Keywords: IdentifiedObject + AliasName : String [0, 1] + description : String [0, 1] + mRID : String [0, 1] + name : String [0, 1] Core :: GeographicalRegion Core :: SubGeographicalRegion Core :: Substation

General introduction

 Nowadays, the energy demand keeps on increasing and is expected to double by 2030 with its consequences on the pollution of the environment. At the same time, the development of the electrical system is very slow due to investment budget constraints. In this context, the electrical system assets are exposed to large pressure due to network congestions. The advent of DGs (Distributed generation) into the previous passive distribution network has increased this pressure. In addition, the presence of Distributed generation has introduced several technical challenges [1] on network operation and protection system. Bi-directional power flows, modification of short-circuit currents, amongst others, due to the presence of DERs, has created new concerns on existing protection coordination strategies, resulting in maloperations on the protection system: unnecessary protection tripping, protection relay blinding, fuse premature blowing, amongst others.

It is a fact that the penetration of distributed energy resources will keep on increasing mainly at the distribution network side. To keep the electric network developing and operating more efficiently, the changes in the distribution network call for a new mindset on distribution automation functions and more specifically protection coordination. They also call for extensive real-time interoperable information exchange between Control Center, feeder, DER, plug-in electric vehicles (PEV), storage devices, and so on based on stable and proven international standards.

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-The electrical network model modifications require an up to date alignment on both Control Center and distribution feeder single line diagrams. During runtime, the feeder should be able to read the "as-built" network model from the Control Center in a file format, use it to update its single line diagram and integrate it into feeder automation functions. To date, this operation does not exist.

However, during planning period, substation engineers configure manually the modifications from a specification in paper format, increasing then the engineering time. One constraint is to make these modifications "on the fly" (pseudo real-time). This aspect raises issues on system management, or how to perform secured distributed automation evolution (i.e. evolutions of each of the components participating to these distributed automation function) on an operating critical system. From a user's point of view (i.e. Utilities), a large constraint is to guarantee a multivendor architecture, then leading to rely on existing standards such as IEC 61850 at the substation and field levels and CIM (Common Information Model) at enterprise level.

-Different technologies of DERs are connected to the distribution feeder. Their integration to the global network model at the Control Center and network control applications might be easier if all the electrical network components are modeled with the same semantic and syntax. In the meantime, the DER data models defined on IEC 61850-7-420 are not interoperable with the SCADA which is based on CIM (Common Information Model).

Current research works [2], Electricity industry in Europe

[3], international standardization committees such as the Technical Committee TC 57 within IEC (International Electrotechnical Committee) [4], [5] and CEN-CENELEC-ETSI [6] have identified very strong requirements for IEC 61850 and CIM (IEC 61968/61970/62325) interoperability on a large variety of domains such as grid operation, grid automation, Distributed Energy Resources (DER) management, industry automation, amongst others. P a g e 15 | 161 Public This research work is part of the so-called "Smart Grid" [7] concept and will use the result of the harmonization between IEC 61850 and IEC CIM for improving the protection coordination on distribution feeders in presence of DERs (also known as active distribution feeders).

The objective is to investigate a new concept of improving the protection coordination on distribution feeders in presence of DERs. The scenario is to transfer to the distribution feeder part of the global knowledge of the Control Center, through a secure incremental management of the power automation systems (including both field and enterprise levels). In fact, the current protection system on the feeder has no knowledge on the electrical network it is protecting. Therefore, by transferring the network model to it, a better protection coordination could be obtained by having all the protection devices exchanging data with each other in real-time.

A new mindset, discussed from chapter 3, consisting in providing knowledge to a distribution feeder controller is presented. This mindset utilizes the harmonization between IEC 61850 and IEC CIM standards to transfer the as-built network connectivity model from the Control Center (model based on IEC CIM) to a feeder controller (model based on IEC 61850). The knowledge provided to the feeder helps it to better perform some automation functions such as protection coordination amongst others. Several decentralized approaches have been proposed in the research literature, but none of them deals with the provision of standardized knowledge from CIM-based operation side down to the IEC 61850-based distribution feeder. This approach enables an incremental management, i.e. an integration "onthe-fly" of network model changes into the distribution feeder automation functions. It also paves the way for the industrialization of the Smart Grid applications based on proven standards such as IEC 61850 and CIM. A new protection scheme called Zone Differential Protection (ZDP) is also presented from chapter 4 in application of the new mindset. The ZDP, embedded into a distribution feeder controller, uses the network model transferred by the Control Center to perform the protection coordination along the feeder by applying the differential protection principle on a three-phase, unbalanced and node-breaker network model including distributed generation. As its name suggests, the nodebreaker network model is the network model with nodes and breaker as opposed to P a g e 17 | 161 Public protection coordination. The thesis is in the framework of the partnership between Grenoble INP and Schneider Electric under the supervision of the G2eLab (Electrical Engineering research Laboratory).

This thesis is organized in five chapters.

In the first chapter, a general description of the power system is given with a focus on the distribution network. The motivations of the change of energy paradigm are highlighted. In addition, the technical challenges introduced by DERs on protection coordination along with the grid codes constraints will be covered.

The second chapter focuses on the protection of distribution networks. The protection coordination strategies used in passive distribution networks is discussed. Also, the current state of the art philosophies of protection coordination of active distribution networks is presented.

The harmonization between the CIM and IEC 61850 data models is reviewed in the chapter three.

The chapter four sets the required theoretical basis for the modeling of the proposed "zone differential protection" on an active distribution feeder. Also, an overview on the modeling methodology, the assumptions and the operational requirements of the zone differential protection are developed. This will give an idea on the multi-faceted modeling required to design a zone differential protection for the distribution feeder.

Finally, in the fifth chapter, the previous modeling approaches are applied to a test feeder to achieve steady-state studies (load flow and short-circuit studies) to simulate the behavior of the zone differential protection. The simulation results will be presented. However, due to time constraints, the dynamic studies have not been covered in this thesis which has been done in the half of the regular duration.

This thesis has been partially funded by Schneider Electric in support of my personal initiative to investigate a new mindset consisting of transferring part of the global knowledge of the SCADA to a distribution feeder to better achieve some distributed automation functions such as Volt/VAR control, load shedding optimization,

I.1. Introduction

To better understand the motivations of this research subject and get an idea on potential constraints, technical choices, the chapter I gives a description of the power system.

The electric system structure, its components and operation are discussed along with the advent of the DERs (Distributed Energy Resources) and the operational requirements imposed to them by the grid codes. In this chapter, the power system will be presented with a special focus on the distribution system.

I.2. The change of energy paradigm

The conventional grid model is a system where large amounts of energy are produced from centralized power generation and injected into the transmission system. The energy is transferred then to the distribution network which supplies, then, the end-users. In this model, the power is produced from large power plants with typically fossil-fuel-based primary energy. For many decades, the power production from fossil and non-renewable energies has been recognized as one of the main causes of the destruction of ozone layer due to the emission of greenhouse gases. Nevertheless, the IPPC (Intergovernmental Panel on Climate Change) experts are still not categoric to say that the power generation is the root cause of the climate change [8]. However, the public opinion has developed new aspirations for environment protection and sustainable development. It is putting increasing pressure to governments to take the right decisions. Then, governments had put in place new policies such as the liberalization of energy markets to raise investment, energy efficiency programs to reduce the energy consumption, the modification of the energy mix with the insertion of renewable energies, the provision of financial support to end-users for the installation of solar PV, among others. This was the advent of DERs (Distributed Energy Resources) in the distribution system which became active. A new energy paradigm emerged where the power is also injected within the distribution system.

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The new energy paradigm has introduced technical challenges into the power system that need to be studied to better understand the constrains induced on protection coordination amongst all.

I.3. The power system

The electric system is defined as the global and complex infrastructure extending from the generating power plants down to the remote load centers. It is generally divided into three parts:

-The power generation system -The transmission system -The distribution system I.3.1. The power generation system

Traditionally, the power is supplied in top-down by power generation system to distribution system via the transmission system. To designate the generation part of the power system, the term "bulk generation" was used to insist on the large quantity of energy produced by generators. Power generation is ensured by generators which convert different forms of primary sources into an electric energy. The quantity of electric energy produced can be controlled by modulating the quantity of primary energy at the input.

I.3.2 The transmission system

The load centers are generally located very far from power plants even though part of the load can be connected to the transmission system. However, the transfer of large quantity of energy to remote locations can create significant energy losses.

Therefore, to reduce the power losses to its minimum, a high voltage system also termed "transmission system" is needed. This transmission system is composed of High Voltage (HV) lines which interconnect HV/MV substations considered as the interfaces between the transmission and the distribution systems. The transmission system also allows national and international interconnections by connecting HV substations. A fraction of the energy flowing through the transmission system is used

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I.3.3. The distribution system

Most of the customers are connected in low voltage (LV), some others on the medium voltage (MV). Therefore, to carry the energy to the furthest customers with the adequate voltage level, the distribution system performs successive voltage reduction from HV/MV to MV/LV distribution substations. The voltage levels used may differ from one country to another, however, the distribution system is generally operated with voltages below 50kV as per the voltage decomposition defined in [START_REF] Afnor | NFC 18510 -Opérations sur les ouvrages et installations électriques et dans un environnement électrique -Prévention du risque électrique[END_REF].

As discussed in the introduction, the focus of this thesis is on the protection of distribution networks in presence of DER. Therefore, in the rest of the thesis, the emphasis will be put on the distribution system where the distribution network is one component.

I.4. The distribution system

The distribution system is a set of primary radial circuits that a utility uses to deliver power from HV/MV substation(s) to the end customers. During operation, the distribution system can be subject to different types of faults that must be detected and selectively eliminated by a protection system to ensure a good continuity of power supply. Before analyzing the protection system of a distribution system, it is crucial to understand the different parts of this network, its components, structure, organization and control before and after the insertion of DERs (Distributed Energy Resources). To this end, the section I.4.1 gives a description of the distribution system which can be divided into four main parts:

-The HV/MV supplying primary substation(s) The HV/MV "primary" substation makes the interface between the transmission system and the distribution system. The HV/MV substation plays an important role in the security and the quality of supply to the distribution network. One or more backup supplies are found in these substations due to the N-1 requirement which enforces to ensure the continuity of supply whenever a supplying source or equipment is lost. Physically, the substation is generally composed of several HV and

-

.2. The MV network

The MV network is composed of a set of feeder circuits connected to the MV busbar(s) of the HV/MV substation. Each feeder has a backbone that can carry the circuit many kilometers away from the substation. The backbone has multiple tappedoff laterals and sub-laterals feeding MV loads or MV/LV distribution substations supplying the LV loads. Several distribution schemes can be found with distributed neutral point or not. In rural areas, loads are generally supplied through overhead lines or a mix of cables and overhead lines. As for urban areas, the power supply is generally done through cables. To ensure the continuity of supply, a feeder circuit may have one or more back-up feeders originating from the same or other HV/MV substations. An appropriate circuit reconfiguration is carried out following an outage or to relieve an overloaded circuit. In the US, reclosers are installed on MV feeder backbone or on the main laterals allowing more flexibility during circuit reconfiguration and making possible the isolation of the faulty circuit.

I.4.1.3. The MV/LV distribution substations

The MV/LV distribution "secondary" substation is the interface between the MV and the LV distribution networks. The MV/LV distribution substation is composed of MV incoming feeders, distribution power transformers and LV outgoing feeders. In addition, a set of devices for metering, remote control, measurement and protection can be found.

I.4.1.4. The LV network

The LV (Low Voltage) network is supplied by the MV/LV distribution transformers. In this thesis, the LV network will not be modeled and the LV loads will be considered as "aggregated" loads at the MV level.

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.2. The components of a distribution network

The previous section discussed the main parts of a distribution network. In this section, an overview on the distribution network components is given..

I.4.2.1. Power transformers

The purpose of power transformers is to transfer electrical energy from one voltage to another. Power transformers can be found in HV/MV transmission substations where they generally step-down the voltage to supply the distribution network. In this case, they are equipped with an on-load tap changer for voltage regulation to counteract internal voltage drop as well as HV voltage deviations. Power transformers are also found in MV/LV distribution substations. Very often, they can be installed on top of poles (pole-mounted transformers) when serving rural areas. In addition, power transformers can be used as step-up transformers especially when they are connected to decentralized generation located on the LV side of the distribution network.

I.4.2.2. Line voltage regulators

The line voltage regulator is a unit ratio power transformer that is generally installed in series on MV feeders. It is equipped with taps that allows a voltage control on the feeder.

I.4.2.3. Capacitor banks

The purpose of capacitor banks is to supply reactive power to compensate the reactive power needed for example on heavy loads spots. In traditional distribution networks where the power is supplied from the main HV/MV substation, the capacitor bank reduces the reactive power flowing from the upstream which, then, reduces the voltage drop. The capacitor banks can be of fixed type or voltage regulated.

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.2.4. Loads

A load can be thought of as a point of electric energy consumption. In the distribution network, the load may be balanced with the same current on the three phases or unbalanced if the load is not evenly distributed on the three phases. In addition, it can be single phase, phase to phase or three phase loads. As for three phase loads, they may be connected in wye or delta. In presence of DER (Distributed Energy Resources), some loads may have different behaviors. For example, an energy storage system may be momentarily charging (in which case it is seen as a load) or discharging (it is then seen as a source).

I.4.2.5. Conductors

A distribution network is made of several conductor sections of different characteristics connected to carry the power towards loads points. The conductor sections can be installed underground (cables) or overhead (lines). The conductors are specified according to several criteria: the rated current to carry, the voltage drop and the maximum short-circuit current at the installation point.

I.4.2.6. Circuit breakers

A circuit breaker is a mechanical switching device that has the capability of making, carrying continuously and breaking electrical current on normal operating conditions, but also the capability of breaking the fault current up to a specified value. It is used in conjunction with a protection relay which sends a command to the tripping coil to open the circuit breaker or a command to the closing coil during a reclosing sequence or a manual close.

I.4.2.7. Reclosers

A recloser is a circuit breaker equipped with a protection relay. It is designed to execute a preset open/close sequence before going to lockout. It is generally placed on MV overhead lines to improve the continuity of supply after a fault occurrence. In addition, it can be used for network protection or circuit reconfiguration.

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.2.8. Sectionalizers

A sectionalizer is a disconnector equipped with a relay that counts the number of operations of an upstream breaker or recloser during a fault sequence and opens when they reach the preset count while the breaker or recloser is still open. It can neither reclose nor break a fault current.

I.4.2.9. Instrument transformers

Instrument transformers are used to transform high primary voltages or currents into smaller values than can be safely handled by secondary equipment (protection devices for example). They have a primary winding which carries the primary voltage or current and a secondary winding to which secondary devices such as protection relays are connected. A transformation ratio is applied between the primary and secondary value of voltage or current. Instrument transformers that modifies the magnitude of current are referred to as "current transformers" (CT) and those transforming the magnitude of the voltage are called "voltage transformers" (VT).

In practice, a transformation error is introduced by the instrument transformer. The table I-1 gives the accuracy for current transformers used in protection applications.

For example, during its transformation, a conventional current transformer (CT) with an accuracy class of 5P introduces a maximum error of magnitude 5% of its nominal current for short-current values equal to their accuracy limit factor (ALF) while the current transformer is at its rated accuracy power Sn. On normal operating conditions, the transformation error is 1% of the nominal current of the CT.

Accuracy class

Current Besides these static errors, the instrument transformer has a transient response during fault conditions which may result in core saturation. As a result, a malfunction of the protection relays can follow. As can be seen, instrument transformers are very important in a protection system as they are the interfaces between power system and the protection relays.

I.4.2.10. Fuses

A fuse is a protective device consisting on a metallic element that melts to create a circuit discontinuity in presence of a faulty current that exceeds the fuse rating for a certain time. The fuse melts according to specific inverse time-current curve.

However, the fuse should allow normal operating currents and overloads to flow without deteriorating.

I.4.2.11. Protection relays

A protection relay is a device that responds to signals from instruments transformers (current transformers, voltage transformers) and commands a circuit breaker to open under faulty conditions. One of the main challenges of protection relays is to ensure a good stability of the relays during current transformers (CT) saturation as the protection relays face a large current transformation error and the current measured by the relays is altered [10]. For many years, the traditional electricity distribution network was passive as the electric power was only supplied in top-down from the transmission network via HV/MV substation. There was no embedded generation. The distribution feeder was radial as there was only one path for the power to flow from the feeding substation to the end users. In the same way, there was only one path for the short-circuit currents to flow from the source (which is the HV/MV substation) to the fault inside the distribution network.

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.3.2. Control of traditional distribution networks

The distribution network has been historically controlled and monitored by a SCADA located at a Control Center in a centralized approach where Control Center operators manage the circuit reconfiguration, the switching of capacitor banks, the voltage control, amongst others. Besides this remote control, the substation could be controlled locally through a substation automation system (SAS) or manual commands from operators. Recently, the concept of "feeder automation" has been introduced to perform some automation function under the feeder control.

I.4.3.3. Protection of traditional distribution networks

In the absence of decentralized generation, the distribution network is considered as radial and fed from the main power station. If a fault appears downstream of an MV feeder connected to the main power station, only the main substation is contributing to that fault. Thus, the short circuit current will be flowing from the main substation to the fault (upstream to downstream). To achieve a protection coordination in this context, the basic idea has been, up to now, to create a grading margin between the protection devices in cascade in the fault path to eliminate the fault while restraining the outage to the only affected section.

Traditionally, overcurrent-based protection devices (fuse, recloser and overcurrent protection relay) are used on distribution networks. Several technologies of protection relays (electronic, digital) may be found with or without direction detection functionality. Also, in some distribution networks, sectionalizers are added to the landscape to improve the fault location and isolation in conjunction with reclosers.

Basically, the current flowing on the circuit is supervised and should the magnitude of this current exceed a preset threshold for a time delay, the protection device that is the closest to the fault will open to isolate the fault, leaving the rest of the circuit energized. The tripping time delay is according to a preset time-current characteristic.

More details are given in chapter II on the philosophies of protection used on both passive and active distribution networks. There is no consensus on the definition of DERs but the Institute of Electrical and Electronics Engineers (IEEE) defines the DERs as "sources of electric power that are not connected to a bulk power transmission system. DER include both generators and energy storage technologies" [START_REF]/ D6.0 -Draft Standard for Interconnection and Interoperability of Distributed Energy Resources with Associated Electric Power System Interfaces[END_REF]. In Europe, the term DERs includes the decentralized generation, the storage and the controllable loads. The definition of IEEE will be considered as it suits better the application (protection coordination) we will discuss further from chapter 4. The load controllability has no effect on our protection scheme as the loads manipulated in our application are aggregated at the MV level. Also, storage systems are considered as loads during their charging period and sources when they are discharging.

In the rest of the section, the different technologies of decentralized generation will be presented with their current contribution during short-circuits. In addition, the challenges the protection coordination must face in presence of DERs which will be discussed.

I.4.4.1. The decentralized generation

Basically, the decentralized generation covers all the power generation sources recently installed on the distribution network and at the end users' premises following the deregulation of the energy markets. In fact, the deregulation of energy markets has set incentives to promote the power production from renewable energies. The decentralized generation can be classified according several criteria: the primary energy used, the technology of power conversion. According to the primary energy used, there are two categories:

-Renewable energy based decentralized generating sources also known as intermittent generating sources: example of solar PVs and wind generators.

Because the input primary energy is based on weather conditions which is not perfectly known, these generating sources have a stochastic behavior;

-Non-renewable energy based decentralized generating sources such as smallscale diesel generators. They have a deterministic behavior causing the energy produced to be dependent on the injected primary energy. -Synchronous machines;

-Induction machines;

-Inverter-based generation sources which are interfaced to the grid through power electronics: case of solar PV installations for example.

Synchronous machines:

The synchronous generator has three impedances [START_REF] Kundur | Power System Stability and Control[END_REF]: the subtransient positive sequence reactance (X''d), the transient positive sequence reactance (X'd) and the synchronous positive sequence reactance (Xd) with X''d<X'd<Xd. As a result, the short-circuit contribution of the generator differs according to the current reactance of the generator. If a short-circuit is applied at the terminal of a synchronous machine, the current will start out very high and decay to a steady-state value. Synchronous machines generally deliver about six times the rated current for several cycles before decaying to between 400% and 200% of rated current [START_REF] Phadke | Computer relaying for power systems[END_REF].

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If a short-circuit is applied at the terminal of an induction machine, the current will start out very high before decaying rapidly to zero due to the demagnetization of the machine. The induction machines deliver about six times rated current during this very short time (usually from one to three cycles) [START_REF] Keller | Understanding Fault Characteristics of Inverter-Based Distributed Energy Resources[END_REF].

Power electronics interfaced generating sources:

On power electronics interfaced decentralized generators, the short-circuit contribution of inverters is less than 200% of the inverter rated current [START_REF] Keller | Understanding Fault Characteristics of Inverter-Based Distributed Energy Resources[END_REF].

As we can see, the different types of decentralized generators respond differently during short-circuits. On normal operating conditions, the output power of intermittent generators is dependent on weather conditions.

I.4.5. The distribution network in presence of DERs

As discussed previously, the distribution network operation, planning and protection are impacted by the presence of DERs. In this section, the highlight is only put on aspects related to protection coordination. Before developing the protection issues introduced by DERs, we present the new network architecture. Then, the challenges on control and protection of the distribution system are discussed.

I.4.5.1. Conceptual architecture

In the new paradigm, the network control becomes more complex with the new actors. In addition, the power flow becomes bi-directional and the short-circuit currents have several paths to flow: from the traditional main source (which is the HV/MV substation) to the fault on one hand and from the decentralized generators to the fault on the other hand.

I.4.5.2. Control of distribution networks in presence of DERs

In the traditional control scheme, the centralized control scheme requires several teams of network operators. In addition, the central control scheme becomes more

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Public complex in presence of DERs. Therefore, the question of the relevance of the current centralized control scheme arises. A mechanism for providing an MV feeder with the maximum relevant information to help it better perform critical functions such as protection coordination, voltage profile mitigation, circuit reconfiguration amongst others could be very interesting and could also open new perspectives for feeder automation. The question is not to declare the current centralized control inefficient and useless but to relieve control operators at the Control Center by assigning more tasks to MV feeders in a new control scheme combining the centralized and decentralized schemes.

I.4.5.3. Protection coordination issues in distribution networks in presence of DERs

The protection system must adapt to the presence of DERs. To do so, it is important to understand the challenges introduced by DERs on protection coordination.

Amongst these issues, we have the unnecessary protection tripping, the protection blinding, the fuse premature blowing, islanding detection concerns, difficulty of reclosing after a fault, grounding concerns, lack of protection coordination in islanded mode. In this section, these challenges are presented. An MV network consisting of two MV feeders (Feeder 1 and Feeder 2) with distributed generators (DG1-4) on each of the two feeders is used to highlight some protection concerns introduced by the presence of distributed generation. source and from the decentralized generators (DG). It is important to mention that on feeder 1, the direction of the fault current is from the MV bus to the three-phase fault point while on feeder 2, the direction is towards the MV bus due to the infeed from the generator DG4. If the fault current measured by the protection relay on each feeder exceeds the preset overcurrent thresholds, the two relays will trip should the relays are not fitted with the directionality. As a result, an undesired tripping will occur on the adjacent sound feeder (feeder 2) for a fault on feeder 1. The presence of decentralized generation into the electricity distribution network also affects the fuses. Specifically, a fuse is selected based on a maximum load on the feeder and a short circuit current on the protected circuit. But, due to the contribution of decentralized generation, the total short circuit current crossing the fuse is increased in such a way that a premature fuse blowing could be experienced as mentioned on Fig. I-5. The common practice would recommend, for a fugitive fault, to enable a high-speed reclosing to save a downstream fuse from blowing.

Consequently, to improve the selectivity in presence of decentralized generation, it is Decentralized generation (DG) is normally supposed to stop energizing a portion of the network that has been separated from the main power distribution grid. In other words, to avoid the continuous energization of a fault for example, the DG should be decoupled by a loss of mains protection. Generally, the loss of mains protection is not an efficient means to detect the absence of the main power supply especially in presence of DG. This point is of importance mainly for security reasons but also for the service restoration. In the traditional passive distribution network, an auto recloser could decide to reclose after a fault without taking care of what is happening downstream. Indeed, traditionally, there was no other source except the main power source at the HV/MV substation. But, in presence of DG, care should be taken to coordinate the reclosing with the neighboring sources for two reasons:

situations could arise such as closing a circuit breaker out of synchronism (main power supply and the DG not necessarily synchronized);

in passive distribution network, the typical dead time value for high speed reclosing is between 100 to 500ms. This dead time must be reconsidered in presence of DG otherwise if the reclosing order comes too fast, there may not be enough time to extinguish the arc.

I.4.5.3.6. Lack of coordination in islanded mode

In islanded mode, the protection settings in grid connected mode are not necessarily valid and may need to be updated due to the reduction of the short circuit current.

Moreover, a coordination is required between overcurrent and under voltage thresholds on the generating sources (example of DG4) as depicted in the Fig. I-6. The presence of Distributed Generators (DG) can create different neutral point arrangements. On one hand, when the secondary side of the power transformer connecting a DG (call it TR-DG) to the main power supply is coupled in wye and earthed, then in case of earth fault on the MV network, both neutral point at the main power supply side and the neutral point of TR-DG will be contributing to the fault current. On the other hand, during the islanded mode, two situations may arise: a neutral point fixed by TR-DG or an isolated neutral point. As a result, these situations will influence the protection against earth faults and the network security.

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In the light of the previous sections, it clearly appears that the introduction of DG in the initial traditional passive network has created several concerns on protection coordination that must be addressed carefully. The protection strategies will be discussed in the chapter 2.

I.4.6. Different types of network configuration

The design of the zone differential protection we want to investigate in this thesis requires the knowledge of the network connectivity of the distribution feeder including the loads, the capacitor banks, line voltage regulators, generators, circuit breakers, reclosers, etc. and the connectivity between them. There are several network configurations on distribution networks amongst which:

the radial configuration where the loads are supplied via individual circuits from the HV/MV substation without interconnection to any back-up HV/MV substation. In this configuration, the protection coordination is generally based on simple overcurrent protection relays with a time/current grading between them. However, the radial configuration may be more sophisticated in presence of reclosers;

the open loop configuration where the one supplying HV/MV substation is interconnected to at least another neighboring HV/MV substation via switches.

On normal operating conditions, by opening switches at appropriate points, the network can be operated as a radial circuit;

the looped configuration which are more complex and where basic overcurrent protection relays cannot ensure a good protection coordination. Distance or directional protection are required in this configuration.

Whatever the configuration, an important and determinant element is the knowledge of the position of circuit breakers and reclosers as it is used for the creation of zones of protection.

I.4.7. Neutral configurations

The study of the neutral configuration is very important as it determines how the earth is connected (grounding) on the source side, hence the earth current flow according

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Public to the grounding method. The main purposes of grounding are to minimize potential transient over voltages to comply with local, state, national codes for personnel safety requirements and to assist in the rapid detection and isolation of the trouble or fault areas [START_REF]IEEE PES AMPS DSAS Test Feeder Working Group, IEEE 123 nodes test feeder[END_REF]. The MV neutral configuration is defined at the HV/MV power transformers located at HM/MV substations and is very important when dealing with protection aspects because each neutral arrangement dictates a different protection scheme. In this section, two main MV networks are presented: three phase MV networks with 3 wires as in Europe and three phase MV networks with 4 wires as in the US.

I.4.7.1. Neutral configurations used in Europe

In Europe, the MV distribution networks are composed of 3 wires for the three phases. Four different neutral arrangements can be found as described below:

directly earthed neutral point where the MV neutral point of the HV/MV power transformer at the main substation is directly connected to the earth (Fig.

I-7-a).
In this case, the earth fault current is important and can exceed the three phase fault current.

isolated neutral point where there is no direct link between the system neutral as a compromise to avoid high stresses on equipment, to reduce the disturbances on telephone networks, while taking full advantage of the protection system performance, especially the sensitivity [START_REF] Croguennoc | Protection des réseaux à moyenne tension de distribution publique, D4810[END_REF]. In this example, a generator below 110kV must disconnect during a fault when the associated voltage drop reaches Uret for a duration of tclear (time to clear). As we can see, the protection system must adapt to the constraints defined by the grid code as it is crucial to coordinate the time to clear required on generators with zone differential protection where there are in-zone generating sources, etc.

In the US, the IEEE 1547 set of standards define the interconnection technical specifications and functional requirements for DERs. The objective of a protection coordination system is to protect electrical assets against the impacts of short-circuits, but also ensure the continuity of the power supply by disconnecting the faulty part from the rest of the electrical system. The protection coordination consists in arranging the settings on protective devices installed on the network to detect and eliminate the fault on the affected part of the network. This function is critical and should be ensured in any case including in presence of DERs.

I.4.9.1. Problem formulation

To ensure the protection coordination, several philosophies based on distance protection [START_REF] Sinclair | Distance Protection in Distribution Systems: How It Assists With Integrating Distributed Resources[END_REF], [START_REF] Sirsi | Application of Fault Current Limiter to limit Distributed Generation effect on Distance Relay Coordination[END_REF], fault current limiters [START_REF] Li | Overcurrent protection coordination in a power distribution network with the active superconductive fault current limiter[END_REF], [START_REF] Sirsi | Application of Fault Current Limiter to limit Distributed Generation effect on Distance Relay Coordination[END_REF], IEC 61850-based logic selectivity [START_REF] Giustina | Toward an Adaptive Protection System for the distribution grid by using the IEC 61850[END_REF], overcurrent-based adaptive protection with change of setting groups [START_REF] Ishchenko | Practical Implementation of Adaptive Protection and Control in a Medium Voltage Microgrid[END_REF],

overcurrent-based adaptive protection with dynamic change of settings have been proposed [START_REF] Bhattarai | An Adaptive Overcurrent Protection in Smart Distribution Grid[END_REF]. Unfortunately, while these approaches have the advantage of somehow improving the protection coordination, there is still room for improvements.

Firstly, for distance or overcurrent-based protection schemes, the impact of the intermediate infeed may create an under-reaching phenomenon [START_REF] Sinclair | Distance Protection in Distribution Systems: How It Assists With Integrating Distributed Resources[END_REF] (for distance relays) and loss of sensitivity or relay blinding.

Secondly, the data exchange between the MV feeder and the Control Center is not fully used due to the difference between their data models, CIM (Common Information Model) at the Control Center and IEC 61850 at the MV feeder level.

Therefore, the gaps between these two data models need to be studied.

Thirdly, in the current protection coordination strategies, the evolution on the feeder network connectivity model (addition of a new customer or substation or generating source, decommissioning of equipment) is not dynamically integrated into the protection scheme in operation time. In addition, the modification of the electrical characteristics of an equipment is not known by the protection system itself except by protection engineers who are obliged to make a coordination study to check the validity of current settings. The protection system has no means to integrate the Fourthly, an MV feeder may momentarily extend to a back-up feeder following a circuit reconfiguration for instance. In this case, it is important for the feeder to integrate to its control the network components that were initially connected to a back-up feeder for example. For several resources, this may be viewed as a change of "jurisdiction". The protection scheme could be more intelligent to adapt to these changes.

Besides the previous aspects related to protection coordination, the network control architecture should also adapt. Historically, the distribution network has been monitored from the Control Center in a centralized architecture. All the substations and field devices were controlled from the Control Center, leading to consequent data flows between substations and Control Center on one hand, and between the field devices and Control Center on the other hand. The current centralized control model will be more and more inefficient and unrealistic in some point of view due to the need of increased controllability and observability, the geographically large scale of distribution networks, the necessity of active control with DER introduction, the need to monitor the Electric Vehicles (EV) and the Demand Side Management (DSM), among others. Therefore, a centralized control architecture becomes extremely complex and communication-intensive in such a way that questions arise about the relevance of this control architecture. One of the main questions today is how to design a control system that combines both centralized and decentralized control architectures avoiding being in an "all centralized" or "all decentralized" control architecture?

However, the decentralized control at a distribution feeder controller level would require an interaction between, on one hand, the Control Center which uses the CIM Addressing these hindrances could give many possibilities to feeder automation and increase the resiliency of the control system while relieving the network operators.

I.4.9.2. Research objectives and scientific contributions

This research work was intended with one objective in mind: to create an added value on protection coordination on active distribution networks by providing the MV feeder with its matrimonial base. Basically, the distribution feeder does not have any knowledge about the downstream network it is supplying. So, the scenario is to use the fruit of the harmonization between the CIM and IEC 61850 data models to provide a distribution feeder with the network connectivity model of the downstream circuit it controls to help it better perform some automation functions such as the protection coordination. A controller located at the head of the distribution feeder will analyze the incoming network model and split it into zones on which a so-called "Zone Differential Protection" will be applied in collaboration with protection relays located at zone boundaries. The protection relays at the zone boundaries will send their instantaneous electric currents to the feeder controller to check the current balance in each zone. The instantaneous currents from all the components (intermittent and non-intermittent generating sources, the load currents at MV/LV substations, capacitor banks, the current injection at the boundaries, etc.) within each zone are assessed to check the current balance in the zone. In addition, the status of circuit breakers or reclosers are sent to the controller. The fact that the differential protection is self-selective and fast makes it a good candidate for the protection of distribution networks in presence of Distributed Generation (DG).

I.4.9.3. Conclusion

The protection coordination on distribution networks becomes more complex in The objective of a distribution system operator is to deliver electric power to its customers with a good quality of supply under the constraint of optimal capital and operational costs. The electric power is supplied from substations connected to customers via distribution feeders. Basically, a good quality of supply is a good continuity of supply while ensuring that the voltage and the frequency of the supplied energy stays within predetermined limits. Keeping the voltage and the frequency in certain limits is the task of voltage and frequency regulation systems which are out of the scope of this thesis. In this section, we will focus on the protection system as an essential function for improving the continuity of supply on the distribution network. In fact, the power system is subject to disturbances originating from either endogenously (example of a grid operator error or an ageing of the insulators) or exogenously due to lightning strikes, animals, growing trees, grid operator error among others. Whatever the origin, these disturbances may produce short-circuit currents flowing from the different generating sources to the fault location. The protection of distribution networks consists of installing protection devices at specific points of the distribution network and arranging their settings for efficiently protecting both electrical equipment and people against the dangerous effects of faults. This activity is referred to as protection coordination.

A properly coordinated 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 [START_REF] Lakervi | Electricity Distribution Network Design[END_REF]. To achieve this coordination, different protection schemes exist. In this section, the emphasis will be put only on the protection of the MV distribution networks. The objective of this section is to present the protection coordination techniques traditionally used on passive distribution networks. Then, the protection coordination philosophies on active distribution networks are analyzed with their advantages and drawbacks from which a zone differential protection scheme is proposed.

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II.2. Definitions

Before reviewing the protection coordination strategies, a few definitions along with the basic requirements of a protection scheme are given for a better understanding of the further sections.

Current grading: difference of current magnitude setting between two consecutive protection relays.

Minimum short-circuit current: minimum current magnitude measured by a protection device during a fault.

Overcurrent relay: a protection relay whose decision is related to the degree by which the measured current exceeds a set value [START_REF] Areva | Network Protection & Automation Guide[END_REF].

Protection system: a combination of protection equipment designed to secure, under predetermined conditions, usually abnormal, the disconnection of an element of a power system, or to give an alarm signal, or both [START_REF] Areva | Network Protection & Automation Guide[END_REF].

Relay operating time: time delay that elapses between the detection of the fault by the relay and the instant where the relay issues a trip command.

Relay pick-up: a relay is said to "pick-up" when it changes from the de-energized position to the energized position [START_REF] Areva | Network Protection & Automation Guide[END_REF]. For example, when the electric current measured by the relay exceeds a preset threshold, the relay will pick-up.

Selectivity path: path defined by the set of all protective devices involved in a fault from one source to the fault location.

Setting: preset value of the 'energizing' quantity (voltage, or current or a combination of them) over/under which the relay is expected to operate.

Setting group change:

to adapt the protection settings to different network contexts, modern relays have several setting groups containing each, the same set of protection functions but with possibly different settings.

Time grading: the time interval that must be allowed between the operation of two adjacent relays to achieve correct discrimination between them [START_REF] Areva | Network Protection & Automation Guide[END_REF].

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Public II.3. Basic requirements of a protection system A distribution network is subject to different types of faults which may appear on any part of the network. These faults may be shunt faults or series faults. Shunt faults involve one phase with the ground, two phases with or without ground, three phases with or without ground. A series fault is typically a broken conductor for example. But, whatever the type, the faulty part should be disconnected from the network. However, in Petersen coil grounded networks, a phase to ground fault could be treated as temporarily operational. In this case, the first fault is tolerated while the second gives place to a trip. The objective of the protection system is to detect the fault and open the faulty circuit (exclusion of the electrical network operated with a fault) either by sending a trip order to the appropriate circuit breakers/reclosers or via a fuse blowing.

To perform its tasks, the protection system must ensure some basic requirements:

-Selectivity: the protection system should disconnect the smallest portion of the power system affected by a fault to minimize the impact of the outage on customer supply. The selectivity can be ensured via basic current magnitude, time criteria, directional criteria; hence, unnecessary customer shortages can be avoided;

-Operating speed: when we are dealing with protection topics, one important thing to have in mind is that protection belongs to the so-called "critical applications". As such, the notion of speed is critical because the effects of faults can be very dangerous for electric equipment (damages on insulation, electrodynamic stresses, fire, among others) and for people and animals (high touch voltage). In addition, the fault clearance time which is the sum of the protection and the circuit breaker operating times counted from the fault occurrence, has a decisive impact on network stability. Moreover, some types of loads cannot withstand for a long time the under voltage induced by a fault.

Consequently, the fault clearance time is a key parameter on a protection system:

-Sensitivity: it is the ability of protection system to detect the smallest possible fault current: the smaller is the current, the more sensitive is the protection. This

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Public sensitivity will be affected by the measuring devices in charge of the current acquisition (current transformers) but also by the level of the short circuit power;

-Reliability: the protection system must fulfil its function in its whole operational lifetime. [START_REF] Phadke | Power system relaying[END_REF] considers that relays, in contrast with most other equipment, have two alternative ways in which they can be unreliable: they may fail to operate when they are expected to, or they may operate when they are not expected to.

In this respect, [START_REF] Phadke | Power system relaying[END_REF] decomposes reliability into two branches: dependability which is the measure of the certainty that the relay will operate correctly for all faults which they are designed to operate and security which is the measure of the certainty that the relay will not operate incorrectly for any fault.

The equations below, giving the expressions of dependability, security and reliability [START_REF] Phadke | Power system relaying[END_REF], will be used later to assess the performance of our proposed protection coordination solution. Any protection scheme should have the target to maximize the previous objectives.

II.4. Protection of passive distribution networks

In historical electricity distribution networks, MV feeders were generally operated in radial configuration. The power was flowing in one direction, from the source (main HV/MV substation) to the load. The protection coordination was designed by considering no embedded generation in the distribution network. As a matter of fact,

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Public such a network was referred to as a "passive" network. The main protection devices in a traditional distribution network are the protection relays, reclosers and fuses.

These devices are arranged to ensure the selectivity using the different coordination techniques presented below.

II.4.1. Overcurrent-based protection coordination technique

In traditional electricity distribution networks, the MV feeder is in general protected by overcurrent protection devices which use overcurrent as a criterion for detecting faults. The protection device operates should an electric current value is exceeded.

The basic idea is that, during a fault, the short-circuit current increases as the fault is close to the source. Thus, this behavior is utilized to create a discrimination between protective devices in cascade. As illustrated in Fig. II-1-a, the short-circuit current measured by the protection relay PR1 is higher for a fault at F1 than for faults at F2 and F3. So, the selectivity can be done based on the fault current variation along the circuit.

For the fault F3, the selectivity path is between the fuse F, the recloser R and the upstream protection relays PR1, PR2 and PR3. There are two approaches to ensure the selectivity between the fuse and the recloser (direct upstream protection device):

the fuse blowing scheme where the fuse blows during the fault downstream;

the fuse saving scheme in which the upstream recloser de-energizes the circuit at the fault occurrence to avoid the fuse blowing for fugitive fault. The fuse blowing is allowed only should the fault be permanent.

Therefore, the criterion for protection operation is that the flowing current exceeds the preset threshold (Is) during a preset time delay (ts). The operating time of the protection device may have a constant or inverse characteristic. With a constant characteristic, the operating time is constant for any current magnitude above a preset overcurrent setting Is whereas in an inverse characteristic, the operating time decreases as soon as the measured current increases above Is. the overcurrent settings are generally non-directional. In this case, the upstream capacitive current flowing from sound feeders towards the faulty feeder during an earth fault may create the so-called "sympathetic" tripping on these sound feeders should the flowing current exceed the non-directional earth settings.

The "sympathetic" tripping may also be created by the short-circuit current contribution from one or more distributed generator(s) connected to an adjacent feeder and feeding a fault on a faulty feeder.

II.4.2. Coordination based on a direction criterion

To tackle the issue of "sympathetic" tripping on these sound feeders, a voltage input is added, where appropriate, to the simple overcurrent measurement to define a current flow directionality.

In the principle, the phase shift between the voltage and current is used to define an operation area and a restraining area. The overcurrent protection relay operates as soon as the operating point falls within the operating area and restrains otherwise.

The two main criteria for the operation of the overcurrent protection relay are:

the short-circuit current and voltage magnitudes should be above respectively the overcurrent and voltage settings and the phase angle between the voltage and current should be within the predefined angle operating range

In this technique, data exchange between directional elements of different protection devices is not a 'must' in general. However, it may be required to ensure selectivity under drastic time constraints.

It is important to note that the direction criterion is also used on distribution networks operated in loop or when the main feeder is supplied in back-up by a neighboring feeder from the same supplying substation as the main feeder or from another HV/MV substation. In fact, when the supply is from a back-up source, there may be an inversion of the power flow and short-circuit current. The selectivity paths may also be inverted. As described in [START_REF] Sautriau | Protection des réseaux par le système de Sélectivité Logique[END_REF], the basic principle of logic selectivity is that any protection device affected by the fault will send:

a logic wait signal (LWS) to the upstream protection stage;

a tripping signal to the circuit breaker to which it is associated.

As shown on Fig. II-2, the protection relay PR1 sends a logic wait signal to the relay PR2 whenever a fault appears on the downstream side of PR1.

The basic idea is to temporary block the fast threshold of the upstream overcurrent protection following a pick-up on the neighboring downstream protection. However, a second threshold (time delayed) is available at the upstream level in case the downstream protection fails to trip its associated circuit breaker.

In this technique, enough short-circuit current is necessary to create a relay pick-up.

Then, the relay will be able to send the logic wait signal upstream. Therefore, there is a data exchange between the different stages of protection devices involved in the selectivity path.

. Conclusion on protection coordination techniques on passive distribution networks

The previous protection coordination techniques have been used for long time in traditional passive distribution networks and have proven to be effective most of the time. In addition, a single setting of protection devices was enough to establish the protection coordination even though, in some cases, a change of setting group may be used. But unfortunately, these techniques will not be efficient in presence of distributed generation due to bi-directional short-circuit current and power flow and other concerns mentioned in the chapter 1 such as the risk of fuse premature blowing, relay blinding, among others. Therefore, a lot of researchers have investigated new protection schemes that adapt to network changing conditions particularly in active distribution networks. In the literature, the term "adaptive protection" is used to characterize this new protection philosophy. Adaptive protection is an automatic procedure that monitors and amends protection relay settings to make them better attuned to prevailing system operating conditions [START_REF] Phadke | Computer relaying for power systems[END_REF]. In [START_REF] Ishchenko | Practical Implementation of Adaptive Protection and Control in a Medium Voltage Microgrid[END_REF], the author discussed an IEC 61850-based protection coordination approach implemented in Hailuoto island pilot project. In his approach, the author suggested to automatically adapts the protection settings to the changes in network conditions via a setting group change. The scheme uses a communication-assisted concept with an IEC 61850-based data exchange between field protective relays and the protection relay at the main feeder. To note that, in the proposed solution, the setting group change required on the protective relays along the feeder is managed by a centralized grid automation controller (playing also the role of gateway for communications between substation and control center) located at the HV/MV substation. In [START_REF] Bhattarai | An Adaptive Overcurrent Protection in Smart Distribution Grid[END_REF], a combination of a local adaptive and communication assisted central protection is proposed, whereby the relay settings are dynamically updated based on online identification of the network topologies and status of DERs.

Particularly, the local adaptive protection updates relay settings based on DERs status ON/OFF employing locally acquired information, whereas the centralized protection updates the relay settings during major changes in grid topologies:

network reconfiguration and switching between islanded and grid connected modes.

Two phase overcurrent thresholds are used (for multi-phase faults): the low threshold have an inverse time characteristic used to monitor the overloads whereas the high thresholds have a definite time characteristic set at the same time delay with different current settings. The TMS (Time multiplier setting) of low overcurrent threshold is dynamically adjusted on changing network conditions. In these approaches, the first drawback is the risk of protection blinding could be a real issue on distribution Basically, a distance protection uses the voltage and current measured locally to compute the total impedance between the relay position to a fault. This total impedance is correlated to the impedance per unit of length to give the distance to the fault. [START_REF] Sinclair | Distance Protection in Distribution Systems: How It Assists With Integrating Distributed Resources[END_REF] proposed a solution based on a mix of traditional overcurrent protection and distance elements. In the principle, two overcurrent protection thresholds are used in combination with distance elements. The zone 1 of the distance protection is used to trip very rapidly for fault very close to the feeder source. It is coordinated with a fuse saving scheme allowing then to save the fuse for transient faults. The reaches on other distance forward zones (zones 2 and 3) act as a back-up to overcurrent protection depending on the presence or not of a midline recloser.

But, while this solution compensates for many limitations of overcurrent relays, provides an adaptive adjustment of the zone reach for both phase-to-phase and for phase to earth faults together with an adaptation to heavy load situations, it has some disadvantages. Firstly, the proposed solution may be weakened on some network conditions such as an insertion of distributed generator is the zone 1 reach.

In this case, the fault current infeed from decentralized generations creates an underreaching phenomenon that may prevent the distance protection from seeing the fault in the right zone and, in some cases, not tripping. This is mainly the case when the DG is connected between the distance relay (at the main MV feeder) and the fault point. A distance protection relay is said to underreach when the apparent impedance measured by the relay is greater than the real impedance to the fault [START_REF] Areva | Network Protection & Automation Guide[END_REF].

Another situation is the connection of MV/LV transformers (of rated power greater than 2500kVA) close to the main MV feeder could be conflicting with the zone 1 reach. Secondly, the decentralized generators may create some issues in the direction determination as reported in [START_REF] Schaefer | Impacts of DER on Distribution System Protection, EES-UETP Course[END_REF]. Therefore, a forward fault could be seen in reverse.

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Fault current limiters

To reduce the contributions of distributed energy resources to the short-circuit current measured by the protection relays to avoid an update of the protection plan, authors such as [6], proposed an approach based on fault current limiters. A fault current limiter is a low impedance device that has no action during normal operation.

However, during fault it takes fast action by inserting high impedance in series with a DG (in general, the fault current limiting device is in series with the source that is likely to impact a protection coordination with its contribution to short-circuit). In the same vein, [START_REF] Barker | Determining the Impact of Distributed Generation on Power Systems, I. Radial Distribution Systems[END_REF] discussed a protection coordination scheme based on distance relay and fault current limiter to suppress the underreaching phenomenon introduced by the DG.

As we can see, this solution requires the installation of a fault current limiter in series with each decentralized generation. Also, the behavior of distributed generators with a fault current limiter in series is not covered in the light of the grid code requirements for generators during fault.

II.5.4. Logic selectivity-based protection coordination using IEC 61850

The principle of logic selectivity has already been presented previously in the protection of traditional distribution networks. This technique has proven to be effective in passive distribution networks where it was applied in radial, open loop and closed loop configuration (in combination with directional overcurrent functions) to reduce the fault clearance time while ensuring a good protection selectivity. [START_REF] Giustina | Toward an Adaptive Protection System for the distribution grid by using the IEC 61850[END_REF] applied this technique and combined it with a FLISR (Fault Location Isolation and Service Restoration) to improve the continuity of supply. The authors used IEC 61850 GOOSE (Generic Object Oriented Substation Event) messages to allow exchange of overcurrent pick-up signals between relays. A GOOSE is a service using a mechanism of publisher/subscriber to allow a fast and reliable system wide distribution of input/output values from a publisher to receivers through a multicast/broadcast method [START_REF]IS/ Amendment 1, Power systems management and associated information exchange -Part 7-2: Basic Information and communication structure -Abstract Communication Service Interface (ACSI)[END_REF]. More details on the IEC 61850 standard is given in the next chapter. The first drawback in the proposed solution is that the bi-directional power flow and short-circuit current flow require directional protection function.

However, as discussed previously, the presence of distributed generator may create

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Public an issue in the direction determination. Secondly, the pick-up overcurrent stage is not safe from blinding due to DG intermediate fault current injection, which may result in the non-operation of some protection thresholds. Thirdly, the network model is unknown to the controller which is monitoring the status of circuit breakers to determine the current configuration of the network. Therefore, the controller do not have the capability to automatically enroll the status of new upcoming circuit breakers in the protection scheme, which could be interesting especially during network model evolution.

II.5.5. Limitations of protection coordination techniques on active distribution networks

Although many techniques have already been proposed, they remain limited in scope. Their scope do not include the following aspects:

-Firstly, the protection scheme needs to be automatically adapted to changing network conditions (installation of a new circuit on an existing feeder, circuit reconfiguration, islanding operating mode, connection of new distributed generator, etc.), equipment parameters modification (replacement of an old power transformer, replacement of a line conductor), to cope with a meshed network including multiple infeed from DG;

-Secondly, the reduction of fault current at the main MV feeder level due to the infeed from DG may increase the fault clearance time of the main MV feeder. This fault clearance time is to be reduced for any fault, anywhere in the distribution network even in presence of intermediate infeed from DG.

II.5.6. Conclusion

In this chapter, we looked at the protection coordination techniques both on passive and active distribution networks with their advantages and drawbacks. To overcome all the limitations discussed previously, we propose a novel concept of protection scheme based on differential protection called "Zone Differential Protection" (ZDP). In fact, the differential protection has been used for long time on unit protection (generator, transformer, line, cable, motor, etc.). The basic principle is to check that the current entering the protected area is equal to the current leaving the protected P a g e 66 | 161 Public area. In the case of a distribution feeder, the Zone Differential Protection would be a wide area protection requiring data exchange between protection devices at remote locations. In the principle, a controller placed at the head of the feeder is first given the network model of the feeder. Then, from this knowledge, the feeder controller splits the feeder into zones and checks for each zone, the balance between entering, leaving and internal components (capacitor banks, storage, generators, loads) currents.

The modeling of the Zone Differential Protection will be developed in the chapter 4.

To Center and the distribution feeder located at the supplying substation, and on the other hand, a cooperation between protection devices at both feeder and field levels.

One of the key levers for efficiently achieving these data exchange is by exchanging information on a syntactic and semantic levels between the Control Center and feeder but also between feeder devices. In other words, the data model used at the Control Center (IEC Common Information Model) and the one used on the Substation/feeder/field levels (IEC 61850) must be interoperable. Interoperability is the ability of two or more IEDs from the same vendor, or different vendors, to exchange information and use that information for correct execution of specified functions [START_REF]IEC 61850 -Communication networks and system in power utility automation -Part 1 -Introduction and overview -Edition 2.0[END_REF]. This interoperability is only possible through harmonization which is obtained within a standardization framework. At IEC (International Electrotechnical Commission) level, the technical committee TC57 is concerned with issues related to power system management and associated information exchange. Much of the work within TC57 is focused on creating standards facilitating interoperability of communication and control systems used for power system control and operation.

The two core standards identified by IEC TC57 for implementing Smart Grid in the power utility automation are IEC 61850 and the Common Information Model [6].

In this thesis, two use cases are analyzed. The first use case dealing with the transfer of network model from the Control Center to the distribution feeder is discussed in this chapter as it requires the harmonization between IEC CIM and IEC 61850.

The second use case is concerned with a device to device data exchange to achieve a protection scheme. This part will be discussed in chapter 4 as it uses the IEC Before being able to achieve the first use case, it is necessary to understand both semantic and syntactic structures of each relevant data model. Therefore, in this chapter, we will first introduce the IEC 61850 and IEC CIM standards. The attempt is not to go into the details of the two standards but rather to give an overview on the data models. Secondly, the methodology for harmonizing the two data models will be covered. This will allow us to define the mapping rules between the two data models.

Thirdly, the status of the current activities related to harmonization between IEC 61850 and IEC CIM at the IEC TC57 level will be discussed. However, the scope of the harmonization will be restricted to the domain of our first use case. Finally, the constraints of the current IEC CIM and IEC 61850 data models for achieving later our second use case (see details in chapter IV dedicated to modeling) will be described.

III.2. IEC 61850 and IEC CIM

IEC CIM and IEC 61850 are two sets of standards maintained by the Technical Committee TC57 of the International Electrotechnical Commission (IEC). TC57 consists of several working groups (WG), each responsible for developing a standard that addresses a specific issue on power system communication and control [6].

Amongst others, the Working Group 10 is dedicated to standardization activities related to IEC 61850 while Working Groups 13 (IEC 61970), 14 (IEC 61968), 16 (IEC 62325) are dedicated to IEC CIM. To ensure the long-term interoperability, including between IEC 61850 and IEC CIM, the WG19 is in charge of the harmonization of the activities of all the Working Groups within the TC57 [START_REF]Power system management and associated information exchange, Current and future smart grid standardization activities[END_REF]. Even though they both refer to the same power system, the IEC 61850 and IEC CIM have been initially developed separately resulting in different data models. However, as shown in IEC 61850 is concerned with automation systems that consist of one or more Intelligent Electronic Devices (IEDs) connected by a communication system [START_REF]TS: « Power system management and associated information exchange -Interoperability in the long term -Part 2: CIM-IEC 61850 harmonization[END_REF]. The goal of this standard is to provide interoperability between the IEDs from different manufacturers or, more precisely, between application functions to be performed in the power system hosted in the IEDs from different manufacturers [START_REF] Iec | 2020 -Power systems management and associated information exchange -Part 5: Communication requirements for functions and device models, Edition 2.0[END_REF].

To this end, IEC 61850 has three components: The initial scope of IEC 61850 was the standardization of communication in substation automation systems. The first edition of the standard was primarily related to protection, control and monitoring. Then, the original parts of the IEC 61850 series, consisting of ten parts, were updated and extended to cover new areas amongst which:

-A data
-The communication between substations (IEC 61850-90-1); Before moving further, it is important to understand the modeling approach of IEC 61850 to see how the data to be exchanged is organized.

-

III.2.1.3. Data modeling approach

The approach of IEC 61850 as defined in [START_REF]IEC 61850 -Communication networks and system in power utility automation -Part 1 -Introduction and overview -Edition 2.0[END_REF] is to decompose the application functions into the smallest entities which are used to exchange information. The granularity is given by a reasonable distributed allocation of these entities to dedicated devices (IED). These entities are called Logical Nodes [4]. Knowing how the data is organized, the next step is to understand how to exchange the data. The SCL object model has five basic parts [START_REF] Sirsi | Application of Fault Current Limiter to limit Distributed Generation effect on Distance Relay Coordination[END_REF]:

1) Header: to identify the SCL configuration file and version;

2) Substation / Line / Process: to describe the functional structure of a primary process and identify the primary devices and their electrical connections inside substations and power networks. This part contains the electrical network model;

3) Product: this stands for all Substation Automation product-related objects such as IEDs and logical node implementations; it also includes distributed IEDs such as RTUs (Remote Terminal Units) typically installed on MV/LV substations along the distribution feeder; Initially the IEC 61850 was dedicated to Substation Automation. Today, the advent of DER have changed the electrical network paradigm especially on distribution networks which were traditionally passive. Therefore, the scope of IEC 61850 has been extended on many areas as discussed on section III. Public a result, the data exchange between these applications is difficult and requires the development of adapters between each two applications.

In addition, an exchange of network models is required between utilities to model the equivalent network of the neighboring utilities for planning studies. For this network model exchange to happen seamlessly, a common semantic model is required.

The Common Information Model (CIM) is an information model that allows the integration of data in a multi-vendor environment on one hand, and the exchange of network model between utilities on the other hand. The CIM model uses the Unified Modeling Language (UML) to represent all power system components into classes with their attributes along with the relationships between them. By providing a standard way of representing power system resources as classes and attributes, along with their relationships, the CIM facilitates the integration and interoperability of network applications developed independently by different vendors, between entire systems running network applications developed independently, or between a system running network applications and other systems concerned with different aspects of power system operations, such as generation or distribution management [START_REF]-Energy management system application program interface (EMS-API) -Part 301: Common information model (CIM) base, Edition 7, CIM17[END_REF]. As shown on Fig. III-4, the CIM consists in three main series of standards:

- The initial scope of the CIM was on balanced electrical networks (transmission and generation) according to the EMS (Energy Management System) perspective.

IEC

III.2.2.2. Data model

As discussed previously, the scope of the CIM is wide. However, we do not attempt to cover of the data model but only our domain of interest which is how to model an electrical network. The understanding of the two data models allows us to proceed with the harmonization in the next section. However, generic differences between the two data models can be highlighted before proceeding into the harmonization. Firstly, the CIM focused on EMS (Energy Management Systems) while IEC 61850 was on substation before 2009 and has been later extended to the power system. Secondly, to build a network model, even though the network connectivity parameters (terminals, connectivity nodes, etc.) are very similar between CIM and IEC 61850, the power system components identification method is different because where CIM has a genuine and unique ID, IEC 61850 uses the 'name' attribute as ID. Thirdly, the mapping between CIM classes and equivalent IEC 61850 ones is not always a oneto-one mapping because for some classes, it is a one-to-many mapping. Lastly, the CIM model is poor concerning the communication (IP address, VLAN, and so on) and protection aspects. The mapping consists in establishing a correspondence between power system components in both models to allow the model transformation. Fig. III-7 specifies the equipment mapping between IEC 61850 and IEC CIM as per [5]. As illustrated in Fig. III-7, the type of equipment in IEC 61850 SCL is defined by a type code whilst in the CIM the equipment type is defined by its concrete class. Table III-1, in the appendix A1, shows the type codes described in [START_REF]IEC 61850-6-Power systems management and associated information exchange -Part 6: Configuration description language for communication in power utility automation systems related to IEDs[END_REF]. More details of the mapping of those type codes to CIM classes, defined in [START_REF]-Energy management system application program interface (EMS-API) -Part 301: Common information model (CIM) base, Edition 7, CIM17[END_REF], is given in [START_REF] Iec | 2020 -Power systems management and associated information exchange -Part 5: Communication requirements for functions and device models, Edition 2.0[END_REF]. In addition, Table III-2 to Table III-6, in the appendix A1, depict the mapping related to power system components, equipment names, geographic position, connectivity elements and equipment containers. It is important to put the emphasis on the identification of the power system resources. In fact, each power system resource can be identified using the mRID and name attributes associated to the CIM IdentifiedObject class. While in IEC 61850, the power system resources inherits the name and desc attributes from the tNaming class. The most common issue is to map the CIM global unique ID mRID attribute to IEC 61850 which do not have this attribute. In lieu and place, IEC 61850 has the name attribute playing the role of its ID; which may be confusing especially during the model re-export. However, in our thesis, we have considered that the network model is only changed from Control Center where it is globally maintained. Therefore, as will be discussed further, the power system IDs should be defined from the CIM model and propagated to all the applications consuming these data.

P
The equipment mapping previously presented is a generic mapping process. In fact, to map power system components on unbalanced networks, more insight is

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III.3.2. Specificities of unbalanced distribution networks

With unbalanced MV distribution networks, it is necessary to consider the representation of power system resources on a per phase basis as the mapping discussed previously mainly covered three phase balanced elements.

On the SCL object model shown on

III.4. Conclusion

CIM and IEC 61850 are two core standards to achieve the Smart Grid Objectives [START_REF]Power system management and associated information exchange, Current and future smart grid standardization activities[END_REF]. In this chapter, we discussed the necessary alignment between the two data models along with the current harmonization activities at the IEC TC 57 level. Also, the mapping between power system resources in both data models has been discussed. This will allow us to convert our incoming CIM network model into IEC 61850 even though some parts are missing (protection functions, communication parameters for example). During specification time, the transferred file may be used by an IEC 61850 System engineer in lieu and place of the current specification method which is in paper format. However, during run-time, an 'on the fly' configuration process is needed for updating our feeder protection system.

The next chapter deals with the Zone Differential Protection based on the incoming distribution feeder network model. An unbalanced three phase distribution feeder is given its own network model to create zones of protection to which the differential protection principles will be applied. In this regard, an adapted version of the IEEE 123 nodes test feeder is modelled in CIM, then translated in IEC 61850 and finally supplied to a feeder controller for performing the needed protection scheme. The real value of bringing the computations on the field is that the remote service for protection settings changes can be easily achieved if based on IEC 61850.

IV.1. Introduction

A good analysis of a distribution power system requires a correct understanding of the behavior of the components composing this power system. Therefore, an adequate representation of those components is essential in each type of power system study to capture the power system reality. The representation of power system components will depend on the types of network analysis to achieve.

In this section, we will be interested in the study of a new zone differential protection applied to an electricity distribution feeder. Basically, the distribution feeder is split into different invariant zones. On each zone, the principle of the differential protection is applied to check that the balance between loads (internal loads and external load towards neighboring zones) and the generation (internal generation and current injections at the zone borders). The validation of such protection scheme requires to perform steady state power flow and short-circuit simulations. In addition, dynamics simulations are necessary. Therefore, the power system components representation should be done to allow for these types of analysis. Also, a prerequisite to any study of implementation of a protection scheme is to identify the technical constraints on the network that should be accounted for. To this end, the following technical aspects should be considered:

-The magnetizing inrush phenomenon appearing during power transformer energization must be considered. In fact, the magnetizing inrush is a transient current appearing on the primary side of a power transformer when it is being energized. As it drives a fault-like high current, this normal phenomenon must be accounted for; -The harmonic pollution from power electronics interfacing some non-utility generating sources with the grid; -The neutral configuration of the distribution network for managing the earth faults;

-The load pattern is not perfectly known; -The unbalanced phasing and loading should also be considered as the distribution network may consist of several one, two and three phase loads;

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Public -The topology changes due to circuit reconfiguration should also be accounted for since it potentially transfers part of the distribution feeder circuit onto another feeder acting as a back-up. Hence, the zone differential protection of the back-up feeder should integrate this new portion of network to the feeder centralized differential protection scheme; -The presence of intermittent generation which introduce uncertainty on their available output power and create many technical challenges on protection amongst which sympathetic tripping, premature fuse blowing, potential relay blinding, increase of the fault elimination time, etc.; -The presence of sources interfaced by inverters which short-circuit current contribution is limited to 120% of the inverter's rated current; -Any addition of a new component, decommissioning of a component, modification of an electrical parameter on an existing component may have a significant impact on the zone differential protection, which might result in unnecessary tripping. As such, the integration of these changes into the protection scheme during run-time, is a real challenge.

Through the different technical aspects mentioned above, we can see the distribution system is a complex. To study this system, we will consider a multi-faceted approach with four different levels of modeling.

In the first level of modeling, the distribution feeder is described in CIM model.

Recall that the Control Center uses an application called 'network model manager' which centralizes and maintains the distribution network model. This application is used by the Control Center to transfer the network model to the distribution feeder at the substation. Therefore, the Common Information Model (CIM) discussed in chapter 3 is used to describe each network component of the targeted distribution network in CIM by using CIM objects. Then, the description is contextualized and stored in a CIM XML file which is finally sent to the feeder to give it the knowledge of its downstream network. This approach has two main advantages: the first is to enable an easy integration of changes (addition of new equipment, deletion of an existing equipment, modification of electric parameters) on the network model into automation functions such as zone differential protection scheme by tying the network model to P a g e 90 | 161 Public these functions. The second advantage is to avoid being in an all-centralized control architecture by sharing part of the global knowledge with the feeder. This makes possible the so-called "feeder automation" which is the capacity of the feeder to perform automation functions (voltage control, wide area protection scheme, power balancing, circuit reconfiguration, etc.).

In the second level, we are interested in the study of the behavior of the electrical system. In this level, each distribution network component (synchronous generation, solar PV, load, capacitor bank, line voltage regulator, power transformer, etc.) will be modeled to put in evidence its physical behavior during a specific power system study like power flow or short circuit study.

For the sake of computations simplification, a third level has been added. This level utilizes the graph theory which is very helpful in the analysis of complex systems such as electricity distribution networks. In fact, the differential protection is expected to trip rapidly and isolate the only faulty portion of the electric network by sending a trip command to one to several circuit breaker(s) or recloser(s). Indeed, isolating a part of an electric network is only possible if there is a circuit breaker or recloser to disconnect that part. To do so, it is important to view the distribution feeder within a network paradigm that enables us to get the connections between the different components (connectivity). So, the idea is to transform the distribution feeder circuit into a graph which is then split at its boundaries into several sub-circuits called subgraphs, each representing an invariant zone on which a differential protection scheme can be implemented. An invariant zone is a zone which is insensitive to topology changes.

The fourth level is dedicated to the modeling of the electrical network components in IEC 61850 model. Even though the Control Center is sending a network model in CIM XML file to the distribution feeder, this later does not use the CIM model but the IEC 61850 model. It turns out that the incoming network model needs to be transformed into IEC 61850 model which is possible thanks to the harmonization results between the two data models. See chapter 3 for more details. In fact, today, the integration of the changes on the network model into a protection scheme demands the manual intervention of an IEC 61850 system engineer to create the SCD (System Configuration Description) and further generate the CID (Configured

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Public IED Description) files for protective devices. This approach is time-consuming, not error free and does not allow a direct integration of changes onto the automation functions during runtime. But, in the future, this network model update will be done 'on the fly' without any human intervention to update the feeder automation functions. But, before proceeding, it is important to give some basic principles on the differential protection before presenting how it can be applied to a distribution feeder.

IV.2. Basic principles of the differential protection

Kirchhoff's current law states that the current flowing into a node must be equal to the current flowing out of it. This principle is used in the differential protection which compare the magnitude of the current entering a protected area to the magnitude of the current leaving that area. Should the differential current be not zero, a fault is assumed to occur in the protected zone. See appendix A2 for more details.

The basic principles described in appendix A2 focused on differential protection applied to a high voltage transmission line. However, a distribution feeder circuit has many specificities that need to be analyzed before implementing the differential protection principles on it. To facilitate the understanding of the rest of the discussion, a few definitions are given in the following subsections.

IV.3. Reference distribution feeder IV.3.1. Definitions

Our objective is to apply the previous differential protection principles to a distribution feeder. However, to better understand the rest of the discussions, some definitions are necessary. Fig. IV-4 is used for illustration.

Definition IV-1 -Protected area:

A protected area is the area which is under protection. It is delimited by the current transformers located at the boundaries of the protected area. At any given time, when we refer to a fault at any bus within a specific zone, say zone 1, this fault is referred to as an "internal fault" relatively to zone 1. For all the neighboring zones (other than the faulty one), the fault is regarded as an "external fault".

Definition IV-4 -Zone boundary:

A zone boundary refers to the link between different zones. It is ensured by either a circuit breaker or a recloser. To isolate a faulty protected area, a trip command is sent to each of the zone boundaries to open them. Each zone boundary is equipped with a protective device connected to a current measurement.

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Definition IV-5 -Zone differential protection:

The zone differential protection corresponds to a differential protection applied to a zone which, in this case, represents the "protected area". Each zone includes at least one current infeed and one or several current outfeed (s), loads. Also, electrical equipment such as capacitor banks, generators, power transformer, storage system, amongst others may be present.

Definition IV-6 -Peripheral unit (PU):

The peripheral units have responsibility for collecting the required data, such as voltages and currents, circuit breaker/recloser status and processing it into digital form for onwards transmission to the central unit [START_REF] Areva | Network Protection & Automation Guide[END_REF].

Definition IV-7 -Central unit (CU):

The central unit performs the calculations required for the protection functions [START_REF] Areva | Network Protection & Automation Guide[END_REF]. In fact, at reception of the electric current samples and circuit breaker/recloser status from peripheral units, it calculates the differential current in the protected area after a time alignment of the samples to account for time latencies. Should the total injected current does not match with the total consumed current, a fault is assumed in the zone under consideration.

Definition IV-8 -Intertrip:

Tripping signal that is send to a remote protective device to open its circuit breaker or recloser. The intertrip signals are sent to the peripheral units by the central unit. In a zone differential protection context, the intertrip signals are sent to boundaries should a fault is detected within the zone.

Definition IV-9 -Zone of study:

We are basically interested in the protection of the distribution feeder which is the electric network extending from the circuit breaker at the supplying substation to one or more tie points downstream. For load flow and short-circuit studies, it is important to account for the supplying grid. Therefore, the zone of study includes the distribution feeder itself and the feeding source. However, our protection scheme will be only applied to the feeder.

. Specificities of distribution feeders

The distribution system consists generally in a set of radial feeders connected to one or several feeding substations. A circuit breaker placed at the head of the feeder (substation side) connects each distribution feeder to the feeding substation. In the rest of the discussion, we will focus on North American type distribution feeders.

In the US, the distribution network is in four wires as the neutral point is directly earthed and distributed at several points. In addition, the electricity distribution can be done on two to four wires through several laterals and sub-laterals tapped off the main circuit. Hence, the loads may be balanced or unbalanced. A few decades ago, when the circuit were small with a few customers, it was acceptable to open the circuit breaker at the head of the feeder to isolate a fault. Nowadays, with feeder circuits spreading over a large geographic area and with increasing demand related to quality of supply, reclosers have been introduced in the distribution feeders, giving the possibility to isolate smaller parts of the feeder during a fault. Basically, a recloser is like a circuit breaker in that it has the capability to break a short-circuit and perform a reclosing sequence.

Compared to traditional passive distribution feeder where the power generally comes only from one substation at a time, the current distribution feeder is active due to the presence of distributed energy resources (generating sources, storage and controllable loads) which contribute to the power flows and short-circuit currents. The variability of the output power of the generating sources is stochastic for intermittent sources and deterministic for non-intermittent ones. In addition, the circuit reconfiguration modifies the topology of the feeder circuit to mitigate some overload constraints or to restore the service after an outage. Though, the electricity distribution system is a complex and dynamic system. As a matter of fact, the differential protection principle presented above needs to adapt to this context. For the rest of this thesis, we use a reference distribution feeder on which the differential protection will be implemented.

IV.3.3. Choice of our test distribution feeder

A set of test feeders has been developed by IEEE (Institute of Electrical and Electronics Engineers) with the intend of providing the software developers with

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Public common data for validating some power system analysis functions such as power flow, optimal power flow, etc. To validate the differential protection, the selected test feeder should represent various distribution network specificities including the presence of reclosers to allow for the creation of protection zones for the simulation of both internal and external faults. In addition, the test feeder should include unbalanced loads and phasing to cover specificities of unbalanced distribution networks. This is typically the case of North American distribution networks. As a result, the IEEE 123 nodes test feeder has been selected as it consists of a large network with unbalanced phasing and loads, capacitors banks, line voltage regulators and many reclosers.

IV.3.4. Description of the test feeder network

The IEEE 123 nodes test feeder [START_REF]IEEE PES AMPS DSAS Test Feeder Working Group, IEEE 123 nodes test feeder[END_REF]

IV.3.5. Modifications brought to the test feeder

Firstly, to allow multi-directional power flows and short circuit currents contributions especially for protection coordination purposes, some changes have been brought to the base IEEE 123 nodes test feeder. These changes consist in the connection of :

-one 400kW diesel generator (D1) at node 18 through a 0.48/4.16kV-1000kVA-7%-Dyn11 power transformer; the 4.16kV side of the transformer is coupled in delta (D), the 480V side is in wye (yn) and the vector group is 11; -a second 400kW diesel generator (D2) at node 79 through a 0.48/4.16kV-1000kVA-7%-Dyn11 power transformer; the 4.16kV side of the transformer is coupled in delta (D), the 480V side is in wye (yn) and the vector group is 11.

Secondly, the normally opened reclosers have not been considered in our model.

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The normally opened reclosers are used for service restoration which are not in our scope. Finally, the load models have all been changed to 'constant power' to be able to perform time-series power flow simulations in OpenDSS as discussed further. In the rest of the document, the modified IEEE 123 nodes test feeder, shown in Fig. IV-5, will be referred to as 'reference network'.

IV.4. Modeling approach

In this section, we will discuss the modeling environment, the modeling tools and the modeling principles. Then, the modeling of the different network components will be introduced.

IV.4.1. Description of the modeling environment

As already explained previously, the Control Center has a global knowledge on the connectivity model of the distribution network. Unlike the topology, which is a snapshot of the network, the network connectivity model defines the physical connection of the network i.e. how the different components of the network are connected to each other regardless of the status of reclosers or circuit breakers. The network model, described in CIM model, is transferred to the MV feeder controller to give it the knowledge of the downstream network it is supplying. In this thesis, this knowledge is used to perform a zone differential protection scheme on an active distribution test feeder. To this end, a simplified Distribution Management System (DMS) has been modeled using an object-oriented programming language called Python. The

.2. Modeling tools

To analyze the active and complex distribution network for a protection coordination purpose, it is important to understand the impact of the variability introduced by intermittent sources, the impact of storage systems and both balanced and unbalanced loads, the contribution of the different generating sources to the short circuit current, the effect of harmonics, among others. In traditional passive distribution networks, the load flow calculations methods were using one of the network specificity, which is a radial circuit connected to a single voltage controlled bus. The insertion of distributed energy resources into the previous passive network has introduced new difficulties in the distribution network modeling. One of these difficulties is the multi-directional power flows. Another difficulty is that the distributed energy resources come in many different technologies that need to be modeled in power system simulations tools. Furthermore, to understand the impact of the variability of the intermittent generating sources on distribution automation functions and characterize the time-dependent aspects of the system, the modeling tool should have a sequential time simulation capability also called time series, which is not easy It is implemented in three forms [START_REF] Dugan | EPRI Distribution System Simulator[END_REF]:

-A stand-alone executable program (OpenDSS.exe) -An in-process COM server DLL designed to be driven from a variety of existing software platforms (OpenDSSEngine.DLL) -A Stdcall DLL that provides all the functions of the COM server, but can be used from languages that do not support COM or that require Thread safe execution as on a Cloud server (OpenDSSDirect.DLL)

The OpenDSS program has been use for many applications such as load flow, fault study, harmonics study, etc.

In this thesis, we will be using the second form of implementation consisting in driving the OpenDSS from Python through the COM interface. The main reason is that, in a smart grid context where many specific control functions may be required, advanced capabilities offered by object-oriented languages such as Python allow new features to be added to OpenDSS functionalities such as user-defined scripting, complex network analysis, plotting capabilities of Python. Once the OpenDSS netlist is built together with load and generation profiles, Python performs a time-series simulation by iterating over several time steps and commanding OpenDSS to execute a power flow for each time step. At each simulation step, the current at the zone boundaries are retrieved from OpenDSS and combined with load and internal generation currents to calculate the differential currents in each zone. Then, the relevant actions are taken accordingly. This approach is slower as Python stops OpenDSS at each time step to retrieve the solution of the simulation, process the data and take relevant decisions. However, for a protection scheme, it is necessary to monitor the current flow at each simulation step to check whether the operating point lies within the operating region of the zone differential protection. -The power ramp-up on generating sources is not considered in this thesis; -For time constraints reasons, the communication network has not been modeled. Therefore, the time latencies from the transmission of electric currents by peripheral units to their reception by the central unit (feeder controller) have not been considered; the electric currents are read by the controller for each simulation; -For security reasons, it is assumed that no protected zone can be operated in islanded mode; IV.4.5. Constraints As discussed in the basic requirements of a protection system, one important quality of a protection system is the sensitivity, i.e. the ability to detect very small currents.

To define the minimum setting value of the differential protection, it is crucial to make allowance for the false differential currents during normal operating conditions and during some transient normal situations. CT (current transformer) errors: the conversion of the current flowing in the primary circuit to a secondary current that is safer for the protection device connected to the secondary winding of the CT creates both amplitude and phase errors called transformation errors.

IV.4.5.1. False differential currents

Power transformer inrush current: the inrush current is a transient current appearing on the primary side of the power transformer when its primary winding is energized.

However, even though the inrush current is very high (several times the power transformer rated current) in magnitude, it is not a fault and should not cause a trip. The core of network modeling is to describe all the network components (conducting equipment in CIM) and how there are connected to each other also referred to as "connectivity". The CIM modeling is a very challenging activity since it demands a good understanding of the network components data to map on relevant CIM classes.

In this section, our aim is to describe the network model of a distribution feeder in CIM. The created network model will be further transferred to the controller of the related MV feeder from the Control Center. To this end, one question must be answered: how to pass from the core CIM information model in UML to a file that can be exchanged, understood and used for some purposes? To answer this question, The CIM three layers architecture defines a workflow to pass from the information and semantic models to a syntactic level that allows a file exchange. The first layer of the architecture corresponds to the core information model composed of hundreds of CIM classes and thousands of attributes expressed in UML diagrams. However, for the needs of a specific business, a contextual definition called "profile" is defined in the second layer. This profile is a restricted subset of the core information model.

Finally, the third layer, which uses the previous profile, allows an information exchange through messages or files. This information exchange is enabled by a serialization process.

IV.5.1.2. Serialization of the network model in CIM

In fact, the profiles can be expressed syntactically in either XML (eXtensible Markup Language) or RDF (Resource Description Framework). However, since RDF allows the description of the link between different components of an electrical network, which is important in network model exchange, it will be used for the serialization of the network model for exchange purposes. In the rest of this section, the first two layers are used to model the conducting equipment of our test feeder by instantiating some classes of the base information model and contextualizing their attributes to the need of our application. The third layer is discussed further.

Before converting the conducting equipment of the distribution feeder circuit into CIM objects, let us first discuss how CIM uses a class diagram to abstract a distribution feeder with its conducting equipment and the connectivity between them.

IV.5.2. Modeling of the distribution feeder

At a very high level, a distribution feeder can be regarded as a container extending from a supplying source (typically a primary HV/MV substation) to one or several opened tie points. The feeder consists of interconnected network components called conducting equipment. In CIM, the Line class is used to model the feeder. See appendix A4 for more details. As described in the introduction of this section, the CIM model has a three layers architecture: one for the information model, the second for the contextualization of the base information model and the last layer which focuses on the serialization or how to describe the CIM network model into a format that can be exchanged. The first two layers have been discussed previously. To exchange power system network model, CIM uses the RDF model which provides a means of mapping object-oriented design like CIM to XML. RDF allows us to describe a collection of data using a triplet statement also known as (subject, predicate, object) or (resource, property, value). In the RDF model, a resource is anything that can be identified. A Uniform Resource Identifier (URI) is used to designate a resource. A property is any characteristic of a resource that can be described with a value. The triplet (resource, property, value) is the atomic unit of information in RDF and is called a "statement" [START_REF] Widergren | XML for CIM model exchange[END_REF]. To illustrate this concept, an example of serialization of an EnergySource object using CIM RDF XML is given in -The "resource" EnergySource with the unique ID "_63AFF42B-4970-4CDC-A5FB-C34D99AB1AA3" has a "property" called name which value is "source -The "resource" EnergySource with the unique ID "_63AFF42B-4970-4CDC-A5FB-C34D99AB1AA3" has a "property" called EquipmentContainer which unique ID value is "#_E1E770AC-2698-498B-BA7F-90C3411C6FF0" -The "resource" EnergySource with the unique ID "_63AFF42B-4970-4CDC-A5FB-C34D99AB1AA3" has a "property" called voltageMagnitude which value is 90 The analysis of a distribution feeder requires a correct understanding of the network under consideration. The network to be modeled consists of many buses connected by branches such as cables, lines, transformers, switching devices. To facilitate the modeling of this network, simplify the analysis and the queries on it, the graph theory is used. In fact, the distribution feeder electrical network can be regarded as a graph G = (V, E) where V = {v1, v2, ….vn} is the set of nodes and E = {e1, e2, …em} is the set of edges linking different nodes. Each node can connect a load, a source. Furthermore, due to the multi-directional power flow with the presence of distributed energy resources, the graph edges will be undirected. Hence, the network can be represented as an undirected graph G with n nodes and m edges. There are two possible models for representing the distribution feeder with a graph. The first model called "bus-branch" is a simplified model that describes the feeder network as buses and branches without any switching devices. However, when dealing with a zone differential protection, it is very important that the feeder network model includes switching devices such as circuit breakers or reclosers to be able to isolate the faulty zones. To overcome this limitation, a "node-breaker" model is used. The nodebreaker is a breaker-oriented model allowing a detailed modeling of the network.

Fortunately, as the incoming network model from the Control Center includes switching devices (circuit breaker and reclosers for example), this model will be used to represent the distribution feeder network in a graph.

Zone creation

The objective of the zone creation is to have invariants areas in the feeder, each representing the smallest possible zones in the circuit that can be isolated by a differential protection relay. As such, the differential protection principle can be applied on each of the zone acting then as a "protected area". To create a zone, it is essential that the feeder circuit includes switching devices controllable by protection relays. Therefore, for protection reasons, a zone boundary is always equipped with a This creates several islands representing subgraphs of the initial graph. Then, the subgraphs are extracted to finally form the zones.

Zone abstraction

To further implement the differential protection on the distribution feeder, additional details are necessary. Zone incoming and outgoing currents are not enough to determine the differential current in the zone. The different electric components in the zone need to be identified. ) and storage systems.

However, a specificity of the storage system is that, depending on its operating status (charging, discharging, idling), the storage system can be a load (

+ stor I
), or a generating source ( Eq. IV.10 However, because the proposed differential protection is phase segregative, Eq. IV.10 will be define for each phase as below:

( )

A stor A gen A stor A bank cap A load A ext load A inj I I I I I I I _ int_ _ _ _ _ int_ _ _ _ _ - + + - + + = - Eq. IV.11.a ( ) B stor B gen B stor B bank cap B load B ext load B inj I I I I I I I _ int_ _ _ _ _ int_ _ _ _ _ - + + - + + = - Eq. IV.11.b ( ) C stor C gen C stor C bank cap C load C ext load C inj I I I I I I I _ int_ _ _ _ _ int_ _ _ _ _ - + + - + + = - Eq. IV.11.c
Therefore, as with the formulation of differential current in Eq.IV.5, it is possible to rewrite Eq.IV.11.a, Eq.IV.11.b and Eq.IV.11.c as below:

( ) ( ) ( ) A stor A gen A stor A bank cap A load A ext load A inj I I I I I I I A Idiff _ int_ _ _ _ _ int_ _ _ _ _ _ - + + - + + - - = Eq. IV.12.a ( ) ( ) ( ) B stor B gen B stor B bank cap B load B ext load B inj I I I I I I I B Idiff _ int_ _ _ _ _ int_ _ _ _ _ _ - + + - + + - - = Eq. IV.12.b ( ) ( ) ( ) C stor C gen C stor C bank cap C load C ext load C inj I I I I I I I C Idiff _ int_ _ _ _ _ int_ _ _ _ _ _ - + + - + + - - =
Eq. IV.12.c

The operation of the zone differential protection occurs should the current diff I be greater than or equal to the differential pick-up value as follows:

A phase on value up - pick _ al differenti I A diff  Eq. IV.13.a B phase on value up - pick _ al differenti I B diff  Eq. IV.13.b C phase on value up - pick _ al differenti I C diff  Eq. IV.13.c
In theory,

C diff B diff A diff I I I _ _ _ and ,
are equal to 0 under normal operating conditions. and during external faults. However, in practice, some false differential current should be accounted for as discussed in section IV.4.5.1.

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Public Similarly to the differential current, the restraining current defined in Eq.IV.7 can be applied to reformulate. We get:

( ) Eq. IV.14

2 int _ _ int _ _ - + + - + + + + =
On a per phase basis, the restraining current can be rewritten as follows:

( )

2 _ _ int_ _ _ _ _ int_ _ _ _ _ A stor A gen A stor A bank cap A load A ext load A inj I I I I I I I A Irestr - + + - + + + + = Eq. IV.15.a ( ) 2 _ _ int_ _ _ _ _ int_ _ _ _ _ B stor B gen B stor B bank cap B load B ext load B inj I I I I I I I B Irestr - + + - + + + + + = Eq. IV.15.b ( ) 2 _ _ int_ _ _ _ _ int_ _ _ _ _ C stor C gen C stor C bank cap C load C ext load C inj I I I I I I I C Irestr - + + - + + + + + =
Eq. IV.15.c Finally, the differential protection trips should one of the two conditions below be met:

For phase A:

A s A restr A diff A s A restr I I k I I I _ 1 _ 1 _ _ 2 _ and +    Eq. IV.16.a ( ) A s A s A s A restr A diff A s A restr I I k I I k I I I _ 1 _ 2 1 _ 2 _ 2 _ _ 2 _ and +  + -    Eq. IV.16.b
For phase B:

B s B restr B diff B s B restr I I k I I I _ 1 _ 1 _ _ 2 _ and +   
Eq. IV.17.a ( )

B s B s B s B restr B diff B s B restr I I k I I k I I I _ 1 _ 2 1 _ 2 _ 2 _ _ 2 _ and +  + -   
Eq. IV.17.b

For phase C:

C s C restr C diff C s C restr I I k I I I _ 1 _ 1 _ _ 2 _ and +   
Eq. IV.18.a

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C s C s C s C restr C diff C s C restr I I k I I k I I I _ 1 _ 2 1 _ 2 _ 2 _ _ 2 _ and +  + -    Eq. IV.18.b
At this stage, the parameters of the operating characteristic are defined (differential and restraining pick-up current, slopes) along with trip conditions, the zone differential protection can be applied to each zone. In the next section, the behavior of the zone differential protection is analyzed. study, it is modeled as the slack bus, i.e. with a constant voltage source and a reference angle of zero. To account for short circuit calculation, the upstream source is characterized by its equivalent impedance which determines the current contribution of the source to short circuits on the feeder. According to the IEC60909 standard, the equivalent impedance of the upstream network is related to the system nominal voltage and the short circuit current by the following equations:

1 ' ' 3 3 1 . 1 Z U n k I   =
Eq. IV.19

0 2 1 ' ' 1 1 . 1 3 Z Z Z U n k I + +   =
Eq. IV.20

Where:

= Ik ' ' 3 three-phase short-circuit current contribution of the upstream source; = Ik ' ' 1 single-phase short-circuit current contribution of the upstream source;

1 1 1 X j R Z  + =
is the positive sequence equivalent impedance of the upstream source at the connection point;

2 2 2 X j R Z  + =
is the negative sequence equivalent impedance of the upstream source at the connection point; it is assumed that the negative sequence impedance is equal to the positive sequence impedance;

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In our thesis, we will model the three-phase, single-phase short circuit currents and the time constants X1/R1 and X0/R0 of the upstream source in lieu and place of the equivalent impedances.

IV.8.2. Power transformer

The reference network includes one 90/4.16kV power transformer with on-load tap changer, two 4.16/LV power transformer with off-load tap changer and six line voltage regulators. Any power transformer can be modeled as shown in Fig. The equivalent resistance of the core losses is not modeled as it does not impact our use case. The magnetizing inrush should be accounted for due to the potential

IV-19. R 1 X 1 X m R 2 X 2 1 2 N 2 N 1 V 1 V 2 2 Z 1 Z R p

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Public unnecessary tripping it might cause. However, the effect of this parameter is not effective on steady state.

IV.8.3. Line and cable segments

The reference network consists of many single-phase and three-phases AC lines segments with relatively short lengths, between one hundred to one thousand meters. The presence of short line segments enables to model them as a series impedance (composed by a resistance in series with an inductance) while neglecting the shunt capacitance. However, with this simple representation, the capacitive current generated from each line segment is ignored during earth faults. For unbalanced three-phase systems, there is a requirement to accurately define the individual conductor parameters for each phase and their spacing. This is to allow unbalanced power-flow engines to create the impedance matrices for the unbalanced lines [START_REF] Epri | Common Information Model Primer -Fourth Edition -Technical report[END_REF]. Actually, line segment impedances can be represented at the base frequency either by its symmetrical component impedances (

1 1 1 X j R Z  + = = positive
sequence impedance and

0 0 0 X j R Z  + =
= zero sequence impedance) or by the impedance matrices. Whatever representation, any line segment can be defined by referring to a "linecode" that contains the impedances per unit length. But, as the representation by symmetrical components does not account for line asymmetries, we will use the impedance matrices for each single and multi-phase line segments as below.

For single-phase line segment:

A For two-phase line segment:

As formulated on Eq. IV-21, Eq. IV-22 and Eq. IV-23, a two-phase line segment is modeled by the following impedance matrices: Eq. IV.24

        =
        = 22 21 12 11 x x x x xmatrix
Eq. IV.25 Thus, the only properties required for completely defining a line segment are the "linecode" name and the length of the segment.

        =
IV.8.4. Load Loads are power delivery points which can be, according to their nature and use, residential, industrial, commercial load or a combination of them. In this thesis, all the loads of our reference distribution feeder are connected to the medium voltage side (4.16kV) of the network. In addition, load types can be constant power, or constant current or constant impedance.

In the network simulation software (OpenDSS), the load can be modeled by providing amongst others the rated powers and the load type. However, this only allow for a snapshot power flow simulation. To check the behavior of the Zone Differential Protection under different load conditions, time series simulation is used. However, the time series simulation is only possible for constant power load type in OpenDSS.

Therefore, the different loads types are reverted to constant and a load profile is associated to each load. A load profile is a predefined curve that sets the behavior of a piece of load. The instantaneous customer and system loads are often considered to have Gaussian distributions [START_REF] Lakervi | Electricity Distribution Network Design[END_REF]. To create the load profiles, we generate random values following a normal distribution with a mean =0.5 (50% of the rated load) and a standard deviation =0.05 (5% of the rated load).

See details in the appendix B5;

IV.8.5. Capacitor bank A capacitor bank is used for reactive power compensation with the objective to improve a voltage profile. As expressed in Eq.IV.30, the reactive power Q of the capacitor bank is determined by its capacitance C, the operating voltage U and the frequency f with

   = 2 f ,  being the angular frequency 2 U C Q  =
Eq. IV.30

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Public As with load, capacitor bank will be given profiles. To define the profile, let us consider that a capacitor bank may be in one of the situations below :

▪ Available and ready to start but put out of service. Let us call this status AVOS;

▪ Available in service meaning that the capacitor bank is switched on. Let us call it AVIS;

▪ In maintenance denoted by UNAV for unavailable.

To illustrate these situations, time-dependent curves are given on Fig.IV-21. In the principle, these curves are generated from Python as follows :

-UNAV (unavailable): a one-hour duration is randomly generated between 1 and 24h to simulate the unavailability of the capacitor bank;

-AVOS (available out of service): between 0 to 9 hours AM;

-AVIS (available in service): switched on between 9AM and 10PM unless there is a contingency in between for maintenance reasons (simulated by UNAV parameter). Similarly to the load, a generation profile is used to define the behavior of a piece of generating source. To create the profiles for diesel machines, we generate a constant injection curve where generators produce constantly their rated active and reactive powers.

IV.9. Modeling of the test feeder into the power system simulation tool (OpenDSS)

As already discussed, OpenDSS has been chosen for our network simulations. In appendix B5, the OpenDSS version of the reference network generated from Python is given. In appendix C5, the OpenDSS version of the modified reference network (to check the incremental management aspect) including addition of new power system components is shown.

It is very important to mention that the direction of the electric current flow is very impactful in a differential protection. As any flow, this electric current flows in a direction which may be forward or backward. Therefore, because the flow is oriented, it can be given a positive or negative sign. This current sign can be defined thanks to the CT (current transformer) polarity. A CT is an equipment that changes the magnitude of a primary electric current from a high value to a lower value withstandable by to a protection device connected to its secondary winding.

However, the CT model in OpenDSS does not provide the current flow direction.

Therefore, the current direction will be computed within our scripts.

V.1. Introduction

For recall, in chapter II, the protection coordination issues due to the presence of DERs (Distributed Energy Resources) on the distribution feeders were presented.

Then, we went through the necessary alignment of CIM and IEC 61850 data models in chapter III to make transfer of the network model to the feeder possible.

Finally, the modeling of the proposed new Zone Differential Protection (ZDP) has been described in chapter IV.

In the current chapter, the implementation and behavior of the zone differential protection are analyzed through simulations. It is important to mention that dynamic simulations have not been performed in this thesis to fully validate the ZDP. For both power flow and short-circuit simulations, the results will be presented in tabular format indicating, for each zone, the total internal load + generation current along with the currents flowing in/out of the zone. In addition, the current operating point (Irestr, Idiff) will be shown on the differential characteristic as shown on The proposed ZDP is a biased differential protection with four basic parameters as described in section IV.2. The setting values are defined as below:

V.2. Simulation methodology

V.3.1.1. Setting criteria of Is1
Is1 is the differential current pick-up setting. Its setting should fulfil the following criteria:

-Greater or equal to 130% of the maximum phase load current of the zone (criterion 1);

-Below the minimum short-circuit current (criterion 2);

-Above the maximum differential current under normal operating conditions due to current transformer errors, IED measuring errors (criterion 3);

For the IEEE 123 nodes feeder, which includes both overhead lines segments along with cables, high resistive faults may appear generally on overhead parts, causing the short-circuit currents to potentially fall below the maximum phase load

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Public current. Hence, criteria 1 and 2 may be conflicting if the short-circuit current is not sufficiently high compared to the maximum phase load current. On the contrary, if the faults are direct with high short-circuit currents, then, criterion 1 and 2 can be easily satisfied.

Finally, to account for criterion 3, a setting of 10% of the phase rated current of the zone has been considered to ensure sensitivity for resistive faults especially on overhead lines. This setting has been validated upon the short-circuit simulations.

V.3.1.2. Setting of slope k1

Under normal operation, a differential current may appear due to CT errors. The slope k1 is fitted to avoid any undesired tripping. It is typically set to 30%.

V.3.1.3. Setting of Is2 and slope k2

Is2 is the restraining current pick-up setting. For each zone, Is2 is a knee point for discriminating the maximum possible operating current on a phase with the through fault current on the same phase. At the occurrence of a fault in a zone, a through fault current flows in neighboring zones which may create CT saturation on zone borders. This could result in an unnecessary tripping of the sound zone.

Hence, the knee-point current Is2 is set to 120% of the rated phase current of the zone. Furthermore, a second slope k2 is used to ensure the stability of sound neighboring zones during external faults. The slope k2 is typically set to 80%.

V.3.2. Current sign convention

The current entering one zone is considered as positive while the leaving one is counted negative. In addition, all the current measurements are taken from the terminal 1 on each conducting equipment.

V.3.3. Tripping decisions

The ZDP operating point is the point of coordinate (Irestr, Idiff) resulting in the calculation of Idiff and Irestr as per Eq. IV.12.a, Eq. IV.12.b, Eq. IV.12.c, Eq.

IV.15.a, Eq. IV.15.b, Eq. IV. (coded into 128 bits) pre-assigned. However, the basic export was not adequate to our ZDP for some reasons. Recall that each power system component has one or more terminals connecting the component to phases of the network. Also, the ZDP is phase segregative and needs to clearly identify the phase(s) to which each power system component is connected to especially for unbalanced distribution networks. But, as illustrated on the extract below, this information is not present in the initial CIM export.

However, the base CIM 'Terminal' class has a 'phase' attribute which can take one of the following values : A, B, C, AB, BC, AC, ABC, ABCN. Therefore, the 'phase' attribute has been added to each terminal as per its connection to the network.

The modification of the previous extract is shown below. The OpenDSS netlist has been automatically created from the reference network model to allow network simulations. For recall, OpenDSS is controlled by Python through its COM interface. The netlist is given in appendix B5 for SP1.

V.4.1.6. Normal sequential power flow simulations in SP1

The normal sequential power flow simulation consists in 24 simulation steps. For each simulation step, the balance between the total internal (load -generation)

and the arithmetic sum of currents on zone border(s) is checked for each phase of different zones. For the sake of clarity, the first simulation step is detailed below with computations done over zone 1. Also, the graph representation of the complete reference network connectivity and the zone 1 are given respectively on To evaluate the conditions of operation of the zone differential protection, the process is, firstly, to compute for each zone, the actual phase differential and restraining currents. Secondly, the zone differential and restraining pick-up currents are computed. This second step allows the drawing of the operating characteristic of the ZDP. Thirdly, the previously computed differential and restraining currents are placed on the zone differential operating characteristic to check if there is a trip or not. Finally, the border(s) are tripped should a fault occurs inside a zone.

Computation of actual phase differential and restraining currents:

The actual differential (Idiff_A, Idiff_B and Idiff_C) and restraining (Irestr_A, Irestr_B and Irestr_C) currents are computed based on the equations Eq.IV.12a, Eq.IV.12b, Eq.IV.12c, Eq.IV.15a, Eq.IV.15b, Eq.IV.15c. To achieve these computations the result of the power flow simulation performed on the reference network model is used. The Python script commands OpenDSS to run a power From the values given on the table above, we can compute the differential currents on zone 1.

Actual differential current on phase A (Idiff_A)

On Eq.IV.12.a, the expression ( )

A ext load A inj I I _ _ _ -
represents the difference between the total current injected on phase A of one zone and the total current retrieved from the zone while the expression ( ) ( )

A stor A gen A stor A bank cap A load I I I I I _ int_ _ _ _ _ int_ _ - + + - + +
is the total internal (loadgeneration) on phase A of the same zone.

( )

A ext load A inj I I _ _ _ -
is obtained by adding the currents given at the zone borders.

The current summation at zone 1 borders gives : Public Therefore, the differential current Idiff_A is close to zero as ( )

A ext load A inj I I _ _ _ - is equal to ( ) ( ) A stor A gen A stor A bank cap A load I I I I I _ int_ _ _ _ _ int_ _ - + + - + +
. Same for phases B and C.

Actual restraining current on phase A (Irestr_A)

Similarly, the value of the restraining currents can be computed based on Eq.IV.15.a, Eq.IV.15.b and Eq.IV.15.c. Secondly, the differential and restraining pick-up settings defined on sections V.3.1.1 (for differential threshold Is1), and V.3.1.3 (for restraining threshold Is2) must be evaluated. For remind, the zone differential protection trips should the conditions described on Eq.IV.16a, Eq.IV.16b be met for phase A, Eq.IV.17a, Eq.IV.17b be met for phase B, Eq.IV.18a and Eq.IV.18b be met for phase C. The zone differential protection (ZDP) will only trip if Eq.16.b or Eq.17.b or Eq.18.b are satisfied. In other words, if the operating point falls within the "trip area". However, as shown on Fig V .1, the operation point on each phase is always in the "NO TRIP AREA". Therefore, the ZDP does not trip in this case. This behaviour is normal as the ZDP is expected to be stable on normal operating conditions. See more results on appendix B6 for SP1. The simulation results of the fault number 1 are given below with a focus on zone From the values given on the table above, we can compute the differential currents on zone 1.

Actual differential current (Idiff_A) on phase A

( ) Public Therefore, compared to the (load-gen) currents on the corresponding phases given on the previous table, the actual differential current is nearly zero.

A ext load A inj I I _ _ _ - = 457.39+311.

Actual restraining current (Irestr_A) on phase A

The restraining current is given below: The results show that the ZDP does not issue a trip command for isolating zone 1. The ZDP is executed sequentially, meaning that the differential function is applied to each zone, one at a time. Table V Similarly to SP1, the same preliminary checks are conducted in SP2. See appendices C1 to C5.

V.4.2.1. Modified reference network model

In the appendix C1, an extract of the newly added parts is given. New power system components have been added to the initial reference network as follows:

-Addition of a single phase load connected to phase B at bus 251 in zone 3 -Addition of a single phase load connected to phase B at bus 185 in in zone 4 -Addition of a three phase line segment between buses 151 and 251 in zone 3 -Addition of a three phase line segment between buses 85 and 185 in zone 4

V.4.2.

Graph of the modified network

The modified network is then translated into its equivalent graph as in simulation package (SP1) for future zones creation. See the illustration in appendix C3 for the simulation package SP2.

V.4.2.3. Zones creation in SP2

Following the construction of the new graph, Python generates the different zones composing the graph. A snapshot of each created zone in SP2 is given in

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Public Appendix C4 along with the borders. For each zone, the breakers/reclosers at borders are shown based on the connectivity data into the previous graph.

V.4.2.4. OpenDSS netlist of the modified reference network in SP2

The OpenDSS netlist has been automatically created from the modified reference network to allow network simulations. An extract of the netlist containing the added elements is given in appendix C5 for SP2.

V.4.2.5. Normal sequential power flow simulations in SP2

The results are given below where only zone 1 is illustrated (see appendix C6 for more results on simulation package SP2) :

Current flow :

Actual differential current on phase A (Idiff_A)

Applying the same process as in the simulation package 1 (SP1), we get:

( )

A ext load A inj I I _ _ _ - = 25.22-72.14j for phase A ( ) B ext load B inj I I _ _ _ - = 14.81+15.21j for phase B ( ) C ext load C inj I I _ _ _ - = 40.55+77.34j for phase C
Therefore, the differential current Idiff_A is close to zero as ( )

A ext load A inj I I _ _ _ - is equal to ( ) ( ) A stor A gen A stor A bank cap A load I I I I I _ int_ _ _ _ _ int_ _ - + + - + +
. Same for phases B and C.

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Actual restraining current on phase A (Irestr_A)

Similarly, the value of the restraining currents are given below : The results of the first fault simulation are given below. A fault is simulated on the newly added bus 251 in zone 3. However, for all the other zones 1, 2, 4, 5 and 6, the ZDP is supposed to be stable. Zone 1 will be used to illustrate the stability for external faults while zone 3 will be used to illustrate the trip within the faulty zone. Current flow during short-circuit: From the values given on the table above, we can compute the differential and restraining currents on zone 1.

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Actual differential current on phase A (Idiff_A)

Applying the same process as in the simulation package 1 (SP1), we get:

( ) Therefore, the differential current Idiff_A is close to zero as ( )

A
A ext load A inj I I _ _ _ - is equal to ( ) ( ) A stor A gen A stor A bank cap A load I I I I I _ int_ _ _ _ _ int_ _ - + + - + +
. Same for phases B and C.

Actual restraining current on phase A (Irestr_A)

Similarly, the value of the restraining currents are given below :

ZDP operating time:

The operating time of the ZDP for the fault on bus 251 in zone 3 is 176.8ms. See appendix C7 for results on the other zones.

. Conclusions on simulation results

The simulations conducted in this chapter show that the new concept of Zone Differential Protection (ZDP) proposed could ensure a good protection coordination in distribution feeders with embedded distributed generation. The behavior of the ZDP have been reported under steady state sequential power flow and short-circuit based on the reference network model. In addition, the same simulations have been performed on the modified version of the reference network model in order to check the incremental aspect or how the modifications are enrolled into the ZDP. The ZDP operation times range between 110 and 220ms over different zones. However, this operating time is high, partly due to the script that has been added for the determination of the electric current direction (see section IV.9), before the computations of differential currents. Consequently, even though the unfaulty zones do not trip their border(s) for external faults, the generating sources within those sound zones will trip.

The implementation of the Zone Differential Protection was complex as several difficulties had to be overcome amongst which:

-The reformulation of the basic principle of differential protection based on Kirchhoff's current law stating that the current flowing into a node must be equal to the current flowing out of it. However, a zone has internal loads and distributed generation along with external current injection(s) and loads.

Therefore, an adaptation of the basic principle was required; -The zone creation was also a challenge. The graph representation of the distribution feeder was a great help to the zone creation; -The unbalance of loads had to be accounted for as our reference network consisted of single phase, two phase and three phase equipment connected in delta or star; -The management of changes in the incoming network model is a 'must' especially when the feeder automation functions is expected to integrate modifications 'on the fly' during operation; In addition, some recommendations related to IEC 61850 and CIM data models are given below to facilitate the implementation of the concept.

Recommendations related to IEC 61850:

-IEC SCL does not allow for a distribution feeder (line container) to contain substations which are containers themselves; several MV/LV distribution substations can be connected to a distribution feeder. Therefore, it should be possible to represent a distribution substation as a container, then connect it to a feeder;

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Public -In IEC61850, the fact that the name of an object plays the role of its ID may be confusing during the conversion of the CIM incoming network model to IEC61850 SCL. As a result, we recommend adding an 'ID' attribute to each IEC 61850 object and align its reference to the mRID from the CIM incoming network model.

Recommendations related to IEC CIM:

-Also, to be able to fully tie the feeder automation functions to the incoming network model, some enhancements must be brought to the CIM model The zone differential protection brings a solution to the protection coordination on active distribution feeders. However, due to time constraints, many aspects have not been covered. Therefore, further simulations are required to prove the reliability of the zone differential protection. There are many perspectives to this research work. The following directions could be dug:

-The integration of the advanced metering infrastructure (AMI) into the distribution feeder automation could increase the observability level on the distribution network and improve the accuracy of the calculations performed by the differential protection scheme. AMI is the infrastructure by which timestamped meter data are remotely collected periodically. For the purpose of the zone differential protection, the collected meter data will be transferred to the feeder controller. Two main constraints need to be considered. Firstly, the metering system should be able to transfer the load current measurements at a periodicity adequate for time critical applications such as the zone differential protection. Secondly, a harmonization between the data model used on the feeder (IEC 61850) and the data model used for metering (COSEM) is needed. Accurate load models could be used in lieu and place of harmonization. However, the lack of standardization could be a drawback to its wide adoption; -The Phasor Monitoring Unit into a Wide Area Monitoring System to allow the transmission of electric current values and breakers status from peripheral units to the feeder controller (central unit) would be a large enhancement.

The time latencies considerations during the currents transmission through routers would be of major support for the ZDP.

-The zone invariance may be reformulated by considering the presence of sectionalizers on some laterals or sub-laterals of each zone; this could significantly improve the reliability indicators; -The dynamic updating of the differential protection following a change of jurisdiction on one zone, more specifically when one zone is transferred to a back-up distribution feeder. In fact, the electric currents from the zone -The cost benefit analysis (CBA) needs to be covered. In fact, the benefits of a zone differential protection must not only be examined from the technical point of view, an economic assessment is also necessary.

-Dynamic simulations including the transient models of generators in order to consider the grid code constraints on generators.

APPENDIX A2

Basic principle of differential protection

The basic principle of a differential protection is to compare the magnitude of the current entering a protected area to the magnitude of the current leaving that area. Should the differential current be not zero, a fault is deemed to occur in the protected zone. The differential protection is a direct application of the Kirchhoff's first Law stating that the vector sum of the currents entering the protected area is equal to the vector sum of the currents leaving the protected area. Traditionally, the differential protection is used for the protection of a line, a generator, a motor, a transformer, a reactor, a cable or busbar.

In the Fig. IV-1, the differential protection is applied on a high voltage overhead line just for the sake of illustration. Before analyzing the current flows during normal and abnormal situations, it is important to mention that for a line, there is one differential protection relay at each terminal of the line. Each protection relay calculates the differential current by comparing the current measured locally to the current receives from the protection relay at the other terminal of the line and vice versa. According to this figure, the currents flowing in the line L1 can be expressed as follows Where:

-I1m and I2m represent the magnitudes of currents I1 and I2 -q I1 and q I2 represent the phases of currents I1 and I2 On normal operating conditions, the current flows from sources to loads as in Fig. IV-1. Alternatively, when a fault appears on line L1, the short-circuit currents flow from the upstream sources to the fault point as indicated on Fig. IV-2. As we can see, the current flow direction is different in the two situations and this will, of course, directly impacts the calculation of the differential current. Therefore, it is useful to establish a convention of direction of current flow. To this end, the direction measured from the busbar onwards along a feeder is taken as positive. However, it is important to mention that the differential protection relay gets the flowing current from a current transformer connected to it which, as its name suggests, transforms the primary current flowing in the line into a secondary current that the relay can withstand. So, the current flow direction will be depending on how the current transformer is connected. On Fig. IV-1, a black dot is represented close to each of the current transformers CT11, CT12, CT21 and CT22 to represent their positive entry point (hot point).

Finally, when the current flows from one busbar to the line and the CT hot point is located at the busbar side, the protection relay considers the flowing current is in the forward direction. Therefore, the polarity is positive, and the current is given a positive sign. Alternatively, when the current flows from the line to the busbar while the CT hot point is still located at the busbar side, the protection relay considers the flowing current is in the backward direction. The polarity is negative, and the current is given a negative sign.

( ) ( ) Now, let us consider a fault on line L1 (abnormal situations), both protection relays R11 and R12 see a forward direction current flow as the measured currents flow from their busbars (respectively A and B) to the line. Hence, the differential protection one each side of the line measures the summation of the currents at both sides of the line. Should the differential current be not zero, a fault is deemed to exist on the line. During normal operating conditions, as the current flow direction changes compared to the abnormal situation, the differential protection measures the difference of the currents at both sides of the line under consideration. Then, the differential current is written as follows:

1 1 1 1 1 sin cos I m I m I j I I θ θ × × + × = Eq. IV.1 Eq. IV.2 ( ) ( ) 2
I I I diff + = Eq. IV.3 ( ) ( ) [ ] ( ) ( ) [ ] 2
2 1 I I I diff - = ( ) ( ) [ ] ( ) ( ) [ ] 2 2 1 2 2 1 Im Im Re Re I I I I I diff - + - =
Eq. IV.5

Eq. IV.6

In practice, however, a considerable differential current can sometimes occur under normal load conditions or during a "through fault" even though there is no fault in the protected area. This is especially the case when a through fault is accompanied by a current transformer (CT) saturation . In addition, the inaccuracies in the measurement and the inaccuracies introduced by the difference of magnetizing curves of the current transformers forming the protected area (CT11/CT12 for line L1 and CT21/CT22 for line L2 in Fig. IV-1) bring a differential current during normal operating conditions. As a result, the lowest threshold of the differential protection (also called differential protection operating value) should fulfill at least the following criteria:

-Be greater than the inaccuracies appearing on normal operating conditions (criterion 1) -Be below the minimum short-circuit current for a fault on the protected area (criterion 2) -Be stable during a through fault. This is the case, for example, of the differential protection on line L2 which should be stable when a fault appears on line L1 (see Fig. IV-2

) (criterion 3)

To ensure the stability of the differential protection for external faults, a restraining condition (Eq.IV.7) is added. Finally, the condition in Eq.IV.3 is supplemented by a second condition representing the scalar mean of the magnitude of currents at the line terminals: At a very high level, a feeder can be regarded as a container starting from a supplying source (a primary substation for example) and ending at a selected tie point. The feeder consists of several network components called conducting equipment. In CIM, the Line class is used to model the feeder. The class diagram on Fig. IV-9 shows the concept of equipment containers to describe the hierarchies in CIM. As we can see, there is an inheritance relation between the Line class and the EquipmentContainer class meaning that the feeder, modeled as a Line, is an Equipment container. Furthermore, the line is contained within a SubGeographicalRegion and a GeographicalRegion.

In each rectangle, the text in bold is the CIM package containing the class and the normal text is the name of the class. For example, the Line class is contained in the Wires package. This concept of container may be very interesting when performing feeder automation in that the container can be considered as a dynamic "jurisdiction" containing a set of conducting equipment participating to an automation function at the instant t. The automation function might be a voltage control scheme, a protection coordination scheme, etc. Should the feeder topology changes following a circuit reconfiguration, the extension of the feeder "jurisdiction" is going to change, either to exclude or include conducting equipment from/to the current feeder container. Typically, in the case of a differential protection, a zone may be excluded to the feeder jurisdiction at the instant t after a fault or circuit reconfiguration. As a result, the electric currents information of this zone will be automatically excluded from the differential protection current calculations performed by the feeder [START_REF]IEC 61850-6-Power systems management and associated information exchange -Part 6: Configuration description language for communication in power utility automation systems related to IEDs[END_REF] To model the connectivity, Terminal and connectivity node are defined [START_REF]IEC 61850-6-Power systems management and associated information exchange -Part 6: Configuration description language for communication in power utility automation systems related to IEDs[END_REF]. Basically, each conducting equipment has one or more terminal(s). A terminal may be connected to one and only one connectivity node. A connectivity node may connect one or more terminals of different conducting equipment. So, the connectivity is achieved by associating the terminal(s) of conducting equipment to the right connectivity nodes. Each terminal, connectivity node has a name and a unique identifier (ID).

A4-2-Modeling of the connectivity A4-3-Modeling of the conducting equipment A conducting equipment is a network component that carries electric current. CIM uses UML to define a class hierarchy for each conducting equipment by stating that any conducting equipment is basically an equipment which is itself a power system resource. In addition, each power system resource must be identified by a unique identifier called MRID (Master Resource ID) and a name. Translating this in UML, the ConductingEquipment class inherits from its parent, the Equipment class, which in turn inherits from the PowerSystemResource class. Also, to allow for its identification, the PowerSystemResource class inherits from the IdentifiedObject class as shown on Fig. IV-9.

Furthermore, the ConductingEquipment class has sub-classes which inherit from their parent attributes and association to other classes such as the Terminal. In our reference distribution feeder, the following network components will be covered and modeled in CIM: the circuit breaker/recloser, cable and line sections, capacitor bank, power transformer, line voltage regulator, wind and CHP generating source, storage system, PV, load, upstream source and buses. These components can be categorized into two groups: two-terminals conducting equipment, one-terminal conducting equipment. Whatever the number of terminals, each conducting equipment has a name, a unique ID, a base voltage and an equipment container.

The Fig.IV-10 gives a UML description of a two-terminals conducting equipment and how it connects to both upstream and downstream nodes. However, even though a power transformer is a twoterminals conducting equipment, this UML description does not include the power transformer which has some specificities that are discussed further.

A4-3-1 -Modeling of two terminal conducting equipment

Appendix A4 -Translation of the reference network components into CIM model -continued

A4-3-1-1 -Modeling of the circuit breaker

The circuit breaker is a mechanical switching device capable of making, carrying, and breaking currents under normal circuit conditions and, making, carrying for a specified time, and breaking currents under specified abnormal circuit conditions e.g. those of short circuit [START_REF] Ishchenko | Practical Implementation of Adaptive Protection and Control in a Medium Voltage Microgrid[END_REF].

As for the recloser, it is a pole-mounted fault interrupter with built-in phase and ground relays, current transformer (CT), and supplemental controls [START_REF]IEC 61850-6-Power systems management and associated information exchange -Part 6: Configuration description language for communication in power utility automation systems related to IEDs[END_REF]. After a fault, it can execute a preset reclosing sequence a preset number of times before going to a lock-out condition. However, since it is designed to operate like the circuit breaker, the recloser will be modeled as a circuit breaker even though the dedicated class in CIM is the recloser class.

In CIM, the circuit breaker is a piece of conducting equipment represented by the Breaker class. As indicated on the Fig. IV-11, the Breaker is a type of switch, which inherits from its parent class, the ProtectedSwitch class, which in its turn inherits from the Switch class. As a conducting Equipment, the Breaker inherits also to all the parent classes defined on the class inheritance hierarchy (Equipment, PowerSystemResource, IdentifiedObject classes). One of the main attribute of a circuit breaker object model is its status. The status is represented by the property "normalOpen" associated to the Switch class from which the Breaker class inherits.

A4-3-1-2 -Modeling of cable and overhead line

The test feeder consists of several single, two and three phase cable and line sections. Therefore, we will adopt the same modeling principles as on the load. In CIM, a three-phase balanced line segment is basically represented by the ACLineSegment class with the length of the line section as attribute. However, for a three-phase unbalanced line segment, the ACLineSegmentPhase class, representing each phase of the line segment, is associated to the ACLineSegment class. To define the impedance per unit length of each line segment, we use the concept of "linecode". To this end, the PerLengthPhaseImpedance class defines the impedance and admittance parameters per unit length of n-wire unbalanced lines, in matrix form [START_REF]IEC 61850-6-Power systems management and associated information exchange -Part 6: Configuration description language for communication in power utility automation systems related to IEDs[END_REF]. But, since the linecode is in matrix format as detailed further in section 5. The coupling is determined by the "connectionKind" attribute on the PowerTransformerEnd class.

In our test feeder, the primary winding (90kV side) is connected in wye with the neutral point to the ground (YN). The secondary winding (4.16kV side) is also connected in wye with the neutral point to the ground (yn) through an impedance which limits the earth fault current to 300A. Therefore, on the 4.16kV side of this substation power transformer, the "grounded" attribute of the TransformerEnd class instance will be set to "True" while the "rground" and "xground" are set to the related impedance of limitation. Likewise, on the 90kV side of the transformer, the "grounded" attribute will be set to "True" while the "rground" and "xground" are set to zero as there is no earth current limitation.

A4-3-2-1 -Modeling of the upstream source

The upstream source is the Thevenin equivalent of the grid at the supplying point. In CIM, the upstream source maps to the EnergySource class. Among all the EnergySource class attributes, the following attributes are sufficient to characterize the upstream source:

-The Voltage magnitude and angle -The equivalent positive sequence resistance (r) and reactance (x) at the grid connection point -The equivalent zero sequence resistance (r0) and reactance (x0) at the grid connection point

A4-3-2-2 -Modeling of load

Load may be connected between one phase to ground, two phases or three phases. In addition, when it is a three-phase load, it may be balanced or unbalanced. In CIM, a load maps to the EnergyConsumer class with the following attributes:

-The load model (constant power, constant current or constant impedance) which maps to LoadResponseCharacteristic class -The rated active and reactive powers -The phase connection (Delta or Wye) Appendix A4 -Translation of the reference network components into CIM model -continued

In addition, an unbalanced load introduces a complexity in the modeling. In fact, to the EnergyConsumer class, it is necessary to associate a sub class called EnergyConsumerPhase for each phase of the unbalanced load that introduces an extra attribute related to the phase the load is connected to (A, B or C).

A4-3-2-3 -Modeling of capacitor bank

Our test feeder includes both single and tri phase capacitor banks. Therefore, we will adopt the same modeling principles as on the load. In CIM, a capacitor bank is mapped using the LinearShuntCompensator class with the following attributes: U is the phase to phase voltage, V is the phase to ground voltage and Q is the rated reactive power of the capacitor bank. Furthermore, it is necessary to associate to the LinearShuntCompensator class, a sub class called LinearShuntCompensatorPhase, for each phase of the single-phase capacitor banks C88a, C90b and C92c. This introduces an extra attribute related to the phase the capacitor bank is connected to (A, B or C).

A4-3-2-4 -Modeling of synchronous machine

In CIM, a synchronous machine is mapped using the SynchronousMachine class with the following attributes:

-The rated active and reactive powers -The rated voltage -The power factor -The synchronous, transient, subtransient positive sequence reactances -The production mode : PQ, PV

B5-11-Bus coordinates

The bus coordinates of the network are defined in a file called : Test_Buscoords.DSS. The content is given below in five blocks. For each block, the first column represents the bus name, the second and third being the corresponding (x,y) coordinates. -0.00-0.00j -0.00-0.00j -0.00-0.00j

!BUS COORDINATES

NO TRIP takes place as the ZDP differential current is zero. The operating point is not in the trip area.

NO TRIP takes place as the ZDP differential current is zero. The operating point is not in the trip area.

NO TRIP takes place as the ZDP differential current is zero. The operating point is not in the trip area. The ZDP operating point is in the TRIP area because there is a fault on phase A of zone 3.

Idiff_A
NO TRIP takes place as the ZDP differential current is zero.

The ZDP operating point is in the TRIP area because there is a fault on phase B of zone 3. -0.00+0.00j -0.00-0.00j 0.00-0.00j 0.00+0.00j 0.00+0.00j 0.00+0.00j

Operating point

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero. -0.00+0.00j -0.00-0.00j 0.00-0.00j 0.00+0.00j 0.00+0.00j 0.00+0.00j

Idiff_A/
NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero. 3.54-7.87j -5.12-0.38j 3.91+5.63j

Idiff_A/
NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero. -0.00-0.00j -0.00-0.00j -0.00-0.00j

Idiff_A/
NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

B5-11-Bus coordinates

The bus coordinates of the network are defined in a file called : Test_Buscoords.DSS. The content is given below in five blocks. For each block, the first column represents the bus name, the second and third being the corresponding (x,y) coordinates.

Appendix

Fig 8 : 46 Fig 1 :Fig 9 :Fig.IV- 13 :Fig.V- 4 :

 84619134 Fig.I-1 : Example of HV/MV substation 24 Fig.I-2 : Types of decentralized generation according to the primary energy 32

P a g e 16

 16 | 161 Public bus-branch without breakers. The three major components of this scheme are a) the extraction of the incoming network model, b) the creation of network zones between network circuit breakers and c) the application of a reformulated differential protection version to each zone.

  The MV network -The MV/LV distribution substations -The LV network P a g e 23 | 161 Public I.4.1. Main parts of the distribution system I.4.1.1. The HV/MV primary substation(s)

Fig

  Fig.I-1. Example of HV/MV substation

I. 4 . 3 .

 43 The distribution network -Traditional context I.4.3.1. Conceptual architecture

P a g e 31 | 161 PublicI. 4 . 4 .

 16144 Distributed Energy Resources (DERs)

P a g e 32

 32 Fig.I-2. Types of decentralized generation according to the primary energy

I. 4 . 5 . 3 . 1 .

 4531 Unnecessary protection trippingThe unnecessary protection tripping is explained on Fig.I-3 on which a three-phase fault is placed at point F1. The fault current flows from the main upstream 90kV

P a g e 35 | 161 PublicFig.I- 3 .

 1613 Fig.I-3. Unnecessary protection tripping

P a g e 37

 37 Fig.I-5. Fuse premature blowing

P a g e 38 | 161 PublicI. 4 . 5 . 3 . 5 .

 1614535 Difficulty of reclosing after a fault

P a g e 39 | 161 Public

 161 Fig.I-6. Lack of protection coordination in islanded mode

  Fig.I-7-a -Directly earthed neutral configuration

Fig.I- 7

 7 Fig.I-7-c -Neutral point earthed through a Petersen coil

P a g e 44

 44 Fig.I-7-d -Neutral point earthed through a resistance

Fig.I- 7 Fig.I- 8 .

 78 Fig.I-7-e -Distributed neutral point on MV networks with four wires

P a g e 47 | 161 PublicI. 4 . 9 .

 16149 Problem formulation and research objectives

P a g e 48 | 161

 161 Publicchanges on assets by itself. Introducing a new process of change management could enhance the protection system and more globally other distribution automation functions such as voltage control, load shedding optimization, etc. Each function would be tied to the feeder network connectivity model.

(

  Common Information Model) data model and the feeder which uses the IEC 61850 and, between the electric components on the feeder circuit and the feeder controller on the other hand which both use the IEC 61850. As a result, a harmonization of P a g e 49 | 161 Public these two data models is necessary. This decentralized control would pave the way for the transfer of network model from the Control Center to the MV feeder.

Fig.II- 1 .

 1 Fig.II-1-c show the operating characteristics of two protection devices in cascade respectively with constant and inverse characteristics. On Fig.II-1, the overcurrentbased coordination technique between the protection devices PR3, PR2, PR1 and R(recloser) is achieved by grading the settings of current pick-up and operating time

P a g e 60 | 161 PublicII. 4 . 3 .

 16143 Coordination based on a logic selectivity Even with directional overcurrent protection relays, the fault clearance time increases as we move towards the main supplying substation, which increases the stress on equipment. The logic selectivity has been patented by Schneider Electric (formerly Merlin Gerin) to reduce the fault clearance time while maintaining the protection coordination.

P a g e 61 | 161 PublicFig.II- 2 .

 1612 Fig.II-2. Logic selectivity principle

P a g e 62 | 161 PublicII. 5 .

 1615 Protection of active distribution networksSo long as the distribution network was passive and radially operated, the protection coordination techniques described previously worked correctly. But, the insertion of distributed energy resources (DER) into the initially passive distribution network has introduced many challenges on the protection coordination. Some of these difficulties have been discussed in the chapter 1. In the following section, we will present and analyze the state of the art in protection coordination strategies used on distribution networks in presence of DERs.II.5.1. Adaptive protection schemes based on overcurrent relays

P a g e 70 | 161

 161 Public 61850 equivalent model of the incoming IEC CIM network model as the input to achieve the distribution feeder protection scheme. All the devices involved in the data exchange (IEC 61850 compliant) are already interoperable.

  Fig.III-1 -Harmonization work mapping in the Smart GridArchitecture Model (SGAM)[START_REF]IEC TR 62357-1-Power systems management and associated information exchange -Part 1: Reference architecture[END_REF]

-----Public--

  The communication between substation and control centers (IEC 61850-90-2); Condition monitoring (IEC 61850-90-3); The feeder automation (IEC 61850-90-6); The modeling of photovoltaic, storage and other DER inverters (IEC 61850-90-7); The modeling of hydropower plants (IEC 61850-7-410), distributed energy resources (IEC 61850-7-420); The modeling of wind turbines has been standardized according to IEC 61850, within the IEC 61400-25 series, Communications for monitoring and control of wind power plants; P a g e 73 | 161 Wide area engineering guidelines (IEC 61850-90-12); Power quality (IEC 61850-90-17).

  The logical nodes can be organized into one or more Logical Devices (LD). Each logical Node has properties called Data Objects (DO) and each Data Object has Data Attributes (DA) with their associated types. The IEC61850 data modeling shown on Fig.III-2 illustrates how a physical circuit breaker is virtualized into a Logical Node instance (XCBR1) with its data object Pos and related data attributes (Status StVal and quality q).

Fig.III- 2 -

 2 Fig.III-2 -IEC 61850 data modeling[4]

4 ) 5 )

 45 Fig.III-3 shows a simplified UML (Unified Modeling Language) model of IEC 61850 with primary equipment containership, allocation of functions to different containers and substation topology. In addition, the IED (product section of the SCL) is shown with its associated communication information.

Fig.III- 4 -

 4 Fig.III-4 -Package dependencies in CIM[START_REF]-Energy management system application program interface (EMS-API) -Part 301: Common information model (CIM) base, Edition 7, CIM17[END_REF]

Fig.III- 5 -

 5 Fig.III-5 -Equipment class hierarchy in CIMadapted from[START_REF]-Energy management system application program interface (EMS-API) -Part 301: Common information model (CIM) base, Edition 7, CIM17[END_REF]

P a g e 81 | 161 PublicFig.III- 7 -

 1617 Fig.III-7 -Equipment mapping between IEC 61850 and CIMadapted from[START_REF]TS: « Power system management and associated information exchange -Interoperability in the long term -Part 2: CIM-IEC 61850 harmonization[END_REF]

Fig.III- 3 ,

 3 the Equipment object may have a SubEquipment object to cover non three phase scenarios. The CIM models provide a means to specify equivalent single-line representation of balanced three phase networks or to additionally and optionally specify individual phase detail. In single phase networks there is a direct correspondence between Terminal objects and physical wire connections. In the single-line representation of balanced three phase networks we use one Terminal to represent the group of coordinating phase connections. Thus, one Terminal can be used to specify one or more coordinated phase connections using the Terminal.phases attribute which is of enumeration type PhaseCode. PhaseCode has the possible phase connection combinations of ABC, ABCN, AB, BC, CA, A, B, C and so forth [39]. Therefore, we can summarize by considering the following scenarios: = 'AC' or 'BC' or 'AC' The Fig.III-8 shows, for each CIM conducting equipment, the associated single-phase element which is an equivalent to the IEC 61850 SubEquipment.

  Fig.III-8 -Phase wire data model in CIM[START_REF]-Energy management system application program interface (EMS-API) -Part 301: Common information model (CIM) base, Edition 7, CIM17[END_REF]

  Fig.IV-4 shows a feeder consisting in several zones, each representing a protected area.

Fig.IV- 4 -

 4 Fig.IV-4 -Example of a distribution feeder split in zones

  is characterized by overhead lines and underground cables, unbalanced loading with constant current, constant impedance, or constant power model, line voltage regulators, shunt capacitor banks, and multiple switches. As illustrated in Fig.IV-5, this test feeder is a 4.16kV circuit supplied by a single point 90kV external grid through one 90/4.16kV-10MVA power transformer connected between nodes 150 and 150r. The network data of the IEEE 123 nodes test feeder is given on appendix A3. Fig.IV-5 shows the network structure.

  Fig.IV-5 -Reference network

  Fig.IV-6 -Modeling environment

  P a g e 100 | 161Public to obtain with a classic snapshot modeling technique. OpenDSS (Open Distribution System Simulator) meets these requirements.The OpenDSS is a comprehensive electrical system simulation tool for electric utility distribution systems. OpenDSS refers to the open-source implementation of the DSS.

IV. 4 . 3 .

 43 Modeling principles Due to time constraints, the connectivity model of the reference network in CIM RDF XML format is created from a retro-engineering process by making a CIM export of the reference network from OpenDSS. The exported file is the base network connectivity model. Assuming the network connectivity model is at the Control Center, this CIM RDF XML file is passed to the MV feeder controller. At reception of this file, the controller does many operations (Fig.IV-7) amongst which: -The parsing and extraction of the network components and connectivity; -The creation of a graph for network analysis and zone creation; -The creation of the IEC 61850 equivalent of the incoming network model as the feeder is using the IEC 61850 data model; in addition, what is envisioned is the P a g e 101 | 161 Public reduction of the engineering process by automatically achieving the model transformation in lieu and place of an IEC 61850 system engineer. This automatic translation can be very useful for feeder automation functions which could be in position to integrate 'on the fly' the changes on the incoming network model; -The generation of the OpenDSS netlist from Python for providing the power system simulation software with the updated version of the network in case there are changes into it.

Fig

  Fig.IV-7 -Simulation architecture

Fig.IV- 8

 8 Fig.IV-8 shows the different causes of false differential currents. The false differential currents may be originating from :

  Fig.IV-8 -False differential currents during load and external faults[START_REF] Ziegler | download.e-bookshelf[END_REF]

  we will adopt the CIM three layers architecture based on UN/CEFACT CCTS (Core Component Technical Specification) and shown on previous Fig.III-6. This architecture is discussed below. P a g e 104 | 161 Public IV.5.1.1. The three layers architecture of CIM

  P a g e 105 | 161 Public IV.5.3. Introduction to RDF (Resource Description Framework)

  Fig.IV-15. As we can see on Fig.IV-15, the description of the EnergySource resource uses both CIM and RDF vocabularies. The example below gives nine sets of statements amongst which only the three first are described are follows:

  Fig.IV-15 -Example of serialization of the 'EnergySource' Object in CIM RDF XML

  P a g e 108 | 161Public recloser or a circuit breaker. A feeder circuit may consist of several zones interconnected through circuit breakers or reclosers acting as "boundaries".In view of the circuit on Fig.IV-16 below, the reference network has five reclosers and one circuit breaker which can be regarded as "boundaries" between the different zones. Therefore, the reference network can be split into six interconnected zones as shown on Fig.IV-16. The creation of zone is implemented in Python by considering the global reference network as a graph that may be split off to form a set of subgraphs (equivalent to sub-circuits), each representing a zone. More specifically, a graph traversal is performed to find the location of boundaries. Once a boundary is found, it is opened, and the process continues until all the boundaries are visited.

Fig

  Fig.IV-16 -Reference network split in zones

  injected from capacitor banks which are considered as negative loads.Considering that the sum of generated current equals the sum of consumed current,

IV. 7 . 2 .

 72 Fig. IV-18 -Data exchange between central and peripheral units

Fig

  Fig. IV-19 -Power transformer electrical model

Fig.IV- 20 -

 20 Fig.IV-20 -Pi model of a line segment

26 For:

 26 three-phase line segment:Similarly, a three-phase line segment is modeled by the following impedance matrices: unit length (Ω/km) on respectively phase 1, reactance per unit length (Ω/km) between phase 1 and 2 31 13 , x x : reactance per unit length (Ω/km) between phase 1 c : capacitance (nF) between phase 2 and 3

Fig.IV- 21 -

 21 Fig.IV-21 -Example of operating profile of a capacitor bank

  P a g e 122 | 161Public IV.10. ConclusionBefore conducting the steady state simulations, it was necessary to adequately model the reference network. Four modeling levels have been discussed. Firstly, the reference network has been modeled in CIM to mirror the physical reference network originating from the Control Center. This is called the incoming network model.Secondly, the reference network has been modeled in IEC 61850 (feeder data model) thanks to the harmonization between CIM and IEC 61850. Thirdly, a graph has been created from the reference network for ZDP zones creation. Finally, the behavioral modeling of the reference network components have been presented to get ready the network simulator (OpenDSS) for running the steady state simulations in the next chapter.

1 --CPU count = 8 -

 18 Basically, steady state network simulations are run based on the modeling process described on Fig.IV-6 and Fig.IV-7. For each simulation, a controller, located at the head of the distribution feeder, gets the currents from all relevant power system components and sequentially computes, for each phase of the different zones of the feeder, the bias and differential currents. The bias and differential currents represent the operating point of the zone differential protection, with bias current on the abscissa and differential current on the ordinate. Finally, the differential protection operating point is placed on the operating characteristic to check if it falls within the operating (TRIP AREA) or restraining region (NO TRIP AREA). See tripping characteristic on Fig.IV.3 in appendix A2. The network simulations are divided into two Simulations Packages (SP) : -The first package (SP1) consists in assessing the behavior of the zone differential protection using the adapted IEEE 123 nodes network model (call it reference network model); -In the second package (SP2), some changes (addition of new power system components) are introduced into the reference network model to check the P a g e 127 | 161 Public incremental management aspect or how these changes are enrolled in the zone differential protection.For each simulation package, there are some preliminary checks before network simulations begin.V.2.1. Preliminary checksBefore assessing the behavior of the ZDP, the preliminary verifications below are done to ensure that all the power system components in the incoming network model are enrolled in the feeder controller protection scheme and more globally in the feeder automation functions. ▪ IEC 61850 equivalent of the incoming CIM network model: consisting in checking that all the power system components in the CIM model are present in the IEC 61850 XML file. The CIM network model corresponding to the reference network model and the equivalent IEC 61850 XML file are shown respectively on appendices B1 and B2 for SP1. To illustrate the incremental management or how the changes are integrated in the ZDP, an update of the initial CIM network model with new power system components is given along with its IEC 61850 equivalent in appendices C1 and C2 dedicated to SP2; ▪ The graph of the global network including all the nodes and edges: consisting in checking that the graph reflects the given network model. See appendices B3 and C3 respectively for SP1 and SP2; ▪ The zones creation: the split of the incoming network model into zones is checked, along with the composition and borders of each zone. See graph of each zone in appendices B4 and C4 respectively for SP1 and SP2.Now that the feeder controller has all the data per zone, network simulations can be performed.V.2.2. Network simulationsTo make possible the network simulations for ZDP validation, it is necessary to model the incoming network model (from CIM) under the selected power system simulation software. As already discussed in section IV.4.2, OpenDSS has beenP a g e 128 | 161Public chosen. Therefore, the automatic generation of the OpenDSS netlist from Python will be checked for alignment with the incoming network model before starting the simulations. However, OpenDSS allows a profile to be associated to a load only if the load model is "constant power". Therefore, the load models have been changed accordingly. See modified OpenDSS netlist in appendices B5 and C5 respectively for SP1 and SP2.Once the network is modeled in OpenDSS, two types of simulations are conducted as below:-A normal 24 steps sequential power flow simulation mirroring the normal operating conditions (based on load and generation profiles) in which the ZDP is not supposed to operate. The results of the power flow simulations are shown in appendices B6 and C6 respectively for SP1 and SP2; -Short-circuit simulations where different types of faults will be applied on the network while varying their location and their resistance. The ZDP is supposed to operate only if the fault appears within the zone. It should be stable for external faults. The results are shown in appendices B7 and C7 respectively for SP1 and SP2;The ZDP is evaluated on a per phase base. For each zone, what is monitored is the balance between, on one hand, the currents flowing in/out of the zone and the total internal (load + generation) currents on the other hand in line with equation Eq.IV.10. Should this equation be not satisfied, and the operating point falls in the operation region of the differential characteristic, the ZDP operates. See settings criteria related to the differential operating value in section IV.3.1.1.V.2.3. Simulation toolsAs discussed previously, the network simulation tool used to conduct our simulations is OpenDSS. However, OpenDSS is controlled through the COM interface by Python to take profit of the capabilities of Python. The python version and computer characteristics used for the simulation are given below : -Python version = 3.6.Python compiler = MSC v.1900 64 bit (AMD64) P a g e 129 | 161 Public -System = Windows 7 -processor = Intel64 Family 6 Model 60 Stepping 3, Genuine Intel, 3.4GHz, Intel i5 Interpreter = 64bit V.2.4. Format of simulation results

Fig

  Fig.IV-3 to check the behavior of the zone differential protection.

Fig.V- 1 4 P

 14 Fig.V-1 and Fig.V-2 for illustration. See zone borders in appendix B4.

  P a g e 136 | 161Public flow for every simulation step. For each step, the power flow solution is read by the Python script to compute, for each zone, the total internal (load -generation) current along with the currents flowing on zone borders.The results are given below (see appendix B6 for more results on simulation package SP1) :Current flow Zone 1 -Phase A Zone 1 -Phase B Zone 1 -Phase CTotal internal (loadgen) (A)

  35.64+63.98j for phase C P a g e 137 | 161

1 = 1 = 8 . 2 = 2 =

 11822 differential current pick-up setting on phase A. It is set to 10% of the phase A rated current = (7.49+3.74j). We get A s I _ 37A = 0.1*In_A P a g e 138 | 161 Public A s I _ restraining current pick-up setting on phase A. It is set to 120% of the phase A rated current = (89.88+44.88j). We get A s I _ 100.46A = 1.2*In_ATo complete the drawing of the differential protection operating characteristic, the slopes k1 and k2 are added as defined in V.3.1.2 (k1=30%, k2=80%). Same principles apply to phases B and C.

  Fig V.3 -ZDP operating points of zone 1 -Normal power flow -Simulation step 1

  P a g e 140 | 161Public V.4.1.7. Short-circuit simulations in SP1Following the same process as previously, short-circuit simulations are conducted to check the behaviour of the ZDP during abnormal conditions. The simulations include several direct and resistive faults at different buses of the reference network. The following faults have been simulated :

  21+60.91j for phase C P a g e 141 | 161

Fig

  Fig.V.4 shows that the operating point is in the "no trip area" of the operating characteristic.

Fig

  Fig.V.5 gives the ZDP operating point (represented by a black cross) on each phase of zone 1, at the first simulation step. As illustrated on Fig.V.5, the operating point is within the "NO TRIP AREA" of the ZDP for all three phases A, B and C. Therefore, no trip takes place which is normal during normal operating conditions.See more results on appendix C6 for SP2.

Fig.V. 6

 6 Fig.V.6 gives the graph representation of zone 3 in SP2.

  94+88.91j for phase C

Fig

  Fig.V.7-a and Fig.V.7.b gives the ZDP operating point (represented by a black cross) on each phase for respectively zone 1 and zone 3. As shown on Fig.V.7-a, the operating point is zone 1 is within the "NO TRIP AREA" for phases A, B and C.See more results on appendix C7 for SP2.

Fig V. 7

 7 Fig V.7-b -ZDP operating points of zone 3 for an in-zone BN fault, bus 251

  P a g e 151 | 161 Public V.5

  P a g e 152 | 161 Public Chapter VI : General Conclusions and Perspectives P a g e 153 | 161 Public VI.1. Conclusions The presence of DERs (Distributed Energy Resources) on traditionally passive distribution networks has not only brought changes on the energy supply paradigm but also on automation functions such as protection coordination, Volt/Var/Watt control to name a few. Adverse effects of distributed on the protection coordination on the distribution feeder has been highlighted, leading to the need for a new protection coordination paradigm. This research work has brought the following key contributions: -Proposition of a new mindset consisting in providing the distribution feeder with knowledge on the electric circuit it is supplying. This knowledge is centralized at the Control Center which uses the CIM (Common Information Model) data model. The scenario was to transfer, to the distribution feeder, its network model from the Control Center to help it perform some automation functions (protection coordination, Volt/Var/Watt control, etc.). However, because the distribution feeder data model is based on IEC 61850, the harmonization between CIM and IEC 61850 was required. The proposed mindset have been applied to protection coordination to show its applicability. However, it could also be applied to other feeder automation functions amongst which the Volt/Var/Watt control; -Analysis of CIM and IEC 61850 data models and design of a model transformation engine allowing the network model transfer to the feeder; -Based on the transferred knowledge, a new protection scheme called Zone Differential Protection (ZDP), located at the head of the feeder, have been investigated and applied to a modified version of the IEEE 123 nodes test feeder to assess its behavior during steady state power flow and disturbances. The chapters IV et V discussed the main developments in terms of modeling and simulations on the proposed ZDP. The simulations have shown the stability of the ZDP under normal power flow. During faulty conditions, the ZDP does not trip sound zones borders for external faults. However, the high operating time of the ZDP (between 116 and 216ms) will P a g e 154 | 161 Public create an unavailability of distributed generation within sound zones. As already discussed, the high operation time can be reduced if the power system simulator used, gives the current flow direction; -The proposed network model transfer enables a network model continuity between the Control Center and the feeder automation functions, then allowing, an update 'on the fly' of the envisioned feeder automation functions. Needless to say that IEC 61850 and CIM data model are not currently aligned on aspects related to the protection and communication. However, harmonization between the IEC 61850 and CIM are still ongoing at IEC level.-Proposition to have the same method of identifying power system components on CIM and IEC 61850. In fact, the current IEC 61850 model uses a 'name' attribute to identify the power system components, meaning that if for example the name of a component is changed by the IEC 61850 System engineer, The Control Center does not know if this component represents a new component or the same one but with a new name. In the simulations conducted, an 'ID' attribute has been added to each IEC 61850 power system component as the counterpart of the CIM mRID (master ID) attribute.

  particularly the communication aspects. Communication parameters such as IP address, VLAN (Virtual Local Area Network), MAC address do not currently exist in the CIM model. Therefore, their addition could be a real enhancement for the feeder automation. -In addition, the protection and control model is incomplete in CIM. In fact, the proposed protection functions are very limited, making difficult if not impossible the specification of protection functions on a feeder. The extension of the protection and control model could facilitate the generation of the IEC 61850 SCL files. P a g e 156 | 161 Public VI.2. Perspectives

  P a g e 157 | 161 Public peripheral unit(s) need to be redirected to the central unit of the back-up distribution feeder; -The management of the evolution in the incoming network model needs to be improved. Whenever the network model is received from the Control Center, the feeder controller rebuilds the graph of the whole network which is time consuming. It could be interesting to investigate a new approach to only update the modified part of the network model; -The system management aspects for the automatic updating of the protection devices to account for firmware updates; -The online maintenance of the protection devices involved in the protection coordination without sacrificing the reliability of the protection coordination; -The use of parallel computing for a distribution feeder with several interconnected zones. Our simulations have been done based on a sequential algorithm, meaning that the differential protection computations are applied to each zone instead of applying it simultaneously to all zones;

  Fig.IV-2 -Current flow direction during fault

Fig.IV- 3 -

 3 Fig.IV-3 -Operating characteristic of a biased differential protection

  Fig.IV-9 -Equipment container class diagram -adapted from[START_REF]IEC 61850-6-Power systems management and associated information exchange -Part 6: Configuration description language for communication in power utility automation systems related to IEDs[END_REF]

Fig

  Fig.IV-10 -Two-terminals conducting equipment and its connectivity

  Fig.IV-12 -Modeling of a three-phase unbalanced line segment using a linecode defined in matrix format

  Fig.IV-14-One-terminal conducting equipment and its connectivity

-

  The rated active and reactive powers -The phase connection (Delta or Wye) -The nominal voltage -The positive sequence shunt susceptance (b) per section With:

[

  Fault at bus 35 in Zone 3 -Fault on phase = AB -Fault resistance R = 0 ohms ] Appendix B7 -Short-circuit simulation -SP1

[

  Fault at bus 35 in Zone 3 -Fault on phase = AB -Fault resistance R = 0 ohms ] Appendix B7 -Short-circuit simulation -SP1

[

  Fault at bus 35 in Zone 3 -Fault on phase = AB -Fault resistance R = 0 ohms ] Appendix B7 -Short-circuit simulation -SP1

[

  Fault at bus 35 in Zone 3 -Fault on phase = AB -Fault resistance R = 50 ohms ] Appendix B7 -Short-circuit simulation -SP1

[

  Fault at bus 61s in Zone 6 -Fault on phase = ABC -Fault resistance R = 0 ohms ] Appendix B7 -Short-circuit simulation -SP1

[

  Fault at bus 450 in Zone 4 -Fault on phase = ABC -Fault resistance R = 0 ohms ] Appendix B7 -Short-circuit simulation -SP1

Table I -

 I

		magnitude	Angle error  at	Total error at n*In
		error at nominal In	nominal In	(rated accuracy limit)
	5P	1%		5%
			60 minutes
	10P	3%		10%
			Public

1-Accuracy class as per IEC 61869-2 P a g e 29 | 161

  Public applied to a distribution feeder based on the transfer of its network connectivity model from the Control Center. To understand the technical challenges in this thesis, we have described previously the power system and more specifically the distribution system both in its traditional model and in the new paradigm. The protection coordination concerns introduced by DG have been exposed. In the next chapter, we present the state of the art in protection coordination on active distribution networks. .2. Definitions .................................................................................................................................. II.3. Basic requirements of a protection system................................................................................ II.4. Protection of passive distribution networks ..............................................................................

presence of Distributed Generation. Nevertheless, it should be ensured without degrading the reliability indicators. Many strategies have been proposed to continue to ensure a good protection coordination in presence of Distributed Generation. In this thesis, we investigate a new concept of Zone Differential Protection (ZDP) P a g e 50 | 161 II.1. Introduction ................................................................................................................................ IIII.4.1. Overcurrent-based protection coordination technique ..................................................... II.4.2. Coordination based on a direction criterion ....................................................................... II.4.3. Coordination based on a logic selectivity ............................................................................ II.4.4. Conclusion on protection coordination techniques on passive distribution networks ...... II.5. Protection of active distribution networks ................................................................................ II.5.1. Adaptive protection schemes based on overcurrent relays ............................................... II.5.2. Adaptive protection schemes based on distance relays ..................................................... II.5.3. Fault current limiters ........................................................................................................... II.5.4. Logic selectivity-based protection coordination using IEC 61850 ....................................... II.5.5. Limitations of protection coordination techniques on active distribution networks ......... II.5.6. Conclusion ........................................................................................................................... P a g e 53 | 161 Public II.1. Introduction

  Public networks with a significant penetration level of DER. Another drawback of this solution is that the protection settings in each setting group is tied to the network configuration. So, anytime there is a new network configuration, it is necessary to check the validity of the settings in the new context.

P a g e 63 | 161 II.5.2. Adaptive protection schemes based on distance relays

  Introduction ............................................................................................................................... III.2. IEC 61850 and IEC CIM .............................................................................................................. III.2.1. IEC 61850 ............................................................................................................................ III.2.1.1. Goal and definition ...................................................................................................... III.2.1.2. Scope ........................................................................................................................... III.2.1.3. Data modeling approach ............................................................................................. III.2.1.4. System Configuration Description Language (SCL) object model ............................... III.2.2. Common Information Model (CIM) .................................................................................... Conclusion .................................................................................................................................

	Chapter III : Harmonization between III.1. Introduction
	The previous chapter 2 highlighted the impacts of DG on the protection coordination IEC 61850 and CIM (Common on MV distribution feeders. These impacts call for new requirements on protection Information Model) coordination. As discussed in chapter 1, the objective of this research work is to
	investigate a new concept for improving the protection coordination on distribution
	feeders. The concept (developed in chapter 4) consists in transferring to the feeder,
	its electrical network model from the Control Center, to allow it better ensure the
	Chapter III : Harmonization between IEC 61850 and CIM (Common Information Model) ................... protection coordination in presence of DG. The electrical network model contains
	be able to achieve the Zone Differential Protection, the distribution feeder needs to have the model of the downstream network it is supplying. This knowledge is only available at the Control Center which uses the CIM (Common Information Model) data model while the feeder data model is based on IEC 61850. Therefore, due to the difference of data models, a harmonization on the relevant domains is necessary between the CIM and IEC 61850 data models to allow their interoperability. This will require a deep analysis of the two data models to understand their specificities, discrepancies, limits and how a model transformation can be designed to allow the transfer of the feeder network model. electrical components on the feeder along with the connectivity between them. To III.1. III.2.2.1. Definition and scope .................................................................................................... reach this goal, a data exchange is required on one hand, between the Control
	III.2.2.2. Data model ..................................................................................................................
	III.3. Harmonization between IEC 61850 and IEC CIM ......................................................................
	III.3.1. Methodology of harmonization ........................................................................................
	III.3.2. Specificities of unbalanced distribution networks .............................................................
	III.3.3. Data models constrains for achieving the transfer of network model ..............................
	P a g e 67 | 161 P a g e 68 | 161 III.4. P a g e 69 | 161
	Public Public

  .b are met for phase A, Eq. IV.17.a or Eq. IV.17.b for phase B, Eq. IV.18.a or Eq. IV.18.b for phase C.

	V.4. Interpretation of simulation results
	V.4.1. Simulations in simulation package SP1
	In this section, the preliminary checks discussed previously, and the steady state
	network simulation conducted on reference network model are presented.

15.

c. The ZDP trips should previous Eq. IV.

[START_REF] Barker | Determining the Impact of Distributed Generation on Power Systems, I. Radial Distribution Systems[END_REF]

.a or Eq. P a g e 131 | 161 Public IV.16V.4.1.1. Reference network model In the appendix B1, our reference network model is given in a CIM RDF XML file mirroring the real network in CIM model. This initial CIM RDF XML model is obtained through a retro engineering process during which the reference network was firstly model in OpenDSS. Then, an export to CIM has been done from OpenDSS. The advantage of doing this is to get all the network components IDs

  As discussed in section IV.6, the incoming reference network model is converted into a graph representing the connectivity of the network. The graph is used here especially for zone creations. See appendix B3 for the simulation package SP1.

	V.4.1.4. Zones creation
	Following the global graph construction, Python generates the different zones
	composing the global graph. A snapshot of each created zone in SP1 is given in
	Appendix B4 along with the borders. For each zone, the breakers/reclosers at

P a g e 132 | 161 Public V.4.1.2. IEC 61850 equivalent of reference model To date, the IEC 61850 configuration of substations, feeders are done manually by a System engineer from an incoming network described in paper format. This process does not allow an update 'on the fly' of the envisioned feeder automation functions from incoming CIM model. As already discussed, we proposed and simulated an automatic transformation of the CIM model into IEC 61850. Of course, several critical data required in the feeder/substation automation such as IP address, VLAN, full protection functions, are currently missing in the CIM model. Therefore, in the future, the CIM model should provide the capability to directly integrate the missing data to allow for the generation of the full IEC 61850 configuration file of the feeder/substation.

In addition, as highlighted in section III.3.1, the current IEC 61850 model uses a 'name' attribute to identify the power system components, meaning that if for example the name of a component is changed at IEC 61850 level, nobody knows if this component represents a new component or the same one but with a new name. Therefore, if a Control Center application asks for data from the component via the previous name, the connection to the component will be refused. See appendix B2a for details on the current identification approach. As a result, we proposed to have the same identification method on both models. In the simulations conducted, an 'ID' attribute is added to each IEC 61850 power system component as the counterpart of the CIM mRID (master ID) attribute. Appendix B2b illustrates the proposed identification method for the IEC 61850 file. P a g e 133 | 161 Public V.4.1.3. Graph of the reference network borders are shown based on the connectivity data into the graph. The knowledge of the borders is used by the ZDP to isolate the faulty zone. After the zones creation, all the power system components (load, generating sources, capacitor banks, etc.) belonging to a specific zone are checked by the Python script before starting the ZDP computations. V.4.1.5. OpenDSS netlist of the reference network in SP1

  .1 gives the ZDP operation time for each faulty zone. The operating time we are referring to in table V.1 is the time between the fault detection and the ZDP decision.

	Fault number	Fault location Bus Zone	Phases involved	Fault resistance ()	ZDP operating zone (ms) time in faulty
	1	35	3	AB	0	136.39
	2	35	3	AB	50	158.79
	3	61s	6	ABC	0	116.23
	4	78	4	BC	100	200.77
	5	450	4	ABC	0	216.60
	Table V.1 -ZDP operating time obtained for faults on zones 3, 6 and 4
	V.4.2. Simulations in simulation package SP2
					P a g e 143 | 161
				Public

Operating point : (290.8In,0.0In)

	Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B6 -Power flow simulation -SP1 -continued Appendix B7 -Short-circuit simulation -SP1
	Simulation step 1/24 Simulation step 1/24 Simulation step 1/24 Simulation step 1/24 Simulation step 1/24 Simulation step 1/24 Simulation step 2/24 Simulation step 2/24 Simulation step 2/24 Simulation step 2/24 Simulation step 2/24 Simulation step 2/24 Simulation step 3/24 Simulation step 3/24 Simulation step 3/24 Simulation step 3/24 Simulation step 3/24 Simulation step 3/24 Simulation step 4/24 Simulation step 4/24 Simulation step 4/24 Simulation step 4/24 Simulation step 4/24 Simulation step 4/24 Simulation step 5/24 Simulation step 5/24 Simulation step 5/24 Simulation step 5/24 Simulation step 5/24 Simulation step 5/24 Simulation step 6/24 Simulation step 6/24 Simulation step 6/24 Simulation step 6/24 Simulation step 6/24 Simulation step 6/24 Simulation step 7/24 Simulation step 7/24 Simulation step 7/24 Simulation step 7/24 Simulation step 7/24 Simulation step 7/24 Simulation step 8/24 Simulation step 8/24 Simulation step 8/24 Simulation step 8/24 Simulation step 8/24 Simulation step 8/24 Simulation step 9/24 Simulation step 9/24 Simulation step 9/24 Simulation step 9/24 Simulation step 9/24 Simulation step 9/24 Simulation step 10/24 Simulation step 10/24 Simulation step 10/24 Simulation step 10/24 Simulation step 10/24 Simulation step 10/24 [ Fault at bus 35 in Zone 3 -Fault on phase = AB -Fault resistance R = 0 ohms ]
	Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1
	DEFINITION							Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A							Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B					Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C	2025 1125 2325 1500
	58 2075 1850 77 3925 1375 internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen)					14 1200 2150 7 1000 1500 21.59-61.62j 36.08-70.84j 53.75-97.13j 6.84-65.22j 26.21-44.11j 0.00+0.00j 27.83-73.40j 38.90-78.30j 57.76-104.31j 14.62+32.55j 26.91-44.88j 0.00+0.00j 27.62-74.34j 35.42-73.46j 53.53-94.67j 19.80-75.15j 26.34-44.92j 0.00+0.00j 31.23-75.92j 37.07-76.27j 52.90-100.37j 4.88-54.47j 26.14-44.11j 0.00+0.00j 27.35-74.20j 40.61-80.27j 52.72-96.44j 5.61-58.11j 26.84-45.50j 0.00+0.00j 29.20-74.88j 37.93-76.61j 53.98-98.99j -0.22-44.76j 26.82-45.11j 0.00+0.00j 27.68-71.76j 37.87-79.77j 54.52-100.74j 7.12-51.03j 27.05-45.68j 0.00+0.00j 25.58-68.35j 35.11-73.18j 57.30-106.38j 4.90-53.41j 27.20-45.94j 0.00+0.00j 24.59-70.22j 35.76-71.97j 56.15-104.18j -0.02-43.47j 27.70-46.52j 0.00+0.00j 19.73-62.00j 38.89-79.24j 55.11-99.38j 0.41-47.39j 26.46-44.47j 0.00+0.00j 457.38+311.30j		82 4025 175 61 3075 1300 19.91+14.71j -72.02-0.36j -115.79+12.81j -57.48+22.64j -30.32-0.93j 0.00+0.00j 10.10+13.80j -69.74-0.25j -119.85+12.73j 29.44-32.94j -30.85-1.14j 0.00+0.00j 13.29+13.03j -66.75-1.24j -118.54+13.82j -68.55+26.02j -35.17-0.99j 0.00+0.00j 4.78+13.09j -66.37+0.45j -116.55+11.99j -59.62+26.41j -31.10-0.95j 0.00+0.00j 9.80+12.52j -64.86-0.05j -114.08+12.46j -61.96+24.40j -28.12-0.90j 0.00+0.00j 11.83+13.10j -69.43-1.82j -121.24+13.46j -43.53+35.56j -32.03-1.09j 0.00+0.00j 9.62+13.63j -72.29-1.15j -108.81+11.72j -58.08+32.98j -33.44-1.04j 0.00+0.00j 12.10+14.07j -68.62-0.87j -122.59+13.74j -54.42+26.80j -27.25-0.88j 0.00+0.00j 17.73+14.11j -72.50-1.30j -123.24+12.70j -49.49+29.00j -30.23-0.98j 0.00+0.00j 17.55+15.00j -69.07-1.27j -109.53+12.29j -43.87+33.76j -32.74-1.14j 0.00+0.00j 659.55-130.17j	75 4550 1575 64 3075 2625 35.66+63.99j 29.19+56.32j 42.35+63.02j 45.22+43.57j 20.97+37.97j 0.00+0.00j 39.33+77.94j 29.84+59.35j 48.69+73.16j -39.15-6.99j 19.12+35.09j 0.00+0.00j 42.73+82.16j 33.07+60.48j 46.09+68.03j 43.44+49.04j 19.32+34.63j 0.00+0.00j 42.22+82.26j 32.46+64.30j 47.11+69.28j 41.45+29.01j 20.35+36.71j 0.00+0.00j 41.88+83.13j 29.50+56.93j 46.69+69.32j 43.12+40.51j 21.15+38.02j 0.00+0.00j 41.11+81.36j 30.80+59.08j 48.47+72.15j 38.55+13.94j 18.45+33.75j 0.00+0.00j 38.96+77.71j 28.93+58.05j 45.34+67.52j 40.28+20.75j 22.13+40.23j 0.00+0.00j 37.41+72.51j 31.20+60.44j 49.85+73.52j 39.30+29.21j 19.97+36.21j 0.00+0.00j 38.15+71.89j 32.25+61.03j 50.49+74.86j 42.21+21.15j 18.11+33.04j 0.00+0.00j 35.83+70.97j 26.74+53.44j 46.52+69.48j 40.93+18.53j 18.44+33.93j 0.00+0.00j 563.22+60.92j	1975 3275 4325 1850
	99 4350 2100 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1					88 2950 1300 144.68-338.94j 69.29-180.16j 53.77-97.15j 33.14-109.33j 26.23-44.11j 0.00+0.00j 136.80-333.57j 51.19-155.79j 57.76-104.34j 26.92-44.90j 26.92-44.90j 0.00+0.00j 162.87-362.58j 81.67-193.56j 53.56-94.68j 46.20-120.12j 26.35-44.93j 0.00+0.00j 152.37-351.15j 68.20-174.84j 52.91-100.37j 31.09-98.60j 26.15-44.11j 0.00+0.00j 153.31-354.56j 73.18-183.88j 52.75-96.46j 32.52-103.63j 26.86-45.51j 0.00+0.00j 147.86-340.37j 64.64-166.48j 54.00-99.00j 26.66-89.89j 26.82-45.11j 0.00+0.00j 154.40-349.05j 72.14-176.50j 54.54-100.77j 34.23-96.74j 27.05-45.68j 0.00+0.00j 150.28-347.31j 67.31-172.56j 57.34-106.40j 32.16-99.40j 27.22-45.96j 0.00+0.00j 144.35-336.40j 63.56-161.95j 56.18-104.21j 27.75-90.00j 27.72-46.52j 0.00+0.00j 140.78-332.54j 65.87-171.13j 55.14-99.39j 26.94-91.91j 26.49-44.47j 0.00+0.00j 150.90-4512.31j		25r 1500 3150 -255.77+48.63j -159.82+21.18j -115.83+12.77j -87.80+21.62j -30.32-0.95j 0.00+0.00j -239.77+57.85j -129.98+31.39j -119.86+12.69j -30.86-1.15j -30.86-1.15j 0.00+0.00j -275.72+50.43j -170.45+23.65j -118.55+13.77j -103.71+24.96j -35.16-1.01j 0.00+0.00j -268.89+50.75j -157.09+25.74j -116.55+11.95j -90.72+25.37j -31.10-0.97j 0.00+0.00j -259.25+48.23j -154.93+23.31j -114.08+12.43j -90.08+23.42j -28.11-0.91j 0.00+0.00j -254.46+59.00j -145.02+32.50j -121.25+13.44j -75.58+34.40j -32.04-1.11j 0.00+0.00j -263.03+55.93j -163.82+30.66j -108.82+11.68j -91.52+31.87j -33.43-1.05j 0.00+0.00j -260.79+52.63j -150.27+24.90j -122.60+13.71j -81.66+25.84j -27.25-0.89j 0.00+0.00j -257.78+53.31j -152.23+26.58j -123.26+12.65j -79.72+27.96j -30.22-0.99j 0.00+0.00j -237.73+58.44j -145.71+31.22j -109.55+12.25j -76.64+32.55j -32.75-1.16j 0.00+0.00j -2611.91+3622.32j	18 1500 2325 173.28+264.82j 95.30+137.84j 42.34+63.00j 66.15+81.51j 20.97+37.96j 0.00+0.00j 176.07+252.64j 88.07+101.51j 48.69+73.17j 19.12+35.10j 19.12+35.10j 0.00+0.00j 184.54+294.33j 95.74+144.14j 46.08+68.03j 62.72+83.67j 19.30+34.64j 0.00+0.00j 183.47+281.53j 94.17+130.01j 47.11+69.28j 61.75+65.71j 20.34+36.71j 0.00+0.00j 182.24+287.92j 93.68+135.46j 46.68+69.32j 64.22+78.53j 21.14+38.03j 0.00+0.00j 177.28+260.28j 87.73+106.78j 48.46+72.15j 56.97+47.70j 18.44+33.75j 0.00+0.00j 175.55+264.24j 91.27+119.01j 45.33+67.52j 62.38+60.96j 22.12+40.23j 0.00+0.00j 177.63+271.88j 90.37+125.85j 49.85+73.52j 59.22+65.41j 19.96+36.21j 0.00+0.00j 181.08+261.96j 92.47+115.23j 50.48+74.85j 60.28+54.20j 18.10+33.04j 0.00+0.00j 168.38+246.35j 86.05+105.91j 46.51+69.48j 59.34+52.46j 18.43+33.93j 0.00+0.00j 744.44+301.55j	875 3650
	20 925 2325 160r 3175 1850 BR2 BR4 BR5 BR2 BR4 BR5 BR2 BR4 BR5 BR2 BR4 BR5 BR2 BR4 BR5 BR2 BR4 BR5 BR2 BR4 BR5 BR2 BR4 BR5 BR2 BR4 BR5 BR2 BR4 BR5 BR2					52 2000 1500 22 975 2625 -69.29+180.16j -33.14+109.33j -26.23+44.11j -51.19+155.79j -12.28+77.51j -12.28+77.51j -81.67+193.56j -46.20+120.12j -26.35+44.93j -68.20+174.84j -31.09+98.60j -26.35+44.93j -73.18+183.88j -32.52+103.63j -26.86+45.51j -64.64+166.48j -26.66+89.89j -26.82+45.11j -72.14+176.50j -34.23+96.74j -27.05+45.68j -67.31+172.56j -32.16+99.40j -27.22+45.96j -63.56+161.95j -27.75+90.00j -27.72+46.52j -65.87+171.13j -26.94+91.91j -26.49+44.47j -161.74-273.21j		106 3750 2725 108 3525 3050 159.82-21.18j 87.80-21.62j 30.32+0.95j 129.98-31.39j 60.26-31.73j 60.26-31.73j 170.45-23.65j 103.71-24.96j 35.16+1.01j 157.09-25.74j 90.72-25.37j 31.10+0.97j 154.93-23.31j 90.08-23.42j 28.11+0.91j 145.02-32.50j 75.58-34.40j 32.04+1.11j 163.82-30.66j 91.52-31.87j 33.43+1.05j 150.27-24.90j 81.66-25.84j 27.25+0.89j 152.23-26.58j 79.72-27.96j 30.22+0.99j 145.71-31.22j 76.64-32.55j 32.75+1.16j -238.25+241.28j	31 1150 3375 38 2325 2000 -95.30-137.84j -66.15-81.51j -20.97-37.96j -88.07-101.51j -58.27-42.14j -58.27-42.14j -95.74-144.14j -62.72-83.67j -19.30-34.64j -94.17-130.01j -61.75-65.71j -20.34-36.71j -93.68-135.46j -64.22-78.53j -21.14-38.03j -87.73-106.78j -56.97-47.70j -18.44-33.75j -91.27-119.01j -62.38-60.96j -22.12-40.23j -90.37-125.85j -59.22-65.41j -19.96-36.21j -92.47-115.23j -60.28-54.20j -18.10-33.04j -86.05-105.91j -59.34-52.46j -18.43-33.93j -127.23-157.73j	2650 2300 300 1500
	8 1200 1500 BR3 BR6 BR3 BR6 BR3 BR6 BR3 BR6 BR3 BR6 BR3 BR6 BR3 BR6 BR3 BR6 BR3 BR6 BR3 BR6 BR3					84 4700 425 -53.77+97.15j -0.00-0.00j -57.76+104.34j -0.00-0.00j -53.56+94.68j -0.00-0.00j -52.91+100.37j -0.00-0.00j -52.75+96.46j -0.00-0.00j -54.00+99.00j -0.00-0.00j -54.54+100.77j -0.00-0.00j -57.34+106.40j -0.00-0.00j -56.18+104.21j -0.00-0.00j -55.14+99.39j -0.00-0.00j 468.23+5096.83j		78 4025 1375 115.83-12.77j -0.00-0.00j 119.86-12.69j -0.00-0.00j 118.55-13.77j -0.00-0.00j 116.55-11.95j -0.00-0.00j 114.08-12.43j -0.00-0.00j 121.25-13.44j -0.00-0.00j 108.82-11.68j -0.00-0.00j 122.60-13.71j -0.00-0.00j 123.26-12.65j -0.00-0.00j 109.55-12.25j -0.00-0.00j 3509.71-3993.77j	109 3975 3050 -42.34-63.00j -0.00-0.00j -48.69-73.17j -0.00-0.00j -46.08-68.03j -0.00-0.00j -47.11-69.28j -0.00-0.00j -46.68-69.32j -0.00-0.00j -48.46-72.15j -0.00-0.00j -45.33-67.52j -0.00-0.00j -49.85-73.52j -0.00-0.00j -50.48-74.85j -0.00-0.00j -46.51-69.48j -0.00-0.00j -54.00-82.91j	1825 3275
	5 1025 1250									60 3075 1850					15 1500 1250	1000 1400 2450	1450 2150
	83 4275 175		Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A *		89 2775 1125					74 4150 1575	114 5125 2925	1500 875
	98 3800 2100			8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8						72 3525 1575					92 2550 825	96 2025 925	1150 3150
	9 1200 1725 24 950 2875			7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7						61s 3175 1300 65 2650 2625				112 4275 2925 81 4025 425 NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA	53 2200 1500 51 2725 3275	700 1675 3525 2100
	73 3800 1575			6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6						79 4250 1375	46 2475 3025 ZDP operating characteristic Operating point :	57 2325 1850	2050 3650
	104 4775 2450		5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5						12 1200 1275		(62.7In,0.0In)	40 1975 2575	103 4075 2450	1850 1250
	4 700 1050 37 1775 2000 25 1500 3150			2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4				9r 1200 1725 44 1975 3025 76 3525 1375 k2 k2 k2 k2 k2 k2 k2 k2 NO TRIP takes place on normal operating conditions as the 50 2475 3275 23 1500 2875 19 1250 2325 protection on phase A -it is currently below the characteristic. Therefore, NO TRIP takes place -which is the case on normal operating conditions ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the k2 NO TRIP takes place on normal operating conditions as the k2 NO TRIP takes place on normal operating conditions as the k2 k2 NO TRIP takes place on normal operating conditions as the k2 NO TRIP takes place on normal operating conditions as the k2 NO TRIP takes place on normal operating conditions as the k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 NO TRIP takes place on normal operating conditions as the NO TRIP takes place on normal operating conditions as the NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. k2 k2 k2 The current Operating point of the differential TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA	55 2600 1500 150 100 1500 67 3525 1850	2300 2575 4275 3050 1975 2825
	28 1500 3350 13 1500 1500 102 3750 2450 Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A	1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1	0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0	k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1	1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1	Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2	3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3	63 3075 2275 100 4650 2100 45 2175 3025 NO TRIP takes place on normal operating conditions as the 91 2550 1125 68 3725 1850 43 2475 2825 ZDP differential current is zero. 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18	19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19	20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20	21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21	22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22	87 3050 1125 113 4800 2925 90 2775 900 Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A *	4500 1375 1600 1500 150r 100 1500
	450 5450 2100 86 3255 725 93 2325 1125 85 4700 900 160 3175 1850 62 3075 2100 Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the Idiiff_x is the differential current on the of the current zone. x = A or B or C * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x	5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8			29 1500 3650 300 3245 4010 59 1825 1850 35 1975 2325 21 1500 2625 56 2875 1500				3 700 1250 610 3275 1300 101 3525 2450 135 1600 2325 6 1275 1150 69 4000 1850 NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA	27 875 3150 80 4025 900 11 950 2150 111 4275 3625 36 2075 2000 39 2650 2000	1150 3675 3525 2725 4600 1850 3525 2200 1500 1350 3187 3928
	1 700 1500 Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up			4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4				49 2225 3275 TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA					94 2325 850	30 1850 3650	4325 2725
	setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current.			2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 3 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3							k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2		NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the
	setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x
	rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% rated current. k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current.	Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B	1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1		k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1								NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero.		Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B *
					0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0		1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1	2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2	3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3	4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4	5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5	6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6	7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7	8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8	9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9	10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10	11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11	12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12	13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13	14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14	15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15	16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16	17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17	18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18	19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19	20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20	21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21	22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22
								Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B
				Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C *
				8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8
				7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7
																			NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA
				6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6
				5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5
				4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4				TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA
				3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3							k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2		NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero.
				2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2										ZDP differential current is zero.
														NO TRIP takes place on normal operating conditionsas the
				1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1		k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1								ZDP differential current is zero.
		Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C																					Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C *
				0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0		1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1	2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2	3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3	4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4	5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5	6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6	7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7	8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8	9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9	10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10	11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11	12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12	13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13	14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14	15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15	16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16	17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17	18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18	19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19	20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20	21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21	22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22
								Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero.

NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero.

NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero.

NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero.

NO TRIP takes place on normal operating conditionsas the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero. The operating point is not in the trip area.

NO TRIP takes place as the ZDP differential current is zero. The operating point is not in the trip area.

NO TRIP takes place as the ZDP differential current is zero. The operating point is not in the trip area.

: (20.3In,40.51In) Operating point : (21In,42.2In)

	Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1
	[ Fault at bus 35 in Zone 3 -Fault on phase = AB -Fault resistance R = 0 ohms ] [ Fault at bus 35 in Zone 3 -Fault on phase = AB -Fault resistance R = 0 ohms ]
	Zone : 4 Zone : 5
				Phase A Phase A							Phase B Phase B								Phase C Phase C
	internal (Load -gen) internal (Load -gen)	148.83+349.66j 7.14-29.27j					290.16-233.89j -16.66-2.27j						68.47+54.16j 22.59+40.18j
	BR4 BR5		156.00+320.35j 7.15-29.28j					273.54-236.17j -16.64-2.27j						91.03+94.35j 22.58+40.19j
	BR5		-7.15+29.28j							16.64+2.27j						-22.58-40.19j
		Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A *
		8 8 8
		7 7 7													NO TRIP AREA NO TRIP AREA NO TRIP AREA
		6 6 6
		5 5 5
		4 4 4		TRIP AREA TRIP AREA
		3 3 3					k2 k2
		2 2 2
		1 1 1	k1 k1
		Is1_A Is1_A																						Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A *
		0 0 0	1 1 1	2 2 2	3 3 3	4 4 4	5 5 5	6 6 6	7 7 7	8 8 8	9 9 9	10 10 10	11 11 11	12 12 12	13 13 13	14 14 14	15 15 15	16 16 16	17 17 17	18 18 18	19 19 19	20 20 20	21 21 21	22 22 22
			Is2_A Is2_A
		Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B *
	* In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x	8 8 8
	of the current zone. x = A or B or C of the current zone. x = A or B or C of the current zone. x = A or B or C
	Idiiff_x is the differential current on the Idiiff_x is the differential current on the Idiiff_x is the differential current on the	7 7 7													NO TRIP AREA NO TRIP AREA
	phase x of the current zone. phase x of the current zone. phase x of the current zone.	6 6 6
	Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone.	5 5 5
	Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up	4 4 4		TRIP AREA TRIP AREA
	setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current.	3 3 3					k2 k2
	Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up	2 2 2
	setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x
	rated current. rated current. rated current.	1 1 1	k1 k1
	k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80%	Is1_B Is1_B																						Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B *
		0 0 0	1 1 1	2 2 2	3 3 3	4 4 4	5 5 5	6 6 6	7 7 7	8 8 8	9 9 9	10 10 10	11 11 11	12 12 12	13 13 13	14 14 14	15 15 15	16 16 16	17 17 17	18 18 18	19 19 19	20 20 20	21 21 21	22 22 22
			Is2_B Is2_B
		Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C *
		8 8 8
		7 7 7
															NO TRIP AREA NO TRIP AREA
		6 6 6
		5 5 5
		4 4 4		TRIP AREA TRIP AREA
		3 3 3					k2 k2
		2 2 2
		1 1 1	k1 k1
		Is1_C Is1_C																						Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C *
		0 0 0	1 1 1	2 2 2	3 3 3	4 4 4	5 5 5	6 6 6	7 7 7	8 8 8	9 9 9	10 10 10	11 11 11	12 12 12	13 13 13	14 14 14	15 15 15	16 16 16	17 17 17	18 18 18	19 19 19	20 20 20	21 21 21	22 22 22
			Is2_C Is2_C

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

44.5In,0In) Operating point at : (212.7In,0In) Operating point at : (50.5In,0In)

	Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1
	[ Fault at bus 61s in Zone 6 -Fault on phase = ABC -Fault resistance R = 0 ohms ] [ Fault at bus 61s in Zone 6 -Fault on phase = ABC -Fault resistance R = 0 ohms ]
	Zone : 1 Zone : 2
				Phase A Phase A							Phase B Phase B								Phase C Phase C
	internal (Load -gen) internal (Load -gen)	39.89+103.13j 10.46-22.32j						135.42-74.97j -15.55+0.37j						-114.70-15.27j 6.10+9.16j
	BR1 BR2		-446.33-3582.03j -492.95-4057.64j					-2888.32+2453.72j -3347.22+2723.46j					3455.00+1137.01j 3911.34+1370.35j
	BR2 BR4		515.46+3622.56j -32.97+457.39j					2954.40-2514.04j 408.38-209.79j					-3539.25-1113.74j -378.18-265.76j
	BR3 BR6		-29.23+62.63j -515.46-3622.56j					69.34-14.65j -2954.40+2514.04j					-30.47-38.53j 3539.25+1113.74j
		In_A * Idiff_A/In_A *
		8 8
		7 7													NO TRIP AREA NO TRIP AREA
		6 6
		5 5
		4 4		TRIP AREA TRIP AREA
		3 3					k2 k2
		2 2
		1 1	k1 k1
		Is1_A Is1_A																						Irestr_A/In_A * Irestr_A/In_A *
		0 0	1 1	2 2	3 3	4 4	5 5	6 6	7 7	8 8	9 9	10 10	11 11	12 12	13 13	14 14	15 15	16 16	17 17	18 18	19 19	20 20	21 21	22 22
			Is2_A Is2_A
		Idiff_B/In_B * Idiff_B/In_B *
	* In_x is the rated current of the phase x * In_x is the rated current of the phase x	8 8
	of the current zone. x = A or B or C of the current zone. x = A or B or C
	Idiiff_x is the differential current on the Idiiff_x is the differential current on the	7 7													NO TRIP AREA NO TRIP AREA
	phase x of the current zone. phase x of the current zone.	6 6
	Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone.	5 5
	Is1_x is the differential current pick-up Is1_x is the differential current pick-up	4 4		TRIP AREA TRIP AREA
	setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current.	3 3					k2 k2
	Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up	2 2
	setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x
	rated current. rated current.	1 1	k1 k1
	k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80%	Is1_B Is1_B																						Irestr_B/In_B * Irestr_B/In_B *
		0 0	1 1	2 2	3 3	4 4	5 5	6 6	7 7	8 8	9 9	10 10	11 11	12 12	13 13	14 14	15 15	16 16	17 17	18 18	19 19	20 20	21 21	22 22
			Is2_B Is2_B
		Idiff_C/In_C * Idiff_C/In_C *
		8 8
		7 7
															NO TRIP AREA NO TRIP AREA
		6 6
		5 5
		4 4		TRIP AREA TRIP AREA
		3 3					k2 k2
		2 2
		1 1	k1 k1
		Is1_C Is1_C																						Irestr_C/In_C * Irestr_C/In_C *
		0 0	1 1	2 2	3 3	4 4	5 5	6 6	7 7	8 8	9 9	10 10	11 11	12 12	13 13	14 14	15 15	16 16	17 17	18 18	19 19	20 20	21 21	22 22
			Is2_C Is2_C

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

Operating point at : (

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

Operating point at : (

64.5In,114In) Operating point at : (88.7In,158.3In) Operating point at : (78.5In,139.5In)

	Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1
	[ Fault at bus 61s in Zone 6 -Fault on phase = ABC -Fault resistance R = 0 ohms ] [ Fault at bus 61s in Zone 6 -Fault on phase = ABC -Fault resistance R = 0 ohms ]
	Zone : 3 Zone : 4
				Phase A Phase A							Phase B Phase B								Phase C Phase C
	internal (Load -gen) internal (Load -gen)	29.23-62.66j -36.52+465.27j					-69.33+14.65j 413.50-209.41j						30.46+38.54j -382.08-271.40j
	BR3 BR4		29.23-62.63j -32.97+457.39j					-69.34+14.65j 408.38-209.79j						30.47+38.53j -378.18-265.76j
	BR5			-3.54+7.87j							5.12+0.38j							-3.91-5.63j
		Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A *
		8 8 8
		7 7 7													NO TRIP AREA NO TRIP AREA NO TRIP AREA
		6 6 6
		5 5 5
		4 4 4		TRIP AREA TRIP AREA
		3 3 3					k2 k2
		2 2 2
		1 1 1	k1 k1
		Is1_A Is1_A																						Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A *
		0 0 0	1 1 1	2 2 2	3 3 3	4 4 4	5 5 5	6 6 6	7 7 7	8 8 8	9 9 9	10 10 10	11 11 11	12 12 12	13 13 13	14 14 14	15 15 15	16 16 16	17 17 17	18 18 18	19 19 19	20 20 20	21 21 21	22 22 22
			Is2_A Is2_A
		Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B *
	* In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x	8 8 8
	of the current zone. x = A or B or C of the current zone. x = A or B or C of the current zone. x = A or B or C
	Idiiff_x is the differential current on the Idiiff_x is the differential current on the Idiiff_x is the differential current on the	7 7 7													NO TRIP AREA NO TRIP AREA
	phase x of the current zone. phase x of the current zone. phase x of the current zone.	6 6 6
	Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone.	5 5 5
	Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up	4 4 4		TRIP AREA TRIP AREA
	setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current.	3 3 3					k2 k2
	Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up	2 2 2
	setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x
	rated current. rated current. rated current.	1 1 1	k1 k1
	k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80%	Is1_B Is1_B																						Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B *
		0 0 0	1 1 1	2 2 2	3 3 3	4 4 4	5 5 5	6 6 6	7 7 7	8 8 8	9 9 9	10 10 10	11 11 11	12 12 12	13 13 13	14 14 14	15 15 15	16 16 16	17 17 17	18 18 18	19 19 19	20 20 20	21 21 21	22 22 22
			Is2_B Is2_B
		Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C *
		8 8 8
		7 7 7
															NO TRIP AREA NO TRIP AREA
		6 6 6
		5 5 5
		4 4 4		TRIP AREA TRIP AREA
		3 3 3					k2 k2
		2 2 2
		1 1 1	k1 k1
		Is1_C Is1_C																						Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C *
		0 0 0	1 1 1	2 2 2	3 3 3	4 4 4	5 5 5	6 6 6	7 7 7	8 8 8	9 9 9	10 10 10	11 11 11	12 12 12	13 13 13	14 14 14	15 15 15	16 16 16	17 17 17	18 18 18	19 19 19	20 20 20	21 21 21	22 22 22
			Is2_C Is2_C

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

Operating point at : (30.6In,0.0In) Operating point at : (143.9In,0.0In) Operating point at : (36.7In,0.0In)

	Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1
	[ Fault at bus 61s in Zone 6 -Fault on phase = ABC -Fault resistance R = 0 ohms ] [ Fault at bus 78 in Zone 4 -Fault on phase = BC -Fault resistance R = 100 ohms ] [ Fault at bus 78 in Zone 4 -Fault on phase = BC -Fault resistance R = 100 ohms ] [ Fault at bus 78 in Zone 4 -Fault on phase = BC -Fault resistance R = 100 ohms ] [ Fault at bus 78 in Zone 4 -Fault on phase = BC -Fault resistance R = 100 ohms ] [ Fault at bus 78 in Zone 4 -Fault on phase = BC -Fault resistance R = 100 ohms ] [ Fault at bus 78 in Zone 4 -Fault on phase = BC -Fault resistance R = 100 ohms ] [ Fault at bus 450 in Zone 4 -Fault on phase = ABC -Fault resistance R = 0 ohms ] [ Fault at bus 450 in Zone 4 -Fault on phase = ABC -Fault resistance R = 0 ohms ]
	Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2
				Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A							Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B								Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C
	internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen)	-0.00+0.00j 37.89-85.28j 42.90-92.47j 63.50-120.26j 91.13+2.48j 31.71-57.34j 0.00+0.00j 57.92+38.49j 22.01-43.39j						-0.00-0.00j 7.55+20.25j -79.88+0.62j -135.55+16.74j -34.26-64.08j -38.48-0.26j -0.00+0.00j 93.13-39.46j -37.50+3.75j						0.00-0.00j 46.28+86.00j 38.87+70.28j 56.11+81.01j -54.78+58.54j 24.49+41.78j 0.00+0.00j -67.12+26.02j 15.94+25.77j
	BR6 BR1 BR2 BR3 BR4 BR5 BR6 BR1 BR2		-492.95-4057.64j 267.16-352.97j 165.76-147.38j 63.51-120.28j 122.84-54.91j 31.72-57.35j -0.00-0.00j -273.74-2481.00j -373.42-2438.25j					-3347.22+2723.46j -301.39-37.52j -173.37-74.45j -135.56+16.71j -93.52-75.01j -38.46-0.28j -0.00-0.00j -2109.53+1461.63j -2109.25+1482.22j					3911.34+1370.35j 112.46+360.90j 10.09+193.91j 56.11+81.02j -28.73+123.62j 24.47+41.78j -0.00-0.00j 2470.48+990.84j 2498.47+914.08j
	BR2 BR4 BR5 BR2 BR4		-165.76+147.38j -122.84+54.91j -31.72+57.35j 373.42+2438.25j 395.44+2394.89j					173.37+74.45j 93.52+75.01j 38.46+0.28j 2109.25-1482.22j 2071.76-1478.49j					-10.09-193.91j 28.73-123.62j -24.47-41.78j -2498.47-914.08j -2482.55-888.31j
	BR3 BR6 BR3 BR6		-63.51+120.28j -0.00-0.00j -41.75+81.23j -0.00-0.00j						135.56-16.71j -0.00-0.00j 93.42-18.89j -0.00-0.00j						-56.11-81.02j -0.00-0.00j -39.13-50.74j -0.00-0.00j
		In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A *
		8 8 8 8 8 8 8 8 8
		7 7 7 7 7 7 7 7 7	Operating point at :									NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA
		6 6 6 6 6 6 6 6 6	(62.9In,125.7In)
		5 5 5 5 5 5 5 5 5
		4 4 4 4 4 4 4 4 4		TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA
		3 3 3 3 3 3 3 3 3					k2 k2 k2 k2 k2 k2 k2 k2 k2		TRIP takes place as the ZDP operating point is in the trip area. NO TRIP takes place as the ZDP differential current is zero on
		2 2 2 2 2 2 2 2 2							phase A.
											NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero.
		1 1 1 1 1 1 1 1 1	k1 k1 k1 k1 k1 k1 k1 k1 k1
		Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A																							Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A *
		0 0 0 0 0 0 0 0 0	1 1 1 1 1 1 1 1 1	2 2 2 2 2 2 2 2 2	3 3 3 3 3 3 3 3 3	4 4 4 4 4 4 4 4 4	5 5 5 5 5 5 5 5 5	6 6 6 6 6 6 6 6 6	7 7 7 7 7 7 7 7 7	8 8 8 8 8 8 8 8 8	9 9 9 9 9 9 9 9 9	10 10 10 10 10 10 10 10 10	11 11 11 11 11 11 11 11 11	12 12 12 12 12 12 12 12 12	13 13 13 13 13 13 13 13 13	14 14 14 14 14 14 14 14 14	15 15 15 15 15 15 15 15 15	16 16 16 16 16 16 16 16 16	17 17 17 17 17 17 17 17 17	18 18 18 18 18 18 18 18 18	19 19 19 19 19 19 19 19 19	20 20 20 20 20 20 20 20 20	21 21 21 21 21 21 21 21 21	22 22 22 22 22 22 22 22 22	23 23
			Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A Is2_A
		Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B *
	* In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x	8 8 8 8 8 8 8 8 8
	of the current zone. x = A or B or C of the current zone. x = A or B or C of the current zone. x = A or B or C of the current zone. x = A or B or C of the current zone. x = A or B or C of the current zone. x = A or B or C of the current zone. x = A or B or C of the current zone. x = A or B or C of the current zone. x = A or B or C
	Idiiff_x is the differential current on the Idiiff_x is the differential current on the Idiiff_x is the differential current on the Idiiff_x is the differential current on the Idiiff_x is the differential current on the Idiiff_x is the differential current on the Idiiff_x is the differential current on the Idiiff_x is the differential current on the Idiiff_x is the differential current on the	7 7 7 7 7 7 7 7 7													NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA
	phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone.	6 6 6 6 6 6 6 6 6	Operating point at :
	Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone.	5 5 5 5 5 5 5 5 5	(116.2In,232.5In)
	Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up	4 4 4 4 4 4 4 4 4		TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA
	setting. It is set to 10% of the phase x rated current. Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current.	2 3 2 2 2 2 2 2 2 2 3 3 3 3 3 3 3 3					k2 k2 k2 k2 k2 k2 k2 k2 k2		TRIP takes place as the ZDP operating area on phase B. point is in the trip area. TRIP takes place as the ZDP operating point is in the TRIP
	setting. It is set to 120% of the phase x rated current. setting. It is set to 120% of the phase x rated current. setting. It is set to 120% of the phase x rated current. setting. It is set to 120% of the phase x rated current. setting. It is set to 120% of the phase x rated current. setting. It is set to 120% of the phase x rated current. setting. It is set to 120% of the phase x rated current. setting. It is set to 120% of the phase x rated current. setting. It is set to 120% of the phase x rated current.	1 1 1 1 1 1 1 1 1	k1 k1 k1 k1 k1 k1 k1 k1 k1								NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero.
	k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80%	Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B																							Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B *
		0 0 0 0 0 0 0 0 0	1 1 1 1 1 1 1 1 1	2 2 2 2 2 2 2 2 2	3 3 3 3 3 3 3 3 3	4 4 4 4 4 4 4 4 4	5 5 5 5 5 5 5 5 5	6 6 6 6 6 6 6 6 6	7 7 7 7 7 7 7 7 7	8 8 8 8 8 8 8 8 8	9 9 9 9 9 9 9 9 9	10 10 10 10 10 10 10 10 10	11 11 11 11 11 11 11 11 11	12 12 12 12 12 12 12 12 12	13 13 13 13 13 13 13 13 13	14 14 14 14 14 14 14 14 14	15 15 15 15 15 15 15 15 15	16 16 16 16 16 16 16 16 16	17 17 17 17 17 17 17 17 17	18 18 18 18 18 18 18 18 18	19 19 19 19 19 19 19 19 19	20 20 20 20 20 20 20 20 20	21 21 21 21 21 21 21 21 21	22 22 22 22 22 22 22 22 22	23 23
			Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B
		Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C *
		8 8 8 8 8 8 8 8 8
		7 7 7 7 7 7 7 7 7
		6 6 6 6 6 6 6 6 6	(89.1In,178.2In) Operating point at :									NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA
		5 5 5 5 5 5 5 5 5
		4 4 4 4 4 4 4 4 4		TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA
		3 3 3 3 3 3 3 3 3					k2 k2 k2 k2 k2 k2 k2 k2 k2		TRIP takes place as the ZDP operating TRIP takes place as the ZDP operating point is in the TRIP
		2 2 2 2 2 2 2 2 2							point is in the trip area. area on phase C.
										NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero.
		1 1 1 1 1 1 1 1 1	k1 k1 k1 k1 k1 k1 k1 k1 k1
		Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C																							Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C *
		0 0 0 0 0 0 0 0 0	1 1 1 1 1 1 1 1 1	2 2 2 2 2 2 2 2 2	3 3 3 3 3 3 3 3 3	4 4 4 4 4 4 4 4 4	5 5 5 5 5 5 5 5 5	6 6 6 6 6 6 6 6 6	7 7 7 7 7 7 7 7 7	8 8 8 8 8 8 8 8 8	9 9 9 9 9 9 9 9 9	10 10 10 10 10 10 10 10 10	11 11 11 11 11 11 11 11 11	12 12 12 12 12 12 12 12 12	13 13 13 13 13 13 13 13 13	14 14 14 14 14 14 14 14 14	15 15 15 15 15 15 15 15 15	16 16 16 16 16 16 16 16 16	17 17 17 17 17 17 17 17 17	18 18 18 18 18 18 18 18 18	19 19 19 19 19 19 19 19 19	20 20 20 20 20 20 20 20 20	21 21 21 21 21 21 21 21 21	22 22 22 22 22 22 22 22 22	23 23
			Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero.

Operating point at : (38.7In,0.0In) Operating point at : (52.8In,0.0In) Operating point at : (50.2In,0.0In)

	Appendix B7 -Short-circuit simulation -SP1 Appendix B7 -Short-circuit simulation -SP1
	[ Fault at bus 450 in Zone 4 -Fault on phase = ABC -Fault resistance R = 0 ohms ] [ Fault at bus 450 in Zone 4 -Fault on phase = ABC -Fault resistance R = 0 ohms ]
	Zone : 3 Zone : 4
				Phase A Phase A							Phase B Phase B								Phase C Phase C
	internal (Load -gen) internal (Load -gen)	41.75-81.21j 36.09+357.43j					-93.44+18.91j 309.24-165.47j						39.14+50.74j -335.10-161.85j
	BR3 BR4		41.75-81.23j -395.44-2394.89j					-93.42+18.89j -2071.76+1478.49j					39.13+50.74j 2482.55+888.31j
	BR5		-10.43+16.69j							11.94-0.81j							-6.68-11.47j
		Idiff_A/In_A * Idiff_A/In_A *
		8 8
		7 7		Operating point at :								NO TRIP AREA NO TRIP AREA
		6 6		(10.
		5 5
		4 4		TRIP AREA TRIP AREA
		3 3					k2 k2
		2 2							TRIP takes place as the operating point of the ZDP is in the
									NO TRIP takes place as the ZDP differential current is zero. trip area on phase A.
		1 1	k1 k1
		Is1_A Is1_A																							Irestr_A/In_A * Irestr_A/In_A *
		0 0	1 1	2 2	3 3	4 4	5 5	6 6	7 7	8 8	9 9	10 10	11 11	12 12	13 13	14 14	15 15	16 16	17 17	18 18	19 19	20 20	21 21	22 22	23
			Is2_A Is2_A
		Idiff_B/In_B * Idiff_B/In_B *
	* In_x is the rated current of the phase x * In_x is the rated current of the phase x	8 8
	of the current zone. x = A or B or C of the current zone. x = A or B or C
	Idiiff_x is the differential current on the Idiiff_x is the differential current on the	7 7													NO TRIP AREA NO TRIP AREA
	phase x of the current zone. phase x of the current zone.	6 6
	Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone.	5 5
	Is1_x is the differential current pick-up Is1_x is the differential current pick-up	4 4		TRIP AREA TRIP AREA
	setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current.	3 3					k2 k2		TRIP takes place as the operating point of the ZDP is in the
	Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up	2 2							trip area on phase B.
	setting. It is set to 120% of the phase x rated current. setting. It is set to 120% of the phase x rated current.	1 1	k1 k1								NO TRIP takes place as the ZDP differential current is zero.
	k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80%	Is1_B Is1_B																							Irestr_B/In_B * Irestr_B/In_B *
		0 0	1 1	2 2	3 3	4 4	5 5	6 6	7 7	8 8	9 9	10 10	11 11	12 12	13 13	14 14	15 15	16 16	17 17	18 18	19 19	20 20	21 21	22 22	23
			Is2_B Is2_B
		Idiff_C/In_C * Idiff_C/In_C *
		8 8
		7 7
															NO TRIP AREA NO TRIP AREA
		6 6
		5 5
		4 4		TRIP AREA TRIP AREA
		3 3					k2 k2		TRIP takes place as the operating point of the ZDP is in the
		2 2							trip area on phase C.
										NO TRIP takes place as the ZDP differential current is zero.
		1 1	k1 k1
		Is1_C Is1_C																							Irestr_C/In_C * Irestr_C/In_C *
		0 0	1 1	2 2	3 3	4 4	5 5	6 6	7 7	8 8	9 9	10 10	11 11	12 12	13 13	14 14	15 15	16 16	17 17	18 18	19 19	20 20	21 21	22 22	23
			Is2_C Is2_C

7In,21.2In) Operating point at : (11.7In,23.1In) Operating point at : (12.0In,23.9In)

	Appendix B7 -Short-circuit simulation -SP1
	[ Fault at bus 450 in Zone 4 -Fault on phase = ABC -Fault resistance R = 0 ohms ]
	Zone : 5
				Phase A							Phase B								Phase C
	internal (Load -gen)	10.42-16.69j							-11.95+0.82j						6.68+11.47j
	BR5		10.43-16.69j							-11.94+0.81j						6.68+11.47j
		Idiff_A/In_A * Idiff_A/In_A *
		8 8
		7 7													NO TRIP AREA NO TRIP AREA
		6 6
		5 5
		4 4		TRIP AREA TRIP AREA
		3 3					k2		NO TRIP takes place as the ZDP differential current is zero.
		2 2
		1 1	k1
		Is1_A Is1_A																							Irestr_A/In_A * Irestr_A/In_A *
		0 0	1 1	2 2	3 3	4 4	5 5	6 6	7 7	8 8	9 9	10 10	11 11	12 12	13 13	14 14	15 15	16 16	17 17	18 18	19 19	20 20	21 21	22 22	23 23
			Is2_A Is2_A
		Idiff_B/In_B * Idiff_B/In_B *
	* In_x is the rated current of the phase x * In_x is the rated current of the phase x	8 8
	of the current zone. x = A or B or C of the current zone. x = A or B or C
	Idiiff_x is the differential current on the Idiiff_x is the differential current on the	7 7													NO TRIP AREA NO TRIP AREA
	phase x of the current zone. phase x of the current zone.	6 6
	Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone.	5 5
	Is1_x is the differential current pick-up Is1_x is the differential current pick-up	4 4		TRIP AREA
	setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current.	3 3					k2
	Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up	2 2							NO TRIP takes place as the ZDP differential current is zero.
	setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x
	rated current. rated current.	1 1	k1
	k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80%	Is1_B Is1_B																							Irestr_B/In_B * Irestr_B/In_B *
		0 0	1 1	2 2	3 3	4 4	5 5	6 6	7 7	8 8	9 9	10 10	11 11	12 12	13 13	14 14	15 15	16 16	17 17	18 18	19 19	20 20	21 21	22 22	23 23
			Is2_B Is2_B
		Idiff_C/In_C * Idiff_C/In_C *
		8 8
		7 7
															NO TRIP AREA
		6 6
		5 5
		4 4		TRIP AREA
		3 3					k2
									NO TRIP takes place as the ZDP differential current is zero.
		2 2
		1 1	k1
		Is1_C Is1_C																							Irestr_C/In_C * Irestr_C/In_C *
		0 0	1 1	2 2	3 3	4 4	5 5	6 6	7 7	8 8	9 9	10 10	11 11	12 12	13 13	14 14	15 15	16 16	17 17	18 18	19 19	20 20	21 21	22 22	23 23
			Is2_C Is2_C

TRIP takes place on phase B as their is a fault on phase B and the resulting ZDP operating point is in the trip area.

  Fault at bus 251 (newly added bus in Zone 3) -Fault on phase = B -Fault resistance R = ohms ] [ Fault at bus 251 (newly added bus in Zone 3) -Fault on phase = B -Fault resistance R = ohms ] NO TRIP takes place as the ZDP differential current is zero (fault within the zone but not on phase A) [ Fault at bus 251 (newly added bus in Zone 3) -Fault on phase = B -Fault resistance R = ohms ] [ Fault at bus 251 (newly added bus in Zone 3) -Fault on phase = B -Fault resistance R = ohms ] [ Fault at bus 251 (newly added bus in Zone 3) -Fault on phase = B -Fault resistance R = ohms ]

	C5 -OpenDSS netlist of the reference network -SP2 -continued Appendix C6 -Power flow simulation -SP2 -continued Simulation step 1/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 1/24 Simulation step 1/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 1/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 1/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 1/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 2/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 2/24 Simulation step 2/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 2/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 2/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 2/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 3/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 3/24 Simulation step 3/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 3/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 3/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 3/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 4/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 4/24 Simulation step 4/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 4/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 4/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 4/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 5/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 5/24 Simulation step 5/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 5/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 5/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 5/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 6/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 6/24 Simulation step 6/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 6/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 6/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 6/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 7/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 7/24 Simulation step 7/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 7/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 7/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 7/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 8/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 8/24 Simulation step 8/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 8/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 8/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 8/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 9/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 9/24 Simulation step 9/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 9/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 9/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 9/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 10/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 10/24 Simulation step 10/24 Appendix C6 -Power flow simulation -SP2 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 10/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 10/24 Appendix C6 -Power flow simulation -SP2 -continued Simulation step 10/24 [ Appendix C7 -Short-circuit simulation -SP2 Appendix C7 -Short-circuit simulation -SP2 Appendix C7 -Short-circuit simulation -SP2 Appendix C7 -Short-circuit simulation -SP2 Appendix C7 -Short-circuit simulation -SP2 Appendix C7 -Short-circuit simulation -SP2
	Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6 Zone : 1 Zone : 2 Zone : 3 Zone : 4 Zone : 5 Zone : 6
	!BUS											Note : new buses generated from the network model in SP2 are highlighted in red	925 2325
	COORDINATES DEFINITION			Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A Phase A							Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B Phase B								Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C Phase C	4500 1375 4700 425
	25r 1500 3150 68 3725 1850 77 3925 1375 23 1500 2875 92 2550 825 73 3800 1575 108 3525 3050 93 2325 1125 80 4025 900 76 3525 1375 62 3075 2100 74 4150 1575 27 875 3150 44 1975 3025 57 2325 1850 4 700 1050 96 2025 925 61s 3175 1300 40 1975 2575 41 2300 2575 67 3525 1850 160r 3175 1850 42 1975 2825 185 4362 900 5 1025 1250 9 1200 1725 internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) internal (Load -gen) Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. setting. It is set to 10% of the phase x rated current. Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Is1_x is the differential current pick-up Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. phase x of the current zone. Irestr_x is the restraining current on the phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. phase x of the current zone. of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the of the current zone. x = A or B or C Idiiff_x is the differential current on the * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x * In_x is the rated current of the phase x Is1_A Idiff_B/In_B * 25.18-72.13j 37.26-74.22j 52.40-97.81j 33.02-92.21j 26.39-45.53j 0.00+0.00j 25.38-69.20j 39.19-79.67j 52.46-97.38j 35.86-92.19j 26.48-45.81j 0.00+0.00j 24.84-68.78j 36.18-77.13j 50.89-94.35j 37.06-97.25j 25.27-43.64j 0.00+0.00j 28.77-71.49j 36.31-76.01j 52.08-95.51j 44.84-94.44j 27.70-48.18j 0.00+0.00j 29.88-74.57j 38.37-80.00j 52.56-97.14j 40.41-91.37j 26.07-45.30j 0.00+0.00j 29.84-74.93j 40.01-79.18j 48.62-90.02j 37.73-89.01j 27.06-46.80j 0.00+0.00j 30.20-75.78j 35.19-76.12j 53.38-101.44j 43.05-95.65j 26.99-47.02j 0.00+0.00j 28.48-74.67j 40.33-82.76j 52.70-95.05j 37.24-94.35j 27.46-47.88j 0.00+0.00j 24.19-68.94j 39.40-79.82j 53.61-99.31j 35.68-88.46j 25.58-44.26j 0.00+0.00j 24.00-68.14j 36.57-78.53j 50.20-90.79j 37.20-97.96j 27.09-46.94j 0.00+0.00j 42.35-83.53j 42.22-92.71j 62.88-119.82j 117.46-31.45j 30.88-57.15j 0.00+0.00j 26 1150 3150 78 4025 1375 47 1975 3275 51 2725 3275 55 2600 1500 65 2650 2625 83 4275 175 88 2950 1300 60 3075 1850 19 1250 2325 160 3175 1850 112 4275 2925 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 k2 3 k2 3 k2 3 k2 3 k2 4 TRIP AREA 4 TRIP AREA 4 TRIP AREA 4 TRIP AREA 4 TRIP AREA 33 875 3650 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 113 4800 2925 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 3 700 1250 Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * Idiff_B/In_B * 49 2225 3275 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A 0 1 2 3 4 5 6 7 Is2_A Extract (10 first simulation steps over 24) 25 1500 3150 14.83+15.24j -63.88+0.42j -108.91+12.20j -92.26+19.45j -32.36-0.81j 0.00+0.00j 8.57+13.78j -63.02-0.01j -108.65+12.38j -97.08+19.51j -34.40-0.82j 0.00+0.00j 11.09+13.28j -66.08-0.32j -111.12+12.62j -95.55+16.07j -32.36-0.75j 0.00+0.00j 4.21+14.06j -68.37-0.83j -107.43+12.57j -105.57+23.40j -35.17-0.72j 0.00+0.00j 6.83+15.12j -64.48-0.73j -111.23+12.73j -99.56+21.96j -31.90-0.72j 0.00+0.00j 5.45+13.68j -72.78-1.17j -103.86+11.97j -104.80+17.07j -33.72-0.66j 0.00+0.00j 7.25+15.64j -65.92-0.50j -109.94+12.50j -104.80+20.80j -27.69-0.64j 0.00+0.00j 11.02+15.06j -62.84-0.11j -115.94+13.66j -94.66+19.42j -32.82-0.80j 0.00+0.00j 16.58+16.40j -66.28+0.26j -113.22+12.52j -91.89+19.27j -29.82-0.75j 0.00+0.00j 13.29+14.81j -58.63-0.25j -114.11+13.00j -96.33+20.52j -30.64-0.79j 0.00+0.00j 13.47+22.25j -79.85+1.22j -135.35+18.67j -77.36-68.45j -38.70+0.04j 0.00+0.00j 38 2325 2000 61 3075 1300 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place as the ZDP differential current is zero (fault outside the zone) 109 3975 3050 86 3255 725 24 950 2875 6 1275 1150 NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA 97 3525 2100 30 1850 3650 106 3750 2725 16 1500 875 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 8 9 10 11 12 13 14 15 16 17 Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A Is1_A 58 2075 1850 7 1000 1500 28 1500 3350 29 1500 3650 105 3525 2725 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 1 k1 Power flow simulation results in SP2-2 the ZDP differential current is zero. 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 3 4 TRIP AREA k2 zero (fault outside the zone) 3 k2 3 k2 3 k2 3 k2 3 k2 NO TRIP takes place as the ZDP differential current is 4 TRIP AREA 4 TRIP AREA 4 TRIP AREA 4 TRIP AREA 4 TRIP AREA 45 2175 3025 31 1150 3375 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 48 1825 3275 66 2650 2300 6 ZDP operating characteristic 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 14 1200 2150 43 2475 2825 95 2025 1125 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 NO TRIP AREA 7 99 4350 2100 10 1450 2150 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 69 4000 1850 100 4650 2100 Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * Idiff_A/In_A * 35 1975 2325 79 4250 1375 103 4075 2450 64 3075 2625 BR3 -52.42+97.83j 108.92-12.17j BR6 -0.00-0.00j -0.00-0.00j BR3 -52.48+97.38j 108.66-12.34j BR6 -0.00-0.00j -0.00-0.00j BR3 -50.92+94.36j 111.13-12.59j BR6 -0.00-0.00j -0.00-0.00j BR3 -52.10+95.51j 107.42-12.53j BR6 -0.00-0.00j -0.00-0.00j BR3 -52.59+97.16j 111.22-12.69j BR6 -0.00-0.00j -0.00-0.00j BR3 -48.65+90.03j 103.87-11.93j BR6 -0.00-0.00j -0.00-0.00j BR3 -53.41+101.45j 109.95-12.46j BR6 -0.00-0.00j -0.00-0.00j BR3 -52.72+95.08j 115.94-13.63j BR6 -0.00-0.00j -0.00-0.00j BR3 -53.63+99.32j 113.22-12.48j BR6 -0.00-0.00j -0.00-0.00j BR3 -50.22+90.80j 114.12-12.97j BR6 -0.00-0.00j -0.00-0.00j BR3 -62.89+119.84j 176.54+1.88j BR6 -0.00-0.00j -0.00-0.00j 610 3275 1300 63 3075 2275 150r 100 1500 BR2 -96.76+211.99j 188.47-18.92j BR4 -59.47+137.77j 124.60-18.57j BR4 59.47-137.77j -124.60+18.57j BR2 -101.64+217.70j 194.45-18.54j BR4 -62.41+138.04j 131.45-18.62j BR4 62.41-138.04j -131.45+18.62j BR2 -98.60+218.05j 193.96-14.88j BR4 -62.37+140.93j 127.88-15.26j BR4 62.37-140.93j -127.88+15.26j BR2 -108.94+218.62j 209.06-21.70j BR4 -72.60+142.64j 140.71-22.59j BR4 72.60-142.64j -140.71+22.59j BR2 -104.95+216.69j 195.90-20.34j BR4 -66.54+136.71j 131.44-21.15j BR4 66.54-136.71j -131.44+21.15j BR2 -104.92+215.01j 211.25-15.09j BR4 -64.85+135.85j 138.49-16.33j BR4 64.85-135.85j -138.49+16.33j BR2 -105.30+218.81j 198.38-19.52j BR4 -70.09+142.70j 132.47-20.08j BR4 70.09-142.70j -132.47+20.08j BR2 -105.13+224.99j 190.28-18.38j BR4 -64.75+142.25j 127.45-18.56j BR4 64.75-142.25j -127.45+18.56j BR2 -100.76+212.55j 187.97-18.63j BR4 -61.31+132.75j 121.70-18.45j BR4 61.31-132.75j -121.70+18.45j BR2 -100.97+223.46j 185.57-19.33j BR4 -64.35+144.94j 126.95-19.66j BR4 64.35-144.94j -126.95+19.66j BR2 -190.58+181.35j 195.80+67.33j BR4 -148.34+88.65j 115.99+68.47j BR4 148.34-88.65j -115.99-68.47j 150 100 1500 36 2075 2000 BR1 174.40-381.96j -282.58+46.30j BR2 96.76-211.99j -188.47+18.92j BR3 52.42-97.83j -108.92+12.17j BR5 -26.41+45.54j 32.36+0.82j BR5 26.41-45.54j -32.36-0.82j BR6 0.00+0.00j 0.00+0.00j BR1 179.52-384.30j -294.55+44.62j BR2 101.64-217.70j -194.45+18.54j BR3 52.48-97.38j -108.66+12.34j BR5 -26.49+45.83j 34.39+0.84j BR5 26.49-45.83j -34.39-0.84j BR6 0.00+0.00j 0.00+0.00j BR1 174.38-381.22j -294.02+40.72j BR2 98.60-218.05j -193.96+14.88j BR3 50.92-94.36j -111.13+12.59j BR5 -25.29+43.65j 32.36+0.76j BR5 25.29-43.65j -32.36-0.76j BR6 0.00+0.00j 0.00+0.00j BR1 189.82-385.62j -312.28+48.25j BR2 108.94-218.62j -209.06+21.70j BR3 52.10-95.51j -107.42+12.53j BR5 -27.71+48.19j 35.16+0.74j BR5 27.71-48.19j -35.16-0.74j BR6 0.00+0.00j 0.00+0.00j BR1 187.46-388.43j -300.32+48.12j BR2 104.95-216.69j -195.90+20.34j BR3 52.59-97.16j -111.22+12.69j BR5 -26.09+45.32j +31.90+0.74j BR5 26.09-45.32j -31.90-0.74j BR6 0.00+0.00j 0.00+0.00j BR1 183.42-379.98j -309.68+40.65j BR2 104.92-215.01j -211.25+15.09j BR3 48.65-90.03j -103.87+11.93j BR5 -27.08+46.82j 33.72+0.68j BR5 27.08-46.82j -33.72-0.68j BR6 0.00+0.00j 0.00+0.00j BR1 188.93-396.07j -301.09+47.58j BR2 105.30-218.81j -198.38+19.52j BR3 53.41-101.45j -109.95+12.46j BR5 -26.99+47.04j 27.69+0.65j BR5 26.99-47.04j -27.69-0.65j BR6 0.00+0.00j 0.00+0.00j BR1 186.35-394.74j -295.21+47.05j BR2 105.13-224.99j -190.28+18.38j BR3 52.72-95.08j -115.94+13.63j BR5 -27.48+47.89j 32.81+0.81j BR5 27.48-47.89j -32.81-0.81j BR6 0.00+0.00j 0.00+0.00j BR1 178.63-380.82j -284.63+47.49j BR2 100.76-212.55j -187.97+18.63j BR3 53.63-99.32j -113.22+12.48j BR5 -25.60+44.27j 29.81+0.76j BR5 25.60-44.27j -29.81-0.76j BR6 0.00+0.00j 0.00+0.00j BR1 175.21-382.42j -286.42+47.08j BR2 100.97-223.46j -185.57+19.33j BR3 50.22-90.80j -114.12+12.97j BR5 -27.11+46.95j 30.63+0.81j BR5 27.11-46.95j -30.63-0.81j BR6 0.00+0.00j 0.00+0.00j BR1 295.82-384.75j -358.88-47.01j BR2 190.58-181.35j -195.80-67.33j BR3 62.89-119.84j -176.54-1.88j BR5 -30.88+57.18j 38.69-0.02j BR5 30.88-57.18j -38.69+0.02j BR6 0.00+0.00j 0.00+0.00j	18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18	19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19	59 1825 1850 40.55+77.35j 29.86+55.90j 47.22+70.14j 50.62+74.18j 18.39+32.67j 0.00+0.00j 36.13+69.66j 32.98+61.27j 44.03+65.14j 52.11+76.60j 21.00+37.13j 0.00+0.00j 36.88+70.22j 29.80+57.58j 45.65+67.70j 56.46+82.36j 19.81+35.04j 0.00+0.00j 38.17+74.90j 30.57+57.18j 44.91+66.54j 52.50+74.07j 19.02+33.82j 0.00+0.00j 40.37+80.64j 30.31+56.29j 45.67+67.64j 48.33+71.07j 18.76+33.38j 0.00+0.00j 39.59+76.84j 32.49+58.48j 43.95+65.80j 56.66+77.94j 19.53+34.59j 0.00+0.00j 37.69+77.34j 29.51+57.08j 48.43+70.27j 52.95+76.22j 19.20+34.07j 0.00+0.00j 40.73+80.40j 26.21+49.01j 43.56+64.50j 52.66+78.56j 23.81+42.20j 0.00+0.00j 36.59+71.41j 31.90+61.18j 45.61+67.18j 49.60+67.02j 18.21+32.53j 0.00+0.00j 38.65+72.92j 31.13+60.49j 41.66+61.91j 53.19+78.84j 19.90+35.27j 0.00+0.00j 50.95+88.94j 39.21+70.05j 56.32+80.84j -40.97+106.21j 24.84+41.92j 0.00+0.00j 2 700 1675 151 3187 3928 12 1200 1275 53 2200 1500 11 950 2150 39 2650 2000 82 4025 175 87 3050 1125 102 3750 2450 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 20 21 22 23 20 21 22 23 20 21 22 23 20 21 22 23 20 21 22 23 20 21 22 23 Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * Irestr_A/In_A * 72 3525 1575 70 4325 1850 13 1500 1500 104 4775 2450 111 4275 3625 107 4325 2725 32 1150 3675 98 3800 2100 46 2475 3025 152 1600 1500 197 3525 2200 9r 1200 1725 -47.21-70.14j -0.00-0.00j -44.01-65.14j -0.00-0.00j -45.63-67.70j -0.00-0.00j -44.90-66.54j -0.00-0.00j -45.66-67.65j -0.00-0.00j -43.95-65.79j -0.00-0.00j -48.42-70.26j -0.00-0.00j -43.56-64.49j -0.00-0.00j -45.61-67.19j -0.00-0.00j -41.65-61.91j -0.00-0.00j -56.31-80.85j -0.00-0.00j 94 2325 850 21 1500 2625 -98.79-162.76j -68.97-106.85j 68.97+106.85j -106.01-174.98j -73.08-113.71j 73.08+113.71j -106.00-174.99j -76.25-117.40j 76.25+117.40j -102.01-165.07j -71.49-107.89j 71.49+107.89j -97.33-160.75j -67.07-104.46j 67.07+104.46j -108.62-171.03j -76.17-112.55j 76.17+112.55j -101.57-167.37j -72.11-110.29j 72.11+110.29j -102.63-169.75j -76.47-120.75j 76.47+120.75j -99.62-160.72j -67.78-99.54j 67.78+99.54j -104.14-174.59j -73.05-114.10j 73.05+114.10j -22.98-218.20j 16.18-148.14j -16.18+148.14j 17 1850 1250 18 1500 2325 186.55+310.24j 98.79+162.76j 47.21+70.14j -18.38-32.67j 18.38+32.67j 0.00+0.00j 186.13+309.79j 106.01+174.98j 44.01+65.14j -20.99-37.13j 20.99+37.13j 0.00+0.00j 188.52+312.91j 106.00+174.99j 45.63+67.70j -19.80-35.04j 19.80+35.04j 0.00+0.00j 185.07+306.52j 102.01+165.07j 44.90+66.54j -19.02-33.82j 19.02+33.82j 0.00+0.00j 183.34+309.05j 97.33+160.75j 45.66+67.65j -18.76-33.38j 18.76+33.38j 0.00+0.00j 192.14+313.66j 108.62+171.03j 43.95+65.79j -19.53-34.60j 19.53+34.60j 0.00+0.00j 187.67+314.96j 101.57+167.37j 48.42+70.26j -19.19-34.06j 19.19+34.06j 0.00+0.00j 186.89+314.65j 102.63+169.75j 43.56+64.49j -23.81-42.19j 23.81+42.19j 0.00+0.00j 181.82+299.34j 99.62+160.72j 45.61+67.19j -18.20-32.53j 18.20+32.53j 0.00+0.00j 184.43+309.42j 104.14+174.59j 41.65+61.91j -19.89-35.27j 19.89+35.27j 0.00+0.00j 130.23+387.96j 22.98+218.20j 56.31+80.85j -24.83-41.93j 24.83+41.93j 0.00+0.00j	2000 1500 2475 3275 3245 4010 2050 3650 2775 900 4550 1575 2325 1500 4275 3050 1600 2325 2875 1500 5125 2925 4025 425 2956 3928 1775 2000 4600 1850 3525 2450 1500 1350 975 2625 1400 2450 1500 1250 2775 1125 300 1500 1200 1500 700 1500 5450 2100 2550 1125 4700 900
	Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up Is2_x is the restraining current pick-up	2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2
	setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x setting. It is set to 120% of the phase x
	rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current. rated current.	1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1	k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1
	k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80% k1, k2 : slopes -k1=30% & k2=80%	Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B Is1_B																							Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B * Irestr_B/In_B *
		0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0	1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1	2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2	3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3	4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4	5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5	6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6	7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7	8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8	9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9	10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10	11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11	12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12	13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13	14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14	15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15	16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16	17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17	18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18	19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19	20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20	21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21	22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22	23 23 23 23 23 23
			Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B Is2_B
		Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C * Idiff_C/In_C *
		8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8
		7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7
														NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA NO TRIP AREA
		6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6
		5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5								NO TRIP takes place as the ZDP differential current is zero (fault outside the zone)
		4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4		TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA TRIP AREA					NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as NO TRIP takes place on normal operating conditions as
		3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3					k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2 k2			the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero. the ZDP differential current is zero.
		2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2
		1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1	k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1 k1
		Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C Is1_C																							Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C * Irestr_C/In_C *
		0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0	1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1	2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2	3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3	4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4	5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5	6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6	7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7	8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8	9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9	10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10	11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11	12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12 12	13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13	14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14 14	15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15 15	16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16 16	17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17 17	18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18 18	19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19 19	20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20	21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21 21	22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22	23 23 23 23 23 23
			Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C Is2_C

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero. NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place on normal operating conditions as the ZDP differential current is zero.

NO TRIP takes place as the ZDP differential current is zero (fault outside the zone)

NO TRIP takes place as the ZDP differential current is zero (fault outside the zone) NO TRIP takes place as the ZDP differential current is zero (fault outside the zone)

NO TRIP takes place as the ZDP differential current is zero (fault within the zone but not on phase A) NO TRIP takes place as the ZDP differential current is zero (fault outside the zone) NO TRIP takes place as the ZDP differential current is zero (fault outside the zone) NO TRIP takes place as the ZDP differential current is zero (fault outside the zone) NO TRIP takes place as the ZDP differential current is zero (fault outside the zone)

NO TRIP takes place as the ZDP differential current is zero (fault outside the zone) NO TRIP takes place as the ZDP differential current is zero (fault outside the zone) NO TRIP takes place as the ZDP differential current is zero (fault outside the zone) NO TRIP takes place as the ZDP differential current is zero (fault outside the zone) NO TRIP takes place as the ZDP differential current is zero (fault outside the zone)

Note : new lines generated from the network model in SP2 are highlighted in red

Note : new loads generated from the network model in SP2 are highlighted in red

Acknowledgements

This PhD work is the fruit of collaboration between the Grenoble Electrical Engineering Laboratory (G2ELab) and my employer Schneider Electric. It was a good opportunity for me to work on a personal initiative consisting in investigating a new mindset for improving the distribution feeder automation functions through the harmonization between the CIM data model and IEC 61850 data model. Over these years of research, I have had the opportunity to meet many people both at Schneider !LOADSHAPES DEFINITION New LoadShape.loadcurve_s92c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s92c.txt action=normalize New LoadShape.loadcurve_s76c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s76c.txt action=normalize New LoadShape.loadcurve_s4c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s4c.txt action=normalize New LoadShape.loadcurve_s42a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s42a.txt action=normalize New LoadShape.loadcurve_s9a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s9a.txt action=normalize New LoadShape.loadcurve_s103c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s103c.txt action=normalize New LoadShape.loadcurve_s35a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s35a.txt action=normalize New LoadShape.loadcurve_s45a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s45a.txt action=normalize New LoadShape.loadcurve_s51a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s51a.txt action=normalize New LoadShape.loadcurve_s55a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s55a.txt action=normalize New LoadShape.loadcurve_s65b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s65b.txt action=normalize New LoadShape.loadcurve_s58b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s58b.txt action=normalize New LoadShape.loadcurve_s83c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s83c.txt action=normalize New LoadShape.loadcurve_s77b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s77b.txt action=normalize New LoadShape.loadcurve_s49c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s49c.txt action=normalize New LoadShape.loadcurve_s5c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s5c.txt action=normalize New LoadShape.loadcurve_s60a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s60a.txt action=normalize New LoadShape.loadcurve_s33a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s33a.txt action=normalize New LoadShape.loadcurve_s96b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s96b.txt action=normalize New LoadShape.loadcurve_s99b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s99b.txt action=normalize New LoadShape.loadcurve_s10a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s10a.txt action=normalize New LoadShape.loadcurve_s43b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s43b.txt action=normalize New LoadShape.loadcurve_s95b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s95b.txt action=normalize New LoadShape.loadcurve_s68a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s68a.txt action=normalize New LoadShape.loadcurve_s106b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s106b.txt action=normalize New LoadShape.loadcurve_s30c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s30c.txt action=normalize New LoadShape.loadcurve_s24c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s24c.txt action=normalize New LoadShape.loadcurve_s38b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s38b.txt action=normalize C5-6-Loads The loads are defined in a file called : Test_Loads.DSS. As already explained, the load models have been changed to 'Constant power' to be able to run a time series power flow. The content is given below: Appendix C5 -OpenDSS netlist of the reference network -SP2 -continued C5-6-Loads -continued Appendix C5 -OpenDSS netlist of the reference network -SP2 -continued New LoadShape.loadcurve_s17c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s17c.txt action=normalize New LoadShape.loadcurve_s94a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s94a.txt action=normalize New LoadShape.loadcurve_s46a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s46a.txt action=normalize New LoadShape.loadcurve_s65c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s65c.txt action=normalize New LoadShape.loadcurve_s107b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s107b.txt action=normalize New LoadShape.loadcurve_s111a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s111a.txt action=normalize New LoadShape.loadcurve_s70a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s70a.txt action=normalize New LoadShape.loadcurve_s104c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s104c.txt action=normalize New LoadShape.loadcurve_s86b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s86b.txt action=normalize New LoadShape.loadcurve_s39b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s39b.txt action=normalize New LoadShape.loadcurve_s12b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s12b.txt action=normalize New LoadShape.loadcurve_s49a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s49a.txt action=normalize New LoadShape.loadcurve_s62c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s62c.txt action=normalize New LoadShape.loadcurve_s20a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s20a.txt action=normalize New LoadShape.loadcurve_s28a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s28a.txt action=normalize New LoadShape.loadcurve_s113a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s113a.txt action=normalize New LoadShape.loadcurve_s6c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s6c.txt action=normalize New LoadShape.loadcurve_s29a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s29a.txt action=normalize New LoadShape.loadcurve_s32c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s32c.txt action=normalize New LoadShape.loadcurve_s11a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s11a.txt action=normalize New LoadShape.loadcurve_s41c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s41c.txt action=normalize New LoadShape.loadcurve_s71a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s71a.txt action=normalize New LoadShape.loadcurve_s59b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s59b.txt action=normalize New LoadShape.loadcurve_s79a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s79a.txt action=normalize New LoadShape.loadcurve_s31c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s31c.txt action=normalize New LoadShape.loadcurve_s69a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s69a.txt action=normalize New LoadShape.loadcurve_s74c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s74c.txt action=normalize New LoadShape.loadcurve_s114a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s114a.txt action=normalize New LoadShape.loadcurve_s112a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s112a.txt action=normalize New LoadShape.loadcurve_s73c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s73c.txt action=normalize New LoadShape.loadcurve_s65a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s65a.txt action=normalize New LoadShape.loadcurve_s50c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s50c.txt action=normalize New LoadShape.loadcurve_s66c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s66c.txt action=normalize New LoadShape.loadcurve_s56b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s56b.txt action=normalize New LoadShape.loadcurve_s84c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s84c.txt action=normalize New LoadShape.loadcurve_s90b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s90b.txt action=normalize New LoadShape.loadcurve_s2b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s2b.txt action=normalize New LoadShape.loadcurve_s34c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s34c.txt action=normalize New LoadShape.loadcurve_s251c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s251c.txt action=normalize New LoadShape.loadcurve_s49b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s49b.txt action=normalize New LoadShape.loadcurve_s7a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s7a.txt action=normalize New LoadShape.loadcurve_s48 npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s48.txt action=normalize New LoadShape.loadcurve_s16c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s16c.txt action=normalize New LoadShape.loadcurve_s185b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s185b.txt action=normalize New LoadShape.loadcurve_s22b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s22b.txt action=normalize New LoadShape.loadcurve_s1a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s1a.txt action=normalize New LoadShape.loadcurve_s88a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s88a.txt action=normalize New LoadShape.loadcurve_s82a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s82a.txt action=normalize New LoadShape.loadcurve_s53a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s53a.txt action=normalize New LoadShape.loadcurve_s98a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s98a.txt action=normalize New LoadShape.loadcurve_s87b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s87b.txt action=normalize New LoadShape.loadcurve_s52a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s52a.txt action=normalize New LoadShape.loadcurve_s63a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s63a.txt action=normalize New LoadShape.loadcurve_s19a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s19a.txt action=normalize New LoadShape.loadcurve_s47 npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s47.txt action=normalize New LoadShape.loadcurve_s76b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s76b.txt action=normalize New LoadShape.loadcurve_s85c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s85c.txt action=normalize New LoadShape.loadcurve_s100c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s100c.txt action=normalize New LoadShape.loadcurve_s109a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s109a.txt action=normalize New LoadShape.loadcurve_s102c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s102c.txt action=normalize New LoadShape.loadcurve_s64b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s64b.txt action=normalize New LoadShape.loadcurve_s76a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s76a.txt action=normalize New LoadShape.loadcurve_s37a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s37a.txt action=normalize New LoadShape.loadcurve_s80b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s80b.txt action=normalize New LoadShape.loadcurve_s75c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s75c.txt action=normalize C5-6-Loads -continued

B5-5-Breakers/Reclosers

The breakers/reclosers are defined in a file called : Test_Breakers.DSS. The content is given below: !BREAKER DEFINITION !NORMALLY CLOSED SWITCHES ARE DEFINED AS SHORT LINES New Line.BR4 phases=3 Bus1=60.1.2.3 Bus2=160.1.2.3 r1=0.001 r0=0.001 x1=0.0 x0=0.0 c1=0.0 c0=0.0 Length=0.001 Switch=yes New Line.BR2 phases=3 Bus1=13.1.2.3 Bus2=152.1.2.3 r1=0.001 r0=0.001 x1=0.0 x0=0.0 c1=0.0 c0=0.0 Length=0.001 Switch=yes New Line.BR6 phases=3 Bus1=61.1.2.3 Bus2=61s.1.2.3 r1=0.001 r0=0.001 x1=0.0 x0=0.0 c1=0.0 c0=0.0 Length=0.001 Switch=yes New Line.BR3 phases=3 Bus1=18.1.2.3 Bus2=135.1.2.3 r1=0.001 r0=0.001 x1=0.0 x0=0.0 c1=0.0 c0=0.0 Length=0.001 Switch=yes New Line.BR5 phases=3 Bus1=97.1.2.3 Bus2=197.1.2.3 r1=0.001 r0=0.001 x1=0.0 x0=0.0 c1=0.0 c0=0.0 Length=0.001 Switch=yes New Line.BR1 phases=3 Bus1=150r.1.2.3 Bus2=149.1.2.3 r1=0.001 r0=0.001 x1=0.0 x0=0.0 c1=0.0 c0=0.0 Length=0.001 Switch=yes Appendix B5 -OpenDSS netlist of the reference network -SP1 -continued

B5-6-Loads

The loads are defined in a file called : Test_Loads.DSS. As already explained, the load models have been changed to 'Constant power' to be able to run a time series power flow. The content is given below:

LOADSHAPES DEFINITION New LoadShape.loadcurve_s99b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s99b.txt action=normalize New LoadShape.loadcurve_s20a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s20a.txt action=normalize New LoadShape.loadcurve_s5c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s5c.txt action=normalize New LoadShape.loadcurve_s24c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s24c.txt action=normalize New LoadShape.loadcurve_s37a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s37a.txt action=normalize New LoadShape.loadcurve_s102c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s102c.txt action=normalize New LoadShape.loadcurve_s83c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s83c.txt action=normalize New LoadShape.loadcurve_s85c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s85c.txt action=normalize New LoadShape.loadcurve_s62c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s62c.txt action=normalize New LoadShape.loadcurve_s88a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s88a.txt action=normalize New LoadShape.loadcurve_s52a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s52a.txt action=normalize New LoadShape.loadcurve_s84c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s84c.txt action=normalize New LoadShape.loadcurve_s65b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s65b.txt action=normalize New LoadShape.loadcurve_s79a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s79a.txt action=normalize New LoadShape.loadcurve_s7a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s7a.txt action=normalize New LoadShape.loadcurve_s12b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s12b.txt action=normalize New LoadShape.loadcurve_s76a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s76a.txt action=normalize New LoadShape.loadcurve_s63a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s63a.txt action=normalize New LoadShape.loadcurve_s29a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s29a.txt action=normalize New LoadShape.loadcurve_s74c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s74c.txt action=normalize New LoadShape.loadcurve_s92c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s92c.txt action=normalize New LoadShape.loadcurve_s49b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s49b.txt action=normalize New LoadShape.loadcurve_s112a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s112a.txt action=normalize New LoadShape.loadcurve_s46a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s46a.txt action=normalize New LoadShape.loadcurve_s50c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s50c.txt action=normalize New LoadShape.loadcurve_s1a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s1a.txt action=normalize New LoadShape.loadcurve_s6c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s6c.txt action=normalize New LoadShape.loadcurve_s75c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s75c.txt action=normalize Appendix B5 -OpenDSS netlist of the reference network -SP1 -continued New LoadShape.loadcurve_s104c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s104c.txt action=normalize New LoadShape.loadcurve_s76b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s76b.txt action=normalize New LoadShape.loadcurve_s22b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s22b.txt action=normalize New LoadShape.loadcurve_s96b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s96b.txt action=normalize New LoadShape.loadcurve_s103c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s103c.txt action=normalize New LoadShape.loadcurve_s113a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s113a.txt action=normalize New LoadShape.loadcurve_s43b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s43b.txt action=normalize New LoadShape.loadcurve_s82a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s82a.txt action=normalize New LoadShape.loadcurve_s90b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s90b.txt action=normalize New LoadShape.loadcurve_s80b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s80b.txt action=normalize New LoadShape.loadcurve_s11a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s11a.txt action=normalize New LoadShape.loadcurve_s55a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s55a.txt action=normalize New LoadShape.loadcurve_s111a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s111a.txt action=normalize New LoadShape.loadcurve_s49c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s49c.txt action=normalize New LoadShape.loadcurve_s109a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s109a.txt action=normalize New LoadShape.loadcurve_s65c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s65c.txt action=normalize New LoadShape.loadcurve_s70a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s70a.txt action=normalize New LoadShape.loadcurve_s87b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s87b.txt action=normalize New LoadShape.loadcurve_s59b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s59b.txt action=normalize New LoadShape.loadcurve_s98a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s98a.txt action=normalize New LoadShape.loadcurve_s86b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s86b.txt action=normalize New LoadShape.loadcurve_s66c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s66c.txt action=normalize New LoadShape.loadcurve_s38b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s38b.txt action=normalize New LoadShape.loadcurve_s48 npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s48.txt action=normalize New LoadShape.loadcurve_s51a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s51a.txt action=normalize New LoadShape.loadcurve_s19a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s19a.txt action=normalize New LoadShape.loadcurve_s53a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s53a.txt action=normalize New LoadShape.loadcurve_s64b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s64b.txt action=normalize New LoadShape.loadcurve_s9a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s9a.txt action=normalize New LoadShape.loadcurve_s73c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s73c.txt action=normalize New LoadShape.loadcurve_s77b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s77b.txt action=normalize New LoadShape.loadcurve_s4c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s4c.txt action=normalize B5-6-Loads -continued Appendix B5 -OpenDSS netlist of the reference network -SP1 -continued B5-6-Loads -continued New LoadShape.loadcurve_s35a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s35a.txt action=normalize New LoadShape.loadcurve_s100c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s100c.txt action=normalize New LoadShape.loadcurve_s33a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s33a.txt action=normalize New LoadShape.loadcurve_s69a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s69a.txt action=normalize New LoadShape.loadcurve_s28a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s28a.txt action=normalize New LoadShape.loadcurve_s71a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s71a.txt action=normalize New LoadShape.loadcurve_s30c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s30c.txt action=normalize New LoadShape.loadcurve_s10a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s10a.txt action=normalize New LoadShape.loadcurve_s31c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s31c.txt action=normalize New LoadShape.loadcurve_s65a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s65a.txt action=normalize New LoadShape.loadcurve_s49a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s49a.txt action=normalize New LoadShape.loadcurve_s58b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s58b.txt action=normalize New LoadShape.loadcurve_s45a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s45a.txt action=normalize New LoadShape.loadcurve_s56b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s56b.txt action=normalize New LoadShape.loadcurve_s47 npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s47.txt action=normalize New LoadShape.loadcurve_s114a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s114a.txt action=normalize New LoadShape.loadcurve_s32c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s32c.txt action=normalize New LoadShape.loadcurve_s42a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s42a.txt action=normalize New LoadShape.loadcurve_s76c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s76c.txt action=normalize New LoadShape.loadcurve_s41c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s41c.txt action=normalize New LoadShape.loadcurve_s16c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s16c.txt action=normalize New LoadShape.loadcurve_s2b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s2b.txt action=normalize New LoadShape.loadcurve_s107b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s107b.txt action=normalize New LoadShape.loadcurve_s60a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s60a.txt action=normalize New LoadShape.loadcurve_s106b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s106b.txt action=normalize New LoadShape.loadcurve_s39b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s39b.txt action=normalize New LoadShape.loadcurve_s95b npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s95b.txt action=normalize New LoadShape.loadcurve_s34c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s34c.txt action=normalize New LoadShape.loadcurve_s68a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s68a.txt action=normalize New LoadShape.loadcurve_s17c npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s17c.txt action=normalize New LoadShape.loadcurve_s94a npts=24 interval=1 csvfile=C:/Users/SESA160732/Documents/test/loadcurve_s94a.txt action=normalize

Appendix B5 -OpenDSS netlist of the reference network -SP1 -continued B5-6-Loads -continued !LOAD DEFINITION New Load.s99b Bus1=99.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s99b status=variable New Load.s20a Bus1=20.1 Phases=1 Conn=Wye Model=5 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s20a status=variable New Load.s5c Bus1=5.3 Phases=1 Conn=Wye Model=5 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s5c status=variable New Load.s24c Bus1=24.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s24c status=variable New Load.s37a Bus1=37.1 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s37a status=variable New Load.s102c Bus1=102.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s102c status=variable New Load.s83c Bus1=83.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s83c status=variable New Load.s85c Bus1=85.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s85c status=variable New Load.s62c Bus1=62.3 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s62c status=variable New Load.s88a Bus1=88.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s88a status=variable New Load.s52a Bus1=52.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s52a status=variable New Load.s84c Bus1=84.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s84c status=variable New Load.s65b Bus1=65.2.3 Phases=1 Conn=Delta Model=2 kV=4.16 kW=35.0 kvar=25.0 daily=loadcurve_s65b status=variable New Load.s79a Bus1=79.1 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s79a status=variable New Load.s7a Bus1=7.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s7a status=variable New Load.s12b Bus1=12.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s12b status=variable New Load.s76a Bus1=76.1.2 Phases=1 Conn=Delta Model=5 kV=4.16 kW=105.0 kvar=80.0 daily=loadcurve_s76a status=variable New Load.s63a Bus1=63.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s63a status=variable New Load.s29a Bus1=29.1 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s29a status=variable New Load.s74c Bus1=74.3 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s74c status=variable New Load.s92c Bus1=92.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s92c status=variable New Load.s49b Bus1=49.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=70.0 kvar=50.0 daily=loadcurve_s49b status=variable New Load.s112a Bus1=112.1 Phases=1 Conn=Wye Model=5 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s112a status=variable New Load.s46a Bus1=46.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s46a status=variable New Load.s50c Bus1=50.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s50c status=variable New Load.s1a Bus1=1.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s1a status=variable New Load.s6c Bus1=6.3 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s6c status=variable New Load.s75c Bus1=75.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s75c status=variable New Load.s104c Bus1=104.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s104c status=variable Appendix B5 -OpenDSS netlist of the reference network -SP1 -continued B5-6-Loads -continued New Load.s76b Bus1=76.2.3 Phases=1 Conn=Delta Model=5 kV=4.16 kW=70.0 kvar=50.0 daily=loadcurve_s76b status=variable New Load.s22b Bus1=22.2 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s22b status=variable New Load.s96b Bus1=96.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s96b status=variable New Load.s103c Bus1=103.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s103c status=variable New Load.s113a Bus1=113.1 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s113a status=variable New Load.s43b Bus1=43.2 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s43b status=variable New Load.s82a Bus1=82.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s82a status=variable New Load.s90b Bus1=90.2 Phases=1 Conn=Wye Model=5 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s90b status=variable New Load.s80b Bus1=80.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s80b status=variable New Load.s11a Bus1=11.1 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s11a status=variable New Load.s55a Bus1=55.1 Phases=1 Conn=Wye Model=2 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s55a status=variable New Load.s111a Bus1=111.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s111a status=variable New Load.s49c Bus1=49.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=35.0 kvar=20.0 daily=loadcurve_s49c status=variable New Load.s109a Bus1=109.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s109a status=variable New Load.s65c Bus1=65.3.1 Phases=1 Conn=Delta Model=2 kV=4.16 kW=70.0 kvar=50.0 daily=loadcurve_s65c status=variable New Load.s70a Bus1=70.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s70a status=variable New Load.s87b Bus1=87.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s87b status=variable New Load.s59b Bus1=59.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s59b status=variable New Load.s98a Bus1=98.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s98a status=variable New Load.s86b Bus1=86.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s86b status=variable New Load.s66c Bus1=66.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=75.0 kvar=35.0 daily=loadcurve_s66c status=variable New Load.s38b Bus1=38.2 Phases=1 Conn=Wye Model=5 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s38b status=variable New Load.s48 Bus1=48 Phases=3 Conn=Wye Model=2 kV=4.16 kW=210.0 kvar=150.0 daily=loadcurve_s48 status=variable New Load.s51a Bus1=51.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s51a status=variable New Load.s19a Bus1=19.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s19a status=variable New Load.s53a Bus1=53.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s53a status=variable New Load.s64b Bus1=64.2 Phases=1 Conn=Wye Model=5 kV=2.4 kW=75.0 kvar=35.0 daily=loadcurve_s64b status=variable New Load.s9a Bus1=9.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s9a status=variable New Load.s73c Bus1=73.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s73c status=variable New Load.s77b Bus1=77.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s77b status=variable New Load.s4c Bus1=4.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s4c status=variable Appendix B5 -OpenDSS netlist of the reference network -SP1 -continued B5-6-Loads -continued New Load.s35a Bus1=35.1.2 Phases=1 Conn=Delta Model=1 kV=4.16 kW=40.0 kvar=20.0 daily=loadcurve_s35a status=variable New Load.s100c Bus1=100.3 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s100c status=variable New Load.s33a Bus1=33.1 Phases=1 Conn=Wye Model=5 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s33a status=variable New Load.s69a Bus1=69.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s69a status=variable New Load.s28a Bus1=28.1 Phases=1 Conn=Wye Model=5 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s28a status=variable New Load.s71a Bus1=71.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s71a status=variable New Load.s30c Bus1=30.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s30c status=variable New Load.s10a Bus1=10.1 Phases=1 Conn=Wye Model=5 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s10a status=variable New Load.s31c Bus1=31.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s31c status=variable New Load.s65a Bus1=65.1.2 Phases=1 Conn=Delta Model=2 kV=4.16 kW=35.0 kvar=25.0 daily=loadcurve_s65a status=variable New Load.s49a Bus1=49.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=35.0 kvar=25.0 daily=loadcurve_s49a status=variable New Load.s58b Bus1=58.2 Phases=1 Conn=Wye Model=5 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s58b status=variable New Load.s45a Bus1=45.1 Phases=1 Conn=Wye Model=5 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s45a status=variable New Load.s56b Bus1=56.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s56b status=variable New Load.s47 Bus1=47 Phases=3 Conn=Wye Model=5 kV=4.16 kW=105.0 kvar=75.0 daily=loadcurve_s47 status=variable New Load.s114a Bus1=114.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s114a status=variable New Load.s32c Bus1=32.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s32c status=variable New Load.s42a Bus1=42.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s42a status=variable New Load.s76c Bus1=76.3.1 Phases=1 Conn=Delta Model=5 kV=4.16 kW=70.0 kvar=50.0 daily=loadcurve_s76c status=variable New Load.s41c Bus1=41.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s41c status=variable New Load.s16c Bus1=16.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s16c status=variable New Load.s2b Bus1=2.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s2b status=variable New Load.s107b Bus1=107.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s107b status=variable New Load.s60a Bus1=60.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s60a status=variable New Load.s106b Bus1=106.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s106b status=variable New Load.s39b Bus1=39.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s39b status=variable New Load.s95b Bus1=95.2 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s95b status=variable New Load.s34c Bus1=34.3 Phases=1 Conn=Wye Model=2 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s34c status=variable New Load.s68a Bus1=68.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s68a status=variable New Load.s17c Bus1=17.3 Phases=1 Conn=Wye Model=1 kV=2.4 kW=20.0 kvar=10.0 daily=loadcurve_s17c status=variable New Load.s94a Bus1=94.1 Phases=1 Conn=Wye Model=1 kV=2.4 kW=40.0 kvar=20.0 daily=loadcurve_s94a status=variable Appendix B5 -OpenDSS netlist of the reference network -SP1 -continued

APPENDIX A1

Mapping between IEC 61850 and CIM Table III-1 -Equipment type codes [START_REF] Iec | 2020 -Power systems management and associated information exchange -Part 5: Communication requirements for functions and device models, Edition 2.0[END_REF] Appendix A1 -Mapping between IEC 61850 and CIM Appendix A1 -Mapping between IEC 61850 and CIM -continued

The table below gives the mapping between IEC 61850 equipment type/Logical nodes to the related CIM classes. The table is not exhaustive as it presents only the equipment involved further in our test feeder.

Table III-2 -Correspondence between IEC 61850 Logical Nodes and CIM classes adapted from [START_REF]TS: « Power system management and associated information exchange -Interoperability in the long term -Part 2: CIM-IEC 61850 harmonization[END_REF], [START_REF] Iec | 2020 -Power systems management and associated information exchange -Part 5: Communication requirements for functions and device models, Edition 2.0[END_REF] Table III-3 -Equipment name mapping between IEC 61850 and CIM [START_REF]TS: « Power system management and associated information exchange -Interoperability in the long term -Part 2: CIM-IEC 61850 harmonization[END_REF] Table III-4 -Geographic position mapping between IEC 61850 and CIM [START_REF]TS: « Power system management and associated information exchange -Interoperability in the long term -Part 2: CIM-IEC 61850 harmonization[END_REF] Table III-5 -Connectivity elements mapping between IEC 61850 and CIM [START_REF]TS: « Power system management and associated information exchange -Interoperability in the long term -Part 2: CIM-IEC 61850 harmonization[END_REF] APPENDIX A4

Translation of the reference network components into CIM classes The same approach used for modeling the circuit breaker is applied to the other conducting equipment.

APPENDIX B1

Extract of the reference network model (for SP1) in CIM RDF XML . . <cim:LinearShuntCompensator rdf:ID="_18961F0F-D570-408C-80C1-1551788B5B20"> <cim:IdentifiedObject.mRID>_18961F0F-D570-408C-80C1-1551788B5B20</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>c88a</cim:IdentifiedObject.name> <cim:Equipment.EquipmentContainer rdf:resource="#_3DF0CE82-665C-4858-B771-CA45A02CEFE1"/> <cim:ConductingEquipment.BaseVoltage rdf:resource="#_F96DD9D3-AD7B-4947-8387-E6F851C54296"/> <cim:ShuntCompensator.nomU>2402</cim:ShuntCompensator.nomU> <cim:LinearShuntCompensator.bPerSection>0.00866610602738073</cim:LinearShuntCompensator.bPerSection> <cim:LinearShuntCompensator.gPerSection>0</cim:LinearShuntCompensator.gPerSection> <cim:ShuntCompensator.aVRDelay>0</cim:ShuntCompensator.aVRDelay> <cim:ShuntCompensator.phaseConnection rdf:resource="http://iec.ch/TC57/2012/CIM-schema-cim17#PhaseShuntConnectionKind.Y"/> <cim:ShuntCompensator.grounded>true</cim:ShuntCompensator.grounded> <cim:LinearShuntCompensator.b0PerSection>0</cim:LinearShuntCompensator.b0PerSection> <cim:LinearShuntCompensator.g0PerSection>0</cim:LinearShuntCompensator.g0PerSection> <cim:ShuntCompensator.normalSections>1</cim:ShuntCompensator.normalSections> <cim:ShuntCompensator.maximumSections>1</cim:ShuntCompensator.maximumSections> <cim:PowerSystemResource.Location rdf:resource="#_5A7893E3-6837-44E4-B0B0-E833B21FED93"/> </cim:LinearShuntCompensator> <cim:LinearShuntCompensatorPhase rdf:ID="_7392057D-3F09-4C49-B56E-2E9D88123B88"> <cim:IdentifiedObject.mRID>_7392057D-3F09-4C49-B56E-2E9D88123B88</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>c88a_A</cim:IdentifiedObject.name> <cim:ShuntCompensatorPhase.phase rdf:resource="http://iec.ch/TC57/2012/CIM-schema-cim17#SinglePhaseKind.A"/> <cim:LinearShuntCompensatorPhase.bPerSection>0.00866610602738073</cim:LinearShuntCompensatorPhase.bPerSection> <cim:LinearShuntCompensatorPhase.gPerSection>0</cim:LinearShuntCompensatorPhase.gPerSection> <cim:ShuntCompensatorPhase.normalSections>1</cim:ShuntCompensatorPhase.normalSections> <cim:ShuntCompensatorPhase.maximumSections>1</cim:ShuntCompensatorPhase.maximumSections> <cim:ShuntCompensatorPhase.ShuntCompensator rdf:resource="#_18961F0F-D570-408C-80C1-1551788B5B20"/> <cim:PowerSystemResource.Location rdf:resource="#_5A7893E3-6837-44E4-B0B0-E833B21FED93"/> </cim:LinearShuntCompensatorPhase> <cim:Terminal rdf:ID="_B0569CAE-15FF-4007-ABDA-C64BC2065F1A"> <cim:IdentifiedObject.mRID>_B0569CAE-15FF-4007-ABDA-C64BC2065F1A</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>c88a_T1</cim:IdentifiedObject.name> <cim:Terminal.ConductingEquipment rdf:resource="#_18961F0F-D570-408C-80C1-1551788B5B20"/> <cim:Terminal.phases>A</cim:Terminal.phases> <cim:ACDCTerminal.sequenceNumber>1</cim:ACDCTerminal.sequenceNumber> <cim:Terminal.ConnectivityNode rdf:resource="#_ACAB7F66-28E4-48C9-B0F0-8DE116147839"/> </cim:Terminal> cim:Location rdf:ID="_5A7893E3-6837-44E4-B0B0-E833B21FED93"> <cim:IdentifiedObject.mRID>_5A7893E3-6837-44E4-B0B0-E833B21FED93</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>c88a_Loc</cim:IdentifiedObject.name> <cim:Location.CoordinateSystem rdf:resource="#_BD8112C9-C464-46A6-8E1F-BD352D6A1E62"/> </cim:Location> <cim:PositionPoint rdf:ID="_9FF6E287-4C8D-45A0-A682-6C3AB6A7B5C5"> <cim:PositionPoint.Location rdf:resource="#_5A7893E3-6837-44E4-B0B0 TransformerMeshImpedance.FromTransformerEnd rdf:resource="#_86B9E48C-9D73-46E7-859B-FF8CF21D32C0"/> <cim:TransformerMeshImpedance.ToTransformerEnd rdf:resource="#_794458D3-8841-4040-B73C-B275B268AB4D"/> </cim:TransformerMeshImpedance> <cim:PowerTransformerEnd rdf:ID="_86B9E48C-9D73-46E7-859B-FF8CF21D32C0"> <cim:IdentifiedObject.mRID>_86B9E48C-9D73-46E7-859B-FF8CF21D32C0</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>tr_d1_End_1</cim:IdentifiedObject.name> <cim:PowerTransformerEnd.PowerTransformer rdf:resource="#_96FE98C4-1488-45CC-AB2F-BE5A4B0E9FB7"/> <cim:PowerTransformerEnd.ratedS>1000000</cim:PowerTransformerEnd.ratedS> <cim:PowerTransformerEnd.ratedU>480</cim:PowerTransformerEnd.ratedU> <cim:PowerTransformerEnd.r>0.00146304</cim:PowerTransformerEnd.r> <cim:PowerTransformerEnd.connectionKind rdf:resource="http://iec.ch/TC57/2012/CIM-schema-cim17#WindingConnection.D"/> <cim:PowerTransformerEnd.phaseAngleClock>0</cim:PowerTransformerEnd.phaseAngleClock> <cim:TransformerEnd.endNumber>1</cim:TransformerEnd.endNumber> <cim:TransformerEnd.grounded>false</cim:TransformerEnd.grounded> <cim:TransformerEnd.Terminal rdf:resource="#_907F6F53-9E85-47BF-B755-07F660291CD3"/> <cim:TransformerEnd.BaseVoltage rdf:resource="#_BFFD575E-F1CE-4B02-AB92-4982916C677C"/> </cim:PowerTransformerEnd> . . <cim:ACLineSegment rdf:ID="_987B1FD8-45B6-4F25-8D1F-26F589904C26"> <cim:IdentifiedObject.mRID>_987B1FD8-45B6-4F25-8D1F-26F589904C26</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>l115</cim:IdentifiedObject.name> <cim:Equipment.EquipmentContainer rdf:resource="#_3DF0CE82-665C-4858-B771-CA45A02CEFE1"/> <cim:ConductingEquipment.BaseVoltage rdf:resource="#_F96DD9D3-AD7B-4947-8387-E6F851C54296"/> <cim:Conductor.length>0.4</cim:Conductor.length> <cim:ACLineSegment.PerLengthImpedance rdf:resource="#_1BE75351-23F5-440A-85A8-C267D0B80F27"/> <cim:PowerSystemResource.Location rdf:resource="#_EB6118D5-D9E9-4DCC-B7F9-D326C1514DCE"/> </cim:ACLineSegment> <cim:Terminal rdf:ID="_7D57189C-F4C6-47FB-8545-76B73EAD5A28"> <cim:IdentifiedObject.mRID>_7D57189C-F4C6-47FB-8545-76B73EAD5A28</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>l115_T1</cim:IdentifiedObject.name> <cim:Terminal.ConductingEquipment rdf:resource="#_987B1FD8-45B6-4F25-8D1F-26F589904C26"/> <cim:Terminal.phases>ABC</cim:Terminal.phases> <cim:ACDCTerminal.sequenceNumber>1</cim:ACDCTerminal.sequenceNumber> <cim:Terminal.ConnectivityNode rdf:resource="#_E3095E22-6F2C-47F8-9829-6FC4CA56ADFE"/> </cim:Terminal> <cim:Terminal rdf:ID="_B069C354-E9CF-48A3-BB16-35E42E601143"> <cim:IdentifiedObject.mRID>_B069C354-E9CF-48A3-BB16-35E42E601143</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>l115_T2</cim:IdentifiedObject.name> <cim:Terminal.ConductingEquipment rdf:resource="#_987B1FD8-45B6-4F25-8D1F-26F589904C26"/> <cim:Terminal.phases>ABC</cim:Terminal.phases> <cim:ACDCTerminal.sequenceNumber>2</cim:ACDCTerminal.sequenceNumber> <cim:Terminal.ConnectivityNode rdf:resource="#_F2CAAF0B-6E41-4EC6-8BD7-4D875A9FAD8F"/> </cim:Terminal> <cim:Location rdf:ID="_EB6118D5-D9E9-4DCC-B7F9-D326C1514DCE"> <cim:IdentifiedObject.mRID>_EB6118D5-D9E9-4DCC-B7F9-D326C1514DCE</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>l115_Loc</cim:IdentifiedObject.name> <cim:Location.CoordinateSystem rdf:resource="#_BD8112C9-C464-46A6-8E1F-BD352D6A1E62"/> </cim:Location> <cim:PositionPoint rdf:ID="_E2B56EB6-1240-424A-BD87-EA5007738449"> <cim:PositionPoint. 47FE-8709-6D88A5338B8B"> <cim:IdentifiedObject.mRID>_521F4438-4E98-47FE-8709-6D88A5338B8B</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>s1a</cim:IdentifiedObject.name> <cim:Equipment.EquipmentContainer rdf:resource="#_3DF0CE82-665C-4858-B771-CA45A02CEFE1"/> <cim:ConductingEquipment.BaseVoltage rdf:resource="#_F96DD9D3-AD7B-4947-8387-E6F851C54296"/> <cim:EnergyConsumer.LoadResponse rdf:resource="#_74551824-C994-44C0-91B6-67B3033E0CDE"/> <cim:EnergyConsumer.pfixed>40000</cim:EnergyConsumer.pfixed> <cim:EnergyConsumer.qfixed>20000</cim:EnergyConsumer.qfixed> <cim:EnergyConsumer.customerCount>1</cim:EnergyConsumer.customerCount> <cim:EnergyConsumer.phaseConnection rdf:resource="http://iec.ch/TC57/2012/CIM-schema-cim17#PhaseShuntConnectionKind.Y"/> <cim:EnergyConsumer.grounded>true</cim:EnergyConsumer.grounded> <cim:PowerSystemResource.Location rdf:resource="#_CAEFA31E-7169-47A0-9249-8A3FD96F597F"/> </cim:EnergyConsumer> <cim:EnergyConsumerPhase rdf:ID="_DBF46BBC-5F6D-4CED-8D6D-1048A31A0136"> <cim:IdentifiedObject.mRID>_DBF46BBC-5F6D-4CED-8D6D-1048A31A0136</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>s1a_A</cim:IdentifiedObject.name> <cim:EnergyConsumerPhase.phase rdf:resource="http://iec.ch/TC57/2012/CIM-schema-cim17#SinglePhaseKind.A"/> <cim:EnergyConsumerPhase.pfixed>40000</cim:EnergyConsumerPhase.pfixed> <cim:EnergyConsumerPhase.qfixed>20000</cim:EnergyConsumerPhase.qfixed> <cim:EnergyConsumerPhase.EnergyConsumer rdf:resource="#_521F4438-4E98-47FE-8709-6D88A5338B8B"/> <cim:PowerSystemResource.Location rdf:resource="#_CAEFA31E-7169-47A0-9249-8A3FD96F597F"/> </cim:EnergyConsumerPhase> <cim:Terminal rdf:ID="_F85F8D95-13F9-4343-8CAD-865B42F2CEFC"> <cim:IdentifiedObject.mRID>_F85F8D95-13F9-4343-8CAD-865B42F2CEFC</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>s1a_T1</cim:IdentifiedObject.name> <cim:Terminal.ConductingEquipment rdf:resource="#_521F4438-4E98-47FE-8709-6D88A5338B8B"/> <cim:Terminal.phases>A</cim:Terminal.phases> <cim:ACDCTerminal.sequenceNumber>1</cim:ACDCTerminal.sequenceNumber> <cim:Terminal.ConnectivityNode rdf:resource="#_F2CAAF0B-6E41-4EC6-8BD7-4D875A9FAD8F"/> </cim:Terminal> <cim:Location rdf:ID="_CAEFA31E-7169-47A0-9249-8A3FD96F597F"> <cim:IdentifiedObject.mRID>_CAEFA31E-7169-47A0-9249-8A3FD96F597F</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>s1a_Loc</cim:IdentifiedObject.name> <cim:Location.CoordinateSystem rdf:resource="#_BD8112C9-C464-46A6-8E1F-BD352D6A1E62"/> </cim:Location> <cim:PositionPoint rdf:ID="_C64EFA88-CF0C-4800-B8F9-1AB6126B5BFA"> <cim:PositionPoint.Location rdf:resource="#_CAEFA31E-7169-47A0-9249-8A3FD96F597F"/> <cim:PositionPoint.sequenceNumber>1</cim:PositionPoint.sequenceNumber> <cim:PositionPoint.xPosition>700</cim:PositionPoint.xPosition> <cim:PositionPoint.yPosition>1500</cim:PositionPoint.yPosition> </cim:PositionPoint> . . . . . . <cim:PerLengthPhaseImpedance rdf:ID="_236C9E22-D9E7-4869-8B2B-D17EFF0B4539"> <cim:IdentifiedObject.mRID>_236C9E22-D9E7-4869-8B2B-D17EFF0B4539</cim:IdentifiedObject.mRID> <cim:IdentifiedObject.name>6</cim:IdentifiedObject.name> <cim:PerLengthPhaseImpedance.conductorCount>3</cim:PerLengthPhaseImpedance.conductorCount> </cim:PerLengthPhaseImpedance> <cim:PhaseImpedanceData rdf:ID="_C883530F-B10A-4AB8-9BB5-03BA6C6BE072"> <cim:PhaseImpedanceData.PhaseImpedance rdf:resource="#_236C9E22-D9E7-4869-8B2B-D17EFF0B4539"/> <cim:PhaseImpedanceData.sequenceNumber>1</cim:PhaseImpedanceData.sequenceNumber> <cim:PhaseImpedanceData.r>0.086666667</cim:PhaseImpedanceData.r> <cim:PhaseImpedanceData.x>0.204166667</cim:PhaseImpedanceData.x> <cim:PhaseImpedanceData.b>8.95891141236381E-007</cim:PhaseImpedanceData.b> </cim:PhaseImpedanceData> <cim:PhaseImpedanceData rdf:ID="_1B616E35-04C0-4352-89F1-4BC9357DD57D"> <cim:PhaseImpedanceData.PhaseImpedance rdf:resource="#_236C9E22-D9E7-4869-8B2B-D17EFF0B4539"/> <cim:PhaseImpedanceData.sequenceNumber>2</cim:PhaseImpedanceData.sequenceNumber> <cim:PhaseImpedanceData.r>0.02907197</cim:PhaseImpedanceData.r> <cim:PhaseImpedanceData.x>0.072897727</cim:PhaseImpedanceData.x> <cim:PhaseImpedanceData.b>-1.1019311093514E-007</cim:PhaseImpedanceData.b> </cim:PhaseImpedanceData> <cim:PhaseImpedanceData rdf:ID="_E525ADC8-82F4-4537-9122-75054822DAAA"> <cim:PhaseImpedanceData.PhaseImpedance rdf:resource="#_236C9E22-D9E7-4869-8B2B-D17EFF0B4539"/> <cim:PhaseImpedanceData.sequenceNumber>3</cim:PhaseImpedanceData.sequenceNumber> <cim:PhaseImpedanceData.r>0.029545455</cim:PhaseImpedanceData.r> <cim:PhaseImpedanceData.x>0.095018939</cim:PhaseImpedanceData.x> <cim:PhaseImpedanceData.b>-2.89118820038372E-007</cim:PhaseImpedanceData.b> </cim:PhaseImpedanceData> <cim:PhaseImpedanceData rdf:ID="_023F53F6-D654-4B9B-BA0D-F1C84574D8D0"> <cim:PhaseImpedanceData.PhaseImpedance rdf:resource="#_236C9E22-D9E7-4869-8B2B-D17EFF0B4539"/> <cim:PhaseImpedanceData.sequenceNumber>4</cim:PhaseImpedanceData.sequenceNumber> <cim:PhaseImpedanceData.r>0.087405303</cim:PhaseImpedanceData.r> <cim:PhaseImpedanceData.x>0.201723485</cim:PhaseImpedanceData.x> <cim:PhaseImpedanceData.b>8.51794957582517E-007</cim:PhaseImpedanceData.b> </cim:PhaseImpedanceData> <cim:PhaseImpedanceData rdf:ID="_FBAED954-184F-4C9D-B8BF-DE6ACF11E500"> <cim:PhaseImpedanceData.PhaseImpedance rdf:resource="#_236C9E22-D9E7-4869-8B2B-D17EFF0B4539"/> <cim:PhaseImpedanceData.sequenceNumber>5</cim:PhaseImpedanceData.sequenceNumber> <cim:PhaseImpedanceData.r>0.029924242</cim:PhaseImpedanceData.r> <cim:PhaseImpedanceData.x>0.080227273</cim:PhaseImpedanceData.x> <cim:PhaseImpedanceData.b>-1.83786705469228E-007</cim:PhaseImpedanceData.b> </cim:PhaseImpedanceData> <cim:PhaseImpedanceData rdf:ID="_46A78215-EBD9-41AE-8677-291AC4569A1F"> <cim:PhaseImpedanceData.PhaseImpedance rdf:resource="#_236C9E22-D9E7-4869-8B2B-D17EFF0B4539"/> <cim:PhaseImpedanceData.sequenceNumber>6</cim:PhaseImpedanceData.sequenceNumber> <cim:PhaseImpedanceData.r>0.088371212</cim:PhaseImpedanceData.r> <cim:PhaseImpedanceData.x>0.198522727</cim:PhaseImpedanceData.x> <cim:PhaseImpedanceData.b>9.43932938440164E-007</cim:PhaseImpedanceData.b> </cim:PhaseImpedanceData> . . . . </rdf:RDF> APPENDIX B2

Extract of IEC 61850 equivalent of the reference network model In SP1

The extract given hereafter is an extract of IEC 61850 equivalent of the reference network model where each power system component is identified by its 'name' attribute.

Appendix B2a -Extract of IEC 61850 equivalent of the reference network model <?xml version="1.0" ?> <SCL xmlns:xsi="http://www.w3.org/2001/XMLSchema-instance" xsi:noNamespaceSchemaLocation="test_validity_of_xml_file.xsd"> <Header> <History id="TEST_THESIS_02012021.py" toolID="Python 3.6"/> </Header> <Line Desc="My Main feeder" Name="ieee123"> <PowerTransformer Desc="Regulator" Name="reg4c" Type="PTR"> <SubEquipment Name="T" phase="C"> <LNode ldInst="C1" lnClass="YPTR" lnInst="1"/> </SubEquipment> <TransformerWinding Name="W1" Type="PTW"> <Terminal cNodeName="160" connectivityNode="ieee123/M1/160" lineName="ieee123" pathName="ieee123/M1/reg4c/T1"/> </TransformerWinding> <TransformerWinding Name="W2" Type="PTW"> <Terminal cNodeName="160r" connectivityNode="ieee123/M1/160r" lineName="ieee123" pathName="ieee123/M1/reg4c/T2"/> </TransformerWinding> </PowerTransformer> <PowerTransformer Desc="Power Transformer" Name="xfm1" Type="PTR"> <TransformerWinding Name="W1" Type="PTW"> <Terminal cNodeName="61s" connectivityNode="ieee123/M1/61s" lineName="ieee123" pathName="ieee123/M1/xfm1/T1"/> </TransformerWinding> <TransformerWinding Name="W2" Type="PTW"> <Terminal cNodeName="610" connectivityNode="ieee123/N1/610" lineName="ieee123" pathName="ieee123/N1/xfm1/T2"/> </TransformerWinding> </PowerTransformer> <PowerTransformer Desc="Power Transformer" Name="tr_d2" Type="PTR"> <TransformerWinding Name="W2" Type="PTW"> <Terminal cNodeName="79" connectivityNode="ieee123/M1/79" lineName="ieee123" pathName="ieee123/M1/tr_d2/T2"/> </TransformerWinding> <TransformerWinding Name="W1" Type="PTW"> <Terminal cNodeName="900" connectivityNode="ieee123/N1/900" lineName="ieee123" pathName="ieee123/N1/tr_d2/T1"/> </TransformerWinding> </PowerTransformer> <PowerTransformer Desc="Regulator" Name="reg4b" Type="PTR"> <SubEquipment Name="S" phase="B"> <LNode ldInst="C1" lnClass="YPTR" lnInst="1"/> </SubEquipment> <TransformerWinding Name="W1" Type="PTW"> <Terminal cNodeName="160" connectivityNode="ieee123/M1/160" lineName="ieee123" pathName="ieee123/M1/reg4b/T1"/> </TransformerWinding> <TransformerWinding Name="W2" Type="PTW"> <Terminal cNodeName="160r" connectivityNode="ieee123/M1/160r" lineName="ieee123" pathName="ieee123/M1/reg4b/T2"/> </TransformerWinding> </PowerTransformer> . . . Appendix B2a -Extract of IEC 61850 equivalent of the reference network model -continued . . <VoltageLevel Name="M1"> <Voltage multiplier="k" unit="V" value="4.16"/> <ConductingEquipment Desc="Line/Cable segment" Name="l50" Type="LIN" pathName="ieee123/M1/l50"> <Terminal cNodeName="50" connectivityNode="ieee123/M1/50" lineName="ieee123" pathName="ieee123/M1/l50/T1"/> <Terminal cNodeName="51" connectivityNode="ieee123/M1/51" lineName="ieee123" pathName="ieee123/M1/l50/T2"/> </ConductingEquipment> . . <ConductingEquipment Desc="Circuit Breaker" Name="BR2" Type="CBR" pathName="ieee123/M1/BR2"> <Terminal cNodeName="152" connectivityNode="ieee123/M1/152" lineName="ieee123" pathName="ieee123/M1/BR2/T2"/> <Terminal cNodeName="13" connectivityNode="ieee123/M1/13" lineName="ieee123" pathName="ieee123/M1/BR2/T1"/> </ConductingEquipment> . . <ConductingEquipment Desc="Load" ID="_7EB6DFDC-7551-473B-86F8-4D164AF5F272" Name="s76c" Type="LOD" pathName="ieee123/M1/s76c"> <SubEquipment Name="R" phase="A"> <LNode ldInst="C1" lnClass="DLOD" lnInst="1"/> </SubEquipment> <SubEquipment Name="T" phase="C"> <LNode ldInst="C1" lnClass="DLOD" lnInst="2"/> </SubEquipment> <Terminal cNodeName="76" connectivityNode="ieee123/M1/76" lineName="ieee123" pathName="ieee123/M1/s76c/T1"/> </ConductingEquipment> . . <ConductingEquipment Desc="Shunt reactance" Name="c83" Type="CAP" pathName="ieee123/M1/c83"> <Terminal cNodeName="83" connectivityNode="ieee123/M1/83" lineName="ieee123" pathName="ieee123/M1/c83/T1"/> </ConductingEquipment> </VoltageLevel> <ConnectivityNode Name="160" pathName="ieee123/M1/160" x="3175" y="1850"/> <ConnectivityNode Name="160r" pathName="ieee123/M1/160r" x="3175" y="1850"/> . . <ConnectivityNode Name="149" pathName="ieee123/M1/149" x="300" y="1500"/> <ConnectivityNode Name="105" pathName="ieee123/M1/105" x="3525" y="2725"/> <ConnectivityNode Name="135" pathName="ieee123/M1/135" x="1600" y="2325"/> <ConnectivityNode Name="36" pathName="ieee123/M1/36" x="2075" y="2000"/> </Line> . .

</SCL>

The extract given hereafter is an extract of the IEC 61850 equivalent of the reference network model where a new ID attribute is proposed. In fact, each power system components is identified not by its 'name' attribute but by the same ID attribute as in the previous CIM reference model. Appendix B2b -Extract of IEC 61850 equivalent file with a new ID attribute <?xml version="1.0" ?> <SCL xmlns:xsi="http://www.w3.org/2001/XMLSchema-instance" xsi:noNamespaceSchemaLocation="test_validity_of_xml_file.xsd"> <Header> <History id="TEST_THESIS_02012021.py" toolID="Python 3.6"/> </Header> <Line Desc="My Main feeder" Name="ieee123"> <PowerTransformer Desc="Regulator" ID="_C1322FC5-5B22-4749-93A6-EA61C62B70F9" Name="reg4c" Type="PTR"> <SubEquipment Name="T" phase="C"> <LNode ldInst="C1" lnClass="YPTR" lnInst="1"/> </SubEquipment> <TransformerWinding Name="W2" Type="PTW"> <Terminal ID="_E1CBF52D-4EE0-47B6-AA43-496DD3542B66" cNodeName="160r" cnID="_4081276C-7B87-4933-B054-8EB8A5885330" connectivityNode="ieee123/M1/160r" lineName="ieee123" pathName="ieee123/M1/reg4c/T2"/> </TransformerWinding> <TransformerWinding Name="W1" Type="PTW"> <Terminal ID="_60F1F0DF-4B16-4EE1-8BE0-E23CFF550E47" cNodeName="160" cnID="_D4C8BDE7-E247-4EE8-8793-A2EA58AE0EF3" connectivityNode="ieee123/M1/160" lineName="ieee123" pathName="ieee123/M1/reg4c/T1"/> </TransformerWinding> </PowerTransformer> <PowerTransformer Desc="Power Transformer" ID="_F6149DF5-4148-44B0-B3C3-71B5D65A23DF" Name="xfm1" Type="PTR"> <TransformerWinding Name="W2" Type="PTW"> <Terminal ID="_1512D37C-E6EB-4C66-8227-DE61904931FC" cNodeName="610" cnID="_278091EC-8E96-4726-8F04-E9EF3A367C23" connectivityNode="ieee123/N1/610" lineName="ieee123" pathName="ieee123/N1/xfm1/T2"/> </TransformerWinding> <TransformerWinding Name="W1" Type="PTW"> <Terminal ID="_7DED97E9-C1B5-47AA-A990-EDF4B906EBCF" cNodeName="61s" cnID="_54AE8769-8E8A-447F-BA9B-40234889A138" connectivityNode="ieee123/M1/61s" lineName="ieee123" pathName="ieee123/M1/xfm1/T1"/> </TransformerWinding> </PowerTransformer> <PowerTransformer Desc="Power Transformer" ID="_BC6757C7-4E37-4E4E-8E85-3A1B3EB7828C" Name="tr_d2" Type="PTR"> <TransformerWinding Name="W1" Type="PTW"> <Terminal ID="_956696F2-8C6D-4201-9FEA-6DAA154072A0" cNodeName="900" cnID="_AB9514F7-40B8-4BA6-9276-30F948A305DB" connectivityNode="ieee123/N1/900" lineName="ieee123" pathName="ieee123/N1/tr_d2/T1"/> </TransformerWinding> <TransformerWinding Name="W2" Type="PTW"> <Terminal ID="_9DC27B71-69B3-4720-A9C6-67A05387E816" cNodeName="79" cnID="_C9A52B48-9DE8-4900-B53B-64262D4B8989" connectivityNode="ieee123/M1/79" lineName="ieee123" pathName="ieee123/M1/tr_d2/T2"/> </TransformerWinding> </PowerTransformer> . . <VoltageLevel Name="M1"> <Voltage multiplier="k" unit="V" value="4.16"/> <ConductingEquipment Desc="Line/Cable segment" ID="_8B5D38A8-3993-4FA5-899B-624F6A7DD88F" Name="l50" Type="LIN" pathName="ieee123/M1/l50"> <Terminal ID="_80E66F61-86B4-4861-AF54-A50C7CDAE33C" cNodeName="51" cnID="_B1A89E68-5C0B-4D19-A445-270541356243" connectivityNode="ieee123/M1/51" lineName="ieee123" pathName="ieee123/M1/l50/T2"/> <Terminal ID="_112F745E-32F1-4F64-898E-0C0C1846C5C5" cNodeName="50" cnID="_969CD7EF-E12E-4135-85CB-F527D400B525" connectivityNode="ieee123/M1/50" lineName="ieee123" pathName="ieee123/M1/l50/T1"/> </ConductingEquipment> . . <ConductingEquipment Desc="Circuit Breaker" ID="_1D244F54-A550-49A2-80CE-126C35EA8E54" Name="BR2" Type="CBR" pathName="ieee123/M1/BR2"> <Terminal ID="_3F044E5E-CFFB-4D8F-8105-30B7A553F751" cNodeName="152" cnID="_C1AEEBD9-B4C7-40E4-B72F-4914A881222E" connectivityNode="ieee123/M1/152" lineName="ieee123" pathName="ieee123/M1/BR2/T2"/> <Terminal ID="_8D1CAA7A-F621-4A5B-8E27-933885D45E55" cNodeName="13" cnID="_023C19D1-FFF2-4DC2-9E28-85A28BED56C1" connectivityNode="ieee123/M1/13" lineName="ieee123" pathName="ieee123/M1/BR2/T1"/> </ConductingEquipment> . . <ConductingEquipment Desc="Load" ID="_4A179794-9F66-4AE3-9821-97BD29E159CC" Name="s76b" Type="LOD" pathName="ieee123/M1/s76b"> <SubEquipment Name="S" phase="B"> <LNode ldInst="C1" lnClass="DLOD" lnInst="1"/> </SubEquipment> <SubEquipment Name="T" phase="C"> <LNode ldInst="C1" lnClass="DLOD" lnInst="2"/> </SubEquipment> <Terminal ID="_6751E76A-9DD7-4714-9A63-87B3E491BEE9" cNodeName="76" cnID="_574AC391-32EF-451F-BAB6-5E2B72F9189E" connectivityNode="ieee123/M1/76" lineName="ieee123" pathName="ieee123/M1/s76b/T1"/> </ConductingEquipment> . . <ConductingEquipment Desc="Shunt reactance" ID="_E41ADC05-89CA-47D8-9684-861DCCCB3B86" Name="c83" Type="CAP" pathName="ieee123/M1/c83"> <Terminal ID="_23E29E9E-AECC-48D9-8AC4-EC65BF424845" cNodeName="83" cnID="_A81E9B6E-2B12-4FAA-8F66-DCAFC391F83A" connectivityNode="ieee123/M1/83" lineName="ieee123" pathName="ieee123/M1/c83/T1"/> </ConductingEquipment> . . </VoltageLevel> <ConnectivityNode ID="_4081276C-7B87-4933-B054-8EB8A5885330" Name="160r" pathName="ieee123/M1/160r" x="3175" y="1850"/> <ConnectivityNode ID="_D4C8BDE7-E247-4EE8-8793-A2EA58AE0EF3" Name="160" pathName="ieee123/M1/160" x="3175" y="1850"/> . . <ConnectivityNode ID="_E3095E22-6F2C-47F8-9829-6FC4CA56ADFE" Name="149" pathName="ieee123/M1/149" x="300" y="1500"/> <ConnectivityNode ID="_9934C41E-F800-4F01-BF82-8A11A6A4234F" Name="105" pathName="ieee123/M1/105" x="3525" y="2725"/> <ConnectivityNode ID="_02C2A344-B877-4592-8827-599024A72C08" Name="135" pathName="ieee123/M1/135" x="1600" y="2325"/> <ConnectivityNode ID="_13EF69CD-4EA8-46EC-8B49-09E0BBE45039" Name="36" pathName="ieee123/M1/36" x="2075" y="2000"/> </Line> . . </SCL>

APPENDIX B3

Graph of the reference network for simulations in SP1

Appendix B3 -Graph of the reference network

The graph below represents the connectivity of the reference network.

APPENDIX B4

Zones creation in SP1 <Voltage multiplier="k" unit="V" value="4.16"/> <ConductingEquipment Desc="Line/Cable segment" ID="_8B5D38A8-3993-4FA5-899B-624F6A7DD88F" Name="l50" Type="LIN" pathName="ieee123/M1/l50"> <Terminal ID="_80E66F61-86B4-4861-AF54-A50C7CDAE33C" cNodeName="51" cnID="_B1A89E68-5C0B-4D19-A445-270541356243" connectivityNode="ieee123/M1/51" lineName="ieee123" pathName="ieee123/M1/l50/T2"/> <Terminal ID="_112F745E-32F1-4F64-898E-0C0C1846C5C5" cNodeName="50" cnID="_969CD7EF-E12E-4135-85CB-F527D400B525" connectivityNode="ieee123/M1/50" lineName="ieee123" pathName="ieee123/M1/l50/T1"/> </ConductingEquipment> . . <ConductingEquipment Desc="Line/Cable segment" ID="_DDCDACD1-04B8-4B60-91D1-106944E0D3DD" Name="l185" Type="LIN" pathName="ieee123/M1/l185"> <SubEquipment Name="S" phase="B"> <LNode ldInst="C1" lnClass="ZLIN" lnInst="1"/> </SubEquipment> <Terminal ID="_DD0DE051-AF37-44CC-9A4A-A89B83BD17DD" cNodeName="185" cnID="_0B65D343-ECEF-4E33-AB5C-965914E6290E" connectivityNode="ieee123/M1/ 185" lineName="ieee123" pathName="ieee123/M1/l185/T1"/> <Terminal ID="_DDB79BA0-FDD3-4F9B-9E14-91C32340C8DD" cNodeName="85" cnID="_BB4A3F9C-98B8-46A1-BAC2-BBF58FF98FBB" connectivityNode="ieee123/M1/ 85" lineName="ieee123" pathName="ieee123/M1/l185/T2"/> </ConductingEquipment> . . <ConductingEquipment Desc="Load" ID="_F3DAA273-A8F9-4CB4-BF80-410F9D36233C" Name="s251c" Type="LOD" pathName="ieee123/M1/s251c"> <SubEquipment Name="T" phase="C"> <LNode ldInst="C1" lnClass="DLOD" lnInst="1"/> </SubEquipment> <Terminal ID="_F20CB43F-D0A4-42E9-96EF-DB907B7836AB" cNodeName="251" cnID="_CC4A3F9C-98B8-46A1-BAC2-BBF58FF98FCC" connectivityNode="ieee123/M1/ 251" lineName="ieee123" pathName="ieee123/M1/s251c/T1"/> </ConductingEquipment> . . </VoltageLevel> <ConnectivityNode ID="_4081276C-7B87-4933-B054-8EB8A5885330" Name="160r" pathName="ieee123/M1/160r" x="3175" y="1850"/> <ConnectivityNode ID="_D4C8BDE7-E247-4EE8-8793-A2EA58AE0EF3" Name="160" pathName="ieee123/M1/160" x="3175" y="1850"/> . . <ConnectivityNode ID="_CC4A3F9C-98B8-46A1-BAC2-BBF58FF98FCC" Name="251" pathName="ieee123/M1/251" x="2956" y="3928"/> <ConnectivityNode ID="_BB4A3F9C-98B8-46A1-BAC2-BBF58FF98FBB" Name="185" pathName="ieee123/M1/185" x="4362" y="900"/> </Line> . . </SCL> Graph of the updated reference network for simulations in SP2

Appendix C3 -Graph of the updated reference network -SP2

The graph below represents the connectivity of the reference network where 02 single phase loads and 02 overhead line segments have been added as highlighted below in red.

APPENDIX C4

Zones creation with the updated reference network -SP2

ABSTRACT :

The presence of Distributed Energy Resources on conventional distribution systems has not only brought changes on the energy supply paradigm but also on distribution automation functions inducing new technical challenges on protection coordination systems, voltage control, to name a few. It has also increased the level of controllability and observability, making the network control more complex.

MOTS CLEFS :

Smart Grid, gestion décentralisée, gestion incrémentale, interopérabilité, harmonisation IEC 61850/CIM, modèle de connectivité, protection différentielle de zone, modèle 'node breaker'