BACKGROUND OF THE INVENTION
The invention generally relates to protection of power overhead
transmission lines and cables where the protected line (or cable) has a
transformer (or transformers) tapped between the substations. More
particulirly, the present invention allows the application of well-known current
differential protection principles without measuring the currents at the line
terminals of the tapped transformer.
An overhead power transmission line or a cable - referred to as a "line"
in this document - can be protected in a variety of ways. The applied protection
solution depends on the line voltage level, line configuration, importance of the
protected line for the power system as a whole, as well as available
communication means and bandwidth for the protection equipment.
Among known protection techniques, the overcurrent protection
principle is perhaps the simplest. The principle relies on the magnitude of the
current and classifies situations with excessive currents as fault conditions. The
principle has many versions including directional and voltage supervision, and
definite or current-dependent time-delayed operation. With all these
enhancements the overcurrent principle can be applied to certain line
configurations only; primarily, on the power distribution level.
The distance protection principle derives an "apparent" impedance from
the voltages and currents measured at the substation and associated with the
protected line. The technique for measuring the impedance (either directly or
indirecrly) insures that the apparent impedance - for any type of fault - is
proportional to the actual geometrical distance from the substation to the fault

positior. Distance relays are capable of locating faults on the line with
precision, at least in ideal conditions. Thus, they can protect complex line
configurations. In actual situations, however, several factors affect accuracy of
distance relays. In order to avoid malfunction of a distance relay on near
externa faults, the relay reach cannot be set to 100% of the line length but it is
set usually at 70-90% depending on the quality of the applied protection
equipment.
In order to protect the entire line, several time-delayed overreaching
distance zones are usually used. This is known as a stepped distance protection
scheme
By exchanging at least one bit of information, two distance relays
installed at both ends of a protected line can be arranged into a so-called pilot,
scheme A pilot scheme can be organized either using a permissive or blocking
logic and always ensures much more reliable protection comparing with two
individual distance relays without any means of communication. There are
situations, however, such as simultaneous external and internal faults, where
the dis ance-based pilot scheme may fail to provide reliable protection.
Sensitivity of distance protection schemes is another limitation.
The line current differential principle is another protection technique. It
compares the currents, typically the current phasors, at both the terminals of the
protected line. In the case of an external fault the currents match almost
perfectly, while during internal faults, the difference is significant. A line
current differential relay creates internally a signal proportional to the
difference between the locally measured current and the remote current (the
differential current or signal). To cope with line charge currents, and
transfer nation errors of the Current Transformers (CTs) including saturation,
the percentage differential principle is used. The differential current is not
compared against a threshold but against a apecially formed restraining current
-2-
Various types of operate/no-operate characteristics can be used to accomplish
the percentage current differential characteristic.
There are typically several requirements of the current differential
protection principle. First, significant amounts of information must be
exchanged over long distances (tens or hundreds of kilometers).
Microprocessor-based protective relays exchange their locally measured
current phasors in a digital form over a communication channel set up using
fiber optic links, microwave channels or some other physical medium.
Second, the microprocessor-based relays at both line terminals must be
accuracy synchronized in order to measurethe line terminal current at the
same time instances. This is accomplished utilizing, for example, well-known
Global Positioning System (GPSlas a source of a absolute clock or using some
other techniques for self-synchronization of two or more line current
differertial relays. Such a technique is described in U.S. Patent 4,715,000.
Third, the circuits connected to the protected line such as tapped lines or
transformers must be monitored current in order to apply the current
differential protection principle this may create a problem as the tapped
connections are meant to provide a cost-effective alternative to actual
substations. The taps are made outside the main substations, they are rarely
equipped with proper protection means such a Circuit Breakers (CBs) and CTs.
Also, high-speed communication from the tap position may be a problem. This
either limits application of line current differential relays on tapped lines or
makes the tapped line connections economically less attractive.
Presently-known techniques do not adequately address these problems.
SUMMARY OF THE INVENTION
The present invention overcomes the problems described above, achievss additional advantages, by providing for a method or system to apply_
the li:ie current differential relay to protect tapped lines without the
measurements at the tap.
According to exemplary embodiments, the current differential relays are
made immune to the load current drawn by the tapped transformer under
normal system conditions and to the fault current for faults at the distribution
busbar of the tapped transformer. This is accomplished by adding distance
supervision to the line current differential scheme. The differential scheme is
permitted to trip only if the appropriately set distance relay sees the fault within
its operating zone.
The disclosed embodiments use a distance protection element, either as
a pan of the line current differential integrated protective relay or implemented
as a separate relay integrated with the line current differential relay, to
supervise the operation of the latter. The distance element is set to detect the
faults ocated/on the protected transmission line, and within the tapped
transformer, but not the faults located at the distribution busbar of the tapped
transformer. As the tapped transformers are of relatively low power, their
impedance is relatively high; thus, a reach setting meeting the above
require nents is possible. The distance zone is set as an instantaneous zone
overreaching the line length with a security margin with respect to the
distribution busbar of the tapped transformer. The zone may be set as an
overreaching zone because the differential protection element is capable of
distinguishing faults on the line or the tapped transformer from the faults
outside the line.
Another obstacle is associated with external ground faults. The tapped
transformers have typically their primary winding, i.e. the winding coupled to
the line wye-connected with a grounded neutral, and as such, they create a path
for the :ero sequence current during ground faults. Thus, if an external ground
fault oc;urs, the zero sequence current is fed by the tapped transformer and the
current balance monitored by the line differential relay as the differential signal
gets upset. The differential scheme would see significant differential current
and would malfunction on external ground faults, despite the distance
supervision if the external fault is located within the overreaching distance
zone.
To overcome this problem, exemplary embodiments of the present
invention subtract the zero sequence current from the currents at both line
terminals prior to calculating the differential signal. Owing to this, the
differertial signal is insensitive to the zero sequence component of the current
and the current differential scheme becomes stable on external ground faults-
Subtracting the zero sequence current from the differential signal would,
however, degrade relay sensitivity by approximately 1/3rd on internal single
line to ground faults. To maintain sensitivity, the zero sequence component is
subtracted when calculating the restraining signal as well.
Another problem generated by the operation of subtracting the zero
sequenced component from the differential and restraining signals is that the
phase-selective operation of the current differential principle would be lost.
Normally, the differential relay is implemented on the per phase basis and
responcs selectively to various types of faults. Particularly, if a single line to
grounc fault occurs, the relay can trip - if programmed to do so - the CB only
in the cefective phase (single pole tripping). This is typically followed by the
operation of autoreclosing the breaker after a pre-defined time interval in
anticipation of a fault to disappear by itself. This keeps the line in service and
ensures certain power transfer between the substations.
When the zero sequence current is removed from the differential current,
the differential currents in the healthy phases during an internal single line to
ground faults would equal approximately l/3rd of the fault current. The
restraining current would be to too low to prevent relay malfunction in the
healthy phases. Consequently, the relay that compensates for the zero sequence
current would always trip all three phases. To prevent that the present invention
uses both the traditional line current differential characteristic and the modified
(zero sequence compensated) line current differential characteristic in parallel.
The first one tends to overtrip on external faults. The latter tends to overtrip
healthy phases on internal faults.To solve the problem the two differential
characteristics supervise each other mutually and the phase-selective operation
is regained.
In accordance with are
tapped transformer can be protected by current differential relays installed
exclusively in the substations, without degrading sensitivity and phase-
selectivity of the protection on internal faults nor jeopardizing relay stability on
external faults.
BRIEF' DESCRIPTION OF THE ACCOMPAYING DRAWINGS
The present invention and its resulting advantages can be more fully
understood by reading the following Detailed Description in conjunction
with the accompanying drawings, in which:
FIG. 1 shows an arrangement of a power line between the substations A
and B with a power transformer tapped at the position T. The differential
protection zone is bounded by the CTs and includes a portion of transformer
windings.

FIG. 2 presents a sample two-slope operating characteristic of the
curreni differential element on the differential - restraining plane.
]1G. 3 depicts normal load conditions with the power transferred from
the substation A to B. The load current drawn by the tapped transformer
appears as the differential signal.
FIG. 4 presents an overall logic diagram of the present invention.
FIG. 5 illustrates the distance supervision.
FIG. 6 depicts external ground fault conditions. The transformer tapped
within ;he differential zone generates the zero sequence current that is present
at the substation B but it is not present at the substation A. This creates a
spurious differential signal.
FIG. 7 presents a detailed block diagram of the improved current
differential algorithm. The figure should be read in conjunction with FIG. 6
which shows how the DIFF1 and DIFF2 flags are used to create the operate
signal, OP.
DETAILED DESCRIPTION OF THE INVENTION
A. INTRODUCTION
With reference to FIG. 1 a line current differential scheme comprises of
two relays measuring the currents at both terminals of the protected line (or
three relays for three terminal lines) through two sets of CTs, and of a
communication channel that enables the relays to exchange the locally
measured currents. Each relay combines its locally measured currents with the
remote currents and the differential (subscript D) and restraining (subscript R)
currents are calculated as follows:

In equation (1) and the following description the superscripts stand for
stations, while the subscripts stand for phases or other notation.
The formulae (2a) for the restraining current is generic. Practical
realizations include, but are not limited to:

where d in equation (2d) is an extra restraining factor calculated based
on the loise in the input signals as described in U.S. Patent 5,809,045.
The particular definition of the restraining signal is not important to the
present discussion, as the disclosed embodiments will work with any suitably-
definec restraining signal.
For purposes of explanation, description it is assumed that the current
phasors are used; however, it will be appreciated that instantaneous current
values can also be used. Further, while the present invention works for three-
arid multi-terminal lines, the method will be explained assuming a two-terminal
line case.
The differential and restraining signals are subjected to the operating
characteristic, and a corresponding flag is set if the differential - restraining
point falls into the operate region. FIG. 2 depicts an exemplary two-slope

characteristic. It should be noted, however, that the present invention is
applicable with any differential characteristic including the one that uses a
dynami:: restraint as given by equation (2d).
B. DISTANCE SUPERVISION
In the case of a transmission line with a tapped transformer, certain load
currenr is drawn from the line by the transformer in normal load conditions as
shown in FIG 3. Consequently, the differential signal calculated by the relays
would be:

At the same time the restraining current, regardless of the applied
approach, would be close to the line load current. The differential current of
equation (3) may be high enough as compared with the restraining current to
cause the operation of the differential protection element. Distance supervision
as described later can be applied to solve this problem.
Another problem originates from external faults at the distribution bus
of the tapped transformer. The current differential relay may be sensitive
enough to see such faults, but preferably should not operate as the line does not
need to be taken out of service in the case of a fault outside the line and the
tapped transformer. A distance supervision as described later can be applied to
solve t lis problem.
Yet another problem occurs when the line is energized. One breaker gets
closed energizing the line and the tapped power transformer while the other
remains open. In such conditions, the differential and restraining currents are
equal. At the same time, the tapped transformer draws significant inrush
magnetizing current. The differential relay may malfunction in such conditions
Distance supervision can be applied to solve this problem.

With reference to FIG. 4, a line distance protection element or a separate
relay supervises operation of the line current differential element (the AND
gate producing the operate signal, OP).
In one embodiment, reach of the line distance protection element is
preferably set to achieve the following objectives:
a) The distance element should not see faults at the distribution busbar
of the tapped transformer.
b) The distance element should see faults along the entire line.
c) The distance element should not operate during transformer
energization due to magnetizing inrush currents.
As the rated power of tapped transformers is relatively small compared
with the typical power transfer through the protected line, it is reasonable to
assume that conditions a) and b) can be met simultaneously in majority of
practical applications.
Suitable filtering can be implemented in conventional microprocessor-
based distance relays to meet the requirement c) in conjunction with a) and b).
FIG. 5 illustrates the distance supervision principle.
C. REMOVAL OF THE ZERO SEQUENCF CURRENT
During external ground faults as depicted in FIG. 6, the positive,
negative and zero sequence currents would flow through the line from the
substition A to the substation B without upsetting the current balance between
the line terminals (assuming the tapped transformer is not connected to the
source of power which is the practical case). An additional zero sequence
current, however, would be generated by the transformer if its primary winding
is wye-connected and grounded (which is a practical case). The zero sequence
current would flow towards the fault through one substation only (the
substation B in FIG. 6). This would create a spurious differential signal as
follows:

At the same time the restraining current, regardless of the applied
approach, would be close to the line load current in the healthy phases and
close to the fault current in the faulted phases. In both the cases, the spurious
differential signal is likely to be high enough to cause relay malfunction.
To solve this problem, the zero sequence current can be subtracted from
the phase current prior to calculating the differential signal. Such a modified
differential signal can be calculated as (phase A shown, phases B and C are
treated accordingly):

The modified differential current calculated as (5) does not respond to
any zero sequence currents during external faults. The differential currents in
all three phases would be zero for any type of external fault.
However, during ground internal faults the modified differential current
calculated as (5) would be smaller comparing with the traditional current (1)
and the relay sensitivity would be degraded. To maintain relay sensitivity, the
restraining current is modified accordingly (definition (2d) of the restraining
current is used below for illustration):

Equation (6) provides just an example. It should be noted that the
¦A
calculation of the restraining signal from the phase currents after removing the
zero sequence component works with any definition of the restraining signal.
Once the modified differential and restraining signals are created by the
relay, they are subjected to the differentia] characteristic and the output operate
flag, DIFF2, is created. As in the case of a traditional current differential
technique, this is done on the per phase basis
D. PHASE-SELECTIVE OPERATION
Removing the zero sequence current from the differential current
ensures relay stability during external ground faults. This operation, however,
would cause a problem as the current differential relay would operate in all
three phases for any internal ground fault, and consequently, the advantage of a
phase-selective operation would be lost. This is so because the fault current in
one (single line to ground fault) or two phases (line to line to ground fault)
contains significant zero sequence component. That component is than
subtracted from the small load current in the healthy phase (or phases) creating
a large differential signal as compared with the restraining signal in the healthy
phase (phases).
To regain the phase-selective operation, it is preferable to use both the
traditional and modified (zero sequence compensated) differential
characteristics.
The traditional characteristic, setting the flag DIFF1 in FIG. 4, shows a
tendency to overtrip on external ground faults, but is phase-selective on internal
faults The modified characteristic, setting the flag DIFF2 in FIG. 4, shows a
tendency to overtrip healthy phases on internal faults, but it is stable on
external faults. Therefore the two characteristics should supervise each other
mutually (the AND gate in FIG. 4). The resulting per-phase operands DIFFA,

DIFFB and DIFFc retain both stability on external faults and phase-selectivity
on internal faults. The latter enables proper identification of a faulted phase for
the sin.gle-pole tripping mode.
FIG. 7 depicts one possible implementation of the two differential
characteristics.
An alternative way of implementing the two characteristics is to.
dynamically select the effective differential current out of the traditional and
modified differential currents according to the following equations:

and than select the corresponding restraining current depending on the
selection of the differential current.
While the foregoing description includes many details and specificities,
it is to be understood that these have been included for purposes of explanation
only, and are not to be interpreted as limitations of the present invention. Many
modifications to the embodiments described above can be made without
departing from the spirit and scope of the invention, as is intended to be
encompassed by the following claims and their legal equivalents.
We Ciaim
--------------
1. A method for providing protective control to a tapped line in a power
system, comprising the steps of: -
- measuring (110) one or more local currents in a first protection
element;
- receiving (120), in the first protection element, one or more remote
current measurements from a second protection element;
- calculating (130) one or more differential currents based on the
local and remote current measurements;
- receiving (140) one or more local voltages and the one or more
local currents in at least one distance protection element; and
- determining (150) in at least one distance protection element, an
apparent impedance from the one or more local currents and
voltages;
characterized in that the at least one distance protection element
does not determine the apparent impedance for faults occurring in
a busbar of a tapped transformer connected to the tapped line.
2. A method as claimed in Claim 1 wherein the first and second protective
elements are protective relays.
3. A method as claimed in Claim 2 wherein the first protection element
comprises the at least one distance protection element.
4. A method as claimed in Claim 1 wherein the at least one distance
protection element determines the apparent impedance for faults
occurring along substantially the entire tapped line.
5. A method as claimed in Claim 1 wherein the at least one distance
protection element does not operate during an energization of the tapped
transformer.
6. A method for providing protective control to a tapped line in a power
system comprising the steps of: -
- measuring one or more local currents in a first protection element;
- receiving/ in the first protection element, one or more remote
current measurements from a second protection element;
- calculating one or more differential currents based on the local and
remote current measurements;
- receiving one or more iocai voitages and the one or more iocai
currents in at least one distance protection element;
- determining, in the at least one distance protection element, an
apparent impedance from the one or more local currents and
voltages;
- determining, for an external ground fault, one or more zero
sequence currents; and
- subtracting the one or more zero sequence currents from the one
or more local currents prior to the step of calculating the one or
more differential currents.
7. A method as claimed in Claim 6 comprising:
- generating a first restraining current based on the one or more
differential currents; and
- outputting a first protective control signal based on the one or
more differential currents and the first restraining current.
8. A method as claimed in Claim 7 comprising:
- determining, for an interna! ground fault, one or more second
differential currents and one or more second restraining currents
from the one or more local currents and the one or more remote
currents;
- outputting a second protective control signal based on the one or
more second differential currents and the one or more second
restraining currents; and
- effecting a protective control operation based on both the first
protective control signal and the second protective control signal.
9. A method for providing protective control to a tapped line in a power
system, comprising the steps of: -
- measuring one or more local currents in a first protection element;
- receiving, in the first protection element, one or more remote
current measurements from a second protection element;
- calculating one or more differential currents based on the local and
remote current measurements;
- calculating one or more restraining currents based on the one or
more differential currents;
- outputting a first protective control signal based on the one or
more differential currents and the one or more restraining currents;
- determining one or more zero sequence currents;
- subtracting the one or more zero sequence currents from the local
and remote current measurements to generate modified current
measurements;
- calculating one or more modified differential currents from the
modified current measurements;
- calculating one or more modified restraining currents from the
modified current measurements; and
• outputting a second protective control signal based on the one or
more modified differential currents and the one or more modified
restraining currents.
10. A method as claimed in Claim 9 comprising affecting protective control
based on both the first and second protective control signals.
11. A method as claimed in Claim 9 comprising:
- selecting a minimum of the one or more differential currents and
the one or more modified differential currents;
- selecting a corresponding restraining signal; and
- affecting protective control based on the selected differential
current and corresponding restraining signal.
12.A method as claimed in Claim 9 wherein the first and second protection
elements are protective relays.
13. A method as claimed in Claim 9 comprising:
• receiving one or more local voltages and the one or more local
currents in at least one distance protection element;
- determining, in the at least one distance protection element, an
apparent impedance from the one or more local currents and
voltages;
- generating a third protective control signal based on the apparent
impedance; and
- affecting protective control based on the first protective control
signal, the second protective control signal, and the third protective
control signal.
14.A method as claimed in Claim 13 wherein the at least one distance
protection element determines the apparent impedance for faults
occurring along substantially the entire tapped line.
15.A method as claimed in Claim 13 wherein the at least one distance
protection element does not determine the apparent impedance for faults
occurring in a busbar of a tapped transformer connected to the taped line.
16.A method as claimed in Claim 15 wherein the at least one distance
protection element does not operate during an energization of the tapped
transformer.

The invention relates to a method for providing protective control to a tapped
line in a power system, comprising the steps of: - measuring (110) one or more
local currents in a first protection element: receiving (120), in the first protection
element, one or more remote current measurements from a second protection
element; calculating (130) one or more differential currents based on the local
and remote current measurements; receiving (140) one or more local voltages
and the one or more local currents in at least one distance protection element;
and determining (150) in at least one distance protection element, an apparent
impedance from the one or more local currents and voltages; at least one
distance protection element does not determine the apparent impedance for
faults occurring in a busbar of a tapped transformer connected to the tapped
line.