section 2 scada-ems 2-file 2

This document contains Siemens Power Transmission & Distribution, Inc. Confidential and Proprietary Information

and is subject to the restrictions stated on the proprietary page.

Volume II

Network Analysis Applications

IME WGI SCADA 30-0124 01/05 Contents Siemens EMA



CONTENTS

1. Energy Management Applications Software 1 2. Power Applications Software 1

2.1 Load Frequency Control 5 2.1.1 General 5

2.2 Performance Monitor 14 2.2.1 General 14 2.2.2 Control Performance Standards 14

2.3 Reserve Monitor 14 2.3.1 General 14 2.3.2 Concept 15

2.3.2.1 Active Reserve Monitoring 15 2.3.2.2 Reactive Reserve Monitoring 18

2.4 Economic Dispatch 19 2.4.1 General 19 2.4.2 Dispatch Calculations 19 2.4.3 Concept 20

2.5 Constrained Economic Dispatch – Option 1 23 2.5.1 General 23 2.5.2 Concept 24

2.6 Constrained Economic Dispatch – Option 2 24 2.6.1 General 24 2.6.2 Concept 24 2.6.3 Method 25

2.7 Production Costing 25 2.7.1 General 25 2.7.2 Concept 25

2.8 Interchange Transaction Scheduler 27 2.8.1 General 27 2.8.2 Concept 28

2.8.2.1 Pre-Scheduling 28 2.8.2.1.1 Contracts 28 2.8.2.1.2 Transactions 28 2.8.2.1.3 Schedules 28

2.8.2.2 Scheduling 29 2.8.2.3 Summaries 29 2.8.2.4 Maintenance 29 2.8.2.5 Interfacing 29

2.8.2.5.1 Instantaneous Net Scheduled Interchange 29 2.8.2.5.2 Inadvertent Interchange 30 2.8.2.5.3 ASCII File Import 30 2.8.2.5.4 User Interface 30

2.9 Economy A Evaluation (EconA) 31 2.9.1 Overview 31 2.9.2 Concept 31

2.10 Energy Accounting 32 2.10.1 Overview 32 2.10.2 Concept 32

IME WGI SCADA 30-0124 01/05 Volume II, Contents i Siemens EMA



3. Network Analysis Applications Software 1 3.1 Model Update (MU) 5

3.1.1 MU Functional Description 5 3.1.2 MU Interface with Other Functions 6 3.1.3 MU Algorithm 7 3.1.4 MU User Interface 7

3.2 State Estimator (SE) 8 3.2.1 SE Functional Description 11 3.2.2 SE Interface with Other Functions 13 3.2.3 SE Algorithm 14 3.2.4 SE Measurement Set 17 3.2.5 SE User Interface 18

3.3 Network Parameter Adaptation (NPA) 20 3.3.1 NPA Functional Description 20 3.3.2 NPA Interface with Other Functions 21 3.3.3 NPA Algorithm 22 3.3.4 NPA User Interface 25

3.4 Security Analysis (SA) 25 3.4.1 SA Functional Description 27 3.4.2 SA Interface with Other Functions 29 3.4.3 SA Algorithm 29 3.4.4 SA Contingency Screening 32

3.4.4.1 SA Performance Indices 32 3.4.4.2 SA Real Power Performance Index 32 3.4.4.3 SA Voltage/Reactive Power Performance Index 32 3.4.4.4 SA Contingency Ranking 33 3.4.4.5 Computational Efficiency of SA Contingency Screening 34

3.4.5 SA User Interface 35 3.5 Voltage Scheduler (VS) 36

3.5.1 VS Functional Description 36 3.5.2 VS Interfaces with Other Functions 37 3.5.3 VS Algorithm 37 3.5.4 VS User Interface 38

3.6 Dispatcher Power Flow (DPF) 39 3.6.1 DPF Functional Description 40 3.6.2 DPF Interface with Other Functions 43 3.6.3 DPF Algorithm 43 3.6.4 DPF User Interface 47

3.7 Outage Scheduler (OS) 51 3.7.1 OS Functional Description 52 3.7.2 OS Interface with Other Functions 54 3.7.3 OS Algorithm 54 3.7.4 OS User Interface 54

3.8 Short Circuit Calculations (SCC) 57 3.8.1 SCC Functional Description 58 3.8.2 SCC Interface with Other Functions 60 3.8.3 SCC Algorithm 61

3.8.3.1 Formation and Factorization of the Bus Admittance Matrix 63 3.8.3.2 Network Modifications 64

3.8.4 SCC User Interface 64 3.9 Network Analysis Execution Control 67

IME WGI SCADA 30-0124 01/05 Volume II, Contents ii Siemens EMA



4. Forecast/Scheduling Application Software 1 4.1 Short-Term Load Forecast 3

4.1.1 Overview 3 4.1.2 Concept 4

4.1.2.1 Updating/Adaptation of Historical Data 5 4.1.2.2 Forecast Algorithms 5 4.1.2.3 Very Short-Term Prediction 7 4.1.2.4 After-the-Fact Error Analysis 7

4.2 Unit Commitment 7 4.2.1 General 7 4.2.2 Concept 8 4.2.3 Solution Method 14 4.2.4 Input and Output 16

4.3 Case Comparison (CP) 17 4.3.1 General 17 4.3.2 Concept 17

5. Operator Training Simulator (OTS) 1 5.1 OTS Executive Overview 1 5.2 Introduction and Overview 3 5.3 OTS Functional Description 5 5.4 OTS Capabilities 7 5.5 OTS Techniques and Algorithms 7

5.5.1 Topology Processor 9 5.5.1.1 Raw Topology Processor 9 5.5.1.2 Power Flow 9

5.5.2 OTS Network Model Output 10 5.5.3 OTS Load Modeling 11

5.5.3.1 Load Models 11 5.5.3.2 Cold Load Models 11

5.5.4 OTS Dynamic Modeling 13 5.5.5 OTS System Dimensionality and Generator Coherency 14 5.5.6 The OTS Power Plant 15 5.5.7 VAR Resources 18 5.5.8 HVDC Model 18 5.5.9 OTS Relays 18 5.5.10 External Generation Control Areas 19 5.5.11 Simulation of Voltage Collapse 19 5.5.12 OTS Sizing Considerations 20 5.5.13 OTS Performance 20

5.6 OTS Educational Subsystem 21 5.6.1 Conditional Events 22 5.6.2 Session Support 23 5.6.3 Base Case Creation 24 5.6.4 PSM Reports 24

5.7 Heuristic Scenario Builder (HSB) [Optional] 24 5.8 Transient Stability [Optional] 25 5.9 OTS User Interface 25

5.9.1 Event Editor 25 5.9.2 Event Library Maintenance 25 5.9.3 Condition Editor 26 5.9.4 Performance Measurement Editor 26 5.9.5 Instructor Message Window 26 5.9.6 One-Line Diagrams 27

IME WGI SCADA 30-0124 01/05 Volume II, Contents iii Siemens EMA



IME WGI SCADA 30-0124 01/05 Volume II, Contents iv Siemens EMA

5.9.7 Sample Displays 27 5.10 Base Case and Event Library Maintenance 30

5.10.1 Motivation and Discussion 30 5.10.2 Outline of Solution of Case Retention 31 5.10.3 OTS Capability for Case and Event Library Retention 31

6. DMS Applications Software 1 6.1 Operations Support Applications 3

6.1.1 Outage Management System (OMS) 3 6.1.2 Switching Procedure Management (SPM) 5 6.1.3 Fault Location 7 6.1.4 Fault Isolation and Service Restoration 9 6.1.5 Free Placed Jumpers, Grounds, and Cuts 12 6.1.6 Graphical Query 13

6.2 Network Analysis Applications 14 6.2.1 Topology Processing 14 6.2.2 Distribution System Power Flow (DSPF) 16

6.2.2.1 Power Flow Solution 16 6.2.2.2 Equipment Modeling Within the Power Flow Solution 17 6.2.2.3 Load Setup 18 6.2.2.4 DSPF Executions 19 6.2.2.5 Input Data 19 6.2.2.6 Output Data 21

6.2.3 Volt/Var Control 22 6.2.3.1 Volt/Var Optimization Procedure 22 6.2.3.2 VVC Execution 23 6.2.3.3 Input Data 23 6.2.3.4 Output Data 24

6.2.4 Optimal Feeder Reconfiguration 24 6.2.4.1 Solution Procedure for Feeder Reconfiguration 25 6.2.4.2 Input Data 26 6.2.4.3 Output Data 26

6.3 Planned Functions 27 6.3.1 Cold Load Pickup 27 6.3.2 On-Line Short Circuit Calculation 27 6.3.3 Transformer Load Management 28 6.3.4 Load Forecasting 28

1. Energy Management Applications Software

The Energy Management applications provide the system dispatcher with tools that help analyze and manage the available energy resources and transmission capabilities of the power system. These applications are characterized by algorithmically intensive software designed to assist the dispatcher in optimizing system performance, including both economics and security.

These applications share the common environment of User Interface, Basic System Software, etc., that also support the applications described in preceding sections (Volume I) of this proposal, as illustrated in Figure 1-1.

The major categories for these applications are:

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User Interface StandardsUser Interface StandardsPower Applications – Section 2

Network Analysis Applications – Section 3

Forecast and Scheduling Applications – Section 4

Dispatcher Training Simulator Subsystem – Section 5

Distribution Management System – Section 6

Power Applications — These applications are designed to relieve the dispatcher from the task of matching generation resources to load and interchange in an economic and secure manner.

Figure 1-1. Open System Architecture Model

Network Analysis Applications — These applications process the abundance of available SCADA data to provide the dispatcher with a best estimate of the true state of the network, evaluate system security, calculate penalty factors, and analyze control strategies for relieving overloads and reducing network losses. In the study mode, these applications allow the dispatcher to examine current or projected future conditions and evaluate possible control strategies for increasing system performance.


and is subject to the restrictions stated on the proprietary page. IME WGI SCADA 30-0124 01/05 Volume II, Section 1 1-1 Siemens EMA

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OperatingSystem

• Load Frequency Control• Economic Dispatch• Production Costing• Reserve Monitor• Interchange Transaction Scheduler• Interchange Transaction Evaluation A• Energy Accounting• Performance Monitor• Constrained Economic Dispatch

• Model Update• State Estimator• Network Parameter Adaptation• Network Sensitivity• Security Analysis• Power Flow (DPF/OPF)• Voltage Scheduler• Security Dispatch• Short Circuit Calculations• Outage Scheduler

• Short Term Load Forecast• Unit Commitment• Transaction Evaluation• Case Comparison• Hydro Scheduling• Water Worth Value

Forecasting &SchedulingApplicationSoftware

PowerApplicationSoftware

NetworkAnalysis

ApplicationSoftware

SystemSupportSoftware

SCADAApplicationSoftware

Energy ManagementApplications

Energy ManagementApplications

Figure 1-2. Energy Management Applications Software Overview

Forecast and Scheduling Applications — These applications assist the dispatcher in predicting system load, setting commitment schedules, and evaluating the economics of possible interchange transactions.

This suite of applications contains a large number of highly integrated subsystems, representing Siemens' leadership and experience in delivering application software. Through stable and field proven functional interfaces between the applications, additional capability can be realized for the user. For example, future interchange may be evaluated with or without a commitment case, and the results of the economic evaluation analyzed for its affect on system flows, losses, security, etc., using the projected equipment outages for the time of the analysis.





Many such interfaces have been developed both to other application areas (Figure 1-2) and within the energy management applications (Figure 1-3), representing Siemens' commitment and emphasis on providing not only state of the art software, but useful tools for the operations environment.

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InformationManagement

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Simulator

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LFC/ED/RM

InterchangeTransactionScheduler

EnergyAccounting

ProductionCosting

UnitCommitment

LoadForecast

TransactionEvaluation

ModelUpdate

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VoltageScheduler

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Study SecurityAnalysis

Real- TimeStudy

Operator Training

NetworkAnalysis

Forecast &Scheduling

PowerApplications

Model Update

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StudyVoltage

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Information Management

Figure 1-3. Power System Applications Overview

2. Power Applications Software

The power application software performs the Automatic Generation Control and dispatching functions of the ECS. It regulates the real power output of generators; economically allocates generating demands among committed units; and calculates operating reserves, production costs, and interchange schedules. It incorporates a logical and comprehensive set of man-machine features for operator supervision and control of generation and interchange. The power application software also calculates production cost data, provides the means for scheduling interchange transactions between companies, and supports the recording of Energy Accounting

data. Figure 2-1 shows the interrelationship of the power application functions

Power ApplicationsSoftware


OperatingSystem

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ProductionCosting

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Figure 2-1. Power Application Software



Major features of the power application programs are:

On-line operator displays that summarize the operational results obtained by execution of the power application programs

Operator entry with verification of values with specified limits using on-line control displays.

Tuning displays through which control parameters for the system and units may be modified for optimum automatic control. These displays also support assessment of unit control response for use in tuning.

Alarms for changes of state and out-of-limits values plus logging of operator actions and system events.

The following sections describe the proposed operation of the Power Applications (PA) functions specified by Iraq SCADA Refurbishment. These are:

Automatic Generation Control (AGC), which consists of:

Load Frequency Control (LFC) 2.1

Performance Monitor (PM) 2.2

Reserve Monitor (RM) 2.3

Economic Dispatch (ED) 2.4

Constrained Economic Dispatch (Option 1) 2.5

Constrained Economic Dispatch (Option 2) 2.6

Production Costing (PC) 2.7

Interchange Transaction Scheduler (ITS) 2.8

Economy A Evaluation (Econ A) 2.9

Energy Accounting (EA) 2.10

The proposal functions are based upon the Iraq SCADA Refurbishment specification and Siemens' experience in implementing other ECS systems containing similar power application requirements.

General Functionality

In real-time the Power Applications require a significant amount of coordination between the control center and the various power plant facilities.

System-wide economic benefits can be achieved if this coordination can be optimized taking into consideration unit efficiencies, fuel costs and availability,



transmission efficiencies, unit and transmission outages as well as interchange power, availability and price.



Survey of Power Applications

The Load Frequency Control function (LFC) provides the control mechanism to link the load dispatch center and the generation units under its supervision.

It enables a utility to meet its own load together with contracts with neighbors while contributing to the regulation of system frequency.

By making small variations to the reference frequency and/or to the scheduled tie-line power it is also possible to control time error and inadvertent energy interchange.

The Performance Monitor (PM) function provides information about the behavior of the power system for control criteria reporting and so that LFC can be adjusted via its tuning parameters to provide a desirable overall performance.

The PM function is designed to enhance the basic reporting activities concerning the internal operation of the LFC function itself.

The Reserve Monitor (RM) helps power system operators prepare for possible sudden loss of generation, arising from unit trips or the outage of interconnections to a neighboring area from which energy is being purchased.

It enables the integrated management by the operator of generation, pumping, interchange, shunt capacitor banks, shunt reactors and interruptible load reserves, with respect to required reserve targets.

The basic Economic Dispatch concept refers to the optimum allocation of load among specified generating units.

Depending upon the end purpose, an optimum unit generation distribution for the real-time power system operation can be used for the following functions:

Automatic Generation Control

Advisory Generation Control

Real-Time rescheduling of scheduled generation.

Constrained Economic Dispatch (CED) is responsible for allocating generation in an optimal manner among the committed units to minimize production costs and to relieve branch overloads. CED is dependent on the Real-Time Optimal Power Flow function to detect security violations and to provide CED with a set of critical constraints and sensitivities.

Production Costing (PC) refers to the calculations which seek to analyze the actual costs of the daily production, to determine the sources of such costs, and to identify opportunities for improvement.



The purpose of the Interchange Transaction Scheduler (ITS) is to enable a power system to define and review the interchange transactions which it has with other areas in the interconnected network.

ITS provides summary information to the operator for review and provides interchange information to the Automatic Generation Control, Economy Dispatch, and Reserve Monitor functions for use in real-time control and monitoring, as well as to Economy A and Unit Commitment for studies

Economy A Evaluation (Econ A) provides the dispatcher with a tool for quick, online, real-time evaluation of proposed sales and purchases of energy. It may also be used in a study mode to plan market strategies.

One important function within an Energy Control System is a well working automatic Energy Accounting system, which is able to deliver information about the current and past energy transfers, generation and consumption. Energy Accounting supports the historical maintenance of accounting data and its archival. Within Energy Accounting, the ability to perform additional calculations is supported. These calculations can be as simple as the grouping of data to calculate additional values or processing of interchange data based on tariff periods.

General User Interface Features of Power Application

The Automatic Generation Control Overview display provides a summary of all available functions as well as an overall health check of a control area.

Access is via poke points and/or softkeys.

Generation Control displays are structured in general to include:

Operating displays

Schedule displays

Parameter displays

Other specific displays

Usage of Technological Address for application data base points enables the visualization of their contents via the standard display building software. Thus, the user can easily create or customize any application data displays in addition to the standard displays.



BF2 959

RMPower System

Frequency 59.979 Hz

Generation 1864 MWNon-AGC 11 MWManual 0 MWScheduled 0 MWEconomic 1853 MW

InterchangeActual 66 MWDesired 75 MW

System LoadActual 1803 MWForecast 1800 MW

2: Process/2: Process/ RealTime - Automatic Generation Control & SchedulingRealTime - Automatic Generation Control & Scheduling

Automatic Generation Control Overview

ED PCM

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ACE 2.4 MW

Sustained GenerationManual 0 MWSchedule 0 MWEconomic 1808 MWTotal 1808 MW

Temporary GenerationTotal 32 MW

Regulating RangeRaise 40 MWLower 25 MW

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Control1808 MW 30.917

Advisory1808 MW 30.917

Target1864 MW 22.390

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Target 9620 $/h

Responsive Ready Operatingfast slow fast slow

res too low res too low res too low res too low5 MW 20 MW 45 MW 62 MW 62 MW

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Generation 1864 MWNon-AGC 11 MWManual 0 MWScheduled 0 MWEconomic 1853 MW

InterchangeActual 66 MWDesired 75 MW

System LoadActual 1803 MWForecast 1800 MW

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Sustained GenerationManual 0 MWSchedule 0 MWEconomic 1808 MWTotal 1808 MW

Temporary GenerationTotal 32 MW

Regulating RangeRaise 40 MWLower 25 MW

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Target1864 MW 22.390

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Current 10757 $/h

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Responsive Ready Operatingfast slow fast slow

res too low res too low res too low res too low5 MW 20 MW 45 MW 62 MW 62 MW

CurrentReserve

Figure 2-2. Automatic Generation Control Overview Display

2.1 Load Frequency Control

2.1.1 General

The overall objective of Load Frequency Control (LFC) is the power output alteration of certain electric generators within a predefined area of an electrical network in response to changes in system frequency and/or tie-line flows as well as their reference values, so as to meet the area's obligations to contribute to system regulation and/or to honor interchange agreements with other areas.

The LFC System enables the above objectives to be met via the integrated management of generation resources from a central location. It includes all of the secondary control features plus enough tertiary control features to enable total unit output (temporary plus sustained components) to be controlled as a single quantity.



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Figure 2-3. LFC Overview

The deviations from the area's obligations are defined in terms of the control expression for Area Control Error: ACE = ∆P + B ∆F

where :

∆P = Net Interchange Error [MW]

∆F = Frequency Error [Hz]

B= System Frequency Bias [MW/Hz]

System time and energy can also be controlled by making small adjustments to the frequency and interchange reference values respectively. This capability is described in subsequent sections.

Interfaces

The LFC software system is closely linked to the Application Data software system. It also relies on supervisory control output software for transmitting the setpoint commands.

The Application Data software system coordinates the interaction between the Economic Dispatch system and the LFC System and supplies these functions with data from the User Interface (control modes, parameters etc.), from Data Acquisition, and from the Scheduling Applications.

Other functions are available to help with the production of schedules if required.

The Control Approach



The general mechanism for correcting the Area Control Error is shown in Figure 2-4. It consists of an outer loop for area control and an inner unit control.

The calculation of area control error takes into account not only the effect of governor response to system frequency and changes in net interchange, but also:

Desired changes in frequency bias from the natural one,

Possible external area control error signals and

The separation of internally generated changes from external changes originating from the power system.

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Figure 2-4. LFC Control Loops

The generation allocation and control algorithm also includes features to enable high speed processing of known generation changes and non-linear and variable unit behavior to be managed.

The control approach consists of five tasks:



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Area ControlGeneration CalculationGeneration DistributionCompensationUnit Control

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Generation Control

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Figure 2-5. LFC Control Approach

Additional necessary auxiliary functions are carried out by a preprocessing module, which performs the following functions :

Status processing of LFC-relevant messages (tie-line connection, etc.)

Interpreting frequency, interchange and unit measurement quality flags

Filtering of frequency and interchange power

Area Control

This module carries out the area control error calculation. The Area Control Error (ACE) represents the deviation of the current situation from the area's obligations.

These obligations can involve frequency, interchange power, time and energy interchange as single items or in certain combinations:

The ACE calculation is controlled via the operator entered control mode:

CONTROL MODE ACE CALCULATION

Constant Frequency ACE : = B * ∆F

Constant net interchange ACE : = ∆P

Tie-line bias ACE : = ∆P + B * ∆F

Constant frequency with time correction ACE : = B * ∆F + Tc

Tie-line bias with time correction ACE : = ∆P + B * ∆F + Tc

Constant net interchange with energy ACE : = ∆P + Ec correction

Tie-line bias with energy correction ACE : = ∆P + Ec + B * ∆F

Tie-line bias with time and energy ACE : = ∆P + Ec + B * ∆F + Tc



where:

B = natural system bias [MW/Hz]

The value of frequency bias used in the ACE calculation consists of a network bias and a plant bias. The network bias is made up from a bias estimate for the load. The plant bias is calculated as the total of the individual bias factors for all on-line units within the area. Alternatively, an operator entered system bias also can be used.

∆P = net interchange error [MW]

The network interchange reference is usually provided by the interchange scheduling system. If AGC is running as power plant controller, it comes from the supervisory AGC system.

∆F = frequency deviation [Hz]

Usually the reference frequency is the nominal frequency of the area. Furthermore, a reference frequency offset can be entered by the operator or can be scheduled.

Ec = energy correction [MW]

Unilateral payback of inadvertent energy (as calculated by Energy Accounting) may be performed by LFC. Energy Accounting maintains separate values for on and off peak inadvertent.

Tc = time correction [MW]

For correcting the electrical time, the (measured) time error is multiplied by an operator entered value (Bt, time bias) for calculating an offset to ACE.

Additionally, a parameter representing a share of externally supplied ACE or an Area Requirement can be added to the term of ACE described above.

Generation Calculation

The purpose of the generation calculation function is to determine the total desired generation of units under LFC control.

In conjunction with ACE, the following terms are taken into account:

Anticipatory Control

Via anticipation logic, it is possible to eliminate an ACE which would exist because of a steadily increasing or decreasing load.

Unit Aid



The ACE represents the deviation of the actual behavior from the area's obligations to meet a pre-defined amount of interchange power at a specific reference frequency. However, the average frequency may be different from the pre-defined value due to external influences not under control of the AGC system. To ensure that limits are respected and all generation can be allocated economically as required, the AGC system takes into account the additional primary control component associated with the frequency deviation (unit aid).

Stabilization

A feedback of the total unit generation reference is used to stabilize the control input in the presence of unexpected unit behavior. If actual generation is not available because of a telemetry failure, the result of the unit simulation (see unit control) is used instead.

Non-Linear Processing

The resulting signal, including all control responsibilities (area control signal), is processed by a Proportional plus Integral (PI) controller with different handling of small and large signals. This non-linear dynamic element consists of the following parts:




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Normal gain

The purpose of the normal gain factor is to enable the overall responsiveness of the control system to be set without disturbing the relationship between the proportional and integral components of the PI-Controller. Normal gain is a dispatcher adjustable parameter.

Small signal gain

The small signal gain is used to set the sensitivity of the AGC system to small values of ACE (i.e., where the normal value of ACE is lower than the noise threshold).

Dead band

The dead band ensures that control action for small random values of ACE is different from control action for normal values.

Integrator

The integration time is always equal to the basic unit control time constant (compensated regulation). Slower speed control (without altering the PI relationship) is obtained by changing the normal gain as described above.

The output of the PI-controller is the total desired generation which is necessary to meet the area's obligations.

Generation Distribution

The generation distribution function is responsible for distributing the total desired generation to AGC units in a way which is consistent with their capabilities defined by the unit operating modes:

Figure 2-6. Unit Operating Modes



Independent units are not considered by the LFC system

Dependent units are supervised by the LFC system, but not on remote control. A setpoint is sent via the Remote Terminal Unit (RTU), if the unit is updated.

Inflexible units do not contribute to system regulation.

Supportive units regulate only when the regulating capacity of flexible units is inadequate

Flexible units are those assigned to normal system regulation.

The source of the base load can be specified by the operator. Manual Ramping is controlled via the specified target value, the ramp rate and/or the ramp time. For generation distribution the total regulating range is divided into three parts:

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Lower Emergency Regulating RangeRegulating LOW

MostConstrained

- Lower operating limit (external)- Calculated limits (internal automatic)- Derated minimum capacity (manual)


MostConstrained

- Upper operating limit (external)- Calculated limits (internal automatic)- Derated minimum capacity (manual)

Figure 2-7. Regulating Ranges

Normal regulating range

The sum of the operator adjustable regulating ranges of all flexible units.



Boosted regulating range

The sum of the emergency regulating range (the range between emergency regulating high and low) of all flexible units minus the normal regulating range.

Assist regulating range

The sum of the emergency regulating range of all assist units.

The procedure for units not in an independent mode is first to allocate sustained generation, and then to subtract it from the total desired generation. The result is the temporary generation, which is split between the regulating units in accordance to their regulating participation (specified by their operating modes and their regulating ranges). Then, the sustained and temporary generation components are individually recombined to obtain the unit desired generations. Units in an independent mode are taken into account only via the effect they have on the area control error. Prohibited regions are crossed with the maximum transient loading rate.

Sustained Generation Allocation:

The allocation process basically consists of incrementing the sustained generation each cycle at current allowable rate until it reaches a defined target value (specified by operator, schedule or Economic Dispatch (ED) ). The target value is limited by the sustained loading range, calculated from the total regulating range and the reserved regulating ranges.

BF2 967

Base Unit

Ramp Unit

Schedule Unit

Economic Unit

Sustained Generation Allocation


BF2 967

Base Unit

Ramp Unit

Schedule Unit

Economic Unit



Permissive Dispatch:

Units in Ramp or Schedule Mode (and without regulation assigned) have their generation frozen by being placed in Base Mode if they are being loaded in the direction which would further violate the limit, if there is a generation disturbance or a limiting occurs. Operator action is then required to return such units to their programmed loading situation after the regulation restriction has been removed.

The temporary generation component is obtained by subtracting the sustained generation component from the total desired generation.

Temporary Generation Allocation:



All regulation resources (e.g., normal or normal plus boost or normal plus boost plus assist) whose total is less than the current temporary generation are defined to be saturated and they simply contribute their maximum available regulating capacity.

The remainder is allocated according to participation factors which are derived as the individual regulating capacities divided by the total regulating capacity over all units on LFC and in this condition.

The regulation participation factors themselves are not available for external manipulation. They are influenced by the unit regulating ranges and operating modes, as well as by operator entry of participation.

Economic Dispatch Activation:

In order to free saturated regulating capacity, and to reduce the time which is used while generation distribution is done in a less economic way, the economic dispatch function is activated immediately whenever the temporary generation exceeds an operator defined limit.

Compensation

The unit generation calculated by the generation dispatch module is compensated, so that all units used by the LFC program have similar average response time (basic unit control time constant) under normal conditions. A smooth change-over between units is activated when routine generation re-distribution is being carried out.

The compensation procedure is bypassed during generation disturbances and during crossing of prohibited regions.

Unit Control

The unit control function enables generating units to be connected to different sources of generation requirements via a variety of unit interface arrangements and signal types.

Generation input processing provides the selection between a manual and an automatic mode and limitation of the corresponding input value where appropriate.

The manual control mode can in general be defined either as:

Reference (i.e., allowing a frequency influence),

Absolute (i.e., not allowing a frequency influence)

Conditional absolute (i.e., not allowing a frequency influence if the frequency deviation is small).

LFC performs both pulse and setpoint output. Selection of pulse or setpoint is done independently for each unit.



A basic unit model is used to simulate unit power output for the purpose of stabilizing unit control and supporting the central LFC algorithm.

The integral control action ensures that the unit power output can be controlled to a true MW value even if some other intermediate control quantity is being used (e.g., a valve position). The unit control error (the input of the integral control module) is calculated as the difference of real unit power output and the result of the unit simulation. Closed loop integral control can be carried out at user request.

The control output process calculates the total unit generation command, translates it into a unit control command, and sends it to the supervisory control output software for transmission to the unit.



Units being controlled are subjected to:

Tests to determine if they are properly following control command

Logic to define their ability to continue to be controlled

2.2 Performance Monitor

2.2.1 General

The Performance Monitor (PM) function provides information about the behavior of the power system under Load Frequency Control (LFC) so that LFC can be adjusted via its tuning parameters to provide a desirable overall performance.

2.2.2 Control Performance Standards

The LFC Performance Monitor examines and reports on LFC control using the NERC (North American Electric Reliability Council) Control performance.

The Control Performance Standards (CPS) are always evaluated based on Tie-Line Bias ACE. Corrections for Unilateral Inadvertent Payback and Automatic Time Error Correction are not included.

CPSI is a measure of the control area’s contribution to maintenance of interconnected system frequency. It is calculated based on clock-minute averages. CPS2 is a measure of the control area’s meeting of its own control obligations. Compliance Factors for CPS1 and CPS2 are calculated and stored in the Relational Data Base Management System (RDBMS). Forms are provided to show daily, monthly, and annual CPS performance.

2.3 Reserve Monitor

2.3.1 General

The Reserve Monitor (RM) manages the risk associated with a range of probable power system contingencies by comparing the reserve contributions with the reserve requirements for a variety of reserve classes (e.g., recovery phases after a disturbance).

Acceptable risk is defined via requirements which are expressed in terms of:

The worst contingency (the loss of largest unit or largest interchang)



Plus an allowable margin (plus or minus) from this amount.

Reserve monitoring is implemented for active and reactive reserves.

2.3.2 Concept

2.3.2.1 Active Reserve Monitoring

For a power system to be able to survive a disturbance and proceed to return to the normal operating state, its power supply capability must be greater than the demand for some specified points in time after the disturbance.

For each specified point in time, the reserve contributions of all reserve elements are totaled for comparison with the requirements. These totals are referred to as Reserve Classes.

The reserve classes and typical response times are shown in the following Table 2-1.

Table 2-1. Typical Response Times for Reserve Classes

Reserve Class Typical Response Time Responsive Reserve (of significance only for isolated networks) 20 seconds Fast Ready Reserve (This is needed to ensure system recovery before fuel transport mechanisms have been able to react completely.)

2 minutes

Slow Ready Reserve (This is the maximum reserve available from readily available sources)

10 minutes

Fast Operating Reserve (This is the reserve which can be most quickly available from that which is not immediately accessible from on-line sources)

30 minutes

Slow Operating Reserve (This is the slowest form of reserve which must be activated from off-line sources)

2 hours

Reserve Elements

Power system elements which contribute to reserve can be either:

Units (hydro, steam, gas turbine)

Interchange transactions

Pumps

Interruptible load

All reserve elements can be designated as being available for reserves or unavailable for reserves by the dispatcher/operator.



Reserve Matrix

Each reserve element can assist with a particular reserve class using a certain reserve calculation type, which depends on the reserve element type and the time after the disturbance (i.e., the response time of the reserve class as shown in Figure 2-8).

BF2 968

Ready OperatingReserve

class

Elementtype

Responsive

Fast Slow Fast Slow

Hydro-Generators Spinning Spinning Standby Standby Standby

PumpsAuto

TrippingAuto

Tripping Tripping Tripping Tripping

PumpGenerators

AutoTripping

AutoTripping

Tripping &Standby

Tripping &Standby

Tripping &Standby

SteamUnits

StoredEnergy

Spinning Spinning WarmStandby

WarmStandby

GasTurbines Spinning

AutoStandby Standby Standby Standby

Inter-change

EmergencyContracts

EmergencyContracts

EmergencyContracts

Interrupt-able load

U/F LoadShedding Tripping Tripping Tripping

BF2 968

Ready OperatingReserve

class

Elementtype

Responsive

Fast Slow Fast Slow

Hydro-Generators Spinning Spinning Standby Standby Standby

PumpsAuto

TrippingAuto

Tripping Tripping Tripping Tripping

PumpGenerators

AutoTripping

AutoTripping

Tripping &Standby

Tripping &Standby

Tripping &Standby

SteamUnits

StoredEnergy

Spinning Spinning WarmStandby

WarmStandby

GasTurbines Spinning

AutoStandby Standby Standby Standby

Inter-change

EmergencyContracts

EmergencyContracts

EmergencyContracts

Interrupt-able load

U/F LoadShedding Tripping Tripping Tripping

Figure 2-8. Reserve Matrix

Reserve Calculation Types

The following reserve calculations are supported:

Stored Energy Reserve

This restricted type of reserve depends solely upon the transient loading rate and the high pressure turbine production factor (stored energy fraction). This reserve mechanism is only associated with thermal units.

Spinning Reserve

Spinning reserve is the reserve that can be made available from synchronized units. It is the difference between current loading point and the current regulating high limit. Spinning reserve is also limited by unit ramping limitations. This constraint for each



reserve class is equal to the unit's maximum sustained rate times the reserve class corresponding time period (e.g., 10 minutes for Slow Ready Reserve).

Standby Reserve

Standby reserve is the contribution from off-line units which can be brought on-line manually (Standby) or automatically (Auto-Standby). The time to bring a unit on-line is derived from the time the unit was actually off-line. A linear relationship is used between warm startup and cold startup.

Pump Reserve

Each pumping unit can be defined as being able to have its pumping action manually (Tripping) or automatically (Auto-Tripping) interrupted in emergencies. In addition, a pumped hydro unit can be quick started as a generator or can be tripped while pumping and restarted as generator (Tripping & Standby).

Interruptible Load Reserve

Each radial feeder can be specified if its load should be included in an interruptible load computation for a feeder group. These feeder loads are then summed to yield the total contribution to reserve for the corresponding group.

The load of such a radial feeder group can be designated as being shed either manually (Tripping) or by an under frequency relay (U/F Load Shedding).

Interchange Reserve

Each interchange transaction can be specified if it can be interrupted in an emergency situation after mutual agreement of the partners (non-firm interchange transaction).

Interchange transactions can be specified which are not active during normal operation but can be activated by the operator in emergency situations (emergency capacity transactions). The scheduled values of both types of interchange are separately summed up to yield their respective contributions to reserve.

Reserve contribution totals are calculated for all reserve elements for each time period (i.e., reserve class). The reserve contribution of each reserve element for each reserve class and the reserve class totals are available on operator displays.

Reserve Requirements

Reserve requirements are defined in terms of the standard risk (loss of the largest unit or of the largest interchange, or a power export to a partner in emergency) and/or a variation from this risk (i.e., an absolute value, or a percentage of the largest unit, of the largest interchange, and/or of the actual load).



2.3.2.2 Reactive Reserve Monitoring

The reactive reserve of generators is calculated as the difference between the actual reactive output and the reactive rating, which is a function of the actual active output:

BF2 969

current P ... current active power outputcurrent Q ... current reactive power output

Q

High Regulating Limit

Q (ind) max.

current Q

Q (cap) max.

currentP

P

Cap. Reserve

Ind. Reserve

Low Regulating LimitBF2 969

current P ... current active power outputcurrent Q ... current reactive power output

Q

High Regulating Limit

Q (ind) max.

current Q

Q (cap) max.

currentP

P

Cap. Reserve

Ind. Reserve

Low Regulating Limit

Figure 2-9. Generator Capability Curve

The generator capability curve can be defined as piecewise linear approximations.

The reactive reserve of static shunt elements is calculated as the difference between the actual amount of reactive power and the nominal capacity.

The inductive and capacitive reserve contributions of the reactive reserve elements are summed separately over the whole network area and over defined parts of the area (zones). The total inductive and capacitive reserve contribution of a zone is checked against operator defined requirements. All reactive reserve contributions (inductive and capacitive) which do not meet the defined requirements will be alarmed.

The reserve contribution of interchanges are defined as the difference between the actual reactive power and definable limits.



2.4 Economic Dispatch

2.4.1 General

Economic Dispatch (ED) is the allocation or change in allocation of the power resources, which are connected to the system at a particular time, to meet the system load and interchange schedules at that time in a manner which minimizes the overall economic cost to the system. The Economic Dispatch function provides the generation base point values for each generation unit that participates in the optimization. For the purpose of this function the on-line units are divided into four groups depending on their operating modes:

Economic - Automatically controlled units regulating their economic desired generation

Manual - Manually controlled units regulating their economic desired generation

Schedule - Automatically controlled units regulating their scheduled generation

Base - Base loaded units

BF2 970

EconomicEconomic

ManualManual

ScheduleSchedule

BaseBaseBF2 970

EconomicEconomic

ManualManual

ScheduleSchedule

BaseBase

Figure 2-10. Unit Loading Groups



2.4.2 Dispatch Calculations

In response to these modes of unit operations, three different dispatch calculations are performed to meet real-time dispatch requirements (i.e., tertiary control) and also the advisory and schedule requirements of the dispatching personnel:

The Control Pass calculates the economic base point values for those units that are automatically controlled to their economic desired generation (i.e., Automatic Generation Control). With every change of the system load, new base point values are evaluated (real-time dispatch).

The Advisory Pass calculates the economic base point values for all the units in the Control Pass plus those single units which are manually controlled and for which the operator desires to have a recommendation as to how they should be loaded for most desirable economics.

The Target Pass computes of the optimum base load for all on-line units for the most desirable system economics. The result of this calculation can be used as reference values by the system dispatcher or by other functions.

2.4.3 Concept

Economic Dispatch is based on the principle of equal incremental costs (i.e., Lambda Dispatch). By application of a fast step-by-step algorithm, lambda is determined in a non-iterative process. This allows the ED cycle time to be very short.

Unit Operating Modes

In the context of Economic Dispatch only some of the operating modes are considered for the inclusion of units in the two dispatch calculation passes. These are:

Economic

Economic advisory

In addition, all on-line units can be included in the target dispatch based operator selection.

Unit Costs

The lambda dispatch algorithm operates with incremental cost curves for the determination of the optimal load allocation among thermal and hydro units. Hydro units are included in the optimization via the use of water consumption curves and Water Worth Values.

For thermal units the incremental cost curve is calculated from the incremental heat rate curve, fuel price, efficiency factor and incremental maintenance cost. The fuel



price may result from different fuel types or different ratios of mixed fuels (multi-fueled units). The incremental heat rate curve selection can be done automatically based on the selected fuel or fuel ratio.

Incremental curves are approximated by linear monotonically increasing segments and curves that have flat or not continuous sections can be accommodated. Uneconomic loading regions around valve points are considered by not operating units in such regions.

Transmission losses are considered by means of Penalty Factors calculated by the Network Sensitivity function (or can be manually entered if necessary).

Unit Limits

Unit operating arrangements like generation limits, regulating ranges, and loading rates are taken into account.



BF2 971

Sustained Loading Range

Economic Upper LimitG

ener

atio

n Le

vel Maximum Unit Capacity

Economic Lower Limit

- Lower operating limit- Calculated limits- Derated minimum capacity


Regulating LOW

Lower ReservedRegulating Range

MaximumRegulating

RangeProhibited Region

Upper ReservedRegulating Range

Regulating HIGH

Total Regulating Range

- Lower operating limit- Calculated limits- Derated maximum capacity

MostConcentrated

MostConcentrated

BF2 971

Sustained Loading Range

Economic Upper LimitG

ener

atio

n Le

vel Maximum Unit Capacity

Economic Lower Limit

- Lower operating limit- Calculated limits- Derated minimum capacity


Regulating LOW

Lower ReservedRegulating Range

MaximumRegulating

RangeProhibited Region

Upper ReservedRegulating Range

Regulating HIGH

Total Regulating Range

- Lower operating limit- Calculated limits- Derated maximum capacity

MostConcentrated

MostConcentrated

Figure 2-11. Resulting Sustained Loading Range

Economic limits for each unit are dispatcher/operator enterable in order to provide for midterm and long-term economic optimization considerations or fuel constraints. For ED purposes a predefined fraction of the maximum loading/ de-loading rate, the sustained loading rate, can be manually input.

Sustained Generation Component

The temporary component (Ptemp ) of the total generation received from Automatic Generation Control (AGC) is transferred to the sustained component by allocating it to the economic units. For the calculation of the total generation to be economically distributed (PED), the sum of the current base points (BP) of the units in economic mode is also determined. Two calculation modes are possible:

Normal (after the fact):...

PED = ΣBPecon + Ptemp

Feed-forward (coping with the system load and interchange development in the near future):.

PED= ΣBPecon + Ptemp + Pfeedforward



Anticipatory Dispatch

Pfeedforward represents the forecasted variations of the load and scheduled variations of interchanges and generators within a certain time range into the future (current time + observation time = T*, e.g., + 5 minutes). Regardless of the normal/feed forward mode the Economic Dispatch results handed over to AGC are base point values with the target time T*.

The effect is that when time T* is reached, the temporary component has been smoothly shifted to the sustained component.

Optimizing the Reserve Constraints

Considering the total amount to be economically distributed, Economic Dispatch checks the responsive and fast ready reserve requirements received from the Reserve Monitor function. If the requirements are not met, Economic Dispatch increases the reserve contributions for some of the economic units by calculating lower reserve limits for others as shown in Figure 2-12:

In this way the minimum generation limits of those units which are loaded with a smaller load than the restricted reserve loading point (group 1) are increased, so that the increments will be enough to meet the reserve requirements. Though these loading offsets do not change the reserve contribution of group 1, the corresponding unloading of the units of group 2 by the same amount causes the desired increase in the reserve contribution.

BF2 972

Generation Level

regulating high

restricted reserve

loading offset

loading point

current loading

regulating low

loading offset

reserve limit

Group 1 Group 2

maximum reserve

restricted reserve

BF2 972

Generation Level

regulating high

restricted reserve

loading offset

loading point

current loading

regulating low

loading offset

reserve limit

Group 1 Group 2

maximum reserve

restricted reserve

Figure 2-12. Altering Generator Loading to Increase Reserve Contribution



Activation

ED can be activated with real-time data cyclically, spontaneously (e.g., due to a significant change in the sustained generation or upon changes in unit operating conditions or unit parameters) or manually on operator request.

Functional Environment

The ED-Control Pass receives the temporary system load component to be economically allocated from the AGC function. Then ED supplies the AGC function with base load values for each unit.

From the Reserve Monitor, the ED-Control Pass receives the amount of generation requirement which is necessary to meet the generation reserve requirements. With this value, ED performs a reserve dispatch prior to allocating generation.

BF2 973

Data Acquisitionand Control

ScheduleManagement

System

ManualScheduling

Unit CommitmentHydro Scheduling

Reserve Monitor Economic Dispatch

ConstrainedEconomicDispatch

Control Pass

Advisory Pass

Target Pass

LFC UI

Optional

BF2 973

Data Acquisitionand Control

ScheduleManagement

System

ManualScheduling

Unit CommitmentHydro Scheduling

Reserve Monitor Economic Dispatch


Control Pass

Advisory Pass

Target Pass

LFC UI

Optional

Figure 2-13. Functional Environment



2.5 Constrained Economic Dispatch – Option 1

2.5.1 General

Constrained Economic Dispatch (CED) is responsible for allocating generation in an optimal manner among the committed units to minimize production costs and to relieve branch overloads. CED is dependent on the Real-Time Optimal Power Flow function to detect security violations and to provide CED with a set of critical constraints and sensitivities.



CED performs the Control and Advisory pass dispatches. With the control pass, CED can be operated in either an open loop or a closed loop mode. In open loop mode, CED results may be monitored by the dispatcher/operator but they will not be used to control generation. In closed loop mode, CED results are used by AGC to control generation and reduce overloads when they exist.

After successful resolution of all branch flow constraints, closed-loop CED remains active until all branch flows are at or below some fraction (typically 90%) of the respective branch limits. This prevents “hunting” which could cause repeated violations. During this period, closed loop CED basically replaces the conventional ED. After the period, the operator is informed that the power system is back at its secure and economic state and that closed-loop CED is ready to be switched off (i.e., the closed loop for CED may now be opened and conventional ED used instead).

2.5.2 Concept

Refer to Section 3.7 of this proposal for a complete description of the Security Constrained Dispatch function which incorporates the Real-Time Optimal Power Flow and Constrained Economic Dispatch.

2.6 Constrained Economic Dispatch – Option 2

2.6.1 General

This option of Constrained Economic Dispatch (CEDEX) covers the functionality of both Economic Dispatch (Section 2.4) and Constrained Economic Dispatch – Option 1 (Section 2.5) as an alternative approach to optimization of real-time power resources. CEDEX minimizes the overall system operating costs with respect to system power balance, reserve requirements, transmission branch capacities, power plant limitations, and generating unit characteristics.

CEDEX performs the Control, the Adivsory, and the Target Dispatch passes under the same conditions and unit operating modes as the Economic Dispatch. Also, an Anticipatory Dispatch is provided. In addition to the branch flow limitations of Option 1 of Constrained Economic Dispatch, Option 2 covers economic and security requirements simultaneously.

2.6.2 Concept

The optimization concept is derived from economical and technical characteristics of power systems. The objective is to minimize the total system production costs subject to:

Power generation balance

This document contains Siemens Power Transmission & Distribution, Inc. Confidential and Proprietary Information and is subject to the restrictions stated on the proprietary page.

IME WGI SCADA 30-0124 01/05 Volume II, Section 2 2-31 Siemens EMA

Spinning reserve requirements

Transmission line capacities

Power plants generation limits

Unit power and reserve characteristics

Unit power output and reserve limits

CEDEX provides the optimal base points for dispatched generating units to support feedback control as a part of Automatic Generation Control.

2.6.3 Method

All dispatch passes utilize a solution technique based on the nonlinear Dantzig-Wolfe decomposition principle. The solution proceeds in two phases. In the first phase the initial feasible solution is provided, while in the second phase the optimal power allocation is achieved. Both phases are performed through iterative solution of System Optimal Dispatch and the set of single Unit Optimal Dispatches.

The System Optimal Dispatch provides the most economical manner of satisfying system requirements (power balance, reserve level, branch capacities and plant limits). The optimal solution is constructed as the best combination of generating unit responses to energy and reserve marginal prices.

On the other side, the Unit Optimal Dispatch provides the most economical unit power outputs under given energy and reserve prices. The optimal unit responses are calculated separately using unit operating cost curves, reserve capabilities, and generating limits.

2.7 Production Costing

2.7.1 General

Production Costing (PC) refers to the calculations which seek to analyze the actual costs of the daily production, to determine the sources of such costs, and to identify opportunities for improvement.

2.7.2 Concept

The system dispatcher is provided with a tool to monitor and summarize the production costs of thermal units and to compare them with the optimal production costs.



The real-time production costs are calculated from the output load of the unit. Missing values, e.g. due to an interrupted data transmission, can be manually entered or corrected.

After each run of the cyclic economic dispatch target pass calculation, the real production costs are compared with the theoretical production costs resulting from the optimal load allocation of the economic dispatch target pass. The theoretical production costs result when all on-line units, except those which are tagged not to be "in target", are operating at equal incremental cost. An alarm message is generated whenever the real-time production cost for the interval exceeds the theoretical production cost by a certain enterable amount.



BF2 974

Man-MachineInterface Report Production

Historicaland

Future Data

DataAcquisition

ProductionCosting

ProductionCosting

Economic Dispatch

Target Pass

BF2 974

Man-MachineInterface Report Production

Historicaland

Future Data

DataAcquisition

ProductionCosting

ProductionCosting

Economic Dispatch

Target Pass

Figure 2-14. Functional Environment

Production costs are computed as a function of:

MWh output

Input/output curves

Type and rate of used fuels

Fuel heat content

Fixed percentage costs associated with fuel type

Efficiency factor

Startup and maintenance costs (fixed and incremental) are also taken into account.

Production Costing provides cost and fuel consumption values for each unit and data base defined groups. Unit group values are used to support plant and system totals



BF2 975

UnitsUnits Unit GroupsUnit Groups

Current Consumptionof Each Fuel Type

Displayed Results

Current Fuel Consumption

Difference Between Total Current and Total

Theoretical Costs


Theoretical Production Costs

Current Production Costs

BF2 975


Current Consumptionof Each Fuel Type

Displayed Results

Current Fuel Consumption

Difference Between Total Current and Total

Theoretical Costs


Theoretical Production Costs

Current Production Costs

Figure 2-15. PC Results

2.8 Interchange Transaction Scheduler

2.8.1 General

The SINAUT Spectrum 3.x Interchange Transaction Scheduler (ITS) separates the user's tasks into pre-scheduling and real-time scheduling components and associates information with date ranges rather than single days. ITS uses the full range of pertinent data a utility has-from contract information all the way down to actual scheduling. ITS is based upon a Relational Data Base Management System (RDBMS) with a graphical user interface (GUI) front-end.

Pre-scheduling consists of Contract, Transaction, and Schedule information. For a given contract with another power company, the data from the actual contract is entered. From this Contract, Transactions are created for possibilities that the contract covers. Additional attributes of the Transaction are also added. Various types of energy can be defined via the Transaction, including interchange, capacity, bilateral inadvertent pay-back, non-metered generation sources, non-metered load sources, and DC-Lines. Schedules are then created from the Transaction attributes, and further attributes are added to define the Schedule.



Real-time scheduling consists of manipulating (creating, deleting, viewing, and modifying) scheduled MW information. This information can be presented as segments or grids. Segments are the underlying concept in ITS. They consist of MW values and start and stop times (segments are graphically represented as trapezoids -- see Segment Figure 2-13). Grids are very traditional-a way to present the scheduled MW data in discrete steps (typically an hour at a time). Segments and grids define target MW power values, and conversion between the two is fully supported - but only stored in the database in segment format. Daylight Saving Time (DST) is fully supported. Instantaneous interchange is calculated for use by Load Frequency Control (LFC), Economic Dispatch (ED), Reserve Monitor (RM), Economy A (EconA), and Unit Commitment (UC).

After the fact cleanup of schedules will typically involve adjusting the segments to agree with Energy Accounting (EA) data as well as the other company data to bring both parties into agreement in preparation for the billing process. The energy information is made available to the EA function for use in calculating inadvertent interchange.

Summary information is provided by means of a System Summary, a Firm/Non-Firm Summary, a Load Summary, a Group Summary, a Company Summary, a Type Summary, and a Company by Type Summary.

2.8.2 Concept

The Interchange Transaction Scheduler function is composed of the following subfunctions:

2.8.2.1 Pre-Scheduling

ITS provides the tools to perform pre-scheduling by defining criteria which will guide the scheduling of power. This is performed by creating, editing, and deleting contract information.

2.8.2.1.1 Contracts

From each Contract, multiple Transactions may be defined. Once attributes are defined in a Contract, they are automatically inherited in any of its Transactions at creation time, where they can be overridden.

2.8.2.1.2 Transactions

From each Contract, multiple Transactions may be defined. Once attributes are defined in a Transaction, they are automatically inherited in any of its Schedules at creation time, where they can be overridden.



2.8.2.1.3 Schedules

From each Transaction, Schedules may be defined. Each Schedule is a specific instance of a Transaction. Once attributes are defined in a Transaction, they are automatically inherited in any of its Schedules at creation time, where they can be overridden. A Schedule defines the framework whereby specific instances of energy can be scheduled via segments or grids, but does not itself include any MW or time data.

2.8.2.2 Scheduling

In Scheduling, the following concepts are used: Segments and Grids. Segments are the underlying principle from which the grids are calculated. Segments form trapezoids when drawn-they is a start/stop scheduling mechanism where the start point, the stop point, the start ramp information, the stop ramp information, and the MW level are specified. Where a start time is specified for the duplicate hour in a 25 hour day, the first occurrence of the hour is assumed. Where a stop time is specified for duplicate hour in a 25 hour day, the second occurrence is assumed.

2.8.2.3 Summaries

Summary information is displayed in many ways in a daily format-System Summaries, System Firm/Non-Firm Summaries, Load Summaries, Group Summaries, Company Summaries, Type Summaries, and Company by Type Summaries. Summaries are available for any date. Where applicable, summary information is sorted first by company, then by transaction type. Inactive schedule data is not used in the calculation of summaries. Daily totals including on and off peak subtotals are included on each summary.

2.8.2.4 Maintenance

On-line maintenance of ITS support data is available for the following data:

Company definitions:

Transaction Type definitions:

Company Loss definitions:

Peak Period definitions:

Daylight Saving Time switchover information

Other types of data can be defined and scheduled, such as Non-metered generation sources, Non-metered loads, and DC-Lines. While these types of data are supported



in the database and in the displays, interfaces for these data are not provided due to varying requirements.

2.8.2.5 Interfacing

ITS interfaces with many other functions in the ECS. Functions which make use of ITS data include LFC, ED, RM, UC, EconA, and EA. Inactive schedule data is not passed to other functions.

2.8.2.5.1 Instantaneous Net Scheduled Interchange

This subfunction calculates the Instantaneous Net Scheduled Interchange (INSI) of LFC. INSI is calculated for LFC to use each cycle from schedule information. The effects of ramping are used in the calculation of INSI. Only active, external company interchange schedule information is used in the calculation of INSI. The ability to use, ignore, augment or override INSI is provided within the LFC function.

This subfunction calculates the Instantaneous Net Scheduled Reserves for use by RM in the calculation of system reserves. The reserve contributions are calculated for RM to use each cycle. The effects of ramping are included in this calculation. Only active capacity schedule information is used.

This subfunction calculates the Instantaneous Net Scheduled Non-Firm Interchange (also known as interruptible interchange) for use by RM in the calculation of system reserves. These reserve contributions are calculated for RM to use each cycle. The effects of ramping are included in this calculation. Only active non-firm interchange schedule information is used.

2.8.2.5.2 Inadvertent Interchange

This subfunction passes the hourly system net scheduled interchange to EA to calculate the system's cumulative inadvertent energy into on-peak and off-peak accounts. This transfer occurs periodically and when changes are made to ITS data. The previous hours’ data is transferred on an hourly basis. All past hours affected by a change are transferred. The hourly system net scheduled interchange is the net of all active external interchange schedules (bilateral pay-back schedules are not included) for an hour.

2.8.2.5.3 ASCII File Import

Segments can be imported via an ASCII file mechanism. When imported, the Segments are placed in temporary import tables. The data is then validated to confirm that it maps correctly to an existing Schedule (by matching the company name, transaction type and suffix, and direction). Once successfully validated, the Segments are automatically imported into ITS and placed on-line. The imported data



can either overwrite any existing data, or can be added in addition to what already exists. If the data does not pass validation, it goes into Accept/Reject tables for review. The data can then be accepted and transferred into the on-line ITS either hour by hour, or for the entire day. Data can be rejected by the user on an hourly or daily basis. Once the data is rejected, it is moved to temporary reject tables, where they can be edited or deleted by the user. Once the user is satisfied with the data, it can be un-rejected either hourly or for the entire day, and then can be accepted. Once deleted from the reject tables, data is erased from ITS.

2.8.2.5.4 User Interface

ITS displays serve as the user's primary interface to ITS. Console function assignment support is provided by the ECS. ITS Display support is provided by the Oracle Forms Designer. ITS is a multi-user function. The following section describes the types of data that are displayed.

For the Segment Scheduling form, a section of each form is devoted to a swapping region that can display different types of information to help reduce information overload. New Segment, Financial, Ramping, Wheeling, and Characteristics sections are supported.

A pop-up calendar is also supported to aid in the selection of dates. Additionally, arrows are available for next/previous record (Contract, Transaction, or Schedule depending upon the display) and next/previous active record for pre-scheduling and scheduling data. A Go To button is provided to select a specific schedule to display. Next/previous day and next/previous week are available on summary displays.

On ITS displays, when underlying data has been changed by another user, a Refresh button will appear to indicate to the user that the displayed data should be refreshed.

2.9 Economy A Evaluation (EconA)

2.9.1 Overview

Economy A Evaluation (EconA) provides a quick tool for dispatchers to use for evaluating proposed short-term energy exchanges, as well as for developing market bid strategies.

It has both a real-time mode, which evaluates energy exchanges based upon current real-time system conditions, and a study mode, which allows for evaluation of single- and multi-hour exchanges starting now or in the future.



2.9.2 Concept

A proposed transaction is modeled in Economy A as:

A direction (sale or purchase)

A maximum size

A number of steps or blocks

A proposed price for each block

The system production (generation) cost is first evaluated without the transaction. Each block is then sequentially added, with the production cost being recalculated based on the change in generation requirements. The change in production cost is compared to the cost of the purchase or income from the sale.

Real-time evaluation allows the dispatcher to define a proposed transaction as described above. Once that is done, pressing a single button causes Economy A to retrieve all current system conditions (load, desired interchange, list of committed units, incremental heat rate curves, fuel costs, penalty factors, et cetera) and immediately evaluate the transaction.

Study evaluation provides separate initialization and evaluation steps. In addition to retrieving data from current system conditions, data for future hours may be retrieved from any of the following functions that are part of the system:

Interchange Transaction Scheduling

Short Term Load Forecast

Unit Commitment

Network Sensitivity

After the data has been retrieved, it may be edited by the dispatcher before evaluation is performed. Repeated “edit-evaluate-analyze” cycles may be performed, if desired

2.10 Energy Accounting

2.10.1 Overview

In an Energy Control System, Energy Accounting (EA) delivers all information about the current and past energy transfer, generation and consumption.

Energy Accounting provides the ability to perform calculations such as data averaging, minima/maxima determinations and contract based calculations, and



stores the data for a specified period of time. The collected and calculated data may be displayed via User Interface.

Energy Accounting maintains data for display for the current day, current week, current month and year.

The storage of the data accommodates daylight savings time.

Interchange Accounting, as a part of Energy Accounting, takes into account the respective tariff rates, which are defined by Interchange Contracts.

2.10.2 Concept

The following figure is an overview of the EA function showing all of its components:

BF2 980

AccumulatorDataProcessing

ApplicationData

InterchangeScheduling

Daily, Weekly,Monthly,

EA-Reports


EA-ReportsEnergy

Accounting

AccumulatedValues

AccumulatedValues

CombinationRules

CombinationRules

ContractsContracts

BF2 980

AccumulatorDataProcessing

ApplicationData

InterchangeScheduling


EA-Reports


EA-ReportsEnergy

Accounting

AccumulatedValues

AccumulatedValues

CombinationRules

CombinationRules

ContractsContracts

Figure 2-16. Overview of the EA function





Value Definition

The accumulated values that are relevant for the energy accounting task are defined via the Database Administration subsystem (DBA). Additionally secondary values can be defined, which serve as destination for the results of calculations upon the primary values.

Calculations

As energy accounting is utility-specific, the Energy Accounting function provides freely definable calculation rules.

Typical calculation rules for accumulated values are sums of several values of one period to a total as well as totals over all the periods of a day. The appropriate rules for these calculations are defined with the Data Base Administration subsystem.

Cyclic

After the termination of a period, when all accumulated values are supplied by the Accumulated Data Processing.

At the end of the tariff day

This is the moment when daily reports are printed for all partners and customers. Additionally, at the end of a week or month, the appropriate reports are printed out.

Recalculation

During report editing the operator can manually substitute accumulated values. All other values, which depend on the substituted values, are recalculated (e.g., totals, sums, costs etc.) on operator command.

Energy Accounting Displays

Energy Accounting displays can be defined or changed on-line by the operator. Energy accounting values can be automatically stored in the Historical And Future Data. Data stored in Historical and Future data may be transmitted to the RDBMS. The features of the RDBMS may be used to display and access the data.

3. Network Analysis Applications Software

This section describes the Network Analysis (NA) subsystem proposed for Iraq SCADA Refurbishment.

The Network Analysis functions are divided into two types: those that execute automatically on a periodic basis are known as the Real-Time (RT) functions and those that execute on demand by the operator are known as the Study (S) functions. The Real-Time and Study Network Analysis functions proposed for Iraq SCADA Refurbishment include:

Real-Time Network Analysis functions:

• Model Update (MU)

• State Estimator (SE)

• Network Parameter Adaptation (NPA)

• Security Analysis (SA)

• Voltage Scheduler (VS)

• Short Circuit Calculations (SCC)

Study Network Analysis functions:

• Study Security Analysis (SA)

• Dispatcher Power Flow (DPF)

• Optimal Power Flow (OPF)

• Outage Scheduler (OS)

• Short Circuit Calculations (SCC)

Figure 3-1 shows an overview of the set of Network Analysis functions proposed for Iraq SCADA Refurbishment.





Network AnalysisApplications Software

Network AnalysisApplications Software

BF2 120

OperatingSystem

Software

Model Update



Network ParameterAdaptation

State Estimator

Security Analysis

Voltage Scheduler

Dispatcher Power Flow / Optimal

Power Flow

Generation ControlAnd Scheduling

Applications



BF2 121-2


OutageScheduler

Figure 3-1. Network Analysis Application Software

Figure 3-2 shows an overview of the proposed set of Real-Time functions. Figure 3-3 shows a detailed relationship of all Real-Time and Study functions proposed for

Iraq SCADA Refurbishment. BF2 309-1

POWER FLOW

REAL TIME NETWORK

MODEL

SHORT CIRCUITCALCULATIONS

CONTINGENCYSIMULATION

STATEESTIMATOR

MODELUPDATE

REALTIME

UPDATE

ONE LINEDIAGRAMS

SECURITY ANALYSIS

NETWORKPARAMETERADAPTATION

TABULARDISPLAY


MODEL

CONTINGENCYSELECTION

VOLTAGESCHEDULER

Figure 3-2. Real-Time Network Analysis Overview





ShortCircuit Calc.

Results

BF2 310

OFF-LINE ON-LINE

SystemDescription

DatabaseGeneration

From Load Forecast

From Unit Commitment

OutageScheduler

Real Time Data

ModelUpdate

StateEstimator

DispatcherPower FlowInitialization

SaveCases


NetworkParameterAdaptation

(NPA)

Real Time

Study

StudyRealTime

Dispatcher/Optimal

Power FlowSecurityAnalysis

To DTS

VoltageScheduler

SecurityAnalysis


SecurityAnalysisResults

(Real-Time)

ShortCircuit

CalculationResults

VoltageScheduler

Results

LoadForecast

Schedules

UnitCommitmentSchedules

OutageSchedules

NetworkDescription

PowerFlow

Results

SecurityAnalysisResults(Study)

NetworkTopology

& Measure-ments

NPAModel

NetworkTopology& SystemSolution

NetworkBase Data

Figure 3-3. Network Analysis Applications – Real-Time/Study

Siemens' Network Analysis functions have been rigorously tested on many large systems with very diverse and complicated power network systems. As a result of this experience, a number of claims can be made for the functions.

The algorithms employed by the Network Analysis functions are field proven on many networks. In recent years Siemens has established the operable use of new algorithms in the field on existing systems before offering them. Development of each new customer's network model has brought improved insight by our staff into representation and analytic solution methods applicable to various electrical equipment and system operating procedures.

The performance of the functions is established. Timings and resource requirements are well known and a high level of confidence can be attached to projected system performance.

Several of the functions use algorithms which are truly state-of-the-art. The State Estimator, for example, uses a fully-coupled orthogonal transformation algorithm

which incorporates line flows, bus voltages, bus injections, ampere measurements, and known zero injections which typically occur at high voltage buses in transmission stations. The Security Analysis function uses the fast decoupled power flow algorithm and adaptive local solution techniques which produces accurate complex power (active and reactive power) solutions at a considerable savings in computer time. It includes a sophisticated screening process to eliminate non-critical contingencies. The Optimal Power Flow (OPF) is a second generation development which incorporates both linear programming and full Newton algorithms to be used as appropriate to the optimization problem at hand; production cost, losses, real or reactive security or combinations of these.

3.1 Model Update (MU)

The Model Update function determines the real-time configuration of the power network for use by the State Estimator and other real-time network analysis functions. It is fully general to effectively process any type of station layout. The same topology processing algorithm as used in Model Update is used in the Study Network Analysis functions, such as power flow, to support study case network configurations.

The function takes as input:

Telemetered logical device status (circuit breakers and/or disconnect switches)

Telemetered tap positions for LTC or phase shifter transformers

Manual entry or override of the above data by the operator

Normal or default status from the database

In study case use, the algorithm can accept as input either a copy of the real-time configuration or a saved study case configuration.

Model Update constructs a bus-oriented model of the network. In this process, connections within each station are separately maintained as are the voltage levels within stations. Electrical islanding is detected as well.

3.1.1 MU Functional Description

The Model Update function builds the bus oriented network model for use by other network analysis functions. Some of the features of the Model Update function are:

Processes logical device status

Performs a topological analysis



Builds the bus model of the network

Algorithmically organized on a station/voltage level basis

Detects electrical islanding

Maintains equipment energized/de-energized status

Used in real-time and study analyses

STATICNETWORK

DATA

NETWORK PARAMETERADAPTATION

AGC

BF2 311

STATEESTIMATOR

POWERFLOW

ANALOGMEASURE-

MENTSSCADA

MEASURE-MENT DATA


REAL TIMEBUS

MODEL

REAL TIMENETWORKSTATUS

RETRIEVALOF STATUS

ANDANALOGS

STATION MODEL REBUILD

STATICNETWORK

DATA


AGC

BF2 311

STATEESTIMATOR

POWERFLOW

ANALOGMEASURE-

MENTSSCADA

MEASURE-MENT DATA


REAL TIMEBUS

MODEL

REAL TIMENETWORKSTATUS

RETRIEVALOF STATUS

ANDANALOGS

STATION MODEL REBUILD

Figure 3-4. Overview of the Model Update Function

Network data is available from several sources. Network topology and normal status of breakers, switches, etc., are always available from the network database; the real-time status and analog values for measurements are obtained from the SCADA database. Further, manual entries of status external to the SCADA system and operator override of SCADA status may be made from one-line displays associated with the Model Update function. System load and current unit parameters are obtained from Automatic Generation Control, time-switched breaker positions and load parameters are obtained from Network Parameter Adaptation.

At the start of each real-time Network Analysis sequence, Model Update obtains the latest data from each of its sources to construct a single model of the entire network (both internal and external companies).



Normally, Model Update executes automatically at the frequency required for State Estimator executions and when pre-defined network switching devices operate; however, it may also be executed by an operator request.

3.1.2 MU Interface with Other Functions

Model Update interfaces with the following functions:



Acquisition: To obtain real-time status and analog network data.

State Estimator: The State Estimator uses the analog measurements and the real-time bus model to obtain a complete steady-state solution of the network.

Power Flow: Receives the network model for study purposes.

Network Parameter Adaptation: To obtain time-switched breaker status and load data. The current status of telemetered switches are sent to NPA to support the adaptation process.

Automatic Generation Control: The system load and various operating unit parameters are obtained from generation control.

3.1.3 MU Algorithm

Model Update first accesses the latest status and analog telemetry from the SCADA database. The analog quantities are then stored for use by the State Estimator. Status is then merged with the normal status from the base data to give a complete real-time status for the entire network. (Manual overrides entered via SCADA are also respected by Model Update, so they need not be re-entered.) This status is next compared to the previous real-time status, and a list of those stations where differences occur is compiled and stored. If no stations have changed, the State Estimator is executed directly; if changes have occurred, the station model rebuild logic is executed to update the network model for those stations with status changes.

A list of changed stations resides in the real-time network status area, along with the new status. Station model rebuild logic processes each station in the list independently. It obtains the topology of equipment in the station in terms of nodes from the network base data; nodes are then sorted into buses based on what logical devices are closed in the real-time status; finally, equipment attached to a node is listed with the bus of which that node is a part. The resulting station model is stored into the real-time bus model area, replacing the old model for that station. When all changed stations have been processed, the State Estimator is executed.

3.1.4 MU User Interface

Real-Time Network Status Displays: These are the data entry displays for Model Update. They display network statuses for all logical devices, transformer taps and phase-shifter taps defined in the network database. These displays are primarily used to complement usage of the one-line diagrams which normally describe only the areas covered by the SCADA system. They allow the operator to view and manually alter network status for the entire system for use by the real-time Network Analysis functions.



Network status is displayed on one-line diagrams. The one-line diagram displays the network connectivity. The one-lines as a group explicitly show each status which the operator may need to change or review.



The types of variables which may be displayed and entered are:

Logical device status

LTC Transformer tap position

Phase-Shifter tap position

Analog measurement status

For the first three types, operator entry overrides any telemetered value, and the entered value is used. In the latter case, analogs may be removed from consideration in the State Estimator by changing its status, but operator entry of an analog value is not permitted.

Outaged Equipment Summary Display: This display lists the outaged equipments.

Abnormal Devices Summary Display: This display lists the logical devices with abnormal status.

Changed Devices Summary Display: This display lists the logical devices whose statuses have changed since the previous execution of the Real-Time Sequence.

3.2 State Estimator (SE)

The State Estimator function provides a complete and reliable network solution using the real-time measurements, forecasted load and generation, scheduled voltages and any operator entries. The solution for the "observable" portion of the network model is based on noisy, yet redundant real-time measurements. The solution for the "unobservable" portion is based on scattered telemetry, forecasted load and generation, scheduled voltages and any operator entries.

Throughout this proposal, the term "observable" is used to refer to the portion(s) of the network with sufficient, redundant real-time measurements. The remainder of the network will be referred to as the "unobservable" or "external" portion(s) of the network.

The real-time measurements are often noisy, but overall are redundant in terms of a power flow solution. State estimation exploits this redundancy to improve the solution accuracy beyond that of the measurements in the observable network. The State Estimator performs an observability analysis at each execution to assess the boundaries of observability, which may vary with time according to the availability of telemetry.

For the external network, load and generation is forecasted. The State Estimator uses these forecasted values, together with scheduled voltages, scattered telemetry and any operator entries to determine a complex voltage estimate for the unobservable portion of the network model, thus providing a complete solution for



the entire network model.



The State Estimator function:

Estimates a complete real-time network solution

Provides an assessment of the reliability and accuracy of the data acquisition system by the detection of bad measurements (anomalies) in the observable network

Provides an assessment of the accuracy of the network model

Provides pending and historical anomaly (metering error) detection records

Provides pending and historical records for abnormal measurements (those that are manually replaced, saturated, or declared unusable by the operator)

Provides the bus injection solutions used by Network Parameter Adaptation to develop the observable system load distribution models

Provides the base case real-time total network solution to support the Security Analysis function and other network functions

Some of the salient features of the State Estimator function are as follows:

Orthogonal transformation algorithm

Handles zero injection buses as high confidence measurements

Bias estimation via time averaging of residuals

Anomaly detection via normalized residuals, compensation method, or weighted residuals

Telemetered transformer and phase shifter tap estimation

Uses pseudo load estimates automatically

Can use power pool exchange data

One line diagram output

Overload monitoring

Tracking solution

Measurement set can include:

• Branch MW and MVAR, paired or unpaired

• Bus kV (allows for multiple measurements)



• Generation MW and MVAR, paired or unpaired

• Load MW and MVAR, paired or unpaired

• Breaker flow MW and MVAR

• Branch Amperes

• LTC and phase shifter tap positions

Solves for multiple observable and electrical islands

Dispatches generation as necessary

Meets generation MW and MVAR and bus voltage constraints

Some of the general benefits of the State Estimator are as follows:

Ability to estimate values when not measured or when telemetry fails.

Reduction of field personnel for telemetry maintenance

Increases the confidence the operator has in the analog values

Ability to produce a suitable base case for the Security Analysis function.

Ability to detect and reject anomalous measurements.

Ease with which implementation of telemetry can take place

The following are some of the specific benefits of the State Estimator function proposed by Siemens:

The State Estimator solves the entire (observable and external) network in one pass. This eliminates the boundary mismatch common in two-pass estimators. This is possible through the use of Orthogonal Estimation which allows mixing of real and pseudo measurements without significant degradation of the estimate of the observable portion of the network.

The orthogonal transformation algorithm provides an accurate and stable coupled solution where considerable large differences in measurement confidence values can be handled.

Use of known zero injections adds a significant level of redundancy and reliability. Increased redundancy results in an improved solution and accurate bad data detection. Zero injections improve reliability by making the solution less dependent on a small set of measurements.



The State Estimator solution incorporates measured transformer and phase shifter taps as state variables. This provides an accurate estimation of tap positions based on real-time telemetry.

The State Estimator solves multiple electrical and observable islands



Branch ampere estimation is used to enhance redundancy and reduce the need for transducer installation.

Normalized residuals are the best way to find bad data – avoids transmission of errors in one measurement to other neighboring measurements.

3.2.1 SE Functional Description

The purpose of the State Estimator function (Figure 3-5) is to provide a complete network solution from the real-time measurements, forecasted load and generation, scheduled voltages and operator entries. The real-time measurements are imperfect but redundant. This redundancy permits the State Estimator to determine an estimate for the complex voltage solution for the observable portion of the network model which best matches the information given by the unfiltered measurements. For the portion of the network model that is unobservable, load and generation is forecasted and bus voltage is scheduled. These forecasted and scheduled values along with scattered telemetry and any operator entries are used by the State Estimator to determine a complex voltage estimate for the unobservable portion of the network model.

BF2 312-1

VOLTAGESCHEDULER

STATIONTABULAR

OUTPUT DATA STATE

ESTIMATORSOLUTION

REAL-TIMENETWORK

MODEL

SECURITYANALYSIS

MODELUPDATEDATA

ANALOGMEASURE-

MENT

REAL TIMEBUS

MODEL

CURRENTBUS LOADVALUES

EXTERNALSYSTEM

INPUT DATA


POWER FLOWDPF/OPF

GENERATIONSCHEDULER

LOADSCHEDULER

ONE LINEDIAGRAMS BUILD STATE

ESTIMATIONSTATION

TABULATIONOUTPUT

MEASURE-MENT

ALARMS &BIAS DATA



Figure 3-5. Overview of State Estimator Function



The function processes branch MW/MVAR flows and bus injections as complex power measurement pairs for solution efficiency. The function, however also utilizes unpaired active or reactive components.

The State Estimator uses branch real and reactive power flows, bus real and reactive power injections, voltage magnitude, ampere, and transformer and phase shifter tap measurements. The function uses the real-time status and measurements collected by the Data Acquisition function to calculate the best fit voltage solution (magnitude and phase angle) for the observable network model. The observable network model will be limited to that portion of the system where adequate real-time measurements exist. When appropriate, "pseudo-measurements" of forecasted bus loads are used to circumvent the loss of observability due to measurement failures.

The observable network model is dynamically reduced to the limit of observability due to loss of measurements, detection of anomalies, or changes in the network configuration. This dynamic determination of the observable network boundary is identified and is recognized by the Network Parameter Adaptation function.

The State Estimator uses all other available information to estimate the complex voltage solution for the unobservable network. This information is obtained via the following sources:

The load scheduler forecasts the load in the external network using parameters obtained from the Network Parameter Adaptation function.

The generation scheduler forecasts the generation for non-telemetered units using a simple unit commitment scheme and economic allocation factors. The factors are changeable by the user. Each company is economically dispatched to the forecasted load and company net interchange. The State Estimator allows manual entry of external company interchanges.

Voltage magnitudes corresponding to desired voltages for voltage regulated buses in the external network using parameters obtained from the Network Parameter Adaptation function.

Scattered telemetry, i.e., any telemetry which may exist in the external network.

With the assignment of these measurements the external network becomes "observable". Formal anomaly detection and rejection are not done for the external network measurements because they are not meaningful as compared to measurements in the observable network.

The State Estimator has the ability to perform, in the external network, generation MW and MVAR and regulated voltage limiting. This ensures that these parameters stay within reasonable estimates. This is accomplished through manipulation of the confidence values assigned to each measurement.

The output of the State Estimator is used by the operator and as the base case for



further network analysis calculations and modeling. The information available for the operator, analyst, and system maintenance personnel is of three types:

Single solution branch flows, bus voltages and injection details

Measurement anomaly and abnormal information

Measurement bias information

The single solution details include the latest solution data. This data includes estimates of all branch flows (lines, transformers, phase shifters and series devices), bus voltages and bus injections. The data also contains all measurement quantities used for the solution. This data can be displayed on both one-line diagrams and tabular displays.

The pending and historical anomaly files are records of the bad measurements which have been detected by the estimator. These records are displayed in three ways. First, the pending anomalies are available on workstation displays. Second, the pending and historical records are available on the line printer by operator request. Third, the historical record is printed on the line printer automatically whenever a set number of new historical entries have been accumulated.

The pending and historical abnormal measurement files are records of the abnormal measurement status (i.e., the measurement availability status) conditions which existed prior to the solution. The three workstation and line printer display options are the same as those available to the anomaly records discussed in the preceding paragraph.

The bias detection data is used to determine where minor consistent measurement errors exist in the real-time measurements. These errors may be either due to meter calibration errors or may be due to a network modeling error. This feature is a tool which assists in the improvement of the system network modeling parameters and as a tool to assist in the evaluation and maintenance of the measurement system. This data is output on the line printer upon operator request via the workstation.

3.2.2 SE Interface with Other Functions

The State Estimator interfaces with the following functions:

Model Update: The current representation of the network and the current measurements and measurement status are obtained from Model Update.

Network Parameter Adaptation: The State Estimator obtains the load parameters which are used to calculate load MW and MVAR values for use as pseudo measurements and forecasted external measurements. Network Parameter Adaptation uses the State Estimator results for the observable portions of the network to update the adaptive load parameters.



][][][[)(

2/12/12/12/1

1

XHRZRZHRZRXHZRXHZXJ

T

T

∆−∆∆−∆=

∆−∆∆−∆=∆−−−−

−



Analysis: Security Analysis uses the total network solution to assess the security of the system.

Security Constrained Economic Dispatch (Option): The total network solution is used as a starting point for the security constrained economic dispatch function.

Voltage Scheduler (Option): The total network solution is used to determine optimized settings of MVAR sources to minimize system losses.

Power Flow: The total network solution as a starting point for studies involving the current network.

3.2.3 SE Algorithm

The State Estimator solution method is the Givens rotations algorithm in which orthogonal transformation is applied to network measurement equations. The set of system measurements can be modelled as:

z = h (X) + η (1)

where:

z is the (mx1) measurement vector

X is the (nx1) system state vector

h(X) is the (mx1) vector of non-linear measurement functions

and

η is the (mx1) vector of measurement errors

m is the number of measurements

n is the number of busses

Assuming sufficient measurement redundancy, i.e., m>n, the best estimate of the state is obtained by minimizing the weighted least square objective function. The objective function, J(X), is given below:

(2)

)]([)([)( 1 XhzRXhzXJ T −−= −

Rewriting J(X) in an incremental form to accommodate the non-linearity of the problem, we get

(3)

where:

∆Ζ is the (mx1) measurement mismatch vector

H is the (mxn) measurement Jacobian

∆X is the (nx1) correction vector to the systemstate

and

R is the (mxm) diagonal measurement covariance matrix.



Define Q to be an orthogonal (mxm) matrix, i.e., QTQ = I where I is the identity matrix, such that

(4)

=− UD

HQR0

2/12/1

where:

D is a diagonal (nxn) matrix

and

U is an upper triangular (nxn) matrix

When applied to the measurement mismatch vector ∆Z, Q will give

(5) Q

∆∆

=∆−

2

12/1

2/12/1

ZZ

RDD

ZR

where:

∆Z1, ∆Z2 is the resulting (mxl) independent vectors of the orthogolization process

and

DR is a resulting diagonal (nxn) matrix

Apply QTQ to the objective function J(∆X) shown in equation (3), we get:

J (∆X) = [R-1/2 ∆Z – R-1/2 H∆X]T QTQ [R-1/2 ∆Z – R-1/2 H∆X]

= [QR-1/2 ∆Z – QR -1/2 H∆X]T [QR-1/2 ∆Z – QR-1/2 H∆X] (6)

Minimization of J(∆X) in (6) by setting its gradient to zero leads to:

U ∆X = ∆Z1 (7)

The correction ∆X to the state vector is computed as a solution to (7).

The State Estimator function estimates the system state (complex voltage solution) by iteratively solving equations (4), (5) and (7). In each iteration, the following basic equation is solved:

Xk+1 = Xk + U-1 ∆Z1k (8)

where:



Xk is the estimate of the system complex voltage solution for the kth teration

∆Z1k is the resulting independent vector of the orthogonalization process at the kth iteration

A derivation of the Givens rotation algorithm is given in Reference 1

Orthogonal transformations (4) and (5) are performed in optimal order for columns and rows of U using efficient form of Givens rotation with initial null matrix and two-multiplication scheme for elementary transformations. Equation (8) is solved in optimal order using sparse matrix techniques. The solution is iterative and has the Newton's method quadratic convergence properties.

A large number of buses will be buses where the injection is known to be zero. This occurs at most higher voltage buses when more than one voltage level is modeled in a station. The robustness of the orthogonal transformation algorithm allows the State Estimator to explicitly handle these known zero injections as very high confidence measurements.

Bad Data Detection

After a solution is derived, the resulting performance index given by equation (9) is checked against a set of Chi-squared confidence limits.

(9)

2

)i(estmeas

1i

mP

2

)i(Z)i(Z

−

==

σΣI

where:

PI is the performance index

Z(i)meas is the ith measured value

Z(i)est is the estimate of the ith measurement

σ2(i) is the input variance for the ith measurement

m is the number of measurements

A Chi-squared value is calculated for the number of degrees of freedom which exist and the input confidence level desired. Equation (10) is used to determine the Chi-



1 N. Vempati, I. W. Slutsker and W. F. Tinney, "Enhancements to Givens Rotations for Power System State Estimation", Paper 90SM 492-9 PWRS, Presented at the IEEE/PES Summer Power Meeting, Minneapolis, Minnesota, July, 1990.

2=χ [ ] 2

12df(X)12 −+


squared value:

(10)



where:

χ2 is the Chi-squared value

d is the number of degrees of freedom

f(X) is the standard deviation given by the normal curve for a specified probability

X is the probability specified by the user.

If the performance index exceeds the Chi-squared value, then the presence of the bad data is detected. The next step is to identify it.

Bad Data Identification

The user can select between three identification methods:

Measurement compensation method

Normalized residual method

Weighted residuals

The measurement compensation method consists of two phases:

The potentially bad measurements are processed one at a time. The measurement value is modified in such a way that effect of the measurement on the estimation results is canceled (compensation). The new values of residuals are obtained using the linear residual calculation (based on residual sensitivity matrix).

The statistical analysis of estimated errors of suspected measurement is performed. True anomalies are separated from good measurements.

Normalized residual method calculates differences of all measurements and their corresponding estimates weighted by the normalized measurement confidence. The weighted residuals method calculates differences of all measurements and their estimates weighted by the user defined confidences. In both methods, the calculated values are checked against a threshold value. All those which exceed the threshold are considered as anomalies and removed from the measurement set, and the solution is repeated.

The solution is a static least-squares fit, and can be demonstrated in a simulation environment for test purposes.



3.2.4 SE Measurement Set

The State Estimator handles paired and unpaired MW and MVAR measurements through the following devices:

Transmission lines

Transformers

Phase-shifters

Series devices

Bus injections (generators and loads)

Circuit breakers

The Estimator handles the MW and MVAR power flow measurements in pairs for solution efficiency. The State Estimator utilizes unpaired measurements, even though paired measurements are more desirable. The Estimator will also handle ampere measurements and multiple bus voltage magnitude measurements.

Additionally, the State Estimator incorporates transformer and phase shifter tap position measurements into this measurement set.

It is assumed in this proposal that the telemetered measurement set that defines the observable network will meet the following general rules:

At least 50% of all modeled buses will have voltage magnitude measurements.

In general, one end of each modeled branch will either be measured, or will be connected to a zero injection bus or a measured injection bus.

The system-wide measurement redundancy for branch flows and known zero injections will be greater than 1.75. The redundancy value is given by:

R = (mb + mz + mi )/n (11)

where:

R is the redundancy value

mb is the number of complex branch flow measurements

mz is the number of known zero injection buses

mi is the number of measured complex injection buses



n is the number of modeled buses

The measurements will be fairly evenly distributed across the modeled network such that local redundancy is approximately equal to system redundancy.

3.2.5 SE User Interface

Execution Control Display: The execution control display controls the use of the State Estimator.



Station Output Displays: Two types of station output displays exist: a one-line diagram display and a tabular display. The one-line diagram displays show the State Estimator estimated voltages, branch flows and injections. The station tabular displays are generated upon operator request via the execution control display and show the measurements, the estimates and the deviations and all equipment flows. Since there are many stations, a table of contents is provided by station for the station tabular displays.

Anomaly Pending Display: The anomaly pending display shows all the anomaly conditions which were detected by the State Estimator solution during the last execution.

Abnormal Pending Display: The abnormal pending display shows all the abnormal measurement conditions existing in the real-time State Estimator network during the last execution. Conditions detected are saturation, RTU out-of-service and operator specified out-of-service. Also included in this display is the availability index when it is less than a specified threshold. The availability index is a means to prevent measurement chattering between consecutive SE executions. The index for a measurement is set to 1.0 any time it is found to be anomalous or abnormal. In subsequent SE executions, if the telemetered measurement becomes good, the index will be exponentially scaled down. The measurement will not be used by SE until its availability index becomes less than a specified threshold. Until then, the measurement will be considered abnormal.

Measurement Error Analysis Display: This display allows the user to evaluate the reliability of the State Estimator solution. A measurement is included in this display if the difference between its measured and estimated values are greater than a preset threshold. The existence of large errors indicates bad telemetry, incorrect scheduled values or topology errors.

Voltage Range Limit and Branch Overload Threshold Display: This display allows the user to enter a range of bus voltage outside of which bus voltages will be considered in limit violation. Similarly, a threshold is entered for branches in percent of rating.

Overload Displays: There are two overload displays, one for new overloads (those occurring in this run but not the previous) and one for existing overloads (those occurring in this run and also the previous). The time and date the overload appeared on the new overload display is shown for all entries on the existing overload display.

Network Losses: The total network losses are calculated and presented for the total modeled network.

Single Solution Output Listing: A single solution output listing can be obtained via the execution control display. The listing is in similar form to the workstation display and consists of line printer output of:

Anomaly Pending File



Abnormal Pending File

Station Tabular Detail

Table of Contents for Stations



Anomaly History Listing: Via the execution control display, the user can obtain an anomaly history listing. The history shows those anomalies which existed and have been corrected. The listing shows for the anomaly the time first detected, the time last detected and the number of detections.

Bias File Listing: Via the execution control display, the user can obtain a listing of the bias file. The bias file can also be cleared via the execution control display. The bias file listing contains for each measurement the average values since the last clearing of the bias file for the following quantities:

The engineering unit measurement bias in MW, MVAR, KV, ampere.

The bias in terms of the measurement confidence.

The calculated deviation both in engineering units and in terms of the input standard deviation.

The input standard deviation.

3.3 Network Parameter Adaptation (NPA)

The Network Parameter Adaptation function provides parameters used to generate a forecast of bus loads, regulated bus voltages, and of the status of time-switched breakers. As part of the Real-Time Sequence, the program periodically updates company, zone and load group parameters, non-conforming loads, desired voltages for regulating equipments, and, for selected points, telemetered time-switched breaker schedules. In real-time execution, the parameters are used by the State Estimator function to schedule loads and desired voltages at all unobservable buses and to generate pseudo load measurements. In study situations, the parameters are used by the Power Flow function to schedule bus loads and desired voltages for the specified day and hour of a study.

A load group is defined as one or more loads to be treated collectively. One typical use would be for the set of feeders on a bus having a transformer measurement for power into the bus but not having individual real and reactive feeder measurements. (A non-conforming load is a bus load that does not follow the typical system load pattern.) A zone is a set of load groups, and non-conforming loads, typically representing an area of the power system. Time-switched breakers are typically used for capacitor/reactor banks. A regulating equipment is a generating unit, LTC transformer, or voltage-controlling capacitor that has been specified to control voltage at a bus.

3.3.1 NPA Functional Description

Network Parameter Adaptation function (Figure 3-6) adapts forecasting parameters for load group, non-conforming loads, and voltage MW and MVAR, desired voltages



for regulating equipment, and time-switched capacitor/reactor breaker positions for which data is available. It also adapts the zone and company MW values. The forecasting parameters for load groups, non-conforming loads, and voltages are adapted from the State Estimator solutions; the time-switched breaker positions, for adaptive breakers only, are time filtered from the telemetry data. In both cases, an exponential filter is used to smooth the new data points in with the old data points.



POWER FLOW

STATEESTIMATOR

BF2 314


FILE

STATEESTIMATORSOLUTION

MODELUPDATE

SOLUTION

TIME-SWITCHEDBREAKERUPDATE

ERRORANALYSIS

LOADFACTORUPDATE

VOLTAGEPARAMETER

UPDATE

POWER FLOW

STATEESTIMATOR

BF2 314


FILE

STATEESTIMATORSOLUTION

MODELUPDATE

SOLUTION

TIME-SWITCHEDBREAKERUPDATE

ERRORANALYSIS

LOADFACTORUPDATE

VOLTAGEPARAMETER

UPDATE

Figure 3-6. Overview of Network Parameter Adaptation Function

Parameters are kept for:

Load group MW and non-conforming load and MVAR

Desired voltage magnitude for regulating equipment

Switch position

The load groups and non-conforming loads are defined via the Information Management function. A load group is defined as the set of power system loads, which encompass an area. By defining the equipment, which defines the boundary of the load group, the Load Factor Update function adaptively updates the load group parameters. Non-conforming loads are adaptively updated if they are observable.

Each load element may have multiple sets of parameters to define its changing relationship to overall company load over the hours of the week. The user defined, via Information Management, the day-type and each of the 24 hours within the day-type over which each load element parameter set should be updated. Parameters for each load element are distributed over nine day types on a 24 hour day basis. The day types cover seven days of the week plus two holiday types. The number of day types is configurable.

For the load element parameters, two statistics are kept for each: the average deviation from a predefined normal and a maximum deviation from a predefined normal. These statistics are available to the user via workstation displays.



3.3.2 NPA Interface with Other Functions

Network Parameter Adaptation interfaces with the following functions:



State Estimator: The MW and MVAR equipment flows are obtained from the State Estimator to update the load group, non-conforming load, zone and company parameter values. The State Estimator uses the load group, non-conforming load, zone and company parameters to schedule the loads that will be used as pseudo measurements. The State Estimator also uses the scheduled loads and desired voltages in the external network.

Update: To obtain the current system load to update the load group, non-conforming load, zone and company parameter values, and to obtain the current real-time status to update the time-switched breaker positions.

Power Flow: The Power Flow function uses the adaptive load group, zone, non-conforming load, and company parameters to schedule load, the voltage parameter to schedule desired voltages for regulating equipment, and the time-switched breaker position parameters to schedule the time-switched breaker positions.

3.3.3 NPA Algorithm

The Network Parameter Adaptation function maintains the load group, non-conforming zone, company, desired voltage, and time-switched breaker parameters which are either fixed values or adapted by the Network Parameter Adaptation update function. The function that requests a forecast uses the proper load group, non-conforming load, zone, company, desired voltage, and time-switched breaker parameters that correspond to the hour and day type the forecast is requested for. The actual calculation of the forecast is performed in the using function (such as the Power Flow function or the State Estimator function) and not by Network Parameter Adaptation.

NPA Adaptive Update Equations

All NPA parameters except for the company MW parameters are adaptively updated using the following equation:

NPAPnew(j, d, h) = αNPAPold(j, d, h) + (1-α) NPAPrts (12)

where:

NPAP Stands for each of the following NPA parameter types:

a) Load Group MW; adapted using the SE observable network solution

b) Load Group MVAR; adapted using the SE observable network solution

c) Zone MW; adapted using the SE complete network solution

d) Time-switched breaker positions; adapted from telemetry retrieved via Model Update – 1.0 for closed and 0.0 for open.



NPAPnew = The new adaptively updated NPA parameter value

NPAPold = The old adaptively updated NPA parameter value prior to the current update

NPAPrts = The actual/estimated parameter value provided by the real-time functions.

� = The adaptive smoothing constant. Each parameter type has its own adaptive constant.

J = The jth item of NPAP

d = The dth day type

h = The hth hour

The equation for updating the company MW is:

COMW (p, d, h) = ZSUM (p, d, h) (13)

where:

p = The pth company

COMW = The company adaptive MW load value for specified day and hour

ZSUM = The sum of adaptive MW zone load value for all zones in the pth company for a specified day and hour

NPA Forecast Equations

The general equation for load group real and reactive power forecasts are:

W(i,d,h) = LGMW (i,d,h) • S(P)/COMW (i,d,h) (14)

R(i,d,h) = LGMVAR (i,d,h) • S(P)/COMW (i,d,h) (15)

where:

W = The load group MW forecast

R = The load group MVAR forecast

LGMW = The load group adaptive MW value for a specified day and hour

LGMVAR = The load group adaptive MVAR value for a specified day and hour

i = The ith load group



d = The dth day type

h = The hth hour

S = The company MW load for which forecast is requested

COMW = The company adaptive MW value for a specified day and hour



Zone load forecast are represented by the following equation:

Z(k,d,h) = ZMW (k,d,h) • S(P)/COMW (p,d,h) (16)

where:

ZMW = The zone adaptive MW load for a specified day and hour

p = The pth company

Z = The zone MW forecast

k = The kth zone

In most cases, the value of company MW load(s) is specified and zone and load group MW forecasts are computed using that value in accordance with equations 3, 4, and 5. This is the general case in real-time use.

For study case use, the capability is provided to use an adaptive value of company MW load for a specified day and hour for scheduling of zone and load group MW loads. In that case, the company MW load forecast is taken to be:

S(P) = COMW (p,d,h) (17)

Zone and load group MW forecasts are then simplified:

Z (k,d,h) = ZMW (k,d,h)

W (i,d,h) = LGMW (i,d,h)

R (i,d,h) = LGMVAR (i,d,h)

Time-switched breakers are described by a single parameter referred to as the switch parameter. This switch parameter is a number between zero and one, where zero represents a closed switch and one represents an open switch. The general equation for forecasting the switch position is:

0 for SP (K,j,d,m) < TOL

ISP(K,d,m) = (18)

1 for SP (K,j,d,m) > TOL

where:

SP is the switch parameter (0.0 < SP < 1.0)

ISP is the logical switch position (0 or 1)



TOL is the switching threshold

K is the Kth time-switched breaker

d is the dth day type

m is the mth hour

3.3.4 NPA User Interface

Execution Control Display: The execution control display controls the execution of the line printer output and the initialization of parameters.

Load Group and Zone Parameter Values Display: This display shows the parameters for all load groups and zones, whether they are adaptive, the day-type and the adapted and default values. The operator can change the violation tolerances via this display.

Non-Conforming Load Parameters Display: This display is similar to the load group parameter values display.

Desired Voltage Parameters Display: This display is similar to the load group parameter values display.

Time-Switched Breaker Position Parameters Display: This display is similar to the load group Parameter Values display.

Current Violations Display: This display contains the current load group violations. The display contains:

Type of violation (MW or MVAR)

Deviation from normal

Normal and adaptive values

Average and maximum deviations

Time of occurrence of maximum error

Similar displays exist for non-conforming loads, desired voltage and time-switched breaker positions.

The contents of the Parameter Values displays and the Current Violations displays can be listed on a printer via the Execution Control display.



3.4 Security Analysis (SA)

The purpose of the Security Analysis function is to determine the security of the power system under specified contingencies. For each contingency, Security Analysis simulates the steady-state power flow solution and checks the network for out-of-range conditions. An exception report is generated for ease of interpretation.



The Security Analysis function provides the following features:

Studies effects of contingencies on current system

Alerts the operator about what can happen, before it really happens

Operator can take precautionary measures, thus avoiding possible problems

Only the worst problems are reported

Both overloads and voltage problems are reported

Other unique features of the proposed Security Analysis function can be summarized as follows:

Analyzes many contingency cases using AC load flow (adaptive local solution and fast decoupled power flow)

Screens contingency cases for those requiring full analysis

Real-Time – initializes the base case to the State Estimator network solution

Study – initializes the base case to the study Power Flow results

Handles multiple outages of lines, transformers, phase shifters, series devices, DC lines, generating units, loads and circuit breaker operations

Solves for cascading outages

Solves islanded systems, isolated buses and split buses

Handles transfer of load to a different feeder if the original becomes de-energized

Ranks contingency results and presents violations of each contingency

Reallocates of lost generation

Simulates movement of on-load tap changing transformers

Performs MVAR limiting of units

Regulates the voltage of a local or remote bus with capacitor bank switching

Dynamically adds contingencies to list based on branch overloads detected by the State Estimator function

Input to the Security Analysis function consists of:

Base case network from the State Estimator or the Power Flow



Contingency list (operator may modify interactively)

Priority level (or subset) of contingencies to be analyzed

Violation thresholds as a percent of limits

The following is a summary of the available output options:

Violation list – violations for each contingency

Severity index and rank of each contingency

New violations since the last solution in real-time

3.4.1 SA Functional Description

The Security Analysis function (Figure 3-7) uses the Fast Decoupled Power Flow (FDPF) technique to obtain the network solution. A converged solution with or without limiting generator excitation, automatic transformer tap control and capacitor bank switching can be obtained from a full AC analysis for any or all contingencies. Alternatively, a screening process can be used which consists of ranking contingencies according to the expected severity of the resulting branch MVA overloads, voltage limit violations or bus reactive power limit violations following one or more (operator may modify interactively) iteration(s) of AC analysis and then selecting a small worst case list for full AC analysis. The major contributing techniques used in the procedure are:

Adaptive local solution technique

Sparsity-oriented programming

Optimally ordered triangular factorization

A direct solution technique

Use of the Factor Update Technique (FUT) to simulate outages

A nonlinear network model

Decoupled real and reactive equations



BF2 316

POWERFLOW

CONTINGENCYSIMULATIONS

OUTPUTPROCESSING

INPUTPREPARATION

CONTINGENCYLIST SETUP

STATEESTIMATOR

LINEPRINTER

SCREENING& RANKING

INPUT CRT DISPLAYS

OUTPUT CRT SUMMARIES

CONTINGENCY LISTS &

SCREENING PARAMETERS

INPUT NETWORK

BUS MODEL

SECURITY ANALYSIS RESULTS

BF2 316

POWERFLOW

CONTINGENCYSIMULATIONS

OUTPUTPROCESSING

INPUTPREPARATION

CONTINGENCYLIST SETUP

STATEESTIMATOR

LINEPRINTER

SCREENING& RANKING

INPUT CRT DISPLAYS


CONTINGENCY LISTS &

SCREENING PARAMETERS

INPUT NETWORK

BUS MODEL

SECURITY ANALYSIS RESULTS

Figure 3-7. Overview of Security Analysis Function

The contingency screening technique processes the specified contingencies with the exception of those that are flagged to bypass the screening process. It then sorts all of them into two separate screened contingency lists based on MW branch overloads or MVAR/KV violations, following one full iteration of AC analysis. Contingencies in the screened contingency lists are simulated for full AC solution until a "Stopping Criterion" is met. (Further description is provided in Section 3.5.4.5.) For the full AC solutions, it is possible to take into account automatic correction of generator VARs for increased accuracy. In addition, Security Analysis recognizes contingencies that cause system islanding and appropriately modifies the analysis.

Security Analysis analyzes independently, either the real-time network from the State Estimator function or a study network from the Power Flow. For each of these executions, SA simulates contingencies contained in the contingency list. Each contingency can consist of any combination of the following:

Branch outages

Load element outages

Generating unit outages

DC link outages (for either the single ended bus injection model or the double ended branch model)

Logical device status changes (open or close)

Bus outages can be simulated by outaging all branches connected to a bus or by changes in logical device statuses.



Associated with each contingency is a priority. The user first selects a priority range for an execution (real-time and study executions have separate priority ranges), Security Analysis then simulates all contingencies in the list within that priority range.

For all those contingencies with a generator unit, load or DC link bus injection outage, the lost generation is allocated to the remaining generators via user changeable participation factors. The generator allocator is also utilized to maintain a power balance under islanding conditions. The participation factors could correspond to machine inertias or to governor droop characteristics. Separate sets of participation factors are maintained for study and real-time users. Unit limits are respected by the allocation.

For each solution of a contingency, elements are checked for out-of-range conditions. The following types of limits can be checked:

Branch flow limits

Generator reactive limits

Voltage deviation limits

The user can specify at what percentage of the ratings, violations are to be generated. For example, 80 percent for branches would result in a violation whenever a branch is loaded to more than 80 percent of its current rating.

For each contingency simulated, an index is calculated as a guide to the relative seriousness of the contingency. This index is used for ranking the contingencies. When contingency screening is performed, this ranking can be used to execute full AC analysis on the worst cases. This ranking can also be displayed in the study mode to assist the operator with assignment of priority values.

3.4.2 SA Interface with Other Functions

Security Analysis interfaces with the following functions:

State Estimator: To obtain the solved real-time network (real-time mode)

Power Flow: To obtain the solved study network (study mode)

3.4.3 SA Algorithm

A detailed development of the fast decoupled power flow is published in reference (1). Key points of the algorithm are repeated below.



1 B. Stott and O. Alsac, "Fast Decoupled Load Flow", IEEE Trans. on Power Apparatus and Systems, Vol. PAS-93, May/June 1974.


Expressions for the real and reactive power injections at node k can be written as:

Pk = V2k Gkk + Vk ∑ Vm(Gkmcosθkm+Bkmsinθkm) (20)

mεαk

Qk = V2k Bkk + Vk ∑ Vm(Gkmsinθkm+Bkmcosθkm) (21)

mεαk

where:

Pk + jQk is the power injection at node k

Vk is the voltage magnitude at node k

θkm is the voltage phase angle across branch km

Gkm + jBkm is the km entry in the branch admittance matrix

Gkk + jBkk is the driving point admittance of node k

αk is the set of branches connected to node k

N is the number of system nodes

The system of equations for real power mismatch and reactive power mismatch can be approximated as:

[∆Π/ς] =[Β∋] [∆θ] (22)

[∆Θ/ς] =[Β∀] [∆ς] (23)

where ∆θ and ∆V are voltage angle and magnitude corrections. [B'] and [B"] are matrices given by

B'km = B"km = – Vk Vm Bkm (24)

B'kk = B"kk = – V2k Bkk (25)

The above expressions are obtained by making the following assumptions:

Transmission line resistance’s are negligible (compared to reactance’s).



Angle θ is small i.e. Sin θ ~ θ.

Voltage magnitude is approximately 1 p.u.

The effects of the network elements that predominantly affect the MW flows (e.g. phase-shifters) are ignored in the [B'] equations.

The effects of the network elements that predominantly affect the MVAR flows are ignored in the [B"] equations, e.g., effect of off-nominal transformer tap.

These assumptions result in the mathematical formulation of two sets of equations with decoupled constant matrices [B'] and [B"]. These equations in (3) and (4) are solved to obtain network voltages and angles by using sparsity oriented programming techniques to perform optimally ordered triangular factorization and direct solution. Branch outages are simulated using the Partial Factorization Technique (PFT) to update the [B'] and [B"] matrices. Generator outages and generator MVAR limiting are simulated using the Factor Update Technique (FUT). The solution method uses a non-linear model and, using the decoupling assumptions to speed up the computation, obtains exact answers to the load flow problem. Further computational speed up is also obtained by judicious use of the adaptive local solution technique. Consequently, even when only the first few iterations are used for contingency selection, the accuracy is superior to fully linear methods such as the method of distribution factors.

Security Analysis uses the Zero Mismatch Power Flow (ZMPF) (2 ), which is an enhanced modification of the Fast Decoupled Power Flow, to obtain converged solutions for all contingencies flagged as potentially harmful during screening and selected for full AC analysis. The computational efficiency of the Zero Mismatch Power Flow is derived from the fact that it utilizes only a minimum number of bus mismatch calculations in order to obtain a converged load flow, whereas, in the traditional FDPF real and reactive power mismatches are computed at all buses and for all iterations until convergence.

The basis of the ZM approach is to exploit localization in solving power network problems arising from contingency analysis by relying on the following observed facts:

The effect of most local changes in power networks tend to remain localized.

Iterative solutions of network problems whose effects are initially widespread tend to become localized as the iterations converge.

2 R. Bacher and W.F. Tinney, "Faster Local Power Flow Solutions: The Zero Mismatch Approach", paper presented at the IEEE/PES Winter Power Meeting, New York, NY, Jan. 29-Feb. 3, 1989.



In the ZMPF algorithm, bus MW/MVAR mismatches smaller than a certain tolerance are processed as if these mismatches were actually zero, and computational effort is thus saved by skipping computation of relatively small MW/MVAR mismatches. The adaptive localization and bounding of mismatches and iteration solutions are accomplished using sparse vector methods. Thus, the ZMPF provides a faster converged decoupled power flow solution using MW/MVAR mismatches computed at only a subset of buses but without requiring the use of reduced equivalent networks and without modifying the factors of the global network equations. The adaptive nature of the ZMPF allows the local area being evaluated to follow the actual MW/MVAR mismatch values from iteration to iteration. This guarantees that all buses affected by the contingency are properly evaluated.

3.4.4 SA Contingency Screening

3.4.4.1 SA Performance Indices

The system performance index is a measure that can be used to evaluate the relative severity of a contingency. System performance indices are not unique and take on different forms depending on the parameters that are of most importance to the system engineer. However, in selecting a performance index, physical properties of the system should be taken into consideration. The most common form of a system performance index gives a measure of the deviation of the system variables such as line flows, bus voltages, bus power injections from their rated values.

Due to the weak coupling between the real power and the (compared to reactances) reactive power equations, two separate performance indices are defined:

Real Power Performance Index

Voltage/Reactive Power Performance Index

3.4.4.2 SA Real Power Performance Index

For computational efficiency, branch power flow monitoring is accomplished by branch angle monitoring using equivalent branch angle limits transformed from the branch MVA limits. The real power performance index,PIθ, shown in the following equation gives a measure of branch overloads.

(26) 2WPI

0d

d

=

θ

θΣαθθ

where:

Wθ = Real power weighting factor



θd = Branch angle of branch d

θod = Branch normal angle limit of branch d

α = Set of overloaded branches

3.4.4.3 SA Voltage/Reactive Power Performance Index

The voltage/reactive power performance index, PIVQ, is given by equation:



−∑

∆∆∑ +=

QQQ

WVVWPI m

i

mii

i

iQVVQ

22

lim γβ

( 27)

where:

∆Vi = Voltage magnitude change from the base case at bus i

∆Vilim = Voltage magnitude change limit at bus i

Qi = Reactive power injection at bus i

Qim

= Midpoint between reactive high and low limits

i.e., (Q_

i + Qi)/2

Q_

i, Qi = Reactive power high and low limit at bus i

WQ = Reactive power weighting factor

WV = Voltage magnitude weighting factor

β = Set of buses at which the voltage deviation is either below a specified minimum or above a specified maximum

γ = Set of buses at which the reactive power is either below a specified minimum or above a specified maximum.

It should be re-emphasized here that performance indices are not unique and usually depend on what the engineer considers important in evaluating the security of the system.

3.4.4.4 SA Contingency Ranking

One or more iteration(s) of the Fast Decoupled Power Flow are used to calculate the performance indices for every contingency. Contingencies are then ranked on the basis of the magnitudes of their corresponding performance indices. Ranking for overloads and ranking for voltage problems are done separately since the two are normally uncorrelated.

Contingency Selection – Stopping Criteria



Once the ranking of contingencies is done according to their severity, the more severe cases may be analyzed further for more details with more accuracy. Full AC analysis of the outages in the ranked lists are carried out until a "stopping criterion" is met. The Stopping Criteria may take one of the following two forms:

Study the most severe N cases from each ranked list

Study all cases with possible violations

3.4.4.5 Computational Efficiency of SA Contingency Screening

The computational efficiency of the screening algorithm is derived from the following features:

Extensive use of Sparse Vector (SV) methods (3 ) (fast forward and fast backward techniques).

Efficient bounding technique (4 ) for fast computation and checking of branch angle limit violation.

Transformation of branch normal MVA limits to branch normal angle limits for efficient branch limit checking.

Adaptive reactive mismatch bounding for fast computation of bus voltage magnitudes.

Use of Approximate Sparse Vector (ASV) (5 ) techniques (skip-back-by-column).

Essentially, contingency screening is accomplished in two steps. First, execute the FDPF for the operator defined number of screening iterations. Second, evaluate equipment loading at the state following the screening iterations. The use of multiple screening iterations is essential to properly reflect the effects of voltage control devices in the screening phase.

During MW screening the algorithm employs sparse vector methods and approximate sparse vector methods to quickly compute all significant bus angle

3 W.F. Tinney, V. Brandwajn and S.M. Chan, "Sparse Vector Methods", IEEE Trans. on

Power App. and Systems, Vol. PAS-104, No. 2, Feb. 1985, pp. 295-301. 4 V. Brandwajn, "Efficient Bounding Method for Linear Contingency Analysis", IEEE Trans.

on Power Systems, Vol. 3, No. 3, Feb. 1988, pp. 38-43. 5 R. Bacher, G.C. Ejebe and W.F. Tinney, "Approximate Spare Vector Techniques for

Power Network Solutions", Proceedings of 1989 Power Industry Computer Applications Conference, Seattle, WA, May 1-5, 1989, pp. 2-8.



changes globally throughout the power network, and then applies the incremental angle bounding criteria for fast checking of branch angle limit violations.

During the voltage screening phase, contingencies that cause significant voltage changes and limit violations are detected. The efficiency of the voltage screening phase is enhanced by Adaptive Localization in the reactive power mismatch computation. Using the bus angles from MW screening, the reactive power mismatches are calculated initially for those buses in the immediate electrical neighborhood of the outage and, subsequently, adaptively for those other buses with significant MVAR mismatches. The second set of buses are quickly determined by Adaptive Expansion of the boundaries of the neighborhood and computation of the reactive power mismatches at the new boundary buses. The algorithm adaptively decides how far to go and in which direction by examining the computed numerical values of the MVAR mismatches. Once all the significant MVAR mismatches for the contingency are computed then the associated bus voltage changes and limit violations are determined globally throughout the power network using fast forward and skip-back-by-column techniques. All branches and buses in the network are checked for violations as appropriate.

3.4.5 SA User Interface

Execution Control Display: The execution control display controls the execution of Security Analysis and provides for entry of execution parameters such as the title of a study case, limit violation parameters, outage priority, etc.

Working Contingency List Displays: The purpose of the working contingency display is to provide a mechanism for preparing the contingency list. This list is not used by the solution. The user can enter new contingencies, delete existing contingencies, change normal priorities, or reorder the contingencies. The entire working list can be validated (i.e., checked for errors) or implemented (i.e., replace the existing on-line contingency list). New contingencies are defined and existing contingencies are modified by entering the outage title, station name, the element type, the element name and priority via interactive contingency editor displays. Validation checks are performed on an individual contingency being modified in the contingency editor.

Active Contingency List Display: This display shows the title of the contingency, the normal priority of the contingency and its operator modifiable actual priority. The contingencies in this display are actually used in the solution.

Generator Allocation Displays: The Generator Allocation participation factors for units are initialized to database default values. These participation factors can be viewed and modified separately for real-time and study through the Generator Allocation Display. These factors can be reset to default at any time via the execution control display.

Summary Display: This display contains for the last execution of Security Analysis, a summary of the case including case title, number of contingencies simulated,



number of violations checked, number of contingencies with violations, violation thresholds and other pertinent summary data.

Violation List Display: This display enumerates the violations that occurred with each contingency. For each violation, the station, equipment identifier, rating and solved value in both engineering units and percent of rating are displayed. The output for each contingency is presented in the order which represents the severity of the contingency.

Real-Time Existing Violations Display: This display shows all the contingency/violation pairs encountered in the most recent execution of Security Analysis in real-time. The time the violation of each pair was first detected is included in this display. If the time shown is previous to the last run, it means that the pair was in violation in all intervening runs.

Real-Time New Violations Display: This display shows the contingency/violation pairs encountered in the most recent execution of Security Analysis in real-time that did not exist in the previous run.



3.5 Voltage Scheduler (VS)

The Voltage Scheduler is a real-time application of the Optimal Power Flow algorithm in loss optimization or reactive power security mode. The function has two purposes:

1. To eliminate or reduce voltage violations and branch overloads using LTC transformer tap positions, generator bus voltages and controllable capacitor/reactor MVAR values.

2. If there are no branch overloads or violations, to determine the optimum setting for LTC transformer tap positions, generator bus voltages, controllable capacitor/reactor MVAR values and phase shifter tap positions which minimize Iraq SCADA Refurbishment MW transmission losses.

All bus voltage, branch flow and control variable limits are enforced in both execution modes.

Features can be summarized as:

Real-Time optimization of network voltages and MVAR flows to eliminate or reduce reactive power constraint violations or to achieve minimum active power losses.

Automatically selects its execution mode based on real-time bus voltage and branch loading conditions

Relaxation of limit violations in an optimal fashion when a feasible solution cannot be found

3.5.1 VS Functional Description

The Voltage Scheduler function (Figure 3-8) operates on the real-time network model. It determines the reactive power control settings that relieves the existing bus voltage violations and branch overloads or minimize real power transmission losses.

The Voltage Scheduler first checks for voltage violations or branch overloads in the State Estimator (SE) solution. If there are voltage violations or branch overloads, Voltage Scheduler reschedules LTC transformer tap positions, generator bus voltages and controllable capacitor/reactor MVAR values in minimum control shift fashion to relieve the overloads/violations. The VS advises the user regarding what can be done to eliminate or relieve the network problems. VS does not attempt to minimize active power loses if there are overloads/violations in the SE solution.

If there are no voltage violations or branch overloads in the SE solution, the Voltage Scheduler determines the optimum settings for LTC transformer tap positions,



generator bus voltages, controllable capacitor/reactor MVAR values and phase shifter tap positions which minimize Iraq SCADA Refurbishment MW transmission losses.



INPUT CRT DISPLAYS

VOLTAGE SCHEDULER

PARAMETERS

BF2 317

VOLTAGE SCHEDULER SOLUTION

OUTPUTPROCESSING

STATEESTIMATOR

SOLUTION DATA

TRANSFER


REAL TIME NETWORK

MODEL

VSRESULTS

INPUT CRT DISPLAYS

VOLTAGE SCHEDULER

PARAMETERS

BF2 317

VOLTAGE SCHEDULER SOLUTION

OUTPUTPROCESSING

STATEESTIMATOR

SOLUTION DATA

TRANSFER


REAL TIME NETWORK

MODEL

VSRESULTS

Figure 3-8. Overview of Voltage Scheduler Function

The Voltage Scheduler function is executed automatically at a specified periodic frequency following the execution of the State Estimator function. The results can be used (manually) by the dispatcher to alter the system voltages to minimize voltage violations or active power losses. The function ranks the controls in their appropriate order of effectiveness in eliminating overloads or changing system losses. This gives the option to filter out control actions that have minor impact on the objective (feasibility or loss minimization).

The Voltage Scheduler function can also be executed on demand via the Real-Time Sequence Execution Control Display.

The algorithms for the Voltage Scheduler are exactly the same as the ones used by the Optimal Power Flow in a MVAR security optimization and loss minimization mode. For more details refer to Section 3.9.3.

3.5.2 VS Interfaces with Other Functions

State Estimator constructs the solved real-time network which is the sole source of network description for Voltage Scheduler.

3.5.3 VS Algorithm

The algorithms for the Voltage Scheduler are exactly the same as the ones used by the Optimal Power Flow in a MVAR security optimization loss minimization mode. For more details on the algorithm refer to Section 3.9.3.



3.5.4 VS User Interface

As with other real-time functions, control of execution of the Voltage Scheduler (VS) function is provided on the Real-Time Sequence Execution Control display. VS provides only the displays of its local data requirements.

Company Control Status Display: This display provides for entry of optimization control statuses for the various companies and allows for enabling/ disabling bus voltage control status, and global enable/disable for branch flow control status.

Unit Voltage/MVAR Parameters Display: This display provides for entry of unit voltage ranges and control statuses.

LTC Parameters Display: This display allows entry of LTC voltage ranges and control statuses.

Phase Shifter Parameters Display: Phase shifter ranges and control statuses are entered on this display.

Capacitor/Reactor Parameters Display: This display allows entry of controllable capacitor/reactor voltage ranges and control statuses.

System Bus Voltage Limits Display: This display is used to enable or disable voltage limit checks on non-regulated buses using voltage range limits.

Unit Summary Display: This display shows the rescheduled unit voltage setting before and after VS solution. The controls are listed in order of effectiveness.

LTC Summary Display: This display shows the rescheduled LTC voltage setting before and after VS solution. The controls are listed in order of effectiveness.

Phase Shifter Summary Display: The current and optimized phase shifter tap settings are displayed here. The controls are listed in order of effectiveness. Phase shifters are only used as controls for loss minimization.

Capacitor/Reactor Summary Display: This display shows the rescheduled controllable capacitor/reactor tap setting before and after VS solution. The controls are listed in order of effectiveness.

Pre- and Post-Solution Violation Summary Displays: Displays will be provided to show the violations that existed before and after VS solution.

Losses Summary Display: This display shows the active power losses before and after the VS solution together with the change in losses.

Branch Overloads Display: This display shows the overloaded branches after the VS solution.



3.6 Dispatcher Power Flow (DPF)

The Dispatcher Power Flow function is a study function which executes only on user request; it is used to examine the steady-state conditions which may exist on the power network under a wide variety of hypothesized conditions. The following summarizes the features within the Dispatcher Power Flow function:

Provides a full A-C power flow

• Voltage magnitudes and phase angles

• Real and reactive power flows

Provides study load flow solutions of network conditions

• Computes and limit checks MW, MVAR, KV, MVA

• May use real-time conditions as the "base case" or a saved study case

• Permits modifications to the "base case"

Provides convenient input and output

• Uses Study Case Input/Output workstation displays which have the same static structure as SCADA one-line displays for entry and output in a familiar form

• Tabular input/output workstation formats are also available

• Batch-type print-outs can be requested

Permits as entry most variable conditions

• Breaker status

• Load MW/MVAR

• System load or interchange; limits, costs

• Generator values – limits, costs, availability

• Transformer taps, limits, setpoints

• DC link schedules and control mode parameters

Operator control of convergence tolerances and other solution parameters

Ability to designate a generator as controlling the voltage at a remote bus. In addition, a tap changing transformer can be designated to control the voltage



at either side of the transformer or at a remote bus. Voltage Control Capacitors (VCC) can also be designated to control their bus voltage.

Generators, LTC transformers, and VCCs can simultaneously regulate the voltage of a local or remote bus.

MVAR limiting of units is represented

Handles multiple electrical islands

Interfaces to an Outage Scheduler function (Option)

3.6.1 DPF Functional Description

An overview of the Dispatcher Power Flow function is shown in Figure 3-9.

BF2 319

DPF/OPFPOWERFLOW

SAVECASES

TABULARDISPLAY

HARD COPYOUTPUT

UNITCOMMITMENT

STUDYNETWORK

MODEL

STUDYSECURITYANALYSIS

OUTAGESCEDULES

(Option)

SHORTCIRCUIT

CALCULATIONS

REAL-TIMENETWORKMODEL OR

SAVE CASES

NETWORKPARAMETERADAPTION

ONE LINEDIAGRAMS

DPF/OPFSOLUTION

FILE

BF2 319

DPF/OPFPOWERFLOW

SAVECASES

TABULARDISPLAY

HARD COPYOUTPUT

UNITCOMMITMENT

STUDYNETWORK

MODEL

STUDYSECURITYANALYSIS

OUTAGESCEDULES

(Option)

SHORTCIRCUIT

CALCULATIONS

REAL-TIMENETWORKMODEL OR

SAVE CASES

NETWORKPARAMETERADAPTION

ONE LINEDIAGRAMS

DPF/OPFSOLUTION

FILE

Figure 3-9. Overview of Power Flow Function

In order to facilitate use of the Dispatcher Power Flow, an extensive system of data initialization and scheduling subfunctions are included and are implemented through the user interface.

The data initialization subfunctions allow an operator to retrieve the data required to define a Dispatcher Power Flow in several ways:

The entire input data file may be retrieved from any one of the previously-stored Dispatcher Power Flow input cases. Data is stored in the input file at the device level.



The entire input file may be copied from the State Estimator function, resulting in a definition which matches the real-time network configuration and real-time solution.

The file may be constructed piecemeal. Network status can be obtained from either the "normal" device positions or from real-time, the network load can be obtained using Network Parameter Adaptation parameters for any specified hour, all other parameters can be obtained from database default.

A Load Scheduler is provided within the Dispatcher Power Flow system. The Load Scheduler retrieves from Network Parameter Adaptation, the appropriate set of real and reactive power load distribution and switchable device parameters for the day and hour type specified by the user for the power flow run. The user may then modify any of these parameters. The forecasted load and the relationship of external company loads to the Iraq SCADA Refurbishment company load can also be modified before executing the Load Scheduling function. Scheduled loads can be reviewed after execution and individual load point real and/or reactive loads can be modified if necessary.

A Generation Scheduler is also provided which acts within the Dispatcher Power Flow system. When invoked by the user, this subfunction schedules unit generation to meet the specified load and interchange for each company, and it also schedules the desired voltage for each unit utilizing data from Network Parameter Adaptation. The generator MW outputs are determined by a simplified dispatch/commitment algorithm which uses a quadratic cost curve and ignores losses, time-dependent costs, etc. The operator may retrieve the unit MW schedules from the Unit Commitment function. The desired voltages are determined from data entered in the database defining a linear relationship between each unit desired voltage and the company load.

Before and after each data activity, displays are available for operator override of the default data. The only data which always has an operator as its source are:

Time and date being studied

Net Interchange for external companies

The network database which serves as input to the Power Flow has an explicit representation of all bus sections and logical devices (breakers, switches, etc.) which are entered via the Information Management function. All network status for the Dispatcher Power Flow is then displayed and entered on one-line diagrams by actual switching processes. If, in the course of setting up a Dispatcher Power Flow, the operator has made such entries, he will also execute the Study Station Model Rebuild subfunction which processes logical device status to produce buses, where a bus consists of all bus sections connected by closed devices. This serves two purposes: it reduces the network dimensionally to a more reasonable level for the network solution, and it determines which elements of the network (units, branches, etc.) are not connected to any legitimate bus.



At any time, the data residing in the Dispatcher Power Flow input area may be saved in one of the Power Flow input cases for future retrieval. Any case so saved remains available until either a new case is stored in that area or a new database is stored by Information Management which has introduced an incompatible set of network identifiers. The data is saved to the most detailed level (i.e., device status, load point level).

The following special features are handled:

Net interchange is controlled for all companies.

Generating units control a voltage anywhere in the system.

Non phase-shifting transformers are modeled with taps on both sides. One of the taps may also be designated as tap-changing and may control either a voltage on the high or low side or a remote bus voltage. All taps are input and solved as discrete integer tap settings.

Phase-shifting transformers are modeled as simple angular shifts in series with an impedance.

DC links are modeled as a single bus injection or a double ended branch for a variety of control modes.

Limits are respected on unit MW and MVAR outputs, transformer taps, and phase-shifter taps.

Voltage control capacitors may control their bus voltages.

If the network is disconnected, up to ten subnetworks having both load and generation are solved in a single solution step.

The output data produced by the solution subfunction is immediately available for display. Detailed results are available both on one-line diagrams and in tabular station-by-station formats suitable for reproduction on the line-printer. Tabular summary displays are available for:

Overloaded lines, transformers, and voltage limit violations

Generation MW, MVAR

Tap changers

Phase-shifters

Voltage Control Capacitors

DC links

Bus voltage control



Zone, company and system generation, load and losses

Solution summary

Line-printer copies of all of these except the one-lines are available by operator request, and to reduce the volume of detailed printout, this may be requested only for a selected zone (where a zone is a predefined subset of a company).

A save area is also provided so that copies of the Dispatcher Power Flow output may be saved for future review. An output case which is recalled from storage is available for all the same subfunctions as one generated by the solution.

An Output Case Comparison subfunction is also available within the Dispatcher Power Flow. This subfunction compares the output results of two network solutions and identifies the differences. The differences are generally sorted by company, and then by the amount of difference of the various types of equipment. Differences which are below a user-modifiable threshold are removed from the results to simplify comparison. Additionally, the user may specify which companies should be included in the comparison. The following case comparisons are permitted.

One power flow user versus another power flow user

One power flow user versus a power flow save case

One power flow save case versus another power flow save case

One power flow user versus State Estimator results

Security Dispatch results versus State Estimator results

Voltage Scheduler versus State Estimator results

Security Dispatch versus Voltage Scheduler results

3.6.2 DPF Interface with Other Functions

The Power Flow uses data from the following functions:

Model Update: To obtain the real-time status of logical devices.

Network Parameter Adaptation: To obtain data necessary to forecast distributed network loads.

State Estimator: To obtain the real-time solution of the network.

Unit Commitment (Option): May be used to retrieve unit MW output schedules.



Outage Scheduler (Option): To obtain the outage schedules of logical devices for a specified time and date.

The Power Flow supplies data to the following functions:

Study Security Analysis: Receives the solved network from the Power Flow output to be used as a base case for security studies.

Short Circuit Calculations: Receives the solved network from the Power Flow output to be used as the base case for short circuit calculation studies.

3.6.3 DPF Algorithm

The Dispatcher's Power Flow makes use of the two distinct solution algorithms; the Fast Decoupled Power Flow (FDPF) algorithm and the Newton-Raphson (NR) algorithm. The FDPF algorithm is the first choice because of its speed advantage. However, for certain network topologies, network parameters, and control designations, it is known that the FDPF algorithm has difficulty converging. In such an event the solution switches to the NR algorithm, which has better convergence properties. This switching is performed by the solution subfunction itself. It is possible to specify that the FDPF not be used at all.

The essence of the power flow problem is to solve a set of general non-linear equations of the form:

F(X) = 0 (35)

Where F is a non-linear vector function of a vector argument X.

The power flow equations are a set of N complex equations, one for each bus, of the form:

(36) ( )Nk

meVjBGm

NkeV

netk

jQnetk

P jmkmkm

jk

,...,10

1 ==+

=Σ−++− θθ

where:

Vk is the voltage magnitude at bus k

θk is the voltage angle at bus k

Gkm +jBkm is the (k,m)th element of the bus admittance matrix



kbusatinjectionspowerreactiveandrealnettheareQ

Pnet

k

netk

The preceding equation can be separated into two real equations:

Pknet – Pk (V,�) = 0

k = 1, ..., N (37)

Qknet – Qk (V,�) = 0

These equations can be solved by making use of the Taylor series expansion of F(X). The vector matrix Taylor expansion of F(X) about the initial guess X = X(0) is:

F(X) = F(X(0)) + J�X + higher order terms (38)

)0()(

)( XXX

XFJ

j

jij

=∂

∂= atevaluated

Where J is the Jacobian matrix:

Ignoring the higher order terms this can be rewritten as:

(39) ( ))0(XFKJ −=∆

This equation is solved for ∆X using optimal ordering and Gaussian elimination. The state variables, X, are updated by the corrections, ∆X, serving as a new guess, X(K). If Fi(X

(K)) is less than some tolerance for all i, then X(K) is the desired solution. If not

then a new Taylor's series expansion about the point X(K) is performed and the process repeats. This is the Newton-Raphson algorithm. Note that it requires the Jacobian matrix to be recalculated and refactorized each iteration.

The Fast Decoupled Power Flow algorithm can be developed from the Newton-Raphson algorithm in the following manner. When using the Taylor series expansion, with the higher order terms ignored, the real and reactive power mismatches at bus k (WPk and WQk) can be written as:

( ).sincos1

kmkmkmkmmknetKk

BGVm

NVPP θθ +

=Σ−=∆

(40)



( )kmkmkmkmmk

netkk

BGVm

NVQQ θθ cossin

1−

=Σ−=∆

(41)

where:

θkm = θk – θm

Applying the Newton-Raphson method to the solution of these non-linear equations, the Jacobian matrix equation has the general form:

=

V/VL

MJH

QP

∆θ∆

∆∆

(42)

where: H, M, J, and L are coupling submatrices with the following definitions:

[H] = θ∂

∂ P

[M] = VP∂V

∂ ≈ [0]

[J] = θ∂

∂ ≈ [0] Q

[L] = VQV

∂∂

Elements of the off-diagonal submatrices J and M are much smaller in magnitude than elements of the diagonal submatrices H and L in the matrix equation due to the weak coupling between the real power and the reactive power equations. Neglecting the off-diagonal coupling submatrices M and J, two sets of matrix equations are obtained:

∆Π = [Η] [∆θ] (43)

�Q = [L] [�V/V] (44)

where:

Hkm = Lkm = Vk Vm (Gkm sin θkm – Bkm cos θkm )



Hkk = -Bkk Vk2 -Qk and Lkk = -Bkk Vk

2 + Qk

Further simplifications are made by observing that in most realistic situations:

cos θkm ~ 1

Gkm sin θkm << Bkm

and

Qk << Bkk Vk2

With these approximation equations (9) and (10) reduce to:

[�P] = [VB'V] [��] (45)

[�Q] = [VB"V] [�V/V] (46)

Where the elements of B' and B" are elements of -B, the susceptance matrix.

Taking the left most V terms to the left-hand side of the equations and setting the right most V term to 1 p.u. in equation (45), as V affects the MVAR flows mainly, equations (45) and (46) reduce to:

[�P/V] = [B'] [��] (47)

[�Q/V] = [B"] [�V] (48)

Equations (47) and (48) are the standard Fast Decoupled Power Flow equations. In calculating the elements of B' and B", the following decoupling considerations are used:

a. Shunt elements and off-nominal transformers are neglected in B'.

b. Phase shifters angle effects are neglected in B".

c. Series resistances are neglected in B'.

The major advantage of these equations is that the matrices [B'] and [B"] only need to be calculated and factorized once. This is the characteristic that gives the FDPF algorithm its speed advantage over the NR algorithm.

3.6.4 DPF User Interface

The Power Flow has an extensive system of displays which make this a very general and highly interactive function. Some of the key displays are summarized below:



Execution Control Display: This display serves as the central mechanism for operator control of the Power Flow study system. Through it, the operator can enter basic system parameters and request execution of the various Power Flow functions. Some studies may be set up and executed without the use of any other display.

The Execution Control Display is a logical sequence of steps (function executions) which form the setup, solution and review stages of a Power Flow study, together with display/entry of appropriate parameters at the various steps.

The operator may request execution of any step by selecting the point corresponding to the desired action. Not all steps need to be executed. Different studies will call for slightly different actions. The system is exceptionally flexible where change cases are being run in sequence. Between runs, only those steps where changes occurred need to be re-executed.

Saved Case List Display: This display lists basic descriptive information concerning cases currently resident in the input save area, including:

Case identification

Case title (it is the operator's responsibility, prior to saving a case, to enter a title which will clearly describes the case)

Time being studied

Time saved

Input Case Summary Display: This display is designed to summarize the major characteristics of the system currently existing in the input work area.

The network title, which is the title of the base case network stored by Information Management, the case title and time being studied make up the first part of the display. The second section of this display summarizes load, generation, and interchange for each company.

Load Parameters Display: This display provides the operator with a detailed picture of network load data. It lists all bus section loads within each load group in each company.

Load Group Parameters Display: This display shows all the load groups in the network, including:

Company zone and load group name

Percent of company load

MVAR/MW ratio for the load group

MW, MVAR load group total



Generator MW Parameters Display: This display provides a detailed summary of generator real power data. It lists all generators in each station in each company.

Generator Reactive Parameters Display: This display provides a detailed summary of generator reactive and voltage regulation data. It lists all generators in each station in each company.

DC Link Parameters Display: This display provides a detailed summary of the DC link schedules and control mode selections. Available control modes include constant voltage, constant MW, and constant ampere.

LTC Transformer Parameters Display: This display provides a detailed summary of LTC transformer data. It lists all voltage transformers which have LTCs by station and company.

Phase-Shifter Parameters Display: This display provides a detailed summary of phase-shifter data.

Voltage Control Capacitor Parameters Display: This display provides a detailed summary of voltage control capacitors data.

Station Input One-Line Displays: Station one-line diagrams will be provided for entry of status and transformer taps.

Abnormal Status Display: This display provides a summary of abnormal logical devices (as entered via the station input one-lines). It lists only those devices whose status is abnormal.

Solution Summary Display: This display is generated by the solution algorithm. It reports the progress of the solution.

Saved Output Case Summary Display: This display lists the cases stored in the output save area and is identical in form to the display described for input cases.

Output Case Summary Display: This display contains the same variables described for the input case summary, except that it describes the current output case and includes the final disposition of the case and the solution output values for such quantities as company generation.

Overload Summary Display: This display lists all lines and transformers in the power flow results which are above their normal rating.

Generation Summary Display: This display lists the solved real and reactive output for each generating unit.

LTC Summary Display: This display lists each solved transformer regulating tap, together with its limits and identification.

Phase-Shifter Summary Display: This display lists each phase-shifter tap, together



with its limits and identification.

Voltage Control Capacitor Summary Display: This display lists each solved voltage control capacitor tap and MVAR output.

Voltage Limits Summary Display: This display will list each bus which violates its high/low voltage limits.

Station Results Display: This display gives a detailed picture in tabular form of the Power Flow results on a bus-by-bus basis for each station in each company.

The Station Results display contains the following information:

Table of contents

Station name and company name

Bus nominal KV, solved KV and solved angle in degrees

Line, connecting station, MW, MVAR, amps, and percent loading

Transformer name, opposite winding KV, MW, MVAR, MVA and percent loading

Capacitor name and MVAR

Load MW, MVAR

Unit name, MW and MVAR

Station One-Line Output Diagrams: Power flow results will be additionally provided in detail on one-line diagrams. The static portion of such displays will correspond with the station input one-lines, but there will be no enterable data. Instead, the status will be displayed along with the loading of selected equipment and the KV at selected bus sections. Overloaded and out-of-range conditions will be shown in inverse video.

Abnormal Status (Output) Display: This display is identical to that for input; it is carried into the output for informational purposes.

Index of Displays: This display provides an index of Power Flow displays with poke-point selection of each.

Additionally, the Output Case Comparison subfunction of the Dispatcher Power Flow has a separate set of displays for executing the subfunction and for review of the results.

Through the Output Case Comparison input displays, the user is provided with the necessary mechanism to set up the desired case comparison. Entry is allowed for the following data:



Output Case Comparison Input Data:

Source for case 1

Source for case 2

MVA branch flow comparison threshold

Unit MW comparison threshold

Unit and VCC MVAR comparison threshold

LTC and VCC tap position comparison threshold

Voltage comparison threshold

For output results of the comparison, the subfunctions displays the case 1 value, the case 2 value, and the difference between the case 1 and case 2 values for a wide variety of values. A summary of the output data provided by these displays is as follows:

Company Summary Data:

Load MW

Delivered load MW

MW loss percentage

MW losses

Net interchange

MW generation

Generation MW capacity

Hourly fuel cost

Bus Voltage Data:

Voltage in KV

Voltage in per unit

Regulated bus voltage flag

Bus Model Data:

Bus configuration



Bus voltage

Unit Data:

Unit MW

Unit MVAR

Regulated bus voltage



LTC Data:

Tap position


Phase-Shifter Data:

Tap position

Load Data:

Load MW

Load MVAR

VCC Data:

Tap positions

MVAR output


Branch Data:

MVA flow

3.7 Outage Scheduler (OS)

The Outage Scheduler (OS) function provides data entry via workstation displays of expected future generator and equipment outages and optional specification of generator operating MW and operating limits. The equipment schedules, which include both generator and equipment outages, are used by the Optimal Power Flow and Unit Scheduling functions in order to retrieve equipment statuses for a specified future date and time. The Outage Scheduler uses the Relational Database Management System (RDBMS) for entry and storage of schedule information, and for report generation.

The Outage Scheduler function consists of the following subfunctions:

Entry Validation

Schedule Viewing, Ordering and Reporting

Schedule Archiving



User entries are validated by the RDBMS as they are entered. Outage Schedule information in the RDBMS can be displayed in many different formats. Ordering and viewing of Outage Schedule information can be accomplished based upon selected criteria that is used by the RDBMS. A report can be generated for the set of schedules currently being viewed. Equipment schedules that are no longer active for a specified period of time are archived from the Outage Scheduler operational database to the HFD/Outage Scheduler database.

3.7.1 OS Functional Description

Entry Validation

Entry validation is executed automatically following a data entry. Whenever one or more equipment schedules are added, deleted or modified, entry validation is executed to validate the schedules' information. Valid equipment are those that are defined in the Network Applications Primitive Database. All error-free schedules are stored in the relational database. For all invalid schedule information, error messages are generated. Invalid data could be as follows:

Invalid station name

Invalid voltage level name

Invalid equipment name

Invalid time span (i.e., end time is earlier than start time)

Invalid or incomplete device status

Duplicate equipment name with overlapping schedule times

Invalid unit limit or capacity

Switching actions required to implement the outage are automatically generated. OS provides a list of switches whose operation will produce the outage. The capability for the user to modify and delete switching actions from this list is provided.

It is also possible to enter equipment schedules for record purposes only. Schedules entered for record purposes only are indicated to validation by an equipment type of "INFO" (information).

It is possible for the dispatcher/operator to enter schedules for any future date supported by the RDBMS. The equipment to be included in the outage may be entered by selecting the equipment from a real-time one-line diagram.

Equipment schedules are organized into schedule groups. A schedule group is a grouping of one or more related equipment outage schedules. The schedule group provides for quick identification of related outage schedules for ordering, viewing and



reporting purposes. A schedule group may contain any combination of equipment schedules, with the same or varied equipment type, equipment status, start/end date, and schedule status.

The capabilities to duplicate, modify, and delete schedule entries and schedule groups by the user are provided.

Schedule Viewing, Ordering, and Reporting

Schedule ordering is handled by the RDBMS. Schedules can be ordered in a number of different ways. Examples of criteria that could be used by the RDBMS for ordering are as follows:

Group identifier

Start date/time of schedule (day, month, year, hour)

End date/time of schedule (day, month, year, hour)

Station name, voltage level name, or equipment name

Schedule Status

Equipment type

The ordering process can sub-divide the outages into outages in effect for past, present, and future days. A view of all schedules is also available. The following rules are examples that could be used by the ordering subfunction:

1. Schedules whose end dates are earlier than the present day are included in the past ordered list.

2. All schedules for which the start date is earlier than, or same as, the present day and the end date is the same as, or greater than, the present day are included in the lists for the present day.

3. All schedules for which the end date is later than the present day are included in the list for future days. Thus, an outage for the present day that continues into a future day will be included on both present day and future day lists.

These are only a few of the criteria that can be used for selecting and ordering the equipment schedule information for viewing and report purposes.

A report may be generated on any list of equipment schedules currently being viewed via the user-specified ordering and viewing criteria.

Schedule Archiving

The Schedule Archiving subfunction is automatically executed periodically (once per



day) to archive schedules which have end dates expired for a user specified number of days prior to the current day. This subfunction can also be executed by manual request. The automatic archiving of schedules can be enabled/disabled by the dispatcher/operator.

The capability to view, order, and report on the previously archived schedules is provided. Similar functionality for the viewing, ordering, and reporting of on-line schedules is provided for archived schedules. The primary difference is that the archived schedules may be viewed for a specific range of dates, rather than the past, present, and future subdivisions used for on-line schedules.

3.7.2 OS Interface with Other Functions

The Outage Scheduler interfaces with the following functions:

Power Flow (DPF/OPF):

• Uses schedules of logical device status for a specified time and date.

• Uses the primary company operating unit data for a specified time period

Unit Commitment (UC) uses the primary company operating unit data for a specified time period.

3.7.3 OS Algorithm

The Outage Scheduler function does not involve any formalized algorithms. The RDBMS provides the techniques that are used for the viewing, ordering, reporting, and archive subfunctions.

3.7.4 OS User Interface

All user interactions for the Outage Scheduler function are performed through the RDBMS user interface. Start and end times on the displays are entered, maintained, and displayed by year, month, day, and hour.

Displays can be grouped functionally into the following areas:

Execution control

Input displays

Output displays

Execution Control Display: The Outage Scheduler execution control provides the



following capabilities:

Enabling/Disabling automatic execution of Schedule Archive subfunction.

Manual execution of the Schedule Archive subfunction.

Manual execution of the Schedule Ordering subfunction on a pre-defined ordering and querying criteria.

Edit Outage Schedules Input Display

The Edit Outage Schedules Input Display provides the user with the capability of adding, deleting, duplicating, or modifying equipment outage schedules and schedule groups.

Entry of a schedule group includes specification of the following information:

Group identifier

Entry date

The following schedule group information is entered for record purposes:

Name of responsible person

Comments

All equipment schedule data is enterable or selectable via a list of values. Additionally, equipment identifiers may be entered by selection of a network equipment from a one-line diagram. Entry of an equipment schedule includes specification of the following information:

Equipment type

• LN (transmission line)

• GU (generating unit including synchronous condenser)

• XF (transformer)

• PS (phase-shifter)

• SD (series device)

• RC (shunt reactor)

• DI (DC injection)

• DC (DC line)



• FB (filter bank)

• CP (shunt capacitor)

• BRSW (breaker/switch)

• INFO (information for record purposes only)

Station name

Voltage level name

Equipment name

Element name

Start date/time of schedule

End date/time of schedule

Equipment status between the start and end times

• OS, IS (out of service, in service for branches and shunt equipment)

• OP, CL (open, closed for logical devices)

• MR, UA, FX, AV, VC, DS (must run, unavailable, fixed, available, voltage support, and disconnected for generating units)

For generating unit outage schedules, the MW value for fixed units and the derated high and low MW operating limits for must run and available generators

Outage schedule status

• ACTIVE

• CANCELLED

The following equipment schedule information is entered for record purposes:

Remarks

Name of responsible dispatcher/operator

Name of operational dispatcher/operator

Name of field dispatcher/operator



Time when work started

Time when field dispatcher/operator arrived on-site.

Once a network equipment outage has been validated, required switching actions are generated. The following information is available for addition, deletion, or modification:

Switch station name

Switch voltage level name

Switching field name

Switch name

Start date/time switch status (OPEN, CLOSED)

End date/time switch status (OPEN, CLOSED)

Schedule Ordering Output Displays

The Order Outage Schedules and HFD/OS Archived Outage Schedules displays are the query interface to all existing and archived schedules, respectively. The following information is provided following an executed query in either form:

Group identifier

Equipment type

Station name

Voltage level name

Equipment name

Element name

Start date/time

End date/time

Scheduled equipment status between start and end times

Unit MW (for fixed)

Unit high limit (for must run and available)

Unit low limit (for must run and available)



Schedule status

Validation status (VALID, INVALID)

Date saved (HFD/OS Archived Outage Schedules only)

Queries may then be executed by the operator using the RDBMS interface to reduce the schedule list to that of interest such as currently active schedules, current day schedules, schedules within a specific station, or schedules ordered by user selected criteria. Validation status provides information on the validity of the outage following any primitive database changes. A report can be generated on the set of schedules currently being viewed.

3.8 Short Circuit Calculations (SCC)

The Short Circuit Calculation function is designed to compute the fault levels in electric power systems. The following fault types are considered:

Three phase to ground

Single phase to ground

Phase to phase

Double phase to ground

The Short Circuit Calculation function provides the following features:

Studies the effect of fault on current system

Alerts the operator about what can happen, before it really happens

Real-time – initializes the base case to the State Estimator solution

Study – initializes the base case to the Power Flow results

Simulates topology changes due to a single branch outage prior to fault

Mutual coupled lines

Input to the Short Circuit Calculation functions consists of:

Base case network from the State Estimator or the Power Flow

Fault types and locations (operator may modify interactively in study mode)

The following is a summary of available output options:



Fault Violation List – violations for each fault

Bus fault currents with and without branch outages

Maximum fault current contributions on each branch and generator

SHORT CIRCUITCALCULATION

SOLUTION

BF2 320

TABULARDISPLAY

HARD COPYOUTPUT

STATEESTIMATOR

INPUTNETWORK

BUSMODEL

POWERFLOW

NETWORKRETRIEVAL

INPUTCRT

DISPLAY

FAULTDATA

FAULTDATA

SHORT CIRCUITCALCULATION

SOLUTION

BF2 320

TABULARDISPLAY

HARD COPYOUTPUT

STATEESTIMATOR

INPUTNETWORK

BUSMODEL

POWERFLOW

NETWORKRETRIEVAL

INPUTCRT

DISPLAY

FAULTDATA

FAULTDATA

Figure 3-10. Overview of Short Circuit Calculations Function

3.8.1 SCC Functional Description

The purpose of the Short Circuit Calculations function is to compute the fault currents and fault current contributions. Fault currents at a faulted bus are compared against all circuit breaker ratings for each circuit breaker connected to the faulted bus. Fault current contributions from branches and generating units near the faulted bus are also calculated and may be compared against their respective fault ratings. Any fault current or fault current contribution which exceeds a non-zero rating appears on a Fault Violation List. The violation checking is skipped for any rating which has a zero value.

The Short Circuit Calculation solution makes use of symmetrical component transformation, sparsity techniques for forming and factorizing bus admittance matrices, and Fast Forward and Fast Backward solutions to solve for relevant portions of the bus impedance matrices.

The symmetrical component reference frame is used to analyze any of the unbalanced fault types (single phase-to-ground fault, phase-to-phase fault, or double phase-to-ground fault). This method requires the construction and use of positive sequence, negative sequence, and zero sequence bus admittance matrices. The Short Circuit Calculations function may be used to study balanced (three phase to ground) faults only, in which case zero sequence admittance values are not required.

The real-time mode of Short Circuit Calculations utilizes the network solution



obtained from the State Estimator function as the network pre-fault condition. The study mode of Short Circuit Calculations may utilize the network solution obtained from either the Optimal Power Flow function or the State Estimator function as the network pre-fault condition.

Fault Ratings

Fault ratings may be defined on any or all of the circuit breakers and/or they may be defined on any or all of the branches or units. A branch may have a unique fault rating defined for each end of the branch. The fault ratings that are assigned to branches or units do not have to be associated with any specific circuit breakers. A special value of zero is used to indicate an undefined fault rating.

Fault Selection

There are two methods available for selection of fault location(s) — Multiple Fault Selection or Individual Fault Selection. Even though multiple fault locations and fault types may be analyzed, each fault is evaluated separately. So, the fault currents that are to be calculated are due to only one fault being applied. Typically the Multiple Fault Selection method is used to calculate fault current and their contributions from a small number of buses (user enterable) apart from the fault. While the Individual Fault Selection may be used to evaluate fault currents several buses from the fault or examine the effects of branch outages.

The following fault types are available for either Multiple Fault Selection or Individual Fault Selection mode:

Three phase to ground

Single phase to ground

Phase to phase

Double phase to ground

The selection of the fault types and fault locations are under operator control through the user interface. In the Multiple Fault Selection mode, separate flags exist to enable/disable evaluations of each fault type at each station/voltage level. In the Individual Fault Selection mode, an individual branch name is used to identify the fault location.

Branch Outages

The Short Circuit Calculations function can perform fault analysis with a single branch outage. When branch outages are studied, the fault analysis is repeated for each branch outage one at a time. In the Multiple Fault Selection mode, when a violation occurs at the faulted bus without a branch outage, an option is available to study the effects of branch outages of all branches connected to the faulted bus. In the Individual Fault Selection mode, an option is available to study the effects of



selected branch outages or all branches connected to the faulted bus. For efficiency reasons, nominal voltages at each bus (1.0 per unit and zero angle) are used as the prefault voltages during the evaluation of a branch outage.

Mutual Coupling

The Short Circuit calculations function allows the modeling of mutual coupled lines by including the appropriate elements in the zero sequence matrix.

One-Lines

Multiple faults and fault types may be evaluated with each Short Circuit Calculations study. So, only the maximum value of fault current contribution associated with each branch and unit from all of the fault types and locations is available for one-line displays. The fault type and bus name of the fault location for each of these maximum values are also made available.

Fault Impedances

The Short Circuit Calculations function allows the modeling of fault impedances (Zf) and fault to ground impedances (Zg). Different values of impedances (both resistance and reactance) may be used for each of the fault types (three phase-to-ground fault, single phase-to-ground fault, phase-to-phase fault, and double phase-to-ground fault). However, only one set of impedances, per fault type may be used for all fault locations being evaluated. A three phase-to-ground fault is a balanced fault, so the fault to ground impedance value is not required. The fault impedance for this type of fault is the impedance seen from each of the three phases to the point of the fault. For a single phase-to-ground fault, the faulted phase is shorted to ground, so only the fault to ground impedance is used. For a phase-to-phase fault, ground is not involved, so only the fault impedance is used which is the value of impedance in between the two faulted phases. For a double phase-to-ground fault, both the fault impedance and fault to ground impedance are used.

3.8.2 SCC Interface with Other Functions

The SCC function interfaces with the following functions:

Power Flow: To obtain the network model and solved state to be used as the prefault network condition for SCC studies.

State Estimator: To obtain the network model and solved state to be used as the prefault network condition for SCC studies.

3.8.3 SCC Algorithm

The SCC function uses the Thevenin Equivalent bus impedance formulation in the



symmetrical component frame of reference to compute unbalanced fault currents and voltages. Formally:

VF = VO – Z IF (49)

where:

VF = Voltage vector

VO = Prefault voltage vector

Z = Bus impedance matrix

IF = Bus current vector with zero everywhere except at the fault bus

The calculation of faults requires that the appropriate Thevenin equivalent for the buses involved in the fault be available. The Thevenin voltages, V0, are the voltages at these buses prior to the application of the fault. The positive sequence Thevenin voltages can be selected to be the solved voltages or 1.0 p.u. at zero degrees, with the zero- and negative-sequence voltages being zero.

The key to the computational efficiency of the SCC algorithm is the combined application of the following features:

Symmetrical component transformation

Sparsity-oriented factorization of the bus admittance matrices

Use of sparse vector methods (FF-Fast Forward and FB-Fast Back)

The way in which the Thevenin impedances are obtained and the simulation of topology changes are described later.

During the formation of the positive-sequence bus admittance matrix, the admittance values of generator sub-transient reactance and the connected loads are incorporated into the diagonal elements of the buses to which they are connected.

The major steps in the Short Circuit Calculations are as follows:

Step 1. Convert all solved MW/MVAR values of load, DC injections, and DC branch values into constant impedances.

Step 2. Form and factorize the positive sequence bus admittance matrix [Ybus]. If unbalanced faults are to be evaluated, also form and factorize the zero sequence matrix bus admittance the matrix. The negative sequence bus admittance matrix is not formed, since it is assumed to be the transpose of the positive sequence matrix.



Step 3. Determine the list of output buses of interest. This consists of all buses within "n" levels from the faulted bus p. The parameter "n" is user specified, which is typically set to one for Multiple Fault studies and set to the full network for Individual Fault studies.

Step 4. For a fault at bus p, find only column p of each of the three inverse bus admittance matrices [Ybus]-1 = [Z]. Fast Forward (FF) and Fast Backward (FB) solutions are used to minimize the number of arithmetic operations while calculating the minimum number of desired elements for column p. The FB solution path is chosen in such a way to insure all output bus elements of column p will be found.

Step 5. For each fault type being evaluated at bus p, calculate the sequence fault currents and voltages at bus p.

Step 6. For each sequence, calculate post-fault voltages for any of the remaining output buses.

Step 7. Calculate fault current contributions for all branches and units within the circle of output buses.

Step 8. The resulting sequence fault currents and fault current contributions are transformed into a, b, c phase values. The maximum of the three phase fault currents is retained as the Bus Fault Current for the fault being studied. Similarly the maximum each of the three phase values of each fault current contribution is retained as the branch or unit Fault Current Contribution.

Step 9. Each circuit breaker connected to the faulted bus is checked for violations. Any of these circuit breakers which have non-zero ratings and the rating does not exceed the Bus Fault Current are included on the Fault Violation List.

Step 10. Each of the branch and unit Fault Current Contributions is checked for violations by comparing the value to the respective branch or unit fault rating. Any non-zero rating which is exceeded is included on the Fault Violation List.

Step 11. For each branch and unit Fault Current Contribution value which exceeds the value calculated for the respective branch and unit by all other previous fault types or locations, update the respective one-line table and the tables containing the fault type and bus name of the fault location.

Step 12. Repeat starting at step 3 for each bus which requires a fault to be evaluated.



3.8.3.1 Formation and Factorization of the Bus Admittance Matrix

The initial step consists of the formation of the three sequence admittance matrices. These are:

[Y1] - The positive sequence admittance matrix

[Y2] - The negative sequence admittance matrix

[Y0] - The zero sequence admittance matrix

The construction of the positive sequence admittance matrix Y1, is similar to the standard bus admittance matrix used for a standard Power Flow. The exceptions are that admittances representing generators and loads will be included in the diagonal elements of Y1. Also, the asymmetries introduced by phase-shifters will be included in Y1, so Y1 is not a symmetrical matrix.

The construction of the zero sequence admittance matrix Y0, differs from Y1 in the following ways:

Zero sequence admittance values are used

The admittance for a load is assumed to be zero (no diagonal contribution)

Phase Shifter angles are assumed to be zero

Mutual coupling line impedances are included

The transformer admittances will be determined based on the winding type

It should be noted here that negative sequence admittance matrix Y2 is actually equal to the transpose of Y1 and therefore the following manipulations are done only for Y1 and Y0 in the actual calculation. Each admittance matrix is optimally ordered using sparsity techniques and factorized into the following forms:

[Y] = [L] [D] [U], Y� Y1, Y2, Y0 (50)

where:

[L] is a lower triangular matrix

[D] is a diagonal matrix

[U] is an upper triangular matrix



3.8.3.2 Network Modifications

The SCC function provides capability for the study of contingency cases where the configuration of the original network changes due to a single branch outage. A method of modeling the effects of the branch outage is used which will avoid the refactorization of an entire bus admittance matrix. Only the elements of each sequence bus admittance matrix that effect the Fast Back solution path are modified. This is accomplished by performing reverse factorization along the Fast Back solution path, adjusting the elements for the branch outage, and finally forward factorization along the Fast Back solution path. The following steps are used on each sequence bus admittance matrix to model the effects of the branch outage:

Step 1. Find the required changes to the bus admittance matrix due to the branch outage.

Step 2. Set up the paths for a Fast Forward and Fast Back solution.

Step 3. Performs reverse factorization of a sparse matrix along the given Fast Back solution path.

Step 4. Subtract the branch outage admittance elements from the reversed factorized matrix.

Step 5. Performs forward factorization of the sparse matrix along the given Fast Backward solution path.

Step 6. Perform the Fast Forward and Fast Back solution.

Step 7. Restore factored matrix elements along the given Fast Backward solution path.

3.8.4 SCC User Interface

A set of displays are provided to enable the user to prepare the input to the SCC function, control the execution and verify the specific results.

Execution Control Display: The display provides the user full control over the execution of the SCC function. It enables users to execute the data retrieval subfunctions and to specify the relevant execution options. The display admits program parameters via enterable fields and has sensitized points that cause subfunction executions. They are organized in an order reflecting the logical sequence of the SCC steps.

Input Displays

Generating Unit



• Unit impedance X"d

• Unit zero-sequence impedance X0

• Fault rating associated with unit's breaker(s)

Transmission Line

• Line zero-sequence impedance (including charging)

• Fault ratings associated with each end of the line

Transformer

• Transformer winding types

• Transformer grounding impedance

• Transformer zero-sequence impedance

• Fault ratings associated with each end

Phase-Shifter

• Phase-shifter zero-sequence impedance


Series Device

• Series devices zero-sequence impedance


Circuit Breaker

• Fault rating

Mutual Coupled Lines

• Line names and impedances

The following data items may be input:

Flag to enable/disable the use of solved voltages

Fault impedances and fault to ground impedances

Fault locations and fault types are required. There are two methods available to



provide fault location and type information. An input flag is available to select one of the following two methods:

Individual fault selection

Multiple fault selection

The following data is required for an individual fault selection:

Flags for selection of fault type (choice of any or all of 3-phase, phase-to-phase, 2-phase to ground and 1-phase to ground

Station name

Equipment name

Equipment type

• Line

• Transformer

• Phase shifter

• Series Device

For Transformers, Phase shifters, or Series Devices faults are calculated at both ends of each branch

Flag to specify type of branch outage study (N = none, S = selected, A = All branches)

When selected branch outages are being used, the following data is required for each outaged branch:

• Station name

• Equipment type

• Equipment name

The multiple fault selection mode requires flags to be set at each station and voltage level where fault analysis is to be performed. For each station/voltage level there are four flags to enable/disable the four fault types (3-phase, phase-to-phase, 2-phase to ground, 1-phase to ground). A fault study will be performed for each electrical bus at a given station/voltage level which has a flag enabled to perform a fault study.

Output Displays



For every bus in the system, the following output is provided for multiple fault studies:

Station name, voltage level, and bus name where fault is located

Total Bus Fault current value for each fault type

• Blank value for the buses not analyzed



For the individual fault studies, the following output is provided:

Total Bus Fault Current with and without any branch outages

• Fault current for each selected branch outage is provided

The following output is available for either Multiple Fault Selection or Individual Fault Selection mode:

1. The maximum value of fault current contribution associated with each branch and unit (near the faulted bus) from all of the fault types and locations is output for tabular and/or one-line displays. The fault type and bus name of the fault location for each of these maximum values is also output.

2. Fault currents at a faulted bus are compared against all circuit breaker ratings for each circuit breaker connected to the faulted bus. Fault current contributions from branches and generating units near the faulted bus are also compared against their respective fault ratings. Any fault current or fault current contribution which exceeds a non-zero rating appears on a Fault Violation List. The violation checking is bypassed for any rating which has a zero value. The following output is provided:

Station and equipment name

Equipment type (Circuit Breaker, Line, Transformer, Phase Shifter, Series Device or Unit)

Fault current

Fault rating

Percent violated

Fault type (3-phase, phase-to-phase, 2-phase to ground, or 1-phase to ground)

Branch Outage and type of branch being outaged (blank for non-branch outage faults)

3. A Branch Outage summary with the following output is provided:

type and bus name of fault location

Outaged branch station and equipment name and type of branch

Outaged branch pre-outaged fault current contribution

Fault current contributions with and without branch outage



3.9 Network Analysis Execution Control

The Real-Time Network Analysis Execution Control display (Figure 3-11) provides control over the execution frequency of all of the functions of the Real-Time Network Analysis sequence. It also provides the capability to manually execute any function of the Real-Time Network Analysis sequence. The sequence shown in Figure 3-11 flows from top to bottom after being initiated by one of the trigger sources.

Each Real-Time function has an associated enable/disable switch frequency parameter and a counter. The frequency parameter specifies what the number of executions of the State Estimator function must be before the associated function executes. Each counter is reset to the parameter value after executing the associated function and decremented by one every time the State Estimator is executed. When the counter is zero, if the function is enabled, the next function is bid.

The Real-Time Sequence can be initiated in one of three ways: Manual, Event or Periodic. These triggers are described below.

Manual Run Request: A manual run request causes any existing sequence to abort after the function presently being executed completes. The manually requested function is then executed, followed by functions according to the normal sequence.

Event Request: The sequence can also be triggered in response to specific events, unless the event run switch is opened. An event trigger has priority over a periodic trigger and terminates and restarts a sequence already running from a periodic request or a prior event request. This event trigger is not initiated until a user-specified amount of time (typically, one minute or less) has elapsed since the last status change affecting the network model, thereby allowing the system to stabilize.

Periodic Request: The Real-Time Sequence may be initiated periodically unless the periodic run switch is opened. The periodic initiation has the lowest priority and may be interrupted due to a manual or event request.

The Real-Time Sequence Execution Control display has two other executable control functions, RESTART and CLEAR.

RESTART provides the ability to execute the real-time sequence initialization subfunction to obtain a totally re-initialized bus model. The circuit breakers and taps can be initialized back to database values. The Real-Time Sequence then continues as normal except for the fact that all stations will have their bus model rebuilt. This provides the operator with a known starting point for the network model.

If a sequence aborts (due to hardware or software failure) before completion, the operator is notified that the sequence has halted via the display pending feature. The Real-Time Sequence may also be locked by a non-cleared request flag if a sequence aborts. To provide recovery capability, a CLEAR request flag capability is also provided in the Execution Control display. By clearing all flags, it restores the



Real-Time Sequence control to a normal status in which no functions are executing and no functions are waiting to be executed. This clearing is also done automatically when a system failover occurs.





Figure 3-11. Real-Time Sequence Execution Control

4. Forecast/Scheduling Application Software

The forecasting and scheduling application software includes tools for forecasting system load, scheduling generation, and analyzing the feasibility and cost of proposed interchange transactions. As shown in Figure 4-1, forecasting and scheduling functions interact with each other as well as with other application software.

Forecasting and Scheduling Application

Software


Software

OperatingSystem

Software

UnitCommitment




LoadForecast

CaseComparison



NetworkAnalysis

ApplicationSoftware

BF2 113


Software


Software

OperatingSystem

Software

UnitCommitment




LoadForecast

CaseComparison



NetworkAnalysis

ApplicationSoftware

BF2 113

Figure 4-1. Forecasting and Scheduling Application Software



The common sequence of operator job tasks includes the following steps in order.

Update the load forecast for weather forecast changes, or known load deviations and save the load forecast if desired.

Update generation schedule for forced maintenance or for maintenance schedule deviations. Based upon the unit commitment results, reschedule unit outages, or

Evaluate interchange transactions to cover any capacity or energy deficiencies, or to improve economics.

UNITCOMMITMENT

LOADFORECAST

NETWORK LOSSPENALTYFACTORS

TRANSACTIONEVALUATION

CASECOMPARISON

POWERFLOW

LOADDATA

WEATHER DATA

WEATHER FORECAST

INTERCHANGETRANSACTIONSCHEDULES

AGCDATA

BF2 328

UNITCOMMITMENT

LOADFORECAST

NETWORK LOSSPENALTYFACTORS

TRANSACTIONEVALUATION

CASECOMPARISON

POWERFLOW

LOADDATA

WEATHER DATA

WEATHER FORECAST

INTERCHANGETRANSACTIONSCHEDULES

AGCDATA

BF2 328

Figure 4-2. Forecast/Scheduling Applications Interfaces

Survey of Forecast and Scheduling Applications

Both the Load Forecast and Unit Commitment/Transaction Evaluation/Case Comparison functions are Oracle based. Input data and results for each function reside in an Oracle database. Furthermore, the user interface consists entirely of Oracle forms.

Load Forecast

The Load Forecast function assists the dispatcher/operator in forecasting the hourly loads for the total system and for individual forecast areas within the system. Load Forecast supports multiple forecast algorithms and provides tools for the dispatcher/operator to manually enter or manipulate the forecast.

Unit Commitment



An important aspect of operating a power system is the scheduling of thermal generating units to supply the load with minimum operating cost. The minimum cost is achieved by determining the most economical start up and shut down times for the thermal units, and their associated generation.

Unit Commitment also supports Transaction Evaluation and Case Comparison tools to provide the operator all of the information needed to make scheduling decisions.

Case Comparison

The Case Comparison (CP) function compares data items in two completed study cases and reports to the operator significant differences. Case Comparison compares both the study input data and output data and allows the operator to enter in the thresholds used to determine what a significant difference is.

BF2 958

Unit Commitment InterchangeTransactionEvaluation B

Short TermLoad Forecasting

InterchangeTransactionScheduling

His

toric

al D

ata

Man

agem

ent

SCHEDULE MANAGEMENT SYSTEM

Data Acquisition and ControlU

ser I

nter

face

CaseComparison

ReserveMonitor

AutomaticGeneration

Control

AGCPerformance

Monitor

ProductionCosting

EconomicDispatch


InterchangeTransactionEvaluation A

EnergyAccounting

BF2 958

Unit Commitment InterchangeTransactionEvaluation B

Short TermLoad Forecasting

InterchangeTransactionScheduling

His

toric

al D

ata

Man

agem

ent

SCHEDULE MANAGEMENT SYSTEM

Data Acquisition and ControlU

ser I

nter

face

CaseComparison

ReserveMonitor

AutomaticGeneration

Control

AGCPerformance

Monitor

ProductionCosting

EconomicDispatch


InterchangeTransactionEvaluation A

EnergyAccounting

Figure 4-3. Overview of Forecast and Scheduling and Power Applications

4.1 Short-Term Load Forecast

4.1.1 Overview

The forecasted power system load forms the basis for planning of sufficient generation, spinning reserve, and operating reserve.



The Short-Term Load Forecast function assists the dispatcher/operator in forecasting the hourly loads for the total system and for individual forecast areas within the system. Short-Term Load Forecast supports the following methods of forecasting loads:



Similar Day algorithm

Pattern Matching algorithm

Multiple Regression algorithm

Adaptive Regression Analysis (based upon Kalman Filter Theory)

Operator entry and/or modification of the forecast

Short-Term Load Forecast supports a 168-hour study horizon with one half hour or one hour time steps.

Total System Load1200MW

Mo Tu We Th Fr Sa Su

981

Total System Load1200MW

Mo Tu We Th Fr Sa Su

981

Figure 4-4. Total System Load

4.1.2 Concept

Load Forecast is used to forecast the load for each forecast area in the system and to provide a total system forecast. Forecast preparation is done in the working forecast. When satisfied with the load forecast, the dispatcher/operator may transfer the load forecast from the working forecast to the current forecast, where it may be accessed by other functions.

Load Forecast maintains a historical file of load and weather data and a weather forecast for use in forecast preparation. There is also a study forecast with its own historical file, weather forecast and load forecast separate from the working forecast data. The study forecast can be used to study hypothetical forecasting situations, including forecasts for time periods other than the one covered by the working forecast. In addition, there are save cases for storing study forecasts for later use.

Short term load forecast is basically structured into the following parts:

Updating/adaptation of historical data



Forecast algorithms



Very short-term prediction

After-the-fact error analysis

4.1.2.1 Updating/Adaptation of Historical Data

The Load Forecast historical data base is updated periodically for the selected time step (e.g., half hourly) via Data Acquisition functions.

If the power system load of a particular day is essentially influenced by special events, the historical data should be adapted to match the load level without disturbing influences. Via a correction schedule the operator can manually enter additive correction terms for the time interval in question.

4.1.2.2 Forecast Algorithms

Similar Day Load Forecast

The similar day forecast is based on predefined load patterns and weather increment patterns. There are load and increment patterns for each forecast area, for each day type and for each month of the year. Each pattern consists of hourly MW values for one day. The similar day patterns are defined initially through data base generation. Subsequently, they can be reviewed, and edited through displays.

The load patterns are non-weather sensitive, that is, they provide the average load values given normal weather for that time of year. The weather increment patterns are the expected load change under hot weather conditions. Positive increments indicate that load increases in hotter than normal weather. Negative increments indicate the reverse. Under cold weather conditions, the increments are subtracted rather than added to the non-weather sensitive load pattern values. The dispatcher/operator enters the predicted weather for each forecast day, hot (H), normal (N) or cold (D).

Pattern Matching Forecast

The pattern matching forecast uses the high and low weather data values for the forecast day and compares them with the high and low values for the days in the history file. The search is normally confined to historical days of the same day type as the forecast day, but it can be expanded to include other day types as specified by the dispatcher/operator. The search can also be limited as to how much of the available historical data is used. For example, the dispatcher/operator may limit the search to the past eight weeks, ignoring earlier data.

The pattern matching algorithm computes a difference index for valid historical day searched using a weighted sum-of-squares formula. There are separate weighting factors for the high and low values of every weather data value, so that more significance can be attached to differences in, for example, high temperature over



ns Siemens Power Transmission & Distribution, Inc. Confidential and Propri


4-8 Time

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This document contai etary Information

IME WGI SCADA 30-0124 01/05 Volume II, Section 4 Siemens EMA

low temperature. Other separate factors may be used to also account for differences in the significance of different types of weather data. There are also weighting factors for the age of the data, in number of days before the current day and for the difference in time of year, as represented by the number of days between the calendar dates of the historical day and the forecast day.

The output of the pattern matching search is a list of valid historical dates and their associated difference indices. The list is sorted from lowest index (best match) to highest index. The dispatcher/operator can choose one of the candidate historical dates for the forecast, in which case the actual load data is transferred into the load forecast for the appropriate forecast date and forecast area. The dispatcher/operator can also choose to use a weighted average of the candidate dates as the forecast. Once the data is transferred into the load forecast, the dispatcher/operator can alter it using any of the usual modification tools, such as scaling.

Regression Analysis

By means of multiple regression analysis or adaptive regression analysis the statistical relationship between total system load and the influences of time, day type, and weather conditions are calculated. The selected data analysis is started daily and on operator request.

It is possible to treat each day of the week separately for the purpose of data analysis or to define clustered day types.

The assumptions for the applied load model are similar weekly load patterns on the one hand and influencing factors to explain the differences between the weekly load patterns on the other hand. The load model is based on polynomial functions of the influences and day type dummies.

The regression coefficients are computed by an equally or exponentially weighted least squares estimation using the defined amount of historical data. A bandwidth check is applied to eliminate non-typical historical data.

In case of considerable weather sensitivity of the load, a good load forecast requires a good weather data forecast. The operator gives minimum and maximum temperature, average humidity, average cloud covering, and average wind velocity for each day of the study horizon.

To calculate hourly temperature values a standardized temperature curve is determined from the historical data and adapted to the min./max. values. Continuous model updating is performed by automatically correcting the forecast temperature curve of the actual day using the most recent measured temperature values.

Figure 4-5. Temperature Adjustment

The light intensity is calculated for a given geographic position under the assumption of no cloud situation. The expected degree of cloud covering reduces this brightness curve.

Using the regression coefficients and the forecasted weather variables as well as the type of day, the forecast load is calculated.

Operator Manipulation

To assist the operator in generating the load forecast, the Short-Term Load Forecast function supports direct data entry of forecast values by the operator and tools to assist the operator in making changes to the forecast as easily as possible. Included are:

Total daily energy scaling

Peak load scaling

Addition by a constant

Subtraction by a constant

Multiplication by a constant

Forecast copy

4.1.2.3 Very Short-Term Prediction

This special feature provides a feed-forward load correction term. A moving average model is applied to the time series of the most recent forecast errors. By means of the predicted errors the short term load forecast can be considerably improved.

4.1.2.4 After-the-Fact Error Analysis

Comparing the measured load with the forecasted load provides information concerning the accuracy of the power system load forecast. Absolute error, mean deviation, mean absolute deviation, and standard deviation are calculated for each day and displayed.



4.2 Unit Commitment

4.2.1 General

An important aspect of operating a power system is the scheduling of thermal generating units and power transactions to supply the load with minimum operating cost. The minimum costs are achieved by determining the most economical start up and shut down times for the thermal units and power transactions, and their associated output power levels.

The study period is usually divided into hourly intervals, and the Unit Commitment (UC) is treated as a discrete time problem. At every time interval decisions of starting up and shutting down of units are made.

To assure the determination of realizable schedules, the unit commitment has to recognize a variety of operating constraints which arise from

Units

Plants

Total system

In addition to providing generation to meet the load, scheduled units must also provide reserve margins to meet uncertainties of the forecasted load or to cover equipment failure. The provision of these reserve margins and satisfying other constraints means that additional cost must be incurred.

The characteristics of the Unit Commitment function are:

Costs to be minimized: include fuel cost, unit startup cost and unit operating and maintenance cost and power transactions cost.

Transmission losses: are taken into account by means of penalty factors.

Commitment schedule: The resulting commitment schedule regards all relevant operating constraints of the generating units and the system.

Time step: Basic unit of time 1 hour or half of hour

Study horizon: Usually from 1 to 168 hours (maximum: up to 31 days for hourly time setup)

Starting point in real-time mode: Current time (next time step)

Starting point in study mode: Selectable by the operator

End point: End of current or next study horizon, always given by end of an energy limitation, if applicable



The algorithm provides the on/off status, as well as the power outputs of thermal units at every time step. The utilization of interchange transactions is also provided. In addition, the amount of fuel used by each unit and each group of units and detailed and total costs are available. The amount of spinning and standby reserves carried on each unit and the total system reserve are also displayed.

4.2.2 Concept

The objective of the Unit Commitment function is to determine the startup and shutdown schedule of available generating units as well as the schedule of power transactions, to meet system load and reserve requirements at minimum cost for the entire period, subject to a variety of equipment, system, and environmental constraints.

The UC function requires a wide array of input data including:



Unit data

Unit group data (e.g., plant data)

Interchange data

System data

The input data can be divided into the following two classes:

Constant over the study horizon

Variable over the study horizon

Variable data can be specified by a schedule.

Unit Information

Unit Status

The unit status can be specified for each unit for each time step.

Available units:

These units may be committed or decommitted. This decision is made by the UC optimization algorithm.

Fixed generation units:

These units are not considered by the optimization algorithm. These units are usually nuclear or very large steam units.

Must-run units:

These units must not be decommitted but they may be dispatched to a higher/ lower level of generation. These units must be kept on-line e.g., for voltage control purposes.

Not available units:

These units are scheduled for maintenance or they are off-line due to a forced outage.

Unit Types

The following unit types are supported:

Nuclear units

Fossil fueled steam thermal units



Multi-fueled units

Gas turbines

Unit constraints

Unit generation limits:

The following limits are used for each unit: (Figure 4-6)

Maximum capacity: physical limit

Maximum generation limit: operating limit

Minimum capacity: physical limit

Minimum generation limit: operating limit

PP_Cap_max

P_Max

P_MinP_Cap_Min

kBF2 983

PP_Cap_max

P_Max

P_MinP_Cap_Min

kBF2 983

Figure 4-6. Unit Generation Limits

The minimum and the maximum generation limits constrain the operating range.

These limits can be changed by the operator via UC displays. The maximum capacity is used as the unit's capability only for reserve calculations.

Derated capacity (specified by a schedule):

Partial outages of a unit (e.g., a feed mill being out) can limit its maximum output to a value below its full maximum capacity

Minimum up-time:

If the unit is turned on-line it must stay on for a certain period of time.

Minimum down-time:



If a unit is shut down it must stay down for a certain period of time.



Limited ramp rate of unit loading:

The maximum allowable change of unit power output between two time steps is limited by the sustained ramp rate. The sustained ramp rate values may be different for load increase and load decrease.

Time to reach minimum operating limit:

The number of hours required for a unit to ramp from 0 MW to the minimum operating limit. The unit is not dispatchable during this time, but can contribute to total generation.

Reserve contribution limits:

As the reserves have to be available within a specified period of time the contribution of each unit to these reserves can be limited.

Unit Operation Curves

The operator can enter the incremental heat rate curve (Figure 4-7). Each unit may be associated with several curves to consider different fuels or different cooling agent temperatures.

IncrementalHeat Rate (BTU/KWH)

P_Min P_Max Output (MW)BF2 986**

Figure 4-7. Unit Incremental Heat Rate Curve

Unit Cost Data

Fuel price

Start-up cost

Shut down cost

Start up cost: when cooling down the unit's boiler curve 1 at Figure 4-8, and from hot stand by curve 2 at Figure 4-8. Start up cost of a unit depends on the time interval between the last shutdown and start up.

Operating and maintenance cost



Penalty factors



Start-UpCost

Down timeBF2 987

12

Start-UpCost

Down timeBF2 987

12

Figure 4-8. Startup Cost

Unit Group Constraints

A group of units can be defined for units which are coupled by the primary energy supply (e.g., gas pipe line or oil tank storage).

Plant related constraints

Maximum number of units which can be started up simultaneously (due to crew limitations or auxiliary system limitations).

Minimum number of hours between unit startups.

Maximum number of units startups per day.

Interchange Data

All relevant data for interchange transactions with a neighboring utility are provided from the Interchange Transaction Scheduler (ITS) function. For each utility several transactions may exist. All transaction related data can be modified/entered by the operator via the ITS function.

Constraints related to interchange transactions:

Start and stop time

Maximum/minimum energy per basic time steps

Cost data related to interchange transactions:

Energy price of the transaction

Penalty factor



System-Wide Constraints

Total system demand:

The total system demand is determined by the Load Forecast (LF) function or may be specified by the dispatcher/operator.

Desired spinning reserve:

The desired spinning reserve can be specified as a fixed MW amount that is given for each time interval (same default value for all time steps or different values for each time step)

Desired operating reserve:

The possible data input for the standby reserve requirement is similar to the definition of the desired spinning reserve.

Output Results

The output of the Unit Commitment function is presented to the operator in tabular and displays to assist in the evaluation of the Study function. Output results include:

Commitment Schedule

Committed units at each time interval of the scheduling period

Generation level of each unit

Utilization of interchange transactions

Interchange power of each transaction

Production Cost

Fuel consumption and fuel cost at each time interval and over certain time periods (e.g., day)

Start-up cost

Operating and Maintenance cost

All values of cost are presented per unit, per plant and per total system.

Reserves

Spinning and total operating reserve at each time interval:

Per unit



Per total system

4.2.3 Solution Method

The Unit Commitment problem is solved by an Augmented Lagrangian Relaxation algorithm.

The mathematical formulation of the unit commitment problem can be represented with the decision variables in a concise manner as follows:

The objective of the master problem for unit commitment is to minimize the total system cost, TSC, over the entire study period:

[ ( ) ]TNCPFTSC titiiit

,, +ΣΣ=

where:

t = Basic time step of the study period

i = Generating unit or dispatchable transaction index

Pi,t = Generation of unit i or MW level of dispatchable transaction i at basic time step t

Fi = Production Fuel cost of unit i or cost of dispatchable transaction i

TNCi,t = Transition cost that is the sum of start up and shut down costs

Subject to the coupling constraints such as generation/load/interchange balance equality constraint, reserve inequality constraints, transmission transfer interfaces or lines/transformers flow constraints, etc.

( ) MTRPfU

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,...,1;,...,1

,...,1

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where:

m = Coupling constraint index

M = Number of coupling constraints

T = Number of time steps in the study period

Ui,t = Operating status of unit i at a time step t

Dt = System demand requirement at hour t



fi,m = Contribution of unit/dispatchable transaction to constraint m

Rt,m = Value of constraint requirement m at a time step t

The above system constraints requirements are relaxed and added to the cost function using Lagrange multipliers. In addition, quadratic penalty terms associated with system demand requirements are added to the objective function to improve the convexity of the problem. The Augmented Lagrangian function, L, is therefore written as:

[

−

••−

•+

−••−

+

=

∑∑

−•∑

∑ΣΣ

RPfU

DPU

DPUTNCPF

mttimii

tim

mt

ttii

tititiiit

ttii

tic

L

,,,,,

2

,,,,

,,2/

µ

λ

where, c is a penalty factor or penalty weight. It is typically initialized based on the difference between the largest and smallest system incremental costs divided by the difference between load values corresponding to these system lambdas.

Except for the quadratic term, the Augmented Lagrangian function L is separable and the master problem can be decomposed into a set of independent subproblems each associated with its own local constraints. To overcome the non separability of the quadratic term and maintain the separability of the problem, we utilize the Auxiliary Problem Principle to linearize the quadratic terms around the current operating point. Thus, the augmented Lagrange function for the subproblems in the (k+1)th iteration, neglecting constant terms is:

]2,,

,,,,,

,,,,,,

21

2

−

•−

−•+

•−•−+

=

ΣΣ

ΣΣΣ

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titi

k

tj

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tjj

it

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tjj

ti

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it

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where is the sum of generating powers at previous iteration, and is

generating power of source i (unit or transaction) at previous iteration at time step t. In the convex case, the convergence of the algorithm was proven when 1/e > 2 c.

Pk tjj

,Σ Pk ti,

For a given set of Lagrange multipliers, these local optimization subproblems are solved independently using a single unit dynamic programming (DP) method. Note that within the local optimization subproblems the coupling constraints have no direct effect; they are represented only indirectly through the Lagrange multipliers that are used to modify their objective functions.



The single unit DP solution must observe all local constraints, i.e., those that apply to unit operation (maximum and minimum power limits, minimum up and down times, ramp rates, etc.). In a single unit DP all unit characteristics can be rigorously represented while maintaining a reasonable small state space to ensure low execution time. The solutions of the unit problems are coordinated within each plant to meet the plant start-up constraint by solving the unit problems in order of solution priority, and constraining start-ups of lower priority units based on the solutions for higher priority units.

The master problem solution is concerned with adjusting the values of the Lagrange multipliers in order to satisfy the coupling constraints. This is done through an iterative process. At every iteration, all subproblems are solved for a given value of the Lagrange multipliers. Then the multipliers are updated using a subgradient technique in which the change in the value of each multiplier is proportional to the violation of its associated coupling constraint.

The computation of the coupling constraint violations is based on a dynamic merit order that is changing from one iteration to another. The dynamic merit order is utilizing the information from the dual subproblem (dual cost, MW levels, etc.) to order the units/ transactions from the cheapest to the most expensive. Whether a unit is committed or not at a particular time step depends on the unit’s position in the dynamic merit order list. Units are committed from the list one by one until the coupling constraints are satisfied. If the number of units/transactions is not enough, the value of the violation is computed and the corresponding Lagrange multiplier is updated to prepare for another iteration. The commitment of units from the priority list takes the local constraints such as minimum up and down times into account.

It should be noticed that our algorithm maximizes the dual problem while maintaining feasibility of the primal problem. This approach is different from other Lagrangian approaches that attempt to maximize the dual function then struggle to obtain a feasible primal solution using different types of system dependent heuristics.

Once a solution for the commitment stage is obtained, the dispatch stage is initiated to minimize the production costs by dispatching on-line units and committed dispatchable transactions to the most economical MW levels. For this purpose we have implemented very efficient algorithm base on nonlinear version of Dantzig-Wolfe decomposition principle. The dispatch problem is formulated using nonlinear piece wise quadratic cost functions (piece wise linear incremental cost curves), and solution obtained have equal λ property.

4.2.4 Input and Output

The overview of input data and output results is given on Figure 4-9.



UNIT COMMITMENT

System Data Unit Data Unit GroupData

Interchange Data

988-1098

CommitmentSchedule

ProductionCost

Spinning andOperatingReserve

FuelConsumption

– Total system demand

– Required spinning and operating reserve constraints

– Status

– Cost data

– Constraints

– Plant related constraints

– Cost data

– Constraints

UNIT COMMITMENT

System Data Unit Data Unit GroupData

Interchange Data

988-1098

CommitmentSchedule

ProductionCost

Spinning andOperatingReserve

FuelConsumption

– Total system demand

– Required spinning and operating reserve constraints

– Status

– Cost data

– Constraints

– Plant related constraints

– Cost data

– Constraints

Figure 4-9. Overview of Input Data and Output Results

4.3 Case Comparison (CP)

4.3.1 General

The Case Comparison (CP) function identifies differences in two completed study cases from Unit Commitment (UC) and/or Transaction Evaluation (TE) selected by the operator. CP compares both the input required for the study and the output from the study.

Selected input/output data is checked for differences which exceed a comparison threshold. Comparison thresholds are used to filter out trivial differences in the data. When such a difference is detected, the two actual values and their difference are presented to the operator via Oracle Forms displays. A separate display describing which data items contain differences exists as part of the results.

4.3.2 Concept

The Case Comparison function compares certain data items in two completed studies from the Unit Commitment (UC) and/or Transaction Evaluation (TE) functions. Each study must consist of both the input data required to execute the study as well as the execution results from that input. The studies are selected from the save cases and/or the working case of UC and TE.



Hourly Values

The selected study cases are checked for differences in the following system hourly data values:

Load requirement

Base net interchange

Miscellaneous generation

UC generation

Net dispatchable interchange

Total net requirement

Spinning reserve

Quick-start reserve

Operating reserve

Production cost

Startup/shutdown cost

Operating cost

Dispatchable transaction cost

Total cost

Lambda

System Study Total Values

The selected study cases are checked for differences in the following study totals:

Load requirement

Base net interchange

Miscellaneous generation

UC generation

Net dispatchable interchange

Production cost





Startup/shutdown cost

Operating cost

Dispatchable transaction cost

Total cost

In addition, the following hourly values and totals are checked:

Unit hourly and study total generation

Dispatchable transaction hourly and study total MW

Following Case Comparison execution, a comparison summary can be displayed that indicates in which of the above data categories significant differences were found. For each data category, a threshold is used to ignore trivial differences.

Displays are available that show the values of the data in each of the above categories for both of the selected cases side-by-side, along with the computed difference for significant differences. Where there is no significant difference, the difference value is zero.

In addition to the side-by-side viewing displays, for the hourly data additional displays are available that only show hours in which there are significant differences. When a significant difference in a system hourly quantity is found, the date and hour along with the data category, the two actual values and their difference are written to a comparison display. All differences for day one, hour one appear first, those for day one, hour two second, etc.

If the study periods differ for the two cases, then Case Comparison compares only the common period.

5. Operator Training Simulator (OTS)

5.1 OTS Executive Overview

Siemens offers the added value OTS in terms of unique features and capabilities, which open up our product for capabilities over and beyond the initial EPRI OTS.

Robustness of OTS Power Flow and Dynamic Solution

The current OTS release has numerous corrections that provide stability of the OTS power flow and dynamic solution to our Customers (NSP, Con-Edison, and Spain). In several Eight hour long restoration drills the software has been put to extreme stress tests with a wide variety of network ill conditioning and numerical stability problems.

Permanent Base Cases

Data maintenance model changes invalidate the base cases and events in most Vendors’ OTS. Some users stop or limit the use of OTS due to the labor involved in repeated recreation of the base cases and events for data base changes. The time taken in the vendors’ product cycle to achieve a reliable tool to resolve the previous database cases in the new database is in the order of eighteen months.

Robust EMS Snapshot Initialization Capability

Siemens solution offers a well tested and a unique approach of using a OTS resident State Estimator filter prior to the OTS Power flow solution of the network model with the real-time SCADA data. Most other OTS vendors employ a direct power flow approach or the use of the on-line system’s State Estimator results for the real-time snapshot. The direct power flow based approach is not a reliable method as it has the fundamental weakness of lack of consideration for data inconsistency in the parts of network with measurement redundancy, and data in-availability for parts of network which are not observable. On-line system’s State Estimator results based approach is certainly better than the direct power flow based approach in the Engineering point of view. If models in the on-line system State Estimator and that of OTS are different, either by plan or due to time lags in the maintenance cycle, the on-line system State Estimator based approach for OTS real-time snapshot will fail. With due consideration to the cited issues, Siemens proposed OTS solution employs an OTS resident State Estimator based filter approach.

Siemens Value Additions to the OTS Since Delivery to EPRI

In addition to the first EPRI OTS delivery, Siemens also delivered a workstation based OTS to EPRI in 1993. Ever since, Siemens has been expanding the EPRI OTS based Siemens OTS continually under internally and externally funded efforts. In over twenty implementations, Siemens OTS has been thoroughly tested by our Customers and the corrections to the problems have been continually updated to the Siemens base OTS software.



A list of significant enhancements Siemens has made to its OTS, following the initial delivery of the EPRI OTS include:



Robust real-time Snapshot Initialization with the OTS resident State Estimator filter to ensure a reliable solution.

Improved algorithm related to solution tracking and numerical stability with respect to open ended lines and their reconnection when very huge charging MVArs are involved. Such issues in the past always led to power flow divergence or non-convergence.

Permanent retention of Power System Model Base cases and Instructor Event Libraries across network model changes

Oracle based database management and UI for the primitive data management.

Fully menu driven Instructor event creation and editing tools

Fully menu driven, Conditional Events that allow Events to be associated with the network conditions as opposed to time.

Event type enhancements of stuck breaker events, loss of data-link, station alarms, etc.

Collection of validated Pool models from NYPP, PJM and SPAIN which allows us to create new pool models quickly.

Substantial improvements to enhance the calculation of processed ACE and unit desired signals for the external AGC systems (as external models are getting larger in the current day networks.)

Cold Load pick-up modeling (validated at least in five implementations).

Heuristic (Automatic) Scenario Builder improvements, ease of rules data inputs, and solution stabilization following validation on different customer databases

Transient Stability study program (EPRI ETMSP – Extended Transient Mid-term and Short-term Dynamics Program) interfaced to the OTS PSM. Along with the real-time snapshot capability, this feature provides means to study the stability problems of the current on-line operating conditions. The results of the study are graphically available to the user.

Zero droop governor modeling which allows the manipulation of newly connected load sharing by the Hydro or Gas Turbines in the islanded network operation during System Restoration, a practice which is getting more practical recognition.

A very rich and a more accurate set of default data collected over many implementations for the prime mover models, based on the type and rating of the units. The prime mover model data are very hard to obtain.



Practical simulation of Fault events that provides automatic fault isolation and considers fault duration, isolation, and reconnection attempts.

Synchro check relay test for hot/dead buses and lines

Stability of Software: Black start capability and ill-conditioned network power flow convergence improvements were identified and corrected as a result of over six system restoration drills conducted by Siemens OTS customers. The OTS typically undergoes 500-800 switching actions in a four to six hour period by a team of three to six operators. In comparable OTS’s, such use generally led to voltage divergence or non-convergence in the past. The multi-user stress test resulted in the identification and correction of a number of power flow problems with regard to numerical ill conditioning of networks. Stabilizing aspects are added to the OTS power flow to significantly improve the robustness. We also provided realistic voltage regulation and remote regulation during islanded conditions.

The base OTS version we use in 1999 projects is the software we provided as Release 3.4 in the fourth quarter of 1998 from DEVELOPMENT. Release 3.4 has very formally tested software, and is our most stable internal release from Development to Delivery to undergo Availability (Stability) tests and Y2K tests.

Siemens Future OTS plans

Current Siemens OTS Application database is based on what we originally delivered for EPRI OTS. Siemens has on-going development for the Oracle Based standalone applications for Network, OTS, and other applications. Siemens vision for the standalone applications is the use of third party Industry standard method of Oracle Database and User Interface linked to the Oracle Database. We have Development plans to move our OTS Application database to an Oracle Database.

5.2 Introduction and Overview

In the last two decades, power systems have become increasingly complex and the requirements placed on Operators in all phases of system operations: normal, emergency and restorative, have increased correspondingly. In past years, training of power system control center Operators was done largely on the job. Experience and skill were gradually accumulated over the years. Experience in the operation of the power system under normal conditions was accumulated relatively quickly since most systems are operated under normal conditions most of the time. However, experience in alleviating emergencies and in restoring the system from total or partial blackouts is accumulated much more slowly since on most systems, these conditions occur much less often.

With an Operator Training Simulator (OTS), it has become possible to improve the quality of training for power system Operators. The OTS allows Operators to be exposed to simulated power system emergencies and to practice alleviating these emergencies. Similarly, Operators may practice system restoration under simulated conditions. Since Operators may be exposed to simulated emergency and



restorative conditions on the OTS, frequently and at will, as opposed to rarely and by chance on the job; the time required to train a new operator may be significantly shortened. Similarly, with an OTS, it becomes possible to expose existing Operators to emergencies and restoration procedures as part of refresher training. With an OTS, it is possible to achieve and to maintain a high level of operational readiness among power system Operators.

The proposed OTS is designed specifically to achieve these results. It is based on technology initially developed at Siemens as part of the Electric Power Research Institute research project RP1915-2, "Operator Training Simulator" and RP1915-8 "UNIX based PSM for OTS" and further enhanced by Siemens. The most important attributes of the OTS are fidelity and accuracy.



Fidelity and accuracy mean that the OTS behaves as the real world does. The simulator presents results to the Operators that are as accurate as those observed by the ECS using typical power system telemetry. Fidelity means that the operator uses User Interface and Application functions that are identical in the OTS and in the ECS.

The OTS includes long-term dynamic models of the electrical network, loads, generators, turbines, and boilers. The OTS also includes the control functions of the ECS: SCADA, power applications and their UI.

In addition, an Educational Subsystem is provided with features which allow the instructor to construct groups of one or more training events or power system disturbances and to store and retrieve these groups of events.

The OTS is a standard software package designed to execute in a dedicated processor with consoles dedicated to training while the simulator is running. System Management software allows workstations to be switched into simulation mode or back to on-line, or ECS mode.

The simulator has the capability of starting from any one of several stored base cases. This enables the operator to study a variety of different cases by starting from any base case and making changes if necessary to create the specific case desired. This capability can be used by the operator to study various cases that simulate day-to-day operations.

Other significant features of the OTS include:

The network model used by the OTS is identical to the network model of the ECS

The user prepares a single master data base from which the OTS and ECS data sets are generated

The user prepares and maintains a single set of displays which is used by both the ECS and OTS

The OTS AGC, SCADA systems are identical to ECS (electrical features)

The OTS includes several levels of modeling complexity for the prime mover models

The OTS allows the use of multiple consoles to support team training and an instructor position

Multiple islands may be modelled

The OTS supports a load model which includes the effect of frequency, voltage, load management and voltage regulation by subtransmission reactive shunts and taps

The OTS supports system restoration/blackstart exercises



The OTS includes a model of DC transmission

Under frequency load shedding is modeled in the OTS

The OTS may be initialized from a snapshot of the real-time system

The OTS allows representation of a wide range of power system events or disturbances

The OTS may include a model of the AGC systems of external companies

The OTS includes relay models for:

• Over/under voltage

• Inverse time overcurrent

• Over/Under Frequency relays

• Synchro Check relays

• Time Switched

• Volts/Hz

• Over/under excitation

• Automatic Reclosure

The OTS includes features that allow the instructor to play the role of power plant Operators, substation Operators, and neighboring company Operators.

5.3 OTS Functional Description

The overall simulator system can be logically divided into four principle subsystems; the Power System Model (PSM), the Control Center Model (CCM), the Educational System and the User Interface (UI). Figure 5-1 shows the relationship of these subsystems and their components with the exception of UI. The UI interface affects input and output for the Control Center Model and Educational Systems.



PROTECTION MODELING

GENERATOR MODELING

BF2 336A

DISPLAY AND

CONTROL

APPLICATION FUNCTIONS

DISPATCHERLOGGINGSUPERVISORY CONTROL

NETWORK SIMULATION

DATA ACQUISITION

LOAD MODELING

TRAINING SEQUENCE SELECTION

SYSTEM EVENTS

BASE CASE

SELECTIONINSTRUCTOR

EDUCATIONAL SYSTEM

POWER SYSTEM MODEL

CONTROL CENTER MODEL

PROTECTION MODELING

GENERATOR MODELING

BF2 336A

DISPLAY AND

CONTROL

APPLICATION FUNCTIONS

DISPATCHERLOGGINGSUPERVISORY CONTROL

NETWORK SIMULATION

DATA ACQUISITION

LOAD MODELING

TRAINING SEQUENCE SELECTION

SYSTEM EVENTS

BASE CASE

SELECTIONINSTRUCTOR

EDUCATIONAL SYSTEM

POWER SYSTEM MODEL

CONTROL CENTER MODEL

Figure 5-1. Overview of OTS Function

The PSM simulates response of load, generation and network conditions (flows and voltages) to control actions, which were initiated either from the Educational System or Control Center Model. The PSM includes a load model function, network modeling which is implemented as a network topology processor and a fast decoupled load flow algorithm and a set of prime mover models and frequency response programs.

The Control Center Model includes a replica of the control functions in the ECS. Included are selected SCADA/AGC functions and Network Analysis functions.

The Educational Subsystem provides a means for sequences of events to be defined, stored and retrieved by the instructor. Separate displays are used to define each sequence and to catalog by title those presently stored.

The User Interface relates to all of the previous subsystems. It provides display and control via the workstation display and keyboard, and logging of all system events.



5.4 OTS Capabilities

The OTS provides the trainee with the capability to perform generation and transmission dispatching functions in simulation mode. The OTS is specifically designed to permit training a operator in all phases of system operation: normal, emergency and restoration.

The Control Center Model includes a replica of the Control functions in use in the ECS. Replication means that the features and UI of these functions in the ECS and OTS are identical, as seen by the trainee at his console. The following functions are included in the OTS:

Data Acquisition

Data Processing

Data Dissemination

Supervisory Control

Automatic Generation Control

Power System Network Analysis functions

The ECS functions that have interaction with RTUs are altered so that they interact with the Power System Model, but are identical from the viewpoint of the trainee.

5.5 OTS Techniques and Algorithms

This section gives an overview of the major software components of the OTS and gives an understanding of how the simulation is executed and why certain responses are obtained.

Figure 5-2 shows the order of execution for the major modules. The models of the OTS can be separated into two categories: The static solution and the dynamic solution. The static solution includes the simulation of transmission lines, transformers, relays, circuit breakers, etc. It includes models whose dynamics are too fast to be observed through the SCADA system data acquisition scans. The dynamic solution includes the simulation of boilers, turbines, nuclear units and the frequency response of the power system. The dynamic solution is accomplished using a numerical integration (trapezoidal method) with a time step of one second.



BF2 337

STATIC SOLUTION

Network Topology Processing

Bus Load Calculations

DYNAMIC SOLUTION

N

Y

Solve power flow on fullsystem

Circuit Breaker Switching?

Island Load Calculations

External AGC Model

Advance Integration Time Step

Frequency Model

Power Plant Models

Transformer Model

Load Model

Protective Relay Model

BF2 337

STATIC SOLUTION

Network Topology Processing

Bus Load Calculations

DYNAMIC SOLUTION

N

Y

Solve power flow on fullsystem

Circuit Breaker Switching?

Island Load Calculations

External AGC Model

Advance Integration Time Step

Frequency Model

Power Plant Models

Transformer Model

Load Model

Protective Relay Model

Figure 5-2. Overview of OTS Cycle Calculation

One execution of the modules shown in Figure 5-2 is called an OTS cycle. Once every cycle the load, relay and transformer models are updated. The static solution and the dynamic solution are also updated once per OTS cycle. If the Educational Subsystem or relay actions introduce changes such as breaker openings into the electrical network, the new network topology is determined by the network topology processing module. A power flow solution determines the flows and voltages throughout the network.

The dynamic solution includes the calculation of island load, the effect of the controllers of external AGC control areas, the frequency response of the system and power plant models. The effects of island electrical frequency are taken into account in the calculation of load (the effects of voltage on bus load is considered in the power flow).

Major portions of the OTS are described in the following sections.



5.5.1 Topology Processor

The proposed OTS uses a special Topology Processor that is integrated with the OTS power flow. The combined topology processor/power flow is an order of magnitude faster than the ones previously used in simulators.

5.5.1.1 Raw Topology Processor

The OTS Topology Processor analyzes the open/close status of circuit breakers and switches and determines the electrical configuration of the network. In the OTS, a special purpose topology processor is used which keeps track of network modifications over time. The OTS topology processor passes information about network changes to the power flow which uses this information to incrementally re-order and incrementally update the factors of the matrices used in the power flow solution.

This special purpose topology processor was developed as part of the EPRI project RP1915-2, Operator Training Simulator . A key idea of the special purpose topology processor is to accommodate the ordering in the topology processor. When a network change occurs, the previous order is updated by flagging the discarded buses and by appending the new buses last in the order of processing. Although the resulting new busses are in non-optimal order which causes extra fill-ins during processing of these new buses, the resulting processing is much quicker than re-ordering the matrices completely. The results of topology change are introduced into the factorization matrices using state-of-the-art factor updating algorithms.

After the OTS has been executing for some time, the effects of topology changes accumulate. The system must be re-ordered and re-factored to avoid the buildup of computational inefficiency. This rebuilding and refactoring is done during a cycle when there is no topology change as opposed to during a cycle when a topology change has occurred and the operator is highly sensitized to the response of the OTS. An OTS cycle during which the matrices are rebuilt does take longer, but these cycles are chosen to occur during a time when the system is quiet.

5.5.1.2 Power Flow

The proposed OTS uses a special purpose fast-decoupled power flow that has been designed to give fast results following a topology change and to perform well under stressed conditions. The OTS power flow is different from traditional power flows with respect to the modeling of control strategies, such as area interchange controls and transformer tap changing. In the OTS, representation of such control strategies is done outside the Power Flow Solution since slower time constants such as those of the AGC system and transformer tap mechanism must be taken into account.

The modeling of generator MVAR limiting in most power flows causes the power flow to take additional iterations and slows the overall time to convergence.



In the proposed OTS, special modifications were introduced in the modeling of the power flow to overcome the convergence problems normally caused by generator MVAR limiting. In the OTS power flow, all MVAR limiting interactions are resolved before proceeding to the next active power portion of the power flow. The net effect of this implementation is that the power flow converges more quickly in the case when there is MVAR limiting.

In the proposed OTS, special features were introduced into the power flow to ensure good convergence on a customer's network. Loads may be modeled as functions of voltage (see also Section 5.4.3). The voltage dependence of the nominal load is included in the computation of the power flow mismatches. This has the effect of stabilizing the power flow solution at low voltages.

5.5.2 OTS Network Model Output

Once the OTS power flow has been solved, Network Model Output function uses the complex voltage solution of the power flow and branch impedances to calculate branch flows. See Figure 5-3.

Analog measurement data is mapped to the appropriate data structures and are displayed by means of the SCADA system.



BF2 338A

TOP (TOPOLOGY

PROCESSOR)

POWER FLOW

SOLUTION

NMO (NETWORK

MODEL OUTPUT)

NETWORKELEMENT DATA &

CONNECTIONS

BREAKERSTATUS

BREAKERCONNECTIONS

POWER FLOWINPUT

SOLUTION

BF2 338A

TOP (TOPOLOGY

PROCESSOR)

POWER FLOW

SOLUTION

NMO (NETWORK

MODEL OUTPUT)

NETWORKELEMENT DATA &

CONNECTIONS

BREAKERSTATUS

BREAKERCONNECTIONS

POWER FLOWINPUT

SOLUTION

Figure 5-3. OTS Network Analysis Overview



5.5.3 OTS Load Modeling

5.5.3.1 Load Models

The OTS power system model may include several companies. A load curve is allowed for each company, which consists of load values for each five-minute interval. At each simulation cycle, a load value is determined by interpolating between successive points on the load curve. Bus load elements are then calculated as a fixed percentage of the load value assuming that the system is operating at nominal voltage and frequency. Bus loads are further distributed to feeder loads. Feeder loads can be of conforming (following load curve) or non-conforming (fixed load) type. The feeder load is then modified by a variable factor of the form (1 + pf(R)) where f(R) is random variable uniformly distributed between (-1/2, + 1/2) and p is a programmer enterable value.

In order to provide the flexibility to represent loads at different levels of detail, the user is presented with a menu of load models of varying complexity which may be defined at the time of data base generation. These models are summarized briefly:

Model O This is the simplest model in which load is represented as a fixed MW, MVAR.

Model OS This model includes the effect of voltage and frequency deviations on the load. Load can be represented as constant MVA, constant current, or constant impedance. Variations of load due to frequently changes are also modeled.

Model OM In this model, the effect of load management is included. Fractions of feeder load may be removed and re-applied.

Model OSM This model includes the effect of load management in the Model OS.

Model OSR This model includes the effect of distribution transformer tap changes, and distribution reactive switching in the Model OS.

Model OSMR This model is the complete model. It includes the effect of load management and feeder level reactive factors in the Model OS.

Research work as part of RP1915-2 pointed to the importance of load models in the simulation of voltage collapse.

The effect of the "cold load" has been incorporated in the models and algorithms of the OTS. When a feeder is de-energized for a period of time, upon reconnection to the network, the value of the feeder load is usually higher than the value at the time of the loss of the load. The OTS cold load model represents the long-term effect of the cold load behavior.



5.5.3.2 Cold Load Models

The effect of the "cold load" is incorporated in the models and algorithms of the OTS. When a feeder is deenergized for a period of time, upon reconnection to the network, the value of the feeder load is usually higher than the value at the time of loss of the load. The value of the load upon reconnection may be initially up to ten times the normal value for a short period of time (less than a cycle time), and 1.5 - 2 times the normal value very shortly afterwards. This value will gradually drop down to the normal load value within 25-30 minutes.

The OTS cold load model represents the long term effect of the cold load behavior since the trainee views the power system through the sampling of the telemetry data by the SCADA system. This sampling occurs at a frequency that justifies ignoring the initial surge of energizing a feeder.

Cold load pick up is modeled by simulating typical phenomenon that the load power increases exponentially with the time following a load switch off. The reverse occurs when the load is reenergized.

PC = Phot [1 + a (1 -e-bt)] (1)

Where: Phot is the MW value of the energized load and Pcold is the MW value of the load "seen" immediately after the load is reconnected. Time T is the load outage duration. The value of the load declines toward Phot when the load is reconnected (Figure 5-5)). This decline is represented by equation 2. Since b signifies the inverse of the time constant at which the load decays, it can be assumed that b has the same value as in equation 1.

Ph = Pcold [1 - ah (1 -e-bt)] (2)

Time t in equation 2 is the time since the load was energized.

Pc

Pcold

Phot

Time T Figure 5-4. Load Switched Off



Ph

Pcold

Phot

Time T Figure 5-5. Load Switched On

The cold load pick-up problem formula is done for more generalized conditions which are:

a. Load is re-energized during transit from hot to cold state before it reaches the cold state.

b. Load is de-energized in restoration during transit from cold to hot state before it reaches the hot state.

5.5.4 OTS Dynamic Modeling

Transient stability studies have historically used the most highly developed models of power systems. Other system models have included analog computer representation of simplified systems either for teaching power systems concepts or in simulating load frequency control strategies. In addition, considerable analytical work and some analog and digital simulation has been done by mechanical and electrical control engineers on modeling of steam power plants, mainly for the purpose of designing power plant controls.

The operator simulation process, and the models employed, differ from those models primarily in the time frame considered. Transient time scales are on the order of cycles (0.016 seconds for 60HZ systems) and longer dynamic stability runs last only a few seconds. The time frame for response of human control actions is the determining factor in the design of the simulation. Events which are beyond the range of human perception are not of interest, especially when viewed by telemetry with ten second scans and through workstations with sampling of about two seconds. At the other extreme, it is important that the simulation be run in real-time and be economical for "runs" of a half hour or more. These considerations result in an emphasis on prime mover dynamics and system frequency behavior in the structure of the simulation.



Because of the time response of AGC and operator control, we are dealing with slow speed phenomena rather than the transient and synchronizing effects not observed by the controller (either AGC or human). Also because of the requirement for real-time response of the simulated power system, extensively detailed models of components with short time constants would require a short integration time step and a correspondingly heavy computational burden. In this case we require a rather coarse time step (1 second) as compared to transient stability. For certain system condition such as setting droop of some units to zero during restoration or emergency conditions, the integration time step is dynamically adjusted to less than one second.

During steady state operation conditions, line flows and losses are the result of generation, excitation, and load. The network solution is therefore, more than adequately modelled by an efficiently coded load flow.

A schematic overview of control response modeling is shown in Figure 5-6.

BF2 339

LOADMODEL

UNDERFREQUENCYRELAYING

FREQUENCYMODEL

POWERFLOW

GENERATIONMODEL

EXT.AGCMODELS

SCHEDULEDFREQUENCY

INTERCHANGESCHEDULE

ToGovernors

P Mech. P Elect.

Tie Flow& Generations

-+

Freq.S

BF2 339

LOADMODEL

UNDERFREQUENCYRELAYING

FREQUENCYMODEL

POWERFLOW

GENERATIONMODEL

EXT.AGCMODELS

SCHEDULEDFREQUENCY

INTERCHANGESCHEDULE

ToGovernors

P Mech. P Elect.

Tie Flow& Generations

-+

Freq.S

Figure 5-6. OTS Control Response Modeling

5.5.5 OTS System Dimensionality and Generator Coherency

The dimensionality of the dynamic frequency model is reduced from the number of generators to one per swing-area (island), by the assumption of generator coherency within the control area.

In transient stability studies a swing equation is written for each generator and each may accelerate at its own rate.



dtd

dtd

W

H δδ DPelecPmech +=−2

2

0

2

where

Pmech = mechanical power P.U. MW

Pelec = electrical power P.U. MW

H = P.U. inertia constant (seconds)

δ = angular rotor position (radians)

D = machine damping constant (MW-sec.)

W = angular velocity (radians)

We reduce the order of this equation by accepting the assumption that the electrical interconnections are so strong that the entire control area or any one island within the system, can be characterized by a single frequency

dtdδ

=f

The assumption has the effect of eliminating the synchronizing swings and transient behavior between generators, which cannot be controlled by the operator or the AGC. The resulting formulation is called the Long-Term Dynamic formulation.

5.5.6 The OTS Power Plant

In the proposed OTS, component models are included for all commonly used power plant types. These models have been implemented specifically for the purpose of operator training. The criteria used in the selection and implementation of these models are fidelity and accuracy. Accuracy means that the models behave as the real world does as seen through power system instrumentation and telemetry. Fidelity means that the models respond in the same timeframe as the real world for systems with hundreds of units.

Using these criteria, separate component models are provided for the following types of energy sources:

Fossil Fuel Model (once through super-critical, once through sub-critical and drum boiler units)

Pressurized Water Reactor

Boiling Water Reactor



Combustion Turbine

Hydro Turbine

In a similar manner to the load models, the user is given a menu of models of varying accuracy for the fossil fuel models, the boiling water reactor model and the hydro turbine model. The user may choose the level of accuracy and computation burden for each of these three models. Figures 5-7, 5-8, and 5-9 show the three levels or tiers that are available within the fossil fuel type of model.

The first tier fossil model is recommended for larger generating units within the immediate service area of the main system. The second tier of models is recommended for larger generating units in the external world which are close to the immediate service area of the main system. The third tier of fossil model is recommended for other units in the external world. Exact selection from the menu of available tiers of models is left to the customer at the time of data base generation.

The first tier fossil models include the representation of the following types of controls: boiler flow, turbine flow and coordinated control. A model is included for the governor which includes governor deadband and non-linearity. The effects of off-nominal voltages and frequency on plant auxiliaries are included in the model. Moreover, this model will account for fast winddown of some generating units, generally in release mode coordinated with pumped storage hydro units picking up the load.

A representation is used for the turbine that is consistent with the IEEE committee recommendations. This model, Figure 5-10 can represent separate pressure level turbines, reheaters and crossovers by choosing the appropriate model parameters.

Hydro electric units are modeled using the energy source model. By selection of the hydro electric unit status, the unit may generate or pump with a desired MW value. While pumping, the unit behaves as a fixed active power load. While generating, the unit behaves as a source of active power generation with reactive power (voltage regulation) capability.



1.0

01R

LVG

1TS+1

ΣK

1-K

1S

Σ

KP1

KI1S

1T1S+1

Σ1S Σ PI Σ

PI

K11

TfwS+1

1S

1CD

Σ aux

Σ

Σ

DKS

1S

1Csh

ΣK2S

ΣΣ

Ds

TfuS+1 1-QT

OT

KP

KIS

K SD

Σ

PEB

Σ Σ

MEB

ThrottlePressureSet Point

PI

ΣPRLOLMFD

pedb

+-

+

+

+-

-

-DLMT

0

+

+

++

+

-

-

-

e FrequencyVoltage

Boiler Control

-

+

ThrottlePressure

ValveArea

Input to TURBIN

ValveRateLimit

ValveRateLimit

ValveNon-

linearity

vtr

0

vop

voc

DLT(loadlimit)

Steam Flow Rate

Backlash

+

+

++

++

-

PSLM

0

morl

mcrl

RateLimit

LoadDemand

MechanicalPower

Output (uag)

RateLimits

Demand Accumulator

AGCpulse

Pressure Controls

Coordinated Control

Throttle Pressure

Fuel Supply Path

Feed Water Path

BF2 341

Π

1.0

01R

LVG

1TS+1

ΣK

1-K

1S

Σ

KP1

KI1S

1T1S+1

Σ1S Σ PI Σ

PI

K11

TfwS+1

1S

1CD

Σ aux

Σ

Σ

DKS

1S

1Csh

ΣK2S

ΣΣ

Ds

TfuS+1 1-QT

OT

KP

KIS

K SD

Σ

PEB

Σ Σ

MEB

ThrottlePressureSet Point

PI

ΣPRLOLMFD

pedb

+-

+

+

+-

-

-DLMT

0

+

+

++

+

-

-

-

e FrequencyVoltage

Boiler Control

-

+

ThrottlePressure

ValveArea

Input to TURBIN

ValveRateLimit

ValveRateLimit

ValveNon-

linearity

vtr

0

vop

voc

DLT(loadlimit)

Steam Flow Rate

Backlash

+

+

++

++

-

PSLM

0

morl

mcrl

RateLimit

LoadDemand

MechanicalPower

Output (uag)

RateLimits

Demand Accumulator

AGCpulse

Pressure Controls

Coordinated Control

Throttle Pressure

Fuel Supply Path

Feed Water Path

BF2 341

Π

Figure 5-7. First Tier Fossil Model



1.0

01 R

LVGSK

1-K

1 S

S1 S S PI S

PI

1 TfwS+1

S aux

S

S

Ds

TfuS+1 1-QT

OT

KP

KI S

PEB

S SThrottle Pressure Set Point

GPL

SPRLOLMFD

+-

+

+-

-

DLMT

0

+

++

-

-

e Frequency Voltage

Throttle Pressure

Input to TURBIN

DLT (load limit)

Steam Flow Rate

++

++

-

PSLM

0

morl

mcrl

Rate Limit

Load Demand

Mechanical Power

Output (uag)

Rate Limits

Demand Accumulator

AGC pulse

Throttle Pressure

BF2 342

+

Governor Motor

KC

S

S

-

+1 CAS

KB

Steam Flow Rate

1.0

01 R

LVGSK

1-K

1 S

S1 S SS PI SS

PI

1 TfwS+1

SS aux

SS

SS

Ds

TfuS+1 1-QT

OT

KP

KI S

PEB

SS SSThrottle Pressure Set Point

GPL

SSPRLOLMFD

+-

+

+-

-

DLMT

0

+

++

-

-

e Frequency Voltage

Throttle Pressure

Input to TURBIN

DLT (load limit)

Steam Flow Rate

++

++

-

PSLM

0

morl

mcrl

Rate Limit

Load Demand

Mechanical Power

Output (uag)

Rate Limits

Demand Accumulator

AGC pulse

Throttle Pressure

BF2 342

+

Governor Motor

KC

SS

SS

-

+1 CAS

KB

Steam Flow Rate

Figure 5-8. Second Tier Fossil Model

BF2 343

1 R

K1 S Σ Turbine

FD

-

Deadband

+AGC pulse

Raise

Lower

Power Output

Boiler ModelBF2 343

1 R

K1 S Σ Turbine

FD

-

Deadband

+AGC pulse

Raise

Lower

Power Output

Boiler Model

Figure 5-9. Third Tier Fossil Model



BF2 344

Shaft #1 Power Output

UAG


1 1+TT1•S

Σ

TK1

+

TK3 TK5 TK7

1 1+TT2•S

1 1+TT3•S

1 1+TT4•S

TK4 TK6 TK8

Σ

Σ Σ Σ

Σ

++

+

++

+

+

Steam Flow Rate

Steam Chest

1st Reheater

2nd Reheater

Crossover

High Pressure Turbine

Intermediate Pressure Turbine

Low Pressure Turbine


++

++

BF2 344


UAG


1 1+TT1•S

Σ

TK1

+

TK3 TK5 TK7

1 1+TT2•S

1 1+TT3•S

1 1+TT4•S

TK4 TK6 TK8

Σ

Σ Σ Σ

Σ

++

+

++

+

+

Steam Flow Rate

Steam Chest

1st Reheater

2nd Reheater

Crossover

High Pressure Turbine

Intermediate Pressure Turbine



++

++

Figure 5-10. Generalized Turbine Model

5.5.7 VAR Resources

The OTS includes modeling of automatic control of VAR resources such as synchronous condensers.

5.5.8 HVDC Model

The OTS includes modeling of the HVDC transmission lines. The DC transmission line is modeled as an injection at the corresponding nodes of the modeled AC electrical network

5.5.9 OTS Relays

In the proposed OTS, models are available for those relays that act in the timeframe of long-term dynamics. Other relays that act in a transient timeframe may be modeled as events in the OTS Event Scheduler. The following relay models are available in the OTS.

Over/Under Voltage

Volts/Hz

Inverse time overcurrent

Over/Under Frequency



Over/under Excitation

Synchro Check

Automatic Reclosure

The relay outputs will not occur until after a timer associated with each relay has expired. The time delay of each relay is specified separately for each relay model.

5.5.10 External Generation Control Areas

The OTS includes the ability to define a group of companies as an external control area. The capability is provided to define an AGC controller for each external control area. The external AGC controller includes an Interchange Transaction Scheduler for that control area, an Economic Dispatch function and a load frequency controller. The Economic Dispatch and AGC for external companies although simplified, contain the features of modern ECS. The instructor is provided with the ability to change scheduled frequency, the frequency line bias factor, the AGC control status and interchange ramp rates for each external control area. The instructor may schedule the interchange transactions among external companies.

5.5.11 Simulation of Voltage Collapse

The following are key features of the proposed OTS that allow the simulation of voltage collapse in the OTS.

On-load tap changing with time constraints

Over or under excitation capability of generators represented by fast MVAR limits as opposed to that of steady-state limits.

Bus loads split into feeders and feeders selectively, including the effects of distribution tap changes, distribution reactive switching, and load management factors, selective feeder factors for constant Z, I and P portions of any load.

Bus load variation as a quadratic function of voltage included in power flow mismatch computations, stabilizing the power flow solution at low voltages.

Network islanding is demonstrated easily in the OTS with the help of tools provided to the instructor by means of events, displays, and OTS power flow.

Partial or total blackouts happen in the OTS as in real life due to island abnormal speeds or voltages and relays. The Power System Model and Control Center Models continue to run after a blackout. Power plants can be started up one by one and loads can be restored to parts or the entire network by using the tools provided to the role-playing instructor and trainee.



5.5.12 OTS Sizing Considerations

The size of the OTS system model is as follows:

Maximum Number

Item Allowed Bus 1000 Nodes 10000 Voltage Levels 10 Companies 40 Zones 100 Generators 600 Turbines 600 Boilers 600 Branches (Lines+Transformers+Phase+Shifters+Series Devices) 3000 AC Transmission lines 2000 Transformers 400 LTC Transformers 400 Phase Shifters 20 Series Devices 100 Shunts Capacitors/Reactors 1000 Protective Relays 8000 Switches, Beakers, Disconnects 7000 AC Substations 1500 Loads (each load is allowed MW & MVAR components) 3000 AGC Areas 40 Islands 10 Base Cases 20 Event Groups 250 Events/Group (Each Event Group is a page long display) 20 Snapshots 20

All of the OTS PSM and IP software is very well modularized. Dimension changes can be made with minimum effort, as the OTS PSM and IP software is flexible for any future expansion.

5.5.13 OTS Performance

The OTS cycle time will be within an average of five seconds. Usually hardware selections are made to closely match the scan time of the SCADA system. OTS supports NA studies of one DPF per 15 minutes, one SCOPF per 30 minutes, one SA per 30 minutes, and one FL per 30 minutes.



5.6 OTS Educational Subsystem

The proposed OTS includes an Educational Subsystem which allows the instructor to set up the event groups which make up the scenarios (pre-session activities), to participate in the scenario (session activities) and to debrief the trainee (post-session activities).

The OTS provides the instructor with the ability to conduct pre-session activities. These include the preparation, editing and saving of a base case. A base case may be retrieved from a previously stored base case, may be obtained from a real-time snapshot or may be created interactively during simulation.

Groups of events or system malfunctions may be created and implemented along with a base case to create a scenario. Events are scheduled to occur based on the time specified in the scenario. Once a group of events is defined, the group of events may be saved, edited or restored. Multiple event groups may be activated concurrently. The following are some examples of events:

Simulation stop

Simulation pause

Total or partial loss of a generator output

Total or partial loss of a bus loading

System load changes (spikes, steps)

Unit derating

Change in scheduled interchange transaction between the AGC control areas

Change the desired voltage controlled by generators

Change minimum and maximum voltage regulation limits of LTCs

Change in unit status (automatic, manual, etc.)

Circuit breaker trip

Circuit breaker close

Circuit breaker trip with successful reclosure; this can be used to simulate the occurrence of temporary faults on transmission lines

Circuit breaker trip with unsuccessful reclosure; this can be used to simulate the occurrence of permanent faults on transmission lines, bus faults, or generator faults



Breaker disable—Disables any Supervisory Control action on a specific breaker

Breaker enable—Enables any Supervisory Control action on a specific breaker

Stuck Breaker—Disables breaker specified and identifies up to six breakers that operate due to breaker failure

Relay disable

Relay enable

LTC disable—Disables voltage regulation of LTC

LTC enable—Enables a previously disabled LTC

Loss of RTU

Restore RTU

Loss of a single point of an RTU

Saturation

RTU telemetry failure

Restore of a single point of an RTU

Replace analog points (bad data)

Replace digital points (bad data)

Blocking of control signals from AGC to generating units

Messages to the instructor to take certain actions or contact the trainee at certain times

A relative or absolute event is executed when the simulation time becomes equal or larger than the time of the event. A conditional event, however, is executed whenever the result of a "logical function" becomes true.

The Event Scheduler provides a menu-driven method of selecting event types, equipment names and actions while creating event scenarios. The instructor is not required to manually type in any Event data. Event equipment data may be selected from a one-line display and "dropped" into the event window. By using this feature, it is not required that the instructor knows the names of every piece of equipment since the equipment can be selected from the one-line diagrams or the menu.



5.6.1 Conditional Events

OTS events can be triggered based upon one of three criteria:

Time relative to the activation of the event group

Absolute time

The evaluation of user-defined conditions

Classical events are defined as functions of time in a relative or absolute term. Conditional events are defined as logical expressions comprising:

Several global variables

Several network variables

Values for comparison

Arithmetic and logical operators

Each "variable" represents an individual condition, which is grouped along with several other conditions by means of logical operators to form a condition boolean expression. This powerful feature can also be exploited to automate certain role-playing actions of instructor. The conditions that are used to trigger events are defined through the Conditional Event Editor. These conditions are Boolean expressions combining multiple individual network conditions.

Most of the analog values and digital values calculated by the Power System Modeling can be used in these expressions. The terms in the expression can be grouped using parenthesis to form more complex condition boolean expressions. The active condition boolean expressions are evaluated during each modeling sequence cycle. When it is found to be true, the associated events will be executed. Associated events are edited using the Event Editor. The Event Editor allows maintaining an Event Library, where each event(s) can be associated with the time or with the condition expression created in the Conditional Event Editor.

5.6.2 Session Support

The OTS provides the instructor with the ability to participate during the scenario or training session. The instructor may start/stop or pause/resume the OTS. An event may be inserted or over-ridden during the scenario. A snapshot may be demanded manually or set up to occur periodically. The instructor is provided with features that allow him to play the role of operators outside the control room such as: power plant operators, substation operators and operators of neighboring companies.

The OTS provides the instructor with facilities to be used in the debriefing of the trainee. The OTS may be reinitialized to a periodic or manual snapshot and the simulation may be resumed to review part of the scenario with the trainee. Key data



is saved and presented to the instructor on instructor and trainee logs to assist the instructor with analyzing the scenario.

The Instructor Position Man-Machine Interface (IPMMI) is a workstation-based full graphics interface that takes advantage of the latest in graphics technology. Multi-windowing choice of several fonts and colors are some of these technologies used, as well as the use of icons and pull-down menus are supported in IPMMI.

The purpose of Instructor Position is to allow an instructor to control Power System Modeling of the Operator Training Simulator and to allow the instructor to perform control actions normally done by power plant operators and dispatchers of neighboring companies. The instructor through Instructor Position Man-Machine Interface (IPMMI) can initiate, execute and terminate an OTS training session. The instructor through IPMMI can create and control OTS training scenarios.



5.6.3 Base Case Creation

OTS simulation can be initialized to any of the following:

Base case

Snapshot

EMS Power Flow or State Estimator Solution

EMS Real-time snapshot

A snapshot is an intermediate step in creating a base case or a base case in its evolution. Snapshots can be automatic or on demand.

5.6.4 PSM Reports

PSM includes the following report facilities:

Instructor logs that report instructor and trainee control actions

Performance evaluator that tracks the specified bus, branch, frequency and ACE violations and their recoveries with the associated time stamps

Snapshot capability which allows the session to be restored to an earlier system condition, for any review purposes

PSM displays, logs and performance evaluation displays can be printed any time for report purposes

The CCM report facilities are also available to the instructor as they are.

5.7 Heuristic Scenario Builder (HSB) [Optional]

In addition to capability of building a scenario interactively by the instructor. An automatic way of building scenarios is available. Heuristic Scenario Builder (HSB) enables an instructor to automatically build a training scenario to be subsequently used by the Operator Training Simulator (OTS) during training sessions.

The HSB builds and validates scenarios using information about the type of trainee, the complexity of the training exercise, the training goal, and the power system conditions prevailing during the training session. Knowledge about scenario creation is introduced in the form of rules. Thus, the methodology used by the HSB falls within the realm of expert systems applications.



5.8 Transient Stability [Optional]

The instructor position can provide a Transient Stability function to assist the instructor in building and verifying training scenarios.

The instructor can choose to pause the simulator, transfer the PSM data onto EPRI-ETMSP transient stability program input case and request a transient stability run. Transient stability comprised relay operations are added as additional breaker operation events. Thus, the OTS PSM is enhanced to include the long-term effects of topology changes occurred during the short-term and mid-term system dynamics. Results of the stability run for bus voltages and generator rotor angles cane be plotted.

5.9 OTS User Interface

The UI includes most of the functions provided in the on-line system.

The simulator may include a logger and a videocopier (which includes the capability to copy the workstation diagrams) as options. Also included, is the database administrator function to enable on-line modifications in the database and for construction/modification of displays.

5.9.1 Event Editor

The Event Editor is a Motif based application that provides an interface for building event group. The Event Editor is comprised of three windows:

List Window. This is the parent window and displays an event group (a group of 20 events). Events can be added to the list via the Edit Window. The event description is entered via this window.

Overview Window. This window is called from the Display menu bar of the List window. Its purpose is to display an overview of all event groups and allow the easy retrieval of an event group by selecting it from this window.

Edit Window. This window is called from the EDIT button of the List Window.

Creating events with the event editor has the advantage of selecting the equipment from a list of all equipment names applicable for that event type. The instructor only needs to select the equipment from the list; no typing of equipment names is required.

5.9.2 Event Library Maintenance

All the existing event groups are automatically revalidated for the new database. The invalid event groups and events are flagged. The user can call up the invalid



event group and remove or correct the invalid events. An example would be a new database where equipment was removed or had its ID changed.

5.9.3 Condition Editor

The Condition Editor is a Motif based application that provides an interface for building conditional events. The Condition Editor is comprised of three windows:

Overview Window. This window gives an overview of all condition groups and provides a way to bring a specific group into the editor.

Condition Group Window. This window displays the condition group and provides an interface for deleting conditions and for grouping conditions by parenthesis.

Condition Edit Window. This window provides an interface for creating

individual conditions. These conditions are added to the Condition Group Window as either “AND” or “OR” conditions.

Condition groups are created by adding conditions to the Condition Group Window from the Condition Editor Window. The Condition Editor Window will not allow conditions to be added that are inconsistent. For example, a breaker cannot be compared to an analog value.

Conditions in the Condition Group Window can logically be grouped by adding parenthesis. The syntax of the condition group is checked before conditions are saved.

5.9.4 Performance Measurement Editor

The Performance Measurement Branches and Performance Measurement Bus Bars Editor is a Motif based application that provides an interface for entering the branch and bus bars information for the performance measurements. These editors are comprised of two windows:

Performance Measurement Branches or Performance Measurement Bus Bars Window. This is the parent window and displays the branch or bus bar information.

Edit Window. This window provides an interface to select the branch or bus bar equipment to add to the performance measurement list.



5.9.5 Instructor Message Window

The instructor is notified of any drastic changes in the PSM, such as island blackout, relay trips, etc., through the Instructor Message Window. It shows any switching actions that occur on the PSM or CCM. The simulation time and frequency is shown. In addition, if there are any simulation command or data entry validation errors, this is also shown in this window. Any simulation commands and the OTS responses are reported in the Instructor Message Window. In some instances, the Instructor Message Window also prompts the instructor for the correct simulation control actions.

5.9.6 One-Line Diagrams

These displays are the SCADA one-line diagrams from the CCM system available for the instructors. Instructors can control and perform switching actions via one-lines for OTS sessions. Instructors can also use one-lines for Event Editing purposes.

5.9.7 Sample Displays

The following pages contain sample displays.



Figure 5-11. Initialization and Base Case Control Display



Figure 5-12. Event Group Activation Display



Figure 5-13. Event Group Editor



Figure 5-14. Event Editor Window

5.10 Base Case and Event Library Maintenance

5.10.1 Motivation and Discussion

The retention of the base case across databases has been a critical problem for the operator Training Simulator (OTS) Instructors and Engineers. The database is constantly updated mainly for enhancing the accuracy of the model to closely match the actual power system. Currently, most OTS systems lose the Base Cases and the Event Library when a new Database with network model changes is loaded in to the OTS system. With the result, the user spends considerable amount of time reproducing the old cases and the events with respect to the new model. Some times the user avoids the new data base having a more accurate model, due to the cost (time and effort) associated with reproducing the important training cases. Solutions to save the entire OTS Power System Model (PSM) and Control Center Model (CCM) databases, for the sake of recalling an old base case may serve the need at times. But this method is not effective as the model is old and does not utilize the subsequent updates made to the model towards enhancing the accuracy. Based on the feedback received from the OTS users, Siemens has designed a pragmatic solution to this problem.



5.10.2 Outline of Solution of Case Retention

The main entities of an old base case, which the user wants to be transferred in to the current database will be the network configuration, and the profiles of generation, voltage, and flows. Siemens solution involves the PSM closely reproducing the main entities of the old base case in the new model. Subsequently, when the PSM case is retained and restored, the CCM digitals and analogs are provided by the PSM to synchronize the SCADA database.

Selected solution deals with reproducing the network conditions as closely as possible, even after considerable model changes. When a Case is created, it is also exported in to flat files for key load flow inputs along with equipment IDs. After a new data base is brought in to the OTS, the Case Retention software compares the equipment IDs of the last and current (new) database, and carries forward the key load flow inputs in to the new database. The key inputs are the equipment PSP, QSP and VSP (specified active power, reactive power, and voltage respectively), generator statuses and limits, transformer taps, and switching device positions essential for a bus model and a load flow. The company load and interchange schedules are saved for the purposes of producing a generation and load dispatch.

5.10.3 OTS Capability for Case and Event Library Retention

The Instructor can check the old case against the new model. Instructor displays provide a Database Change Report for the list of equipment added or deleted in the current model with respect to the old cases. The database defaults are used for the added new equipment. Loads will be based on the case company load, new load schedules, and the new model. To account for the equipment added or deleted, adjustments are made in the new model by incremental generation dispatch for the new load dispatch. In certain cases it is possible that the system is split in to multiple network islands. Selected solution accounts also for islands by dispatching the load and generation accordingly with in each island.

Essentially, the old PSM case information is used, and incremental dispatch balances the power in the model. It is followed by a power flow with generation slack to solve for the voltages, angles, and power flows in the new model. Invalid (power flow rejected) cases are informed to the user. If necessary, the user can study the report of changes in the model, adjust generators or breaker positions, and recreate a solved case. When there are ID changes for some equipment, or for any other adjustments, the flat PSM case file can also be edited and modified by the Instructor or the Engineer. The flat case files become permanent and are retained even during a Database or a software upgrade. These flat files have format definitions associated with it to help the user interpret the case information.

The user can systematically build the base cases with the desired operating conditions and the events to suit a scenario or training session. The base case (operating condition) and all of the events are carried forward across databases in spite of model changes.





The Instructor has the following displayed information for managing the retained Base cases:

Catalog of Cases

Control of Saving or Restoring of retained cases

Database Change Report for Cases

Other standard Instructor displays to allow changes and resave the case in the new model

Existing event groups are automatically revalidated for the new database. The invalid events are flagged. The user can call up the invalid event groups and remove or correct any invalid events. An example would be a new database where equipment was removed or had its ID changed. The Database change report also provides means of a reference, in case any additional events are required due to any insertion of new equipment in the model.

6. DMS Applications Software

This section gives an overview of the DMS Applications. There are several key features of the DMS that are summarized briefly below:

Unification of "islands of automation"

DMS as an extension of the system architecture described in Volume I

Consistency of Look and Feel

End User Focus

Applications

Unification of "Islands of Automation"

During the early years of the computer industry, electric utilities introduced computer systems as separate standalone systems, each with a specific task, giving rise to the term "islands of automation." Frequently different computer systems required entry and maintenance of identical data that placed a substantial burden on the utility. With the advent of networking technology and the development of LAN and WAN standards in the 1980's, it is now possible to connect these systems together, with resultant improvements in usability and reduction in maintenance costs. A key feature of the DMS is its connectivity and interfaces with other utility computer systems. With reference to Figure 6-1, DMS applications have the ability to exchange data with the several important utility computer systems.

The DMS system has interfaces to AM/FM/GIS systems. These interfaces allow the import of data for use by DMS and SCADA applications. An interface with a Customer Information or Trouble Call system allows extraction of data for use by the DMS Applications (e.g. Outage Management System). An interface is provided in the form of ICCP (or ELCOM 90 or IDEC) data links to other SCADA, EMS, and DMS systems within the same utility and with other neighboring utilities. This allows the exchange of operational data in real time. Interfaces are provided to Load Management Systems to allow the control of load in real time. Other interfaces are provided to Engineering/Planning, and Office systems through LAN's and/or WAN's.

DMS as an Extension of the Common System Architecture

The DMS system is based on the Open Systems Architecture described in Volume I of this proposal. The Basic System Services and User Interface Standards are the same in the EMS and DMS systems. In certain areas, extensions have been made to support requirements unique to DMS. These include expansion of the database by an order of magnitude to allow for typical DMS sizing requirements. Extensions have also been made in the User Interface to allow for the display of geographic displays with real time performance and the correlation of geographic and schematic diagrams. For a description of these extensions, please refer to Volume I.



Due to the use of a common architecture, it is possible to deliver DMS systems in many forms and over a wide-ranging scale. On the low end of the scale, DMS systems may be delivered as DMS only configurations, without SCADA functions, for use as a replacement for a paper mapboard in a distribution office. DMS systems may be integrated with SCADA functions and delivered as combined DMS/SCADA systems. They may also be delivered as combined EMS/DMS/SCADA systems. Systems may also be delivered as single site systems and as multi-site systems with communications and coordination of maintenance through a single site.

Consistency of Look and Feel

Due to the use of a common architecture and due to the use of standards, there is a consistency of "look and feel" across the DMS/EMS applications. This consistency provides benefits in the areas of: reduced time on the part of operators to learn new applications, improved productivity on the part of operators, and reduction of stress during emergency conditions.

End User Focus

DMS applications were developed based on the requirements of the end user. Detailed requirements were solicited from a DMS Advisory Group made up of utility customers. During all stages of development, feedback and evaluation of the DMS system was obtained from this Advisory Group.

Applications

The DMS applications are described in the next sections as follows:

6.1 Operation Support Applications 6.1.1 Outage Management System 6.1.2 Switching Procedure Management 6.1.3 Fault Location 6.1.4 Fault Isolation and Service Restoration 6.1.5 Free Placed Jumpers, Grounds and Cuts 6.1.6 Graphical Query

6.2 Network Applications

6.2.1 Topology Processing 6.2.2 Distribution System Power Flow 6.2.3 Volt/Var Control 6.2.4 Optimal Feeder Reconfiguration



AM/FM/GISInformationSystems/

Trouble Call

LoadManagement

System

OfficeEnvironment

Planning/Design

DMSOtherSystems

BF2 9016

Figure 6-1. DMS System Interfaces

6.1 Operations Support Applications

Operations support applications are used by the operator on a daily basis to aid in the maintenance and support of the distribution network. These applications are oracle based and allow for significant user interface. All of these applications are tightly integrated into the DMS real time network.

6.1.1 Outage Management System (OMS)

The Outage Management System (OMS) expedites the execution of tasks associated with the handling of scheduled/unscheduled outages that occur in the electrical network and provides support to operators at all stages of the process. OMS processing can begin with the reception of a trouble call or a SCADA indication of a fault or an outage and continue until power has been successfully restored to the effected customers or equipment. Operations, which occur in this process, are documented and collected in outage records. Among other things, an outage record consists of creation date, current stage, dispatcher’s name, comments, affected area of the network, switching procedure list, authorization identification, etc. OMS



supports communications to external computer systems such as trouble call systems, customer information systems and report analysis systems.

The OMS process starts with the indication of a fault or outage. This indication of a fault or outage may come from a variety of sources such as the SCADA system, operator-entered data, a trouble call center, or another DMS application. As a result of the indication, OMS alerts the operator of the outage via alarms and status indicators on the network diagrams. The outage information is automatically grouped according to current network connectivity and existing outage records. An entry is made into the outage record for transformer (or load), which has been de-energized as a result of the indication and subsequent analysis. The outage record proceeds through several different pre-defined states during the planned or unplanned outage resolution process.

Once the fault has been identified, the next step in the OMS process is to locate the problem area. The operator will use Fault Location and Topology Processing tools to perform this task. Notes may be stored in the OMS records during this location process.

Furthermore, the operator will want to isolate the fault and restore service to as much of the affected network as possible. The Fault Isolation and Service Restoration function assists the operator in determining the required switching actions. Isolation and Restoration actions are stored as part of the outage record. As each transformer/load is taken out of service or brought back into service, the equipment in the OMS record will be automatically updated to reflect that service has been lost or restored. The outage duration and load lost information is maintained in the outage record. This information is used for quality calculations.

When the outage processing is complete, the outage record is closed. At this point, the record is stored for historical purposes. It can also be sent to a remote site for further processing.

The OMS process also assists in the creation, preparation, and execution of scheduled outages. A scheduled outage may originate at an external site. From there it is transferred to the DMS site for processing. Once in the DMS site the request is accepted or rejected. If accepted the request changes to an OMS job and the job preparation begins. This preparation includes the addition of any switching actions and any authorization codes, which are needed to execute the scheduled outage. Once the preparation is complete the request is transferred back to the originating site for approval and authorization. Once approved the request is returned to the DMS site for execution at the specified date and time.

During execution the state of the outage record changes and the execution steps are tracked. The identification of the field crews and dispatchers are stored with the outage record as well as switching times and comments. This information is used for future analysis and problem tracking.

During the life cycle of this request OMS monitors the current state, and authorization of the request, allowing notes to be added at any point by the dispatcher. When completed this request is closed and stored in an archive file.



Security measures are enforced to allow some personnel to view the records at any time without allowing them to change the data in the record. Defining the users allowed to access the system and roles for those users once they are on the system enforces this.

This process supports the calculation of the quality of service indices: Customer Average Interruption Index (CAIDI), and the Service Average Interruption Index (SAIDI). Other indices may be defined on a project basis. This information along with the other outage record (and SPM) information is organized into daily reports which are transmitted to the appropriate information centers.

6.1.2 Switching Procedure Management (SPM)

Switching Procedure Management provides the distribution system operator powerful tools for creating, viewing and executing switching procedures in both process (real-time) and simulation modes of operation.

In order to reduce time and effort to create a switching procedure, many of the fields of the procedure are defaulted. The operator may also automatically create switching steps in the procedure, by graphically selecting actions on the network displays.

A switching procedure can contain the following general information:

Title

Type (Normal, Daily, Weekly, Disturbance, etc.)

Scheduled Begin and End Dates

Time of Creation/Modification

Status (Notified, Planned, Active, Closed)

Work Crew Number

Name of Author/Operator

Area of Responsibility

Notes

Switching procedure entries also include supervisory control commands and organizational steps.

Supervisory control commands contained within a switching procedure are of the following type:

Control (Remote)



Tag

Manual Replace (Update)

These commands contain information such as time of execution, equipment identification, dispatcher identification, field crew identification, action, etc. The commands are used for opening and closing switches, changing tap positions, setting and removing tags, grounding devices, etc.

Organizational steps within a switching procedure are of the following type:

Wait step

Break step

Comments

An extensive management system is provided with features that allow sorting, selection, copying, saving, restoring and review of switching procedures.

Through the summary display, switching procedures may be sorted according to number, type, period, status, etc. The summary also provides one-step access to the individual switching procedures. Switching procedures contain an identifier that associates them with outage records. They can also exist as stand alone entities. Many switching procedures can be associated with the same outage record.

The summary displays are also used to select procedures from the procedure library or the active procedure list. Procedures can exist in the libraries for a user-specified amount of time at the end of which the procedure is archived to a disk file. Dispatchers can select procedures to be copied into outage records and used for current operations.

Switching procedure management is initiated from the man-machine interface of the DMS system. This implies initiation from the schematic diagrams or from the outage records.

Procedure Creation

Several features are provided to assist the operator in the preparation and modification of the switching procedures. These features include technological editing, and recording as well as copy, insert, delete and invert capabilities. Switching procedures can be created automatically by applications such as Fault Isolation and Service Restoration or manually by a dispatcher through technological editing or recording.

Technological Editing refers to the process of selecting equipment to be controlled via the network diagrams. By positioning the cursor on the selected equipment and performing a Supervisor Control action or manual update, the Technological Address and the other associated information about the equipment is entered automatically into the switching procedure along with the desired control action. When in the technological editing mode of operation, all commands from the network diagrams,



propagate to the switching procedure and are not sent to the real-time system for execution. The network diagram identifier is automatically stored in the switching procedure for each control action such that the proper display is available via “Drag and Drop” during schedule execution. Technological editing can be performed in either process or simulation mode.

The recording feature allows switching procedures to be created by recording actual supervisory control actions or manual updates. The relevant operations performed on the network diagrams are automatically entered into the procedures. When recording, the operations are executed in network control. Record, Stop and Resume features are provided allowing the operator to choose only the desired actions to be recorded in the switching procedure.

In Technological editing mode, the same procedure is followed but no information is sent to the Supervisory Control.

After creation, the switching procedure appears in the summary display.

Viewing and Execution

After the desired switching procedure has been selected, if the operator has the proper authorization, he can execute it in a simulation mode, or in a real time mode. In either mode, the effects of the procedure are shown on the schematic diagrams through color changes in the diagrams. Network tools (trace, power flow analysis, etc.) can be run against the network configuration which results from the switching procedure execution.

The entire contents of the procedure may be executed via an “execute all” function, or the procedure may be executed step by step.

Each action in the switching procedure has a button that provides for easy access of the associated diagram where the action will be performed and the topological results of the action can be viewed.

The dispatcher can send copies of the procedure to field crews and other utility company departments for review. The procedures can also be printed.

6.1.3 Fault Location

Many primary distribution systems are designed and constructed as meshed networks, but are operated as radial feeder systems with tie switches normally open in the mesh network. These normally-open tie switches can facilitate transferring unfaulted, but out-of-service load to neighboring feeders to minimize the total load that has to be disconnected over a prolonged period in the event of a feeder fault.

Once a fault is quickly cleared by a primary protective device, such as a circuit breaker or a recloser, the fault can be isolated by opening appropriate sectionalizing switches. Service can then be restored to unfaulted but out-of-service sections by closing tie switches even before repair work for the faulty feeder section begins.



Since a large portion of the faulted feeder is likely to be de-energized as a result of tripping of the protective device, it is desirable to locate the exact faulted section in order to limit the area to be isolated as small as possible.

The Fault Location function is designed to determine the smallest possible faulted section based on available real-time data from SCADA and other information such as that from the trouble call system. Another method used by the Fault Location function is based on the bisection search, which requires systematic trial switching operations.

Depending on the nature of the system involved, faults can be classified into transient or permanent (persistent). Transient faults normally clear themselves, and such faults are not considered by this function. Faults handled by the Fault Location function are permanent in nature.

Input Data

The type of data from SCADA that will be used to locate the faulted section includes:

Status (open/close) of protective devices

Status of fault indicators (overcurrent sensing devices)

Besides the above data, other data sources include:

Outaged equipment (e.g. transformers) based on customer calls from the Outage Management system (OMS)

Results from trial switching operations (e.g breaker opening or closing)

The fault location function uses the current network topology and the above inputs to determine the faulted area.

Output Processing

The output of the fault location function is the switching devices and fault indicators bounding the faulted area. The faulted area can be shown in a tabular form or shown graphically by highlighting it on the worldmap display. The results of the fault location can also be sent to the Outage Management System (OMS).

Fault Location Procedure

The overall procedure for locating the faulted section consists of two schemes.

Scheme 1 determines the faulted feeder and the smallest possible faulted segment using real-time data from SCADA.

Scheme 2 narrows the faulted segment identified by Scheme 1 down through trial switching operations.

Scheme 1: Inference Procedure



Assuming that the structure of the distribution system during normal operations is radial, the fault location logic is based on the following observations:

A change in the status of a protective device and/or a fault indicator from a normal status to an alarm status indicates an occurrence of a fault.

The fault location must be downstream from the tripped protective device.

Trouble callers must be served from those distribution transformers located downstream from the tripped protective devices.

Assuming perfect coordination between protective devices, if there exist additional protective devices located downstream from the tripped protective device, the fault location must be between the tripped protective device and the immediate downstream protective device.

For a group of fault indicators located on a feeder in series, the fault indicators can be classified into two groups - those whose status has changed and those whose status has not changed. The fault location must be between the most downstream fault indicator whose status has changed and the most upstream indicator whose status has not changed.

Based on the above observations, faults are located as follows. First, a feeder on which a fault has occurred is identified. Next, using tracing tools, the smallest possible faulted feeder segment and its boundary switches are determined. If there are multiple faults on multiple feeders, the above two steps are repeatedly applied to all faulted feeders.

The function has an ability to identify bad fault indicators. For example, suppose that three fault indicators are installed in series on a feeder. If the middle fault indictor does not indicate passing of fault current while the other two indicate occurrence of a fault, the middle fault indicator is assumed to be bad. User defined rules can be added to the function for detecting incorrect status of indicators.

Scheme 2: Bisection Search

If there are operable switches located within the faulted segment identified by Scheme 1, the identification of the faulted section can further be narrowed down by trial switching operations. In case of no real-time fault indicator SCADA data that can be used by Scheme 1, Scheme 2 can be initiated directly. The systematic trial switching is based on the well-known bisection search technique.

The actual implementation consists of a sequence of trial switching operations which utilize (i) the bisection search module which acts as a brain in decision making, and (ii) SCADA for supervisory control and acquisition of status data. The major steps may be summarized as follows:

Based on the SCADA input data, the bisection search module determines a switching procedure to be implemented.



The operator confirms or makes modifications to the switching procedure shown in a Switching Procedure Management (SPM) form and then executes it.

Any change in the status of the specified protective device resulting from the switching operation is fed back through SCADA and shown on the one-line diagram. Such results are passed to the bisection search module and the process repeats as the feeder section to be examined is continuously reduced. The process terminates if there exist no switches that can be operated within the feeder segment under investigation.

During implementation of the bisection search, not all switches may be allowed to be operated. For example, the operator may desire to consider only remotely-controllable switches for possible switching operations. It may be the case that certain switches should not be considered at all for certain reasons. To accommodate such situations, the fault location function provides a mechanism to define and use switch classes or categories, with the user defining the classes of switches that may or may not be used.

6.1.4 Fault Isolation and Service Restoration

Fault Isolation and Service Restoration (FISR) determines switching actions which allow the operator to isolate areas of the network and to restore service to customers. These switching actions are determined in a manner which will minimize the effect of the outage.

Fault Isolation and Service Restoration is a set of tools used to support the operator in performing the following tasks:

Isolate individual equipment or an area of the network.

Restore power to deenergized areas of the network.

Isolate outage area and immediately restore power to deenergized areas of the network not faulted or isolated.

Restore a network to its normal state

The primary aim is to support the operator in selecting the best isolation and restoration scenario.

The function generates possible switching procedures for isolation and/or restoration and displays them using tabular displays. FISR interfaces with the Switching Procedure Management (SPM) function and provides the ability to use the SPM functionality for switching procedures generated by FISR.

FISR interfaces with the Outage Management System (OMS) function. FISR generated switching procedures can be associated with outage records created in OMS. In addition, input information about the faulted sections to isolate may come from OMS.



The switching actions involved in any switching procedure can be displayed on the network worldmaps. The effect of the switchings can be simulated to determine equipment that would get energized/ de-energized. A power flow can be run on the network with the switching actions simulated to determine if there will be line/transformer overloads or bus voltage violations. The switching actions can also be executed.

The fault isolation and service restoration functions are initiated after the location of the faulted segment or zone has been determined. The location of the fault may be the output of the Fault Location function.

FISR can be executed on both the real-time system and any study case system.

Isolation Tool

The Isolation tool provides an interactive environment for the operator to determine a set of switching actions required to isolate equipment or areas of the network specified by the isolation request, while minimizing the effect on other areas of the network.

The tool performs topological tracing to determine the minimal set of switches to open to completely isolate the selected equipment.

If the selected equipment is energized, the tool can be configured to generate restoration steps before isolation steps to supply (from alternate sources) equipment that is not isolated. This ensures that there is no unnecessary loss of load due to the isolation. This may be used when equipment needs to taken out of service for a future planned outage.

The Isolation tool separates the selected equipment into groups and generates a switching procedure for each group for the isolation of all equipment in that group.

Restoration Tool

The Restoration tool provides an interactive environment for evaluating multiple strategies for energizing portions of the distribution network that are out of service.

The Restoration tool generates all possible ways of restoring service to the de-energized sections without violation of substation transformer capacities. The tool first attempts to restore all the de-energized load selected for restoration without opening switches to break up de-energized islands. If that is not successful, it tries to restore all the de-energized load with some of the de-energized islands being split up into smaller pieces. If this also fails, the tool tries to perform partial restoration which involves dropping some load.

Restore to Normal Status Tool

This tool provides the operator with capability to generate a switching procedure that returns the given network to its nominal configuration. The normal configuration is defined by the database default switch status in the database. This function may be initiated after the end of an emergency outage condition when all repair work is



complete and the network is ready to be brought to its normal operating configuration.



Input Data

The input to FISR comes from user selected equipment on the worldmap displays. The user can chose equipment to isolate, equipment to restore, equipment not to restore, sources to use etc.

The input to FISR can also come from the Fault Location function or the Outage Management System.

Output Processing

The output of FISR is a set of switching procedures. The switching procedures are shown in a tabular form using the Switching Procedure Management (SPM) tool. Each switching procedure may consist of one or more switching steps. The switching steps can be shown graphically on the worldmap display. The effect of executing the procedure can be simulated graphically on the worldmap display.

Quantifying Switching Procedures

Each switching procedure has associated with it the following information:

Type of the procedure (isolation, restoration, restore to normal etc.)

List of switching steps and switching actions in the procedure

Load Restored - total kW load that will be restored by executing the switching procedure

Customers Restored - total number of customers that will be restored by executing the switching procedure

Transformers Restored - total number of transformers that will be restored by executing the switching procedure

Load not Restored - total kW load that will be unserved after execution of the switching procedure

Customers not Restored - total number of customers that will be unserved after execution of the switching procedure

Transformers not Restored - total number of transformers that will be unserved after execution of the switching procedure

Voltage Violation Index - index reflecting the bus voltage violations that may occur after the execution of the switching procedure

Line Overload Index - index reflecting the line overloads that may occur after the execution of the switching procedure

Losses - total real power loss after the execution of the switching procedure



Degree of difficulty Index - index representing the degree of difficulty of access/switching of the switches involved in the switching procedure

Some of the above values/indices are calculated based on a power flow execution on a network with the execution of the switching procedure simulated.

Sequencing of Switching Actions

The following rules are used in sequencing switching steps of a switching procedure:

Any unnecessary loss of load is prevented by load transfer prior to isolation (this may cause temporary loop/parallel operating conditions)

If a switching action creates a loop/parallel condition, the next switching action will attempt to break the loop/parallel to restore radiality

Open switching actions for splitting of de-energized islands are done before the closing actions for picking up pieces of the island load

When picking up multiple de-energized islands, the switchings to energize islands is done before switchings to close switches between de-energized islands

6.1.5 Free Placed Jumpers, Grounds, and Cuts

The “Jumpers, Grounds, and Cuts” (JGCJGC) function is a dispatcher’s tool use to easily introduce temporary changes to a world map that corresponds to changes in the field.

This feature allows an operator to change the network model to show a feeder being cut, grounded, or attached (jumpered) to another feeder. When the repair is completed, the change can be removed and the network model returned to its original state.

These changes can be made without a formal DBA editing session to modify the database.

Process Overview

The JGC function could be used to make the following changes to a world map:

Cut

When a dispatcher wishes to indicate that a line has been broken or purposefully cut, he or she would select the "Cut" option from the JGC menu and then indicate which line is to be cut and where on the line that cut is to take place. A predefined switching field will be added to the line at the point selected. This switching field consists of a main switch which is used to disconnect the two ends of the cut and two Isolator Ground switches which



can be used to ground one or both sides of the cut. Each time this world map is displayed, the coloring of each of the two line pieces shows whether it was energized or not. The operator can close or open the switch to connect or disconnect the two parts of the line and optionally close or open the Iso Ground switches to ground one or both sides of the cut. The opening and closing of these switches can be used to connect and disconnect the two pieces of the line without having to remove and reenter the cut itself.



Ground

When a dispatcher wishes to indicate that a line or busbar has been grounded, he or she would select the "Ground" option from the JGC menu and then indicate which line or busbar is to be grounded. A ground symbol will be placed on the line, at the point indicated by the operator. Each time this world map is displayed, the coloring of the line and all parts of the network electrically connected to the line will show that the line was grounded.

Jumper

When a dispatcher wishes to indicate that two lines have been connected together, he or she would select the "Jumper" option from the JGC menu and then indicate which two lines are to be connected.

A line will be connected to each of the two selected feeders at the selected points. These lines will be connected at their other ends by a pseudo switch. Each time this worldmap is displayed, the coloring of the lines will show that they are electrically connected. By opening and closing the switch, the operator can show connected or disconnected feeders without having to remove the jumper wire itself.

6.1.6 Graphical Query

The Graphical Query Function (GQF) enables displaying and manipulating data for selected components of a distribution system. It can be done in a tabular form or directly on Spectrum UI world maps. Graphical query can retrieve both, real time and study case data, from any data base source available to the SCADA and DMS network applications. The function can be initiated by an operator through the Spectrum UI world maps.

The GQF can be broken down into the following subfunctions:

Query format

Tabular graphical query

Anchored graphical query

Info query

Query format indicates to the GQF what data is available to be displayed by the function. It provides the necessary presentation format and data access information.

Tabular query presents data in a tabular display on an MMI console. The tabular display allows the operator to view the data, manipulate the data by sorting or filtering.



Anchored query presents data for a single item directly on a Spectrum UI world map. The query data becomes part of the world map and is affected by panning and zooming like any other item on the display. Anchored queries may be built permanently onto the Spectrum world map using the display editor or they can be temporarily placed on the world map on demand.

Info query displays primitive attribute data and switching procedure actions for single selected elements on a predefined data base form. Info query also can display other predefined information on an element including raster image data.

6.2 Network Analysis Applications

This section describes applications which are more algorithmic based and run against the network topology.

6.2.1 Topology Processing

Topology Processing consists of the following functions:

Topology Analysis

Network Tracing

Network Coloring

Topology Analysis

Topology Analysis is responsible for maintaining the real-time dynamic and study mode topologies of the distribution network model for use by the Network and Operations analysis functions (Fault Isolation and Service Restoration, Outage Management System and Distribution Power Flow).

Changes in the status of logical devices, such as switches and breakers, generate modifications to the distribution network model. In order to avoid a complete recomputation of the model, only the sections affected are updated.

Interactive Topological Tracing

The Interactive Topological Tracing function provides the capability to perform traces of electrically connected equipment in the Distribution Management System. The operator requests particular kinds of trace and selects equipment on graphical displays (schematic or geographic). Special coloring of the equipment shows the results of the trace on the graphical display. The electrical connectivity can be based on normal or current switch status.

The following types of traces are supported:



Type of Trace Description All For a selected equipment, traces all electrically

connected equipment. UpStream For a selected equipment, traces all equipment

upstream. DownStream For a selected equipment, traces all equipment

downstream. Between For two selected equipment elements, traces the

path between them. If more than one paths exists, choose one arbitrarily.

Common For two or more selected equipment elements, gives the first common upstream branch. If no common upstream branch exists gives the true common point.

Feeder Extent For a selected equipment, trace all connected equipment up to the feeder head, and down to the ends of the feeder.

The UpStream, UpStream with branch, Downstream and Common type of traces are valid only for radial portion of the DMS network.

Selection of the Interactive Topological Tracing Facility

Selecting the TRACE menu button activates the Interactive Topological Tracing function. This puts the displays in tracing mode. Three sub-menus, which allow operators to perform their tracing request, are displayed:

Option menu: This is a pull-down menu allowing the operator to select the type of trace.

Color menu: This is a pull-down menu allowing the operator to select the color of the tracing results.

Data menu: This is a pull-down menu allowing the operator to select the use of either normal switch statuses or current switch statuses to determine the electrical connectivity for this trace request.

Network Coloring

Topology Analysis determines several states of the distribution network configuration. Network Coloring provides for their representation via different colors and indications displayed on the distribution network diagrams. These states are defined below:

Energized (Live) — Energization status of all equipment in the Distribution Network Model. Different colors may be chosen to represent the energized state of different feeder circuits. This allows for more efficient visualization of the individual feeder circuits on the one-line diagrams.



De-energized (Dead) — A different color than that used for other states of the distribution equipment is used to represent the dead state. Typically, a single color is used throughout the system to draw the operator's attention quickly to the affected area.

Grounded (Earthed) — Grounded circuits are also represented with a single color. This indication aids in safety considerations as well as informing the operator that the ground must be removed before re-energization is attempted.

Abnormal — Devices presently in a state other than their defined normal state are represented with a separate color.

Loop State — Portions of energized DMS electrical subnetworks are considered to be in a loop state if there exists a path from a component back to itself that may be traced without traversing the same component twice.

Parallel State — Components of energized DMS electrical subnetworks are considered to be in a parallel site if they are connected to more than one source of injected power.

Looped and Parallel — Components meeting both the loop and parallel state criteria.

6.2.2 Distribution System Power Flow (DSPF)

The Distribution System Power Flow is used to study electric power distribution networks under different loading conditions and configurations. The power flow program can solve both positive sequence and three phase unbalanced representations of the network. The Distribution System Power Flow (DSPF) includes the following functions:

Real-time DSPF, which provides the operators with kW, kVAR, kV, Amp etc. for the present state of the distribution network. The current electrical connectivity information is derived from the SCADA database for telemetered or manually updated devices. The power flow executes periodically, upon any change in the distribution network, as well as on operator demand. The results of the real-time DSPF reflect the actual state of the distribution network.

Study DSPF, which provides the operators and engineers with kW, kVAR, kV, Amp etc. for an independent copy of the distribution network. It can be used to model “what if” scenarios. A number of saved cases are available to store input parameters, which can be retrieved to be used as input base cases for further scenarios. The study DSPF is executed on operator demand.

The DSPF always works with a subset of the distribution network. The subnetwork model may consist of a single feeder or a group of feeders connected to a feed point(s) (also referred to as an injection source(s)). The subnetwork model may include both radial and meshed configurations as the topology dictates. The



selection of the subnetwork is automatic for real-time DSPF when its execution has been initiated by switching in the network. For demand executions of the real-time DSPF and for study DSPF, the sub-network will be selected by the operator via facilities provided on the one-line schematic (or geographic) displays.

Where solution of the entire distribution network model is needed, as in the periodic real-time DSPF execution, DSPF views the entire model as being a combination of sub-networks and performs its processing on a sub-network by sub-network basis.

6.2.2.1 Power Flow Solution

The Current Injection method is used for solving the power flow. The algorithm is built based on phase components model to be able to solve power flow for both three phase unbalanced and balanced power systems. In the latter case the model is automatically simplified to single phase positive sequence. The algorithm is well suited to handle radial and meshed configurations, wide ranges of R/X ratios, and can take into account the presence of small generating units.

The Current Injection algorithm is based on the factorized nodal admittance matrix and injected nodal currents. The implementation of the power flow is based on the standard techniques for optimal ordering, factorization, and forward/back substitution. PV buses (generators) are treated by correction of generator angles based on node reactance matrix built for the reduced size network.

6.2.2.2 Equipment Modeling Within the Power Flow Solution

The Power Flow algorithm treats load value as voltage dependent i.e. load active and reactive powers are modeled as a function of voltage at the bus where the load is connected. A polynomial representation, which is a combination of constant power/current/impedance characteristics, is used to model the load to voltage dependence.

The power flow algorithm has a Load Scaling option which ensures that the injected power value from power flow solution is equal to the desired (measured) value. When the Load Scaling option is chosen, individual conforming non-telemetered load input values are scaled by a scaling factor such that the total injected power stays at a desired value.

Line Modeling

For three phase unbalanced power flow solution, lines are represented in phase components according to their real phase number (three phase, two phase and single phase) and are modeled in terms of their self and mutual impedances. For positive sequence power flow solution (symmetric balanced power system), only positive sequence impedance values are used for all line types. The pi-equivalent line model is used to represent ground susceptances.

Transformer Modeling



For three phase unbalanced power flow solution, three phase transformers, banks of three or two single-phase transformers, and single phase transformers are represented in phase components according to their winding connections. The following connection schemes are simulated corresponding to primary and secondary sides: wye/wye, wye/delta, delta/wye, delta/delta, open delta/open delta, open delta/open wye, and a single phase transformer connection. Wye connection may be grounded or ungrounded in any connection scheme.

For positive sequence power flow solution (symmetric balanced power system), transformers are modeled as single-phase pi-equivalents.

Voltage Regulator Controller

Voltage regulator controller may be part of load-tap-changing (LTC) mechanism in a substation transformer or part of a step-type line voltage regulator, which is an autotransformer and LTC mechanism built into an integral unit. All types of voltage regulator controllers are simulated in the power flow solution taking into account voltage limitations, line drop compensation, granularity of each step and bandwidth of the controller.

Generator Modeling

Generators such as co–generators (cogens), non–utility generators (NUGs), independent power producers (IPPs), and other similar units can be modeled in the power flow solution. Generators may be designated as either constant real power/constant voltage units (PV units) or constant real power/constant power factor units (PQ units). Reactive power limits for these generators are modeled as a pair of fixed upper and lower KVAR values.

Shunt Capacitors and Reactors

Shunts are defined by their kVAR values at nominal voltage. Within the power flow solution, they are modeled as constant admittance devices. The kW component of the shunt, if entered, represents resistive losses in the shunt.

Capacitor Controllers

Two types of controllers are simulated for switched capacitors: time switched and voltage control. Time switched controllers switch capacitors ON or OFF based on a pre-defined time schedule. Voltage control capacitors are switched ON when capacitor voltage is less than minimum voltage setting and switched OFF when this voltage is higher than the maximum voltage setting.

Injection Sources

Distribution networks are typically connected to the high voltage network at a point referred to as “an injection source”. The injection sources are modeled as slack buses in the Power Flow Solution. The slack buses act as infinite buses with fixed voltage magnitude and angle settings.



6.2.2.3 Load Setup

The Load Setup function within the Power Flow calculates individual scheduled load values at nominal voltage. These scheduled load values are then used as input to the DSPF.

An individual load can be defined as either conforming or non-conforming. Conforming loads follow a certain load curve. These loads are used in the load scaling procedure. Non-conforming loads have fixed schedules and do not follow any load curve and are therefore not used in load scaling.

The active power (KW) values for individual distribution transformer conforming load are calculated based on the following data:

The maximum load supplied by its distribution transformer

Its load curve

The total injected power (kW) for the entire subnetwork

The reactive power (kVAR) component of each distribution transformer conforming load is computed from the load’s power factor once the kW component has been calculated.

When real-time measurements are available either at the injection source, feeder head or along the feeder, these measurements are used to scale corresponding non-telemetered loads downstream to the measurements. Validation checking of real-time measurements is performed.

Load Curve Data

To derive the load curve data for a distribution transformer load, the Load Modeling subfunction supports the usage of generic load curves for different load types such as residential, commercial, industrial, agricultural etc.

Each generic load curve is an hourly profile over several seasons and day types. Each distribution transformer load has a load type defined. From the load curve, the load model factor is derived for the time and date of study. The time and date is the current time and date if the processing is in real-time, or operator entered if the processing is in a study mode.

6.2.2.4 DSPF Executions

Real-time DSPF Execution

The real-time DSPF execution can be triggered periodically, on switch status change, or upon operator demand



Periodic Execution: The real-time DSPF is periodically executed to provide a real-time solutions for the entire distribution network.

Event Execution: When events occur, the real-time DSPF is initiated after a short delay (typically 10-20 seconds, as set by the operators). This delay is intended to allow the system to reach a stable state. When triggered by events, the DSPF analyzes only those feeders that have been affected by these events since the last execution of the real-time DSPF function.

Demand Execution: Operators may initiate the real-time DSPF function at any time. In this case, no delay in execution occurs. The area to be analyzed is selected by the operator.

Study Mode DSPF Execution

The operator can execute the DSPF in Study Mode for a selected subnetwork. The operator can start either from the real-time distribution network model or from a Saved Case.

The operator can perform “what if” studies on the selected subnetwork to determine the loading, voltage profile, and losses. For example, the following “what if” conditions might be analyzed:

Sections of an adjacent feeder were switched to it

A capacitor was switched into the circuit

A substation bus were split into two separate buses

A tie-switch between circuits fed from adjacent substations were closed, leading to looped circuits

Load levels were changed

6.2.2.5 Input Data

In addition to the network connectivity data and the telemetered data from SCADA, the DSPF uses the following input data.



Typified Data

Season Type - season names (e.g. summer, winter) and season start/end day and month

Day Type - days of the week included in weekdays and weekends

Load type - load to voltage dependence data for each load type

Load Curve - 24-hours load profile for each load type

Line Type - resistance and reactance per unit length, positive and zero sequence resistance and reactance for three phase lines, charging, ratings (long, medium and short term) for each line type

Operational Device Data

Busbars – technological names, nominal voltage and phase

Lines: - technological names, phase, line types and length or impedances and ratings

Transformers - technological names, phase, connection type, impedances, admittances, low and high side voltages, tap changer data for high and low side, local controllers data

Loads - technological names, phase, conforming load data (load type, maximum loading with respect to connected transformer) or non-conforming load data (active and reactive power, time schedule)

Capacitors - technological names, phase, installed reactive power, percent of active power loss, nominal voltage, local controllers data

Generators - technological names, phase, power schedule, minimum and maximum power limits, unit type for simulation (PV or PQ)

Injections - technological names, active / reactive power and voltage according to phases

Run-time Parameters

Solution options - selection of voltage limit type (long, medium and short term) and values, load scaling options and simulation of local controllers

Periodicity – cycle time for periodic execution

Study time – specification of the time for which power flow needs to be executed

Injection powers and voltages – manual entry of powers and voltages for injection sources



Data from the ECS System

Results of the state estimator and/or bus load forecast functions from the ECS system may be used as inputs to the DSPF. The state estimator may provide power and voltage values for the injection source busbars at the boundary of the transmission and distribution systems. The bus load forecast may provide forecast load for injection sources to be used by the power flow calculations to study future loading conditions.

6.2.2.6 Output Data

The following output data is presented in tabular form

Busbar voltage (kV and per unit values), cumulative voltage drop and voltage imbalance (for three phase buses, negative sequence voltage).

Slack bus active/reactive powers and voltage

Capacitor/reactor bank initial and final ON/OFF statuses (may be different because of local controllers)

Line active/reactive power flow from and to, and current

Line power losses (kW and kVAR), no-load reactive power loss and voltage drop

Transformer active/reactive power flow from and to, and amperes

Transformer load and no-load power losses (active and reactive)

Transformer voltage drop, voltage tap increment and initial and final tap positions (may be different because of local controllers)

Load final active/reactive power

Small generation unit active/reactive powers and voltage

The following summary listings are presented in tabular form:

A list of all busbars which have their per-unit voltages below a low voltage limit or above a high voltage limit. The limits can be specified by the operator.

A list of all feeder sections which have currents exceeding the conductor rating (ampere capacity) by a limit specified by the operator (e.g., 90% or 120% of capacity).

A list of all transformers which have loading exceeding the transformer rating (KVA rating) by a limit specified by the operator (e.g., 90% or 120% of capacity).



Total real power losses for the subnetwork in kW and in percent.

The graphical query feature can be used to view the above tabular information graphically on worldmap displays.

All busbars and branches that have overloads are shown in a different color on the worldmap displays.

6.2.3 Volt/Var Control

An intelligent centralized Volt/Var control (VVC) is an important DMS function for dealing with the complexity of the voltage and reactive power control in a modern distribution system. This complexity usually limits the capabilities of local automatic controllers which typically monitor voltage regulators and switched capacitors.

The centralized Volt/Var control function allows the following capabilities:

Local controllers can respond to changing system conditions

Various Volt/Var control objectives can be utilized

Volt/Var control can be optimal at the system level, not just at the local level

The Volt/Var control function provides the possibility to control transformer tap position changers (LTC, line voltage regulators) and switchable shunt reactive devices (typically capacitors) directly or through existing local automatic controllers. Co-gens, NUGs and IPPs are modeled, but are not used as control resources in the optimization.

The VVC always works with a subset of the distribution network the same way as DSPF.

The VVC function’s primary objective is to satisfy voltage and loading constraints. If the primary objective is satisfied, secondary objectives are to minimize power loss, or to minimize power demand, or to maximize generated reactive power, or to maximize revenue.

6.2.3.1 Volt/Var Optimization Procedure

Method

From the mathematical point of view, the Volt/Var control optimization is a discrete minimization (maximization) problem with inequality constraints. The oriented discrete coordinate descent method is used for the optimization procedure. This method is classified as a combinatorial discrete programming method. The method suits distribution system Volt/Var optimization because control actions are discrete and the objective function is nonlinear.



Procedure

The value to be minimized (maximized) in optimization procedure is a combination of different types of active power variables. The objective function value is determined from the power flow solution given the settings of the control variables. The goal of the optimization procedure is to find the objective function extremum, while satisfying the constraints and limits. The approach used to satisfy constraints is to include the constraints in the objective function as penalties. It is possible that even through there are no violations after the execution of all the controls in the final VVC solution, there may be violations in the interim period between the execution of any two controls. In order to prevent these violations (if needed) a special algorithm checks and changes the sequence in which VVC controls are executed.



The constraints and limits to be satisfied are as follows:

The voltage at transformer buses must be within specified constraints

The loading of the feeder sections and transformers must be below specified constraints

The power factor at distribution substation buses must be within specified limits.

Distribution System Power Flow Interface

The VVC starts from the base case Distribution System Power Flow solution. Loads are simulated as part of this solution. In real-time, they are simulated based on the available telemetered measurements together with all statistical information pertaining to customer consumption in the specified time, day type and season. In study mode, user determined entries are used instead of remote measurements.

The power system model used in the VVC procedure is the same phase component model used in DSPF. The power flow solution is used by the optimization procedure to evaluate the effectiveness of the various possible control actions. The internal power flow solution is based on the same factorized matrix and is very time efficient which enables efficient calculation of the system state a large number of times.

6.2.3.2 VVC Execution

The Volt/Var control may be executed in either real-time or study mode. In real-time, the function automatically models the current state of the power system using telemetry where available and using historical load data where telemetry is not available. In the study mode, the configuration as well as transformer loads are defined by the user. Tools are provided so that the study may start either from the real time model or a saved case.

In the real time mode, the function operates in open loop or in closed loop. In the open loop mode, Volt/Var control generates advisory control actions that may then be implemented by the dispatcher. In the closed loop mode, Volt/Var control generates control action orders and requests Network Control (NC) to execute the orders automatically without the need for operator intervention. All control orders are logged for reviewing and analysis.

In real-time mode, the Volt/Var control may be setup such that it operates in periodic open-loop mode, or in periodic closed-loop mode. In addition it can be executed on user demand in open-loop mode. In study mode, the Volt/Var control can only operate in open-loop mode.



6.2.3.3 Input Data

The input date for VVC is the same as that for DSPF with additional options for selection of the optimization objectives. The user can select from the following objectives:

Minimize distribution system power loss

Minimize power demand (sum of distribution power loss and customer demand)

Maximize generated reactive power (absolute value of substation transformer reactive power)

Maximize revenue (the difference between energy sales and energy prime cost)

Keep the system within constraints.

6.2.3.4 Output Data

The VVC output shows specific VVC results for dispatcher review through tabular displays and schematic maps. These results consist of two parts: summary of power flow before and after optimization, and desired (optimal) control actions.

The summary of power flow results include the following values before and after optimization: objective function, injected active and reactive powers, total load and total power loss, integrated low and high voltage violations, maximum and minimum bus voltages.

Desired control actions and their impact on the objective function improvement are shown on a separate tabular display. If a voltage regulator is installed on the substation transformer the control action is not to change tap positions but to change this controller settings. The same is true for capacitor controllers. Control actions are also sent to Switching Procedure Management (SPM) for executions through the SPM display.

The graphical query feature can be used to view results of the VVC power flow calculations graphically on worldmap displays. Comparison of the results (e.g. bus voltages, line flows) of the VVC execution and the real-time power flow can also be done graphically using the query feature.

6.2.4 Optimal Feeder Reconfiguration

The Feeder Reconfiguration function determines switching actions which allow the operator to reconfigure distribution primary feeders. Through feeder reconfiguration, loads on one feeder are transferred to another feeder, resulting in changes in feeder voltage profiles, line and transformer loadings, etc. By judiciously implementing



feeder reconfiguration, the operator can eliminate adverse operating conditions such as line/transformer overloads and low voltages that customers may experience. Feeder reconfiguration can also provide operating benefits such as reduction in distribution system losses.

The types of benefits that can be obtained from feeder reconfiguration may be classified into tangible and intangible benefits. Improvement in service quality and reliability may be an example of intangible benefit. In this Feeder Reconfiguration function, only tangible benefits are dealt with. The primary Feeder Reconfiguration objective is to satisfy loading constraints. Voltage constraints are considered too because of the modeling of automatic voltage controllers as part of the internal power flow. If primary objective is satisfied, secondary objectives are to minimize power loss, to minimize unevenness in the supplying transformers loading (substation transformer balancing), or a combined load balancing and loss minimization objective (multi-objective optimization),

To implement the Feeder Reconfiguration function, the user is required to specify the area to be considered for feeder reconfiguration. Electrically connected subsystems and normally opened switches to be involved in feeder reconfiguration can then be identified.



Not all switches, which create loop configuration, may be closed or opened to implement feeder reconfiguration. For example, the operator may desire to consider only remotely-controllable switches for possible switching operations. It may be the case that certain switches should not be considered at all for certain reasons. Feeder Reconfiguration function accommodates such situations.

The output from the Feeder Reconfiguration function includes a switching procedure, and the values of the objective functions before and after feeder reconfiguration.

6.2.4.1 Solution Procedure for Feeder Reconfiguration

Problem Formulation

The overall objective function consists of up to three individual objectives: power losses, degree of unbalance in supply transformer loading, violation indexes. Each of these objectives is per-unitized and multiplied by its weighting factor (penalty). It is noted that the overall objective function is to be minimized.

Power losses are calculated by summing up active power losses occurring in all line sections and transformers within the study boundary. The value of the total power losses is per-unitized by dividing the kW losses by the total power demand within the study area.

The degree of unbalance in an individual transformer loading is defined as the difference between the load on the supplying transformer and the average loading of all transformers located within the study boundary. Loading on each transformer is per-unitized by dividing the load by the transformer rating. The average loading in per unit is determined by dividing the total load on all supply transformers involved by the sum of the ratings of all those transformers.

Line/transformer loading and voltage constraints are represented as inequality constraints. During the solution process, they are included in the objective function as penalty terms.

Solution Approach

The feeder reconfiguration problem is formulated as an optimization problem. Since the resulting formulation is too complicated to be solved in a single step, the solution procedure consists of two stages:

Stage 1— A sub-optimal solution is first determined by a fast non-iterative procedure.

Stage 2—The sub-optimal solution passed from Stage 1 is improved iteratively until no further improvement can be obtained.

In Stage 1, all normally-open switches located within the user-specified boundary of the distribution system are assumed to be closed initially. The resulting distribution system is of mesh network structure. The Stage-1 problem then becomes one of



determining switches to be opened in order to yield a radial distribution system. It is to be noted that in this stage, not all terms in the overall objective function are optimized simultaneously. Instead, a solution is found to optimize the most critical single objective function which is to be specified by the user. The use of a single objective can be justified since the result will be used as a mere starting solution that will be improved in Stage 2.

In Stage 2, using the solution obtained in Stage 1 as a starting solution, the procedure iteratively finds a better solution until no further improvement is possible. At every intermediate iteration, the change in the overall objective function is examined when a switch adjacent to the position of a currently open switch is simulated to be opened while the currently open switch is simulated to be closed. This approach is often referred to as a branch exchange scheme. It is to be noted that switching operations are not actually performed during the two-stage solution process.

Distribution System Power Flow Interface

The Feeder Reconfiguration starts from the base case Distribution System Power Flow solution. Loads are simulated as part of this solution. In real-time, they are simulated based on the available telemetered measurements together with all statistical information pertaining to customer consumption in the specified time, day type and season. In study mode user determined entries are used instead of SCADA measurements.

The power system model used in Feeder Reconfiguration procedure is the same phase component model used in DSPF. The power flow solution is used by the solution procedure to evaluate the effectiveness of the various configurations. Power flow is called only few times according to solution procedure logic. The power flow solution is very time efficient which enables efficient calculation of the system state a large number of times

6.2.4.2 Input Data

The input date for Feeder Reconfiguration is the same as that for DSPF with additional options for selection of the optimization objectives. The user can select from the following objectives:

To keep the system within constraints (removal of constraint violations)

To minimize distribution system power loss

To minimize unevenness in supplying transformers loading (substation transformer balancing)

Combination of the latter objectives, where each objective is included in the total sum with user-specified or default weighting factor



The user selects the feeder reconfiguration study area on the worldmap displays. Options exist to select portions of the network or the entire network.

6.2.4.3 Output Data

The output data includes reconfiguration switching procedures (shown through the SPM tabular displays) and the optimization results. A summary display shows the following values before and after reconfiguration: objective function, total power loss, unevenness in substation transformer loading, violation indexes: overload, low and high voltage. The switching operations display includes: ordered list of switches to be opened/closed (in pairs for normal conditions), and their impact on the objective function improvement.

6.3 Planned Functions

6.3.1 Cold Load Pickup

The effect of "cold loads" is included in the load model to aid the operator in studying flows and voltages, which occur during restoration of outaged feeders, feeder sections, and loads. When a load is de-energized for a period of time, upon reconnection to the network the value of the load is usually higher than the value at the time of loss of the load. This value will gradually drop down to the normal load value following reconnection of the load.

The load model provided is based on two operator-entered times: the time elapsed since disconnection of the load, and the time elapsed since reconnection of the load. The model assumes that the load power increases exponentially with the time since disconnection, until it reaches a peak value. The load decreases from the value at reconnection, also as an exponential function. The exponential factors are used to adjust the normal, or "hot", load computed as in the standard load model. The case, in which the load is reconnected before the peak value is reached, is also included.

It is assumed that only the conforming portion of the load demonstrates the "cold load" characteristic. Initial surges and other short-term transients are not included in the scope of this cold load model.

A number of parameters are required to define each type of cold load. These are entered as part of the description of each type of load during data base preparation.

6.3.2 On-Line Short Circuit Calculation

The on-line short circuit function may be initialized from real time data by means of the Distribution Power Flow. It is used to compute the short circuit flows, and to compare these flows against current relay settings. The operator is notified if calculated current flows are not consistent with current relay settings, so that



corrective action may be taken. This function is used following feeder reconfiguration.

To initiate a short circuit study, the operator selects the fault type, fault location, and impedance (if applicable). The following fault types are allowed:

Single line to ground

Line to Line

Double line to ground

Three Lines to ground

Single line open

Double line open

The solution algorithm reuses the matrices of the Distribution Power Flow. All the modeling capabilities (symmetric and asymmetric) of the DPF are included in the short circuit program. This function is also available for use in study mode along with the study DPF.

6.3.3 Transformer Load Management

This function has an interface to data acquisition. For each substation, a list is maintained of distribution transformers, current kVA loading, kVA rating, percent of kVA loading, core temperature, and time-overload factor since initial overload. This function allows the operator to utilize the short-term overload capabilities of the transformer to obtain relief during emergencies.

This function also has a load-balancing feature that utilizes optimal feeder reconfiguration. This feature comes in useful when there are several adjacent distribution feeders, which are designed as a network but are operated radially. The function uses heuristic searches, which transfers feeder sections from heavily loaded transformers to lightly loaded transformers. The objective of the search is to improve the loading on transformers so that they are more nearly equal. Extensive use is made of the trace feature of topology processing during this search. The power flow is utilized to check whether the proposed solution satisfies operating constraints. Candidate switching actions are presented to the operator for review and action.

6.3.4 Load Forecasting

The Load Forecasting function allows the operator to best estimate the load at the feeder level up to 10 days in advance.

The load forecasting for DMS is the same as the one for EMS, but contains additional capability to distribute station loads to feeders. From the feeder head the





load is distributed geographically to individual distribution loads by means of the load model described in the section on the power flow.

Two options are available.

1. The pattern matching approach uses feeder patterns to distribute the substation transformer loads obtained from the EMS similar day load forecast to feeders. If feeder measurements are available, these patterns can be adaptively updated based on measurement data.

2. The weather adaptive load forecast is similar to the one used by the EMS. If local weather information is available; these forecasts can be factored into the zone load forecasts that are then distributed to the substations and feeders as described for item # 1.

The Load Forecasting function is integrated in the DMS system and contains archiving and retrieving facilities. Save cases can be compared and the differences between them highlighted.

section 2 scada-ems 2-file 2

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