Content uploaded by Edgardo Desarden
Author content
All content in this area was uploaded by Edgardo Desarden on Nov 02, 2021
Content may be subject to copyright.
Analysis of Grid Support Functionality Dynamics Under Ride-Through
Requirements Using Power-Hardware-in-the-Loop Implementation
Edgardo Desarden-Carrero1, Rachid Darbali-Zamora2, Erick E. Aponte-Bezares1
1University of Puerto Rico-Mayagüez, Mayagüez, Puerto Rico 00682, USA
2Sandia National Laboratories, Albuquerque, New Mexico, 87185, USA
Abstract – Due to the increased penetration in Distributed Energy
Resources (DERs), especially in Photovoltaic (PV) systems, voltage
and frequency regulation has become a topic of interest. Utilities
have been requesting DER voltage and frequency support for
almost two decades. Their request was addressed by standards
such as the IEEE Std 1547-2018. With the continuous
improvements in inverters’ ability to control their output voltage,
power, and frequency, a group of advanced techniques to support
the grid is now required by the interconnection standard. These
techniques are known as Grid Support Functions (GSF), and they
allow the inverter to provide voltage and frequency support to the
grid as well as the ability to ride-through abnormal events.
Understanding how a GSF behaves is challenging, especially when
multiple GSFs are combined to help the utility to control the
system voltage and frequency. This paper evaluates the effects of
GSF’s on the IEEE Std 1547.1-2020 Unintentional Islanding Test
5B by comparing simulation results from a developed PV inverter
model and experimental results from a Power Hardware-in-the-
Loop platform.
Index Terms – photovoltaic inverter, grid support functions,
ride-through, Power-Hardware-in-the-Loop.
I. INTRODUCTION
Grid Support Functions (GSF) are advanced modes of
operation that allow Photovoltaic (PV) inverters to provide
support to the grid under abnormal voltage and frequency
conditions. GSFs provide a benefit to both grid voltage and
frequency stability while at the same time reducing the need of
costly grid upgrades [1], [2]. However, GSFs can cause
deviation in voltage and frequency during ride-through
operations [3]. Also, variation in voltage and frequency during
the ride-through process can make islanding detection more
difficult for PV inverters. As a result, the Unintentional
Islanding (UI) detection time can be longer or undetectable in
some cases [4], [5]. The IEEE Std 1547.1-2020 Cat. B UI test
requires PV inverters to operate in combinations of different
GSFs in a variety of modes of operation to test PV inverter UI
detection performance under different conditions [6], [7], [8].
II. REACTIVE POWER MODES
Reactive power support can provide grid voltage stability.
Multiple reactive power modes are mandatory in IEEE Std
1547-2020. The reactive power mode can be set to Constant
Power Factor (CPF), Volt-Var Control (VVC), Watt-Var
Control (WVC), and Constant Reactive Power (CQ) [2]. Only
VVC and WVC can be set to their default settings or aggressive
mode. The continuous adjustment of active and reactive power
depending on the voltage, frequency, and active power in the
Point of Common Coupling (PCC) can lead the system to
voltage and frequency oscillations that could exceed the PV
inverter tripping point setting. The IEEE Std 1547-2020
requires a unity constant power factor mode to be the default
settings of any installed PV inverter until the electric power
source operator specifies different conditions [6].
A. Constant Power Factor (CPF)
The CPF mode sets the PV inverter to operates at the same
level of real and reactive power delivered. This is independent
of the amount of energy supplied by the PV inverter [9]. The
maximum allowable response time for the equipment under test
to maintain constant power is 10 s or less [7].
B. Constant Reactive Power (CQ)
In the CQ mode, the PV inverter must maintain constant
reactive power no matter what has been specified (injection or
absorption mode) by the utility operator [6]. The CQ mode
lacks accuracy for voltage regulation and in some cases tends
to unnecessary reactive power absorption [10], [11].
C. Volt-Var Control (VVC)
The VVC allows a PV inverter to provide reactive power
based on the PCC’s voltage measurements [12]. Thus, a VVC
is a relationship between voltage and reactive power. PV
inverters can absorb or inject reactive power to improve voltage
stability [13], [14]. The voltage stability is achieved by either
utilizing excess capacity not being used for real power or
reducing real power and allowing reactive power generation.
Fig. 1shows the VVC characteristic curve as a linear function
that controls the reactive output power based on the PV
inverter’s voltage.
D. Active Power-Reactive Power Control (WVC)
The WVC dynamic power reference mode is another
technology that achieves voltage regulation [15]. In this mode,
the PV inverter controls the reactive power output dynamically
as a function of active power. Fig. 2 shows the WVC
characteristic curve for the UI Test. This test has two modes of
operation: Default (DFLT) and Most Aggressive (MA).
Fig. 1. Volt-Var Control Characteristic Curve.
978-1-6654-1922-2/21/$31.00 ©2021 IEEE
1795
2021 IEEE 48th Photovoltaic Specialists Conference (PVSC) | 978-1-6654-1922-2/21/$31.00 ©2021 IEEE | DOI: 10.1109/PVSC43889.2021.9518679
Fig. 2. Watt-Vars Control Characteristic Curve.
III. ACTIVE POWER MODES
The active power mode uses the grid voltage and frequency
information to generate an active power reference for the PV
inverter [6]. These active power techniques have been designed
to facilitate the high integration of DERs. This mode has two
options available: Volt-Watt Control (VWC) and
Frequency-Watt Control (FWC) [7].
A. Volt-Watt Control Mode (VWC)
In the VWC, the input for the control is the grid voltage, and
the control action is the active power reference from the VWC
function [16]. Fig. 3 shows the VWC power characteristic curve
for the UI test.
B. Frequency-Watt Control Mode (FWC)
In the Frequency-Watt Control (FWC), the control input is
the grid frequency, and the control action is the active power,
as shown in Fig. 4. In this function, the inverter’s active power
is controlled based on a Frequency-Watt droop function that
causes the inverter to share a portion of the load change, thereby
supporting the grid [17], [18].
IV. RIDE-THROUGH SCENARIO
Due to the increase in DER penetration levels, many utilities
depend on PV systems to maintain grid stability. The
IEEE Std 1547-2018 specifies the mandatory, uniform, and
universal requirements at the PCC when interconnecting a PV
inverter to the grid. The IEEE Std 1547-2108 requires an island
detection disconnecting time of less than 2 s but now requires
mandatory ride-through operation for PV inverters with that
capability. The mandatory procedure specifies that PV inverters
must stay connected and actively regulate voltage and
frequency at the PCC, riding through abnormal voltage and
frequency conditions [19].
Fig. 3: Volt-Watt Control Characteristic Curve
Fig. 4. Frequency-Watt Control Characteristic Curve.
To effectively regulate voltage and frequency at the PCC, the
PV inverter depends on GSFs. GSFs can be combined to allow
a PV inverter to control both voltage and frequency at its PCC.
The GSFs response time can also be adjusted in different
aggressiveness mode levels; Less Aggressive (LA), DFLT, and
MA. Response time is defined as the duration for the PV
inverter to increase or decrease its output power from 0% to
90%. The IEEE P1547 UI Test specifies the response times as
10 s for LA, 5 s, and 10 s for DFLT, and 1 s for MA. Fig. 5
shows a PV inverter’s active power adjusted in LA, DFLT, and
MA modes. PV inverters at different GSFs aggressiveness
levels can support the utility under abnormal voltage and
frequency situations. However, when PV inverters are
connected to a high fluctuating bus, special considerations must
be given when setting GSFs at MA. The high voltage and
current fluctuation in the bus combined with GSFs at MA can
push PV inverters to exceed its tripping limits, causing them to
disconnect or to go into momentary cessation. This condition
could represent more instability to the system due sudden
increase in the load.
V. IMPLEMENTING GRID SUPPORT FUNCTIONS
Different approaches can be implemented to enable PV
inverters with GSF control. An effective method to implement
GSF control is by using the control tables specified by the IEEE
in Fig. 1 through Fig. 4 to help set the trigger points in the
controller depending on the GSF implemented. Once the
controller is triggered, it will begin to increase or decrease the
active or reactive power based on the controlled variable in the
control curve. The response time in which the output power will
be increased or decreased will be specified with the mode of
operation (LA, DFLT, MA), as shown in Fig. 5. Many inverter
manufacturers rely on using ramps to control the inverter’s
output power through GSFs.
Fig. 5. Different Response Times as Specified in the IEEE Std 1547.1
978-1-6654-1922-2/21/$31.00 ©2021 IEEE
1796
In order to implement this concept in a simulation tool, it is
necessary to sample and capture the time duration produced by
the control ramp. The ramp slope will be controlled with a gain
block, and the output power will be accumulated and stored, as
shown in Fig. 6.
VI. TEST SCENARIO WITH POWER-HARDWARE-IN-THE-LOOP
There are guides and parameters of operation specified by the
IEEE to develop a GSF model, but there is no specific approach
to mathematically represent them. An approach is to model the
system using GSFs regulation and compare the results with
experimental results obtained from testing commercially
available devices. When similar behavior is achieved, it is
possible to optimize the GSF control of the model.
Results for the IEEE Std 1547.1 UI Test 5B are obtained for
a commercially available PV inverter using a Power-Hardware-
in-the-Loop (PHIL) platform [20], [21]. The PV inverter is
tested operating with GSFs (VVC, FWC and VWC set to
DFLT) [22]. In test 5 the PV inverter is connected to the grid in
parallel with a RLC load. The parallel RLC load is intended to
absorb the entire PV inverter capacity with active power and
nonreactive power.
Test 5B is performed in the three different modes (DFLT,
LA, MA) to assess the control performance of the GSFs in
different scenarios. An unbalanced reactive power of (a total of
2.3 kVars and 767 Vars per phase) is added to the load to
recreate the same initial conditions of Test 5B performed with
PHIL platform. This initial unbalance will also force the GSFs
to start operating immediately after de islanded condition is
created at 1 s. The IEEE standard specifies that UI tests
implemented with PHIL techniques should be sustained for at
least 10 s in island mode with the inverter UI detection option
disabled. The developed model must comply with the exact
requirement of time to be reliable. Implementing a GSF is
necessary to have a PV inverter model that operates similar to
commercially available PV inverters, regulating voltage and
current when islanded. One alternative in developing a PV
inverter model is to use the Simulink dynamic load model.
OR
CLOCK
S/H
In Out
S
T
F
Switch
IncRamp
DecRamp
SUB
+
-
T
F
Switch
-0.9 Sat
In Out
-1 to 1
÷
DIV
RampOut
EnableOut
-1
== -1
-1
1
== 1
Mode
MUL
MUL
2
ADD
+
+
+1
2
3
Multi
Switch
10
5
1
(a)
S/H
In Out
S Delay
In Out ADD
+
+Sat
In Out
Pout
Min Max
EnableIn
RampIn
Pout_Initial
PoutINV
(b)
Fig. 6. Simulink Output Power and Ramp Control. (a) Increment and
Decrement Ramp. (b) Memory to Hold Accumulated Power.
Source
Impedance
Voltage
Source Three
Phase
PV
Inverters
RLC
Load
Three
Phase
Breaker
PCC
Fig. 7. Model of the Unintentional Islanding Test.
In order for the dynamic load model to operate as a power
source, the active and reactive power setpoint are defined as
negative values. The dynamic load is designed to regulate
voltage, current, power, and frequency when connected at the
PCC during the islanding test. It is important to note that the
dynamic load model only operates as a power source and does
not include islanding detection or the ability to execute UI
disconnection. The model of the UI test is illustrated in Fig. 7.
VII. POWER-HARDWARE-IN-THE-LOOP GSF VALIDATION
This test has been performed in a PHIL system with a
commercially available PV inverter. The parameter to test PV
inverter in DFLT mode performance are shown in Table I.
TABLE I:
GSFS CONTROL PARAMETERS - DFLT MODE
GSF
Parameter
Action
Response Time
FWC
F ≤ 59.964 Hz
Increase P
0.9/5 (Ppu/s)
F ≥ 60.036 Hz
Decrease P
0.9/5 (Ppu/s)
VVC
VL ≤ 271 V
Increase Q
0.9/10 (Qpu/s)
VL ≥ 283 V
Decrease Q
0.9/10 (Qpu/s)
VWC
VL ≥ 293 V
Decrease P
0.9/10 (Ppu/s)
The UI detection and mitigation option in the inverter was set to “OFF”
In order to control the system’s voltage and frequency
response, the PV inverter operates at a specified deadband.
When the parameters are outside their respective deadband, the
system controls one variable at a time. Fig. 8 shows the results
for IEEE Std 1547.1 test 5B in DFLT mode implemented with
PHIL. Voltage and frequency deadbands are shown with
dashed horizontal lines (identified in the same color as the
waveforms scale). Notice that the settings for the frequency
deadband force the frequency waveform to operate at 60 Hz.
The test illustrated in Fig. 8 demonstrates that the PV inverter
has been initially programmed to only supply active power
without supplying any reactive power. However, these two
quantities will change as the GSFs take control. The parallel
RLC load absorbs the full PV inverter capacity as active power
(24 kW Total, 8 kW per phase). The RLC load’s reactive power
is not ideally tunned in resonance. This means the utility is
supplying reactive power (a total of 2.3 kVars and 767 Vars per
phase) to compensate.
978-1-6654-1922-2/21/$31.00 ©2021 IEEE
1797
(a)
(b)
Fig. 8. IEEE Std 1547 UI Cat B. Test 5B Implemented with PHIL (VVC, FWC and VWC).
(a) Power at Load. (b) Load Voltage and Frequency.
The supplied reactive power provided by the utility will act
as an unbalance initial condition that the GSFs will try to
regulate into the control deadbands after the system is islanded
after 1 s. The islanded signal is shown as a dotted magenta
vertical line in 1 s. Fig. 8 (b) shows that after 1 s, the system is
islanded and the frequency value is outside the deadband. From
1 s to 2.1 s, the system is able to control the frequency. At 2.1 s
the frequency returns into the deadband, and the frequency
control stops. At this point, the voltage parameter is outside the
deadband. From 2.1 s to 2.9 s, the system controls the voltage
and regulates it into the deadband at 2.9 s. Table II summarizes
the PV inverter GSF control throughout the test period.
TABLE II:
ENABLED GRID SUPPORT FUNCTION CONTROL SETTINGS
Start Time (s)
End Time (s)
Enabled Control
2.9
4.5
Frequency
4.5
5.6
Frequency
5.6
6.6
Voltage
6.6
8.3
Frequency
8.3
9.5
Frequency
9.5
10.0
Voltage
Notice that when the frequency control is repeated at small
time period, both parameters are in control. Due to the restricted
frequency range, the system returns to frequency control
immediately. At 4 s and 7.8 s, when the system’s active power
is almost equal to the system’s apparent power, the reactive
power is close to zero due to the PV inverter operating at
maximum capacity. When the frequency changes from
increasing to decreasing, the voltage is at the lower limit of the
deadband, and a spike in signals is observed, caused by the
activation of the VVC. With these plots showing the behavior
of power, voltage, and frequency in test 5B when implemented
with PHIL techniques, it is possible to develop a simulation
model with GSF control.
VIII. MATLAB/SIMULINK MODEL RESULTS
A. IEEE Std 1547.1 Cat B UI Test 5B (Mode: DFLT)
Fig. 9 shows the results of test 5 implemented in Simulink.
Notice that there are similarities when comparing Fig. 8 with
the results from Fig. 9. Two more plots were added to analyze
the behavior and performance of GSFs. Fig. 9 (c), indicates
when the system has enabled voltage control or frequency
control, and Fig. 9 (d) illustrates how the system manages the
real and the reactive power. This is an indicator that the
designed GSFs are operating as desired.
In Fig. 9 (b), when the model goes into an islanded state after
1 s, the amount of reactive power supplied by the utility should
be handled by the PV inverter. To fulfill test 5B, the amount of
reactive power provided by the PV inverter should be zero. The
PV inverter achieves this requirement by increasing the
frequency achieve a resonance state which forces the demanded
reactive power to zero. The load frequency is incremented by
the PV inverter from 60 Hz to 62 Hz to reach resonant state.
From the results shown in Fig. 9 (a), at 1.1 s, the resonance
effect can be observed when the reactive power reaches zero
after the island condition at 1 s.
Immediately after the island condition in 1 s, the frequency
increases. It can be observed in Fig. 9 (c) and Fig. 9 (d) that the
FWC is activated when the frequency control signal is too high,
indicating the frequency needs to be modified. As shown in
Fig. 9 (d), from 1 s to 1.8 s, the FWC starts reducing the active
power and increasing the reactive power to reduce the
frequency to its nominal levels. A reduction in active power
will cause the system voltage to decrease. Decreasing the
system voltage will cause a reduction in the reactive power at
the load. Therefore, the PV inverter will reduce the system
frequency to match the drop in reactive power. At 1.7 s the
frequency returns to its nominal value, but the voltage moves
outside the deadband.
978-1-6654-1922-2/21/$31.00 ©2021 IEEE
1798
(a)
(b)
(c)
(d)
Fig. 9. IEEE Std 1547 UI Cat B. Test 5B Implemented with MATLAB/Simulink (VVC, FWC and VWC set to DFLT).
(a) Power at Load. (b) Load Voltage and Frequency. (c) Control Areas. (d) Inverter Output Power Levels.
As a result, the voltage control indicator becomes 1, which
means the system voltage needs to be adjusted, as shown in
Fig. 9 (c). Results from Fig. 9 (d) illustrate that The VVC starts
increasing the active and reactive power at 1.7 s until the system
voltage returns to the control deadband area at 2.3 s.
When the VVC increases the reactive power, the system
voltage increases as well, and the system frequency decrease to
match reactive power. This reduction in frequency will trigger
the FWC at 2.3 s, increasing the active power, and decreasing
the reactive power increase the system frequency. At 2.5 s the
system still needs to increase the frequency, but the PV inverter
is approaching its maximum capacity. The FWC sets the active
power to zero at 2.5 s to avoid an overload condition but
decreases the reactive power to achieve the frequency deadband
at 2.7 s. After this point, the GSFs repeat the same behavior
every 1.78 s. Test 5B in DFLT mode never increases the system
voltage over 293 V or 1.06 pu. For this reason, the VWC
illustrated in Fig. 3 never activates during this test.
B. IEEE Std 1547.1 Cat B UI Test 5B (Mode: LA)
The LA mode operates at the slowest response time. This
mode tends to be a stable control because of its wider
deadbands and longer response time. The parameters to test PV
inverter in the LA mode performance are shown in Table III.
TABLE III:
GSFS CONTROL PARAMETERS - LA MODE
GSF
Parameter
Action
Response Time
FWC
F ≤ 59.00 Hz
Increase P
0.9/10 (Ppu/s)
F ≥ 61.00 Hz
Decrease P
0.9/10 (Ppu/s)
VVC
VL ≤ 271 V
Increase Q
0.9/10 (Qpu/s)
VL ≥ 283 V
Decrease Q
0.9/10 (Qpu/s)
VWC
VL ≥ 293 V
Decrease P
0.9/10 (Ppu/s)
Fig. 10 shows the results for the LA case. Notice from Fig. 10 (b)
that after the island is formed at 1 s, both voltage and frequency
were in control inside their respective deadbands.
978-1-6654-1922-2/21/$31.00 ©2021 IEEE
1799
(a)
(b)
(c)
(d)
Fig. 10. IEEE Std 1547 UI Cat B. Test 5B Implemented with MATLAB/Simulink (VVC, FWC and VWC set to LA).
(a) Power at Load. (b) Load Voltage and Frequency. (c) Control Areas. (d) Inverter Output Power Levels.
Fig. 10 shows the results for the LA mode. Notice in
Fig. 10 (b) that after the island is formed at 1 s, both voltage
and frequency were in control inside their respective
deadbands. At 1.1 s the frequency goes out its deadband, and
the system performs a frequency control procedure until 1.6 s.
At 1.6 s the voltage is outside of its deadband and the VVC
performs a voltage control operation until 1.7 s. Notice that the
system reaches a stable state at 1.7 s; after that point, the system
remains in a stable state until reaching 10 s. As illustrated in
Fig. 10 (b), the wide range in the voltage deadbands (10 V
range) in combination with the wide range in the frequency
deadband (2 Hz range) produces a wider equilibrium area for
the GSFs controls.
C. IEEE Std 1547.1 Cat B UI Test 5B (Mode: MA)
When the GSF is set to MA mode, it represents the most
challenging scenario to maintain the PV inverter operating in a
stable state. The challenge for PV inverters is to attempt to
maintain voltage and frequency under normal conditions
adjusting the real and the reactive power within 1 s of reaction
time. Stability in the MA mode dramatically depends on the
load when the PV inverter is islanded. When the PV inverter is
connected to the grid, the PV inverter operates stable due to the
grids stiffness and support. However, a significant oversight in
detecting an island condition arises when the PV inverter is
operating, providing support to the grid through ride-through
actions and GSFs. The parameters to test the PV inverter
performance in the MA mode are shown in Table IV.
TABLE IV:
GSFS CONTROL PARAMETERS - MA MODE:
GSF
Parameter
Action
Response Time
FWC
F ≤ 59.983 Hz
Increase P
0.9/10 (Ppu/s)
F ≥ 61.017 Hz
Decrease P
0.9/10 (Ppu/s)
VVC
VL ≤ 277 V
Increase Q
0.9/10 (Qpu/s)
VL ≥ 277 V
Decrease Q
0.9/10 (Qpu/s)
VWC
VL ≥ 291 V
Decrease P
0.9/10 (Ppu/s)
978-1-6654-1922-2/21/$31.00 ©2021 IEEE
1800
(a)
(b)
(c)
(d)
Fig. 11. IEEE Std 1547 UI Cat B. Test 5B Implemented with MATLAB/Simulink (VVC, FWC and VWC set to MA).
(a) Power at Load. (b) Load Voltage and Frequency. (c) Control Areas. (d) Inverter Output Power Levels.
Fig. 11 illustrates the results obtained for the MA case
scenario. Notice from the results Fig. 11 (a) through Fig. 11 (d)
that there is noticeably shorter response times for this mode of
operation. This rapid control scheme, in combination with an
RLC load that is not in perfect balanced resonance,
demonstrates that the system has considerably more
oscillations.
The results presented in Fig. 11 (c) illustrate that there is a
pattern of three control areas that are repeating every 0.8 s. This
short time in the pattern repetition reflects a stabilized system
even though it could have larger oscillations. Fig. 11 (a)
illustrates that there’s an average of 4 kVars of oscillations in
this mode of operation. Also, these results demonstrate that the
active power is reduced from 8 kW to 5.5 kW. This
considerable oscillation in power is reflected in significant
voltage and frequency variations. The terminal voltage
illustrates a drop of 40 V while the frequency magnitudes vary
5 Hz from the nominal 60 Hz.
IX. CONCLUSION
IEEE Std 1547.1 stipulates the requirements for the GSFs
operation, but there is not a specific technique or approach to
implement GSFs for a PV inverter. This paper evaluates GSF’s
effects on the IEEE Std 1547.1-2020 UI Test 5B implemented
using a PHIL platform. Using a simulation model of a PV
inverter with programed GSFs a comparison between simulated
and experimental results is illustrated. A simulation model with
different GSFs is programmed and implemented to represent
and help study the effect of GSFs in the stabilization of voltage
and frequency in distribution systems. Also, the simulation
model is able to test how GSFs impact the islanding detection
in PV inverters. This model provides an understanding into
GSFs operations as well as insight into PV inverter control
dynamics for maintaining voltage and frequency stability.
PHIL results illustrate how the PV inverter is able to both inject
and absorb both active and reactive power to regulate voltage
and frequency.
978-1-6654-1922-2/21/$31.00 ©2021 IEEE
1801
ACKNOWLEDGMENT
Sandia National Laboratories is a multi-mission laboratory
managed and operated by National Technology and
Engineering Solutions of Sandia, LLC., a wholly-owned
subsidiary of Honeywell International, Inc., for the US
Department of Energy’s National Nuclear Security
Administration under contract DE-NA-0003525.
This work was sponsored in part by the Consortium for
Hybrid Resilient Energy Systems (CHRES) under grant
number DE-NA0003982 from the National Nuclear Security
Administration part of the U.S. Department of Energy.
REFERENCES
[1] Institute of Electrical and Electronics Engineers, “IEEE 1547.1‐
2020 Standard Conformance Test Interconnecting Distributed
Energy,” 2020.
[2] N. Gökmen, W. Hu, and Z. Chen, “A Simple PV Inverter Power
Factor Control Method Based on Solar Irradiance Variation”,
2017 IEEE Manchester PowerTech, 2017.
[3] S. Gonzalez, E. Desarden-Carrero, N. S. Gurule and E. E.
Aponte-Bezares, “Unintentional Islanding Evaluation Utilizing
Discrete RLC Circuit Versus Power Hardware-in-the Loop
Method”, 2019 IEEE 46th Photovoltaic Specialists Conference
(PVSC), 2019, pp. 1-8.
[4] E. Desardén-Carrero, R. Darbali-Zamora and E. E. Aponte-
Bezares, “Analysis of Commonly Used Local Anti-Islanding
Protection Methods in Photovoltaic Systems in Light of the New
IEEE 1547-2018 Standard Requirements”, 2019 IEEE 46th
Photovoltaic Specialists Conference (PVSC), 2019, pp. 2962-
2969.
[5] M. Ropp, D. Schultz, J. Neely and S. Gonzalez, “Effect of Grid
Support Functions and VRT/FRT Capability on Autonomous
Anti-Islanding Schemes in Photovoltaic Converters”, 2016
IEEE 43rd Photovoltaic Specialists Conference (PVSC), 2016,
pp. 1853-1856.
[6] Institute of Electrical and Electronics Engineers, “IEEE Std
1547-2018 (Revision of IEEE Std 1547-2003) : IEEE Standard
for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces.,”
IEEE, 2018.
[7] Institute of Electrical and Electronics Engineers, “P1547.1/D9.5
Draft Standard Conformance Test Procedures for Equipment
Interconnecting Distributed Energy Resources with Electric
Power Systems and Associated Interfaces”, 2019.
[8] E. Desarden-Carrero, R. Darbali-Zamora, N. S. Gurule, E.
Aponte-Bezares and S. Gonzalez, “Evaluation of the IEEE Std
1547.1-2020 Unintentional Islanding Test Using Power
Hardware-in-the-Loop”, 2020 47th IEEE Photovoltaic
Specialists Conference (PVSC), 2020, pp. 2262-2269.
[9] J. Seuss, M. J. Reno, R. J. Broderick, and S. Grijalva, “SANDIA
REPORT Analysis of PV Advanced Inverter Functions and
Setpoints under Time Series Simulation,” 2016.
[10] B. Craciun, D. Sera, E. A. Man, T. Kerekes, V. A. Muresan and
R. Teodorescu, “Improved Voltage Regulation Strategies by PV
Inverters in LV Rural Networks”, 2012 3rd IEEE International
Symposium on Power Electronics for Distributed Generation
Systems (PEDG), 2012, pp. 775-781.
[11] J. Johnson, A. Summers, R. Darbali-Zamora, J. Hernandez-
Alvidrez, J. Quiroz, D. Arnold, J. Anandan; “Distribution
Voltage Regulation Using Extremum Seeking Control with
Power Hardware-in-the-Loop,” IEEE Journal of Photovoltaics,
vol. 8, no. 6, pp. 1824-1832, Nov. 2018.
[12] A. Alkuhayli, F. Hafiz and I. Husain, “Volt/Var Control in
Distribution Networks with High Penetration of PV Considering
Inverter Utilization”, 2017 IEEE Power & Energy Society
General Meeting, 2017, pp. 1-5.
[13] M. G. Kashani, M. Mobarrez and S. Bhattacharya, "Smart
Inverter Volt-Watt Control Design in High PV Penetrated
Distribution Systems”, 2017 IEEE Energy Conversion Congress
and Exposition (ECCE), 2017, pp. 4447-4452.
[14] F. Ding, A. Nguyen, S. Walinga, A. Nagarajan, M. Baggu, S.
Chakraborty, M. McCarty and F. Bell, “Application of
Autonomous Smart Inverter Volt-VAR Function for Voltage
Reduction Energy Savings and Power Quality in Electric
Distribution Systems”, 2017 IEEE Power & Energy Society
Innovative Smart Grid Technologies Conference (ISGT), 2017,
pp. 1-5.
[15] Y. Liu, W. Qin, L. Dq, D. Q. J. Lqj, D. Q. J. Lei, and F. Li,
“Distribution Network Voltage Control by Active
Power/Reactive Power Injection from PV Inverters”, 2018 13th
IEEE Conference on Industrial Electronics and Applications
(ICIEA), 2018, pp. 543-547.
[16] K. Prabakar, M. Shirazi, A. Singh and S. Chakraborty,
“Advanced Photovoltaic Inverter Control Development and
Validation in a Controller-Hardware-in-the-Loop Test Bed”,
2017 IEEE Energy Conversion Congress and Exposition
(ECCE), 2017, pp. 1673-1679.
[17] D. Pattabiraman, R. H. Lasseter. and T. M. Jahns, “Comparison
of Grid Following and Grid Forming Control for a High Inverter
Penetration Power System”, 2018 IEEE Power & Energy
Society General Meeting (PESGM), 2018, pp. 1-5.
[18] R. Darbali-Zamora, J. E. Quiroz, J. Hernández-Alvidrez, J.
Johnson and E. I. Ortiz-Rivera, "Validation of a Real-Time
Power Hardware-in-the-Loop Distribution Circuit Simulation
with Renewable Energy Sources," 2018 IEEE 7th World
Conference on Photovoltaic Energy Conversion (WCPEC) (A
Joint Conference of 45th IEEE PVSC, 28th PVSEC & 34th EU
PVSEC), 2018, pp. 1380-1385.
[19] J. Johnson, J. C. Neely, J. J. Delhotal and M. Lave,
“Photovoltaic Frequency–Watt Curve Design for Frequency
Regulation and Fast Contingency Reserves”, IEEE Journal of
Photovoltaics, vol. 6, no. 6, pp. 1611-1618, Nov. 2016.
[20] R. Darbali-Zamora, J. Johnson, N. S. Gurule, M. J. Reno, N.
Ninad and E. Apablaza-Arancibia, “Evaluation of Photovoltaic
Inverters Under Balanced and Unbalanced Voltage Phase Angle
Jump Conditions”, 2020 47th IEEE Photovoltaic Specialists
Conference (PVSC), 2020, pp. 1562-1569.
[21] R. Darbali-Zamora, J. Hernandez-Alvidrez, A. Summers, N. S.
Gurule, M. J. Reno and J. Johnson, “Distribution Feeder Fault
Comparison Utilizing a Real-Time Power Hardware-in-the-
Loop Approach for Photovoltaic System Applications”, 2019
IEEE 46th Photovoltaic Specialists Conference (PVSC), 2019,
pp. 2916-2922.
[22] N. Ninad et al., “PV Inverter Grid Support Function Assessment
using Open-Source IEEE P1547.1 Test Package,” 2020 47th
IEEE Photovoltaic Specialists Conference (PVSC), 2020, pp.
1138-1144.
978-1-6654-1922-2/21/$31.00 ©2021 IEEE
1802
