10.3_Practical Implementation of Microgrid Control, Protection, and Communications_Manson_SEL

Practical Implementation of Microgrid Control, Protection, and Communications

Scott MansonTechnology Director, SEL

Control Cost, Quality, FeaturesHardware-in-the-Loop Testing

Both Mechanical and Electrical Systems Must Be Modeled Accurately!

Controller

Inputs

ControllerStatus

Controls

Dynamic Simulation

System

Outputs

0.961.0

Power (pu)

Frequency (pu)

1.0

Steady-State Droop Line

3

21

Transient Governor Behavior

Governor Frequency Set Point

Factory Acceptance Tests Improved With Hardware-in-the-Loop Testing

66

65

64

63

62

61

60

590 10 20 30 40

Time (s)

Freq

uenc

y (H

z)

Field

Simulation

Inverter-Based Generation Has Limited Overload Capacity

Short-Term Capacity Limit

Long-Term Capacity Limit

Inverter-Based Generation

Q

P

Rotating Generators

Q

P

Load Balancing Must Happen Faster With Inverter-Based Generation

Pow

er, F

requ

ency

Time

Rotating Generation Power

Rotating Generator Frequency

Power

Frequency

Load

Inverter-Based Power

Inverter-Based Frequency

FAST Load Shedding Prevents Blackouts

Grid-Tied Operation

Islanded Operation

Synchronization Systems

Automatic Decoupling

Load Shedding

Subcycle FAST

Controller

Relay

Status Trip

PF Deadband

–PF

+PF

–P +P

–PF

+PF

+Q

–QEnlargement of Origin

–100 +100

–50

+50

Deadband Control

Boundary

+28.9

PFsp1, sp2

PFactual1

PFactual1

+0.5

PF–0.5 PF

+0.5

PF –0.5 PF

Power Factor Control Limits Must Be Considered Carefully!

Frequency and Voltage Define Power System Resilience

1/f

t

f

V

V

2V

63

57

Rotating Generator

Sets

1.3 0.7

Generation Shedding

Load Shedding

Allowable Operation

65

1.2 0.8

55

Inverter Technology

A

CB2 CB157

60

63

f (Hz)

B

Reliability Improved With Several Load-Balancing Techniques

CB1 Opens:Contingency

Load Shedding Island Generator

AutobalancingAka “AGC”

CB2 Opens

Underfrequency Load Shedding

Overfrequency Generation Runback

How Much “Responsive” Generation Is Required to Ensure Stability?Step 1: Identify grid time constants

+

–

–DER Frequency/Droop Controller

Steady-State Electrical Load

Frequency

+ –

Simplification

Frequency

1JS

1R

2

R1 S

DER Frequency/Droop Controller

Power System 2 (seconds)Utility 0.5 to 1.2 Microgrid 0.25 to 2.5

How Much “Responsive” Generation Is Required to Ensure Stability?Step 2: Tabulate Incremental Reserve Margins (IRM)

DER Rating (kW) IRM (%) IRM (MW)PV 200 0 0Battery (SLOW) 1000 5 50Battery (FAST) 1000 100 1000Steam Extraction Turbine 1200 0 0CHP 900 10 90Gas Turbine 1500 40 600Diesel Genset 1000 40 400Totals 6800 31.5 2140

How Much “Responsive” Generation Is Required to Ensure Stability?Step 3: Compare Total IRM to Largest Disturbance

Event kWSmall Motor 200LCI drive 2000Large Feeder 5000Small Feeder 800Available IRM 2140

50

49.449

48

Hz

DERs will trip

Macrogrid

Power

Freq

uenc

y

Microgrid

Power

Frequency

Load

Freq

uenc

y (H

z)

474849505152535455

0 50 100 150 200 250 300Time (seconds)

Unstable Microgrid

Governor Controls must be Adapted for Changing load Composition

Load Responses Are Different for Islanded Microgrids

Intelligent Relays Are Used to Adapt DER Controllers

Turbine

Electric Generator

Valve Turbine Controller

MicrogridMacrogrid

Relay

Microgrid Controller

Relay

Relay

Relay

Relay

RelayRelay

Relay Relay

Relay

It’s an Island !

Protection Must Adapt to Changing Fault Conditions Fault levels Grounding Directions Impedances

DERt

I

Relay

20,000

20,000

2,000

2,000

Fault Current Independent Protection Schemes Are Preferred Line current differential Transformer differential

Bus differential Time domain (future)

Security for Critical Infrastructure

• Avoid OS and software• Made in the USA • Mature Processes• Vertical Integration• Cyber Security

Conclusions

Testing reduces installation and maintenance costs Fast control systems prevent outages Reliable load balancing maintains stability Adaptive protection saves lives Security in depth is mandatory