Transcript Feb 2011 - IEEE Entity Web Hosting

•AEP’s gridSMARTsm Strategy & Technologies
IEEE Meeting
February 24, 2011
Richard Greer
1
The Evolution of the Electric Utility System
Before Smart Grid:
One-way power flow,
simple interactions
After Smart Grid:
Two-way power flow,
multi-stakeholder
interactions
Adapted from EPRI Presentation by Joe Hughes
NIST Standards Workshop
April 28, 2008
2
AEP’s Distribution “Grid Management” Infrastructure
• Transforming from Single Source Distribution Circuits to an
Interconnected Grid with Multiple Sources, Real Time Visualization,
Optimization, Automation, and Control.
–
–
–
–
–
Installation of a distribution management system (SCADA) and the development of a distribution
energy management system with visualization tools for “multi-source” distribution operations.
Control of voltage and Var to maximize grid efficiency from the generator to the customer
Circuit reconfiguration to improve reliability and optimize circuit performance.
Accommodate and take full advantage of distributed energy sources including renewables,
storage, customer generation, and demand response
Installation of remote sensors and automated control devices to provide “real time” analysis of
the dispatch of multiple sources on a feeder
3
Distribution Operations Center (DOC)
Distribution Management System
DSCADA
Outage Management System
(OMS)
CYBER SECURITY FIREWALL
Real Time
BACKHAUL COMMUNICATIONS
Real Time
and
Historical
Data
Distributed
Energy
Resources
Fault
Locating
Distribution
Automation
Equipment
Monitoring
and
Diagnostics
gridManagement Analytics
AMI
Meters
Distribution Operations Center (DOC)
Distribution Management System
Outage Management System
(OMS)
DSCADA
Distributed
Generation
Transformers
Power Up
Energy Storage
Line Devices
Power Down
Demand Response
Insulators
CYBER SECURITY
FIREWALL
PING
Solar
& Wind
Conductors
Real Time
Meter Events
PHEVs
BACKHAUL COMMUNICATIONS
Real Time
and
Equipment
Historical
Monitoring
Data
and
Diagnostics
Distribution
Automation
Distributed Energy
Resources
Fault
Locating
Fault Values
Circuit Reconfiguration
gridManagement Analytics
Anticipation
Device Status
Indication
Remote Operation
Volt Var Control (IVVC)
AMI
Meters
Distribution Operations Center (DOC)
Distribution Management System
DSCADA
Outage Management System
(OMS)
CYBER SECURITY FIREWALL
Real Time
BACKHAUL COMMUNICATIONS
Real Time
and
Historical
Demand
Data
Reliability Engineers
Response Analytics
Customer
Fault
Locating
Distribution
Automation
Planning Engineers
gridManagement
Equipment
Monitoring
and
Diagnostics
AMI
Meters
Operation Engineers
Analytics
Transmission Co-Located Engineers
Distribution Market Clearing (future)
AEP gridSMART Deployment Status
Indiana Michigan Power (AEP) – In Service
• 10,000 AMI pilot program (GE meters)
• Distribution automation
• Programmable communicating thermostats
• Enhanced time-of-use tariffs
• Customer web portal for monitoring & management
AEP Ohio – In Progress
AEP Texas – In Progress
• 110,000 AMI deployment in NE Columbus area
• Full suite of distribution automation technologies
• Advanced technology deployment (Energy storage, PHEVs)
• Enhanced time-of-use tariffs
• Home area networks & grid-friendly appliances
• Approximately 1 million AMI meters
• In-home display devices
• Tariffs & programs to be offered by REPs
7
Automated Circuit Reconfiguration
• Utilizes communication and intelligent
technology to minimize # of customers impacted by an outage
• can improve circuit reliability by 30 – 50%
• Can improve energy efficiency by notifying operations when a capacitor bank is
abnormal
• Improves safety and efficiency for field employees by using SCADA for remote
switching
• This technology has been evolving over several years and
standards are being developed.
• Actual deployment still is limited in most utilities.
• AEP has deployed this technology on less than 2% of circuits.
• The potential for improving reliability and increasing energy efficiency of
distribution circuits is high if more automation is deployed.
8
Temporary Fault – Momentary Interruption
900
B
R
R
300
300
300
Station A
900
B
R
300
R
300
300
300
Station B
900
B
R
300
R
300
Operational Summary
• Traditional Circuit
• Temporary Fault – no sustained outage
• 600 Customers saw a short interruption
(blink)
• MAIFI = 1 for these 600 customers
10
Permanent Fault
600 Customers Outaged
900
B
R
R
300
300
300
Station A
900
B
R
300
R
300
300
300
Station B
900
B
R
300
R
300
Operational Summary
•
•
•
•
•
•
Traditional Circuit
Permanent Fault
1 Instantaneous and 2 time delay trips
600 Customers Outaged
Circuit SAIFI = 600 / 900 = 0.67
System SAIFI = 600 / 2,700 = 0.22
12
Permanent Fault
With DA = 300 Customers Outaged
900
B
R
R
300
300
300
Station A
900
R
B
R
300
R
300
300
300
Station B
900
B
R
300
R
300
Operational Summary
•
•
•
•
•
•
•
•
•
Circuits With DA
Permanent Fault
1 Instantaneous and 2 time delay trips
DA Reconfigured Circuits
600 Customers saw short interruptions (blinks)
300 Customers Outaged
Circuit SAIFI = 300 / 900 = 0.33
System SAIFI = 300 / 2,700 = 0.11
MAIFI for 300 Customers = 1
14
Transformer Diagnostics & Monitoring
• GE Hydran M2: An intelligent, online transformer monitoring system
that provides:
– Per phase real time load,
– Per phase winding temperatures,
– Transformer top oil temperature,
– The level of combustible gases
and moisture in dielectric oil,
– Oil bubbling temperature,
– Aging rate and early detection of
incipient faults in station
transformers.
• 73 units installed
• Visible via SCADA and PI Historian
15
AEP’s Volt Var Control Technologies
Utility Voltage / Var Control:
1.
Projected benefits of 2% demand and energy reduction are highly predictable because customer
consumption is reduced with no action required on their part.
The technology optimizes power factor and voltage levels based on selected parameters
2.
a.
b.
c.
3.
Power factors close to unity minimize losses and relieve transmission congestion
Projected response is a 0.7% demand / energy reduction for each 1% volt reduction
Projected result is 2 - 4% demand and energy reduction
Utilizes communications and computerized intelligence to control voltage regulators and
capacitors on the distribution system
Algorithm uses end of line monitoring feedback to ensure minimum required voltage maintained
4.
AEP Ohio Demonstration Projects:
1.
Equipment deployment and demonstration of Volt Var Control technologies
a.
b.
2.
GE IVVC – 5 Stations (4 -34KV & 7 - 13KV Circuits)
AdaptiVolt – 1 Station (6 – 13KV Circuits)
Independent analysis by Battelle of theoretical and measured results – Expect savings
of MW, MWH, MVAR, and MVARH
a.
b.
Analysis of financial benefits of MW, MWH, MVAR, and MVARH savings
Projections of system wide benefits
Utility VVC can achieve predictable EE/DR and emission reduction goals
16
Estimated Benefits with GE IVVC on Karl Road 12 kV Feeder
Demand Reduction
= 88 KVA (2.1%) if
voltage reduced 3%
KVA Reduction
= 325 KVA (8.4%) if pf
= 1.0 (4185-3860)
Energy Reduction =
52 KW * 8760 =
455 MWH if voltage
Reduced 3%
17
Voltage Range Goals
•
Volts at Residential Meter:
Historical
Voltage
Range
128
“B” Utilization
“B” Service
“A” Utilization
120
“A” Service
124
•
ANSI Standard C 84.1 –
1995 “Electrical Power
Systems and
Equipment – Voltage
Ratings”
[similar to CAN3-C23583 (R2000)]
–Nominal 120 VAC – Range A
(Normal Operation)
•Service Voltage 114 v – 126 v
– Voltage at which utility delivers
power to home
116
•Utilization Voltage 110v – 126 v
112
IVVC Range
– Voltage at which equipment uses
power
– Optimum voltage for most motors
rated at 115 v
– Incandescent Lamps rated at 120 v
108
–Nominal 120 VAC – Range B
(Out of Normal Operation)
104
•Service Voltage 110 v – 127 v
•Utilization Voltage 106v – 127 v
(Adapitvolt estimates)
18
East Broad Station – Volt Var Control
19
East Broad – 1406 Geographic Layout
REG 1
CAP 2
CAP 1
Substation
EOL 55
EOL 57
CAP 3
EOL 56
REG 2 CAP 4
20
East Broad – 1406 Voltage Profile
CAP 1
CAP 2
REG 1
CAP 3
REG 2
CAP 4
EOL 55
Substation
Normal Operation
With VVC
126.0
124.0
122.0
120.0
118.0
116.0
21
East Broad – 1408 Geographic Layout
Substation
EOL 64
CAP 1
EOL 63
CAP 2
22
East Broad – 1408 Voltage Profile
EOL 64
Substation
CAP 1
Normal Operation
EOL 63
CAP 2
With VVC
125.0
123.0
121.0
119.0
117.0
Norm al Operation
With VVC
125.0
123.0
121.0
119.0
117.0
23
Battelle Study – Initial Projections on 8 GE CVVC
Circuits
Projected Peak Demand Reduction 3%
Projected Energy Reduction 3.3%
24
Volt VAR Control can reduce customer consumption
and energy cost
123 Volts
119 Volts
1,055.6 KW
607,600 kwh
$43,740 / mo
1,034.48 KW
595,448 kwh
$42,873 / mo
25
Challenges
• “Near Real Time Operation” requires highly reliable
communication
• Vendor solutions for VVC are still evolving
• Finding balance point for investment in circuit upgrades
vs. control systems
• Understanding how technical benefits translate into
financial benefits
• Determining appropriate regulatory recovery strategy
• Communicating that demand and energy reductions are
mostly due to reduced consumption and the loss
reduction piece is small
26
AEP’s gridSMART Advanced Technologies
Distributed Renewable Generation
• 70 KW photovoltaic panels installed on roofs of
AEP Service Centers in Newark,OH and Athens,OH
[70 KW X 2 = 140KW]
• R&D project comparing traditional PV to concentrated
PV at AEP’s Dolan Engineering lab (Groveport, OH)
27
Plug-in Electric Vehicles and Infrastructure
Corporate Strategy and Readiness
• AEP strongly supports and promotes the adoption of
PEV technology
• Developing consumer programs (system-wide)
which may include “EV-Friendly” rates and
incentives.
• Working with various stakeholders in all AEP states
to ensure greatest consumer experience.
PEV Demonstration – Columbus, Ohio (2010-2013)
• Deploying 10 PEVs and 15 charging stations to AEP
employees living in the demo area.
• Collecting and analyzing driving/charging behaviors
and potential impact to grid. Utilizing “smart
charging” to reduce impact.
• Vehicles will include Chevy Volts, Smart EVs, Ford
Escape PHEV, 2 Prius converted to PHEV
28
AEP’s gridSMART Advanced Technologies
Substation Scale Battery
• 2006: 1 MW, 7.2 MWh; Deferred substation upgrade
in Charleston, WV
• 2008: Three installations; 2 MW, 14.4 MWh each;
With “islanding” in Bluffton,OH; Balls Gap,WV;
East Busco,IN
• 2010: 4MW, 25MWh; To be installed in Presidio, TX
Community Energy Storage
• Small distributed energy storage units connected to
the secondary of transformers serving a few houses
or commercial loads.
• Pursuing development & deployment:
29
AEP’s (NaS) Battery Application
1 MW, 7.2 MWh installed in Chemical
Station (Charleston, WV - 2006)
• Deferred substation upgrades
Three installations in 2008 (2 MW Each)
• Peak Shaving
• Demonstrate “Islanding”
• Storage of intermittent renewables
• Sub-transmission support
AEP selected Sodium Sulfur (NaS) technology
• Proven technology in Japan (TEPCO)
• 1-10 MW, 4-8 hour storage systems
• NaS strengths:
290-360 ºC
•
•
•
•
Commercial record over 1MW (over 100 installations)
Cost
Compactness
Modularity & Ability to be relocated
AEP NaS Application #1
31
Bluffton, OH NaS 2 MW in Service
32
AEP 2006 Project – Performance Data
• Scheduled trapezoidal Charge &
Discharge profiles
2006
- 1.0 MW Discharge
• Improved the feeder load factor by
5% (from 75% to 80%)
+ 1.2 MW Charge
Three
Successful
Years of
Peak
Shaving
2007
2008
NaS Islanding – S&C IntelliTEAM II
34
Community Energy Storage (CES)
CES is a small distributed energy storage unit connected to
the secondary of transformers serving a few houses or
small commercial loads
Key Parameters
Value
Power (active and
reactive)
25 kVA
Energy
75 kWh
Voltage - Secondary
240 / 120V
Battery - PHEV
Li-Ion
Round Trip AC Energy
Efficiency
> 85%
25 KVA
AEP Specifications for CES is “OPEN SOURCE” for Public Use and Feedback.
EPRI is hosting free, open webcasts to solicit industry wide input.
www.aeptechcenter.com/ces
35
AEP Ohio GridSMART Demonstration - CES
• CES: 2MW/2MWh; Fleet of 80 25-kW Units
• Circuit: Morse Rd 5801; 13 kV, 6.3 MVA Peak
Load, 1742 customers
• Coverage: Approximately 20% of customers
• Schedule:
• Status: Jun 2010 – Prototype under construction
North
Aug 2010 Test Prototypes
Apr 2011 First 0.5MW
Oct 2011 Remaining 1.5MW
Morse Rd 5801
Community Energy Storage (CES)
CES is a distributed fleet of small energy storage units
connected to the secondary of transformers serving a few
houses or small commercial loads.
STATION
CES
CES
CES
CES
37
CES Layout
38
CES – Virtual Station Scale Storage
CES is Operated as a Fleet offering a Multi-MW, Multi-hour Storage
Local Benefits:
1) Backup power
2) Flicker Mitigation
3) Renewable Integration
Substation
CES
Power Lines
Communication and Control Links
39
CES – Virtual Station Scale Storage
CES is Operated as a Fleet offering a Multi-MW, Multi-hour Storage
Grid Benefits:
Local Benefits:
4) Load Leveling at substation
5) Power Factor Correction
6) Ancillary services
1) Backup power
2) Flicker Mitigation
3) Renewable Integration
Operations
Center
CES Control Hub
Communication &
Control Layout for
CES
Substation
CES
CES
CES
CES
Power Lines
Communication and Control Links
40
CES Control Environment
Enterprise Systems
CIS
(Customer)
AMI
Head-end
GIS
(Asset)
History
Archives
OMS
(Outage)
D-SCADA
CES
Management
MDM
(Meter)
DWM
(Work)
T-SCADA
Backhaul (Fiber and other)
Regional
(Station)
VV
Controller
DA
Controller
CES
Controller
D-SCADA
RTU
T-SCADA
RTU
Mesh Network (DNP)
Feeder
Devices
Capacitor
Regulator
HAN
Customer
Devices
HVAC
Thermostat
Recloser
Switch
CES
Unit
Revenue
Meter
(Zigbee / HomePlug)
Water
Heater
Customer
Display
PEV Smart
Charger
41
Circuit Load Leveling Example
Circuit Demand
42
Time Triggered Load Following
Set Points:
• Start Time (same for all days)
• Minimum Demand below which no energy should be discharged
Minimum
Demand at
for discharge
2:00 pm
Day1
No Discharge
on Low
demands
2:00 pm
Day2
2:00 pm
Day3
43
Load Leveling Challenge – perfect timing
Inadequate energy on
high-peak days makes
peak shaving ineffective
Set Trigger
Level
44
Load Leveling – Spread Across the CES Fleet
Feeder
Load
CES
#1
CES
#2
Trigger Level for
Charge
CES
#3
Trigger Level for
Discharge
Circuit Feeder's charge and discharge needs
are assessed periodically and divided among
CES Units on the circuit feeder
Midnight
Morning
Noon
Evening
Feeder level demand profile showing CES Unit charge and discharge
45
CES Energy Allocation during backup
Each customer connected to the CES Unit gets a fair share of
available stored energy at the time an outage occurs.
CES goes into backup (island) mode
1. Establish the island, calculate available energy per
locally connected customer; x kWh
2. Instruct each locally connected meter to initiate energy
limiting; allow x kWh
3. If a customer reaches energy allocation, x kWh, the
meter opens its disconnect switch
46
CES Energy Allocation - Return
CES returns from backup (island) mode when the circuit
returns to normal (system is stable for 5 minutes)
1. CES synchronizes and reconnects to circuit, closed
transition
2. CES cancels energy allocation instruction to each locally
connected meter
3. Each open meter closes the disconnect switch {unless
there was another active command to open}
47
CES Customer Interface Challenges
•Another box in the yard, installation
•Equipment access for maintenance
•Transformer has 4 customers, 2 are interested
•Reliability is not really a problem
•My neighbor will use all the energy
48
Transforming to a Smart Grid Engineer
• Distribution Engineers will need new skills to plan for
stations and circuits utilizing DA, IVVC, DG, and
other new technologies.
• Planning and protection studies will be more complex
• Distribution Engineers will also have access to new
data to help analyze system performance and
validate the results of studies.
– An interesting example is the ability to collect data on the
performance of Distributed Generation (DG) and validate the
DG’s impact on the system during abnormal conditions.
– This type of analysis should lead to higher confidence levels
for Distribution Engineers charged with assuring proper
operation of their circuits while accommodating and taking
advantage of DG in a Smart Grid world
49
Summary
• Customers will see higher reliability and more
opportunity to control their energy usage and cost.
• Utility employees will have new systems to learn, new
responsibilities, and much more information about
system operation than they have ever had.
• The public at large should see environmental benefits
as a Smart Grid helps reduce emissions from
generating plants by helping control demand and
energy usage while still assuring the customers’
needs for energy are met.
50
Questions?
Richard Greer – AEP – [email protected]
540-985-2617
51