Draft Transmission Planning Guideline Mar 2012

7/25/2019 Draft Transmission Planning Guideline Mar 2012

1/91

Draft Guidelines for Transmission Planning

March 2012

Prepared for


2/91

Draft as of March 2012 2

Table of Contents

ABBREVIATIONS ............................................................................................................... 6

DEFINITION OF TERMS ...................................................................................................... 9

GENERAL STATEMENT ..................................................................................................... 12

1. INTRODUCTION ....................................................................................................... 13

1.1 Introduction ............................................................................................................... 13

1.2 Planning Horizon ........................................................................................................ 13

1.3 Planning Process ........................................................................................................ 14

2. Forecasting ............................................................................................................. 16

2.1 Introduction ............................................................................................................... 16

2.2 Forecast Information .................................................................................................. 16

2.3 Forecasting Methodology ........................................................................................... 17

3. Standards and Criteria ............................................................................................. 19

3.1 Introduction ............................................................................................................... 19

3.2 Performance Standards as per the PGC ....................................................................... 20

3.2.1 System Losses ..................................................... ................................................................. .......... 20

3.2.2 Congestion .................................................................................................................................... 20

3.3 Planning Criteria and Limits ........................................................................................ 21

3.3.1 Planning for Redundancy .............................................................................................................. 21

3.3.2 Technical Limits ............................................................................................................................. 22

3.3.3 Power Factor Considerations ........................................................................................................ 26

3.3.4 Minimum and Peak Load Demand Considerations ....................................................................... 263.3.5 Planning for Disposal of Assets ..................................................................................................... 27

3.3.6 Planning for Generation ................................................................................................................ 27

4. Technical Studies ..................................................................................................... 28

4.1 Introduction ............................................................................................................... 28

4.2 Data Requirement ...................................................................................................... 28

4.3 Load Flow Studies ...................................................................................................... 32

4.3.1 Minimum Data Requirements ....................................................................................................... 32

4.3.2 Criteria and Study Scenarios ......................................................................................................... 334.3.3 Load Assumptions ......................................................................................................................... 33

4.3.4 Generation Assumptions ............................................................................................................... 34

4.4 Short Circuit Studies ................................................................................................... 35

4.5 Switching Studies ....................................................................................................... 36

4.6 Voltage Stability ......................................................................................................... 36

4.7 Transient Stability ...................................................................................................... 38


4.7.2 Criteria ........................................................................................................................................... 38

4.7.3 Methodology ................................................................................................................................. 39

4.7.4 Results ........................................................................................................................................... 41

4.7.5 Transient Instability ....................................................................................................................... 424.8 Small Signal Stability .................................................................................................. 43



3/91


4.8.2 Criteria ........................................................................................................................................... 434.8.3 Methodology ................................................................................................................................. 44

4.8.4 Results ........................................................................................................................................... 45

4.9 Sub-synchronous Resonance (SSR) Studies .................................................................. 45


4.9.2 Frequency Scanning ...................................................................................................................... 47

4.9.3 Eigenvalue Analysis ....................................................................................................................... 47

4.10 Generation Facilities ................................................................................................... 484.10.1 Integration of Generation Facilities .......................................................................................... 484.10.2 Renewable Generation ............................................................................................................. 49

4.10.3 Minimum Data Requirements .................................................................................................. 50

4.10.4 Type of Studies ......................................................................................................................... 50

4.11 Quality of Supply Studies ............................................................................................ 50

4.11.1 Unbalance Studies .................................................................................................................... 50

4.11.2 Voltage Distortion Studies ........................................................................................................ 51

4.12 Right of Way and Environmental Considerations ......................................................... 51

5. Transmission Assets................................................................................................. 52

5.1 Introduction ............................................................................................................... 52

5.2 Transformers ............................................................................................................. 52

5.3 Switchgear ................................................................................................................. 53

5.3.1 PCBs ............................................................................................................................................... 53

5.3.2 Isolators or Disconnecting Switches .............................................................................................. 54

5.3.3 Gas Insulated Switchgear .............................................................................................................. 54

5.4 Transmission Lines ..................................................................................................... 54

5.4.1 Design of Transmission Lines ........................................................................................................ 54

5.4.2 Thermal Limits ............................................................................................................................... 55

5.4.3 Voltage Limits ................................................................................................................................ 56

5.4.4 Conductor Optimization ................................................................................................................ 56

5.5 Capacitors (Series and Shunt) ..................................................................................... 56

5.5.1 General .......................................................................................................................................... 56

5.5.2 Shunt Capacitors ........................................................................................................................... 56

5.5.3 Series Capacitors ........................................................................................................................... 58

5.6 Reactors (Series and Shunt) ........................................................................................ 59

5.6.1 Application of Shunt Reactors ....................................................................................................... 59

5.6.2 Switchgear ..................................................................................................................................... 60

5.6.3 Other Types of Reactors ................................................................................................................ 60

5.7 HVDC Schemes ........................................................................................................... 61

5.8 FACTS Devices ............................................................................................................ 625.8.1 SVCs ............................................................................................................................................... 62

5.8.2 STATCOM ...................................................................................................................................... 63

5.8.3 TCSC ............................................................................................................................................... 63

5.8.4 Unified Power Flow Controller (UPFC) .......................................................................................... 64

5.8.5 Thyristor Controlled Breaking Resistor (TCBR) .............................................................................. 64

5.9 Busbar ....................................................................................................................... 64

6. Transmission Planning in a Market Environment...................................................... 65

6.1 Introduction ............................................................................................................... 65

6.2 Coordination Among the Regulated Transmmission Entity, Grid Customers, System

Operator and Market Operator............................................................................................... 65

6.3 Open Access and Grid Planning ................................................................................... 65


4/91


6.4 Alleviation of Congestion to Enhance Market Efficiency .............................................. 65

6.5 Market Impact Studies to Assess Impact on WESM of Congestion Alleviation CAPEX

Projects .................................................................................................................................. 66

6.6 Impact of Different Generation Patterns ..................................................................... 66

7. Project Selection and DocumenTation ...................................................................... 67

7.1 Introduction ............................................................................................................... 677.2 Project Evaluation ...................................................................................................... 67

7.2.1 Defining the Problem .................................................................................................................... 68

7.2.2 Selecting Potential Solutions ......................................................................................................... 697.2.3 Technical Analysis.......................................................................................................................... 70

7.2.4 Market Analysis ............................................................................................................................. 70

7.2.5 Financial Analysis .......................................................................................................................... 74

7.3 Prioritization .............................................................................................................. 78

7.4 Project Documentation .............................................................................................. 78

REFERENCES ................................................................................................................... 81

APPENDIX A: List of Standards used by the Regulated Transmission Entity for Transmission

Line design ..................................................................................................................... 83


5/91


Date Issued: 21 March 2012

Document Name: Transmission Planning Guideline rev 8

Document Version: Draft Transmission Guideline

Project Team: Pieter Nel, Machiel Coetzee, Dr Yen-Shong Chiao, Kris Tampinco

Name of Project: Development of Transmission Planning Guidelines


6/91


ABBREVIATIONS

ABBREVIATION TERM

A

A Ampere

AAC All Aluminum ConductorAAAC All Aluminum Alloy Conductor

AC Alternating Current

ACSR Aluminum Conductor Steel Reinforced

AIS Air Insulated Switchgear

AVR Automatic Voltage Regulator

B

C

CAPEX Capital Expenditure

CCC Capacitor Commutated Converter

CPV Concentrated PhotovoltaicCSP Concentrated Solar Power

CT Current Transformer

CVC Constraint Violation Coefficient

D

DC Direct Current

DCF Discounted Cash Flow

DDP Distribution Development Plan

DFIG Double-fed Induction Generator

DOE Department of Energy

DU Distribution Utility

EEENS Expected Energy Not Supplied

EPIRA Electric Power Industry Reform Act (R.A. No. 9136)

Eq Voltage behind Transient Reactance

ERC Energy Regulatory Commission

F

FACTS Flexible AC Transmission System Devices

G

GIS Gas Insulated Switchgear

GTO Gate Turnoff

H

HVAC High Voltage Alternating Current

HVDC High Voltage Direct Current

Hz Hertz

I

IGBT Insulated Gate Bipolar Transistor

J

K

kA Kilo Ampere

km Kilometer

kV Kilovolt

kWh kilo Watt Hour


7/91


ABBREVIATION TERM

L

LC Inductive-Capacitive

LV Low Voltage

LWAP Load Weighted Average Price

M

MAE Mean Absolute ErrorMAPE Mean Absolute Percentage Error

MDOM Market Dispatch Optimization Model

MOV Metal Oxide Varistor

ms Milliseconds

MSE Mean Squared Error

MTS Main Transmission System

MV Medium Voltage

MVA Megavolt Ampere

MVAr Megavolt Ampere Reactive

MW Megawatt

MWH Megawatt Hour

N

NGCP National Grid Corporation of the Philippines

NPV Net Present Value

O

OPGW Optical Fiber Ground Wire

P

PCB Power Circuit Breaker

PDM Price Determination Methodology

PDP Power Development Program

PEP Philippine Energy Plan

PGC Philippine Grid CodePhP Philippine Pesos

PSM Price Substitution Methodology

PSS Power System Stabilizers

PSS/E Power System Simulator for Engineering

pu Per Unit

PV Photovoltaic

Q

R

RMS Root-Mean-Square

RMSE Root Mean Squared ErrorsRTWR Rules for Setting Transmission Wheeling Rates

RTU

S

SCO Synchronous Condenser

SIL Surge Impedance Loading

SPS Special Protection System

SRMC Short Run Marginal Cost

SSE Sum of Squared Errors

SSR Subsynchronous Resonance

STATCOM Static Condenser or Compensator

SVC Static VAr Compensator

T

TCBR Thyristor Controlled Breaking Resistor


8/91


ABBREVIATION TERM

TCR Thyristor Controlled Reactor

TCSC Thyristor Controlled Series Capacitors

TDP Transmission Development Plan

TIS Torsional Interaction Susceptibility

TSC Thyristor Switched Capacitor

TOSP Time of System Peak

UUPFC Unified Power Flow Controller

V

VAr Volt Ampere Reactive

VSC Voltage Sourced Converter

VT Voltage Transformer

W

WESM Wholesale Electricity Spot Market

X

Y

Z


9/91


10/91


11/91


12/91


GENERAL STATEMENT

This document serves as a guide to the Regulated Transmission Entity of the Philippines in planning

its transmission network and to aid in the preparation of the capital expenditure (CAPEX) forecasts in

the Revenue Application that it must submit to the Energy Regulatory Commission (ERC) prior to each

regulatory period. It is intended that the information to be submitted to support the RevenueApplication will have a similar content and structure to the Transmission Development Plan (TDP) that

will be submitted to the Department of Energy (DOE) but may include additional information specific to

the requirements set out by the DOE and the Philippine Grid Code (PGC).

The requirements set out in this guideline are the minimum requirements of the ERC but do not

replace or supersede any additional requirements set out in the Rules for Setting Transmission

Wheeling Rates (RTWR) and the PGC. In addition, the requirements set out in this guideline should

not be interpreted as overriding the responsibility of the Regulated Transmission Entity to determine

and justify the CAPEX needed to provide the level of service its consumers expect.


13/91


1. INTRODUCTION

1.1 INTRODUCTION

Efficient and effective grid planning is critical for maintaining the quality of service expected

from the Regulated Transmission Entity as well as in managing the growth of the power

system. Such planning process includes assessments that will assist in ensuring that theRegulated Transmission Entitysassets are fully leveraged and that availability and quality of

supply is not sacrificed. The processes detailed in this guideline will aid the Regulated

Transmission Entity in identifying solutions to network problems as well as prioritizing the

improvements by undertaking the necessary analysis that will ensure the appropriate balance

between the overall cost of a project and the expected benefit to the customers.

The RTWR1requires the Regulated Transmission Entity to provide its forward forecasts of its

proposed annual CAPEX for each year of the regulatory period. Such forecasts will be

reviewed as to whether it is cost effective; reasonably efficient from a design and

implementation point of view; and is likely to support the forecast growth in customer, co-

incident peak demand and energy delivered to enable the Regulated Transmission Entity to at

a minimum meet its target levels of performance. Furthermore, the PGC2 identifies that the

Regulated Transmission Entity has lead responsibility for grid planning and has further

specified the required technical studies and planning procedures. From these requirements it

is apparent that the Regulated Transmission Entity should have an accurate and robust

planning process in place not only to support its proposed CAPEX but also to align with the

objectives of the Electric Power Industry Reform Act3(EPIRA) to set an efficient grid planning

process in order to ensure the quality, reliability, security and affordability of electrical

transmission services.

This guideline was developed consistent with the requirements of the PGC. The documentspecifies standards and criteria for grid planning as well as explains the required technical

studies not only taking into account the power quality requirements in the PGC but also

considering the best practices of transmission entities in other jurisdictions. Moreover, to aid

the Regulated Transmission Entity in planning transmission projects, this guideline also

includes information on planning transmission equipment; planning in a market environment;

and how to evaluate as well as prioritize projects.

1.2 PLANNING HORIZON

The RTWR specifies that the electricity transmission system planning horizon is fifteen (15)

years or as otherwise determined by the ERC based on reasonable planning policies. Thus,for purposes of grid planning by the Regulated Transmission Entity, long-term studies

employing a planning horizon of fifteen (15) years (unless revised by the ERC), are required to

be conducted in order to determine the most beneficial technologies to serve long-term

system requirements and identify strategic power corridors. The same planning horizon shall

be utilized for evaluating the expected level of use of transmission assets in order to manage

the effect of optimization on CAPEX projects.

1 Rules for Setting Transmission Wheeling Rates for 2003 to around 2027, Energy Regulatory Commission, Philippines,

September 2009.2Philippine Grid Code Amendment No. 1, Grid Management Committee, Energy Regulatory Commission, Philippines, April

2007.3Electric Power Industry Reform Act (Republic Act No. 9136), Congress of the Philippines, July 2000.


14/91


1.3 PLANNING PROCESS

It is the intent of this guideline to set an effective planning process in order to ensure

sustainability and efficiency of transmission services which is the primary objective of

regulation. Moreover, in relation to the regulatory reset process for the Regulated

Transmission Entity, this guideline will aid in the preparation of the proposed CAPEX referred

to in Section 5.10 of the RTWR which forms part of the Revenue Application to be submitted

by the Regulated Transmission Entity to the ERC. Such Revenue Application will be submittedat the date determined by the ERC after reviewing all the issues raised following the release of

the Issues Paper. Pursuant to Section 7.1.2 of the RTWR, the Issues Paper will be published

not less than 21 months prior to the start of each regulatory period. The Third Regulatory

Period has commenced on January 1, 2011 and will end on December 31, 2015. Thus, it is

expected that the Fourth Regulatory Period will commence on January 1, 2016.

The RTWR and the Issues Paper specifies the minimum requirements for CAPEX

applications. To further assist the Regulated Transmission Entity in its application to the ERC,

this guideline details the specific process the Regulated Transmission Entity has to follow in

formulating project requests keeping in mind issues relating to the technical, environmental

and economic aspects of the project.

Transmission Development Plan (TDP)

While this guideline is intended to assist in the regulatory reset process, it is expected that

having an effective planning process in place will also assist in the preparation of the TDP

given that as per Section 10(a) of the EPIRA, the TDP is primarily a plan for managing the

transmission system through efficient planning.

The main difference between the TDP and the forecast CAPEX application is that the TDP is

prepared annually by the Regulated Transmission Entity to be submitted for approval to the

DOE for integration into the Power Development Program (PDP) and the Philippine Energy

Plan (PEP). On the other hand, the forecast CAPEX application is prepared once every

regulatory reset. It should be noted however that any plan for expansion or improvement of

transmission facilities is required to be approved by the ERC pursuant to Section 10(c) of the

EPIRA,

Another difference between the forecast CAPEX and the TDP is that the forecast CAPEX

considers only projects for the next five (5) years of the regulatory period while the TDP

covers a 10-year plan. The Regulated Transmission Entity has however indicated that the first

years of the TDP normally constitute the CAPEX approved by the ERC for the Regulatory

Period while the latter years of the 10-year period are indicative projects.

The Regulated Transmission Entity is required under the EPIRA to consult electric power

industry participants in the preparation of the TDP. In relation to grid planning, and as also

indicated below, it is recommended that the grid users, market operator and system operator

also be consulted during the planning process in order to assist the Regulated Transmission

Entity in identifying congestion problems that may result in increased electricity prices due to

transmission congestion.

Philippine Grid Code (PGC)

Section 5.2.1 of the PGC states that the Regulated Transmission Entity shall have leadresponsibility for grid planning including:


15/91


a) Analyzing the impact of the connection of new facilities;

b) Planning expansion of the grid to ensure its adequacy to meet forecasted demand

and the connection of new generating plants; and

c) Identifying congestion problems that may result in increased outages or raise the

cost of service significantly.

It is worth emphasizing that while the lead responsibility falls under the Regulated

Transmission Entity, coordination with grid users, the market operator and the system

operator is necessary during the planning process (and not only during real time) in order to

assist in identifying congestion problems that may result in increased electricity prices due to

transmission congestion. This need is further explained in Section 6 of this guideline.

Consistent with Chapter 5 of the PGC, Section 4 of this guideline specifies the different grid

planning studies required to be conducted by the Regulated Transmission Entity in order to

ensure the safety, reliability, security and stability of the grid. Section 4 also includes other

studies deemed necessary to efficiently perform the responsibilities of the Regulated

Transmission Entity. Moreover, Section 4 of this document also details the data requirementsfor the different types of planning studies to be undertaken by the Regulated Transmission

Entity.


16/91


17/91


present the results of the analysis to the ERC in relation to the affected CAPEX projects as

part of its Revenue Application.

In terms of the forecasts required for the Market Simulation Model, it is recommended that the

relevant historic load data e.g. hourly load for each modeled node, are obtained from the

market operator for the purpose of preparing the forecast load profile or load duration curve for

the forecast years.

In order to ensure consistency with the DDP, PDP, as well as with the forecasts used in the

WESM, the Regulated Transmission Entity should not alter any forecasts provided by DUs for

use in the development of its own forecasts. However in the review of the submitted forecasts,

the Regulated Transmission Entity is encouraged to clarify any issues with regards to the

forecasts provided by the DUs and await any revision to the forecasts if necessary.

2.3 FORECASTING METHODOLOGY

Forecasting models can be divided into statistically based and intelligence-based models and

all have different characteristics, features and strengths. The selection of the most suitable

forecasting model is highly dependent on the following parameters: forecast time frame, dataavailability, the accuracy and cost of the forecast, the application and purpose of the forecast.

5

Regarding the forecast time frame, as indicated in Section 2.1 above, the forecasting

technique required in relation to the regulatory reset process of the Regulated Transmission

Entity is long term forecasting which is intended for applications in relation to capacity

expansion as well as studies on the return of capital investments. The long term forecast is

required for a period of fifteen (15) years, which is the planning horizon set as per the RTWR

unless it is otherwise revised by the ERC, which will then be used to develop the capital

requirement for the next five (5) years which is the prescribed time frame for a regulatory

period.

Long term forecasts take into account historical load data, the number of customers in

different categories, the economic and demographic data and their forecasts, and other

factors. Typically, power utilities serve customers of different types such as residential,

commercial and industrial, and different factors affect the forecasting of each class. However,

in the case of the Regulated Transmission Entity, there appears to be no requirement to take

into account the different types of customers since these will already be taken into account in

the submitted forecasts by the DUs. Given this, the focus of the Regulated Transmission

Entity will be on historical load data, the economic and demographic data and their forecasts,

and other factors.

Statistically based methods forecast the current value of a variable by using explicit

mathematical combinations of the previous values of that variable and, possibly, previous

values of exogenous factors.6Long term forecasting using statistically based models require

years of economic and demographic data and is affected by environmental, economic, political

and social factors. The econometric approach is broadly used for long term forecasting which

combines economic theory and statistical techniques for forecasting electricity load demand.

The approach estimates the relationships between energy consumption and factors

5 Business Intelligence in Economic Forecasting: Technologies and Techniques, F. Elakrmi and N. A. Shikhah, Amman

University, Jordan.6Power System Planning, Howard Technology, Middle East.


18/91


influencing consumption. The relationships are typically estimated by the least-squares

method or time series methods.7

It should be noted that the availability of accurate and consistent information is an important

factor in the determination of which model to use. One reason for this is the difficulty in

forecasting demographic and economic factors versus that of load forecasting.8 If accurate

information on economic and demographic factors is not readily available, then the

econometric approach may not be the most suitable model. Extrapolation models whichinvolve fitting trend curves to basic historical data are simple and easy to use however is most

appropriate for short term projections because it ignores the possible interaction of load

demand with other economic factors.9 Thus, for long term forecasting using extrapolation

models, it is appropriate to take into account discounting the earliest elements of the forecast

by incorporating weighting factors (suitable weighting factors are from 0.25 to 0.90) in the

calculation of the least squares (best fit) solution.10

Intelligence-based models e.g. Fuzzy Systems, attempts to model the human reasoning

process at a cognitive level which requires expert knowledge. The algorithms associated with

intelligence-based models neither require a mathematical model that will map inputs to

outputs nor require precise inputs.11

Results of studies undertaken in different countries have indicated differences in terms of what

is most appropriate for long term forecasting. From other studies, statistically based models

are recommended to be used while there are also studies that indicate that intelligence-based

models prove superior to statistically based models.

It is the Regulated Transmission Entitys responsibility to select the most appropriate model

(or models, as several load forecasting methods may be used in parallel), whether it be

statistically based, intelligence based or a combination of different model types. To assist in

the selection, the Regulated Transmission Entity shall test the acceptability or the accuracy of

the algorithms. There are different measures to test the accuracy of a model e.g. the mean

absolute error (MAE), mean absolute percentage error (MAPE), sum of squared errors (SSE),

mean squared error (MSE) and root mean squared errors (RMSE).12

The MAPE and the SSE

are the most widely used for load forecasting, and in such accuracy tests, the difference

between the actual load and forecast load is calculated and the model with an error ranging

from 2-5% is considered as exhibiting good performance. Among the models that have

passed the test on accuracy, the model with the least error is the most suitable. The results of

the test on the model selection shall be documented by the Regulated Transmission Entity

and shall be made available during the review of the expenditure forecasts. Such

documentation should also be made available earlier in the regulatory reset process in the

event that the ERC requires such information to be submitted as part of the Revenue

Application.

7Applied Mathematics for Power Systems, E. A. Feinberg and D. Genethliou, State University of New York, New York.

8Modern Power System Analysis, D.P. Kothari, I.J. Nagrath, New York, 2008.

9Demand Forecasting for Electricity, N. Bohr.

10

Computer Analysis Methods for Power Systems, G.T. Heyat, New York. 11Fuzzy Ideology based Long Term Forecasting, J. H. Pujar, World Academy of Science, Engineering and Technology, India.

12 Long Term Energy Consumption Forecasting Using Genetic Programming, K. Karabulut, A. Alkan, A. Yilmaz, Yasar

University, Turkey, 2008.


19/91


3. STANDARDS AND CRITERIA

3.1 INTRODUCTION

The overall goal of the planning activities can be expressed as follows:

The planning of the grid or transmission system shall aim at the identification of the least-costalternative, or the alternative which maximizes the net benefit with due attention being paid to

major uncertainty factors and providing adequate security and reliability.

Grid planning has to be based on realities concerning geographical conditions, technical

status and possibilities, and the sizes and locations of the power markets. Due to the fact that

the Philippines power system is covering a widespread geographical area with scattered

population and long distances between the most inexpensive power resources and the power

market, integrated generation and grid planning has to be performed. Thus, grid planning also

has to be undertaken with the intention of identifying projects in close coordination and

cooperation with not only with DUs but more importantly with generation facilities.

The main task for the power industry in the Philippines would be to supply the customers with

electric power, in sufficient amount and with an economically viable supply quality.

In most countries, there is substantial competition between the different industry sectors of the

society to get capital for necessary investment and rehabilitation projects. The Philippines is in

this respect no exception. Since the power industry is so capital intensive, the requirements on

power supply reliability should generally not be too rigid; the stricter the criteria the higher the

investment to be called for.

A basic principle of grid planning is that all equipment should be within normal capacity ratings

and normal voltage limits when the system is operating with all scheduled elements in service

and is not experiencing faults or other abnormal faults or disturbances.

Furthermore, the system should be capable of operating within emergency capacity ratings

and emergency voltage limits immediately following a system fault that results in the loss of a

single element (N-1). The system operator will then manage the transmission system to return

to a healthy operating condition as soon as possible to ensure continuity of supply within the

capacity ratings and voltage limits.

An objective of this guideline is to use planning criteria also recognized in other jurisdictions to

assist the Regulated Transmission Entity in developing a secure and reliable transmission

system. The planning criteria described in this guideline shall be used for any new

transmission system development project in the Philippines.

It is the Regulated Transmission Entitys13

responsibility to identify many possible solutions to

satisfy the need and to comply with the planning criteria. It is also the task of the Regulated

Transmission Entity to rank the possible solutions in such a way that it can be acceptable to

the environment, complete the implementation in the time specified and that it is the best

solution with a good balance between technical fit and economic viability (techno-economic).

13 The Regulated Transmission Entity as the system planning engineer is responsible for the expansion needs of the

transmission system by conducting the appropriate power system studies to comply with the requirements as set out in thisguideline and the PGC.


20/91


The transmission system plan must comply with all the statutory and technical limits as

documented in the PGC and all other relevant standards and specifications that may be

applicable in the Philippines.

3.2 PERFORMANCE STANDARDS AS PER THE PGC

The Regulated Transmission Entity must ensure that the transmission system is designed to

comply with the quality requirements as stipulated in Chapter 3 of the PGC.

3.2.1 System Losses

The transmission system losses are a major concern to any utility. The aim for any system

planning engineer is to reduce the system losses as far as technically possible in the process

of developing the transmission system. It is the task of the Regulated Transmission Entity to

calculate the system losses for all possible alternatives considered and to use these results as

one of the drivers to determine the best techno-economic solution for system development.

Typically the Regulated Transmission Entity will calculate the impact on system losses for the

life time of the expected new project infrastructure as part of the project justification.

System loss shall be classified into three categories: Technical loss, non-technical loss and

administrative loss.

The technical loss shall be the aggregate of conductor loss, the core loss in transformers, and

any loss due to technical metering error.

The non-technical loss shall be the aggregate of the energy loss due to meter-reading errors

and meter tampering.

The administrative loss shall include the energy that is required for the proper operation of the

Grid.

3.2.2 Congestion

Congestion in relation to operating in a market environment has yet to be defined in the PGC.

For the purpose of grid planning as set out in this guideline, transmission congestion shall

mean a situation where, because the transmission limit of a transmission line or the capacity

of a transformer is reached and no more power may be transmitted through this line or

transformer, cheaper power from a generating unit cannot be dispatched and transmitted

through this line or transformer and instead more expensive power has to be dispatched to

meet the load demand.

While Chapter 3 of the PGC does not contain standards in relation to transmission congestion

as defined above, it is primarily the Regulated Transmission Entitys responsibility to identify

the congestion problems that may result in increased outages or raise the cost of service or

the electricity prices due to transmission congestions significantly. This is further explained in

Section 6 of this guideline.


21/91


22/91


23/91


24/91


During system healthy conditions no interconnected line is allowed to exceed the

normal continuous (thermal) limit of the line. This is the 75C thermal rating of the

transmission line.

2. N-1 Contingencies

During a single contingency or N-1 condition, no interconnected line is allowed to

exceed the emergency thermal limit of the line for a maximum period of 2 (two) hours.The thermal ratings are a function of the design and construction of the transmission

line. The rating of the terminal equipment should be taken into consideration. It is

possible that the terminal equipment of a specific line could be lower than the

emergency rating of the conductor and this will then act as the emergency rating of the

transmission line. It is advisable for the Regulated Transmission Entity to identify

these limiting conditions and replace the terminal equipment to increase the

emergency rating of the line to be equal to the conductor limit or 90C thermal rating of

the transmission line.

The Regulated Transmission Entity normally considers only the 75C thermal rating of

the transmission lines during system planning studies and not the 90C thermal rating

of the transmission line because such thermal rating of the transmission line should be

used for operational purposes only.

Loading of Transformers

The specific assessment to be used for any new development or upgrading of the

transmission system, must comply with the following criteria for transformer loading:

1. System Healthy Conditions

During system healthy conditions no transformer is allowed to exceed the nameplatecontinuous Megavolt Ampere (MVA) rating of the transformer. This is typically the

100% nameplate rating of the transformer in MVA.

2. N-1 Contingencies

During a single contingency or N-1 condition, no transformer is allowed to exceed the

nameplate continuous MVA rating of the transformer. This is typically the 100% of the

nameplate rating of the transformer in MVA.

The overloading of transformers is only for system operations and not for the purpose

of grid planning specifically in the consideration for system planning studies.

Series Capacitor Banks

The series capacitor bank must be designed in line with IEC standards. The IEC standard

specifies the following design criteria and any new development or upgrading of the

transmission system must be compliant to these criteria:

8 hours in a 12-hour period: 1.1 times rated current;

hour in a 6 hour period: 1.35 times rated current; and

10 minutes in a 2 hour period: 1.5 times rated current.


25/91


Shunt Capacitors or Shunt Reactors

The use of shunt capacitor banks or shunt reactors for voltage control must be sized in such a

way that it does not cause a voltage change of more than three percent (3%) during system

healthy conditions when it is active in the transmission system. Furthermore, in an N-1

contingency scenario, the voltage change must not exceed five percent (5%) when it is active

in the transmission system.

Power Circuit Breakers

Newly-commissioned power circuit breakers (PCBs) should be selected with somewhat high

interrupting capacities, potentially more than the initial fault level in the area. This is to avoid

frequent replacement every time there are new generation facilities nearby or new

transmission lines terminated at the station that contributes to higher fault level. The

Regulated Transmission Entity shall standardize on PCB sizes which will be a good strategic

method to minimize the number of spares that will be required.

The following is the limits specified for PCBs and shall not be exceeded:

Single-phase breaking current: 1.15 times 3 phase fault current

Peak breaking current: 2.55 times 3 phase root-mean-square (RMS) fault

current

Tap Changer

In order to determine whether capacitors are required to correct any voltage violations, all

transformers equipped with on-load tap changers should be adjusted to nominal rating. The

full range of the transformer taps should be available for the use of the system operator in

order to control the system voltages.

Voltage Control and Reactive Power Support

The Regulated Transmission Entity is not encouraged to use the reactive power capability of

generation facilities or the transformer tapping range to control system voltages in planning

studies. The use of shunt capacitors and shunt reactors should be considered to ensure

voltage limits are complied with during system healthy and contingency operation of the

transmission system.

The use of series compensation could be considered to increase voltage levels in long radial

networks. Static VAr compensators (SVCs) should be considered to provide dynamic voltagecontrol during system contingencies. The SVCs reactive capability should, however, not be

used during steady state operating conditions.

The reactive power capability of generation facilities and the tapping of transmission

transformers should only be used during N-1 contingencies and emergency situations and

should be viewed as operational supporting mechanisms rather than planning solutions.

For reactors the following planning criteria should be adhered to:

The size of switched reactors should be restricted to limit the change in system

voltage when any one unit is switched in or out of service. The voltage change shouldnot exceed three percent (3%) of the nominal voltage during system healthy condition

or five percent (5%) of the nominal voltage during single contingencies;


26/91


During minimum load and any one reactor out of service, the maximum continuous

system voltage should not be exceeded;

During minimum load and any one reactor out of service, the maximum reactive

power absorption capability of no generator unit may be exceeded; and

The steady state voltage at the line open end, resulting from energizing or tripping of a

transmission line circuit breaker during normal operating conditions, should notexceed the maximum continuous system voltage.

System Stability Limits

It is the objective of system stability simulations to analyze the stability of the transmission

system in a given time period. Consistent with Section 4.4.9.3 of the PGC, the maximum

clearing time per voltage level that shall be used for simulations in relation to grid planning

shall be as per the limits below. This is further explained in Section 4.7 of this guideline.

85 milliseconds (ms) for 500 kilovolt;

100 ms for 230 kV and 138 kV; and

120 ms for voltages less than 138 kV.

3.3.3 Power Factor Considerations

The power factor of the load has a major impact on the transmission system as it affects the

voltage profile and transmission losses. A bad power factor17

requires a high amount of

reactive power from the system. The Regulated Transmission Entity must either install

reactive devices to supply the MVArs for the load or buy reactive energy from the generation

facilities connected to the grid. The process of buying reactive energy is currently via Ancillary

Services Procurement Agreements between the Regulated Transmission Entity and interested

and qualified generation facilities; however, in the future ancillary services may already be

traded in the WESM. Even though, at this stage, power factor correction methods will be to a

certain extent an expensive exercise for the Regulated Transmission Entity, improving the

power factor at the loads will decrease the system losses and have a direct impact on

operating cost.

It is recommended that the Regulated Transmission Entity encourages the DUs and other

large customers to improve their power factor at the point of common coupling to values of

around 0.95 which is a typical practice in other jurisdictions.

Currently, the Regulated Transmission Entity utilizes the load power factors based on the

actual average power factor from the billing information of customers for purposes of

undertaking simulations.

3.3.4 Minimum and Peak Load Demand Considerations

The Regulated Transmission Entity has indicated that the minimum load demand in Luzon is

assumed to be 45% of the peak demand while for Visayas and Mindanao it is 60%. These

ratios according to the Regulated Transmission Entity are based from historical data, which

are then used to study the over-voltages during off-peak periods.

17A bad power factor is typically anything less than 0.95.


27/91


3.3.5 Planning for Disposal of Assets

At the end of the useful life of equipment, the Regulated Transmission Entity should undertake

a condition assessment in order to determine whether the equipment is required to be

replaced. It should be noted that assets should only be disposed when they can no longer be

economically justified and not because it has already reached the end of its useful life. In the

event that assets have already been identified for disposal based on the result of the condition

assessment, then such assets should be considered for replacement. It should however benoted that such projects, even if it is considered as a replacement project only, should still be

evaluated and documented in accordance with this guideline.

3.3.6 Planning for Generation

Power Plant location

It would be an ideal solution if the generation facilities could be located as close as possible to

the load which is in many cases is unattainable due to physical constraints or the specific

interest of investors. It is however recommended for the Regulated Transmission Entity to

make available the sites where incoming generation facilities can connect which entailsminimal transmission system reinforcement. In cases when the generation facility has already

decided on a location, the Regulated Transmission Entitys participation shall be in the

integration studies.

Embedded Generation

New embedded generation facilities will have an impact on the quality of supply, the fault

levels and stability of the grid and eventually on the operation, voltage control and operating

reserves. Thus, it is encouraged that embedded generation integration studies shall be a joint

effort among the relevant DU or large customer and the Regulated Transmission Entity.


28/91


4. TECHNICAL STUDIES

4.1 INTRODUCTION

This section provides guidelines for the different applicable studies that are required to be

performed as part of developing a transmission system plan. This guideline is established

specifically for developing a plan that will assist the Regulated Transmission Entity in theregulatory reset process but is also foreseen to aid in the development of the TDP. The

applicable studies described in this section include load flows (steady state analysis), transient

stability, voltage stability, small signal analysis, quality of supply, frequency stability and

switching studies.

4.2 DATA REQUIREMENT

Any technical study requires information describing assets to various levels of technical detail.

Below is a list of required data that shall be used in performing the required technical studies.

The following data requirement is also consistent with the requirements set in the PGC.

Historical energy and load demand data

Forecasted energy and load demand data

Generator unit data

o De-rated capacity (in Megawatt (MW));

o Additional capacity (in MW) obtainable from generating units in excess of net

declared capability;

o Minimum stable loading (in MW);

o Reactive power capability curve;

o Stator armature resistance;

o Direct axis synchronous, transient, and sub-transient reactances;

o Quadrature axis synchronous, transient, and sub-transient reactances;

o Direct axis transient and sub-transient time constants;

o Quadrature axis transient and sub-transient time constants;

o Turbine and generating unit inertia constant (in MW sec/MVA);

o Rated field current (in Ampere (A)) at rated MW and MVAr output and at rated

terminal voltage; and

o Short circuit and open circuit characteristic curves.

The following information for step-up transformers is required for each generating unit:

o Rated MVA;

o Rated Frequency (in Hertz (Hz));


29/91


o Rated voltage (in kV);

o Voltage ratio;

o Positive sequence reactance (maximum, minimum, and nominal tap);

o Positive sequence resistance (maximum, minimum, and nominal tap);

o Zero sequence reactance;

o Tap changer range;

o Tap changer step size; and

o Tap changer type (on load or off circuit).

The following excitation control system parameters is required for each generating

unit:

o

Direct current (DC) gain of excitation loop;

o Rated field voltage;

o Maximum field voltage;

o Minimum field voltage;

o Maximum rate of change of field voltage (rising);

o Maximum rate of change of field voltage (falling);

o Details of excitation loop described in diagram form showing transferfunctions of individual elements;

o Dynamic characteristics of over-excitation limiter; and

o Dynamic characteristics of under-excitation limiter.

The following speed-governing system parameters is required for each reheat steam

generating unit:

o High pressure governor average gain (in MW/Hz);

o Speeder motor setting range;

o Speed droop characteristic curve;

o High pressure governor valve time constant;

o High pressure governor valve opening limits;

o High pressure governor valve rate limits;

o Re-heater time constant (active energy stored in re-heater);

o Intermediate pressure governor average gain (in MW/Hz);


30/91


o Intermediate pressure governor setting range;

o Intermediate pressure governor valve time constant;

o Intermediate pressure governor valve opening limits;

o Intermediate pressure governor valve rate limits;

o Intermediate pressure governor loop; and

o A governor block diagram showing the transfer functions of individual

elements.

The following speed-governing system parameters is required for each non-reheat

steam, gas turbine, geothermal, and hydro generating unit:

o Governor average gain;

o Speeder motor setting range;

o Speed droop characteristic curve;

o Time constant of steam or fuel governor valve or water column inertia;

o Governor valve opening limits;

o Governor valve rate limits; and

o Time constant of turbine.

The following plant flexibility performance data is required for each generation facility:

o Rate of loading following weekend shutdown (generating unit and generation

facility);

o Rate of loading following an overnight shutdown (generating unit and

generation facility);

o Block load following synchronizing;

o Rate of load reduction from normal rated MW;

o Regulating range; and

o Load rejection capability while still synchronized and able to supply load.

The following auxiliary load demand data is required:

o Normal unit-supplied auxiliary load for each generating unit at rated MW

output; and

o Each generation facility auxiliary load where the station auxiliary load is

supplied from the grid.

General grid data required:


31/91


o The electrical diagrams and drawings are required to indicate the quantities,

ratings, and operating parameters of the following:

Equipment (e.g., generating units, power transformers, and circuit

breakers);

Electrical circuits (e.g., overhead lines and underground cables);

Substation bus arrangements;

Grounding arrangements;

Phasing arrangements; and

Switching facilities.

o The following circuit parameters are required:

Rated and operating voltage (in kV);

Positive sequence resistance and reactance (in ohm);

Positive sequence shunt susceptance (Siemens or ohm-1);

Zero sequence resistance and reactance (ohm); and

Zero sequence susceptance (Siemens or ohm-1).

o The following data is required for a step-up and power transformers:

Rated MVA;

Rated voltages (kV);

Winding arrangement;

Positive sequence resistance and reactance (at max, min, and

nominal tap);

Zero sequence reactance for three-legged core type transformer;

Tap changer range, step size and type (on-load or off-load); and

Basic lightning impulse insulation level (in kV).

o The following information is required for the switchgear, including circuit

breakers, load break switches, and disconnect switches:

Rated voltage (in kV);

Rated current (in A);

Rated symmetrical RMS short-circuit current (in kA); and

Basic lightning impulse insulation level (in kV).


32/91


o The following data on independently-switched reactive power compensation

equipment is required:

Rated capacity (in MVAr);

Rated voltage (in kV);

Type (e.g., shunt inductor, shunt capacitor, SVC); and

Operation and control details (e.g. fixed or variable, automatic, or

manual).

o The following data is required if a customers load demand may be supplied

from alternative connection point(s):

The alternative connection point(s);

The demand normally supplied from each alternative connection

point;

The demand which may be transferred from or to each alternative

connection point; and

The control (e.g., manual or automatic) arrangements for transfer

including the time required to affect the transfer for forced outage and

planned maintenance conditions.

The data requirement specified in Section 4.2 is required, where relevant, if a distribution

system (or other customer or end-user system) has embedded generation facilities and

significantly large motors. The short circuit contribution of the embedded generating units and

the large motors at the connection point shall be provided by the DU (or the other customer or

end-user). The short circuit current shall be calculated in accordance with the IEC Standards

or any equivalent national standards.

4.3 LOAD FLOW STUDIES

Load flow studies are typically conducted using a computer simulation package (e.g. Power

System Simulator for Engineering (PSS/E)) with a valid study file containing the grid model.

The purpose of the study is to determine whether an existing or reinforced system can satisfy

the voltage and current limits, under steady state conditions, when the system is healthy or

when one or more components are out of service.

4.3.1 Minimum Data Requirements

To be able to compare a proper load flow scenario the following data is required at a

minimum:

Load forecast for peak and light load at each substation

Positive sequence parameters for all equipment:

o Resistance;

o Reactance;


33/91


o Susceptance;

o Line length; and

o Rating of equipment.

Generation patterns and constraints

4.3.2 Criteria and Study Scenarios

Load flow studies should be conducted for the following network conditions:

a) annual peak load, typical generation pattern with peaking plant in generation mode;

and

b) light load scenario (the minimum load given by the load forecast) and generation

scaled down to light load scenarios.

The grid should be studied for healthy conditions and for N-1 contingencies. N-2 or greater

contingencies (including generation contingencies) will only be investigated when it isconsidered likely that a valid business case will exist to justify the additional capital

expenditure to address them.

For light load conditions, the system is only studied for healthy conditions as maximum

voltages are likely to occur with all lines in service. Potentially, the only contingency condition

that could increase the voltage is the loss of a shunt reactor or the loss of load. Furthermore,

if there is shunt reactors in the system under investigation, studies must still be conducted to

ensure that no unacceptable over-voltages will occur.

Each network scenario should include a calculation of system losses which will typically form

part of the financial justification of the project.

4.3.3 Load Assumptions

Since individual loads peak at different times, the total system maximum demand at time of

system peak (TOSP) is less than the sum of the individual peak loads. To obtain realistic

generation conditions and average loading and losses in studies of the overall transmission

system, each individual peak load is scaled down by a diversity factor such that the total load

on the generation facilities matches the forecasted load for the total system. The adjusted

loads are known as diversified maximum demands.

For studies of selected areas in the system (regions or islands), individual loads should beadjusted such that the total load in that area matches the actual or expected maximum value.

It is probable that these values will occur at a time different from the TOSP.

For studies where the supply to only one specific load point or customer is being investigated,

the actual undiversified peak value of this load or substation should be used.

For light loading scenarios the minimum load must be based on historical data for each grid,

e.g.:

Luzon 45% of system peak

Visayas 60% of system peak


34/91


Mindanao 60% of system peak

4.3.4 Generation Assumptions

The Regulated Transmission Entity is currently undertaking studies using the dispatch

scenarios for Luzon, Visayas and Mindanao as set out below. These have been reviewed and

assessed to be acceptable and is therefore recommended to be used in the conduct of load

flow studies.

Luzon

The following generation dispatch conditions shall be used:

Maximum North-Wet (all generation facility outputs in the northern part of the grid are

set to their maximum capacities)

Maximum South-Dry (all generation facility outputs in the southern part of the grid are

set to their maximum capacities)

Typical scenario (generation facility outputs are based on the typical output levels of

plants during system peak load).

The above scenarios shall ensure that regardless of dispatch combination, the N-1

compliance of the grid is assessed for all possibilities. Additional scenarios are also currently

being considered by the Regulated Transmission Entity for particular study areas where

varying dispatch output of associated generation facilities could result in additional

transmission system constraints.

Visayas

The following generation dispatch conditions shall be used:

Maximum Leyte Scenario (the geothermal generation facilities in Leyte are maximized

while the generation facilities in Panay serve as regulating plants; the power plants in

Cebu, Negros and Bohol are maximized)

Maximum Panay Scenario (the generation facilities in Panay are maximized while the

geothermal generation facilities in Leyte serve as regulating plants; the generation

facilities in Cebu, Negros and Bohol are maximized).

For the Visayas dispatch scenarios above, the following general considerations shall be

observed:

Base load generation facilities are priority dispatch over peaking generation facilities.

In case base load generation facilities are already sufficient to supply the entire load

requirement of the Visayas grid, which is mostly the case upon entry of additional

generation facilities, all peaking plants are assumed to be offline;

Intermittent generation facilities are assumed either at full dispatch or offline

depending on which is the worst scenario; and

Embedded generation facilities are assumed online until the end of their bilateral

contract.

Mindanao


35/91


The generation dispatch scenario that shall be used for Mindanao is the Maximum North

Scenario. This scenario shall be used to guarantee the adequacy of transmission lines that will

deliver power to the South and Northwestern Mindanao areas during contingencies. The

assumption for the scenario is that the power, especially those coming from hydro-electric

generation facilities are maximized thereby stressing the highest loading to the transmission

lines that supply power to the load centers i.e. Davao and General Santos.

4.4 SHORT CIRCUIT STUDIES

Fault level studies should be done for a number of reasons as listed below:

Any new planned grid reinforcement requires a fault level analysis to determine if fault

level values are going to exceed the ratings of existing equipment such as circuit

breakers, current transformers (CTs), or other switchgear and busbars;

For relevant new assets, appropriate fault ratings are determined by fault level studies

which should consider planned projects including generation which may have an

impact on the fault level in future. This is to ensure that new equipment is not required

to be replaced due to rising fault level increases in the short term;

Studies for the connection of new voltage waveform distorting load (e.g. arc furnaces,

mine winders, etc.) or switching of large motors require that the minimum credible

fault level is determined;

Fault level studies should be performed as an input to calculating protection settings.

This is to ensure that protection relays operate correctly in response to faults;

Fault level studies should be performed for high voltage direct current (HVDC)

termination points in the network to determine the relative maximum size of a

converter station when conventional HVDC is considered; and

Fault level studies should be performed to determine the maximum size of shunt

devices at a specific location.

Overview studies of fault levels throughout the system only require the calculation of three (3)

phase fault levels (using only the positive sequence network). Generation facilities should be

represented by a voltage of 1 per unit (pu) behind a saturated sub-transient reactance and all

transformers by their reactances on nominal tap. The Regulated Transmission Entity shall

consider the scenario of all generation facilitiesonline to get the most conservative values.

When higher accuracy is required, fault studies should follow a load flow study in which themagnitude and angle of the generation facility voltages behind transient reactances are

derived and the appropriate tap positions and reactances of the various transformers are

calculated. To determine maximum possible fault levels, all existing generation facilities (even

small generation units) should be in service and active.

Single phase fault analysis requires setting up the negative and zero sequence parameters in

addition to the positive sequence parameters in the PSS/E model. Furthermore, the

grounding setup for transformers needs to be accurately modeled. It is noted that, if

transformers are solidly earthed a single phase fault level can exceed three (3) phase levels in

certain scenarios.


36/91


Circuit breakers that exceed rupturing capacity18

and other assets for which technical

limitations have been breached should be replaced to avoid risk of damage to assets and

personnel. As an interim solution, or permanent solution at the expense of operational

flexibility, the assets which were identified to be replaced could be operated by reducing fault

in-feeds19

instead of replacing these assets. This reduction in fault in-feeds can be done by

splitting busbars, adding fault limiting reactors, or bypassing the over-stressed bus with certain

lines. It is important to note that the above solution is an operational solution and not a

planning solution and the solution is therefore not viewed as a medium to longer term solution

when planning the network.

Fault level revisions should be communicated to customers whenever an expansion plan is

expected to have a significant impact on fault levels. Communicating to customers in a timely

manner will allow customers the opportunity to take necessary action to ensure their

equipment can withstand the revised fault levels.

To determine the minimum credible fault level at a particular point of the transmission system,

a fault level study is performed with a load flow solution including the most onerous

contingency (N-1) or as appropriate. The values obtained is used to determine if a large motor

can be started; or if additional reinforcement is required to raise the fault level sufficiently to

start the motor; or the customer could be advised that a soft motor starting system should be

installed. In general, this is more of a consideration for DUs than the Regulated Transmission

Entity, unless a customer is connected directly to the grid.

4.5 SWITCHING STUDIES

Load flow studies are typically used to calculate the initial and final steady state voltages when

lines, capacitors, reactors or loads are switched. On the other hand, switching studies

contribute to the decision making of the size and location of equipment such as capacitors and

reactors. Line reactors are tested to ensure that transmission lines can be energized without

exceeding voltage limits when a reactor is in service. These studies should be conducted to

ensure that the voltage change is less than three percent (3%) when switching shunt

capacitors in and out or when switching interruptible loads. A typical value of 5% can be used

during single contingencies in the network.

For switching studies, variable MVAr devices are allowed to operate normally, but transformer

taps are fixed and no switching of shunt capacitors or reactors is allowed.

Dynamic switching studies, to determine instantaneous voltages after a switching operation

may be required for insulation coordination. These studies require the use of dynamic

programs (travelling wave, electro-magnetic transient programs etc.) and are generally theresponsibility of the generation facilities (however, the Regulated Transmission Entity may

participate in such studies).

4.6 VOLTAGE STABILITY

Voltage stability refers to the ability of a system to maintain steady voltages at all buses in the

system, from a given initial operating condition, after being subjected to a fault or disturbance.

Voltage stability depends on the ability of the system to maintain equilibrium between load

supply and load demand. Voltage instability occurs in the form of a progressive rise or fall of

18 Rupturing capacity or breaking capacity expresses the current that a circuit breaker is capable of breaking at a givenrecovery voltage under certain set conditions of operation.19

Fault in-feeds refer to fault current flowing into the transmission system linked directly to an asset or assets.


37/91


voltages of some buses and may lead to the loss of load in an area, tripping of transmission

lines and other elements by their protection circuits. These outages may lead to more

outages that in turn may lead to loss of synchronism or activation of the under field current

limit protection of some generation facilities.

At transmission voltages (higher voltages), the voltage drop at the receiving end is mainly

caused by the flow of reactive power through the reactance of the transmission system. The

reactive power flow in the system will be reduced if reactive power is supplied at the receivingend. This is typically achieved by means of e.g. shunt capacitors, SVCs, generation facilities,

synchronous condensers or some flexible AC transmission system (FACTS) devices.

Generation facilities, synchronous condensers and SVCs are variable reactive power or MVAr

sources and could be used to supply reactive power and to keep the voltage more constant.

The maximum angle, as measured between two directly connected substations, should

preferably not exceed 45oor 50

o.

The voltage stability limit can be established for any given system by carrying out load flow

studies with progressively increased loads until the load flow fails to converge20

. The power

flow just before the point of non-convergence is assumed to be the maximum power that can

be supplied before the voltage collapses. It would be impractical to attempt to operate the

system at this point since small load variations are bound to occur. In practice, the maximum

power transfer should be restricted to a value of typically ten percent (10%) below the

maximum value (knee-point of the power voltage-curve).

The maximum power transfer is limited either by voltage collapse or by an unacceptably low

receiving end voltage as follows:

ten percent (10%) less than the power level corresponding the point of non-

convergence as described above, or

the power which causes the receiving end voltage to reach the minimum

recommended value.

When an SVC is available in the area of study, the SVC dynamic range should not be used

completely to determine the steady state transfer capability. The maximum power transfer

should be limited to the point before the SVC starts to operate outside its normal steady state

position.

The Regulated Transmission Entity should look at the following equipment to improve the

voltage collapse limit of the transmission system:

Shunt capacitor banks to improve receiving end voltages;

Series capacitor banks to reduce line impedance and effectively increase receiving

end voltages. Series capacitor banks also increase the Surge impedance loading

(SIL) of a transmission line; and

Transmission lines as a more expensive solution to reduce system impedance.

20Being able to converge is the term used to explain that the load flow software found a numeric solution to the network model

which indicates that the solution modelled appear viable from a numeric perspective. Fails to converge is the term used toexplain that the load flow software did not find a numeric solution to the network model which indicates that the solutionmodelled appear not to be viable from a numeric perspective.


38/91


4.7 TRANSIENT STABILITY

The grid relies on synchronous machines for generation of electrical power and a necessary

condition for satisfactory system operation is that all synchronous machines remain in

synchronism. Transient stability is the ability of the system to maintain synchronism when

subjected to a severe fault or disturbance, such as a short circuit on a transmission line. The

resulting system response involves large excursions (oscillating or alternating motion away

from a point of equilibrium) of generator rotor angles and is influenced by the nonlinear power-angle relationship. Transient stability in this regard relates to first swing stability of the

transmission system.

4.7.1 Minimum Data Requirements

The following data is required to perform transient stability analysis:

Load flow case file representing the pre-fault state of the system;

Dynamics data file representing the dynamic behavior of each dynamic component;

and

Sequence of events.

The following items must be included in the dynamics data file to perform transient stability

simulations as the equipments dynamic behavior may influence the results:

Generation facilities;

Excitation systems;

Power system stabilizers (PSS);

Governors;

Loads; and

SVCs or HVDC or synchronous condensers (SCOs) or FACTS devices.

4.7.2 Criteria

Study scenarios

The characteristics of the transmission system should be such as to maintain stabilityfollowing:

A three phase line or busbar fault, cleared in normal protection times, with the system

healthy and the most onerous system loading condition;

A single phase fault cleared in bus trip times21

, with the system healthy and the most

onerous system loading condition; and

21Bus trip time is the time that the bus zone protection will take to strip a busbar when required due to a specific fault condition

and will differ from substation to substation.


39/91


A single phase fault cleared in normal protection times, with any one line out of

service and the generation facility loaded to average output.

Fault Clearing Times

The fault clearing time is defined as the time it takes for the protection equipment to clear or

remove the fault from the power system to allow normal operation to proceed. Typical fault

clearing times for the protection installed in the power system are as per the table below:

Table 1: Typical Clearing Times

TYPE OF FAULT 500kV 138 kV - 230kV


40/91


Faults that change the topology of the transmission system, change the system reactance and

alter the power-angle relationships of generation facilities shall be applied. These faults are

considered to have the most onerous impact on system stability and are specified as follows:

A three-phase zero impedance line-end fault cleared by tripping the faulted line;

A three-phase busbar fault cleared by tripping the relevant outlets from the associated

busbar;

Loss of generation;

Loss of major load; and

Loss of tie-lines.

As a note, three-phase faults are considered to have the most onerous impact on the system

from a transient stability point of view compared with that of a single phase faults.

Output Parameters

The following output parameters are not specific to transient stability results and contain

typical output parameters for any kind of stability study. The analysis of the output channels

(or variables that provide the resulting values from the study) allows the Regulated

Transmission Entity to differentiate between the different stability phenomena. The following

outputs are useful when interpreting the outcome of any stability analysis and can typically be

plotted relative to time.

Relative Rotor Angle and Speed: This information is used to determine whether the

machines(s) would remain in synchronism or not (pole-slip) following a fault. These

plots provide an indication of how the machines in an area are oscillating with respectto each other. The rotor angle variable output is used in assessing the magnitude and

duration of post-fault power system oscillations.

Generation Real Power: The real power variable output is used to determine whether

or not the power output of the generating unit is less than zero which would indicate

that the generating unit acts as a motor. In this event, the inverse power relay settings

should be examined to determine whether this would result in unit tripping. Typically,

an indication of oscillation frequencies and system damping can also be obtained from

these variable outputs.

Generation Reactive Power: The generation reactive power variable output is usedto determine whether or not the reactive power output will be sufficiently damped and

return within the continuous rating of the machine. Insufficient steady state voltage

support exists if the reactive power fails to recover within the continuous rating.

Bus Voltage: Variable output for bus voltages provide information on whether

machines remain in synchronism or not. The bus voltage variable output is useful in

assessing the magnitude and duration of post-fault voltage dips and peak-to-peak

voltage oscillations. Furthermore, these variable outputs provide an indication of

system damping and the level to which voltages are expected to return to its steady

state value.


41/91


Bus Frequency: The bus frequency variable output provides the magnitude and

duration of the post-fault frequency decline or increase in the transmission system,

especially during loss of load or generation.

Line Flows: The line flow variable output provides information on the magnitude of

the post-fault active and reactive power swings on transmission lines. Furthermore, it

provides information on transient power exchange and the occurrence of possible out-

of-step conditions between two grids or islands. As a note, when large powerreversals occur on transmission lines, out-of-step conditions may be evident.

Accelerating Power: The accelerating power variable output provides information

regarding the dynamic response of the prime mover system (turbine and governor

control system) of the machine. It also provides information on whether the machine

would remain in synchronism or not following a fault.

Generator Field Voltage: The generator field voltage variable output provides

information on the dynamic response of the exci

Draft Transmission Planning Guideline Mar 2012

Documents

Transcript of Draft Transmission Planning Guideline Mar 2012