Distributed Energy Resources€¦ · Before joining Beckwith Electric, Wayne performed in...

DistributedEnergy

Resources

Operation, Protection & Control

1

161031_CNY_2 Hr

November 7, 2016

Syracuse, NY

Presenter Contact Info

Wayne Hartmann is VP, Protection and Smart Grid Solutions for BeckwithElectric. He provides Customer and Industry linkage to Beckwith Electric’ssolutions, as well as contributing expertise for application engineering, trainingand product development.

Wayne HartmannVP, Smart Grid and Protection Solutions

Beckwith Electric [email protected]

904-238-3844

Before joining Beckwith Electric, Wayne performed in application, sales and marketing managementcapacities with PowerSecure, General Electric, Siemens Power T&D and Alstom T&D. During the courseof Wayne's participation in the industry, his focus has been on the application of protection and controlsystems for electrical generation, transmission, distribution, and distributed energy resources.

Wayne is very active in IEEE as a Senior Member serving as a Main Committee Member of the IEEEPower System Relaying Committee for 25 years. His IEEE tenure includes having chaired the RotatingMachinery Protection Subcommittee (’07-’10), contributing to numerous standards, guides,transactions, reports and tutorials, and teaching at the T&D Conference and various local PES and IASchapters. He has authored and presented numerous technical papers and contributed to McGraw-Hill's“Standard Handbook of Power Plant Engineering, 2nd Ed.”

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mailto:[email protected]

Objectives• Define DER

• Explore Types of DERs

• Why DER?

• Utility Drivers for DER

• Mission Critical Power and Conversion to DER

• DER Operational Sequences

• IEEE 1547: Industry DER Guide

• Interconnection Protection: “The Five Food Groups”

• Interconnection Transformer Impacts

• Self Protecting Inverters

3

Objectives• Generator Types and Impacts

– Synchronous– Induction– Asynchronous (Inverter Based)

• Example Protection Applications

• Protective Relay as a Utility/DER Interface Point

• Distribution Protection Coordination Issues

• Harmonics

• Smart Grid / Microgrid and DER

• Impact of IEEE 1547A

• VVO/IVVC with DER

• Summary and Q&A

4

4

What is DER?• Generation of electricity from small energy sources

– Typically <=10MW

• May be based at facilities, including industrial, commercial and residential, as well as utilities

• For this exploration, connected into distribution

• Use of Distributed Energy Resource (DER) allows collection of energy from many sources and may provide lower environmental impacts and improved security of supply

5

5

What is DER?

Also called:

• Distributed Generation (DG)

• Distributed Resource (DR)

• Dispersed Generation (DG)

• Embedded Generation

• Decentralized Generation

• Dispersed Storage & Generation (DSP)

• Decentralized Energy

• Distributed Energy

• Independent Power Producer (IPP)

• Non-Utility Generator (NUG)

6

6

• Conventional (Not Green)

– Burn conventional fuel

• Diesel

• Oil

• Gasoline

• Natural Gas (seen as “greener”)

DER: Green or Conventionalby Energy Source

7

7

Conventional DERIndustrial Gas Turbine Reciprocating Diesel

Reciprocating Gaseous FuelMicroturbine Gaseous Fuel

Reciprocating aka: Internal Combustion Engine (ICE)

8

8

Fuel Cell

Conventional DER

9

9

• Green (Renewable)

- Use renewable sources to reduce reliance on fossil fuels:

• Hydro

• Solar (PV)

• Solar (thermal to steam)

• Wind

• Biodiesel

DER: Green or Conventional by Energy Source

10

• Biogas (methane decomposition)

• Biomass (direct burn/gasification)

• Tidal

• Storage (battery)

10

Renewable DER

Small HydroSolar (PV)

PV Array/Battery

(DC)AC Output

11

Solar (Thermal)

11

Renewable DER

Biogas

Wind

Biomass

• May be induction or

synchronous generator

output

• May be mixture of

generator and inverter

output

12

12

Renewable DER

Biodiesel Tidal

13

Renewable DERStorage Battery

Battery(DC)

AC Output

14

14

• T&D Issues– Decrease losses

– DER at the point of use is not subject to transport loss

– T&D losses range 3-7%

• Demand Response – Turn On Local DER to Turn Off Load to System”

– No prebound/rebound effects in callable application

– Allows larger critical process C&I Customers to participate in demand response programs

– aka: Peak Reduction

Why DER: Utility Drivers

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15

THIS IS THE MOST EXPENSIVE, INEFFICIENT, AND

ENVIRONMENTALLY-DAMAGING POWER PER KWH OF

ELECTRICITY ACTUALLY CONSUMED

• Accumulated Annual Demand of Highest 5% occurs about 400 hrs/Year

• 100s of Billions of $ of equipment and capacity idle for most of the time

Reality of Grid Load Dynamics (Peak Demand)

16

16

• With DER

DER in a Demand Response Role

• Without DER

DER

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17

Sustainability & Losses:Conventional Power Delivery

Transmission

Losses

Subtransmission

Losses

Distribution

Losses

Bulk Generation

Asset

Load

525 kVA

500 kVA

•Losses typically 3-7%

•5% used in this example

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18

Transmission

Losses

Subtransmission

Losses

Distribution

Losses

Bulk Generation

Asset

LoadDG

500 kVA 500 kVA

•Heat rates (efficiency) of modern engine/gensets applied in DER

systems are as good, if not better, than combustion turbines (CTs) [1,2].

• DER capacity has a heat rate of 9,800 btu/kWh saving approximately

2,200 btu/kWh of fuel input compared to the overall peak power

generation portfolio published by eGrid [3].

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[1] California Energy Commission;

http://www.energy.ca.gov/distgen/equipment/reciprocating_engines/reciprocating_engines.html

[2] California Energy Commission;

http://www.energy.ca.gov/distgen/equipment/combustion_turbines/combustion_turbines.html

[3] http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html

Sustainability & Losses:Conventional Power Delivery

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Non-Signaled Passive Demand Response:Rebound Effect

Time of Day

Loa

d

Curtailed Load

Rebound Load

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Signaled Passive Demand Response:Prebound-Rebound Effect

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Signaled DER-based Demand Response:No Prebound-Rebound Effects

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• Transmission decongestion

• Distribution decongestion

• Distribution build-out deferral

• Grid Support – Ancillary Services

• Voltage regulation

• VAR Support

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• T&D Issues– Firming of Green Power

• Green power has intermittency issues

• Answered with fast syncing DER

– Conventional DER

– Storage

– Ready and Standby Reserves• Fast syncing prime movers

– Spinning Reserves• Synchronized storage


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ATS vs. Circuit Breakers

LOAD

UTILITY

G

LOAD

UTILITY

G

G

M

ATS Circuit Breakers

• ATS does not protect

• ATS cannot long-term parallel

• Circuit Breakers cost more than an ATS, but provide

protection and operational flexibility

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25

Conversion of ATS-based emergency system to dual purpose emergency and

“bumpless” peak shaving system

LOAD

UTILITY

G

LOAD

UTILITY

G

G

M

Existing FacilityFacility Retrofit with Switchgear/

Protection/Controls for Grid Paralleled

Generator Operation

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26

LOAD

UTILITY

Existing FacilityFacility with Generator and

Switchgear/Protection/Controls

Added

LOAD

UTILITY

G

G

M

Greenfield dual-purpose emergency and “bumpless” peak shaving system

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27

Complex Application: Dual-Fed Facility Main-Tie-Main

UTILITY UTILITY

T

LOADS

L L LLL L

LOADS

M

1

M

2

Existing Facility

UTILITY UTILITY

LOADS

L L LLL L

LOADS

M

1

M

2

Facility with Generators and

Switchgear/Controls Added

G

G

T

G

G

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Operational Sequence Details

• Emergency Power

• Load Isolation

• Load Following

• Export

To know how DER is controlled in parallel with a utility is important for DER Interconnection protection application

When control fails, protection is the safety net

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29

Po

we

r

Facility Demand

Generator Output

Utility Import

Time

Generator Starts

Generator CB 52G Closes

Generator Picks Up Load

Utility Power Fails,

Utility CB 52M Opens

Emergency Power Mode

Generator CB 52G Opens,

Generator Shuts Down

Utility CB 52M Closes,

Generator Unloads

LOAD

UTILITY

G

G

M

WL

WU

WG

Emergency Power: Details

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Load Isolation: Details

Load

Management

LOAD

UTILITY

G

G

M

WL

WU

WG

Po

we

rFacility Demand

Generator OutputUtility Import

Time

Load Management Period

Main Breaker to

Utility Opens

Main Breaker to

Utility Closes,

Generator

Unloads

Generator Starts,

Synchronizes and

Picks Up Load

Generator

Breaker Opens,

Generator Shuts

Down

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Load Following: Details

Load Management

LOAD

UTILITY

G

G

M

WL

WU

WG

Po

we

r

Facility Demand

Generator OutputUtility Import

Time


Utility Import

Generator Starts,

Synchronizes and

Picks Up Load Generator

Breaker Opens,

Generator Shuts

Down

Generator

Unloads

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32

Export: Details

Load Management

LOAD

UTILITY

G

G

M

WL

WU

WG

Po

we

r Facility Demand

Generator Output

Utility Import

Time


Export to Utility if Possible

Generator Starts

Generator CB 52G Closes

Generator Picks Up Load

Generator CB 52G Opens,

Generator Cools

& Shuts Down

Generator Unloads

Facility Demand

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Example DER System

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35

UTILITY

LOAD

52

G

52

M

LV Switchgear

Load Bus

G

Interconnection Protection

Generator Control & Switchgear Position Control

Engine/Generator

Communications for Remote Dispatch &

Monitoring

Interconnection Protection in LV Switchgear

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Interconnection Protection in LV Switchgear

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Protective Relay

36

UTILITY

LOAD

52

G

52

M

LV Switchgear

Load Bus

G



Engine/Generator


Monitoring

Protection and Control

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• Protection that allows the DER to operate in parallel to utility

• Large non-utility generators do not require specific interconnection protection

- Integrated into transmission system

- Interconnection breaker(s) are tripped by transmission line/bus/transformer protection.

• Smaller DERs do require specific interconnection protection- Goes for conventional as well as inverter-based systems

What is DER Interconnection Protection?

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Protection ObjectivesUtility Perspective

Personnel safety after deliberate feeder de-energizing

Minimize/prevent DER fault backfeed contribution Coordination issues with other protective elements

Breakers/relays and reclosers on affected feeder

Breakers/relays and reclosers in adjacent feeders off the same bus as affected feeder

Damage to equipment

Transient overvoltage

Ferroresonance

Avoid damage to utility equipment and customer loads from

abnormal operating conditions during islanding Voltage issues

Frequency issues

Harmonic/PQ issues

Simplify restoration Easier reclosing without synchronizing at utility breakers

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Protection Objectives DER Perspective

Avoid mal-synchronization damage

Can occur after utility reclosing after initial feeder clearing

Out-of-phase closing (shaft torque stress; motors and generators)

Minimize/prevent damage to DER by pumping current into

utility fault

Detection of abnormal operating conditions at utility that

can cause damage to DER and facility

Over/under voltage

Over/under frequency

Overexcitation

Unbalanced voltages/single phasing

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• Seamless integration of DERs into utility protection system despite:- “Too many cooks in the kitchen”

• Owner, Consultant, Packager, Utility

- Ownership boundaries- Conflicting objectives of DER Owners vs. Utility

• DER Owner: “We do not want to pay for anything.”• Utility: “We want everything and for you to pay for it.”

• Ensuring protection is correct over the life of installation- Settings are properly developed- If installation or EPS changes, assess impact on existing

protection

DER Protection Engineering Challenges

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41

IEEE 1547

IEEE Std. 1547A; Ride through (2014)

42

Presently under

revision to include

1547a content

Really good

application guide

42

• DR Unit: Distributed Resource (DER)

• EPS: Electric Power System

• Interconnection: The result of the process of adding DR to an Area EPS.

• Interconnection Equipment: Individual or multiple devices used in an interconnection system.

• Interconnection System: The collection of all interconnection equipment and

functions, taken as a group, used to interconnect DR unit(s) to an Area EPS.

DR Unit Area EPS

Interconnection system

IEEE 1547 Definitions

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43

Area EPS

• Area EPS is the portion of the

power system that is impacted

by the DER

• Typically the distribution system

including the connected

substation

• If DER capacity is large,

transmission could possibly be

effected

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44

IEEE 1547 Definitions

PCC: Point of Common Coupling

PI: Point of Interconnection

EPS: Electric Power System

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45

IEEE-1547: 50,000’ Overview• Safety

– Personnel working on a utility system must be protected from backfeed or accidental energization from DER

• Impact of size– Intended to cover up to 10MW

• Local Disturbances– Quality of service on the utility system should not be degraded

(voltage, frequency, harmonic limits)

• Impact to Existing Distribution Protection– Dealing with bi-directional power flows and coordination in radial

systems turned multiple source systems

• Impact of Islanding– Creation of unintentional islands must be detected and eliminated as

fast as possible

46

46

Greatly complicates restoration

- Requires synchronizing at utility substation

- Inhibits automatic reclosing

Power quality issue

- DER may not be able to maintain voltage, frequency and harmonics within acceptable levels (load generation; no harmonic “sink”)

SmartGrid and Microgrid may allow islanding in future

Islanded Operation of DER with Utility Load Is Generally Not Allowed

Loads Loads Loads

Loads LoadsLoads Loads Loads

Loads Loads

Loads Loads Loads

Loads

Loads

DER

Utility Substation

If DER creates a feeder island,reclosing requires synchronizing atthe utility substation

Feeder Island

47

47

Feeder deenergizes when utility opens feeder

Restoration responsibility on the DER

- Requires synchronizing to Utility

DER Facility Islanding to the Utility is Allowed

Loads Loads Loads



Loads

LoadsDER

Utility Substation

DER can create its own island,and synchronize to the utility

DER Island

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48

DER Interconnection Protection• Transformer connections

– Effect on EPS fault duties

– Effect on possible overvoltage conditions

– Interaction with generator connections

– System modifications

• Grounding of the DER system– Grounding for safety

– Effect on EPS ground protection

• Abnormal system configurations– Alternate source

– Abnormal sectionalizing

– Alternate breaker or transfer bus

IEEE 1547 Standard Series: Addressed Areas

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49

DER Interconnection Protection• Radial versus bidirectional power flow

– Effect on protective equipment

– Effect on voltage regulators

– System modifications

– System costs

• Voltage deviations– Three-phase

– Single-phase

– Induction versus synchronous

– Voltage rise phenomenon

– Surges, sags, and swells


50

50

DER Interconnection Protection

• Unintended islanding

• Reclosing– Main or source circuit breaker

– Reclosers and sectionalizers

– DR equipment

• Harmonics

• Flicker

• Spot Networks


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51

Spot Network

• Network Protectors are not rated for fault duty that DER can backfeed

through them

• They are also not rated for larger-than-rated voltage that can occur when

DER is on-line and the network protector is open

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52

DER Interconnection Protection

• Synchronization

• Loss of synchronism

• Operational safety practices

• System capability– Short-circuit capability of EPS equipment

– Loading capability of Area EPS

IEEE 1547 Standard Series Addressed Areas

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53

• Utility-Grade interconnection relays- Pass all pertinent ANSI standards- C37.90-1,2,3

• CT and VT requirements (quantities sensed)

• Winding configuration of interconnection transformers

• Functional protection- 81U/O, 27, 59, etc. - Settings of some interconnection functions

• Pick ups• Trip times

What Utilities Generally Specify

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Protection Elements and Use

– “The Five Food Groups”• Loss of Parallel Operation (utility disconnected)

– Anti-Islanding

• Abnormal Power Flow– Anti-Islanding

• Fault Backfeed Removal

• Detection of Damaging System Conditions

• Restoration

– Impact on interconnection protection• Interconnection transformer configuration• Various types of DERs

– Induction, Synchronous, Asynchronous (Inverters)

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55

Loss of Utility Parallel (Anti-Islanding)

– Voltage and frequency (27, 59, 81-U, 81-O)

– Rate-of-change of frequency (81R, aka ROCOF)

Based on load (real and reactive) not equaling generation

Abnormal Power Flow (Anti-Islanding)

– Power (32F, 32R-U)

Based on power flow violations across the PCC

Interconnection Protection“The Five Food Groups”

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Low Import Power: 32R-U

32R-U Relay pickup set

to at least 5% of total

connected generator

rated KVA

32R-U Relay

programmed to trip when

imported power falls

below the pick-up level

Switching off a large

amount of facility load

may cause nuisance

tripping

Generator Control should

have proper bias power

margin set

SUPPLY,Low Side

52

I

UTILITY

52

G

52

L

RelayLOADS

ReversePower

ForwardPower

REVERSE UNDERPOWER (32R-U)

NO TRIP

Reverse Forward

TRIP

Pick up

-P +P

52

G b 52

Ib

Control/Status Input programmed to block 32R-U if either/both the generator breaker or

interconnection breaker are open

57

57

• Bias is made in the genset controller to ensure import of 40kW when paralleled

• 32R-U is set lower with appropriate margin (trips if import goes below genset control setpoint)

Low Import Power: 32R-U

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58

Fault Backfeed Detection

Phase and overcurrent (51V, 51)

– Directional overcurrent (67) or impedance (21) may be used

Backfeed from Grounded DER

– Ground overcurrent (50N/51N)

Directional ground overcurrent (67N) may be used

Backfeed from Ungrounded DER

– Ground over/under voltage (27N, 27N/59N)

– Negative sequence overcurrent (46)

Based on abnormally high current or abnormally low/high

voltage as a result of faults


59

59

The winding arrangements facing the

utility and the facility have an impact on

protection

Interconnection Transformer convention:

• Utility = Primary

• Facility = Secondary

Interconnection Transformer Winding

Arrangements Impact Protection

60

60

Interconnection TransformersPrimary (Utility) Grounding Impacts

Grounded Primary: Pros:

• No overvoltage for ground fault at F1

• No overvoltage for ground fault at F2

• No ground current from feeder for faults at

F3 (delta sec. only)

Cons:• Provides an unwanted ground current for

feeder faults at F1 and F2

• Creates a ground source even when delta secondary circuit is disconnected

• May cause coordination problems within facility as well as increased ground fault current to Utility

• Allows feeder relaying at A to respond to a secondary ground fault at F3 (Ygnd-Ygnd

only)

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61

Interconnection TransformersPrimary (Utility) Grounding Impacts

Ungrounded Primary:

Pros:

• No ground fault backfeed for fault at F1

& F2

• No ground current from breaker A for a

fault at F3

Cons:

• Supplies the feeder from an

ungrounded source after substation

breaker A trips causing overvoltage

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62

a

bc

a

bc

ground

Van=Vag

Vbn=VbgVbn=Vbg

n=g

vag=0

n

Van

= -Vng

Vcn Vbn

Vbg

Vcg

Unfaulted

Ground Fault

DER

Backfeed to Utility

DER Facility

Ungrounded Primary:

Faulted System Backfeed Overvoltage

63

63

a

bc

a

bc

ground

Van=Vag

Vbn=VbgVbn=Vbg

n=g

vag=0

n

Van

= -Vng

Vcn Vbn

Vbg

Vcg

Unfaulted

Ground Fault

DER

Backfeed to

Utility

DER

Facility

59

N

Sensing Ungrounded System Ground Faults

with 3 Voltage Transformers

64

64

a

bc

a

bc

ground

Van=Vag

Vbn=VbgVbn=Vbg

n=g

vag=0

n

Van

= -Vng

Vcn Vbn

Vbg

Vcg

Unfaulted

Ground Fault

Sensing Ungrounded System Ground Faults

with 1 Voltage Transformer

DER

Backfeed to Utility

DER Facility

59

N

27

N

• Subject to ferroresonance

• Place maximum resistive

burden on VT to help

prevent

65

65

• Many utilities only allow use of ungrounded primary windings only if the DER sustains at least a 200% overload on islanding

• The overload prevents the overvoltage from occurring

Impact of Overvoltage:

Saturation Curve of Pole-Top Transformer

66

66

• When applying non-directional phase or ground elements for fault backfeed protection (50P, 50N, 51P, 51N), they must be coordinated for faults in the facility and on the utility.

• This could lead to longer clearing times for utility faults.

• To speed up response of utility faults, use of directional elements (67, 67N, 21P), set to only trip in the utility’s direction, will provide maximum trip speed.

Directional vs. Non-Directional Elements at the PCC

DG

Protection

C

A

B

DG

Protection

67

67


Damaging System Conditions

– Open phase condition or load imbalance (46, 47), negative sequence current and voltage

– Phase sequence reversal , negative sequence voltage (47)

– Loss of synchronism (78)

– Ferroresonance, instantaneous overvoltage (59I)

Based on current or voltage imbalance (including reverse phase rotation),

power system and DER going out-of-step, or ferroresonance

Facilitate proper restoration

– All elements reset, voltage and frequency within limits

– Reconnect timer (79) (all DER)

– Sync check (25)

• Synchronous generators , some inverters and facilities with motor loads

68

68

• Induction

• Excitation provided externally by system- VAR drain

• Less costly than synchronous machines- No excitation system or control

- No sync equipment needed

• Limited in size to <=500 KVA

• May cause ferroresonance after disconnection from utility

(self-excitation from nearby caps)

VAr Source

Induction Generator

Types of Generators

• Some Wind Power

• Some Small Hydro

• Some small prime mover driven

69

69

• Ferroresonance can take place between an induction generator and capacitors after utility disconnection from feeder

– Ferroresonance can also occur on Synchronous Generators!

• Generator is excited by capacitors if the reactive components of the generator (XG) and aggregated capacitors (XC) are close in value

• This interplay produces non-sinusoidal waveforms with high voltage peaks. This causes transformers to saturate, causing non-linearities that exacerbate the problem.

Ferroresonance

70

70

New York Field Tests- 1989

Field Test Circuit

Test Circuit Setup

71

71

Conditions:

Wye-Wye Transformers, 100kVAr capacitance, 60kW generator, 12kW load

New York Field Tests- 1989

Field Test Circuit

Ferroresonance:

Test Circuit Setup

72

72

52

I

UTILITY

52

G

BUS

LED Targets

Programmable I/O

Metering

IRIG-B Input

Communications Ports

Waveform Capture

Sequence of Events

Integral HMI

Multiple Setting Groups

Dual Power Supply

1

59

N

27

N1 or 3

Ungrounded Primary

Protection Element Usage

51

N

50

N

M-3520 Relay

Fault Backfeed Removal

Damaging Conditions

Loss of Utility Parallel(Anti-Islanding)

Abnormal Power Flow

Restoration

213251

V67

3Y

79

27475981

0/U

81

R

25

59

I

60

FL46

67

N50

1

2 or 3

78

Grounded Primary

73

73

Inverter Active Anti-Islanding Protection

Impedance Measurement

• Similar Methodologies and Other Names– Power Shift; Current Notching; Output Variation

• Theory:– Amplitude of current changed (increased)

– With utility connected, little resultant voltage change

– With utility disconnected, larger resultant change

• Works well with single inverter

• Multiple inverters can swamp each other out as amplitude change is not synced between inverters

74

74


Detection of Impedance at Specific Frequency

• Similar Methodologies and Other Names– Harmonic amplitude jump

• Theory:– Inject a current harmonic of a specific frequency

– Utility impedance is much lower than the load impedance at the harmonic frequency, then the harmonic current flows into the grid, and no abnormal voltage is seen

– With utility disconnected, a harmonic voltage is developed

• Works well with multiple inverters

• May be difficult to obtain secure yet dependable settings

75

75


Slip Mode Frequency Shift (SFS)

• Similar Methodologies and Other Names– Slide Mode Frequency Shift; Phase Lock Loop Slip; “Follow the Herd”

• Theory:– Moves phase angle of voltage dependent on frequency measured,

thereby causing changes in frequency– With utility connected, frequency does not change– With utility disconnected, frequency change is detected

• Highly effective in the multiple inverter applications and provides a good compromise between islanding detection effectiveness, output power quality, and impact on transient response of overall power system.

• May be difficult to obtain secure yet dependable settings

76

76


Frequency Bias

• Similar Methodologies and Other Names– Frequency Shift Up/Down; Active Frequency Drift

• Theory:– Current waveform of inverter is slightly distorted such that there is a

continuous trend to change frequency– When connected to utility, it is impossible to change frequency– When disconnected from utility, frequency forced to drift up or down

• Frequency bias requires small degradation of PV inverter output power quality

• In order to maintain effectiveness in multiple-inverter case, there would have to be agreement between all inverters on direction of the frequency bias.

77

77

Inverter Active Anti-Islanding Protection Sandia Frequency Shift (SFS)

• Similar Methodologies and Other Names– Accelerated Frequency Drift; Active Frequency Drift with Positive

Feedback; “Follow the Herd”

• Theory:– Frequency is changed up or down depending on if higher or lower

than rated– When connected to the utility grid, minor grid frequency changes are

detected and the method attempts to increase the change in frequency but the stability of the grid prevents change

– When disconnected from the utility, the frequency is forced to drift up or down

78

78


Sandia Frequency Shift (SFS) (con’t)

• Provides a good compromise between islanding detection effectiveness, output power quality, and system transient response effects

• Requires that the output power quality be reduced slightly when it is connected to the grid because the positive feedback amplifies changes that take place on the grid

79

79

Inverter Active Anti-Islanding Protection Sandia Voltage Shift (SVS)

• Similar Methodologies and Other Names– Voltage shift, positive feedback on voltage; “Follow the Herd”

• Theory:– Voltage is increased or decreased according to if utility voltage is

above or below rated– When connected to the utility grid, there is no change in voltage– When disconnected from the utility, there is a change in voltage

• Effective islanding prevention

• Method may have small impacts on the utility system transient response and power quality– Penetration levels of inverters using SVS may have to be kept low on

weaker grids in order to avoid system-level problems

80

80

Inverter Active Anti-Islanding Protection Frequency Jump

• Similar Methodologies and Other Names– Zebra Method

• Theory:– Dead zones are inserted into the output current waveform at some

interval of cycles– When connected to the utility grid, the dead zone is not detected– When disconnected from the utility grid, the dead zone is detected

• Not useful on multiple inverter applications

81

81

Induction Contributes fault current

Usually not capable of fault backfeed VARs from system required to operate

Fault contribution characteristics same as induction motor

Sync equipment not needed

Synchronous Contributes fault current

Capable of short time sustained fault backfeed due to presence of an exciter

Sync equipment needed

Types of Power Sources

82

82

Synchronous Generator

Synchronous

- Excitation provided by field

• May be a VAR source

• Requires excitation system and control

- Sync equipment needed

- Sized 10kW and up

• Types of Generators

- Prime mover driven

- Some wind

- Some hydro (larger)

83

83

Small Generator Fault Current Contribution

• It’s all about x”d - t”d, x’d - t’d, and xd, plus how excited (self or PMG)

– x”d used for initial fault level determination

• x”d and t”d is subtransient current time

– x”d used for next interval of fault level determination

• x'd and t’d is transient current time

• Consult genset manufacturer for alternator data sheets!

84

84

≈400kVA Generator

Rated Amps = 482A

85

85

Self-Excited

Genset

86

Fault Current for≈400kVA Generator

86

Small Genset Current Decrement for PMG

• PMG =

Permanent

Magnet

Generator

• Uses PM

Excitation that

does not fully

collapse fault

current

• This example is

from a small

genset, about

600A rated

current

“Cummins Power Generation: Application Manual -- Liquid Cooled Generator Sets” -- Ver.G.EN

87

87

• Asynchronous (Static Power Converters)

– Capable of limited fault current

– Grid Paralleled and Grid Isolation Variants and Operational Modes• Grid Isolated Mode uses Voltage Control and

may be capable of fault backfeed and fault ride-through

• Grid Isolated Mode may require sync check for connected loads if rotating machinery

Types of Power Sources

88

88

Asynchronous

- Static Power Converter (SPC) converts generator

frequency to system frequency (dc-ac or ac-dc-ac)

VARs

Types of Generators

•Solar, PV

•Fuel Cells

•Wind

•Microturbine

•Storage

Asynchronous Generator:

Static Power Converter or Inverter

DER

89

Asynchronous Tie

89

• Voltage Controlled

• Can provide limited fault current to the grid

• Fault current is in the order of 1.1-1.3 pu rated load current

• Can provide fault ride-through

– Fault current will be maintained as long as trip settings allow

• Operating in Voltage Control Mode: Fault current reactive component will increase as the inverter contributes to a fault

• Can cause system transient overvoltages if power output to connected load ratio suddenly decreases (transient control issue)

Non-Grid Parallel Inverters

90

90

• Current Controlled

• Can provide limited fault current

– Fault current is in the order of 1.1-1.3 pu rated load current

– Fault current will decay when utility disconnects

– If overloaded current will diminish even faster

• Can cause system transient overvoltages if power output to connected load ratio suddenly decreases (transient control issue)

Grid Paralleled Inverters

91

91

• Most grid paralleled inverters have built-in anti-islanding protection (if UL 1741 compliant)

– Inverter tries to periodically change output (f, V or I)• If grid is hot, inverter cannot make noticeable change

• If grid has tripped, the f, V or I moves and the controller trips the machine

– Difficult to test; some utilities do not trust and require other protection

Grid Paralleled Inverters

92

92

Inverters, Sudden Load Rejection and Overvoltage

INVERTER

Inverter Isolation Transformer

PCC Transformer

480V Bus Utility

MV

To UTILITY

SUBSTATION

To OTHER FEEDER LOADS

“Effective grounding of distributed generation inverters may not mitigate transient and temporary overvoltage”;

WPRC Conference 2012; M. E. Ropp, Member, IEEE, M. Johnson, Member, IEEE, D. Schutz, Member, IEEE, S. Cozine,

Member, IEEE

• Tests run on inverter to

connected to 480V Bus,

then connected to

utility MV feeder

• Used different

ISOLATION transformer

winding arrangements

and PCC transformer

winding arrangements

• Varied the level of load

rejection (load:gen) to

see transient voltage

response effects

93

93

Typical response seen when load is suddenly rejected and load:gen ratio changes

94


94

Transient overvoltage an inverter control issue, not a grounding issue

95


95

DER Reconnect Timer & Reclose Permissive• Used to assure utility has gone through successful reclose cycle

• Set longer than total reclose cycle

• All clearing and shot time, plus longest possible reclaim time

• Typically set in minutes

• Uses permissive from voltage and frequency functions to assure utility source is back and viable

96

96

DER Protection Coordination

• Tripping Order

– Utility

– DER Interconnect

– DER Generator

• Restoration Order

– Utility Substation Breaker (or Recloser)

– DER Interconnection Breaker

– DER Generator Breaker (if tripped)

97

97

ORUTILITY (PCC)

PROTECTIONS

TRIP

UTILITY

CB

0T

UTIILTY CB

RECONNECT

PERMISSIVE

SYNC CHECK

FUNCTION

NOT

RECONNECT

TIMER

NOTES:

“T” in the timer function is the preset time delay. Timer is time

delay on pickup type.

Sync check function(s) sourced from PTs from the load bus and

the Utility (PCC)

(PCC)

(PCC)

AND

UTILITY

LOAD

52

G

52

M

LV Switchgear

Load Bus

G



Engine/Generator


Monitoring

Typical Trip/Reconnect Logic

98

98

Harmonics

• Single DER harmonic limits• What about high penetration with

different inverter firing methods?

99

Source: 1547 D3.1, unapproved draft

99

Harmonic Concerns• If high penetration of inverters causes great

enough harmonics at system resonant point, currents flow to cap banks and cause hearting and possible damage

– Inverters are the source

– Caps are the sink

• A good defense is a good defense

– Employ DER protection and capacitor bank controls with harmonic monitoring, alarming and tripping

100

100

Harmonic Monitoring, Alarming and Tripping

• DER Protective Relay should monitor, log, alarm and trip for:

– THD, voltage or current

– TDD, current

• TDD is called out in IEEE-1547

• Capacitor Control should monitor, log, alarm and trip for:

– THD, voltage

101

101

DER Loads Loads

Utility

Point of Common Coupling

Interconnection Transformer

DER InterconnectionProtection

Sync

3Y

3Y or

1

Point of Interconnection

Interconnection Protection Placement

102

102

DER Loads Loads


Utility



Sync

3Y or

1


103


103

DER Loads Loads

Utility




Sync

Ungrounded Primary

Only

3Y or

1

3Y- or 1


104


104

DER Loads Loads

Utility




Sync

Ungrounded Primary

Only

3Y or

1

3Y- or 1


105


105

106

52

I

UTILITY

52

G

BUS

LED Targets

Programmable I/O

Metering

IRIG-B Input


Waveform Capture

Sequence of Events

Integral HMI


Dual Power Supply

1

59

N

27

N1 or 3

Ungrounded Primary


51

N

50

N

M-3520 Relay


Damaging Conditions


Abnormal Power Flow

Restoration

213251

V67

3Y

79

27475981

0/U

81

R

25

59

I

60

FL46

67

N50

1

2 or 3

78

Grounded Primary

Comprehensive Protection Application

106

52

I

UTILITY

52

G

BUS

LED Targets

Programmable I/O


Waveform Capture

Sequence of Events

Integral HMI


59

N

27

N1

Ungrounded Primary



Damaging Conditions


Abnormal Power Flow

Restoration

51

V3Y

79

27475981

0/U

25

59

I

60

FL46

51

N

1

2 or 3

Grounded Primary

*

**

**

* = Use of 27N & 59N excludes 25 from use* = Use of 25 excludes 27N and 59N from use** = If using 27N, 59N or 25, VTs must be open delta

32

107

Small DER or Inverter Protection Application

107

108


Damaging Conditions


Abnormal Power Flow

Restoration


1

Time Overcurrent

Ground

Inverse TimeOvercurrent

Ground

50G 51G

M-7610A I-PAC

3I1, I2, I3, IN (3 I )

59Vx

27Vx

DirectionalOvercurrent

Ground

Overvoltage Undervoltage

V1, V2, V3 ,VN (3 V )

3

VX

67G

25

Sync Check

5 55

IG

0

0

60FL

VT FuseLoss

DirectionalTime Overcurrent • Phase • Neg. Seq. • Neutral

BreakerFailure

50 BF

DirectionalPower

32

Definite TimeOvercurrent • Phase • Neutral

Inverse TimeOvercurrent• Phase with Voltage Restraint• Phase with Voltage Control• Neutral

NegativeSequence

Overcurrent

45555

UnderPowerRelay

37PQN

6751

50 PN 46

Volts/Hz

24

Undervoltage• Phase• Neutral• Phase-to-Phase

PN

PP27

4

Negative Sequence

Overvoltage

4759

Overvoltage• Phase• Neutral• Phase-to-Phase

PN

PP

4

OU81

Frequency• Over• Under

4

59I

PeakOvervoltage

81R

Frequency Rate of Change

2

P-VRP-VC

N

79

UTILITY

52

I

52

G

1

1 or 3

LOAD BUS

Reconnect

Advanced Convergent Protection Application

108

109

• Ethernet

– 7 Concurrent Sessions

• Protocols

– DNP 3.0

– IEC-61850

• Cyber Security

– NERC CIPS

– FIPS

– Radius

– IEEE Complaint Passwords

• Extended Logging

– Distributed Data Storage at PCC

• Power Quality Monitoring

– 128 samples per cycle

– Harmonics to the 63rd

– THD, TDD

– Sag/Swell/Flicker

• DME Oscillography Capture

• Utility/DER Interface Point

Convergent Attributes for Smart Grid

109

• 2002 Survey- Grounded wye primary – 58%

- Delta primary – 9%

- Other – 33%

• 1995 Survey- Grounded wye primary – 33%

- Delta primary – 33%

- Other – 33%


IEEE Distribution Practices Survey – 1/02

110

110

• No effect – 22%

• Revised feeder coordination – 39%

• Added directional ground relays – 25%

• Added direction phase relays – 22%

• Added supervisory control - 22%

• Revised switching procedures – 19%

Impact on Utility Protection


111

111

Bidirectional Fault Currents: Coordination

• Use directional elements in substation protection, mid-line reclosers and DER

– Substation• Directionalize using 67 and 67N (instead of 50/51 and 50/51N)

• Trip toward DER (downstream) to avoid sympathy trips for out-of-section faults

• Trip toward Substation for remote breaker failure

– Reclosers• Directionalize using 67 and 67N (instead of 50/51 and 50/51N)

• Trip toward Substation for remote breaker failure

– DER• Directionalize using 67 and 67N (instead of 50/51 and 50/51N)

• Trip direction away from DER (upstream)

112

112

50

51

50

N

51

N

50

51

50

N

51

N

50

51

50

N

51

N 50

51

50

N

51

N

50

51

50

N

51

N

50 5150

N

51

N

Radial Distribution

• Non-directional phase and ground overcurrent elements

12

3

113

113

DG

6767

N

67

67

N

67

67

N

67

67

N

67

67

N

67

67

N

DER on System

• Directional phase and ground overcurrent elements

• Use voltage polarization

12

3

114

Directionalization toward DER helps prevent sympathy trips

from out-of-section faults

114

DG

6767

N

67

67

N

67

67

N

67

67

N

67

67

N

67

67

N

Directionalization toward Substation providesremote breaker failure protection

• Directional phase and ground overcurrent elements• Use voltage polarization• All reverse looking elements trip slower than all forward

looking elements

1

23

4

115

DER on System

115

• Revise reclosing practices – 50%

• Added voltage relays to supervise reclosing – 36%

• Extend 1st shot reclose time – 26%

• Added transfer trip – 20%

• Eliminate reclosing – 14%

• Added sync check – 6%

• Reduce reclose attempts – 6%

DER Impact on Utility Reclosing


116

116

• If high-speed reclosing is employed, the DER interconnection protection must be faster!

• Clearing time includes protection operation and breaker opening

Utility Reclosing Issues:It is all about time……….

DER must trip from

utility in this interval

117

117

• As DER penetration increases, the ability to “ride-though” transient faults on adjacent feeders and transmission is becoming more important

• IEEE 1547 has had an addendum (1547a-2014) that allows:

– “Loosening” of voltage and frequency limits to allow fault “ride-through”

– DER to actively control their reactive power output

• IEEE 1547 ”a” addresses ride-through by making it a utility choice to allow or disallow it

• Off-nominal voltage and frequency limits may be greatly widened, offering ride-through capability

• Impact: Changes for protection setpoints for all types of DER

IEEE 1547 Addendum: IEEE 1547a

It’s all about “Ride-Through”

118

118


It’s all about “Ride-Through”

119

119


120

120

• If large amounts of DER are easily “shaken off” for transient out-of-section faults, voltage and power flow upset can occur in:

– Feeders

– Substations

– Transmission

• Fault ride-through capability makes the system more stable

– Distribution: Having large amounts of DER “shaken off” for transient events suddenly upsets loadflow and attendant voltage drops.

• Impacts include unnecessary LTC, regulator and capacitor control switching

• If amount of DER shaken off is large enough, voltage limits may be violated

– Transmission: Having large amounts of DER “shaken off” for transient events may upset loadflow into transmission impacting voltage, VAR flow and stability


121

121

aBase voltages are the nominal system voltages stated in [ANSI C84.1] Table 1.

bDR ≤ 30kW, maximum clearing times; DR >30kW, default clearing times.

122

Present IEEE 1547 Trip values for Voltage (59, 27)

122

Proposed IEEE 1547A Trip values for Voltage (59, 27)

123

123


Voltage Ridethrough

Graph from “1547a and Rule 21, Smart Inverter Workshop,” June 21, 2013, SCE

124

124

Example of Inverter P & Q Output Capability

Graph from Mar/Apr 2014 IEEE PES Magazine Article “Lab Tests” by Roland Brundlinger,

Thomas Straaser, Georg Lauss, Andy Hoke, Sudipta Chakraborty, Greg Martin, Benjamin Kropotkin,

Jay Johnson and Eric de Jong

125

125

Proposed IEEE 1547A Trip values for Frequency (81-0, 81-U)

Default settings Ranges of adjustability(a)

Function Frequency

(Hz).

Clearing time

(s)

Frequency (Hz) Clearing time

(s)

UF1 57 0.16 56 – 60 0 – 10

UF2 59.5 20 56 – 60 0 – 300

Power reduction (b)

60.3 n/a 60 - 64 n/a

OF1 60.5 20 60 – 64 0 – 300

OF2 62 0.16 60 - 64 0 - 10

(a) Unless otherwise specified, default ranges of adjustability shall be as stated.

(b) When used, the DR power reduction function settings shall be as mutually

agreed to by the area EPS and DR operators.

126

126


Frequency Ridethrough

Graph from “1547a and Rule 21, Smart Inverter Workshop,” June 21, 2013, SCE

127

127

1547A: Active Voltage/VAR Control

• Coordination with and approval of, the area EPS and DR operators, shall be required for the DR to actively participate to regulate the voltage by changes of real and reactive power.

• The DR shall not cause the Area EPS service voltage at other Local EPSs to go outside the requirements of ANSI C84.1-2006 1 1995, Range A.

128

128

Controls incorporate setpoints, deadbands,

ramp timers, etc.

Example DER Control Interface

Power (W) and

VAR Control

Contacts for

Operation Modes

Power (W) Control

129

129

• Uses droop characteristic

• Based on voltage sensing at PCC or PI

• If inverter based, a “Smart” Inverter

130

DER Actively Controlling VAR

130

DER Interconnection Relay as the Utility Interface Point

131

131

DERInterconnectionProtective Relay

DER Control System(MODBUS Master)

UtilitySCADA

(Radio,Fiberoptic,Hardwire

from RTU)

Commands

Data

DNP TCP/IPMODBUS TCP/IP

Embedded cybersecurity

per NERC CIP V5 and

IEEE 1686

RUN/STOP

CONTROL Var/Unity PF

Operational,PQ, Metering,DFR, SOE

Commands

Status

RUN/STOP


Operational Status

FACILITY with DER

DER Variability: V/VAR Issues

Coping Methods for Fast DER Variability: Using DMS and Controllable Assets

– “Ramp Rate” or “Capacity Fill” Dispatch• Conventional “fast start” distributed generation to supply

real/reactive power

• Distributed synchronous condensers to supply/sink reactive power

• Storage/conversion to supply/sink real power

• Storage/conversion to supply reactive power

– May be accomplished by DSM or local control from nearby large DER variable asset

• Starting/Stopping

• Direct setpoint control or initiating setting group changes

132

132

Constant Capacityfrom “Capacity Fill”

Assets

• Not Firmed

• Firmed

Time

Ou

tpu

t

Time

Ou

tpu

t= Variable DR Output

= Output Firmed

133

133

Ramped Capacityfrom

“Capacity Fill” Assets

Time

Ou

tpu

t

Time

Ou

tpu

t= Variable DR Output

= Output Firmed

134

• Not Firmed

• Firmed

134

Storage Applications

Utility Distribution Substation Storagefor Demand Response Use

AC/DC

FEEDERS

UTILITY

115kV

13.8kV

Storage

13.8kV 480V

SCADA

135

135

Storage Applications

AC/DC

UTILITY

13.8kV

Storage

480V

SCADA

AC/DC

Storage

AC/DC

13.8kV

Storage

480V

SCADA

AC/DC

Storage

Adjust Storage Capacity forScalable Demand and Duration

136

136

Storage Placement

DER

Highly Variable DER

DER

Storage

(Dispatchable)

137

137

GenTranSubTranDistUtilization

DER Today

DG

DG

DG

Bulk

Generation

Transmission

Sub

Transmission

Distribution

Substation

Substation

With DG

Distribution

With DG

Distribution

Substation

Distribution

Substation

138

138

Bi-Directional Powerflows

DER Tomorrow

DG

DG

DG

DG

DG

DG

DG

DG

DG

DG

DG

DG

Bulk

Generation

Transmission

Sub

Transmission

Distribution

Substation

Distribution

With DG

Distribution

With DG

Distribution

With DG

Distribution

Substation

Distribution

Substation

139

139

• Enables Green Power Interconnected at the Distribution Level

• Smart Grids Must Overcome Many Limitations:

- Loss of Protective System Coordination

- Voltage Control (reactive support)

- Restoration Problems

- Capacity/Load balance

- Green power variability and non-dispatchability

• IEEE 1547 is presently too restrictive for large amounts of DER

– Issue with high amount of DER capacity being lost at once for disturbance or other recoverable event

– 1547A helps address that

Smart Grid and DER

140

140

University Campus Microgrid

Creation of DER and load islands

for economic, power quality or

power security reasons

141

141

Smart Grids ̶ Microgrids

Just as a single DER is synced to the utility, groups of DER as a Microgrid

are synced to the utility after operating islanded

142

142

Smart Grid Application of DER: Microgrids

143

143

• Voltage control with high levels of DER require some type of adaptive watt/VAR control

• Advanced control will be needed on DER, voltage regulating and reactive support (capacitors) elements

• Normal power from Utility to load– Utility strong source

• DER may backfeed– Typically a weaker source

• What to do with power reversal from sectionalizing?

• What to do with power reversal from DER?

• What to do about LDC with DER influencing?

High Penetration of DER on Distribution Systems

Will Require Smart Grid Technology to Control System Voltage

144

144

Acronyms

• CAPC = Capacitor Control

• REGC = Regulator Control

• LTCC = Load Tapchanging Transformer Control

• RPF = Reverse Power Flow

• DA = Distribution Automation

• EMS = Energy Management System

• DMS = Distribution Management System

• EOL = End of Line, as in EOL Voltage

• DERP = DER Protection

145

145

Communications to REGC

• Pros:– REGC does as commanded, using analog setpoint or

profile group • Using “Heartbeat,” control knows if communications is lost

– Go to “Plan B;” operation mode with comms

• Cons:– Costs of communications infrastructure– Requires DMS with either modeling or feedback to

properly execute commands• Feedback requires recloser position status,

EOL voltage sensing• Modeling requires creation, updating and upkeep

146

146

Use of Powerflow Direction Change by REGC

• Pros:

– Communications not needed to detect RPF situation

– Control is autonomous (no DMS/SCADA required)

– Autodetermination Mode allows dynamic source stiffness determination and proper regulation based on the dynamic conditions

• Cons:

– Settings may require change if feeder changes over time

• Ex., LDC-RX

147

147

REGC: Reverse Power Method Discussion

• Regulate Forward (Ignore) – continues unit action as though forward power flow continued to exist. – Use where weak DER without active voltage control was causing RPF

with little expected line drop

• Block – inhibits automatic operation, leaving regulator on present tap. – Use where source of RPF is not expected to change voltage on RPF

side of REG

• Return to Neutral – drives tap position to neutral and then stops– Use where small unpredictable change in voltage may be

encountered on RPF side of REG

148

148


• Regulate Reverse – (calculated voltage or measured voltage) regulates according to reverse power settings.– Use where RPF side of REG is a strong source (many MWs of DER or a

feeder reconfiguration) and regulate voltage on the non-RPF side of the REG

• Change in directional of feeder source by DA

• Regulate Reverse (measured) – allows the control to switch its voltage sensing input from a load side VT to a source side VT if one is available and operate in Regulate Reverse Mode using that input.– Use where RPF side of REG is a strong source (DER or feeder) and

regulate voltage on the non-RPF side of the REG

149

149


• Distributed Generation – remains forward regulating and allows alternate LDC (R and X) or LDC (Z) values to be applied to control when reverse power is detected. – Use where RPF side is from a moderately stiff source to change

LDC/LDZ while still regulating forward

• Auto Determination – allows control to use "Smart Reverse Power" feature to choose applicable reverse power mode, either DG/DER or Regulate Reverse. – Will dynamically determine stiff source and selectively use either:Forward Regulation in DG/DER

New voltage band center, bandwidth Use of VAR-Bias or LDC RX or Z,

Reverse Regulation New voltage band center, bandwidth Use of VAR-Bias or LDC RX or Z,

150

150

Improved Volt/VAR Coordination between DERs/CAPCs and REGCs/LTCCs

• REGCs and/or LTCCs:

– Typically use LDC-RX or LDC-Z

– No direct feedback mechanism using LDC-RX or LDC-Z for PF or VAR control

• Voltage-control based CAPCs:

– VAR measurement not available

– Switch on voltage• Less expensive than VAR control and sensors

• May be used at end of line

How do we coordinate to obtain optimum VVO/IVVC?

151

151

Use of VAR-Bias to Coordinate DERs/CAPs with REGs and LTCs

• REGC and LTCC use information on VAR flow

– Is the flow out to the line (load)?

– Is the flow into the source?

• The above indicate if you are or are not at/near unity power factor

• VAR flow into the REG or LTC indicate the voltage downline is higher than the voltage at the REG or LTC

152

152

Use of VAR-Bias to Coordinate DERs/CAPs with REGs and LTCs

• Use a“VAR-Bias” characteristic of to change the response of the REGC or LTCC

• The VAR-Bias characteristic can be tailored for normal operation (non-CVR) and CVR operation

– Normal (non-CVR) Operation: Negative VAR Bias

– CVR Operation: Positive VAR Bias

153

153

VAR Bias (LTCC and REGC)• In the Negative Mode (Normal), as:

– VARs flow toward source (leading VAR at LTCC/REGC)• Voltage bandcenter rises, causing voltage-controlled:

DERs to decrease VAR output

CAPCs to switch banks off, stopping VAR output

– VARs flow toward load (lagging VAR at LTCC/REGC)• Voltage bandcenter lowers, causing voltage-controlled:

DERs to decrease VAR output

CAPCs to switch banks on, outputting VAR

154

This action tends to create unity power factor and flatten voltage profile

Normal, Non-CVR ApplicationNegative Linear VAR Bias

Leading VARsLagging VARs120V

121V

118V

117V

116V

122V

123V

124V

119V

154

VAR Bias (LTCC and RECC)• In the Positive Mode (CVR), as:

155

This action tends to allow deep voltage reduction at the feeder origin as end of line voltage is higher than at REG or LTC output


121V

118V

117V

116V

122V

123V

124V

119V

CVR ApplicationPositive Linear VAR Bias

155

• VARs flow toward source (leading VAR at LTCC/REGC)

– Voltage bandcenter lowers, causing voltage-controlled:DERs to decrease VAR output

CAPCs to switch banks on, outputting VAR

• VARs flow toward load (lagging VAR at LTCC/REGC)

– Voltage bandcenter rises, causing voltage-controlled:DERs to decrease VAR output

CAPCs to switch banks off, stopping VAR output

126

120

114

0 1 2 3 4 5 6 7 8

Positive VAR-Bias Method

Traditional VVO; CVR

Distance (%)

Vo

lts

(sec

on

da

ry)

Traditional VVO; non-CVR

No VVO

CVR: REGs/LTC with DERs/CAPs

• For CVR, forcing overVAr on feeder, causes end of line voltage to rise

• You can have a deeper voltage reduction at the beginning of the line where most of the load is located

156

156

Normal Operation:Negative VAR-Bias

• Voltage near center of band

• Near unity power factor

157

52

Closed

Opened

Closed

Opened

Closed

Opened

Closed

Opened

121V

118V

117V

116V

122V

123V

124V

119V

120V

NORMAL OPERATION (non-CVR)

DERVArOUT

VArIN

VLOW VHIGH

DERVArOUT

VArIN

VLOW VHIGH

157



121V

118V

117V

116V

122V

123V

124V

119V


• Inductive load increases, pf lags, voltage decreases.

• REG bandcenter lowers.

• Caps come on, DER outputs VAr

• Voltage and VArnormalize

158

52

Closed

Opened

Closed

Opened

Closed

Opened

Closed

Opened

121V

118V

117V

116V

122V

123V

124V

119V

120V


DERVArOUT

VArIN

VLOW VHIGH

DERVArOUT

VArIN

VLOW VHIGH

158



121V

118V

117V

116V

122V

123V

124V

119V

2

1

3


• Inductive load decreases, pfleads, voltage rises.

• REG bandcenter rises.

• Caps switch off, DER consumes VAr

• Voltage and VArnormalize

159

52

Closed

Opened

Closed

Opened

Closed

Opened

Closed

Opened

121V

118V

117V

116V

122V

123V

124V

119V

120V


DERVArOUT

VArIN

VLOW VHIGH

DERVArOUT

VArIN

VLOW VHIGH

159

1



121V

118V

117V

116V

122V

123V

124V

119V

3

2

1


• Resistive load decreases, pfremains the same, voltage rises

• REG taps down, voltage normalizes

• CAPs and DER do not change VAr output

160

52

Closed

Opened

Closed

Opened

Closed

Opened

Closed

Opened

121V

118V

117V

116V

122V

123V

124V

119V

120V


1

2

3

DERVArOUT

VArIN

VLOW VHIGH

DERVArOUT

VArIN

VLOW VHIGH

160

1



121V

118V

117V

116V

122V

123V

124V

119V

3

2

1


• Resistive load increases, pf leads, voltage decreases

• REG taps up, voltage normalizes

• CAPs and DER do not change VAroutput

161

52

Closed

Opened

Closed

Opened

Closed

Opened

Closed

Opened

121V

118V

117V

116V

122V

123V

124V

119V

120V


1

23

DERVArOUT

VArIN

VLOW VHIGH

DERVArOUT

VArIN

VLOW VHIGH

161

1



121V

118V

117V

116V

122V

123V

124V

119V 3

2

1

Voltage Bandcenter and Bandwidth: LTC/REG, CAP, DER

• CAPS and DER furthest away from source have faster time delay than upline similar devices

162

162

52

Closed

Opened

Closed

Opened

Closed

Opened

Closed

Opened

DERVArOUT

VArIN

VLOW VHIGH

DERVArOUT

VArIN

VLOW VHIGH



121V

118V

117V

116V

122V

123V

124V

119V

REGCAP

DER

REG

CAP

DER

Before CVR Operation:Negative VAR-Bias

• Normal load, voltage near center bandcenter

• Near unity power factor

163

52

Closed

Opened

Closed

Opened

Closed

Opened

Closed

Opened

121V

118V

117V

116V

122V

123V

124V

119V

120V


DERVArOUT

VArIN

VLOW VHIGH

DERVArOUT

VArIN

VLOW VHIGH

163



121V

118V

117V

116V

122V

123V

124V

119V

CVR Operation:Positive VAR-Bias

164

52

Closed

Opened

Closed

Opened

Closed

Opened

Closed

Opened

121V

118V

117V

116V

122V

123V

124V

119V

120V

CVR OPERATION

1

2

DERVArOUT

VArIN

VLOW VHIGH

DERVArOUT

VArIN

VLOW VHIGH

• REG forces voltage lower

• CAPs begin to switch on and DER outputs VAr

164


121V

118V

117V

116V

122V

123V

124V

119V


2

1

CVR Operation:Positive VAR-Bias

165

52

Closed

Opened

Closed

Opened

Closed

Opened

Closed

Opened

121V

118V

117V

116V

122V

123V

124V

119V

120V

CVR OPERATION

1

2

DERVArOUT

VArIN

VLOW VHIGH

DERVArOUT

VArIN

VLOW VHIGH

• VARs begin to lead.

• REG forces voltage even lower.

• More CAPs switch on and DER outputs VAr

165


121V

118V

117V

116V

122V

123V

124V

119V


2

1

3

DER Interconnection Relay as a Utility Access Point

Embedded cybersecurity is key as DER is not in a substation

166

166

DERInterconnectionProtective Relay

DER Control System(MODBUS Master)

UtilitySCADA

(Radio,Fiberoptic,Hardwire

from RTU)

Commands

Data

DNP TCP/IPMODBUS TCP/IP

Embedded cybersecurity

per NERC CIP V5 and

IEEE 1686

RUN/STOP


Operational,PQ, Metering,DFR, SOE

Commands

Status

RUN/STOP


Operational Status

FACILITY with DER

CAPs and DER• As power flows and assumed reactive voltage drops can

change as DER proliferates, consider changing fixed CAPs to switched to avoid overvoltage (from excessive VAR support) under high DER output conditions

• Consider active voltage (VAR) control of DER as proliferation increases

167

VRef

(V2,Q2)V1 V4

Voltage (p.u.)

Re

acti

ve P

ow

er

(% o

f St

ate

d C

apab

ility

)

Inje

ctin

g (o

ver-

exci

ted

)

Dead Band

VL: Voltage Lower Limit for DER Continuous operationVH: Voltage Upper Limit for DER Continuous operation

Ab

sorb

ing

(un

der

-exc

ited

) VL VH

0(V3,Q3)

(V1,Q1)

(V4,Q4)

167

• Coping Methods for Fast DER Variability:• Consider regulators change taps sequentially ensure

voltage on feeder is quickly restored

• Using sequential over non-sequential operation shortens time to restore voltage

• Consider substation caps be controlled on VAR/pf with high voltage and low voltage override

• Consider line caps be controlled on using voltage

168

Traditional Volt/VAR Elements

168

Effects of Reverse Power from DER on

Line Drop Compensation (LDC)

DER

If RPF is large enough to cause reverse power flow, the REGC will operate to lower voltage

Using to “Distributed Generation Mode” changes the polarity of the LDC (and factors if desired) under reverse power conditions to prevent this from occurring

169

169

DER

DER

Vo

lta

ge

Vo

lta

ge

Effect of DER on Regulator


LDC is reduced when DER contributes power

More DER power = less load = less LDC = voltage setpoint lowers

If DER is in PF mode, it maintains a VAR output to not import or export any VARs, so it cannot control voltage

Voltage profile can change depending on:

o R and XL of the line

o Reactive compensation to counter the XL

o Power output of the DER

170

170

DER

Vo

lta

ge

DER



171

171

Assume line R and XLdrops are low

Assume REGC in DG Mode

Assume variable DER power output per the graphic

Line voltage assumes “smile” profile

Curve of smile (flat or very arced) not the severeo Arc more severe with

higher R and XL, more DER output



172

172

DER

Vo

lta

ge

DER

Assume line R and XLdrops are low

Assume REGC in DG Mode

Assume variable DER power output per the graphic

Line voltage assumes “smile” profile

Curve of smile (flat or very arced) not the severeo Arc more severe with

higher R and XL, more DER output

DER

SCADADNP 3.0

EOL

Use of an End-of-Line Monitor (EOL) to

Transmit Voltage Value to Regulator

With EOL feedback, you are not modeling the EOL voltage. You measure it.

EOL monitoring, working with a regulator, can handle dynamic situations and multiple sources to adjust line voltage

Works when DG Mode where unfavorable line/DER output characteristics existo Smile arc too severe or DER EOL voltage too high

173

173

DER and REGCs/LTCCs

• Use of VAR-Bias avoids LDC issues as DER power output increases

• If DER can control VAr output, by coordinating DER voltage output setting with REGC/LTCC bandcenter will keep voltage at the setting

– VAR-Bias reacts to VAR to maintain unity PF

– REGC/LTCC, CAPs and active DERs maintain voltage

174

174

DER

SCADADNP 3.0

EOL

Use of an End-of-Line Monitor (EOL) to

Transmit Voltage Value to Regulator

With EOL feedback, you are not modeling the EOL voltage. You measure it.

EOL monitoring, working with a regulator, can handle dynamic situations and multiple sources to adjust line voltage

175

175

Communications to CAPC

• Pros:– CAPC does as commanded, using analog setpoint

or profile group • Using “Heartbeat,” control knows if communications is lost

– Go to “Plan B;” operation mode with comms

• Cons:– Costs of communications infrastructure– Requires DMS with either modeling or feedback to

properly execute commands• Feedback requires recloser position status, EOL voltage

sensing; may require VAR sensing at substation• Modeling requires creation, updating and upkeep

176

176

Use of Autoadaptive Methodology by CAPC

• CAPCs, using Autoadaptive delta-voltage based control, alter their timing to properly switch per control’s new location from source on feeder (furthest from source switches first).

– This implementation maintains better multi-capacitor control action on a given feeder regardless of configuration.

– Uses delta-V observed on switching to change timing

– Increasing delta-V = further distance (more impedance) from source

177

177

Use of Autoadaptive Methodology by CAPC

• Pros:

– Communications not needed to retune CAPC time settings

– Control is autonomous (no DMS/SCADA required)

– Upon another reconfiguration, CAPC will learn new time setting depending on its position form the source

• Cons:

– None

178

178

• Properly designed interconnection protection addresses concerns of both DER owners and utility

• State and national regulators, and the IEEE, continue to create and update interconnection guidelines

• Interconnection transformer configuration plays a pivotal role in interconnection protection

Summary

179

179

• Restoration practices need to be part of the overall interconnection protection

• Smart Grid Solutions will be needed to meet high penetrations of DER

• Protective Relays for DER interconnection protection may find greater application in inverter-based systems due to the adoption of IEEE 1547A

Summary

180

180

Recommended Reading

• IEEE 1547 Series of Standards for Interconnecting Distributed Resources with Electric Power Systems, http://grouper.ieee.org/groups/scc21/

• On-Site Power Generation, by EGSA, ISBN# 0-9625949-4-6

• Intertie Protection of Consumer-Owned Sources of Generation 3 MVA or Less, IEEE PSRC WG Report

• Evaluation of Islanding Detection Methods for Utility-Interactive Inverters in Photovoltaic Systems, Sandia National Laboratories, Ward Bower and Michael Ropp

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181

• “Update on the Current Status of DG Interconnection Protection―What 1547 Doesn’t Tell You,” Charles Mozina, Beckwith Electric, presented at 2003 Western Protective Relay Conference on Beckwith website

• Distribution Line Protection Practices Industry Survey Results, Dec. 2002, IEEE PSRC Working Group Report

• Combined Heating, Cooling & Power Handbook, Marcel Dekker, by Neil Petchers, ISBN# 0-88173-349-0

• “Benefits of Using Customer Distributed Generation for Demand Response,” W. Hartmann, P. Kalv; Distributech2011

182

Recommended Reading

182

• “How to Nuisance Trip Distributed Generation,” W. Hartmann, presented at Power System Conference, Clemson University, Clemson, SC, March 2003

• “Relay Performance in DG Islands,” Ferro, Gish, Wagner and Jones, IEEE Transactions on Power Delivery, January 1989

• Effect of Distribution Automation on Protective Relaying, 2012, IEEE PSRC Working Group Report

• 1547a and Rule 21, Smart Inverter Workshop, June 21, 2013, SCE

183

Recommended Reading

183

DistributedEnergy

Resources

Operation, Protection & Control

184

161005_CNY_2 Hr

November 7, 2016

Syracuse, NY

Distributed Energy Resources€¦ · Before joining Beckwith Electric, Wayne performed in...

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