2014 PV Distribution System Modeling Workshop: Interaction and Coordination with EPS Equipment: Chase Sun, PG&E

1. Inverter coordination with
existing distribution equipment
Chase Sun
PG&E
May 6, 2014
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2. Areas require coordination
• Protection
• Voltage regulation
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3. Protection
• Run fault studies with inverter modelled and with the inverter
contribution.
• Set each inverter to trip for end of line fault if possible. Conventional
overcurrent settings may not be adequate for variable resources such as
PV inverters since the settings may be too high when the PV output is low
in the morning and in the late afternoon. Often, the inverters are set up
for sequential tripping, using anti-islanding, after the feeder tripped first.
• Check to make sure that the inverter will not trip for adjacent feeder faults
that should be cleared by the adjacent feeder breaker.
• Check the existing feeder protective device settings for relays, reclosers,
interrupters, fuses, to make sure the existing relay settings are still
adequate with the inverter contribution. In other words, make sure the
devices will not be de-sensitized by a significant amount as to not trip for
an in-section fault. This is not usually an issue due to the low inverter
fault duty.
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4. Protection
• Check that the additional inverter fault duty will not
overstress existing equipment. This is usually not an
issue due to the low inverter fault duty.
• In general, each protective device, including inverters,
should trip for faults within its protected section and
not trip for faults outside of its protection zone. This is
problematic since the existing inverters are set up for
low penetration mode and may overtrip.
• At high penetrations, the inverter should not trip for a
system-wide event and aggravate the severity of the
event. This is being addressed in the Phase 1 revised
trip settings.
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5. Voltage interaction/coordination
Background
• Main issues:
• Traditionally, generators were connected to the transmission system, designed for
multi-directional flow where the conductors are much bigger and sized for both
local load and loop flow. Also, the transmission system is not regulated as tightly
as the distribution system.
• Distribution system was designed in a radial tree configuration, to distribute power
at the lowest cost. So, the distribution feeder mainline is composed of big
conductors, similar to a tree trunk, and the branch conductors are sized for local
load but not capable of carrying current for any significant distance without severe
voltage drop.
• For example, on the PG&E system, less than 15% of the overall distribution
conductor population are large mainline conductors sized at 397 MCM or larger.
PVs connected to large mainline conductors have minimal voltage impact to other
customers. But more than 85% of the locations have smaller conductors with
various degrees of voltage impact. The worst cases are larger units at the end of
small feeder conductors. In the interconnection studies, once the feeder is
reconductored, the voltage issues usually go away.
• PG&E has approximately 140,000 circuit miles of distribution conductors. it costs
about $500,000/mile to replace the conductor to 397 MCM or larger.
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6. Voltage interaction/coordination
Background
As a frame of reference, we can look at the current load review process:
• The distribution loads are reviewed during load interconnection to insure
that the load switching will not cause excessive voltage fluctuation to
other customers.
• CA Rule 2 limits the largest single phase 240V motor that can be started
across the line to 7.5 HP and the largest 480V, 3 phase motor that can be
switched across the line to 100 HP.
• Rule 2, Sec D3d states that for its operating convenience and necessity,
PG&E may elect to supply an applicant whose demand load is in excess of
2,000 kVA from a substation on the customer premises supplied from a
transmission source.
• Load has diversity that is well understood and utilized by the operating
utilities.
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7. Voltage interaction/coordination
Background
• The distribution system is also regulated to +/-5% of nominal
voltage by radial tap changing voltage regulators to provide the
proper utilization voltage to the distribution customers.
• The tap changing voltage regulators are not effective in regulating
voltage in the reverse direction when DG is present.
• The existing E/M regulators used time delays to coordinate
operation between multiple regulators. Since these are E/M
regulators, it takes time to change taps. Typically, there is about 20-
45 second time delay between regulators to insure the upstream
regulator is done with its correction before the next stage regulator
operates. Setting the time delays too close may cause hunting and
unstable operation between the regulators.
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8. Voltage Regulation
• There are no specific operational provisions for voltage rise due to DG in
Rule 21. For example, if the feeder is operating at 126V at peak already, as
allowed by Rule 2, there is no room for DG voltage rise. The good thing is
that PV peaks at noon and the feeders typically peak at 4-6 PM when the
PV output is much lower. At noon, the feeder voltage is typically not at
126V and there is more room for DG voltage rise. Please note that the
higher trip set point of 132 V specified in Rule 21 is intended to cover
voltage rise within the customer facility and not intended to allow the DG
to cause voltage beyond the PCC to operate at 132V.
• When Conservation Voltage Regulation (CVR) program is present, the
required operating voltage is restricted to +0% and -5% range which
further reduce the available DG operating voltage margin.
• Typically, the distribution engineer make adjustments in the voltage
regulator settings, when possible, to accommodate the DG voltage rise.
Often this reduces the operating flexibility of the distribution feeder.
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9. Voltage regulation
• DGs are generation sources and will cause voltage to rise in order to
push out the rated power.
• DGs are located on the load side of the voltage regulators and may
render the regulators ineffective.
• DGs are intermittent and not dependable from a capacity
perspective.
• PV also does not have that much diversity when it comes to cloud
cover effects. When a cloud cover comes over, the PV output may
drop from 100% down to 20% within seconds. For a storm cloud,
the drop may go lower.
• PV and wind output fluctuations may occur much faster than the
E/M voltage regulators can respond. Without mitigation, this may
reduce the power quality on the existing feeders and may have the
potential to damage customer equipment.
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10. Conventional voltage mitigation
• Reset LTC and voltage regulators, where possible, to allow more margin for the
inverters to operate.
• Replace radial regulator control to bi-directional control and set in Cogen Mode.
Bi-directional mode is intended for radial feed from a back-up feeder and not
intended for DG.
• Remove Load Drop Compensator setting and use flat voltage regulation and install
additional voltage regulators as needed.
• Re-design the LTC control circuit to allow proper voltage on the other feeders.
• Install large PV on dedicated feeders to minimize impact on load customers that
require +/-5% voltage regulation. This is how PG&E designed its own large PV
installations.
• Connect larger PV to the mainline, large conductors, and close to the substation.
• Reconductor the small wires causing the voltage violations. This is the most
effective and simplest but sometimes the most expensive option
• Relocate voltage regulators and capacitors to account for the prevailing DG
outputs.
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11. Potential smart inverter mitigations
• Note: The discussion below is relevant to larger inverters.
Volt/var control with small inverters may not be effective
since they may not be able to buck the system to any
significant extent. Also operating the feeder at off-unity PF
may increase the line current and increase line losses.
• High voltage due to PV reverse flow
– Set inverter at lagging PF to drag voltage down. This mode is
not considered active voltage regulation and is allowed under
the current Rule 21 and IEEE-1547. But this may require
installation of capacitors elsewhere to make up for the lost vars
to avoid voltage problems elsewhere.
– Reduce output at unit PF to maintain voltage below limits. This
may be viable for occasional overvoltage conditions.
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12. Smart Inverter Voltage Enhancements
• Other voltage control opportunities also exist
and should be explored.
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13. Active volt/var control issues
• Autonomous active volt/var control using local voltage feedback needs to
be coordinated carefully when there are multiple active control inverters
in the vicinity. If not coordinated properly, this may lead to the devices
fighting each other and potentially worse voltage on the feeder. This is
still an evolving area that needs more study.
• Communication based active volt/var control may be much simpler since
the central control computer can dictate which unit is in control at any
given time. But this may require a real time smart grid computer and an
extensive communication infrastructure, which do not exist at this time.
– Local master slave set-up is also possible with radio communication between the units.
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14. Potential ways to avoid/minimize inintended interaction
between autonomous active control inverters:
• Defined ramp up of var absorption rate when voltage goes over a preset
level to help reduce the local voltage.
• Defined ramp up of var injection when voltage goes below a preset level
to help raise the local voltage.
• Include deadbands to de-sensitize the inverter response
• Define time delay between specific inverters to allow one inverter to
complete its control action before the next inverter act.
• The inverter can respond much quicker than the voltage regulators when
the voltage is outside of the deadband. So, it would be desirable to have
the inverter complete its active voltage control action before the voltage
regulators respond. This may also minimize the regulator response and
reduce the wear and tear on the regulators.
• Set a large inverter to active volt/var control and disable the active
volt/var on the smaller units to avoid complications
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15. Outstanding high penetration issues
• Scenario 1: When there is a large amount of DG on the feeder that
displaced load normally, and there is a momentary fault on the
feeder. The feeder breaker will trip to clear the fault and all of the
DG are required to de-energize the line for safety reasons. On the
PG&E system, the feeder breaker is typically designed to reclose in
5 seconds to test the line. If the momentary fault cleared, the
feeder will be energized. But at that time, the DGs will be off and
the regulator will be seeing much higher load but it will not respond
until the time delay period expired. So, the effect is the same as a
large load switching in together. In that time frame, the customers
may experience low voltage due to the higher load. Without the DG
being there, there will not be any load masking and the regulator
will be set for the correct load level before and after the fault.
• A possible mitigation is to decrease the inverter re-energizing time
to minimize the time that the customers experience low voltage.
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16. High Penetration Issues
• Scenario 2: When there is a close-in adjacent feeder
fault, the bus voltage may sag to close to zero. The
current UV setpoint is 0.16 second at <50% voltage.
But the feeder breaker may not trip for more than 0.25
sec and all of the DG tied to that bus will trip
unnecessarily due to the current Rule 21 and IEEE-1547
setting. The sudden loss of a large amount of DG
capacity may also lead to low voltage conditions for the
load customers on the unfaulted feeder, until the
voltage regulation equipment can respond.
• The mitigation is presented in the Phase 1 UV settings
where we extended the time delay to 1 second for UV
<50% voltage.
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