM CONlROL

Load Frequency Control

A.Ll A.L2 A.I.3 A.L4

Functional Description Mathematical Formulation The LFC Algorithm Important Factors

A-I

A-4

A.2 Economic Dispatch • . • . . . • . • . • . . . A-13

A.3

A.4

A.5

A.2.1 A.2.2 A.2.3 A.2.4 A.2.5

Functional Description Mathematical Formulation The ED Algorithm Important Factors Integration of LFC and ED

Reserve Margi ns .

NERC-OC Cri teria

Summary . . . . .

A.6 References For Appendix A

B. PHOTOVOLTAIC POWER GENERATION SYSTEMS

B.l Photovol taic System Configurations

B.Ll B.l.2

Dispersed PV Systems Central Station PV Generators

A-20

A-22

A-29

A-3l

B-1

B-1

B.2 PV Array Design Characteristics. . . . . . . . • . . . • B-10

B.3

B.2.l B.2.2

PV Power Plant Response Rates PV Response to Changes in Insolation

Cloud Types • . . . . . . . . . . • B-19

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B.4

B.S

B.6

B.7

B.3.1 B.3.2

Cloud Groups Cloud Types

The Deterministic Cloud Model

Special Cases of Interest

B.S.1 Cloud Moving with Angle 9=90 0

B.S.2 Cloud Moving at 450 over a Square Array

The Stochastic Cloud Model

B.6.1 B.6.2 B.6.3 B.6.4

Shadow Field Formation Effect of Cloud Cover on PV System Computer Simulation Graphical Outputs

References for Appendix B

B-2S

B-30

B-32

B-38

C. POWER SYSTEM LOAD BEHAVIOR . • . • . • • • • . • • • • • • C-l

C.l Introduction

C.2 Typical Load Patterns

C.3 Load Simul a ti on

C.4 Load Stochastic Behavior

C.S References for Appendix C

D. AGC SIMULATION . . • • •

D.l Power Systems Modeling

D.2 The Existing AGC Simulation Program

D.S

D.2.l D.2.2 D.2.3 D.2.4

AGC Program Structure The AGC Program Models Data Requirements Typical Simulation Results

References for Appendix D

C-l

C-3

C-3

C-7

C-lS

D-1

D-l

D-10

D-22

E. THE ARIZONA SYSTEM OF APS AND SRP • • • • • . • • • • • • E-1

E.1 Introducti on E-1

E.2 The Three Area Control Simulation E-1

E.3 Area Parameters E-2

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E.3.1 E.3.2

APS Generation SRP Generation

E.4 Validation Simulations of the APS/SRP System ...... E-7

E.4.1 E.4.2

System Measured Performance Data Simulated Results of Validation Test

E.5 References for Appendix E . . . . . . • . . . • . . .. E-27

F. TABULATED SIMULATION RESULTS

G. GFNERATION SCHEDULES

H. COMPUTER OUTPUT SAMPLE

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ACKNOWLEDGEMENTS

A large number of people contributed to the work described herein.

Engineers from APS and SRP. working under special subcontracts. provided

information on their systems that were essential to the success of the

project. These prople included Dick Ingersoll and Phil Vogt of APS. and

Steve Chalmers. Mike Hitt. and John Underhill of SRP. All gave generously of

their time and provided helpful support and comment that only experienced

people can provide. We also acknowledge the generous support of the planning

and the mechanical engineers from both utili ties who helped us gather the

necessary power plant data.

Several people at ASU also provided support. Faculty members Anjan Bose

and Paul Russell helped with Appendi ces A and B. respectively. Graduate

student Muhammed Khan developed the cloud model. and Dale Tice provided the

Spline program and other software support. Anj an Bose 'also provided many

comments and suggestions throughout the work that were very helpful.

The special projects group at APS were helpful in making frequency

measurements and assisted in the interpretation of data. These people

included Dick Farmer. Baj Agrawal. and John Christy.

Special thanks are due also to Sudhir Virmani and Systems Control. Inc ••

who supplied the AGC simulation program that provided a working computational

tool for this project.

The Sandia project management of Mike Thomas provided genuine support and

helped keep the project focused on the proper objectives. Gary Jones. also

of Sandia. was always a skilled observer and provided valuable advice on our

interpretation of PV behavior.

Finally. we acknowledge the skill and patience of our secretary. Mrs.

Lani Collins. who was responsible for the quality of this report.

P.M. Anderson

November 1983

xi

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Section 1

EXECUTIVE SUMMARY

This project was established to examine the effect on utility operation of

photovol taic (PV) generation that is interconnected to an electric utility

grid. Various PV concentrations and performance characteristics are examined

in this report and the effect on uti Ii ty genera tion control performance is

evaluated.

The purpose of these studies is to model the behavior of PV generators, to

integrate these model generators into a typical utility system, and to

determine the resulting system behavior. The results of these studies show

clearly that PV generation can be integrated into a utility system in

substantial amounts without creating any unusual problems in system operation

and control. The most severe condition created by PV generation results from

the sudden change in PV generator output when the entire array is completely

covered or uncovered by a fast moving cloud bank. This appears to the system

to be very much like the large, sudden load change associated with industrial

rolling mills or electric furnaces. These large load changes can be tole

rated but, as their size increases, any system will begin to experience

control problems as the disturbance size approaches about 10 percent of the

connected load. Because the PV generation is uncontrolled and appears to the

system to be part of the load, this same kind of limitation is observed for

large PV penetrations. There are a number of control countermeasures that

can be used to minimize the effect of large load changes.

measures are studied and the results reported herein.

Several such

Much of this report is involved with the study of the limiting conditions of

rapid PV changes in large concentrated arrays. These changes are studi ed

under various system load conditions, but all load cases studied were chosen

to illustrate rapid load ramping and maximum control effort. This combi

nation of maximum PV change and rapid load ramping is chosen to provide a

severe practi cal test to the sys tem control. Thi s kind of 'worst case

analysis' is commonly performed in power system studies and represents a

condi tion of maximum stress. Most of the time the system performs much

better than would be implied by these tests. We concentrate on these severe

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case studies to probe the limits of system performance, and to devise control

countermeasures that are effective. It should not be assumed that these

severe cases are the system norm.

Generation control is evaluated in terms of a quantity called 'area control

error' or ACE. In North America, the industry has set gUidelines of accep

tabl e ACE performance as a measure of the adequacy of generati on control.

These industry guidelines are used in the present studies to evaluate the

effect of rapid changes in PV generation on the control performance. The

studies were made using computer simulations that analyze the power plant

dynamics over time periods of 30 minutes, with the ACE performance computed

as part of the simulation.

The results provide detailed models of PV generation changes in response to

cloud movements. These models include the complete covering or uncovering of

an array by a large cloud and the stochastic behavior due to many small

clouds. The PV generation, being uncontrOlled, appears to the system control

center to be part of the net system load. The PV generation has a much

faster response rate than conventional generating uni ts and the effect of

clouds can cause rapid load changes that must be compensated for by the

conventional generating units. These simulations were performed using actual

system data and generation schedules of the Arizona Public Service Company

and the Salt River Project. both of whom cooperated fully in the work.

The computer simulations were made using an automatic generation control

(AGC) program, a block diagram of which is shown in Figure 1.1. The simu

lation is driven by the load model for each control area. The generation of

each area is dispatched by the control center in response to load changes.

Our simulation represented three areas; the APS area, the SRP area, and a

large third area to represent the Western United States and Canada. In these

simUlations, a PV generator of a given size was represented in one area and

this PV generation was changed in response to a predetermined cloud movement.

It was determined that the complete covering (shadowing) or uncovering of an

array represented the most severe PV change. Wind velocities of 5, 10, and

15 mls were studied to determine the effect of the different rates of change

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LOAD PLANT DATA DATA

PLOAD

~ PNET LOAD + L SYSTEM

DYNAMICS -

PPV COMMANDS

CLOUD PV CONTROL MODEL GENERATOR CENTER

Figure 1.1 Simulation Program Structure

MEASUREMEN TS

PERFORMANCE OBSERVATION

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in the PV generation. Performance measures were recorded for each simulation

run to provide a means of comparing results.

The performance measures believed to be the most practical to use were taken

to be those prescribed by the North American Electric Reliability Council

(NERC) Operating Committee, often referred to as the NERC-OC criteria. These

guidelines are necessarily broad and constitute a minimum standard with which

every system conforms.

The guidelines are practical minimum control standards. They have been

arrived at by pooling the long years of experience of large numbers of system

operators across the USA and Canada.

The NERC-oC Guidelines consist of twenty-two sections, each pertaining to a

particular aspect of system operation. Six guidelines directly affect

control performance. The one measure that is deemed the most useful in

determining control performance" is the 'area control error,' or ACE. This

quantity, which is used extensively to monitor system perfcrmance in a given

area, is described fully in Appendix A. Separate criteria are used for

normal and disturbance conditions.

In our studie s. the average ACE cri terion proved to be the most useful, and

is the one used extensively in evaluating results. Another criteria,

relating to the time between zero crossings, was less valuable because ACE

often failed to cross zero at all in our simulations, which were only 30

minutes in duration.

Simulations were performed with PV generation added to either the APS or SRP

system in sizes of 50, 100. 150. 200. and 250 MW. Comparative runs were made

for a Fall (light) load condition. a Winter peak condition, and a Summer

annual peak condi tion. Summary plots of these runs were made, similar to

those of Figure 1.2 and 1.3. Figure 1.2 shows the val ue of average ACE for

varying PV ratings with wind velocities of 5. 10. and 15 m/s. Note that the

average ACE cri teria is exceeded for ratings in the 80 to 100 MW range for

the example shown in Figure 1.2.

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3: ~

Z

LaJ U

• <t w (!) <t 0:: W

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+60 15 I /5

"0 / I I

+ 50 / V

I / I I

I I +40

I 1 V /

/ /

+30

+20

+10

,

1'1 if ~ / /

/;' I

A 'I / /

NERC LIMIT r--~-~----- _. ~ ---r--

f /' '1//

~

~/ , o

o 50 100 150 200 250

PV RATING IN MW

Figure 1.2 Average ACE for Various Positive PV Penetrations on the SRP System, Winter Load Condition

1-6

O~----~~----~-------L------~------~ o 50 100 150 200 250

PV RATING IN MW


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Various corrective measures were also examined, an example of which is shown

in Figure 1.3. Using the 15 mls wind to uncover the PV array, the effect of

adding regulation of an existing unit (42) is shown to increase the PV rating

to 100 MW at which point we again violate the NERC limit. Al so shown in

Figure 1.3 is the effect of adding a faster response unit such as a combined

cycle generating uni t. One such unit (55) rai ses the viola tion limi t to 125

MW and two units (55 + 56) raises this crossing to about 150 MW. These and

other results are presented to indicate the limits of PV penetration on the

APS and SRP systems for the load levels studied.

A summary of the results are presented in Table 1.1 in terms of the range of

% penetrations, where the percentages are based on load served. The

'positive PV' case refers to a switching £n of the PV array and the 'negative

PV' case to a switching off operation. Both the worst case and the best case

are recorded in the table, where the best case is that due to either a more

favorable (5 m/s) wind or added regulating capacity. From these results we

may compute averages to conclude approximately that

• Substantial PV generation totals in the power systems studied cause no

serious system upsets, even when switching on or off at maximum rate.

• For large PV penetrations, say 10% or more of the system generation, the

utility may wish to change the generation amount or type assigned to

regulation duty in order to respond quickly to PV changes.

• For the pOSitive PV case both the APS and SRP systems should be able to

correct for a 5 to 10% PV penetration, although this may require

adjustments in the normal regulation schedule, additional regulating

units, or both.

• For the negative PV case both APS and SRP should be able to accommodate

6 to 8% penetration except at the annual peak (Summer) load condition,

at which time both systems have small regulating reserves •

1-8 Table 1.1

Range of Values at Which the Average ACE Cd terion

is Exceeded, Stated as a % of System Load

FALL WINTER SUMMER

Min Max Min Max Min Max

Posi tive APS 10.2 16.3 5.5 6.3 3.4 4.6

Posi tive SRP 5.8 6.8 5.3 10.0 5.3 7.4

Negative APS 4.4 8.2 1.1 8.2 0.7 1.5

Negative SRP 2.4 5.8 1.0 6.7 2.6 3.0

These conclusions are specific to the APS and SRP systems analyzed.

The report also presents certain general conclusions that are believed to be

consistent with the observed data and its relevence to power system perfor

mance in general.

• The change in PV generation due to cloud movement appears to the power

system as a change in load, and is very much like the large industrial

load condition observed on many utility systems.

• As PV penetrations exceed the range of 5 to 10% of the system load, the

conventional generation has difficulty in tracking rapid PV changes.

• When PV generation changes are made there is a possibility that NERC-OC

guidelines will be exceeded temporarily.

• A utility that has an uncontrolled large PV plant may have to make

accommodations in the dispatch of regulating units to assure adequate

positive and negative regulating margins, distribution, and rates.

• The system operator would benefit by having metered information from

concentrated PV generators as well as good forecasts of cloud location,

type, and movement.

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In worst case conditions the utility may have to add spinning reserve to

the generation mix and may need to control the PV generator in order to

fully comply with the NERC guidelines,

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2.1 PURPOSE OF WORK

Section 2

INlRODUCfION

The purpose of the work described herein is to study the stochastic behavior

of photovol taic (PV) electric generating units that are integrated into a

utility system. Our particular objective in these studies has been to

examine the effect of PV behavior on the utility operation, control, and

generation dispatch. We assume that PV generating units are installed on the

utility system in various configurations, from small dispersed units to

large, concentrated central stations. (See Appendix B for PV models.)

PV generating units have operating characteristics that are greatly different

than conventional utility generating units. There are two characteristics in

particular that are of interest in the present studies; the speed of response

and the energy storage. PV units have a much faster speed of response than

conventional utility generators--orders of magni tude faster. In this study

we examine the effect of rapidly changing PV generation on the system

operation and quantify this effect through computer simulations. PV uni ts

are also unique in their lack of energy storage. Conventional utili ty

generating units have substantial energy storage that is continually

exchanged with the system load. PV units do not have this capability. Since

present system controls are predicated on the basis of conventional unit

characteristics, we are interested in examining the effect of PV units on

thi s control.

2.2 GIlNERATION CONlROL

Utility generation is controlled to optimize economy under certain physical

and operational constraints. This control is performed at centralized

'energy control centers,' where computers are used to analyze the system

condition and to send control signals to all generating units in that

computer's control area (usually a given operating company). These energy

control centers are described in Appendix A. We assume that, for the

purposes of the present study, the PV generating units are not controlled.

2-2

This means that all PV generation appears to the control center as a negative

electrical load. The behavior of this load. and its effect on the control

performance. is of central interest.

2.3 SYSTEM MODELING

Our approach to these studies is to construct a realistic dynamic computer

simulation of the utility generation. the energy control center. and the

utility load (which includes the PV generation). This requires careful

examination of the mathematical models required for the particular system

dynamics of interest.

In order to insure realism in the studies. agreements were made with the

Arizona Public Service Company (APS) and the Salt River Project (SRP) , both

of Phoenix, Arizona. These utilities provided data for their systems.

including their loads. generation characteristics, and generation schedules

for speci fie conditions. These system condi tions then provided a realistic

framework to which PV generation was added for study purposes.

The mathematical model of the PV generating units is described in Appendix B

of thi s report. We derive models that describe the PV output for various

cloud conditions that cause the output to vary in either a deterministic or

stochastic manner.

We also use some care in m,odeling the load characteristics of the APS-SRP

interconnected system. Utility load is controlled by the consumer and

appears to the supplying utility as a randomly varying pattern. We attempt

to model thi s random load characteris ti c as accuratel y as possibl e.

evaluation and the resulting model are described in Appendix C.

2.4 COMPUTER SIMULATION

This

A computer simulation, developed as part of a Department of Energy research

project, was obtained from Systems Control. Inc. that provided an excellent

basis for these studies. This simulation, described in Appendix D. provides

a method of modeling and studying conventional utility generating units and

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their control performance. Our objectives required that we revise the

utility load representation to permit the inclusion of PV generation.

Appendix D provides a description of the simulation structure and the type of

results obtainable. It also provides information on the conventional

generating unit models and describes the data requirements for these models.

The actual system loading conditions identified for study were selected in

consultation with APS and SRP. Actual system loading and generation

schedules were used to establish realistic condi tions and to validate the

simulation. These system load conditions are described in Appendix E.

Section 3 describes the simulation results. In cases where control perfor-

mance violations occurred. certain corrective measures were studied and are

reported in this section. Finally. Section 4 provides some conclusions and

comments on the results.

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Section 3

SIMULATION RESULTS

This section s1lIIlmarizes a group of simulation runs with concentrated PV

generation included as an integral part of the utility generation mix. The

generation simulated, other than the PV generation, consists of the actual

APS and SRP generation, A three area simulation is used throughout, with

WSCC (see Appendix E) forming the third area. PV generation is added to the

APS or SRP areas, under varying conditions of PV penetration, generation mix,

and load behavior, to determine the resulting system performance. Particular

attention is paid to the NERC-OC performance criteria as a standard by which

control evaluation is measured. The NERC-OC performance criteria are

discussed in Appendix A.

3.1 INTRODUCTION

The simulation runs evaluated herein use three control areas with actual APS

and SRP uni ts comprising two of the areas and WSCC the third area. It is

considered important that realistic generation be used in these control

studies so that the results can be interpreted by utility engineers on a

basis that they find familiar and reasonable. To this base of actual

generation is added PV generating units of varying sizes and load scenarios

that are selected to stress the control performance in a realistic way.

Various load behaviors can be studied using the AGC simulation program.

However, it is generally agreed that load ramping, at constant ramp rate, is

one of the most difficult load behaviors for the generation to follow. The

reason for this is that the control is essentially an integral control, which

attempts to reduce any control error to zero in a reasonable time. However,

integral control systems are theoretically unable to track a ramped input

without error. Thus, a ramped load condition tends to exert control pressure

on the system to minimize the control error, and represents a practical test

condition that is experienced by the utility generators every day. When this

load ramping is coupled with PV ramping, at a much greater rate, a practical

severe system control test is established.

3 -2

The ramp rates of loads on utility systems are generally observed to be about

0.2% per minute, where the base load is the system peak. Thus. a 2000 MIi'

peaking system might experience a maximum load ramp rate of 4.0 MW/min. This

rate could be effectively increased by a change in energy sales scheduled

during the ramping period. Load ramps in both the increasing and decreasing

direction are of interest.

3.2 CONTROL PERFORMANCE CRITERIA

The NERC-OC control performance criteria, described in Appendix A, include

various measures of the effectiveness of system controls. Two measures that

are often used are the average value of ACE and the time between zero

crossings of ACE.

The average value of ACE is a convenient measure of the long-term performance

of the control that is easily measured and readily understood. The NERC

criteria, however, state that this control performance criterion can be

disregarded under certain conditions. One such condition is a sudden change

in load that exceeds a prescribed amount. Thus, the rapid switching of a PV

generator that appears to the control as a sudden load change, may establish

a condi tion that the control would not be expected to follow, and hence

eliminates this criterion from consideration (under given conditions>. It

should be noted that this average ACE cri teri on was e stabli shed with only

conventional generation in mind. This suggests that widespread use of PV (or

other stochastic or rapidly changing generation types) may require the

creation of new control criteria.

Another important performance cri terion is the requi rement that ACE cross

zero at least once each 10 minute period. This criterion is not relaxed for

unusual load conditions and must be adhered to even with large penetrations

of PV generation.

Thirty minute simulations were run in all tests described herein, with PV

generation increasing in 50 MW increments from 0-250 MW, for both increase

and decrease of PV generation. For each simulation, 11 control performance

criteria were computed and recorded. These criteria are:

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(1) RMS ACE (electrical) • MW

(2) RMS ACE (me chani ca 1) • MW

(3) RMS ACE (fil tered electrical) • MW

(4) Average ACE. MW

(5) Inadvertent Energy. MWh

(6) Time Error. s

(7) RMS Frequency Error, Hz

(8) Max Time Between Zero Crossings of ACE.

(9) Time of Occurrence of (8) • s

(10) Maximum Value of ACE. MW

(11) Time of Occurrence of Max ACE. s

These values are computed as follows:

Let

ACE Pmni - Psni + B At

where

Pmni metered net interchange, MW

Psni scheduled net interchange, MW

B frequency bias, MW/Hz

Af frequency error, Hz

But

Pmni PG - PL

where

PG area el ectri cal generation, MW

PL area load, MW

We may also define the generation as

PG

where PL

PGO

PLO

H

and

PGO - BG Af -

~O + BvH

H 30

mechanical power generation at 60 Hz

load at 60 Hz

area inertia constant. s

Substituting into (3-1) we compute

3-3

s

(3-1)

(3-2)

(3-3)

3-4

(3-4)

We define the quantity in parentheses to be the 'dynamic ace' DACE (or

mechanical ACE) [11.

DACE = PGO - PLO - Psni

Using the above equations, we define the following terms:

(1) RMS ACE (electrical)

RMS ACE(Electrical)

(2) RMS ACE(mechanical)

RMS ACE (Mechanical)

(3) Filtered Electrical ACE (FACE):

FACEk+l = ~*ACEk+l + (1-~) FACEk

(4) Average ACE

Ave ACE = ~ 2 ACE N

(5) Inadvertent Interchange

(6 )

(7)

WI = 36~O 1 (Interchange Error *AGC CYcle Time) N

Time Error

(Frequency Error *AGC CYcle Time)

RMS Frequency Error

(3-5)

(3-6)

(3-7)

(3-8)

(3-9)

(3-10)

(3-11)

(3-12)

The summary of simulation runs for all load and generation conditions are

given in tables of Appendix F for both the negative and positive change in PV

generation. Two control indices that are required by NERC for all control

areas are the Average ACE and the Time Between ACE Zero Crossings. These

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control criteria may be plotted for the simulated load condi tions to illu

strate the effect of PV generation changes on system control.

Tests of both the APS and SRP sys tems were conducted for three di fferent

loading conditions: (l) a Fall morning (light) load. (2) a Winter peak

morning load, and (3) a Summer peak afternoon load. In each case the load

ramp is the basic load behavior to be studied. The Fall load (1) is typical

of that period of the year when loads are near the annual minimum. The

Winter load (2) is of interest because morning load ramp rates are greatest

during this season, and the generation mix is typical of winter peak load

conditions. Fina!ly. the Summer load (3) is of interest because this is the

peak time of the year and a large fraction of available generation is

scheduled for operation.

A description of the simulation results for each of these load periods is

presented. In each case, PV generation is added to the normal generation

mix, and the system response to sudden changes in PV generation is analyzed •

3.2.1 Deterministic PV Behavior

The first set of tests examines the effect of fast ramping of the PV

generation according to the Deterministic PV Model described in Appendix B.

When a large cloud, moving at a constant velocity, covers the array, the PV

generation changes in a ramp-like fashion. The ramp rate of this change is

in the nei ghborhood of one or two JAW/ s. In response to thi s change, the

conventi onal genera ti on is di rected by the control center to change its

output to correct the load-generation imbalance. These corrections, however,

are limited to only those generators that are on 'regulation' or on automatic

control and these regula ted generators are capable of a I imi ted response

rate, usually in the range of 2 to 3%/min. This means that the control error

will not be corrected rapidly and there is a possibili ty that certain NERC

control criteria will be exceeded. The exact amount of control response

depends on the size of the PV generator and whether this generation increases

or decreases. When the PV generation decreases the system control sees this

as a sudden increase in load, and the regulated generation is caused to

increase to replace the lost PV generation. This is conceived to be the most

3-6

difficult case, because the regulated generation may reach its upper

capability limit before attaining a balanced load-generation condition.

The net load seen by the system generation depends on the state of the PV

generation. The two cases of interest are illustrated in Figure 3.1. In

Figure 3.1(a) the PV generation rated PR is initially turned on (no clouds)

and is gradually covered by a large cloud. This makes the net load increase

by an amount equal to the PV rating. To simulate this condition, the

generation is scheduled to serve a load of Po' with adequate total generation

for the expected ramp condi tion. In our simulations, we scheduled the same

total generation as would be required for load Po' but backed off the

scheduled power of the less efficient units to exactly equRI the net initial

load Po'. We refer to this set of study conditions as the 'negative PV' set,

since the change in PV generation is negative.

Figure 3.1(b) illustrates the opposite problem. Here the load is initially

the actual system load Po and the PV generator rated PR suddenly switches on

due to movement of the cloud away from the array. This is the 'positive PV'

condition and it causes the net system load to decrease. Both the positive

and negative PV changes are described below for the three (Fall, Winter,

Summerl seasonal load ramp si tua tions and for the PV connected as part of

either the APS or SRP systems.

For the deterministic cloud behavior of the PV generator, the total average

rate of change of generation is of interest, because it is this rate that the

conventional generation must counteract in order to hold ACE to acceptable

values. This average rate of change is shown in Table 3.1, where the cloud

front is assumed to be inclined at 600 from the PV rectangular coordinates.

These rates of change will be useful in evaluating system performance under a

given generating condition.

•

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•

•

~ ~

z Cl <C 9

3: ~

Z

Cl « o ...J

p' 1

o

I

/~PV RATED PR

SW ITCHES OFF

3-7

(a) NEGATIVE PV CHANGE

o

Po

o

TIME

\ E~ \..Ot:-.O - -N'--1\. --- ----

( ---"'P: :TEO PR

SWITCHES ON (b) POSITIVE PV CHANGE

TIME Figure 3.1 Net Load Seen by System Generation with PV Generation

Switching (a) Off and (b) On in Switching Time ts

3-8

PV Rating MW

Table 3.1 Average Rate of Change of PV Generation for Wind Velocities of 5,10, and 15 mls

Transi t Time in minutes at 15 mls

Average Rate of Change in MW/min 15 mls 10 mls 5 mls

----------~---------------------------~------------------------------

50 1.81 27.6 18.4 9.2

100 2.55 39.2 26.1 13 .1

150 3.13 47.9 31.9 16.0

200 3.61 55.4 36.9 18.5

250 4.04 61.9 41.3 20.6

3.2.2 Probabilistic PV Behavior

The second set of tests involves the study of the stochastic behavior of a PV

unit under scattered cloud condtions. For this condition the PV generation

is continually changing in a random manner. This resul ts in a substantial

increase in the effective noise level in the observed system load, and causes

the generating units to continually 'chase' these disturbances. The results

of this condition show that both average ACE and time between zero crossings

are acceptable. Although the load deviation is much greater than normal, the

average characteristic is nearly constant and the net system disturbance is

not great. This analysis ignores the possible affect on the transmission

network, however, where the sudden PV switching may cause voltage flicker

problems that may be significant. The analysis of voltage problems is beyond

the scope of this project. Since this condition did not result in

significant control problems it was conducted only for the Fall load

condi tion.

Sections 3.3 and 3.4 present simulation results with PV generation added to

the APS and SRP systems, respectively. All three load levels are analyzed

for each system, using the deterministic cloud model in all cases. Section

3.5 presents results for both the APS and SRP systems where a probabilistic

cloud model is used.

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3 -9

3.3 PV GFNERATION 00 TIlE APS SYSTEM

The first set of tests provides for the addition of PV generation to the APS

system for each of the three load levels, Fall, Winter, and Summer. The APS

basic load conditions for these levels is shown in Table 3.2.

Table 3.2

Study Load Condi tions for the APS Sys tem

FALL WINTER SUMMER

Initial Load, MW 1470 1825 2944

Ramp Rate MW/min 2.7 3.2 0.65

Ramp Rate %/min 0.184 0.175 0.022

The Fall load is typi cal of a seasonal minimum load condi tion where the

morning load pickup is of interest.

maximum annual ramp rate studied.

annual peak load level.

3.3.1 The APS Fall Morning Load

The Winter condi tion represents the

Finally, the Summer condition is the

The Fall conditions selected for study on the APS system are shown in Table

3.3. Several items of interest should be noted from this data.

(1) APS is carrying a total spinning reserve of 648.6 MW (24%). but only

183.7 MW of this reserve is under automatic contr?l and therefore

available to replace any loss of PV generation.

(2) The total APS load is initially 2660 MW, but this will increase to 2741

MW during the 30 minute simulation, assuming a constant scheduled sale

of 1190 MW.

(3) The maximum PV generation loss that can be sustained with this

generation mix is about 180 MW, which corresponds to the regulation

margin. The negative margin (shown in parentheses in Table 3.3) is over

•

•

3-11

400 Mi, indicating that this system has much greater capability of

recovering from a load loss (+PV) than from a load increase (-PV).

The total response margin or available ramp rate of all units,

neglecting control deadband, is about 22 MW, which is inadequate to

track even a SO MW PV generation change at 15 mls (see Table 3.1).

The results of simulations for the APS Fall load level are presented in a

detailed tabular form in Appendix F. Here we present and discuss a summary

of these results.

For the positive PV case, runs were made for the normal generation schedule

of Table 3.3 with the wind velocity fixed at 15, 10, and 5 m/s. These

results are summarized in Figure 3.2 and 3.3, which show the NERC-OC criteria

average ACE and maximum time between zero crossings of ACE, respectively.

The average ACE is compared against the NERC limit for this performance

criterion, which is computed as (see Appendix A)

Ld = 0.025 AL + 5 Mi (3-13)

where AL is the greatest annual hourly load change in Mi. For the 1982 APS

system, AL was observed to be 252 Mi, thereby fixing Ld at 11.3 MW for all

simulations. This value is shown as a horizoutal dashed line in Figure 3.2.

Note that for a wind velocity of 15 mIs, the maximum wind velocity normally

expected, the NERC criteria or Average ACE is exceeded at about 150 MW.

Lower wind velocities permit even 200 MW PV generators to remain within the

NERC limit.

The NERC limit on the time between zero crossings is shown in Figure 3.3 and

the 600 second limit is again noted to be exceeded at about 150 MW. This

criterion proved to be of limited value in our simulations, especially for

the negative PV cases. The reason for this is that the simulations were

limited in all cases to 30 minutes (1800 s) and in many cases the ACE did not

cross zero at all in this time period. Thus, we rely more heavily on the

average ACE as the performance measure of interest.

In order to improve the system performance, and thereby permit the use of a

larger PV generator, various corrective measures were attempted. These

measures are summarized in Figure 3.4. where the 15 mls case with normal

3-12

3: ~

Z

IJJ U « IJJ (!) « a:: IJJ

~

+60

+ 50

+40

+30

+20

+10

/ v,/ / /

~

~/ /'

NERC LIMIT r- ..,.../ - - - - -,....~ --------r---~

~" '" ." '" . , fI' " ,.-" " -," ~.-~ _ ... ", --~ 1------ .

15 MIS

10 MIS

5 MIS

50 100 150 200 250

PV RATING IN MW

Figure 3.2 Average ACE for Various Positive PV penetrations on the APS System, Fall Load Condition

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•

•

~ Z o U

800

IJJ 700 C/)

Z

IJJ

!:l 600 La.. o C/) (!)

Z 500 C/)

~ o 400 a:: IJJ N

200

Figure 3.3

3-13

,.

oJ " ~ ~ ~ '"

L ' I

NERC LIMIT '-/

/ I

/ /

/ V I

/ / /

/ ~

) I

/ I

/ / I

V--- I v

50 100 150 200 250

PV RATING IN MW Maximum Time Between Zero Crossings of ACE for Various Positive PV Penetrations on the APS System, Fall Load Conditions

3-14

+60~------~----~~----~~----~~----~

+ 50r-----~~----_+------~------~----~

OL---~~~~~--__ _L __ --~ ____ __J

o 50 100 150 200 250

PV RATING IN MW

Figure 3.4 Average ACE for Various Positive PV Penetrations on the APS System, Fall Load Condition

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3-15

generation is also shown for comparison. The first corrective measure is the

scheduling of more uni ts to regulation duty. From Table 3.3 it is observed

that generators 3 and 9 have a total reserve of about 247 MW that can be

picked up. Not shown in Table 3.3 is the minimum generation limits of these

units (44.0 and 98.0, respectively), giving these units a reserve of 181 MW

that can be shed. For the positive PV case it is this load shedding

capability that will be needed (see Figure 3.1). The da$hed curve labeled

3+9 on A (Automatic Control) in Figure 3.4 shows the improvement in system

performance due to this added control capability.

Another method of improving control is through the use of combustion turbines

or combined cycle generating units. These units have very responsive gas or

oil firing systems that make the generators very maneuverable. Figure 3.4

shows the effect of adding first one and then two of APS' combined cycle

units, both scheduled initially at SO MW.

This process of utilizing additional units raises two questions, one of cost

and one of scheduling. Combined cycle uni ts, al though very efficient in

their thermo dynamic cycle, burn high cost gas or oil as a fuel. Assume that

oil fired generation costs tSS/MWh compared to t12/MWh for coal. This means

that a combined cycle unit generating 50 MW introduces a t2150/hr penalty in

fuel cost for every such unit used. if the added oil fired generation

displaces coal. The second problem is that of scheduling. If the added new

uni t effectively backs off a base loaded (manually controlled) unit, the

result will be an improvement in regulating capacity. If it replaces a regu

lating unit output it will improve regulation for negative PV and reduce the

regulating margin for positive PV. In the simulations performed for this

project, the added generation was used to replace base load generation

whenever possible. Also, the 75 MW combined cycle units were always

scheduled at 50 MW so that they could regulate either up or down. This

compromise setting was used since it could be argued that the system operator

does not know if the PV unit is on or off.

In summary, we note that the APS system can effectively absorb about 150 MW

of PV generation (1~) at the Fall 1982 load level without adverse effect and

that up to about 200 MW of PV (13.6%) can be accommodated with the addition

of regulating margin that is readily available.

3-16

-60------~------~--------~~--------

o~----~------~------~------~----~ o 50 100 150 200

PV RATING IN MW

Figure 3.5 Average ACE for Various Negative PV Penetrations on the APS System, Fall Load Condition

250

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3-17

O~~==~--~L---~L---~L---~ o 50 100 150 200

PV RATING IN MW

Figure 3.6 Average ACE for Various Negative PV Penetrations on the APS System, Fall Load Condition

250

3-18

The negative PV case is more critical. Here the PV generation is turning off

at a rapid rate and this appears to the controller as a large increase in an

already increasing load ramp (see Figure 3.1). The results are summarized in

Figures 3.S and 3.6. Note that the NERC limit is now exceeded at well below

100 Mi, but that the addition of regulating capacity is an effective

countermeasure.

Finally, we note that corrective measures, such' as those described, are

effective but the degree of improvement depends very much on the normal

generation schedule. This is particularly important when the normal schedule

has the units operating near their maximum or minimum limits. Placing such

units on automatic control does very little good if they are forced to their

limiting value quickly.

3.3.2 The APS Winter Morning Load

As noted in Table 3.2, the Winter load condition is different from the Fall

in the rapid ramp rate olthe load, which challenges the control to keep up

with the load change. The total Winter APS load is greater than the Fall

condi tion described in the previous section, but the net transfer out of the

area is smaller. The net resul t h a smaller generation total (2266 Winter

compared to 2660 Fall) with a much smaller regulation margin. The generation

schedule is shown ill Table 3.4. Note the very small response margin avail

able for this load condition.

The simulation results for the positive PV case are shown in Figures 3.7 and

3.8. For this condition the NERC limit is exceeded for PV sizes of about 100

Mi. Figure 3.8 indicates that improvements are possible if additional

regulation is available, but correction well beyond those illustrated are

needed for any significant improvement.

The results for the negative PV case are shown in Figures 3.9 and 3.10.

These results appear to be reasonably good, considering the severity of the

load behavior. but such resd ts requi red careful ' tuning' of the genera tion

schedule. Figure 3.11 shows a comparison for three generation schedules, all

for the same negative PV case. The line marked W corresponds to the IS mls

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3-19

• Table 3.4 APS 1982 Winter System Study Condi tions

Generator Rating Generation Schedule in MW Spinning Regulation Response No. Name.~_ Mil' ~nV!m Manual Auto Total Reserve ~/If~! gi~~_~~ _ ~arg!n

---'-"'-~'.'-' ..

1 FCl 175 4 162.8 162.8 12.2 12.2 4.0 2 FC2 177 4 163.1 163.1 13.9 13.9 4.0 3 FC3 220 5 214.9 214.9 5.1 5.1 5.0 4 FC4 800 20 5 FC5 800 20 695.0 695.0 105.0 6 CHI 116 2 104.6 104.6 11.4 11.4 2.0 7 CH2 235 5 225.6 225.6 9.4 9.4 5.0 8 CH3 245 7 245.1 245.1 0.0 0.0 0.0 9 CH4 370 8 300.2 300.2 0.0

10 OC1 115 6 37.6 37.6 77 .4 77 .4 6.0 11 OC2 115 6 12 SG1 115 6 28.8 28.8 28.8 86.2 86.2 6.0 13 SG2 115 6 14 YU1 75 2 34.0 34.0 41.0 15 WP4 33 3 16 WP5 12 1 17 WP6 63 6 18 CC1 75 5 50.0 50.0 25.0 5.0 19 CC2 75 5 • 20 CC3 75 5 21 OC CT 56 5 23 WP CT 112 5 25 SG CT 55 5 26 YU CT 56 5 32 CI 7 3 4.0 4.0 2.6

----------------- ~------

1277.3 1017.6 2266.1 364.2 240.6 37.0 Transfer Out 441 (511.8) APS Load 1825.1

•

3-20

3: :E

Z

IJJ U <{

IJJ (!) <{ 0:: IJJ

~

+60r-----~------~------~----~~ __ ~~

+50r-----~------~----~------~--~~

+40

+30

+20

--- _~C LlMIL +10

o------~~--~------~----~----~ o 100 150 200 250

PV RATING IN MW

Figure 3.7 Average ACE for Various Positive PV Penetrations on the APS System, Winter Load Condition

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• 3-21

+60~----~-------r------~------~~~~

+50r-----~------+_----_+------~~~~

0~-----4~----~------~------~----~ o 50 100 150 200 250

PV RATING IN MW

Figure 3.8 Average ACE for Various Positive PV Penetrations on the APS System, Winter Load Condition

+20 ON

3-22

3: ~

Z

I.LJ U <t

I.LJ (!) <t a:: I.LJ

~

-60--------~----~~----~------~--------

15M/S -50~------~----~------~-------+------~

10

-40

5

-30

-20

--- UMJ.I... -10

O~----~~----~------~------~------~ o 50 100 150 200 250

PV RATING IN MW

Figure 3.9 Average ACE for Various Negative PV Penetrations on the APS System, Winter Load Condition

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3-23

-6o.------r------~----_,------~----~

5M/S

-50r------r------r-----~------~----~1ge50

O~----~------~----~-------L----~ o 50 100 150 200 250

PV RATING IN MW


3-24

o~----~------~------~------~----~ o 50 100 150 200 250

PV RATING IN MW


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3-25

case from Figure 3.9. The generation for this case was scheduled by care

fully subtracting from both the manual and automatic generators in a fixed

ratio. so as to release capacity for regulation in proportion to the PV size.

Line U was the resul t of reducing only the manual generation in 50 MW

increments for each 50 MW jump in PV rating. The dashed line in between is a

rough economic dispatch prepared with the help of APS engineers. The result

ing differences are dramatic and illustrate the benefit of reducing the

schedule on the regulating units to provide them with more margin. This is

believed to be an issue that a utility would have to work out if a PV unit

were integrated with this system.

In summary. 100 MW (5.5%) appears to be about the limiting value for PV size

on the APS system at this load level. This limiting value represents a lower

penetration level than the Fall load condition because of the lower regula

ting margin for the Winter condition.

3.3.3 The APS Summer Peak Load

The Summer load level selected for simulation was that occuring during the

coincident 1982 APS-SRP peak hour. At this load level the load is great.

nearly all available generation is in service. and the load ramp rate is

small. This means that the generation should have little difficulty in

tracking the load and the only major load-generation imbalance will be that

due to PV generation changes.

The generation schedule for this condition is shown in Table 3.5. Note that

nearly all APS generators are scheduled. Also note that the regulation

margin is very small. because most units are scheduled to operate at near

rated capacity. This means that a negative PV change will be hard for the

system to follow. but a positive PV change should cause little difficulty.

The simulation results are summarized in Figures 3.12-15. Figures 3.12-13

illustrate the posi tive PV case. where it is noted that 100 MW PV systems

cause little difficulty. even though the available response margin is small

(20 MW/min). Moreover. adding an additional unit to automatic regulation

duty improves the result, as shown in Figure 3.13.

3-26 • Table 3.5 APS 1982 Summer System Study Condi tions

Generator Rating Generation Schedule in MW Spinning Regulation Response No. Name MW MW/m Manual Auto Total Reserve __ Mllrgin M_ar~iIl_ -~----- --------_._._- "'.-----.-~ -----~.--. ----

I FCI 175 4 108.6 108.6 66.4 2 FC2 177 4 162.5 162.5 14.5 3 FC3 220 5 215.8 215.8 4.2 4 FC4 800 20 722.0 722.0 78 .0 5 FC5 800 20 6 Clll 116 2 107.2 107.2 8.8 8.8 2.0 7 CH2 235 5 234.4 234.4 0.6 0.6 5.0 8 CR3 245 7 243.8 243.8 1.2 1.2 7.0 9 Cll4 370 8 348.6 348.6 1.4

10 OC1 115 6 80.8 80.8 34.2 11 OC2 115 6 80.8 80.8 34.2 34.2 6.0 12 SG1 115 6 13 SG2 115 6 100.8 100.8 14.2 14.2 6.0 14 YU1 75 2 74.0 74.0 1.0 15 WP4 33 3 n.n 32.0 1.0 16 WP5 12 1 11.6 11.6 0.4 17 WP6 63 6 53.5 53.5 9.5 18 CC1 75 5 31.0 31.0 44.0 19 CC2 75 5 31.0 31.0 44.0 • 20 CC3 75 5 31.0 31.0 44.0 21 OC CT 56 5 52.5 52.5 3.5 23 WP CT 112 5 104.3 104.3 7.7 25 SG CT 55 5 52.0 52.0 3.0 26 YU CT 56 5 51.0 51.0 5.0 n CI 7 3 4.2 4.2 2.8

---~--- .. ----~- --.----- --_._-

2166.4 767.0 2933.4 423.6 59.0 26.0 Transfer 11.0 (447.0) APS Load 2944.4

•

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3-27

+60~----~------~------~----~~----~15

10 + 50~-----+------~------+-----~--~L-~

0"----'-o 50 100 150 200 250

PV RAT I NG IN MW

Figure 3.12 Average ACE for Various Positive PV Penetrations on the APS System, Summer Load Condition

3-28

+ 60,.---........ --------..-------.---""""':1 J5 MIS

o~--~~~----~------~------~----~ o 50 100 150 200 250

PV RATING IN MW

Figure 3.13 Average ACE for Various Positive PV Penetrations on the APS System, Summer Load Condition

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3-29

The negative PV case, however, shows a very poor response. Even a SO MW PV

change causes a large error in average ACE, and this condition is little

improved by the addi tion on one or two regulating uni ta. This represents a

case where the system is running at nearly maximum capability and with little

margin. Under such condi ti ons, the loss of the PV generation has serious

consequences.

3.4 PV GENERATION (N TIlE SRP SYSTEM

The SRP system is very much like that of APS in size, load makeup, and

generation mix. The significant differences are:

o The SRP imports large amounts of power from the Navajo power plant,

which is partly owned by SRP, but the Navajo plant is outside the SRP

control area and therefore is unavailable for regulation.

o SRP has about 260 MW of hydro generation, which is an excellent source

of regulation capability providing water is available when needed for

this purpose (when the PV is operating).

The SRP load conditions for the 1982 level of this study are shown in Table

3.6.

Table 3.6

Study Load Conditions for the SRP System

FALL WINTER SUMMER

Ini t i a1 Load MW 1034 1498 2160

Ramp Rate MW/min 2.3 2.1 0.13

Ramp Rate %/min 0.222 0.140 0.006

These load and ramp characteristics are similar to the APS loads. Therefore,

any difference in the generation response will be due largely to the differ

ence in the generation mix serving each load level •

Detailed results of the SRP studies are given in Appendix F, but are

summarized here for convenience.

3-30

3: ~

Z

W U <t

w C) <t a:: W

~

-60

-50

-40

-30

-20

--10

/ o o

I~ fE Is I

1 I f, l'[' ,

Ii f' '/ ~

AI

j ~

NERC LIMIT - --- --- --- ---

50 100 150 200 250

PV RATING IN MW

Figure 3.14 Average ACE for Various Negative PV Penetrations on the APS System, Summer Load Condition

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3-31

~I .~ ~ ~I ,~ ~ ~ ~/ ~ ,'< .... "/.. ~

-60r-----.------r/~/~~'T-~/r-~~--~

I / /

" / V _50 __ ----~----~Jr7/_.~/TJ~----~----~ I , , I " / / I, / I -40~----+_~~~J/~/~~----~----~

/ I I I ~ /

I I I -30~-----r+1/-+,1-71·-tr/------~----~----~

II I / I

/ I I I

/11 -20r----+-V~~--~----~------~----~ "II

I~IJI / /~l

-10 - -:-~~ - - - - - - _N~C_ L.lliJIL_ /..' '/ '1~ ~?

o~----~----~------~----~----~ o 50 100 150 200 250

PV RATING IN MW

Figure 3.15 Average ACE for Various Negative PV Penetrations on the APS System, Summer Load Condition

3-32

3.4.1 The SRP Fall Morning Load

The Fall condi tions selected for study on the SRP system are sUlllJllarized in

Table 3.7. This light load level on the SRP system presents an interesting

problem because of the large transfer into the system and the small number of

uni ts available for regulating duty. The regulation margin of 175 MW is a

respectable quantity but the available response margin is small (5.0 MW/min).

The results for the positive PV case are shown in Figures 3.16 and 3.17. For

the SRP system the NERC limit is based on the 1982 maximum hourly load change

of 229 MW, giving a value of Ld of 10.7 MW. The results are disappointing

and indicate the lack of available units with rapid response rate. Even

placing unit 42 on regulation or adding a hydro (HM4) or combined cycle unit

fails to provide substantial relief (see Figure 3.17).

The negative PV case, shown in Figures 3.18 and 3.19, are even more critical.

Here, even the 50 MW PV generator switching causes the NERC limit to be

succeeded. The addition of new units to the regulation reserve is helpful,

but there is little room for additional units at this low load level. The

problem at this load level is aggravated by having limited regulation margin.

It would appear that several fast acting units would be required to correct

this problem, and it would be more economical to curtail operation of- the PV

unit, since only about 50 MW would be feasible at this load level.

3.4.2 The SRP Winter Morning Load

The SRP Winter generation schedule is given in Table 3.8. One notes

immediately that generator 41, which is scheduled for regulation, is fully

loaded and has no regulating margin for the negative PV case. The positive

PV case, however, should have a much better regulation capability.

The resul ts for the posi ti ve PV case are given in Fi gures 3.20 and 3.21.

This system has reasonably good regula tion and has adequa te capabi Ii ty to

support 75 to 100 MW of PV generation. The capability is greatly improved by

adding combined cycle units (55 and 56), as noted in Figure 3.21.

•

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•

3-33

• Table 3.7 SRP 1982 Fall System Study Condi tions

Generator Rating Generation Schedule in MW Spinning Regulation Response No. Name MW MW/m Manual Auto Total Reserve Margin Margin

41 COl 350 3 281.0 281.0 99.0 99.0 3.0 42 CO2 350 3 213.0 213.0 167.0 43 AF1 111 2 35.0 35.0 76.0 76.0 2.0 45 AF3 178 4 49 AF5 64 4 52 KY4 51 5 53 KY5 47 5 55 SAl 72 7 56 SA2 72 7 57 ROO 36 4 58 HM1 11 6 59 HM2 11 6 60 HM3 11 6 61 HM4 93 4 62 MFl 10 1 63 MF2 44 4 64 SM 13 1 65 CC 3

213.0 316.0 529.0 342.0 175.0 5.0 • Transfer In 505.0 (117) SRP Load 1034.0

•

3-34

~ :?! Z

l.&J U « l.&J (!) « 0:: l.&J

~

+60 I

,~ 15 /10 I , •

+ 50 I ,

/ I

+40

I / / / r,

// , /, +30 t / ,

fJ'I ~I

+20 /11 ~I

+10

VI I

--- 'r-lr- --r--- - ~ _NER~ r- LIMIL

't

~ 'I

,. o o 50 100 150 200 250

PV RATING IN MW

Figure 3.16 Average ACE for Various Positive PV Penetrations on the SRP System, Fall Load Condition

•

•

•

•

•

3-35

+50~-----+-------r-1~~~----~r-----~

O~~--~------~-------L------~----~ o 50 100 150 200

PV RATING IN MW

Figure 3.17 Average ACE for Various Positive PV Penetrations on the SRP System, Fall Load Condition

250

3-36

3= ~

2:

IJ.J U <t

IJ.J (.!) « a:: IJ.J > <t

-60 I~ ~p ,'5

-50 J J . I

I -40

I I

I I

-30

l -20

jJ 'I

-10 --II- -

/ o o 50

NERe LIMIT -- --- --- i- ---

100 150 200 250

PV RATING IN MW

Figure 3.18 Average ACE for Various Negative PV Penetrations on the SRP System, Fall Load Condition

•

•

•

•

•

3-37

-6or-----~-----=~~~~~,-0~N~A~--------

-50~-----+----~~--~--+-----~~----~

O~----~------~----~-------L----~ o 50 100 150 200 250

PV RATING IN MW

Figure 3.19 Average ACE for Various Negative PV Penetrations on the SRP System, Fall Load Condition

3-38 • Table 3.8 SRP 1982 Winter System Study Condi tions


41 COl 350 3 355.0 355.0 0.0 0.0 0,0 42 CO2 350 3 184.0 184.0 166.0 43 AFl 111 2 78.0 78.0 33.0 33.0 2.0 45 AF3 178 4 138.0 138.0 40.0 40.0 4.0 49 AF5 64 4 52 KY4 51 S 14.0 14.0 37.0 53 KY5 47 5 55 SAl 72 7 S6 SA2 72 7 S7 ROO 36 4 58 HMI 11 6 10.0 10.0 1.0 S9 HM2 11 6 10.0 10.0 1.0 60 HM3 11 6 10.0 10.0 1.0 61 HM4 93 4 49.0 49.0 44.0 44.0 4.0 62 NFl 10 1 63 MF2 44 4 64 SM 13 1 65 CC 3


•

•

•

3-39

+60~----~~----~~----~-----r~--~--~ 5

+50~-----+-------r------+--r.-~r------4

o ""'----~ o 50 100 150 200 250

PV RAT I NG IN MW


3-40

o~------~~------~------~------~------~ o 50 100 150 200 250

PV RATING IN MW


•

•

•

•

3-41

The negative PV case resul ts are shown in Figure 3.22. As postulated

previously. this system lacks regnlation capability and even a small PV loss

causes the average ACE criterion to be exceeded. This situation is greatly

improved by placing unit 42 on automatic control. curve 42A in Figure 3.23.

The addition of combined cycle units (55 and 56) greatly improves the situa

tion as shown in Figure 3.23.

Another sol uti on to the nega ti ve PV case is ill ustra ted in Fi gure 3.24.

Here. the dashed lines represent the same condition as Figure 3.22 except

that generator 42 is placed on regulation and the fully loaded generator 41

is placed on manual control. The solid line shows the 15 mls run from Figure

3.22 for comparison.

In summary. the Winter load condition is capable of supporting about 100 MW

(6.6%) of PV generation. but it requires oil-fired generation to achieve

adequate regulation.

3.4.3 The SRP Summer Peak Load

The SRP Summer generation schedule is shown in Table 3.9. The load level for

this case is high and most units are operating at near rated capacity. Even

some units on regulation are operating with very little margin. indicating

that the negative PV cases will be difficult for the system to accommodate.

The results of the SRP Summer simulations are summarized in Figures 3.25-

3.28. The positive PV condition does not cause a serious problem for this

system because the system has 670 MW on regulation. most of it highly loaded

and very capable of shedding large amounts of load. Clearly. over 100 MW of

PV capacity can be easily accommodated for this condition. and even larger PV

concentrations can be added by increasing the regulating capacity. as shown

in Figure 3.26.

The negative PV case. however. is much more severe. The system has very

limited capability for increasing generation. because of the heavy load. Even

adding the partially loaded unit 45 to regulating duty provides only marginal

improvement. and combined cycl e uni ts provide simi! ar reI lef. as shown in

3-42

3: :?! Z

I.&J U <t I.&J (!) <t 0:: I.&J

~

-60~----~------~--~~~------~-------

-50~------r-------r-H-+---~----~~----~

-40

-30

-20

NERC LIMIT

O~----~------~-------L------~----~ o 50 100 150 200 250

PV RATING IN MW

Figure 3.22 Average ACE for Various Negative PV Penetrations on the SRP System, Winter Load Condition

•

•

•

3: :E Z

L&J U

• « L&J (!) « a:: L&J

~

•

3-43

-60~----~------~--~~=r~T-~----~ 5+56 (! 50

-50~----~~-----+-4--~~~~--~----~

-40

-30

-20

L1MIL

O~~--~-------L------~------~----~ o 50 100 150 200 250

PV RATING IN MW


3-44

3= ~

Z

UJ U <t

UJ (!) <t a:: UJ

~

-50~-----1-------+~-----r~~+-~----~

-40

-30

-20

LIMIT --

O=-------~----~--------------~--------o 50 100 150 200 250

PV RATING IN MW


•

•

•

3-45 • Table 3.9 SRP 1982 Summer System Study Condi tions


41 COl 350 3 356.0 356.0 0.0 0.0 0.0 42 CO2 350 3 361.0 361.0 0.0 43 AFI 111 2 87.0 87.0 24.0 24.0 2.0 45 AF3 178 4 145.0 145.0 33.0 49 AF5 64 4 51.0 51.0 13.0 52 KY4 51 5 46.0 46.0 5.0 53 (Y5 47 5 45.0 45.0 2.0 2.0 5.0 55 SAl 72 7 56 SA2 72 7 67.0 67.0 5.0 5.0 7.0 57 ROO 36 4 36.0 36.0 0.0 58 HM1 11 6 10.0 10.0 1.0 S9 HM2 11 6 10.0 10.0 1.0 60 HM3 11 6 10.0 10.0 1.0 61 HM4 93 4 75.0 75.0 18.0 18.0 4.0 62 MF1 10 1 9.0 9.0 1.0 63 MF2 44 4 40.0 40.0 4.0 4.0 4.0 64 SM 13 1 9.0 9.0 4.0 65 CC 3 . 2.0 2.0 1.0


•

3-46

+60~----~------~-------r------~---'~ 15 1'0

I + 50~-----+------~------+------4--~--~

+40~-----r------~----~------~--~/~ /

/ /

+30~-----+------~------+---~~--~--~

+20~-----r------+-----~~----~----~

--+IO~-----+------~~----~~--~------~

0~---4~------~----~------~-----~

5

o 50 100 150 200 250

PV RATING IN MW

Figure 3.25 Average ACE for Various Positive PV Penetrations on the SRP System, Summer Load Condition

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3-47

+60r-----~------,_------~----~----~~

+50r------r------+------4------~-+--~

o~--~~----~------~----~----~

55 ~ 50 45A

o 50 100 150 200 250

PV RATING IN MW

Figure 3.26 Average ACE for Various Positive PV Penetrations on the SRP System, Summer Load Condition

3-48

3: ::E Z

lLJ U « IJJ (!) « a:: lLJ

~

-60

-50

-40

-30

-20

----10 A' /"~

o o 50

15f'I ~ jfJ

" /

PI ~

/1 " , I

I ~ 'II

1'/ /;1 'I

V -- --- _N.EBC_ t-~LL _

100 150 200 250

PV RATING IN MW

Figure 3.27 Average ACE for Various Negative PV Penetrations on the SRP System, Summer Load Condition

•

•

•

•

•

3-49

-60~-----'------~----~~~----~------

-50~-----+------~--~~~~--~~----~

O~----~------~------~-----L----~ o 50 100 150 200 250

PV RATING IN MW

Figure 3.28 Average ACE for Various Negative PV Penetrations on the SRP System, Summer Load Condition

3-50 ...

Figure 3.28. One must conclude that the PV loss creates a serious problem at

this load level and the operator would be inclined to shut down the PV rather

than operate several combined cycle units for regulation.

3.5 PROBABILISTIC CLOUD MODEL SIMULATIONS

It was noted previously that the random shadowing of the PV array by scat

tered cloud patterns produces a PV power output that varies in an unpredic

table manner. On the average, this random behavior tends toward a mean value

that is dependent on the array size, the type of cloud, and the fraction of

the sky covered by these clouds. For a given array size and sky cover, the

cloud type then determines the average output. For the simulations performed

for this project, the fraction of sky covered was set to 96% and held

constant at that value since this is only a scaling factor in the result.

The random nature of the PV behavior for these simulations makes the net

system load appear to the control center as having a strong noise component.

Thi s noi se component, which is due to both the load noi se and the PV

behavior, is strongly influenced by the PV output. This output tends to vary

rapidly about its mean value compared to the energy storage Hme constants of

the conventional generating uni ts. Thi s 1 arge rapi d vari a tion cause s the

control to change direction relatively often, with the result that the ACE

tends to cross zero often. The relatively slow thermal generation tends to

filter the noise due to the load and PV behavior, with the result being a

relatively normal controlled generation output.

Simulations using the random PV generator model were run only for the Fall

load level. The PV plant rating for these runs was held constant at 250 MW

and the cloud type varied. This sequence of runs was performed for the PV

generati on connected to each area CAPS and SRP) in turn. The resul ts of

these runs is presented in Table 3.10, where the value of average ACE is

given for all three cloud types with the sky cover constant at 96%. In all

cases the average ACE is well below the allowable limit. We conclude,

therefore, that the random PV behavior is not a serious problem for the APS

and SRP sys tems.

•

•

•

•

Table 3.10

Average ACE in MW for the Fall Load Level, Random PV

Area

of PV

APS

SRP

3.6 SUMMARY OF RESULTS

Clond Type

1 2 3

-0.53 -0.40 -0.78

3.42 -0.29 -0.66

3-51

The results of all simulations are summarized in Table 3.11 where the

quantity 'Max PV' is the approximate value of PV rating, for the case of a 15

mls wind, at the point where the plotted response curve crosses the 'NERC

LIMIT' line. This means that any PV rating in excess of the 'Max PV' value

tabula ted will resul t in exceeding the NERC-OC gui deUne for average ACE .

This is a simplistic criterion by which to judge a complex process, but it is

realistic in terms of accepted industry practice.

For the most part, the posi tive PV cases perform well up to about 5'111

penetration, i.e., 5'111 of the scheduled load at that time. Under certain

generation dispatches, this penetration can be increased (see APS Fall).

This, however, depends on the available units and their capability for

performing regulation duty. This will vary seasonally and will be different

for each utility.

3-52

Tabh 3.11

Summary of Limitins PV Ratinss for All Cases

FALL WINTER SUMMER

PV Type Ares Quantity MW " MW " MW % -----------------------------------------------------------------------------Posi tive APS Max PV 150 10.2 100 5.5 100 3.4

Reg Margin 434 29.5 511 28.0 447 15.2

MW/Min 22 1.5 37 2.0 26 0.9

Posi tive SRP Max PV 60 5.8 80 5.3 115 5.3

Reg Margin 117 11.3 331 22.1 160 7.4

MW/Min 5 0.5 10 0.7 22 1.0

Negative APS Max PV 65 4.4 20· 1.1 20 0.7

Reg Margin 184 12.5 240 13.2 59 2.0

MW/Min 22 1.5 37 2.0 26 0.9

Negative SRP Max PV 25 2.4 15 1.0 55 2.6

Reg Margin 175 16.9 112 7.5 53 2.5

MW/Min 5 0.5 10 0.7 22 1.0

*Normal Scheduh

----------------------------------------~-.-----------------------------------

The negative PV cases are clearly more difficult to accommodate when the

normal utility load is increasing. as was the case for all studies performed

here. The resul ts in Table 3.11 indicate that problems begin to occur at

about the 2% penetration level. although some cases indicate that problems

begin at lower levels. This is very strongly a function of the generation

schedule established by the operator. as noted from the APS Winter case where

an 'optimum dispatch' was clearly helpful (see Figure 3.11).

It should also be noted that all studies were conducted under conditions of

an increasing load ramp at nearly maximum seasonal conditions. Had the load

been chosen to ramp downward. the resul ts for positive and negative PV would

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•

3-53

be reversed and the posl ti ve PV case would be limi ting. This assumes that

<he ramp rate of conventional generators is the same downward as upward,

~hich is not universally true, but is a reasonable assumption on the whole.

Reference:

Virmani, et Ill.. 'Development and Implementation of Advanced Automatic

Generation Control; Final Report of Task I, Modeling and Analysis of the

WEPOO System,' DOE Contract EC-77-01-2118, Systems Control, Inc., 1979 •

•

•

•

Section 4

CONCLUSIONS

4.1 RESEARCH RESULTS

This project was proposed for the study of the effects of PV generation on

the operation and control of a utility system. The means of accomplishing

this objective was proposed as a computer simulation that would be capable of

evaluating control and performance.

These objectives have been realized. A sui table computer simulation was

obtained and was modified. validated. and used in the study of real systems.

This simulation tool remains as a tool for future studies by utilities or

research workers.

Another objective of this work was to evaluate the possible affect of PV

generation on utility operation. In this regard. we evaluated only the

effect on utility generation and the generation control. not the network

response.

resul t in

We found that large PV penetrations. of about 5 .. or more. can

control guideline viola tions. This resul t can not be sta ted

categorically, however. since the cont~ol performance depends so much on the

utility generation mix and the amount of that generation assigned to area

regulation. If the two utility systems that we studied are typical, and we

have reason to believe that they are,

generation could be a problem if no

uti! ity.

then the impact of significant PV

corrective action is taken by the

We also have shown that the utility has methods at its disposal of correcting

any observed control viola ti ons. One me thod is Simply to assign addi tiona!

spinning generation to a regulating function. Another alternative is to add

regulating units. particularly units that have rapid response rates such as

combustion turbines or hydro units. This corrective measure may be costly

and should be evaluated in terms usually used for unit commitment and econo

mic dispa tch •

4-2 ~ 4.2 SPECIFIC OBSERVATIONS AND CONCLUSI~S

In Table 3.10 a summary of results is presented. The.e results are pessimis

tic in the sense that they record the case for the wor.t wind condition (15

m/s) and for no corrective measures at all. Since any prudent system

operator would take corrective measures. these results should be taken as

limiting. However. based on the se limi ting reaul ta. we may draw certain

conclusions.

• The negative PV case was the most severe of thou studied. but this

would not be the case if the load were modeled as ramping downward.

Thus, either the positive or negative PV switching could be critical.

depending on the load behavior at a particular time.

• The resul ts indicate that the NERC Average ACE cri tarion is usually

exceeded at sbout 5 .. penetration for the positive PV case and at 1-2'1(,

for the negative PV case.

• Differences can be observed in the results. The se may be due to a

number of factors. some of which are the following:

(1) Generation regulating response depends on the regulating margin and

rate of response of individual units, whereas Table 3.10 gives only

the system totals. The dispatch computer anticipates the unit

response to prevent overshoot. and this affects the overall system

behavior.

(2) The uni t governors have deadband that can delay a given uni t from

beginning its response to control signals.

(3) The system is nonlinear; hence. a uniform cause-effect observation

should not be anticipated and, indeed, is not observed.

• In most cases where response is poor, this result can be attributed to

inadequate regulating margin, inadequate response rate of regulating

uni ts, or both.

• The resul ts for the criti cal nega ti ve PV case is strongly dependent on

the generation commitment and schedule. A. conventional uni ts are

•

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•

•

•

4-3

backed off to accommodate PV generation. this reduction should be

subtracted from regulating units only. if possible. This improves the

regulating margin by an amount equal to the PV rating. (This was not

done in all of th,J simulations. Instead. the reductions were usually

made based on economic dispatch and other operating considerations.)

• The addition of PV generating units adds a new dimension to generation

dispatch and control:

(1) The operator should monitor both positive and negative regulating

margin.

(2) The regdating margin should be well balanced among regulating

units.

(3) Units should be chosen for regulation that have good response rates.

both upward and downward.

(4) If possible. the operator should know the state of PV generation and

should have reliable forecasts of cloud movements.

(5) Under certain severe load. generation. and cloud condi tions it may

be advisable to control the PV generation rather than schedule

expensive regulation.

Table 4.1 presents a more optimistic picture than that of Table 3.10. which

examined only the worst case. In Table 4.1 both the worst case and the best

case are recorded. where the best case is that due to either a more favorable

(5 m/s) wind or added regulating capacity. From these results we may observe

that

• For the positive PV case both the APS and SRP systems should be able to

correct for a 5 to 1()11, PV penetration. although this may require

adjustments in the normal regulation schedule. additional regulating

units. or both.

• For the negative PV case both APS and SRP should be able to accommodate

6 to ~ penetration except at the annual peak (Summer) load condition.

at which time both systems have small regulating reserves •

4-4

Table 4.1

Range of PV Limiting Cases in % of Initial Load

FALL WINTER SUMMER

Min Max Min Max Min Max

Positive APS 10.2 16.3 5.5 6.3 3.4 4.6

Posi ti ve SRP 5.8 6.8 5.3 10.0 5.3 7.4

Negative APs 4.4 8.2 1.1 8.2 0.7 1.5

Negative SRP 2.4 5.8 1.0 6.7 2.6 3.0

4.3 GENERAL CONCLUSIONS

The simulation studies made as a part of this project were limited to an

examination of two utilities with a mostly coal-based thermal generation mix.

Although the uti Ii ti es were speci fic in terms of uni t mode 1 s, generation

dispatch, and load behavior, the results are probably typical of North

American systems. One is tempted, therefore, to draw general conclusions

that might be applied to the entire industry. Al though the resul ts are

believed to be typical in most respects, one should extropolate these

findings with considerable caution. We have but a single datum point to

guide OUT. thinking, and our conclusions based on this datum must be made

cautiously.

In particular, it would be unwise to concentrate on any single simulation

resul t for a general conclusion. Each individual simulation is loaded with

assumptions concerning system configuration, dispatch, load and PV presence.

• Substantial PV generation totals can be accommodated by a power system

without causing problems, even when the PV generation switches on and

off at the maximum rate •

• For PV penetrations of 10% or more, the utility will probably schedule

more uni ts to regulating duty and may regulate with faster responding

units.

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•

•

•

4-5

• Although certain PV penetrations are observed to cause severe apsets in

ACE. the correction of this error is available and is ef'feGtive, if

applied in sufficient quantity.

• There may be periods of maximum load during which the uti Ii ty has a

shortage in regulating capacity. and may not have stcndlly URi. ts

available. For such conditions. it may be in the utilities' b'Ht

interest to control the PV output during intermittent cloudy weather. to

prevent generation upsets that can not be regulated.

Taken as a whole. however. we can identify unmistakable trends that we may

confidently assert would be observed on any system.

identify some of these general observations.

We a t temp t here to

• As PV penetrations exceed the range of S~ or greater of the system load.

the conventional generation has difficulty in tracking rapid PV changes.

• When PV generation changes are made there is a possibility that NERC-OC

guidelines will be exceeded temporarily.

• A uti Ii ty that has an uncontrolled large PV plant may wi sh to make

accommodations in the dispatch of regulating units to assure adequate

positive and negative regulating margins. distributions. and rates.

• The system operator would benefit by having metered 1nformation from

concentrated PV generators as well as good forecasts of cloud location.

type, and movement.

4.4 UTILITY EVALUATION

The Arizona Public Service Company (APS) and the Salt River Project (SRP)

were associated with the project described herein. They have also prepared

their evaluations of the work. This evaluation follows.

4-6 Utility Comment On The ASU Study and Report Entitled:

Analysis Of The Stochastic Properties Of

Photovoltaic Generation On Utility Operation

The purpose of this project was to study the stochastic properties of

photovoltaic (PV) systems when integrated into a utility generation system,

wi th the specific obj ecti ve of examining the effect on uti Ii ty operation,

control, and generation dispatch. 1 The project involved the modeling and

analytical evaluation related to PV system behavior, the problems identified

in system operation and control, and the development of possible solutions to

these problems. A utility team from Arizona Public Service and Salt River

Project was asked to participate to assure realism and practical application

of the results and conclusions reached by the ASU research team. The utility

team was to:

1) Provide consultation to insure the analysis undertaken considered and

captured the many practical and real-time aspects of utility system

operation including the intricacies involved in minute by minute load

dispatch and generator operation,

2) Provide real-time data on utility system operation, incl uding those

periods involving very high ascending or descending load profiles,

and to,

3) Assist in study direction, assumptions, and analyses.

The utility team actively participated in formulation of the study's

analytical process, development of assumptions, modeling techniques and

selection of computer programs. The team met on a periodiC basis, at key

study intervals, reviewing individual task progress and overall program

results.

The utility team participated in the study basically for two reasons:

one, to add a sense of real world to the study and two, to start the educa

tion process regarding photovoltaic systems and their impact on utility

operation. The team's invol vement was principally focused on assuring the

study program and resul ts met a reasonableness check such that the results

would be meaningful and useful from a utility perspective.

The utility team's overall impression of the study results is that there

are some limitations but generally large scale PV systems can be economically

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•

•

•

•

4-7

integrated into the utility electrical system. with minimal impact on opera-

tion, control and generation dispatch. The study results and theoretical

impact on system operations are basically as expected with a resource of this

nature. PV resources will have an impact on uni t commitment decisions.

system regulation or unit response requirements, reserve requirements,

economics and the system dispatchers as they will be required to spend more

time in utilizing this resource than they otherwise would with conventional

resources.

System regulation (control of generation as required to meet changes in

system requirements) is significantly impacted by PV generation as it can

quickly increase or decrease in output. The study evaluated the effect of

the PV facility's size versus units on control. etc •• and found that the size

of each installation should be kept at or below a specific level to allow the

utility to remain within the North American Electric Reliability Criteria

(NERC) control guidelines.

Although the evergy cost is relatively low and displacement of higher

cost resources assured. the treatment of the PV resource for reserve purposes

must be evaluated possibly on an hourly basis. On a clear day, a utility

would most likely leave some of its firm resources off-line to maximize

savings. On a cloudy day. unit commitment to cover the uncertainty of the PV

output would be necessary and any available PV generation would simply reduce

the output of units already on line.

The commitment of additional conventional controllable generation

alleviates the regulation problem to some degree. but obviously the commit

ment of additional generation, to offset the potential rapid change in PV

output. will adversely affect the economics. Some of these problems will

undoubtedly be minimized with the addition of PV output controls. weather

stations providing advance warning of cloud cover. space diversity. etc.

As already noted.

provided insight into

the study has provided useful resul ts. The study

the control and generation dispatch issues which

utilities will encounter with the application of largescale PV resources.

The development of a study methodology and identification of principle

assumptions is also seen as a very valuable contribution. In addition, the

analysis provided the background required to begin development of a planning

and operating philosophy regarding PV resources. With the aid of the

computer program used in this analysis (which is being documented as an

4-8

extensi on of thi s work effort>, most util Hies would be well equipped to

evaluate the application of resources such as the PV system.

Regarding what needs to be done at this point, studies involving voltage

control (i.e., flicker), interconnection to the system, size, location, etc.,

will have to be completed to provide a complete assessment. Future studies

and the application of PV systems to the existing electrical network will be

highly dependent on the developing technology and its economic viability.

When large scale PV systems begin to appear, additional studies will be

required with more system orientation. Several years of actual on-line

testing will be required to fully determine the value of a PV system.

Researchers from the universities could provide additional expertise in the

field of theory and application which may not be readily available to the

utilities. Study teams made up of personnel from both the utility industry

and universities can make an important contribution to the development of the

PV system. The universities can help to develop good control models while

the utilities pursue extensive production costing and load flow studies.

lAPS system 1983 Summer peak was 2899 MW, installed capacity 3531 MW.

system 1983 Summer peak was 2260 MW, installed capacity 3226 MW.

SRP

•

•

•

•

•

•

Section 5

RECOMMENDATIONS FOR F1JIDIE WORK

The present project was carried out using a compllter simulation of a power

system. The simulation program was modified to permit the study of PV

generation in response to cloud movement. Various PV amounts were added to

the APS and SRP systems to determine the effect on generation control and the

NEIC operating guidelines.

In reviewing the resul ts of this study, several areas of future work are

observed. One area deals with simulation studies and the other with the

computer simulation itself.

5.1 SIMULATION SIDDIES

It is not possible to draw general conclusions from the study of only two

utility systems. The APS and SRP systems both include coal and oil-fired

theraal plants and have available a variety of hydro and combustion turbine

peaking units. At present, their systems do not include nuclear generation.

Utilities with a generation mix substantially different from those studied

will naturally question the results insofar a. their applicability to

a.other, quite different, system. This would suggest more extensive testing

of other uti Ii ty systems to see if similar ruul ts are observed. Wi th the

simulation tool available, there is no reason why any utility should not be

able to run similar tests on their own system.

5.2 SIMULATION PROGRAM IMPROVEMENTS

The experience with the AGC simulation program reveals some areas where

improvellent would be desi rabl e. The needed improvements are in two areas:

(1) power plant modeling, and (2) network modeling.

5.2.1 Power Plant Modelins

The current version of the program provides for detailed drum-type, fossil

fuel,i plants and a Simple model for small units, such as combustion

5-2

turbines. These two models were adequate for the APS and SRP studies, but

may not be adequate for other utility systems. In particular, the following

plant models are needed for general usage:

nuclear reactor unity (BWR and PWR)

combustion turbine units

once-through fossil boiler units

large hydro units

There are some additional needs that would make the program more useful. An

economic di spa tch algorithm would help in the redi spa tch of units to properly

schedule the PV generation. A method of interfacing the utility load to the

simulation model would be desirable. Improvements in the interactive

features of the program would make its use more effective. All of the models

required to provide for normal generation simulation are available, having

been used in other dynamic simulation programs. Thus, this additional

requirement becomes mostly a programming task to add these known models and

verify their performance.

5.2.2 Network Modeling

The current version of the simulation program does not model the transmission

natwork at all. All generators and loads are tied solidly together in a

given control area, as if the network were perfect. This is an idealistic

simplification that is accurate only insofar as the operator avoids network

probl ems.

The network model needed is only the high voltage interconnection that tie

the power plants together. The low voltage distribution systems will be

modeled as loads applied to the transmission network. This combined model of

power pI ants pI us ne twork is usually called a long-term dynami c model. No

simulation program is available that provides this combined capability

although EPRI has performed some research on the subject.

There are two reasons why a network model may be necessary for some studies.

First, the PV switching might cause serious voltage flicker problems in the

locality of the PV plant that may require correction. Second, if the network

•

•

•

•

•

•

5-3,4

is very heavily loaded, the loss of a large PV resource could have serious

effects that could lead to cascading live outages, voltage collapse, or loss

of load. These phenomena cannot be studied without a network representation.

There are two ways of adding a network to the present simulation. One way is

to solve the network separately, between integration steps, using the

computed generator powers as network injections. This is the partitioned

approach. Another approach is to merge the network algebraic equations with

the dynami c di fference equa ti ons to form a simul taneous sol uti on. Either

method will work and research will show which is the better approach in this

case.

5 .3 PRJ;ORITIES

The highest priority in the foregoing needs is in the modeling area. Some

utility companies will be unable to accurately model their system without the

addition of some of the models mentioned. The next priority should be the

addition of a transmission network model.

• 5-5,6 Section 6

APPENDICES

A. Power System Control

B. Photovoltaic Power Generating Systems

C. Power System Load Behavior

D. AGC Simula ti on

E. The Arizona System of APS and SRP

F. Tabulated Simulation Results

G. Generation Schedules

• H . Computer Output Sample

•

•

•

•

Appendix A

POWER SYSTEM CONTROL

The operation and control of interconnected power systems require the

adjustment of the generation-transmission-distribution system such that the

electric demand is met at all times in a secure and economic manner. The

control decisions are made primarily at the company level although, in some

regions, utili ties have formed operating pools to exploi t the economics of

joint operation. The decision analysi s and the control coordination is

conducted by a configuration of computers under the direction of human

operators.

The main objective in power system operation is to minimize cost while

matching generation to load. making sure that the operational limits of all

the equipment in the system are not violated. Although this is a wel1

defined optimization problem it is too large both in variable space and time

to be solvable in real time. Instead, the optimization problem is decomposed

temporally into several optimization problems to make the solutions feasible

with modern day computers.

In real time, the generation is adjusted to meet load every few seconds and

the outputs of the on-line generators are adjusted every few minutes to

minimize the cost of generation. These real time functions are known as load

frequency control (LFC) and economic dispatch (ED) and, together with a few

other real time functions like reserve monitoring and transaction scheduling,

consti tute automatic generation control (AGC). The main characteri s ti c of

AGC is that it operates automatical1y in real time to control the power

system.

However, the total cost optimization over time requires the proper scheduling

of the generators. The economic dispatch adjusts the output of generators

already on line, but commitment and decommitment of all the available

generators must be scheduled for optimal cost operation over time. Normally

the commitment decisions are made hourly and an optimal schedule must be

determined several days into the future. Figure A.I shows the time rela

tionships between LFC, ED and unit commitment (UC). An added difficulty in

•

Lono Term

Functions (MS,FS,HS) I

Short Term Functions (UC,HTC)

Economic Dispatch (ED,RM)

Load Frequency Control (LFC)

•

=l

::1

L .. I year + I week

L .. I week + I hour

• ---------_ .. Reo I Time

~ 2-10 minutes

• • ----------- Reol Time t-- 2 -6 seconds

Figure A.I Comparison of Time Frames of Power System Control

•

;l> I

N

•

•

•

•

A-3

UC arises because of energy limited generation. such as hydro plants with

water storage. The hydro-thermal coordination (HTC) can be one of the subset

of optimization problems.

Optimization over longer periods must take into account the seasonal

scheduling of water to hydro plants (DS). the scheduling of fuels (FS) for

thermal plants and the scheduling of maintenance for generating uni ts (MS).

Weekly scheduling of water. fuel and maintenance can be done to optimize cost

over several months for such long term optimization (see Figure A.I).

The different functions mentioned above are the decomposed subsets of the

total optimization problem. The long term, short term and real time

functions are separated by time horizons and then each subset is further

decomposed into separate functions. Power system operations require the

optimal solutions for all these separate problems although the mathematical

rigor used in such solutions may vary according to the cost savings obtained

in particular systems •

The long term functions are sometimes referred to as operations planning

functions. The system generation planning functions are also optimization

procedures. In planning, however. the time horizon is much longer (many

years) and the decision variables are the additional equipment needed for

system expansion. The objective is to minimize not only production cost but

also the needed capital cost for new equipment.

In this report. the impact of PV on system operations is explored. Thus. the

planning considerations and the capital cost of PV is not of direct interest.

The main characteristic of PV generation is that its production cost is small

and its availability is both cyclic and weather dependent. Since the econo

mic advantage of PV generation is clear. most of the emphasis here is on the

effect of PV on load frequency control. Related considerations of spinning

and ready reserve are also explored.

In this section the general area of power system control is introduced. In

the first subsection load frequency control is described. Economic dispatch

and reserve margin moni toring are presented in the next two subsections.

A-4

These real time functions, which constitute automatic generation control,

must be designed to meet the guidelines of the North America Electric

Reliability Council - Operating Committee (NERC-OC). The relevant NERC-OC

criteria are discussed next. The other economic considerations in the short

term and long term functions are presented briefly. Finally the

implementation of such power system control is discussed in terms of the

computational resources and commnnications required.

A.l LOAD FREQUENCY CONTROL

A.1.1 Functional Descrip.U.~1!.

The main objective of power system operation is to meet the electrical load

by matching generation to load demand. Since the load is changing randomly

without any control by the utilities, the problem is to continuously sense

the load and adjust generation accordingly. The best way to sense the

load-generation imbal ance is to moni tor frequency: when generation exceeds

load the frequency goes up from 60 Hertz and vice versa. The increase

(decrease) of frequency is the same as the increase (decrease) of the average

generator shaft speed.

Each generator is equipped with governor control that senses its own shaft

speed and adjusts the power of the prime mover by opening or closing the

valves to adjust the flow of steam or water. Governor controls are designed

so that turbine load reductions result in an increase in shaft speed. This

gives the turbine a negative torque-speed characteristic that intersects the

system load-frequency characteristic to give stable dynamic performance. The

turbine characteristic is usually called a 'droop' characteristic because the

turbine speed reduces as load is added. The value of the droop character

istic is usually stated in terms of the steady-state percent speed change

from full load to no load. This characteristic is adjustable, and is

normally set to about S% in the U.S. Figure A.2 shows a S'II> droop charac

teristic for both 100% and SO% loads.

If the power sys tem operates only wi th the control of the governors the

frequency would vary according to the load. To be able to control the

•

•

•

•

•

•

o w W Q.. (/)

SPEED-Q-iANGER SET TO GIVE RATED SPEED AT 100 % OF RATED OUTPUT

PERCENT OF RATED OUTPUT

SPEED-CHANGER SET TO GIVE RATED SPEED AT 50% OF RATED OUTPUT

Figure A.2 Governor Steady-state Droop Characteristic

A-S

A-6

frequency to 60 Hz at all load levels the governor reference must be adjusted

and the droop characteristic shifted up or down depending on the load. This

is accomplished by load frequency control. If the power system were not

interconnected the governor control and the load frequency control could be

shown in block diagram form as in Figure A.3. It should be noted that the

magni tude of the frequency change in an interconnected system is usually

small. For the system of Figure A.2 we may compute the steady state

frequency deviation Af

-60R • APn

PTotal Hz (A-I)

where R is the regulation or droop (-o.05). APn is the disturbance in MW. and

PTotal is the total rating of all generators in the system. Thus. for

example. a 100 MW step change in generation on a 50,000 MW system with an

average 5% regulation could be 0.006 Hz.

If the system is interconnected a disturbance in one system will affect the

frequency of the whole interconnection. The LFC in each system must respond

to the change but only in a manner that is equitable. In emergency

conditions the different systems should respond according to their size with

the system having the emergency picking up full responsibility. This is

known as tie line bias control. The block diagram for a two system tie line

bias control is shown in Figure A.4. The rest of this subsection describes

tie line bias LFC.

Load frequency control seeks to achieve three primary objectives. which are

stated below in priority order:

1. To maiutain frequency at the scheduled value.

2. To maintain net power interchanges with neighboring control areas at the

scheduled values.

3. To maintain power allocation among units at economically desired values.

The first two objectives are met by means of proportional-plus-integral

control on an error signal composed of frequency and net interchange

devi a ti ons. The third objective is met by apportioning the total needed

•

•

•

• A-7

I/R

GGT(~) t.PGCI) j'APD(I) Gp(l)

~+ t.Pe(I)+ - - Kp t. 1+ kTR' I

1+ TRI I

1+ sTp

f CI)

• GOVERNOR -TURBINE POWER SYSTEM

Figure A.3 Approximate Block Diagram of the Frequency Control System

•

A-a

+

+

~PGI(S) ~PDI(s)

GGTI Gp1

_ K" ,+ k, TRI 5 + Kpl

S I+TRIS 1+ 5Tpl

~Pt' ,(5) Ie,

~Ptie 1(5) ,

--~Ptie, 2(5)

GGT2 Gp2 l+k2 TR2

5 + Kp2 1:

5 I+TR2

5 l+sT~

~PG2(S) ~'D2 (5)

Figure A.4 An Approximate Representation of a TWo Area

System Dynamic Behavior

•

tJ=j(S>

• ~F2(5)

•

•

•

A-9

adjustments in power between the different units according to participation

factors calculated from the economic characteristics of the units.

In addition, certain secondary objectives are defined. In spi te of the

integral control, errors in frequency and net interchange do tend to

accumulate over time. These time errors and accumulated interchange areas

are reduced by adjusting the controller settings according to procedures

agreed upon by the whole interconnection.

Also, the controller should be such that it avoids excessive movement of the

generation levels as this increases the wear of the units. The trade-off is

between an acceptable level of load following and an acceptable level of

generator movement. This is mainly achieved by properly filtering the error

signal.

The error signal, called area control error (ACE), is given by

ACE (A-2)

where

API Scheduled Net Interchange - Actual Net Interchange, in MW

Af Scheduled Frequency - Actual Frequency, in Hz

P = Frequency Bias Constant, in MW/Hz

The ACE represents the power imbalance between generation and load at any

instant. The constant P represents the sensitivity of this imbalance for

this control area to the system frequency. It is assumed that if the

frequency deviates from schedule, each area should provide a correction

according to its frequency bias (which is roughly proportional to its system

size) whether or not it contributed to the frequency deviation •

A-IO

As mentioned before. ACB must be filtered or smoothed such that excessive and

random changes in ACE are not translated into corrective action. Since these

excessive changes are different for different systems the filter parameters

have to be tuned specifically for each control area.

The filtered ACE is then used to obtain a proportional-plus-integral control

signal. This control signal is modified by limiters. deadbands and gain

constants that are tuned to the particular system. This control signal is

then divided among the generating units under control to obtain unit control

errors (UCB):

UCEi PFi x ACB (A-3)

for unit i where PFi. the participation factor for unit i. is such that

1

and where N is the total nllDlber of uni ts under control. PF i may be made

proportional to the inverse of the second derivative of the cost of unit i so

that the units would be loaded according to their costs. However. cost may

not be the only consideration because the different units may have different

response rates and it may be necessary to move the faster generators more to

obtain an acceptable response. Thus the PF's usually reflect both cost and

response of the units.

The UCB's are then sent to the various units under control and the generating

units are monitored to see that the corrections take place.

frequency control loop is shown in Figure A.S.

A.l.3 The LFC AI80rith~_

The load

The load frequency control is accompli shed by the control center digi tal

computer. It is. therefore. a sampled data controller where the measurements

are sampled every 2 to 6 seconds. The measurements consist of freqnency. all

•

•

•

•

•

Filters

Net

Interchanoe

Schedu led Interchanlle

PI

Controller

Scheduled Frequency

• • •

PFI

UCEI

UCE 2

• To • Control

Units •

PFN

Measured

Frequency

Tie Line Measurements

Figure A.S The Load Frequency Control Loop Used to Compute

the Unit Control Errors

A-ll

A-12

the tie line real power flows, and all unit real power generations. The

simultaneity of this data is desirable but most often a window smaller than

the 2 - 6 second sampling is all that can be obtained. Also, because of the

far flung nature of power systems communication, delays between the actual

measurement and receipt by the computer can be variable.

The whole control calculation, from ACE to UCE, is done once per sampling

period. The fil tering of ACE is done by digital filters. Some weighted

averaging over past ACE samples is often a part of this filtering. The

proportional-pIUS-integral control signal is then cOlllputed, the integration

being a summing process over past samples. The proportional signal and the

integral signal are usually computed by passing them through deadbands and

limiters. The gain constant on the integral signal is kept smaller than the

proportional signal to avoid instability. The UeE's are then calculated by

multiplying the ACE by the stored participation factors. The UCE's are then

translated into control raise or lower pulses that are sent on to the

generator governor motor actuators by communication channel. The movement of

a generator is monitored by comparing subsequent generation measurements to

check that it has moved according to the pulses sent out.

A.l.4 Important Factors

The main philosophy in the design of LFC is that each system should follow

its own load very closely during normal operation while during emergencies

each system should contribute according to its relative size in the

interconnection without regard to the locality to the emersency. Thus, the

most important factor in obtaining good control of a syatem is its inherent

capability of following its own load. This is guarantud if the system has

adequate regulation margin as well as adequate response capability. Systems

that have mainly thermal generation often have difficulty in keeping up with

the load because of the slow response of the units.

The design of the controller itself is an important factor and the proper

tuning of the controller parameters is needed to obtain ' good' control

without 'excessive' movement of units. Tuning is system specific and,

a1 though system simul a tions are often used as aids, IIIOS t of the parama ter

adjustments are made in the field using heuristic procedures.

•

•

•

•

•

•

A-13

A.2 ECONOMIC DISPATCH

A.2.1 Functional Description

Since all the generating units that are on line have different costs of

generation, it is necessary to find the generation levels of each of these

uni ts that would meet the load at the minimum cost. This should take into

account the fact that the cost of generation in one generator is not

proportional to its generation level but is a nonlinear function of power.

In addition, since the system is geographically spread out, the transmission

losses are dependent on the generation pattern and must be considered in

obtaining the optimum pattern.

A variation of optimizing cost is to optimize stack emissions, which may be

necessary in urban areas with air quality problems. The optimization

problem, however, is identical and the cost vs. generation curves are are

replaced by emission vs. generation curves in the formulation •

Certain other factors have to be considered when obtaining the optimum

generation pattern. One is that the generation pattern provide adequate

reserve margins. This is often done by constraining the generation level to

a lower boundary than the generating capabil i ty. A more di ffi cult set of

constraints to consider are the transmission limits. Under certain real time

conditions it is possible that the most economic pattern may not be feasible

because of unacceptable line flows or voltage conditions. The present day

economic dispatch algorithm cannot handle these security constraints.

Alternative methods based on optimal power flows have been suggested but have

not yet been used for real time dispatch.

A.2.2 Mathematical Formulation

The total cost of generation is given by

N

C = 2 Fi(Pi)

i=l

(A-4)

A-14

where

Pi = the generation level of the ith generator

Fi the cost function of the ith generator

N the number of generators on line

This cost is minimized subject to the constraint that the total generation

meets the total load plus losses:

(A-S)

where

Pn the system load demand

and

PL = the total transmission losses given by

PL = f(Pl. P2 ••••• PN) (A-6)

where f is some function of the generation pattern.

Also. each of the generators is limited in its capacity and has the

inequality contraints

i 1.2 ••.• ,N.

The cost functions Fi(Pi) are nonlinear and have discontinuous derivatives.

For the equal marginal cost algorithm to work. it is necessary for the first

derivative of Fi (Pi) to be monotone increasing. These incremental cost

curves are often represented as mono toni cally increasing I inear pi ecewi se

linear functions.

The loss function f in (A-S) is often presented as

~T B ~ (A-7)

•

•

•

•

•

•

A-15

where

and B is an NxN constant matrix. Equation (A-6) is an approximation as the

losses are related not only to the real powers generated but are also

functions of the reactive powers generated. In some modern control centers

the network equations are solved with real time data to obtain the real time

ne twork mode I • In such a case the partial derivative of PL with respect to

Pi can be calculated accurately and used instead of (A-6).

A.2.3 The ED Algorithm

The algorithm used is that of equal incremental cost. This optimal condition

is given by the coordinating equations

A. i 1. 2 •••• , N (A-8)

where Li is the penalty factor for unit i, given by

1

(A-9) 1 -

and A. is a constant (the Lagrangian constant).

These coordinating equations are solved every few minutes to obtain new set

point Pi for the generating units. This is done on the control center

digital computer. The real time measurements used as input are the actual

generation levels Pi, the summation of which provides the total generation

needed. If the measured Pi's were not optimal, the solution of the

coordinating equations provides new set points which are then sent as signals

to the generators •

A-16

The coordinating equations are solved using a simple learch procedure. First

the penal ty factors are calculated from the B matrix or the solved network.

The incremental cost curves are then adjusted (multiplied) by their

respective penalty factors. A A is chosen and the Pi'S for all the units are

found from these adjusted curves. If the sum of the Pi's is more (less) than

the desired generation A is decreased (increased) by a step size until the

Pi's that sum to the desired generation are found. A simple search algorithm

for the A step size is used such that large changes in A can be converged to

rapidly as well as the usual small changes in A in the normal tracking mode.

The capacity limits of the units are incorporated by setting Pi constant when

A violates the limit for the i th unit. This algorithm is illustrated in

Figure A.6.

A.2.4 Important Factors

The accuracy of optimal dispatch clearly depends on the accuracy of the cost

curves. The cost curves are determined periodically by tetting but often the

test interval is several years. during which time these curves can change

significantly due to gradual changes in uni t performance (boiler slagging.

etc.). In the short run, temporary malfunctions in the steam cycle affect

the cost curves temporarily but this is seldom factored into the dispatching

process. The assumption of monotonically increasing piecewise linear

incremental cost curves also introduces inaccuracies. In fact. it has been

suggested that these curves are such that the optimal solution is to load the

units at the valve points (break points) on the curve.

This economic dispatch algorithm generally applies to only thermal generation

units that have cost characteristics of the type discussed here. The hydro

units should be dispatched by different criteria. Although there is no cost

for the water. the amount of water available is limited over a given period

and the displacement of fossil fuel by this water determines its worth.

Thus. the consideration of hydro units requires optimization over time and

not just optimization at any given instant. as discussed previously. If.

however. the water usage limitation over a period i& known. say from a

previousl y computed hydro optimiza tion, the coordina tion equa tions can be

extended to include the hydro units:

•

•

•

A-17

•

$/MW

• Pin MW

Figure A.6 Graphical Depiction of Equal Incremental Cost

•

A-18

dFi dVj Li Lj Vj = A isS, jaH (A-lO)

dPi dPj

where S denotes the se t of steam units on line.

H denotes the set of hydro units on line.

V· J is the water flow in the j th hydro unl t.

and Vj is a Lagrangian constant representing the worth of water in

the jth hydro unit.

If the Vj'S are known apriori, say from the hydro-thermal coordination (HTC)

program, the hydro units can be dispatched as equivalent thermal units whose

costs are given by

jaH (A-ll)

More often, however, the HTC program is used to determine the set points of

the hydro uni ts directly and these are used in real time toge ther wi th the

dispatching of steam units.

A.2.S Integration of LFC and ED

The load frequency control function and the economic dispatch function both

operate automatically in real time but with vastly different time periods.

Both adjust generation levels but LFC corrects every few seconds to follow

the load variation while ED corrects every few minutes to assure minimal

cost. The two functions must be integrated such that both objectives are met

without conflicting control action.

The logic used to avoid this conflict is shown in Figure A.7. The unit set

point is calculated by ED once every few minutes. The unit generation is

measured every few seconds.

uni t economic error (UEE).

A comparison with the set point provides the

This is then compared the unit control error

(UCE) calculated by the LFC. Both UEE and UCE are computed every LFC cycle

and if they are of the same sign there is not conflict of control action.

•

•

•

•

ACE

Unit Control Error

(UCE)

Unit Economic

Error (UEE)

- Unit L Mea surement

+

Unit Setpomt

•

+ If ACE> K, Permissive

If ACE ~ K, Mandatory

Permissive

CS=UCE

Mandatory

ItsnUCE)=s g ( C5=UCE

Otherwise CS=O

Control

Signal (CS)

n UEE g (

Figure A.7 The Control Strategy for Computing Economic Unit

Control Signals

•

:> I f-'

'"

A-20

If, however, UEE and UCE have opposite signs, a logical decision must be made

as to which goal is more significant. In mandatory control, no control

signal is sent that would move the unit away from its economic set point. In

permissive control, following the load is considered more important and

control signals moving the units away from their economic set pOints are

allowed. Often mandatory control is used during normal operation with an

automatic transfer to the permissive mode during emergencies when ACE exceeds

a given threshold, as shown in Figure A.7.

One reason for the rise of such conflict between LFC and ED during normal

modes of operation is that the economic set points are calculated too

infrequently during rapid changes of load. A suggested method to avoid this

is to dispatch dynamically to a load forecast of 15 to 20 minutes into the

future instead of the present practice of dispatching to the present

requirement. Of course, the simple ED algorithm of equalizing marginal cost

would not be applicable then and some dynamic optimization method would be

necessary,

A.3 RESERVE MARGINS

During operation it is necessary to have some generation as reserve. The

system is planned such that the total generating capacity of the system must

be substantially higher than the peak load. Thus a power system should not

normally have difficul ty in meeting its load. During operation, however,

this capaci ty, or at least a portion of it, must be available quickly to

supply additional load in case of emergency.

Emergencies can occur because of the sudden loss of a large generating unit.

The loss of the power to the interconnected system results in the immediate

drawdown of the kinetic energy stored in all the turbine generator inertia

shafts. The dynamics of this performance is depicted in Figure A.3. This

results in a perceptible slowing of the shaft speed and a drop in frequency.

The individual governors immediately increase the power input to the shafts

and the load frequency controllers also start to increase the governor

settings to stabilize frequency. The increase in generation must come from

the excess generation available from the units that are already on line

•

•

•

•

•

•

A-21

because units cannot be brought on line this quickly. The excess generation

available on a power system from the units that are already on line is known

as the 'spinning reserve.' The portion of this reserve that is under load

frequency control is called the 'regulation margin.' Ready reserve is the

generation that can be made available within ten minutes. including quick

start generation like hydro and combustion turbines.

The actual definitions of spinning reserve and the required amount of

reserves vary slightly from power pool to power pool. Every member company

of a power pool agrees to carry the required amount of reserve that is deemed

adequate to provide sufficient reliability for the pool system. Usually the

reserve requirement depends on the largest unit under operation in the pool.

Since the system must be able to absorb the loss of this largest unit. this

loss of generation wi th some safety margin must be made up by the pool

members. Each member utility is expected to carry a reserve in proportion to

its total generation.

The concept of spinning reserve and regulation margin is important to real

time control. Usually the reserve margins are moni tored in real time and

checked against requirements. The operator is alerted in case of inadequate

reserves. Usually spinni ng and ready reserve are moni tored. as these are

pool requirements but regulation margin is not. However. regulation margin

is the most important in terms of the load frequency control of the system.

Not only is the margin itself important but so is the response rate of that

regulating margin. That is. the rate at which generation can be increased or

decreased by the LFC determines the adequacy of the system control. The

response rate depends on the type of generation; for example. thermal

generation has slow response rates whereas hydro generation responds very

quickly. Thus. purely thermal systems with base load generators tend to have

difficulty keeping up with rapid load changes.

One attraction of PV generation is that if the sun is shining the power can

be turned on very quickly and vice versa. This could be very helpful in a

system that does not have adequate response rates. The problem is that the

PV generation is the cheapest generation and would be dispatched to its full

capabi li ty whenever it is avail abl e. Thus PV generation can be backed off

A-22

but not added quickly. To be able to use it as regulation margin, some of

the PV generation will have to be held back at considerable economic penalty.

However, this may be desirable where the response rate is a problem. This

is, however, not a solution to the response rate problem because this PV

component of regulation margin will not be available at night or on cloudy

days, at which times adequate r.egulation margin must be maintained on the

system from other sources.

A.4 NERC-OC CRITERIA

Since all the control areas are interconnected with their neighbors for the

betterment of overall system operation,

area use control strategies that do

it has become necessary that each

not disrupt the operation of a

neighboring area. Thus, each area must conform to a certain set of operating

guidelines that all areas of the interconnection must agree upon. These are

known as the NERC-OC Guidelines and are formulated by the North American

Electric Reliabiity Council - Operating Committee (NERC-OC). The guidelines

are necessarily broad and constitute a minimum standard with which every

system must conform.

As would be expected of an interconnection made up of so many systems, there

is never close agreement on what constitutes ideal control. The guidelines

are, therefore, compromi ses be tween di ffering philosophies and are

continually evolving as the viewpoints of NERC-OC members gradually change

wi th new experi ence. Thus, some of the information provided here may have

been superceded by recent changes.

It should be noted that these guidelines constitute the best possible minimum

control standards and have been arrived at by pooling the long years of

experience of large numbers of system operators across the USA and Canada.

Since both simulation and analytical tools have been lacking, these

guidelines have been remarkably successful in their usefulness.

It is very doubtful that any tools of study will find any disadvantages of

the guidelines as a minimum standard. However, more stringent minimum

standards can be imposed to everyone's satisfaction if they can be shown to

be operationally more efficient and cost effective.

•

•

•

•

•

A-23

The NERC-OC Guidelines constitute twenty-two sections, listed in Table A-I,

each pertaining to a particular aspect of system operation. As would be

expected. many of the guidelines deal with procedural matters needed to

maintain successful cooperation within the interconnection. Six guidelines,

marked in the table with asterisks, together with the supplement entitled

, Control Performance Cri teri a' di rectI y affect control performance. A very

brief summary of these relevant guidelines is given on the following pages •

A-24

Table A-I

mE NERC-OC GUIDELINES

* 1. Automatic Generation Control

* 2. Frequency bias setting

* 3. Scheduled Interchange

* 4. Time error standard and correction

* S. Inadvertent interchange accumnlations

6. Calibration of frequency meters and time error devices

7. Monthly summary of inadvertent interchanse accumulations

8. Regulating surveys

9. Action in emersency

*10. Reserve capacity

11. Load shedding, sectionalizing and restoration

12. Communications

13. Generation Security

14. Relaying

15. Transmission

16. Maintenance coordination

17. Training of dispatchers and operators in interconnected

system operation

18. Notification of system disturbances

19. Exchange of information

20. Analysis of system disturbances

21. Monitoring for system security

22. Action for an energy emergency

The items marked with an * affect system control performance.

•

•

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•

•

•

A-25

Area Control Error

The NERC-OC Control Performance Criteria were developed to monitor the

control performance for any control area. The area control error (ACE) is

used extensively by these performance cri teria to moni tor the performance.

Separate criteria are used for normal and disturbance conditions.

A. For Normal System Conditions

1. ACE must equal zero at least once in each ten-minute interval.

There are six ten-minute intervals in each hour. This is known as

the Al Criteria.

2. The average ACE in each ten-minute interval must be within a

specified 'allowable limit.' This average deviation

(da ) is determined as the algebraic mean of ACE for a ten-minute

interval. The allowable limit (Ld) is given as

Ld = .025 AL + 5 MW

where AL is the greatest hourly change in the net system load of a

control area on the day of its maximum summer or winter peak. This

is known as the A2 Criteria.

B. For Disturbance Conditions

A disturbance condition is defined as one that meets the following

characteristics:

(1) ACE exceeds a limit of Lm = 3Ld' and

(2) there is loss of generation or load. Under these condi tions the

following criteria apply.

1. ACE must equal zero wi thin 10 minutes of the occurrence of the

disturbance (Criteria B1).

2. Corrective action must be forthcoming within one minute of a

disturbance (Criteria B2).

Frequency Bias Setting

Frequency bias setting should be equal to the system frequency response and

must be greater than one-hundredth of peak load for the area. It must be

A-26

kept constant with resettings allowed on each January 1 or on a major change

in the system. Thus,

Net change in tie loading (MW) x·l0 B where p

Sudden change in frequency (Hz)

and

B > 1% of annual peak load

Inadvertent Interchange

Inadvertent accumulation must be corrected during the 'on-peak' hours if the

accumulation occurred during those hours or in the 'off-peak' hours if it

occurred then. Correction can be scheduled with another area of opposite

accumulation if intervening areas agree. Correction can be done unilaterally

only if it will reduce time error. In this case, a frequency offset up to

0.02 Hz may be used or a tie schedule offset up to the higher value of 0.2p

MW or 5 MW. This correction must stop when either inadvertent or time error

returns to zero or when a time error correction is initiated.

Time Error

Time error correction is initi a ted for the whol e interconnecti on when the

error exceeds agreed upon limi ts. These limits have fl uctua ted from ::'2

seconds to ::'6 seconds. In addition, NERC-OC is experimenting with

anticipating time error and compensating ahead of time. A correction is done

by a frequency offset of 0.02 Hz or an interchange schedule offset of 0.2p

MW. Correction is stopped when the error is less than given limits or after

five hours. These limits are al so being experimented with by keeping the

correction stoppage limit from the negative side different from the limit

from the positive side.

Surveys

Regular system-wide surveys are conducted by NERC-OC to monitor the quality

of control. These are initiated by the chairman of the NERC-OC System

•

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A-27

Control Performance Subcommittee and are conducted through its members who

represent each of the regions. These are divided into two general

categories:

1. Regulation Surveys

2. Control Performance Criteria Surveys

The Regulation Surveys are used to determine the frequency response and the

control error for the areas. The Survey of Area Frequency-Response

Characteristic is conducted at least once a year. This is done by choosing a

survey time when a large change in load or generation has caused a

substantial frequency fluctuation. Frequency charts for this time sent to

all systems who then provide certain system data for that time. This survey

assures a regular check on the adequacy of the frequency for each area.

The Survey of Area Control Error is done at least four times a year. Again,

the survey time is chosen to be during some abnormal condition and the system

frequency deviation at this time is sent to every system. All the relevant

factors affecting ACE are then supplied by each control area on a standard

form. This survey assures a regular check on the meeting of the load and

frequency bias obligations by each area.

Although these Regulation Surveys are very valuable to the NERC-OC, the

information they provide are static. This gives only an indirect measure of

dynamic performance. However, this data does provide a system-wide check as

to how well areas are meeting their interconnection obligations.

The Control Performance Criteria Surveys are conducted during periods

considered necessary. The surveys provide a qualitive picture of the dynamic

performance of each sys tem over a continuous period of time. Da ta is

collected from the individual area ACE charts as to how often the guidelines

for ACE behavior is violated. The average ACE used in this survey is the

average of the absolute val ue of ACE over ten minutes which is actually a

better measure of ACE variations than the algebraic mean, which is how

average ACE is normally defined •

A-28

Thi s survey enabI es a comparison of the dynallli c performance of every area

with every other area for this specific time period. This has been attempted

by NERC-OC although there has been some disagreement concerning the standards

used for comparison.

Time ~nd Inadvertent Interchange

In addition to the above surveys, NERC-OC also keeps track of the system time

and the inadvertent interchange accumulations of the different control areas.

These are the best indicators of how well the whole interconnection is

operated and provides data on individual areas as well.

The time error correction is simultaneously applied by all interconnected

areas in the Eastern region, at a previously arranged time. If all systems

operate normally, slow time error builds up during load pickup and fast time

error during load dropoff. So, a cyclic daily effect in time error is

normally expected. However, the magni tude of the error f1 uctua tions are

limited within certain bounds at though there is some disagreement on what

thi s bound should be. NERC-OC has experimented wi th bounds be tween :::2

seconds to :::6 seconds and even unsymmetrical positive/negative limits. Since

the natural tendency of the system is towards slow time errors, which are

caused by undergeneration, this has to be guarded against more carefully.

Slow time error tends to occur for the morning pickup and so it is helpful to

be a little fast as the 'on peak' period is entered. Also, a lower limit on

the slow time corrections tends to keep the error profile better.

The error correction criterion has been closely studied by NERC-OC for a long

period by experimenting with different start and stop limits. Much has been

learned about how to control this error, although emergencies can still play

havoc with it. On January 10,1978 the time error reached -27.7 seconds

because of capaci ty shortage on the Eastern Interconnection due largely to

the widespread freeze-up of coal yards.

The inadvertent interchange accumulations are tabulated monthly for each

region as well as for all of NERC-OC. Accumulations occur when every area

cannot meet its schedul ed genera tion and other areas must overgenera te or

•

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•

•

A-29

undergenerate to compensate. To keep the repayment equitable, accumulations

are paid back either on 'on peak' or on 'off peak' according to the period

when it occurred.

Such paybacks pose a major problem because an area that has to pay back may

not be able to find a neighbor with an opposite accumulation to schedule it.

Paying back unilaterally to the system is allowed only if it corrects time

error and so if the time error is in the wrong direction. accumulations can

get 'locked in' for substantial periods of time. There is considerable

concern about this because these accumulations can be directly related to

operating cost. Although better performance by each system in meeting their

scheduled obligations would improve the sitnation. emergencies will still

arise to create accumulations. Also. there is the argument that

strengthening the system to further minimize emergencies is contrary to the

whole purpose of interconnections, which are supposed to be for inadvertent

interchange during emergencies.

Obviously. there is a close connection between time error and inadvertent

accumulation and they are caused by the same problem. i.e., an inability to

meet load and interchange schedules at all times. There are some suggestions

that these two problems should be treated as one and strategies to correct

them should be coordinated. One suggested method is to ignore time error and

just concentrate on inadvertent corrections. One problem is that inadvertent

payback is left up to each control area and there are no strict limitations

on the scheduling of this payback. On the other hand. time error correction

decisions are centralized for the whole interconnection (or is done

automatically as in the Western USA) and follows narrowly defined procedures.

NERC-OC is now looking into improving the accumulation problem by proposing a

financial penalty scheme. The concept is good. as energy always costs money.

but a workable scheme is far from obvious.

A.S SUMMARY

Power sys tem control has two components; a continuously acting control of

frequency by the unit speed governors and a sampled-data control of

frequency. tie-line interchange. and individual unit generation by the system

A-30

control center. Industry standards have been developed that attempt to

monitor and regulate the control performance so that all utili ties in the

interconnection share the responsibilities as well as the benefits of

interconnected operation.

The principle control performance variable used to determine the adequacy of

control is the area control error (ACE). ACE is affected by errors in either

frequency or tie-line power flow, and therefore measures the net load on the

system. This is a responsive control measure that provides a method of

monitoring the control of any company, as well as monitoring the performance

of an entire interconnected system.

The affect of uncontrolled generation, such as PV generation, is to add a

component to the net control area load that has the ability to change very

fast. In this sense, a large PV generation is similar in its dynamic

behavior to a large steel mill or electric arc furnace. Large load changes,

caused by sudden PV generation changes, must be tracked by generation that is

under automatic control. It is possible that large penetrations of PV

generation may require that the utility schedule a larger spinning reserve or

schedule more units to regulation duty. These questions will receive further

attention in Sections 7 and 8.

•

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•

•

A-31

A.6 REFERENCES FOR APPENDIX A

The following references are presented because of their broad review of the

state of the art in power system opreations and scheduling. They also

contain exhaustive bibliographies on these topics.

1. IEEE Committee Report. 'Present Practices in the Economic Operation of

Power Systems,' IEEE Trans. PAS, vol. 90, July/August 1971.

2. T. S. Dillon and K. Morsztyn, 'New Developments in the Optimal Control of

Integrated (Hydro-Thermal) Power Systems Including a Comparison of

Different Computational Procedures,' Proceedings IEEE. vol. 62. July

1974.

3. A. M. Sasson and H. M. Merrill. 'Some Applications of Optimization

Techniques to Power Systems Problems,' Proceedings IEEE, vol. 62, July

1974.

4. H. H. Happ, 'An Overview of Short and Long Range Operations Planning

Functions in Power Systems,' Symposium on Computerized Operation of Power

Systems, Elsevier Scientific Publishing Company, 1975.

5. D. N. Ewart, 'Automatic Generation Control:

Conditions,' Systems Engineering for Power:

Henniker, New Hampshire, 1975.

Performance Under Normal

Status and Prospects;

6. T. W. Reddoch, 'Load Frequency control Performance with Reference to the

Use of Advanced Control Theory,' Systems Engineering for Power: Status

and Prospects; Henniker, New Hampshire, 1975.

7. J. Zaborszky, A. K. Subramani am and K. M. Lu, ' Control Interfaces in

Generation Allocation,' Systems Engineering for Power: Status and

Prospects; Henniker, New Hampshire, 1975.

8. H. H. Happ, 'Optimal Power Dispatch,' Systems Engineering for Power:

Status and Prospects; Henniker, New Hampshire, 1975.

9. F. Schweppe, M. Ruane and J. Gruhl, 'Economic-Environmental Operation of

Electric Power Systems,' Systems Engineering for Power: Status and


10. F. C. Galiana, 'Short Term Load Forecasting,' Systems Engineering for

Power: Status and Prospects; Henniker, New Hampshire, 1975.

11. J. Gruhl, F. Schweppe and M. Ruane, 'Unit Commitment Scheduling of

Electric Power Systems,' Systems Engineering for Power: Status and


A-32

12. W. T. Miles and L. C. Markel, 'Simulation Methods for Nuclear Production

Scheduling,' Systems Engineering for Power: Status and Prospects;

Henniker, New Hampshire, 1975.

13. H. H. Happ, 'Optimal Power Dispatch - A Comprehensive Survey,' IEEE Trans

PAS, May/June 1977.

14. H. M. Merrill, 'Power Plant Maintenance Scheduling with Integer

Programming,' IEEE/PES Tutorial Course on Application of Optimization

Methods in Power System Engineering, 1976.

15. L. Engles, J. Peschon, R. E. Larson and K. N. Stanton, 'Dynamic

Programming Applied to Hydro and Thermal Generation Scheduling,' IEEE/PES

Tutorial Course on Application of Optimization Methods in Power System

Engineering, 1976.

16. IEEE Committee Report, 'Bibliography on PlUIIped Storage to 1975,' IEEE

Trans. PAS, May/June 1976.

17. M. E. El-Hawary and G. S. Christensen, 'Optimal Operation of Large Scale

Power Systems,' Control and Dynamic Systems: Advances in Theory and

Applications, vol. 13, 1977.

18. IEEE Committee Report, 'Current Operating-Economic Problems Involving

Unit and Fuel Scheduling,' IEEE/PES S1UIImer Meeting, Los Angeles, 1978.

19. M. E. El-Hawary and G. s. Christensen, Optimal Economic Operation of

Electric Power Systems, Academic Press, New York, 1979.

20. M. G. Morgan and S. N. Tal ukdar, 'Electric Load Management: Some

Techni cal, Economi c, Regul a tory and Social Issues,' IEEE Proceedings,

February 1979.

21. IEEE Committee Report, 'Load Management from a System Operator's

Viewpoint,' IEEE/PES Winter Meeting, New York, 1980.

22. S. S. Sachdeva, 'Bibliography on Optimal Reservoir Drawdown for the

Hydroelectric-Thermal Power System Operation,' IEEE/PES S1IIIJBer Meeting.

Minneapolis, 1980.

23. IEEE Committee Report, 'Description and Bibliography of Major Economy

Security Functions: Part I - Descriptions, Part II - Bibliography

(1959-1972), Part III - Bibliography (1973-1979), IEEE Trans. on PAS,

January 1981.

24. IEEE Committee Report, 'Bibliography on Load Management,' IEEE Trans, on

PAS, May 1981,

25. Z. A, Yamayee, 'Maintenance Scheduling: Description, Literature Survey,

and Interface with Overall Operations Scheduling,' IEEE/PES Winter

Meeting, New York, 1982.

•

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•

Appendix B

PHOTOVOLTAIC POWER GENERATION SYSTEMS

Photovoltaic power generators that are designed for interconection with

utility systems have performance characteristics that are considerably

different from conventional thermal or hydroelectric generating plants. This

secti on presents a brief discussion of photovol taic (PV) generation wi th

emphasis on those characteristics that affect the dynamic performance of the

generated power and its interaction with the utility system.

B.l PHOTOVOLTAIC SYSTEM CONFIGURATIONS

PV generation systems that are presently envisioned for utility intercon

nection are of two basic types; dispersed and concentrated. Dispersed PV

sources are congeneration systems that are connected to utility distribution

systems through inverters (called power conditioners). Future systems of

this type will probably be small flat plate systems, usually of 10 kW or less

peak output, that are customer owned and are dispersed widely throughout the

utility service area. Intermediate sizes of PV generators. in the 10 kW to 1

l~ range. are candidates for industrial and commercial cogeneration systems,

which are also expected to widely disperse throughout the system. probably at

the subtramsmission level. Central station PV sources are larger. concen

trated generating systems that are located at a single site and with

interconnection to the utility system at the transmission voltage level.

These systems are estimated to be much larger in generating capability. with

systems of over 100 MW being of interest for study purposes.

B.l.l Dispersed PV Systems

Dispersed small PV systems. because of their small size. will be intercon

nected with the utility grid at the distribution level. Figure B.l

illustrates the structure of a typical power system that distinguishes the

various voltage levels of interest. Distribution primary feeders are nearly

always radial circuits and are in the 4 to 34 kV class. with 12 kV being a

common vol tage. Distribution transformers step this vol tage down to the

120/240 volt secondary level. from which individual customer services are

fed .

B-2

GINERATION

SUBTRANSMISltON SUBSTATION

SUITRANSMISSION -CIRCUIT

TRANI MilliON

'j€ /

DISTRI8UTION SUBSTATION

OfN! IUTION

TRANSFORMER

CUSTOMERS' SERVICES

Figure B.! The Principle Voltage Levels in a Power System

•

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•

•

B-3

Dispersed PV systems will probably be interconnected to the utility system at

both the distribution primary and secondary level, with larger systems

connected at the higher voltages. Figure B.2 illustrates the cascade

structure of distribution as a group of radial feeds from the distribution

substation. The distribution supply is seen to have a cascade structure from

feeder to distribution transformer to secondary and, finally, to the

individual household or commercial load. The small PV generation will be

injected into this radial structure either at the secondary or the primary

voltage level. Figure B.3 shows a feeder with PV generation connected at the

secondary voltage level. This might be typical of small PV generators, such

as those owned by an individual homeowner. The power conditioner is designed

to monitor the secondary voltage (dashed line) so that the PV generation can

be automatically removed when trouble occurs on the utility system. Figure

B.3 illustrates a possible second control mode that would interact with the

system control center.

management' functi on.

control function, for

Thi s control mode could evol ve as part of a ' load

The control purpose would be largely an emergency

example, to quickly shut down PV generation during

times of emergency overgeneration due to unforseen islanding of portions of

the network.

Another type of PV interconnection is a direct connection to the distribution

primary voltage level, as shown in Figure B.4. This design employs a

separa te step-up transformer Tl to in terconnect with the uti li ty primary

distribution.

B.l.2 Central Station PV Generators

Central station PV generators are presently conceived as a parallel

connection of a large number of PV modules of about five megawatts capacity,

each with its own power conditioner [1,2], A typical site layout might be as

shown in Figure B.S. This arrangement is for a conceived flat plate design

of 200 MW capacity, which would be interconnected to the utility system at

the subtransmission (34.5 to 230 tV) level [1]. A one-line diagram of the

subtransmission substation connection, using a double-bus arrangement, is

shown in Figure B.6. This design, conceived by The Aerospace Corporation,

provides for inverter transformers that step up the ±lS00 Vdc output to 34.5

kV through 1-34.5 tV inverter transformers, as shown in Figure B.7. Note

I I ... TRANS ~

DIST rP PRI rL- DIST ,.......- SECl I LOADl GEN NET SUBl FDRl XFMRI

~ ~ I I

f+ 1- -- 2 ~ 2 2 2

••• ~ ••• • •• ~

••• I I

1..+ rl- n - n ~ LOADn n

f-OIST r--SUB2

f-OIST r-SUB3

••• DIST r--L-. SUBN

Figure B.2 Radial Distribution Feeder Cascade Architecture

• • •

• • •

Conmand \-------- ---------------------, SYSTEM

CONTROL Measure CENTER I- - - - - - - - - - - - - - - - ___________ -,

~--'-+~I--~ I

Measure I I Corrmand ! , I I CLOUD POWER I I SUN f-- MODEL I-- ARRAY 1-+ COND I I I I t I + I

GEN t--TRANS DIST

f--+ PRI DIST

I--NET r--- SUB FDR XFMR SEC t-- LOAD

Figure B.3 PV Connection to Distribution Secondaries

B-6

r

UTILITY

INSOLATION

--/---------- T I, , .. - - --

, •• "1"

I FIELD

SOLAR PV f--WIRING

ARRAY AND SWITCHING

r- POWER I

~ CONDITION! NG I I I

_ ...J

... '{ ... rrrn

LOAD

Figure B.4 PV Connection to Distribution Primaries

through a Step-up Transformer

•

•

•

• • • ~345 kVf230 kV SUBSTATION

AND PLANT CONTROL [r-L-.-0 AND MAINTENANCE FACILITIES ,--I

I P4 4

~ .~ -= -= ~ = -=- -= 1 1 1 1 1

,

~ [

b [

~3 [ 3

1 l - ~1 1 1

\ 1

[P [

r [ ~ [ L M.H. tTyp of 581 , .-------

[P2 [ 2

1 ~1 '" 1 - =1 1 1

11 ; I

'-___ J ,

I LJ I

~---j L-_~ I LJ L-_ .. , 820 ft ,20ft ~--------------6700 ft----------------j

Figure E.S Plant Site Layout for a 200 MW Flate Plate Design [1]

•

3 . 1000 MCM HGAS 34.5 kV UNDERGROUND CABLE ITYPI

100 MVA

3 4 5

34.5/230 kV to L ___ --,

TRANSFORMER

3.45 kV SWITCHGEAR SPECIFICATION POS I, 6 & 11 - 2000A DISCONNECTS CIAC

BRKR TRIP SETIING 17llOA POS 2, 3, 5, THRU 9 - 1200A DISCONNECTS elRC OAKR TRIP SETIIHG 450A

POS 4 - 120M DISCONNECT CIRC BRKR TRIP SETIING BOOA 230 kV LINE 2 230 kV LINE 1

NOTE: All 34.5 kV circuit breakers to have 20,000 amps inlerrupling capacity

230 kV

100 MVA 34.51230 kV TRANSFORMER

P SUBFlELD SEE FIGURE 9

250A - 34.5 kV FUSIBLE DISCONNECT W/250A FUSE

230 kV SWITCHGEAR SPECifiCATIONS POS 1 & 4 - !OIlIlA DISCONNECTS CIAC CAKR TRIP SEnlNG 210A

PDS 2 & 3 - 2IlIlIIA OlSCONNECTS CIAC BRKR TRIP SETTING PEA SYSTEM REQUIREMENTS FOR TRANSMISSION LINE

Figure B.6 Single Line Diagra. of AC Power Collection Wiring

for a 200 MW Flat Plate Design [1]

• •

t:d I

CD

•

'" ;:, CD

> '" '" ... M

/

4MVA 1 kV/34.5 kV TRANSFORMER

h 4000A-1000 VAC, 3+

~ .... -+-+---l-_~ -1500

2F, SOOOA

I 5000A BUS ± 1500 vac

4000A-l000 VAC, 3+ 4 MVA I kV/34.5 kV TRANSFORMER

POWER CONDITIONING UNIT CONFIGURATION

TO SOURCE CIRCUIT PANELBOARDS ,

• • 32 SOURCE CIRCUITS TOTAL

TOTAL OF 16 SOURCE CIRCUITS TOTAL OF 16 SOURCE CIRCUITS

2'10 CU/XHHW UF CABLE (TYP)

SOURCE CIRCUIT TROUBLE INDICATION

. !_ ........ - CURRENT MONITORING RELAY

TOTAL OF 16 SOURCE CIRCUIT PROTECTIVE/TROUBLE MONITORING DEVICES

4 HOO MCM CU/XHHW CURRENT MONITORING RELAY

POWER COLLECTION PANEL + 1500 VDC 500A BUS

MAIN DC SWITCHBOARD SOURCE CIRCUIT GROUP PANELBOARD

Figure B.7 Single Line Diagram of the DC Wiring System

for a 200 MW Flat Plate DeSign [lJ

B-IO

that. from Figure B.S. the 200 MW flat plate PV plant requires a site area of

2042 1 2573 meters (6.700 x 8.440 feet) for a total area of 5.25Xl06 m2

(56.51106 ft2). Concentrator designs require even more area. as shown in

Table B.1.

Flat Plate

Concentrator

Table B.l

Approximate Space Requirements for a 200MW PV Plant Designed by The Aerospace Corporation [1]

Site Dimensions

m

2042 X 2573

2730 X 4075

Array Area

106 m2 acres

5.25

11.12

1312

2760

Power Density

W/m2

38.09

17.98

B.2 PV ARRAY DESIGN CHARACTERISTICS

Power Pack

26.25

55.62

PV array configurations are of two types; fixed til t or tracking arrays.

Either type could be made up of flat plate PV modules or concentrator arrays.

but most flat plate systems are fixed and concentrator systems are usually

tracking. Tracking arrays require more physical space than flat plate

modules at fixed tilt.

This study is concerned with the effect of PV generator variation. due to

cloud movement. on the controllability of the power system. From a control

viewpoint. the switching of small generation systems is of practically no

interest since the system already experiences load discontinui ties at least

as great as presently conceived from small flat plate systems. such as might

be found on a single home.

component of system load.

These small changes are effectively a noise

Large industrial genera tors or uti Ii ty owned

central station PV systems are another matter. These large. concentrated PV

plants have the ability to change generation very quickly. On days with

scattered or broken cloud patterns. a large generation step change or noise

•

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•

B-U

pattern is possible. These large generation changes may cause a significant

problem with the system control, particularly if the PV generation is a large

fraction of the total generation.

It is interesting to note that large central station PV generators will

require a large land area for plants of considerable size. In English units

for a tracking system we compute the area for the system of Table B.l as

A = (0.0551m2/MW) (100 hectares/1m2) (2.471 acres/hectare) 13.6 acres/MW

Therefore a 100 MW tracking plant requires about 1300 acres or two square

miles (sections) of land. Table B.2 provides some additional conversions for

this same system (Table B.l).

MW

100

200

400

600

800

Table B.2

Conversions Related to PV Generating Plants

with Tracking Arrays (55 m2/kW) [1]

1m2 Acres Sections

5.5 1359 2.12

11.0 2718 4.25

22.0 5436 8.49

33.0 8154 12.74

44.0 10872 16.99

B.2.1 PV Power Plant Response Rates

PV power plants are expected to be significantly different from conventional

power plants in terms of the response rate-of-change of power. This differ

ence is due to the absence of energy storage in the PV plant design as well

as the different energy conversion technology.

Conventional power plants have significant accounts of energy storage. This

storage is in two forms; mechanical (rotational) and thermal energy. When

the power system load suddenly changes. energy is exchanged with these

B-12

storage media as the system stabilizes its operation to the new load level.

This exchange takes place first with the rotational system, in the time frame

of seconds, and later with the thermal system, in the time frame of minutes.

Since the load has a substantial stochastic component, these energy storage

reservoi rs provide a means of smoothing out the frequency (speed) control,

while providing fast response to the load demands.

Table B.3 provides information on the response rates and storage capacity of

typical thermal and hydroelectric power plants [4]. Typically, a thermal

plant has storage capacity to provide 15 to 20 percent response in 10 to 30

seconds. Over longer periods (minutes) the response rate is much slower and

depends on the change in the boiler firing rate [5]. This plant maneuvering

capability is shown in Figure B.B.

PV power plants do not have energy storage and are therefore unable to

increase their output, even temporarily, above the direct conversion rate of

sunlight to electricity. Thus, no matter what the change in load demand or

frequency, the PV generation will remain constant as long as the insolation

is constant.

The PV response rate to either a change in insolation or control is expected

to be very fast, with a maximum power rate of change in the range of 130 to

350 Mi/minute, depending on the cloud type, sky coverage, solar elevation,

and cloud veloci ty. Figure B.9 shows the resul ts of cloud simulations

performed by The Aerospace Corporation [3]. This figure shows maximum rates

of change in excess of 200 Mi/min. (3.33 Mils).

•

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B-13

Table B.3

Dynamic Characteristics of Conventional Generating Units

Generation Type

Fossil-Steam Gas or Oil

Coal

Nuclear Steam

Gas Turbine Heavy-Duty Aircraft-Derivative

Hydro High Head Medium Head Low Head

Emergency Fast Pickup Amount Available Time % of Rating Required

20 10 sec. 30 30 sec.

IS 10 sec. 20 30 sec.

8 10 sec. 20 30 sec.

100 S sec. 100 S sec.

0 10 sec. 20 10 sec .

100 10 sec.

Maximum Ra te for Sustained Load Changes

2-~ min.

2-~ min.

1 -3" min.

20'11/sec. 20'11/sec.

l%/sec. S"/sec. 10000/sec.

Starting Time

Hours

Hours

Hours

3-10 min. l-S min.

1-5 min. 3-5 min. 1-5 min.

Because of these unique characteristics of the PV power plant, zero energy

storage and fast generation changes, the inclusion of such plants in the

generation mix presents several interesting problems. First, the PV plant

will not contribute to system frequency regulation since the plant output is

not dependent on frequency. Second, the plant will not contribute to load

following unless it is determined that such control is more economical than

using conventional generation. This would depend on the particular

generation mix and operating costs of available units •

B-14

.... f-:> z ~ .... ~ ~

i! W-!;i II::

.... en z 0 "-en .... II::

FREOUENCY REGULATION

1000 "'----,.,.

100

ID

TIE-LINE THERMAL BACKU~

DAILY LOAD FOLLOWING

0.1 ~~~~~----~--~----~~~----~~------~ 0.01 0.1 10 100 1000

MINUTES TO PERFORM LOAO CHANGE

Figure B.S Maneuvering Requirements of Generating Units

for Utility System Operation [4J

•

•

•

•

•

•

30

20 -

C 10-'E

-30!:--+----!;--;J,-+.-?:~-i_-~-l~-~ a

Figure B.9 Rate of Change of Power for Type 1 Clouds

at 36 km/h and 400 Solar Elevation [5]

B-15

B-16

To establish maximum practical rates of change for PV central power plants

the data in Table B.4 is helpful. These data a.sume that a large cloud bank

moves over the PV array at 54 tm/h (15m/s), which is the highest practical

speed of cloud movement [3]. A range of power pack area. is shown in Table

a.4, representing a range of power densi tie.. For prel iminary PV plant

designs, the practical area requirements are assUllled to be 25 m2/kW for a

fixed flat plate system and 55 m2/kW for a tracking concentrator design [1].

These practical plant designs assume an array field that provides access for

maintenance, as shown in Figure B.S. Hence, much of the total space consists

of driveways (or walkways). A solidly-packed array field would require much

less space (20 to 40 m2/1W) and would experience mOre rapid power output

changes as the cloud moves past. If the array field is square, the maximum

rate of change occurs when the cloud covers the field diagonally. This is

shown in Table B.4 and Figure B.I0.

PV cell temperature variation will cause chanles in conversioD efficiency

and. therefore, in power available from the PV lource. However, the

temperature changes are assumed to occur slowly compared to the time

intervals of interest in this study, and are ilnored in our calculations.

The effect of a sudden loss of a PV array or of an entire PV central station

can easily be simulated as a step change in generation. Such PV plant forced

outagea are no di fferent than the loss of a conventional uni t, in terms of

the effect on system control performance. The sudden addition of PV

generation, following a cloud passage, pre.ents an increaae rate in

generation that is not possible with conventional units.

•

•

•

•

•

•

B-17

Table B.4

Maximum Rates of Change of Power in a PV Array with Cloud Velocity of 54 km/h (I5m/5)

Array Power Power Pack Maximum RamI! Rate, MW/s

MW, peak m2/kW Uniform Ramp Worst Case,

Wind at 00 Wind at 450

800 5 6.0 8.48

10 4.24 6.00

20 3.0 4.24

40 2.12 3.00

400 5 4.24 6.00

10 3.0 4.24

20 2.12 3.00

40 1.5 . 2.12

200 5 3.0 4.24

10 2.12 3.00

20 1.5 2.12

40 1.06 1.50

100 5 2.12 3.00

10 1.5 2.12

20 1.06 1.50

40 0.75 1.06

B.2.2 PV Resl!onse to Changes in Insolation

Changes in insolation cause changes in available power that depend on the

array configuration. Flat plate modules will display an almost constant

conversion efficiency over a wide range of insolation so that the available

power can be confidently taken to be a linear function of total insolation

falling on the array. Cloud cover on flat plate modules may reduce direct

normal insolation nearly to zero, but reflected insolation can provide up to

25 percent of the uncovered power capability. Concentrators sensi ti ve to

only direct normal insolation, on the other hand, will convert no reflected

sunlight so that cloud cover may reduce the power available from those arrays

to virtually zero.

B-l8 80CMW

Power

Power

o.

O.

~ _____________ 3MW/sec ____________ ~

(a) Cloud cover moving parallel to array side

~ __________ 4.24MW/sec, max ________ ~

(b) Cloud cover moving parallel to array diagonal

Cloud Exits

Figure B.lO Power History of 800 MW Array with Large Cloud Cover

Moving Parallel to Array Diagonal at 54km/h.

Power Pack, 20 m2/kw. Solar Noon.

Cloud Exits

•

•

•

•

•

•

B-19

Recordings of solar insolation made by Salt River Project employees at Page.

Arizona are shown in Figures B.II and B.12. Figure B.II shows the solar

insolation as a function of time on a flat plate. non-tracking array. Part

(a) of the figure shows the nearly sinusoidal insolation history on a clear

day in August. Part (b) shows an August day that is cloudy and illustrates

the sharp changes in insolation due to cloud interference.

Figure B.12 shows the insolation of a tracking concentrator device. also

measured in August at Page. Arizona. Part (a) shows the output on a clear

day, and illustrates the pronounced 'shoulders' added to the output curve due

to the device tracking ability. Part (b) shows the output of the tracking

array on a cloudy day.

The power conditioners for all of the sizes of systems considered in this

study are assumed to operate at unity power factor at all times. No reactive

power changes are accounted for from or to the PV source.

Time lags in the energy conversion processes are so small, in the array and

in the power conditioner, that this study neglects them. The system is

described with inertia equal to zero.

B.3 CLOUD TYPES

A cloud is a visible aggregate of minute particles of water or ice. or of

both, in the free air [6]. Clouds are formed when the air is unable to

hold the water vapor in invisi bl e form. The capaci ty of air to hold its

water vapor in invisible form depends upon the amount of vapor and the

temperature of the air. At lower temperatures the air can hold less water

than air of higher temperatures. Thus, it follows that clouds result

because air, with a certain amount of water vapor, has been cooled below a

point where it can retain all of that water in invisible form.

Air may be cooled in various ways. The most important air cooling is

brought about by the pushing of the air, that has been heated because of

its position near the surface of the earth, into a colder region aloft.

•

•

(b)

Figure m.l1 Solar Insolation on a Fixed Flat Plate Array in • August at Page. Arizona. (a) Clear day, (b) Cloudy day

B-21

•

(a)

•

... (b)

Figure B.12 Solar Insolation on a Tracking Concentrator Array in

Augnst at Page, Arizona. (a) Clear day, (b) Cloudy day

B-22

When a low pressure region is approaching, great masses of surface air

enter the low from all sides. Usually, the air from the south and east is

warmer and more moist. If this air becomes cooled below its dew point it

often forms the extensive clouds associated with storm fronts. Smaller

masses of air may be heated near the surface of the earth under clear

conditions. This causes the clouds to rise and eventually mix into the

cooler air above. In this manner heat and moisture is carried upward.

This rising air cools by expansion and at a certain level, which depends

upon the moisture content, it becomes saturated. Above this the rising

volume becomes visible as cumulus clouds.

B.3.1 Cloud Groups

Meterologists have identified ten different cloud types. These fall into

four groups. Three of these groups are based on altitude; high, middle and

low. Clouds in these groups are usually relatively flat. The fourth group

consists of 'towering' or 'vertically developed' clouds that are easily

recognized by their extensive vertical height and their rapid growth [7].

High Altitude Clouds

High a1 titude clouds are of three types: (1) Cirrus, (2) Cirrostratus and

(3) Cirrocumulus. In temperate latitudes they are found at very high

al ti tudes, ranging from three to eight miles. They are extremely thin

(less than 100 feet thick). Because of their great aIti tude, all three

types consist almost entirely of ice crystals. Cirrus clouds are

recognized by their white, delicate filament and silky sheen. Cirrostratus

clouds di ffer in that they cover most or all of the sky in a whiti sh,

transparent veil. Both cirrus and cirrostratus can often be distinguished

by the halo they create around the sun or moon. Cirrocumulus is easily

recognized by its overall patchy or sheetlike appearance and their speckled

texture (caused by small globules that group together to form this cloud

type) •

Cirrus clouds can be either a sign of fair weather or the first herald of

an approaching storm system. Very high cirrus elements that are thin and

wispy are a good indicator of fair weather, particularly if they are not

•

•

•

•

•

•

B-23

followed by cirrostratus clouds. Other cirrus types are often the signal

of bad weather. Cirrus clouds arranged in parallel bands or stripes

indicate the possibility of bad weather ahead.

As a general rule, the higher cirrus clouds foretell fair weather, while

the lower ones are the first sign of stormy weather or windy weather,

Middle-Altitude Clouds

Middle altitude clouds are of two types: (1) Altostratus and (2) Alto

cumulus. Altostratus clouds cover the sky with a blue grey veil. Although

light rain or snow can fall from them, the presence of .ltostratul is more

important as a forecasting aid. When al tostratus appear several hours

after the cirrus and cirrostratus, the chances of precipitation are hiah.

On the other hand, altocumulus clouds should not be interpreUd as a

forewarning of precipitation from weather fronts. The altocumulus is

distinguished by the way its moderate to large puffs are arranged in ,roups

or lines.

Low Level Clouds

There are three basic forms of low level clouds: (I) Stratocumulul,

(2) Stratus. and (3) Nimbostratus. All three are capable of producina

precipitation, but the amount and duration are greatest with nimbostratus.

For this reason, nimbostratus clouds are commonly called rain clouds. They

are low and thick and often have a deep grey coloring. Stratocumulus are

most often seen in winter. Their soft large globular cloud elements

combine in groups or waves to cover very large portions of the sky.

Stratus is a soft, foglike cloud that frequently produces a drizzle, but

not rain. They often begin as fog and are transformed into stratus when

the fog lifts or its lower layer dissipates.

Towering or Vertical Clouds

The clouds belonging to this group are the most beautiful and often the

most dangerous. The types are: (1) Cumulus and (2) Cumulonilllbus. These

clouds occur almost exclusively on warm and sunny days or alon, the

imaginary line that marks the cold front. Cumulns clouds are the ealiest

B-24

to recognize. Their undersides are quite flat. grayish and low (500 to

1.500 m). and their cauliflower sides can tower a mile high. glistening

white in the high midday sun. Since the cumulus are formed by convection

currents [8]. they are most frequently found inland and along the coast.

but usually not far out at sea. They form in the morning and then grow in

number and size until at times they dot the entire sky by midafternoon.

They often die rapidly with the late afternoon sun. The lower and thicker

the cumulus clouds are, the higher the chance that they will transform into

rain-yielding Cumulus Congestus or Cumulonimbus. When the sky -is dotted

with rows of small cumulus. it is a sign of fair and dry weather that day.

Cumulus Congestus is not a basic type of cloud but a member of the cumulus

family. It is an important cloud to recognize not only because it can

produce rain showers but also as a forerunner of more severe weather. When

fast growing Cumulus Congestus are seen in mid to late morning. there is a

good chance of afternoon thunderstorms.

Cumulonimbus is a storm cloud that may be several miles across with its top

reaching from three to ten miles high. It is marked by an anvil shaped top

made up of ice crystals.

B.3.2 Cloud Types

Clouds important to this study are those that produce sharp shadows on the

ground. Those sharp shadows will produce maximum rate of change of power

for any given shadow (cloud) velocity. High altitude clouds move at higher

velocities than lower clouds but do not produce sharp shadows. Water

clouds with bases below 1500 m (5000 ft) cast sharp shadows. These types

of clouds can be classified into three types that are defined by the World

Meterological Cloud Classification:

Type 1: Cumulus humilis (fractus)

Type 2: Cumulus mediocris (congestus)

Type 3: Cumulonimbus calvus

Details and their characteristics have previously been discussed and can be

obtained from reference [9]. which notes that the statistics of cloud

sizes. shapes. spacing. and distributions have been obtained from several

U-2 flights across the United States [10-12].

•

•

•

•

•

•

B-25

The frequency distribution of cloud size in a given cloud area is shown in

Figure B.13 for the three cumuli form type of clouds. The percentage of

small clouds is greater for type I clouds and is smallest for type 3

clouds. The data for each of the three types of clouds were fitted to a

linear semilogarithmic line by least squares fit [13]. The data and the

least square lines are shown in Figure B.13. These least square lines are

given by the equations

Type 1:

Type 2:

Type 3:

P 16.086 - 16.256 In A

P 14.754 - 6.363 In A

P = 10.50 - 3.061 In A

(B-1)

(B-2)

(B-3)

where P is the probability of a cloud of area A occuring in the total cloud

area.

B.4 THE DETERMINISTIC CLOUD MODEL

In this section we develop the deterministic model of the behavior of a PV

generator due to the effect of clouds of group 2 and group 3. Some of the

clouds in these groups are very large and produce sharp shadows covering a

large portion of the sky. For example, nimbostratus clouds, which are

common rain clouds, create unbroken shadows that move at velocities of up

to about 50 km/h.

In deriving the cloud model we make the following assumptions:

1) The posi tion of any point on the front is of no concern; only the

position of the front with respect to time is required.

2) The front is a straight line and every point on the front is moving

with equal and constant velocity. Then the position of the front or any

point on it is a linear function of time.

3) The trailing edge also consists of a straight line with equal velocity

and has a given time delay with respect to the front •

;:;s a:: <: 0 ::> 0 ...J U ...J

~ 40 g Z

:p LU U Z LU a:: a:: ::> u u 0 u. 0

>-u Z LU ::> 0 LLJ a:: u.

•

' ... , ...... ...

...... 1 •

""... I .... ----+--' ...... L 0 I "-... 'I 1 ...... " ___ ' I ...

-i--" I ..... "~"" I

0-- Type 1 0---- Type 2 t::. -- - Type 3

4 567810 30 40 50 70 100

CLOUD AREA (km2)

Figure B.13 Probability of Occurrence of Cloud Areas for Three

Cumuliform Cloud Types

•

•

•

•

B-27

4) The cloud bank consists of clouds that are thick. with sharp shadow

edges. and will produce a total shadow on the ground.

The equation of a straight line representing the cloud front at a time to. as

shown in Figure B.14. is of the form

y(x.t) = mx+b-at = x tan 9 + L - (t-to ) Vy

where Vy v cos 9

to = is the time the cloud front hits the array at (O.L)

e angle of the front with respect to the x axis

(B-4)

Now let tl be defined as the time that a point on the storm front coincides

with the origin (0.0) as shown in Figure B.14.

The distance d traveled by the cloud front in time tl is given by

d = D Sin e = L Cos e The time tl-to is found from

d - = L Cos elv v

(B-S)

(B-6) tl - to = Here the paint of interest is not the velocity of a point on the cloud front.

but it is the effective velocity of the cloud front. which is the velocity

component of the front in the x and y direction as shown in Figure B.14.

The position of the cloud front for t o <t<tl is shown in Figure B.lS. The

area covered is given by

(B-7)

As the cloud moves past the origin the area increases linearly. as shown in

Figure B.16.

The area covered by the cloud front during this period is given by

O;l-S)

The rate of area covered is maximum and linear. Therefore. the total area

covered during the interval to i t i t2 is

2 1/2vxvy (t-to )

1/2vxvy (tl-to)2 + Lvx(t-tl) (B-9)

B-28

t=to

v

w

Figure B.14 Position of the Cloud Front with Respect to the PV Array

--r L

position / at to./?'

/

t

__ -position at tl

~---w----'!>I

Figure B.IS Area of Cloud Shadow Coverage for to<t<t2

•

•

•

B-29

• y

b

/ /

x

~---w-___ ~

• Figure B .16 Area of Cloud Shadow Coverage for t{ t< t2

y

L

x

• Figure B.17 Area of Cloud Shadow Coverage for t 2<t<t3

B-30

For t>t2 the area covered by the cloud front is as shown in Figure B.17 and

is given by

Therefore, the total area covered during the time

t2 i t i t3 is given by

AT = Al + A2 + A3 2

1/2 VxVy (tl-to) + Lvx (t2-tl)

+ Lvx (t-t2) - 1/2 vxVy (t-t2)2 2 2

1/2 vxvy(t1-to) + Lvx(t-tl) - 1/2 vxVy(t-t2)

(B-I0)

(B-11)

The cumulative area AT coverage as a function of time is shown in Figure

B.18. The regions t o<t<t1 and t2<t<t3 are both quadratic in the time

variable t, but the region t1<t<t2 is linear and exhibits the maximum rate

of change. Summarizing the previous results, we write the cumulative area

coverage as

~= + Lvx (t-t1)

+ Lvx (t-t1) 2 - 1/2vxvy (t-t2)

B.5 SPECIAL CASES OF INTEREST

t2<t<t3

Two special cases are of interest in considering AT vs t.

1) The case where 9=00 or 9=900

2) The case where W=L (a square array) and 9=450

These will be discussed in turn.

B.5.1 Cloud Moving with Angle 9=90 0

(B-12)

If the cloud is moving at right angles to the array orientation, i.e.,

9=900, the change in PV output vs time is linear. The area covered by the

cloud front in time t-to is determined as follows. The position of the

cloud front is as shown in Figure B.19.

•

•

•

•

•

•

.... -.----.

I

.J I I i

Figure B.18 Cumulative Area of Cloud Shadow Coverage

---->'----+-'--~-'--J---~ t2=t3

W

t

Figure B.19 Position of the Cloud Front

B-31

B-32

The area covered by the storm cloud front is given by

AT = xlL = Lvx(t-to )

For this case the output changes linearily with time.

B.S.2 Cloud Moving at 45 0 Over A Square Array

(B-13)

o If the array is square and the cloud front is maving at 45 with the array

orientation, the maximum rate of change in output is achieved. Because the

array is square and the cloud is moving at a 450 angle to the array axis.

the times tl and t2 shown in Figures B.14 and B.17. respectively. are

equal. Thus the cumulative area coverage is given by (4-12) with vx=vy • or

to<t<tl

2 2 + Lvx (t-tl) - 1/2vx (t-tl)

(B-14)

B.6 THE STOCHASTIC CLOUD MODEL

The purpose of this study is to produce a model that can easily be handled in

a computer simulation. The elliptical shape of the cloud would be the most

physically realistic shapes. but it is difficult to handle the ellipses on

the computer. For our study. simplified cloud shapes, consisting of separate

rectangles. were used as the cloud model.

The percentage area covered by the cloud is derived from the probability of

the occurance of a cloud of size A in the cloud field from equation B-1 thru

B-3. A cloud of size A is generated randomly with a distribution as shown in

Figure B.13.

B.6.1 Shadow Field Formation

The array fields may be rectangular. square or in any other shape.

Rectangular shapes will be assumed in this study. The cloud shadows are

assumed to move parallel to ei ther ax! s of the rectangl e or a t any angle.

The percentage area covered by a cloud in each increment of time is

determined from the probability of the sky being covered with particular

type of cloud.

•

•

•

•

•

•

B-33

Figure B.20 shows a typical simulation for the type 1 cloud. The size of the

cloud field is increased at each interval of time as it moves over the array

nntil the leading edge of the cloud pattern reaches the farthest point on the

array. After that time the leading cloud shadows are subtracted in each

simulation time step and a new trailing cloud pattern, of random size, is

added.

B.6.2 Effect of Cloud Cover on PV System

Cloud cover that shadows a part of a PV array field will reduce the power

output from that portion of the field that is shadowed. Most important to

this study is the rate of change of power from the array as the cloud shadow

change s. Power from the array will be taken to be proportional to the area

exposed. The rate of change of power from the array will depend on the

change of the shadow size and the velocity of the cloud shadow moving across

the array. The changes in power will occur in a random manner as the

individual cloud moves pass the array site. These changes in power will give

maximum rate of change of array power when the covering or uncovering occurs

at maximum velocity •

B.6.3 Computer Simulation

Input data for the simulation includes the length and the width of the

collector field, the power of the collector field, the drift velocity of the

cloud, the type of the cloud, total time for which the simulation has to be

run and the time increment. The simulation forms the shadow field, using the

drift velocity and array dimensions provided.

field is incremented in time. At each time

The posi tion of the shadow

increment the portion of the

collector field shadowed is determined and the power is computed. The

program has the capability of keeping track of the amount of power added and

lost at every increment of time.

B.6.4 Graphical Outputs

Graphical outputs of Calcomp plots for the following data.

1) Power available vs time

2) Probability distribution

The samples of each type of plot for type 1 clouds are as shown in Figure

B.21 through B.23 •

B-34

•

L

•

w ~I

Figure B.20 Typical Cloud Shadow Pattern for a Type 1 Cloud

•

•

•

C .. , n-C',.' ~

o o

LD r-~

o o

OJ

; I

I

B-35

LD+-____ ~----~----~------~----~----~ ~D ' 0 0 4 0 ' 0 0 8 0 . 0 0 1 2 0 . DO 1 6 0 . 0 0 2 CJ 0 ' 0 0 2 4 0 ' 00

TIME IN SEcbNOS *10 1

~ Figure B.21 Change of Power due to Type 1 Cloud at a Sky Cover of Nine-Tenths and a Solar Elevation of 100 800 MW PV Rating

3: L

B-36 o o tD

o o

N

0 0

CO

0 0

""

Zo ......... 0

0::: 0

W 3: 0 (LO

0

'<T I

0 0

co I

0 0

N

o o

lD

Figure B.22

1 Ii

40,00 80,00 TIME IN

~~

120,00 SEC

160.00

* 101

200.00

Change of Power due to Type 2 Cloud at a Sky Cover of Nine-Tenths and a Solar Elevation of 100 800 MW PV Rating

•

•

240,00

•

•

•

•

:J: ::c

o o

OJ en

o o lD en

o o

0 0

N en

ZO 0 ,-< ,

0 n::en lJ.J 3: 0 (LO

0 . CD CD

0 0

lD CD

o o .

o o

B-37

~ f,

1\

,\1

~ il !

N~---------.----------.----------r----------r---------'----------' CDO. OO 40.00 80.00 120.00 160.00 200.00 240.00

TIME IN SECONDS *10 1

Figure B.23 Change of Power due to Type 3 Cloud at'a Sky Cover of Nine-Tenths and a Solar Elevation of 100 800 MW PV Rating

B-38

B.6 REFERENCES FOR APPENDIX B

1. Simberger, Edward J., 'Central Station Photovoltaic Power Plant Design,'

Aerospace Report No. ATR-82-(9595)-01, September 1982.

2. Hein, R.E., D.J. Hughes,

Central Power Station,'

Aerospace, February 1983.

and B.W. Heller, 'Design of a Photovol taic

Final Report SAND 82-7149, Martin Marietta

3. Laurence, C.L. and P.J. Peters, 'Solar Collector Transient Studies.'

Aerospace Report No. ATR-77(7506-03)-I-R, 1977.

4. Marsh, W.D., Economics of Electric Utility Generation, Oxford

University Press, 1980.

5. Eward, D.N., M.H. Dawes, R.P. Schulz, and A.S. Brower, 'Power Response

Requirements for Electric Utility Generating Units. 'Proceedings

American Power Conference, vol. 40, 1978, pp. 1139-1150.

6. International Cloud Atlas, Vol 1. Secretariat of the World Meteroiogical

Organization, Geneva, 1956.

7.

8.

Richmond W. Longley, 'Elements of Meterology.' John Wiley and Sons,

Inc •• 1970.

Hurd C. Willett and Fredrick Sanders, 'Descriptive Meterology.' second

edition. Academic Press, Inc •• New York, 1959.

9. R.T. Hall. 'Cloud Shadow Modelling,' Report No. ATM 76(7506-01)-1, The

Aerospace Corporation, September 12. 1975.

10. R.H. Blackmer and S.M. Serebreny, 'Dimensions and Distributions of

Cumulus Clouds as Shown by U-2 Photographs,' Stanford Research Institute

Scientific Report 4, AFCRL-62-609, July 1962.

11. R.H. Blackmer, 'Statistical Distribution of Cumulus Clouds from U-2

Photographs,' Stanford Research InsU tute Technical Report I, November

1962.

12. R.H. Blackmer and J.E. Alder, 'Statistics of Cumuliform Clouds from U-2

Photographs,' Stanform Research Institute Final Report, May 1963.

13. C.L. Laurence and P.J. Peters, 'Solar Collector Transient Studies,'

Report No. ATR-77(7506-03)-I, The Aerospace Corporation, January 4,

1977.

•

•

•

•

•

•

Appendix C

POWER SYSTEM LOAD BEHAVIOR

C.l INTRODUCTION

Power system control operates in response to load demand. Simply stated. the

control must do two things: it must adjust generation to meet load demand,

and it must hold frequency to the desired 60 Hz. Moreover. it is highly

desirable that this be accomplished in the most economical manner possible.

All this must be done in a real-time control environment where fast computer

analysis of the developing load pattern is essential to success.

Economic dispatch, as noted in Appendix A, involves committing the generating

units in an economic manner and adjusting the output of each op~rating unit

to achieve minimnm cost. The present study is not greatly concerned about

economic di spa tch except to note that the response of generating uni ts to

rapid or sustained load changes is strongly dependent on the type of uni t.

This was illustrated in Table B.3, where we noted the generally slow response

rates of large thermal uni ts. Thus. a system composed entirely of large

thermal units would not be expected to respond as fast as a system that is

predominately hydro. This means tha t control response is dependent on the

types of units available to provide control action, and this may be dictated.

to a degree. on economics.

Our study is concerned about the response of a given mix of uni ts to load

changes, where the load change may include uncontrolled PV generation. The

system di spa tcher knows from experience the general daily load shape. He

makes a daily forecast of this load shape. and has units operating, or

scheduled to operate. to meet the demand forecast. Therefore. in our

studies, we can assnme that there is adequate generation to meet any load

shape. It may be necessary, however, to examine the responsiveness of a

given generation mix to load changes that are aggravated by PV switching. We

will use the same criteria for determining the adequacy of control that the

system operators use, viz •• the NERC-OC operating criteria. These criteria

are based mostly on observations of frequency and the computed control

parameter called area control error (ACE),

C-2

Finally, a word about frequency control. It is important to understand that

a power system is designed to operate at a given frequency.

this design frequency is 60 Hz. The operating utilities

In the U.S.,

do not sell

frequency, they sell energy, but so many of us depend on accurate frequency

for industrial processes and time measurement that the utilities all regulate

frequency to a very small error.

There is another reason for frequency control. All power plant equipment,

such as turbines, generators, fans, and pumps, are designed for use in an

integrated system that assumes constant frequency. Prblonged operation at

low frequency reduces the output of fans and pumps, and can even cause

permanent damage to turbine blades and generator insulation (due to increased

heating). Thus, when a sudden load increase causes a momentary drop in

frequency, it is not an acceptable solution to just 'ride out' the distur

bance at off-nominal frequency. The system desi gn incl udes speed governors

that make rapid adjustment of all generator shaft speeds in response to

frequency error. Thus, the speed governing is an important element in the

present study, and system frequency behavior will also be monitored.

Another important system design characteristic that affects the ability to

track load changes is the sampl ed nature of sys tem control. The control

center is usually a long distance from generating plants. Measurements are

made periodically, usually every 2 to 6 seconds, to determine power plant

performance. This gives the control computer a small window through which it

must view the system, and which limits the control response. A large load

change, for example, may not be observed at all for a few seconds.

Fortunately, every generator has local controllers that operate continuously

to hold frequency, voltage, pressure, and other essential plant variables.

The system operator will not be aware of these actions until the next data

scan, after which the control computer will develop and broadcast a response.

This response will readjust speed governor set points as well as boiler

firing rates to accommodate the system to the observed change.

•

•

•

•

•

•

C-3

C.2 TYPICAL LOAD PATTERNS

Load behavior over time differs by geographic region and by season of the

year. These differences are graphically illustrated in the EPRI Report [1].

'Synthetic Electric Utility Systems for Evaluating Advanced Technologies.'

Figure C.l illustrates some of the differences in seasonal load shapes. This

system (EPRI Scenario E) is summer peaking with relatively high weekly load

factor. Note the sharp evening peak buildup in spring or fall. the smooth

summer load shape. and the large mid-day drop in winter.

Contrast this performance with that of EPRI Scenario C, shown in Figure C.2.

This system has a lower weekly load factor and displays a more erratic

mid-day behavior with sharp peaks. Some of these peaks present a challenge

to the power system control and could cause the control performance criteria

to be exceeded.

There are four general areas of load performance that warrant our attention

in these studies. These are increasing ramps, decreasing ramps, posi ti ve

rates of change (valleys), and negative rates of change (peaks). The EPRI

Synthetic System data are valuable since they provide typical load behavior

characteristics to help us calibrate our tests. They are al so valuable

because they are known to be taken from actual system experience, and are

therefore realistic. We will modify these loads by the inclusion of PV

generation as a negative load component, as shown in Figure C.3.

C.3 LOAD SIMULATION

In the computation of system net load for the simulation. as shown in Figure

C.3. a time series of net load data points is computed based on the system

load data and the PV generator output. The PV generated power may be based

on normal insolation received at the array sight, or may be modified by cloud

movement. Thus, a sharp ramping of the PV output may be observed or a random

output may be generated in response to a random cloud pattern •

SlH:lI'tt' 1'0'0"'" T~ ~ ~ ~::pr~.RPr! L-__ ~ __ ~ __ ~ ____ ~ __ ~ __ ~ __ ~~

Spring/Fall Weekly Load Cycle Plot Summer Weekly Load Cycle Plot

Winter Weekly Load Cycle Plot

Figure C.l EPRI Scenario E

• • •

() I .,.

• •

F'R:~~!.. ~ __ -L __ ~ ____ L-__ -L __ ~ ____ ~I _____ ~

Spring/Fall Weekly Load Cycle Plot Suamer Weekly Load Cycle Plot

Winter Weekly Load Cycle Plot

Figure C.2 EPR! Scenario C

•

(") I

V1

LOAD PLANT DATA DATA

PLOAD

+ PNET LOAD ~ SYSTEM

DYNAMICS -PPV

COMMANDS

CLOUD PV CONTROL MODEL GENERATOR CENTER

Figure C.3 Simulation Program Structure

• •


MEASUREMEN TS

•

("') I a.

•

•

•

C-7

The system load data is usually known in terms of 60 minute integrated demand

readings. which gives the average power for each hour of the day. This

hourly data must be interpreted as a smooth change in output, minute by

minute, such as might be obtained by connecting the hourly readings by a

smooth curve, such as that shown in Figure C.4(a). This is accomplished by a

computer program called SPLINE that provides this smooth curve fit and

guarantees continuity of both the power and its derivative.

Figure C.4(b) shows graphically the time frame of a typical simulation run of

20 to 30 minutes. During this relatively short time, the simulation solves

the system differential equation digitally, using a 0.5 second time step.

Thus, a 30 minute simulation actually requires the load data to be computed

on 0.5 second intervals, or a total of 3600 load data points for the run.

This same resolution is also required of the rv output, with the net load

being the required input to the simulation.

Figure C.5 shows the introduction of the SPLINE program to provide the load

power with the desired time resolution.

C.4 LOAD STOCHASTIC BEHAVIOR

Any observation of power system operating variables, such as load or fre

quency, shows that the system is constantly perturbed by small disturbances.

These disturbances are clearly evident in a frequency chart recorded at the

control center (see Figure E.12). These small changes in frequency are due

to the stochastic nature of the load, which is being constantly altered by

the users of electric power. These load changes are small in relation to the

total load, but exactly how small is dependent on the system. Some systems,

for example, supply steel mills with operating electric arc furnaces that

effecti vely short ci rcui t the el ectri c system in a random pa ttern. This,

however, is an extreme case. Most systems observe a noise level variance of

only 1-5% of the peak demand.

One of the objectives of this study was to represent the stochastic behavior

of the load and to determine the effect of this random load variation on

control performance. The stochastic PV model is presented in Appendix B.

C-8

PLOAD

SPLINE PROGRAM

Given Load Data

(a) Producing a smooth curve from hourly data

~_~_~_TYPiCal Simulation Run of 20-30 minutes

I

P-i t

(b) Typical simulation time frame

Figure C.4 Modifying Load Data for Simulation Studies

•

• t

•

•

WHITE NOISE

HOURLY LOAD DATA

DIGITAL FILTER

CLOUD MODEL

SPLINE PROGRAM

•

PLOAD

+ PNOISE + PNET LOAD I----~Ll--------.I

PV GENERATOR

COMMANDS

""LANT DATA

SYSTEM DYNAMICS

CONTROL CENTER

MEASUREMENTS

Figure C.S Simulation Program Structure with SPLINE Program

and Load Noise Representation

•


C-IO

Here we develop a stochastic model for the load itself. This model will

consist of a filtered white noise input to the simulation. as shown in Figure

C.S.

In order to determine the load noise characteristics of the power system,

measurements were taken at the 230 and SOO kV levels at the Arizona Public

Service Company (APS) Westwing Substation.

frequency and power flow in various lines.

Measurement:s were made of both

Since frequency is ,proportional

to the integral of power. this gave measurements of both the cause and effect

variables. However, frequency behavior depends on the net system

accelerating power Pal which is computed as

Pa = Pm-Pe MW (C-l)

where Pm is the total mechanical power output of all turbinesano Pe is the

total electric power output of all generators. System frequency deviation is

computed as

(C-2)

where Pa is normalized to any convenient base value and a is proportional to

the system rotational energy. The only way we can effectively measure Pa is

by measuring Af.

Measurements were taken on the APS system with the assistance of their

engineers and technicians. The measuring device used was a Hewlett Packard

Structural Dynami c Analyzer (SDA). which has the capabi 1 i ty of measuring.

processing. and storing da ta taken over a long period of time and then

computing a smoothed estimate of the measured performance variable. The

results of interest are shown in Figure C.6.

Figure C.6 shows a plot of frequency noise power in db on a logorithmic

scale. This is a convenient way of plotting data to determine average system

characteristics. Note. for example. the average slope in the characteristic

of about 20 db/decade, but may be at 40 db/decade below 10 mHz.

reasonably well with other published measurements [2,3].

This agrees

•

•

•

•

•

•

X, 45.3B5 m

" SPEC YI -42. 152

R#I 13 #fo,1 121 -20. cm~ -,.-____________ --,-_________ ----,

-30

-40

LGMAG DB

-70

-8C.I1JCI1J ~-----,----r------_',_--_._----___1 J 5 10

5.0Z:::Z m

XI 46. 769 m

" SPEC Y. -42. 101

R#. 13

(a)

100

LG HZ

YI -55. em~ #11. 121 EXPAND

-4al1Je0-,.-________________ -, ______ --.

LGMAG DB

-7a zm~

I

I

l !

I I

J ,

I I

1 10

~ \

I 20

I

j I I I I I

30 40 so 60 70

c-u

W.I':~2 m LG HZ 9C.~ZC m

(b)

Figure C.6 Logarithmic Plots of Frequency Noise Power in db

(a) 5 to 500 mHz range. (b) 10 to 90 mHz range

dPd

AP w per unit

c +L l+k TRS AP m + - APa 1 A

~ --2HS - 1 + TRS -

APf 0 .-

1 - -R

Figure C.7 Basic Governor Control Loop for Frequency Behavior

• • •

•

•

•

C-13

The region in the neighborhood of 50 mHz is of interest because of the promi-

nent peak elthibi ted. This is due to the effect of the speed governors.

acting on turbine generator systems that are dominated by reheat steam

turbine time constants. The basic control loop is shown in Figure C.7, where

the following parameters are identified:

APc per unit governor set point, adjusted by the control center

APm = per unit mechanical power of turbine

APd per unit load disturbance power

APf = per unit frequency damping power

Alii per unit speed ( frequency)

-H = inertia constant = 5.0 s

D damping constant 1.0 pu

TR reheat time constant ;; 10.0 s

R = governor regulation ;; 0.05-0.10

k high pressure turbine fraction ;; 0.3

The system shown in Figure C.7 is readily solved to give

(C-3)

{ 2 [1 1 2HRTR S + TR + 2H

We are interested in the solution where APc=O, which has the form, for a step

change in APd. of

-AR

DR+!

where A is the size of the step load change.

response is determined from

= --------------

(C-4)

The closed loop frequency

(C-5)

C-14

where, for the average system values given above, we compute

ron2 = (D+I/R)/2HTR 0.110

or

0.3317 rad/s (0.053 Hz) (C-6)

which agrees very well with the observed hump in Figure C.6. As a matter of

interest, we also compute

S [2H+TR(D+k/R)]/4HTRron

= 0.7538 (C-7)

which indicates operation at below critical damping.

Clearly the resonance in Figure C.6 is due to governor action. It is not

clear, however, if more than one governor is represented by the observed

characteristic, which shows more than one reSonance.

In order to represent the noise characteristic in the simulation, a digital

filter was designed to modify a white noise input [41. The theory of digital

filtering is considered beyond the scope of this work. The filter designed

for this purpose modified the broad spectrum of white noise to produce a

noise characteristic that exhibits the same spectral response as that

observed on the real system. This filter was designed by a graduate student

in the spectral analysis research group at ASU as a part of his Ph.D.

research [4].

•

•

•

•

•

•

C-15

C.S REFERENCES FOR APPENDIX C

1. Zaininger, H.W., et al., 'Synthetic Electric Utility Systems for

Evaluating Advanced Technologies,' EPRI Report EM-28S. February 1977.

2. Taylor. C.W •• E.Y. Lee. and D.P. Dave. 'Automatic Generation Control

Analysis with Governor Deadband Effects.' IEEE Transactions. vol.

PAS-98. n. 6. November/December 1979. p. 2030-2036.

3. Vimani. S. et al •• 'Development and Implementation of Advanced

Automatic Generation Control; Final Report of Task 1, Modeling and

Analysis of the WEPCO System.' Final Report of DOE Contract

EC-77-01-2118. Systems Control. Inc., 1979.

4. Brachad. Behshad. 'Digital Signal Processing with the Aid of Singular

Value Decomposition' Ph.D. Thesis. Arizona State University. 1983 •

•

•

•

Appendix D AGC SIMULATION

This section presents a discussion of the dynamic modeling of a power system

and the method of focusing on the system dynamics pertinent to power system

automatic generation control (AGC). The modeling of the system components

essential to this process, including photovoltaic (PV) generation sources,

are presented. The kinds of results available from these simulations are

reviewed. Finally, the extension from deterministic to probabilistic

simulation is discussed.

D.l POWER SYSTEM MODELING

In this section we discuss power system modeling for dynamic simulation and

present some assumptions that are appropriate for AGC simulation.

Power system dynamic simulation is always a compromise since any conceivable

change in the system operation excites many modes of dynamic response. Thus,

it is essential that the simulation design focus on the essential variables

that are the most influential in producing the results that are of interest.

Another aspect of simplification is the need for selecting the geographic

locality of interest and of providing a

power system external to that locality.

simplified representation of the

The reason for this is that the

interconnected power

disturbances may have

represent the entire

Sys tems are generally

widespread consequences.

sys tem or have avail able

portions that are not of primary concern.

very large, and

Hence one must

a simplified model

certain

either

of the

The scope of this problem is illustrated by Figure D.l, which shows the

regional divisions of the North American Electric Reliability Council (NERC).

In the portion of North America illustrated, there are four interconnected

systems:

WSCC - the Western interconnection

ERCOT - the Texas interconnection

D~ •

• Figure D.l The NERC Regions

•

•

•

•

Hydro Quebec - the Canadian Province of Quebec

BCAR, MAAC, MAIN, MARCA, NPCC, SERC, SPP - the Eastern

interconnection

D-3

All of these interconnections, except Hydro Quebec, consists of an electrical

interconnection of many operating utilities that are tied together by high

voltage transmission lines called 'tie lines.' Geographically, these

operating interconections are very large and the electrical characteristics

are extensive. Some of these characteristics are give in Table D.I.

A given dynamic simulation is usually focused on a particular area, or even a

single operating utility, within these huge systems. For AGC simulation, the

focal point is the control area, which is shown pictorially in Figure D.2.

The primary elements in the control area are:

• the transmission network

• the generators

• the prime mover system

• the loads

• the tie lines to neighboring systems

• the system control center

All of these elements are shown in Figure D.2. Each interconnected area in

North America consists of a number of these control areas, each intercon

nected to its neighbors by tie lines over which power transfers are scheduled

as required to meet area needs.

In some simulations the response of individual power plants in response to a

given disturbance is the focal point of interest, requiring that each

generator and prime mover be explicitly represented in the simulation. For

AGC simulation we are interested in tracking the total output of all

generation to a change in system load, and in the control signals sent to the

generators by the system control center. This means that we can simplify the

generation system modeling. For a given generator, the speed of the turbine

generator shaft, and hence the generator frequency, is dete1T1ined by Newton's

law, given by

D-4

Table D.l

Approximate Si~e of the North American Interconnected

Power Systellls For the Year 1980

Bastetn Area 'estern Area Texas Area

Network Nodes 7,304 1,666 1,500

Network Branches 11,812 1,822 2.100

Generators 1.622 364 150

Generating Capacity, MW 377.064 97.998 42.000

Total Load. MW 356.690 81.017 32.000

Total Rotating Energy. MJ 1.627,650 377.619 128.640

•

•

•

•

•

•

OTHER { GENERATORS

VOLTAGECONTROL~

I--U-' PRIME MOVER • :V

ENERGY I GEN I

SOURCE I I

ENERGY SOURCE

CONTROL

___ .S~W l

I. ~~~~~ • • GEN

GEN OUTPUT CONTROL SIGNALS

POWER

SYSTEM TRANSMISSION

NETWORK

• SYSTEM

LOADS

TIE LINES

OTHER SYS

TIE LINE POWER

L..------I SYSTEM CONTROL. CENTER SYS

FREe

SYSTEM FREQUENCY REFERENCE

TIE LINE POWER >--'

SCHEDULE

Figure D.2 The Principal Elements of a Utility Control Area

D-S

D-6

dill J (D-l)

dt

where J is the shaft (generator plus several turbines) moment of inertia, III

is the shaft speed in radians per second, and Ta is the accelerating torque

in Newton-meters [1]. For power system calculations, · .. e usually normalize

equation (D-l) to compute in per unit

dill 2H Pmech - Pel ect (D-2)

dt

where

H = normalized inertia constant in seconds

III speed in per unit

t time in seconds

Pa accelerating power in per unit

Pmech mechanical power of turbines in per unit

Pel ect el ectri cal power of generator in per unit

The system diagram for the enUre system is shown in Figure D.g.

Since we are not concerned about the individual shaft speeds in AGe modeling,

the problem is restructured to compute the average frequency by finding the

net system accelerating power, as shown in Figure D.4. This simplification

is used because the variation of load is slow compared to the shaft dynamics,

wi th load ramps in the minutes-to-hours time frame. Moreover, the time

constants of the predominate thermal generation are also slow, with time

constants measured in minutes. This dynamic range is often referred to in

the literature as 'long-term dynamics' [2-4]. This dynamic range is shown in

perspective in Figure D.S. AGe simulations have evolved as a special case of

the long-term dynamics programs. The major difference is that the long-term

dynamics simulation programs represent the transmission network, but the AGe

simulations do not. In AGe simulations all generation is connected to a

•

•

•

D-7

• I st TURBINE - GENERATOR

GOVERNOR ,-- PRIME MOVER GENERATOR

MODEL MODEL

~ Pmech(l} Pelect(! ) LOA OS

•

• ~WI I ~+

2Hls t- Z • ~

0 III ~ • III a:: ~ 0 III ~

• Z f-ILl

• <I: Z a::

• f-

nth TURBINE - GENERATOR -GOVERNOR -

GENERATOR ,- PRIME MOVER MODEL MODEL

P mechen) Palact(n)

~wn I ~+ 2Hns t-.~

Figure D.3 A System Dynamic Model that Preserves Individual

~ Unit Speed Dynamics

•

GOVERNOR GENERATOR ,.-. PRIME MOVER

MODEL MODEL

• • TRANS-r- • • MISSION

• • NETWORK

L..-GOVERNOR GENERATOR PRIME MOVER MODEL

MODEL

+

IPmech ~

AWav J + IPe1ect & -2HTS t ~ Dav

Figure D.4 A System Dynamic Model that Assumes Uniform Speed

(Frequency) Dynami~s

•

LOAD

• • •

S

•

t:J I

00

• • •

I .- - - ... ---~

LIGHTNING OVERVOLTA~ES

I ~·t"SWiTCHIN<r SURGE1S

L...o .. t- tt '.-.. ~ SUBSYNCHRot;J0US RE,SONANC~

•• d de ••. _'" ... • .~

TRANSIENT a LlNE~R STABIILlTY

'-- -LONG TER~ DYNA,MICS

TIE - LINE REGUL~TION

DAILy LOAD rOLLOW~NG

-7 -6 5 -4 -3 -z Z 10

3 10

4 10

5 10

6 10 10 10 10 10 10 0.1 10 10

t t TIME SCALE, sec ~ t t I fLsec. I degree at 60 Hz I cycle I sec. I min I hour I day

Figure D.S The Time Scale Associated With Dynamic Ranges

Important Power System

D-IO

common network bus and the area load is connected to the same bus. In its

simplest form, the system components in an AGC simulation are shown in Figure

D.6. One generating source is modeled in the local area for each unique type

of power plant, for example,

• fossil fueled boiler

• nuclear

• combustion turbine

• hydro

The system control center for the local area is also represented mathemati

cally and the frequency equation (D-2) is solved for both the local and

external areas [6-8]. One of the objectives of this project is to add a

mathematical model to the AGC simulation that will represent the area PV

generation.

The AGC simulation program used in this project was developed for DOE by

Systems Control, Inc. [6,7]. Another similar simulation program was

developed by Philadelphia Electric Co. [8-10], in parallel with the DOE work,

under sponsorship of EPRI. The DOE program is referred to as an 'advanced

AGC simulation program' because of its use in the study of alternative AGC

strategies and turbine value point loading [6.7]. The programs are similar

in their basic philosophy of modeling but differ slightly in detail. The SCI

program includes a model of a more modern system control center, and

incorporates the effect of measurement noise on all measured variables.

The following section provides detailed information on the AGC simulation

structure. data requirements, and computed results.

D.2 mE EXISTING AGC SIMULATION PROGRAM

This section reviews the structure and modeling of the existing AGC simu-

lation programs. The next section describes the modifications that are

required in order to simulate the effects of PV generation.

•

•

•

•

•

Pc; , .. PGZ P,Z PZ' Pc. ext

2 .. ... .. • ••• PGN N

.. PL PLext

LOCAL AREA (I) EXTERNAL AREA(2)

Figure D.6 Equivalent System Representation in an AGC Simulation

of One Control Area Connected to an External System

D-ll

D-12

D,2,1 AGC Program Structure

The basic structure of the AGC simulation program (AGCSIM) is shown in Figure

D,7, As noted previously. the program includes dynamic models of the genera

tion systems. with all generation of a given type modeled either individually

or as one composi te generator, The generation outputs are used by the

control center model to develop control commands. exactly as in the actual

power system (see Figure D,2), The driving function of the simulator is the

system load. which is modeled as a time series representing the load behavior

of the entire control area as a function of time. Integration time steps of

0,5 - 1,0 seconds are usually required for the power plant models. Thus a 30

minute time series would require up to 3600 state evaluations for each system

state, This means that simulations of load variation over periods of 30

minutes to perhaps one hour are feasible. but longer time periods would be

expensive, Typical simulations. run in 15 to 30 minute segments. are

probably the most cost effective,

A flow chart of the computations performed in the SCI program is shown in

Figure D,8, The results obtained from the simulation include the system

frequency. generated power. and power plant variables as functions of time,

Any state variable modeled may be tabulated or plotted, The variables

usually of greatest interest. however. are the frequency and control

variables such as area control error (ACE), These variables are usually

checked against industry performance standards. discussed in Appendix A,

Figure D,9 shows the system representation of a three area problem, In each

area the control center monitors the generation at each generator. and

simultaneously monitors the sum of tie line power to adjacent control areas,

These measured quantities are shown in the figure by dashed lines indicating

data communication channels, Typically. these remote data points are scanned

every two to four seconds by the control computer and command signals are

sent out to control generation at the same time schedule, The AGC simulation

can be programmed to duplicate this data acquisition frequency. including the

introduction of band limited white noise on the communications channels [6],

One purpose of the simulator is to permit the user to insert new generation

or AGe control a1 gori thms in to the simul a tion. hence these functions are

modeled in a modular fashion with well defined interface variables,

•

•

D-13

• SAMPLING

CONTROL 1--- ---, CENTER CONTROL I MODEL t-----, I

I I I I I I I I

+ J LOAD GENERATION

AGCSIM -- DYNAMIC MODEL

MODELS

• ~. t

OUT PUT

-Figure D.7 The Basic Structure of the AGe Simulation Programs

•

D-14

INITIALIZE AREA J'I

COMPUTE AREA: METERED INTERCHANGE AREA CONTROL ERROR INADVERTENT ENERGY MEASUREMENT NOISE GENERATION CONTROL

COMPUTE INTEGRATION TIME STEP

Figure D.B AGC Simulation Flow Chart

•

•

•

• •

rr= - - -=-- =-= ;=---=-=- ....... - - l --- -'GI '23

r --;, -=--=-=---:::: -::.- - - 11 I 32 PG� ___ _ I n: _ ~ I w -- -- ffi I

I ~ w I (\/ U

~...J

I W ~ 0::1-~z

I 8 I L-------l

J--1t----+-1--------+-----I1--~ I ~ I I I ~--- ~W~ UO...J I

~--fI----,,:,PL21 I 'L3·----I1----.j - n: n: I ~!z I

I - 8 I I I

---I

LAREA 2 I ________ --.J L _

I - Pu I

~'-A-RE-A~---'I ______ J Figure D.9 System Representation for a Three Area Interconnected System

•

t:::! I I-' V1

D-16

D.2.2 The AGC Program Models

An overview of the system model for the computation of frequency response is

shown in Figure D.IO. The entire system dynamic behavior is driven by the

system load. which enters the simulation in the lower right of the figure.

The PV generation. being an uncontrolled generation source. is considered to

be a (negative) part of the system load.

The most important dynamic component in the AGC simulation is the represen

tation of the power plants. The SCI program provides two power plant models;

a simple model for representing fast combustion turbine or hydro units and a

detailed model for large thermal units.

The simple model is shown in Figure D.Il. This model is adequate for the

representation of small fast-acting units that have negligible thermal energy

storage.

The detailed model is shown in Figure D.12. The important parameters in this

model are the boiler capacitance CD and CSH' which represent the large

thermal energy storage. and the turbine reheat time constants. TS' T6' and

T7' All of these parameters can be large. typically several seconds. and

directly affect the speed of response of the unit.

The other important model is the control center i tsel f. This is shown in

Fi gure D.13. The control center computes the system area control error

(ACE). based on system measurements made every two to t;ix seconds. This

quanti ty represents the need for control actions by individual generators.

These control actions are sent to the individual generators according to

economies and user-selected participation factors.

D.2.3 Data Requirements

The data requirements for accurate simulation of existing generators is

rather extensive and invol ves not only physi cal parame ters. such as sizes.

ratings, etc., but also field adjusted controller gains and system perfor-

mance data. Systems Control has summerized these data requirements in a

five-page data acquiSition form for use with their AGC simulation.

•

•

•

• AREA AGC ~

DATA ACQUISITION r------ -, I I I I I MEASUREMENT

NOISE I

• FREQUENCY

AREA NET IN 1"ERCHANGE

I'ROGRA.'1 ! I UN IT El.ECTR ):CAL GENERATION ~. -I-I

I l UNIT TIIROT ~:LE PRESSURE AREA

L ______ ---1 ETC.

N~:T

INTERCHANGE

AREA LOAD AT 60 liz

r--------- - ---, Unit

I IM~ Control SPEED

~ GOVERNOR

Pulses I • REFERENCE TURIIlNE lL ~ I MOTOR BOILER I + Control I I

"it Area Electrical _ Area

+ Generation E + Load

AREA LOAD

MODEL

Pulses for I Other Units 1- ~ I GENERATING I Generation

of other units In area

PERFORMANCE IIISTORY

I 1----- - _ .. ~-

UNlT I --- _-1 Mechanical Gen~ration

of other unit"+ In area

AREA MECHANICAL POWER

+

E

t

C

-

+

System Mechanical+

+ Generation

Mechanical Power eneratlon in other

ureati

Systeln l.oad - MW

SYSTEM FREQUENCY (liz)

Figure D.lO Overview of the AGe Simulation Program

30

~

SYSTEM FREQUENCY

(IIERTZ)

....-'''----. System Damping Coefficient MW/llz

•

D-18

LRM

1 + 1 - z: -+ s

+ l+ST~

1 - -R

~

Figure D.ll A Single Time Constant Model for a Generating Unit

Mechanical Power

•

•

•

•

TIlR PRE SET POI

OTTLE SSURE

+ NT

IPL LIM

+ IT~

-

LRH

--' 1 S

• ~

PRESSURE CONTROLLER FUEL SYSTEM

DRilll

K l+TRS +

lL -so 1 I-<}:- 1 Kp+_~ 1--0

lltf~--'"'- l- e I- l+TFS CDS S + +

TIIROTTLE PRESSURE

GIPL

1<

,

lC ,..

I-~ +~ ~I- LVG I2frlk:r--

l-

l/R

I FREQUENCY DEVIATION

LOAD LIMIT

RATE POSITION

VALVE LHIITS

SUPERHEATER

f-to:- - 1 KS..r CsnS +

STEAI'I FLO\J

1 1+S't4

~ 5J .~ •

L...... -11+~T5 ~ 1 I- 1+ST 1-1-

6

r$J ~ r$J 11JIUlINE

Figure D.12 The Detailed Generating Unit Model

8 1

1+ST1

too

[$J

•

MECII POWER

6f

•

IUAG j" I

+

PARTICIPATION F'T----i FACTORS

~--1 ECONOMIC DISPATCH

+

BP OTHER UNITS

UAGI---~--__________________________________ ~

~IT CONTROl. ERROR

PULSE RAISE/LOWER

GENERATOR PULSES TO

'-----.... UNIT I

Figure D.13 The Control Center Computation Structure for Frequency

Control, Load Control, and Economic Dispatch

(Automatic Generation Control)

• •

t:l I

N o

•

•

•

D-21

Data is also required for the external area. Probably the most i_port.nt

item is the external inertia, which can be critical if the external area is

small, or about the same size as the area under detailed study. Usually, the

area under study is the smaller and the external area need only be known

approximately. The external area inertia can be obtained by ~ubtracting the

internal inertia from the total regional inertia given in Tabl~ D.I.

D.2.4 Typical Simulation Results

Simulation results are available in either printed tabular form Or printer

plots of selected variables as a function of time. A typical tabular output

is shown in Appendix H.

Printed plots are fast to obtain and are usually desir~d for visual

evaluation of data. A typical plotted output is shown in Appendix H •

D-22

D.3 REFERENCES FOR APPENDIX D

1. Anderson, P. M. and A. A. Fouad, Power System Control and Stability.

Iowa State University Press. 1977.

2. Schulz. R. P., Anne E. Turner. and D. N. Ewart. 'Long Term Power System

Dynamics, Vol I. Summary and Technical Report,' EPRI Final Report

90-7-0, June 1974.

3. Turner, Anne, 'Long Term Power System Dynamica, Vol II, Dynamics

Simulation Program,' EPRI Final Report 90-7-0, October 1974.

4. Schulz, R. P. and Anne E. Turner, 'Long Term Power System Dynamics,

Phase II,' EPRI Final Report EL-367, February 1977.

S. Smith, L. M. and J. H. Spare, 'Area Control Simulator Program, Vol 1:

Technical Manual,' EPRI Final Report EL-1648, vI, December 1980.

6. VirmaIli,S., S. Kim, R. Podmore, T. Athay, and D. Ross, 'Development and

Implementation of Advanced Automatic Generation Control,' Final Report

of Task 1, Modeling and Analysis of the 'REPCO System. DOE Contract

EC-77-01-2118, 1979.

7. ibid, Appendix A, AOC Simulation Program User's Guide, 1979.

8. Smith, L. M. and J. H. Spare, 'Area Control Simulator Program, Vol 2:

Programming Manual,' EMU Final Report EL-1648, v2, December 1980.


Program Listing,' EPRI Final Report EL-1648, v3, December 1980.


Multiarea Models,' EPRI Final Report EL-1648, v4, December 1980.

•

•

•

•

•

Appendix E

THE ARIZONA SYSTEM OF APS AND SRP

E.l INTRODUCTION

The study of power system response to PV generation changes, using a computer

simulation of generation control, requires the use of a realistic system

model. One way to do this would be to arbitrarily model a system of fossil,

nuclear, and hydroelectric plants that are assembled in some mixture that is

typical of a given geographical region. Another approach is to use the

actual generation mix of a given utility. Our approach is the latter. We

arranged at the outset of our study to enlist the cooperation and support of

Arizona Public Service Company (APS) and the Salt River Project (SRP), both

of Phoenix. These utilities provided data on their system generation, loads,

and control centers. This provided a realistic setting for validating the

computer simulation, as well as providing experienced observers to comment on

the resul ts.

E.2 THE THREE AREA CONTROL SIMULATION

The system modeled for simulation is a three-area system. similar to that of

Figure D.9. In our studies the three areas are identified as the APS control

area. the SRP control area. and the Western Systems Coordinating Council

(WSCC) control area. WSCC is a large interconnected power system that covers

the Western United States. Figure D.l shows the geographic region. This

system operates separately from the Eastern United States. In 1982. the WSCC

had about 70,000 MW of load (on peak) and had an installed generating

capacity of about 8S.000 MW (see Table D.l).

The operating utilities in WSCC have organized themselves into power pools

for the coordination of generation control. Our simulation involves a

portion of one of these pools that includes APS and SRP as member utilities.

Both APS and SRP own and operate control centers that schedule and regulate

their own generation. These two control areas have the capability of

exchanging purchased power be tween themselves. wi th the amount of these

purchases or sales being moni tored at transmission metering points. Each

E-2

utility can also purchase or sell power to other utilities within wsee. These other utilities are not represented in detail in our simulation, but

simply become part of the 70,000 MW system represented as wsee.

Figure E.1 shows the Arizona generation and transmission system, both present

and planned. The simulation was constructed on the basis of 1982 data. with

each utili ty modeled to include the company load, all generation owned and

controlled by that company, and the interconnection with the two neighboring

areas.

E.3 AREA PARAMETERS

The purpose of thi s section is to provide some de tai 1 of the APS, SRP and

wsee area model parameters that are used in the simulation. The APS and SRP

generators are represented individually. The wsee generation is represented

by a simple power plant model, with a total rating approximately equal to the

sum of all generators in wsee outside of Arizona.

E.3.1 APS Generation

The APS generation represented in the study is listed in Table E.1. It

should be noted that these units are not all scheduled for generating duty at

one time, but units are added in order of increasing operating cost as the

load increases and are removed as the load drops. Therefore the simulation

of any given time period of, say, 30 minutes, will require a prior evaluation

to determine the units to be committed during that period.

From Table E.1, APS is observed to be a sys tem tha t depends primarily on

coal-fired steam plants for base load, and with oil fired steam plants and

combustion turbines available for peaking duty. Note the difference in

operating cost between coal and oil fired uni ts. This suggests that the

large, low cost uni ts will be base loaded and the smaller, more expensive

uni ts will be assigned peaking and load regulating duty. The PV plant is

assumed to have an operating cost of about $12.S/Mwh, and hence would be base

loaded [1].

•

•

•

•

MIGUEL

TO Iillf:I{ICO ,,I',lilnl .... :.:, , ... ) TO M!:JUCO

1#1,'""1

Figure E.1

•

10 CUll'tCaTl

SRtNGERVILLE 345 KV LINES TO COI'IO""DO, 1'912 TO .. cKI .... Ey •• "2 TO IIkKINLEY. , •• r TO GftEENLEE. 1985 TO G"£EMLE! • 191'1 TO ""EENlEt:, ..,87 TO UlNA. 1987

The 1982-1992 Southwest Area Transmission System

•

@

Table E.l

APS Generation

Generator Rating Normal Max Approximate Rated Energy of Each Unit Generation Operating Cost Storage, MJ

Plant MVA MW ~ Fuel $/MWh Rotating Thermal

Four Corners 1-2 192 175 Drum Coal 13 600.96 970.56 Four Corners 3 256 220 Drum Coal 13 865.28 3408.64 Four Corners 4-5 909 750 OnTh Coal 11 2536.11 4181.40 ChoUa 1 116 116 Drum Coal 16 388,60 757.10 ChoUa 2-3 321 235 Drum Coal 16 1139.55 4124.85 ChoUa 4-5 460 350 Drum Coal 15 1182.20 2132.10 Saguaro 1-2 118 115 Drum Oil/Gas 55 488.52 1044.30 Ocotillo 1-2 134 115 Drum Oil/Gas 51 388.60 1768.80 Yucca 1 102 25 Drum Oil/Gas 49 331.50 1708.50 West Ph:.: 4 35.3 33 Drum Oil/Gas 75 193.00 • West Phx 5 15.6 12 Drum Oil/Gas 80 66.00 • West Phx 6 70.6 63 Drum Oil/Gas 70 341.00 • WPCC 1-3 146.7 85 CCyc Oil/Gas SO 220.00 • WPCT 1-2 62.5 56 CTrb Oil/Gas 70 720.60 • Ocotillo CT 1-2 62.5 56 CTrb Oil/Gas 70 720.60 • Saguaro CT 1-2 62.5 54 CTrb Oil/Gas 70 720.60 • Y_a CT 1-2 23 19 CTrb Oil/Gas 70 218.50 • Yuma CT 3 72.2 55 CTrb Oil/Gas 70 560.40 • Y_a CT 4 72.8 54 CTrb Oil 102 560.40 • Douglas CT 1 27.2 20 CTrb Oil 102 217.60 • *Not calculated--unit not modeled in de tail.

• • •

•

•

•

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s..-(J.)

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C] '-"J (J) (l)

Figure E.2

I:S:I LD

(1) 0)

Time i n h 0 u r- E;

Winter 1982 Peak Week for APS

u::r UJ

''-

E-6

• F1Z Publ ic ~=;er··\/ice;~=;un. RU~~l28~~=;a.t. ~=;ep4 ":32 l

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--. " . --:- -------r -----" -:. -------:' .. -~ ---.; ---., ---.; ----. ---:- -------:- -------r -------:. -------:. -------.: ----" --.; ------- • .2D " ",.,"',' · ",.,"',' , ",.,'" I ,

: : ; : : ; : : : ; , , , . , , , , , ,

. 1[1 , """"" -- - -- _.; - - -- - - - -:- -- - -. - -,- - - - - -- -;- - _ .. - -- -;. - - - --. -:. -- - -- .. - ~ - - - - - - - -;- - - - - - - -:- . - - . - - -;- - -- - -- -:- --- - - " -:' -- . ----:. -------

" """" , " "" I • " , " "",." , " """" , :' """""

HlllllllliIIIlIUiul!!ililll!!!!!!!IIIt1j!I1!!I!!lllil!!II!l!llljll!1111!!lIjllllllilllljuul!!I!!!il!!I!llllIlil!!I!!t1lllillllllllllliul!Ilil!lli!'!I'I!!'i

ru ~ w ro ro ru ~ w w ro ru ~ w N ~ ¢ W ~ w m Q ru ~ ~ m C,l)

Time in h[J~~r::;

Figure E.3 Suamer 1982 Peak Week for APS

•

•

•

•

E-7

The APS load behavior is typical of many summer-peaking utilities. This is

illustrated in Figures E.2 and E.3, which show the winter and summer peak

weeks for the APS system for the year 1982. The winter load usually shows a

fast morning pickup, ramping at about 3.0 MW/min (about 0.3%/min), with a

deep afternoon load valley, followed by an evening peak. The summer load

does not have the afternoon valley, and the load continues to build through

out the working hours of the day. The typical summer day hils a slower

morning ramp rate than winter, with 1.5 MW/min estimated as typical for the

week shown in Figure E.3.

Figures E.4 and E.5 show the peak winter and summer daily load pattern.

These figures illustrate more clearly the rate of morning load increase as

well as the rate of decrease later in the day.

E.3.2 SRP Generation

The SRP generatiou mix is shown in Table E.2. It shoule be pointed out that,

from an area control viewpoint, the three units at Navajo are outside the SRP

control area. These three units, although operated by SRP, are simulated as

being part of the WSCC control area.

The operating cost of SRP generation again reflects the great difference

between the cost of coal and oil as a boiler fuel. Again, for comparison.

the operating cost of a PV plant should be taken as about ~12.5/Mwh.

The load behavior of the SRP sys tem is vecy much dependent on the time of

year, due largely to the difference between heating and air conditioning

load. Figures E.6 and E.7 show the 1982 winter and summer peak weeks,

respectively. These curves exhibit load characteristics that are typical of

the Southwestern United States. Figures E.8 and E.9 show the 1982 peak day

for winter and summer load. respectively. The maximum ramp rates observed on

these peak days are about 2.2 MW/min in both winter and summer.

E.4 VALIDATION SIMULATIONS OF TIlE APS/SRP SYSTEM

An important aspect of computer simulation is to establish a means of

validating the computed results against the actual performance of the

E-8

• F1Z Pub] ic Service- Thu t'sd ,:t"'l Feb 4 1982 -'

1 [j[1

3: ~ 90

lrl C',J

80 IS)

C1,J

:::J ?0

CL

r-----.. -! ---------:- ---- --. --- ---------: -. -. ----r --------[ --------r --------! --------r --------: --------

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- - - - - - -:- - - - -- - - - --- -. -- - ----~ --------.;- . ----- - - :- - - ---- -- ,

cLJJ: : : ! : : : : : : : -------.; - - -.. - - -- -' . ---~ ------- - -:- - - -- - -- - ~ ---------~ -------. -: -. -----. -:- --------.; -------- -:- - - -- - ----: ---- ---

1 """"" , : : : : : : : : : ' , , I, .,' I , , " . .,

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, "", I , , - - - - _ .... - - - - • - - - • - - - - - - - _ ..... - - - - - - - _. - - - - - - - - ..t. ________ • ________ ..o. ____ • ___ • ________ .o. ______ • _. ________ _

: : : : : ; : : : : , , , , I • , , I ,

" "." I , I I I I • I , , ,

" '" I • • I

5E1 : : : , : : : : : : : ----- __ ... ________ , _________ r _______ • _________ ,... ________ • ______ • __ .. ________ ~--------- .. ---- ___ H. _______ ._r _______ _

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:: : : : I

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--------: --------.;- - -- _. -: ---------:- --------: -. -----. -:- --------' _. -------:- --------: --------v:. -. -- --_, ------__ , , "" , l '." , l I I ,

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--------;- --------~ ---.. -----r -. --.... -.: ---------:- --------.: -------. -r --------~ -~ -------;- --------~ ---------:- ------. -, , I I , , l I , I • •

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, , I • I ,. '" , , , , , " ~"

~ , , , I • " '" , I " ",

I] 0[1 I

I:'] co CD CO .-<

Time in hours

Figure E.4 The APS 1982 Winter P.ak Day

•

E-9

• r

I i 1

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1 1 , !

1 . >J[1

3: ~

""- _90 , , -------- -- ------,------_ ..• ,,------_ ...

cr) ()) C:O .80 -"------;---------;---------;---------'----- ----:--------- --------

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, , , , , , , , ,

:::l Q

lSI

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, • , , I ,50 , I , , , , , , , , , . , , ,

-t-" , , , , , , , , , , • , I I ,

C , , , I , I, I,

- -. - _. -.,- - -- - - - - - r - - - - - - - -.,- - - - - - - - -. - - .. - - - - - -,- - - - - - - - - - - - - - - - ~- - - - - - - - -. - - - - - - - _ .... - - - - - -- - r -" - - - - - - .... - - - - - - --, , , I , · " ,

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rJ) , , • , I

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I , • r • , Ft. "

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.20

W ,et

, I " "'" , . , " , '" - - - - - - - _;_ - - - - - - - - ~ - - - - - - - - _:_ - - - - - - o. __ : _ _ _ _ _ _ _ _: _________ .; _________ ; _________ .: _________ : _________ .: _________ ; _______ _

, " "," . 1 [1

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--' " ,," " " I , , " ,

[1 • ,] [1 '--_L.--'-__ '--~I_-'-_ ___'___' --' __ -'----1-1 ~_L__L,--LI _'----"'_-'----'----'_'---"--'-----'

i:sl Ct.J >::t U] CO lSI C'.J " ([I OJ fSI nJ cu Ci.J

T i me i n h ou r' :,;

Figure E.5 The APS 1982 Summer Peak Day

•

Table E.2

SRP Generation Approximate

Generator Rating Normal Max Operating Cost Rated Energy of Each Uni t Generation It/Dh Storage, MJ

Plant MVA D 1:IM Fuel Min Full Rotating Theraal

Navajo 1-2-3 892.4 750 OnTh Coal 11.00 2561.19 4462.00 Coronado 1-2 456.6 350 Drum Coal 23.00 1205.4.2 4417.61 Agua Fri a 1-2 133.7 111 Drum Gas 62.22 39.35 462.30 1693 ;76 Agua Fria 3 192.0 180 Drum Gas 58.82 37.56 685.44 2426.8 Agua Fria 4 89.5 69 CTrb Gas 376.07 54.90 616.66 • Agua Fria 5-6 79.1 64 CTrb Gas 376.07 55.63 616.98 • lyre 1 35.3 34 Drum Gas 70.48 53.13 119.67 • lyre 2 70.6 70 Drwn Gas 66.49 45.28 273.18 lyre 3-4 62.5 51 Ctrb Gas 351.60 60.39 Kyre 5-6 67.0 47 CTrb Gas 192.71 56.12 Horse Mesa 1-2-3 11.0 11 Hydr 24.53 • Horse Mesa 4 96.5 93 PTrb 311.70 • Mormon Flat 1 10.0 10 Hydr 24.00 • Mormon Flat 2 47.0 44 PTrb 177.66 • Roosevelt 34.8 36 Hydr 109.62 • Stewart Mtn. 13.0 13 Hydr 28.99 • San tan 1-4 115.0 72 CCyc Gas 74.06 36.54 667.00 • *Not calculated--unit not modeled in de tail.

• • •

•

+:'

• .... J

!

1. __

•

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! , , , , - - - - - - , - - - ~ .. "l~ ¥ - - - - - -,- - - - - _ •• -, - - - - - ..

I I ' , .

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, , , ,

E-ll

, --\

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, , , , - - _ .. - - -;- - - - . - - ..;- " -- - - - -;- .. " - - - - - ~ . --_ .. -:- ~ ---.... -.: ----- . -i-" ----~ -:- -- .. ---: .. --.. -. --:- -----.. -;

, ,

,~. , ,j 'c' It, '" J .ULLU.EU" i" , ! "lUuJ.W i ! i iii !I: , "lllillilUJlJlllili) , " jl.EL~lWJ.J1LULllU= i"" II f! '" i, <i " ; ijjllt;'UEJuiULlJU.JlliLUiLd

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Tirn6 in hou,";,;

Figure E.6 Winter 1982 Peak Week for SRP

r _____ ~~12 __ . _____ . __ .. __ . __ . __________ "_ .. ___________ . __ ._. __ . ______ . _____ ._ .. ______ . __ _

I ,

I L_

-1---'

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,F' l... ..; .. ______ : .. ____ .. ; __ ... __ : : : I . ,." II :" .,---- .. -- ...... :--.----;------.:------.;----: j j :--· .... ;---- .. ·:·· .... 1

.~ I ~J ~ ~J C"J lillill ,wili-.UL .. ll.lUllL!.lll1.1li.Jl!.LllilJ )11 '1 i j fI i llliWLillWLLU.J.llJ..jJJJ.iJ.iliu.wJJUi.tWU1.illlli l lllHl ) \II Ii LUllllWlllliJ.lWJ.l.iw.lUllLulu.ullWJJJ

G 0~ ~ u ro Q ru ~ ill ro Q ru ~ ro ro ......., '-'J 1--' tr I~I r",- co tTl lSI I-Ij (Il "'=1- lD _DJ

.,........ ........t ........ ,......, -.-.I .,......,

Tlrne In hours - ------- ----- - --- ------~------- ----- -~--------------------------

Figure E.7 Su.mer 1982 Peak leek for SIP

•

•

•

•

•

•

_ ...... _. __ .. _._. ___ . ______ ._. __ ._ .. __ .. _. ______ .. ___ . ________ .... _._ ... _ ..... _._ ... ___ .. __ .. _ .... ___ . ___ ... _ ......... __ .. _J<;.::ll_

-~ I i.· .. .l

Ll)

:...-

r.D

,-

1 • (:l[i

.. gEl

.?D

l._ ..._______. ____ . __

Pi \i6 " ,J an I

•• _____ .... __ "H ____ r

, , , , , , , ,

, , . -- - - -', -~ - -- -- - -,- .. -

, , ... ____ ,. ___ H H"_,, ____ ... _"*, _______ .,_, , , , , , ,

-.::]"" oj] co

Figure E.8 The SRP 1982 Winter Peak Day

, ----- .. "j

! "'1

E-14

"-'-',

,-, ' . 'J

-f-C'

F.: i \lG r', Rug.

1, (Hol r------ -;·--·-·-·T---- ---,---------~---------~---- -··T·---r-~r~T-L-------r- --"i--- -- - ~

: : : : , '_: : ,-1: :

_SLl - . ·--i- -- -.-->-.---.j--- .-- .j- ------+~~J-f.- ---: -----.-:---- ---~-----~~L----:-- ---- : I ' : : : J : I: '

. EO I--L~F~'- --L~- n: ' ---1- ---_n -t---- m_ 1-- '" --: -n n -- 1------ ---(_n _:m __ m( __ n -j [ ::::'::, I .. '::,(::,) r- --- -. --.-~------"-~-. --.. -" -:- ------,.-:- ---- -----'-- ,- --; --- -.- ------~ -----' ---~--.----- j

. 4°1...:: .................. .. ...................... ·1

,3E1 ~------;-- ----.; - ---i---- - - - ---.;-- ----- --,- -- -, -----. ---:-------, --- --- -- -- -- --- ---I

'" ~:jl. . .. ")+.11 , 1 [1 ~ __ n ___ : ________ : ____ • ___ : ______ .. : _________ : __ n __ -: •• ---- :---------:- -------:- ----:------:---------j

I ' : : : : : : : : : : I i : : : : : : : : : : : 1

[1 , [1 ,~1 L. __ .L_L ___ L-l._....l_L_L-....L ____ l. __ .l __ .L ___ L ___ L_..L.......L __ i ___ L_...l.... __ L_--,-' __ L.. __ 1._..l __

G N ~ ~ 00 Q ru ~ W 00 Q ru v

l C"!.j CU (1.j

_____________ . ________ . ______ . ______ ._ ... ______ . __ ~_~~_~n e~!:~_!-I o:~~~= _____________ . __ ,_ .. _____ , _____ ... ___ .. _._J

Figure E.9 Ike SIP 1912 S .... r Peak Day

•

•

•

•

•

•

E-15

physical system being studied. In order to validate the AGe simulation for

this project, APS. SRP, and ASU agreed upon a target date for which both

utilities would collect operations data. The date selected was November 24,

1982, which was the day before the Thanksgiving holiday. This day was

selected because past utility experience indicated unusual ramp rates that

could conceivably provide a good test of the simulated system control. As it

turned out, November 24, 1982 was a lIlearly normal fa11 day, but it still

provided good data for the purpose of validation.

E.4.1 System Measured Performance Data

The system measured performance was provided by APS and SRP in the form of

genera ti on and frequency charts. The genera tion charts show total system

generation, which is really the total system load. These charts were

digitized to provide the input load data for the simulation.

Figure E.I0 shows the APS morning load pickup between the hours of 6:30 and

7:30 AM. Note the initial drop in load just after 6:30 AM. This causes the

control to track a load drop, which is immediately followed by a sharp rise,

and would tend to upset the control performance. Figure E.ll shows the same

data for the SRP load, but taken from a strip chart recorder.

The validation simulation was performed over the 30 minute period 6:30-7:00

AM. For this period, the load is given digitally in Table E.3. From these

data we may compute the average load ramp rate to be 2.7 Ml/min for APS and

2.3 Ml/min for SRP. These are considered to be about typical for these

systems for this part of the year. Similar measurements taken at the time of

the winter or summer peak would be expected to exhibit as much as 4.0 Ml/min

ramp rate. Thi 5 can al so be aggrava t"d by an increasing transfer schedule

(sale) of power between the utilities that could add about 1.0 Ml/min to the

ramp rate of generation for the selling utility.

E-16

1660 ~-

1580

1560--

1540

1520 -

1500

1460

1460 --

1440

1420 --~ 6'30 om

--

-.- -::~

7:00

Figure E.10 APS Morning Load Pickup

November 24, 1982

•

•

7:30

•

•

• i I : , , I

III I

I , ,

,. , ; i

i i ! i i I I I ' : I I ; I I , , ,

: I

, , I , i ! !

! I , !

! ' I , " ,

!

, ,

• ; ;

I I !

Figure E.11 SRP Morning Load Pickup , ' !6I . November 24, 1982

i '." " I I I , I

E-18

Table E.3

APS and SRP Loads in MW November 24, 1982

Time APS Load Ram~ Rate SRP Load Ram~ Rate MW MW/min MW MW/min

0630 1472 1.1 1036 1.8

0640 1483 3.6 1054 4.6 0650 lS19 3.5 1100 0.4 0700 1554 2.7 1104 2.3 ave ave

The computed resul t of interest for the simulation is the performance of

frequency with time. During the period (6:30-7:30 AM) of interest, the

actual system frequency record is shown in Figure E.12. Note the slight

decline infrequency from about 6: 30 to 6: 40 AM. During this period the

system generation was being rapidly increased and the frequency recovered to

about normal by 6:40 AM.

E.4.2 Simulated Results of Validation Test

The simulated results of the November 24 load is presented in this section.

Figures E.13, E.14, and E.lS show the simulated loads in MW for APS, SRP, and

WSCC respectively, Note that the load scale must be mul tiplied by 100 for

the APS and SRP loads, and by 1000 for the WSCC load.

Figure E.16 shows the response of one of the APS 4 Corners units. This is

one of the units that is on 'regulation,' or it is being controlled in

response to system load increase. No actual generation chart was available

for comparison, but the plant performance was confirmed to be typical of the

response anticipated in this situation.

Figure E.17 shows the simulated frequency deviation due to the stochastic

load input from the load noise generator. Figures E.13-E.lS do not show this

load noise, but it is evident in the actual load data charts. The frequency

simulated did remain quite close to 60 Hz, as required. Because of the

random nature of the load, it is not to be expected that the computed

frequency will exactly ma tch the actual sys tem frequency. We note simply

•

•

•

• 7:10

7:00

6:50

'. 6:40

I

6:30 s ,J .. • I I·

.

• F~gure E.12

I

I

II

5 .e

IJ~~ III ~ I! I

~ II I

· 1(1 i~~

1 I

I 1 ; I

, i I .1

I I I. i I ! -I' I I --LJL.-LLLl-.t..U-.l-L+-+-, +-i .l.-, 1-, ++, -11

APS/SRP Frequency Record in Hz, November 24, 1982

E-20 ''it; .. I.·" : ... ~,,::i A 0 0 E 0 F 0 g 0 H 0 J " 0

dJ"CIi I, SCALi fA~ ItJR . , 0£-t\j2 1;: 00 I~ .0 1.3 ,2 ... L.J ClIl " 40 1:;00 I • .., J~ 20 ,,,,10 17.4u 11i.00

r tHE .............. ~ +++ ........ •• t ... ~ .... t t t ~.t ... , •• I • ......... ++ t ....... _ •• ++t • t ~ .......... ., 't +++-t+++ •• ++++.++++ ... ++++++++++ ... + .. + 000+ .. .. .. ....

Uu 00 .. • • •

JCQ 00 • • • •

• • • •

• • • • •

• • •

'iOO 00 .. •

• • • •

i400 00 .. • • • •

13!50 00 ... • • •

Uoo 00 ... • • •

Figure E.13 Simulated APS Load in MW vs. Time in Seconds from 0630 to 0700, November 24, 1982

•

•

•

•

•

•

•

.'

•

•

•

•

L.u .. D ~.;;; J

• 00

" 0

10 20

• F 0

JI 30

o " J o 11-21

QCALE f-A~ (OR ~ 1 OE">,j:l 11 8::1 1<iI.40 12.9:. 13 ,I,)

Tll1£ ...................... , , , ~, -tv.,.+. I ...... +'.1" •• , ' ................... ·t .......... ++. t ....... t .. ++ ...... t ++ .. +++ .............. ++++ ....... ++++ ................ .. 000+ .. .. .. .. .. .. ..

1.5000 .. + +

JI,}Q 00 .. + +

4~ OQ ..

toOO 00 ... + + + • •

150 00 .. • +

YOQ O-J ... •

l(;30 00

,;200 00 ... + •

+

1000 00 + • + •

Figure E.l4 Simulated SRP Load in MW vs. Time in Seconds from 0630 to 0700, November 24, 1982

E-22 • 0 o H Q Q

LuA(jiJ, SCAl E FA(.;fOR - I OEH;.J 3'.50 4u 00 ~J Ov 4L '0 4~ 00 4. 5D u 00 4J. SO U. OU 44. IV

r I~ ......... + ............... t .......... t ... +.+ t. +.~ . I • •••••• t ..... +++.++ t , ............................................ ++.+++++ ..... ++++ o 00 .. ...... .. ... ...

4~O OU ..

,,00 00 ..

7~O 00 ..

lQ!tO 00 ...

+ !.lOO 00 ..

1350 00

+

+ •

+

•

•

•

+ +

+ +

• •

+ •

• •

• • •

• •

• +

• +

+ •

11,) ...... ..

•

•

Figure E.1S Simulated WSCC Load in MW vs. Time in Seconds from 0630 to 0700, November 24, 1982

+

+

•

•

•

•

•

•

•

•

A., j '"," .. ~"=

UA"lll o '0 1 00 1 10

o

1 20 1 30

E 0 o

I 40 1 '0

Q 0

/.. '0

H 0

DeALt: FA":TOR ... 1 DE"'v; 1.1(1 1,90 L'9G

r I !"IE ............... t,. •• t , , .• , ................................. , .... t"1 .... 1 ............... , .. ",.1 t t ..... -.. t.t ....... t ...................................... .

000+ + ....... + + '" ..

UO 00 +

Joo_ 00 ...

I~OQ 00 ...

13$0 O.J •

1$00 00

Figure E.l6

+ + +

+ •

+ +

+ •

Response of APS Generator at 4 Corners in Response to Control Commands

+ +

+

+

+

+

:"Y::IIEM ....... RUSLI::b • " 0 0 • 0 F Q • 0 " 0 ~ J 0 E-24

•• IiiCAi.-1 fAL. fOl . , II •• -0_ '0 -0 40 o 30 - 0 2(1 -0 10 000 0" .... 0.:10 Q,40 .. fl"if + .......... ~ ............... ~, ......... ., ................ ~., , ......... + ... of .. +++++11-. ........................................ + •••••• + ...... + o 00 .. .. .. •• •••••

,50 00 .. · ·

Joe OQ ..

4!tO 00

/;joa 00

· ·

900 00 •

1050_ 00 ..

· · +

1200- 00

Il'-O 00 ...

+ + •

+ + • + •

+ +

•

+ • • • •

• + •

• + •

+ + •

• • +

+ • • +

Figure E.17 Simulated System Frequency Deviation for 0630-0700, November 24, 1982

• +

+ +

+ +

• •

+

•

• +

+ +

•

( . +

'" •

•

•

•

•

•

E-25

that the trend in both the actual and simulated results is for the frequency

to deviate randomly from 60 Hz, but to average about 60 Hz over a long time.

Figure E.18 shows the simulated behavior of the area control error (ACE) for

APS during the validation run. ACE is computed to deviate randomly about

zero with peak differences of less than 10 MW. This agrees g6nerally with

observed system performance. according to the project utility advisors.

Because of the random behavior of the system and of the simulation it is not

possible to state flatly the degree of accuracy in these simulations.

However, it was noted that all computed system variables behave in what must

be considered a normal manner, and with no noted errors. The validation was

therefore declared to be acceptable .

E-26

ACi.< I! -2 'I) -<I 0<1 , '" , 0" -0 to

• 0 •• ."" , 00

bCAL~ !'"In,lull; .. J C)C.H,;Z L so :a. Oil 02.511

T1I'IE .......... y ........ ,.,. H t? •••••••• ~ t .• , , , •••••••• t t ............ +t ..... t+ ... ++ •••• ~ ft+.·.··++ ... •• •• • ......... +. 000+ .. t.. ........ ..

4!10 ao ...

. I!lQ 00 ..

. "00 00 ..

lO~O au

lCOO 00 ..

1100 00 ..

Ftgur~ E.18 Simulated Area Control Error (ACE) in MW for APS, 0630 to 0700, November 24, 1982

•

•

•

•

•

•

E-27

E.S REFERmCES FOR APPENDIX E

1. Hein, R.E., D.J. Hughes, and B.W. Heller, 'Design of a Photovoltaic:

Central Power Station,' Martin Marietta Aerospace, Final Report for

Contract 62-9142 (Sand 82-7149), Denver, February 1983 •

•

•

•

APPENDIX F

Tabulated Simulation Results

t-l

Appendb F

SIMULATION RESULTS

The results of all simulations are presented in tabular form. Summaries of

all simulations on the APS system are s~marized in Table F.1. A similar

summary for SRP system simulations is given in Table F.2. These tables

provide numerical measures of each simulation, computed using equations

3.1-3.12. plus a record of other pertinent observations.

F-2

•

•

•

• Table F .1

Summary of APS Simulations

Table Load PV Wind Generation No. Level TXl!e Velocitx Remarks Schedule Al Fall + 15 Normal Generation FO A2 " + 10 " " A3 " + 5 " A4 " + 15 3+9 on Automatic " AS " + 15 ICC at 50 MW " A6 + 15 2CC at 50 MW each "

A7 Fall 15 Normal Generation FI-F5 A8 " 10 " " " A9 " 5 " " "

AI0 " 15 3+9 on Automatic " All " 15 ICC at 50 MW A12 " 15 2CC at 50 MW each

A13 Winter + 15 Normal Generation wO A14 " + 10 " " " A15 + 5 " " A16 " + 15 5 on Automatic " A17 " + 15 ICC at 50 MW " Al8 " + 15 2CC at 50 MW each " • A19 Winter 15 Normal Gen.-Opt. Dispatch WI-W5 A20 " 10 " " " " A21 " 5 " " " A22 " 15 5 on Automatic A23 " 15 ICC at 50 MW " A24 " 15 2CC at 50 MW

A25 Summer + 15 Normal Generation SO A26 + 10 " " A27 " + 5 " " A28 " + 15 1 on Automatic " A29 " + 15 1+18 on Automatic "

A30 Summer 15 Normal Generation 81-85 A31 " 10 " " " A32 " 5 " " " A33 " 15 1 on Automatic " A34 " 15 1+18 on Automatic " A35 " 15 1+18+19 on Automatic "

A36 Winter 15 Normal Gen.-Manual Dispatch U1-U5 A37 " 15 Normal Gen.-Normal Dispatch V1-V5

• r-3

Table F.2 • Summary of SRP Simulations

Table Load PV Wind Generation No. Level Ty~e Velocity Remarks Schedule SI Fall + 15 Normal Generation FO S2 " + 10 " " " S3 + 5 " " " 84 " + 15 42 on Automatic S5 " + 15 HM4 at 50 MW 86 + 15 HM4 + CC at 50 MW each "

S7 Fall 15 Normal Generation GI-G5 S8 " 10 " " S9 " 5 "

S10 " 15 42 on Automa ti c Sl1 15 HM4 at 50 MW " S12 15 HM4 + CC at SO MW each:

S13 Winter + 15 Normal Generation WO 814 " + 10 " " " SIS " + 5 " " " S16 + 15 42 on Automatic " S17 " + 15 ICC at SO MW S18 + 15 2CC at 50 MW each

S19 Winter 15 Normal Generation X1-X5 • S20 " 10 " " " S21 " 5 " " " S22 " 15 42 on Automatic S23 " 15 ICC at 50 MW S24 " 15 2CC at 50 MW

S25 Summer + 15 Normal Generation SO 826 + 10 " " " S27 + 5 " " " S28 + 15 45 on Automa ti c " S29 + 15 ICC at 50 MW

S30 Summer 15 Normal Generation TI-T5 S31 " 10 " " S32 " 5 " " " S33 15 45 on Automatic " S34 15 ICC at 50 MW "

835 Winter 15 Normal Gen 41M-42A XI-X5 S36 " 10 " " S37 " 5 " "

f-4 •

• • • ~

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 3.38 5.22 13.69 26.41 42.71 61.39

RMS ACE (MECH) 3.38 5.21 13.69 26.41 42.71 61. 39

RMS ACE (EL FLT) 0.76 2.96 11.24 23.51 39.44 57.81

AVERAGE ACE -0.57 0.63 4.54 11. 52 21. 97 35.89

INADVERTENT -0.1421 -0.7261 -2.6440 -6.0623 -11.1591 -17.9800

TIME ERROR -0.0642 -0.0619 -0.0559 -0.0451 -0.0264 -0.0055

RMS M 0.0024 0.0023 0.0022 0.0022 0.0023 0.0028

MAX t BTW ACE ZERO XING 32.0 156.0 364.0 636.0 764.0 1096.0 ..... I

V1 t OF LAST ZERO XING 168.0 184.0 392.0 664.0 792.0 1124.0

MAX ACE -12.10 25.71 59.92 92.87 129.34 173.02

t OF MAX ACE 1736.0 92.0 124.0 168.0 180.0 236.0

F.1. 15 m/s

FALL

APS

POSITIVE PV

~

MW PV GENERATION

0 50 100 150 200 250

RMSACE (ElEC) 4.-06 10.09 19.19 32.37 48.59

RMS ACE eMECH) 4.05 10.08 19.19 32.37 48.60

RMS ACE (El FlT) 1.90 8.28 17.20 30.07 46.06

AVERAGE ACE 0.29 3.36 8.43 16.86 28.90

INADVERTENT -0.5501 -2.0668 -4.5586 -B.6734 -14.5644

TIME ERROR -0.0609 -0.0577 -0.0512 -0.0366 -0.0168

RMS lit 0.0023 0.0022 0.0022 0.0021 0.0023

..., MAX t BTW ACE ZERO XING 164.0 364.0 636.0 764.0 1096.0 1 0'\

t OF lAST ZERO XING 192.0 392.0 664.0 792.0 1124.0

MAX ACE 15.74 41.27 69.77 98.62 132.42

t OF MAX ACE 124.0 180.0 236.0 296.0 296.0

F.1. 10 m/s

• • •

• • • ~

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 3.47 4.37 6.74 11.95 19.86

RMS ACE (MECH) 3.46 4.36 6.75 11.96 19.88

RMS ACE (EL FLT) 0.96 2.63 5.59 11.05 18.98

AVERAGE ACE -0.08 0.89 2.70 6.66 12.86

INADVERTENT -0.3754 -0.8445 -1. 7382 -3.6773 -6.7111

TIME ERROR -0.0622 -0.0602 -0.0585 -0.0521 -0.0419

RMS tlf 0.0023 0.0022 0.0022 0.0021 0.0019 H, I ~ MAX t BTW ACE ZERO XING 52.0 232.0 504.0 768.0 1016.0

t OF LAST ZERO XING 96.0 432.0 664.0 928.0 1176.0

MAX ACE -12.24 13.86 21.14 34.57 .50.00

t OF MAX ACE 1736.0 236.0 472.0 472.0 548.0

F.1. 5 m/s

MW PV GENERATION

0 50 100 150 200 250

RMS·ACE (ELEC) 4.04 7.72 15.49 26.09 39.57

RMS ACE (MECH) 4.03 7.71 15.48 26.09 39.57

RMS ACE (EL FLT) 1.64 5.52 12.92 23.01 36.12

AVERAGE ACE -0.21 1. 70 5.38 10.88 19.35

INADVERTENT -0.3110 -1.2453 -3.0545 -5.7474 -9.8929

TIME ERROR -0.0626 -0.0595 -0.0463 -0.0463 -0.0329

RMS l:Jf 0.0023 0.0022 0.0022 0.0022 0.0023

..., MAX t BTW ACE ZERO XING 108.0 212.0 364.0 588.0 764.0 I

ex> t OF LAST ZERO XING 136.0 240.0 392.0 616.0 792.0

MAX ACE 14.129 38.37 63.21 98.34 128.75

tOF MAX ACE 92.0 124.0 148.0 180.0 236.0

F.1. 15 m/s

3 + 9 on A

• • •

• • • ~

MW PV GENERATION

0 50 100 150 200 250

RMS·ACE (ELEC) 4.29 10.13 20.29 34.25 51.98

RMS ACE (MECH) 4.29 10 .12 20.29 34.25 51.98

RMS ACE (EL FLT) 1.97 7.83 17.49 31.18 48.70

AVERAGE ACE 0.15 2.89 7.89 16.84 32.66

INADVERTENT -0.4899 -1. 8341 -4.2822 -8.6581 -16.3980

TIME ERROR -0.0620 -0.0580 -0.0505 -0.0360 -0.0100

RMS M 0.0023 0.0022 0.0022 0.0022 0.0023

H, MAX t BTW ACE ZERO XING 124.0 256.0 404.0 764.0 1428.0

I '-0


MAX ACE 17.93 48.37 78.30 114.33 152.94

t OF MAX ACE 92.0 124.0 168.0 180.0 236.0

F.l. 15 m/s

Icc

c:.

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 3.96 7.85 15.92 27.15 43.36

RMS ACE (MECH) 3.96 7.85 15.92 27.15 43.36

RMS ACE (EL FLT) 1.62 5.67 13.27 24.04 40.24

AVERAGE ACE -0.20 1.82 5.50 11. 58 26.15

INADVERTENT -0.3160 -1. 3075 -3.1111 -6.0826 -13.2156

TIME ERROR -0.0628 -0.0598 -0.0542 -0.0435 ~0.6210

....., RMS flf 0.0023 0.13023 0.0022 0.0022 0.0022 I ...... 0

MAX t BTW ACE ZERO XING 108.0 212.0 364.0 588.0 1260.0


MAX ACE 14.49 39.11 65.33 100.95 IJ4.29

t OF MAX ACE 92.0 124.0 168.0 180.0 236.0

F .1. 15 m/s

2cc

• • •

• • • ;:

MW PV GENERATION

0 50 100 150 200 250

RMSACE (ELEC) 3.38 7.82 27.70 48.41 75.54 95.53

RMS ACE (MECH) 3.38 7.81 27.69 48.41 75.53 95.52

RMS ACE (EL FL T) 0.76 5.96 25.43 45.79 72.25 92.19

AVERAGE ACE -0.57 -4.78 -25.20 -44.88 -71.05 -86.83

INADVERTENT -0.1421 1.9103 11.9125 21. 5462 34.3488 42.0713

TIME ERROR -0.0642 -0.0720 -0.1031 -0.1339 -0.1768 -0.2013

RMS M 0.0024 0.0026 0.0036 0.0047 0.0061 0.0071 H) I I-' MAX t BTW ACE ZERO XING I-' 32.0 216.0

t OF LAST ZERO XING 168.0 236.0

MAX ACE -12.10 -27.84 -63.70 -105.90 -150.33 -187.88

t OF MAX ACE 1736.0 96.0 152.0 196.0 196.0 220.0

F .1. 15 m/s

Fall

APS

Negative PV

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 6.95 25.57 42.91 69.23 85.68

RMS ACE (MECH) 6.94 25.57 42.90 69.22 85.67

RMS ACE (EL FL T) 5.25 23.62 40.78 66.47 82.99

AVERAGE ACE -4.31 -23.62 -40.46 -65.63 -78.54

INADVERTENT 1.6890 11.1427 19.3911 31. 6895 38.0157

TIME ERROR -0.0697 -0.1000 -0.1261 -0.1687 -0.1885

RMS LIf 0.0025 0.0035 0.0044 0.0059 0.0066 ..... I

t MAX t BTW ACE ZERO XI NG 200.0

t OF LAST ZERO XING 236.0

MAX ACE -22.77 -52.55 -83.67 -121.87 -1.61.91

t OF MAX ACE 1736.0 196.0 260.0 284.0 320.0

F.1. 10 m/s

-

• • •

• • MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 6.35 22.43 35.99 56.55 65.62

RMS ACE (MECH) 6.34 22.42 35.98 56.54 65.61

RMS ACE (EL FLT) 4.73 20.83 34.34 54.29 63.63

AVERAGE ACE -3.93 -20.37 -33.65 -52.43 -60.13

INADVERTENT 1.5043 9.5533 16.0559 25.2399 29.0172

TIME ERROR -0.0689 -0.0945 -0.1156 -0.1461 -0.1575

H:> I

RMS L\f 0.0025 0.0036 0.0041 0.0051 0.0056 t;

MAX t BTW ACE ZERO XING 128.0 36.0


MAX ACE -23.09 -46.66 -57.00 -81.06 -104.89

t OF MAX ACE 1736.0 1736.0 1736.0 1736.0 664.0

F.1. 5 m/s

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ElEC) 4.22 11.23 23.03 38.52 61. 71

RMS ACE (MECtl) 4.21 11. 23 23.03 38.52 61. 71

RMS.ACE (El FlT) 2.03 9.31 20.71 38.50 58.66

AVERAGE ACE -1.17 -7.34 -17.82 -31.15 -53.82

INADVERTENT 0.1673 3.1859 8.3081 14.8276 25.9129

TIME ERROR -0.0626 -0.0727 -0.0904 -0.1120 -0.1492

RMS M 0.0023 0.0026 0.0033 0.0040 0.0053

..., I

MAX t BTW ACE ZERO XING 104.0 384.0 1004.0 I-' .;:-

t OF LAST ZERO XING 124.0 404.0 1024.0

MAX ACE -17.47 -39.51 -76.67 -114.67 -149.28

t OF MAX ACE 96.0 146.0 156.0 192.0 220.0

F.1. 15 m/s

3+9 on A

• •

• • • r1W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 4.85 18.20 37.73 64.28 88.63

RMS ACE (MECH) 4.84 18.20 37.72 64.28 88.63

RMS ACE (EL FLT) 2.84 16.00 35.12 61.12 85.29

AVERAGE ACE -1.90 -14.81 -34.37 -60.46 -83.02

INADVERTENT 0.5171 6.8289 16.4058 29.1710 40.2105

TIME ERROR -0.0650 -0.0864 -0.1165 -0.1592 -0.1952

RMS M 0.0024 0.0031 0.0041 0.0055 0.0068

MAX t BTW ACE ZERO XING 160;0 452.0 ...., I t OF LAST ZERO XING 180.0 472.0 f-'

VI

MAX ACE -21.55 -51.34 -91.31 -134.70 -170.11

t OF MAX ACE 96.0 156.0 160.0 196.0 220.0

F .1. 15 m/s

ICC

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ElEC) 4.10 11.34 27.11 52.21 79.42

RMS ACE (MECH) 4.09 11.34 27.11 52.20 79.41

R~lS ACE (El FlT) 1.93 9.32 24.50 49.31 76.14

AVERAGE ACE -1.15 -7.45 -23.20 -48.76 -75.36

INADVERTENT 0.1342 3.2392 10.9412 23.4502 36.4574

TIME ERROR -0.0661 -0.0727 -0.0987 -0.1396 -0.1833

RMSM 0.0024 0.0026 0.0035 0.0049 0.0063 ...., I MAX t BTW ACE ZERO XING 104.0 384.0 f-' CT\


MAX ACE -16.85 -39.96 -78.35 -117.86 -152.64

t OF MAX ACE 96.0 156.0 156.0 196.0 220.0

F .1. 15 m/s

2CC

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 8.76 6.63 16.29 33.73 55.94 83.21

RMS ACE (MECH) 8.75 6.63 16.29 33.73 55.94 83.22

RMS ACE (EL FLT) 7.24 4.64 14.77 31.99 53.74 80.59

AVERAGE ACE -6.71 0.37 11.70 28.60 49.60 75.86

INADVERTENT 2.8318 -0.6324 -6.1913 -14.4564 -24.7205 -37.5786

TIME ERROR -0.0786 -0.0669 -0.0513 -0.0238 0.0122 0.0525

RMS M 0.0029 0.0026 0.0022 0.0018 0.0020 0.0029

..., MAX t BTW ACE ZERO XING 164.0 164.0 1164.0 1708.0 I ,....

t OF LAST ZERO XING 956.0 192.0 1192.0 1736.0 -""I

MAX ACE -27.06 21.11 55.03 90.46 127.03 171. 73

t OF MAX ACE 1736.0 92.0 124.0 180.0 180.0 236.0

W.1. 15 m/s

WINTER APS

Positive PV

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ElEC) 6.37 14.48 29.60 49.80 75.39

RMS ACE (MECH) 6.37 14.48 29.61 49.81 75.39

RMS ACE (EL FlT) 4.42 13.43 28.51 48.32 73.49

AVERAGE ACE 0.12 10.98 26.04 45.13 69.40

INADVERTENT -0.5086 -5.8342 -13.2263 -22.5639 -34.4308

TIME ERROR -0.0674 -0.0517 -0.0308 0.0005 0.0401

RMS M 0.0026 0.0022 0.0018 0.0017 0.0024

..... MAX t BTW ACE ZERO XING 256.0 1024.0 1708.0 "

l-' co t OF lAST ZERO XING 284.0 1052.0 1736.0

MAX ACE -21.21 39.13 70.69 101.89 138.23

t OF MAX ACE 1736.0 236.0 236.0 296.0 340.0

W.1. 10 m/s

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 5.80 11.01 22.94 38.68 58.24

RMS ACE (MECH) 5.80 11.02 22.95 38.69 58.25

RMS ACE (EL FLT) 3.77 10.08 22.23 37.72 56.92

AVERAGE ACE -0.31 R.37 20.41 35.18 52.79

INADVERTENT -0.2997 -4.5581 -10.4504 -17.6775 -26.3043

TIME ERROR -0.0679 -0.0560 -0.6368 -0.0133 0.0133

RMS LIf 0.0026 0.0023 0.0019 0.0015 0.0017 H, I MAX t BTW ACE ZERO XING 120.0 892.0 1576.0 i-'

'-0


MAX ACE -20.74 26.90 46.10 66.00 ~3.48

t OF MAX ACE 1736.0 440.0 472.0 592.0 704.0

W.l. 5m/s

~~w PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 10.34 5.96 13.00 27.04 44.30 65.48

RMS ACE (MECH) 10.33 5.96 13.00 27.04 44.31 65.48

RMS ACE (EL FLT) 8.66 3.82 11.60 25.58 42.43 63.24

AVERAGE ACE -7.88 0.19 9.49 23.14 39.68 59.65

INADVERTENT 3.3976 -0.5576 -5.1159 -11. 7988 -19.8954 -29.6397

TIME ERROR -0.0814 -0.0691 -0.0559 -0.0344 -0.0086 0.0276

RMS ef 0.6030 0.0027 0.0023 0.0018 0.0017 0.0022 ..., I f\) MAX t BTW ACE ZERO XI NG 148.0 124.0 764.0 1708.0 0

t OF LAST ZERO XING 700.0 152.0 792.0 1736.0

MAX ACE -32.24 -20.05 44.73 72 .61 105.71 140.49

t OF MAX ACE 1736.0 1736.0 124.0 180.0 180.0 236.0

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 10.49 6.02 13.15 27.71 45.96 79.81

RMS ACE (MECHl 10.48 6.02 13.15 27.71 49.97 70.81

RMS ACE (EL FLT) 8.79 3.89 11. 71 26.10 43.86 68.40

AVERAGE ACE -7.98 0.31 9.50 73.38 40.55 63.83

INADVERTENT 3.4594 -0.6109 -5.1090 -11.9087 -20.2976 -31.6879

TIME ERROR -0.0797 -0.0685 -0.0538 -0.0325 -0.0033 0.0339

RMS M 0.0030 0.0026 0.0023 0.0018 0.0018 0.0024 H:> I MAX t BTW ACE ZERO XING 148.0 124.0 764.0 1708.0 ro '-'


MAX ACE -32.48 -20.27 46.59 77 .48 113.88 154.21

t OF MAX ACE 1736.0 1736.0 124.0 168.0 180.0 236.0

W.1. 15 m/s

+ lCC + 19

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 8.46 5.76 10.63 22.79 38.03 58.66

R~lS ACE (MECH) 8.45 5.76 10.63 22.79 38.03 58.66

RMS ACE (EL FLT) 6.88 3.59 9.22 21. 36 36.09 56.36

AVERAGE ACE -6.38 -0.01 7.53 19.29 33.58 52.33

INADVERTENT 2.6692 -0.4472 -4.1424 -9.9077 -16.8898 -26.0697

TIME ERROR -0.0780 -0.0681 -0.0565 -0.0390 -0.0147 0.0142

RMSM 0.0029 0.0026 0.0023 0.0019 0.0016 0.0019 ..., I MAX t BTW ACE ZERO XING 164.0 124.0 668.0 1612.0 ro ro


MAX ACE -27.32 -19.57 37.08 64.68 100.36 p5.92

t OF MAX ACE 1736.0 1736.0 124.0 168.0 180.0 236.0

W.1. 15 m/s

+ 2CC + 19+20

• •

• • • MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 8.11 8.55 18.19 32.97 51. 72 73.17

RMS ACE (MECH) 8.10 8.54 18.18 32.96 51. 72 73.17

RMS ACE (EL FLT) 4.95 4.89 15.58 30.52 49.17 70.37

AVERAGE ACE -4.59 1.68 8.98 21.39 39.00 59.57

INADVERTENT 1. 9027 -1.1514 -4.7248 -10.7764 -19.4200 -29.4865

TIME ERROR -0.0588 -0.0466 -0.0352 -0.0122 0.0120 0.0446

RMS M 0.0026 0.0023 0.0022 0.0022 0.0022 0.0032

...., MAX t BTW ACE ZERO XING 84.0 164.0 636.0 1024.0 1428.0 1708.0 , Kl u.>

t OF LAST ZERO XING 1324.0 192.0 664.0 1052.0 1456.0 1736.0

~lAX ACE -28.54 32.45 66.83 98.11 134.43 178.48

t OF MAX ACE 1736.0 92.0 124.0 180.0 180.0 236.0

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 7.84 15.56 28.19 44.39 63.51

RMS ACE (MECH) 7.82 15.55 28.19 44.39 63.52

R~lS ACE (EL FLT) 3.96 13.25 26.31 42.60 61.60

AVERAGE ACE 1.29 7.65 18.71 34.25 52.86

INADVERTENT -0.9520 -4.0809 -9.4852 -17.0873 -26.1907

TIME ERROR -0.0457 -0.0386 -0.0196 0.0054 0.0359

...., RMS oM 0.0023 0.0022 0.0021 0.0023 0.0028 I I\) .j::"" MAX t BTW ACE ZERO XING 216.0 420.0 1000.0 1420.0 1692.0


MAX ACE 28.89 53.21 82.88 108.02 1~7.44

t OF MAX ACE 124.0 236.0 236.0 296.0 340.0

S.l. 10 m/s

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 7.01 11.18 19.7~ 31.50 45.72

R~1S ACE (MECH) 7.00 11.19 19.75 31.52 45.74

RMS ACE (EL FL T) 2.80 8.93 18.30 30.36 44.56

AVERAGE ACE 0.79 5.53 13.82 25.73 39.50

INADVERTENT -0.7085 -3.0305 -7.0870 -12.9250 -19.6595

TIME ERROR -0.0470 -0.0398 -0.0268 -0.0089 0.0137

RMS M 0.0024 0.0022 0.0021 0.0020 0.0022 H, I MAX t BTW ACE ZERO XING 84.0 468.0 1084.0 1452.0 1628.0 II)

VI


MAX ACE 23.05 33.67 51.38 67.63 ?7.02

t OF MAX ACE 236.0 340.0 472.0 472.0 592.0

S.1. 5 m/s

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 7.50 7.88 15.23 27.40 43.28 61.88

RMS ACE (MECH) 7.48 7.87 15.22 27.39 43.28 61.88

RMS ACE (EL FL T) 3.95 3.73 12.35 24.75 40.58 59.00

AVERAGE ACE -3.60 0.86 6.09 15.06 27.71 44.27

INADVERTENT 1.4354 -0.7614 -3.3212 -7.6862 -13.8894 -21.9968

TIME ERROR -0.0547 -0.0495 -0.0413 -0.0232 -0.0053 0.0208

RMS M 0.0025 0.0024 0.0023 0.0023 0.0024 0.0028 HJ I ro MAX t BTW ACE ZERO XING 60.0 164.0 404.0 668.0 1024.0 1428.0 0\


MAX ACE -26.67 29.64 59.43 87.11 123.42 193. 84

t OF MAX ACE 1736.0 92.0 124.0 180.0 180.0 236.0

S.l. 15 m!s

1 on A

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 7.19 7.94 18.69 33.33

RMS ACE (MECH) 7.18 7.93 18.69 33.33

RMS ACE (EL FLT) 3.27 4.23 16.54 31.18

AVERAGE ACE -2.79 3.11 15.28 28.92

INADVERTENT 1.0233 -1.8645 -7.8227 -14.4675

TIME ERROR -0.0555 -0.0463 -0.0276 -0.0010

RMS M 0.0025 0.0024 0.0020 0.0020 ....,

MAX t BTW ACE ZERO XING 60.0 164.0 668.0 1708.0 I II:) -:j


MAX ACE -26.45 26.81 58.59 86.95

t OF MAX ACE 1736.0 92.0 124.0 180.0

S.l. 15 m/s

1 + 18 A

r1W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 4.78

RMS ACE (MECH) 4.79

RMS ACE (EL FLT) 0.58

AVERAGE ACE -0.37

INADVERTENT -0.1771

TIME ERROR -0.0541

RMS M 0.0025 ..., I MAX t BTW ACE ZERO XING 36.0 I\) 0:>


MAX ACE 12.44

t OF MAX ACE 1092.0

S.1. 15 m/s

1 + 18 + 19 A

. -

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 8.76 8.93 12.74 23.90 39.64 58.29

RMS ACE (MECH) 8.75 8.92 12.74 23.90 39.64 58.29

RMS ACE (EL FLT) 7.24 7.14 10.83 21. 33 36.49 54.64

AVERAGE ACE -6.71 -6.23 -10.53 -20.47 -35.07 -52.36

INADVERTENT 2.8318 2.6763 4.7788 9.6372 16.7815 25.2439

TIME ERROR -0.0786 -0.0662 -0.0730 -0.0896 -0.1133 -0.1401

RMS llf 0.0029 0.0026 0.0028 0.0033 0.0041 0.0050

..., MAX t BTW ACE ZERO XING 164.0 124.0 216.0 I

II:) \0 t OF LAST ZERO XING 956.0 1152.0 236.0

MAX ACE -27.06 -28.60 -33.64 -70.80 -106.85 -).40.44

t OF MAX ACE 1736.0 1736.0 104.0 156.0 196.0 220.0

W.l. 15 m/s

WINTER

APS

Negative PV

t1W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 8.54 11.65 20.28 33.45 49.73

RMS ACE (MECH) 8.53 11.64 20.27 33.44 49.72

RMS ACE (EL FL T) 6.82 9.95 18.40 31.22 47.09

AVERAGE ACE -5.86 -9.74 -18.25 -31.00 -46.40

INADVERTENT 2.4923 4.3925 8.5546 14.7897 22.3396

TIME ERROR -0.0654 -0.0720 -0.0852 -0.1062 -0.1292

RMS M 0.0025 0.0027 0.0031 0.0038 0.0046 ....

<1 MAX t BTW ACE ZERO XING 128.0 256.0 0


MAX ACE -27.73 -31.87 -42.58 -68.45 -99.05

t OF MAX ACE 1736.0 1736.0 1736.0 260.0 320.0

W.1. 10 m/s

• • •


0 50 100 150 200 250

RMS ACE (ELEC) B.39 10.54 17.47 27.15 3B.60

RMS ACE (MECHl 8.38 10.53 17.47 27.14 38.59

RMS ACE (EL FLT) 6.73 9.01 15.85 25.39 36.50

AVERAGE ACE -5.86 -B.77 -15.42 -24.38 -34.84

INADVERTENT 2.4940 3.9198 7.1774 11.5631 16.6B10

TIME ERROR -0.0656 -0.0697 -0.0800 -0.0941 -0.1106

..., RMS Lif 0.0025 0.0027 0.0030 0.0034 0.0040 I

lJJ I-' MAX t BTW ACE ZERO XING 124.0 148.0 48.0 52.0


MAX ACE -27.72 -31.12 -42.50 -55.21 -69.62

t OF MAX ACE 1736.0 1736.0 1736.0 1736.0 1736.0

W.1. 5 m/s

r1W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 7.92 7.09 9.43 17 .17 29.68 44.91

RMS ACE (MECH) 7.91 7.09 9.43 17 .17 29.69 44.91

RMS ACE (EL FLT) 6.31 5.06 7.55 15.04 27.00 41.86

AVERAGE ACE -6.06 -4.38 -7.20 -14.28 -25.74 -40.05

INADVERTENT 2.5018 1.7688 3.1405 6.6112 12.2195 19.2148

TIME ERROR -0.0792 -0.0635 -0.0692 -0.0795 -0.0977 -0.1218

RMS M 0.0030 0.0025 0.0026 0.0030 0.0036 0.0044 .....

MAX t BTW ACE ZERO XING 168.0 100.0 216.0 768.0 I l.J.> I\)


MAX ACE -25.50 -24.82 -27.94 -57.22 -86.73 -lI5.51

t OF MAX ACE 1736.0 1736.0 104.0 156.0 192.0 196.0

W.1. 15 m/s

5 on A

• • •

• ,tt • MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 7.81 7.12 9.31 17.90 33.56 53.28

RMS ACE (MECHl 7.80 7.11 9.31 17.90 33.56 53.28

RMS ACE (EL FLT l 6.29 5.16 7.48 15.65 30.56 49.88

AVERAGE ACE -6.02 -4.39 -7.18 -14.83 -29.56 -48.90

INADVERTENT 2.4833 1.7703 3.1427 6.8804 14.0921 23.5407

TIME ERROR -0.0789 -0.0635 -0.0671 -0.0805 -0.1032 -0.1364

RMS .6f 0.0029 0.0025 0.0026 0.0030 0.0037 0.0048 .... I MAX t BTW ACE ZERO XING 168.0 100.0 216.0 768.0 LA>

LA>


MAX ACE -24.59 -24.40 -27.03 -59.80 -92.71 -125.56

t OF MAX ACE 1736.0 1736.0 96.0 156.0 192.0 196.0

W.1. 15m/s

19 @ 50

I1W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 7.44 5.61 7.72 13.92 26.26 45.29

RMS ACE (MECH) 7.42 5.60 7.72 13.92 26.26 45.29

RMS ACE (EL FLT) 5.92 3.33 5.78 12.05 23.44 42.06

AVERAGE ACE -5.69 -3.00 -5.36 -11.48 -22.30 -41.38

INADVERTENT 2.3252 1.0849 2.2494 5.2498 10.5301 19.8662

TIME ERROR -0.0783 -0.0619 -0.0643 -0.0735 -0.0930 -0.1236 ....,

RMS M 0.0024 0.0025 0.0028 0.0034 0.0044 I 0.0029 co -I=""

MAX t BTW ACE ZERO XING 288.0 168.0 212.0 420.0


MAX ACE -21.62 -19.58 -24.21 -48.79 -77 .84 -110.60

t OF MAX ACE 1736.0 1736.0 96.0 156.0 196.0 196.0

W.1. 15 m/s

19 + 20 @ 50

• • •

• • t1W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 8.11 25.84 53.26 105.65 136.23

RMS ACE (MECH) 8.10 25.83 53.26 105.65 136.23

RMS ACE (EL FLT) 4.95 24.08 50.92 101.95 131.63

AVERAGE ACE -4.59 -24.73 -52.01 -103.53 -133.05

INADVERTENT 1. 9027 11. 7854 25.1412 50.3507 64.7846

TIME ERROR -0.0588 -0.0870 -0.1299 -0.2122 -0.2612 H,

RMSM 0.0026 0.0034 0.0047 0.0074 0.0090 I LA> \Jl

MAX t BTW ACE ZERO XING 84.0


MAX ACE -28.54 -48.35 -86.01 -144.35 -186.39

t OF MAX ACE 1736.0 1736.0 156.0 196.IJ 196.0

5.1. 15 m/s

SUMMER

APS

Negati ve PV

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 25.41 52.22 103.09 132.50

R~1S ACE (MECH) 25.40 52.21 103.08 132.50

RMS ACE (EL FLT) 23.70 50.06 99.61 128.18

AVERAGE ACE -24.20 -50.85 -100.35 -128.39

INADVERTENT 11.5161 24.5735 48.7923 62.5166

TIME ERROR -0.0874 -0.1281 -0.2074 -0.2519

RMS M 0.0034 0.0047 0.0073 0.0087 ....,

MAX t BTW ACE ZERO XING t L0 0'\

t OF LAST ZERO XING

MAX ACE -48.12 -81. 52 -131.06 -173.95

t OF ~lAX ACE 1736.0 196.0 260.0 320.0

S.l. ]0 m/s

• •


0 50 100 150 200 250

RMS ACE (ELEC) 25.14 49.30 96.69 121.50

RMS ACE (MECH) 25.14 49.29 96.69 121.49

RMS ACE (EL FLT) 23.45 47.37 93.44 117.45

AVERAGE ACE -23.49 -47.30 -92.20 -114.64

INADVERTENT 11.1631 22.8172 44.7980 55.7822

TIME ERROR -0.0871 -0.1246 -0.1951 -0.2306 ..., I

W RMS Llf 0.0034 0.0046 0.0069 0.0082 -;j

MAX t BTW ACE ZERO XING

t OF LAST ZERO XING

MAX ACE -46.46 -73.81 -128.98 -158.58

t OF MAX ACE 1736.0 1736.0 1736.0 1736.0

~~\~ PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 7.94 20.50 43.17 83.08 109.71

R~1S ACE (MECH) 7.92 20.50 43.16 83.07 109.70

Rt<lS ACE (EL FLT) 4.66 18.72 41.04 79.88 105.74

AVERAGE ACE -4.23 -19.25 -41.96 -81.17 -106.79

INADVERTENT 1. 7465 9.0932 20.2149 39.4099 51. 9493

TIME ERROR -0.0555 -0.0801 -0.1150 -0.1762 -0.2171 ..., I RMS M 0.0025 0.0032 0.0043 0.0062 0.0076 VJ (Xl



MAX ACE -28.10 -42.12 -73.58 -129.35 -172.48

t OF MAX ACE 1736.0 1736.0 156.0 196.0 196.0

S.l. 15 m/s

1 on A

• • •

• • • ~1H PV GENERATION

0 50 100 150 200 250

Rr~S ACE (ELEC) 7.39 16.66 35.32 64.77 87.75

RMS ACE (MECH) 7.37 16.65 35.31 64.76 87.74

R~lS ACE (EL FL T) 3.75 14.82 33.41 62.00 84.28

AVERAGE ACE -3.43 -15.24 -34.22 -63.10 -85.18

INADVERTENT 1.3424 7.1398 16.4359 30.5666 41. 3754

TIME ERROR -0.0559 -0.0720 -0.1013 -0.1477 -0.1822 ...,

RMS M 0.0026 0.0030 0.0038 0.0053 0.0064 I l>l \.0

MAX t BTH ACE ZERO XING 60.0 784.0


MAX ACE -27.02 -38.08 -58.70 -108.12 -150.68

t OF MAX ACE 1736.0 1736.0 156.0 156.0 196.0

S.1. 15 m/s

1 + 18 on A

r1W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 7.10 14.42 29.07 54.41 71.74

RMS ACE (MECH) 7.08 14.41 29.06 54.40 71. 74

RMS ACE (EL FLT) 3.07 12.40 27.29 51.97 68.64

AVERAGE ACE -2.62 -12.77 -28.00 -52.98 -69.44

INADVERTENT 0.9392 5.9137 13.3755 25.6172 33.6728

TIME ERROR -0.0554 -0.0703 -0.0938 -0.1307 -0.1574 .....

0.0047 I RMS L\f 0.0025 0.0029 0.0036 0.0056 oj:"" 0



MAX ACE -25.47 -37.16 -51.93 -93.46 -131. 75

t OF MAX ACE 1736.0 1736.0 1736.0 156.0 196.0

S.1. 15 m/s

1 + 18 + 19 on A

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 8.76 23.30 48.40 79.64

R~1S ACE (MECH) 8.75 23.29 48.39 79.64

~lS ACE (EL FLT) 7.24 21.26 45.67 75.89

AVERAGE ACE -6.71 -20.23 -45.38 -76.45

INADVERTENT 2.8318 9.4465 21. 7577 36.9625

TIME ERROR -0.0786 -0.1001 -0.1398 -0.1894 ....,

RMS I':.f 0.0029 0.0037 0.0050 0.0066 I -+=-i-'



MAX ACE -27.06 -53.86 -84.74 -120.35

t OF MAX ACE 1736.0 1736.0 1736.0 1736.0

~~w PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 19.48 38.93 41.87 66.10

RMS ACE (MECH) 19.47 38.92 41.87 66.10

RMS ACE (EL FLT) 17.72 36.64 39.27 62.78

AVERAGE ACE -17.19 -36.67 -39.65 -63.61

INADVERTENT 8.0054 17.5425 18.9867 30.7072

TIME ERROR -0.0887 -0.1192 -0.1258 -0.1643

RMS M 0.0033 0.0043 0.0045 0.0057 ..... I MAX t BTVJ ACE ZERO X I NG 216.0 .j:='

'" t OF LAST ZERO XING 236.0

MAX ACE -46.29 -70.07 -71.12 -105.72

t OF MAX ACE 1736.0 1736.0 1736.0 196.0

W.1. 15m/s

WINTER

APS

Negative PV

• • •

• • • ~1W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 3.07 13.60 41.96 78.51 119.20

R~1S ACE (MECH) 3.07 13.61 41. 96 78.51 119.21

R~lS ACE (EL FLT) 1.98 12.41 40.48 76.48 116.65

AVERAGE ACE -2.03 7.11 35.50 71.27 111.18

INADVERTENT 0.5875 -3.8796 -17.7857 -35.2790 -54.8162

TIME ERROR -0.0642 -0.0485 -0.0053 0.0537 0.1157 .... RMSM 0.0024 0.0020 0.0015 0.0027 0.0045 I +0-w



MAX ACE -8.58 40.26 88.34 137.00 183.95

t OF MAX ACE 380.0 112.0 168.0 188.0 248.0

F.1. 15m/s

FALL

SRP

Positi ve PV

NW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 12.37 39.37 73.60

R~1S ACE (MEeH) 12.37 39.37 73.60

R~lS ACE (EL FLT) 11.34 38.13 71.88

AVERAGE ACE 6.53 33.49 66.59

INADVERTENT -3.5980 -16.7966 -32.9926

TIME ERROR -0.0503 -0.0080 0.0453

.... RMS LIf 0.0020 0.0015 0.0024 I

.f:- MAX t BTW ACE ZERO XING 816.0 .f:-


MAX ACE 38.15 81. 79 128.48

t OF MAX ACE 168.0 248.0 272.0

F.2. 10 m/s

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 9.61 33.13 63.24

R~1S ACE (MECH) 9.61 33.13 63.24

R~lS ACE (EL FLT) 8.84 32.32 61.97

AVERAGE ACE 4.96 28.62 56.81

INADVERTENT -2.8325 -14.3984 -28.2002

THlE ERROR -0.0527 -0.0145 0.0307 ....,

RMS b. f 0.0021 0.0014 0.0020 I -I=' \J1



MAX ACE 28.43 67.31 108.10

t OF MAX ACE 332.0 448.0 516.0

F.2. 5 m/s

~1W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 10.09 32.08 60.64 93.93

R~1S ACE (MECH) 10.09 32.08 60.64 93.93

R~lS ACE (EL FLT) 8.77 30.36 58.48 91.39

AVERAGE ACE 4.96 25.00 51.30 82.77

INADVERTENT -2.8264 -12.6343 -25.5069 -40.9085

TIME ERROR -0.0522 -0.0205 0.0212 0.0718

'il RMSM 0.0021 0.0016 0.0021 0.0034

I ~ MAX t BTW ACE ZERO XING 792.0 0\


MAX ACE 35.73 80.78 127.75 172.29

t OF MAX ACE 112.0 168.0 188.0 204.0

F .2. 15 m/s

42 on A

• •

• • • ~~w PV GENERATION

0 50 100 150 200 250 -- .. ".'._ . ....,-_._.-

Ri~S ACE (ELEC) 9.50 36.63 73.17 113.20

R~·lS ACE (MECH) 9.51 36.64 73.17 113.20

R~lS ACE (EL FLT) 8.32 35.34 71.19 110.43

AVERAGE ACE 4.64 31.36 68.02 107.16

INADVERTENT -2.6715 -15.7610 -33.6843 -52.8529

TIME ERROR -0.0525 -0.0122 0.0489 0.1089

...., RMS Llf 0.0021 0.0015 0.0024 0.0042 I +" -.J ~lAX t BTl-I ACE ZERO XING 792.0


r~AX ACE 34.07 77 .17 125.88 172.05

t OF ~lAX ACE 84.0 132.0 188.0 248.0

F.2. 15 m/s

61 on @ 50 (HM4)

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 5.82 27.29 62.55 105.86

RMS ACE (MECH) 5.83 27.29 62.55 105.87

RMS ACE (EL FLT) 4.71 26.10 60.80 103.23

AVERAGE ACE 2.60 22.66 58.70 101. 74

INADVERTENT -1. 6736 -11.4997 -29.1373 -50.1966

TIME ERROR -0.0561 -0.0255 0.0318 0.1010

RMSM 0.0021 0.0015 0.0018 0.0038 ...,

MAX t BTW ACE ZERO XING 472.0 I .s:=-O)


MAX ACE 23.90 65.01 110.80 154.65

t OF MAX ACE 84.0 132.0 168.0 204.0

F.2. 15 m/s

61 & 56 @ 50

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 3.10 23.74 64.22 109.82

RMS ACE (MECH) 3.11 23.74 64.22 109.82

RMS ACE (EL FLT) 2.06 22.85 62.85 107.36

AVERAGE ACE -2.08 -19.47 -60.27 -106.20

INADVERTENT 0.6087 9.1279 29.1087 51. 5810

TIME ERROR -0.0644 -0.0913 -0.1540 -0.2280

RMS M 0.0024 0.0033 0.0054 0.0078 '11 I

MAX t BTW ACE ZERO XING 1656.0 oj::"" 92.0 \0


MAX ACE -9.05 -49.95 -98.42 -147.34

t OF MAX ACE 380.0 96.0 144.0 260.0

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 23.34 63.36 107.89

RMS ACE (MECH) 23.33 63.36 107.89

RMS ACE (EL FLT) 22.56 62.15 105.60

AVERAGE ACE -19.39 -59.32 -103.63

INADVERTENT 9.0878 28.6279 50.3203

HJ TIME ERROR -0.0911 -0.1550 -0.2238 I

VI C RMS !if 0.0033 0.0054 0.0077


t OF LAST ZERO XING 1672 .0

MAX ACE -48.41 -98.58 -146.68

t OF MAX ACE 144.0 260.0 260.0

F.2. 10 m/s

• • •

• • t~W PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 21.02 57.49 98.23

RMS ACE (MECH) 21.02 57.49 98.23

RMS ACE (EL FLT) 20.45 56.55 96.20

AVERAGE ACE -17.56 -53.14 -92.09

INADVERTENT 8.1986 25.6092 44.6712 ...., I

TIME ERROR -0.0873 -0.1442 -0.2059 \Jl I--'

RMSM 0.0031 0.0051 0.0072



MAX ACE -44.19 -87.82 -134.05

t OF MAX ACE 380.0 444.0 548.0

F.2. 5 m/s

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 2.38 14.29 41.13 76.04

RMS ACE (MECH) 2.39 14.29 41.13 76.03

RMS ACE (EL FLT) 0.58 13.00 39.59 74.22

AVERAGE ACE -0.50 -7.89 -30.25 -64.97

INADVERTENT -0.1528 3.4497 14.4047 31.3985

TIME ERROR -0.0603 -0.0744 -0.1080 -0.1630

H.l RMS M 0.0022 0.0027 0.0040 0.0059 I V1 ro

MAX t BTW ACE ZERO XING 660.0 1576.0 52.0


MAX ACE -7.61 -45.02 -91.55 -137.19

t OF MAX ACE 380.0 96.0 144.0 184.0

F.2. 15 m/s

42 on A

• •

• •

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 2.47 12.73 38.28 77 .44

RMS ACE (MECH) 2.48 12.73 38.28 77 .44

RMS ACE (EL FL T) 0.84 11.45 36.66 75.29

AVERAGE ACE -0.77 -6.98 -31. 52 -72.29

INADVERTENT -0.0242 3.0067 15.0195 34.9725

TIME ERROR -0.0614 -0.0726 -0.1111 -0.1756

RMS t, f 0.0023 0.0027 0.0040 0.0061 ,..., I

MAX t BTW ACE ZERO XING 64.0 748.0 V1 ( .,


MAX ACE -7.82 -43.12 -88.21 -133.56

t OF MAX ACE 380.0 96.0 144.0 184.0

F.2. 15 m/s

61 @ 50 MW

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 10.52 8.30 26.58 52.74 84.15

RMS ACE (MECH) 10.52 8.30 26.58 52.74 84.15

RMS ACE (EL FLT) 9.43 6.34 24.65 50.56 81.70

AVERAGE ACE -9.02 1.49 16.34 40.50 69.75

INADVERTENT 3.9874 -1.1994 -8.4599 -20.2957 -34.6199

TIME ERROR -0.0786 -0.0683 -0.0437 -0.0066 0.0386

RMS M 0.0029 0.0027 0.0024 0.0023 0.0033 ...., I

\Jl MAX t BTW ACE ZERO XING 244.0 228.0 1112.0 -J:o""


MAX ACE -23.74 35.58 76.80 122.61 165.74

t OF MAX ACE 1784.0 84.0 132.0 168.0 204.0

W.2. 15 m/s

WINTER

SRP

Pas iti ve PV

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 7.33 23.74 48.14 77 .35

RMS ACE (MECH) 7.33 23.74 48.14 77.35

RMS ACE (EL FLT) 5.50 22.15 46.38 75.37

AVERAGE ACE 1.25 15.07 37.41 64.31

INADVERTENT -1. 0915 -7.8586 -18.7830 -31. 9599

TIME ERROR -0.0699 -0.0486 -0.0120 0.0290 H, RMS !If 0.0027 0.0024 0.0022 0.0029 I \.Jl \.Jl



MAX ACE 30.58 66.56 111.61 156.82

t OF MAX ACE 132.0 248.0 248.0 332.0

W.2. 10 m/s

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 5.07 16.37 36.29 60.56 88.63 RMS ACE (MECH) 5.08 16.38 36.30 60.57 88.63

RMS ACE (EL FL T) 3.41 15.38 35.22 59.31 87.18

AVERAGE ACE 0.20 10.88 29.09 50.70 76.52

INADVERTENT -0.5765 -5.7895 -14.6959 -25.2931 -37.9382

TIME ERROR -0.0715 -0.0522 -0.0230 0.0088 0.0482

RMS M 0.0027 0.0023 0.0020 0.0022 0.0031 ...,

MAX t BTW ACE ZERO XING 260.0 1044.0 I IJl 0'\


MAX ACE 17.45 45.81 81.02 121.91 155.66

t OF MAX ACE 248.0 332.0 516.0 576.0 676.0

W.2. 5 m/s

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 8.44 5.81 19.78 43.49 73.38

RMS ACE (MECH) 8.44 5.81 19.78 43.49 73.38

RMS ACE (EL FLT) 7.33 3.69 17.72 41.35 70.90

AVERAGE ACE -6.94 0.58 10.84 33.39 62.40

INADVERTENT 2.9234 -0.7697 -5.7716 -16.8267 -31.0203

TIME ERROR -0.0820 -0.0716 -0.0529 -0.0196 0.0271

RMS M 0.0031 0.0027 0.0024 0.0022 0.0027 H" I

\Jl MAX t BTW ACE ZERO XING -l 144.0 180.0 780.0


MAX. ACE -20.18 27.42 66.13 111.27 152.81

t OF ~lAX ACE 1784.0 84.0 132.0 168.0 204.0

W.2. 15 m/s

42 on A

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 3.44 5.42 16.46 32.96 54.10 80.56

RMS ACE (MECH) 3.44 5.42 16.46 32.96 54.10 80.56

RMS ACE (EL FLT) 0.74 3.25 14.09 30.16 51.10 77 .48

AVERAGE ACE -0.50 0.75 6.16 16.16 32.31 58.01

INADVERTENT -0.1863 -0.8109 -3.4502 -8.3475 -16.2370 -28.8260

...., TIME ERROR -0.0654 -0.0654 -0.0554 -0.0399 -0.0120 0.0272 I

\J1 RMS llf 0.0025 0.0025 0.0024 0.0024 0.0028 0.0035 0:>

MAX t BTW ACE ZERO XING 64.0 180.0 436.0 680.0 968.0


MAX ACE -9.72 26.18 63.78 105.47 145.08 188.17

t OF MAX ACE 380.0 84.00 132.0 168.0 188.0 248.0

W.2. 15 m/s

55 @ 50

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 3.57 4.83 12.72 26.32 43.65 66.98

RMS ACE (MECH) 3.57 4.83 12.72 26.31 43.66 66.98

RMS ACE (EL FLT) 0.90 2.48 10.37 23.45 40.43 63.79

AVERAGE ACE -0.61 0.36 4.11 11.49 22.66 45.52

INADVERTENT -0.1395 -0.6173 -2.4531 -6.0571 -11.5237 -22.7017

TIME ERROR -0.0670 -0.0657 -0.0597 -0.0471 -0.0292 0.0086

>-; RMS M 0.0026 0.0025 0.0024 0.0024 0.0026 0.0030 f

\.TJ \D MAX t BTW ACE ZERO XING 64.0 120.0 348.0 568.0 792.0 1708.0


MAX ACE -11. 34 24.14 54.50 94.71 132.34 171.26

t OF MAX ACE 260.0 84.0 132.0 168.0 188.0 248.0

W.2. 15 m/s

55 + 56 @ 50

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 19.20 44.49 78.08 116.19

RMS ACE (MECH) 19.20 44.49 78.08 116.19

RMS ACE (EL FLT) 17.89 42.75 76.00 113.38

AVERAGE ACE -18.20 -41.59 -73.41 -110.64

INADVERTENT 8.4832 19.9332 35.5003 53.7070

TIME ERROR -0.0927 -0.1294 -0.1806 -0.2418

RMS M 0.0034 0.0045 0.0063 0.0084 ...., I

MAX t BTW ACE ZERO XING 0\ '"'

t OF LAST ZERO XING

MAX ACE -41.15 -85.69 -130.41 -178.31

t OF MAX ACE 96.0 144.0 184.0 212.0

W.2. 15 m/s

WINTER

SRP

Negative PV

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 18.52 42.48 74.17

RMS ACE (MECH) 18.52 42.48 74.17

RMS ACE (EL FLT) 17.34 40.95 72.38

AVERAGE ACE -17.63 -39.95 -69.52

INADVERTENT 8.2019 19.1274 33.5814

TIME ERROR -0.0922 -0.1271 -0.1767

RMS M 0.0033 0.0045 0.0062 '"t I

MAX t BTW ACE ZERO XING 0'\ f-'

t OF LAST ZERO XING

MAX ACE -35.51 -77.83 -126.22

t OF MAX ACE 144.0 260.0 260.0

W.2. 10 m/s

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 17.99 38.60 66.54

RMS ACE (MECH) 17.99 38.60 66.53

RMS ACE (EL FLT) 16.91 37.36 65.15

AVERAGE ACE -17.01 -36.02 -61.49

INADVERTENT 7.8989 17.2077 29.6722

TIME ERROR -0.0912 -0.1204 -0.1613

H, RMS M 0.0033 0.0043 0.0057 I

0"\ !\) MAX t BTW ACE ZERO XING

t OF LAST ZERO XING

MAX ACE -31.68 -67.40 -104.22

t OF MAX ACE 260.0 380.0 504.0

W.2. 5 m/s

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 8.44 14.14 33.84 60.08 91. 31

RMS ACE (MECH) 8.44 14.14 33.84 60.07 91.31

RMS ACE (EL FLT) 7.33 12.80 32.10 57.91 88.84

AVERAGE ACE -6.94 -12.90 -30.46 -53.99 -82.89

INADVERTENT 2.9234 5.8845 14.4820 25.9930 40.1306

TIME ERROR -0.0820 -0.0846 -0.1124 -0.1505 -0.1973 ....,

RMS M 0.0031 0.0031 0.0040 0.0053 0.0070 I (j\ w



MAX ACE -20.18 -37.45 -78.62 -120.95 -167.47

t OF MAX ACE 1784.0 96.0 144.0 184.0 212.0

W.2. 15 m/s

42A

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 3.44 7.96 23.82 49.20 79.60

RMS ACE (MECH) 3.44 7.97 23.82 49.19 79.59

RMS ACE (EL FLT) 0.74 6.20 21.89 47.10 77 .26

AVERAGE ACE -0.50 -3.28 -17.10 -40.65 -69.53

INADVERTENT -0.1863 1.1783 7.9387 19.4644 33.5968

TIME ERROR -0.0654 -0.0694 -0.0921 -0.1294 -0.1751

RMS t;f 0.0025 0.0026 0.0034 0.0047 0.0063 '1> I MAX t BTW ACE ZERO XING 64.0 304.0 800.0 0\ .;:-


MAX ACE -9.72 -35.04 -74.39 -114.82 -160.08

t OF MAX ACE 380.0 96.0 144.0 184.0 212.0

W.2. 15 m/s

55 @ 50

• • •


0 50 100 150 200 250

RMS ACE (ELEC) 3.57 5.73 17.55 39.66 68.64

RMS ACE (MECH) 3.57 5.74 17.56 39.66 68.64

RMS ACE (EL FLT) 0.90 3.85 15.47 37.39 66.10

AVERAGE ACE -0.61 -2.09 -11.30 -33.68 -61.52

INADVERTENT -0.1395 0.5956 5.0978 16.0542 29.6795

TIME ERROR -0.0670 -0.0674 -0.0830 -0.1181 -0.1622

RMS 6f 0.0026 0.0026 0.0031 0.0042 0.0057 'i> I 0\ MAX t BTW ACE ZERO XING 64.0 232.0 544.0 \Jl


MAX ACE -11.34 -26.45 -63.17 -101.48 -143.26

t OF ~lAX ACE 260.0 96.0 144.0 172.0 212.0

W.2. 15 m/s

55 + 56 @ 50

MW PV GENERATION

0 50 100 150 200 250 -----------_. RMS ACE (ELEC) 8.11 7.43 18.88 35.51 56.93 87.09 RMS ACE (MECH) 8.10 7.44 18.88 35.50 56.93 87.09 RMS ACE (EL FLT) 4.95 4.65 16.21 32.51 53.82 83.97

AVERAGE ACE -4.59 2.01 7.99 18.32 37.48 71.63

INADVERTENT 1.9027 -1.3618 -4.2879 -9.3345 -18.7167 -25.4170

TIME ERROR -0.0588 -0.0535 -0.0440 -0.0261 0.0036 0.0593

RMS M 0.0026 0.0025 0.0024 0.0025 0.0029 0.0038 ...., I

MAX t BTW ACE ZERO XING 0"\ 84.0 212.0 436.0 780.0 1244.0 0"\


MAX ACE -28.54 34.16 71.58 113.7 152.40 195.76

t OF f.1AX ACE 1736.0 84.0 132.0 168.0 188.0 248.0

S.2. 15 m/s

SUMMER

SRP

Positive PV

• • •

• • • ~~w PV GENERATION

0 50 100 150 200 250 - ---- .-- --- -

RMS ACE (ELEC) 7.23 17.11 31.81 51.35 80.10

R~1S ACE (MECH) 7.24 17.11 31.81 51.36 80.11

R~lS ACE (EL FLT) 4.59 14.87 29.43 48.97 77 .75

AVERAGE ACE 1.84 7.41 16.98 34.77 67.13

INADVERTENT -1.2886 -4.0022 -8.6811 -17.3877 -33.2186

TIME ERROR -0.0556 -0.0446 -0.0286 -0.0004 0.0521 H;, I RMS !':.f 0.0026 0.0024 0.0025 0.0027 0.0034 0'\

-'l



MAX ACE 29.59 61.65 99.07 135.00 178.96

t OF ~lAX ACE 132.0 188.0 248.0 300.0 332.0

5.2. 10 m/s

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ELEC) 5.40 8.43 14.68 27.67 51.85

R~1S ACE (MECH) 5.41 8.43 14.70 27.68 51.86

R~lS ACE (EL FL T) 2.27 6.50 13.35 26.54 50.69

AVERAGE ACE 1.01 3.19 8.11 20.24 45.48

INADVERTENT -0.8801 -1.9460 -4.3392 -10.2777 -22.6236

TIME ERROR -0.0559 -0.0524 -0.0424 -0.0238 0.0173 ..., RMS M 0.0025 0.0025 0.0024 0.0022 0.0023 I 0"\ (Xl



MAX ACE 17.96 32.12 46.11 71.25 102.12

t OF MAX ACE 332.0 332.0 448.0 576.0 - 576.0

5.2. 5 m/s

• • •


0 50 100 150 200 250 . - - .. - ,_._, -.-~.---.--

RMS ACE (ELEC) 4.82 7.19 17.81 33.53 52.73 77 .08

R~1S ACE (MECH) 4.84 7.20 17.81 33.53 52.73 77 .09

R~lS ACE (EL FLT) 0.51 4.29 15.07 30.50 49.41 73.72

AVERAGE ACE 0.06 1.80 7.21 16.82 30.30 54.21

INADVERTENT -0.3994 -1.2690 -3.9215 -8.5112 -15.2009 -26.9031

TIME ERROR -0.0554 -0.0555 -0.0471 -0.0305 -0.0080 0.0303 ...., I RMS b. f 0.0026 0.0026 0.0025 0.0025 0.0029 0.0036 0\

\0

MAX t BTW ACE ZERO XING 36.0 212.0 436.0 704.0 900.0 1316.0


MAX ACE 14.69 33.92 70.07 110.89 148.28 189.80

t OF ~lAX ACE 892.0 84.0 132.0 168.0 188.0 248.0

S.2. 15 m/s

45 on A

MW PV GENERATION

0 50 100 150 200 250 -, -" - -. --~-- ~---

RMS ACE (ELEC) 4.90 6.71 15.88 30.02 47.87 72.38

RMS ACE (MECH) 4.91 6.72 15.88 30.02 47.87 72.39

R~lS ACE (EL FLT) 0.52 3.57 12.95 26.80 44.43 68.98

AVERAGE ACE 0.05 1.35 5.87 13.94 27.82 54.52

INADVERTENT -0.3974 -1.0507 -3.2532 -7.1994 -13.9900 -27.0537

TIME ERROR -0.0558 -0.0562 -0.0475 -0.0343 -0.0123 0.0308

H, RMS M 0.0026 0.0026 0.0024 0.0025 0.0027 0.0032 I

i3 MAX t BTW ACE ZEHO XING 40.0 164.0 348.0 556.0 990.0

t OF LAST ZERO Xl NG 1544.0 196.0 380.0 588.0 932.0

MAX ACE 14.99 32.00 66.46 105.34 142.30 181.59

t OF ~lAX ACE 332.0 84.0 132.0 168.0 188.0 248.0

S.2. 15 m/s

55 @ 50 MW

• •


0 50 100 150 200 250 . - ,. - - .. _----,-_ .... _--

RHS ACE (ELEC) 8.11 10.75 34.24 68.72 107.94

R~lS ACE (MECH) 8.10 10.75 34.24 68.72 107.94

RfvlS ACE (EL FLT) 4.95 9.07 32.52 66.32 104.56

AVERAGE ACE -4.59 -8.99 -32.61 -66.44 -104.89

INADVERTENT 1.9027 4.0260 15.6013 32.1538 50.9671

TIME ERROR -0.0588 -0.0701 -0.1056 -0.1600 -0.2219

RMS M 0.0026 0.0029 0.0040 0.0057 0.0077

H.> MAX t BTW ACE ZEIIO XING 84.0 368.0 I --...J I-'


~lAX ACE -28.54 -34.85 -73.91 -112.73 -152.61

t OF MAX ACE 1736.0 96.0 144.0 172.0 212.0

S.2. 15 m/s

SUMMER

SRP

Negative PV

MW PV GENERATION

0 50 100 150 200 250 . - - ----.---"-.-.. ~-----,-- ---

RMS ACE (ElEC) 10.65 32.91 65.81

RMS ACE (MECH) 10.66 32.91 65.81

R~lS ACE (El FLT) 9.23 31.47 63.68

AVERAGE ACE -9.32 -31.60 -63.39

INADVERTENT 4.1890 15.0963 30.6643

TIME ERROR -0.0710 -0.1053 -0.1546

RMS M 0.0030 0.0040 0.0055

...., MAX t Bnl ACE ZERO XING 368.0 1

~ t OF LAST ZERO XING 1672.0

MAX ACE -28.79 -58.57 -104.68

t OF MAX ACE 144.0 212.0 260.0

5.2. 10 m/s

• • •


0 50 100 150 200 250 -- --'---'-"-"-'". - - - ---------

RMS ACE (ELEC) 9.55 29.76 59.61

RMS ACE (MECH) 9.56 29.76 59.61

RfvlS ACE (EL FLT) 8.20 28.51 57.73

AVERAGE ACE -8.29 -28.02 -55.71

INADVERTENT 3.6837 13.3369 26.8913

TIME ERROR -0.0696 -0.1006 -0.1443

RMS M 0.0029 0.0038 0.0053 H) MAX t BnJ ACE ZERO XING 368.0 I ~ LV


MAX ACE -22.43 -49.49 -82.74

t OF fvlAX ACE 260.0 380.0 648.0

S.2. 5 m/s

MW PV GENERATION

0 50 100 150 200 250 . - .. _-_ .. __ .- - - -~-,- .. - - .-.- . - .,'--- -.-

Ri~S ACE (ELEC) 4.82 8.32 26.87 57.59 92.39

R~1S ACE (MECH) 4.84 8.33 26.87 57.59 92.39

Rf.'lS ACE (EL FLT) 0.51 6.31 25.17 55.38 89.39

AVERAGE ACE 0.06 -6.01 -24.56 -54.69 -88.97

INADVERTENT -0.3994 2.5686 11.6604 26.4080 43.1672

TIME ERROR -0.0554 -0.0654 -0.0926 -0.1409 -0.1973

RMS M 0.0026 0.0028 0.0036 0.0051 0.0069 ...., I MAX t BTW ACE ZERO XING 36.0 224.0 ~


MAX ACE 14.69 -29.72 -68.20 -106.16 -147.12

t OF ~lAX ACE 892.0 96.0 144.0 172.0 212.0

S.2. 15 m/s

45 on A

• • •

• • ~~w PV GENERATION

0 50 100 150 200 250 - ~ -~-~- ~,----- -,--- . ------------- ---

RMS ACE (ELEC) 4.90 8.11 24.66 43.33 93.56

RMS ACE (MECH) 4.91 8.10 24.67 43.33 93.56

R~lS ACE (EL FLT) 0.52 5.69 23.05 41.26 90.47

AVERAGE ACE 0.05 -5.66 -22.98 -40.30 -90.92

I NAOVERTENT -0.3974 2.3989 10.8861 19.3608 44.1238

TIME ERROR -0.0558 -0.0649 -0.0904 -0.1183 -0.2003

RMS 6f 0.0026 0.0028 0.0035 0.0044 0.0070 ...., I

MAX t BTVJ ACE ZERO XING 144.0 ~ 40.0 V1


MAX ACE 14.99 -25.44 -61. 78 -94.65 -138.69

t OF ~lAX ACE 332.0 96.0 144.0 172 .0 212.0

S.2. 15 m/s

55 @ 50

~~\~ PV GENERATION

0 50 100 150 200 250 .. -- - .. _- - - - - ". _. ~ -- -------,,--"-_.-

RMS ACE (£LEC) 3.57 10.57 30.40 57.52 89.60

RNS ACE (MECH) 3.58 10.57 30.40 57.52 89.59

RNS ACE (EL FL 1 ) 1.32 9.00 28.61 55.48 87.29

AVERAGE ACE -1.22 -5.29 -19.22 -43.38 -75.68

INADVERTENT 0.1646 2.1572 8.9835 20.7954 36.5975

TIME ERROR -0.0668 -0.0732 -0 . .0942 -0.1340 -0.1864

.... RMS M 0.0026 0.0028 0.0.035 0.0.050 0.0067 I

~ ~1AX t BTW ACE ZE 1m x I NG 48.0 432.0 1004.0 1544.0

t .oF LAST ZERO XING 668.0 448.D 1020.0 1568.0

MAX ACE -11.58 -40.87 -84 • .04 -126.51 -173.31

t OF ~1AX ACE 38.0 • .0 96 • .0 144.0 184 . .0 212 . .0

W.2. 15 m/s

42A Base 41M

• • •

• • • ~1W PV GENERATION

0 50 100 150 200 250 ~---

Ri1S ACE (ELEC) 9.12 27.13 52.40 82.66

Rt,lS ACE (MECH) 9.13 27.13 52.40 82.66

R~lS ACE (EL FL 1 ) 7.75 25.69 50.78 80.82

AVERAGE ACE -4.65 -17.31 -39.66 -69.90

INADVERTENT 1.8417 8.0407 18.9707 33.7595

TI~lE ERROR -0.0725 -0.0923 -0.1287 -0.1786 ...., I R~lS 6. f 0.0027 0.0035 0.0048 0.0065 ::i

~lAX t BHJ ACE ZERO XING 432.0 1012.0 1544.0


MAX ACE -34.23 -72.93 -119.02 -159.85

t OF ~lAX ACI:. 144.0 212.0 260.0 316.0

W.2. ,10 m/s

42A Base 41M

MW PV GENERATION

0 50 100 150 200 250

RMS ACE (ElEC) 7.54 21. 72 42.32 68.43

RMS ACE (MECH) 7.55 21.71 42.32 68.43

RMS ACE (El FlT) 6.39 20.79 41.37 67.30

AVERAGE ACE -3.96 -14.28 -32.88 -58.52

INADVERTENT 1.5031 6.5639 15.6672 28 •. 2132

TIME ERROR -0.0714 -0.0861 -0.1159 -0.1571

RMS M 0.0027 0.0032 0.0042 0.0057

..., MAX t BTW ACE ZERO XING t

472.0 948.0 1504.0 ~ t OF lAST ZERO XING 560.0 1036.0 1592.0

MAX ACE -28.24 -58.68 -88.67 -126.41

t OF MAX ACE 260.0 380.0 472.0 600.0

W.2 .. 5 m/s

42A Base 41 M

• •

•

•

•

APPENDIX G

Generation Schedules

g-l

Appeadh: G

GFNBRATION SCHEDULES

Generation schedules are required for each of the siaulations that exactly

matches the ini tial area generation (at t .. O) to the area loa4 plua net

interchange out of the area. Thh dispa tch Bchedule fa •• ed for the areas

not impacted by PV generation and is also uled for 'positive PV' cases, since

these cases initially have PV generation aet for .ero.

For 'negative PV' cases, however, the PV is iaitially operating at its rated

value (50,100, ISO, 200, 250 MW). Addin, thil given aao.at of PV generation

requires a rescheduling of conveational geaeration, th •• aeceslitating five

additional dispatch schedules, one corl"espondina to each PV ratiaS studied.

These negative PV schedules wel"e constructed with the a •• istance of APS and

SRP engineers. For the Wintel" load case it has bean shown that the

construction of these schedules is cdtical (see Section 3). Thus, three

sepal"ate schedules are given for this load level to demonstrate the

importance of this calculation.

The schedules al"e summal"ized in Table G.l and the individual schedules

tabulated in G.2-G.I0. In these tables, units marked with en , are assigned

to regulation duty.

•

•

•

• Table G.1 Summary of Generation Schedules

SEASON AREA COMPANY 0 50 100 150 200 250 COMMENT

Fall 1 APS FO Fl F2 F3 F4 F5 Normal Fall 2 SRP FO Gl G2 G3 G4 G5 Normal

Winter 1 APS WO VI V2 V3 V4 V5 Normal Winter 2 SRP WO Xl X2 X3 X4 X5 Normal Winter 1 APS WO WI W2 W3 W4 W5 Optimum Winter 2 SRP WO Yl Y2 Y3 Y4 Y5 Optimum Winter 1 APS WO Ul U2 U3 U4 US Manual

Summer 1 APS SO SI S2 S3 S4 S5 Normal Summer 2 SRP SO T1 T2 T3 1'4 1'5 Normal

•

• g-3

• Table G.2 GENERATION SCHEDULE

Company: APS Area: 1 Load Level: 1982 Fall Po: 1470

Initial Load Deviation From Po Generator Load FO Load Fl Load F2 Load F3 Load F4 Load 5 No. Name 0 -50 -100 -150 -200 -250

1 FCI 156.4· 156.4 156.4 156.4 156.4 156.4 2 FC2 102.5· 102.5 102.5 102.5 102.5 102.5 3 FC3 73.6 73.6 73.6 73 .6 73.6 73.6 4 FC4 757.6 757.6 757.6 757.6 757.6 757.6 5 FC5 762.0 762.0 762.0 762.0 762.0 762.0 6 Cholla 1 15.8· 75.8 75.8 75.8 15.8 68.9 7 Ch 2 205.3· 205.3 205.3 205.3 198.1 155.0 8 Ch 3 224.3* 224.3 224.3 192.8 150.0 150.0 9 Ch 4 249.5 217.S 167.5 149.0 149.0 149.0

10 Oco 1 30.0 30.0 30.0 30.0 30.0 30.0 11 Oco 2 12 Sag 1 13 Sag 2 14 Yucca 1 23.0 5.0 S.O S.O S.O S.O 15 WP 4 16 WP 5 17 WP 6 • 18 WPCC 1 19 WPCC 2 20 WPCC 3 21 OcoCT 1 22 OcoCT 2 23 WP CT 1 24 WP CT 2 25 SagCT 1 26 SagCT 2 27 DougCT 1 28 YumaCT 1 29 YumaCT 2 30 YumaCT 3 31 YumaCT 4

2660.0 2610 2560 2510 2460 2410 Net Interchange 1190,0 out

Net Load 1470.0

• g-4

• Company: SRP Area: 2

Generator Load FO No. Name 0

41 Caron 1 281* 42 Coron 2 213 43 AFI 37* 44 AF2 45 AF3 46 Kyr 1 47 Kyr 2 48 AFCT 4 49 AFCT 5 50 AFCT 6 51 KyrCT 3 52 KyrCT 4 53 KyrCT 5 54 KyrCT 6 55 SanCC 1 56 SanCC 2 57 Rvelt • 58 8M 1 59 8M 2 60 8M3 61 8M 4 62 NFl 63 MF 2 64 SMtn 65 CCut

531 Net Interchange 505 In

Net Load 1036

•

Table G.3 GENERATION SCHEDULE

Load Level: 1982 Fall Po: 1036 @ 2.3 MW/min

Initial Load Deviation From Po Load Gl Load G2 Load G3 Load G4 -50 -100 -150 -200

231* 213

35*

181* 213

35*

g-5

131* 213 35*

120* 174

35*

Load G5 -250

120* 124

35*

• Table G.4 GFNEaATION SCHEDULE

Normal Di spa tch

Company: APS Area: 1 toad Level: 1982 Winter Po: 1825 MW

Initial Load Deviation From Po Generator Load WO Load VI Load V2 Load V3 Load V4 Load V5 No. Name 0 -50 -100 -150 -200 -250

1 FC1 162.8- 162.8- 162.8- 162.8- 162.8- 162.8-2 FC2 163.1- 163.1- 163.1- 163.1- 163.1 163.1-3 FC3 214.9 215.9 214.5 214.5 214.5 214.5 4 FC4 5 FC5 695.0 695.0 695.0 695.0 695.0 695.0 6 Cholla 1 104.6 104.6 104.6 104.6 104.6 104.6 7 Ch 2 225.6- 204.6- 155.0- 155.0- 155.0- 155.0-8 Ch 3 245.1- 245.1- 245.1- 195.0- 150.0- 150.0-9 Ch 4 300.2 300,2 300.2 300.2 295.0 245.0

10 Oco 1 37.6- 37.6- 37.6- 37.6- 37.6- 37.6-11 Oco 2 12 Sag 1 28.8- 28.8- 28.8- 28.8- 28.8- 28.8-13 Sag 2 14 Yucca 1 34.0 5.0 5.0 5.0 5.0 5.0 15 WP 4 16 WP 5 • 17 WP 6 18 WPCC 1 50- 50- 50- 50- 50- 50-19 WPCC 2 20 WPCC 3 21 OcoCT 1 22 OcoCT 2 23 WP CT 1 24 WP CT 2 25 SagCT 1 26 SagCT 2 27 DougCT 1 28 YumaCT 1 29 YumaCT 2 30 YumaCT 3 31 YumaCT 4 32 Ch-Irving 4.4 4.4 4.4 4.4 4.4 4.4

2266.1 2216.1 2166.5 2116 2066 2016

Net Interchange 441.0 out Net Load 1825.1

• g-6


Normal Dispatch

Company: SRP Area: 2 Load Level: Winter 1982 Po: 1498 @ 2.1 MW/min

Initial Load Deviation From Po Generator Load WO Load Xl Load X2 Load X3 Load X4 Load X5 No. Name 0 -50 -100 -150 -200 -250

41 Coron 1 355* 349* 349* 349* 349* 349* 42 Coron 2 184 184 184 184 184 156 43 AF1 78* 65* 64* 37*(min) 37* 37* 44 AF2 45 AF3 138* 138* 138* 115* 65* 55*(min) 46 Kyr 1 47 Kyr 2 48 AFCT 4 49 AFCT 5 SO AFCT 6 51 KyrCT 3 52 KyrCT 4 14 4(min) 4 4 4 4 53 KyrCT 5 54 KyrCT 6 55 SanCC 1 56 SanCC 2 • 57 Rvelt 58 HM 1 10 3 (min) 3 3 3 3 59 HM 2 10 3(min) 3 3 3 3 60 HM 3 10 3(min) 3 3 3 3 61 HM 4 49* 49* 0 0 0 0 62 MF 1 63 MF 2 64 SMtn 65 CCut


Net Load 1498

• g-7

Table G.6 • G~ERATION SCHEDULE Optimum Di spa tch

Company: APS Area: 1 Load Level: 1982 Winter Po: 1825

Initial Load Deviation From Po Generator Load WO Load WI Load W2 Load W3 Load W4 Load W5 No. Name 0 -50 -100 -150 -200 -250

1 FCI 162.8· 157.8· 152.8· 147.8· 142.8· 137.8· 2 FC2 163.1· 158.1· 153.1· 148.1· 143.1· 138.1· 3 FC3 214.8 214.8 214.8 214.8 214.8 214.8 4 FC4 5 FC5 695.0 685.0 675.0 665.0 655.0 645.0 6 Cholla 1 104.6· 104.6· 104.6· 104.6· 104.6· 104.6· 7 Ch 2 225.6· 215.6· 205.6· 195.6· 185.6· 175.6· 8 Ch 3 245.1· 235.1· 225.1· 215.1· 205.1· 195.1· 9 Ch 4 300.2 295.2 290.2 285.2 280.2 275.2

10 Oco 1 37.6· 37.6· 37.6· 37.6· 37.6· 37.6· 11 Oco 2 12 Sag 1 28.8· 28.8· 28.8· 28.8· 28.8· 28.8· 13 Sag 2 14 Yucca 1 34.0 29.0 24.0 19.0 14.0 9.0 15 WP 4 16 WP 5 • 17 WP 6 18 WPCC 1 50.0· 50.0· 50.0· 50.0· 50.0· 50.0· 19 WPCC 2 20 WPCC 3 21 OcoCT 1 22 OcoCT 2 23 WP CT 1 24 WP CT 2 25 SagCT 1 26 SagCT 2 27 DougCT 1 28 YumaCT 1 29 YumaCT 2 30 YumaCT 3 31 YumaCT 4 32 Ch-Irving 4.4 4.4 4.4 4.4 4.4 4.4

2266.0 2216.0 2166.0 2116.0 2066.0 2016.0

Net Interchange 441 out Net Load 1825

• g-8

• Table G.7 GfNERATION SCHEDULE

Optimum Dispatch

Company: SRP Area: 2 Load Level: 1982 Winter Po: 1498 @ 2.1 MW/min

Initial Load Deviation From Po Generator Load WO Load Y1 Load Y2 Load Y3 Load Y4 Load Y5 No. Name 0 -50 -100 -150 -200 -250

41 Coron 1 355 340 325 310 295 280 42 Coron 2 184* 179* 174* 169* 164* 159* 43 AF1 78* 73* 68* 63* 58* 52* 44 AF2 45 AF3 138* 128* 118* 108* 98* 88* 46 Kyr 1 47 Kyr 2 48 AFCT4 49 AFCT 5 50 AFCT6 51 KyrCT 3 52 KyrCT 4 14 12 10 8 6 4 53 KyrCT 5 54 KyrCT 6 55 SanCC 1 56 SanCC 2 • 57 Rvelt 58 HM 1 10 9 8 7 6 5 59 HM 2 10 9 8 7 6 5 60 HM 3 10 9 8 7 6 5 61 HM 4 49* 39* 29* 19* 9* 0* 62 1IF1 63 MF 2 64 SMtn 65 CCut


Net Load 1498

• g-9

Company: APS

Generator No. Name

1 FCI 2 FC2 3 FC3 4 FC4 5 FC5 6 Cholla 1 7 Ch 2 8 Ch 3 9 Ch 4

10 Oco 1 11 Oco 2 12 Sag 1 13 Sag 2 14 Yucca 1 15 WP 4 16 WP 5 17 WP 6 18 WPCC 1 19 WPCC 2 20 WPCC 3 21 OcoCT 1 22 OcoCT 2 23 WP CT 1 24 WP CT 2 25 SagCT 1 26 SagCT 2 27 DougCT 1 28 YumaCT 1 29 YumaCT 2 30 YumaCT 3 31 YumaCT 4 32 CH-Irv

Area: 1

Load WO o

162.8· 163.1· 214.8

695.0 104.6· 225.6· 245.1· 300.2 37.6·

28.8·

34.0

50.0·

4.4

2266.0 Net Interchange 441.0 Out

Net Load 1825.0

Table G.8 GENERATION SCHEDULE

Normal Dhpa tch

Load Level: 1982 Winter Po: 1825

Initial Load Deviation FrOB Po Load U1 Load U2 Load U3 -50 -100 -150 -200

645.0 595.0 545.0 495.0

• -250

445.0

•

•


Company: APS Area: 1 Load Level: 19S2 Summer Po: 2944

Initial Load Deviation From Po Generator Load SO Load Sl Load S2 Load S3 Load S4 Load S5 No. Name 0 -50 -100 -150 -200 -250

1 FCI 10S.6 10S.6 10S.6 10S.6 10S.6 10S.6 2 FC2 162.5 162.5 162.5 162.5 162.5 162.5 3 FC3 215.S 215.S 215.S 215.S 215.S 215.S 4 FC4 722.0 722.0 722.0 722.0 722.0 722.0 5 FCS 6 Cholla 1 107.2· 107.2· 107.2· 107.2- 107.2· 107.2· 7 Ch 2 234.4· 234.4· lS9.6· 139.6· S9.6· 50.0· S Ch 3 243.S· 243.S· 243.S· 243. S. 243.S· 233.4· 9 Ch 4 34S.6 34S.6 34S.6 34S.6 34S.6 34S.6

10 Oco 1 SO .S SO.S SO.S SO.S SO.S SO.S 11 Oco 2 SO .S. SO .S. SO.S· SO.S· SO .S. SO.S· 12 Sag 1 13 Sag 2 100.S· 100.S· 69.S· 25.0· 25.0· 25.0· 14 Yucca 1 74.0 24.0 5.0 5.0 5.0 5.0 15 WP 4 32.0 32.0 32.0 32.0 32.0 32.0 16 WP 5 11.6 11.6 11.6 11.6 11.6 11.6 17 WP 6 53.5 53.5 53.5 53.5 53.5 53.5 • IS WPCC 1 31.0 31.0 31.0 31.0 31.0 31.0 19 WPCC 2 31.0 31.0 31.0 31.0 31,0 31.0 20 WPCC 3 31.0 31.0 31.0 31.0 31.0 31.0 21 OcoCT 1 52.5 52.5 52.5 52.5 52.5 52.5 22 OcoCT 2 23 WP CT 1 104.3 104.3 104.3 104.3 104.3 104.3 24 WP CT 2 25 SagCT 1 52.0 52.0 52.0 52.0 52.0 52.0 26 SagCT 2 27 DougCT 1 2S YumaCT 1 51.0 51.0 51.0 51.0 51.0 51.0 29 YumaCT 2 30 YumaCT 3 31 YumaCT 4 32 Ch-Irving 4.2 4.2 4.2 4.2 4.2 4.2

2933.4 2SS3 2SS3 27S3 2733 26S3 Net Interchange 10.6 In

Net Load 2944.0

• g-ll

• Table G.IO G~ERATION SCHEDULE

Company: SRP Area: 2 Load Level: Summer 1982 Po: 2160 @ 0.13 MW/min

Initial Load Deviation From Po Generator Load SO Load n Load T2 Load T3 Load T4 Load TS No. Name 0 -50 -100 -150 -200 -250

41 Cor on 1 356· 356· 356· 356· 356· 356· 42 Coron 2 361 361 361 361 361 361 43 AFI 87* 87· 87· 65· 37· 37· 44 AF2 45 AF3 145 145 145 145 123 123 46 Kyr 1 47 Kyr 2 48 AFCT 4 49 AFCT 5 51 51 32 4 4 4 50 AFCT 6 51 KyrCT 3 52 KyrCT 4 46 4 4 4 4 4 53 KyrCT 5 45· 37· 6* 6· 6· 6· 54 KyrCT 6 55 SanCC 1 56 SanCC 2 67· 67* 67· 67· 67 67 57 Rvelt 36 36 36 36 36 36 • 58 HM 1 10 10 10 10 10 10 59 HM 2 10 10 10 10 10 10 60 HM 3 10 10 10 10 10 10 61 HM 4 75* 75· 75· 75· 75* 75· 62 NFl 9 9 9 9 9 9 63 MF 2 40 40 40 40 40 40 64 SMtn 9 9 9 9 9 9 65 CCut 2 2 2 2 2 2

1359 1309 1259 1209 1159 1109 Net Interchange 801 In

Net Load 2160

•

•

•

•

APPENDIX H

Computer Output Sample

h-l

P" I I\)

AuTQMrl:.: G~N£R ... 'nON CO!'HRw_ SI"'1',JLATION - SYSTEMS CONTROL INC

LISTING u~ TIlLE ~ARDS

$

81 t'\,,,.,~;'"7 !C~~ u;= AF::: 8,.; SRP S¥STEMS wITH E):TER~A~ WS:C SYSTEM

AREA IS APS ARE'" '2 15 SRP AREA_ IS wsec

• ..,..INSC:':-·T Cw~MENT CA~DS HERE FOR UNITS** APS/~~~ SIMV:"'ATION FOR WINTER 1982

N:jr1o:=:~ OF UN I TS INT£:G'::ATION S7E.:P IN SECON:)S PRINT IN'7ERVAl.. IN SECONDS FRiOQUiONCY FlL TiOR CONSTANT UNIT G<N STANJ~RD DEVIATION

3

DEAJ 5~ND HtG~ LIMIT PRESS"":: FILT'" COIJST S:H~tl.j:....ED FRE },-,EN;: i DEBUG ~N~ICATDF ELECT :.~ HECri ,;£:'J CONTROL

A ('I 360 ;1 40'. A ';! ('I 3::'0 2 40'. A ::; B 3·~0 21500.

00000 00000 00000

CONTPQ;.,. CARD - RiO:; NET S:"iEDVLE

74 NVMBER OF AREAS 0 SQOOO PLOT INTERvAL IN SECONDS

15 OOjOO FREQVEN:Y STANDAR:J DEVIATION O. 95000 VNIT GEN FILTER CONSTANT !. OOOuD DEAD BAND Luw LIMIT

o. ooeoc, PRESSUPiO STANDARD DEvIATION O. 95000 ACE FILTER CONSTANT

60 00000 STEP SIZE FRACT!ON 0 SYSTEM DAMPING

0 0000e

0.20000 0.00000 5.00000 0.95000 0.20000 0.00000 5.00000 0.95000 0.20000 0.00000 5.00000 0.95000

TARGET VALVES:

3 15 00000

O. 00000 O. 95000 O. 00000

O. 00000 0 95000

0 3000 00000

1.00000 1. 00000 1. 00000

s 441 0 2 -650 0 3 209.0 o 0.0 o 0.0

S 4 CONT:ra~ CARD - U"'.!lT DATA'

U 1 192. 00 1. 000 175.00 35.00 4. 00 4. 00 0 :2 1 3.130 5.000 000 7. 000 O. 000 3.000 4.000

U ? 1 192.00 1 000 177. 00 35.00 ~. 00 4. 00 D 2 :2 3. 130 5. 000 1. 000 7. 000 O. 000 3.000 4.000

\J 3 1 256.00 1.000 220. 00 44.00 5. 00 5 00 D 2 ::; 3. 380 5. 000 1. 000 7. 000 O. 000 3.000 5.000

V ~ o 909.00 1.000 800.00 200.00 20.00 20.00 Ii 2 4 2. 7"0 5. 000 1 000 7. 000 0.000 3.000 20.000

V ~ 909.00 1. 000 800. 00 200.00 20. 00 20. 00 D ;1 ~ 2.790 5. 000 1. 000 7. 000 0.000 3.000 20.000

V 6 134.0Q 1.000 116. 00 40.00 2.00 2.00 D :2 " 2900 5.000 000 7.000 O. 000 3.000 2.000

V -, 321. 00 1. 000 235. 00 110. 00 5.00 5.00 D 2 7 3. 550 5. 000 000 7 000 0 000 3.000 5.000

V 8 321.00 1.000 245. 00 110. 00 7.00 7. 00

•

0 0 0 0 0 0

O. 500 1.500

O. 500 1. 500

O. 500 1. 500

0.500 1. 500

0.500 1. 500

O. SOD 1. 500

0500 1.500

•

pI

W

D ;;;

U 9 D:;;: ~t

li 10 D 2 10

U 11 D:2 11

V 12 D 2 l~

U .~

D 2 13

V 14 D2 14

U D

U o

U D

U D

U D

IJ i~

13 18

17 19

u ~O

D ~'O

U dl D :Ii

U 23 D 1 23

U d:J o 25

U 2~

o 2"

U D

32 32

li ~ 1 D 2 ~1

U 42 D 2 42

li ,,~

o 2 ~3

1

o

o

o

o

o

o

o

o

o

o

2

;;;

2

3 550

46C< 00 .2 5-:'0

134.00 2. 900

13~ 00 2.900

118 DO 4. 1"0

118 00 4. 140

102 00 3.250

33.30 4.230

12. 00 4.830

be 00 4. 9"0

75.00 2. 930

75.00 2.930

75. 00 2. 930

5590 11.530

112. 40 11. 530

5450 2 . .,30

55.90 11. 530

5 60 2 930

45.=.. 60 2. 640

456.60 2.640

13400 3. ~'50

5. 000 000 7.000 o 000 3.000 7. 000

1 000 370 00 98 00 i3 00 8 00 5.000 000 7.000 0.000 3.000 8000

1000 115.00 30.00 b.OO 6.00 5.000 1.000 7.000 0.000 3.000 6.000

1000 115.00 30.00 b.OO 6.00 ~ COO 1.000 7.000 0000 3.000 6000

1. 000 115 00 28. 00 b. 00 b. 00 5000 1.000 7.000 0.000 3.000 6000

1000 11500 30.00 6.00 6.00 5.000 000 7000 0.000 3.000 6.000

1. 000 75 00 5. 00 2 00 2. 00 5.000 1. 000 7 000 0.000 3.0')0 2.000

1. 000 5.000

33.30 1000 3.50 3.50 000 7.000 0.000 3.000 5.000

1000 12.00 5.00 1.50 1.50 5.000 1.000 7000 0.000 3.000 5.000

1.00~ b330 20.00 b.OO 6.05 5.000 000 7000 0.000 3.000 5.000

1.000 75.00 25.00 5.00 5.00 5. 000 000 7.000 0.000 3.000 5.000

1 000 75. 00 25. 00 5. 00 5. 00 5.000 1.000 7.000 0.000 3.000 5.000

1. 000 75. 00 25. 00 5. 00 5. 00 5.000 1.000 7.000 0000 3.000 5.000

1. 000 55. 90 4. 00 5 00 5. 00 5.000 1.000 7.000 0.000 3.000 5.000

1.000 112.40 B.OO 5.00 5.00 5.000 1.000 7.000 0.000 3.000 5.000

1. 000 54. 50 4. 00 5 00 5. 00 5.000 1.000 7.000 0.000 3.000 5.000

1.000 55.90 4.00 500 5.00 5.000 1.000 7.000 0.000 3.000 5.000

1 000 5. 60 O. 00 5. 00 5. 00 5.000 1.000 7.000 0.000 3.000 5.000

1.000 355.00 167.00 3.00 3.00 5.000 1.000 7.000 0.000 3.000 3.000

1.000 350.00 167.00 3.00 3.00 5.000 1.000 7.000 0.000 3.000 3.000

1000 11100 32 00 2.00 2.00 5.000 000 7000 0000 3.000 2.000

• Q 5C,0 1.500

O. 500 500

O. 500 500

o. 500 SOD

O. 500 500

0.500 1.500

o 500 1. 500

O. 500 1. 500

0.500 500

0.500 1. 500

O. 500 1. 500

0.500 1. 500

0.500 1. :;00

0.500 1. 500

0.500 1. 500

O. 500 1. 500

0.500 1. 500

0.500 500

o. 500 1. 500

0.500 1. 500

o. 500 1.500

•

U D

U D

U D

U D

U D

U D

U D

U D

u o

U D

U D

U D

U D

U .D

57

60 60

.. 1

.01

6~

64

U 11 o 2 II

U 12 D :2 . 7~

U TJ o 2 13

U D

o

o

o

o

o

o

o

o

o

1

:2

2

:2

2

2

.2

2

2

2

3

192 00 3.570

7= 10 7,6':'0

62 50 11. 570

67 00 8. 360

72 00 5,800

7~ 00 5 8['0

3e. 00 3 150

11 00 2. 2::;0

11 00 2. ~:?O

11 00 2.230

96. 50 3.230

10 00 2. 400

47.00 3 780

13.00 2 230

3 00 2 230

8~2.40

2.870

892. 40 2.970

892 40 2.670

3 81000.00 4.310

INFFTIA CO"~T FOR THi: SYSTEM

1 COO 17B 00 50.00 4.00 400 5000 1000 7000 0000 3000 2.000

1 000 5.0vO

64.00 400 4.00 400 000 7000 0.000 3.000 4.000

1.00j 51.00 4.00 500 500 5.000 1.000 7.000 3.000 O.O~O 4.000

1.000 5 000

47.00 6.00 500 5.00 000 7.000 3000 O.COO 4.000

1. 000 72. 00 20. 00 7. 00 7. 00 5.000 1.000 7.000 3.000 0.000 4.000

1 000 7200 20.00 7.00 7.00 5.000 000 7000 3.000 0.000 4.000

1. 000 36 00 19.00 4.00 4.00 5.000 1.000 7.000 3000 0.000 4.000

1 000 11. 00 3. 00 2 00 2. 00 5.000 1.000 7.000 0.000 3.000 2.000

1 OOC· 11 00 3. 00 '" 00 2. 00 5.000 000 7000 0.000 3.000 2.000

1.000 11.00 3.00 200 2.00 5.000 1.000 7.000 0.000 3.000 2.000

1.000 93.00 40.00 4.00 4.00 5.000 1.000 7000 3 boo 3.000 4.000

1.000 10.00 3.00 1.00 1.00 5000 000 7.000 3.000 0.000 4.000

1.000 44.00 30.00 4.00 4.00 5.000 1.000 7.000 3000 0.000 4.000

1.000 1300 1.00 1.00 1.00 5.000 1.000 7.000 3000 0.000 4.000

1 000 3.00 1.00 0.50 0.50 ~ 000 1000 7000 3.000 0.000 4.000

1. 000 5.000

803.00 0.00 15.00 1500 000 7.000 0.000 3.000 15.000

1.000 803.00 0.00 15.00 15.00 5.000 1.000 7.000 0000 3.000 15.000

1. 000 5.000

803.00 0.00 1500 15.00 000 7000 0.000 3.000 15.000

1.000 80000.00 0.00 2500.00 2500.00 5.000 500.000 17.000 0.001 1500.0003000.000

3713586

•

O. 500 1. 500

O. 500 1. 500

O. 500 1. 500

O. 500 500

0.500 1.500

0.500 1. 500

0.500 1.500

O. 500 1. 50c)

o 50·:' 1. 500

O. 500 1. 500

0.500 1. 500

O. 500 1. 500

O. 500 1. 500

O. 500 1.500

0.500 1.500

O. 500 1. 500

O. 500 1.500

O. 500 1. 500

O. 100 1. 000

•

pI

\.n

• r'PE 2 UNIT DATll,

UNIT f",,:.,R

1 2 1 3 1 4 1 5 1

6 7 8 9

10

11 12 13 14 41

72

73

UNI1

2 3

" 6 7 8 9

10

11 12 13 14 41

42 ~3

~5

71 72

73

1 1 1 1 1

2

;> ;> ;>

3 3

3

IB

o o o o o

o o o o o

o o o o o

o o o o o

o

2 CDO 2 0:,0 2 000 2 000 2~ 000

2 000 2 000 2.000 2. 000 ~~OOO

2. 000 2.000 2. (<(iO 2 000 2 Q.jQ

.:::..000 2 000 2. 000 2.000 -=:.,0':10

;c 000

CSH

5. 350 5. 350

16.860 .3 900 .3 '1'00

4 400 15 700 15. 700

b 380 19 000

1'7.000 12.900 12 900 24 000

3.710

3 710 5. 6~O 5. 630 4.000 4 000

4.000

PKI

:;; 010 G 010 o 010 0.010 O~ 010

0.010 D. 010 O. 010 0.010 o 010

O. 010 0.010 o 010 o 010 0.010

o 010 o 010 Q. 010 O. 010 o 010

o 010

GAINPL

10 000 10.000 10.000 10 000 10 000

10.000 10.000 10.000 10. 000 10.000

10 000 10 000 10.000 10.000 10.000

10 000 10.000 10.000 10.000 10.000

10.000

T0RBINi:: TV?E OAT" OT .... ER THAN TYPE 0;

Ul'~IT IT T;(l n.3

0.000 o 000 o 000 o 000 O. COO

O. 000 o 000 O.OO} O. 000 0.000

0.000 O. 000 o 000 o 000 0.000

0.000 O. 000 o. 000 O. 000 0.000

o 000

PRLO,-M

0.800 0.800 0.800 o 800 0.800

0.800 o 800 o 800 O. 800 0.800

0.800 o 800 O. 800 O. 800 0.800

0.800 0.800 0.800 0.800 0.800

0.800

T;(4

PTR

o. 000 0.000 0.000 0.000 O. 000

0.000 0.000 0.000 0.000 0.000

0.000 o 000 o 000 O~O~O

0.000

O. 000 o 000 o. 000 O. 000 0.000

O~OOO

POSLRM

1. 000 1. 000 1. 000 1.000 1. 000

1. 000 1. 000 1. 000 1. 000 1. 000

1. 000 1. 000 1. 000 1. 000 1. 000

1. 000 1. 000 1. 000 1. 000 1. 000

1.000

T;(5

• DLMT

1. 000 1. 000 1. 000 1. 000 1. 000

1.000 1. 000 1. 000 1. 000 1. 000

1. 000 1. 000 1. 000 1. 000 1. 000

1.000 1. 000 1. 000 1. 000 1. 000

L 000

VRATL

100.000 100.000 100. 000 100.000 100.000

100.000 100.000 100.000 100.000 100.000

100.000 100.000 100.000 100 000 100.000

100.000 100.000 100.000 100. 000 100.000

100.000

n\6

FvELD

6.000 6.000 6.000 6.000 6. 000

6.000 6.000 6.000 6.000 6.000

6.000 6.000 6 000 6.000 6.000

6.000 6.000 6.000 6.000 6.000

6.000

VTRAVL

1. 000 1. 000 1 000 1. 000 1. 000

1. 000 1. 000 1. 000 1. 000 1.000

1 000 1. 000 1. 000 1.000 1. 000

1. 000 1. 000 1. 000 1. 000 1. 000

1. 000

TII7

THPSP

1. 000 1. 000 1. 000 1. 000 1. 000

1. 000 1. 000 1. 000 1. 000 1. 000

1. 000 1.000 1. 000 1. 000 1. 000

L 000 1. 000 1. 000 1. 000 1. 000

1. 000

TT4

0.000 0.000 0.000 O. 000 0.000

0.000 0.000 0.000 0.000 0.000

0.000 0.000 O. 000 0.000 0.000

0.000 0.000 0.000 0.000 0.000

0.000

TII8

FUELT

9.000 9.000 9.000 9.000 9.000

9.000 9.000 9.000 9.000 9.000

9.000 9.000 9.000 9.000 9.000

9.000 9.000 9.000 9.000 9.000

9.000

DLDLT

1.000 1. 000 1. 000 1.000 1. 000

1.000 1. 000 1. 000 1. 000 .. 000

1. 000 1. 000 1. 000 1. 000 1.000

1. 000 1. 000 1. 000 1.000 1. 000

1. 000

TT5

CD

4. 760 4.760 9.770 5.300 5.300

6.900 10 000 10.000 2.890 7.400

7.400 4.800 4.800 9.500

15.640

15640 19.650 19.650 6.000 6.000

6.000

FEliS

Dr·,S

1. ODD 1. 000 1.000 1. 000 1. 000

1. 000 1.0'00 1.000 1. 000 1. 000

1. 000 1. 000 1. 000 1.000 1. 000

1. 000 1. 000 1. 000 1. 000 1. 000

LOOO

lOUT

0.0001111 11111 o 0001111 11111 0.0001111 11111 0.0001111 11111 o 000111::' 11111

0.0001111111111 0.000111::11111 O. 0001111111111 O. 0001111111111 0.000111:1..:11:11

0.0001111111111 O. 0001111: 11111 0.0001111111111 0.0001111:1.11111 O. 0001111 n 1111

0.0001111111111 O. 000111 ::. 111111 0.0001111111111 0.0001111111111 0.000111:111111

0.0001111111111

TT6 TT7

•

;.- 0 370 0 330 O. 000 0 300 0.000 0 000 0.000 4.080 o. 450 0.000 ;: ;: 0 370 0 330 o. 000 o. 300 0.000 o. 000 0.000 4.080 o. 450 0.000 3 :2 0 280 0 440 0 000 o. 280 0.000 o. 000 0.000 3.380 O. 500 O.OCO 4 :2 0 3[<0 0 230 u. 000 O. 000 0.470 O. 000 0.000 7. 500 o. 600 0.000 5 :2 0 300 0 230 O. 000 O. 000 0.470 O. 000 0.000 7. 500 o. 600 0.000

6 :2 O. 236 O. 466 O. 000 0.299 0.000 0.000 O. 000 10. 000 O. 500 0.000 7 :2 0 274 O. 259 O. 000 0.4~7 0.000 0.000 0.000 10. 000 0 500 0.000 8 :2 O. 274 0 259 O. 000 0.467 0.000 O. 000 0.000 10.000 o. 500 0.000 9 2 o. 300 0 200 o. 000 0.500 0.000 0.000 0.000 7.000 o. 600 0.000

10 ;: 0 2L5 0 454 o. 000 O. 300 0.000 0.000 0.000 10.000 o. 500 0.000

11 ? o. 245 0 454 O. 000 O. 300 0.000 0.000 O. 000 10. 000 O. 500 0.000 12 :2 O. 250 0 500 0.000 O. 250 0.000 0.000 O. 000 10. 000 O. 500 0.000 13 :2 O. 250 O. 500 o 000 0.250 0.000 0.000 0.000 10. 000 O. 500 0.000 14 :2 0 250 o. 500 0.000 0.250 0.000 0 000 0.000 0.000 0.000 O.ODO 41 2· o. 300 O. 200 0.000 o. 500 0.000 o 000 0.000 7.000 o 600 0.000

42 :2 o. 300 o. 200 0 000 O. 500 o. 000 O. 000 O. 000 7.000 O. 600 0.000 43 :2 O. 300 O. 200 O. 000 o 500 O. 000 0 000 O. 000 7.000 O. 600 0.000 .. :; ~ . O. 300 o. 200 O. 000 O. 500 O. 000 0.000 o. 000 7.000 0 600 0.000 71 ;, 0 300 O. 200 O. 000 O. 500 O. 000 0.000 0.000 7.000 O. 600 0.000 72 2 0 300 O. 200 0 000 O. 500 O. 000 0.000 0.000 7. 000 0 600 0.000

~.,

,~ :;> 0 300 0 200 O. 000 O. SOD O. 000 0 000 0.000 7. 000 O. 600 0000

$ 5 CO'lTRO_ CI,RD - UNIT LOADING DATA:

p-UN,·, LOADING tJ.4TA 1

0'> E. 0 1 1 A 1.00000 142.90000 1.00000 175.00000 0.00000 E 0 '" 1 A 1.00000 143. 10001 1. 00000 177.00000 0.00000 E. 0 3 1 1'1 0.00000 214.90000 0.00000 220.00000 000000 E 0 .. 1 1'1 0.00000 0.00000 0.00000 800.00000 0.00000 E 0 5 1 1'1 1. 00000 655.00000 1. 00000 900.00000 0.00000 E. 0 6 1 A 1.00000 104. 60000 1. 00000 116.00000 0.00000 E. 0 ;' 1 A 1. 00000 185. 60001 1. 00000 235.00000 0.00000 E. 0 e 1 A 1. 00000 205. 10001 1. OC:OO 245.00000 0.00000 E 0 ;; 1 ,., o. 00000 280.20001 0.00000 350.00000 0.00000 E 0 10 1 A 1. 00000 37.60000 1. 00000 115.00000 0.00000 E 0 11 1 1'1 0.00000 0.00000 0.00000 115.00000 0.00000 E 0 12 1 A 1. 00000 29.90000 1.00000 115.00000 0.00000 E 0 13 1 1'1 0.00000 0.00000 0.00000 99.00000 0.00000 E 0 14 1 1'1 0.00000 14. 00000 0.00000 75.00000 0.00000 E 0 15 1 1'1 o 00000 0 00000 0.00000 33.30000 0.00000 E 0 16 1 1'1 0.00000 o. 00000 0.00000 12.00000 0.00000 E 0 17 1 1'1 O. 00000 0 00000 0.00000 63.00000 0.00000 E 0 IS 1 A 1.00000 50 00000 1. 00000 75.00000 0.00000 E 0 19 1 A I. 00000 50.00000 1.00000 75.00000 0.00000 E 0 20 1 A I. 00000 50.00000 1.00000 75.00000 o 00000 E. 0 21 1 1'1 0.00000 0.00000 0.00000 55.90000 0.00000 E 0 23 1 ,., o. 00000 0.00000 o.o~ooo 112.40000 0.00000 E. 0 25 1 ,., O. 00000 0.00000 0.00000 54.50000 0.00000 E 0 26 1 1'1 O. 00000 000000 0.00000 56.40000 0.00000 E 0 32 1 1'1 0 00000 4.40000 0.00000 5.60000 0.00000 E 0 41 2 1'1 1 00000 355.00000 I. 00000 3~0.00000 0.00000 E 0 42 2 A 1. 00000 1B4.00000 I. O~OO 350.00000 0.00000 E 0 43 2 A 1.00000 79.00000 1. OO~OO 111. 00000 0.00000 E 0 45 2 A 1. 00000 139 00000 1.00000 17B.OOOOO 0.00000 E 0 4'" ;,; H 0 00000 0.00000 O.OC~OO 64.00000 0.00000 E 0 52 2 1'1 0.00000 14.00000 0.00000 51. 00000 0.00000

• • •

• • E G 5~ 2 M 0 00000 a 00000 O. 00':",00 47. 00000 O. OO~.)OO E 0 5:; 2 A 1 00000 50. 0::0;:,0 1. O~:OO 72 00000 0 00000 E ;; 5~ 2 t. 1 0000e 50 (0)00 1 00000 72 00000 0 OOGOO E. 0 57 ~ '" o. 00000 0 coooo a o~~oo 36 00000 O. 00000 E 0 sa 2 ~, O. 0000C' 10 oc-ooo O. 00000 11. 00000 O. 00000 E 0 5, 2 '" 0 00000 10 L'0000 0 00')00 11 00000 O. 00000 E 0 60 2 M O. 00000 10 00000 O. 00000 11. 00000 O. 00000 E 0 61 2 i' 1. ooooe' 49. 00000 1. 00000 93.00000 O. 00000 E 0 62 2 M 0 00000 o. 00000 0 00000 10. 00000 O. 00000 E v 63 2 M 0 00000 o. 00000 o. OOC-OO 44. 00000 O. 00000 E 0 64 2 M 0 00000 0.00000 o. 00000 13. 00000 0 00000 E 0 t·5 2 M O. 00000 O. OQjGO 0 00000 3. 00000 0 00000 f (: 71 - M 0 oooee, 757 00000 0 ocooo 803.00000 0.00000 E 0 !e:. ~ '" 0 00000 754. 0(:000 0 00000 803.00000 0.00000 E 0 73 3 M O. 00000 415. IJOOOO O. 00000 803.00000 O. 00000 E 0 71). 3 i' 1. 00000 38089. OG000 1. O~COO 81000.00000 O. 00000

$ 7 CONT~:O:"" C/',RD - S'J~HARY OF INITIAL COND I T IONS:

::>' I ex>

•

S,,":""-~ARy' OF F"V GEI\1ERATIO~~ PA!;AMETERS PV RATING -2C~ 0 M~ AI=\RAY :....ENGTH ARPA; ~IDTH

WIND \.:=:LOC I TV W r l'~G ANGLE: TIME-ZERO

SUM:'".A;:,. OF IN:TIAi.... CONDITIONS

!tHTiAL AlE" LO,:,DS (MOl)·

1624::;-J2~ 1.!:::6 3:;'294 40003. 48:;47 H~I:IAl. U57!'TE !="OR UNIT 1 (PLl) ;

2044. C METERS 2SI~ 0 METERS

1 =. 0 MIS 60 0 DEC

0 0 S

o. 74323 O. 74328 1. 5524b 1. 00000 0 74328 0.74328' O. 74328 o. 74328 o. 74328 -6. 68948

aETIAL US-:-4TE .OR UNIT 2 (PLl );

o. 74484 o. 74"-84 1- 55478 1- 00000 o. 74"-~4 0.7"-:':;84 o. 74484 O. 74484 o. 74484 -6. 70354

H~:Tlr,L VST;''-.TE FOR UNIT 3 (PLl) ;

o. 83:;Ob O. 83906 70403 1. 00000 o. 83906 O.83:rOt· 0 83906 a 83906 c 83906 -7. 55156

lNITII'.l. USiL.TE FOR UNIT 5 I PLI) ;

o. 72057 0, 72057 1. 51922 l. 00000 0.72057 O. 72057 0 72057 0 72057 o. 72057 -6. 49515

INITIAL L1ST.',TE FOR LIN IT 6 (PLI) ;

o. 77992 O. 77992 1- 60827 1 00000 0 77<;;2 O.7i·9Q2 0.77992 O. 77992 O. 77992 -7. 01925

INrTI~L UST£·.TE FOR LIN IT 7 (PU) ;

O. 57791 o. 57791 l. 33398 1- 00000 o. 57791 o ,7791 0.57791 O. 57791 o. 57791 -5.20118

INITiAL USTI.I.TE FOR UNiT a (PU) ;

O. 633t.6 0, t.::i8b6 1 40788 1- 00000 0 63a66 a ~3E66 0 63866 0 1>3866 o. 63866 -5. 74791

INITIAL usr':'TE FOR UNIT 9 (PU) ;

O. bC'~13 0.60913 37104 1- 00000 o. 60913 O.~O-?13 0 60913 O. 60913 o. 60913 -5.48217

INIT":4L USTI',TE FOR UNIT 10 (PU) :

o. 27~:;2 0.27992 1- 07835 l- 00000 o. 279"2 O.27~92 0.27992 O. 27992 0 27992 -2.51925

INITIAL UST"TE FOR UNIT 12 (PU) ;

o. 24330 o. 24330 05919 l- 00000 o. 24330 O.2~3:::0 0 24330 o. 24330 0 24330 -2. 18966

• •

•

pI

\0

If'J~7~rL UST!;.7E FOR UNIT 14 (Pli) ;

0 13725 O. 13725 1 01854 0 13725 Q 13725 O. 13725 0 13725

INITIAL US-;-.:.TE FOR UNIT 41 (PU) :

O. 7774;:; O. 77749 1. 60449 O. T1749 0 77749 0 77749 0 77749

INIT!AL UST£oTE FOR UNIT 42 (PU) :

0.40:210 0.40210 1 16166 O.40~lu O. 40210 0.40210 CJ 40210

ItJ:TIAl. UST!TE FOR UNIT 43 (PU):

O. 57;;'0::; 0, 57909 l. 33535 O. 57';09 o 57909 O. 57909 0 57909

INI7IAL US ~!. TE FOR UNIT 45 (PU) :

0 71666 O. 71666 1. 51360 0.71 C:·66 0 71666 0 71666 O. 71666

!N:7IAl US;-"'TE FOR U~IT 71 (PU) :

O. 84827 0 B~827 1. 71957 0.84827 0.84827 O. 84827 0 84827

INll IAL USTt'TE FOR UNIT 72 (PU) :

O. 84491 0.84491 l. 71388 O. 84491 0 84491 0. 84491 O. 84491

:NIT!AL US7ATE FOR UNIT 73 (PU) :

O. 465C'4 O. 46504 1 21626 O. .li65Q4 0 46504 O. 46504 O. 46504

IN Ii In UN!-;- ACTUAL GENERATIONS (MW),

14~. 70,,=S 143 G08SB 214. 80000 104 5J~.e7 1 ~5, 50888 ;;:05. 00890 28~. 20001

0 CjCGC: 2f2 70887 O. ooooe; 14. 00000 0 ·00C0.:, o. 00000 49 90887 O. 00000 o. 00000 o. 00000 o. 00000 0.00000 o. 00000 0 00000 o. 00000 0.00000

o. 00000 4 40000 O. 00000 0.00000 o. 00000 o. 00000 0.00000 000000

355 00000 183. 59824 77. :;9824 0.00000 O. 00000 0 00000 0.00000 0.00000 o. oc·ooo 14. 00000 o 00000 0.00000 o. 00000 0 00000 10 00000 10 00000

4B. :;982~ O. COOOO O. 00000 o. 00000 o. OC'000 o. 00000 o. 00000 0 00000

757 OG00G 7~4.00000 415. 00000 38286, 48047 INri IAL UN:T DE81RED G.E!'~ERATIONS (Moll .

• • 1. GOGue- 0 13725

-1. 23529

l. 00000 O. 77749 -6.99737

1. 00000 0.40210 -3. 61889

1 ooooe o. 579<.'9 -s. 21182

1. 00000 0 71,<,66 -6.44992

l. 00000 O. 84827 -7. 63447

1. 00000 O. 84491 -7.60421

1. 00000 O. 46504 -4. 18534

a 00000 655. ooc~o 37. 50887 0.00000 0.00000 0.00000 0.00000

o. 00000 0.00000

137.59824 0.00000 0.00000

10.00000

0.00000 0.00000

1.lC! 70:;:8 143 00888 214 80000 O. 00000 655 00000 104 5':'227 1=c;, =0886 205.00885 .280 . 20001 37.50887

D C,JC':':: .;ce. 70B87 0.00000 14 00000 0.00000 0 'JO: :.: o. 00000 49.90887 0 00000 0.00000 O. CO·JGO 0 00000 o. coooo o. 00000 0.00000 O. CG(;OC: O. 00000 0.00000 0 00000 0.00000

o. 00300: 4. 40000 0.00000 0 00000 0.00000 O. GOOCH) 0 00000 0.00000 0 00000 O.OCOOO

355 [;::-,(:00 183. 59824 77.59824 U 00000 137.59824 O. L:,YjOO O. 00000 0.00000 o. 00000 0.00000 0 00000 14. 00000 0.00000 o. 00000 0.00000 0.00000 o. 00000 10.00000 10 00000 10.00000

48. 59324- 0.00000 0.00000 o. 00000 o. 00000 o. o,::~,oc 0,00000 0.00000 0 00000 o. 00000

7'57. O~""':,OC· _ 754.00000 41500000 38286 48047 IN:: Ir,t UNIT LOton r:1EI=" POSITIONS (PU) :

O. 74328 O. 74484 0, 8390b 0, 00000 O. 72057 0 77~=;? O. 57791 0 63866 0 60913 0,27992 C \>~ :J0 0 24330 0, 00000 0, 13725 0.00000 o. cc-:oC: 0, 00000 0, 66545 0 00000 0.00000 0 0,:··)-:-0 o. 00000 o. 00000 0 00000 0,00000 0, oc<~·,)O 0 00000 0 00000 0 00000 "0.00000

0 e,G.:":;::' o. 78571 0,00000 0 00000 o. 00000 0 OC·GOO 0.00000 0.00000 0 00000 o. 00000 0, 77749 0,40210 0.57909 O. 00000 O. 71666 0,00000 0.00000 0.00000 o. 00000 0.00000 ::r 0.00000 0.22400 0.00000 O. 00000 0.00000 , ,... 0, 00000 0.00000 0.90909 O. 90909 0.90909

0 o. ::';0:61 o. 00000 0.00000 o. 00000 0.00000 0, OC'vO:) 0, 00000 0.00000 o. 00000 0.00000 O. 34527 O. 84491 0.46504 O. 47267

NDT EtlD "1IME =1300. 00000 SECONDS

AT TIMf o. 00:'00 SECONDS FREQ DEli 0.000

AREA ACt: DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADIIERTENTS

O. 000 o. 000 O. 0 441.0 1627.3 2065.3 0.000 2 O.OOC· o. 000 o 0 -650.0 1494.2 846.4 0.000 :3 0.00':' o. 000 0.0 209.0 40004.3 40212. 5 0.000

AT TI'1f 15.00:·CO SECONDS FREG DEV : -0.002

AREA ACE DYNA/'\IC ACE I1NET SNET LOAD . AREA GENERATIONS AREA INADVERTENT5

1 -3. 550 -3. 964 438. 4 441. 0 1630. 5 2066.4 0.000 2 4.636 4 465 -644.4 -650.0 1500.4 847.3 0.003 3 -26. 56C: -35 240 216.9 209.0 40021. 9 40232.6 0.008

AT TIM. 30. 00:00 SECONI1S FREG DEV = -0. 001

AREA ACE DYNAMIC ACe: /'INET 5NET LOAD AREA GENERATIONS AREA INADIIERTENTS

-6.999 -7.097 434.5 441. 0 1633. 7 2072.0 -0. 026 :2 -4.980 -5,021 -654. 5 -650 0 1501. 5 849.7 -0. 006 3 -15.781 -17.824 210.3 209. 0 40039.8 4024(). 5 0, 018

AT TIME 4S.00:~0 SECONDS FREG DEV := O. 000

• • •

A~EA

3 AT TIM~

AREA

3 AT TiM::

AREA

2 3

AT TI~t:

AREA

1 2

AT TI~E

AREA

1 2 :3

THE UNIT WHICH IS AT TIMF

3 AT TIM;:

AREI.

3 AT TIME

AREA

2 3

ARU

ACE DV~AMiC ACE MNET SNET LOAD AREA GEN£RATIONS AREA INADVERT£NTS

-8 6.;':; 3 62=

-2, 35';: 3 t14

-..;; 138 60 00:·.:,::' SECONDS

432. 6 -646. 1

217.5 FRECl DEli

441. 0 -650.0

209 0 -0

1644.8 1497 1

400S8 4 002

2079.2 949.4

40269.4

-0 056 O. 003 o 021

ACE DVNAMIC ACE

-1~L553 -15 -3. 59: -3. 5J9

-20.968 -16. 71~ /~. 00:'(00 SECOr-m~

ACE DY~AMIC ~CE

-22 835 -22 c35 0.639 0721

-17 92B -15 725 90. OO:'uQ SECONDS

ACE DY"'AMIC ".SE

-31. 7~b -32 -4. :5"-:' -4

-26 70;1:. -43 105.00~:~ SECONDS

584 665 2Ji.

ACE DYNAMIC hC:E

MNET

426. 3 -6~2. 7

221. 1 FREG

MNET

418. 9 -648. 7

21:5.3 FREG

MNET

410.9 -652.9

244.2 FREG

MNET

-SO. 742 -SO 682 392.3 -1. lOb -1 164 -649.0

-SO.9C'? -53 910 23S. 5 DESlRED .,ENERATION WDG) ON UNIT ~,EOIIE THE UNIT UPFER LIMIT (UHU

120. 00 :'00 SECONDS FREQ

ACE DYNAMIC ACE

-5q 89'1 0.05~

4. 567 135.00:<'0

ACE

-62.916 3.641

-38. 48.:; 150. 00 :.c.c-

ACE

-79.624 2. 18S

-16.260 165. 00 :'00

ACE

-54 "2" O. 046 4.031

3ECONDS

DYt.,;AI1IC J...':E

-b2 763 3 704

-35.258 SECONDS

DYNAMIC ACE

-79 ::('22 2 061

-22. 510 SECONDS

DYNAMIC 4':E

MNET

387.3 -648. 8 257.7

FREG

MNET

380.1 -644. 3 246.8

FREG

MNET

363. 5 -645. 7

:273.4 FREG

HNET

DEli

DEV

SNET LOAD AREA GENERATIONS AREA INADVC:RTENTS

441. 0 -650.0

209 0 -0

1663 1 1503 0

40073 6 ('01

2099.4 850"3

40294.7

-0. 111 -0 003 0.032

SNET LOAD AREA GENERATIONS AREA INADVERTENTS

441.0 1674.3 -650.0 1492 1

209.0 40091.2 -0.004

2101. 7 951. 7

402996

-0.176 -0.004 o 065

SNET LOAD AREA GENERATIONS AREA INADIIERTENTS

441.0 1701.7 -650.0 1500.7

209.0 40117.2 -0.006

2113. 3 851.3

40346 0

-0.294 0.000 O. 123


441.0 1730.0 2122.9 -0.474 -650 0 1504. 3 853. 2 -0.003

209.0 40140.2 40380.1 6 HAS ACHIEVED A MAXIMUM VALUE OF 119.293

0.215 MW

THE UHL. OF 116.000 M~ THE uno HAS BEEN SET TO DEV ~ -0.003


441.0 -650.0

209.0 DEV -0

SNET

1742.5 1501. 7

40153.8 005

LOAD

441.0 1760.9 -650.0 1496.3 209.0 40170.7

DEV = -0.006

SNET

441. 0 -650.0 :209.0

DEV = -0

SNET

LOAD

1788.7 1505. 1

40201.0 009

LOAD

2129.9 95:2. 9

40411.5

AREA GENERATIONS

2139.2 852 6

40418.6

AREA GENERATIONS

2148.6 955.4

40469.4

AREA GENERATIONS

-0" 700 0.007 O. 406

AREA INADVERTENTS

-0 895 0.017 o S42

AREA INAD'.'ERTENTS

-1. 224 0.017 0.903

AREA INADIIERTENTS

•

-95.45~ -95 s·:;. 348 5 441.0 1807 8 2158 5 -1.626 ;: o .:::"'~ 0 4~ -646 5 -650.0 1503 8 855. 4 0.030 3 -41. 7"7~ -49 .:~ 278. 7 2090 40215.8 40489.4 1. 100

THE UNiT :::-E3l :1ED ';E~-iERATICN ( DG) ON UNIT 6 HAS ACHIE1jED A MAXIMUM VAL.UE OF 128.465 MW WHICH IS ?2,:)VE T,"~ U~~IT UFcEF- LIMiT (uHU OF 116.000 MW THE UDG HAS BEEN SET TO THE UHL AT TIHF " 1.30 00:·.:·0 SECON["S FREG DEV : -0 005

ARE~. ACE DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -93.027 -92. 612 349.9 441. 0 1815 1 2165.0 -2.028 2 o. 152 0 351 -647.9 -650. 0 1503 4 855.6 0.044 3 -4. 1'3~ 4. 3~0 277.4 209. 0 40238 3 40515.7 1. 408

AT -:-IME 1 '?S. 00:·:0 S~CONDS FREQ DEV -0. 007

AREA ACE DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-106.45:;: -106 76~ 336.9 441. 0 1829 7 2175.4 -2. 361 ;: -0.2':;: -0. 378 -647.9 .,-650.0 1503 8 854 4 O. 055 3 -8 0 7 -':. -14. 726 290 5 209.0 40255 5 40537.9 1. 707

AT TIME =10. 00:::,0 SECONDS FRE(l DEV -0 008

AREA ACE DYNAMIC ACE MNE:T SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-'j.'5.7:2.::- -96 07 ... 347. 9 441. 0 1829.6 2184.4 -2. 799 2 -1. 57';: -1 718 -649.0 -650. 0 1509.8 856.3 O. 058 3 -25. 4~J -32. 874 2806 209. 0 40273. 1 40562.9 2. 034

AT TIME = 225 00.:·0(' SECONDS FREG DEV -0. 006


1 -90.83S -90. 202 352.7 441. 0 1839.9 2192.7 -3.206 ::r 2 O. 9'17 1. 233 -646.4 -650.0 1508.2 857.4 0.064 I 3 -36. 700 -24.731 268.9 209.0 40299.8 40578.8 2.325 ~ THE UNIT CESI~EC GENERATION <VDG) ON UNIT 6 HAS ACHIEVED A MAXIMUM VALUE OF 131. 717 MW

WHICH IS t\EOVE THE UNIT UPPER. LIMIT (uHU OF Ill.. 000 MW. THE unQ HAS BEEN SET TO THE UHL. THE UNIT uESl~ED ;ENERATlDN iLIDQ) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE OF 77.1172 MW WHICH IS {.EOVE THE UNIT UPPER LIMIT (uHU OF 75.0000 MW. THE uno HAS BEEN SET TO THE UHL. AT TIME -~4(). 00:,::) ;t:CONDS FREG DEV = -0.005

AREA ACE [·mAMIe ACE MNET SNET LOAD ARE'" GENERATIONS AREA INADVERTENTS

1 -83.830 -83. 346 359.3 441. 0 1840. 8 2200. 1 -3. 561 2 -1. 36"";'" -1. 167 -649 2 -6:)0. 0 1506. 5 857.3 0.061 3 -27. 5~·: -19.400 259.1 209. 0 40321. 8 40581. 0 2.579

AT TIME 255. 00::;0 SECONDS FRE(z DEV -0 008

AREA ACE DYNAMIC ACE "'NET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-74.897 -74. 749 368.5 441. 0 1842. 5 2211. 1 -3.805 2 -0.262 -0.201 -647.8 -650. 0 1510. 1 858. 2 0.069 3 -56.044 -52.954 244.2 209. 0 40339.2 40597.5 2. 739

AT TIM;:: -= 2,0. 00;·00 SECmJDS FRE" DEV = -0. 003

AREA ACE DYNAI"IIC ACE MNET SNET LOAD ARE'" GENERATIONS AREA INADVERTENTS

-65. 1£2 -65 2'7~ 378.3 441. 0 1837.0 2216.5 -4.099 2 002" -0. 017 -647.5 -650.0 1506.6 857.2 0.076 3 -2e. 562 -30 890 272.1 209.0 40361.9 40603.8 2.977

AT TIME 285.00:::0 SECONDS FREG DEV -0. 005

AREA ACF DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

• •

• • 1 -6:3.25€ -63 136 379.7 441 0 18403 2227. 1 -4.361 2 -1. 07;: -1 022 -649. 1 -650. 0 1508.0 857.4 0.084 3 -3D 3';;:- -35 772 244.9 209.0 40378. 1 40625. 5 3. 149

THE UNI ['E51REt ·;ENE~AT IO"~ 1l...:DG) ON UNIT 6 HAS ACHIEVED A MAX lMUM VALUE OF 131. 960 MOl WHICH I ~BOVE T~~ UNIT UPPE;;:: LIMIT !uHU OF 116.000 1'1W. THE UDO HAS BEEN SET TO THE UHL. THE UNI r,ESIRED ;ENEFATION (\JDG) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE OF 773598 MOl WHICH I HOVE THE Vt-~IT U??E~ LIMIT !UHLl OF 75.0000 M· . ~. THE UDG HAS BEEN SET TO THE UHL. AT TIME ~ 300. 00 ~(·O SECONDS FREQ DEV : -0. 005

ARE'" ACE D·{t-.:AMJC ACE MNET SNET LOAD AREA GENERATIONS AREA INAD,'ERTENTS

1 -51 78~ -51 763 391 2 441. 0 1842. 6 2233.8 -4. 5B3 2 4.441 4. 445 -643.6 -650.0 1503 4 859. 8 0 091 3 -28.273 -27. "18 255. 3 209.0 40393 0 406483 3 337

AT TIME - 315. OO}CO SECONDS FREG DEV -0. 003

AREA ACE DYNAMIC IlCE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -43. 73" -43. 661 39B 7 'I'll. 0 lB46. 7 2240. 7 -4. 741 2 -3. 762 -3 737 -652. 4 -650. 0 1513.0 858. 4 0.093 3 -}4 9"5= -13. 3 0 ;- 247. 2 209 0 40424. 1 40675.6 3.477

AT TIME 33(), 00::;0 5t:CONr:,S FREQ DEV -0 003

AREA ACE DYt>;AMIC ACE MN2T SNET LOAD AREA GENERATIONS AREA INADIIERTENTS

-37.7i34 -37 957 405. 5 441 0 1843. 5 2243.9 -4. 923 2 -5. 335 -5 4G7 -653. 1 -650 0 1506. 6 859. 6 0 DB4 3 -47_261 -52. 856 243. , 209. 0 40440. 7 40655.4 3. 615

AT TIME T 345. OO:·C'O SECONDS FREG DEV -0. 002

AREA ACE DYt>;AMIC ACE MNET SNET LOAD AREA GE"'ERA TI ONS AREA INADIIERTENTS

po -3?051 -38 875 403. 3 441. 0 1842. 5 2247.6 -5.090 I 2 -2.914 -2. 841 -651.6 -650.0 1509.4 857. 1 0.OB9 I--'

W 3 -10.93' -7. 240 247.0 209.0 40459.6 40698.4 3. 757 THE UNIT LES1RED ~ENERATION tl'DGl ON UNIT 6 HAS ACHIEIIED A MAXIMUM VALUE OF" 132. 177 MW WHICH IS t·.~L}vr:. T,.;E UNIT UF"U LIMIT WHLl OF 116.000 MW. THE UDG HAS BEEN SET TO THE UHL. THE UNIT i::'£:=:Ji(ED :;ENSR AT ION (I_IDG) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE OF 77.5767 MW W"ICH IS {"EIJVE" Tt-i~ UNIT UPPER LIMIT WHL) OF 75.0000 MW. THE UDG HAS BEEN SET TO THE UHL. AT TIME ~ 360. 00':'0;J SECONDS FREG DEV = -0.005

AREA ACE r:·\'NAMI C ACE MNET SNET LOAD AREA GENERATIONS AREA lNADVERTENTS

1 -34.9~5 -35 4Q2 40B.2 441 0 1844. 5 2252. 7 -5.246 2 -3.01':' -8. 201 -655.9 -650.0 1514. 6 858. 7 0.081 3 -45. 30~ -54.801 244.3 209.0 40480. 1 40724.4 3. B77

AT TIME 375. 00)00 SECONDS FREG DEV = -0. 003

AREA ACE DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTE~ITS

1 -34.470 -34 182 4080 441 0 1840. 1 2253.5 -5.346 2 -4.23:;: -4. 113 -652.8 -650. 0 1507. 1 860.0 0.070 3 -37.907 -31- 879 2263 209. 0 40495. :1 40717.8 3.936

AT TIM::: ~ 390. OO)GO SECONDS FREQ DEli = -0. 002


1 -32. Spr. -32 359 409. 4 441 0 1948.8 2256.4 -5. 477 2 o. 106 0 197 -648. 9 -650. 0 1515. 7 8bO.2 o. 058 3 -10 8~' , " -6. 240 233 7 209. 0 40518. 3 4075b 4 4. 01b

AT TIME 405. 00:-:;:" SECONDS FREG

AREA ACt. D'd ... AMIC ACE Mt.,jET

-25 1:1 -24 8:,,= 416. 8 2 -3. 911 -3 72~ -653.0 3 -28 QC3 -22 2':-': 214. 1

THE UNIT I>ES1RED GENERATION ,liDG) ON UNIT WHICH IS THE UNIT WHICH IS AT TIM:':: ~

AREI·.

2 3

AT TIME -ARE~.

2 3

AT -IME

AREt.

1 2 3

AT TIM€'

AREA

2 3

THE UNlT WHICH IS THE UNIT WHICH 15 AT TIME'

AREA

2 3

AT TII'IE

AREA

1 2 3

0

.

t-.EaVe Tnt: UNIT UPPE~ LIMIT WHU DESIHED '~ENERATI ON '~'DG) ON UNIT t',EOVE To-iE UNIT UF?EFt LIMIT (uHU

420. 00:,':)0 SECONDS FREG

ACE: DYNAMIC A'-C:: MNET

-27.05; -27 13::: 415.8 1.02: O. 9~1 -647. 1

-50.258 -51 ""r;..1' 22B 4 ~3S. 00: -:-0 SECONDS FREG

ACE DYNAMIC ACE MNET

-32. 455 -3c c;'i6 409 5 -5.0~3 -4 858 -654. 1

-31. 1".J -19 16~ 215. 1 450. OO:,.:·v SECONDS FREG

ACE DYNAI'IIC A:E I'INET

-27. 18~ -26.919 415.0 7. 658 7.767 -641. 2

-32. 896 -27.337 218.8 465 OO:·~O SECONDS FREG

ACE DYNAI''.IC A:E I1NET

-29.64~ -29.493 412.8 -1. 7.5 -1. 654 -650.3

-55.0~2 -51. 945 208. 5 r,ESlRED ~ENERATION (UDO) ON UNIT A£OIi< THE UNIT Uf'FE~ LIMIT <VHU DESJRED ~ENE"ATION (UOQi ON UNIT ,rOVE Tt-:: UNIT UPPER LII'IIT <VHU

460. 00: ~:) SECONr,= FREG

ACE DYNAI'IIC ACE MNET

-I? 731 -19.8~9 422. 9 -4.282 -4.331 -652. 7

-42. IbO -44.645 2262 41:Y5. oo:co SECONDS FREG

ACE DYNAI'IIC ACE MNET

-1:3. 746 -19. 413 424.4 -3. 159 -3. 434 -051. 0

-64. 46': -76.452 223. 7 AT TIME ~ 510.00:00 SECONDS FREG

AREA ACE DYNAMIC ACE I'INET

•

DEli -0. 003

SNET LOAD AREA GENERATIONS AREA lNADVERTENTS

441. 0 1846.5 2259.8 -5.615 -650.0 1512. 1 861. 6 0.045

209.0 40540. 0 40708.1 4.086 0 HAS ACHIEVED A MAXIMUM VALUE OF 132. 548 MW

OF 116.000 MW. THE uno HAS BEEN SET TO THE UHL. 18 HAS ACHIEVED A MAXIMUM VALUE OF 77.9475 MW OF 75.0000 MW, THE UDG HAS BEEN SET TO THE UHL. DEli ; -0. 005

SNET LOAD AREA GENERATIONS AREA HJADVERTENTS

441- 0 1846. 9 2262. 7 -5. 735 -650. 0 1511 0 863. 9 O. 040

209. 0 40556 5 40784. 9 4. 149 DE" -0 002

SNET LOAD AREA GENERATIONS AREA INADIIERTENTS

441 0 1842. 4 2263. 7 -5. 823 -650. 0 1508. 5 863.8 o. 041

209. 0 40575. 8 40792.4 4 173 DEli -0. 002

SNET LOAD AREA GENERATIONS AREA INADliERTENTS

441. 0 1841. 8 2267.0 -5.926 -050.0 1511. 1 863.9 0.047

209.0 40599.9 40816.6 4.213 DE" z -0. 005

SNET LOAD AREA GENERATIONS AREA INADliERTENTS

441. 0 1856. 5 2271. 3 -6.030 -650.0 1519.7 863.9 0.049 209.0 40624.8 40851. 6 4.229

6 HAS ACHIEliED A MAXIMUM VALUE OF 132.626 HW OF 116.000 MOl. THE UDG HAS BEEN SET TO THE UHL. 18 HAS ACHIEliED A MAXIMUM VALUE OF 78.0261 HW OF 75.0000 HW. THE UDC HAS BEEN SET TO THE UHL. DEV z -0 004


441- 0 1848.8 2271. 6 -6. 114 -050. 0 1517.5 804.8 0.038

209. 0 40644. 1 40870.3 4.249 DEli t -0. 004


441. 0 1848. :; 2272.2 -6. 177 -650.0 1512.9 865 8 0.037

20'1.0 400566 40804.9 4.299 DEli z -0 004


•

• • -23 5S -23 418. 8 441 0 1856 5 2273. 4 -6 257

2 -0.0~ -c' -648. 7 -650 0 1514 5 867 2 0 038 3 -4L..3::: -45 213. 3 20Y. 0 40675 2 40895.6 4. 339

AT ~IIE 5.:'~' 00: :,0 5ECm-.:C'; FRECl [,EV -0. 002

AREt; ACE C,,'NAMIC "~,, MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-1,s.03' -15 20"7 425.8 441. 0 1852. 1 2274.S -6351 2 -3.5e1 -3 21-:= -652. 7 -6S0.0 1515.6 866. 1 0.046 3 -40. 922 -23. 5'72 201. 1 209. 0 40700. 1 409198 4.325

THE UNIT DESIRED :;e~ERATION (!_'DG) ON UNIT 6 HAS ACHIEVED A M4XIMUM VALUE OF 133000 MW Wl-iICH IS ABDVE T~E UNIT UPPER LIMIT (UHL~ OF 116. 000 MW THE voe HAS BEEN SET TO THE VHL. THE UNIT DESIRED ;=:NERATION tUOG:) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE OF 78.4004 MW WHICH IS tBOV!' TH~ UNIT U?FER LIMIT {UHL:' OF 75.0000 MW. THE VDG HAS BEEN SET TO THE UHL. AT TIME 540. 00 :': Q SECONDS FRECl DEV = -0 001

AREP. ACE DYr-.jAM I C A:E MNET SNET LOAD AREA GENERATIONS AREA INAOIIERTENTS

-17.8~: -17 e24 423. 6 441. 0 1852 0 2275.6 -6.444 2 -1.8:;S -1 '57 -651 4 -650. 0 1518 2 866.8 0.045 3 -19.41S -14.~82 206. S 209. 0 40722. 4 40928.9 4.359

AT TI'1E 55:'. OO.:-:JO SECONDS FRECl DEV -0. 005

AREA ACE DYNAMIC A:E MNET SNET LOAD AREA GENERATIONS AREA INAOVERTENTS

-21 91~ -21 7C2 419. 9 441 0 1858. 0 2277.b -6 S02 2 1. 81':' 1 899 -647. 4 -b50. 0 1520. 2 868.3 O. 044 3 -3!j.3-+:; -30 817 204.2 209_0 40742. 3 40961. 0 4. 387

AT TIMt=" 5/0.00:":0 SECONDS FRECl DEV -0. 003


! -25. 200 -25 130 416. 5 441. 0 1850. 6 2277.3 -6. 591 ::r 2 -3. 00:; -2 980 -652.4 -650. 0 1517. 1 8b7.0 0.054 I f-' 3 -1 :'>. 5:·3 -14 058 217. 9 209.0 40764. 8 40984. 7 4.432

\J1 AT TIME 585.00:CQ SECONDS FRECl DEV -0. 003

AREA ACE u'{NAMIC ,c.::E MNET SNET LOAD AREA GENERATIONS AREA INADIIERTENTS

1 -19.449 -1" 223 422.4 441. 0 1856.0 2277.8 -6.b?5 2 -1, 1 So::! -1 0610. -650.3 -650.0 1518.3 865.3 0.062 3 -32. 10;8 -27 414 .209.2 209. 0 40780.5 41003.0 4.476

TI-'E UN:T r'ESIRED :;E':ERATIDN (i}OG) ON UNIT 6 HAS ACHIEVED A MAXIMUM VALUE OF 134.242 MW wHICH ·c ,- ?'BeVE THE: UNIT UPPE-' LIMIT lUHU OF 116.000 M .. THE unc HAS BEEN SET TO THE UHL. THE UNIT L,ESJRED GENERATION (UDG) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE O. 79. 6418 MW WHICH IS A20VE THE UNIT UPPER LIMIT IUHLl OF 75.0000 MW. THE vue HAS BEEN SET TO THE UHL. AT TIME ~ 600. 00':'(0 SECONDS FRECl DEV = -0 005


1 -24.86:: -25. 611 418. 1 441. 0 1861. 6 2279.6 -6. 760 2 ~7. 6C;::· -8 116 -b55.9 -650. 0 1523. b 867. 7 0.048 3 -3!J.385 -51 037 246 1 209.0 40798. 2 41044.3 4.508

AT TIME 615.00::00 SECONDS FREQ DEV -0. 003

AREA ACE DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INAOVERTENTS

-21 SO~ -21. 972 420. 8 441. 0 1855. 0 2278.9 -6.827 2 ;:. 07'= 2 011 -646. 3 -650.0 1517 2 867. 1 0.046 3 -<t::2.02':" -45 45S 226. 5 209. 0 40818 3 41035. 6 4. 561

AT TIME 63(l,00::-0 :;ECONr'S FREG DEV -0 004

AI=:E;' ,:..C~ u'':'NAM!C. ,,::;: MNET SNET LOAD !.REA GENERAT iONS APEA INADv'ERTENi'S

-21 5:: -~1 .!?.:. 420 9 441. 0 1853 3 2280 1 -6 922 2 -2.6::_ 2 6t,'] -6513 -650. 0 1521 2 867. 2 O. 046 3 -45 3:::: -43 697 215 3 209. 0 40839. 7 41061. 6 4. 588

AT TIM:: 645. 00:: :. SECG:'Ji::S FREll DE" -0. 003

AREA AC~ i)~'NAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-;>1 7';5 -21. ~57 420. 3 441 0 1857.7 2280.6 -7.011 2 -~. 21"::- -5. 073 -654. 1 -6500 1519. 1 870 3 0.029 3 -42. 84;:- -35 76':, 208. 7 209. 0 40856 9 41074. 5 4.625

THE UN;r :'ES J RED .:;ENERATION lUDG) ON UNIT 6 HA£. ACHIEVED A MAXIMUM VALUE OF 134.091 MW WHICH IS I.BOVE THE UNIT UPPE" LIMIT (UHLl OF 116 000 Miol. THE UDG HAS BEEN SET TO THE UHL. THE U:"YT DES1RED GENEPATION (~,}DG ) ON UNIT 18 HAS ACHIEVEC A MAXIMUM VALUE OF 79.4913 MW WH:::CH IS ABOVE THE UNIT UPPE~ LIMIT (UHLl OF 75. 0000 MW. THE UDG HAS BEEN SET TO THE UHL. AT TIM" 660. 00 :.:.:. SECONDS FREG DE\,! = -0 002

AREA AC:;: [,Vl..lAMIC AI~-':::- MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -21. 77- -;21 70)1 420.2 441. 0 1860. 6 2280.8 -7. 095 2 -6.63, -6 6·8:- -655.6 -650. 0 1526. 7 871. 1 O. 016 3 -36.007 -34, ,"C,'::. 210. 1 209. 0 40886. 6 41096. 7 4 666

Ai TIME 67~. OO:OJ SECO~mS FREel DEV -0. 004

AREt,. ACE I:-VNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -17.9o~ -20. 255 422. 6 441 0 1863 5 2283.3 -7. 169 2 0.036 -0. 085 -648 4 -650. 0 1523 7 873.3 0.018 3 -47. 145 -53. 247 216. 6 209 0 40902. 2 41120.2 4.685

AT iIME 690. 00·:(,0 SECONDS FREe. DEV -0. 003 p-I AREA ACE DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS f-' 0\

1 -;>3. 544 -23 26C· 418. 7 441. 0 1863. 5 2283.3 -7. 258 2 0.40:- O. 524 -648.4 -650.0 1522.8 872.0 O. 032 3 -40215 -34 27"7 214. 8 209.0 40919.8 41131. 9 4. 725

AT TIME 7D5. OO·:C-O SECONDS FREG DEV -0. 003

AREA ACE DYt~AMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-15.t:.c~ -15. 584- 420,. 2 441. 0 1863. 5 2283. 1 -7.339 2 -1. s:;;:€ -1 865 -651. 1 -650.0 1523.4 872.4 0.032

" -2'-.662 -24 et82 213.2 209.0 40941. 9 41165.3 4.747 THE UNIT r'E51REC ;~NEPATrON WDG) ON UNIT <. HAS ACHIEVED A MAXIMUM VALUE OF 133.898 MW WHICH IS I'.EGVE THE UNIT UPPER LIMIT (UHU OF 116.000 MW. THE UDC HAS BEEN SET TO THE UhL. THE UNIT D£SIHED GENERATION (UDG) ON UNIT 16 HAS ACHIEVED A MAXIMUM VALUE OF 79.2980 MW WHICH IS I'EOVE ThE UNIT UPPER LIMIT (uHLl OF 75.0000 MW. THE UDQ HAS BEEN SET TO THE UHL Ai TIMe 7;>0. 00 :'(;0 SECONDS FREG DEV = -0. 003

AREA ACE DYNAMIC ACE MNEi SNET LOAD AREA GENERATIONS AREA INADVERiENTS

1 -lB.261 -16. 243 424.0 441. 0 1858.9 2282.9 -7.421 2 -1.044 -1. 036 -649.8 -650.0 1522.6 872.9 0.027 3 -45.371 -45.000 212.0 209.0 40963. 1 41175.0 4. 772

AT TIME 735. 00)00 SECONDS FREG DEV -0. 002

AREA ACE DYNAMIC ACE MNET SNEi LOAD AREA GENERATIONS AREA INADVERTENTS

-21. 775 -21 688 4208 441.0 1867. 7 2282.7 -7.484

• • •

• 2 -eSO 8 -650 0 1526 6 875. 0 O. 023 3 -40 5= -38 e~~ 228 2 209. 0 40964 6 41213. 5 4.814

AT T1M= 7S() 0 J~.~ SECOND; FREG DEV -0 00.4

ARE'" ACE "Y,,"MIC 10..::0: MNET SNET LOAD AREA CENER" TI ONS AREA INADIIERTENTS

-21 O~- -20 70= 421.2 441 0 1863. 3 2284.0 -7. 584 ;;: '::-1; 55c. 3.655- -645. 2 -650 0 1520. 3 876.0 O. 024 3 -42 ea~ -37 83e 212.2 209. 0 40997. 9 41230.2 4. 857

AT TIMe 765 oo:,~o SECONDS FREG DEY -0 003

AREA ACE D'iNAMIC ACE MNET SNET LOAD AREA GENER" TI ONS AREA INADYERTENTS

-22.B94 -22. 77c 419.7 441.0 1862.8 2283.8 -7.673 ;;: 4.45-; 4. 507 -644 0 -650. 0 1522. 3 875. 5 0.033 3 -47.235 -46 774- 218 0 209.0 41018.0 41232 7 4.893

THE Uf'·~rT [ESIRED ;;~I'~E~ AT I ON t L:OG) ON UNIT 6 HAS ACHIEYED A MAXIMUM YALUE OF 135. 113 MW WHICH IS toBOYE THE U~.;IT UPPER LIMIT lUHL' OF 116.000 MW. THE UD~ HAS eEEN SET TO THE UHL THE Uf'~!T :,E2·1RED :;ENEFATION {UOG) ON UNIT 15 HAS ACHIEVED A MAXIMUM YALUE OF 80 5134 MW WHICH IS t.BOVE TH" U:"T UPFEi' LIMIT {\JHL i OF 75.0000 MW. TH" UDt: HAS BEEN SET TO THE VHL. AT TIME 0 780. 00:C·;:' ~~CONr·s FREel DEY = -0. 004

A!lE~. ACE Dn:AMIC ACe: MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-;>7. 06;;: -20 4;:·;- 415. 5 441 0 1868 3 2283 7 -7.771 ;;: -1 82:. -1 sse· -650. 3 -650 0 1526. 2 875.9 0.030 3 -41. 83'" -28 lOG 223 9 209. 0 41042. 3 41266. 2 4.972

AT TIME 79;i. 00 :'C<:' SECONDS FREG DEV -0. 003

AREI-. ACE DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADYERTENTS p-I

i--' -32.981 -33 05S 410. 441. a 1862. 4 2285.4 -7.841 --..:j 2 -2. 196 -2 :;:;;:8 -650. -650.0 1521. 7 876.2 0.030

3 -69 184 -70 790 216. 8 209.0 41056. 3 41266.8 5.000 AT TIM=: 810. 00:'C0 SECONDS FREG DEY -0. 004

AREA ACE u','hiAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADIIERTENTS

1 -25 198 -25 133 416. 9 441. 0 18664 2287. 1 -7 . .,>49 2 0.343 O. 370 -648. 6 -650. 0 1520.9 875,4 0.036 3 -35 061 -33. 690 214. 9 209. 0 41085. 1 41306.5 5.031

AT TIME 825. oo:c J ~·ECONDS FREG DEY = -0. 003

AREA ACE [:'f'~~AM IC ACE MNET SNET LOAD AREA GENERATIONS AREA INADYERTENTS

-23. 79t. -24 156 4183 441. 0 1868. 1 2287. 9 -8 049 2 7.76;:;- 7. 621 -641. 1 -650.0 1526. I 877.4 0.035 3 -34.47, -42 020 215. 7 209. 0 41100.0 41318. 5 5.101

THE UNIT :;ESIRED ,;E:NE:RATION (0DG) ON UNIT 6 HAS ACHIEVED A MAXIMUM YALUE OF 135.648 MW WHICH IS AeOYE THE VNIT UPPER LIMIT (UHL) OF 116. 000 MW. THE UD; HAS liEEN SET TO THE VHL. THE UNIT !:'ESIRED GENERATION (UDC) ON UNIT 18 HAS ACHIEVED A MAXIMUM YALVE OF 81. 0475 MW WHICH IS AEOYE THE UNIT UFI=ER LIMIT (UHLl OF 75.0000 MW. THE U!)G HAS BEEN SET TO THE UHL. AT TIME 840. OO~'~D SECONDS FREel DEY = -0. 002

AREI< ACE DYNAMIC ACE IINET SNET LOAD AREA GENERATIONS AREA INADYERTENTS

1 -26.841 -26 622 414. 8 441. 0 1873.0 2287.8 -8. 155 2 -0,63- -0. ~4.A -650.0 -650.0 1526.7 876.7 0.039 3 -11. 69:; -7. 113 221. 9 209.0 41119.6 41341. 6 5. 137

AT TIME 855. 00.]0·;) SECONDS FREG DEY - -0. 003

AREA ACE Dr-.AMIC A:E ""NET Sk LOAD AREA GENERA TI DNS AREA INADVERTENTS

-27,3-+~ -27 ·0 414.6 441. 0 1871. 0 2289.0 -8 236 2 3 1"" 3 :cl -643. 9 -650.0 1528. 3 877.9 O. 034 3 -18.7'::/;' -20 ..::..:< ... 225. 7 209.0 41141. 7 41364.9 5 . 211

AT TIME S-/O. \.IV _',_,,': ~ECO!>i[>;;: FREG DEY = -0. 002

AREA ACE rl'NAMIC A·:E MNET SNET LOAD AREA GENERATIONS AREA INADYERTENTS

-22.446 -22 816 419. 9 441. 0 1866. 2 2288.6 -8. 330 2 -2.3J5 -2. "-57 -651 0 -650.0 1523. 6 B78. 7 O. 018 3 --32. C6L -39. 7=>S 225 9 209.0 41161 5 41364.4 5. 270

AT TIM::': E8S. 00 :.:~ SEC Qt..Jr S FREG DE;'; -0 002

AREA ACE DYhlAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -2693;C -26 6::: 414. 5 441. 0 1872.4 2287. 5 -B 427 2 4.805 4 "''':'4 -644.8 -650.0 1529. 1 879.8 O. 024 3 -8. 562 -1 oc::; 215.4 209.0 41182 5 41412.8 5. 305

THE UNIT DES1RED GENE"ATlor, :CDG) ON UNiT 6 HAS ACHIE',ED A MAXIMUM YALUE OF 134.902 MW WHICH IS .. BOYE ThE UNIT UPPEF' LIMIT IUHU OF 116.000 MW. THE UDG HAS BEEN SET TO THE UHL. THE UNIT ['ESIRED ,;ENERATIO·.J . ,_'DG) ON UNIT 18 HAS ACHIEYED A MAXIMUM VALUE OF BO.3023 MW WI-\lCH ·c

,~ A80VE T"';E UNIT UP'::E~ LIMIT (UrlL) OF 75.0000 MW THE uno HAS BEEN SET TO THE UHL. AT TIME '7'00. 00:,('0 3ECON~); FREG DEV = 0.000

AREA ACE uYNAMIC A':E MNET SNET LOAD AREA GENERATIONS AREA INADYERTENTS

-21.066 -20 11;:, 420. I 441. 0 IB67 2 2287.2 -8. 530 2 -6.8Q~ -6 62t! -656. 7 -650. 0 1533. 5 B76.B O. 021 .,. 3 4.392 16 685 218.7 209. 0 41205. B 41424.5 5 . 341

I AT TIM!: 915.00:CO SECONDS FREG DEY -0 003 I--' en AfiEA ACE DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADYERTENTS

-30.968 -30. 19i;i 410.9 441. 0 1873 3 22BB.3 -B. 616 ;; -2.72.;' ;C 40" -651. 8 -650.0 1529. 6 877.3 0.0:9 :3 -30.22~ -13. ;:;9 212. 2 209.0 41221. 1 41449.3 5.381

AT TIMe: 930.00:'(0 SECONDS FREG DEY -0 001


1 -32206 -31. 791 409. 5 441.0 1879. 3 22B9.1 -B. 732 2 -6.622 -6 45C' -655. 9 -650.0 1527 6 B79.1 0.009 3 -9.0t::i. -0. .:~ ~, 227. 2 209.0 41241 0 41467.0 5.479

AT TIME: - 945. 00-:·,:,'] SECONDS FREG DEI: -0. 003

AREA ACE DYNAMIC A::E MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-27.39~ -26. 895 415. 1 441. 0 IB69.9 2290.3 -B. 848 2 -1.985 -1. 779 -650 5 -650.0 1526.5 BSI. 7 -0.004 3 -42.668 -32 191 221. 8 209.0 41256.7 41471. 5 5. 522

THE UNIT CoES) :1ED (;ENERATlmJ f!'.':DG) ON UNIT 6 HAS ACHIEYED A MAXIMUM VALUE OF 136.087 MW WHICH IS ABOYE THE UNIT UFPER LIMIT (uHL) OF 116. 000 MIo:. THE UD\: HAS BEEN SET TO THE UHL. THE UNIT I)ESl REI) ;;ENERATION <VDG) ON UNIT 18 HAS ACHIEYED A MAXIMUM YALUE OF B1. 4866 MW WHICH IS AEDYE THE UNIT UPPER LIMIT (UHL) OF 75.0000 MW. THE UDC HAS BEEN SET TO THE UHL. AT TIME 960.00'"00 SECONDS FREG DEY = -0.004

AREA ACE DYNAMIC ACE MNET SNET LOAD AREA GENER .. TIONS AREA INADYERTENTS

1 -27. 18'> -27 0::.3 415.3 441. 0 1876.2 2291. 5 -B. 960 2 -1. 675 -1 6S2 -650.2 -650 0 1531. 9 BBl. 7 O. 002

• • •

• 3 222 ~ 209 0 41281 ~ 41503.6

AT TIM~ FF-EC:z [IEV' -0 003

AREA MNET SNET LOAD AREA GENERATIONS AREA INAD',IERTH,TS

-20 8=5 -2.1 vee. 2, 35":'

3 -37 5~: -41 1~4

,:.or TIME ;70.00::3 SECONCS

421 7 -646. 1

230. <> FREG DEV

441. 0 -650. 0

209, 0

1877.0 1532. 1

41301. 3 -0 004

2292. 1 881 3

415264

-9.054 0.011 5.646

APEA ACE r:··YNAM!C ACE MNET SNET LOAD AREA GENERATIONS AREA INAD"ERTENTS

-27 c,-,,:,, -27 2 -4. 13- -4,25E 3 -52.0~5 -513

AT TIME :-1005. OO:·.~Q SECONDS

415_ 3 -652 ;;'

228 5 FHE':! DE'J

441. 0 -650 0

209. 0 -0

l8S0 5 1534 7

41316 2 002

2294 3 882 5

41542.5

-9. 173 O. 014 S 727

AREA ACE DYNAMIC A:E MNET SNET LOAD AREA GENERATIONS AREA 'INAN'ERTDJTS

-24. 5=~ -24 5::.;;: 417. 1. 441. 0 1876.0 2293.4 2 -0'. c 0 -2 l~i' -651.4 -650.0 1531 0 884.3 3 -?b.~~~ -206:: 216.5 209.0 41339.7 41561.1

Ti-iE UNIT :ESJR.ED ,;ENEFATlON ".'DGJ ON UNIT 1 HAS ACHIEVED A MAXIMUM VALUE OF 175.393 wHICH IS '.EOVE TriE UlJIT UP~F LIMIT <UHU OF 175.000 MW THE UDG HAS BEEN SET TO THE UNiT :ESlRED ,;E~'E;;ATImJ (0DG) ON UNIT 6 HAS ACHIEVED A MAXIMUM VALUE OF 137.193 WHICH IS "-EOVE T""E U:·,;T UP~E= LIMIT (UHL) OF 116.000 MW. THE UDil HAS BEEN SET TO THE UN1" r:·E~.ji(ED ;ENE~ATION (UDG) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALVE OF 82.5926 .. HICH IS :iOC,VE THE Ue<IT UPPEF, LIMIT (UHL) OF 75.0000 M... THE UD;; HAS BEEN SET TO t.:- TIM::' -: 1 ::-:20. 00: ._.:, S"ECONDS f REG DEV = -0. 003

-9.279 0.013 5. 768 MW

THE UHL. MW

THE UHL. MW

THE UHL.


1 -33.71E -33.645 2 4.448 4 ~75 3 -25.4~~ -23914

AT TIME ~1035.00:CO SECOND;

408.3 441.0 1885.4 -644.5 -650.0 1529.8

223 1 209.0 41357.6 FREG rEV -0 002

2293. 7 885.3

41580.6

-9.407 0.026 5.830

AREA ACE DYNAMIC t..::E MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

2 -26.62c:"

;~. 548 .... 540 3 -13.84C -19.258

~T TIr1=-: :"" 1C:;0. 00 :·::0 SECONDS

415.4 441.0 -6464 -650.0 2305 209.0

FREQ DEV -0

1880 2 1534.2

41382.2 004

2293.4 886.2

41609.3

-9.482 0.024 5.896


-23 215 -2 98;

~ -33.42e -44.0'1 AT TIMF ~~J65.00:CO SECONDS

AREA ACE DYNAMIC ACE

419.8 -651.3 230.6

FREG

MNET

1 -27. 83: -27 507 414. 7 2 -3.0!~ -2.87~ -651.5 3 -4?~2: -43 03~ 216.4

DEV

THE UNIT DESlRED <;ENEf'ATIOr< \UDG) Ot; UNIT WHICH IS ~BOVE TH~ UNIT UPPEc LIMIT (UHL) OF THE UNIT ;:·::SlP.ED ~E~~EPA1"lOt'J (";_:DG) ON UNIT 6 W.,!CH IS t Eove THE U~'HT UFPE~ LIMIT (UHL) OF THE UN1T ::E€.):l:ED :;E~~E;:;ATIDN (:_'D(;-i ON UNI, 18

441 0 1880.0 -650.0 15358 209.0 41404.3

-0.004

2294. 5 885,6

41628.4

-9. 596 0.032 5.987


441. 0 1881. 0 2295.9 -650.0 1534.6 886.2

209.0 41420.4 41641 8 HAS ACHIEVED A MAXIMUM VALUE OF 175.602

175000 MW. THE UDG HAS BEEN SET TO HAS ACHIEVED A MAXIMUM VALUE OF 137.402

116.000 MW THE UDG HAS BEEN SET TO HAS ACHIEVED A MAXIMUM VALUE OF 82.8016

-9.719 0.032 6.047 MW

THE UHL. MW

THE UHL. MW

•

W-:!CH .~ ,~ ;;S'JVl Tt .... ;== UI\, I T U~;:E;:: LIMIT (UHLI OF 75.0000 MW THE UDe HAS EEEN SET TD THE UHL

A-: -:It';: : :;.: i;(J. OC :::.c: sr::CONr:; FRECl DEIJ -0. 004

ARE~ AC;: [-"f!-~AM1_C A:t. I1NET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-32. 9·,)~ -3:· 1e:.';: 409 " 441. 0 1887. 0 2296. 6 -9. 849 2 -1. 25~ -1 :t.~ -649.8 -650. 0 1536 9 887. 1 o. 027 3 -2'::'.19': -31 t.4~ 237. " 20t? C 4144 0 0 41677 9 6 109

AT TIM::: "1::'''5. oo:co SECONe·£ FREG DEV -0 006

AREA ACE DYNAMIC '!'>'CE MNET SNET LOAD AREA GENER A Tl ONS AREA INADVERTENTS

-31.452 -31. 6 c ' -~ 410. 7 441 0 1890. 5 2298. 1 -9.948 ;;: 6.4~= 6 ~.,:I- -642. 3 -0,50. 0 1542. 1 885.6 0 031 ~ -38. 19:: -41. 312 215. 1 209. 0 41465 9 41696.5 6 157

AT T 1\"';::" "'""':.110.00':·:,0 SECONDS FREG DEV -0. 004

ARE;, ACE DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-::'5 177 -25 E~- 416. 9 441. 0 1885. 7 2296. 9 -10. 063 2 2. 708 2 43~ -646.2 -650.0 1528. 7 885. 7 o. O"'!!""':

3 -16.253 -29 1:;4:. 233.1 209.0 41483. 6 41703 0 6. 280 AT TIMe=- = 1.125 OO:-C0 SECONDS FREG DE\.-' -0 002

AREA ACE DYNAMIC AcE I1NET SNST LOAD AREA GENERATIONS AREA INADVERTENTS

1 -36.40= -36 ""'" 405. 5 441 0 1881 7 2297.1 -10.202 2 1. 27" l. 2:-C -6478 -650 0 15:>4.7 886.0 0.031 3 -5.458 -6 2:· .... ' 237 0 209.0 41499.9 41726 5 6.378

ii-iE UNIT I!E:=.J RED ;ENEF.ATION /;·_"PG) ON UNIT 1 HAS ACHIEVED A MAXIMUM VALUE OF 175. 765 MW W-iICH IS A20VE THE UNIT UPPER LIMIT <UHL.I OF 175 000 M·· ~. THE UDG H .. S BEEN SET TO THE UHL. THE Ut-<TT :,::SIHED GENERATION (l:DG) ON UNIT 6 HAS ACHIE'JED A MAXIMUM VALUE OF 137. 565 MW

I:J' WHICH IS ABOVE THE UNIT UPPER LIMIT IUHLl OF 116. 000 I1W. THE unG HAS EEEN SET TO THE UHL , TnE UNJT r-ES1RED GENEf'ATI ON <UDGI ON UNIT lEi HAS ACHIEy'ED A MAXIMUM VALUE OF 82.9651 MW I\) 0 l-lHICH IS 'BDVS T~t: UNIT UPPER LItHT <UHLl OF 75.0000 MW THE UDG HAS BEEN SET TO THE UHL.

AT TIM"- =-1140. 00:·00 SECONDS FREG DEV = -0. 004

I'REA ACE DYNAMIC ACE MNST SNET LOAD AREA GENERATIONS ARSA INADVERTENTS

-31. 2g~ -31. 853 411. 3 441. 0 1888.3 2299.6 -10.326 2 0.285 o. 052 -/'48. 1 -650.0 1534.6 886.5 0.032 "3 -29.740 -41 553 240. 5 209.0 41516.6 41757. 1 6.493

AT TIM~ ;:-1155. OO:GO SECONDS FREGl DEV -0.005

AREA ACE DYNAMIC ACE I1NET SNET LOAD AREA GENER .. TIONS AREA INADVERTENTS

1 -22. 163 -22. 39, 420.6 441. 0 19923 2299. 5 -10.415 2 -0.450 -0 ~8.j -648. 7 -650. 0 1543. 1 888.2 0.029 3 -43.360 -48 15:· 232.2 209. 0 41546.0 41780. 1 6. 548

AT TIME ~ 1170, 00·:'00 SECOND3 FREG DEV -0 004

AREA ACE DY~;AMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -31.426 -31. ~-"""'I ~,~ 410. 9 441. 0 1888.6 2299.2 -10. 528 2 -2.737 -2. 673 -651. 4 -650.0 1539.8 888.9 0031 "3 -36.97'. -33. 73'5 222.4 209.0 41559.7 41792.4 6.653

AT TIME ~1185.00)OO SECONDS FREGl DEV -0. 002

AREA ACE DYNAI1IC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -23.997 -28 568 412. 9 441. 0 1884.0 2297.8 -10.658

• • •

• • • 2 -I 03E -G E"' -650. 1 -650.0 1536.0 889.0 0.0:30 3 -1(,. 8~;: -7.E~-:' 227.2 209.0 41579.3 41806. I 6. 733

THE UNIT [;£51 RE:, ;ENER AT I O~1j ,_DC 1 ON UNIT 1 HAS ACHIEVED A MAX 111UM VALUE OF 175 737 f'\l;

WHICH IS t:.EJVE Tri:'::: UUIT UP?ER LIMIT <UHL) OF 175.000 f'\l; THE UOO HAS BEEN SET TO THE UHL THE UN!T r'ES1 f"<ED ';ENERATION ;UDG-) ON UNIT 6 HAS ACHIEVED A MAXIMUM VALUE OF 137. 537 MW WHICH IS AEOVE T"';E UI..;IT UFFEt; LIMIT (UHL) OF 116,000 MW. THE UOG HAS BEEN SET TO THE UHL. THE UNIT {'EEl RED ,;ENERAT ION ,';00) ON UNIT 16 HAS ACHIEVED A MAXIMUM VALUE OF 82.9367 f'\l; WHICH IS I-EOVE TH€: UNIT UF?ER LIMIT (UHLl OF 75.0000 f'\l;, THE unc HAS BEEN SET TO THE UHL. AT TIME ~120(>. 00:,::0 SECONDS FREG DEV = -0. 003

AREt, ACE DYNAMIC AC€: MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-32. le7 -32. 204 410. 1 441. 0 188S 1 229S, 3 -10, 781 2 -4.317 -4. 357 -653 1 -650. 0 1542 6 889. 5 o. 025 3 -3D, 759 -32. 783 224, 2 209, 0 41607. 9 41832. 1 6. 816

AT TIME =1215.00:'JO SECONDS FREG DEV -0.003

AREA ACE DYNAMIC ACE HNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-30.43G -30 '5~:;: 412, 0 441. 0 1891. 5 2299.5 -10'. 8El 2 -5. 57,=: -5. 63·:, -654 2 -650. 0 1541. 9 691.9 0, 019 3 -28.874 -31 648 231 9 209. 0 41623.4 41655.3 6. 682

AT "IMe: =-1:;:30. 00 :.:.:) Se:CONDS FREG DEV -0 002

AREA ACE C'YNAMIC I'CE MNET SNET LOAD AREA GENERA TI DNS AREA INADVERTENTS

-2'7.8S~ -29 735 412,8 441.0 1667.2 2296.2 -11. 014 ;;; o. 182 o. C:':;3 -648. 1 -650, 0 153".6 892.1 0, 020 3 -36.84<. -33. 77e. 2364 209.0 416490 418654 6. 983

AT TIMe: :::.1245. OOCCO SECONDS FREG DEV -0 003

AREt. ACE DYNAMIC ACE MNt:::T SNET LOAD AREA GENERATIONS AREA INADVERTENTS p-I 1 -30.638 -30 763 411.8 441. 0 1890.4 2300.6 -11. 151

I\) f-> 2 1.704 1 6C,.., -646.9 -650. 0 1540.8 892.0 0.028

3 -20. 629 -31 223 232. 4 209. C 41661. 2 41669.3 7. 108 THE UNIT DESlf\ED ;ENERATION 'UDG) ON UNIT 1 HAS ACHIEVED A MAXIMUM VALUE OF 176 921 MOl wHICH IS ABO v::: THE UNIT UP?E". LIMIT <UHL) OF 175.000 MW. THE unG HAS BEEN SET TO THE UHL THE UNIT L,ES 1 REu GENERATION (I..:DG) ON UNIT 2 HAS ACHIEVED A MAXIMUM VALUE OF 177.221 M~'l wHICH IS /-'.BOVE THE UNIT UFFE~ LIMIT (UHL) OF 177 000 MW. THE UOG HAS BEEN SET TO THE UHL. THE UNIT :-ES1RED ~ENEFATION ('_'DG) ON UNIT 6 HAS ACHIEVED A MAXItlUM VALUE OF 138 721 MW WHICH IS .:<SOVE THE UNIT UPPER LIMIT (UHL) OF 116.000 MW. THE VDC HAS BEEN SET TO THE UHL THE UNIT t'ESli1ED ·:;ENER AT I ON ,UOG) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE OF 84. 1215 MW WHICH IS rEeVE THE U'<1T UfPE;:I LIMIT (UHLl OF 75. 0000 MW. THE UDO HAS BEEN SET TO THE UHL AT TIME ='1260 00 :'VO SECONe,s FREG DEV ~ -0 005

AREA ACE DYNAMIC A':E MNET SNET L3AD AREA GENERATIONS AREA INADVERTENTS

1 -38. 552 -38 434 404.3 441. 0 1897. 2 2301.4 -11.292 2 -0.964 -0. 916 -649.2 -650. 0 1543 0 893.8 0.018 3 -51. 121 -48. 649 225.6 209. 0 41681. 3 41906.8 7. 196

AT TIME ~ 1275. 00':00 SECONDS FREG DEV -0 OO~

AREA ACE DYNAMIC ACE MNET SNET LOAD f ... ~;EI~ GENERATIONS AREA INADVERTENTS

1 -33.056 -33, 23e· 409.6 441. 0 1893. 1 2303.8 -11 399 2 -3.03~ -3. 11;: -651. 4 -650.0 1542. 7 894.3 o. 020 3 -45. 192 -48. 981 227. 1 209.0 41701.0 41923.7 7. 266

1'1 TIME ' 129u. 00:)00 SECONDS FREG DEV -0. 004

AREA ACE D'>'NAMIC A':E MNET SNET LDAD AREA GENERATIDNS AREA INADVERTENTS

-38.44:; -38 C== 403 1 441. 0 1891. 7 2304. 5 -11. 535 2 1. 9(:'2 2. 1. 17 -647 5 -050.0 1546. 6 894 9 o. 020 3 -20. 2·6~ -12,4.S':::' 210.2 209.0 41723 0 41954. 6 . 7. 320

AT TIME = 1 ~;j5 00: :.,,:. ;:::CONDS FREG DEV -0. 003

AREA ACE C·YNAMIC A~~ e- MNET SNET LO",D AREA GENER", Tl ONS AREA INADVERTENTS

1 -3~. 14~. -35. 69': 406.2 441. 0 1885.9 2303.4 -11. 674 2 -3. 131 -2. 944 -651 8 -650.0 1536 5 8,2.7 0.032 3 -32. 4'3~ -22 993 226.0 209.0 41734.9 41951.8 7.388

TH.E UNiT ijES1RED ';E}~~F.ATION <UDG} Or-.; UNIT 1 MAS ACHIEVED A MAXIMUM VALUE OF 176.843 MW WHICH IS t'.EOVE T";:: UNIT UPPEP LIMIT <UHL> OF 175.000 MOl. THE UDG HAS BEEN SET TO THE UHL. THE UNIT DESlRED GENEPATION ,;JOG) ON UNIT 2 HAS ACHIEVED A MAXIMUM VALUE OF 177.143 MW WHICH IS ABOVE THE UNIT UPPER LIMIT (UHL) OF 177.000 MW. THE UDC HAS BEEN SET TO THE UHL THE UNIT DESIRED GENERATION i.t)OG) ON UNIT 6 HAS ACHIEVED A MAXIMUM VALUE OF 138.643 MW WHICH IS AEOVE Tr-IC: UNIT UPPE" LIMIT (uHL> OF 116.000 MW. THE UDC HAS BEEN SET TO THE UHL THE U~JIT DESIRED G-ENERATION {UDG) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE OF 84.0432 MW WHICH IS I.EOVE THE UNIT UPPER LIMIT (UHLl OF 75.0000 MW. THE UDG HAS BEEN SET TO THE UHL. AT TIME :-132(1 00':·::0 SECONDS FREG DEli = -D. 002


1 -34.946 -35 057 406. 9 441 0 1897. 2 2304 1 -11.827 2 3. 174 3. 128 -645.9 -650 0 1540. 2 894.3 0.042 3 -I? 45<;' -21 7;;5 222. 7 209. 0 41768. 3 41991.0 7. 458

AT TIME: ~!33". 00:-:·0 SE:CONDS FREG DEV -D. 004

AREA ACE DVNAMIC ACE t-:r--.:ET SNE:T LOAD AREA GENERATIONS AREA INADVERTENTS

-39. 165 -39. 113 402.9 441. 0 1896. 7 2304.9 -1 L 928 ;; -0.763 -D. 742 -649. 7 -650.0 1545 1 894.3 0.042

::r 3 -20.042 -18.945 227.2 209.0 41782 2 42012.5 7.523 I AT TIME :" 1350. 00:;00 SECONDS FREG DEV -0. 005 18

A~EA ACE DYNAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA I NAD"ER TENTS

1 -31. 157 -31. 346 411. 7 441. 0 1892.8 2305.4 -12. 072 2 -7.621 -7.699 -655.8 -650.0 1539.3 896. 5 O. 040 3 -47.397 -51. 356 229. 7 209.0 41798.5 42032.6 7. 625

AT TIME ~1305. OO:',JO SE:CONDS FREG DEV -0 004


1 -35. 7SI!. -36 044 407.3 441. 0 1896. 7 2304.8 -12. 220 2 O.37~ 0.266 -647.5 -650.0 1544.9 899.8 O. 040 3 -45. 582 -51.015 242.2 209.0 41820.7 42044. 7 7.719

THE UNIT !:·;:SIRED GENERATION IUDG) ON UNIT 1 HAS ACHIEVED A MAXIMUM VALUE OF 176.877 MW WHICH IS f:.20VE THE: UNIT UPPER LIMIT (uHL) OF 175.000 MW. THE UDQ HAS BEEN SET TO THE UHL. THE UNlT DESIRED :;Et<;,RATION (tiDG) ON UNIT 2 HAS ACHIEVED A MAXIMUM W,LVE OF 177.177 MW WHICH IE PEOVE THE U!'~l T UPPER LIMIT <UHLl OF 177.000 MW. THE UDG HAS BEEN SET TO THE UHL. THE UNIT r'SSlnED GENERATION (UDG) ON UNIT 6 HAS ACHIEVED A MAXIMUM VALUE OF 138.677 MW WHICH IS lEOIIE THE UNIT UPPER LIMIT (UHL) OF 116.000 MW. THE unc HAS BEEN SET TO THE UHL. THE UNIT DESIRED ;DERATION <uDG> ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE OF 84.0765 MW WHICH IS AEOVE' THE UNIT UPPER LIMIT <UHU OF 75.0000 MW. THE UIlG HAS Bt:;EN SET TO THE UHL. AT TIME :-1380.00:00 SECONDS FREG DEV = -0 005

ARE~. ACE DYNAMIC ACE MNET 8NET LOAD AREA GENERATIONS AREA INADVERTENTS

1 ·34. 142 -34. 449 408 9 441 0 1897. 1 2306. 1 -12.361 2 O.9e..=: o. 836 -647.0 -650.0 1545.5 898. 5 0.051

• • •

• • 3 -~8 4~~ -64 E5~ 227.9 2090 418495 42077.3 7.817

~ TIM~ ~:2~~ 00::2 ;ECO~~; FRE~ LEV -0 005

AREA MNET SNET LOAD AREA GENERATIONS AREA INAD\IERTENTS

-31 ... c.:.,_'

2 O. 99:;: 162 3 -~8 e;: -40 372

A~ TIME -14;'(" O-:J:·:-Q 5~COND3

410 7 -647. 5

216. 2 FREG DEV

441.0 19008 -650.0 1548.0

209.0 41862.5 -0.005

2305.9 898.9

42091. 4

-12.469 0.058 7.869

AREA ACE DYNAMIC h'.:2 MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-35. 1S;;: 2 O. 954 3 -55.579

AT TIME ~142~.OO::O

-34 E~5 1 077

-49.:;'52 SECONDS

407.5 -647.3

217.9 FREQ

4410 1897.4 -6500 1546.2

209.0 41877.6 DEli -0.004

2306,3 898 5

42114.5

-12.614 O. 073 7.942

AREA ACE DYNAMIC A2E MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -33. 5~= -33 ~23 409.6 441.0 1898.7 2306.8 2 -1.35~ -1 2~: -649.2 -650.0 1546.0 900.8 3 -5~3~: -512:€ 2359 209.0 418998 42123.0

Tf'E U'<IT D"SJRED ~E"E"ATIO" . '_DG) ON UNIT HAS ACHIE"ED A MAXiMUM VALUE OF 177.516 "'~ICH IS ",BOVE T"'O: urcn UP;oE= LIMIT IUHLl OF 175.000 MW THE un" HAS BEEN SET TO THE UNIT ;:-E:S1RED ;ENERATIO!~ UDG) ON UNIT ;;: hAS ACHIEI~.'ED A MAXIMUM VALUE OF 177.816 Wi-1ICH IS ;'2!]VF T~t: VNIT UP~E= LI~:T (UHL) OF 177.000 MW THE uno HAS BEEN SET TO TH£ UN1T :-t.S1RE~' :;E.r';£?ATIOhr ("..:DG> ON UNIT 6 HAS ACHIEVED A MAXIMUM VALUE OF 139.316 WHICH Ie ~£:JVE T",,, UNIT UP=E:= LInT (UHl) OF 116.000 MW THE UDG HAS BEEN SET TO THE UN1T ::f:.SlRED ;ENE.RATIQ~'~ ("":DG) ON UNIT lE. HAS ACHIEVED A MAXIMUM VALUE OF 84. 711S2 WHICH IS PEOVE THE: UNIT UPFE:R LIMiT {UHLl OF 75.0000 MW THE UDG HAS BEEN SET TO AT TIM" ·1440. OO:·C;O SECONDS FREG DE:V = -0,004

-12. 768 O. 068 8. 014 MW

THE UHL, MW

THE UHL MW

THE UHL. MW

THE UHL.


3 AT TIM~

-37. 642 8 626

-30.91-]

-37 37t: 3 73b

405. 0 -644.7 240.9

FREG

441.0 -650 0 209.0

DEV -0

1902_ 1 1544.0

41918.8 003

2307.2 899.3

42159.7

-12.915 0,082 8.115

AREA ACE: DYNAMIC :.:E MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

2 -3~. 727

2. 06= -36 431

2 :;.9l 3 -33.0~7 -31 8~~

AT TIM~ -1'70. OQ::~ ~ECONDS

405 9 -646.3 231.7

FRE(l

441. 0 -650.0

209.0 DEV -0

1904.4 1550.4

41944.3 004

2307. 5 899.4

42182 6

-13.035 o 085 8. 190

AREA ACt: DyNAMIC ;"CE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

2 3

AT TIMe::

-3~ 8·j5 O. 95S

-~O.8':;'6

""l~SS 00::.0

-37. 19c,. O. 796

-49 030 SECONDS

406 2 -647.0

243. 7 FREQ DEV

441.0 1905,3 -650.0 1547.1 209.0 41965 1

-0,004

2308.9 899.4

42189.8

-13. 203 O. 092 8.305

AREA ACE. DY~,AMIC A~" MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -39.152 -38,895 4035 441.0 1909.4 2310.0 2 0.70'? 0.815 -647.6 -650.0 1554 2 900.3 3 -38633 -33 ;;:70 2337 209.0 419868 42227.5

THE UNIT [E;JRED ~ENERATION 'vDG, ON UNIT HAS ACHIEVED A MAXIMUM VALUE OF 177.273 "'HICH IS t;;~""E ,dS U~"lT UPFER LIr'OLT (UHl) OF 175.000 MW. THE UDC HAS BEEN SET TO THE UN1T :·E=.lREi: ';Er-~£~ATION (!JDG) O"'~ UNIT 2 HAS ACHIEVED A MAXIMUM V~.LUE. OF 177.573

-13.352 0.091 8,412 MW

THE UHL. MW

•

W;";!CH I ,c.i:;''JVF Tr-€ UNIT UPPER LIMIT (VHL) OF 177.000 Mlol THE UD;; HAS BEEN SET TO THE UHL. TME UNI ;:'~::,n:Eu .;'E~·~~;:;' AT 1 at..' ~ ~;DG I ON UNIT 6 kAS AC HIE ,.,'Et' A MAXIMUM V';LUE OF 139073 Mlol wHICH I ;"'='~\t'~ Th~ U".IT UPFE= LIMIT (Url:,.. ) OF 116. 000 MW THE un:; HAS BEEN SET TO THE UHi.... ~I-iE u~n r=:~ll,Er:, ';E~~;::R.ATION {L:DG) ON UNIT lE HAS ACHIE\!ED A MAXIMUM VA,"--UE OF 84.4733 Mlol WHICH I ,t.E,:rVr- T~E \NIT U;:FE~ LIMIT (UHL' OF 75.0000 Mlol THE UDO HAS BEEN SET TO THE UHL. AT TIME '-130('. OO~::~ SECONDS FREG DEV = -0. 002

ARE~ ACE DVNAMIC ACE IINET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-33. 1 EO" -32 950 408.6 441. 0 1900 6 2309. 2 -13. 499 2 -5.3-?-:; -5 315 -654 6 -650. 0 1555 6 901. 0 O. 081 3 -14 84'::' -10 SSt:· 223. 1 209. 0 42003. 0 42226. 1 8 537

~ . TIME .-1 S~ 5. 00 :',:0 SECONDS FREG :;EIi -0. 005

AREA ACE D'YNAIIIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-40. 138 -40. 34(: 402. 7 441. 0 1907. 6 2310.6 -13. 624 2 O. IQ~ 0 086 -648 0 -650. 0 15S2. 5 902.5 O. 084 3 - 4':". CJ~~ -50 28~ 231.8 209 0 42023 1 42254.6 8 602

AT TIME ~153(). OC-:-:: . .:, SECONDS FRE", DEV -0. 004

AREA ACE D'{NAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-41 5E=.. -41. 3E 401. 1 441. 0 1909. 1 2310.7 -13. 789 2 -1 5 ": -1 462 -649. 9 -650. 0 1551. 5 901. 8 0 096 :; -47.2:'; -43 543 223. " 209. 0 42043. 3 42264.9 8 684

AT TIM:: ~] 545. 00:,.:::: SECONDS FREG DEV -0. 003

AREA ACE c' {NAMIC ACE IINET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -36, 54;: -36. 644 405. 7 441. 0 1904 4 2310.0 -13.950 2 -3 821 -3 863 -652.6 -650.0 1549.6 901. 8 O. 102

P' 3 -13.621 -15. 765 242.8 209.0 42060 5 42293.2 8.806 I THE UNIT DESJ:7ED :;ENERA T! ON <UDG' ON UNIT 1 HAS ACHIEVED A MAXIMUM VALUE OF 178.~42 Mlol IIJ ..,.. IoIIiICH IS l.P,]V[;' Tf'"iE UNIT UPPER LIMIT (UHU OF 175,000 Mlol THE UDG HAS BEEN SET TO THE UHL.

THE UNIT DESJRED ~ENEr;ATlON WDG) ON UNIT 2 HAS ACHIEVED A MAX;MUM VALUE OF 178.742 11101 IoIIiICH IS ~',BOVE TI-lE UNIT UP?EP LIMIT (uHU OF 177.000 Mlol THE UllC HilS BEEN SET TO THE UHL. THE UNIT D .. S 1 RED ;ENERATION ('-'DG) ON UNIT 6 HAS ACHIEVED A MAXIMUM VALUE OF 140.242 Mlol WHICH IS ABOVE THE UNIT UPPER LIMIT (UHU OF 116.000 Mlol THE UDO HAS BEEN SET TO THE UHL. THE UNIT r'£SJ~ED ·:;ENERATION (IJDC) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE OF 85.6424 IIW WHICH IS P.EOVr:.. THE UNIT UPPER LIMIT (uHLl OF 75.0000 MW THE UDG HAS BEEN SET TO THE UHL. AT TIME =-1 56() OO:CD SECONDS FREG DEV = -0. 004

AREA ACE DYNAIIIC ACE IINET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-41 288 -41. 44:: 40L 4 441 0 1909. 8 2311.2 -14. 122 2 2 7::- 2. c.-48 -645.6 -650. 0 1550. 6 905.1 O. 101 3 -37. 5,~ -40. 776 236. 5 209. 0 42082. 5 42319.0 8. 925

AT TIME =-1 :75. 00: ~.J SECONDS FREG DEV = -0 006

AREA ACE DYNAMIC ACE IINET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -42. 169 -42 396 401. 1 441.0 1913.4 2311. 7 -14. 248 2 -3.58;: -3. 676 -651. 3 -650.0 1556.7 904.9 0, 108 3 -bO.517 -73.282 225.4 209.0 42104. 5 42338.2 8. 985

AT TillE ~IS9('. OO:C,O SECONDS FREG DEV -0 004

AREA ACE DYNAMIC ACE IINET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -43 699 -43. 902 398. 5 44L 0 191L 7 2310.9 -14.426 2 -1. 72<- -I. 810 -650. 5 -650.0 1547.0 904 6 0.113

• • •

P' I

[\) VI

• • 3 -13 48: -22 ~2~ 235.9 209.0 42121.4 42352.9 9.108

A~ TIME -1:::':)~ 00:-:::: SECONDS FREG DEV -0 004

AREA

1 2 3

THe: UN!T WHICH IS THE UNIT WHICH IS 7HE UNIT wHICH IS THE UNIT WHICH IS AT TIM;'.

AREA

2 3

AT THE

AREA

2 3

AT TIME:

AREt-.

;;: 3

AT TIME

AREt

2 ~

THE U1;lT WHICH IS THE: uNIT WHICH IS THE UNIT WHICH 1S THE UNIT WHICH IS AT TIM::

AREA

1 :2 3

AT TIM::::

ACE uYNAMIC A·:E MNET

-40. 4;;:2 -40 323 402. I -2. 645 -2 e.G':' -651 1

-3S.54f -33 477 231 5 ~ESIRED ';'E~t::RATION lUDG) ON UNIT "'SOVE TM;::: UNIT Up'::E;:;' LIMIT <VHU :'eS1RED ;ENERATIO" (JDG' ON UNIT t-,BOVE. T~E U;'J~T UPr=EF LIMIT <VHU .i:ESIRED ;;E. ... ~!::RATION cUDG) ON UNIT ,(£']VE Tt"i~ !jt-HT UPfER LIMIT <VHU DESJRED ;ENERATlON (LlDG) ON UNIT P.EOVE Tr-i£ UNIT UPPER LIMIT <VHU

~1620. 00 :.;:.,:; SECONDS FREG


-33.4S!' -33. '56'5 409.6 -4.561 -4. 596 -652. 5

-53.6')5 -55. 371 231.9 ~ lc3~, 00 :": ~ St:CONDS FREG

ACE :··fNAMIC ACE MNET

-37. :;:~,j -37 729 406.4 -3.613 -~. 6~:· -651. 0

-68.153 -78 817 237. 5 :-1650.00:00 SECONDS FREG

ACE DVNAMIC ACE MNET

-42.299 -42. 501 400. 5 -1. 644 -l. 727 -649.9

-31. 53~ -35 768 244. 2 :-1665 00::: ;) SECONDS FREG


-46. 78~ -47. 200 397.2 1 001 0 ~~s -646.0

-68.8"i,":::" -77. 58': 250.8 ::'ES]i(ED ';£~~ERAT I ON ( 'JDG) ON UNIT t'EC,VF T!-i~ UNIT UF?ER LIMIT (uHL) :ES J f(f.:!J ::;E;-~EF: AT I ON (tJOG) ON UNIT lBL"VE.. THE UNIT UPPER LIMIT lUHU DE:SJ RED .:;.ENERATION (UOG) ON UNIT ~EOVE THE UNIT U?PER LIMIT (uHLl D~SJRED ;;ENERATION (l'DG~ ON UNIT HOVE Tr-iE UNIT UPFER LIMIT lUHU

::-1680.00:'00 SECONDS FREG

ACE r:'VNAMIC 4CE MNET

-4'1. 168 -49.474 393.4 -4.23.a. -4.361 -652. 7

-21. 145 -27.S'59 245.8 ~1695.00:CO SECONDS FREG

SNET LOAD AREA GENERATIONS AREA INAOVERTENTS

441. 0 19073 2310.9 -14. 591 -650.0 1551. 4 903.0 0.122

209.0 42139.4 42371. 5 9.209 I HAS ACHIEVED A MAXIMUM VALUE OF 177.807 MW

OF 175.000 MW THE UDG HAS BEEN SET TO THE UHL. 2 HAS ACHIEVED A MAXIMUM VALUE OF 178.167 MW

OF 177.000 MW. THE UDG HAS BEEN SET TO THE UHL. 6 HAS ACHIEVED A MAXIMUM VALUE OF 139.667 MW

OF 116.000 MW THE lID:: HAS BEEN SET TO THE UHL. 18 HAS ACHIEVED A MAXIMUM VALUE OF 85.0670 MOl OF 75.0000 MW. THE UDG HAS BEEN SET TO THE UHL. DEV = -0. 005


441. 0 1905. 0 2314.5 -14. 760 -650. 0 1556. 6 904.1 O. 120

209. 0 42167. 1 42399.0 9.286 DEV -0. 005

SNET LOAD AREA GENERA T! ONS AREA INADVERTENTS

441- 0 1908.0 2311. 4 -14.886 -650. 0 1551. 7 904. 7 O. 116

209. 0 42177.7 42404. 3 9.352 DEV -0. 003

SNET LOAD AREA GENERA T! ONS AREA INAOVERTENTS

441. 0 1913. 1 2311.6 -IS. 065 -650. 0 1561. 6 905. 7 O. 109

209. 0 42208. 7 42425. 1 9. 476 DEV -0. 006

SNET LOAD AREA GENERlI Tl ONS AREA INAOVERTENTS

441.0 1913.2 2314. 7 -15.253 -650.0 1555.8 907.5 O. 112

209.0 42220.4 42447.3 9.607 1 HAS ACHIE,,'ED A MAXIMUM VALUE OF 179.979 MOl

OF 175.000 MW. THE UDO HAS BEEN SET TO THE UHL. 2 HAS ACHIEVED A MAXIMUM VALUE OF 180.279 MOl

OF 177.000 MW. THE uno HAS BEEN SET TO THE UHL. 0 HAS ACHIEVED A MAXIMUM VALUE.OF 141 779 MW

OF 116.000 MW. THE uno HAS BEEN SET TO THE UHL. 18 HAS ACHIEVED A MAXIMUM VALUE OF 87. 1793 I'IW OF 75.0000 MW. THE UDG HAS BEEN SET TO THE UHL. DEV = -0.004


441. 0 1922.3 :2315. 7 -15.437 -650.0 1558.6 905. 9 O. 121

209. 0 42243.4 42489. 2 9. 762 DEV - -0.003

•

AREA ACE DYNAMIC A~-_t:. MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-44 7~= -44 7bl 398. 0 441. 0 1913 5 2315. 4 -15. 581 2 -1 0-- -1 e,7S -649. 3 -1>50. 0 1555. 7 907. 1 O. 122 3 -35.8~~ -35. qs.! 240. 6 209. 0 42261. 3 42496. 8 9. 882

AT TIMt" :..1710. 00:'--:,0 SECON[!:= FREG DEV -0 003

ARE~. ACE D'mAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-41 479 -41 181 401 4 441 0 1914 7 2315. 9 -15. 760 2 0.83':'" 0 960 -647.3 -650. 0 1554. 4 908. 7 O. 119 3 -40, 421 -3~ 231 237.4 209. 0 42262. 5 42513. 6 9. 989

AT TIME=" :;.."!. 725. 00':'00 SECONDS FREG DEV -0. 003

AREA ACt: D"NAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

-43. 58~ -43 536 398. 9 441. 0 1915.7 2316.2 -15.944 2 -4. 718 -4. e.9t-. -653.2 -650.0 1557. 3 906.3 O. 135 3 -17.2<:·:' -11> 110 247. 6 209.0 42302.2 42542.0 10. 106

THE UNIT DESI:<E~ ;;ENERATIC·~ <UDG) ON UNIT 1 HAS ACHIEVED A MAXIMUM VALUE OF 178.950 MW WHICH TC

,~ t'saVE" THE U~IT UF=ER LIMIT WHU OF 175 000 MW THE UDC; HAS BEEN SET TO THE UHL THE UNIT t·~~,]RED :;'ENE?ATI8'oJ ((.'DG) ON UNIT 2 HAS ACHIEVED A HAXIMUM VALUE OF 179.250 MW WHICH I!' ~EJVE T...,~ U"lT UP;=Ef'. LIMIT <UHU OF 177.000 MW. THE UDG HAS BEEN SET TO THE UHL. THE UNIT :'E~IRED :';ENEJ~ATIO!'" ('-.IDC) ON UNlT 6 HAS ACHIEVED A MAXIMUM VALUE OF 140. 750 MW WHICH I!' ~',EDVE- T,..;=:' UNIT UF~E.R LIMIT <UHU OF 116.000 11101 THE UDG HI'.S BEEN SET TO THE UrlL T.-t~ UNIT I::E;;:·l~ED ·;ENE.~ATIcrl/ (UDG) ON UNIT 18 HAS ACHIEVED A MAXIMUM VALUE 00= 86. 1500 MW WHICH IS (.'EOVE TI'"IE UNIT UFoE~ LIMIT <UHU OF 75.0000 Mw. THE UDG H"S BEEN SET TO THE UHL. AT TII1;:: =..~7<lO. 00: ·:'0 SECGNOS FREG DEV = -0 003

P' ARE" ACE DYN"MIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS I ro

-3'1.67!. 0"- -39. 983 402. 7 441. 0 1914 1 2316 8 -10. 131 ;;: -4. 53~· -4. 665 -653.2 -650.0 1561. 8 908. 6 O. 130 3 -26097 -32 569 232 7 209.0 42328 3 42561. 0 10.240

AT TIME ~175S. 00 C0C· SECON'i)S FREG DEV -0 005

AREA ACE [)Y:';AMIC ACE. I1NET SNE:T LOAD AREA GENERATIONS AREA INADVERTENTS

-40.6,,<:: -41 23.1 402.0 441. 0 1917.7 2318.0 -16.264 ;;: -2, 72-; -2. 961 -651.0 -650.0 1558. 7 908. 7 0.138 3 -308<>= -42 eS0 241.7 209.0 42341.0 42574.8 10.348

AT TIl'!;:: :-17iO 00 :.c,:, SECONDS FREG DEV -0.001

AREA ACE DY~~A"UC ACE MNET SNET LOAD AREA GENERATIONS AREA INAD'JERTENTS

1 -3i:i.28~ -38 167 403.3 441. 0 1921.5 2316. 4 -16.453 2 -2.4£5 -2 43..1 -651 9 -650.0 1559.5 910. 3 O. 126 3 7.347 9 921 237.5 209.0 42363.3 42590. 2 10.479

AT TIME .:;;;1785. OO::'C'O SECONDS FREG ·DEV = -0. 005

AREA ACE D'{NAMIC ACE MNET SNET LOAD AREA GENERATIONS AREA INADVERTENTS

1 -38_ 521 -3e. 490 404. 5 441. 0 1923.5 2318. 5 -16. 636 ;;: -7.755- -7. 743 -655. 8 -650.0 1503.2 911.6 O. 127 3 -48 191 -47 542 235. 7 209.0 42384.9 42625.6 10. 596

PERFOR~AN:E ~VAL'..!ATlDN FOR STVDY: X APSfSRP SIMULATION FOR WINTER 1982

ELAPSEll TIME 1800. 00 SE:ONDS

PA",-4H:::TE:~5 "OR A~:::A

• •

• • RM~ ACE iELEC7

37 6~ F.MS ACE .MECH) RMS ~CE (EL FLT)

~9. 64 30. 49 AVE ACE

-35 07 INADVERTENT

16.781519 TIME ERROF

-0.113314 flM3 FD

Co 004,;0.0

MA); 7!ME BCTN ~E;:::C CROSS ('::EC) =- 0GO

2

AT <SEC! 8 000

ELAPS TIM~ SINCE LAST XING (SEC) 1780.000

RMS ,£leE I.MEeH) RHS ACE {EL FLT) A\lE ACE

MAX VALUE O' ACE -106.845

TIME ERROR

OC·:URE: AT (SEC: 19~ 000

RMS FD PMS t..CE: ; ELECT; 3 sa 3.59 L 33 -1. 24

INADVERTENT -0. 137804 -0. 113314 O. !J04C'E~

MA~ ~IME ~ETN :ERO CROSS 'SEC) 46 000

3

AT (SECj 740.0;')0

ELAPS TIME SINCE LAST XING (SEC) 4.000

MAX VALUE OF ACE -11. 588

OCCUR~:' AT (SEC i 380.00;:'

RMS ACE (ELECT; 39.2:3

PHS ACE 'MEeHl RMS ACE (EL FLT) AVE ACE -35. 33

INAD\lERTENT -10.662348

TIME ERROR -0.113314

RMS FD O.004J63 40.28 34.62

MAX Tlt-'lE BETN ZE~u CROSS {SEC) "-32 000

AT (SEC) 784000

ELAPS TIME SINCE LAST XING (SEC) 28.000

MAX VALUE OF ACE -83.268

OCCURE:' AT (SEC I 776.000

•

UAQ(74) SCALE FACTOR - 1. 0E+03 36 75 37 25 37.7'5 38. 25 3B.75 39.:i!~ 39.75 40, 25 40. 75 41. 25 41. 1~

TTI'1E +++++++++~+++++++++++++++++++++++++++++++++++++++++++++++++++++++++++~+++++++~+++++++++++++++++++++++ • 0.00 + • • •• + + • + • A

+ • • • A

• A

• A

• A A

150.00 + • A • • • + + • •

A + A

A

• A

A A

300. 00 -+ •• + + + + A A

• A A

A A A

A 450 Q,) -+ A • + +

A A

• A

• • • • • 600 00 -+ + + A + + + + +

•

A • • • 750 00 + •• + + +

• + A

• A A A

A A

A t:?OO 0: -+ A •

A A A

A A A

1050 0,: + 0+ • + +

A A A

A A

• • • 1200 00 -+ • A +

• A

• A A A

• • A 1350 00 -+ • • • + +

A A • A

A h-28 • • • • A

1500· 00 + + + + +A + + +

UAQ:(61 ) SCALE FACTOR ... OE+Ol 4. 00 4.60 5.20 5. 80 6. 40 7.00 7.60 8 . .20 8.BO ·9.40 10.00

TIME +++~+++++++++++++++~++++++++++++++++++++++++++++++++++++++.++++++++++++++++++~ ... ++++++ ... +++++++++++++++ • O. 00 + + A + + + + + + + + A

A A A

A A

A A A

150. 00 + A + + + + + + A

A A

A A A A A

A 300. 00 ... A

A A A A

A A

A A A

450 00 + + A + A

A A A

A A

A A

A 600 00 + A + +

A A

A A

A A • A A

A 750 00 + A + +

A

A

A A A A

A A

900. 00 + A + A

A A

A A

A A

A A

10'0 00 + A A A

A A A A

A A

A 1200 00 A +

A A

A A

A A

A A A

1350 00 ... + A

A A • A A h-29

A A

+ A A

A 1'00 00 + A + + +

UAQ(I). I .. 58. 59 SCALE FACTOR. 1.0£+01 0.30 0.42 0.54 O. 66 o. 78 0.90 1.02 I. 14 1.26 1.38 1.50

TIME ++++++++++++++++++++++++++++++++++++++++++++++++++++++++++.~+++++++++++++++++~+++++++++++++++++++++++ O. 00 + + + + + U + + + + +

+ +

150.00 +

300.00 +

4!!10. 00 +

600 00 +

750 00 +

900. 00 +

1050.00 +

1200 00 +

13'0.00 +

+

+ +

+ 1500.00 +

+

+

+ + +

+

+ +

+ +

h-30

+ + +

+ +

D + + +

D + + + +

D + + + +

+ +

D +

D + + +

" + + +

D + + + + +

• + + + + +

•

•

•

•

•

•

UAQ-(45i o 50 O. 80 O. 95 1. 10 1. 25 t.40 1. 55

SCALE ~ACTOR = 1.0E+02 1. 70 1. 85 ;2. 00

TIME 0_00

+++++++++++++++++++++++++++++++++++++++++++++++++++++++++~-++++++++++++++++++++++++++++++++++++++++++

+ + + + ~ + + + + + + +

lS0.00 + A + A A A A A A A A A

300. 00 ... A + + A A A A

+ A A

A A A

450 00 + +A + + A A

A A A A A A

A 600 00 .. + + + A + + +

A A A A

A A A A A

750 00 .. A A A A A A A

A

A

4

900 00 .. A A

A A A A

• A A

1050 O<J .. + A + A A A A A A A A A

1200.0,:' + A A

• A A

A A A A A

1350 00 .. A + + + A A A A

h-31 A A A A A

1'00 00 + A + +

UAG{43} 3.00 3 90 4, 80 ~. 70 6.60

SCALE FACTOR = t 0E+01 7. 50 8.40 9.30 10.20 11. 10 12 00

TIME +++r+++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++ o. 00 + + + A + + + +

A A A

+ A A A A A A

150. 00 + + + + + A + + + + A A A A A A A A A

300 00 ... + A + + A

A A

A A A

A A

450.00 + + A + + A

600. oa + + + + +

• • A A A

• 750 00 + +. +

A

• • A A A A A A

900. 00 + +A + A

A

• • • " " A

A

IOSO.OO +

• • • • • l~OO 00 + A +

• • • • • • • • • 13~0, 00 + • + +

A A

• • h-32 • • •

A

• 1500 00 ... + + + • +

+ + +

•

•

•

UAQ{42) SCALE FACTOR • 1_ 0E+02 1. 60 LBO 2 00 2. :20 2.4.0 2.60 280 3.00 3. 20 3, 40 3.60

TII1E +++~+++++++++++++++.+++++++++++++++++++++++++++++++++++++++~++++~++++++++++++++++++++++++++++++++++++ 0.00 + + A + + + + + + + • A

+ A + A

A A

+ A + A

A A

150. 00 + A + + + + + + + + + A + A + A

A + A + A

A + A + A

300.00 + A + + + + + + A + A

A + A + A + A + A + A

... 4~0.Oa + A + + +

A A A

+ A ... A A ... ...

600.00 + ... + + + + + ... ...

A A A ... ... • ... A

750.00 + A + + + + A A

... A

A A A A A

c;too_oa + ... + + + + A ... ... A ... A A

• A

1050. 00 + A + + + A + A + •

A A A A A A

1200_00 + ... + + + +

• + A ...

A

• ... A

• • 13SO.00 + A + + + + + .' + A + • • + A

A h-33 + ...

... + ...

A !sao.QO + A+ + + + + + +

UAQ(41} ICM.£ FACTOR • L 01:+02 1.60 1. BO 2.00 2.20 2.40 2 60 2.110 3.00 3. aD 3.40 3.60

TIME +++~++++++++++++++++++++++++++++++++++++++++++++++++++++++~.+++++++++++++++++++ .. +++++++++++++++++++++ 0.00 + + + + + + + • + • + • " • + • + A

+ A A ... A A

150.00 + + + + + + + + ... + ... A A A A A A A

+ A 300.00 .. + + + + + + A +

A + ... + A

A + A + A + A + A + A

4!1iO.OO .. + + + + A + A A

" " .. .. .. A A

600.00 + + + + + + A + A A A

" A A

" • .. .. 750. 00 + + + A +

A

" A A .. A A A

" 900. OC + + + + + A + A

" " .. " " " A A

1050 00 + + + + + A + A A A

" " + " " " " 1200. 00 + + + " +

" " " " .. " " " " 1350. 00 + + + + + + " +

" + A + ... • + h-34 A

" + " + ... ... .. 1500.00 .. + + + + + + + + .. +

TIMe o. 00

150 00

300.00

450 00

bOO. 00

• 750 00

'100 Of

1050 00

1;200 00

13:50. DC.

• t~OO_OO

UAG( fl. 2 00

• 18. 19 2. bO 3.20 3 80 4. 40

SCALE FACTOR • 1 OE+01 5. 00 5. bO 6.20 6.80 7.40 8.00

+~.+++++++++++++++++~++++++++++++++++++++++++++++++++++++++~+++~++++++++++++++++++++++++++++++++++++++

B + + + A + + + + B A B A B A , A B B A B • B A

B A B + + +A + +

B A

B A

B A B A B A B A B A

B A

B A

B + +A

B A

B A

B A

B A

B A

B A

B A

B A

B A

B + A

B A

B A

B A

B A

B A

B A

B A

B A

B A

B + + + A

B A B A

B A

B A

B A

B A

B A

B A

B A a + A

B A B A B A , A

8 A A A A A

+ A A A A A A A A A A

+ A B • B A B A B • B A B •

A A A

+ A A A A A A A A A A

+ A + A A

h-35 A A A A A

8 A B A

+ + + A

UAQ(9) BCALE F AC TOR • 1 0E+02 1 00 1 25 1. 50 1. 75 2.00 2. 2~ 2. 50 2. 75 3.00 3. 2:5- ·3.50

TIME +++++++*+++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++ 0.00 + + + + + + + A + + +

A A A A A A A A A

150 00 + + + + + + + A + + + A

• A A A A A

+ A A

300.00 + + + + • + + + A A

• .. A

+ A A A

• 450. 00 -+ + + • + +

• A .. A A A .. A A

600 00 -+ + + A + + + A .. A A A A • A A A

750 00 -+ + A + + A

• A A A A A A A

qOD.DO -+ + A + + +

• A

• .. A A .. A A

10'0 00 -+ + + • + + A A

• A .. A A A A

1200 00 -+ + A + + + A A A A A A .. ..

+ A 1350.00 + + + + + A + + +

+ .. + A • •

h-36 A A

+ • + • + .. • • 1500.00 + • • • • • • ... • •

UAQ{B) SCALE FACTOR • OE+02 1. 00 1 15 1. 30 L 4~ 1. 60 1. 7~ 1. 90 2. 05 2. 20 2.35 2. 50

TIM£. +++~+++++++++++++++.++i·+++++++++++++++++++++++++++++++++++~T+++++++++++++++++~+++++++++++++++++++++++ O. 00 + + + + + + A + + +

fa + A

A A

A A

A A

A A

150.00 + + + + + + A+ + + A

+ A A

A + A + A

A + A

A 300. 00 + + + + A + +

A A

A + A + A

A A A A

450 00 .0- M A A

• A A A A A

• 600 00 + • +

• • • • • • • • • 750. 00 + • +

• • • • • • • A

• 900 00 + • A

• A

• • • • A

• 1050 00 + +A + A

• A

• • • A

• • 1200 00 + + •

• • • • • • • A

• 13'0. 00 -+ + A +

• • • • h-37 A

• + • • • •

1'00.00 -+ + + + + + •

UAQ(7) SCALE FACTOR • 1. 0E+02 1.00 1. 15 1. 30 1. 45 1. bO 1. 75 1. .0 ~.O5 ~. ~O 2.35 2.50

TIME ++++++++++++++++++++++++++++++++++++++++++++++++++++++++++.~++++~++++++++++++~+++++++++++++++++++++++ 0. 00 + + + + + A + + + + + • + A

+ +

+ • + • + • + A

t. 150.00 + + + + + + • + +

+ A

• A

• A

• • • • 300. 00 + + + +. + + + • • • • • • • • •

4~0 00 + + + • + + + + A

• • • • A A A

• 600.00 + + + + + • • +

• • A A

• • • A

• A

750.00 + + • + + + • + A

A

• A

• A A A

900,00 + + + A + + +

• A

• • A A A A A

1050. 00 + + + + A + + + A

• • • • A + A

A

• 1200.00 + + + + + A+ + + + A + • • • • • • + A

• 1350 00 + + + + • + +

• + A

h-38 A • + • • • • + • • • 1500.00 + + + + + + • + • • •

UAQ(b) SCALE FACTOR . 1.0E+Ol 4.00 4.80 5. 60 6. 40 7.20 8.00 8.80 9.60 10. 40 11.20 12.00

TII1£ ++++++++++++++++++++++~+++++++++++++++++++++++++++++++++++.++++++++++++++++++++++++++++++++++++++++++ 0.00 + + + + + + + +A + + • + A

A A

+ A A

A A

+ A A

150.00 + + + " + +

" " A A

A A

A A

A 300. 00 + + + + A

" A

" + A A

" A A

" 450_00 + + " " " + " " " A

" " A 600. 00 + + + + + + " +

A

" " " " " " • " A 750_00 + + + + A +

" " " " A

" A A A

900.00 + + + + " A

" " " " " A

" " 1050.00 + + + + " +

" " A A

" " A

" A 1200 00 + + + " +

" " " A A

" + A + A

" 1350_ 00 + + + + + + + + " +

" " • • " h-39 " A

" " A 1500.00 + + + + + + + + " +

UAG{I L I :; 4, !t .5. 00 5 30 5. 60 b.20 b,50 6.80 7,10

SCALE FACTOR = 1 OE+02 7.40 7.70 8.00

TIME +-++++++ ... +++++++++ ......... -+++ ... +++++++ ... +++ ... +++++++++ ... ++++++++++++_;.+++++++++++++++++t-+++++++++++++++++++++++ o 00 A + B + + + + +

• B A B A B A B A B A B A B A B A B

150.00 A + B + +

• B • B A B A B A B A B A B A B A B

300. 00 A -+ B A B A B A B A B A B A A A A

450. 00 A A A A A A A A A A

600 OC A A A A A A A A

A A

750 00 A

A A A

A A A

A A A

900 GG A A A A A A A A

A A

1050 ijl"j ,..

A

A A

A A A A A A

1200 0') A A A A A A A

A

A

A 1350 00 A

A A A A A A A A A

1500 00 A

B B B B

B B B B B B B B B

• + •

• B B B

• B B B B

+ B B

• • B

• • • B B

+ B

• B B B B

• • B B B

• • B B B B B B B

+ B B B B B

• B B B B

+ B

h-40

" 9 9 9 B B

+ B

+

+

+

+

+

•

•

•

•

•

•

UAG(3) C 60 072 O. 84 0.'16 1. 08

SCALE FACTOR = 1 OE+02 1. 20 1. 32 1.44 1.56 1.68 180

TIME ++++++++++++++++++~++++~+++++++++++~++++++++++~++~++++++++?~++~++~+++++++++++~+++++++++++++++++++++++ 0.00 + + + A

+ •

• A

• A A A

• A A

150 00 + + + A A

+ A A A A

• A A

• 300 00 + + A

A

A A A A A A A A

450 0') .. A A A A A A A A A A

600 00 + + A A A

A

A A A A A A

750 00 .. A A A A A A A A A A

qOO Ou .. A A

A A A A

• A A A

1050 G-: + A A A A A A A A A A

1200 00 + A A A A A

• A A

• A

1'350 O'J .. A A A

• A h-41 A A A A A

l~OO 00 + + A

JAG<.2) o 30 .} 45 o 7S 0_ 90 1. 05 1 20 t.35

SCALE FACTOR = ~ 0E+02 1.50 1.65 1 eo

TIME +++++++ ... + .... +++++++..-.,. ~+++++++++++-++~ .. -++++++++++-+++-tt+++++++++..,.- ....... ++ .. +++ ... +++++7++-... +++++++ .. ++ .. +++ .. +++ -+- ++++ 0_ r):) + + + " +

" " " " " " A A A

150_00 .... +A + A

A A A

A A

A A A

300 0(~ .... A A

A

" A A

" " " A 450 (L A

A A A A A

• Ii A

A

600 A A A A A A A A

A A A A

" A

A A A

A

900 A

A

A

A

A

A A A

A

1050 A

A

"-A

A

A

A A A A

l~OO G·:' A A A

" " " " A

" • 1'35C O~- ... A +

" • " h-42 A A

" " • , 1500 Or: .... + A +

•

•

•

•

•

UAQ( 1) o 3D o. 45 0.60 O. 75 O. 90

SCALE FACTOR • 1 OE~02 1. 05 I 20 1.35 1.50 1.63 1.80

T[ME +++.+++++++++++++~+~+++++++++++++++~++++++++++++++++++++++~++++++++++++++++++++++++++++++++++++++++++ 0.00 + + + + A + +

A

• " . • A

• • • A 150.00 ... +A + +

A A

A A

A A

A A

A 300. 00 + + A + +

A A A

• A

A

• • A

450 OC· + A +

• • A A A

A A

• A

600 00 ... + • • • • • A A A A A

750 0,) ... + A A

• A A A A

• A A

• ao 00 ... A

A A

• A A A A A A

1050 Z' ... A

• • • A A A A A A

1200 00 ... A A A A A

A

• A A A

1350 O,} ~ + + + A + A

• • • h-43 • • A

• • 1'0000 + + + + + • +

.AG{35J SCALE FACTOR : • QE+02 -250 -;:00 -1_ S0 - I. ,J(; -0_ 50 o 00 o 50 1 00 1. 50 2. 00 2 50

T[ME .~+~++~~+~-~++~++~ "~+++~+++~TT~+~~_T~T++++++++++++++++++++T~·++++++++++++++.+++++++++++++++++++++++++ o O:~- A +

A

A A

1-5G 'j .. '

" A

~

" 300 '-'"-.<

"-

60G

" 13'50 "

" "

h-44

"-1 ';00 I).:

+

•

•

T[Mt:: 0.0')

150 01)

300. OC-

450 (J':

600 ,::;-

• 750 v,j

900 0,:

10'30 0<:'

1200 '.1'.)

1350 O,j

• 1500 00

AC(;:(3) -2 50 -2.00 -1.50 -1 00 -0. 50 0.00 0. 50 1. 00

SCALE FACTOR = 1. 50 2. 00

OE-+-02 2. ~O

+"'t.-+- ... ++..,..,. ... +++++++..,. ... +++++ ... +++-+ +-+-+++++-.. +++++++++ "'-1"-"+'" +++++ ... ++.,...:. ++++ ..... +++++-+++++++ t+++++++++++++++++++++++ . A A

A A

A A

A A

A A . A + + A

A A

A A

A + A +

A A

A A

" A A

A A

A A

A A

A

A A

A A

A A

A A

A A

A

A

A +A A

A A

A

A

A

" . +A

A A A

A A

A A . A

A

A A

A A

A + A

A A

A A

A A

A A

+A + A

A A

• • h-45 A

• • • + A +

ACE (;2) -2 50 -,2 00 -1 50 -1 00 -0.50

SCALE FACTOR = 1. OE+Co2 O. 00 O. 50 1. 00 1.50 2.00 2.50

T I ME +++-++-+ ...... + ... + -jo+++ +-++ ,'- ... +-t ... -+ ++-+--++ + -jo ... -t -r- 0/- of"++ -+-++-+++ ... -+- ++++++++++ ++-.1- ++_-t +++++++++++ ++ j-+++++-+-+++-+-++++++++-+-++++ ,) OC ... + + A + +

A

A

A

A A

A 150.0·)+ A +

A A A A A A A A A

300 0':: .. +A +

A

A

450 O·~' + A A

A

A A

A 600 ,:)<. A +

A

A A A A

A 750 Ij} +A

A

A A ;-

A A

A

A A

900 C..: A.

A A A

A

A A

1050 ,:;.-, A+

A A A

A A A

A 1200 C<;. . A+

A

A A

A

A A

135Co DC. A . A

h-46 A

A A A

A 1500 00 . A+ +

•

•

ACE(l) -2 50 -2.00 -1.50 -1. 00 -0. ~O

SCALE FACTOR u 1 OE+02 0.00 o. ~O 1.00 1. 50 2. 00 2 ~O

TIME ++ + t++ ++ t+ ++-.+ +++ .. +-+ ++++ +++++++ .. ++++++++++++++++++++++++.+-+-..... + ... ++of +++++++++++++++++++++++++++++++-t+++ o GO + A + +

A A

A

A A

A 150 ,)G + A

A A

A A

A A

A

A

A

300.00 .. A + A

A A

A A A

A A

A 4'30 0":) -+ A

A A A

A

" A A

A A

600 .'_ .. A A

" A A

A A

A

A A

A

A

A A

A

A

A A

A

A

A

A A

A A

A

A

A

A A

A

A A

A

A

A

1200 0: A

A A

A

A A

A

A A

A

\350 0': + A

A A h-47 A

A A

A A A

" 1500 00 + A

eo -0. 20 -0. 12 -0. 08 -D. 04

SCALE FACTOR '" ~ OE-Gl o 00 0. DB o. 12 O. Ie 0 20

TIME +++ .. ++ ....... + ... +++ .. ++ ........ ++++++++++++++ .. + ....... ++++++ .... -. ...... ++++++ + ... ++ ... ~+++++-t+++++++++++ .. +++++++++++++++++++++++ A G IX- +

A

A A

A A

A A

A 150 0~ +

A A

A A

A

A

A A

300 A + A

A A

A A

A

A A

A A

A A

A A

A A

A A A

_[')0 A . A

A A

A

A

A A

A< A

A A

A A

A

A+

A A

A

A A

A A

A

A .. A A

A A

A A A

A < A

A A

A A

A A

A A

A

1 :;-=:-c A

A A

A A h-48 A

A A

A A

1 '500 O·} A

• LOAD(3'

~"f 50 40 00 40. 5C 41- 0'30 41. 50 42. 00 43. 00 SCALE FACTOR = 1 OE+;)3

43. 50 44. 00 44 50

TIM'::: +++ ~+++ .. -;--++++-f -!- +--+ .. -, ++ ..... + .... ++++.~++++..-+ ... of++++ ... ..,. .. t- ... +++++...-+t-+...--... +++-+-+++++++++++++ ~+ ... +++ ... +++++++++++...-"'++++-+ + + o O:} ...

:;oc

A A

A A A

A A

A {, ., .. ;.

k

A A A

{,

+

A A •

A

• A

"

A

A

+

h-49

LOAD{:;n 12.00 12.90 13. 60 14.40 15. :20 16.00 J6.BO 17.60

SCALE FACTOR ~ 1 OE+O~ 18.40 lQ.20 20.00

TIME +++1>++ .... +++++++++ •• ++++++.++++++++++++++++++++++++++++++++-... +++ .. +++++++++++++~+++++++++++++++++++++++ O. 00 + + A + + + + + +

A

+

+

150.00 +

+

300.00 + +

450.01) + +

+

600 00 -+

150. 00

qOO 00 +

1050 00 -+

1200. CO- -+

1350 00 -+

1500.00 + +

A A

A

•

• • • A

A + A A A

A A

A A

A

• A +

• A

• A

A A

• A A A+

A A

A A A

A A A A A A A A

A A A A A

A A A

A A A

• • • • A

+ •

• A

• A

• • • • • + •

• • • • • A

• • • •

• + •

A

• • • • • • • A A

A

• • • • • • • •

+ +

+ +

+

h-5°

+

•

uJADll, is. 00 1580 16.60 1 i' ... 0 18. 20

SCALE- FACTOR ~ : OE~,:2

19. 00 19.BC 20.60 21.40 22.20 2300

T T ME +++ t+++++++++++++ ...... , ++++++++++++++++++++++++++ .... ~ +++++++++-+-+ ... +++-+ +++-+-+++++++++ ~+++++++ ... +++ ... +++++++++++ O. 00 -+ A + + + +

A A

+ A A

A A

A A +

A

+ + 150.00 + + +

• A A

A A A

A A

300 ao + + + A + A

+

• A A A

+ A

• A A A

• 450.00

A

• • • • • A

bOO GO ... A

;,

A ;, A A , A A

A A

A

+ 750 0;] -+

A

• A A

A A A

A

+ A A

900 00 ... +

A A

A A

A

+ • . + 1050 00 ..

1200 OC -+ ..

A

A A

1350 00 -+ •• • + A

• A

h-51,52. A A

l~OO 00 .. • A

GENERAL REPORTS DISTRIBUTION SYSTEMS PROJECTS

DISTRIBUTION:

R. H. Annan (25) US Department of Energy Forrestal Bldg. 1000 Independence Ave. washington, DC 20585 Attn: M. B. prince

V. N. Rice A. D. Krantz L. Herwig

US Department of Energy

SW

A. Bulawka M. pulscak S. J. Taylor

Attn: Robert D. Jordan, Director Division of Active Heating and Cooling Office of Solar Applications for Bldgs. Washington, DC 20585

US Department of Energy Attn: Michael D. Maybaum, Director Division of passive and Hybrid Office of Solar Applications Washington, DC 20585

Jet Propulsion Laboratory 4800 Oak Grove Drive Pasadena, CA 91103 Attn: R. V. Powell ( 4 )

R. Ferber K. Volkmer W. Callaghan R. Ross R. S. Sugimura S. Krauthamer A. Lawson E. S. Davis

Jet propulsion Laboratory Solar Data center MS 502-414 4800 Oak Grove Drive Pasadena, CA 91103

SERI, Library (2) 1536 Cole Boulevard Bldg. #4 Golden, CO 80401

( 15)

Dist 1

SERI (3) 1617 cole Blvd. Golden, CO 80401 Attn: Walter Short

R. DeBlasio

Center Florida Solar Energy 300 State Road 401 Cape Canaveral, FL Attn: Henry Healey

32920

EPRI P. O. Box 10412 Palo Alto, CA 94303 Attn: Roger Taylor

House Science and Technology Room 374-B Rayburn Building Washington, DC 20515

Energy Laboratory 711 Virginia Rd. Concord, MA 01742 Attn: M. Russell

E. C. Kern

Office of Technology Assessment U. S. Congress Washington, DC 20510

New Mexico Solar Energy Inst. (3) New Mexico State University Attn: J. F. Schaefer P. O. Box 380L Las Cruces, NM 88003

Aerospace Corporation (2) Attn: S. Leonard

E. J. Simburger P. O. BOl{ 92957 LOS Angeles, CA 90009

Alternative Sources of Energy Attn: Larry Stoiaken Milaca, MN 56353

Arco Solar, Inc. Attn: J. Arnett 20542 Plummer Ave. chatsworth, CA 91311

california Energy Commission Attn: E. Quiroz 1111 Howe Avenue Sacramento, CA 95825

Carbone Investment & Management Corp. Attn: Mr. Robert C. Carbone 570 Dwight Place Berkeley, CA 94704

General Electric Co. Attn: E. M.Mehalick Advanced Energy programs P. O. Box 8661 Philadelphia, PA 19101

Georgia Institute of Technology Attn: S. I. Firstman Ccllege of Engineering Atlanta, GA 30332

Hirst COmDA.ny Attn: Mr. Carrol cagle P. O. Drawer 1926 Albuquerque, NM 87103

M3SS Design Attn: Gordon Tully 138 Mt. Auburn St. Ca~bridqe, MA 02138

RAymond J. 8ahm 2513 Kimberley Ct. NW Albllquerque, NM 87120

solarex Corporation Attn: Marth Bozman 1335 Piccard Drive Rockville, MD 20850

Dist 2

Sandia National Laboratories: 2525 R. P. Clark 6200 V. L. Dugan 6220 D. G. Schueler 6221 M. K. Fuentes 6221 T. D. Harrison 6221 D. F. Menicucci 6221 M. G. Thomas (25) 6223 D. Chu 6223 G. J. Jones 6223 T. S. Key 6223 H. N. Post 6223 J. W. Stevens 6224 D. E. Arvizu 6224 E. C. Boes 6224 M. W. Edenburn 6224 A. B. Maish 6224 R. B. Siegel 3141 L. J. Erickson (5) 3151 W. L. Garner (3) 8214 M. A. Pound 3154-3 C. H. Dalin (25)

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