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2018-05-08

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Advances in DER Interconnection Processes and Study Methods1

Advances in DER Interconnection Processes and Study MethodsAlex Nassif, Specialist Engineer

Advances in DER Interconnection Processes and Study Methods

EVOLVING DER ENVIRONMENT IN ALBERTA

• Significant rise in interest for DER connections circa 2014

• Punitive rules incented gas-fired DERs

• Incentives introduced for low-emission commercial and load offsetting installations

• Two categories for DER in Alberta with different requirements:

1. Micro-Generation (MG)

2. Distributed Generation (DG)

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DISTRIBUTION SYSTEM CONNECTION CONSIDERATIONS

Distributed Energy Resources – Why connect to the D-System?

1. Fit for purpose

2. Lower connection cost

3. Faster interconnection process

3



Considerations

1. ATCO system serves predominantly industrial load with low customer density and long feeders

2. 25kV feeders may accommodate up to 25MW

• Maximum standard line apparatus rating of 600A

• In-line devices and conductors with gradually reduced rating

3. Anti-Islanding protection required

• Safety and technical liability concerns

• Transfer Trip is the standard solution for synchronous generators

• Will accept IEEE 1547, UL-1741-SA and CAISO Rule 21 approved inverters

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4. DERs are not permitted to actively regulate voltage on distribution networks in Alberta. (Not Yet)

5. Voltage management is more difficult with distance from the Substation

• R/X characteristics – voltage rise issues

• VAR control becomes less effective

5

Distribution Line

VS VR

Substation PL+jQL

R+jX

DG

PG+jQG

PX

RQ

S

GLGLRS

V

XQQRPPVVV


BECOMING A DER ENABLER

Recent Enabling Developments:

1. Introduced a DG preliminary assessment (Free of Charge)

2. Streamlined DG distribution system study requirements

3. Created and published enhanced information for developers and utility staff (DG & MG primers)

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4. Hosting Capacity (HC) for MGs

• Conducted R&D methods to determine HC

• Releasing Capacity Maps

5. Investigated alternatives for DGs TT:

• Inverters active anti-islanding protection

• Passive anti-islanding protection (addressed later in this presentation)

• Power Line Carrier alternative

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6. Developing Grid Modernization Strategies to enable an interactive environment:

• Advanced Distribution Management System (ADMS).

• Advanced Metering Infrastructure (AMI)

• DER Management Systems (DERMS)

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DG INTERCONNECTION PROCESS

To meet developer expectations and manage manpower commitment, a streamlined DG interconnection process was developed:

1. Preliminary Planning Assessment – 1 week

2. Feasibility Assessment (Application for Connection) – 30 days

3. Connection Proposal (Acceptance of Feasibility Assessment)

4. Engineering Design, Construction and Commissioning (Project Acceptance)

At each step all costs are borne by the customer alone

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1. Phase 0 - Preliminary Planning Assessment (optional)

• ~ 1 hour of planner’s time

• High level connection feasibility assessment based on engineering judgement

• Utilize • GIS

• Distribution Switching Maps

• Substation SLDs and Load Forecasts

• Free of charge

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2. Phase 1 - Feasibility Assessment• Distribution study covering steady-state as well as DG &

load rejection conditions.• Determine feasible generation connection limits,

including specified operating power factor with and without upgrades to the distribution network.

• Ballpark scope for distribution connection and transmission requirements (DTT & substation logic)

• OOM estimate (T & D) provided by Project Manager• Requires an application fee

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3. Phase 2 - Connection Proposal

• Site visit and firm estimate from Distribution

• Dynamic studies (if required) using an EMTP

• DBM scope and estimate from Transmission

• Firm connection proposal provided to DG developer

• A fee is collected. If project does not proceed, unspent monies are returned to the DG developer.

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4. Engineering Design, Construction and Commissioning

• Moves to project execution and is no longer in the planning realm

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EUA: MICRO-GENERATION (MG) REGULATION

• Not to exceed annual load consumption

• Not to exceed the Electric service

• Renewable or Alternative (Emissions < 418kg/MWh)

• Small MG < 150kW, Large MG > 150kW

New enabling conditions:

• Annual load offsetting (multiple adjacent metered sites allowed)

• Nameplate up to 5MW (from previous 1 MW limit)

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MG INTERCONNECTION PROCESS

MG Process:1. Application filed with the DFO

2. Meets renewable/alternative requirements

3. Commercial eligibility (load offsetting)

4. Technical assessment

5. Bi-directional meter installed by DFO

Predicated on system upgrades not being required – DFO bears connection cost

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MG INTERCONNECTION PROCESS

ATCO recent enabling activities:

• Updating the MG connection process

• Developed an MG connection primer for staff use

• Developed hosting capacity guidelines and algorithms

• Developed Technical Interconnection Requirements for DERs that must be met by both MGs and DGs

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TRANSITIONING FROM ACCOMMODATING INTO COOPERATING

Increasing Hosting Capacity and Improving Grid Reliability

ATCO is leveraging smart inverter technologies, by aligning its Technical Interconnection Requirements with those of revised versions of IEEE 1547 and UL 1741:

• Autonomous control functions (e.g., Volt-VAR, Volt-Watt)

• Remote control functions (e.g., dynamic PF, VAR and/or Watt output)

• Enhanced disturbance ride through for system level contingencies

• Visibility and controllability

• Anti-Islanding Protection

Investigating telecom requirements and options

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UPDATES ON DER INTERCONNECTION STANDARDS

1. UL 1741 SA released September 2016

• Includes performance functions as per CAISO Rule 21

2. IEEE 1547 released April 2018

• Aligned with CAISO Rule 21 and UL 1741 SA

3. CSA C22.2 No. 257 (inverters) and CSA C22.3 No. 09 (DERs) to be consolidated and aligned with UL and IEEE standards

ATCO, Fortis and ENMAX are part of CSA Task Forces

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TECHNICAL INVESTIGATIONS/INNOVATION

1. Mitigating overvoltage caused by DERs

2. 8760 Planning for PVs

3. Application of passive protection schemes in selected cases

4. Measures to reduce protection miscoordination

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MITIGATING OVERVOLTAGE CAUSED BY DERS

Problem Definition

20

Distribution Line

VS VR

Substation PL+jQL

R+jX

DG

PG+jQG

PX

RQ

S

GLGLRS

V

XQQRPPVVV

This work was presented in: A. Nassif, X. Long, “Mitigating Overvoltage Scenarios Caused by Large Penetration of Distributed Energy Resources”, 2016 IEEE Electrical Power and Energy Conference, October 12-14, 2016.

• DERs must operate under PF control

• Active power flow causes voltage rise

• PCC voltage is higher under light loading

• R/X characteristics – voltage rise issues

• VAR control is less effective

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Voltage regulator-based solution:

• Neutral Idle (preferred)

• Co-Gen: Reverse settings required

32-step tap changers that provide ±10% regulation

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Power Factor-based solution is limited:I. PF range for inverters is often ± 90%

II. Synchronous gens: capacity curve – often +90% to -0.97% @ rated

III. Induction gens: usually around -89% when not coupled with inverter

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Circuit-based solution: Reconductor the distribution line

• Reduction of the equivalent thevenin impedance at PCC

Expensive!

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1.025

1.030

1.035

1.040

1.045

1.050

1.055

1.060

1.065

1.070

0 5 10 15 20 25

Vo

ltag

e P

rofi

le [

p.u

.]

Distance to Substation [km]

Pf = -0.95

Reconductor

Conductor R (Ω/km) X (Ω/km) B (uS/km)

1/0 0.55 0.46 3.80

#266 0.22 0.40 4.13

#477 0.12 0.38 4.41



Distribution STATCOM – manages voltage through VAR exchange

• DFO manages VAR exchange

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1.030

1.035

1.040

1.045

1.050

1.055

1.060

1.065

1.070

0 5 10 15 20 25

Vo

ltag

e P

rofi

le [

p.u

.]

Distance to Substation [km]

PF = -0.95

STATCOM

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Change the DER operating mode voltage control (DER controls voltage):

• Autonomous Volt-VAR control mode

I. Limited effect

II. Difficult to coordinate with the utility

• Autonomous Volt-Watt control mode

I. Very effective

II. Essentially local power curtailment

III. Difficult to coordinate with the utility

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Future Direction: Coordinated Control (DERMS)

• Coordinate operation between the utility and the DER.

• A system similar to EMS.

• DFO will be able to send signals to control DER output, PF, control modes, etc.

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8760 PLANNING – INCREASING CONNECTION SIZE

• 15 MW PV DER application (1st in queue)

• 5 MW synchronous DER application for 5MW (2nd)

• 12.9 MW POD Capacity

• Minimum POD loading (excluding outages) considered

• Traditional planning:

• Limit PV DER @ 12.9 MW

• Reject Synchronous DER

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8760 PLANNING – INCREASING CONNECTION SIZE

Load Duration Study

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Case 1 Case 2 Case 1 Case 2

# of kWh curtailed* 27148 26932

# of hours curtailment

occurs* 25 22

% of kWh curtailed* 0 0

% of hours curtailment

occurs* 0 0

*assuming synchronous DER operates at 5MW production 8760

Case 1: PV @ 13.3 MW and tilt angle 45 degreesCase 2: PV @ 13.3 MW and tilt angle 52.8 (optimum) degrees

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8760 PLANNING - SMART INVERTERS AND BESS

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Re

acti

ve P

ow

er

Ab

sorp

tio

nIn

ject

ion

VL V1 V2 VRef V3 V4 VH

Dead Band

Act

ive

Po

wer

Ou

tpu

t

VL VRef VH

Dead Band

This work will be published in: A. Nassif, T. Greenwood-Madsen, S. Pirooz-Azad, D. Teshome, “Feeder Voltage Management through Smart Inverter Advanced Functions and Battery Energy Storage System”, 2018 IEEE PES General Meeting, (accepted – August 2018)

Autonomous Voltage Control Inverter Functions



Hypothetical scenario: a feeder in Fort McMurray with 50% penetration distributed PV

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VS

0.6 km

PV

Distributed 1ph and 3ph loads

7 km

#1 AL

PVPVPVPVPV

Distributed 1ph and 3ph PV

0 100 200 300 400 500 600 700 8000

100

200

300

400

500

PV

outp

ut

[kW

]

Volt-Watt

PF=1

0 100 200 300 400 500 600 700 8000

500

1000

1500

PV

outp

ut

[kW

]

Hour

Volt-Watt

PF=1

Last PV

First PV

0 100 200 300 400 500 600 700 8001.02

1.04

1.06

1.08

1.1

1.12

EO

L V

oltage [

p.u

.]

Volt-Watt

PF=1

0 100 200 300 400 500 600 700 8001.03

1.035

1.04

1.045

1.05

1.055

BO

L V

oltage [

p.u

.]

Hour

Volt-Watt

PF=1

About 23% of energy curtailed in June.

Less than 10% curtailment for the full year.

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BESS effect: Best siting:

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0 100 200 300 400 500 600 700 8001.02

1.04

1.06

1.08

1.1

1.12

EO

L V

oltage [

p.u

.]

Volt-Watt

PF=1

BESS 1MWh

BESS 5MWh

BESS 7MWh

0 100 200 300 400 500 600 700 8001.02

1.04

1.06

1.08

1.1

BO

L V

oltage [

p.u

.]

Hour

BESS 1MWh

BESS 5MWh

BESS 7MWh

A 7MWh BESS would be required to keep voltages within targets as compared to Volt-Watt.

0 1 2 3 4 5 6 7 81

1.01

1.02

1.03

1.04

1.05

Voltage [

p.u

.]

Distance from Substation [km]



• Volt-VAR is not effective

• Volt-Watt is very effective and economical (to DFO)

• BESS levels off renewable production, but is expensive

• DERMS is a global solution that retains control to DFO

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Solution Cost Advantages Limitations

Advanced Inverter Functions

LowEffective, localized

solution (Volt-Watt).

Removes utility control. Curtails inverter output.

DERMS Very HighGlobal solution.

Does not remove utility control.

Curtails inverter output, but optimally.

BESS HighUtility retains

control. Provides ancillary services.

Complexity.

2018-05-08

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ANTI-ISLANDING PROTECTION SCHEMES

Islanding:

• Operational and Safety concerns

• Detection and extinction in less than 2 seconds (as per IEEE 1547 and CSA C22.3 No 9 & C22.2 No 257)

• Current methods to industry today:1. Telecom-based

2. Active protection

3. Passive protection

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This work was published in: A. Nassif, C. Madsen, “A Real Case Application of ROCOF and Vector Surge Relays for Anti-Islanding Protection of Distributed Energy Resources”, 2017 IEEE Electrical Power and Energy Conference, October 22-25, 2017



Telecommunication-based (DTT) – standard solution

• Most dependable and secure scheme

• Operates under breaker/dry contact open/close status

• Telecom fail safe provision

• Does not have Non-Detection Zones (NDZ)

• Often the most expensive

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Active schemes

• Active frequency drift (Sandia)

• Positive feedback

• Negative feedback

• Reactive current injection

• Native to most modern inverter technologies

• Difficult to implement in an external relay

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PASSIVE ANTI-ISLANDING PROTECTION SCHEMES

Passive schemes

• Under/Overvoltage (27, 59), under/over frequency (81)

• Vector Surge (78) and Rate-Of-Change-Of-Frequency (ROCOF - 81R)

• All of them have NDZs

• The more dependable, the smaller the NDZ

• The more secure, the larger the NDZ

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Synchronous Generators

1. Predict the rate of frequency change

2. Predict the angular surge

3. Determine the relay detection speed

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PH

f

dt

dfP

Hdt

d

22

00

H – inertia constant (s)ΔP – power mismatch (p.u.)



ROCOF and Vector Surge relay detection times

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0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.2 0.4 0.6 0.8 1

Trip

pin

g T

ime

(s)

Power Imbalance (pu)

H = 2 s

alpha = 20

alpha = 10

alpha = 8

alpha = 5

alpha = 2

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Case study: interim connection

• DTT would involve a T-Tap POD, plus two terminal PODs.

• DTT timeline would strain the project feasibility.

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VS

0.6 km

DER

ACSR 266

8 km

ACSR 1/0

5 km

ACSR 1/0

9 km

ACSR 266

PCC



• Loading Scenarios :

• Summer Min load 7.6 MW, max DER export 6.25 MW (ΔP = 0.22 p.u.)

• Winter Min Load 8.1 MW, max DER export 6.9 MW (ΔP = 0.18 p.u.)

• A reverse power relay (32) was used to guarantee these conditions

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Outcomes:

• The DG remained in operation and protected by the ROCOF alone for 2 years

• No nuisance trips

• Operated when required

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Lessons learned:

• Passive protection may be used for synchronous generators under favorable scenarios

• Considered on a case-by-case basis (study required)

• For inverters, this element will not work well:

• Lack of inertia means large but fast change in frequency

• Load (rather than generator) inertia plays a large role

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FEEDER PROTECTION DE-SENSITIZATION

DER Infeed causes feeder de-sensitization:

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Substation

F0.07s 1s 5min

DG

Substation

Portion of line unprotected

until DG trips

F0.07s 1s 5min

VS

VGZL1 ZL2

IS_F

F

IG_F

Positive-sequence

Zero-sequence

VS_0

VG_0ZL1_0 ZL2_0

IS_F0

ZG_0

ZS_0

V0

IG_F0

ZL_0IL_F0

This work was published in: A. Nassif, “An Analytical Assessment of Feeder Overcurrent Protection with Large Penetration of Distributed Energy Resources”, IEEE Transactions on Industry Applications, 2018 (early access)



Case Study:

• DER will de-sensitize the upstream protection

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Substation

36km

2km

16km

DG – 5MW/7MWType of fault Location No DER 5MW 7MW

LLL

Sub 406 297 278

DER - 342 393

EOL 406 620 653

Bolted LG

Sub 247 170 157

DER - 312 338

EOL 247 475 488

20ohm LG

Sub 207 119 108

DER - 217 232

EOL 207 330 336

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Solutions and Limitations:1. Increase sensitivity of feeder relay – may not be possible

2. Change DER location – fuel source dependent

3. Implement distance protection – similar issue through different angle

4. Sectionalize the feeder – additional interrupter

5. Change transformer winding connection – only effective for I0

6. Accept sequential tripping – will extend fault clearing time

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FUTURE DIRECTION

• Ongoing enablement of DERs requires a paradigm shift for both DFOs and DER owners/operators

• Coordinated operations will be imperative and will require expanded data collection, telemetry, control and functionality

• DFOs will leverage DER advanced functions to improve the system performance and increase penetration

• It is cooperation rather than tolerance

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