PV Impacts on Dynamic Voltage Stability
Ahmad Tbaileh
Chetan Mishra, Kyle Thomas
Dept. of ECE, Virginia Tech
Blacksburg, USA
atahm12@vt.edu
Dominion Virginia Power
Richmond, USA
chetan.mishra@dom.com, kyle.thomas@dom.com
Abstract-In this paper we discuss the impact of PV on dynamic
voltage stability. The power system becomes more vulnerable as
we
add
PV
and
displace
conventional
generation,
and
consequently inertia and VAR support. While PV inverters have
the capability to provide reactive power, the fact that most PVs are
connected at lower voltage levels limits its usefulness. We use the
Dominion Virginia Power's system with different PV scenarios to
show how dynamic voltage stability of the system was significantly
affected. The purpose of this paper is to increase the awareness to
the dynamic voltage stability issues the in case of significant PVs
connected to the system.
Index Terms- Dynamic Stability, Renewable Integration, Solar
PV, Voltage Stability.
I. INTRODUCTION
With the continuous increase in electric load, power
generation must increase with a similar rate to keep up with the
demand. In the last few decades, the sources of power
generation were mainly coal, nuclear, and natural gas. In recent
years, however, it has become mandatory to include a
percentage of clean electric power generation. The Department
of Energy has set requirements by 2030 to use renewable
resources that do not produce harmful by-products, like C02,
coal ash and nuclear waste [I]. There are many ways to convert
renewable energy to electricity. These are mainly seen as
hydropower, wind, biomass and solar generation. While other
sources of renewable energy resources can be more efficient,
solar energy can be optimum to use in certain locations when
the amount of sun radiation is high and the price of land is
relatively inexpensive. One of the ways to convert solar
radiation into electricity can be done using Photovoltaic (PV)
cells. PV cells can convert solar radiation into DC electricity,
which then can be converted to AC through inverters before
integrating it to the grid [2].
Owing to the EPA regulations [3], utilities are driven to
heavily reduce their carbon footprints. In the case of Dominion
VA Power, this drive is further fueled by a 30% tax credit for
solar developers. Thus, a lot of distribution and transmission
interconnected PV is expected. To get the maximum economic
benefits from PV, it seems attractive to displace the more
expensive peaking units with it. While being an economically as
well as environmentally justifiable option, this could lead to
serious reliability concerns, one being the dynamic VAR
supports from the displaced units. In a practical system, most of
the big generators are connected at higher kV levels making the
sharing of real and reactive resources possible over longer
distances. PV inverters can provide reactive support. Yet, the
978-1-5386-1539-3/17/$31.00 ©20171EEE
PVs are being connected at a lower voltage level due to cheaper
interconnection costs and smaller commissioning times. Thus,
displacing conventional units at high kV levels with PVs at
lower kV levels will result in the reactive power from these
resources to be shared locally and not with the rest of the system.
Thus, it becomes necessary to study the voltage stability impact
ofPV.
The authors in [4] investigated the impact ofPV generation
on small signal stability as the dynamic characteristics of PV
are dominated by the inverter. The authors in [5, 6] showed how
the system transient stability becomes more vulnerable to
problems with higher levels of PV penetration. The authors in
[7] discuss the impact of large scale PV on static voltage
stability. Steady-state power flow analysis in not enough to
capture the complete phenomenon of voltage stability,
especially with the growth of dynamic loads (more will be
discussed in section III). The impact of PV integration on static
and dynamic voltage stability with effects of meteorological
factors has been addressed in [8]. This paper comes to study and
emphasize the impact ofPV integration at transmission level on
power system dynamic voltage stability, which has not been
addressed.
The outline of the paper will be as follows. In section II we
discuss the index we used for voltage stability, which namely is
Transient Voltage Stability Index. Section III describes the
dynamic models we used for solar PV and load in our studies.
In section IV we describe the process of how PVs have been
integrated to the system and show the results we obtained for
our case studies. Then the paper will be wrapped up with
conclusions and future work in section V.
II. SHORT TERM VOLTAGE STABILITY INDEX
Since we are studying the impact ofPVs on voltage stability,
it is important to set indices to measure the effects that PV s
leave on voltage stability of the power system. Thus, we use the
Transient Voltage Stability Index.
Transient Voltage Stability Index (TVSI), which has been
proposed by authors in [9], to quantifies the transient voltage
performance of the system buses following a clearance of a
disturbance. TVSI can be calculated using the formula in (1).
TVSI =
"N " T
-'"'=l-'"t=Tc TVDI',.t
NX (T - Tc )
(1)
where N is the total number of buses in the system, T is the
simulation time frame, Tc is the fault clearing time and TDVI
is the transient voltage deviation index, defined in (2).
TDVli,t =
(IVi,Vit-Vi.o .ol, if IVi,Vit-Vi.o .ol
0,
2::
15
otherwise
where V;.[, t is the voltage magnitude of bus i at time t and 0 is
(fault for example), induction motors slow down and in extreme
cases stall, which is marked by a rapid increase in reactive power
consumption. This will depress the voltage further and interfere
with voltage recovery. In extreme cases this could lead to a
collapse [12]. The need for including a dynamic component in
loads to truly simulate the system trajectory during collapse was
first presented in [13]. The problem ofFIDVR is not pronounced
in our test system so a PSS\E standard complex load model
CLODZN was used with 50 % constant current and 50% large
induction motor as used in planning studies.
the threshold for unacceptable voltage deviation level. Hence,
TVSI accounts for the buses with unacceptable violation during
the transient period in addition to the magnitude and the
duration of the violation. Therefore,
it can provide a
quantitative comparison of the system transient voltage
performance following a disturbance. A smaller TVSI value
means the transient voltage performance is better.
Large
Motors
III. DYNAMIC MODELS
A.
Solar PV Model
Discharge
Lighting
Transfonner
Saru£atiOll
Figure 2 CLODZN Load Model
For simulating the dynamic behavior of PV in our studies,
we use the PSS\E's [10] generic PV model with the default
parameters. The model comprises of four modules as shown in
Fig. I.
Figure 1. PSS\E PV Model
The irradiance module contains the data for irradiance levels
at different times, and is useful for studying the effect of cloud
cover. In the present work, we keep the irradiance fixed. This is
followed by the PV panel model that maps the irradiance level
to the maximum DC output power that can be extracted. Here it
should be noted that this assumes the maximum power point
tracking dynamics to be non-existent. The DC output power
serves as the input to the inverter and its controls, which are the
same as type 4 wind generator model.
Low voltage ride through [11] is an inherent feature of this
model. However, it remains connected regardless of the fault
duration which is somewhat unrealistic. However, since we are
more focused on the issue with displacement of dynamic VAR
support, this will still give insight, though a bit optimistic.
B.
Sma11
Motors
Load Model
Voltage stability used to be studied through power flow
simulations only, which consisted of predicting the closeness to
the nose of the PV curve or the bifurcation point. With the
increase in air conditioning loads which are majorly induction
motors, the industry was compelled to study voltage dynamics.
The reason being that in the case of a depressed voltage event
IV. RESULTS
A.
Creation a/Case Studies
The 2019 Summer Peak Eastern Interconnection planning
model was used for our studies to begin with. Only the
Dominion VA Power territory was focused on with 3015 MW
PV added with multiple parameters varied to derive multiple
cases. PV was added to the two transmission zones with lowest
land prices and land availability. The amount ofPVs connected
is 800 MW to zone 4 and 2215 MW to zone 7.
In order to study the impact of having voltage support from
the PVs, two sets of cases were created with same amount of
PV added to the 230 kV and 115 kV buses, respectively. The
interconnection buses in both cases were chosen such that a 230
kV PV bus would have a counterpart 115 kV bus at the same
substation or at most one substation away. This was done to
highlight the region of influence of grid support from PV when
connected at two different voltage levels. As discussed before,
the PV with grid support was modeled as operating in a voltage
control mode with ± 0.95 power factor while lack of grid
support was unity power factor.
Now, to study the impact of displacing VAR resources, the
amount of MW displacement per MW PV added was varied.
This idea was introduced in [14] and was referred to as
displacement ratio.
A displacement ratio of 20% meant 0.2 MW of conventional
generation is displaced for every 1 MW of PV added to the
system. The remaining 0.8 MW is accommodated by re­
dispatching the rest of the units. The amount of Mvar displaced
per zone in our studies is shown in Table I. In the case of
Dominion VA Power, the base load units (mainly coal and
nuclear) were left untouched while the rest of the units were
displaced based on a priority order that was totally driven by
cost. This was done to somehow approximate the market
operation. Once the units were displaced according to the
priority order, rest of the non-base load units have their outputs
scaled down uniformly. The cases of 0 and 1 displacement
ratios are studied in this work.
Table I Mvar displaced per zone
Zone
Mvar Displaced
1
2
138
165
198
3
4
6
23
87
102
7
8
135
103
5
The cases created for our study are summarized in Table [I.
Three variables were studied namely: PV kV level, presence of
grid support and displacement ratio.
Table II Case Studies
Case
1
2
3
4
1
2
3
4
PV
Level
230
230
230
230
ll5
liS
ll5
ll5
kV
Grid
Support
N
Y
N
Y
N
Y
N
Y
Displacement
Ratio
0
0
I
1
0
0
1
1
First, we want to see the impact of different displacement
ratios on the system voltage response, without the presence of
grid support. As discussed earlier in this section, we have four
cases for each voltage level. TVS[ for all cases forPV at 115 kV
level and 230 kV level are shown in Fig. 3 and 4, respectively.
It can be noticed that displacing generators can have a negative
impact on the voltage stability. By comparing the displacement
ratios, with and without grid support (blue vs. grey and orange
vs. yellow, respectively), it can be seen that the system has
mostly higher TVSI, which translates into worse voltage
recovery of the system. This can be related to the fact that while
displacing conventional generation for PV MWs, the system
loses their reactive support as well. This has been noticed when
connecting PVs on either 115 or 230kV substations.
For those faults where the system TVSI had small to no
impact (faults 1, 2 and 10), this can be explained as these faults
occur in zones where small to no displacement happened (zones
5 and 9). When no generators are displaced from a certain zone,
it will maintain its reactive support. This will be seen in the
voltage response of the system after a disturbance, as it remains
unaltered or slightly affected.
160
Vi
C.
Simulation Results
Using TVS[ discussed in section III, we were able to see that
impact of different setting ofPV on the dynamic voltage stability
of the system. The value for 8 is 5% pu, thus treating any value
above 1.05pu or below 0.95pu as a voltage violation.
• 1disp 0 grid
.1 disp 1 grid
100
80
Fault Locations
To study the dynamic voltage stability, we simulated faults
of 150ms and recorded the voltage response across the system
for 5 seconds. The process of selecting fault locations was as
follows. First, we acquired an idea of each bus's reactive power
basin in the original system. This was done by using a Q-V curve
stress test which has been proposed in [15]. This test identifies
all ioss-of-voitage-control and clogging-voltage instabilities due
to shortage of reactive power supply. The output of the stress
test is a set of generators associated with each bus. These
generators had their reactive limit exhausted trying to save the
bus from the voltage collapse. These generators make up the
reactive reserve basin (RRB) for that bus. Secondly, this set of
generators was cross listed with the generators displaced byPV.
Thirdly, buses across the Dominion system are ranked based on
the percent of their RRB overlaps with the displaced generators.
A bus with its whole RRB displaced is at the greatest threat of
voltage collapse. We selected the top 10 buses based on the
ranking to study the faults at. For each bus fault, the line
connected to it with the least impedance is chosen to be tripped
when clearing the fault. This has been done to study the faults
most likely to lead to a collapse.
.0disp 1 grid
120
i::
B.
.0dispOgrid
140
60
I I ,� I I HI
40
20
0
1111
1111
4
1111
Fault
••••
7
10
Figure 3: TVSI for Different Faults for 230kV PV Connection
160
.0 disp Ogrid
140
.Odisp 19rid
120
a1disp 1arid
.1 disp 0 grid
Vi
i::
100
80
60
40
20
0
III
11I1
III
I � I� I � I I
••••
Fault
10
Figure 4: TVSI for Different Faults at 115 kV PV Connection
[t can also be noticed that even the presence of grid support
is not sufficient to counter the effect displacing conventional
generators and losing their reactive support. When PV inverters
provide reactive support, regardless of the voltage level, the
voltage response of the system improves slightly but not enough
(comparing blue vs. orange and grey vs. yellow). This could be
attributed to the fact that a solar developer doesn't necessarily
choose a site based on system reliability. PV locations are
mainly chosen based on land availability and prices while the
generator displacement is driven by operation costs and
environmental concerns which do not necessarily result in the
same location. Thus, the PVs interconnected in our case are not
electrically close to the displaced generators.
To have a closer look at the voltage response of the system,
a comparison between two displacement ratios for the faulted
bus of fault 3 in zone 2 is depicted inFig. 5. We can see how the
voltage response has a larger overshoot and larger oscillations
for 100% compared to 0% displacement. It can be observed that
the voltage response for a higher displacement ratio shows a
higher voltage deviation after disturbance.
l.15 '
1=
'---'=======::;-J
�
--
---�---
.
DR=O.O. GS=O
DR=1.0. GS=O
l.10
I
•
140
_230 kV
_115 kV
120
100
8
0
Vi
60
i::
Il.dlll 1111
40
20
0
II
I.
4
Fault
8
6
••
9
10
Figure 6: TVSI for PV Connected to 230kV vs. ll5kV for Case 2.
160
140
120
100
�80
0
6
40
..9>
�
2
1.05
0
0
II
II
5
l.00
••
8
Fault
10
Figure 7: TVSI for PV Connected to 230kV VS. 115 kV for Case 4
0 .9 �.'oo0
--'--c0�
. O--
--
2
�
0.7
--
4
----;o�; .6
--
Time (5)
�.0B c;--
---
�l.0
--
Figure 5: Voltage Response for different Cases of PV Connection at 230kV
for Fault 3
In this another analysis, the results between the integration
of PV at 115kV against 230kV at the same substations are
compared. We noticed that the system has a better voltage
response given PV inverters are providing grid support,
regardless of the dispatch ratio. The results are shown in Fig. 6
and 7 for cases 2 and 4 comparing TVSI for PVs at 115kV vs.
230kV substations, respectively. It can be seen that the TVSI
had larger values for almost all faults for PVs connected to
115kV compared to 230kV. This can be related to the transfer
of reactive power through the system. Here it should be noted
that the transformer impedance plays a key role in limiting the
flow of reactive power fromPVs to the rest of the system. When
PVs are connected at a higher voltage level, the reactive power
they provide can be shared across the system in a better way.
Lines around the system tend to have smaller impedances at
higher voltage levels, compared to lower voltage levels.
We also compare the voltage response of the faulted bus of
fault 8 in zone 3 for different voltage levels. The results are
shown in Fig. 8. We can notice that the voltage showed a better
response when PVs are connected 230kV compared to 115kV.
This result also emphasized the impact of different voltage level
ofPV connection on the dynamic voltage stability of the system.
l.10 '
1-
l
�====J
--�---�---�--
-
230kV
115kV
l.05
� 1.00
>
0.95
0.9 'C.';;-0
--'---c 0�.2;--
--
�0.';-4 ------Oo';;
-; .6=--�0.;;-B ------1.-,J 0
--
Time (5)
Figure 8: Voltage Response for Case 3 Fault 8 at Different kV Level
V. CONCLUSION
This paper discusses the impact of integrating large amount
of solar PV on the dynamic voltage stability of power system.
The paper demonstrates how displacing conventional
generators, compared to only re-dispatching, can have a
significant negative impact on the voltage stability of the system.
This is because when generators are displaced (shutdown), we
lose the reactive power support they used to provide.
While PV inverters can provide reactive power, the support
they can provide is limited because PVs are being connected at
low voltage levels. This has been established by comparing
different cases where PVs were connected to 115kV against
230kV buses. Lines at lower voltage levels have larger
impedances than higher voltage levels. This will result in a
bottleneck when the reactive power is needed in a distant
location across the system. In addition, PVs sites are not located
in the same place where conventional generators are being
displaced. This will cause a problem as the reactive power
provided byPVs will have a local region of intluence and not be
able to support the whole system as conventional generators
used to.
Part of the future work is to investigate the impact of Low
Voltage Ride Through (LVRT) capability of PV inverters on
dynamic voltage stability.
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