Synchronous Condenser
Selection & Operation
VELCO Granite Substation Upgrade
(2004 – 2008)
Presentation to ERCOT Regional Planning Group
3/19/2016
Vermont Electric Power Company, Inc (VELCO)
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Vermont Electric Power Company (VELCO) was
formed in 1956 from the transmission assets
separately owned by individual Vermont utilities
and with ownership based upon load ratio share
of all the Vermont utilities.
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VELCO is the nation's first statewide, "transmission
only" company
Until the recent merger of the 2 largest distribution
utilities (GMP and CV) there were 20 in Vermont of
which many are municipal based.
In 2006 VT Transco LLC was formed and owns the
transmission faculties while managed by VELCO
VT Transco has 738 miles of transmission lines and
55 transmission facilities (substations, switching
stations and terminals) as well as 1100 miles of
fiber optic cable.
Vermont’s peak demand was in 2006 at 1118 MW
We have about 4-5% of the demand in New
England
The economic downturn plus public policy on
distributed generation has reduced the peak and
curbed its growth
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Vermont / VELCO within ISO-NE, NPCC & NERC
NPCC
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VELCO System Prior to the Northwest Reliability Project
DC
• 2004
• Net importer of energy
• Mostly small scale hydro
– A hand full of GTs, Diesels, wood burners
of marginal size with largest being 52 MW
– Low short circuit strength in north
• 200 MW back-to-back HVDC
converter on main Quebec interface
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Installed in 1985 (control upgrade in 2012)
• Segmented “Block Load” on other
Quebec Interface
• Statcom (VSC) at Essex
– Commissioned in 2001
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VELCO North-west Reliability Project (NRP)
DC
• Extend 345 kV system closer to
Chittenden County
• From there replacing some subtransmission with 115 kV for
additional HV paths into the area
• Add +/- 60°phase shifting
transformers (PSTs) into our north
and central New York ties
• Breaker and Capacitor additions
• Granite Substation Upgrade:
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Two (2) New 230/115 kV Autotransformers
Each In series with 115 kV +/- 60°PSTs
Four (4) 115 kV 25 MVAR Cap Banks
Four (4) +25/-12.5 Sync Cond
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Connected on 13.8 kV AT tertiary windings
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Reactive Power Scoping and Technology for Granite (1/3)
• Project Need / Solution Development:
– For loss of a major line other lines could overload
– A PST on a key tie could avoid its own overload
– Need the 230 kV line at Granite to take on more flow so remaining
overloaded lines can be relieved. As such PSTs were planned for
Granite
– 230 kV tie needs reactive support to source the added real power
and avoid under voltage.
– Time frame for reactive power response allows for starting the
reactive facility pre-contingency to avoid losses and was initially
expected to be operational only 10% of the time
– Following the Essex Statcom project and the observed control
interaction with the HVDC station, Harmonics and low-voltage ride
through were lessons learned and were key points of interest for
the Granite Project
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Reactive Power Scoping and Technology for Granite (2/3)
• Capital Cost & Loss evaluation:
– Since the facility could be left off most of the time and just
started up pre-contingency the loss evaluation looked at two
conditions:
• Reactive facility always online. 90% of the time near 0 MVAR
(due to cap bank reserve capacity switching), 9% of the time at
half capacity and 1% of the time near nameplate
• Reactive facility offline (feeding only loads to keep protection
and controls alive including building HVAC, etc.) 90% of the
time, 9% of the time at half capacity and 1% of the time near
nameplate
– Considering the always online scenario, the SVC (TSCs,
TCRs and/or TSRs) option had the best loss profile. With the
90% offline scenario the Sync. Cond. option had the best
loss profile.
– The Statcom option came in 2nd on both of the above
scenarios.
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Reactive Power Scoping and Technology for Granite (3/3)
• In discussion with the VT Dept. of Public Service (DPS) we were
able to focus on either:
– Two (2) +25/-12.5 MVAR SCs per transformer tertiary
– One (1) SC per tertiary & 2 additional step-down transformers to
connect a 37.5 MVAR thyristor switched capacitor (TSC) & a 17
MVAR thyristor switched reactor (TSR) to each
– Both include mechanically switched capacitor (MSC) banks
– Since MSCs, SCs, TSCs and TSRs do not create harmonics (even
through MSCs and TSCs may interact with them) these are the
preferred tools to avoid lengthy studies to alleviate concerns about
possible interaction with other facilities.
– Statcoms and thyristor controlled reactors (TCRs) both create
harmonics which can be filtered but some level of net harmonics
would be added to the system.
– The above notes only the 1st stage of development at Granite. Later
discussions ruled out other than SC technology for the 1st stage
due to added equipment of having both technologies especially as
the chance of building Stage 2 at Granite became less certain
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Granite Overview 1-line – Granite RPD HMI
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Further Information about Granite (1/3)
• A Redundant Joint VAR controller (JVC) was installed as a part
of the SC installation which has control of the SCs, MSCs and
the Autotransformer LTCs
– The SCs when online are used to regulate the 115 kV
– The MSCs, when SCs are online, switch to offset the output of the
SCs to low loss or potentially absorbing operation
– The MSCs, when SCs are offline, are used to regulate the 115 kV
– The Autotransformer LTCs are used to regulate the 230 kV
• The SCs have 3 stages of dynamic response:
– It immediately response responds based upon to its pre-event field
(AKA: flux or internal voltage) and inertia
– The excitation controller (EC) has fast response for regulating the
13.8 kV bus based upon its set-point
– The JVC with VAR orders to the SCs via their unit controller (UC)
PLC sends increments and decrements to the EC for its 13.8 kV
set-point for change over seconds for 115 kV regulation
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Further Information about Granite (2/3)
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Islanding – Self-excitation
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MSCs and/or SCs
Speed of detection and mitigation
Delayed clearing options
When we switch a cap bank the rotor crowbar of the SC will fire and it
needs to be rated for and also self clear from this condition.
Because the SCs internal voltage is higher than that on the bus
generator class breakers and phase-phase arresters were needed if a
machine tripped during high output
Due to 13.8 kV designed for 40 kA only 3 machines can be connected
on a bus at a time but normally the tie breaker is left open with 2
machines available per tertiary. Stage 2 would require current limiting
reactors to reduce the short circuit duty if more SCs were added
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Further Information about Granite (3/3)
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We opted for a brushless exciter to reduce maintenance and while this
has similar performance on increasing field and therefore VARs it is
slightly slower for reducing the field.
– Because the rotor shaft side of the brushless exciter uses a diode
bridge to convert the AC field it receives into DC to decrease the
field the exciter DC voltage applied can only goto zero and let the
field decay versus applying negative voltage on the brushes to
force it down
– Applying negative voltage on a brushless exciter would have the
same effect as applying the same magnitude of positive.
– Since our contingencies call for a faster capacitive response this is
not an issue.
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SC Rotor Amps to Stator Amps (MVA) and Losses
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Starting a Synchronous Condenser (1/2)
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Due to cost we had opted for a reactor start for our condensers. The
options discussed were:
– Pony Motor Start – This a motor on the same shaft as the SC that spins
the machine up from a 480V or other LV source. This takes longer and has
added expense of the motor, its drives and larger station service system but
causes no significant system voltage drop during the start.
– Direct Line Start – If the system is strong enough, the impedance of the
coupling transformer high enough and/or no sensitive customer loads are
“nearby” then the SC could be placed on the system directly. This is the
fastest start and least expensive solution although the machine may need to
be designed for this
– Reactor Start – the SC will be started off the system but initially in series
with a reactor sized for allowable voltage drop with whatever outages are
assumed. This requires a reactor plus associated cables and at least 1
breaker. Less cost than pony motor but faster start. Most likely not black
start capable
– Since the scoping: Auto-Transformer/Reactor Start – Start with an auto
transformer in series with the SC then transitions to a reactor portion. This
adds an additional step for more control and likewise more cost.
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Starting a Synchronous Condenser (2/2)
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With our reactor start we have the following initial voltage dip with
typical generation dispatch:
– All-lines-In w/ 1 SC on same bus and 2 on other bus: 3.3%
– All-lines-In w/ only 2 SCs on other bus:
3.8%
– All-lines-In w/ no SCs online:
4.4%
– One line out w/ no SCs online:
8.9%
– One line out w/ only 2 SCs on other bus:
7.1%
– One line out w/ other 3 SCs online:
5.9%
With the All-lines-in case the start sequence has 135 seconds of
turning on support systems and validating their operation (shorter if
already online) before breakers operate at which the machine the start
is 12-17 seconds.
With future installations we plan to use pony motors to allow use during
black start
While we initially planned to operate only 10% of the time having some
portion of the facility online provides power quality benefit and mitigates
the power quality impact of additional machine starts
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Initial take on Operation (starting in Q4 2008)
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Before the SCs area caps were carefully applied to work the voltage
step change. Now the step change on area caps is less noticeable
allowing for more flexibility in dispatch
Power Quality: Sensitive loads no longer are effected by the majority of
operations in New Hampshire
Following our transmission expansions in southern Vermont (Q4 2010)
we had excess capacitance during light load periods.
– We initially started the 3rd and 4th machines up in the evening (and
pegged at full inductive for part of the night) and back offline in the
morning but decided to leave them online since if anything the
greatest wear and tear is a start sequence.
– Even when the excess capacitance was resolved ISO-NE
continues to call for the units to run for the added system event ride
through reliability they provide
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Low-Voltage Ride-Through and Delayed Clearing Event
• SC1 (example of all 4 units) – responding to SLG fault
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Some Lessons Learned
• Dedicated transformers versus leveraging transmission
autotransformers, while more expensive, would aid in outage
and clearance work for 13.8 kV system.
– These dedicated transformers would also have dual LV windings
for tying the 2 sides instead of using a tie breaker
• With plan to have units offline the materials of the cooling water,
piping and expansion tank need to be designed to avoid rust as
offline systems may have sustained oxygen in piping and
expansion tank will always have oxygen so it should potentially
be non-ferrous
• Radiator & fan design should look into lower noise options such
as variable speed motors or many smaller fans per radiator
• Pony Motors would avoid voltage drop on start
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Maintenance & Failures
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Radiator fan motors use belts which may break when starting a frozen
radiator fan. Have replaced 3 or 4 sets of belts each winter
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The facility has an extra radiator per unit
3 Radiator fan motors over 2 years will be replaced due to bearings
2 excitation system fans have been replaced over the 5 years. Will replace
all in 5 year intervals as well as electronic capacitors
2 unit controller (PLC) power supplies have failed over 5 years
All cooling water tank pressure-level transducers have been replaced in 3
years but this may have been due to a filtration process which sent more water
past the transducer
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Monthly maintenance includes a list of inspections and cleaning of
components such as air and cooling water filters
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System Operators report on SCADA alarms as needed
HMI remotely checked out regularly
Annual maintenance adds little to the monthly regiment but suggests
inspections that require a shutdown
We expect the know more following a ~5 year inspection
Breakers and Protection Systems on normal maintenance schedules
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Granite RPD Timeline
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2004, Q3: Sent mini-spec out to vendors for info on tech options
2005, Q2: in discussion with state finalized on SCs for Stage 1
– Q3: RFP sent to vendors, Pre-bid meeting, Bids in
2006, Q1: Final Q/A meetings with vendors, Pre-award meeting
– Kick Off meeting following contract
2007, June-July: SC factory witness testing
– December: Controls testing and control panel factory
2008, July-August: testing & commissioning
– September: Trial Operation Begins
– November: Trial Operation Complete
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Wind Generation…
• Wind generators have limits on their voltage/VAR control
• They create harmonics which in low short circuit areas can even
cause problems with their own operation as well as put
harmonics onto the system
• Synchronous Condensers
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Add to the VAR / Voltage capability of a Wind facility
Add modestly to the short circuit levels
No added harmonics (versus an SVC or Statcom)
Simplifying control interaction and voltage control studies
Reduce likelihood for low / high voltage wind facilitiy trips
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Questions / Comments?
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