NEW THERMAL TURBINE GOVERNOR
MODELING FOR THE WECC
Les Pereira (Chairman)
John Undrill
Dmitry Kosterev
Donald Davies
Shawn Patterson
Principal Investigator: Les Pereira
WECC Modeling & Validation Work Group
October 11, 2002
(Revised)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
2
TABLE OF CONTENTS.
SUMMARY
Recommendations
2
3
NEW THERMAL TURBINE GOVERNOR MODELING FOR THE WECC
Introduction
New Thermal Governor Modeling for Thermal and Gas Units
Approach
3-Step Process for Development, Validation and Verification of the New Governor
Model
New Models for Units without Governor and Excitation System Models
Ggov1 Governor Model Data Submittal by Owners – Workshop
Hydro Governors
Major System Impacts and System Responses from the New Governor Modeling
Further Work
Figures 1 to 8
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5
5
5
7
8
8
8
9
10
11
APPENDIX 1 – THE GE GGOV1 MODEL
17
APPENDIX 2 - METHODOLOGY BASED UPON RECORDED RESPONSES OF
THERMAL UNITS - MAY 18, 2001 TEST - NW TRIP 1250 MW
23
APPENDIX 3 - HYDRO TURBINE-GOVERNOR MODELING
35
APPENDIX 4 – GUIDELINES FOR THERMAL GOVERNOR MODEL DATA
SELECTION, VALIDATION, AND SUBMITTAL TO WECC
47
APPENDIX 5 - EFFECTS OF GOVERNOR MODELING UPON OSCILLATORY
DYNAMICS IN SIMULATION OF THE 750 MW GRAND COULEE GENERATION TRIP
ON JUNE 7, 2000
65
APPENDIX 6 - MODELS IN THE WECC 2006HS2SA BASECASE
.
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New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
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NEW THERMAL TURBINE GOVERNOR MODELING
FOR THE WECC
Summary
This report summarizes the work performed in the development, validation and verification of
a new thermal turbine governor model, the GE ggov1 model, for the WECC. The ggov1
model, referenced in the report is a generic thermal governor/turbine model that incorporates
base loading and a load controller. Additionally, a load controller model has been developed
by GE. The model, lcfb1, is identical in structure to the load controller portion of ggov1, and
can be used in tandem with any governor model currently defined in the GE PSLF program.
(See Appendix 1 of the report for details of the ggov1 and lcfb1 models.) Thermal plants
embraces conventional fired steam, nuclear steam, simple cycle gas turbine, and combined
cycle gas turbine plants. The new ggov1 thermal model, or the existing thermal model plus the
lcfb1 load controller, is recommended for use in all planning and operation studies in the
WECC.
Simulations of real time events including staged and random generator trips in the WECC have
indicated that there is a wide difference in the frequency response between simulations and that
recorded by disturbance monitoring equipment. Differences of the order of 50% to 60% have
been noted in both transient peaks and “settling” frequencies. Generator trip tests performed on
May 18th 2001 with all AGCs in the system switched off indicated that only 40% of the
expected governor response in the system occurred in the settling time of 60 seconds.
Based on the generator and system responses in this test recorded by SCADA and disturbance
monitoring equipment, a new governor modeling approach using the GE ggov1 model has
been developed for the WECC. This new modeling approach represents both the governing
action that is generally regarded as the primary control function in most power plants and, in
addition, represents the principles of the power plant controls that are very often of greater
importance in relation to post-transient conditions.
With the ggov1 model1 applied at every thermal generating plant, the new modeling approach
aims to recognize the effects of the basic control elements and operating practices of each
plant, though not the internal details of these aspects of the plants. This is done by setting the
parameters of the ggov1 model according to a simple assignment of each plant to one of a set
of predefined categories. These categories are based on generally known main variations of
steam plant and gas turbine plant control practices. Individual plants are assigned to these
categories empirically on the basis of their behavior as observed in recent system events, in
testing, or both. The parameters used in the ggov1 model, therefore, are not based on specific
internal design details of the plants but on its observed behavioral characteristics. All thermal
and gas turbine units that have demonstrated “unresponsive” characteristics as base loaded
units under load-controller or load limit control are initialized at the generator dispatch level at
1
Appendix 1 illustrates the equivalence of the ggov1 model with internal controller and the appropriate external
lcfb1 controller application with ggov1 (or ieeeg1) models.for thermal units. The report is written based on the
original studies.using the ggov1 model.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
4
the start of each dynamic simulation run. Characteristically similar responses were noted for a
large number of units in the evaluation of the May 18th 2001 system test recordings. These
were categorized under several distinct “response” categories and governor codes, T1 to T3 for
thermal units, and, G1 to G2 for gas turbines, were developed to represent these governors.
The governor modeling effort followed a 3-step process of Development, Validation and
Verification. “Development” of the modeling was based on the recorded responses of the
system and individual generating units during the 1250 MW Northwest Trip Test of May 18th
2001. “Validation” of the model was performed based on the recorded responses of the May
18th 2001 Hoover 750 MW trip test and the June 7th 2000 Coulee 750 MW trip test.
“Verification” of the model was performed by comparing simulations with recordings of
several other system disturbances including the Colstrip 2000 MW trip on Aug.1, 2001, Diablo
950 MW trip on June 3, 2002, and the PDCI bipole trip and 2800 MW RAS in the Northwest
on June 6, 2002. Figures 1 to 8 show plots of these simulations.
The improved modeling of thermal plant response results in reduced overall contribution of
thermal plants to the correction of frequency and a corresponding increase in the contribution
from hydro plants. Because the thermal plants are predominantly in the South, and hydro plants
in the North, this redistribution of plant response has a significant in effect in power flows
across the system, particularly in intertie flows between the North and the South. Hydro
governors and their proper modeling thus play a very important part in the overall simulation
of the system for large disturbances. Improvement in nonlinear hydro governor modeling and
introduction of Kaplan models are recommended.
It was clear as the validation study progressed, that accurate simulation of the events required
the introduction of governor and exciter models for the numerous units without such models.
Typical ggov1 governor models and exst4b exciter models with assumed data were included
for all such units.
The data assumed in the simulations was for the purposes of development, validation and
verification of the new thermal/gas turbine governor model. In accordance with current WECC
policy, the generator owner has the responsibility to provide appropriate modeling data for
their units. The data to be used by WECC in the application of the new thermal/gas turbine
ggov1model should be submitted by the generator owners/control area for each unit. A
workshop will be held to explain to WECC members and generator owners the details of the
new governor model, methodology and data assumed for modeling, and the requirements from
generator owners to verify/refine their model data. All generator owners shall provide a
validation of their selected governor model data by submitting recordings of their generator
responses during system disturbances2 or tests.
Recommendations
M&VWG recommends the new GE ggov1 model to replace all gas turbine governor
models currently in use and to model any currently un-modeled thermal governors. For all
2
Disturbance monitoring equipment recordings are desirable; however high-resolution SCADA (4 seconds or
less, 2 seconds preferred) or data logger recordings are also acceptable.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
generators with load controllers, load controller effects shall be modeled. Currently this
can be accomplished by adding the new GE lcfb1 model. Additionally, M&VWG
recommends that the baseload flag be used to indicate base-loaded or load-limited
generators that cannot respond to increase generation during deviations arising from
generation loss in the system3. The data to be used in the application of the new models
should be submitted by the generator owner for each unit. Recordings of the generator
responses during disturbances or tests shall be submitted as validation for their selected
governor model data. Details of the new governor model, methodology and data
requirements for modeling will be described in a data request letter. Nonlinear modeling of
existing hydro governor and introduction of Kaplan models is also recommended.
Accurate simulation of the system frequency response required the introduction of new
governor and exciter models for the numerous units that do not have models and data.
Owners shall submit the new governor and exciter models for all such units. This
recommendation supersedes the previous recommendation to “block” all governors for
units greater than 150 MW and loaded 90% and above.
3
Note that these units are not “blocked” (ie status equal to zero) in the GE PSLF program.
5
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
6
NEW THERMAL TURBINE GOVERNOR MODELING FOR THE WECC
Introduction
Simulations of real time events including staged and random generator trips in the WECC have
indicated that there is a wide difference in the frequency response between simulations and that
recorded by disturbance monitoring equipment. Differences of the order of 50% to 60% have
been noted in both transient peaks and “settling” frequencies. Governor and load modeling
issues were highlighted in previous work during 2000 by the Task Force of the WECC’s
Modeling & Validation Work Group (M&VWG) for further investigation.
In early 2001, the WECC proposed new criteria to meet the new NERC policies for Frequency
Responsive Reserves (FRR). The new proposed policy, NERC Policy 1C, specifies the
minimum MW component of FRR that should be achievable in 60 seconds. Governor
responses to system frequency deviations during generator trips were thus central to the new
requirements and proper governor modeling again became a critical issue.
Frequency response tests were performed on May 18th 2001 to determine the response of
governors throughout the system. In these tests, 750 MW was tripped at the Hoover power
plant in the Southwest; and in a second test 20 minutes later, 1250MW was tripped in the
Northwest. All AGCs in the system were switched off throughout the system test, and
therefore the pickup of generation in the system was due entirely to governor action.
The tests performed on May 18th 2002 indicated that only 40% of the expected governor
response in the system occured in the ‘settling’ time of 60 seconds. However existing modeling
assumes that 100% of governors respond in accordance with the 5% speed droop governor
characteristic. As a result, there is a significant difference between simulations and actual
recorded system responses. The principal reason for this large discrepancy between simulations
and the recorded system frequency response is that base loaded generators (load limiter or load
controller operation), of primarily thermal and gas units, are not modeled with such limits in
output. Other affects such as non-linear gate movement, dead band etc play a part in modeling,
but have a relatively minor impact. In the modeling of governors, the base-load operation of
units is clearly the dominant effect.
New Governor Modeling for Thermal and Gas Turbine Units
Approach
The new governor modeling approach correctly represents all thermal turbine units that have
demonstrated unresponsive characteristics as “base loaded” units under load-controller or load
limit control. Initializing at the base loaded dispatch level for such units has to be done at the
start of each dynamic simulation run. Thermal plants embraces conventional fired steam,
nuclear steam, simple cycle gas turbine, and combined cycle gas turbine plants.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
7
Fig.1 shows the differences in pickup of a typical thermal unit using the existing modeling and
the new governor modeling. SCADA response of the unit on the May 18th 2001 NW Trip Test
is also shown4. The figure clearly demonstrates how the existing modeling (base case
simulation) of the unit is overly optimistic and far different from the real time operation
response of the unit.
Fig.1 Showing the Differences in Simulations using the Existing Model and the New ggov1 Model for
Governors
The new model (the GE ggov1 model) is described in Appendix 1. The model data used
in the development of the new governor model for each unit is based on the recorded
generator and system responses from SCADA and monitoring equipment obtained during
the May 18th 2001 system tests. Over 200 SCADA response recordings of generator
electrical power were evaluated from the May 18th 2001 system test recordings5.
Characteristically similar responses were noted for a large number of units in this
evaluation. These were categorized under six “response” categories coded T1 to T6 for
thermal units and G1 to G3 for gas turbine units depicting “responsiveness” or
“unresponsiveness” in varying degrees. These governor codes were later simplified to T1
to T3 and G1 to G2 which are the recommended codes. A discussion of the methodology
is included in Appendix 2. Data for the governor codes is given in Table 1 of Appendix 2.
Additionally, a load controller model has been developed by GE. The model, lcfb1, is
identical in structure to the load controller portion of ggov1, and can be used in tandem
with any governor model currently defined in the GE PSLF program. (See Appendix 1 of
the report for details of the ggov1 and lcfb1 models.)
4
It should be noted that the SCADA recordings are of generator electrical power. The resolution of SCADA is at
4 sec intervals and the recordings do not show the detailed electrical power swings as seen in the simulations, but
do show the general response of the unit.
5
Additionally, the CAISO provided data of generator SCADA recordings for other disturbance events that were
used in the model development. Where SCADA data was not available for a specific unit, the information
provided by owners/control areas regarding the base loading or responsiveness of their units was utilized in
selection of theturbine-governor codes.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
In the May 18th Test basecase, 345 existing “ieeeg1’ thermal governor models were
converted to the new ggov1 model with a total MWcap of 73,455 MW. Also 78 existing
“gast” gas turbine governor models with a total MWcap of 8846 MW were converted to
the new ggov1 model.
This recommendation for the new thermal governor model supersedes the previous
recommendation to “block6” all governors for thermal units greater than 150 MW and
loaded 90% and above.
The improved modeling of thermal plant response results in reduced overall contribution
of thermal plants to the correction of frequency and a corresponding increase in the
contribution from hydro plants. Because the thermal plants are predominantly in the South,
and hydro plants in the North, this redistribution of plant response has a significant effect
on power flows across the system, particularly in intertie flows between the North and the
South. Hydro governors and their proper modeling thus play a very important part in the
overall simulation of the system for large disturbances. Improvement in non-linear hydro
governor modeling and introduction of Kaplan models are recommended.
3-Step Process for Development, Validation and Verification of the New Governor
Model
The governor modeling effort followed a 3-step process of Development, Validation and
Verification. “Development” of the modeling was based on the recorded responses of the
system and individual generating units during the 1250 MW Northwest Trip Test of May
18th 2001. “Validation” of the model was performed based on the recorded responses of
the May 18th 2001 Hoover 750 MW trip test and the June 7th 2000 Coulee 750 MW trip
test. “Verification” of the model was performed by comparing simulations with
recordings of several other system disturbances including the Colstrip 2000 MW trip on
Aug.1, 2001, Diablo 950 MW trip on June 3, 2002, PDCI bipole trip and 2800 MW RAS
in the Northwest on June 6, 2002 and several other disturbances. The results of the
simulations compared with real time event recordings are shown in Figures 3 to 8.
The principal differences between the simulations of the two “validation” tests of May 18th
2001 and the random system disturbance recordings were that in the May 18th 2001 test (a)
AGC was switched off to yield pure governor responses of units, (b) simultaneous
SCADA and disturbance monitor recordings were obtained from all control areas, and (c)
generator dispatch and power system data were gathered to create the “base cases” to
simulate the staged events and recordings more accurately.
It should be noted that the SCADA recordings are of generator electrical power and
therefore include the effects of the system network voltages and generator excitation
system responses. The characteristic initial peak noted in the response at the start of the
response is purely inertial. The generating unit mechanical power responses (not recorded
6
Governor “blocking” was an “interim” recommendation by the M&VWG in 1997 to address the noted
deficiency in the frequency response of the system caused by incorrect modeling of thermal/gas governors.
Governors were “blocked” for thermal/gas units greater or equal to 150 MW and loaded at 90% and above.
8
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
9
by SCADA) vary according to the complex dynamics primarily of the boiler system and as
affected by the base load operation of the units.
New Models for Units without Governor and Excitation System Models
It was clear as the validation study progressed, that accurate simulation of the events
required the introduction of governor and exciter models for the numerous units without
such models. Typical ggov1 governor models and exst4b exciter models were included for
all such units with ratings greater or equal to 5 MW. The selection of the governor model
parameters for these units was made based on recorded responses where available. For all
other units, typical data was assumed. (Note: SCADA recordings included only generator
electrical power responses and no information or recorded exciter responses were
available.)
In the May 18th Test basecase, 485 new “ggov1” governor models were added for units
greater than 5 MW with existing exciter models totaling 28,675 MVA. 265 new “exst4”
exciter and “ggov1”governor models were added to the data base totaling 8671 MVA for
units greater than 5 MW that did not have governor or exciter models.
Ggov1 Governor Model Data Submittal by Owners - Workshop
The data assumed in the simulations was for the purposes of development, validation and
verification of the new thermal/gas turbine governor modeling approach. In accordance
with current WECC policy, the generator owner has the responsibility to provide
appropriate modeling data for their units. The data assumed for the governor models in the
development of the model should be verified/refined by the generator owners/control area.
A Workshop was held to explain to WECC members and generator owners the details of
the new governor model, methodology and data assumed for modeling, and the
requirements from generator owners to verify/refine their model data. All generator
owners shall provide a validation of their selected governor model data by submitting
recordings of their generator responses during system disturbances7 or tests.
Hydro Governors
The following are the conclusions concerning hydro turbine governors:
1. Hydro units are very responsive to frequency deviations. Complete response, however,
typically takes from 15 to 90 seconds. On average, a hydro governor will have completed about
two-thirds of its response after 60 seconds. Only a fraction of a typical hydro units response is
completed in the first 10 seconds.
2. Since the pick up of frequency responsive governors, such as hydro units, will increase with
the magnitude of the frequency deviation, to properly simulate these governors requires that
7
Disturbance monitoring equipment recordings are desirable; however high-resolution SCADA or data logger
recordings are also acceptable.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
10
the system frequency response to a disturbance in the simulation is correct. Hence the new
thermal/gas ggov1 model simulations will result in more accurate hydro simulations.
3. The impact of hydro responses and its correct simulation is very important to the overall
system frequency response. More accurate hydro modeling is recommended as follows:
a. Controllers (plant controls, AGC, etc.) may readjust governor set points before a
hydro governor completes its response. These need to be modeled properly for
simulations up to 60 seconds (FRR).
b. Kaplan (adjustable blade) turbines are not represented correctly with the
existing models. Kaplan turbines account for approximately 14,000 MW of
generating capacity on lower-, mid-Columbia and lower Snake dams. Studies
indicate that existing models grossly over-represent governor response in first
10 seconds.
c. Nonlinear turbine gain effects can have a noticeable impact on the amount of
response of a hydro unit and should be included in the models.
d. Modeling hydro governors correctly for all units that do not have such models
presently.
e. The amount of hydro response is dependent on the load level of the generator;
therefore power flow representation of hydro plants must be realistic.
4. The gross mismatch between actual under-frequency events and simulation results is
primarily due to incorrect thermal/gas governor modeling. Correction of thermal plant
modeling increases the relative contribution of hydro plants to the correction of frequency.
Therefore, it becomes equally important to ensure the comprehensiveness and accuracy of
hydro governor modeling.
5. A detailed report on hydro governor studies is presented in Appendix 3.
Major System Impacts and System Responses from the New Thermal Turbine Governor
Modeling
A large number of studies were performed in the development, validation and verification of
the new thermal governor modeling which clearly revealed the impacts of the new modeling
approach on simulations of the WECC system.
The following are the expected impacts on major system operation and planning studies using
the new thermal governor modeling based on findings from the studies already performed:
−
−
−
−
We can clearly predict more accurately the system frequency response for large
generation trips
The new model will provide more accurate studies on the effect on the system of
large RAS operation
Improved hydro plant simulations that directly result from the improved thermal
governor modeling : the studies indicate greater pick up by hydro units with the
improved thermal governor modeling
It provides a more accurate prediction of Intertie flows – eg COI
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
−
11
Comparison of Hydro Vs Thermal generation responses, North Vs South reserves is
facilitated
Provides a better assessment of system oscillations and damping
−
The following operation and planning studies are expected to benefit from the use of the
new thermal governor model:
−
−
−
More accurate assessment of dynamic and transient stability
More accurate assessment of dynamic voltage stability
Accurate prediction of Intertie flows – eg COI and potential COI capacity
limitations
−
Comparison of Hydro Vs Thermal generation responses, North Vs South reserves
is facilitated
−
Underfrequency and load shedding studies involving large generation trips or
system islanding
−
Large RAS effects on system security
−
Study of oscillations and damping.
−
PSS Studies
−
Provides the basis for establishing a more accurate post-transient powerflow
methodology for studies involving large generation or load trips
The new governor model will facilitate the study of FRR and spinning reserves.
Further Work
Further work on governor modeling is anticipated in the following areas:
1. Perform validation studies after obtaining data from generator owners for the new
ggov1 thermal governor model.
2. Obtain and audit data from owners for governor and exciter models for the
numerous units without such models for which typical ggov1 governor models and
exst4b exciter models were included in the validation studies performed.
3. Include Kaplan hydro governor models and non-linear hydro modeling.
4. For studies extending to long periods such as for system oscillations and dynamic
voltage stability, it is important to model Automatic Generation Control (AGC)8.
8
A brief discussion on the application of AGC signals is provided in Appendix 1.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Model Development, Validation and Verification
Development of Model
Based on May 18th 2001 NW 1250 MW Trip Test Case
Validation - Hoover Test 750 MW, May 18th 2001
Coulee 750MW Trip, June 7th 2000
Verification - System Disturbances
- Colstrip 2000MW Trip, August 1, 2001
- Diablo 950 MW trip, June 3, 2002
- PDCI Bipole Trip and NW 2800 MW RAS, June 6, 2002
Fig. 1 Block Diagram showing Model Development, Validation and Verification of the New Governor
Modeling
12
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
13
Block Diagram of General Methodology
Existing
Convert existing ieeeg1 models to ggov1
Models
Convert
*input list
has both
existing gast models to ggov1
Add New Models
Exciters and Governors
a) Thermal and Gas units
b) Hydro units
Create Input List and
Unit "Codes" for Unit
Responses
New Database
Run Initialization for
baseload operation
of ggov1 models
Run Stability Studies
Fig.2
Block Diagram of General Methodology
Add
"AGC"
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig.3 Figure showing the final validated modeling after converting ieeeg1and gast models to the new ggov1
model and adding new governor and excitation models (1113 total)
14
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig.4 (above) Hoover 750 MW trip on May 18th 2001
Fig.5 (below) 750 MW Coulee Trip test on June 7th 2000
15
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig. 6. June 3, 2002 Diablo 950 MW trip
Fig. 7 Colstrip 2000 MW Trip on August 1, 2001
16
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig. 8 PDCI Bipole Trip and NW RAS 2800 MW Trip on June 6, 2002
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New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
APPENDIX 1
THE GE GGOV1 MODEL FOR THERMAL
TURBINE-GOVERNOR CONTROL
AND THE LCFB1 LOAD CONTROLLER MODEL
18
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
19
APPENDIX 1A
USE OF GGOV1 POWER PLANT CONTROL MODEL
John Undrill
General Electric
July 2002
1. Summary
Comparison of simulation results with recorded frequency transients in recent generation-trip
tests and contingency events have shown the existing WECC approach to the modeling of
governing to:
−
understate the frequency dip caused by the trip of a large generator
−
overstate the overall power increase contribution of thermal plants and understate
that of hydro plants
This leads to a general loss of confidence in the ability of simulations to properly indicate the
post-transient distribution of generator outputs and, therefore, of post-transient transmission
system loadings.
There are many possible explanations for these discrepancies. Among
the many:
a) while governor action is generally assumed to be the predominant control effect in
power plants, only about one half of the running capacity has active governors, with the
remainder having control valves either unable to move or under manual control.
b) governor action is present in many plants but is slow to occur and thus appears to be
absent in the time span of interest
c) governor action, while present and prompt, is often countermanded by other control
actions, either immediately or within the first minute of the grid transient
The reality is undoubtedly a combination of all of these possibilities. Initial attempts in WECC
to address the issue of turbine response at the level of minimal changes in system modeling
practice have not been successful. This memorandum describes the new approach that is now
recommended for the representation of the control actions of thermal plants; thermal plants
embraces conventional fired steam, nuclear steam, simple cycle gas turbine, and combined
cycle gas turbine plants.
The new recommended approach is to use a single new model for all thermal plants except
nuclear plants. This new model, ggov1, is a simple generic representation of the plant controls,
as distinct from turbine governor, or a broad range of thermal plants. Its purpose is to represent
both the governing action that is generally regarded as the primary control function in most
power plants and, in addition, to represent the principles of the power plant controls that are
very often of greater importance in relation to post-transient conditions. It recognizes the
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
20
presence in essentially all plants of supervising control elements and managing control
elements as indicated by Figure 1.
With the ggov1 model applied at every thermal generating plant, the new modeling approach
aims to recognize the effects of the basic control elements and operating practices of each
plant, though not the internal details of these aspects of the plants. This is done by setting the
parameters of the ggov1 model according to a simple assignment of each plant to one of a set
of predefined categories. These categories are based on generally known main variations of
steam plant and gas turbine plant control practices. Individual plants are assigned to these
categories empirically on the basis of their behavior as observed in recent system events, in
testing, or both. The parameters used in the ggov1 model, therefore, are not based on specific
internal design details of the plants but, rather, are chosen to reproduce their observed
behavioral characteristics.
2. The ggov1 Model
2.1 Overview
As has been the case in the modeling of thermal turbine-generators for 50 years, the ggov1
model represents both a turbine (or engine) and its governor. As in essentially all of the older
models (such as ieeeg1), the turbine/engine model in ggov1 is not a detailed thermodynamic
treatment but is a very simple linear transfer function representation. The ggov1 model extends
the older practice by controlling this simple turbine/engine model with both the governor, a
basic representation of a supervising control, and a basic managing control.
2.2 The Governor Element
The governor in ggov1 is a proportional-integral-derivative element typical of modern practice.
It allows the droop feedback signal to be either valve position or electrical power and hence
can be used to represent either modern equipment or older mechanical-hydraulic governors.
2.3 The Supervising Element
The supervising element of ggov1 normally represents a load limit. The origin of the load limit
that this element would represent varies widely from plant to plant:
−
−
−
in gas turbines it is exhaust temperature limit
in reciprocating engine plants it might be a cylinder head temperature limit, and
exhaust temperature limit, or a turbocharger manifold pressure limit
in a steam turbine plant it is most likely a limit whose value is decided on and set
by the operator based on his intentions regarding operation of the plant (for
example, he may limit the plant output for a few hours if he is having difficulty
maintaining condenser vacuum because of trouble with a cooling water
circulating pump).
The limit level is stated in terms of turbine power by the parameter,
ldref. It is essential to note that in most cases this parameter is not a direct statement of a limit
value, but rather, is states the turbine power that corresponds to the limit. For example, in a gas
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
21
turbine, the limit is frequently imposed by a curve relating exhaust temperature to several
internal engine variables, and the corresponding limiting power varies with ambient
temperature.
That the limit setting of the supervising control is a variable and not
fixed parameter of the engine is critical. It must be recognized henceforth in grid dynamic
modeling that the setting of parameters describing operational realities is intimately related to,
and as important as, the setting of the pre-disturbance generator power dispatch.
2.4 The Load Management Element
The load management element of ggov1 is intended to represent the power controller that the
control room operator's primary interface with the turbine in many power plants. The load
controller representation of ggov1 is a reset controller that, when active, will work to regulate
the turbine power to the value of its setpoint, Pmwset.
In ggov1 this power setpoint is initialized to match the initial condition turbine power; if
Pmwset is not adjusted during a simulation the load controller will countermand the action of
the governor to return the turbine to its initial condition output.
Like all turbine governor models in the PSLF program, this model recognizes that the power
setpoint of the plant may be adjusted during the period of a grid simulation. Adjustment of the
setpoint may be a manual action of an operator or may be implemented by the receipt of
signals from a grid Automatic Generation Control (AGC) system. Depending on the vintage
and design of the AGC system and plant, adjustment of the required load may be implemented
by:
−
−
−
receipt of raise/lower pulse adjustments to the governor speed/load reference (Pref
in the PSLF program)
receipt of updated values of the governor speed/load reference (Pref in the PSLF
program)
receipt of updated values of the turbine load controller reference (Pmwset in the
ggov1 model)
Where an AGC signal is received at Pref, the load controller should be inactive (Kimw = 0 in
ggov1). Where an AGC signal is received at Pmwset, the value of Pref should not be changed.
While the proper time scale for the managing controller is slow in relation to that of the
governing and supervising loops, there is, nevertheless, a wide variation in the speed of
response of turbine load reference controllers. At the more active end of the spectrum, a load
controller may be able to completely cancel a deviation of output within as little as 30 seconds,
while a reset time of a few minutes would be common in large steam plants. The load
controllers of gas turbine plants would typically be quicker than those in large steam plants.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig. 1 Basic relationship of power plant controls to turbine control
22
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig.2– Block Diagram of the GE ggov1 model
23
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
24
APPENDIX 1B
THE LCFB1 LOAD CONTROLLER
The model, lcfb1, is identical in structure to the load controller portion of ggov1, and can be
used in tandem with any governor model currently defined in the GE PSLF program (see figure
3). Existing ieeeg1 models may be used with the addition of the lcfb1 load controller model if
it applies. Upon initialization, base-loaded units and load-controllers are assigned values in the
and lcfb1 models (similar to the ggov1model) equal to the generator dispatched value specified
in the power flow data. If the effects of a load (or any set point other than frequency) controller
are to be included, the output of the unit will be reset to the value of PMWSET. The speed at
which the resetting takes place is controlled by the value of KI in model lcfb1.
The lcfb1 load controller model represents a supervisory turbine load controller that acts to
maintain turbine power at a set value by continuous adjustment of the turbine governor speedload reference9. This model is intended to represent slow reset 'outer loop' controllers
managing the action of the turbine governor. The load reference of this supervisory load
control loop is accessible as the parameter, Pmwset. Pmwset is given a value automatically
when the model is initialized. The load controller is enabled by setting the flag, pbf, to 1, and
disabled by setting fbf to zero. The controller acts by applying a bias to the turbine-governor
speed load reference, pref. This reference is initialized in the normal manner by the turbinegovernor model.
This model recognizes the two alternative ways of specifying the turbine-governor load
reference. In models such as ggov1 and hygov, the reference is a speed setpoint. In other
models such as ieeeg1 the reference is a per unit load value.
The parameters of lcfb1 must always be set on the basis of a governor speed reference, except
for the first parameter, type, which should be set as follows:
For speed reference governors
type = 0
For load reference governors
type = 1
Lcfb1 checks the model name of the governor model to which it is applied against the above
list of load-reference governors. It issues an error message from the INIT command if the
parameter, type, is inappropriate for these models. Note that lcfb1 can be used with governors
listed below.
9
This material is from the GE PSLF program manual.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Speed
Reference
Load
Reference
Governors
Governors
hygov
ggov1
tgov1
gegt1
ieeeg3
hygov4
g2wscc
gpwscc
ieeeg1
gast
hyg3
hyst1
pidgov
tgov3
w2301
Fig. 3 Block diagram of the lcfb1 model
25
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
APPENDIX 2
THERMAL GOVERNOR MODELING PRINCIPLES
METHODOLOGY BASED UPON RECORDED RESPONSES OF
THERMAL UNITS
MAY 18, 2001 TEST - NW TRIP 1250 MW
26
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
27
METHODOLOGY BASED UPON RECORDED RESPONSES OF
THERMAL UNITS
Codes for Governor Models
The new governor modeling approach represents all thermal and gas turbine units that have
demonstrated unresponsive characteristics as “base loaded” units under load-controller or load
limit control. Initializing at the base loaded dispatch level for such units has to be done at the
start of each dynamic simulation run (See Table 1, ldref).
The model data used in the development of the new governor model (the GE ggov1 model) for
each unit is based on the recorded generator and system responses from SCADA and
monitoring equipment obtained during the May 18th 2001 system tests. Over 200 SCADA
response recordings of generator electrical power were evaluated from the May 18th 2001
system test recordings10. Characteristically similar responses were noted for a large number of
units in this evaluation. These were categorized under six “response” categories coded T1 to
T6 for thermal units and G1 to G3 for gas turbine units depicting “responsiveness” or
“unresponsiveness” in varying degrees. These governor codes were later simplified to T1 to
T3 and G1 to G2, which are the recommended codes shown in Table 1.
Figs. 1 to 5 shows the SCADA responses of typical units in the May 18th 2001 Test. Typical
simulations are shown in Figs. 6 to 8. Fig. 9 shows sensitivity studies illustrating the effect of
varying the code selections.
Data Submittal by Owners
The data (Codes T1 to T3 and G1 to G2) assumed in the simulations was for the purposes of
development, validation and verification of the new thermal/gas turbine governor model. In
accordance with current WECC policy, the generator owner has the responsibility to provide
appropriate modeling data for their units. The data to be used by WECC in the application of
the new thermal/gas turbine ggov1model should be submitted by the generator owners/control
area for each unit. A Workshop will be held to explain to WECC members and generator
owners the details of the new governor model, methodology and data assumed for modeling,
and the requirements from generator owners to verify/refine their model data. All generator
owners shall provide a validation of their selected governor model data by submitting
recordings of their generator responses during system disturbances11 or tests.
10
Validation and Verification of the Codes was performed as described in the Report. Additionally, the CAISO
provided data of generator SCADA recordings for other disturbance events that were used in the model
development. Also data from the WECC surveys was used for units without SCADA recordings.
11
Disturbance monitoring equipment recordings are desirable; however high-resolution SCADA recordings are
also acceptable.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
GOVERNOR CODES
THERMAL TURBINE - GOVERNORS
Code T1 : For units with “fast” load controllers
Code T2 : For units with “slow” load controllers
Code T3 : For units with no load controllers
GAS TURBINE – GOVERNORS
Code G1 : For units with load controllers
Code G2 : For units with no load controllers
28
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
29
Table 1 – Recommended Thermal/Gas Turbine Governor Codes
Recommended Governor Codes
Fast
Parameter
R
rselect
tpelec
maxerr
minerr
kpgov
kigov
kdgov
tdgov
vmax
vmin
tact
kturb
wfnl
tb
tc
flag
teng
tfload
kpload
kiload
ldref *
dm
ropen
rclose
Kimw
pmwset #
Slow
T1
Permanent droop, pu
Feedback signal for droop
Electrical power transducer time
constant, sec
Maximum value for speed error
signal
Minimum value for speed error
signal
Governor proportional gain
Governor integral gain
Governor derivative gain
Governor derivative controller time
constant
Maximum valve position limit
Minimum valve position limit
Actuator time constant
Turbine gain
No load fuel flow, p.u
Turbine lag time constant
Turbine lead time constant
Switch for turbine output
Transport lag time constant for
diesel engine
Load Limiter time constant
Load limiter proportional gain for PI
controller
Load limiter integral gain for PI
controller
Load limiter reference value pu
Mechanical damping coefficient, pu
Maximum valve opening rate,
pu/sec
Minimum valve closing rate, pu/sec
Power controller reset gain
(for lcfb1 controller, this is KI)
Power controller setpoint
None
T2
Fast
T3
None
G1
G2
0.05
0.05
0.05
0.05
0.05
1
1
1
1
1
1
1
1
1
1
0.05
0.05
0.05
0.05
0.05
-0.05
-0.05
-0.05
-0.05
-0.05
10
10
10
10
10
2
2
2
2
2
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
0
0
0
0.15
0.15
0.5
0.5
0.5
0.5
0.5
1
1
1
1.5
1.5
0.01
0.01
0.01
0.18
0.18
10
10
10
0.5
0.5
3
3
3
0
0
0
0
0
0
0
0
0
0
0
0
1
1
1
3
3
0.5
0.5
0.5
1
1
0.2
0.2
0.2
0.2
0.2
1
1
1
1
1
0
0
0
0
0
0.1
0.1
0.1
1
1
-1
-1
0.01 to 0.001 to
0.02 0.005
-1
-1
-1
0.01 to 0.02
0
0
For a description of each item, please refer to the GE ggov1 model
* See text for baseload or limiter
operation
# initialized automatically to power flow value
Gas No Load Controller
Gas With Load Controller
Thermal No Load Controller
Thermal Slow Load Controller
Thermal Fast Load Controller
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig. 1 Shows a typical “Responsive” unit – SCADA recording – Code T3
Fig. 2 Craig2 – Shows a “Partially Responsive” Unit – SCADA recording – Code T2.
The effect of Load Controller Action is clearly seen in the SCADA recording.
30
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig. 3 Cholla 4 – Shows a Partially Responsive Unit - – SCADA recording – Code T2
Fig. 4 - Haynes2 – Responsive Unit (AGC?) - – SCADA recording – Code T3
31
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig. 5
32
Paloverde – “Unresponsive” Unit - – SCADA recording – Base Loaded (ldref)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
33
TYPICAL ILLUSTRATIONS SHOWING THE DIFFERENCE IN RESPONSES
BETWEEN SIMULATIONS USING EXISTING MODELS AND THE NEW GGOV1
MODELING
SCATTERGOOD – CODE T3
Fig. 6. Illustrating Code T3 (No Load Controller). Comparing
SCADA recording and model simulations
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
CRAIG 2 – CODE T2
Fig. 7 Craig 2 - Simulations of a Partially Responsive Unit. Comparing
SCADA recording and base case model simulations – Code T2
34
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
35
PALO VERDE – BASE LOADED
Fig. 8 Palo Verde- Simulations of an Unresponsive Unit. Comparing SCADA recording
and ggov1 model (Base loaded - ldref) simulation
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
36
Fig. 9 Sensitivity Studies showing the effect of varying Turbine-Governor Code selections
for the May 18th 2001 Tests – NW 1250 MW and Hoover 750 MW trips
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
APPENDIX 3
HYDRO TURBINE-GOVERNOR MODELING
37
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
38
Hydro Governor-Turbine Modeling
Shawn Patterson, Bureau of Reclamation
Conclusions
1. Hydro units are very responsive to frequency deviations. Complete response, however,
typically takes from 15 to 90 seconds. On average, a hydro governor will have completed about
two-thirds of its response after 60 seconds. Only a fraction of a typical hydro units response is
completed in the first 10 seconds.
2. Since the pick up of frequency responsive governors, such as hydro units, will increase with
the magnitude of the frequency deviation, to properly simulate these governors requires that
the system frequency response to a disturbance in the simulation is correct. Hence the new
thermal/gas ggov1 model simulations will result in more accurate hydro simulations.
3. The impact of hydro responses and its correct simulation is very important to the overall
system frequency response. More accurate hydro modeling is recommended as follows:
−
Controllers (plant controls, AGC, etc.) may readjust governor set points
before a hydro governor completes its response. These need to be modeled
properly for simulations up to 60 seconds (FRR).
−
Kaplan (adjustable blade) turbines are not represented correctly with the
existing models. Kaplan turbines account for approximately 14,000 MW of
generating capacity on lower-, mid-Columbia and lower Snake dams. Studies
indicate that existing models grossly over-represent governor response in first
10 seconds.
−
Nonlinear turbine gain effects can have a noticeable impact on the amount of
response of a hydro unit and should be included in the models.
−
Modeling hydro governors correctly for all units that do not have such models
presently.
−
The amount of hydro response is dependent on the load level of the generator;
therefore power- flow representation of hydro plants must be realistic.
4. The gross mismatch between actual under-frequency events and simulation results is
primarily due to incorrect thermal/gas governor modeling. However, because hydro
governor/turbine model performance has become very critical, any deficiencies in hydro
modeling assume a greater importance in assessing the overall response of the system.
Hydro Governors/Turbine Response
A study of individual unit response data taken during the May 18, 2001 tests indicate that
hydro units are, in general, very responsive to frequency deviations. Although there was data
available for only a fraction of the total number of hydro plants, the data that was available
showed that nearly all the hydro units examined responded upon the frequency decline. In
many cases, the resolution of the measured SCADA data is not sufficient to determine any
change in generator output. The expected response amounts for these tests are less than one
percent of the rated outputs, so some system may not be able to detect the changes, especially
for smaller units. From those that could measure the change, the responses indicate that the
units will pick up their appropriate share of the load as determined by their permanent droop
settings. In most cases, however, the time constants of a hydro response are quite long and a
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
39
full response may not be completed in a 60 second time frame. The typical range of hydro
governor time constants varies from 20 second to 120 seconds. Plants with long penstocks,
such as pipeline plants (not located on dams) can have a considerably longer response time,
since response time varies principally with the water starting time constant. Electro-hydraulic
governors usually have a more sophisticated controller design, and therefore can be set up to
respond faster than mechanical governors.
Figure 1 shows the measured response of Hoover unit N4. The plot covers two minutes of data.
Note that the unit is still responding after 60 seconds. The time constant of the governor
response is about 30 seconds, which is shorter than the average for hydro units with
mechanical governors. This means that at 30 seconds, the unit's wicket gates will have reached
63 percent of their final travel. Mechanical governors will typically have longer time constants,
around 60 seconds or longer. If the droop (the change in frequency, percent, divided by the
change in gate position, percent) is measured for a unit with a 30 second governor time
constant, at t = 60 seconds it will come out to a value of about 6 percent. After the unit
completes its response, it will reach a final droop value of 5 percent, which is the normal droop
setting throughout the WECC. A simulation of the event using the current database models
shows that after 60 seconds, on average, hydro units had responded about 72 percent of their
final value, based on their droop settings. Therefore, the average hydro governor time constant
in the WECC is near 60 seconds, and the average droop at 60 seconds is near 8 percent.
A governor with a 60 second time constant will respond about 25 percent of its total response
in the first 10 seconds. Therefore, on average, hydro units will impact the transient dip in
frequency after a generation loss only minimally. Most of the hydro response will occur after
the first 10 seconds.
Droop vs. Regulation
Note that a droop setting of 5 percent does not mean a power change of 5 percent (change in
power output, in percent, divided by change in frequency, in percent – referred to as speed
regulation). Some governors are equipped with a power signal feedback, so that the power
response to system frequency is a constant, defined ratio. If a governor uses a power signal
feedback, the unit will respond with the amount determined by the regulation setting, and
nonlinear effects do not affect the response. These governors make up only a small fraction of
the governors in the WECC. The normal method of setting the amount of response of a
governor to a frequency deviation, is through the droop setting, which is defined as a change in
gate or valve position proportional to the frequency deviation. It does not account for any
additional gains, nonlinearity, etc., that is present in the system after the water has been
released to the turbine. It is also important to consider that for mechanical governor systems,
the droop characteristic is accomplished through mechanical linkages, which are subject to the
normal variations inherent in such systems, such as worn or sticking parts, backlash, deadband,
etc. Therefore, it is not unusual for a mechanical system to exhibit a variation in the droop
characteristic of up to 10 percent over its operating range (i.e., variances between 4.5 and 5.5
percent droop.) An electro-hydraulic system can have a much more precise droop
characteristic.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
40
Non-frequency responsive hydro
There are some hydro governors that do not respond to speed variations, but instead, regulate
MW output or turbine flow. This type of control may be found on some single unit plants on
canals or rivers where regulation of water flow is the primary concern. Generators operating in
these modes will not help maintain constant system frequency and cannot be regarded as
frequency responsive reserve. Generators that normally operate under these control modes
should be identified and modeled either with the correct feedback signal or, more
appropriately, without a governor model. If a machine is to be represented without a governor
model because it does not respond to frequency changes, it should be noted in the database so
it will not be confused with the cases where the owner has simply neglected submitting the
governor model.
Governor operation
A hydro governor is a relatively simple piece of equipment and its operation is straightforward
and normally unencumbered by other plant processes. There has been an abundance of data
recorded over many years of operation, and hydro governor operation is very well understood
and predictable in simulation, provided the model data is verified, through tests, as correct.
There are, however, some aspects of hydro plant control not currently accounted for in
simulations, such as MW (e.g., AGC set points) or flow control, which may interfere with their
control of system frequency. There were some indications that during the May 18, 2001 tests,
some hydro units were operating in a MW set point control mode, which would slowly reset
the unit output back to the value prior to the generation loss. It is recommended that the outer
loop, coordinated control, etc, modes be modified with a droop characteristic of their own to
allow proper response to frequency deviation. If this is not possible, then the outer loop control
effects must be modeled.
A detailed comparison of some of the measured responses against simulated responses verifies
that the hydro governor models can accurately represent the actual control systems. Figure 2
compares the gate response of the unit shown in Figure 1 with the simulated response using the
ieeeg3, mechanical governor model. This simulation was performed using the actual frequency
signal measured during the May 18, 2001 tests as an input. Therefore, the signal into the model
is exactly the same as seen by the governor on Hoover unit N4. The simulated response
compares very well against the measured response. Therefore, it is verified that the dynamic
portions of this model, i.e., the governor control loop and the water starting time, TW, are an
accurate representation of the real governor.
Nonlinear effects
However, careful study of the response in Figure 1 reveals that for the 0.13-0.15 percent
change in frequency (at 60 seconds) during this test, the regulation is near 4.5 percent. At the
two-minute mark, the MW response has reached a level that is about 45 percent greater than
determined by the droop setting of 5 percent. The regulation, or effective droop as it is
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
41
sometimes called, is 3.4 percent. This extra response is due to gain in the water column and
turbine portions of the system. Much of the hydro responses from May 18 test data examined
exhibited a regulation level of greater than 5 percent. Most of the data did not contain gate
position data, so it was not possible to compare the regulation to droop.
It is the additional effects of the turbine that complicates the modeling of hydro responses. The
ieeeg3 model, as well as the g2wscc, gpwscc, and the pidgov models in the PSLF program all
include a linear model of the turbine These models currently make up the bulk of the
representation of hydro units in the database. In reality, the dynamics of hydro turbines and the
water flowing through them are quite complex and can be modeled in great detail, most of
which is unnecessary for the purposes of large scale system stability studies. For most studies,
that is, those in which system frequency does not change drastically (e.g., islanded or small
systems), the components of the hydro governor model of primary importance are the portions
with time constants, e.g., pilot valve, main servo, gate rate limit, dashpot, any electronic
compensation, and the water starting time. These components are all represented well in all the
models and are, fortunately, easy to measure and model. Therefore, as demonstrated in Figure
2, the dynamic response characteristic is relatively easy to model correctly.
If, however, the simulation includes large changes in frequency, then the steady state gain
becomes important in predicting the total change in power output of the unit. This gain is
dominated by the permanent droop setting, which in the WECC is normally set to 5 percent,
provided turbine and generator ratings are similar. This corresponds to a governor per unit gain
of 20. There are also some turbine effects that can add to or subtract from the overall gain of
the governor/turbine system. The nonlinear hydro governor models were developed in order to
account for some of these effects. In the PSLF program, mechanical governors can be modeled
with the hygov or hygov4 models, and for electro-hydraulic or digital governors, the
appropriate model is hyg3. These models are recent additions to the program and have not been
adopted by users yet. The nonlinear governor models include a constant, AT, which is used to
add the gain that is effected by the fact that the range of gate position, in percent, does not
correspond one to one with the range of power output. That is, gate position at zero power out
is not zero but near 10 percent in most cases. Rated generator output is obtained at a gate
position of less than 100 percent if the turbine rating is greater than the generator rating.
Therefore AT represents the extra gain due to the typically smaller range of gate operation and
is numerically equal to 1/(Gate full load – Gate no load). The no load turbine flow parameter, qNL,
should be set to ATGatenoloadH01/2.
Another gain effect incorporated into the nonlinear turbine models is that due to speed
dependent turbine damping. The resistance of the water as the turbine turns increases with
speed. Therefore, as speed decreases, the resistance decreases, which manifests itself as extra
power on the generator shaft. This factor varies with turbine designs and is generally difficult
to determine, but a generally accepted typical value is 1 per unit, at 100 percent gate. The
damping decreases with gate position.
An effect also included in the nonlinear models is that due to head variation. Power output
varies as H3/2 so large changes in reservoir levels can affect power output significantly. Head
levels vary considerably from area to area, season to season and year to year, and
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
42
consequently, so does unit capacity and turbine gain. This parameter should be altered only in
rare cases where detailed and specific lake elevations are known and are of interest. Normally,
H0 should be set to 1.0. This value will not affect the output. In fact, the current (v13) and
previous versions of the pslf program does not properly initialize the hygov4 model if H0 has
been set to any other value than 1.0. Since reservoir levels were low in several parts of the
WECC area during the May 18 tests, it was desired to study these effects, however, the
initialization problem and the fact that the model, hygov, does not allow for head variation,
hindered these efforts.
Linear vs. Nonlinear models
Comparing simulations of the linear model, ieeeg3, with the nonlinear model, hygov4, for
Hoover N4, and assuming all other parameters are equal, all of these turbine gain effects
(excluding head variation) discussed so far in the nonlinear model add up to about a 15 percent
increase in power response for the May 18 test, or a 0.5 percent change in generator output.
Figure 3 compares the simulated responses of the linear model, the nonlinear model with Dturb
= 0, and the nonlinear model with Dturb = 1.0. As is evident from the plot, the response with the
nonlinear model comes closer to matching the response with the linear model. But there is still
a significant amount of gain to be added to the water column/turbine model before the actual
response will be approximated.
Also depicted on Figure 3 is a response generated using the nonlinear model and an additional
gain of 1.3 per unit, which duplicates the actual data. With this additional gain, the total
increase in power response for this unit is about 45 percent, or 1.5 percent change in generator
output. This additional gain discrepancy dwarfs all of the other gain effects included in the
nonlinear model. There also happens to be one more additional gain factor to be considered in
a hydro turbine. This is the nonlinear gain effect due to variation in turbine efficiency. Figure 4
shows the measured relationship between gate position and power output (electrical power
output – losses between mechanical power and electrical power are neglected here) for Hoover
N4. Currently, this effect is not modeled for most of the machines in the database.
This curve varies from turbine to turbine, but will in general have a similar S-shape. The
efficiency of hydro turbines varies with the flow. They are usually designed for optimal
efficiency somewhere in the range of about 75-90 percent flow (gate position.) Therefore, as
the gate position increases or decreases from this range, so does the efficiency, and so
consequently, the gain from gate position to power output varies with the operating point.
Hydro turbines are least efficient at low loads, so as the loading increases towards the higher
loads, the gain in efficiency can increase dramatically. The slope of this curve at the operating
points of interest represent the turbine gain, and is typically the greatest between 40 and 80
percent gate position. It is important to note that if a unit is operating at peak efficiency or
above, an increase in gate position will include a decrease in turbine gain (the P-G curve will
result in a smaller increase in output power) while if a unit is operating below peak efficiency,
an increase in gate position will be met with an additional gain from the turbine (the P-G curve
will result in a larger increase in output power.)
Also shown on Figure 4 is the typical hydro P-G curve as defined in pslf. A P-G curve can be
applied to all the hydro governor models, linear or nonlinear types. Included on the figure for
comparison is the slope = 1 line, which is the default linear characteristic if the P-G curve is
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
43
not used. While the default hydro curve has a similar shape as the actual data points for this
unit, substituting the default curve for this case would lead to an overly responsive model when
the unit is loaded below 50 percent, and a model that would respond significantly less when
loaded above 75 percent. Therefore, it can be concluded that the P-G characteristic is a very
important piece of data when constructing a model of a hydro turbine. However, there is an
important caveat in applying this curve: the measured Power vs. Gate data will also include the
effects of the AT and qnl parameters in the nonlinear models. Therefore, if the P-G curve is
used, AT and qnl should be set to 1.0 and zero, respectively, or their effects must be subtracted
from the P-G curve data, which is more difficult.
Effects of hydro units on system frequency
Taking all of the nonlinear turbine gain effects into account, the total added gain can vary
considerably over the operating range of a hydro unit. At its greatest, it may contribute an extra
50 percent gain, or near zero at the lowest. A comparison of linear vs. nonlinear governor
models using typical data for the nonlinear models is shown in Figure 5. These plots also
reflect the system wide use of the ggov1 model for steam and gas units.,
Importance of frequency deviation
A fact that should not be overlooked when considering governor response is that the amount of
response is proportional to the deviation in system frequency. This has nothing to do with the
governor model, but is a function of frequency response. This is why the model validation
steps illustrated in figures 2 and 5 were simulated with actual frequency signals instead of
those generated by the base case model data. Figure 6 shows the response of a hydro unit using
the base case data and compared with a case using the ggov1 model for steam and gas units.
The governor response is much greater when the frequency deviation is greater. Correct
simulation of the system frequency during a disturbance is critical to correct simulation of a
unit governor response.
Other considerations
Types of hydro turbines
The discussion here regarding hydro turbine/governor models applies to Francis type units
only. From test data, is has been determined that the models presently available will not
sufficiently represent units with Kaplan, or propeller type turbines. These units have an
additional control loop that alters the blade angle to optimize the efficiency of the turbine based
on the flow (loading). Therefore, a new model has been developed to more accurately represent
the effects of variable blade angle. Impulse or Pelton wheel turbines have not been addressed
due to their sparse presence in the system.
Deadband
During these investigations the subject of deadband in hydro governors was also addressed.
The computer models currently in use include parameters for setting intentional deadband and
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
44
unintentional deadband. Intentional deadband is a feature in more modern governor designs
that causes very small changes in speed to be ignored, thereby reducing wear and tear on
mechanical parts. This parameter is a set value and should be replicated in the models if it is in
use. The unintentional deadband is a parameter in the model that can be used to incorporate
effects mentioned above, (e.g., sticky parts, hydraulic system nonlinearities, etc.). The overall
effect of using these parameters in the models is to cause a threshold effect, in which there is
not as much governor response throughout the system for small frequency deviations, and then
complete governor response for large deviations. The value of these effects in system studies is
dubious, at best. Furthermore, the presence of unintentional deadband or its magnitude is not
likely to be consistent or even known. If it is discovered, the proper course of action is of
course to eliminate it, not characterize it in the model.
Missing/unverified data
As a final note on hydro governor models, it should be reiterated that the largest source of error
in the modeling of hydro governors is due to unverified model data or no model at all. As has
been noted, half of the machines in the WECC database do not include governor models, and
many of them are known to be hydro models. There is also a large amount of data that looks
suspiciously like typical data. In particular, there are many hygov models that have a gate rate
(velocity) limit of 99 pu/sec, a standard default number, in addition to a physical impossibility.
It is suspected that many of these models are default versions, automatically created during the
conversion of data from the old WSCC program data to the GE format. The old ieeeg2 model
data cannot be converted automatically to any other hydro governor model; therefore the hygov
model was used. The ieeeg2 model was used in the early days of computer studies as a simple
governor model to be used for short duration, transient studies, in which governor action was
unimportant. These models are not appropriate for simulating events like the May 18 tests. Any
models derived from ieeeg2 data should be considered non-validated.
Figure 1 – MW Response of Hoover N4 to May 18, 2001 NW generation trip
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Figure 2 - Gate response comparison - actual vs. simulation
Figure 3 - Response comparisons using different model assumptions
45
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Figure 4 - Nonlinear Power vs. Gate Relationship
Figure 5 - Linear vs. nonlinear hydro models using ggov1
46
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Figure 6 - Effect of ggov1 models on hydro response
47
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
APPENDIX 4
GUIDELINES FOR THERMAL GOVERNOR MODEL DATA
SELECTION, VALIDATION, AND SUBMITTAL TO WECC
Prepared by the Governor Modeling Task Force
WECC Modeling & Validation Work Group
October 9, 2002
48
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
49
Guidelines for Thermal Governor Model Data Selection,
Validation, and Submittal to WECC
Introduction
Studies conducted during 2002 have demonstrated that representing base loading of generators
and generator load controllers has a dramatic effect on simulation results, not only in frequency
deviation studies (reserve, under frequency load shedding, etc.), but will impact the results of
many system stability studies, such as those used to set transfer limits, remedial action, etc. The
results of these studies and the new recommended models for thermal turbine-governors were
distributed to WECC members in a report by a task force of the Modeling and Validation Work
Group titled "New Thermal Turbine Governor Modeling for the WECC". The report clearly
indicates the significant improvement in system simulations as a result of the new thermal
modeling and the corresponding inadequacies of the existing thermal governor models. The
new modeling will significantly improve the predictability of performance of the power system
during major generation and RAS outages. (Fig. 1) A governor modeling workshop was held
in Salt Lake City on August 19-20 to disseminate the information from recent studies and to
describe to generation owners some newly developed models and what information is required
to assign data to the model variables12.
Figure 3 - Improvement in Simulation Accuracy with New Modeling
Model description
Two new models have been developed for use in WECC studies. The ggov1 model, referenced
in the report is a generic thermal governor/turbine model that incorporates base loading and a
load controller. The model, lcfb1, is identical in structure to the load controller portion of
ggov1, and can be used in tandem with any governor model currently defined in the GE PSLF
12
Workshop material is available on the WECC website.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
50
program (see figure 2 for model diagrams). See Appendix 1 of the report listed above for
additional information.
Thermal plants not currently modeled with a governor in the WECC database should be added
using the ggov1 model. All gas turbine units should use the ggov1 model, as all other gas
turbine models will not be supported in future releases of GE PSLF. Hydro units that operate
under load control should also use the lcfb1 model in addition to the appropriate hydro
governor model.
Existing ieeeg1 models may be used with the addition of the lcfb1 load controller model if it
applies. Alternatively, the new ggov1 model may be used for such units with appropriate data
supplied for it.
Upon initialization, base-loaded units and load-controllers are assigned values in the ggov1 and
lcfb1 models equal to the generator dispatched value specified in the power flow data. If the
effects of a load (or any set point other than frequency) controller are to be included, the output
of the unit will be reset to the value of PMWSET. The speed at which the resetting takes place is
controlled by the value of KIMW (KI in model lcfb1.)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
51
Figure 2 - ggov1 (above) and lcfb1 (below) models
Model Data and Validation Requirements
Whether a unit is base loaded and the value of KIMW (or KI) for units with load controllers are
the important pieces of new information that must be added to the database and validated
through measurement.
Current WECC policy requires that all generation owners submit appropriate computer model
data to represent their machines and associated equipment along with recorded data that
validates the accuracy of the computer models. It is therefore required that the data for the new
models discussed herein be validated by comparing actual measured electrical power output
response data of each unit to the computer modeled simulation response. Typical responses of
SCADA recordings of thermal units and simulations with the new governor model and the
existing model (base case) are shown in Figs. 3a, 3b and 3c.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
52
Figure 3a – Example of Slow Load Controller Response vs. Existing and New Models,
kimw = 0.001
Fig. 3b. Example of a Fast Load Controller Simulation with the new ggov1 model,
kimw=0.005
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
53
Fig. 3c. Example of a Base Loaded unit Simulation with the new ggov1 model
Since governor response occurs as a result of system frequency deviation from 60 Hz,
validation data is best obtained during sudden, large generation trips. The recorded data
necessary to perform the model validation consists of system frequency and electrical power
output of the generator in question. Recordings of system frequency of several past and
possible future underfrequency events will be available from the WECC website. The only
recordings necessary for the generator owner to obtain during one of these listed events (or
future events) will be the electrical power output and frequency. Disturbances that are suitable
for validation are those in which system frequency drops 0.15% or more (59.90 Hz or below).
A generation trip of 800 MW or greater will usually result in the appropriate frequency
deviation. Future disturbances that are deemed suitable for validation will be announced
through WECC information distribution channels so that generator response data can be
obtained from recording equipment in a prompt time frame.
For the purpose of validation, the event recordings of the MW output of the generator must be
of sufficient resolution, sampling rate, and length to determine the change in power output of a
generator. The recording should have a resolution not greater than 1 percent of the rated
generator output. The MW data should be recorded at least every 4 seconds or less. The data
record should extend a period of 60-100 seconds or more.
The suggested methods of obtaining measurement data are:
1. SCADA (either local systems or those used for dispatch control centers)
2. Data loggers
3. Digital Excitation/Governor event capturing systems
4. Dedicated monitoring systems (PPSM, disturbance monitors, machine
condition monitors, data acquisition systems)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
54
5. Test Instrumentation (Oscillographic recorders, PC based recorders,
virtual instruments, etc., set to automatically trigger a recording when
system frequency dips below 59.9 Hz)
Recordings of system frequency for the following past underfrequency events will be available
from the WECC website and may be used for data validation
1. May 18, 2001 tests (NW and Hoover trips) – 1250 MW and 750 MW
respectively (10:40 and 10:20 PDT)
2. June 7, 2000 trip tests (750 MW)
3. July 27 (19:19 PDT), 2002 Four Corners trip (2065 MW)
4. July 15 (13:04), 2002 NW RAS trip (2350 MW)
5. July 16 (15:41 PDT), 2002 NW RAS trip (2350 MW)
6. June 6 (13:47 PDT), 2002 PDCI loss ( 2800 MW )
7. June 3, 2002 Diablo Canyon trip (950 MW)
8. Recent Colstrip trips (2000 MW)
9. October 8, 2002 (15:31 PST) – 2900 MW NW RAS trip
Future Events:
• When an underfrequency event occurs in the future that is suitable for model
validation, WECC will send out a notification within 24 hours so that the
generation owners can retrieve the captured validation data. The owner should
also record the manner in which his unit was operated at that time. A file
containing the system frequency vs. time data to be used for validation will be
sent out by WECC at this time.
• The Owner may request SCADA records of the unit from his Control Area
Operator. If SCADA is not available, the Owner should record his unit’s
response to the event using one of the methods described earlier.
Validation of data
1. Using the frequency data as an input, perform a computer simulation of the event using
the new governor model and data. {There are two methods, one using epcls with recorded
data, and the other using the pfs “frequency profile” model. Both methods are described
below.)
2. Verify the simulated response is similar to the measured, recorded response.
3. Adjust the model parameters if necessary to improve the match.
Model data will be considered validated when the power output response of a generator in
simulation of an event closely resembles the actual recording of the event. The simulated
response should be demonstrated to be similar to the measured response over a 60 second time
period. An example of such a comparison is illustrated in figure 3. The response plots should
be submitted to WECC as soon as the comparison data is available. The model data used for
the simulated response should be listed along with the response plots.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
55
The most appropriate way of performing the model validation is to perform the simulation
using the measured frequency data obtained during the actual measured event. A typical
recording of system frequency during such an event is shown in figure 4. This type of
validation can be accomplished by using any of the following methods:
1. Using WECC provided epcls to automatically simulate the validation event using the
GE PSLF program. See Example 1, below.
2. Using a current WECC data base case, approximate the actual event by tripping enough
generation in the simulation to produce a frequency dip that closely approximates the
actual event for comparison. See Example 2 below.
3. The pfs utility in the GE PSLF program, using a frequency “profile”. See Example 3
below.
4. A small, stand-alone program by GE that will allow this to be done is currently being
developed and will be available from the WECC staff in October 2002. This program
will only require the user to input the model data for the appropriate model. See
Example 4 below.
Typical Questions to be asked by the Owner before selection of the appropriate model:
To facilitate answering these questions and in the selection of the appropriate governor
parameters, the Owner may refer to the diagram of approximate responses in Figure 5.
1. Is the generator unit normally operated in a mode that can be considered base loaded? (For
definition of base loaded, see lowest Base Loading Response Box in Fig.5.)
2. Is the generator unit normally operated under load setpoint control, or any other mode of
control that will override automatic action of the governor responding to changes in system
frequency? Other examples of these control modes may be temperature limiters, etc.
3. If the answer to question 2 is yes, is the response time of the dominant controller fast or slow
as indicated on the time scale in figure 5. (See Response Boxes for ‘Fast’ Controllers Code
T113 and ‘Slow’ Code T2 Controllers in Fig.5.)
4. Is the generator unit normally operated in a mode that can be considered Responsive? –
(See Upper ‘Responsive’ Box in Fig.5 for Code T3.)
5. Does the generating unit normally respond to AGC signals?
6. If the generator is currently represented in the WECC database without an excitation system
model, the type of exciter should be specified, e.g., Fully static, Rotating DC, Rotating AC
Brushless, etc., or manufacturer and model information, if known.
13
As discussed at the Workshop, the recommended Code parameter are ‘typical’ values and the Owner should
select appropriate values to suit his application. For example, Code T1 could vary between 0.01 to 0.02 or
greater, and Code T2 could vary between 0.001 to 0.005.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
56
It is realized that units may be operated in different modes from day to day, or even hour to
hour, and that the responses to these questions will vary accordingly. In these cases, it is up
to the owner to decide which mode the unit is most likely to be operated in at any given time.
Most of the base cases of concern are intended to represent the system during daily peak
loading conditions.
Figure 5 - Response Guideline
Additional Data Required
Also critical to the accuracy of WECC system studies is the correct representation of excitation
systems. There are a large number of generators in the WECC database currently represented
without exciter models. It is required that all generators be modeled with the appropriate and
validated exciter models.
See Appendix 6 for details of Units Without Models.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Submittals
Submittals shall be made to :
Donald Davies
WECC
phone: 801-582-0353
email: Donald@wecc.biz
615 Arapeen Drive
Salt Lake City, Utah 84108
57
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
58
Example 1
Validation example using WECC supplied epcls and GE PSLF
A detailed, step by step, example illustrating validation and use of WECC epcls is given below:
1. Obtain the May 18th Test epcl files and the data file for the May 18th Test recording
from the WECC BBS. Put all the files, except "event.p" in your working directory.
Place the "event.p" in your upslf113\stdepecl\" directory.
2. Run the PSLF program.
3. The example given is for two typical generators UnitXX and UnitYY. These units are
dispatched with identical MW loadings in order to compare the effect of fast and slow
controllers.
4. Load the files unitXY.sav for the powerflow and unitXY.dyd for the dynamic stability
run.
5. The unitXY.dyd file has two typical ggov1 models with assumed parameters for fast
and slow ggov1 models.
6. The directory should also contain a data file e010518.dat that has in it data for Unit XX
and UnitXY from the May 18th recordings.
7. Run the epcl RUNunitXY.p which will run the detailed simulation.
8. Plot the electrical power output of the UnitXX and UnitYY from the PSLF Plot
program. (See Fig.6)
9. Compare the output of PSLF with the May 18th recording of unitXX and unitYY
generators during the May 18th Test.
10. Change the kimw parameter of the ggov1 models as appropriate to achieve the best
comparable simulation with the May 18th recordings.
11. A number of runs may be needed to optimize this selection of the ggov1 parameter
kimw. However, these runs are very fast because of the small system simulated.
12. If the generator was clearly in base loaded operation during the May 18th test, denote
this with the appropriate flag by placing a 1 in Column B of the gens table in the PSLF
powerflow program. Run the dynamic simulation. Again compare the output of PSLF
with the May 18th recording for confirmation.
13. Submit the model and plots of the simulation to WECC.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
59
Fig.6 Example 1 - Simulation of Fast and Slow Load Controllers Using the WECC epcls.
(The figure shows that the validated governor model is best represented by a Slow Controller
ggov1 model with the parameter kimw = 0.0015.)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
60
Example 2
Validation example using a typical two Palo Verde generation
drop in GE PSLF
A detailed, step by step example illustrating validation using a current full-loop WECC data
base case is given below:
1. Run the PSLF program with a current basecase – example a Light Spring Case.
2. Load the files xxx.sav for the powerflow and xxx.dyd for the dynamic stability run.
3. The xxx.dyd file should have entered in it the typical ggov1 model with assumed
parameters for the generator you wish to simulate.
4. Run the simulation by tripping 2-Palo Verde Units. (If another disturbance is simulated,
note that using the current model database, tripping the same generation as in the actual
event will not produce enough frequency deviation to properly validate the model. The
optimistic frequency response will result in a pessimistic governor response, so
additional generation will have to be tripped in the simulation14.) A 30 second run is a
minimum , but for a ‘slow’ controller a 60-100 second run may be needed.
5. Plot the output of your generator electrical power from the PSLF Plot program (see
Figure 7).
6. Compare the output of PSLF with the May 18th (or other disturbance) recording of your
generator obtained from SCADA or disturbance recording.
7. Change the kimw parameter of the ggov1 model as appropriate to achieve the best
comparable simulation with the disturbance recording.
8. A number of runs may be needed to optimize this selection of ggov1 parameter kimw.
These runs could take time because system simulated is the full-loop WECC system.
However, the advantage of this method is that it could be done immediately without
special epcls or special case files.
9. If the generator was clearly in base loaded operation during the disturbance, denote this
with the appropriate flag by placing a 1 in Column B of the gens table in PSLF
powerflow program. Run the dynamic simulation. Again compare the output of PSLF
with the disturbance recording for confirmation.
10. Submit the model and plots of the simulation to WECC.
The figure below shows an example of this type of validation, in which a two unit Palo Verde
trip was used to initiate the frequency deviation.
14
This illustrates the current deficiency in representing governor response in the database and the need to
incorporate the additional data discussed herein
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig. 7 Example 2- Simulations of Fast and Slow Load Controllers using loss of two Palo
Verde units.
61
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
62
Example 3
Validation Method using pfs utility in GE PSLF
Step by step example illustrating validation and use of pfs utility for the May 18th Test.
1. Obtain the May 18th Test Profile from WECC – see Figure 8 below
Fig. 8
Example 3 - May 18 frequency recording at the Malin 500 kV bus
2. There are 4 points on the frequency profile as shown in the Figure which will be used in
the ‘pfs’ model as a function of input frequency and time. (see ‘unitXYpfs.dyd file to
be downloaded from the WECC BBS).
3. Run the PSLF program
4. The example given is for a typical generator. Modify the parameters to suit.
5. Load the files unitXY.sav for the powerflow and unitXYpfs.dyd for the dynamic
stability run.
6. The UnitXYpfs.dyd file has a typical ggov1 model with assumed parameters plus the
pfs model.
7. Run the epcl unitXYpfs.p which will load the pfs model using the unitXYpfs.dyd.
8. Plot the electrical power output of the units from the PSLF Plot program.
9. Compare the output of PSLF with the May 18th recording of the generator during the
May 18th Test.
10. Change the kimw parameter of the ggov1 model as appropriate to achieve the best
comparable simulation with May 18th recording.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
63
11. A number of runs may be needed to optimize this selection of ggov1 parameter kimw.
However, these runs are very fast because of the small system simulated.
12. If the generator was clearly in base loaded operation during the May 18th test, denote
this with the appropriate flag by placing a 1 in Column B of the gens table in
PSLF.powerflow program. Run the dynamic simulation. Again compare the output of
PSLF with the May 18th recording for confirmation.
13. Submit the model and plots of the simulation to WECC.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
64
Example 4
Validation example using stand alone program (for non GE
PSLF users)
Details for the running of the stand alone program are identical to the pfs model in Example 1
except that the program represents a small system.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
APPENDIX 5
EFFECTS OF GOVERNOR MODELING UPON OSCILLATORY
DYNAMICS IN SIMULATION OF THE 750 MW GRAND COULEE
GENERATION TRIP ON JUNE 7, 2000
JOHN HAUER AND LES PEREIRA
WECC MODELING & VALIDATION WORK GROUP
August 1, 2002
65
New Thermal Turbine Governor Modeling for the WECC
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66
Effects of Governor Modeling Upon Oscillatory Dynamics in Simulation of
the 750 MW Grand Coulee Generation Trip on June 7, 2000
Summary
This Report is supplemental to recent reports concerning the development and application of a
new thermal governor model(GE ggov1 model) for WECC planning and operation studies
[i,ii]. The primary contribution is a quantitative analysis showing that, in contrast to earlier
models, use of the ggov1 governor model produces much more realistic simulations of
oscillations and damping than the existing dynamic models for the dominant North-South
("Canada-California") mode for the 750 MW Grand Coulee generation trip on June 7, 2000.
Other aspects of dynamic behavior, and other events, will be examined as the associated base
cases become available.
The June 7th 2000 case was chosen as an independent “validation” case for the new model
because the development of the new thermal governor model was based on the May 18th 2001
test case.
A number of operating cases have been constructed for the WECC performance validation tests
of June 7, 2000 [iii]. Until recently, these and other WECC models have generally represented
the dominant North-South ("Canada-California") mode as having about twice the damping that
it actually does. As a result, oscillations of this mode will persist for roughly twice as long as
models predict, and they will be substantially stronger.
These effects have been observed in many model validation efforts. M&VWG examined them
quantitatively for brake insertions performed in the June 7 tests [iv,v], but deferred direct
follow-up action on calibration of oscillatory dynamics in favor of calibrating prime mover
dynamics (chiefly governor behavior). This is a more pressing and fundamental issue, since
frequency regulation and powerflow recovery underlie all other aspects of power system
behavior. There was a general expectation that improved modeling for this aspect of system
behavior would also improve the modeling of oscillatory dynamics, and would at least provide
a better foundation for refining this aspect of system modeling.
The results reported in [i] and [ii] certainly appear to confirm these expectations. Using
simulation data provided by Les Pereira, Fig. 1 compares the results for two different base
cases against data that were recorded on BPA's Phasor Data Concentrator (PDC) for the 1200
MW Grand Coulee generation trip on June 7, 2000. The new base case, with ggov1 modeling,
achieves a very good match against the PDC record, and the match becomes even better if
initial offsets in the records are reconciled.
The more important modes estimated for the two simulation cases are shown in Table 1. Due
to present lack of official names, the two cases are indicated there as June7_OpCase* and
June7_OpCase**. It may be seen that frequency and damping for June7_OpCase** (the
ggov1 case) are realistically close to those observed for the June 7 brake test, even though the
former involves a much stronger disturbance than the latter. Damping for of the North-South
mode is conspicuously wrong for the other models. This is discussed farther in Appendix A
and reference [v]. Damping for June7_OpCase1* is somewhat more realistic than for June7_OpCase1A.
This is likely a result of different model assumptions, which are as yet not determined.
Measurements obtained for generator trips in the actual system are rarely sufficient for reliable
estimation of modal parameters, and the Grand Coulee generation trip on June 7 was no
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
67
exception to this general rule. Oscillatory response from generator trips is usually not very
strong. Such response as does occur is obscured by ordinary system noise, and is often
rendered nonlinear through discrete control actions (as evidenced by the switching transient in
Fig. 1). However, during the first half of 2002, various large generation trips and RAS actions
have provided some very good benchmarks for combined small signal and large signal
analysis. The event of April 18 was especially notable in this regard [vi], and merits closer
examination.
Model Comparisons against Measured Malin-Round Mountain MW Response
160
CouleeTrip060700GenModelsA
07/30/02_13:16:02
140
switching transient
120
100
new base case with ggov1 model
80
60
40
original base case
20
measured data (BPA PDC)
0
-20
55
60
65
70
75
80
Time in Seconds
Fig. 1. Comparison of MW signals: Models vs. Measured
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Table 1. Estimated modal parameters for tests of June 7, 2000
Estimated from measured response for Brake Insertion #1:
Canada-California:
0.265 Hz @ 6.6 % damping ratio
Alberta
0.391 Hz @ 6.2 % damping ratio
Kemano
(not apparent in measurements)
Estimated from June7_OpCase1A for Brake Insertion #1:
Canada-California:
0.279 Hz @
13.5 % damping ratio
Alberta
0.409 Hz @
7.6 % damping ratio
Kemano
0.508 Hz @
7.0 % damping ratio
parasitic oscillation
0.750 Hz @
1.9 % damping ratio
Estimated from measured response for Grand Coulee generation trip:
(data inadequate for reliable estimates - nonlinearities or extraneous inputs)
Estimated from June7_OpCase* for Grand Coulee trip: (old governor model)
Canada-California:
0.282 Hz @
10.7 % damping ratio
Alberta
0.411 Hz @
6.4 % damping ratio
Kemano
0.502 Hz @
7.9 % damping ratio
parasitic oscillation
0.756 Hz @
2.2 % damping ratio
Estimated from June7_OpCase** for Grand Coulee trip: (governor model ggov1)
Canada-California:
0.270 Hz @
6.4 % damping ratio
Alberta
0.401 Hz @
5.1 % damping ratio
Kemano
0.492 Hz @
8.5 % damping ratio
parasitic oscillation
0.741 Hz @
2.4 % damping ratio
68
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
69
Summary of Measured Data for Staged Trip of Grand Coulee Generation on June 7,
2000
Fig. 2 through Fig. 5 provide a 50 second "snapshot" of measured system response for the June
7 Grand Coulee generation trip. The associated data are available for distribution as an ascii
file called CouleeTrip060700GenModelsA.swx.txt. A general overview of measured data for
the generation trip is provided in Appendix B, and some caveats regarding use of monitor data
are presented in Appendix C.
Summary Plot For CouleeTrip060700GenModelsA
60.02
CouleeTrip060700GenModelsA
07/30/02_13:16:02
60
switching transient
59.98
59.96
59.94
59.92
59.9
59.88
59.86
50
55
60
65
70
75
Time
80
85
90
95
100
Key:
GC50 Grand Coulee Bus Voltage
FreqL
MALN Malin Bus Voltage
FreqL
SYLM Sylmar Bus Voltage
FreqL
SCE1 Devers 500 Bus Voltage
FreqL
Page 1
Fig. 2. Key frequency signals for analysis (BPA PDC)
Summary Plot For CouleeTrip060700GenModelsA
0.04
CouleeTrip060700GenModelsA
07/30/02_13:16:02
GC50 Grand Coulee Bus Voltage
FreqR
0.03
0.02
0.01
0
-0.01
-0.02
-0.03
-0.04
50
55
60
65
70
75
80
85
90
95
100
Page 1
Time
Fig. 3. Grand Coulee frequency relative
to SCE Devers (BPA PDC)
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October 17, 2002
70
Summary Plot For CouleeTrip060700GenModelsA Swings
100
CouleeTrip060700GenModelsA
07/30/02_13:16:02
switching transient
50
0
-50
-100
(initial offsets removed)
-150
-200
50
55
60
65
70
75
Time
80
85
90
95
100
Key:
MALN
Round Mountain 1 Current
MW
SCE1
Palo_Verde 500 kV Line
MW
SCE1
Midway 1
MW
BE23
Celilo 3 Current
MW
BE50
Celilo 1 Current
MW
Page 1
Fig. 4. Key MW signals for analysis (BPA PDC)
Summary Plot For CouleeTrip060700GenModelsA
160
CouleeTrip060700GenModelsA
07/30/02_13:16:02
140
120
100
80
60
40
20
0
-20
55
60
65
70
75
80
Time
MALN
Round Mountain 1 Current
MW
MALN
Round Mountain 2 Current
MW
Fig. 5. Malin MW signals for analysis (BPA PDC)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
71
Modal Analysis of Simulated Data for Staged Trip of Grand Coulee Generation on June
7, 2000
The materials in this section record the processing that was used to obtain the Prony solution
(PRS) results shown in Table 1. All Prony fits were performed with just one signal, on the
time range 3.48+[0 20.04] seconds. Result displays are extended to the maximum record time
(TRange=3.48+3.48+[0 25.48]) to observe extrapolation quality of the PRS model, and to
sharpen Fourier results for the frequency domain comparison of the model against the
measured data.
Detailed PRS results are provided in Table 2 and Table 3. Many of the indicate modes
represent the "trend" in the data as the system model moves toward the post-disturbance
powerflow. The quantities shown as Res Mag and Res Angle are the magnitude and angle of
complex weights (called residues) for the associated modes. The overall Prony solution is then
the weighted sum of responses for the individual modes.
Summary Plot For j7baseCOImwA
160
j7baseCOImwA
07/30/02_13:46:14
140
120
100
80
60
40
20
0
-20
0
5
10
15
time
20
25
30
Malin-Round Mountain 1 MW
Malin-Round Mountain 2 MW
Fig. 6. Key MW signals for analysis (original base case)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
72
Summary Plot For j7ggov1COIA.swx
j7ggov1COIA.swx
07/30/02_13:56:38
Malin Voltage (PU)
1.097
1.096
1.095
1.094
1.093
1.092
Malin Frequency
60
59.98
59.96
59.94
59.92
Malin-Round Mountain 1 MW
150
100
50
0
Malin-Round Mountain 2 MW
150
100
50
0
-50
0
5
10
15
20
25
30
time
Page 1
Fig. 7. Key MW signals for analysis (new base case with ggov1 model)
Summary Plot For j7ggov1COIA.swx
160
j7ggov1COIA.swx
07/30/02_13:56:38
140
120
100
80
60
40
20
0
-20
0
5
10
15
time
20
25
30
Malin-Round Mountain 1 MW
Malin-Round Mountain 2 MW
Fig. 8. Malin MW signals for analysis (original base case)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig. 9. (original base case)
Fig. 10. (original base case)
73
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
74
Malin-Round Mountain 1
40
j7baseCOImwA
07/30/02_13:46:14
30
20
10
0
-10
-20
0
5
10
15
20
25
Time (sec)
Fig. 11. Estimated trend for original base case
Table 2. Prony Solution (PRS) results for Malin MW signal in original base case
TRange=3.48+[0 20.04] seconds; decfac=3
In PRSdisp1: caseID=j7baseCOImwA
casetime=07/30/02_13:46:14
Sorted PRS Table for Malin-Round Mountain 1 MW:
Pole
Freq in Hz
Damp Ratio (pu)
Res Mag
1
-0.00412250
N/A
11.11467986
2
0.46146884
N/A
10.90963050
3
2.37731164
N/A
1.96106896
4
0.28191015
0.10671041
20.43009249
6
0.41060449
0.06434103
16.89681412
8
0.47226909
0.07442559
1.19732617
10
0.50246844
0.07943038
5.47406246
12
0.69390588
0.09340142
11.26065323
14
0.75626534
0.02195537
3.04710372
16
0.79936992
0.12354010
10.61708646
18
0.05637956
-0.19258920
0.23601439
Res Angle
0.00000000
180.00000000
0.00000000
-34.94204740
156.27917285
-60.21881366
-85.57763789
-94.35792134
-167.07127689
89.68477895
178.86146308
Simple trend
Simple trend
Simple trend
Interarea oscillation
Interarea oscillation
Interarea oscillation
Interarea oscillation
Interarea oscillation
Interarea oscillation
Interarea oscillation
Unstable trend
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Fig. 12. PRS setup for new base case with ggov1 model
Fig. 13. PRS results for new base case with ggov1 model
75
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
76
Malin-Round Mountain 1
50
j7ggov1COIA.swx
07/30/02_13:56:38
40
30
20
10
0
-10
-20
0
5
10
15
20
25
Time (sec)
Fig. 14. Estimated trend for new base case with ggov1 model
Table 3. Prony Solution (PRS) results for Malin MW signal in new base case with ggov1 model
TRange=3.48+[0 20.04] seconds; decfac=3
In PRSdisp1: caseID=j7ggov1COIA.swx
casetime=07/30/02_13:56:38
Sorted PRS Table for Malin-Round Mountain 1 MW:
Pole
Freq in Hz
Damp Ratio (pu)
Res Mag
1
-0.00353974
N/A
23.17301186
2
0.03607370
0.43461501
13.38528491
4
0.16674015
0.28305684
3.52542023
6
0.26953481
0.06351427
25.72673876
8
0.40063781
0.05126825
20.88392315
10
0.49154784
0.08539522
5.60187967
12
0.61835407
0.06961341
2.89201190
14
0.73704634
0.05422032
14.76264721
16
0.74139786
0.02421565
4.92001044
18
0.87337897
0.05779392
0.85422923
Res Angle
0.00000000
-171.49341970
178.53528976
-41.78303473
145.53731346
-83.79427916
19.23807436
159.29533366
-77.67431037
-30.00666448
Simple trend
Oscillatory trend
Oscillatory trend
Interarea oscillation
Interarea oscillation
Interarea oscillation
Interarea oscillation
Interarea oscillation
Interarea oscillation
Interarea oscillation
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
77
APPENDIX A. Modal Analysis for Brake Insertion #1 on June 7, 2000: Operating Case 1
Most of the model results examined in Working Note [v] are derived from the first operating
case, referred to here as June7_OpCase1. This case is based upon powerflow file jun7112.sav
(last modified 02/02/01) and dynamics file jun7.dyd (last modified on 02/01/01).
Certain defects were observed in June7_OpCase1. The most important is a strong oscillation
of the Kemano plant, at a frequency near o.55 Hz. Kemano representation for this case is
markedly different from that of the pre-test planning case (June7_PreTest1). To determine
the influence of the Kemano representation , sensitivity comparisons were made between the
pretest case and three variants of the operating case. Overall, the cases examined were the
following:
June7_PreTest1
“Old” Kemano representation
June7_OpCase1
“New” Kemano representation
June7_OpCase1A
New Kemano representation but exciters and PSS units removed
June7_OpCase1B
New Kemano representation but exciter gain reduced to 10%
It should be mentioned that Kemano PSS units are effectively turned off in the new
representation, and that this condition reflects equipment tests performed at the Kemano plant.
Table 4 compares frequency and damping of the primary modes for these cases against those
measured for the first brake insertion on June 7, 2000. Model values for damping of the
Canada-California mode are about twice that estimated from the June 7 test data. As
discussed in a later Section, these estimates are based upon linear model approximations to
response signals that contain (hopefully small) nonlinearities. So, like all estimates, these vary
somewhat as one changes the signals and the signal segments that are processed. The model
results in Table 4 are all based upon the same processing choices, and are mutually consistent.
The measured results in Table 4 represent a reasonable worst case estimate, in that alternate
processing choices have been found that yield damping ratios as high as 7.5% for the CanadaCalifornia mode. This is still about half the model values, however.
It is apparent from Table 4 that changing the Kemano representation for the first operating case
has a strong influence upon swing damping for the Kemano mode, and that it has appreciable
influence upon the two dominant modes. At need, this influence can be quantified through
root locus studies. Case June7_OpCase1A, though probably not correct with respect to
Kemano behavior, is being used as the basis for present studies. Reasons for this are that Case
June7_OpCase1A is free of the strong Kemano signal that obscures main grid response in
June7_OpCase, and that the Kemano signal seems somewhat underdamped in
June7_OpCase1B. This issue can be revisited as model calibration progresses.
The modifications in Kemano representation still leave the model with a small parasitic mode
near 0.75 Hz. This is clearly observable at the Kinport and at the Colstrip generators (these
plants are swinging nearly in phase). Kinport modeling was a notorious source of such defects
earlier years, and it should be reviewed again from this standpoint.
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Table 4. Estimated modal parameters for Brake Insertion #1 on June 7, 2000
Estimated from measure response:
Canada-California:
0.265 Hz @ 6.6 % damping ratio
Alberta
0.391 Hz @ 6.2 % damping ratio
Kemano
(no measurements provided)
Estimated from June7_PreCase1:
Canada-California:
0.252 Hz @ 15.6 % damping ratio
Alberta
0.438 Hz @ 7.6 % damping ratio
Kemano
0.646 Hz @ 7.4 % damping ratio
parasitic oscillation
(not observed)
Estimated from June7_OpCase1:
Canada-California:
0.283 Hz @ 12.6 % damping ratio
Alberta
0.416 Hz @ 7.1 % damping ratio
Kemano
0.552 Hz @ 1.7 % damping ratio
parasitic oscillation
0.751 Hz @ 1.6 % damping ratio
Estimated from June7_OpCase1A:
Canada-California:
0.279 Hz @ 13.5 % damping ratio
Alberta
0.409 Hz @ 7.6 % damping ratio
Kemano
0.508 Hz @ 7.0 % damping ratio
parasitic oscillation
0.750 Hz @ 1.9 % damping ratio
Estimated from June7_OpCase1B:
Canada-California:
0.281 Hz @ 12.5 % damping ratio
Alberta
0.411 Hz @ 6.6 % damping ratio
Kemano
0.504 Hz @ 1.5 % damping ratio
parasitic oscillation
0.751 Hz @ 1.8 % damping ratio
78
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
79
APPENDIX B. BPA PDC Records for Grand Coulee Trip on June 7, 2000
Fig. 15 through Fig. 20 show data that were collected on BPA's Phasor Data Concentrator for
the Grand Coulee Trip on June 7, 2000. The parent file is BPA2_0006072029.dst, for which
recording started at 07-Jun-2000 20:29:08.633 GMT Standard. The extracted signals are as
indicated in Table 5. The phasor measurement units (PMUs) may have been out of
synchronism with the GPS reference. The angle information from these PMUs is accordingly
suspect, but the other signals are regarded as valid.
The extracted signals are available for distribution in the following files:
a)
CouleeTrip060700GenModelsA.mat. A 180 second Matlab binary file containing the named
quantities indicated in Table 6.
b) CouleeTrip060700GenModelsA.swx.txt. A 50 second "swing export" ASCII file containing
data for just the time interval [50 100] seconds. Can be read by Excel or similar applications.
The DSI Toolbox reads these files as data types 9 and 3 respectively.
Table 5. BPA PDC Signals for Grand Coulee Trip on June 7, 2000
%
%
%
%
%
%
%
%
%
%
%
%
%
%
%
%
%
%
%
%
%
%
%
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Time
MALN
MALN
SCE1
GC50
JDAY
JDAY
COLS
SCE1
BE23
BE50
GC50
MALN
SYLM
SCE1
GC50
MALN
SYLM
SCE1
GC50
MALN
SYLM
SCE1
Round Mountain 1 Current
Round Mountain 2 Current
Palo_Verde 500 kV Line
Chief Joseph Current
Marion 1 Current
Hanford 1 Current
Broadview 1 Current
Midway 1
Celilo 3 Current
Celilo 1 Current
Grand Coulee Bus Voltage
Malin Bus Voltage
Sylmar Bus Voltage
Devers 500 Bus Voltage
Grand Coulee Bus Voltage
Malin Bus Voltage
Sylmar Bus Voltage
Devers 500 Bus Voltage
Grand Coulee Bus Voltage
Malin Bus Voltage
Sylmar Bus Voltage
Devers 500 Bus Voltage
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
VMag
VMag
VMag
VMag
VAngL
VAngL
VAngL
VAngL
FreqL
FreqL
FreqL
FreqL
Table 6. Contents of file CouleeTrip060700GenModelsA.mat
Name
CFname
CaseComR
PSMfiles
PSMreftimes
PSMsigsX
PSMtype
chankeyX
namesX
tstep
Size
1x16
50x84
1x19
1x1
5400x23
1x11
23x45
23x38
1x1
Bytes
32
8400
38
8
993600
22
2070
1748
8
Class
char array (global)
char array
char array (global)
double array (global)
double array
char array (global)
char array
char array
double array
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
80
Summary Plot For CouleeTrip060700GenModels
CouleeTrip060700GenModels
07/30/02_11:06:52
200
MALN
Round Mountain 1 Current MW
MALN
Round Mountain 2 Current MW
0
-200
200
0
-200
SCE1
-520
Palo_Verde 500 kV Line
MW
-540
-560
GC50 Chief Joseph Current
200
MW
0
-200
JDAY
440
Marion 1 Current
MW
Hanf ord 1 Current
MW
420
400
JDAY
-600
-700
-800
COLS Broadv iew 1 Current
480
MW
460
440
200
SCE1
Midway 1
MW
BE23
Celilo 3 Current
MW
BE50
Celilo 1 Current
MW
150
100
500
400
300
400
300
200
50
55
60
65
70
75
80
85
90
95
100
Time
Fig. 15. BPA PDC Records for Grand Coulee Trip on June 7, 2000 (1/3)
Page 1
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
81
Summary Plot For CouleeTrip060700GenModels
CouleeTrip060700GenModels
07/30/02_11:06:52
GC50 Grand Coulee Bus Voltage
552
VMag
550
548
546
555
MALN Malin Bus Voltage
VMag
SY LM Sy lmar Bus Voltage
VMag
550
545
240
235
230
225
535
SCE1 Dev ers 500 Bus Voltage
VMag
GC50 Grand Coulee Bus Voltage
VAngL
530
525
0
-500
-1000
0
MALN Malin Bus Voltage
VAngL
SY LM Sy lmar Bus Voltage
VAngL
-500
-1000
500
0
-500
-1000
SCE1 Dev ers 500 Bus Voltage
0
VAngL
-500
-1000
50
55
60
65
70
75
80
85
90
95
100
Time
Fig. 16. BPA PDC Records for Grand Coulee Trip on June 7, 2000 (2/3)
Page 1
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
82
Summary Plot For CouleeTrip060700GenModels
CouleeTrip060700GenModels
07/30/02_11:06:52
GC50 Grand Coulee Bus Voltage
60.1
FreqL
60
59.9
59.8
MALN Malin Bus Voltage
60.05
FreqL
60
59.95
59.9
60.1
SYLM Sylmar Bus Voltage
FreqL
SCE1 Devers 500 Bus Voltage
FreqL
GC50 Grand Coulee Bus Voltage
VAngR
60
59.9
59.8
60.05
60
59.95
59.9
-120
-130
-140
(PMU out of synchronism?)
-150
15
MALN Malin Bus Voltage
VAngR
SYLM Sylmar Bus Voltage
VAngR
10
5
0
112
110
(PMU out of synchronism?)
108
106
SCE1 Devers 500 Bus Voltage
1
VAngR
(reference bus for relative angles)
0
-1
50
55
60
65
70
75
80
85
90
95
Time
Fig. 17. BPA PDC Records for Grand Coulee Trip on June 7, 2000 (3/3)
100
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
83
Summary Plot For CouleeTrip060700GenModels
CouleeTrip060700GenModels
07/30/02_11:06:52
556
MALN Malin Bus Voltage
VMag
MALN Malin Bus Voltage
FreqL
554
552
550
548
60.05
60
59.95
59.9
150
MALN
Round Mountain 1 Current MW
MALN
Round Mountain 2 Current MW
100
50
0
-50
150
100
50
0
-50
SCE1 Palo_Verde 500 kV Line
-520
MW
-530
-540
-550
-560
50
55
60
65
70
75
80
85
90
95
100
Time
Page 1
Fig. 18. BPA PDC Records for Grand Coulee Trip on June 7, 2000 (Malin detail #1)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
84
P 6: MALN Malin Bus Voltage
FreqL
LcaseID=CouleeTrip060700GenModels casetime=07/30/02_11:06:52
60.02
60
59.98
59.96
59.94
59.92
50
55
60
65
70
75
80
Time in Seconds
85
90
95
Fig. 19. BPA PDC Records for Grand Coulee Trip on June 7, 2000 (Malin detail #2)
P 8: MALN Round Mountain 2 Current MW
LcaseID=CouleeTrip060700GenModels casetime=07/30/02_11:06:52
160
140
120
100
80
60
40
20
0
-20
50
55
60
65
70
75
80
Time in Seconds
85
90
95
Fig. 20. BPA PDC Records for Grand Coulee Trip on June 7, 2000 (Malin detail #3)
APPENDIX C. Likely Discrepancies in Monitor Records for WSCC Events
System measurements for tests and disturbances should be interpreted with due regard for their
imperfections. These include the following:
•
calibration errors (primarily scaling & offsets)
•
inadequate bandwidth (primarily in analog transducers & communication channels)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
85
•
processing artifacts & aliasing (all transducers & communication channels)
•
loss of GPS synchronism (primarily in PMUs)
•
timestamp errors
•
mislabeled signals
•
failed equipment
Fig. 21 shows offset errors that are known to exist in BPA monitor data for the tests of June 7,
2000 [vii,viii]. Fig. 22 through Fig. 24 show that low bandwidth analog transducers often
provide a distorted view of transient events, while signals from high bandwidth analog
transducers agree closely with those provided by the Macrodyne PMU. The use of
synchronized phasor measurements to correct timestamp and filter effects in monitor records
collected from analog instrumentation is addressed in [viii].
Summary Plot For ProbeNoise_Interactions1_BPA
350 ProbeNoise_Interactions1_BPA
12/11/01_13:30:48
300
250
200
150
100
50
0
Key:
200
400
MALN
600
800
1000
Time
1200
1400
Round Mountain 1 Current MW
Malin-Round
Mountain #1 MW (MW)
1600
1800
(PDC)
(PPSM)
Fig. 21. Signal offsets in BPA records for WSCC system tests on June 7, 2000
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
86
Summary Plot For Malin_Transducer_ChecksA Swings
200
Malin_Transducer_ChecksA
12/20/01_14:37:38
100
0
-100
-200
-300
-400
1215
1220
1225
1230
1235
Time in Seconds
Malin-Round Mountain #1 MW (fast analog transducer)
PG&E Malin Sum MW
(special EMS signal)
PG&E Captain Jack MW
(slow analog transducer)
PG&E Olinda MW
(slow analog transducer)
Fig. 22. Malin area PPSM signals for Chief Joseph dynamic brake insertion #1 on June
7, 2001
Summary Plot For ProbeNoise_Interactions1_BPA Swings
ProbeNoise_Interactions1
12/07/01_16:25:
80
60
40
20
0
-20
-40
107
108
108
109
109
110
Time in Seconds
MALN
Round Mountain 1 Current MW
Malin-Round Mountain #1 MW
(PMU)
(fast analog transducer)
Fig. 23. PMU vs. PPSM signals at Malin (PPSM timestamp corrected)
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
87
Summary Plot For ProbeNoise_Interactions1_BPAxducers
100 ProbeNoise_Interactions1_BPAxduc
12/10/01_09:06:5
50
0
-50
-100
0
1
2
BE23
3
4
5
Time
Celilo 4 Current
6
MW
7
8
9
10
(PMU)
LADWP Celilo 230 kV MW (slow analog transducer)
Fig. 24. PMU vs. PPSM signals at Celilo (PPSM timestamp corrected)
References
[i]
New Thermal Turbine Governor Modeling for the WECC, principal investigator Les Pereira. WECC
Modeling and Validation Work Group, July 26, 2002.
[ii]
Sample Disturbance Simulations - WECC Study Program Disturbances with the New Thermal
Governor ggov1 Model, Donald Davies. M&VWG Working Note, July 13, 2002.
[iii] WSCC SUMMER 2000 SYSTEM STAGED TESTS AND VALIDATION STUDIES—TEST PLAN,
prepared by the WSCC Performance Validation Task Force (PVTF) of the Modeling and Validation Work
Group. May 5, 2000.
[iv] Interim Report on the Model Validation Tests of June 7, 2000 -- Part 1: Oscillatory Dynamics,
principal investigator J. F. Hauer. WSCC Performance Validation Task Force (PVTF) of the Modeling and
Validation Work Group, October 26, 2000.
[v]
Model Comparisons Against the Model Validation Tests of June 7, 2000 -- Oscillatory Dynamics in
Operating Case 1, J. F. Hauer. M&VWG Working Note, March 22, 2001.
[vi] Preliminary Analysis of Western System Response to the NW Generation Trip Event of April 18,
2002, J. F. Hauer and J. W. Burns. Working Note for the WSCC Disturbance Monitoring Work Group,
partial draft of April 25, 2002.
[vii] Possible Scaling Discrepancies for BPA Monitor Data Collected During WSCC Tests on June 7, 2000,
J. F. Hauer. M&VWG Working Note, December 11, 2001.
[viii] Use of Synchronized Phasor Measurements to Correct Timestamp and Filter Effects in Monitor
Records Collected from Analog Instrumentation: Applied to Records of June 7, 2000 and August 10,
1996, J. F. Hauer. M&VWG Working Note, December 21, 2001
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
APPENDIX 6
MODELS IN THE WECC 2006HS2SA BASECASE
88
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Sorted by Area Name
AREA- -----NAME---54 ALBERTA
14 ARIZONA
50 B.C.HYDRO
60 IDAHO
21 IMPERIALCA
26 LADWP
20 MEXICO-CFE
62 MONTANA
18 NEVADA
10 NEW MEXICO
40 NORTHWEST
65 PACE
30 PG AND E
70 PSCOLORADO
22 SANDIEGO
64 SIERRA
24 SOCALIF
52 W KOOTENAY
19 WAPA L.C.
73 WAPA R.M.
63 WAPA U.M.
89
New Thermal Turbine Governor Modeling for the WECC
October 17, 2002
Sorted by Area Number
AREA
NAME
10 NEW MEXICO
14 ARIZONA
18 NEVADA
19 WAPA L.C.
20 MEXICO-CFE
21 IMPERIALCA
22 SANDIEGO
24 SOCALIF
26 LADWP
30 PG AND E
40 NORTHWEST
50 B.C.HYDRO
52 W KOOTENAY
54 ALBERTA
60 IDAHO
62 MONTANA
63 WAPA U.M.
64 SIERRA
65 PACE
70 PSCOLORADO
73 WAPA R.M.
90