A

PROJECT REPORT

ON

Transmission Management by Determining

ATC between Different Zones

By

Venutathipathi

Under the guidance of

Prof. D. M. Vinod KumarDept. of Electrical Engg.

NIT Warangal,Warangal.

DEPARTMENT OF ELECTRICAL ENGINEERING

NATIONAL INSTITUTE OF TECHNOLOGY

WARANGAL – 506 004

ANDHRA PRADESH

INDIA

2011

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DEPARTMENT OF ELECTRICAL ENGINEERING

NATIONAL INSTITUTE OF TECHNOLOGY

WARANGAL-506004

Certificate

This is to certify that the mini project entitled “Transmission Management

by Determining ATC between Different Zones” which is submitted by

murali kandakatla in the partial fulfillment of the requirement for the award of

degree of M.Tech in Power Systems at NIT Warangal has been carried out by

him under my supervision and guidance. The matter embodied in this work has

not been submitted for the award of any other degree

Professor & Head Prof. D. M. Vinod Kumar

Dept. of Electrical Engineering, Dept. of Electrical Engineering,

National Institute of Technology, National Institute of Technology,

Warangal. Warangal.

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iii

Acknowledgement

Success of any work depends upon the dedication, sincerity and hard work. It also

requires some ingredients such as motivation, guidance, encouragement and time.

Whole hearted effort altogether makes the project useful and meaningful.

I am highly grateful to Prof. D. M. Vinod Kumar, NIT Warangal for his continuous

guidance and inspiration in the successful completion of my work.

Finally, I would like to thank all the members, for their continuous motivation in the

success of my mini project work.

(venu thathipathi)

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Abstract

The goal of deregulation in power industry is to enhance competition and to bring new

choices and economical benefits to consumer. The process has necessitated reformulation

of established models of power system operation and control activities. As a consequence

several issues such as system control, security, transmission management, optimal

bidding has came up.

Congestion management is one of the most challenging aspects in a multi buyer / multi-

seller system. For managing congestion, three different methods of accomplishing the

task a) Optimal Power Flow (OPF) model b) price area congestion model and c) US

transaction based Availability Transfer Capability (ATC) model are incorporated. Each

maintains power system security but differ in its impact on the economics of energy

market.

In a competitive power market the task of an Independent System Operator (ISO) is to

ensure full dispatch of the contracted power. However, if it causes the line flows

exceeding their limits, thus treating the system security, the ISO makes decision on the

curtailment of the contracted power.

With the further development of power markets, large amount of electric power wheeling

and frequent transmission transaction emerging, accurately determining ATC and

broadcasting this information in time are very important to prevent and relieve

transmission congestion effectively. In practical power markets, there are large amount of

uncertainties involved in Transmission Reliability Margin (TRM) and Capacity Benefit

Margin (CBM) of ATC. In this work the ATC is calculated and compared using three

different methods, dc distribution factors, ac distribution factor and ac load flow.

The mini project work is intended to demonstrate the aforementioned models on the

IEEE-24 bus (RTS). The simulation studies were conducted with the help of MATLAB

coding.

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Table of Contents

Acknowledgement..............................................................................................................iv

Abstract................................................................................................................................v

1. Power System Deregulation.......................................................................................1

1.1 Introduction.............................................................................................................1

1.2 Vertically Integrated Electrical Utility (VIEU)......................................................1

1.2.1 Need for regulation...........................................................................................1

1.2.2 Features of VIEU.............................................................................................2

1.2.3 Demerits of VIEU............................................................................................2

1.3 Deregulated electrical power industry....................................................................3

1.3.1 Need for Deregulation......................................................................................5

1.3.2 Benefits of deregulated power system.............................................................5

1.3.3 The Market place mechanisms.........................................................................5

1.3.4 Market models..................................................................................................6

1.3.5 ISO activities in Bilateral Market.....................................................................6

1.3.6 Pool operator activities in Pool market............................................................7

1.3.7 Issues involved in Deregulation.......................................................................7

1.4 Conclusion..............................................................................................................7

2. Transmission Congestion management......................................................................8

2.1 Introduction.............................................................................................................8

2.1.1 Definition of congestion...................................................................................8

2.1.2 Importance of congestion management in deregulated structure.....................9

2.1.3 Effects of congestion........................................................................................9

2.2 Congestion management methods........................................................................11

2.3 Conclusion............................................................................................................11

3. Available Transfer Capability (ATC) Based Congestion Management...................12

3.1 Introduction...........................................................................................................12

3.1.1 How the transfer capability is limited............................................................13

3.1.2 ATC definitions..............................................................................................14

3.1.3 ATC principles...............................................................................................15

3.2 Methods of calculation of ATC............................................................................16

3.3 ATC calculation using PTDF...............................................................................16

3.3.1 Power Transfer Distribution Factor (PTDF)..................................................16

1

3.3.2 Calculation of PTDF using DC power flow model........................................17

3.3.3 Calculation of PTDF using AC power flow model........................................18

3.3.4 Algorithm for ATC Determination using DC PTDF.....................................18

3.3.5 Algorithm for ATC determination using AC PTDF......................................19

3.5 ATC calculation using Continuation Power Flow method...................................22

3.7 Case studies...........................................................................................................23

3.7.1 IEEE Reliability Test System (RTS)..............................................................25

3.8 conclusions………………………………………………………………………..26

3.9 references…………………………………………………………………………...27

Appendix- test systems…………………………………………………………………..28

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1. Power System Deregulation

1.1 Introduction

Electrical power industry has been dominated by large utilities that have overall

authorities overall activities in generation, transmission and distribution of power refer to

as vertically integrated utilities. During the nineties many electrical utilities and power

network companies world wide have been forced to changed their ways of doing business

from vertically integrated mechanism to open market system. This kind of process is

called as deregulation or restructuring.

Deregulation word refers to un-bundling of electrical utility or restructuring of

electrical utility and allowing private companies to participate. The aim of deregulation is

to introduce an element of competition into electrical energy delivery and thereby allow

market forces to price energy at low rates for the customer and higher efficiency for the

suppliers.

1.2 Vertically Integrated Electrical Utility (VIEU)

VIEU is referred as Regulated Electrical Power Industry.

Regulation means that the Government has set down laws and rules that put limits on and

define how a particular industry or company can operate.

1.2.1 Need for regulation

1. Risk free way to finance the creation of electric industry

2. Recognition and support from local government to utilities

3. Assured return on investments

4. Establishment of local monopoly

In Figure 1-1 shows the basic structure of regulated power system, in which one

controlling authority-the utility-operated the generation, transmission and distribution

systems located in a fixed geographic area.

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Figure 1-1: Basic structure of VIEU

1.2.2 Features of VIEU

1. Overall authority, overall activities in generation transmission distribution of

power utility lie within its domain of operation.

2. VIEU will be the only electricity provider ion the region and it has obligation to

provide electricity to every one in the region.

3. Information flow is a bilateral one between generation and transmission system

but money flow was unidirectional.

1.2.3 Demerits of VIEU

1. It was often difficult to regulate the cost incurred in generation transmission and

losses occurred in distribution.

2. Losses occurred in distribution is accounted by spreading the cost over all three

components. Hence utilities often charged their customers at an average tariff

depending upon their aggregated cost during the particular period.

3. The prices setting is done by an external regulator agency often involved

considerations other than economics. (Political party interferences or government

policies on new issues etc.)

4. The main objective of VIEU is to minimize the total cost while satisfying all the

associated problems and constraints, but this leads to complex operation issues

because of the big size VIEU. Further VIEU needs centralized planning for long-

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Competitive

Generation

Market

Multiple sellers

Competitive

Retail market

Multiple Buyers

Transco & Disco

term generation, transmission expansion, midterm planning activities such as

maintenance, production scheduling, fuel scheduling for optimal cost.

In spite of all the above demerits VIEU have performed satisfactorily over the long years

with respect to operation, control and planning. But after 1990 there has been very big

mismatch between the growth of the load and the generation expansion. This has led to

ineffective operation of the system. Hence the concept of deregulation has been mooted.

When the generation, transmission and distribution system control are separated in terms

of management and ownership, the power system is said to be deregulated.

1.3 Deregulated electrical power industry

Deregulation in power industry is a restructuring of the rules and economic incentives

that governments set up to control and drive the electric power industry.

Figure 1-2: Unbundling the system

Figure 1-3: Typical configuration of restructured or deregulated power system

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Competition Regulated monopoly Competition

Figure 1-4: The competition

ISO

ISO was appointed for the whole system and its main responsibility is to keep the system

in balance. i.e.,

Imports + productions = Exports + Consumption + losses.

Thus ISO must be an independent authority without any involvement in market

competition. But it validates all the transactions before the actual operation takes place

from the point of view of security of the systems, congestion management, real time

operation etc.

Responsibilities of Independent System Operator

1. System security and reliability

2. Power delivery

3. Transmission pricing

4. Service quality assurance

5. Promotion of economic efficiency and equity

6. Fair market

Market trader/Market operator (Retailer)

Market operator is an entity in the de-regulated environment and is responsible for the

operation of market trading of electricity. He receives the bid offers from various market

participants and determines the markets price based on certain criteria in accordance with

the market structure.

1.3.1 Need for Deregulation

1. To provide cheaper electricity.

2. To offer greater choice to the customer in purchasing the economic energy.

3. To give more choice of generation.

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4. To offer better services w.r.t power quality i.e. Constant voltage, constant freq.

and uninterrupted power supply.

1.3.2 Benefits of deregulated power system

1. Cheaper electricity.

2. Efficient capacity expansion planning at GENCO level, TRANSCO level and

DISCO level.

3. Pricing is cost effective rather than a set tariff.

4. More choice of generation.

5. Better service is possible.

1.3.3 The Market place mechanisms

Table 1-1: Comparison Between different Mechanisms

Type of system No. of buyers Buyers know sellers? All buyers pay same price?

Pool co One Yes Yes

Bilateral exchange Many Yes No

Power exchange Many No Yes

1.3.4 Market models

Two types of market models in deregulated market

1. Pool model

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Market place

Mechanisms

* only one buyer *Multi seller/Multi buyer *Operates like stock exchange

Bilateral

exchange

Power

exchangePool Co

2. Open access model

Table 1-2: Comparison between market models

Open Access Pool

Bulk of the energy transactions are carried

out as bilateral trades while there may also

exist a day ahead spot market

All energy transactions are carried out

through the pool, which may be organized

through a day ahead trading mechanism.

The ISO is responsible for market

administration, generation scheduling or

dispatch functions.

The pool co operator is responsible for the

market settlements, unit commitment (UC)

and determination of pool price.

Participation in the market by gencos is not

mandatory

Participation by gencos is mandatory

The ISO is responsible for system security

and control, procuring necessary ancillary

services.

The pool co operator is responsible for

system security and control, procuring

necessary ancillary services.

Example: Nordic Markets Example :UK Market

1.3.5 ISO activities in Bilateral Market

24 Hours Ahead

1. ISO is informed of all hour-by-hour transactions that are to take place the next

day. The transaction can either be decided by independent market operator based

on bidding mechanism, or through bilateral contract. ISO is not involved in these

processes.

2. ISO then carries out load flow studies and other simulations based on load

forecast, availability of transmission capacity to check system security level.

In real time

1. Monitors system power flows, frequency and voltage and trades interact with

regional networks.

2. Power imbalances are corrected.

After real-time

1. Settlement of accounts and payments for ancillary service providers like reactive

power supporters.

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1.3.6 Pool operator activities in Pool market

24 Hours ahead

1. Carry out load forecast to determine aggregate hourly load demand for the next

day.

2. Receive bids from GENCOs. Based on this information, simulate hourly dispatch

and evaluate system price for each hour of next day.

3. Formulate nodal marginal costs and congestion transmission prices.

In real-time

1. Dispatch generation and load.

2. Procure and provide for system services such as reactive power support, frequency

regulation etc.

3. Do OPF calculation in case of probable congestion situation.

After real-time

1. Calculate the settlements, nodal prices of energy and transmission congestion

surcharges.

1.3.7 Issues involved in Deregulation

Network congestion

Optimal bidding for GENCO

Transmission pricing

Ancillary services management

1.4 Conclusion

This chapter gives an overview of the conventional VIEU and the modern deregulated

power system and contrasts them. Different market models of the deregulated power

system and various issues involved with it are discussed.

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2. Transmission Congestion management

2.1 Introduction

The objective of deregulation in power industry is to enhance competition and

bring new choice and economic benefits to consumers. The process has necessitated

reformulation of established models of power system operation and control activities. As

a consequence several such as system control, security, transmission management and

optimal bidding has come up.

Congestion management [1] is one of the most challenging aspects in a multi-

buyer/multi-seller system. In the vertically integrated utility structure, all the entities such

as generation, transmission and distribution are with in the domain of central energy

management system. Generation is dispatched in order to achieve the system least cost

operation. In such systems, congestion management is usually taken care of by

determining optimal dispatch solution using a model similar to the optimal power flow or

the security constrained economic dispatch problem. This effectively means that a

generation pattern is determined such that the power flow limits on the transmission

system are not exceeded.

This is not so simple in case of deregulated environment. Suppose under

deregulation, every buyer want to purchase cheap hydropower which is available in

northern region of state, buyer we want to lower their cost purchase all the can get even if

they are to far south. If too many sales of such types are made, the transmission system of

a state would overload.

2.1.1 Definition of congestion

Congestion [1] means, “When the producer and consumer of the electrical energy desire

to produce and consume in amounts that would cause the transmission system to operate

at or beyond one or more transfer limit, the system is said to be congested”

Whenever the physical or operational constraints in a transmission network

become active, the system is said to be in a state of congestion. The possible limits that

may be hit in a case of congestion are: line thermal limits, transformer emergency ratings,

bus voltage limits, transient or oscillatory stability limits. These limits constrain the

amount of electric power that can be transmitted between two locations through a

transmission network. Flows should not be allowed to increase to levels where a

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contingency would cause the network to collapse because of voltage instability etc. in a

deregulated structure, the market/s must be modeled so that the market participants

(buyers and sellers of energy) engage freely in transaction and play as per market forces,

but in a manner that does not threaten the integrity of the power system. Thus irrespective

of the market structure in place, congestion management is has universally become an

important activity of power system operators. Universally the dual objectives of

congestion management have been to minimize the interference of the transmission

network in the market for electrical energy and to simultaneously ensure secure operation

of the power system.

In the deregulated power system, the challenge of congestion management for the

transmission system operator is to create a set of rules that ensure sufficient control over

producers and consumers to maintain an acceptable level of power system security and

reliability in both the short term (real time operation) and the long term (transmission and

generation construction) while maximizing market efficiency.

2.1.2 Importance of congestion management in deregulated structure

Kirchoffs’ law combined with the magnitude and the location of the generation

and loads, the line impedances and network topology determine the flow on each line.

The power system security constraints may therefore necessitate a change in the generator

schedule away from the most efficient dispatch. In the traditional vertically integrated

utility environment, the generation patterns are fairly stable and the transmission network

expansion could be planned along with the construction of new generation facilities.

Congestion is usually in frequent in such scenarios and the flow patterns are quite

predictable too. However, in deregulated structures, with generating companies

(GENCOs) competing in an open transmission access environment, the generation / flow

patterns can change drastically over small time periods with the market forces. In such

situations, it becomes necessary to have a congestion management scheme in place to

ensure that the system stay secure.

2.1.3 Effects of congestion

In multi-seller / multi-buyer the operator faces additional problems with congestion.

Some of these can be enlisted as follows:

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1. Forces change generating schedules so that some GENCOs raise and others

reduce output until congestion is eliminated. In pool structure, where central

dispatch is done, Pool co operator has to look after this.

2. Operator compensates the parties who were asked to generate more, paying them

for additional power production and giving lost opportunity payments to parties

who were ordered to cut back.

3. Raising transmission prices during congestion, by collecting congestion fees to

compensate affected GENCO in above point.

Example problem [1]

Effect of network congestion is explained by using simple two-zone system

connected by an interface, shown in Fig. 1.

$10/MWh $20/MWh

200MW 0 MW

100 MW

100 MW 100 MW

Figure 2-5: Two Zone system (No Congestion)

$10/MWh $20/MWh

150MW 50 MW

100 MW 100 MW

50 MW

Figure 2-6: Two Zone system (with 50MW Transfer limit)

Let each zone have a 100 MW constant load. Zone A has a 200 MW generator

with an incremental cost of $10/MWh. Zone B has a 200 MW generator with an

incremental cost of $20/MWh. Assume both generators bid their incremental costs. If

there is no transfer limit between zones, all 200 MW of load will be bought from

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A B

A B

generator A at $10/MWh, at a cost of $2000/h, as shown in Fig. 1(a). If there is a

50MWtransfer limit, then 150MW Will be bought from A at $10/MWh and the remaining

50 MWh must be bought from generator B at $20/MWh, a total cost of $2500/h.

Congestion has created a market inefficiency of 25% of the optimal costs, even without

strategic behavior by the generators. Congestion has also created unlimited market power

for Generator B. B can increase its bid as much as it wants, because the loads must still

buy 50 MW from it. Generator B’s market power would be limited if there was an

additional generator in zone B with a higher incremental cost, or if the loads had nonzero

price elasticity and reduced their energy purchase as prices increased. In the real power

system, cases of both limited and unlimited market power due to congestion can occur.

Unlimited market power is probably not socially tolerable.

2.2 Congestion management methods

Tackling the congestion problem takes different forms in different countries. It

really depends on what type of deregulated model is being employed in a particular

region. Three main forms are identified all over the world to solve the congestion

problem, although details vary widely among specific implementations. Optimal power

flow model is used in United Kingdom, Australia, New Zealand and some parts of United

States of America. The price area congestion control model is used in Norway, Sweden

and Finland and Transaction based model (ATC model) is used in some parts of United

States of America.

Each method has strengths and flaws, and also interrelationships to some extent.

Each maintains power system security but differs in its impact on the economics of

energy market. The following chapters give the details of the above methods.

2.3 Conclusion

This chapter gives the importance of congestion management. The effects of congestion

on the operational and economic aspects of the power system are discussed. Various

methods for handling the congestion problem are addressed.

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3. Available Transfer Capability (ATC) Based Congestion

Management

3.1 Introduction

Congestion management is a vital issue in the power system operator under

deregulated environment and can be a major hurdle to trade of electricity if not properly

implemented. Congestion management ensures the non-violation of operating limits.

Congestion management has direct effect on bidding strategies since the bids under

congestion differ from the normal condition. So, for managing the congestion on the

transmission network efficient power transaction between different zones is required.

Efficient power transfers are necessary in competitive market for reliable supply.

Thus, in this context, Available Transfer Capability (ATC) indicating how much inter

area power transfer can be increased without compromising system security must be

evaluated. Accurate identification of this capability provides vital information for both

planning and operation of bulk power markets. A system which can accommodate large

inter area transfers, is generally more robust and flexible than a system with limited

capability to transfer inter area power. Thus ATC can be used as a rough indicator of

relative system security. In an inter area system the loss of generation of one area can be

replaced generation from other areas. ATC calculations are useful for evaluating the

ability of inter connected system to secure following generation and transmission outages

and also to determine the amount of lost generation that can be replaced by potential

reserves and limiting constraints in each circumstance. ATC information can help

independent system operator (ISO) to determine the validity of bidding results in an open

access deregulated market when timely ATC information is very important. It can also

help the power market participants to place bids strategically when congestion happens.

There is a very strong economic incentive to improve the accuracy and

effectiveness of transfer capability computations for use by system operators, planners

and power markets. The practical computations of transfer capability are evolving.

Without a fast computation algorithm the central computer of the ISO would not calculate

at a faster speed, as the market would appreciate.

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3.1.1 How the transfer capability is limited

The ability of interconnected transmission network to reliably transfer electric

power may be limited by the physical and electrical characteristics of the systems

including any or more of the following [2].

Thermal Limits

Thermal limits establish the maximum amount of electrical current that a

transmission line or electrical facility can conduct over a specified time period before it

sustain permanent damage by overheating or before it violates public safety requirements.

Voltage limits

System voltages and change in voltages must be maintained within the range of

acceptable minimum and maximum limits. For example, minimum voltage limits can

establish the maximum amount of electrical power that can be transferred without causing

damage to the electric system or customer facilities. A widespread collapse of system

voltage can result in a blackout of portion or entire interconnected network.

Stability limits

The transmission network must be capable of surviving disturbances through the

transient and dynamic time periods (from milliseconds to several minutes, respectively)

following the disturbance. All generators connected to ac interconnected transmission

systems operate in synchronism with each other at the same frequency (nominal

frequency is 50 Hertz in India). Immediately following a system disturbance, generators

begin to oscillate relative to each other, causing fluctuations in system frequency, line

loadings, and system voltages. For the system to be stable, the oscillations must diminish

as the electric system attains a new, stable operating point. If a new, stable operating point

is not quickly established, the generators will likely lose synchronism with one another,

and all or a portion of the interconnected electric systems may become unstable. The

results of generator instability may damage equipment and cause uncontrolled,

widespread interruption of electric supply to customers.

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3.1.2 ATC definitions

Available Transfer Capability (ATC) is a measure of the transfer capability remaining

in the physical transmission network for further commercial activity over and above

already committed uses. Mathematically, ATC is defined as the Total Transfer Capability

(TTC) less the Transmission Reliability Margin (TRM), less the sum of existing

transmission commitments (which includes retail customer service) and the Capacity

Benefit Margin (CBM), shown in Figure 3-7

Transmission Reliability Margin (TRM)

Capacity Benefit Margin (CBM)

Available Transfer Capability (ATC)

Total Transfer Capability (TTC) Existing

Transfer Commitments (ETC)

Figure 3-7: Basic Definition of ATC

Total Transfer Capability (TTC) is defined as the amount of electric power that can be

transferred over the interconnected transmission network in a reliable manner while

meeting all of a specific set of defined pre- and post-contingency system conditions.

Transmission Reliability Margin (TRM) is defined as that amount of transmission

transfer capability necessary to ensure that the interconnected transmission network is

secure under a reasonable range of uncertainties in system conditions.

Capacity Benefit Margin (CBM) is defined as that amount of transmission transfer

capability reserved by load serving entities to ensure access to generation from

interconnected systems to meet generation reliability requirements.

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3.1.3 ATC principles

ATC is a measure of the transfer capability remaining in the physical transmission

network for further commercial activity over and above already committed uses. As a

measure bridging the technical characteristics of how interconnected network perform to

the commercial requirements associated with transmission service requests, ATC must

satisfy certain principles balancing both technical and commercial issues. ATC must

accurately reflect the physical realities of the transmission network. The following

principles identify the requirements of the calculation and application of ATC.

1. ATC calculations must produce commercially viable results. ATC produced by

the calculation must give reasonable and dependable indication of transfer

capabilities available to the electrical power market. The frequency and details of

individual ATC calculation must be consistent with the level of commercial

activity and congestion.

2. ATC calculation must recognize time-variant power flow conditions on the entire

inter connected transmission network. In addition, the effect of simultaneous

transfers and parallel path flows throughout the network must be addressed from a

reliability viewpoint. Regardless of the desire for commercial simplification, the

laws of physics govern how the transmission network will react to customer

demand and generation supply. Electrical demand and supply cannot, in general,

be independently of one another. All system conditions, uses, and limits must be

considered to accurately access the capabilities of transmission network.

3. ATC calculation must recognize the dependency of ATC on the points of electric

power injection, the direction of transfer across the interconnected transmission

network, and the points of power extraction. All entities must provide sufficient

information necessary for calculation of the ATC. Electric power flows resulting

from each power transfer use the entire network and not governed by the

commercial terms of the transfer.

4. Regional or wide area interconnection is necessary to develop and post

information that reasonably reflects the ATCs of the interconnected transmission

network. ATC calculation must use a regional or wide-area approach to capture

the interactions of electrical power flows among individual, sub-regional, and

multiregional systems.

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5. ATC calculation must confirm to NERC, regional, sub-regional, power pool, and

individual system reliability planning and operating policies, criteria or guides.

Appropriate system contingencies must be considered.

6. The determination of ATC must accommodate reasonable uncertainties in system

conditions and provide operating flexibility to ensure the secure operation of the

interconnected network. A TRM may be necessary to apply this principle.

Additionally transmission capability (defined as CBM) may need to reserve to

meet generation reliability requirements.

3.2 Methods of calculation of ATC

The transfer margin computation can be implemented with a range of power system

models and computation technique. Here, following four ATC calculation methods are

presented [1].

1. ATC calculation using Power Transfer Distribution Factor (PTDF).

2. ATC calculation using Continuation Power Flow (CPF) method under Base case

and contingency case.

3.3 ATC calculation using PTDF

For ATC determination the MW flows must be allocated to each line or group of lines

in proportion to the MWs being transmitted by each transaction. This is accomplished

through the use of the PTDF.

3.3.1 Power Transfer Distribution Factor (PTDF)

From the power flows point of view, a transaction is specific amount of power

that is injected in to the system and at one bus by a generator and removed at another bus

by a load. The coefficient of linear relationship between the amount of transaction and

flow on a line is called the PTDF [1]. PTDF is also called sensitivity because it relates the

amount of one change – transaction amount – to another change – line power flow.

PTDF is the fraction of the amount of transaction from one bus to another that

flows over a transmission line. PTDFij,mn is the fraction of the amount of transaction from

bus m to bus n that flows over a transmission line connecting bus i and j.

PTDF ij, mn = ( Pijnew / Pmn

new ) (3.1)

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3.3.2 Calculation of PTDF using DC power flow model

The linearity property of dc power flow model can be used to find the transaction amount

that would give rise to a specific power flow, such as interface limits. The following

approximations are made for dc power flow model.

i) Transmission lines have no resistance and therefore no losses.

ii) Voltage magnitudes are constant.

iii) The variation in angles of complex bus voltages is small.

These approximations create a model that is a reasonable approximation of real power

system, which is only slightly nonlinear in normal steady state operation. The model has

advantages for speed of computation and also has some useful properties.

i) Linearity: If the MW in a transaction from one bus to another is doubled, the

flows that are directly attributable to this transaction will also double.

ii) Superposition: The flows on the interfaces can be broken down into a sum of

components each directly attributable to transaction on the system.

With the assumptions listed above, the power flow on a transmission line connecting bus i

to bus j, Pij, is given by

)(10

jiij

ij xP (3.2)

where xi, j line inductive reactance in per unit

θi phase angle at bus i

θj phase angle at bus j

Now, PTDFij, mn is the fraction of a transaction from bus m to bus n that flows over a

transmission line connecting between buses i and j.

ij

jninjmimmnij x

XXXXPTDF

, (3.3)

where

xij - reactance of the transmission line connecting zone i and zone j;

Xim - entry in the ith row and the mth column of the bus reactance

matrix X.

The change in line flow associated with new transaction is then

Pijnew = PTDF ij, mn * Pmn

new (3.4)

where

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Pmnnew = new transaction in MW.

3.3.3 Calculation of PTDF using AC power flow model

In the previous section we have seen PTDF calculation using DC power flow

model. But this involves many assumptions, which lead to inaccurate results. More

accurate PTDFs can be calculated using AC power flow model. Line power flows are

simply function of voltage and angle at its terminal buses. So PTDF is function of these

voltage and angle sensitivities [3].

Consider a bilateral transaction tp between a seller bus, m and buyer bus, n.

Further consider a line, l carrying a part of the transaction power. Let the line be

connected between a bus-i and a bus-j. For a change in real power transaction between the

above seller and buyer say by tp MW, if the change in transmission line quantity q l is

ql, the AC power transfer distribution factors can be defined as:

(ACPTDF) ql-tp = p

l

t

q

(3.5)

where

q l = change in power flow in line l

tp = change in transaction between bus m and n.

3.3.4 Algorithm for ATC Determination using DC PTDF

1) Evaluate the bus injections Pi at each bus i as the algebraic sum of all

generation into the bus minus the sum of all loads on the bus.

2) Multiply the vector of bus injections Pi by the reactance matrix X of the

network to get the vector of bus phase angles.

3) Find the base case line flows Pij for each line as

)(10

jiij

ij xP

4) Read the source bus (m) and sink bus (n) in which the ATC is to be calculated.

Calculate the DC PTDF for each line connecting between bus i and bus j for a

transaction from zone m to zone n using eq. (3.3)

5) Calculate the maximum allowable transaction amount from source bus (m) to sink

bus (n) for each line as

20

}{min ,Max

lmnl

mn PATC

where

Pijmax = line flow limit

Pij0 = Base case line flow

6) The ATC between zone m to zone n is the minimum of the maximum allowable

transaction over all lines

}{min ,Max

ijmnij

mn PATC

3.3.5 Algorithm for ATC determination using AC PTDF

1) Run a base case NR load flow to find the transmission line flows (P l0) for each

line.

2) Read the sending bus (seller bus) m and the receiving bus (buyer bus) n.

3) Assume some positive real power injection change ∆tp (=0.1) at seller bus-m and

negative injection ∆tp at the buyer bus-n and form mismatch vector ( P).

4) Compute the change in voltage magnitude and its angle ( V and ), and

voltages at each bus.

5) Calculate the new values of transmission line flows (Pl) and then calculate the

change in power flow from base case is ( 0lll PPq ) for each line l.

6) Compute AC PTDF for each line by using eq (3.5)

7) Calculate the maximum allowable transaction amount from zone m to zone n for

each line as

tpql

lllmn PTDF

PPP

0maxmax

,

8) The ATC between zone m to zone n is the minimum of maximum allowable

transaction over all lines

21

3.4 ATC calculation using Continuation Power Flow method

In previous sections we have seen the ATC calculations by using PTDF and

LODF, these methods are taking less computational time. But, in accuracy wise it shows

wrong results because the distribution factors are works on the principle of linearity.

Actually the load flow equations are non linear in nature so, the line flows are not

distributed linearly. In previous case we are taking line limit has taken as an active power

limit. But in reality the line limit is taken as a MVA rating. In case of MW limit the

power flow from bus p to bus q is more or less same as bus q to bus p (the difference is

because of losses), but in case of MVA rating there is a big difference between power

flow from p to q and q to p, it is because of reactive power flow on the line.

ATC calculation using NR load flow continuation power flow method gives the

accurate results. But the computational effort and time requirements are large because of

incorporating limits of reactive power flows, voltage limits as well as voltage collapse

and line flow limits [4].

3.4.1 Algorithm for ATC determination under base case and Contingency

case

1. Run the load flow by using NR load flow method

2. Calculate the base case voltages and base case power flow.

Note: power flow is the maximum (Spq , Sqp)

Spq = MVA flow from bus p to bus q

Sqp = MVA flow from bus q to bus p

3. Read the source bus (seller) m and sink bus (buyer) n.

4. Read the number of line outage; if there is no outage goes to next step else simulate

the outage by general technique (put the infinite impedance to corresponding line).

5. Assume some positive real power injection change ∆tp (=0.1) at seller bus m and

negative injection of same amount at the buyer bus n and then form the mismatch

vector.

6. Repeat the load flow and form the new line flows.

7. Check the line flows with maximum MVA rating of the line, if any line flows are

crossing the limit then go to next step, else go to step 4.

8. The maximum possible increment achieved above base- case load at the sink bus is

the ATC.

22

3.5 Case studies

3.5.1 IEEE Reliability Test System (RTS)

The transmission network [1] consists of 24 bus locations connected by 38 lines

and transformers, as shown in Figure A-0-1. The line data and generator data are

tabulated in appendix table.

Number of buses = 24

Number of lines = 38

The simulation studies are conducted on IEEE RTS and calculate the ATC with the

help of PTDF by using DC and AC load flow method. The effectiveness of those methods

is compared with AC NR-Load Flow continuous power flow method. Those three

methods are compared for ATC between different buses under normal conditions. The

results are shown in . The ATC values are calculated by taking active power flow line

limits (instead of MVA) as a constraint.

Table 3-3: Comparison of various methods

S.NO

TRANSACTION

ATC from DCPTDF

ATC from ACPTDF ATC from NRLF

1 14_8 0.48815 0.6579 0.7

2 22-5 2.845 2.5926 2.7

3 10_6 1.1493 1.0137 0.9

4 19_ 5 2.8656 2.628 2.7

5 20_8 0.49191 0.66471 0.7

6 18_5 2.849 2.5998 2.7

7 21_6 1.2262 1.0894 1

8 22_9 3.5654 3.6301 3.7

9 10_3 2.9949 2.99 3.1

10 23_15 6.1479 6.0066 6

23

Observations

1. The distribution factor methods takes less computational time as compare to

continuous power flow method

2. In distribution factor method for different transactions and outages, first we have

to pre-calculate the sensitivity factors, and then we can directly use those factors

for ATC calculations.

3. DC distribution factor method takes less time as compared to remaining methods,

but it shows wrong results because of approximations.

4. AC distribution factor method results are approximately equal to actual case, and

it case less computation time. But, because of linearity is applied to non linear

load flow equation it can give higher ATC values as compared to actual case.

5. AC NRLF continuous power flow method gives exact results, but computational

time is very high.

6. In real time studies the ATC information is necessary for every hour. So, AC

distribution factor method is well suited for real time studies.

24

4. Conclusions

Each of the ATC based congestion management methods discussed in this thesis has

its strengths and its flaws. ATC method directly gives the maximum possible transaction

amount before accepting any transaction and this information is displayed on OASIS

WebPages and uses the information available there to determine if the transmission

system could accommodate transaction, and to reserve the necessary service. Though, this

method is very effective, dynamic online calculation of ATC is difficult, as every single

transaction will have its effect on each and every component in the system. Hence

accurate ATC calculation needs to have fast and accurate computing algorithms, with less

and less assumptions.

The distribution factor methods takes less computational time as compare to continuous

power flow method. In distribution factor method for different transactions and outages,

first we have to pre-calculate the sensitivity factors, and then we can directly use those

factors for ATC calculations. DC distribution factor method takes less time as compared

to remaining methods, but it shows wrong results because of approximations.

AC distribution factor method results are approximately equal to actual case and it takes

less computation time. But, because of linearity applied to non linear load flow equation it

can give higher ATC values as compared to actual case. AC NRLF continuous power

flow method gives exact results, but computational time is very high.

In real time studies the ATC information is necessary for every hour. So, AC distribution

factor method is well suited for real time studies.

Presently congestion management is a challenging aspect in the deregulated market.

Whatever be the method followed to alleviate the congestion, it is very difficult to ensure

100% security.

25

References

[1] Richard D. Christen, Bruce F. Wollenberg and Ivar Wangensteen, “Transmission

Management in the Deregulated Environment”, Proceedings of the IEEE, Vol.88,

No.2, pp. 170-195, February 2000.

[2] “Available Transfer Capability Definitions and Determination”, NERC Report,

United States.

[3] Ashwani Kumar, S.C.Srivastava and S.N.Singh, Available Transfer Capability

Determination in a Competitive Electricity Market using A.C. Distribution Factors,

pp. 99 to 112

[4] Yan Ou, Chanan Singh, “Assesment of Available Transfer Capability and Margins”,

IEEE Trans. Power Syst., Vol. 17, pp. 463-468, May 2002

[5] G. Hamoud, “Feasibility Assessment of Simultaneous Bilateral Transaction in a

Deregulated Environment”, IEEE Trans. Power Syst., Vol. 15, pp. 22-26, Feb 2000

[6] G. Hamoud, “Assessment of Available Transfer Capability of Transmission Systems”,

IEEE Trans. Power Syst., Vol. 15, pp. 27-32, Feb 2000

[7] G.C. Ejebe, J. Tong, J.G. Waight, J.G. Frame, X. Wang, W.F. Tinney, ”Available

Transfer Capability Calculations”, IEEE Trans. Power syst., Vol. 13, pp. 1521-1527,

Nov 1998

[8] G. Sombuttiwilailert, B. Eua-Arporn, “A Novel Sensitivity Analysis For Total

Transfer Capability Evaluation”, 2001 IEEE pp. 342-347

[9] George J. Anders, ”Probability Concepts in Electric Power Systems”, A Wiley-

Interscience Publication.

[10] IEEE Reliability Test System, A report prepared by the Reliability Test System

task force of the applications of probability methods subcommittee, IEEE

Transactions on Power Apparatus and Systems, Vol. PAS-98, No.6, pp. 2047-2054,

Nov/Dec. 1979.

26

Appendix – Test Systems

4

8

1920

5

6

16

18

9

13

103

72

17

24 1211

2122

1

15 14

23

Area 1 Area 2

Area 3

Figure A-0-1: IEEE 24 BUS SYSTEM.

27

IEEE 24 BUS SYSTEM

Number of buses = 24

Number of line = 38

Slack Bus = 13

Line Data

LineFrom bus

To bus R X Max.powerLine

charging susceptance

Tap rattio

1 1 2 0.0026 0.0139 1.75 0.4611 1

2 1 3 0.0546 0.2112 1.75 0.0572 1

3 1 5 0.0218 0.0845 1.75 0.0229 1

4 2 4 0.0328 0.1267 1.75 0.0343 1

5 2 6 0.0497 0.192 1.75 0.052 1

6 3 9 0.0308 0.119 1.75 0.0322 1

7 3 24 0.0023 0.0839 4 0 1.015

8 4 9 0.0268 0.1037 1.75 0.0281 1

9 5 10 0.0228 0.0883 1.75 0.0239 1

10 6 10 0.0139 0.0605 1.75 2.459 1

11 7 8 0.0159 0.0614 1.75 0.0166 1

12 8 9 0.0427 0.1651 1.75 0.0447 1

13 8 10 0.0427 0.1651 1.75 0.0447 1

14 9 11 0.0023 0.0839 4 0 1.03

15 9 12 0.0023 0.0839 4 0 1.03

16 10 11 0.0023 0.0839 4 0 1.015

17 10 12 0.0023 0.0839 4 0 1.015

18 11 13 0.0061 0.0476 5 0.0999 1

19 11 14 0.0054 0.0418 5 0.0879 1

20 12 13 0.0061 0.0476 5 0.0999 1

21 12 23 0.0124 0.0966 5 0.203 1

22 13 23 0.0111 0.0865 5 0.1818 1

23 14 16 0.005 0.0389 5 0.0818 1

24 15 16 0.0022 0.0173 5 0.0364 1

28

25 15 21 0.0063 0.049 5 0.103 1

26 15 21 0.0063 0.049 5 0.103 1

27 15 24 0.0067 0.0519 5 0.1091 1

28 16 17 0.0033 0.0259 5 0.0545 1

29 16 19 0.0003 0.0231 5 0.0485 1

30 17 18 0.0018 0.0144 5 0.0303 1

31 17 22 0.0135 0.1053 5 0.2212 1

32 18 21 0.0033 0.0259 5 0.0545 1

33 18 21 0.0033 0.0259 5 0.0545 1

34 19 20 0.0051 0.0396 5 0.0833 1

35 19 20 0.0051 0.0396 5 0.0833 1

36 20 23 0.0028 0.0216 5 0.0455 1

37 20 23 0.0028 0.0216 5 0.0455 1

38 21 22 0.0087 0.0678 5 0.1424 1

Bus Data

Bus Type Pgen Pload Pgmax Qgen Qload Vspecified

1 P-V 1.52 1.08 1.92 0 0.22 1.035

2 P-V 1.52 0.97 1.92 0 0.2 1.035

3 P-Q 0 1.8 0 0 0.37 1

4 P-Q 0 0.74 0 0 0.15 1

5 P-Q 0 0.71 0 0 0.14 1

6 P-Q 0 1.36 0 0 0.28 1

7 P-V 1.39273 1.25 3 0 0.25 1.025

8 P-Q 0 1.71 0 0 0.35 1

9 P-Q 0 1.75 0 0 0.36 1

10 P-Q 0 1.95 0 0 0.4 1

11 P-Q 0 0 0 0 0 1

12 P-Q 0 0 0 0 0 1

13 Slack 0 265 5.91 0 54 1.02

14 P-V 0 0.94 0 0 1.39 1

15 P-V 1.55 3.17 2.15 0 0.64 1.014

29

16 P-V 1.55 1 1.55 0 0.2 1.017

17 P-Q 0 0 0 0 0 1

18 P-V 4 3.33 4 0 0.68 1.05

19 P-Q 0 1.81 0 0 0.37 1

20 P-Q 0 1.28 0 0 0.26 1

21 P-V 4 0 4 0 0 1.05

22 P-V 3 0 3 0 0 1.05

23 P-V 6.6 0 6.6 0 0 1.05

24 P-Q 0 0 0 0 0 1

30