IEEE Power & Energy Magazine - November/December 2017 - 65

Verification by Simulation
on a Large-Scale System
Large-scale simulations were performed by the Western
Electricity Coordination Council, which includes all parts
of the United States west of the Rockies, the northern part
of Baja California in Mexico, and the Canadian provinces
of British Columbia and Alberta. Among others, the following contingency case was examined using the inertia-less
system model.
The closing of a transmission line was studied to ensure
that it does not cause excessive transients of current and voltage. To observe this scenario, the power flow of the system
was solved with an outaged line between two major buses
in Arizona, resulting in a high angle difference between the
buses. At t = 15 s, the line was closed, leading to a severe
transient. With the maximum converter current set as 1.7 per
unit (pu), Figures 5 and 6 show the converter currents for
nearby generating units. Based on the figures, we can see
that, although there is a large increase in the instantaneous
current, the predisturbance current value is achieved within
1 s. In addition, as expected, the unit located close to the
line is affected to a much greater extent, but the system is
stable and secure. However, if the nearby generating units
had a maximum current value of 1.4 pu, the unit located
close to the line would trip, while the other units would pick
up the slack.
This large-scale simulation-based exercise has demonstrated that the use of only grid-forming converters with
well-designed control and adequate headroom in the generation resources could work effectively, even in large systems,
and tolerate large disturbances, including significant loss of
generation and closing of large transmission lines.
november/december 2017

Current (p.u.)

availability of fast response from the
1.4
converter devices, can serve ably in
1.4
both arresting frequency change
1.3
1.3
and the recovery of frequency.
1.2
This analysis has shown that the
1.2
1.1
control and operation of a zero-inertia
1
power system is viable. The pri1.1
0.9
mary assumption here is that ade0.8
quate active power margin is avail14.8 15 15.2 15.4 15.6 15.8 16
1
able to balance the system. For this to
be the case with only converter-based
0.9
renewable generation, some of the
renewable sources of energy would
0.8
need to be dispatchable, or wide40
5
10
15
20
25
30
35
spread use of energy storage would
Time (s)
be needed. A second assumption is
that every converter-interfaced gen- figure 5. The converter current of one Plant A unit for the opening of a tie line
eration source is capable of providing between Arizona and Southern California following a line fault.
voltage support, which requires sizing the converter to ensure that sufficient current is available to provide the needed active and
reactive current.
1.5
1.4
1.3
1.2
1.1
1
0.9
0.8

20
25
Time (s)

figure 6. The current of a generating unit located close to
the line with Imax = 1.7.

Near-Term Solution: Power Electronics
Must Be Able to Provide Ancillary Services
In most countries, generation sources are required to provide
some ancillary services. Usually, the type of service depends
on the size of the installation or the voltage level where it
is connected. For transmission-connected installations, it is
now common to provide ancillary services such as reactive
power control and frequency response, but more services
will be needed from converters when they are maintained in
a grid-forming configuration.
✔ Volt/volt ampere reactive (or VAR) regulation: the
adjustment of reactive power following a set point or
using a droop control that links the terminal voltage
and the reactive power. This is required today for most
converters while they are producing active power. As
active power of such installations is usually fluctuating, it will become increasingly necessary that the reactive power capability does not depend on the active
power output. Such a requirement is sometimes called
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Table of Contents for the Digital Edition of IEEE Power & Energy Magazine - November/December 2017