10-08-2013, 12:45 PM
RESrenewable generation on directional overcurrent relay coordination: a case study
Resolving the impact of distributed .pdf (Size: 563.77 KB / Downloads: 63)
Abstract:
Two approaches are proposed to solve the directional overcurrent relay coordination problem
associated with the installation of distributed renewable generation (DRG) in interconnected power delivery
systems (IPDS), depending on the existing system protection capability (adaptive or non-adaptive). For
adaptive protection systems, the first proposed approach introduces a procedure to select the optimal
minimum number of relays, their locations and new settings. This procedure is restricted by the available
relay setting groups. For non-adaptive protection systems, the second proposed approach implements a
practice to obtain optimal minimum fault current limiter values (FCL) to limit DRG fault currents and restore
relay coordination status without altering the original relay settings. An integration of the proposed two
approaches is evaluated for IPDSs possessing both protection systems. Three scenarios are assessed for
different numbers of DRGs, and DRG and fault locations using an optimisation model implemented in GAMS
software and a developed MatLab code. The obtained results are reported and discussed.
Introduction
The vast spread of distributed generation (DG) especially
distributed renewable generation (DRG) installations in
interconnected power delivery systems (IPDS) (primary
distribution and sub-transmission systems) increases burdens
on the existing power system protection schemes and devices.
For IPDSs with multiple supplies, directional overcurrent
relays are necessary to obtain proper relay coordination. These
relays have inverse time overcurrent characteristics that use
fault current values to trip for faults in a specified direction
[1]. Despite the positive impacts of DGs on system design
and operation [2–4], they change the original steady-state
and fault current values and directions resulting from the local
distribution company incoming feed, on which the original
relay settings were calculated [1].
Obtaining new relay coordination
status
In power delivery systems without DGs, mathematical
optimisation approaches were proposed to obtain relay
coordination and minimise the relay operating times. Linear
programming (simplex and generalised reduced gradient
methods) was proposed to obtain relay settings in [5], a
simplex two-phase method was introduced to acquire the
optimal directional overcurrent relay settings for on-line
adaptive protection in [6], and dual simplex was used in [7].
Limiting fault current levels
Network splitting, sequential network tripping schemes,
current limiting reactors and fault current limiter (FCL)
were used to limit the fault current values. Several FCL
technologies, applications and practical prototypes are
reported in [10 – 12]. FCL 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 the power delivery system to limit the fault
current value to a preset limit [13]. FCL was proposed to
be implemented at the beginning of a radial distribution
feeder equipped with a DG in [13]. In [14], the authors
investigated different locations for FCL installation to
maintain relay coordination. However, in [13, 14] the
authors did not examine their application in IPDS with
directional overcurrent relays, provide a value for FCL
impedance in [13], or discuss the impact of having several
DGs in [14]. In [15], FCL was utilised to restore
directional overcurrent relay coordination in a DRG-IPDS
equipped with non-adaptive relays. Thus, situations where
the IPDS is equipped with adaptive relays or combinations
of adaptive and non-adaptive relays were not evaluated.
IPDS under study
Fig. 3 shows only the 33 kV level portion of the 30 bus IEEE
system [18], however, the complete system is modelled in this
study. The IPDS is fed from three primary distribution
substations at buses 10, 12 and 27 and assumed to be
equipped with 29 directional overcurrent relays. The relays
have the standard IEEE moderately inverse relay curves
with the following constants: 0.0515, 0.114 and 0.02 for
A, B and C, respectively [17] and 0.3 s CTI for each
backup-primary relay pair. Three 10 MVA DRG with 0.9
lagging power factor and 0.15 pu. transient reactance [3]
are examined at buses 10, 12 and 19. The candidate DRG
location is chosen by the local distribution company. The
DRG interface transformer is assumed to have the same
DRG capacity and 0.05 pu. reactance [3]. The DRG is
simulated with its rated active power and its reactive power
limits. The FCL implemented in this study is represented
by its inductive type impedance.
Conclusions
This paper introduces two approaches, based on the
existing protection system’s capability, for regaining the
directional overcurrent relay coordination status in an
IPDS equipped with multi-DRGs without disconnecting
DRGs during faults. For an existing adaptive protection
system, the first approach was able to obtain the optimal
minimum number of relays and their locations and
settings for an existing adaptive protection system. It
took into consideration the ARSGs under all ON-State
DRG combinations as well as the no DRG case. Results
show the effectiveness of this procedure for all the
reported conditions. However, this approach might not
be applicable as the number of DRGs increases. In the
second approach, for an existing non-adaptive protection
system, FCL was introduced to locally limit the DRG
drawn current during fault and obtain new relay
coordination status without altering the original relay
setting. The feasible minimum FCL impedance value for
all ON-State DRG combinations was obtained. Results
show the usefulness of this second approach which
applies to any DRG number or capacity. However, as
individual DRG capacities increases, the value of FCL
impedance and its cost increases, which may become
economically unfeasible.