DG Interconnection Issues and Potential Grid-Support Functionalities › static-assets › documents...

Aidan Tuohy, Jeff Smith and Aminul Huque

July 11, 2014

DG Interconnection Issues and Potential Grid-Support Functionalities

2 © 2014 Electric Power Research Institute, Inc. All rights reserved.

Objectives & Agenda

Agenda:

• Background • Potential Bulk System Reliability Impacts

– Frequency – Voltage – Stability – Other Impacts

• Distribution System Issues

• Cost Considerations

Basic Understanding of Need for Advanced Reliability Services from Inverter-Based Generation

Background


The Electric Power System


Looking Forward


What’s the Big Deal?

US

• 80% of renewable generation impacts distribution

• Vast majority provides no grid support

Germany

• Retrofitting >300,000 solar PV units due to voltage and frequency issues

• €70-180 Million!

“Forward Looking Smart Inverters = A Smart Choice” - Terry Boston, (Summer Seminar, 2013)

“There is an immediate need for new solar to be fitted with “smart inverters” to provide necessary voltage support to integrate effectively and prevent costly renovations and reliability impacts” – Western Electric Industry Leaders, Aug 2013

WEIL Western Electric Industry Leaders


Can Inverter-Based Generation be equipped with

Grid Support Functionality?

Key Question?

http://www.google.com/url?sa=i&source=images&cd=&cad=rja&docid=j1dFh7GOUpwowM&tbnid=YQ243D-9MovV5M:&ved=&url=http://www.pgsnacks.com/2009/11/say-yes-say-no-just-dont-say-maybe/&ei=_uVeUvQFhfqLApbBgPAB&psig=AFQjCNFw3ZqP25jsukfUov5nWzJeYVVuJw&ust=1382037374071814


Today’s Smart Inverter Technology Enabling Changes in Grid Codes Inverters converts DC energy to AC energy and interface the generating

plant with electricity grid

Traditional Inverter Functionality Smart Inverter Functionality

• Matching plant output with grid voltage and frequency

• Providing safety by providing unintentional islanding protection

• Disconnect from grid based on V/f set points

• Active power reduction in case of over-frequency

• Fault Ride Through (FRT) • Reactive power and voltage

support • Communication with grid • Many more

DC Power AC Power


IEEE 1547 – 2003

• DR shall not actively regulate the voltage at the PCC

• DR shall cease to energize if frequency >60.5Hz

• Tighter abnormal V/F trip limits and clearance times

IEEE 1547a - 2014

• DR may actively participate to regulate the voltage by changes of real and reactive power

• DR shall be permitted to provide modulated power output as a function of frequency

• Much wider optional V/F trip limits and clearance times

• Under mutual agreement between the EPS and DR operators, other static or dynamic frequency and clearing time trip settings shall be permitted.

Major Changes in 1547 Amendment


General Reliability Concerns

Reliability Functions • Reactive power/voltage control • Active power control

– inertia/primary freq response • Disturbance performance

– voltage & frequency ride through

Other Considerations • Inverter capabilities • Available headroom for wind/PV • Distribute

Inverter-Based Generators must supply Reliability Services as they

Displace Conventional

Sources of those reliability services!


Germany: Challenges to New Insights

Source: Fraunhofer Institute, Germany

Recent Changes in Germany to Address Concern of Grid Reliability

Installed Capacity (2013)

Solar

Wind

~64GW of Installed Wind and PV – mostly connected to LV

and MV grid

Coal

Hydro

Nuclear

Gas

Interconnection Rules • Frequency & Voltage Support

Grid Infrastructure Upgrade • ~$27.5B to $42.5B Upgrade

Two Way Communication • Enabled by Advanced

Distribution Management


Don’t Make the Same Mistake!

“50.2 Hz” frequency concern(!) in Germany

4

5

6

7

8

9

10

50 50.25 50.5 50.75 51 51.25 51.5

Inve

rter

Act

ive

Out

put P

ower

(kW

)

Frequency (Hz)

15,000 PV systems Sized 10kW+

9 GW Nominal Power Over 3 – 4 years

Costing €70 – 180 Million

Retrofitting/ Replacing


Inverter – Role in Power System

Frequency Ride Through

Bulk System Issues


Frequency Ride-Through: Risk of Wide-Spread PV Disconnection

50.8

50.6

50.4

50.2

50.0

49.8

49.6

49.4

49.2

Grid

Fre

quen

cy in

Hz

Time in Seconds

0 10 20 30 40 50 60

Source: T. K. Vrana (2011)

Previous Interconnection Rules

German Operating Frequency Limit

Germany

As of 2012 PV Inverters were not required to provide

frequency support and disconnect from the grid if

the frequency reaches 50.2 Hz

This is similar to all current interconnection

requirements in US as per IEEE 1547-2003


Changes in German Grid Code Frequency Support • Frequency control is required of all generators

– Instead of disconnecting @50.2 Hz, gradually reduce active power output (droop curve) in proportion to the frequency

– Retrofit cost mostly through software update ~ $100-250M

Enacted through EEG (German Renewable Energy Sources Act ) & EnWG (German Law on the Energy Industry)


Updated Interconnection Rules Reduces Risk of Frequency Instability

50.8

50.6

50.4

50.2

50.0

49.8

49.6

49.4

49.2

Grid

Fre

quen

cy in

Hz

Time in Seconds

0 10 20 30 40 50 60

Source: T. K. Vrana (2011)

Previous Interconnection Rules

Updated Interconnection Rules German Operating Frequency Limit

Germany


Coordination with Under Frequency Load Shedding – NPCC Directory 12

Source: NPCC Directory 12, p.11, available at: https://www.npcc.org/Standards/Directories/Directory12%20Full%20Member%20Approved%2020130709%20GJD.pdf

https://www.npcc.org/Standards/Directories/Directory12%20Full%20Member%20Approved%2020130709%20GJD.pdf


Changes in “Response to Abnormal Frequency”

IEEE 1547-2003

IEEE 1547a

Voltage Ride Through

Bulk System Issues


Loss of 250 MW generation

for a normal 230 kV line fault?

Transmission Line Fault


PJM Example LVRT Impact

Source: Mahendra Patel, PJM.


Distributed PV Potential Impact: Low Voltage Ride-Through

FERC Order 661A • Interconnection of wind plants • Requires wind plants remain in

service during – Normally cleared 3-phase

faults to a max. 9 cycles (TOP to provide clearing time)

– 1-phase faults with delayed clearing

– TOP to provide post-fault voltage recovery

Must NOT TRIP Requirement

IEEE Standard 1547-2003** • Interconnection of DER • Requires wind plants disconnect

during

–

Must TRIP Requirement

Voltage Range (% base voltage)

Clearing time(s)

V < 50 0.16 50 ≤ V < 88 2.00

110 < V < 120 1.00 V ≥ 120 0.16

**Proposed Update in 1547a


What is Low Voltage Ride Through (LVRT)?

-600

-400

-200

0

200

400

600

Volta

ge (V

)

-40-30-20-10

010203040

2.05 2.25 2.45 2.65 2.85 3.05 3.25 3.45 3.65

Curr

ent (

A)

Time (s)

6 Cycle Interuption

Inverter Current

Grid Voltage

Inverter able to ride through momentary low voltages and interruptions


Testing L/HVRT Capability EPRI Knoxville Lab

Ride-thru of a voltage sag event to 52% nominal with 15 cycle duration

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

140%

0.01 0.1 1 10

Volta

ge (%

Nom

inal

)

Time (s)


Low Voltage Ride Through: NERC PRC 024

• Applies to ALL generators • Generator relay requirement • NOT plant ride-through requirement


Voltage Ride-Through: AESO (Canada)

AESO standard specifies via VRT

(high and low) curve, similar to

European approach


Changes in “Response to Abnormal Voltages”

IEEE 1547-2003

IEEE 1547a


Specific VRT Requirements – Germany: MV Grid Code

• Not to disconnect from network in the event of network faults • Support with reactive current • After fault clearance not to extract more inductive reactive power than prior to

fault • Reactive current on LV side of transformer 2% of rated current for each 1% of

voltage dip (outside 10% deadband)

Source: BDEW, Technical Guideline, Generating Plants connected to MV network, 2008)

1500 700 1500 3000 time in ms

U/UC

100%

70%

30%

Below this limit: no need to stay connected

Limit 1: for voltage dips above this limit should not initiate any

disconnection or instatbility Limit 2: voltage dips above this limit (and below limit 1) should

be ridden through

Fault occurance


Voltage Regulation – Reactive Power Support

• Power factor setting

• Constant VAR consumption/injection

• Volt-VAR control

• Voltage Setpoint


Considerations: Reactive Range

• Plant requirements can differ – Reduced range at low

wind/PV levels

• Solar PV inverters over-sized for full range at max power output – historically distribution w/unity

PF control

• Dynamic vs. static capability – switched shunts often

included for static range – SVC/STATCOM may be used

for additional dynamic range

Typical Type 3/4 WTG VAR Capability Options

PV Capability (I limits) Vs. Triangle Require.

Frequency and Voltage Stability

Bulk System Issues


High Levels of Inverter-Based Generation Can Impact Frequency Stability

Graphics Source: LBNL-4142E Use of Frequency Response Metrics to Assess the Planning and Operating Requirements for Reliable Integration of Variable Renewable Generation, Prepared for Office of Electric Reliability Federal Energy Regulatory Commission, Dec 2010

Sudden Generation

Loss Non-synchronous VG may provide inertia & primary

frequency response through power

electronics

VG may displace conventional units &

reduce system inertia & primary

frequency response


59.5

59.6

59.7

59.8

59.9

60

60.1

0 5 10 15 20 25 30 35 40 45

Freq

uenc

y (H

z)

Base(15%)

Base (20%)

Base(30%)

Base(40%)

Nadir

Settled Frequency

UFLS

EPRI Frequency Response Project (WECC) Impact of Wind Without Frequency Response

All Else Constant, as Wind Gen without Freq Control

replaces Thermal Gen, Freq Performance Deteriorates

Similar results likely with DER


Example EPRI Simulation Results: Generic Case

As PV Increases Voltage Recovery Time Increases


Simulation Studies : Steady State Assessment

Identify Critical Contingencies and Buses •Ranking •Maximum Voltages Deviations •Lowest Voltages

Perform PV analysis •Determine real power transfer or load level limit

•Test for N,N-1-1,N-1 and N-2 conditions

Perform QV analysis •Determine reactive power margins at critical buses

•Test for N,N-1 and N-1-1 conditions


Simulation Studies : Dynamic Assessment

Impact on Voltages :

Delay in voltage recovery

With and without voltage ride-thru

Impact on Frequency:

Reduction in system inertia due to change in generation mix

PV drop out due to large voltage disturbance (as per IEEE 1547)

Other potential issues

Bulk System Issues


Germany’s System Curve with Increasing PV


Real power control, ramping, and curtailment

100% 75% 25% In 4 seconds In 6 seconds


Active power control / frequency support

• Germany: 10% of grid connection capacity per minute – Above 50.2 HZ, active power reduces at 40% per Hz

• Ireland, ramp rate 1-30MW/min – Active power depends on frequency:

• Above 52 Hz, no active power, • 50.5 -52 Hz, power goes from 100-20% active power

• Nordic: 10% of rated power per minute • Denmark: Active power depends on frequency • GB: Frequency control device for primary and secondary

frequency control, plus over frequency control


Communications with DER • Possibility for DSO to send setpoint values to generators

– Reduce the active power output or change the cos(phi). – Guarantee grid stability in case of emergency situations or congestion

• Can be implemented in various ways: – Audio or radio frequency ripple control – IEC 61850-90-7 – IEC 60870-5-104

Source: R. Bründlinger, Austrian Institute of Technology, “Grid Code Experiences from Europe”, EPRI webcast, May 2014


What’s EPRI Doing in Distributed Resource Integration in Bulk System

Ongoing and Near-Term EPRI Efforts Project/Effort Topic(s) Addressed Timeline

Voltage and Frequency Performance with High Levels of VG

•Impacts of distributed PV on bulk system performance •Grid code/ Requirements •Impact on frequency response and new resources to provide FR

Ongoing

DOE SUNRISE project • TVA & Southern Company strategic plans for PV impacts on dist and bulk system, business models and IRP •CAISO/SMUD production simulations • Coordinate w/ projects in P173 and P174

2013-2015

EPRI White Paper on Demand Response

• Completed end 2013 2013

EPRI Value of the Grid Concept Paper

• Begun end 2013 2013+

Distribution Impacts


Distribution System Impacts

Voltage • Overvoltage • Voltage variations

Equipment Operation • Feeder regulators • Load tap changers • Switched capacitor banks

Demand • “Masking” peak demand • Reducing power factor

System Protection • Relay desensitization • Unintentional islanding

Power Quality • Harmonics

0.0

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Pow

er (p

er-u

nit)

Hour


= Line Regulators= Substation

0.95

0.97

0.99

1.01

1.03

1.05

1.07

1.09

0 60 120 180 240 300 360 420 480 540

Volta

ge (p

u)

Time (sec)

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0.97

0.99

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Volta

ge (p

u)

Time (sec)

Why are Smart Inverters Important? Smart Inverters Mitigating Voltage Issues

46

Voltage at END of feeder

No Control Volt/Var Control

*Simulated in OpenDSS


Use of Smart Inverters for Accommodating Large Number of Distributed PV Systems

24 Hour Simulation

Source: J. Smith, T. Key “High-Penetration PV Impact Analysis on Distribution Systems,” Solar Power International, Oct 2011

Customer Load Customer PV

Primary Voltage

0.9

0.925

0.95

0.975

1

1.025

1.05

0 4 8 12 16 20

Hour

Vol

tage

(pu)

Baseline – No PV

20% PV

Solar Rooftop PV


Use of Smart Inverters for Accommodating Large Number of Distributed PV Systems

24 Hour Simulation

Source: J. Smith, T. Key “High-Penetration PV Impact Analysis on Distribution Systems,” Solar Power International, Oct 2011

VARs

Gen

erat

ed

Capacitive

Inductive

System Voltage

V1 V2 V3 V4

Q1

Q4

Q3 Q2

Primary Voltage

0.9

0.925

0.95

0.975

1

1.025

1.05

0 4 8 12 16 20

Hour

Vol

tage

(pu)

Baseline – No PV

20% PV 20% PV with

volt/var control

Initial analysis indicated 25%-100% more PV can be accommodated using

Volt/var control

Solar Rooftop PV

With volt/var control Volt-Var Control


Increased Hosting Capacity using Smart Inverters

PV at Unity Power Factor PV with Volt/var Control

2500 cases shown Each point = highest primary voltage

ANSI voltage limit

ANSI voltage limit

Increasing penetration (kW)

Max

imum

Fee

der V

olta

ge (p

u)

Max

imum

Fee

der V

olta

ges

(pu)

Increasing penetration (kW)

No observable violations regardless of PV size/location

Possible violations based upon PV size/location

Observable violations occur regardless of size/location

For voltage-constrained feeders, results indicate use of smart inverters can increase feeder hosting capacity for PV

Minimum Hosting Capacity Maximum Hosting Capacity

Minimum Hosting Capacity Max Hosting Capacity


Ongoing Research – Smart Inverter Settings

Objective Determine recommended default settings for actual field deployments of smart inverters

Approach

Time-series simulations in OpenDSS comparing feeder performance with and without smart inverter functions

Value Provide utilities with guidelines for actual PV system installations

Sites Model-based analysis of 3-phase PV systems along with field demonstrations

Wide range of possible smart inverter settings*

*select few shown for illustration


What Smart Inverter Settings are “Best?”

0 5 10 15 20 25

1.024

1.026

1.028

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1.032

1.034

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1.044

Hour

Vol

tage

(pu)

g g

---- Voltvar

---- No PV---- PV base

Daily Distribution Feeder Voltage Profile with different volt/var setpoints


Summary – Smart Inverter Settings

• Overall “best” setting depends upon objective – Improve voltage – Increase efficiency – Decrease regulator operations – Increase hosting capacity

• Preliminary analysis indicates trends in recommended settings can be found

• Caution: Minor changes in settings (volt/var) can have significantly different impacts

• Less “aggressive” settings work – Less risk, less potential benefit

(e.g., increasing hosting capacity)

• Future work for determining recommended settings – Other locations – Other feeders – Combined inverters


Ongoing Research - Smart Inverter Interaction

Objective Evaluate Potential Inverter Interaction Approach

Investigate possible inverter interaction resulting from smart inverter control on multiple PV systems through modeling

Var control flow

VoltVar CurveInverter

Averagingwindow

VReference Q

Average V

QPI

controller

(Kp Ki)

Switching Command

Factors may impact var control:• Volt-var curve parameters• PI controller parameters: Kp and Ki

• Voltage average window length


Initial Results

• Interactions exist between the two close by inverters

• High ratio may cause oscillations

• Smaller adjustments at each step as a result of smaller control parameters reduce oscillations

• Longer voltage averaging window increases magnitude of oscillations, although dampening does occur

• True test will be field demonstrations

4 6 8 10 12 14 16 18 200.95

0.96

0.97

0.98

0.991

1.01

1.02

1.03

1.04

1.05

Time(s)

Vol

tage

(pu)

4 6 8 10 12 14 16 18 200.950.96

0.97

0.980.99

1

1.011.02

1.03

1.041.05

Time(s)

Vol

tage

(pu)

Single PV System

2 PV Systems

Oscillations Observed

Cost Considerations


Inverter Cost and Reliability Impacts PV System Performance

• Inverter cost is a small percentage of the total plant cost/installed cost

• Inverters with grid support functions are not expected cost any higher than current price once the interconnection requirements start incorporating the functional capabilities

• Communication (where needed!) cost will be additional

Average U.S. Utility-Scale PV Price Breakdown (May 2013)

Q1 2013 US PV System Cost Residential - $4.93/W

Commercial-scale - $3.92/W Utility-scale - $2.14/W

National average - $3.37/W

Sources: Sources: GTM Research/SEIA, NREL, Lawrence Berkeley National Lab, BNEF, European Photovoltaic Industry Assn (EPIA), BSW Solar


0

25

50

75

100

125

150

175

200

225

2005 2010 2015 2020 2025 2030 Inst

alle

d PV

Cap

acity

(GW

) in

USA

Years

What if Standards are not Changed?

Source: DOE SunShot Vision Study (Total PV Capacity in U.S. 2008 – 2030)

Retrofitting inverters in a later date could be pretty expensive

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http://www.google.com/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&docid=nwSL3DR_E5MyNM&tbnid=3aF13yJN68lg-M:&ved=0CAUQjRw&url=http://ashishlive.blogspot.com/2013/02/alarm-clock-myth-how-to-wake-up-early.html&ei=7fheUpXPN8asiQKO24CICQ&psig=AFQjCNHD1xHvn0Xk-X7vQNs9e694QaeoTA&ust=1382042188293736


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DG Interconnection Issues and Potential Grid-Support Functionalities › static-assets › documents...

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Transcript of DG Interconnection Issues and Potential Grid-Support Functionalities › static-assets › documents...