1. business and industrial
2. energy
3. electricity

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IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 22, NO. 1, JANUARY 2007
A Distributed Static Series Compensator System
for Realizing Active Power Flow Control on
Existing Power Lines
Deepak M. Divan, Fellow, IEEE, William E. Brumsickle, Senior Member, IEEE, Robert S. Schneider, Member, IEEE,
Bill Kranz, Randal W. Gascoigne, Dale T. Bradshaw, Member, IEEE, Michael R. Ingram, Senior Member, IEEE,
and Ian S. Grant, Fellow, IEEE
Abstract—Flexible AC transmission systems (FACTS) devices
can control power flow in the transmission system to improve asset
utilization, relieve congestion, and limit loop flows. High costs and
reliability concerns have restricted their use in these applications.
The concept of distributed FACTS (D-FACTS) is introduced as a
way to remove these barriers. A new device, the distributed static
series compensator (DSSC), attaches directly to existing HV or
EHV conductors and so does not require HV insulation. It can be
manufactured at low cost from conventional industrial-grade components. The DSSC modules are distributed, a few per conductor
mile, to achieve the desired power flow control functionality by
effectively changing the line reactance. Experimental results from
a prototype module are presented, along with examples of the
benefits deriving from a system of DSSC devices.
Index Terms—Distributed FACTS, flexible AC transmission systems (FACTS), interconnected power systems, power system economics, power system planning, power transmission congestion,
power transmission control, power transmission lines.
I. INTRODUCTION
T
HE U.S. transmission system was developed to serve a
vertically integrated regulated utility structure. Substantial changes and capital investment are required to modify it for
deregulated market needs. Thus it presents a major infrastructural obstacle for the continuing growth of the U.S.$ 224 billion
U.S. electricity market [1]. Electricity demand has increased
25% over the last decade and continues to increase. Overall, adequate generation capacity now exists, or is planned, to meet
projected needs in the U.S. At the same time, annual investment
in transmission facilities has declined over the last decade [1].
Manuscript received December 3, 2004. This work was supported in part by
the Tennessee Valley Authority and in part by Soft Switching Technologies Corporation. Paper no. TPWRD-00573-2004.
D. M. Divan was with Soft Switching Technologies, Middleton, WI 53562
USA. He is now with the Georgia Institute of Technology, Atlanta, GA 30332
USA (e-mail: deepak.divan@ece.gatech.edu).
W. E. Brumsickle, R. S. Schneider, and B. Kranz are with Soft Switching
Technologies, Middleton, WI 56562 USA (e-mail: brumsickle@ieee.org).
R. Gascoigne was with Soft Switching Technologies, Middleton, WI 53562,
USA. He is now a Consultant in Madison, WI 53711 USA.
D. T. Bradshaw was with the Tennessee Valley Authority, Chattanooga,
TN 37402, USA. He is now with Electrivation, Chattanooga, TN 37416 USA
(e-mail: dtbradshaw@electrivation.com).
M. R. Ingram and I. S. Grant are with the Tennessee Valley Authority, Chattanooga, TN 37402 USA (e-mail: mringram@tva.gov; isgrant@tva.gov).
Color versions of Figs. 2–11 are available online at http://ieeexplore.ieee.org.
Digital Object Identifier 10.1109/TPWRD.2006.887103
As a result of load growth, deregulation, and limited investment
in new facilities, transmission congestion has rapidly increased.
Over 50 transmission corridors in the U.S. are routinely congested, causing high economic impact. According to the New
York Independent System Operator (NYISO), T&D system congestion costs over U.S.$ 1 billion per year [2].
Unfortunately, ac power flow follows Ohm’s Law, not contract law. Uncontrolled ‘loop flow’ causes congestion and reliability problems, and reduces the ability to fulfill energy contracts. Loop flows also impact the ability to fully utilize certain
transmission lines, even as other lines suffer congestion, further
limiting available transfer capacity under normal and contingency conditions.
New transmission lines could relieve congestion, but are
expensive to build (U.S.$ 0.5–2 million/mile typically, but costs
can exceed U.S.$ 10 M/mile) and require several years for
approval and construction. One solution to the problem of managing power flow on transmission lines has been through the
use of Flexible AC Transmission Systems (FACTS). FACTS
devices allow control of power flows on ac power systems
through the use of large power converters (10–300 MW) [3].
While several FACTS installations are operating worldwide,
wide scale deployment has not occurred. FACTS typically costs
U.S.$ 120–U.S.$ 150 per kVAr, compared to U.S.$ 15–U.S.$
20/kVAr for static capacitors.
This paper introduces the concept of a distributed static series
compensator (DSSC) that uses multiple low-power single-phase
inverters that attach to the transmission conductor and dynamically control the impedance of the transmission line, allowing
control of active power flow on the line [4]. The DSSC inverters
are self-powered by induction from the line itself, float electrically on the transmission conductors, and are controlled using
wireless or power line communication techniques. Implementation of system level control uses a large number of DSSC modules controlled as a group to realize active control of power flow.
The DSSC can be used to either increase or decrease the effective line impedance, allowing current to be “pushed” away
from or “pulled” into a transmission line. The DSSC concept
overcomes some of the most serious limitations of FACTS devices, and points the way to a new approach for achieving power
flow control–the use of Distributed FACTS or D-FACTS devices. This paper details the principles of operation of the DSSC,
shows operating results from a prototype device, and presents an
analysis of its possible impact on typical power systems.
0885-8977/$20.00 © 2007 IEEE
DIVAN et al.: DSSC SYSTEM FOR REALIZING ACTIVE POWER FLOW CONTROL
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TABLE I
TYPES OF FACTS DEVICE
II. FEATURES AND LIMITATIONS OF FACTS DEVICES
FACTS devices are typically high-power high-voltage power
converters, operating at 138–500 kV and 10–300 MVA, that are
used to control power flow in the transmission and distribution
network. Three basic types of FACTS devices can be identified
as shown in Table I [5].
Shunt devices such as the static VAR compensator (SVC)
and static synchronous compensator (STATCOM), have been
most widely applied, and are typically used for reactive VAR
compensation and voltage support. Series devices such as the
thyristor controlled series capacitor (TCSC) and the static synchronous series compensator (SSSC) can be used for controlling
active power flow on transmission lines. Series-shunt devices
such as the universal power flow controller (UPFC) can be used
for accomplishing both functions with maximum flexibility, and
higher cost.
For controlling power flow on transmission lines, the series
elements clearly have the highest potential and impact. The real
and , along a transmission line
and reactive power flow,
connecting two voltage buses is governed by the two voltage
and
and the voltage phase angle difference,
magnitudes
, as
and
(1)
where
is the impedance of the line, assumed to be purely
inductive. A series compensator is typically used to increase
of the line,
or decrease the effective reactive impedance
thus allowing control of real power flow between the two buses.
The impedance change can be effected by series injection of
a passive capacitive or inductive element in the line. Alternatively, a static inverter can be used to realize a controllable active loss-less element such as a negative or positive inductor or a
synchronous fundamental voltage that is orthogonal to the line
current [6], [7]. In the latter case, the power flow depends on the
as
injected quadrature voltage
(2)
Fig. 1. Variation of transmission line power flow by impedance injection. (a)
Passive impedance injection, as p.u. of
(TCSC). (b) Quadrature voltage injection to achieve active impedance injection (SSSC, DSSC).
X
and the bracketed term is unity if
. Fig. 1 shows,
for equal bus voltage magnitudes, the variation of power flow
along a transmission line that can be achieved by injecting a
or an active impedance [7].
passive impedance
Significant barriers remain to the widespread commercial deployment of FACTS. Ratings of FACTS devices are often in the
100 MW range, with system voltages of 138 to 500 kV. Further,
series injection devices such as TCSC and SSSC, require platforms or custom transformers for isolation, and need to handle
fault voltages and currents. This approach to system implementation has resulted in large and complex converter installations
and barriers that have, so far, limited the commercial success of
FACTS technology. These include:
• high-cost resulting from device complexity and component
requirements;
• single point of failure can cause the entire system to shut
down;
• maintenance and on-site repair requirements for a complex
custom-engineered system adds significantly to system operating cost and increases mean time to repair (MTTR);
• lumped nature of system and initial over-rating of devices
to accommodate future growth provides poor return on investment (ROI);
• custom engineered nature of system results in long design
and build cycles, resulting in high system cost that will not
easily scale down with volume.
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IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 22, NO. 1, JANUARY 2007
Fig. 3. DSSC circuit schematic.
Fig. 2. DSSC concept showing clamp-on capability.
III. DISTRIBUTED STATIC SERIES COMPENSATOR (DSSC)
A controlled transmission system can be made up of a
large number, e.g., hundreds or thousands of DSSC modules,
each module containing a small rated (1–20 kW) single phase
inverter, a communications link and a single turn transformer
(STT) that is mechanically clamped on to—and suspended
from—the transmission line conductor (or insulator). The
STT uses the transmission conductor as a secondary winding,
directly injecting the desired voltage into the cable itself. The
inverter is self-powered by induction from the line, and can
be controlled to inject a voltage that is orthogonal to the line
current directly into the conductor. The module can either be
suspended from the conductor or configured as a replacement
for the conductor support clamp on an insulator. Further,
since it does not require supporting phase-ground insulation,
the module can easily be applied at any transmission voltage
level. Fig. 2 shows an electro-mechanical concept diagram
for a typical DSSC module, while Fig. 3 shows the power
circuit schematic. The mechanical form of the module may
either clip-on to the conductor, as shown in Fig. 2, or may be
incorporated into the insulator suspension clamp, avoiding any
concern about weight and conductor vibration damage.
When the transmission line is not powered up, the STT is bypassed by a normally closed relay contact (R1) that opens once
control power is available. A current transformer is used to generate control power, allowing the DSSC module to operate as
long as the line current is greater than a minimum level, say 150
A. The line appears to the inverter as an inductive current source.
The single phase inverter uses four IGBT devices along with an
output LC filter and a dc bus capacitance. The inverter output
voltage is controlled using pulse width modulation techniques,
and has two components. The first is in quadrature with the line
current, and represents the desired impedance to be injected.
The second is in phase with the line current, and allows compensation of power losses in the inverter, and regulation of the dc
bus of the inverter. System commands for gradual changes are
received from a central control center using a wireless or power
line communication (PLC) technique [8]. In the event of rapid
transients or faults the DSSC modules can be programmed to
operate autonomously. With the DSSC attached and operating
at the conductor potential, conductor temperature measurement
capability is easily added and actual temperature readings can
be communicated to the central system controller.
The STT is a key component of the DSSC module. It is designed such that the module can be clamped onto an existing
transmission line. The STT is designed with a high turns ratio,
. This implies that under a normal line current of say
say
1500 A, the inverter would only handle 20 amperes. Designing
the inverter for 500 volts rms output would then allow the DSSC
module to inject 7 V rms leading or lagging, corresponding to
kVAr in series with the line under normal operating conditions. It is anticipated that such a module could be designed to
weigh less than 45 kg (100 lb), making the module suitable for
direct clamp-on mounting on the transmission conductor.
The STT also allows the inverter to possibly continue operating under fault conditions. For instance, at a fault current of
50 000 A, the inverter current is still only 667 A, well within the
capability of commercially used IGBT devices. This raises the
interesting possibility that unlike TCSCs, the DSSC could regulate line impedance under normal conditions, switching into
a maximum inductance injection mode within microseconds to
prevent an increase in the fault current levels.
The inverter ratings clearly demonstrate that the semiconductors and components used are commercially available in very
high volumes for the motor drives, UPS, and automotive industries, thus validating the potential for realizing low cost.
IV. OPERATION OF DSSC IN POWER SYSTEMS
A controlled transmission line implemented with multiple
DSSC modules can realize significant benefits at a system level.
At the highest level, it can:
• enhance asset utilization;
• reduce system congestion;
• increase available transfer capacity (ATC) of the system;
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TABLE II
CALCULATION OF NUMBER OF DSSC MODULES TO CHANGE
LINE IMPEDANCE BY 1%
Fig. 4. Meshed network system DSSC implementation.
• enhance system reliability and capacity under contingencies;
• enhance system stability.
and can do so with lower capital and operating cost than most
conventional single-point “lumped” solutions, such as FACTS
devices.
An overall meshed network system implementation is shown
schematically in Fig. 4. DSSC modules can be deployed on select lines, or on all lines. Overall operation of the modules is coordinated using a single (or redundant) communication channel
(RF or PLC), with a built-in fail-safe operating mode in case
of fast transients (such as system faults) or communication link
failure. A typical system level command could be for the DSSC
modules to emulate a desired impedance or voltage as a function
of line current. For instance, the line impedance could automatically increase above a current set point, causing current to be
preferentially steered to other lines that are lightly loaded.
Operation of the DSSC modules can be coordinated from the
system control center to realize a variety of optimization functions or operating conditions including:
• system optimization, e.g., loss or VAr minimization;
• maintaining lines out of congestion or below thermal limit;
• reconfiguring current flows to compensate for tripped lines;
• operating lines above steady-state thermal limit under contingency conditions;
• forcing power to flow along contract paths;
• controlling power flow through flow-gates;
• decreasing susceptibility to sub-synchronous resonance;
• marginal reduction of fault currents;
• providing damping of system oscillations.
The DSSC modules are insensitive to the cable voltage rating,
and are targeted for 138 kV to 500 kV systems. The maximum
level of impedance control for specific lines is projected at up
– % of the actual line impedance under rated current
to
conditions. At lower current levels, the range of impedance control can be correspondingly increased. For instance, at half the
nominal current, the impedance control range can be doubled.
The distributed nature of the proposed system also provides fine
granularity in the system rating, along with the ability to expand
the system with demand. System planners can thus plan on increasing the ATC of a line by 2% every year for 10 years to meet
Fig. 5. DSSC control of power flow over parallel lines connecting voltage
buses: uncompensated (top) and with DSSC compensation (bottom).
projected growth needs, without having to invest all the capital
at project start.
Table II shows the characteristics of typical lines at 138 to
765 kV, and examines the applicability of DSSC technology to
realistic applications. Transmission lines are considered to be
typical and representative.
Taking the 138 kV line as an example, it is seen that the reactive voltage drop is 608 V/mile at rated current (corresponding
to 0.79 ohms/mile). A 1% change in the impedance thus requires
an injection of 6.08 V/mile, corresponding to a combined DSSC
rating of 14 kVA/mile based on three phase injection. A varia% in line impedance would thus need 280 kVA or 28
tion of
of the 10 kVA DSSC modules/mile or approximately 9 modules
per conductor per mile.
A. Examples
Fig. 5 shows a simple example of how the DSSC can be controlled so as to relieve transmission congestion. Two lines of
unequal lengths are used to transfer power from bus 1 to bus
2. The assumed line parameters are listed in Table III. Setting
yields line currents of
A, and
A, and power transferred along the lines is
MW and
MW, for a total power transfer of 268 MW between
the buses.
by 20% and
Assuming a DSSC in each line, increasing
by 20% allows use of a larger phase angle
decreasing
, which results in
A giving
MW, and
A and
MW, for a total power transfer of
319 MW between the buses. These results are summarized in
Table IV. The power transferred through line 2 has increased
by almost 50%, while line 1 has been controlled to well within
its thermal limit. Approximately 10.9 MVA of control action,
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TABLE III
LINE PARAMETERS FOR EXAMPLE OF FIG. 5
TABLE IV
POWER TRANSFER BETWEEN TWO BUSES
achieved with 1092 DSSC modules spread over 50 miles of
transmission lines—7.3 modules per mile per conductor, resulted in 51 MW of additional power flow between buses. This
number would be even more advantageous at higher system
voltages. This simple example confirms the ability of the DSSC
to control loop flows, to manage congestion, and to increase the
power handling capacity of transmission lines.
V. LUMPED VERSUS DISTRIBUTED SOLUTIONS
The distributed nature of the DSSC system provides several
benefits. A significant benefit accrues from the ability to stage
capital investments over a longer time, and being able to match
the investment with the actual need or demand. For instance,
system planners exploring the addition of a FACTS system such
as an SSSC or a phase shifting transformer to increase line ATC
would typically plan on a 30 year system operating life, and have
to design the system to handle the growth in demand expected
over that period. Since only a portion of the system capacity
would be usefully deployed in the first year, this suggests that
the return on capital employed (ROCE), a key financial metric
for most organizations, would be low. By way of contrast, a
system implemented with DSSC could be expanded every year
in tandem with actual load growth, and would maximize the utilization of capital. A simple example is used to show the difference.
The 30 mile transmission line shown in Fig. 5 is assumed to
operate with an average line current of 340 A (45% of thermal
limit), growing at 2.5% per year to 713 A (95% of thermal limit)
in 30 years. Lumped and distributed series compensators (or
phase shifting transformer) are to be compared as solutions to
control power flow on the line. Ratings for the two solutions
are: 1) Lumped: a 19.13 MVA SSSC installed beginning of year
1; 2) Distributed: 0.64 MVA of DSSCs installed annually for
30 years. Deployment of either solution allows power flow to
increase from 81.2 MW in year one to 170.3 MW by year 30.
TABLE V
COST COMPARISON FOR LUMPED VERSUS DISTRIBUTED SOLUTIONS
IN A 138 KV/750 A LINE (U.S. DOLLARS)
Significant differences are seen to occur in capital cost and operating cost (energy losses) for the two solutions. Table V summarizes the overall impact on cost of ownership.
Assumptions—for the purposes of the example summarized
in Table V—include U.S.$ 100/kVA first cost for either solution,
a 6% annual cost of capital over 30 years, 2.5% per annum load
growth, nominal energy losses of 2.5% (under full voltage and
current conditions) and an energy cost of U.S.$ 25/MWh. With
today’s FACTS capital costs at U.S.$ 120–U.S.$ 150/kVA, and
DSSC costs expected to be well below U.S.$ 100/kVA, the advantages of the distributed system appear even more compelling.
Another important issue relates to the inaccuracy of the estimated growth rates that are the basis of the economic decision. If
the achieved rate of demand growth is lower than the projected
2.5%, the distributed solution can be deployed only as required,
with minimal impact on the overall cost recovery and return on
investment. On the other hand, for lumped solutions, a slower rate
of growth would dramatically reduce the return on investment.
VI. OPERATIONAL AND ECONOMIC BENEFITS
From an operational perspective, the following characteristics
may be realized for DSSC systems:
• ability to increase or decrease steady state line current
under system controller command, or autonomously;
• ability to monitor actual conductor temperature and manually or automatically limit currents as a function of conductor temperature;
• high system reliability due to massive redundancy, single
unit failure has negligible impact on system performance;
• zero footprint solution;
• robust and rugged under typical fault conditions;
• can be used with conventional or advanced conductors;
• mass produced modules can be stocked on the shelf, and
repaired in the factory—does not require skilled staff on
site;
• easy and rapid installation (may be possible on live line).
These operational benefits, in turn, lead to significant economic
benefits. These include:
• simple scalable tool for congestion management—increase
ATC and revenues;
• improves contingency management capability—reduce
TLR calls and meet contingency operating requirements
without building new lines;
• minimize loop flows and wheeling losses—improved asset
utilization and lower operating cost;
• reduce trapped capital in assets sized for future projected
growth—improves return on capital employed (ROCE);
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647
Fig. 6. DSSC prototype with suspension clamps.
TABLE VI
PROTOTYPE DSSC MODULE SPECIFICATIONS
Fig. 7. DSSC start-up waveforms at 1500 Arms.
Fig. 8. DSSC steady-state waveforms at 1500 Arms and maximum positive
injection. Note: voltage amplitude is scaled by a factor of 100.
Key module specifications are summarized in Table VI.
The power losses in the DSSC module were measured using a
Voltech model PM 3000A power analyzer.
A. Module Testing Results
• improves flexibility of locating new generation and allows
power flow along the contract path—enables bulk energy
trading and reduces overall energy costs;
• incrementally increase line capacity and defer new line
construction—minimize environmental impact, right of
way, and NIMBY issues
VII. EXPERIMENTAL VERIFICATION
A prototype module was designed, built, and tested to validate the DSSC concept. The DSSC module, shown in Fig. 6, is
completely enclosed and designed for suspension from a transmission line. It operates in a self-exciting mode, drawing a small
real power component from the line for control power and internal losses. This prototype was not designed for extended operation suspended on HV transmission systems, nor for minimization of corona effects.
Laboratory testing was done at 480 Vrms with a 3000 kVA
transformer (5.75% impedance) source and resistive loads.
Fig. 7 shows operating waveforms as the module starts up
at 1500 Arms. The inverter voltage is in phase with the line
current as real power is extracted from the line to charge the
inverter DC bus capacitors. Fig. 8 shows steady-state operating
waveforms; note that the injected voltage is orthogonal to the
line current, and represents a positive inductance injection.
In case of overload current levels, e.g., with transmission
faults, the DSSC protects itself by quickly shorting the transformer primary winding, first using the inverter IGBTs, then
with a normally closed mechanical relay. Unlike solutions such
as the TCSC, the DSSC modules do not contribute to the system
fault current, and actually operate to reduce it. The protection
features were demonstrated under simulated 15 000 Arms
current surge conditions by temporarily switching 1 500 A into
a ten-turn coil that was placed in parallel with the single-turn
line conductor carrying 350 Arms initially. Fig. 9 shows the
resulting voltage and combined effective current waveforms at
full negative insertion output. The DSSC inverter voltage can
be seen to quickly collapse to zero during the current surge.
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IEEE TRANSACTIONS ON POWER DELIVERY, VOL. 22, NO. 1, JANUARY 2007
Fig. 9. DSSC operation under 7-cycle 15k Arms fault current. Note: voltage
amplitude is scaled by a factor of 10.
Fig. 11. Current steering effect of DSSC quadrature voltage injection as injected voltage is varied from maximum negative injection at time zero, to maximum positive injection at time 10 s, to zero injection at time 25 s.
these losses can be considerably reduced in a final production
version of the DSSC, through optimization of component materials.
Fig. 10. Simulated parallel transmission lines lab setup. Values are per unit on
a 480 V, 333 kW base. Line 1 is on top, Line 2 on the bottom.
The unit automatically restarted at its previous command point
after the fault current condition cleared.
B. Current Steering in Parallel Transmission Lines
A laboratory simulation of parallel transmission lines between a voltage bus and a load bus was configured as shown in
Fig. 10. Identical inductors were placed in series with each of
two 500 kcmil cables to provide a representative per unit line
impedance. The DSSC is represented as a variable inductance.
in Fig. 10, injected quadrature voltage to effectively
change the line currents while keeping the DSSC current above
the operational minimum of 330 Arms. The resulting rms current profiles, as the DSSC output is varied, are shown in Fig. 11.
The effects of “pushing current away” and “pulling current into”
the controlled line are evident. By design, this prototype unit
operates with line currents down to 330 A. DSSC designs operational to 100 A or less are possible.
C. Extension to Transmission System Usage
The module test data allow us to calculate the impact of deploying the DSSC modules in a power system, such as that depicted in Fig. 5. Assuming 10 modules per conductor mile, one
sees that the energy losses when the system is in bypass mode
total 800 watts/mile at 1 000 A. The insertion inductance in
bypass mode is 8 H/mile or 0.003 ohms, as compared with
a typical transmission conductor impedance of approximately
0.8 ohms/mile, representing a 0.37% change in line impedance.
When the system is operating at full output, the total DSSC
system losses are estimated at 14.7 kW/mile (for three phases)
to achieve a 5.1% increase in current and MVA, compared with
239 MVA of power flowing through the transmission system at
the rated operating point (138 kV/1000 A). It is anticipated that
VIII. CONCLUSION
This paper has presented the novel concept of a DSSC that
uses multiple low-power single-phase inverters that clip-on
to the transmission conductor to dynamically control the
impedance of the transmission line allowing control of active
power flow on the line. The DSSC inverters are self-powered
by induction from the line itself, float electrically on the transmission conductors, and are controlled using wireless or power
line communication techniques. Implementation of system
level control uses a large number of DSSC modules that are
deployed and controlled as a group to realize active control
of power flow. The DSSC can be used to either increase or
decrease the line impedance, allowing current to be ‘pushed’
away from or “pulled” into a transmission line in a networked
system. The DSSC concept overcomes some of the most serious limitations of FACTS devices, and points the way to a
new approach for achieving power flow control—the use of
Distributed FACTS or D-FACTS devices. This paper details the
principles of operation of the DSSC, shows operating results
from a prototype device, and presents a preliminary analysis of
its possible impact on typical power systems. Although many
aspects of implementation have yet to be explored, this paper
has demonstrated the fundamental concept is sound and the
economics are compelling.
ACKNOWLEDGMENT
The authors acknowledge the contributions of Rick Mills in
his work on the DSSC prototype packaging.
REFERENCES
[1] S. Abraham, National Transmission Grid Study U.S. Dept. Energy,
May 2002 [Online]. Available: http://www.eh.doe.gov/ntgs/.
[2] W. J. Museler, President and CEO of the New York Independent System Operator (NYISO) May 22, 2003. New York City
[Online]. Available: http://www.nyiso.com/topics/articles/news_ releases/2003/pa3_presentation.pdf.
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649
[3] N. Hingorani, “Flexible AC transmission,” IEEE Spectr., vol. 30, no.
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[4] D. M. Divan, W. Brumsickle, and R. Schneider, “Distributed floating
series active impedance for power transmission systems,” U.S. Patent
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[5] D. J. Gotham and G. T. Heydt, “Power flow control and power flow
studies for systems with FACTS devices,” IEEE Trans. Power Syst.,
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[6] D. M. Divan, “Non-dissipative switched networks for high power applications,” Inst. Elect. Eng. Electron. Lett., pp. 277–279, Mar. 20, 1984.
[7] L. Gyugyi, C. D. Schauder, and K. K. Sen, “Static synchronous series compensator: A solid-state approach to the series compensation
of transmission lines,” IEEE Trans. Power Del., vol. 12, no. 1, pp.
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[8] D. J. Marihart, “Communications technology guidelines for
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Randal W. Gascoigne received the B.S.E.E. degree from the University of Wisconsin–Madison in 1982.
He was with the University of Wisconsin–Madison, engineering custom instrumentation and controls for a wide variety of applications. From 1987 to
1995, he was a Lab Manager with the staff of the Wisconsin Electric Machines
and Power Electronics Consortium (WEMPEC). From 1995 to 2004, he was a
Senior Engineer for Soft Switching Technologies (SST), Middleton, WI, where
he continued to apply his expertise in circuit design, component selection/specification, and packaging/system design. He also designs and builds electrical fish
barrier controllers for the Wisconsin Department of Natural Resources, and enjoys applying electronics to provide unique solutions to problems in other fields
of endeavor.
Deepak M. Divan (S’78–M’78–SM’91–F’98) is Professor in the School of
Electrical and Computer Engineering and Director of the IPIC Consortium at
the Georgia Institute of Technology (Georgia Tech), Atlanta. He is Chairman
and Chief Technology Officer for Innovolt, Atlanta. From 1995 to 2004, he was
Chairman and CEO/CTO of Soft Switching Technologies, a company in the industrial power quality market. His research interests are in the application of
power electronics for power quality, power reliability, and utility and industrial
applications. He has more than 200 papers and 28 issued and 4 pending patents.
Dr. Divan was the recipient of the 2006 IEEE William E. Newell Award for
contributions in power electronics. He is a Member at Large of the IEEE Power
Electronics Society and is PESC Steering Committee Chair for the society. He is
Technical Chair for the 1991 PESC Conference and Chairman and Transactions
Editor for the IAS-IPCC committee.
William E. Brumsickle (A’89–S’92–M’98–SM’05) received the B.S. degree
in physics from the University of Washington, Seattle, in 1982, and the M.S.
and Ph.D. degrees in electrical engineering (power and energy systems) from
the University of Wisconsin-Madison in 1995 and 1998, respectively.
He was an Applications Engineer for static power conversion products
at Enerpro, Inc., Goleta, CA, from 1985 to 1992. From 1992 to 1998, he
participated in Wisconsin Electric Machines and Power Electronics Consortium (WEMPEC) research projects in soft switching converters, active filters,
power-electronics building blocks (PEBB), large-scale uninterruptible power
supplies (UPS), and traction drive applications of high-voltage insuated-gate
bipolar transistors (IGBTs). In 1998, he joined Soft Switching Technologies,
Middleton, WI, where he is Director of Engineering. His research interests
include power-electronics conversion for utility and industrial applications,
soft switching inverter design and control, and the physics, monitoring, and
mitigation of power-quality disturbances.
Robert S. Schneider (M’90) received the B.S. degree in physics from the University of Wisconsin–Eau Claire in 1982 and the M.S. degree in electrical engineering from the University of Wisconsin–Madison in 1986, where he is currently pursuing a second M.S. degree in controls.
Currently, he is a Lead Engineer, Power Electronics, with Soft Switching
Technologies (SST), Middleton, WI. He was the Project Leader and Principle
Hardware Designer for the first generation of the DySC line of products that
spanned a range of 1.5 kVA through 1.33 MVA. He has more than 18 years
of industrial experience in designing and field testing power-electronic converters and systems, including implementation of photovoltaic, battery storage,
motor drive, servo motor, mini-hydroelectric, distributed generation, and powerquality systems. He has been involved in automatic voltage regulators, single-tothree-phase motor drives, and the introduction of demand flow manufacturing
technology for DySC products. He is a Co-inventor of three of SST’s patented
product technologies. He is a licensed Professional Engineer in the State of Wisconsin.
Bill Kranz received the B.S. degree in electrical engineering from the University of Wisconsin–Madison in 1999.
Currently, he is a Lead Engineer, Embedded Controls, with Soft Switching
Technologies Corp., Middleton, WI. His research interests include real-time
software and analog controls for industrial and utility power protection systems,
power quality, and voltage monitoring equipment, and fue–cell-based inverters.
Dale T. Bradshaw (M’98) is President of Electrivation, Chattanooga, TN. He
is External Program Coordinator for National Rural Electric Cooperative Association’s (NRECA) Cooperative Research Network’s (CRN) Transmission
Reliability and Security Advisory Group; Emerging Technology Team Leader
for the U.S. DOE NETL’s Modern Grid Initiative and University of California,
San Diego’s Smart Grid; Consultant to the California Institute for Energy and
Environment (CIEE) Transmission Research Program; Consultant to Navigant
on the assessment of DOE’s High Temperature Superconductivity Program;
Project Manager for an NRECA Project to identify options for mitigating transmission congestion; Director of Marketing for V&R Energy’s Physical Operating Margin (POM) suite of transmission system analysis software; Technical
Advisor to DOE’s Office of Electric Transmission and Distribution (OETD);
Business Development Consultant for Intelicis; Consultant for a major U.S. flywheel manufacturer; CTO for Advanced Coal Technologies LLC; and a GLG
Leader consulting with Gerson Lehrman Groups Council of Advisors. He was
with the Tennessee Valley Authority and was Senior Manager of Power Delivery
Technology from 1996 until 2004, where he developed projects that improved
transmission grid operations with operational planning, transmission asset utilization with the transmission planning group, and transmission performance
with transmission operations. He and his staff developed, demonstrated, and/or
implemented transmission planning optimization software, improved conductor
splice repair, improved transmission oil analysis, improved transmission oil additives, dynamic line rating systems, reduced cost capacitor design, and lower
cost dynamic reactive compensation systems.
Michael R. Ingram (M’91–SM’96) received the B.E.E. degree (Hons.) from
Auburn University, Auburn University, AL, and the M.S. degree in engineering
management from the University of Tennessee, Chattanooga.
Currently, he is the Senior Manager of Transmission Technologies with the
Tennessee Valley Authority (TVA), Chattanooga, TN. He is responsible for the
research, development, and demonstration of new technologies which improve
electrical quality and reliability, increase power flow, and reduce operating expense of the TVA transmission system and interconnected distribution network.
He provides advice to TVA executives on new technology solutions affecting
the T&D networks and sets strategy for research and development in areas of
energy storage, power quality, power/transmission markets, flexible ac transmission systems (FACTS), and superconductivity. He has been with TVA for
17 years, working in technical project management, protection and control engineering, and substation design. He has authored or coauthored more than 30
technical papers and articles within his area.
Mr. Ingram was the Chairman or Committee Member of several users and
working groups of IEEE, EPRI, and CIGRE. He was named Outstanding Young
Engineer of the Year (2001) by The IEEE Power Engineering Society. He was
named Engineer of the Year in 2001 and 2006 by the TVA. Additionally, he was
a 2001 and 2006 top-ten finalist for Federal Engineer of the Year. Other professional awards include IEEE Millennium Medal; Outstanding Power Engineer
of the Year, 1997; and Chattanooga-Area Young Engineer of the Year, 1996.
Ian S. Grant (F’87) received the B.E. degree from the University of New
Zealand, Auckland, in 1962 and the M.E. degree from the University of New
South Wales, Sydney, Australia, in 1967.
After graduation, he joined the Electricity Commission of NSW, Sydney,
Austalia, followed by General Electric Co. High Voltage Laboratory, Pittsfield,
MA; Power Technologies, Inc., Schenectady, NY; Evonyx, Inc., Hawthorn, NY;
and the Tennessee Valley Authority (TVA), Chattanooga, TN. Currently, he is
Planning Coordinator with TVA’s Transmission Reliability Operation. He is the
author or coauthor of more than 45 papers and books on transmission design,
lightning and transient studies, and insulation coordination.