SEPTEMBER 30, 2014 | HOLYOKE, MA
Wind Interconnection in New
England
ISO/RENEW Meeting
Agenda
1. Welcome and Introductions
2. ISO-NE Overview of New England Power System as it Relates
to Wind Interconnection
3. Interconnection Study Timelines, Budget, and Staffing
4. Minimum Interconnection Standard and Curtailment Risk
5. Modifications to Attachment A and B (Interconnection Study
Request Data), Interconnection Agreement
6. Material Modification Manual
7. Detailed Voltage Studies within Wind Farm Driving Use of
Detailed Models
2
Agenda, cont.
8. Should ISO Operating Criteria of Zero Turbine Trips After
Normal Contingencies be Relaxed?
9. Electronic Data Submittal System
10. Communications
11. New NERC Reporting Requirements
3
AGENDA ITEM 2:
ISO-NE OVERVIEW OF NEW ENGLAND
POWER SYSTEM AS IT RELATES TO WIND
INTERCONNECTION
Generator Interconnection Technical Challenges
• Development Behind Transmission Constraints
• Nature of the Interconnection
• Implications of Generator Technology
• Consequences for System Operations
5
Generation Development Behind Transmission
Constraints
• All generators in New England compete for transmission use in the Energy
Market based on bid price
– A completed interconnection study, meeting overlapping impact requirements
in the Forward Capacity Market, and Large/Small Generator Interconnection
Agreement (L/SGIA) do NOT assure that a resource can always produce energy
– Definite risk of curtailment, even without transmission outages
– Areas of the system where new renewable resources compete with thermal
resources and existing renewable resources, sometimes the same owner
• Regional transmission constraints
– Broader areas of the system which may constrain concurrent operation of
larger groups of generation. Regional constraints may be in series or nested.
• Local transmission constraints
– Smaller areas of the system which may constrain concurrent operation of
smaller groups of generation. May be nested behind other constraints,
particularly regional constraints.
– Many wind curtailments due to local constraints
6
Nature of the Generator Interconnection
•
Any generator located very far from its interconnection to the transmission system
is likely subject to voltage and stability performance issues
•
Any generator interconnecting to a portion of the transmission system with long
and lower voltage facilities is likely subject to voltage and stability performance
issues
•
Many generators are connecting into electrically weak parts of the New England
system and Eastern Interconnection
– 50 miles of 115 kV line roughly equivalent to 450 miles of 345 kV line
•
Wind interconnecting with bare minimum voltage support – no margin
– Per FERC Order 661, wind plants are required to provide .95 power factor to support
voltage control only if the SIS shows that it is required for reliability
•
First-in generators, especially wind, have quickly utilized any limited existing
system margins, resulting in more significant system upgrades for subsequent
generators
7
Implications of Generator Technology
• Synchronous generators can provide voltage and inertial support at their
Point of Interconnection (POI)
• Inverter-based generators typically have not provided significant system
voltage or stability support, although technologies are improving
• Voltage control/reactive power capability of wind generators, where
available, is mostly consumed within the wind farm; little remains for
overall system support
• Some wind generator power electronic controls will not function properly
in weak areas
• Frequent performance issues and adjustments to stability models for
some wind generator and plant voltage control models throughout study
and post study period
8
Consequences for System Operations
• System Impact Study is a discrete testing program
– Does not directly capture full range of real-time load, outages and needs of
system operators to manage the system and operate under a broad range of
conditions
• Interconnections planned with little or no operating margin (pursuant to
FERC Order 661) can and will result in significant plant operating
restrictions
– Normal operating conditions remove facilities from service, inherently
weakening the system
• Wind plants interconnection plans can become immediately insufficient, relative to
the operating condition
– Greatly impacted by line-out conditions
– Actual operating conditions can be much more stressed than in studies
– Limited margin in study conditions results in greater risk of constraints in
normal operation
– Wind farm curtailment very dependent changing system conditions
9
Consequences for System Operations, cont.
• Each plant design is unique; problems mitigated using multiple devices
– Creates a great challenge to practical system operation
– Impractical for System Operators to be able to understand all of the unique features of
each installation
– Far too many operating condition permutations
– This is a growing concern as more facilities are added to the system
• Last-minute modeling and information changes can result in
– Delays to commercial operation
– Output limitations
• These issues with wind farms have resulted in significant complications for
system operations
– For example, the addition of complicated operating interfaces
10
Existing Wind Capacity Overview
New England
CT
MA
ME
NH
RI
VT
NR Capacity (MW)
707.7
0.0
43.5
384 .0
166.5
0.0
113.7
Num of Wind Farms
in this overview
15
0
2
7
3
0
3
Capacity by Type
Capacity by Manufacturer
Vestas 46%
Type III 77%
GE 28%
Type IV 23%
Gamesa 13%
Siemens 7%
Clipper WP Liberty 6%
• NR Capacity: Network Resource Capacity
• The percentage calculation was based on NR Capacity
11
Existing Wind Farms (Maine)
Stetson
60 MW
Kibby
132 MW
Rollins
Keene Road Export
82.5 MW
Orrington South
Record Hill
50.6 MW
Orrington Import
Wyman Hydro
Export
Bull Hill
34.2 MW
Saddleback
34.2 MW
Canton Mt
22.8 MW
Spruce Mt
20 MW
Rumford
Area
Export
Surowiec
South
Note: The MW value of each wind farm is its nameplate capacity.
12
Existing Wind Farms (NH, VT, MA)
Kingdom
64.58 MW
Granite
99.00 MW
Sheffield
40.00 MW
Sheffield +
Highgate
Export
East-West
Whitefield
South +
GRPW
ME- NH
Groton
48.00 MW
Lempster
24.00 MW
Hoosac
28.50 MW
Note: The MW value of each wind farm is its nameplate capacity. 13
The Problem of Electrical Distance
• The transfer of power over long distances using limited
transmission infrastructure results in voltage concerns
– These voltage concerns can be illustrated and investigated using
concepts such as:
•
•
•
•
Surge Impedance Loading (SIL)
PV (Power vs. Voltage) Analysis
QV (Reactive Power vs. Voltage) Analysis
Short Circuit Ratio (SCR)
14
Surge Impedance Loading
• The MW loading of the line at which a natural reactive power
balance occurs
– When a line is loaded above its SIL, it acts like a shunt reactor,
absorbing reactive power from the system
– When a line is loaded below its SIL, it acts like a shunt capacitor,
supplying reactive power to the system
15
Reactive Power and Voltage Analysis: SIL
• VAR Losses and Surge Impedance Loading Analysis
St. Clair curve:
50 miles: the line limit is dependent on the thermal limit
50 miles to 200 miles: the line limit is dependent on the voltage drop
200 miles: the line limit is dependent on the small signal stability
16
Reactive Power and Voltage Analysis: Case Study
• Existing 99 MW wind farm, connected to the New England
system through two 115 kV lines
• SIL
– Post-contingency, the SIL of the remaining 115 kV line is 36 MW
– Wind Farm’s rated real power output is 2.75 times this SIL
• VAR Losses
– In the all-lines-in case, Wind Farm’s rated real power introduced about 23
MVAR of system incremental reactive losses. With one 115 kV line out, the
incremental reactive losses increased to 57 MVAR.
– The net VAR loss inside the Wind Farm was about 31 MVAR
– Total reactive losses of 88 MVAR due to the wind farm
17
Reactive Power and Voltage Analysis: PV Analysis
• PV Analysis – Evaluate Voltage Stability
Voltage depression typically starts from inside the wind farm after the incremental real power
transfer exhausts all the available reactive resources. Wind interconnection has different
voltage collapse behavior from load center due to Low Voltage Ride-through (LVRT)
characters.
18
Reactive Power and Voltage Analysis: Case Study
• In PV analysis, without reactive upgrades, Wind Farm
encounters voltage collapse when approaching its maximum
output
Volt @ 115kV (pu)
115 kV PV Curves (no reactive output at Wind Farm)
1.06
1.01
All Lines In
0.96
Post Contingency
0.91
0.86
0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
Wind Farm Output (MW)
75
80
85
90
95 100 105 110 115
19
Reactive Power and Voltage Analysis: Case Study
Wind Farm 115 kV P-V Curves (with reactive upgrades)
All Lines In
142
140
130
120
110
100
90
80
70
60
50
40
30
20
Post Contingency
10
1.06
1.04
1.02
1.00
0.98
0.96
0.94
0.92
0.90
0
Volt @ 115kV (pu)
• With reactive upgrades, PV performance is improved
Wind Farm Output (MW)
20
Consequences for System Operation
• With the reactive upgrades installed in the field, the system
barely maintains voltage stability
– This tight margin indicates more output restrictions on the wind farm
when the local system has a facility out for maintenance or other
impaired conditions in operations
21
Reactive Power and Voltage Analysis: QV Analysis
• QV Analysis is used to identify reactive margin
and mitigation
22
Wind Farm Study Overview: Short Circuit Ratio
• SCR has been used to indicate the nature of AC/DC system
interactions
– The associated problems are very dependent on the strength of the AC
system relative to the capacity of the DC equipment
• SCR is defined as:
– SCR = short circuit MVA of AC system/DC converter MW rating
23
Wind Farm Study Overview: Short Circuit Ratio
• There is no well-defined boundary for SCR distinguishing weak and strong
systems, but it is common to consider a system “weak” if SCR is below 2.5
• In a “weak” system, the following problems can be associated with wind
interconnections:
–
–
–
–
Steady state voltage violation
Voltage instability
Oscillation in time domain stability simulation
Wind Turbine Generator (WTG) convertor operation instability
• PSS/E models provided by manufacturers do not represent actual
performance under low short circuit conditions
– Decreasing confidence in the models
• Decreasing confidence in the ability of turbines to operate reliably in these
weak conditions
24
Existing Wind Farms (Maine)
In Farm: 36 MVAR
Kibby Sys Inc: 100MVAR
132 MW Qmax*: 45 MVAR
Wyman: 36 MVAR
SIL**:36.5MW(3.65)
SCR***: 1.76
In Farm: 10MVAR
Sys Inc: 30 MVAR
Qmax*: 24 MVAR
SIL**: 39 MW
SCR***: 3.55
Record Hill
50.6 MW
Spruce Mt
20 MW
In Farm: negligible
Sys Inc: 3.45 MVAR
Qmax*: 6.5 MVAR
SIL**: 4 MW
SCR***: 4.04
Spruce Mt
Unity pf
@ WTG
terminal
Ctrl 115kV
Voltage
±8 DVAR
3.5+3.5+3.0
Caps
LTC ctrl 34.5kV
Ctrl
115kV
Voltage
Upper
Kennebec
Hydro Export
Saddleback In Farm: 17 MVAR
34.2 MW Sys Inc: negligible
Canton Mt Qmax*: 27 MVAR
22.8 MW SIL**: 36+36 MW
SCR***: 2.74
Wyman:2 x
18 Caps
Saddleback
Canton Mt
Unity pf @ WTG
terminal
Keene Road Export
Orrington South
Stetson
Ctrl 115kV
Stetson
Voltage
60 MW
Rollins In Farms: 18+18 MVAR
82.5 MW Sys Inc: 26 MVAR
Qmax*: 69 MVAR
Ctrl 115kV
SIL**:39(R)/33(S) MW
Voltage
SCR***: 8.5(R)/4.5(S)
Orrington Import
Bull Hill In Farm: 7 MVAR
34.2 MW Sys Inc: 6 MVAR
Qmax*: 11 MVAR
SIL**:32+32MW
SCR***: 7.78
Ctrl 115kV
Voltage
LTC ctrl
34.5kV
Rumford
Area
Export
Surowiec
South
* Qmax: the maximum reactive power output of the wind farm including
associate reactive devices.
** SIL: the Surge Impedance Loading of the interconnection
***SCR: Short Circuit Ratio at the Point of Interconnection
Sys Inc – The Incremental VAR losses on the system resulting from the wind
farm
Note: The red MW value of each wind farm is its nameplate
capacity.
25
Existing Wind Farms (NH VT MA)
Kingdom
In Farms: 14 MVAR64.58 MW
Sys Inc: 36 MVAR
Sheffield
Qmax*: 31+38(Jay) MVAR
40.00 MW
SIL**:6.9 MW
In Farms: 7 MVAR
SCR***: 2.29
Sys Inc: 18 MVAR
Qmax*: 10 MVAR
Ctrl 115kV Jay
SIL**:36 MW
Voltage
SCR***: 5.42 East-West
Jay Tap:
+27.5 -14
Condenser
4*5.4 Caps
LTC ctrl 34.5kV
In Farms: 31 MVAR
Sys Inc: 57 MVAR
Granite Qmax*: 43 MVAR
99.00 MW SIL**:36 MW
SCR***: 2.57
Ctrl 115kV ±4 DVAR
4*4.8 Caps
Voltage
`
Sheffield +
Highgate
Export
Whitefield
South +
GRPW
Unity pf @ 115kV
Bus(manually)
ME- NH
Groton
48.00 MW
In Farms: 9 MVAR
Sys Inc: negligible
Qmax*: 35 MVAR
SIL**:34 MW
SCR***: 11.03
Ctrl 115kV
Voltage
In Farms: 7 MVAR
Sys Inc: 7 MVAR
Qmax*: 12 MVAR
SIL**:14 MW
Ctrl
SCR***: 8.27
69kV
Hoosac
Voltage
28.50 MW
Lempster
24.00 MW
In Farms: 2 MVAR
Sys Inc: negligible
Qmax*: 0
SIL**:4 MW
SCR***: 4.42
Ctrl 34.5kV
Voltage
2*±4 DVAR
2*2.5 Caps
* Qmax: the maximum reactive power output of the wind farm
including associate reactive devices.
** SIL: the Surge Impedance Loading of the interconnection
***SCR: Short Circuit Ratio at the Point of Interconnection
Note: The red MW value of each wind farm is its nameplate 26
capacity.
AGENDA ITEM 3:
INTERCONNECTION STUDY TIMELINES,
BUDGET, AND STAFFING
Discussion
Improvements Since Last Workshop
• ISO added new on-site study consultant
• ISO is working with existing study consultants to expedite
study schedules
• ISO is providing advance notice of projected approximate start
dates for projects that have been on hold due to
interdependencies with other projects
– Provides project developers an opportunity to verify/refine submitted
data
• Some project developers are refining their projects while they
are on hold, using this time effectively
28
Wind Interconnection in Weak Areas Presents Significant and
Time-Consuming Study Technical Challenges
•
Validation/refinement/replacement of plant models
–
Improper function of initially provided models
–
Electromagnetic transient analysis required for model validation - PSCAD
–
Restudies caused by mid-study model malfunction
•
Detailed voltage analysis inside the wind farm
•
Resolution of wind turbine control mode oscillation (AGO oscillation)
•
Complexity of plant operational control
•
Concurrent steady state voltage, voltage stability, rotor angle stability and interarea oscillation constraints
•
Interaction of local and inter-area transfers
•
Limited reactive support by plant of network issues related to plant
•
Reactive resource coordination control design
•
Electromagnetic transient analysis of power electronic control interactions
•
Each incremental plant further stresses the system, increasing study complexity
AGO – Advanced Grid Option
29
Individual Project Developers Can Be Responsible
for Both Individual and Cumulative Project Delays
• Proposals for plants that are overly large for their electrical location
– Problems getting the basic plant to function
– Challenges addressing the resultant system issues
• Insufficient initial consideration of wind farm design
• Reiterative modification of plant characteristics
• Multiple requests to change equipment manufacturer
• Poorly functioning and/or poorly documented models
• Poor consistency of model performance when comparing PSS/E with PSCAD
• Updates to equipment models for proposed projects
• Updates to equipment models for existing projects
• Inclusion of undesirable response features
– e.g., “Extended Dip”
30
Reiterative Modification of Plant Characteristics
Causes Significant Study Rework
• Station transformer tap setting (or change to on-line tap
changer)
• Unit transformer tap setting
• Unit VAR output limits
• Unit control mode (constant power factor vs. voltage control)
• UVLS (AGO2) settings
• Trip set points
• Additional features (extended dip, weak grid mode …)
• Adding and/or modifying a park controller
31
Consideration of Reactive Upgrades
• The selection and design of reactive upgrades can take a significant
amount of study effort
– Sufficient descriptive detail of the proposed reactive upgrades must be
available for modeling and analysis
– Must coordinate with other existing and proposed devices
– Long time to collect cost estimates
• A request by the wind farm developer to consider a different reactive
upgrade than the proposed upgrade can cause a significant amount of
study re-work
• Static shunt compensation can be inoperable for intermittent resources
due to quickly changing output conditions and infeasible from a
equipment standpoint due to frequent switching operations
32
Proposed Process Efficiency Improvements
• Require detailed wind farm design as part of Interconnection
Request
– ISO can provide equivalent impedance at POI and performance specifications
– Developer to provide comprehensive documentation demonstrating
conformance with performance requirements
– Subsequent data/design changes will be considered a Material Modification
• Establishment of plant interconnection design standards
– POI with SCR less than 5.0 must be corrected to 5.0
– Standard solutions to system performance problems will be
established
– Voltage performance correction studies will consider the most severe
maintenance condition
• Less liberal material modification review
• May consider alternative queuing and study processes in the
future
33
AGENDA ITEM 4:
MINIMUM INTERCONNECTION STANDARD
AND CURTAILMENT RISK
History of Interconnection Standard
Development in New England
• The Minimum Interconnection Standard (MIS) was established in New
England 1998
• Other areas also developed separate Energy and Capacity interconnections
near that time
• Mandatory national Energy and Network (capacity) interconnection
options established in FERC Order 2003
• The integration of the Interconnection Process with the Forward Capacity
Market was achieved in 2009 with the adoption of the “FCM-Q” reforms
– These changes also included reforms to address FERC concerns regarding
interconnection queue processing inefficiencies
• The full development of rules for the processing of Elective Transmission
Upgrades (ETUs) is underway at this time
35
1998 Bucksport Complaint
• …request that Bucksport’s placement in …queue…effective as
of the date…filed its initial application seeking access to the
NEPOOL PTF grid…
• …also request that Bucksport be allowed to interconnect with
the NEPOOL PTF subject to:
1.
2.
Payment of upgrade costs to preserve reliability of the local PTF and
non-PTF system
The use of economic redispatch in lieu of paying for PTF upgrade
costs until such time as NEPOOL implements a congestion
management plan
PTF – Pool Transmission Facility
36
Bucksport Order
• FERC Orders: Bucksport Complaint, NEPOOL July 22 1998
Compliance Tariff
– “One stop shopping” interconnection application to ISO-NE
– Full integration assumptions “unreasonable and unacceptable”
– Generators in past matched/integrated with load; in future will sell to
power exchange
– Alternative to first-come, first-served application is acceptable
– Decision on transmission cost sharing deferred to Congestion
Management System (CMS) development
37
Minimum Interconnection Standard NEPOOL
Compliance Filing – November 13, 1998
• “Minimum Interconnection Standard” defines new acceptable
interconnection level
– No degradation of transmission system capability
• Enhanced Interconnection - Elective study of optional
transmission upgrades for system penetration
– All MIS studies to be completed before Elective (except for studies at
the time already beyond MIS)
• “Full integration” is subjective and has been inconsistently
defined and applied - practically, not a specifically electable
option
38
Minimum Interconnection Standard
• Minimum required upgrades, consistent with:
–
–
–
–
No degradation in transfer capability
Maximum one-for-one displacement of existing/proposed generation
All reliability standards must be met
ISO can still operate and maintain the system
• “Compromise” standard
– More stringent than “plug and play”
– Does not assure incremental capacity to serve load
– Assures no degradation to load-serving capability of the system with
the new generator
39
Enhanced Study
• Applicant’s specification of study conditions/system
penetration
– “Full integration” not an electable option
• Has been replaced by more general “elective expansion”
40
Observation on the Application of the MIS to
New Generators
• New generators are competing with conventional generators
for transmission access
• New generation has very different voltage support and inertial
characteristics and are more distant from the stronger part of
the grid, than conventional generators
• Hence, new generators are not ready substitutes for many of
the thermal generators they are competing with
• Many upgrades may still be required for basic interconnection
pursuant to the MIS
41
2008 FCM-Q Reforms: Summary of Objectives
• Improved the coordination between the requirements of the
FCM and the current FERC-approved Generator
Interconnection Process
• Addressed Intra-Zonal Deliverability in New England
• Addressed Interconnection Queue processing issues that have
been observed across the industry and discussed at FERC
42
Intra-Zonal Deliverability
• In its November 8, 2004 Order, FERC accepted the Minimum
Interconnection Standard on the basis that it:
– “…offers interconnection customers market benefits that are equivalent
to Network Resource Interconnection Service while requiring minimal
upgrade obligations more similar to those required by Energy Resource
Interconnection Service.”
• FERC, however, stated that it may not be just and reasonable
– “…for a generator in one location to sell its capacity as an ICAP resource
to, and receive ICAP payments from, a load in another location if the
generator's output is not deliverable to the load that buys the ICAP
capacity.”
• Accordingly, FERC required the ISO to file "a mechanism that will
ensure generators meet an intra-zonal deliverability test in order to
qualify as an ICAP resource”
ICAP – Installed Capacity
43
Interconnection Processes – Issues at the
National Level
• FERC acknowledged the existence of challenges to the Large
Generator Interconnection Procedure (LGIP) and held a
technical conference on December 11, 2007 in Docket No.
AD08-02-000
• FERC found in the Order on the Technical Conference on
Interconnection Queuing Procedures
– “…it may be appropriate to increase the requirements for getting and
keeping a queue position”
– “… there may be merit in a first-ready, first-served approach, whereby
customers who demonstrate the ability to move forward with project
development are processed first”
44
Observations on the Outcomes of FCM-Q
• Capacity Network Resource Interconnection Service achieved
through successful participation in the FCM
• Integrating the Interconnection Queue with the FCM is a very
complex undertaking for both the ISO and participants
– There is more emphasis than ever on processing queue positions as
quickly as possible
– Implementing a third type of generator interconnection service
(beyond the energy and capacity services) is not considered
achievable at this time
• The Minimum Interconnection Standard was renamed the
Network Capability Interconnection Standard
45
Enhanced Interconnection?
• Not currently under consideration
– ETU process can address various objectives
• Such a change may or may not be counter to the efforts to process
requests as quickly as possible
– Would the enhanced interconnection be optional addition to a request for
Network Resource Interconnection Service?
• Looks like a Network Resource Interconnection Service request & request for an
Elective Transmission Upgrade
• What would be studied in the following queue position?
– Could it be a third type of interconnection service, subject to material
modification restrictions?
– Would need the same discipline as the current process to be effective
• No physical or priority rights in the security constrained economic dispatch
construct
– There is no means to convey enhanced interconnection service, per se
– Incremental Auction Revenue Rights (IARRs) & Capacity Transfer Rights (CTRs)
could be pursued
46
Elective Transmission Upgrades
• The fully developed ETU process will allow for the expansion
of the system by means of a comprehensive interconnection
process, on par with new generation
– Note that there will still be no way to secure a physical or priority right
over such upgrades
47
AGENDA ITEM 5:
MODIFICATIONS TO ATTACHMENT A AND B
(INTERCONNECTION STUDY REQUEST DATA),
INTERCONNECTION AGREEMENT
Standard Wind Farm Data Set
• A standard wind farm data set has been drafted and has been
used in the collection of data from some existing wind farms
49
AGENDA ITEM 6:
MATERIAL MODIFICATION MANUAL
Purpose
• Present procedural rules for administering Material
Modification determinations for Large Generating Facilities
• Briefly describe some of the technical analysis that is part of
the Material Modification process
51
Background
• In response to customer requests and to address the backlog
in its generator interconnection queue, ISO has reviewed how
it administers the process of making a Material Modification
determination
• ISO is implementing procedural rules to add more structure to
the process that should expedite the studies of projects in the
queue and provides notification to customers on key times to
update the technical data for their project
52
Background, cont.
• Interconnection Customers request changes to their existing or
proposed generating facilities for a wide variety of reasons
• These changes can have no impact, can have a large impact on the
studies of other proposed projects or can have a significant impact
on the reliability of the New England’s transmission system
• Proposed changes that may cause a large/significant impact are said
be Material Modifications and require submission of an
Interconnection Request and a new queue position
– Same type of change that requires review pursuant to Section I.3.9
• ISO’s Tariff provides a definition of Material Modification in
Schedule 22 and provides further information on modifications in
Section 4 of the LGIP and Article 5.19 of the LGIA
53
Material Modification Timelines
•
Different thresholds for determining Material Modification depend on the
stage of the project
– After an Interconnection Request is received and before a Feasibility Study
–
–
–
–
Agreement is executed
After the Feasibility Study Agreement is executed and before the Feasibility
Study is completed
After the Feasibility Study is completed and before a System Impact Study
Agreement is executed
After the System Impact Study Agreement is executed and before the System
Impact Study is completed
After the System Impact Study, including evaluation of “as purchased data,”
“as built/as tested data” and changes to existing facilities (e.g., equipment
upgrade, replacement of failed equipment)
•
“As purchased data” is required to be submitted no later than 180 Calendar
Days prior to the Initial Synchronization Date and should be reviewed prior to
the project being allowed to be synchronized to the New England system
•
“As built/as tested” is required to be submitted prior to the Commercial
Operations Date and should be reviewed prior to the project being allowed to
become Commercial
54
Determining Materiality After an Interconnection
Request is Received and Before a Feasibility Study
Agreement is Executed
• The following will be deemed material and require a new
Interconnection
– Any increase to the energy capability or capacity capability output of a
Generating Facility above that specified in an Interconnection
– A change from NR Interconnection Service to Capacity Network
Resource (CNR) Interconnection
– An extension of three or more cumulative years in the Commercial
Operation Date, In-Service Date or Initial Synchronization Date of the
Large Generating Facility unless provisions of Section 4.4.5 of the LGIP
are satisfied
55
Determining Materiality After an Interconnection
Request is Received and Before a Feasibility Study
Agreement is Executed, cont.
• The following will not be deemed material
– Extensions of less than three (3) cumulative years in the Commercial
Operation Date, In-Service Date or Initial Synchronization Date of the
Large Generating Facility to which the Interconnection Request relates
provided that the extension(s) do not exceed seven (7) years from the
date the Interconnection Request was received by the System Operator
– A decrease of electrical output (MW) of the proposed project
– Modification of the technical parameters associated with the Large
Generating Facility technology
– Modification of the Large Generating Facility step-up transformer
impedance characteristics
– Modification of the interconnection configuration
– Modification of the POI based on information from the Scoping Meeting
and identified within five (5) business days of the Scoping Meeting
56
Changes After the Feasibility Study Agreement
is Executed
• When the Feasibility Study is expected to begin more than 60 days
after the Feasibility Study Agreement is executed, ISO-NE will notify
the Interconnection Customer 30 days before the study begins and
allow the Interconnection Customer 30 days to refresh its data to
the degree allowed under the same materiality standards for
changes prior to execution of the Feasibility Agreement
• Once the Feasibility Study has started, it will be completed without
making any changes except those based on study results that were
not anticipated at the Scoping Meeting and are agreed to by the
System Operator and the Interconnecting Transmission Owner.
Other changes will be addressed in the System Impact Study.
57
Determining Materiality During the Feasibility
Study
• The following will be deemed material and require a new
Interconnection
– Any increase to the energy capability or capacity capability output of a
Generating Facility above that specified in an Interconnection
– A change from NR Interconnection Service to CNR Interconnection
– An extension of three or more cumulative years in the Commercial
Operation Date, In-Service Date or Initial Synchronization Date of the
Large Generating Facility unless provisions of Section 4.4.5 of the LGIP
are satisfied
– Modification of the POI that is not based on unanticipated study
results
– Modification of settings of the project’s controls, such as wind farm
voltage control scheme that is not based on unanticipated study
results
58
Determining Materiality During the Feasibility
Study, cont.
• The following will not be deemed material and require a new
Interconnection
– Extensions of less than three (3) cumulative years in the Commercial
Operation Date, In-Service Date or Initial Synchronization Date of the
Large Generating Facility to which the Interconnection Request relates
provided that the extension(s) do not exceed seven (7) years from the
date the Interconnection Request was received by the System
Operator
– A decrease of up to 60 percent of electrical output (MW) of the
proposed project
– Modification of the technical parameters associated with the Large
Generating Facility technology
– Modification of the Large Generating Facility step-up transformer
impedance characteristics
59
Determining Materiality during the Feasibility
Study, cont.
• The following will not be deemed material and require a new
Interconnection
– Modification of the interconnection configuration
– Modification of the POI based on study results that were not
anticipated at the Scoping Meeting and are agreed to by the System
Operator and the Interconnecting Transmission Owner
– Modification of settings of the project’s controls, such as wind farm
voltage control scheme based on study results that were not
anticipated at the Scoping Meeting and are agreed to by the System
Operator and the Interconnecting Transmission Owner
60
Changes After the System Impact Study
Agreement is Executed
•
When a Feasibility Study was completed and the System Impact Study is expected to
begin until more than 60 days after the System Impact Study Agreement is executed,
ISO-NE will notify the Interconnection Customer 30 days before the study begins and
allow the Interconnection Customer 30 days to refresh its data to the degree allowed
under the same materiality standards for changes prior to execution of the System
Impact Agreement
•
When the Feasibility Study will be part of the System Impact Study and the System
Impact Study is expected to begin more than 60 days after the System Impact Study
Agreement is executed, ISO-NE will notify the Interconnection Customer 30 days before
the study begins and allow the Interconnection Customer 30 days to refresh its data to
the degree allowed under the same materiality standards for changes prior to execution
of the System Impact Agreement
•
Once the System Impact Study Study has started, it will be completed without making
any changes except those based on study results that were not anticipated and are
agreed to by the System Operator and the Interconnecting Transmission. Other changes
will be addressed as changes made after the System Impact Study is complete.
61
Determining Materiality During the System
Impact Study
• The following will be deemed material and require a new
Interconnection
– Any increase the energy capability or capacity capability output of a
Generating Facility above that specified in an Interconnection
– A change from NR Interconnection Service to CNR Interconnection
– An extension of three or more cumulative years in the Commercial
Operation Date, In-Service Date or Initial Synchronization Date of the
Large Generating Facility unless provisions of Section 4.4.5 of the LGIP
are satisfied
– Modification of the POI and/or interconnection configuration that is
not based on unanticipated study results
62
Determining Materiality During the System
Impact Study, cont.
• The following may be deemed material and will require
review after the System Impact Study is completed using the
post System Impact Study criteria
– A decrease of the electrical output (MW) of the proposed project
– Modification of the technical parameters associated with the Large
Generating Facility technology
– Modification of the Large Generating Facility step-up transformer
impedance characteristics
63
Determining Materiality During the System
Impact Study, cont.
• The following will not be deemed material and require a new
Interconnection
– Extensions of less than three (3) cumulative years in the Commercial
Operation Date, In-Service Date or Initial Synchronization Date of the
Large Generating Facility to which the Interconnection Request relates
provided that the extension(s) do not exceed seven (7) years from the
date the Interconnection Request was received by the System
Operator
– Modification of the POI and/or the interconnection configuration
based on study results that were not anticipated and are agreed to by
the System Operator and the Interconnecting Transmission Owner
64
Changes After the System Impact Study is Completed
• A proposed project that has a completed System Impact
Study, or an existing generating facility can request that a
proposed change be evaluated to determine if the change is a
Material Modification. If this happens, the proposed change
will be evaluated using a technical screening criteria.
However, there may be proposed changes that have not been
contemplated and might require additional analysis beyond
the normal screening criteria.
• Examples of the technical screening criteria follow
65
Screening Criteria for Changes in MW Output
• The following will be deemed material and will require a new
Interconnection Request
– Any increase to the energy capability or capacity capability output of a
Generating Facility above that specified in an Interconnection Request
– A restudy is needed to re-determine the allocation of system upgrade
costs
• The following will not be deemed material and will not
require a new Interconnection Request
– The decrease does not change upgrade requirements
– The decrease clearly does not require restudy of the project under
consideration or projects with a higher queue position (later in the
queue)
66
Screening Criteria for Changes in Voltage
Control Schemes
• The following will be deemed material and require a new
Interconnection
– A restudy is needed to determine if the change has a significant
impact on the reliability of the transmission system
– A restudy is needed to re-determine the allocation of system
upgrade costs
• The following will not be deemed material and require a
new Interconnection
– There is no voltage problem that may be affected by the change to
the project that is found in any base cases for the most severe N-1
and N-1-1 contingencies and modification
– The new models provide similar or better dynamic voltage
performance based on dynamic simulation of a few severe faults
67
Screening Criteria for Changes in
Interconnection Facility Impedances
• A project’s impedance can change as a result of a change to a
generator step-up transformer, a wind project interconnection
transformer, a wind project collector system, generator leads
or any other Interconnection Facilities
• A project impedance change might have an impact on short
circuit levels, voltage or stability
68
Screening Criteria for Short Circuit Impacts of
Changes in Interconnection Facility Impedances
• The following will be deemed material and require a new
Interconnection
– A complete a short circuit study is needed to determine if the
proposed change causes breaker duties to be exceeded
– A restudy is needed to re-determine the allocation of system upgrade
costs
• The following will not be deemed material and require a new
Interconnection
– The total impedance is greater than that of the existing unit(s) and X/R
ratio is less than or equal to that of the existing unit(s)
– A short circuit study at only the interconnecting bus confirms that
short circuit duty is less than or equal to that of the existing unit(s)
69
Screening Criteria for Stability Impacts of
Changes in Interconnection Facility Impedances
• The following will be deemed material and require a new
Interconnection
– A complete stability study is needed to determine if the proposed
change has a significant impact on the reliability of the transmission
system
– A restudy is needed to re-determine the allocation of system upgrade
costs
• The following will not be deemed material and require a new
Interconnection
– The new models provide similar or better dynamic performance
(better damping, smaller angular swing) based on dynamic simulation
of a few severe faults
70
Screening Criteria for Voltage Impacts of
Changes in Interconnection Facility Impedances
• The following will be deemed material and require a new
Interconnection
– A complete power flow study is needed to determine if the proposed
change has a significant impact on the reliability of the transmission
system
– A restudy is needed to re-determine the allocation of system upgrade
costs
• The following will not be deemed material and require a new
Interconnection
– The change of impedance is small (less than 10% of the impedance
used in the SIS) and there is no pre-existing voltage problem
71
AGENDA ITEM 7:
DETAILED VOLTAGE STUDIES WITHIN WIND
FARM DRIVING USE OF DETAILED MODELS
And continuation of Agenda Item 2:
What project developers can do to minimize their electrical
distance or mitigate these voltage limitations
Detailed Representation of the Wind Farm
• System Impact Studies have required full modeling of the
wind farm in steady state analysis
– Single-turbine equivalents are used in stability analysis
73
Purpose of the Detailed Steady State Review
• Identify tap settings for the unit step-up transformers and the
station step-up transformers
– Tap settings correspond to the most reasonable voltage conditions on
the collector system and the turbine terminals for a range of different
voltage conditions at the POI
• The detailed representation provides direction to the tap
settings to be used in the equivalent models used in stability
analysis
74
Could Developers Perform the In-Farm Review?
• YES! And they should!
• ISO can provide the standard methodology used in the
detailed review for determining initial tap settings
• There may be some remaining concern whether or not the
review has to be revisited as a result of later study findings;
however, efforts will be made to minimize this likelihood
75
Examples of Reactive Upgrades
• Wind Turbine Generators (Type III and Type IV)
– Very limited transient reactive support to the system
• Shunt Compensation
• Static VAR Compensator (SVC)
• STATCOM (DVAR)
• Synchronous Condenser
• Series Capacitors
76
Reactive Power Study Tools
•
SIL and VAR Losses
– Overview of the VAR burden introduced by the interconnection
•
PV Analysis
–
–
–
–
•
Voltage feasibility pretest
Worst scenario and contingency screening
Critical voltage location (bus) searching
Understand the voltage profile in the facility and the region
QV Analysis
– Evaluate reactive margin and high/low voltage potential
– Evaluate the amount and type of reactive compensation needed
•
SCR
– Evaluate potential issue and recommend focus of study
77
Wind Farm Reactive Power Control
• Reactive Power Priority
– Firstly, ensure the WTGs’ continuous operation, proper terminal
voltages
– Then, make the most of the reactive resource for system operation
• Reactive Power Control
– Employ voltage control at the POI if, while doing so, the WTGs can
ensure their terminal voltages
– If WTGs couldn’t ensure their terminal voltages, terminal voltage study
should be carefully conducted to achieve voltage control at POI,
especially for the following conditions:
• Weak system (low SCR), pre-existing system voltage issues, significant VAR
burden introduced by the interconnection, long impedance collector
system
78
Wind Farm Reactive Power Control, cont.
• Possible Solution for Unacceptable Terminal Voltages
– Steady State WTG Terminal Voltages
• Power factor control at POI or voltage control at low voltage side of POI
• Shunts and dynamic devices for POI voltage regulation
• Apply Load Tap Changing (LTC) at the main transformer to accommodate
high side voltage change
• Dynamic Oscillation Mitigation
– Adjust to lower LVRT activation and higher LVRT release voltage
settings
– Tune post fault Q and P recovery control to stabilize terminal voltage
– Apply SVC/STATCOM/Synchronous Condenser/Series Capacitor
– For steady-state voltage solution manipulating shunts and LTC listed
above, detailed model may be needed in dynamic study
79
Wind Farm Reactive Power Control, cont.
• Reactive Power Coordination
– A master controller, communication of all reactive resources
– WTGs control terminal voltage and compensate internal VAR losses
first
– Shunts regulate the POI voltage, compensate external VAR losses, free
up dynamic reactive power from SVC/STATCOM/SC, etc.
– Avoid VAR circulation among resources
• Desired future coordination functions
– Terminal voltage monitoring and voltage violation controlling
– Optimization of individual WTG VAR dispatch
– More accurate internal and external network model at the master
controller
– Coordination among different wind farm and other facilities
80
AGENDA ITEM 8:
SHOULD ISO OPERATING CRITERIA OF ZERO
TURBINE TRIPS AFTER NORMAL
CONTINGENCIES BE RELAXED?
Discussion
AGENDA ITEM 9:
ELECTRONIC DATA SUBMITTAL SYSTEM
Discussion
AGENDA ITEM 10:
COMMUNICATIONS
Discussion
AGENDA ITEM 11:
NEW NERC REPORTING REQUIREMENTS
Discussion
85
APPENDIX I: CONSTRAINTS THAT HAVE BEEN
RELEVANT TO WIND INTERCONNECTION
Potential Regional Transmission Constraints
Constraints with all facilities in
service
Constraints with a facility out
of service (OOS)
• New Brunswick-New England
• Orrington Import
• Orrington-South
• Maine Yankee South
• Surowiec-South
• Maine-New Hampshire
• New Hampshire-Maine
• NNE-Scobie/394
• North-South
• Orrington-North
• New England-New Brunswick
• New England-New Brunswick +
Keene Road Export
87
Geographical Map – Regional and Local
Constraints in ME
88
Geographical Map – Local Constraints in VT and NH
89
Regional Constraints: Orrington South Interface
• Orrington South
– All lines in-service limit is
1,050 MW – 1,200 MW
– Single facility out limits
exist
– Limits due to thermal,
voltage and stability
performance
• 200 MW – 1,200 MW
– Resources behind
constraint
• Existing: ~ 2,120 MW
• Proposed: ~ 510 MW
90
Regional Constraints: Surowiec South Interface
• Surowiec South
– All lines in-service limit is
1,150 MW
– Single facility out limits exist
– Limits due to stability
performance (damping, unit
stability and post-fault
voltage recovery)
• 300 MW – 1,150 MW
– Resources behind constraint
• Existing: ~ 3,480 MW
• Proposed: ~ 1,160 MW
91
Regional Constraints: Orrington Import
Interface
• Orrington Import
– All lines in-service limits do
not exist
– Single facility out limits exist
– Limits due to stability
performance (post fault
voltage recovery, inter-area
instability)
• 250 MW – 1,250 MW
– Resources behind constraint
• Existing: ~ 1,320 MW
• Proposed: ~ 240 MW
92
Local Transmission Constraints
Constraints with all facilities
in service
• Maine
– Keene Road Export
• New Hampshire
– Whitefield South
• Vermont
– Sheffield/Highgate Export
Constraints with a facility
out of service (OOS)
• Maine
–
–
–
–
–
–
Wyman Hydro Export
Inner Rumford
Outer Rumford
Keene Road + BHE Export
Western ME Export
BHE Export
93
Local Constraints: Maine, Wyman Hydro Export
Interface
• Wyman Hydro Export
– All lines in-service limits do not
currently exist
– Single facility out limits exist
• Based upon two 115 kV lines
remaining after limiting
contingency
– Limits due to stability
performance (damping)
• 200 MW – 290 MW
– Resources behind constraint
• Existing: ~ 360 MW
• Proposed : ~ 215 MW
– Area peak load approx. 15 MW
94
Local Constraints: Maine, Inner Rumford Export
Interface
• Inner Rumford Export
– All lines in-service limits do
not currently exist
– Single facility out limits
exist
– Limits due to stability
performance (damping,
unit stability and post-fault
voltage recovery)
• 75 MW – 215 MW
– Resources behind
constraint
• Existing: ~460 MW
• Proposed: ~ 255 MW
– 160 MW (incl. gross mill
loads)
95
Local Constraints: Maine, Outer Rumford
Export Interface
• Outer Rumford Export
– All lines in-service limits do
not exist
– Single facility out limits exist
– Limits due to stability
performance (damping, unit
stability and post-fault
voltage recovery)
• 75 MW – 215 MW
– Resources behind constraint
• Existing: ~645 MW
• Proposed: ~ 255 MW
– 290 MW (incl. gross mill
loads)
96
Local Constraints: Maine, Western Maine
Export Interface
• Western Maine Export
– All lines in-service limits do
not exist
– Single facility out limits exist
– Limits due to stability
performance (damping)
• 300 MW – 500 MW
– Resources behind constraint
• Existing: ~1050 MW
• Proposed: ~ 470 MW
– 420 MW (incl. gross mill
loads)
97
Local Constraints: Maine, Keene Road Export
Interface
• Keene Road Export
– All lines in-service limit
• 155 MW
– Limits due to stability (postfault voltage recovery)
– Facility out limits
• 0 MW – 120 MW
– Resources behind
constraint
• Existing: ~320 MW
• Proposed: ~ 90 MW
– Area peak load approx.
30 MW
98
Local Constraints: Maine, Bangor Hydro Export
Interface
• Bangor Hydro Export
– All lines in-service limits do
not exist
– Single facility out limits exist
– Limits due to stability
performance (damping,
instability)
• 200 MW – 440 MW
– Resources behind constraint
• Existing: ~940 MW
• Proposed: ~270 MW
– Area peak load approx.
270 MW
99
Local Constraints: Maine, Bangor Hydro +
Keene Road Export Interface
• Bangor Hydro + Keene Road
Export
– All lines in-service limits do
not exist
– Single facility out limits exist
– Limits due to stability
performance (damping,
instability)
• 200 MW – 580 MW
– Resources behind constraint
• Existing: ~1,250 MW
• Proposed: ~ 360 MW
– Area peak load approx.
300 MW
100
Local Constraints: New Hampshire, Whitefield
South
• Whitefield South
– All lines in-service limits do exist
• Approximately 150 MW
– Single facility out limits exist and are
lower
– Limits are based upon steady state
voltage and stability performance
(damping and angular stability)
– Resources behind constraint
• Existing: 160 MW
• Proposed: ~70 MW
– Area peak load approx. 60 MW
101
Local Constraints: Vermont, Sheffield/Highgate
Export
• Sheffield/Highgate Export
– All lines in-service limits do exist
• Approximately 250 MW
– Single facility out limits exist and are
lower
– Limits are based upon postcontingent, steady state voltage
performance
– Resources behind constraint
• Existing: 420 MW (including
Highgate)
• Proposed: ~60 MW
– Area peak load approx. 120 MW
102
APPENDIX II: TYPES OF REACTIVE
RESOURCES
Types of Reactive Resources
•
Wind Turbine Generators (Type III and Type IV)
– Efficient for terminal voltage control
– Good for voltage regulation(need to ensure terminal voltage)
– Very limited transient reactive support to the system
•
Shunt Compensation
– Inexpensive, frees up spinning reactive reserve
– However, if system is heavily shunt capacitor compensated, voltage
regulation tends to be poor
– Beyond a certain level, stable operation is unattainable when shunts
are used
– Can be inoperable for intermittent resources due to quickly changing
output conditions and infeasible from a equipment standpoint due to
frequent switching operations
104
Types of Reactive Resources, cont.
•
Static VAR Compensator
– Thyristor Controlled Reactor(s) (TCR), filters and Thyristor
Switched Capacitors (TSC) or Breaker Switched Capacitors (BSC)
– Reduce voltage fluctuation and Shunt Switching
– Support transient voltage and damp system swings
– When voltage is low, reactive compensation reduces
•
STATCOM(DVAR)
– Voltage Sourced Converters (VSC) used solely for reactive power
– Similar performance to SVC but faster, better transient support
– Provide full compensation at low voltage
105
Types of Reactive Resources, cont.
• Synchronous Condenser
– Increase short circuit ratio
– Good for voltage regulation and transient voltage support
• Series Capacitor
– Increase the stability limits by reducing effective impedance
– Produce more compensation in low-voltage condition and less VAR in
high-voltage condition
– Reduce voltage fluctuation and increase effective short circuit capacity
– Significant study effort required to ensure no adverse impact due to
Sub-Synchronous Resonance or other interactions
106