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2014 CIGRÉ Canada Conference
International Center
Toronto, Ontario, September 22-24, 2014
Mackinac HVDC Converter
Automatic runback utilizing locally measured quantities
M. Marz
K. Copp
A. Manty
ATC
USA
D. Dickmander
J. Danielsson
M. Bahrman
ABB Inc
USA
F. Johansson
P. Holmberg
P-E Björklund
H. Duchen
P. Lundberg
ABB AB
Sweden
G. Irwin
Electranix
Canada
S. Sankar
B&V
USA
SUMMARY
The Mackinac VSC (Voltage Source Converter) HVDC Back-to-Back Project is currently in the
commissioning phase and scheduled to be in operation in July in 2014. The HVDC station, located in
the Upper Peninsula (UP) of Michigan, was the technology selected after a thorough evaluation to
determine which technology concept could best solve overload issues in the eastern UP by controlling
flow between Michigan’s upper and lower peninsulas. The flexibility of a VSC HVDC system with
fast active and reactive power control and the possibility to operate each terminal independently as
two STATCOM devices offering reactive power support, even when one terminal is out of operation,
was determined to be the preferred solution for this application. A VSC converter has no minimum
short circuit capacity requirement and can thus be used to black start one terminal from the other and
quickly energize a blacked-out ac network.
The Mackinac HVDC solves the overload issues by reliably controlling flow between the upper and
lower peninsulas. Another major concern is line outages that could separate the central and eastern
parts of the Upper Peninsula following network contingencies. Unplanned line tripping in this weak
network can cause subsequent disturbances and additional outages. To avoid major outages and keep
the system stable, an automatic runback is introduced in the HVDC to alter its power flow by
measuring the phase angle differential across its terminals. The decision to utilize local measurements
at the HVDC to calculate the required change in power flow was a decisive factor for the customer,
since the alternative was to introduce remote measurements of critical lines with fast fiber
communication to the HVDC; only then it would be possible, to react fast enough to very severe
changes in the system to maintain system stability.
The automatic runback, implemented using an AC line emulation function, is activated when a rapid
change of the voltage phase angle difference across HVDC terminals is measured. Based on the angle
difference, a new power reference is calculated and the power order is automatically updated to the
new set point and the HVDC returns to constant power flow operation at the new set point. The AC
line emulation function is continuously scanning for a rapid change in the phase angle across the
terminals and activates when required, to ensure system stability.
The performance of the AC line emulation function has been thoroughly tested in dynamic
performance studies and also in the Factory System Test, where the physical controls were interfaced
to a Real Time Digital Simulator.
KEYWORDS
HVDC – VSC – Weak systems – AC line emulation – Phasor control – Cascaded Two-Level
Converter –
1
INTRODUCTION
After a thorough review of available flow control technologies, a back-to-back voltage source
converter (VSC) HVDC station was installed at the Straits of Mackinac. By controlling the power
flowing between Michigan’s upper and lower peninsulas this station prevents overloads in Upper
Peninsula (UP). Weak system conditions on both sides of the converter station and the desire to limit
control system inputs to locally measured quantities made the development of new control techniques
necessary.
PROJECT NEED
Michigan’s Upper (UP) and Lower (LP) Peninsula transmission systems were designed to serve load,
not transfer power. Although only separated by the St. Mary’s River at Sault Sainte Marie the UP and
Ontario are not electrically connected. When the eastern UP, which had been served radially from the
LP via undersea cables across the Straits of Mackinac, was connected to the rest of the UP, power
transfers between the peninsulas and across the UP became possible, but system strength, as measured
by available fault current remained low. For years, high impedances and a relatively low west to east
energy flow bias kept these transfers low and thermal or voltage issues were rare. When issues did
arise, they were usually resolved by splitting the system to separate the eastern UP from the rest of the
UP (Figure 1).
Figure 1: Eastern UP Transmission System Split
West to east power flow bias is increasing as the demand for low cost and environmentally friendly
generation from west of Lake Michigan increases south and east of the lake (Fig. 2). Most of this
power follows the low impedance path west of the lake, but a small fraction flows through the higher
impedance path north of the lake. The lack of strong sources in the UP made redispatching generation
to avoid thermal and voltage issues caused by this northern flow difficult and expensive. Although
undesirable because it increased reliability risk, splitting the UP system to control flows, once an
occasional requirement, became an all but permanent condition. Building additional facilities to
address the thermal and voltage issues created by the northern flow was investigated and found to be
prohibitively expensive and unachievable in the required timeframe, making flow control the preferred
method to address these issues.
2
Figure 2: Upper Midwestern US Flow Bias
VSC TECHNOLOGY SELECTION
System conditions required the selected flow control technology to operate under weak (low fault
current) system conditions, not contribute to voltage control issues and not create the need for
additional prohibitively expensive dynamic reactive support. Other concerns included cost,
maintenance requirements, operation under fault and outage conditions, and losses. A final
requirement was that the selected technology be a long term fix so that system changes would not
make it obsolete.
Several flow control technologies were considered for the Mackinac Project. While all technologies
evaluated had their advantages and disadvantages, the system conditions at Mackinac made VSC
HVDC the best fit for this project [1].




Series Reactors are technically simple and inexpensive, but have high reactive losses which
would make voltage regulation more difficult, lack adjustability without adding complicating
taps, and can become obsolete due to system changes.
Phase Shifting Transformers (PST) are a well-established technology, but the durability and
speed of the mechanical switches used to adjust PST angle was a concern at Mackinac where
switching operations were expected to be frequent and too slow to avoid voltage collapse
during major contingencies. Multiple phase shifters in series might be necessary to achieve
the phase shift required at Mackinac, if not initially, after several years due to increasing bias
flows.
Variable Frequency Transformers (VFT) act as continuously adjustable phase-shifting
transformers that smoothly ramp from one power level to another [2]. While they allow for
reactive power flow, they do not use reactive power to regulate voltage and would require
added dynamic reactive power compensation to maintain a reasonable system voltage on a
system as weak as at Mackinac.
Line Commutated Converter (LCC) and Capacitor-Commutated Converter (CCC)
HVDC. LCC HVDC is another well-established technology, but consumes reactive power up
to 50 percent of its rating, requires harmonic filtering and a minimum short circuit current
capacity of at least twice the converter rating at the point of interconnection. LCC HVDC is
not an option in this case because of Mackinac’s low short circuit capacity. CCC HVDC was
developed to address the short circuit limitations of LCC [3], but the ability of CCC HVDC to
operate under very low short circuit conditions is limited and created cost and reliability
concerns at Mackinac. Also, the need for reactive power compensation, although reduced
when compared to LCC HVDC, would probably require additional dynamic reactive power
compensation at Mackinac.
3

Voltage Source Converter (VSC) HVDC was chosen for the Mackinac project because of its
ability to (1) operate under any system short circuit current conditions, (2) provide dynamic
vars for voltage regulation independently at each dc terminal, (3) quickly adjust real and
reactive power flow in response to system contingencies, and (4) control flows regardless of
future system changes. Also, with the DC connection between the terminals out of service,
VSC HVDC can be operated as two independent STATCOM devices.
CONVERTER SPECIFICATIONS
The Mackinac HVDC converter station was designed for 200 MW bi-directional power transfer and
+/-100 MVAR at each terminal for local voltage support during steady state and dynamic conditions.
A symmetrical monopole topology was chosen. The converter is a Cascaded Two-Level (CTL)
converter with reduced losses and reduced harmonic generation compared to older generations of VSC
converters. A dc voltage of ±71 kV was selected to achieve the 200MW bi-directional power transfer.
A zero sequence third-harmonic component is added to the sinusoidal reference voltage to reduce the
peak ac converter voltage in order to, with the same dc voltage, achieve an approximately 15%
increased ac-side fundamental frequency voltage.
Following certain contingencies, the UP converter may be left connected to an islanded system and
operate in a fixed frequency/voltage mode with droop settings.
At certain locations the eastern UP power system is connected to the rest of the ATC system via as
few as two 138 kV lines. The outage of one or two specific circuits in the UP can make the eastern UP
either islanded (connected to the rest of the system only through the Mackinac HVDC) or quasiislanded (connected to the rest of the system through the Mackinac HVDC and a single 69 kV
connection). It was desirable that the HVDC maintain system stability under contingencies that
resulted in both islanded and quasi-islanded conditions using only locally sensed signals.
SYSTEM STUDIES
Extensive system studies in PSS/E and PSCAD were performed during development of the HVDC
system to refine and demonstrate the performance of the HVDC controls. The stability studies in
PSS/E covered several different system scenarios and a large number of contingency simulations for
each scenario, in order to confirm stability of the ac power system and HVDC converter for large
disturbances. System stability was demonstrated by use of the strategy of emulating the power-angle
characteristics of an ac line during large disturbances (AC Line Emulation). A damping controller was
also implemented in order to ensure positive damping at a natural mode related to the phasor voltage
control strategy, which imparts a converter characteristic at the Mackinac North bus similar to that of a
large synchronous machine.
System Data
The starting point for the system studies was in the form of four system scenarios:




2014 Light (Winter) Load
2014 Summer Peak Load
2020 Light (Winter) Load
2020 Summer Peak Load
The system data were in the form of large-scale PSS/E models of the Eastern Interconnect, including
dynamics data for all machines of interest. This included hydro and other generation in the Upper
Peninsula, as well as existing or planned wind farms in the vicinity of Mackinac. Dynamic load
models for loads in the Upper Peninsula were also incorporated. This included modeling of a
significant portion of the load as induction motor loads, which influence the ac system behavior during
low voltage events and at fault clearing.
System base case powerflows were developed for the above four scenarios, with the following
variations:
4
-
HVDC Power direction (S-N or N-S)
Prior outages of key transmission lines in the Upper Peninsula
Prior outages of key transmission lines in the Lower Peninsula
HVDC CONTROL OVERVIEW
South Converter
The normal approach used for control of VSC HVDC is referred to as “vector current control”. The
basic principle of vector-current control is to control the converter’s instantaneous active power and
reactive power independently through a fast inner current control loop. The inner current control loop
decouples the current into q and d components, where outer loops can use the d component to control
active power or direct voltage, and the q component to control reactive power or alternating voltage.
Vector current control is a robust and reliable control method that is commonly used in HVDC Light
projects. This is the method chosen for control of the South converter for ATC Mackinac.
As compared to the North side, the South converter AC bus is relatively strong (Minimum Short
Circuit Ratio=2.5). The adopted control approach for the South converter is therefore:
•
•
•
Inner-loop current control
DC voltage control
AC voltage control
North Converter
The North converter AC bus can become extremely weak during certain contingencies in the UP. For
this reason, the vector current control method chosen for the South converter was not chosen for the
North converter. The approach chosen for the North converter is based on direct control of the
converter’s internal AC voltage amplitude and phase, meaning that the internal voltage developed by
the IGBT valves is controlled as a phasor. This control approach is herein referred to as “phasor
voltage control”.
The basic principle of “phasor voltage control” is to keep the internal converter voltage as a fixed
phasor in steady-state (i.e. constant in amplitude and phase). The amplitude control is extended with
an impedance correction to keep the AC network bus voltage, at the HVDC terminal, constant.
The control of the phase is extended with a frequency droop and a phase angle offset to provide
adjustments to control the synchronizing power. “Synchronizing power” in an AC network is the
power flow that opposes increases in relative rotor angles between synchronous machines, thereby
keeping the machines synchronized.
AC Line Emulation
The AC line emulation function monitors the voltage angle across the converter. Following a
disturbance, the power order is calculated according to the (simplified) equation
Pref , ACLEMU 
V1 V2
sin(1   2 ) [1]
X
The effect of the AC line emulation function is an automatic runback of the HVDC Light power
reference for disturbances that give a large change in the ac network impedance. This has the effect of
reducing the possibility of overloading remaining AC transmission lines after loss of key transmission
facilities. The function also has the effect of synchronizing the North AC network to the South AC
network, which also aids the system recovery following disturbances.
Damping Controller
This controller acts on North bus frequency deviation and is tuned to approximately 1 Hz, which is the
main modal frequency of interest for the chosen control structure.
5
STUDIED DYNAMIC CASES
The dynamics cases studied included three categories:
1. Contingencies resulting in extremely weak connection to the Western part of the UP
2. Contingencies resulting in full separation of the Eastern part of the UP from the Western part
(Islanded conditions)
3. Additional contingencies involving key transmission lines in the Lower Peninsula
Two example results from the PSS/E simulations are given for the following conditions:
-
Prior outage of a key 60 km 138 kV line in the Upper Peninsula 160 km north west of
Mackinac
100 ms 3-phase fault at 138 kV bus 120 km west of Mackinac
Trip both 138 kV circuits of a Double Circuit line 120 km west of Mackinac
This is a very severe case involving loss of three major 138 kV lines in the Upper Peninsula, resulting
in the Eastern UP being served from a single 69 kV line. The affected 138 kV lines in this scenario are
all remote from Mackinac.
In the past, the conventional solution for such a scenario would have required remote sensing of the
critical 138 kV lines, with communications of the line status to the HVDC system. A pre-programmed
runback of the HVDC power would then have been triggered by loss of the 138 kV lines. The
difficulty with this conventional approach is that it requires investment in telecommunications
facilities, possibly including redundancy for reliability, and implementation of a Special Protection
System (SPS).
Because of anticipated difficulties with such an approach solutions involving local measurements at
the HVDC station were required. The solution was a combination of the continuous phasor voltage
control together with the transient AC Line Emulation functions previously described, with results
shown as Figure 3 (for S-N operation of the HVDC) and Figure 4 (for N-S operation of the HVDC).
In Figure 3, the action of the AC Line Emulation function reduces the HVDC power reference from
180 MW S-N to approximately 90 MW S-N. This large reduction of HVDC flow, in combination with
damping controller action, preserves the stability of the system.
In Figure 4, the AC Line Emulation function actually reverses the HVDC power direction, from 140
MW N-S pre-contingency to approximately 80 MW S-N post-contingency. This power reversal both
stabilizes the system and helps to offload the remaining 69 kV tie, which otherwise would have been
severely overloaded without the HVDC control action.
In Figure 3 and 4 the first plot shows the North and South converter power, the second plot shows the
North and South ac bus voltages in p.u at point of common coupling, the third plot shows the phase
angle difference across the HVDC terminals; i.e. the locally measured angle difference 1-2 used by
the AC line emulation function in equation [1], and the fourth plot shows the power order calculated
by the AC line emulation function in MW “PREF0MAIN” and the output of the damping controller
“DELTAP0”.
6
North Power [MW]
South Power [MW]
200
100
0
-100
Mackinac N 138 [PU]
Mackinac S 138 [PU]
-200
1.40
2
3
4
5
1
2
3
4
5
1
2
3
4
5
1
2
3
4
5
1.2
1
0.8
0.6
0.4
1200
Angle Separation [Deg]
DELTAP0 [MW]
PREF0MAIN [MW]
1
100
80
60
40
20
2000
100
0
-100
-200
0
Time [s]
Figure 3: HVDC S-N. Trip of key 138 kV lines in UP resulting in Eastern UP
connected to Wisconsin via a single 69 kV line.
North Power [MW]
South Power [MW]
200
100
0
-100
DELTAP0 [MW]
PREF0MAIN [MW]
Angle Separation [Deg]
Mackinac N 138 [PU]
Mackinac S 138 [PU]
-200
1.40
1
2
3
4
5
1
2
3
4
5
1
2
3
4
5
1
2
3
4
5
1.2
1
0.8
0.6
0.4
200
0
-20
-40
-60
-80
2000
100
0
-100
-200
0
Time [s]
Figure 4: HVDC N-S. Trip of key 138 kV lines in UP resulting in Eastern UP connected to
Wisconsin via a single 69 kV line. HVDC power reversal by AC Line Emulation.
7
The results shown in Figures 3 and 4, and other cases in the PSS/E study, were investigated for the
purpose of verifying HVDC and ac network stability under extreme conditions. Because of limitations
in the ac networks, initial operation of the HVDC system in 2014 is anticipated to be at lower power
levels than those shown, particularly for the N-S direction where transfers are constrained until
planned installation of a 345/138 kV network transformer in the central UP is completed.
FACTORY SYSTEM TEST
During the Factory Systems Tests (FST), the physical controls to be delivered to the plant were
connected to a Real Time Digital Simulator (RTDS), where the main circuits are digitally modeled.
The implementation of the AC Line Emulation function was verified during the FST with a simplified
representation of the Northern network. Figure 5 shows a behavior similar to that presented in Figure
3. The case shows the resulting power level after disconnection of a key 138 kV line in the UP, due to
a single phase fault. The sign of the power traces have in this case been modified to improve
presentation resolution. The measurement time was reduced to focus on dynamic performance.
In Figure 5:
- S1_P_PCC: South side, measured power at the Point of Common Coupling (PCC)
- S2_P_PCC: North side side, measured power at the PCC
- S1 UPCC Lx: South side, measured a.c. voltage at the PCC, phase x
- S1_GRID_ANGLE_DIFF_HP: South side, measured grid angle difference
- S2_GRID_ANGLE_DIFF_HP: North side, measured grid angle difference
Figure 5: HVDC N-S. Trip of a key 138 kV line in theUP.
COMMISIONING TESTS
During commissioning, in order not to cause a large disturbance to the UP network, the AC Line
Emulation function was tested by forcing its triggering without changing the network configuration.
For this test case, the new power level calculated by the ACLE function did not differ significantly
from the previous power level. As can be seen in Figure 6 the ACLE function is activated for 15
8
seconds before the power order is updated and power control mode is resumed. The figure below
shows obtained results.
In Figure 6:
- P ORD FR ACLE:
- PO CALC ACLE:
- PO REF to CFC:
- AUTO RUNBACK:
- P UPDATE ACLE:
- ACLE ON LINE:
- FORCE RUNBACK:
Power order reference from ACLE function
Power order continuously calculated by the ACLE function
Power order used by the control, after additional modulations
Signal indicates that Auto Runback from the ACLE function is active
Signal indicates that the power order is to be updated
Signal indicates that ACLE is active
Signal indicates that ACLE has been triggered manually
Figure 6: HVDC N-S. Activation of AC line emulation function during system tests.
BIBLIOGRAPHY
[1]
[2]
[3]
[4]
M. B. Marz. “Mackinac VSC HVDC Flow Control Project Design” Minnesota Power Systems
Conference, November 6-8, 2012. Available at: http://www.cce.umn.edu/Documents/CPEConferences/MIPSYCON-Papers/2012/MackinacVscHvdcFlowControlProjectDesign.pdf
Merkhouf, A, Upadhyay, S, and
Doyon, P, “Variable Frequency Transformer – An
Overview”, IEEE Power Engineering Society General Meeting, 2006.
Flourentzou, N, Agelidis, V.G and Demetriades, G.D, “VSC Based HVDC Power Transmission
Systems: An Overview”, IEEE Transactions on Power Electronics, Vol. 24, Issue 3, 2009
M. Bahrman, P-E Björklund “The New Black Start – System Restoration with Help from
Voltage-Sourced Converter” IEEE power & energy magazine January/February 2014
9