Resultados Analíticos

The Swedish transmission system consists of the two voltage levels 400 kV and 220 kV and has two independent redundant protection systems for each line called SUB1 and SUB2¹. The main reasons for this is to provide local back-up giving fast fault clearing and to limit the affected area by ensuring that only the faulted line is disconnected.

Additionally maintenance work can be performed on protection equipment at the same time as the line is loaded and still have the line satisfactorily protected.

2.7.1 Outline of the protection scheme at the line terminal

Figure 2.18 shows an outline of the standard line protection system in the Swedish transmission system. All line terminals in the Swedish transmission system, apart from a limited numbers of 220 kV terminals, are equipped with a system identical or similar to the one in figure 2.18.

Most devices are duplicated though a few components are shared by the two SUB groups. The same voltage and current transformers are used. Neither the circuit breaker is duplicated. However the voltage signals from the VT into the two SUB groups are protected by independent fuses and different CT coils are used for the current signals. The DC supply for the two SUB groups are separated and are not allowed to share any fuse. Below a description of the abbreviations in figure 2.18 is given:

DP = Distance Protection

JS1-JS23 = Zones 1 to 3 of the directional definite time overcurrent elements

JS3 INV.= The non-directional inverse time overcurrent element U₀ = Zero voltage protection

COM. = Pilot Relaying equipment AR = Auto Recloseing

BFP = Breaker Failure Protection SS = Busbar protection

1. Abbreviation for Subsystem. Often the terms main 1 and main 2 are used.

Figure 2.18 Line protection system.

DP JS1-JS23 JS3 INV.

U

COM.

AR

LOGIC BFP LOGIC

DP JS3 INV.

COM.

AR

FUSES

LINE

U

I

3I₀ 3U₀

SUB 1 SUB 2

DC Supply

DC Supply

I

TRANSMISSION

CB SS

Both SUB 1 and SUB 2 contain a distance relay which is intended to clear short circuit faults. Additionally SUB 1 includes the four zones earth-fault overcurrent relay as described in section 2.3.2. However to assure clearing of small residual currents in case of maintenance work on SUB 1, an inverse time earth-fault overcurrent relay is required in SUB 2. Usually this overcurrent function is included in the distance relay. As discussed in section 2.3.2, Sweden is one of the few countries where earth-fault overcurrent protection is used as the main earth-fault protection whereas distance protection is used as local back-up.

Generally the earth-fault overcurrent protection performs better than distance protection in case of a large fault resistance and gives a higher number of successful auto-reclosures. In the Swedish transmission system about 80 % of the faults are earth-faults which are mainly cleared by the earth-fault overcurrent protection [32].

The disadvantages of the zero-sequence based overcurrent protection is that their reach is dependent of the prevailing network configuration. Hence when extensive network reconfigurations are made the relays must be given new settings to operate as intended.

However in case of an interruption this is not practicable and consequently the relays have incorrect settings with respect to the post fault grid configuration. Adaptive techniques may solve this problem.

However until today no severe accidents have happened due to this phenomenon. Another drawback with the earth-fault overcurrent protection is that a good knowledge about the positive-, negative and zero sequence impedances of the system is required to give the relay proper settings. Additionally the calculation process is complicated;

however computer software can be used for this process.

Breaker failure protection and busbar protection are included in the scheme although they may be considered to be classified as substation protection. Additionally zero voltage protection is required for either SUB 1 or SUB 2. This protection device opens all circuit breakers at a certain voltage level. Usually the setting is somewhere between 0.3 and 0.5 pu. The purpose of this function is to simplify the restoration process after an interruption.

Pilot relaying is widely used to decrease the fault clearing time.

Mainly the pilot relaying schemes ”accelerated underreach” and

”intertripping underreach” are practised [6].

At a few substations the distance protection in one SUB group is replaced by differential protection as the surrounding system configuration makes it preferable.

When the duplicated protection system was introduced in the middle of the seventies it was decided that each SUB group should contain distance relays based upon different principles and/or from two different brands. For example, an electro-mechanical relay should be combined with a solid-state relay or a switched relay should operate in parallel with a full-scheme relay. The background for the decision was to increase reliability as two different relays probably will not suffer from the same design inadequacies. Today this philosophy is slowly changing because (almost) all relays manufactured are numerical and largely based on the same algorithms. However, still different designs of relays are required in the two SUB groups although they must not necessarily be of different brands. The main reason for this requirement is to safeguard against software inadequacies. Another reason may be that it is harder to give two different relay types incorrect settings as compared to identical relays as the ”copy and paste” technique may be avoided.

2.7.2 Mixture of distance relays

The depreciation period for protection relays is 15 years but usually they are used longer. Today there are distance relays which are more than 30 years old in the Swedish system. However the technical life time will probably decrease for computer based devices. About 700 distance protection devices are installed and the mixture based on the type of relay is shown in table 2.1.

Table 2.1: Mixture of different types of distance relays.

SUB 2 was introduced in the middle of the seventies. Therefore no electro-mechanical relays were used since solid-state relays already had entered the market.

The zones of operation for all electromechanical relays have the shape of a (mho)circle. Solid-state and numerical relays have a quadrilateral shape or a combination of a circle and a quadrangle. Table 2.1 shows

Electro mechanical

[%]

Solid-state [%]

Numerical [%]

SUB 1 65.5 16.5 18.0

SUB 2 - 72.5 27.5

Total 37.5 40.5 22.0

that electromechanical relays still compose a large fraction of the line protection devices and probably will be used for a long time into the future. Therefore it is very important to consider this type of relay when stability studies are made. Numerical relays not only offer improvement in protection but are also predicted to entail overall system improvement to meet the demands of deregulation [33]. A new problem which possibly can occur with computer based relays is that the software will be frequently updated. Accordingly there will be a lot of different models in the system but only a few of each device. This may complicate support and maintenance work.

2.8 Advantages and disadvantages with local and