CHAPTER 1: INTRODUCTION

1.1INTRODUCTION

A stable and reliable electric power supply system is an inevitable pre-requisite

for the technological and economic growth of any nation. Due to this, utilities must strive

and ensure that the customer’s reliability requirements are met and the regulators

requirements satisfied at the lowest possible cost. It is known fact around the world that

90% of the customer service interruptions are caused due to failure in distribution system.

Therefore, it is worth considering reliability worth assessments as it provides an

opportunity to incorporate the cost or losses incurred by the utilities customer as a result

of power failure and this must be considered in planning and operating practices.

The power system basically consists of generation, transmission and distribution,

regulated either by a single entity or by the number of entities. Hence, the responsibility

of maintaining reliability at different levels falls with different entities and should be the

common goals of the custodians of the various systems at different levels. Also

Regulators require most of investor owned utilities to report their reliability indices and

the regulator trend is moving towards performance based rates where performance is

rewarded and penalized based as quantified by regulator indices.

1.2 PROBLEM FORMULATION

Electricity networks are, and will continue to be a critical part of our energy

infrastructure,and we have the responsibility to ensure that they are developed

consistently and in a mannerthat meets future demands of society and customers. The

process of network developmentshould be directed towards a long term vision aligned

with the expectations of the present andfuture customers. After corporatization and

forming as utility company, BPCL`s mission is to transmit, distribute and supply

adequate electricity in a safe, reliable and efficient manner andthis has to be

accomplished.

The main problem facing by electric power utilities in developing countries today is that

thepower demand is increasingly rapidly where supply growth is constrained by scarce

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resources,environmental problems and other societal concerns. This has resulted in a

need for moreextensive justifications of the new system facilities, and improvements in

production and useof electricity. System planning and operation based on reliability

cost/worth evaluationapproach provides an opportunity to justify one of the scrutinized

and vulnerable economicsectors in Bhutan. It is with this objective to conduct customer

surveys to find out the outagecost of interruptions.

The analysis of the customer failure statistics reveal that the distribution system

makeshighest individual contribution to the unavailability of supply to the customer.

With the existing system, the customer interruptions is as high as 20-30 hours per year.

Withthe vision of electricity to all within 2017, the interruptions per customer may

furtherdeteriorate due to rapid expansion of the distribution systems. As of now, no

sufficient technical research have been carried out in the distribution network, it may be

due to lack oftechnical expertise in the Utility and most of the interruption has been

caused due to thefailure in the distribution systems.Comparing with other utilities around

the world,reliability standards are very low in distribution system. Hence, it is felt

necessaryto improve the reliability of the system in order to improve the utility’s

performance and tokeep our valued customers satisfied. The reliability improvement

should be based mostprobably upon the consideration of reliability worth and to find the

reliability worth, which is suitable to our context is being formulated.

Intelligent placement of Distributed Generation units, protection devices,

sectionalizers and switches in the distribution feeders has significant impact in reliability

improvement and this will be further assessed along with the capacity outage probability

table(COPT) for the distribution system.

1.3 OBJECTIVE OF THE THESIS

The goal of the power system is to supply electricity to it’s customers in an

economical and reliable manner. Reliability assessment of distribution system has

became very important in recent years in designing and planning distribution systems that

operate in an economical manner with minimal interruption of load demands. Distributed

generation plays a vital role in emerging power system to serve energy to power systems

utilizing the different types of resources and technologies. Initially Distributed generation

units are in standby mode and starts when some load points are interrupted from the

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supply to serve backup generation which could reduce the cost and improve reliability of

the system.

But the existence of the DG units in distribution units will effect on the

restoration time of the load points, this impact can be assessed using the concept of

conditional probability.

1.4 ORGANIZATION OF THE THESIS

Chapter 1 Presents introduction to the overall thesis and the overview of the project. In

the project overview a brief introduction of problems associated with reliability of

distribution system.

Chapter 2 Presents an introduction to reliability, reliability assessment, types of

reliability assessments.

Chapter 3 Presents introduction to DG and its types, advantages, disadvantages,

applications, impact of DG on Power system

Chapter 4 Presents an introduction to reliability assessment indices - General and

Customer oriented indices. Presents use of reliability indices, potential problems with

indices, factors affecting reliability performance

Chapter 5 Presents a details ofreal distribution test system and the required test data

Chapter 6 Presents the results, discussion of results, conclusion and future scope of the

project.

1.5 LITERATURE SURVEY

Prior to the 1960’s, the reliability of proposed power systems was often estimated

by extrapolating the experience obtained from existing systems and using rule-of-thumb

methods to forecast the reliability of new systems.

During the 1960’s considerable work was performed in the field of power system

reliability and some excellent papers were published. The most significant publications

were two company papers by a group of Westinghouse Electric Corporation and Public

Service and Gas Company authors. These papers introduced the concept of a fluctuation

environment to describe the failure rate of transmission system components. The

techniques presented in these papers were approximations which provided results within

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a few percent of those obtained using more theoretical techniques, such as Markov

processes. The application of Markov Chains in the power system reliability field was

illustrated in Reference. The Markov approach is limited in application because of

computer storage requirements and the rounding errors which occur in thesolution of

large systems. Most previous publications have focused on transmission system

reliability. This research focuses on distribution system reliability. This work extends

previous research, which demonstrated sets used in describing power system reliability

calculations. Further References presented the first application to apply linked lists and

pointer concepts to reliability analysis. It took into account constraints associated with

switching operations, but it was relatively slow due to running numerous power flow

calculations. One aspect investigated h ere is the effect of Distributed Generators (DG) on

power system reliability. Standards for connecting DGs into distribution systems are just

being developed. It deals with issues related to existing DG interconnection practices. An

investigation of eleven utilities and industry interconnection standards was performed to

identify the key requirements for a DG connection. The results of this investigation led to

the development of a unified approach for determininginterconnection requirements.

Some considers many aspects of DGs in distribution systems, including protection,

harmonics, transients, voltage and frequency control. A Power flow calculation based on

the positive sequence model of the distribution circuits was presented.

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CHAPTER 2

DISTRIBUTION RELIABILITY ASSESSMENT

2.1 INTRODUCTION

Distribution reliability primarily relates to equipment outages and

customer interruptions. In normal operating conditions, all equipment (except

stand by is energized and all customers are energized. Schedule and unscheduled

events disrupt normal operating conditions and can lead to outages and

interruptions. The unscheduled events are caused either due to human error or due

to equipment failures. The schedule events are meant for periodic maintenance of

the equipment and shall be notified in advance to the customers. Several

indicators are used to evaluate reliability in the transmission and distribution

system. The Regulation can aim to compensate customers for very long

interruptions, keep restoration times under control and create incentives to reduce

the total number and duration of interruptions (disincentives to increase them).

Power quality is an ambiguous term that means many things to many

people. From a consumer perspective, a power quality problem might be defined

as any electric supply condition that causes appliances to malfunction or prevents

their use. From a utility perspective, a power quality problem might be viewed as

noncompliance with various standards such as RMS voltage or harmonics.

Perfect power quality is a perfect sinusoidal with constant frequency and

amplitude. The power Quality is affected when a voltage waveform is distorted

by transients or harmonics, changes its amplitudes or deviates in frequency.

Customer interruptions are power quality concern since it reduces voltage to zero.

Reliability is primarily concerned with customer interruptions and is therefore a

subset of power quality.

Availability is defined as the percentage of time a voltage source is

uninterrupted. The hierarchy of power quality, reliability and availability is

shown in figure 2.1.1. The figure 2.1.1 indicates availability is a subset of

reliability and reliability is a subset of power quality. Power quality deals with

any deviation from a perfect sinusoidal voltage source. Reliability deals with

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interruptions. Availability deals with the probability of being in a interrupted

state.

Fig. 2.1.1: Heirarchy of power quality, reliability and availability

2.2 RELIABILITY AND ITS ASSESSMENT

2.2.1 Reliability

Reliability is an abstract term meaning endurance, dependability and good

performance. For engineering systems however it is more than an abstract term. It is

something that can be compared, evaluated, planned, and designed into a equipment plan

or system. Reliability means ability of the system to perform the function it is designed

for under the operating conditions encountered during its projected life time. Reliability

is often related to in terms of failure rate and outage time. Reliability in the context of

power system can be defined as “A general concept encompassing all the measures of the

ability to deliver electricity to all points of the utilization within acceptable standards and

in the amount desired”.

Frequency and duration of outages are relevant measures for reliability in

electricity supply systems. If reliability is regarded as a technical restriction, adequate

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outage indices have to be evaluated. If outages are associated with costs, reliability shall

be included within operating costs. The estimation of outage cost mostly used around is

the customer survey approach. When comparing among alternatives of approximately

equal total costs, the outage indices will be helpful in selection of the best solution.

The function of an electric power system is to satisfy the system load requirement

with a reasonable assurance of continuity and quality. The ability of the system to

provide an adequate supply of electrical energy is usually designated by the term of

reliability. The concept of power-system reliability is extremely broad and covers all

aspects of the ability of the system to satisfy the customer requirements. There is a

reasonable subdivision of the concern designated as “system reliability”, which is shown

in Figure 2.2.1.

FIGURE 2.2.1 Sub division System Reliability

Figure 2.2.1 represents two basic aspects of a power system: system adequacy and

security.Adequacy relates to the existence of sufficient facilities within the system to

satisfy the consumer load demand. These include the facilities necessary to generate

sufficient energy and the associated transmission and distribution facilities required to

transport the energy to the actual consumer load points. Security relates to the ability of

the system to respond to disturbances arising within that system. Security is therefore

associated with the response of the system to perturbations. Most of the probabilistic

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SYSTEM

SYSTEM ADEQUACY SYSTEM SECURITY

techniques presently available for power-system reliability evaluation are in the domain

of adequacy assessment.

2.2.2 Reliability Assessment

Reliability analysis has a wide range of applications in the engineering

field.Distribution reliability is the ability of the distribution system to perform its

function under stated conditions for a stated period of time without failure. Distribution

reliability is becoming significantly important in the current competitive climate because

the distribution system feeds the customer directly. The distribution system is the face of

the utility to the customer. Its assessment is to determine the system reliability and

customer satisfaction.

Rigorous analytical treatment of distribution reliability requires well defined units

of measurement, referred to as metrics. Many utilities across the world today use

reliability indices to track the performance of the utility or a region or a circuit.

Regulators require most investor owned utilities to report their reliability indices. The

regulatory trend is moving to performance based rates where performance is penalized or

rewarded based as quantified by reliability indices. Most of the utilities also pay bonuses

to managers or others based in part on reliability achievements. Even some of the

commercial and industrial customer asks utilities for their reliability indices when

planning to find a location for their establishments.

2.3 NEED FOR RELIABILITY ASSESSMENT

Reliability analysis of electrical distribution system is considered as a tool for the

planning engineer to ensure a reasonable quality of service and to choose between

different system expansion plans that cost wise were comparable considering system

investment and cost of losses

Reliability indices are significant components of any utility’s ability to measure

long-term electric service performance. Reliability metrics are one indicator of system

health or condition. The same way many complex systems have their own level of health,

these indicators let a utility know if the system is getting better or worse over time. Since

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all systems are different and stressed by different factors, it can be very hard to make a

legitimate comparison between two systems. This means reliability indices are situational

in nature and will present different baselines depending on the many intrinsic factors

affecting the system.

Reliability statistics can help drive utility improvement programs. Nonetheless,

when pursuing reliability improvement, taking a splintered approach can be damaging.

As such, utility managers should be sure to include all departments in a uniform plan to

understand and act on reliability data. In some cases, a system reliability meeting will

help bring other departments into the process of reinforcing system reliability. Whether a

utility decides to use meetings or have technical specialists focus on the issues, it should

be sure to identify gaps and create a uniform approach to reliability.

2.4 RELIABILITY ASSESSMENT TECHNIQUES

The ultimate goal of reliability analysis is to help answer questions like “is the

system reliable enough?” “which scheme will fail less?” and “where can the next dollar

be best spent to improve the system?”. Reliability in power system can be divided in two

basic aspects System adequacy and System security. Adequacy relates to the capacity of

the system in relation to energy demand and security relates to the dynamic response of

the system to disturbances (such as faults). Since distribution systems are seldom loaded

near their limits, system adequacy is of relatively small concern and reliability emphasis

in on system security.

The two main approaches applied to reliability evaluation of distribution systems are ;

• Simulation methods based on drawings from statistical distributions (Monte Carlo).

• Analytical methods based on solution of mathematical models

The Monte Carlo techniques are normally very “time” consuming due to large

number ofdrawings necessary in order to obtain accurate results. The fault contribution

from each component is given by a statistical distribution of failure rates and outage

times. The analytical approach is based on assumptions concerning the statistical

distributions of failure rate and repair times. The most common evaluation techniques

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using a set of approximate equations are failure mode analysis or minimum cut set

analysis. This method is less time consuming than the simulation methods, but suffers

from problems of representing repair times adequately. The analytical approach to

reliability evaluation of radial distribution system shall be used. The approach is called

RELRAD (Reliability in Radial systems) and is complimentary to the minimum cut set

approach.

2.5 IMPACTS OF MITIGATION TECHNIQUES AND PROTECTION SYSTEM

ON RELIABILITY

A properly co-ordinate protection system is vital to ensure that an electricity

distribution network can operate within preset requirements for safety for individual

items of equipment, staff and public, and the network overall. Suitable and reliable

equipment should be installed on all circuits and electrical equipment and to do this,

protective relays are used to initiate the isolation of faulted sections of a network in order

to maintain supplies elsewhere on the system. This then leads to an improved electricity

service with better continuity and quality of supply. This can reduce the permanent

outages and its durations. Nowadays, with the increase of sensitive load with the end

users, to improve the power quality and to mitigate the momentary interruptions is also

equally important. The first step is to find out the root cause of the problem and apply

mitigation solutions to a circuit that affects the largest number of customers.

A better over-current protection scheme can reduce number of customers affected

by temporary and permanent faults. The reliability of the system depends on the

mitigation techniques being used by the utility namely, electric and non-electric

mitigation techniques. So, historical data can be used to quantify improvements and

predict the best locations for sectionalizing devices for reliability improvements. Adding

numbers of recloser at optimal locations can reduce SAIFI, SAIDI but it should be

economically viable. The location and installation of number of Auto-recloser, Switches,

Load Break Swtiches and Sectionalizers either manual or automated helps to reduce fault

rate, repair time and sectioning time which directly reduces the impacts on the system

when fault occurs. The Mitigation Techniques applied shall depend on the need of utility

whether it wants to reduce fault rate, repair time or both or outage duration.

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2.6 RELIABILITY COST AND WORTH

As a concept, reliability is an inherent characteristics and a specific measure that

describes the ability of any system to perform its intended function. The primary

technical function of a power system is to supply electrical energy to its end customers.

This has always been an important system issue and power system personnel have always

strive to ensure that customers receive adequate and secure supplies within reasonable

economic constraints.

The system adequacy basically means the availability of enough generation,

transmission and distribution capacities to meet the customer demand. While on the other

hand security is considered to relate to the ability of the system to respond to disturbances

arising within the system. Therefore, adequacy assessment represents the static

conditions, where as security assessment pertains to the dynamic conditions of the power

system.

Utilities, in a venture to supply power at an economic price with an adequate level

of reliability, often faces challenges to balance the high level of reliability at relatively

low cost, since these two aspects counters each other. Direct evaluation of reliability

worth is a difficult task, therefore, a practical alternative, which is being widely used is to

evaluate the impacts and monetary losses incurred by customers due to power failures.

When an interruption is experienced by a customer, there is an amount of money that the

customer is willing to pay to evade the interruption and this amount is referred to as the

‘customer cost of reliability’.

These costs include both tangible and intangible cost and also the opportunity

cost. As such, to maximize the reliability, utility should balance their reinforcement cost

for reliability improvement and the customer cost for poor reliability. Therefore, the

optimal level of reliability is said to be achieved when the sum of utility cost and the

customer cost is at minimum.

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CHAPTER 3

DISTRIBUTED GENERATION

3.1 INTRODUCTION

DG is not a new concept. A number of utility consumers have been using DG for

decades. Over the last 10 years, the DG market has been somewhat turbulent. In the late

1990s, new regulations/subsidies, such as net metering and renewable portfolio

requirements, and the development of new DG technologies, have sparked broader

interests in distributed generation. DG is power generation built near consumers. DG

sources include small-scale, environmentally-friendly technologies (e.g., photovoltaic and

wind) installed on and designed primarily to serve a single end user’s site. But when

reliability and power quality issues are critical, DG most often includes more traditional

fossil fuel fired reciprocating engines or gas turbines.

The limited generation in the power sector has continually been exacerbated by

load growth, power demand, limitations in the ability to site new transmission lines,

limitations in the ability to construct large scale generation due to increased

environmental regulation, and lack of technology development to meet the new

requirements. Manpower is required to achieve the development of a sustainable,

secured, and economically-viable society and infrastructure. The growth in developed

and developing countries has created an energy divide in terms of wealth. The major

disparities of energy consumption per capita are reflected in developing countries. The

universal electrification challenge to meet the world’s population growth in order to

attain its current per capita electricity consumption will require massive increases in

electricity generation capacities.

Electric energy is produced and delivered practically on real time and there is no

convenient method to readily store it. This makes necessary to maintain a continuous and

almost instantaneous balance between production and consumption of electricity in

power systems. A way to ensure energy balance is by keeping some margin of generation

above the expected demand load, so the system can deal with unexpected mismatches

between supply and demand leading to power shortages. Generation margins are attained

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by providing stand-by plant capacity and they represent reservesof generation capacity

that can be rapidly utilized in case of a supply shortage.

Utilities have traditionally determined reserve requirements using working rules

and more recently probabilistic techniques. They estimate a reasonable amount of

capacity to be reserved and kept available, so that credible contingencies will not cause a

failure of supply. Nevertheless, even when analytical methods are used, a final decision

regarding reserve levels depends on the operator’s judgment of what is the acceptable

risk of system failure. In fact, although it is not always made explicit, this decision is a

trade-off between the additional reliability offered to customers and the cost of keeping

the reserves available.

In some cases, properly planned and operated DG can provide consumers, as well

as society, with a wide variety of benefits. These include economic savings because of

government subsidies and improved environmental performance. Many utilities have

installed DG on their systems and support federal funding of research to develop new

technologies.

The interconnection of DG with the electric grid continues to pose genuine safety

and reliability risks for the utility. DG could reduce the demand for traditional utility

services. DG also poses an economic risk to incumbent utilities and their consumers

unless appropriate rate structures or cost recovery mechanisms are put into place.

Though a small scale power plant, DG is environmentally friendly due to its

“friendly” technologies. These “friendly” technologies include: photovoltaic’s (PV), fuel

cells, small wind turbines, or more conventional technologies such as: micro turbines and

reciprocating engines that are fueled by renewable fuels, for instance, landfill gas. DG

encompasses generation built near to a consumer’s load despite size or energy source.

The latter definition could include diesel-fired generators with significant emissions.

Other definitions of DG include some or all of the following:

• Any qualifying facilities under the Public Utility Regulatory Policies Act of 1978

(PURPA);

• Any generation interconnected with distribution facilities;

• Commercial emergency and standby diesel generators installed, (i.e., hospitals

and hotels);

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• Residential standby generators sold at hardware stores;

• Generators installed by utility at a substation for voltage support or other

reliability purposes;

• Any on-site generation with less than “X” kW or MW of capacity. “X” ranges

everywhere from 10 kW to 50 MW;

• Generation facilities located at or near a load center;

• Demand side management (DSM), energy efficiency, and other tools for reducing

energy usage on the consumer’s side of the meter. The alternative to this

definition would be to abandon the term “distributed generation” completely and

use instead “distributed resources” (DR) or “distributed energy resources (DER)”.

3.2TYPES OF DISTRIBUTED GENERATION

DG can be classified into two major groups, inverter based DG and rotating

machine DG. Normally, inverters are used in DG systems after the generation process,

as the generated voltage may be in DC or AC form, but it is required to be changed to

the nominal voltage and frequency. Therefore, it has to be converted first to DC and then

back to AC with the nominal parameters through the rectifier. In this chapter, some of

the DG technologies, which are available at the present: photovoltaic systems, wind

turbines, fuel cells, micro turbines, synchronous and induction generators are introduced.

3.2.1 Photovoltaic Systems

A photovoltaic system, converts the light received from the sun into electric

energy. In this system, semiconductive materials are used in the construction of solar

cells, which transform the self contained energy of photons into electricity, when they

are exposed to sun light. The cells are placed in an array that is either fixed or moving to

keep tracking the sun in order to generate the maximum power.

These systems are environmental friendly without any kind of emission, easy to

use, with simple designs and it does not require any other fuel than solar light. On the

other hand, they need large spaces and the initial cost is high.

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In Fig. 3.2.1 a photovoltaic panel is shown.

Fig. 3.2.1 Schematic diagram of a photovoltaic system

PV systems generate DC voltage then transferred to AC with the aid of inverters. There

are two general designs that are typically used: with and without battery storages.

3.2.2 Wind Turbines

Wind turbines transform wind energy into electricity. The wind is a highly variable

source, which cannot be stored, thus, it must be handled according to this characteristic.

A general scheme of a wind turbine is shown in Fig. 2.2, where its main components are

presented.

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Fig. 3.2.2 Schematic operation diagram of a wind turbine

The principle of operation of a wind turbine is characterized by two conversion

steps. First the rotor extract the kinetic energy of the wind, changing it into mechanical

torque in the shaft; and in the second step the generation system converts this torque into

electricity.

In the most common system, the generator system gives an AC output voltage that is

dependent on the wind speed. As wind speed is variable, the voltage generated has to be

transferred to DC and back again to AC with the aid of inverters. However, fixed speed

wind turbines are directly connected to grid.

3.2.3 Fuel Cells

Fuel cells operation is similar to a battery that is continuously charged with a fuel gas

with high hydrogen content; this is the charge of the fuel cell together with air, which

supplies the required oxygen for the chemical reaction. The fuel cell utilizes the reaction

of hydrogen and oxygen with the aid of an ion conducting electrolyte to produce an

induced DC voltage. The DC voltage is converted into AC voltage using inverters and

then is delivered to the grid.

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In Fig. 3.2.3 the operation characteristics of a fuel cell are presented.

Fig.3.2.3Schematic diagram of a fuel cell

A fuel cell also produces heat and water along with electricity but it has a high running

cost, which is its major disadvantage. The main advantage of a fuel cell is that there are

no moving parts, which increase the reliability of this technology and no noise is

generated. Moreover, they can be operated with a width spectrum of fossil fuels with

higher efficiency than any other generation device. On the other hand, it is necessary to

assess the impact of the pollution emissions and ageing of the electrolyte characteristics,

as well as its effect in the efficiency and life time of the cell.

3.2.4 Micro Turbines

A micro-turbine is a mechanism that uses the flow of a gas, to covert thermal

energy into mechanical energy. The combustible (usually gas) is mixed in the combustor

chamber with air, which is pumped by the compressor. This product makes the turbine

to rotate, which at the same time, impulses the generator and the compressor. In the most

commonly used design the compressor and turbine are mounted above the same shaft as

the electric generator. This is shown in Fig. 3.2.4

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Fig 3.2.4 Schematic diagram of a micro-turbine

The output voltage from micro-turbines cannot be connected directly to the power grid

or utility, it has to be transferred to DC and then converted back to AC in order to have

the nominal voltage and frequency of the utility. The main advantage of micro-turbines

is the clean operation with low emissions produced and good efficiency. On the other

hand, its disadvantages are the high maintenance cost and the lack of experience in this

field. Very little micro-turbines have been operated for enough time periods to establish

a reliable field database. Furthermore, methods of control and dispatch for a large

number of micro turbines and selling the remaining energy have not been developed yet.

3.3 Impact of Distributed Generation on Power System Grids

The introduction of DG in systems originally radial and designed to operate without any

generation on the distribution system, can significantly impact the power flow and

voltage conditions at both, customers and utility equipment.

These impacts can be manifested as having positive or negative influence, depending on

the DG features and distribution system operation characteristics.

The objective of this thesis, is to investigate the technical impact that the

integration of DG have on the protection coordination of distributed power systems. A

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method to asses this impact, is based on investigate the behaviour of an electric system,

with and without the presence of DG. The difference between the results obtained in

these two operating conditions, gives important information for both, companies in the

electric sector and customers. In that sense, a general view of the main problems

encountered in the integration of DG to the distributed network is presented.

3.3.1 Impact of DG on Voltage Regulation

Radial distribution systems regulate the voltage by the aid of load tap changing

transformers (LTC) at substations, additionally by line regulators on distribution feeders

and shunt capacitors on feeders or along the line. Voltage regulation is based on one way

power flow where regulators are equipped with line drop compensation.

The connection of DG may result in changes in voltage profile along a feeder by

changing the direction and magnitude of real and reactive power flows. Nevertheless,

DG impact on voltage regulation can be positive or negative depending on distribution

system and distributed generator characteristics as well as DG location.

Fig. 3.3.1Voltage profiles with and without DG

In Fig. 3.3.1 the DG is installed downstream the LTC transformer which is

equipped with a line drop compensator (LDC). It is shown that the voltage becomes

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lower on the feeder with DG than without the DG installed in the network. The voltage

regulator will be deceived, setting a voltage lower than is required for sufficient service.

The DG reduces the load observed from the load compensation control side, which

makes the regulator to set less voltage at the end of the feeder. This phenomenon has the

opposite effect to which is expected with the introduction of DG (voltage support).

There are two possible solutions facing this problem: the first solution is to

move the DG unit to the upstream side of the regulator, while the second solution is

adding regulator controls to compensate for the DG output.

The installation of DG units along the power distribution feeders may cause

overvoltage due to too much injection of active and reactive power. For instance, a small

DG system sharing a common distribution transformer with several loads may raise the

voltage on the secondary side, which is sufficient to cause high voltage at these

customers. This can happen if the location of the distribution transformer is at a point on

the feeder where the primary voltage is near or above the fixed limits; for instance:

ANSI (American National Standards Institute) upper limit 126+ volts on a 120 volt base.

During normal operation conditions, without DG, voltage received at the load terminals

is lower than the voltage at the primary of the transformer. The connection of DG can

cause a reverse power flow, maybe even raising the voltage somewhat, and the voltage

received at the customer´s site could be higher than on the primary side of the

distribution transformer.

For any small scale DG unit (< 10MW) the impact on the feeder primary is

negligible. Nonetheless, if the aggregate capacity increases until critical thresholds, then

voltage regulation analysis is necessary to make sure that the feeder voltage will be fixed

within suitable limits.

3.3.2 Impact of DG on Losses

One of the major impacts of Distributed generation is on the losses in a feeder. Locating

the DG units is an important criterion that has to be analyzed to be able to achieve a

better reliability of the system with reduced losses.

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According to, locating DG units to minimize losses is similar to locating

capacitor banks to reduce losses. The main difference between both situations is that DG

may contribute with active power and reactive power (P and Q). On the other hand,

capacitor banks only contribute with reactive power flow (Q). Mainly, generators in the

system operate with a power factor range between 0.85 lagging and unity, but the

presence of inverters and synchronous generators provides a contribution to reactive

power compensation (leading current).

The optimum location of DG can be obtained using load flow analysis software,

which is able to investigate the suitable location of DG within the system in order to

reduce the losses. For instance: if feeders have high losses, adding a number of small

capacity DGs will show an important positive effect on the losses and have a great

benefit to the system. On the other hand, if larger units are added, they must be installed

considering the feeder capacity boundaries. For example: the feeder capacity may be

limited as overhead lines and cables have thermal characteristic that cannot be exceed.

Most DG units are owned by the customers. The grid operators cannot decide

the locations of the DG units. Normally, it is assumed that losses decrease when

generation takes place closer to the load site. However, as it was mentioned, local

increase in power flow in low voltage cables may have undesired consequences due to

thermal characteristics.

3.3.3 Impact of DG on Harmonics

A wave that does not follow a “pure” sinusoidal wave is regarded as

harmonically distorted. This is shown in Fig.3.3.3

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Fig. 3.3.3 Comparison between pure sinusoidal wave and distorted wave

Harmonics are always present in power systems to some extent. They can be

caused by for instance: non-linearity in transformer exciting impedance or loads such as

fluorescent lights, AC to DC conversion equipment, variable-speed drives, switch mode

power equipment, arc furnaces, and other equipment.

DG can be a source of harmonics to the network. Harmonics produced can be

either from the generation unit itself (synchronous generator) or from the power

electronics equipment such as inverters. In the case of inverters, their contribution to the

harmonics currents is in part due to the SCR (Silicon Controlled-Rectifier) type power

inverters that produce high levels of harmonic currents. Nowadays, inverters are designed

with IGBT (Insulated Gate Bipolar Transistor) technology that use pulse width

modulation to generate the injected “pure” sinusoidal wave. This new technology

produces a cleaner output with fewer harmonic that should satisfy the IEEE 1547-2003

standards.

Rotating generators are another source of harmonics, that depends on the design

of the generators winding (pitch of the coils), core non-linearity's, grounding and other

factors that may result in significant harmonics propagation.

When comparing different synchronous generator pitches the best configuration

encountered is with a winding pitch of 2/3 as they are the least third harmonic producers.

Third harmonic is additive in the neutral and is often the most prevalent. On the other

hand, 2/3 winding pitch generators have lower impedance and may cause more harmonic

22

currents to flow from other sources connected in parallel with it. Thus, grounding

arrangement of the generator and step-up transformer will have main impact on limiting

the feeder penetration of harmonics. Grounding schemes can be chosen to remove or

decrease third harmonic injection to the utility system. This would tend to confine it to

the DG site only.

Normally, comparing harmonic contribution from DG with the other impacts

that DG may have on the power system, it is concluded that they are not as much of a

problem. However, in some instants problems may arise and levels can exceed the

IEEE-519 standard (these levels are shown in table 2.1). These problems are usually

caused by resonance with capacitor banks, or problems with equipment that are sensitive

to harmonics. In the worst case, equipment at the DG may need to be disconnected as a

consequence of the extra heating caused by the harmonics.

Table 3.3.3Harmonic current injection requirements for distributed generators per IEEE

519-1992.

Harmonic order Allowed Level Relative to fundamental

(odd harmonics)*

< 11th 4%

< 11th to < 17th 2%

< 17th to 23rd 1.5%

< 23rd to 35th 0.6%

35th or greater 0.3%

Total Harmonic Distortion 5%

*Even harmonics are limited to the 25 of odd values.

The design of a DG installation should be reviewed to determine whether harmonics will

be confined within the DG site or also injected into the utility system. In addition, the

installation needs to fulfil the IEEE-519 standard. According to [3], any analysis should

consider the impact of DG currents on the background utility voltage distortion levels.

The limits for utility system voltage distortion are 5%for THD (total harmonic

distortion) and 3%for any individual harmonic.

23

3.3.4 Impact of DG on Short Circuit Levels of the Network

The presence of DG in a network affects the short circuit levels of the network. It creates

an increase in the fault currents when compared to normal conditions at which no DG is

installed in the network. The fault contribution from a single small DG is not large, but

even so, it will be an increase in the fault current. In the case of many small units, or few

large units, the short circuits levels can be altered enough to cause miss coordination

between protective devices, like fuses or relays.

The influence of DG to faults depends on some factors such as the generating

size of the DG, the distance of the DG from the fault location and the type of DG. This

could affect the reliability and safety of the distribution system.

In the case of one small DG embedded in the system, it will have little effect on

the increase of the level of short circuit currents. On the other hand, if many small units

or a few large units are installed in the system, they can alter the short circuit levels

sufficient to cause fuse-breaker miss-coordination. This could affect the reliability and

safety of the distribution system. Figure 3.3.4 shows a typical fused lateral on a feeder

where fuse saving (fault selective relaying) is utilized and DGs are embedded in the

system. In this case if the fault current is large enough, the fuse may no longer

coordinates with the feeder circuit breaker during a fault. This can lead to unnecessary

fuse operations and decreased reliability on the lateral.

24

G2G1

G3

SUBSTATION

BREAKER

FUSE

FAULT

FEEDER

LATERAL

Fig. 3.3.4Fault contributions due to DG units 1, 2 and 3 are embedded in the system.

Fuse-breaker coordination may be no longer achieved

If the DG is located between the utility substation and the fault, a decrease in

fault current from the utility substation may be observed. This decrease needs to be

investigated for minimum tripping or coordination problems. On the other hand, if the

DG source (or combined DG sources) is strong compared to the utility substation source,

it may have a significant impact on the fault current coming from the utility substation.

This may cause fail to trip, sequential tripping, or coordination problems.

The nature of the DG also affects the short circuit levels. The highest

contributing DG to faults is the synchronous generator. During the first few cycles its

contribution is equal to the induction generator and self excited synchronous generator,

while after the first few cycles the synchronous generator is the most fault current

contributing DG type. The DG type that contributes the least amount of fault current is

the inverter interfaced DG type, in some inverter types the fault contribution lasts for

less than one cycle. Even though a few cycles are a short time, it may be long enough to

impact fuse breaker coordination and breaker duties in some cases.

25

3.4 BENEFITS AND DRAWBACKS

An overview of some common benefits and drawbacks of the DG are presented below:

1) Benefits

• Connection of DG is intended to increase the reliability of power supply

provided to the customers, using local sources, and if possible, reduce the losses

of the transmission and distribution systems.

• The connection of DG to the power system could improve the voltage profile,

power quality and support voltage stability. Therefore, the system can withstand

higher loading situations.

• The installation of DG takes less time and payback period. Many countries are

subsidizing the development of renewable energy projects through a portfolio

obligation and green power certificates. This incentives investment in small

generation plants.

• Some DG technologies have low pollution and good overall efficiencies like

combined heat and power (CHP) and micro-turbines. Besides, renewable energy

based DG like photovoltaic and wind turbines contribute to the reduction of

greenhouse gases.

2) Drawbacks

• Many DG are connected to the grid via power converters, which injects

harmonics into the system.

• The connection of DG might cause over-voltage, fluctuation and unbalance of

the system voltage if coordination with the utility supply is not properly

achieved.

• Depending on the network configuration, the penetration level and the nature of

the DG technology, the power injection of DG may increase the power losses in

the distribution system.

• Short circuit levels are changed when a DG is connected to the network.

Therefore, relay settings should be changed and if there is a disconnection of

DG, relay should be changed back to its previous state.

26

3.5 APPLICATONS OF DISTRIBUTED GENERATION

DG technologies can meet the needs of a wide range of users, with applications in

the residential, commercial, and industrial sectors. Decision makers at all levels need to

be aware of the potential benefits DG can offer. In some instances, DG technologies can

be more cost effective than conventional solutions. Among other things, DG can be used

by utilities to both enhance existing systems and to delay the purchase of transmission

and distribution equipment. In addition, DG units can help meet the changing demands of

end users for premium, reliable or“green” power.

Currently, DG is being utilized most often in a continuous power capacity for

industrialapplications such as food manufacturing, plastics, rubber, metals and chemical

production. Commercial sector usage, while a fraction of total industrial usage, includes

sectors such as grocery stores and hospitals.

Fig 3.5 Applications of DG

27

3.6CHALLENGES ASSOCIATED WITH DISTRIBUTED GENERATING

SYSTEMS

There are no uniform national interconnection standards addressing safety, power

quality and reliability for small distributed generation systems.

The current process for interconnection is not standardized among provinces.

Interconnection may involve communication with several different organizations

The environmental regulations and permit process that have been developed for

larger distributed generation projects make some DG projects uneconomical.

Contractual barriers exist such as liability insurance requirements, fees and

charges, and extensive paperwork.

28

CHAPTER 4

MEASURING RELIABILITY

Along with the variety of definitions of reliability come a variety of ways to

measure it. A metric for reliability is required for assessment of past performance,

consideration of reliability in design, and setting of reliability goals. Many indices have

been defined as measures of reliability. They measure different aspects of reliability or

combinations of different aspects. Only a small number of these are common across

several utilities, and the ones that are commonly used are not always defined in the exact

same manner.

Reliability measures dealing with interruptions address three factors: frequency,

duration, and extent or severity. The extent is the number of customers or load affected,

which is determined by the layout of the distribution system Combining the two key

factors of frequency and duration into a single appropriate measure may not be possible,

so any one index may not be very valuable alone. When assessing reliability, all three

factors should be considered. Each reliability index may be important for a different

purpose. Different utilities use different sets of indices.

4.1 RELIABILITY INDICES

Reliability indices are statistical aggregations of reliability data for a well defined

set of loads, components or customers. Most reliability indices are average values of a

particular reliability characteristic for an entire system, operating region, substation

service territory, or feeder.

Comprehensive treatment is not practicable, but the following sections discuss the

most important reliability indices used around the world. The utility indices have

traditionally only included long duration interruption (usually defined as interruptions

longer than 5 minutes). A common way of defining reliability is in terms of customer and

load based indices.

29

4.1.1 Customer Based Indices

The Utilities commonly use the following two reliability indices for frequency

and duration to quantify the performance of their systems.

System Average Interruption Frequency Index (SAIFI):

System Average Interruption Frequency Index (SAIFI) is designed to give

information about the average frequency of sustained interruptions per customer over a

predefined area.

SAIFI=Total no of customer interruptionsTotalno of customers served

=∑ λi N i

∑ N i

Where λis the failure rate and Ni is the number of customers at load points i.

System Average Interruption Duration Index (SAIDI):

System Average Interruption Duration Index, (SAIDI) is commonly referred to as

customer minutes of interruption or customer hours, and is designed to provide

information about the average time that the customers are interrupted

SAIDI=∑ of customer interruptionsdurationsTotalno of customers served

=∑ U i N i

∑ N i

Where Ui is the annual outage time and Niis the number of customers at loadPoint i.

Customer average interruption duration index (CAIDI):

Customer Average Interruption Duration Index (CAIDI) is the average time

needed to restore service to the average customer per sustained interruption

CAIDI=∑ of customer interruptionsdurationsTotal no of customers interruptions

=∑ U i N i

∑ λ i N i

30

Where λ is the failure rate, Ui is the annual outage time, and Ni is the number of

customers at load point i.

Customer Average Interruption Frequency Index (CAIFI):

Customer Average Interruption Frequency Index (CAIFI) is designed to show

trends in customers interrupted and helps to show the number of customers affected out

of whole customer base.

CAIDI=Total no of customer interruptedTotalno of customers affected

=∑ U i N i

N

Average service availability index (ASAI):

ASAI= customer hoursof available servicecustomers housdemanded

=∑ N i ×8760−∑U i N i

∑ N i−8760

Average service unavailability index (ASUI):

ASUI=1-ASAI

Where λ is the failure rate, Ui is the annual outage time, Ni is the number of

customers at load point i; and 8760 is the number of hours in a calendar year.

4.1.2 Load and Energy-oriented Indices

Energy not supplied index (ENS):

ENS = total energy not supplied by the system =∑La.i /Ui

Where La.iis the average load connected to load point i .

Average energy not supplied index (AENS):

AENS= Totalenergy not suppliedTotal no of customers served

=∑ Li N i

N i

Where Liis the average load connected to load point i .

31

4.1.3 System Performance

The customer and load based indices described in section 4.1.1 and 4.1.2 are

useful for assessing the severity of system failures in future reliability prediction analysis.

They can be used, however, as a means of assessing the past performance of a system.

The assessment of system performance is a valuable procedure for three important

reasons

• It establishes the chronological changes in system performance and therefore helps to

identify weak areas and the need for the reinforcement.

• It establishes existing indices which serves as a guide for acceptable values in future

reliability assessments.

• It enables previous predictions to be compared with actual operating experience.

4.2 USE OF RELIABILITY INDICES

Comparisons across utilities such as the ones made in these programs must be

done with caution. Differing definitions of interruptions can affect the reliability-index

results. How different utilities treat momentary outages, scheduled outages, storms, and

other non-failure related interruptions must be considered. Given these concerns, utilities

may be reluctant to allow comparisons of their performance.

Most utilities use more than one reliability index. More than 80% of the surveyed utilities

maintained SAIDI records. SAIFI, CAIDI, and ASAI were also widely used. Although

the use of indices may have increased over the years, the indices used most commonly

have not changed.

4.3Potential problems with standard indices

Although the most commonly used indices do a reasonable job in tracking the

reliability performance of utilities, they have the potential of allocating spending

decisions that are not closely aligned with customer interests. This is true for utilities that

32

are mature in their reliability improvement process. Once first round of investment is

made, traditional reliability measure may present complications.

The following describes the potential problem with the standard indices.

SAIDI and SAIFI– When making reliability investments, reductions in SAIDI and

SAIFI are proportional to the number of affected customers. This means projects that

affect many customers are preferred to those that affect few customers. However, feeders

with many customers typically have better than average reliability, and feeders with few

customers have worse than average reliability. Therefore, reliability investment based on

SAIFI and SAIDI can drive investments towards densely populated areas where

reliability is already satisfactory.

CAIDI – Although popular with many utilities and regulators, CAIDI is

problematic as measure of reliability. This is because, any view CAIDI as a measure of

operation efficiency; when utility responds more quickly after a fault, CAIDI will go

down. In fact, CAIDI is mathematically equal to SAIDI divided by SAIFI. That is

reliability could be improving in both frequency and duration, but CAIDI could be

increasing. Because of the above problem, the use of CAIDI is decreasing in today’s

world.

4.4 FACTORS AFFECTING RELIABILITY PERFORMANCE

Reliability performance varies dramatically from one system to another and this is

not necessarily an indication that one system has poor performance. Many factors

influence the expected reliability at a particular location or for an entire system.

Reliability indices that reflect reliability performance differ with data definitions

and data classifications. Most Utilities define separate indices for planned and unplanned

events. The interruption caused due to major event like storm, forest fire or a forced

majeure may or may not be considered in reliability performance. Transmission and

Distribution events are considered separately for reliability performance evaluation due to

data classes or nature of events.

The service territory of the utility determines the nature of the events that could be

expected which effect reliability performance. Geography of the service territory such as

thick forest, mountainous terrain, etc is likely to cause reliability issues. Weather is an

important factor that can seriously affect reliability levels. The effects of vegetation such

33

as tree falls, branch intrusion and animal activity from birds, squirrels and pests causing

ground faults affect reliability levels. Maintenance practices such as tree trimming

programs and installation of animal guards could help achieve higher levels of reliability.

Hence, it is obvious to expect a different reliability levels at various locations.

34

CHAPTER 5

DETAILS OF TEST SYSTEM

Introduction

Reliability evaluation techniques have been widely used in many industries such

as power, nuclear, airspace etc. Many techniques have been developed for different

applications. The basic function of an electric power system is to supply customers with

reasonably economical and reliable electricity.

To build an absolutely reliable power system is neither practically realizable nor

economically justifiable. The reliability of a power system can only be improved through

the increased investment in system equipment during either the planning phase or

operating phase. However, over-investment can lead to excessive operating costs, which

must be reflected in the tariff structure.

5.1 RBTS TEST SYSTEM

The application of the proposed technique to a multi-load point distribution system is

clarified using the distribution system shown in Fig 5.1.1

The test system is a real distribution network. The network has 16 load points and 2138

customers. The average fault location time and repair time for all sections are assumed to

be respectively 0.66 and 3 hours.

35

Fig 5.1.1 RBTS test system

36

Fig 5.1.2 Radial distribution system

Fig 5.1.3 Radial distribution system

37

Table 5.1 shows the data associated with sections and load points. Average failure rate of

sections is assumed to be 1.49(failure/yr.km).

Section Number

Length(Km) Loadpoint number at end

node

Average Load at end node(KVA)

No. of Customer at

end node1 0.42 1 90 137

2 0.25 - - -

3 0.294 2 100.1 126

4 0.411 3 18.7 20

5 0.190 - - -

6 0.190 4 90 284

7 0.340 5 269.5 210

8 0.110 - - -

9 0.124 6 50.6 57

10 0.030 7 87.6 135

11 0.124 8 90 172

12 0.200 9 85 170

13 0.140 10 200 190

14 0.104 11 51.04 56

15 0.167 12 26.4 38

16 0.189 - - -

17 0.033 16 45.1 49

18 0.138 13 16.5 10

19 0.481 - - -

20 0.200 14 374 280

21 0.290 15 90 204

Table 5.1 Data associated with sections and load points

38

In this network there are five locations for possible installation of DG units that is shown

in Figure 5.1.1 (these points are defined by the utility considering various factors)

The purpose is to determine the best location and optimum number of DG units in order

to maintain the predefined reliability level. The capacity of each DG unit is assumed to be

650 KVA.

39

CHAPTER 6

EXPERIMENTAL RESULTS

INTRODUCTION:

This chapter presents final results tested on RBTS test system. Average values of

load point and system indices are calculated and presented. Even the probability

distributions of various reliability indices are presented.

6.1 RESULTS

A computer program has been developed to perform necessary computations.

This program first computes failure rate( λ ),restoration time(r), and annual outage

time(u) for each load point then calculate system indices such as SAIFI, SAIDI, CAIDI

and AENS as described before. Three different case studies are considered. For each case

it is assumed that 0, 1, 2, 3, or 4 DG units can be established in each location and then

system indices are calculated.

With Location 1 and availability 0.95

No. of DG’s SAIFI SAIDI CAIDI AENS

0 6.5932 23.0272 3.6599 19.79

1 6.5932 19.875 3.457 17.943

2 6.5932 19.763 3.013 15.993

3 6.5932 17.89 2.763 13.987

4 6.5932 17.54 2.694 13.854

Table 6.1.1 Results with Location 1 and availability 0.95

With Location 1 and availability 0.8

No. of DG’s SAIFI SAIDI CAIDI AENS

1 6.5932 23.95 3.412 18.12

2 6.5932 20.02 3.027 15.95

3 6.5932 18.54 2.843 13.98

4 6.5932 17.32 13.98 13.82

Table 6.1.2 Results with Location 1 and availability 0.8

40

With Location 2 and availability of 0.95

No. of DG’s SAIFI SAIDI CAIDI AENS

0 6.5932 23.0272 3.6599 19.79

1 6.5932 23.002 3.423 18.12

2 6.5932 19.724 2.997 15.987

3 6.5932 2.997 2.639 13.83

4 6.5932 15.987 2.598 13.72

Table 6.1.3 Results with Location 2 and availability 0.95

Because DG units are assumed as standby units they only affect on outage time and

doesn’t affect on interruption frequency, hence SAIFI will be constant in each case and is

equal to 6.5932 (int/cust.yr).

6.2 DISCUSSION OF RESULTS

The comparison between the results obtained for the different case studies indicates

that the load point failure rates are not affected by the availability of one or two DG units in

the studied system. The load point failure rates are dependent only on the main feeder and

laterals failure states and durations. In addition, the two system indices which are based on

the load points failure rate namely, system average interruption frequency index SAIFI and

average service availability index ASAI remained the same for the three case studied. The

main contribution of the DG to the system reliability is the improvement in both the system

average interruption duration index (SAIDI) and the customer average interruption duration

index (CAIDI). Although the frequency of interruption of the system is the same for all cases,

the duration of these interruptions become shorter as the number of DG units in the system

increases. Both the customers and the utilities are benefiting from this improvement in the

duration of interruptions.

41

CONCLUSION

This project proposed an analytical approach to study the DG impacts on

distribution system reliability indices. The method assumes DG units as backup

generation and considers availability and unavailability of DG units. The method is then

applied to a real distribution network and system indices such as SAIFI, SAIDI, CAIDI

and AENS has been computed for 3 cases with the developed computer program. The

results show when DG units are applied as standby units, only affect on outage duration

and don’t affect on interruption frequency so SAIFI will be constant. In addition, the

results show that indices are too sensitive to location, number and availability of DG

units. Hence, the optimum number of DG units for the best location in distribution system

can be obtained using the proposed method.

The analysis of the studied system has proven that the presence of DG is enhancing

the system reliability. This improvement in the system reliability is reflected on the duration

of interruptions per customer per year and the duration of system interruptions per year.

By comparing the results obtained with location1 and location 2 the optimal location

is location 1 because the reliability indices at location 1 are lower compared to location 2.So

the optimal location for placement of DG is location 1.

42

FUTURE SCOPE

Reliability assessment has become important for utility planners in recent years.

Improved service reliability might be motivated by government regulation or by market

competition, but providing superior service at an attractive price is in the interest of both

utilities and customers.

At present the electric power utilities are not much reliable leading to the increase

in the cost of interruptions and power outages effecting economically on the utility and its

customers.

In the near future,these deregulated power utilities must be restructured and

operated as distinct generation, transmission and distribution. This can be achieved by

combining conventional based generation units with the distributed generation units. The

responsibility of maintaining the reliability of the overall power system must and should

be shared by all the involving companies instead of by a single electric utility which leads

to the decrease in the power outages and interruption cost and increases the reliability of

the system.

43

REFERENCES

1. R.E. Brown and S. Gupta and R. D. Christie and S. S. VenkataandR. Fletcher

“Distribution System Reliability Assessment UsingHierarchical Markov

Modeling” IEEE Transactions on PowerDelivery, Vol. 11, No. 4, October 1996

2. A. Chowdhury and D. O. Koval, “Generation reliability impacts of Industry-

owned distributed generation sources,” in IndustryApplications Conference, vol.

2, Oct. 2003, pp. 1321–1327.

3. Ackermann,T.; Andersson,G.; Soder, L.; "Distributed Generation: A Definition”,

Electric Power Systems Research, Vol 57, 2001, pp195– 204.

4. P. A. Daly and J. Morrison, “Understanding the potential benefits of distributed

Generation on power delivery systems,” in Proc.Rural Electric Power Conf.,

2001, pp. A2/1–A2/13.

5. R. Billinton, R, N. Allan, "Reliability Evaluation of Power Systems",2nd edition,

Plenum Press, New York, 1996.

6. R. Billinton and R. Allan, Reliability Evaluation of Engineering Systems:

Concepts and Techniques: Plenum Press, 1994.

7. IEEE Standard 1366-1998, IEEE trial-use guide for electric powerdistribution

reliability Index, 1998.

44

APPENDIX

#include<stdio.h>

#include<conio.h>

void main()

{

Float

AFR,AFLT,ART,AL[100],UL[100],RL,NC[100],ALD[100],LS[100],A,w,x,y,z,T

NCS,TNCI,SCID,ENS,AENS,SAIDI,SAIFI,CAIDI,ASAI,ASUI;

intn,i;

printf("\n ENTER THE NO. OF LOAD POINTS");

scanf("%d",&n);

printf("\nENTER THE AVERAGE FAILURE RATE OF THE SECTIONS");

scanf("%f",&AFR);

printf("\nENTER THE AVERAGE FAULT LOCATION TIME");

scanf("%f",&AFLT);

printf("\nENTER THE AVERAGE REPAIR TIME");

scanf("%f",&ART);

printf("\nENTER THE AVAILABILITY OF DG UNITS");

scanf("%f",&A);

for(i=0;i<n;i++)

{

printf("\n enter the no of customers,avg load demand,Length(km) of the section of

load point %d",i);

scanf("%f%f%f", &NC[i],&ALD[i],&LS[i]);

}

RL=AFLT+ART;

x=0;

for(i=0;i<n;i++)

{

45

AL[i] = AFR*LS[i];

UL[i] = x+AL[i]*RL;

x = AL[i]*RL

}

printf("\n load point reliability incides for the given system");

printf("\nload pt.\tAvg. Failure rate\tAvg. Outage time\tAnnualAvg.outage time");

for(i=0;i<n;i++)

{

printf("\n %d\t %0.2f\t %0.2f\t %0.2f",i,AL[i],RL[i],UL[i]);

}

w=0;x=0;y=0;z=0;

for(i=0;i<n;i++)

{

TNCS=x+NC[i];

x=TNCS;

TNCI=y+AL[i]*NC[i];

y=TNCI;

SCID=z+UL[i]*NC[i];

z=SCID;

ENS=w+ALD[i]*UL[i];

w=ENS;

}

SAIFI=(TNCI/((1-A)*TNCS));

SAIDI=(SCID/((1-A)*TNCS));

CAIDI=SAIDI/SAIFI;

ASAI=(8760-SAIDI)/8760;

ASUI=1-ASAI;

AENS=(ENS/((1-A)*TNCS));

printf("\n System indices are");

46

printf("\n SAIFI=%0.6f\n SAIDI=%0.6f\n CAIDI=%0.6f\n ASAI=%0.6f\n

ASUI=%0.6f\n ENS=%0.6f\n AENS=

%0.6f",SAIFI,SAIDI,CAIDI,ASAI,ASUI,ENS,AENS);

}

47