FINAL REPORT
QP 311 – Kingdom Community Wind Project
Interconnection Feasibility Study
July, 2010
Prepared by:
QP 311 Feasibility Study
Final Report
i
Contains Critical Energy Infrastructure Information
For ISO New England and Vermont Electric Power Company
July 19, 2010
Table of Contents
Executive Summary ....................................................................................................................... iv
1
Background ............................................................................................................................. 1
1.1
Study Objective............................................................................................................... 1
1.2
Project Description.......................................................................................................... 1
1.3
Technical Specifications ................................................................................................. 3
1.3.1
Project Generator Modeling Data ........................................................................... 3
1.3.2
Project Transformer Modeling Data ....................................................................... 4
1.3.3
Project Transmission Line Modeling Data ............................................................. 4
2
Study Area .............................................................................................................................. 6
2.1
Transmission System ...................................................................................................... 6
3
Base Case Development ......................................................................................................... 7
3.1
Base Case Origin and Year ............................................................................................. 7
3.2
Area Load........................................................................................................................ 7
3.3
Planned Projects.............................................................................................................. 7
3.4
Base Case Naming Convention ...................................................................................... 7
3.5
Voltage Operational Analysis ......................................................................................... 8
3.6
Analytical Tools.............................................................................................................. 9
4
Steady State Analysis Methodology ....................................................................................... 9
4.1
Steady State Voltage Limits............................................................................................ 9
4.2
Steady State Thermal Limits........................................................................................... 9
4.3
Steady State Base Case Dispatch and Interface Conditions ......................................... 10
4.4
Steady State Contingency List ...................................................................................... 11
5
Steady State Analysis Results............................................................................................... 12
5.1
Baseline System ............................................................................................................ 12
5.1.1
Voltage Performance ............................................................................................ 12
5.1.2
Thermal Performance............................................................................................ 13
5.2
QP 311 In-Service......................................................................................................... 14
5.2.1
Voltage Performance ............................................................................................ 16
5.2.2
Thermal Performance............................................................................................ 17
6
Short Circuit Analysis........................................................................................................... 18
7
Delta V on Capacitor Switching ........................................................................................... 19
8
Cost Estimates for Required Network Upgrades .................................................................. 19
9
Conclusion ............................................................................................................................ 20
Appendices
Appendix A - Project Information ................................................................................................. A
Appendix B - Study Methodology..................................................................................................B
Appendix C - Preliminary One-Line Diagram................................................................................C
Appendix D - Steady State Contingency List ................................................................................ D
Appendix E - Steady State Base Case Summaries.......................................................................... E
Appendix F - Steady State Base Case Draw Files .......................................................................... F
Appendix G - Steady State Contingency Voltage Results............................................................. G
Appendix H - Steady State Contingency Thermal Results............................................................ H
QP 311 Feasibility Study
Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
List of Tables
Table 1-1 QP 311 Generator Modeling Data.................................................................................. 4
Table 1-2 QP 311 Transformer Modeling Data.............................................................................. 4
Table 1-3 QP 311 Transmission Line Modeling Data .................................................................... 4
Table 1-4 QP 311 Collector String Modeling Data ........................................................................ 5
Table 4-1 Steady State Voltage Criteria ......................................................................................... 9
Table 4-2 Steady State Thermal Criteria ...................................................................................... 10
Table 4-3 Local Area Dispatches.................................................................................................. 11
Table 5-1 Peak Load Contingencies Resulting in Voltage Violations Pre-Project ...................... 13
Table 5-2 Losses Due to Addition of Q311 Project...................................................................... 14
Table 5-3 Newport Area Pre Contingency Voltages .................................................................... 15
Table 5-4 Additional Capacitors for K42 Contingency................................................................ 15
Table 5-5 Reactive Compensation Proposed for the Project ........................................................ 16
Table 5-6 Post Contingency Capacitor Switching at Jay Tap Switching SS................................ 16
Table 6-1 Kingdom Community Wind Short-circuit Fault Duties .............................................. 19
List of Figures
Figure 1-1 Pre Project Simplified One Line Diagram .................................................................... 2
Figure 1-2 Post-Project Simplified One Line Diagram .................................................................. 3
Figure 2-1 Project Geographical Map............................................................................................. 6
Figure 3-1 Steady State Base Case Naming Convention................................................................ 8
QP 311 Feasibility Study
Final Report
July 19, 2010
iii
Contains Critical Energy Infrastructure Information
Executive Summary
RLC Engineering, LLC (RLC) conducted a Feasibility Study (the “Study”) under the ISO New
England Inc. (ISO) Open Access Transmission Tariff (“Tariff”) Schedule 22-Standard Large
Generator Interconnection Procedures (“LGIP”). The Study was performed on behalf of ISO
New England Inc. (ISO) and Vermont Electric Power Company (VELCO) for the
Interconnecting Customer at Queue Position 311 (QP 311) to construct a 63 MW Wind Farm
Project (the “Project”) located in Lowell, Vermont in Orleans County. The wind farm is
proposed to consist of twenty-one 3.0 MW Vestas V90 wind turbines connecting into the new
Vermont Electric Cooperative (VEC) 46 kV Lowell Substation. The Project has a proposed inservice date of October 2012.
Based on a prior study conducted by VELCO and VEC, the following changes are proposed to
occur prior to the Project in-service date:
o Construct Jay Tap Switching Station 4 miles west of the North Troy Substation on the
existing 46 kV transmission line (the VT Public Service Board (PSB) has opened Docket
7604 to review VEC’s Jay Tap Switching Station construction permit application)
o Install five 46 kV breakers at Jay Tap Switching Station
o Install four 2.7 MVAr shunt capacitors at Jay Tap Switching Station
The primary objective of this Study was to determine if interconnecting QP 311 (the Project)
would have significant adverse impact on the reliability and operating characteristics of the
VELCO or VEC transmission systems, the transmission facilities of another Transmission
Owner, or the system of a Market Participant. Steady state conditions and short circuit testing
were analyzed in this Study.
The purpose of the Study was to:
(i)
Analyze the steady-state and short circuit impact of the Project
(ii)
Determine any upgrades to the transmission system that would be required to
mitigate any adverse impacts that the Project could otherwise pose on the
reliability and operating characteristics of the New England transmission system
(iii) Determine any upgrades required to mitigate any degradation to transmission
transfer capability
Project Description
To accommodate the interconnection of the Project, a portion of the existing 34.5 kV
transmission system around Lowell will need to be upgraded to 46 kV and a new 46 kV line will
need to be constructed to interconnect with the VELCO 115 kV transmission system. The
following is an overview of the facilities required for the interconnection of the Project:
QP 311 Feasibility Study
Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
•
•
•
•
•
•
•
•
•
•
•
Install a new 115/46 kV autotransformer on the K41 Line between Highgate and Moshers
Tap to connect to the Jay Tap 46 kV Substation
Install one 46 kV breaker between the Jay Tap Switching Station bus and the 46kV
terminal of the autotransformer
Upgrade 2 miles of existing 46 kV transmission line from Jay Tap Switching Substation
to a tap point (Crossroad) to 795 kcmil ACSR and add three 46 kV Switches at Crossroad
tap point
Construct 2 miles of new 46 kV transmission line from Crossroad tap point to the Jay 17
Substation with 795 kcmil ACSR
Upgrade the 34.5 kV Jay 17 Substation to 46 kV and install a 46/12.47 kV transformer at
Jay 17 Substation
Upgrade 10.4 miles of transmission line (to 795 kcmil ACSR) from Jay 17 Substation to
VEC Lowell Substation
Construct a VEC Lowell 46 kV Substation and install three 46 kV breakers and add a
46/12.47 kV transformer
Construct 5.4 miles of new 46 kV transmission line (795 kcmil ACSR) connecting QP
311 Substation to VEC Lowell 46 kV Substation
Construct a 46/34.5 kV substation in Lowell, Vermont (QP 311 Substation)
Install twenty-one 3.0 MW Vestas V90 wind turbines equipped with their own dedicated
1000 V/34.5 kV GSU
Construct two 34.5kV collector strings connecting the wind turbines with each tying into
the QP 311 Substation at 34.5 kV
See Section 1.2 for a complete discussion of interconnection details.
Steady State
Steady state voltage and thermal analyses examined system performance without the proposed
Project in order to establish a baseline for comparison. System performance was re-evaluated
with the Project and compared with the previous baseline performance to demonstrate the impact
of the Project on area transmission reliability under the guidelines of the Network Capability
Interconnection Standard (NCIS). Several redispatch conditions under the NCIS were evaluated
at each load and transmission operating configuration.
Steady state analysis was evaluated at a summer 2013 peak load level of 31,470 MW and at a
summer 2013 shoulder load level of 22,024 MW for ISO New England. The shoulder load (D1)
dispatch represented the block load being supplied from Hydro Quebec (HQ) and the Highgate
HVDC converter at full output to stress the area in an exporting condition. The peak load (D2)
dispatch represented the block load being supplied from Vermont and the Highgate HVDC
converter out of service to stress the area in an importing condition. Additional sensitivity
dispatches were performed at peak load with the Highgate HVDC converter on and the block
load supplied from either Vermont or HQ. The objective of modeling these various dispatch
scenarios was to examine the proposed Project and the ability of the transmission system to
reliably serve customer demand under various stressed system conditions.
QP 311 Feasibility Study
Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
Based upon the steady state results, the Project as originally proposed posed an adverse impact
on the reliability and operating characteristics of the transmission system, and would require
transmission system upgrades. For many single element contingencies (K28, K38, K42 and
K60) voltage violations of reliability criteria were associated with the Project due to heavy
reactive power losses on the 46 kV transmission system and the post-Project transmission
configuration. With reactive losses exceeding 20 MVAr along the 46 kV transmission corridor
connecting the project to the Jay Tap Switching Station and over 20 MVAr of reactive losses
within the Project facilities, the Project generators alone were incapable of providing the reactive
support needed to sustain acceptable voltage criteria. Also, the post-Project transmission
configuration has the 12W Switch open at N. Troy which removes the reactive support of the Jay
Tap Switching Substation shunt capacitors to the Newport area which is deficient in reactive
resources when the block load is served by Vermont.
Based upon the steady state results, for pre-Project and post-Project dispatches with the block
load on Vermont, contingencies involving the loss of the Irasburg 115/46 kV transformer (H39
transformer and K41 Line stuck breaker) resulted in cases diverging due to the loss of voltage
support for the Montgomery, Eden Corners and Johnson Substation areas. The reliability issues
associated with these contingencies were not addressed in this Feasibility Study.
Several system upgrades and project modifications were analyzed to provide necessary system
voltage support. The following upgrades and modifications are recommended to reliably
maintain system voltage criteria:
•
•
•
•
•
•
•
Add 4 MVAr dynamic reactive support at the Project’s 34 kV bus
The QP 311 46/34.5 kV transformer tapped winding must be modified to the 102.5%
tap
Increase the size of each of the four planned 2.7 MVAr shunt capacitor banks at the
Jay Tap Switching Substation to 5.4 MVAr for a total increase to the system of 10.8
MVAr
Provide automatic capacitor bank switching at Jay Tap to maintain reliable 46 kV
system voltage (or provide dynamic reactive power control)
The Jay Tap Switching Substation 115/46 kV transformer tapped winding must be set
to the 97.5% tap
Add a 5.4 MVAr cap at the Newport-B2 bus for area voltage support
Add a transfer trip scheme to trip the QP 311 units upon loss of 46 kV line or Jay Tap
Switching Station 115/46 kV transformer
When the Project is dispatched locally under stressed exporting conditions (maximum generation
and shoulder load), no thermal reliability issues exist which require mitigation. The 46kV
transmission lines between Irasburg and Central Vermont Public Service Company’s Johnson
Substation are at thermal capacity by generation in the area following contingencies of the K38
Line (Lyndonville-Sheffield 115kV Line). An additional sensitivity redispatch demonstrated
that lowering the Sheffield dispatch with the Project was effective to relieve the loading on the
underlying 46 kV transmission system.
QP 311 Feasibility Study
Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
Short Circuit
Short circuit analysis was performed to determine the fault current levels on the new 46kV
transmission system proposed for the Project. The maximum fault duty was approximately
4400A for a three phase to ground fault and 4900A for a single phase to ground fault at the Jay
Tap 46kV S/S with the Project in-service. These fault duties are low and should be considered in
the engineering design studies for the transmission system upgrades required for the Project.
Cost Estimate
VEC provided a cost estimate of approximately $1,184k to construct the necessary required
network upgrades. The cost projections are based on “installed costs” and do not include the
cost for environmental assessment, permitting or temporary facilities required for outage
protection. VEC has communicated that subject to receipt of timely regulatory approval, the
upgrades can be implemented in time to fit the planned commercial operations schedule for the
Project.
With the addition of the upgrades listed above to the Project as currently defined, the Project
poses no significant adverse impact on the reliability and operating characteristics of the VELCO
or VEC transmission systems, the transmission facilities of another Transmission Owner, or the
system of a Market Participant.
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Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
1
Background
1.1
Study Objective
The primary objective of this Study was to determine if interconnecting QP 311 (the Project)
would have significant adverse impact on the reliability and operating characteristics of the
VELCO or VEC transmission systems, the transmission facilities of another Transmission
Owner, or the system of a Market Participant. Steady state and short circuit conditions were
analyzed in this Study.
1.2
Project Description
The Project consists of the following proposed electrical components and construction activities:
• Split the K41 Line 12.57 miles from Mosher’s Tap end with a three-breaker ring bus and
install a new 115/46 kV autotransformer to connect the 46kV Jay Tap Switching Station
with the VELCO 115kV transmission system
• Install one 46 kV breaker between the Jay Tap Switching Station bus and the 46kV
terminal of the autotransformer
• Construct a 2 mile 46 kV 795 kcmil ACSR transmission line from the Jay 17 Substation
to a tap point (Crossroad) on the existing 46 kV transmission line 2 miles west of the
North Troy Substation
• Upgrade the existing 46 kV transmission line between Jay Tap Switching Substation and
the tap point (Crossroad) to 795 kcmil ACSR
• Install three 46 kV Switches at the Crossroad tap point
• Upgrade the 34.5 kV Jay 17 Substation to 46 kV and replace the 34.5/12.47 transformer
with a 46/12.47 kV transformer
• Construct a VEC Lowell 46 kV Substation
• Install three 46 kV breakers at VEC Lowell Substation
• Install a 46/12.47 kV transformer at VEC Lowell Substation
• Upgrade 10.4 miles of transmission line (to 795 kcmil ACSR) from VEC Lowell 46 kV
Substation to Jay 17 46kV Substation
• Construct a new 46/34.5 kV substation in Lowell, Vermont (QP 311 Substation)
• Install one 46 kV breaker at QP 311 Substation
• Install twenty-one 3.0 MW Vestas V90 wind turbines equipped with their own dedicated
1.0/34.5 kV GSU (actually 3-wdg but modeled as 2-wdg)
• Construct two collector strings connecting the wind turbines with each tying into the QP
311 Substation at 34.5 kV
• Construct 5.4 miles of 46 kV transmission line (795 kcmil ACSR) connecting QP 311
Substation to VEC Lowell 46 kV Substation
• Install a 34.5 kV breaker on each collector line at the QP311 substation
Post-Project, area support for the VEC Lowell Substation and Jay 17 Substation will shift from
the VELCO Irasburg # 42 Substation to the new 115/46 kV Jay Tap Substation. However, the
existing Montgomery, Eden Corners and Johnson Substations will remain supported out of the
VELCO Irasburg #42 Substation. A transmission line which connects the new VEC Lowell 46
kV Substation and existing 46 kV line to Irasburg # 42 Substation for emergency purposes
QP 311 Feasibility Study
Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
remained open for the entire Study. In addition, the North Troy substation will be separated
from the Jay Tap and Richford 46 kV substations.
Figure 1-1 below shows the area transmission configuration pre-Project. Figure 1-2 below
shows the transmission configuration post-Project. The Project will be modeled in detail as
shown in Appendix C. The Project has a proposed in-service date of October 2012.
To Highgate 115 kV
To Moshers Tap 115 kV
K41 Line
North Troy
Switch 14W
Open
Switch 118 closed
Jay Tap
Switching
Station 46 kV
Switch 12W
Closed
To Newport
Center
To E.
Berkshire
2 Miles
2 Miles
Switch 12E
Closed
To Jay
Substation #40
Richford
Jay 17
Substation 34.5 kV
2.7 MVAr
2.7 MVAr
2.7 MVAr
Xfmr
34.5/ 12.47 kV
7.5 MVA
2.7 MVAr
Pre Project
Configuration
VEC / Lowell 34.5 kV
Substation
Xfmr
34.5/12.47kV
To Lowell 12kV
To Montgomery / Eden
Corners / Johnson
Xfmr
46 / 34.5 kV
VELCO Irasburg
Substation #42
Figure 1-1 Pre Project Simplified One Line Diagram
QP 311 Feasibility Study
Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
To Highgate 115 kV
Moshers Tap 115 kV
K41 Line
Xfmr
115 / 46 kV
40 / 66.7 MVA
8.5 % Z
Project
North Troy
Switch 118 closed pre
and post Project
Jay Tap
Switching
Station 115 / 46 kV
Switch 14W
Open pre and
post Project
2 Miles
To E.
Berkshire
GSU
Switch KCW-E
Open
Switch 12W
Open Post Proj.
To Newport
Center
Crossroad
2 Miles
Switch 12E
Closed
34.5 / 1.0 kV
Richford
To Jay
(40)
Collector #1
M
G
2 Miles
Switch KCW-W
Closed
3.16 MVA*
Switch KCW-S
Closed
Jay 17
Substation 46 kV
2.7 MVAr
Eleven units each
consisting of 3 MW and
-0.875 to 0.609 MVAr*
2.7 MVAr
M
Kingdom 46 kV Bus
GSU
34.5 / 1.0 kV
10.4 Miles
2.7 MVAr
2.7 MVAr
Xfmr
46 / 12.47 kV
7.5 MVA
5.4 Miles
3.16 MVA*
Collector #2
Xfmr
46 / 34.5 kV
40 / 66.7 MVA
7.5 % Z
G
Ten units each consisting
of 3 MW and
-0.875 to 0.609 MVAr*
Queue 311
N.O.
Xfmr
46 / 12.47 kV
7.5 MVA
Xfmr
46 / 34.5 kV
7.5 MVA
Substation
* Twenty-one units and GSU’s to
be modeled in detail and not as an
aggregate. Reference Appendix C
for detai
VEC / Lowell 46 kV
Substation
To Montgomery / Eden
Corners / Johnson
To Lowell 12kV
VELCO Irasburg #42
Figure 1-2 Post-Project Simplified One Line Diagram
1.3
Technical Specifications
The following tables contain data as provided by the developer and ISO for the Project. The
installed maximum capability for the Project is 63 MW. Each of the twenty-one 3.0 MW Vestas
V90 wind turbines has its own 1.0/34.5 kV GSU and was modeled in detail as shown in
Appendix C.
1.3.1 Project Generator Modeling Data
The Vestas V90 wind turbine MVAr capability, as provided by the developer, has a power factor
range of 0.96 leading (consuming) to 0.98 lagging (generating). The generators were set to
operate in power factor control mode. The units were set to a fixed MVAr output that attempted
to maintain unity power factor at the point of interconnection (Kingdom 46 kV Bus) while
maintaining acceptable area voltages.
Table 1-1 below provides the generator operating characteristics.
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Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
QP 311 Generator Modeling Data
Type
MVA
PF range
MW
Vestas V90 wind
turbine
3.06
-0.96 to 0.98
3.0
MVAr Capability
Leading /
Lagging /
Consuming Generating
0.875
0.609
Table 1-1 QP 311 Generator Modeling Data
1.3.2 Project Transformer Modeling Data
Table 1-2 below summarizes the data required to model the Project transformers. The
interconnection and GSU transformers are fixed tap transformers with a range of +2 x 2.5%.
Transformer
GSU
Interconnection
Transformer at QP 311
Transformer at Jay
Tap Switching Station
Jay 17 SS
VEC Lowell SS
QP 311 Transformer Data
Nameplate Capacity
Tap Ratio Present Tap
(MVA)
34.5/1.0
Center
3.16
102.5%
46/34.5
40/53.3/66.7
R (pu)
X (pu)
0.0065
0.0948
0.0022
0.0750
40/53.3/66.7
0.0025
0.0850
46/12.47
Center
7.5/9.3
46/12.47
Center
7.5/9.3
Table 1-2 QP 311 Transformer Modeling Data
0.0050
0.0050
0.0700
0.0700
(High Side)
115/46
97.5%
(High Side)
1.3.3 Project Transmission Line Modeling Data
Table 1-3 and Table 1-4 summarize the modeling data for the transmission lines for the Project.
Transmission line ratings were determined using available reference data.
QP 311 Transmission Line Data
Length MVA
Transmission Line
Conductor
(Miles) Rating
QP 311 SS to Lowell SS
795 KCMIL ACSR
5.40
76
VEC Lowell SS to Jay 17 SS
795 KCMIL ACSR
10.40
76
Jay 17 SS to Crossroad tap point (pole
#155) on existing 46 kV line 2miles west 795 KCMIL ACSR
2.0
76
of North Troy SS
Crossroad tap point (pole #155) to Jay
795 KCMIL ACSR
2.0
76
Tap Switching SS
Table 1-3 QP 311 Transmission Line Modeling Data
QP 311 Feasibility Study
Final Report
R (pu)
X (pu)
0.0367 0.1598
0.0707 0.3078
0.0134 0.0602
0.0134 0.0602
July 19, 2010
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Contains Critical Energy Infrastructure Information
From
To
Gen 1
Gen 2
Gen 3
Gen 4
JB-1
Gen 5
JB-2
Gen 6
JB-3
Gen 7
Gen 8
Gen 8
Gen 9
Gen 10
JB-4
Coll Isol
Coll Tap
Gen 2
Gen 3
JB-1
JB-1
JB-2
JB-2
JB-3
JB-3
Coll Tap
JB-4
JB-4
Gen 9
Gen 10
Gen 11
Coll Isol
Coll Tap
KCW 34
From
To
Coll 2 Tap
Gen 12
Gen 13
Gen 14
Coll 2 Tap
JB3-3
JB3-3
JB3-2
JB3-2
JB3-1
JB3-1
Gen 19
Gen 20
Coll 2 Tap
Gen 12
Gen 13
Gen 14
Gen 15
JB3-3
Gen 16
JB3-2
Gen 17
JB3-1
Gen 18
Gen 19
Gen 20
Gen 21
KCW 34
QP 311 Collector 1 Data
Length
Conductor Type
(FT)
1/0 AWG
800
1/0 AWG
1000
1/0 AWG
1600
1/0 AWG
200
500 KCMIL
820
1/0 AWG
200
500 KCMIL
810
500 KCMIL
200
750 KCMIL
200
1/0 AWG
200
500 KCMIL
1200
1/0 AWG
800
1/0 AWG
810
1/0 AWG
950
500 KCMIL
300
795 KCMIL DRAKE
300
795 KCMIL DRAKE
5800
QP 311 Collector 2 Data
Length
Conductor Type
(FT)
500 KCMIL
500
1/0 AWG
900
1/0 AWG
850
1/0 AWG
820
500 KCMIL
3150
1/0 AWG
200
500 KCMIL
810
1/0 AWG
200
500 KCMIL
810
1/0 AWG
200
1/0 AWG
1000
1/0 AWG
850
1/0 AWG
825
795 KCMIL DRAKE
6800
MVA
R (pu)
X (pu)
10.0
10.0
10.0
10.0
23.4
10.0
23.4
23.4
28.4
10.0
23.4
10.0
10.0
10.0
23.4
70
70
0.0147
0.0184
0.0294
0.0037
0.0044
0.0037
0.0044
0.0011
0.0009
0.0037
0.0065
0.0147
0.0149
0.0175
0.0016
0.0007
0.0128
0.0065
0.0082
0.0130
0.0016
0.0048
0.0016
0.0048
0.0012
0.0010
0.0016
0.0071
0.0065
0.0066
0.0077
0.0018
0.0029
0.0562
MVA
R (pu)
X (pu)
23.4
10.0
10.0
10.0
23.4
10.0
23.4
10.0
23.4
10.0
10.0
10.0
10.0
70
0.0027
0.0166
0.0156
0.0151
0.0169
0.0037
0.0044
0.0037
0.0044
0.0037
0.0184
0.0156
0.0152
0.0151
0.0029
0.0073
0.0069
0.0067
0.0185
0.0016
0.0048
0.0016
0.0048
0.0016
0.0082
0.0069
0.0067
0.0658
Table 1-4 QP 311 Collector String Modeling Data
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Final Report
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Contains Critical Energy Infrastructure Information
2
Study Area
2.1
Transmission System
The primary area of concern for this study is the northwestern portion of VEC’s service territory
as shown in Figure 2-1 below. The sub transmission system in this area is heavily networked.
The Project interconnects into the sub transmission system near the North Troy 46 kV Substation
and also ties into the K41 115 kV transmission line between Highgate and Moshers tap. The
Project is connected by a radial 46 kV Line as shown above in Figure 1-2
Project
Interconnection
Project
Location
Figure 2-1 Project Geographical Map
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Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
3
Base Case Development
3.1
Base Case Origin and Year
The base case originated from VELCO and included a model of VELCO’s sub-transmission
system. The base case was revised to reflect proposed area projects.
3.2
Area Load
Using the NEPOOL 2009 Capacity, Energy, Load and Transmission (CELT) Report and the
methodology described in Appendix B –1, steady state analyses using a 2013 peak load forecast
of 31,470 MW and a 2013 shoulder load forecast of 22,024 MW were completed.
3.3
Planned Projects
The following list of planned facilities was present in the base case received from VELCO:
• Comerford QP 148
• Sheffield Wind Project QP 172
• Swanton Project QP 224
• Lyndonville Station
The following list of planned facilities was added to the base case received from VELCO:
• Wind QP 166 (Q195 now a three-terminal line with section to Littleton closed)
• Biomass Project QP 229
• Biomass QP 251
• Biomass QP 307
• Lyndonville Transmission Project Capacitors
• Vermont Southern Loop transmission Project
• QP 274
3.4
Base Case Naming Convention
Steady State base case designations were formatted as follows:
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Final Report
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pk13_ p1_dx
Dispatch Identifier
D1 = Highgate On
D2 = Highgate Off
Project Identifier
p0 = Project out of service
p1 = Project in service
Load Level Identifier
PK = peak load
SH = shoulder load
Followed by load model year
Figure 3-1 Steady State Base Case Naming Convention
Several cases were developed for the Study at a summer 2013 peak load level of 31,470 MW and
at a summer 2013 shoulder load level of 22,024 MW for ISO New England.
Dispatch D1 - The shoulder load (D1) dispatch represented the block load being supplied from
HQ and the Highgate HVDC converter at full output to stress the area in an
exporting condition.
Dispatch D2 - The peak load (D2) dispatch represented the block load being supplied from
Vermont and the Highgate HVDC converter was analyzed out of service to stress
the area in an importing condition.
Sensitivity Dispatch 3- The peak load (D3) dispatch represented the block load being supplied
from Vermont and the Highgate HVDC converter at full output.
Sensitivity Dispatch 4- The peak load (D4) dispatch represented the block load being supplied
from HQ and the Highgate HVDC converter at full output to stress the K42 Line.
The objective of modeling these various dispatch scenarios was to examine the proposed Project
and the ability of the transmission system to reliably serve customer demand under various
stressed system conditions.
3.5 Voltage Operational Analysis
The Study included an accurate and detailed model of the Project. All collector branches,
individual high and low-voltage busses for the wind generators and GSU's were modeled using
the configurations, network impedances, unit reactive capabilities and facility ratings provided.
The detailed model allowed analysis of real and reactive power flows and losses across
individual elements of the Project and made it possible to accurately test and monitor particular
QP 311 Feasibility Study
Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
voltage control strategies. Being able to monitor the terminal voltage at each individual wind
turbine generator made it possible to ensure units at the end of the collector strings remain within
voltage limits. The Project was adjusted (upgrades were added) to compensate for the reactive
losses of its collector system and interconnection facilities.
The Study concluded that by adding a 4 MVAr dynamic reactive device at the Project’s 34kV
bus for voltage control and setting the winding of the QP 311 46/34.5 kV transformer tap to
102.5% of nominal allowed voltages at the Project collector strings and generator buses to be
maintained within criteria for area contingencies (Loss of K42, K41W and K38 Lines) which
otherwise resulted in voltages outside criteria.
3.6
Analytical Tools
A steady state analysis was performed using the GE Power Systems, PSLF load flow software
package, Version 17. Short-circuit analyses were completed using the Aspen One Liner
Program.
4
Steady State Analysis Methodology
Steady state thermal and voltage analyses examined system performance without the proposed
Project in order to establish a baseline for comparison. System performance was then reevaluated with the Project and compared with the previous baseline performance to demonstrate
the impact of the Project on area transmission reliability.
4.1
Steady State Voltage Limits
Table 4-1 identifies the voltage criteria used by VELCO in the primary Study area for steady
state voltage assessment.
Acceptable Voltage Range
Voltage Class
230 kV and above
Pre-Contingency
(Normal Conditions)
0.98 to 1.05pu
Post-Contingency
(Emergency Conditions)
0.95 to 1.05pu
115 kV
0.95 to 1.05pu
0.95 to 1.05pu
Below 115 kV
0.95 to 1.05pu
0.90 to 1.05pu
Table 4-1 Steady State Voltage Criteria
4.2
Steady State Thermal Limits
Table 4-2 contains the thermal loading performance criteria applied to transmission lines and
transformers in the Study.
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Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
System
Condition
Time Interval
Maximum Allowable Facility Loading
Pre-Contingency
(all lines in)
Continuous
Normal Rating
Post-Contingency
Less than 15 minutes after
contingency occurs
More than 15 minutes after
contingency occurs
Short Time Emergency
(STE) Rating
Long Time Emergency
(LTE) Rating
Table 4-2 Steady State Thermal Criteria
4.3
Steady State Base Case Dispatch and Interface Conditions
Two load dispatches were analyzed for the study.
• D1 - Shoulder Load with Highgate on at 210 MW and the block load shifted to HQ to
create a maximum export condition
• D2 - Peak Load with Highgate off and the block load on Vermont. Additional sensitivity
dispatches were also performed at peak load with Highgate on and the block load on
either Vermont or HQ.
For the Study, four base cases were developed to analyze the impact of the Project on area
reliability under stressed system conditions.
Case A - Pre-Project (No Jay Tap 115/46 kV Substation)
Case B - Project On-Line with no redispatch
Case C - Project On-Line with redispatch against remote generation (Western Massachusetts)
Case D - Project On-Line with redispatch against local generation (Sheffield and Swanton)
Table 4-3 identifies these dispatch scenarios.
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Dispatch 2 (Peak Load)
Generator
Dispatch 1 (Shoulder Load)
B
C*
D*
99
29
71
667
42
121
144
19
8
0
0
63
210
130
A - Pre
Project
*
99
29
71
667
42
161
144
40
8
3
42
0
0 / 210*
130
99
29
71
667
42
161
144
40
8
3
42
63
0
130
99
29
71
667
42
161
144
40
8
3
42
63
0 / 210*
130
99
29
71
667
42
161
144
19
8
3
0
63
0 / 210*
130
9
9
9
9
9
9
3
3
3
3
3
3
6.5
3
6.5
3
6.5
3
6.5
3
14
14
14
14
14
14
14
14
66
66
3
66
66
66
3
66
A - Pre
Project
B
C
D
Wind (QP 166)
Biomass (QP 229)
Biomass (QP 251)
Vermont Yankee
Gorge (QP 274)
Moore
Comerford
Wind (QP 172)
Coventry
Barton
Swanton GT
QP 311
Highgate
PV 20
Highgate Falls
(Swanton Hydro)
Sheldon Springs Hydro
Fairfax Hydro
Lower Lamoille
(Peterson, Milton,
Clark Falls)
99
29
71
667
42
121
144
40
8
0
42
0
210
130
99
29
71
667
42
121
144
40
8
0
42
63
210
130
99
29
71
667
42
121
144
40
8
0
42
63
210
130
9
9
3
3
Altresco (W. Mass)
Base Case
* Sensitivity with Highgate on and block load
either on Vermont or HQ
Table 4-3 Local Area Dispatches
Detailed interface transfer and dispatch summaries for each of the baseline cases are included in
Appendix E. Draw files representing the baseline cases are included in Appendix F.
4.4
Steady State Contingency List
The original contingency file provided by VELCO was reviewed and modified for the Study.
Contingency analysis was conducted with approximately 50 contingencies encompassing single
element, transformer, generation and 115kV stuck breaker outages within the northwestern
portion of Vermont’s transmission system.
The Highgate Special Protection System (SPS) is always enabled (armed) and its action is
modeled as appropriate in the contingencies listed in Appendix D. When the flow through the
Highgate HVDC converter is from Quebec to Vermont, the SPS will reduce the converter import
into Vermont to a pre-specified level (usually 150 MW) for loss of any of the following Lines:
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July 19, 2010
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Contains Critical Energy Infrastructure Information
•
•
•
•
•
Georgia – Sandbar (K19 Line)
Georgia – Essex (K21 Line)
Sandbar – Essex (K22 Line)
Sandbar – So. Hero – Plattsburgh (PV-20 line)
Essex – Williston (K23) and Essex - Berlin (K24)
o If the K23 or K24 line is out of service, loss of the other line will cause runback to
the pre-specified level
Contingencies annotated with RB* include the Highgate SPS to model the runback.
For this study it is assumed that a transfer trip scheme will be in place to trip the QP 311 units
upon loss of the transmission line connecting QP 311 (VEC Lowell) 46 kV Substation to Jay 17
46 kV Substation or loss of the Jay Tap 115/46 kV transformer.
Appendix D provides a listing of the contingencies used in the Study.
5
Steady State Analysis Results
5.1
Baseline System
5.1.1
Voltage Performance
Baseline System – All Lines In
Under shoulder load conditions, steady state voltage analysis reported no violations of reliability
criteria for the baseline with all lines in-service for any of the base cases.
Under peak load conditions in Dispatch 2 (including sensitivity dispatches), steady state voltage
analysis reported violations of normal criteria (less than 95%) for the baseline with all lines inservice for 46kV buses in several Vermont load regions. During peak load conditions with the
block load supported by Vermont, the area has insufficient transmission voltage regulation and
reactive resources to maintain voltages above the normal criteria. These voltage issues are
mainly distributed throughout the underlying 46kV and 34kV subtransmission networks.
Baseline System – Post Contingency
Under shoulder load conditions in Dispatch 1, post-contingency voltage analysis reported no
violations of reliability criteria for the baseline with one exception, the Stowe DCT contingency
which causes loss of 115kV and 34.5 kV lines supporting the Stowe area.
Under peak load conditions in Dispatch 2 (and sensitivity dispatch 3) with the block load on
Vermont and Highgate offline, contingencies involving loss of the Irasburg 115/46 kV H39
transformer resulted in solutions diverging due to the loss of voltage support for the
Montgomery, Eden Corners and Johnson Substation areas.
Under peak load conditions in Dispatch 2 with the block load on Vermont and Highgate offline,
post-contingency steady state voltage analysis reported violations of reliability criteria (less than
90%) for multiple contingencies. The following contingencies listed in Table 5-1 resulted in
QP 311 Feasibility Study
Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
voltages below criteria in the baseline pre-Project cases. The Barre 34.5 kV capacitor bank is
available but offline based on the switching criteria in the study methodology.
Outage
Barre X63 Xfmr
D-204
K19
K19_RB
K28
K28_Stuck Bkr
K38
K42
K60
Stowe
Stowe DCT
Fairfax X67 Xfmr
Violations
kV
Barre / Granite Area Busses
Newport / Wenlock Area Busses
East Fairfax / Sandbar Area Busses
East Fairfax / Sandbar Area Busses
Newport / Richford / Wenlock Area Busses
Newport / Richford / Wenlock Area Busses
Newport / Richford / Wenlock Area Busses
Newport / Wenlock Area Busses
Newport / Richford / Wenlock Area Busses
Area Busses Between Johnson and Middlebury
Area Busses From Newport Through Middlebury
East Fairfax Area Busses
Ashland/Beebe
Case Diverged with Block on Vermont
Case Diverged with Block on Vermont
34.5
46
34.5
34.5
46
46
46
46
46
34.5
115 - 34.5
34.5
34.5
U199/X178
Irasburg H39 Xfmr
K41 Stuck breaker
Table 5-1 Peak Load Contingencies Resulting in Voltage Violations Pre-Project
Reliability issues associated with these contingencies were not addressed in the Study.
In the Sensitivity Dispatch 3 with Highgate online and block load on Vermont the following
differences were seen from the D2 dispatch which had Highgate offline:
o The D-204 Line remained within voltage criteria
o The K42 Line outage resulted in voltages above the 105% criteria for the East Fairfax
and VEC Pleasant Valley buses
In the Sensitivity Dispatch 4 with Highgate online and block load on HQ the following
differences were seen from the D2 dispatch which had Highgate offline and the block load on Vt:
o The D-204 Line remained within voltage criteria
o The K28 Line contingency resulted in voltages just above the 105% criteria for the
Sheffield area
o The K41 stuck breaker and Jay SS 40 transformer contingencies resulted in voltages
above the 105% criteria for the Irasburg area
o The K42 Line outage resulted in voltages above the 105% criteria for the East Fairfax
and VEC Pleasant Valley buses
o The Richford Transformer contingency resulted in voltages above the 105% criteria for
the Jay area
5.1.2
Thermal Performance
Baseline System – All Lines In
Under both shoulder and peak load conditions (including sensitivity dispatches), steady state
thermal analysis reported no violations of reliability criteria for the baseline with all lines inservice. In Dispatch 1 with shoulder load and maximum generation, the Littleton to Comerford
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Contains Critical Energy Infrastructure Information
D204 Line is near 100% of its normal rating which confirms the Northern Vermont and New
Hampshire 115 kV areas are at their maximum export limit.
Baseline System – Post Contingency
Under both peak and shoulder load conditions, steady state thermal analysis reported violations
of reliability criteria for the baseline system post contingency. These violations are pre-existing
thermal overloading concerns.
Under Dispatch 1 for shoulder load conditions, loss of the Barre 115/34 kV X63 transformer
resulted in overloading the Berlin to Mountain View 34 kV line, which is outside the local study
area. The U-199/X-178 contingency overloaded the 230 kV Comerford to Littleton D204 Line
to 105.9% and the 115 kV Littleton to Q195 Tap line to 104.8 % of their LTE ratings. Loss of
the K21 overloads the 115 kV Sandbar to Essex K22 Line to 102.6% of its LTE rating, which is
mitigated by the Highgate Runback SPS.
Under Dispatch 2 peak load conditions (including the sensitivity dispatches with Highgate online
and the block load on either Vermont or HQ), loss of the Barre 115/34 kV X63 transformer and
F206 Line resulted in overloading 34.5 kV circuits in central Vermont, which are outside the
local study area. For the K19 and Fairfax 115/34 kV X67 transformer contingencies, overloads
involving the 34 kV Nason St to Nason V line were reported. Additionally the St Albans 115/34
kV transformer contingency overloads the parallel St Albans to Nason 115-34 kV transformer.
For the Sensitivity Dispatch 4 with Highgate online and the block load on HQ, loss of the F206
Line also resulted in loading the Lowell VEC to VEC 21 Tap line to just over 100% LTE.
5.2
QP 311 In-Service
When the Project is in service approximately 42 MVAr in reactive power losses were reported.
These losses occur from the Jay Tap Switching Station to the point of interconnection and
include the Project collector strings and transformer losses. Table 5-2 demonstrates where the
losses occur for QP 311.
Location
MVAr Loss
Jay Tap Switching Station to VEC Lowell 46 kV Line Losses
Project Interconnection 46 kV Line Losses
Project Collector, Project 46/34.5 Transformer and GSU Losses
Total Reactive Power Losses
21.4
6
14.3
41.7
Table 5-2 Losses Due to Addition of Q311 Project
As discussed in Section 1.3, the Vestas V90 units are capable of providing approximately 0.6
MVAr per machine for a total of almost 13 MVAr for the entire wind farm. Along with the
addition of a 4 MVAR dynamic reactive device as discussed in Section 3.5, the Project
compensates for less than half of the total increase in losses when the Project is at full output.
Another change impacting voltage/reactive power performance with the Project is the change in
the 12W switch position at North Troy to Normally Open. With the 12W open, the four 2.7
MVAr capacitor banks at Jay Tap Switching Station are isolated from the Newport area which
QP 311 Feasibility Study
Final Report
July 19, 2010
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Contains Critical Energy Infrastructure Information
exacerbates the low voltage conditions in Dispatch 2 under peak load conditions with Vermont
serving the block load in the Newport area. With the 12W open after the Project, reactive
support was added at the Newport 46 kV bus to help alleviate these low voltages. The addition
of a 5.4 MVAr capacitor bank at the Newport-B2 bus brought bus voltages within the immediate
Newport area above pre-Project levels as demonstrated in Table 5-3.
Newport Area Voltages
Post-Project
Pre Project
Before Newport
Newport B-2 46 kV
S Bay2 46 kV
Coventry 46 kV
Moshers Corner 46 kV
Newport2 46 kV
N. Troy 46 kV
0.94pu
0.94pu
0.92pu
0.95pu
0.95pu
0.95pu
Post-Project
Cap
5.4MVAr Shunt
at Newport 46 kV
0.91pu
0.92pu
0.92pu
0.92pu
0.92pu
0.92pu
0.96pu
0.96pu
0.96pu
0.96pu
0.96pu
0.96pu
Table 5-3 Newport Area Pre Contingency Voltages
Under peak load conditions, steady state voltage analysis reported violations of reliability criteria
post contingency with the Project as originally proposed. Loss of the K42 resulted in the case
solution diverging due to voltage collapse. This demonstrated the need for additional reactive
resources in order to alleviate the reactive losses resulting from the Project. Additional shunt
capacitors were evaluated at VEC Lowell 46 kV substation as well as at Jay Tap substation.
Adding an additional 10.8MVAr of shunt capacitors at the Jay Tap Switching Station maintained
voltages within criteria for the K42 contingency as demonstrated in Table 5-4. A 5.4MVAr
capacitor at VEC Lowell 46 kV substation did not maintain reliability criteria for loss of the K42
Line.
The recommendation for the Project is to increase the four 2.7 MVAr capacitor banks to 5.4
MVAr capacitor banks. This could be accomplished by adding or changing capacitor cans in
each bank.
K 42 Contingency
Loss of Highgate – St. Albans - Georgia
Post-Project
Post-Project
Pre-Project
Highgate 115 kV
Jay Tap Switching 115 kV
Moshers Tap 115 kV
Irasburg 115 kV
Jay Tap Switching 46 kV
VEC Lowell 46 kV
Kingdom 46 kV
0.96pu
N/A
0.98pu
0.99pu
0.93pu
N/A
N/A
Post-Project
No Additional Shunt
Capacitor
VEC Lowell 46 kV or
Jay Tap 115/46 kV SS
Additional 5.4 MVAr
Shunt Capacitor
VEC Lowell 46 kV
SS
Additional 10.8 MVAr
Shunt Capacitor
Jay Tap 115/46 kV SS
Case Diverged
0.94pu
0.95pu
0.97pu
0.97pu
1.0pu
1.0pu
1.0pu
0.97pu
0.99pu
1.0pu
1.0pu
1.0pu
1.0pu
1.0pu
Table 5-4 Additional Capacitors for K42 Contingency
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July 19, 2010
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Contains Critical Energy Infrastructure Information
Table 5-5 demonstrates the reactive compensation proposed for the Project. These upgrades are
in-service for all the analyses performed with the Project in-service.
Amount
(MVAr)
Increase Jay Tap Capacitors
4
2.7
Newport 34 kV Capacitors
1
5.4
Generator capability
21
0.609
DVAR
1
±4.0
Additional Reactive Compensation
Location
# of Devices
Total
MVAr
10.8
5.4
12.8
±4.0
25 to 33.0
Table 5-5 Reactive Compensation Proposed for the Project
5.2.1
Voltage Performance
QP 311 – All Lines In
Under shoulder load conditions, steady state voltage analysis reported no violations of reliability
criteria for the Project configuration with all lines in-service.
Under peak load conditions, steady state voltage analysis reported violations of reliability criteria
for the Project configuration with all lines in-service for several 46 kV buses. These violations
were seen pre-project and the addition of the Project and associated upgrades do not aggravate
these low voltage conditions.
QP311 – Post Contingency
In all dispatches, loss of the 46 kV transmission line from Jay Tap Switching Station to the
Project results in high voltages for the remaining substations connected to Jay Tap 46 kV
Substation. Voltages of 1.10pu occur and would require post-contingency automatic capacitor
switching. Table 5-6 demonstrates the amount of shunts needed to be tripped for acceptable
voltage criteria in the shoulder load D1 dispatch. The application of a dynamic reactive device at
Jay Tap 46 kV Substation may be needed to control the temporary high-voltage condition based
on the Transmission Owner’s design criteria. Also in Dispatch 1, the Stowe DCT remains
unacceptable but closely matches the pre-Project results.
Post Contingency Capacitor Switching at Jay Tap Switching SS
Jay Voltage
Rich Voltage
Device Tripped
Jay Tap Switching Voltage
1.10pu
1.10pu
None
1.11pu
1 Bank of 5.4MVAr
1.09pu
1.09pu
1.08pu
2nd Bank of 5.4MVAr
1.07pu
1.06pu
1.06pu
3rd Bank of 5.4MVAr
1.05u
1.04pu
1.04pu
All Banks
1.03pu
1.03pu
1.02pu
Table 5-6 Post Contingency Capacitor Switching at Jay Tap Switching SS
Under the Dispatch 2 peak load cases (including the sensitivity dispatches), a significant number
of voltage reliability criteria violations exist as seen in the pre project case. The results clearly
demonstrate that the Project does not significantly impact the area reliability under this dispatch
and load condition.
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July 19, 2010
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Contains Critical Energy Infrastructure Information
Under Dispatch 2 peak load dispatch conditions with the block load on Vermont and Highgate
offline, contingencies involving loss of the Irasburg 115/46 kV H38 transformer resulted in
solutions diverging due to the loss of voltage support for the Montgomery, Eden Corners and
Johnson Substation areas. This is a pre-Project condition and the Project as configured has no
affect.
5.2.2
Thermal Performance
In the three base cases with the Project, two scenarios (Case B and C) were developed with no
redispatch in the local area. The third scenario (Case D) was developed with a local redispatch
with Swanton removed and Sheffield reduced. Refer to Table 4-3 for specific details. The
reasons for including the analysis with multiple redispatch conditions were to determine if local
congestion exists and whether the local units used in the redispatch cases were critical to support
of load in the various northern Vermont load pockets. By having multiple redispatch cases, the
analysis was able to distinguish between an adverse impact and local reliability dependencies on
specific generation.
QP 311 – All Lines In
Under Dispatch 1 for shoulder load conditions, steady state thermal analysis reported violations
of reliability criteria for the Project in-service configuration when the project was not
redispatched with local generation (Cases B and C). In this scenario excess generation in the area
occurs and the Comerford to Littleton Tap D204 line overloads to 108% of the normal rating.
This is related to area dispatch and is not experienced when local generation is dispatched off to
accommodate the Project (Case D). Therefore, local area congestion may require restrictions of
generation during off-peak load periods.
Under Dispatch 2 for peak load conditions (including the sensitivity dispatches), steady state
thermal analysis reported no violations of reliability criteria for the Project configuration with all
lines in-service.
QP 311– Post Contingency
Under Dispatch 1 for shoulder load conditions, loss of the Barre 115/34 X63 transformer resulted
in overloads outside the local study area. Other contingencies including loss of the U-199/X-178
Line, B202 Line, K21 Line, K38 Line, K39 Line and K42 Line all resulted in overloading in the
study area when the project was not redispatched with local generation (Cases B and C). This is
related to area dispatch and is not experienced when local generation is dispatched off to
accommodate the Project (Case D). Therefore, local area congestion may require restrictions of
generation during off-peak load periods.
Under Dispatch 1 for shoulder load conditions, reported loadings increased with the Project for
the K38 contingency with local generation dispatched off (Case D). With the Project, some load
at Lowell and Jay 17 is transferred to the new 46 kV line that interconnects the Project to the Jay
Tap Switching Station. This configuration change combined with generation from the Project
and remaining Sheffield generation online results in higher flows on the 46 kV transmission lines
between Irasburg and CVPS Johnson Substations. An alternative redispatch with Sheffield
offline and Swanton at partial output showed lower loadings on this path. No upgrades are
recommended since loading was below the emergency rating and an alternative redispatch
scenario relieved the congestion issue.
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July 19, 2010
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Contains Critical Energy Infrastructure Information
Under Dispatch 2 for peak load conditions (Highgate off and block load on Vermont), when area
generation was dispatched off (Case D) to accommodate the Project, the K19, K19 with runback
(RB), St Albans 115/34 kV transformer (X61 or X64) and East Fairfax 115/34 kV transformer
(X67) contingencies resulted in higher overloads on the Nason V - St Albans and the Nason St Nason V transmission lines. This is a result of peak load conditions, lack of area generation and
Swanton generation reductions. The overloads were similar when local generation was not
redispatched to accommodate the Project (Cases B and C).
Under the Sensitivity Dispatch 4 (block load being supplied from HQ and the Highgate HVDC
converter at full output to stress the K42 Line) when area generation was not dispatched off to
accommodate the Project the K38 contingency resulted in the Highgate-St Albans 115kV Line
(K42) exceeding LTE rating. Redispatching local area generation (Case D) relieves the loading
on the K42.
6
Short Circuit Analysis
Short circuit studies were conducted to assess the impact of the Project on fault current levels
within the VELCO area. The twenty-one VESTAS wind turbine generators were represented as
two separate aggregate machines consisting of eleven and ten units. The wind generators were
modeled as an equivalent synchronous generator per manufacturer’s technical manuals. The
subtransient impedance is used for short-circuit fault calculations from the wind generators. The
generator step-up transformers (GSU’s) were also modeled as two sets of aggregates by
multiplying the base MVA by the number of corresponding units to obtain the new MVA rating;
the per-unit impedance is the same for the aggregate as for a single transformer.
The Kingdom 46/34.5 kV transformer, along with the collector string impedance was modeled as
described in Table 1-2 and Table 1-4. The transformer was modeled as a grounded wye – delta
with the 34.5 kV side being grounded as per the preliminary one line in Appendix C. The 115 /
46 kV Jay Tap transformer was modeled as a three winding wye – wye with a delta tertiary as
per VELCO’s typical installation and as described in Table 1-2.
One line drawings indicate the voltage for many of the buses as 46 kV. The supplied ASPEN
model has these same buses modeled as 48 kV. Line impedances were entered as per unit values
based on the 48 kV base of the ASPEN model.
Following VELCO’s short-circuit analysis guidelines, faults were simulated with an assumed
pre-fault voltage “Flat” option, with 1.05 p.u. voltage. For X/R calculations where X was not
defined, a value of X = 0.0001 p.u. was used. For calculations where R was not defined, the
ANSI X/R ratio was used assuming R = max( X / g , Rc ) with Rc = 0.0001pu and g = 125 for
generators, 40 for transformers, and 10 for all others. Aspen Oneliner Version 11.5 program was
utilized to determine short circuit values.
The below gives a comparison of the short-circuit fault duties of affected buses and includes the
fault duties with and without the Project in service.
QP 311 Feasibility Study
Final Report
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Contains Critical Energy Infrastructure Information
Without Kingdom Wind Generation
Bus Fault
Location
Bus
Voltage
(kV)
Three
Phase
ANSI X/R
Jay
Jay Tap
Jay 17
VEC/Lowell
Kingdom
Kingdom
115
48
48
48
48
34.5
3001
3263
2527
1592
1335
1552
5.4
10.1
7.9
6.2
5.8
6.8
With Kingdom Wind Generation
Delta Amps
Three Single
Single
Three
Single
ANSI X/R
ANSI X/R
ANSI X/R
Phase Phase
Phase
Phase
Phase
2870
3924
2746
1651
1159
2150
5.1
10.2
5.5
4
4.4
7.2
3396
4390
3782
3357
3569
6218
5.7
9.4
8.1
8.5
11.3
14.3
3090
4888
3563
2530
1772
6342
5.2
9.8
5.1
3.7
4.4
16.6
395
1127
1255
1765
2234
4666
220
964
817
879
613
4192
Table 6-1 Kingdom Community Wind Short-circuit Fault Duties
Fault duties are low and should be considered in engineering design studies of the new 46 kV
transmission system supporting the Project. No issues at these levels are expected.
7
Delta V on Capacitor Switching
With the recommended change in capacitor size following the addition of the Project, a study
was conducted to determine the relative change in voltage (Delta – V) on capacitor switching.
Based on the available short-circuit duty listed in Table 6-1 above, the short-circuit MVA at the
Jay Tap 46 kV bus without the Project is 260 MVA. Therefore, the maximum capacitor size to
remain within 3% voltage change is 7.8 MVAr. The largest capacitors to switch at Jay Tap is 5.4
MVAr and within the acceptable range. The 5.4 MVAr capacitors will have an expected DeltaV of 2%.
8
Cost Estimates for Required Network Upgrades
The following is a cost estimate provided by VEC to construct the necessary required network
upgrades. The cost projections are based on “installed costs” and do not include the cost for
environmental assessment, permitting or temporary facilities required for outage protection.
VEC has communicated that subject to receipt of timely regulatory approval, the upgrades can be
implemented in time to fit the planned commercial operations schedule for the Project.
1. Increase from 4 x 2.7MVAr 46kV capacitor bank at the Jay Tap station to 4 x 5.4MVAr bank
and associated switching equipment for voltage control.
Assume 2 switches per 5.4MVAr capacitor rack (3 switches for 10.8MVAr with CB
switching one stage of fixed 2.7MVAr) and 2.7MVAr per layer allowing for the switching on
and off of 2.7MVAr of capacitors incrementally if required. Material: $260k (based on VEC
Jay Switching Station quote for 10.8MVAr bank) to include 2 switches and 10.8MVAr of
capacitors less the estimated cost of 2 steel racks. $100k for 2 additional switches per
breaker bay x 2 = $200k. Total Material: $460k. Estimated Labor: $50k. Total Estimated
Cost + 20% contingency: $612k.
2. Addition of a 5.4MVAr capacitor at the 46kV Newport-B2 bus.
Based on a single 5.4MVAr capacitor bank for VEC Jay Switching Station material.
Material: $143k for 1 switch and 5.4MVAr capacitors including the cost of two steel racks
each with 2.7MVAr of capacitors on first layer (expandable to 5.4MVAr per rack by
installing additional 2.7MVAr of capacitors on second layer). $60k for vacuum circuit
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breaker. Misc relays, interconnection materials: $40k. Total Material: $243k. Estimated
Labor: including concrete foundations and substation additions to accommodate the
capacitor bank: $150k. Total Estimated Cost + 20% contingency: $472k.
3. A protection scheme to trip the wind farm upon loss of the 46kV line or Jay Tap station
115/46kV transformer.
Assuming the use of Schweitzer relays, Transfer Trip systems can be easily employed over
the planned Project communications and fiber optic cable upgrades. Transfer trip of the wind
farm due to a loss of the 46 kV line and/or loss of the 115/46 kV transformer could be
designed and implemented at an incremental cost not to exceed $100,000.
9
Conclusion
Based upon the steady state results, the Project as originally requested posed significant adverse
impact on the reliability and operating characteristics of the transmission system, and would
require additional transmission system upgrades. For many single element contingencies (K28,
K38, K42 and K60) voltage violations of reliability criteria were associated with the Project and
the post-Project transmission configuration. Significant reactive losses occur along the 46 kV
transmission corridor connecting the project to the Jay Tap Switching Station. The Project
generators alone were incapable of providing the MVAr needed to sustain acceptable voltage
criteria. Also, post-Project transmission configuration has the 12W Switch open at N. Troy
which removes the reactive support of the Jay Tap Switching Substation shunt capacitors to the
Newport area.
Several system upgrades and project modifications were analyzed to provide necessary system
support. The following upgrades and modifications are recommended to maintain system
voltage criteria:
•
•
•
•
•
•
•
Add 4 MVAr dynamic reactive support at the Project’s 34 kV bus
The QP 311 46/34.5 kV transformer tapped winding must be modified to the 125%
tap
Increase the size of each of the four 2.7 MVAr shunt capacitor banks at the Jay Tap
Switching Substation to 5.4 MVAr for a total increase to the system of 10.8 MVAr
Provide automatic capacitor bank switching at Jay Tap to maintain reliable 46 kV
system voltage (or provide dynamic reactive power control)
The Jay Tap Switching Substation 115/46 kV transformer tapped winding must be set
to the 97.5% tap
Add a 5.4 MVAr cap at the Newport-B2 bus for area voltage support
Add a trip scheme to trip the QP 311 units upon loss of 46 kV line or Jay Tap
Switching Station 115/46 kV transformer
When the Project is dispatched locally under stressed exporting conditions (maximum generation
and shoulder load), no thermal reliability issues exist which require mitigation.
The Study concluded that by adding a 4 MVAr DVAR at the Project’s 34 kV bus for dynamic
reactive capability and voltage support and adjusting the QP 311 46/34.5 kV transformer tap to
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1.025 maintained the project collector strings and generator bus voltages within criteria for area
contingencies. Increasing the Jay Tap Switching Substation cap banks to 5.4 MVAR as well as
optimizing the Jay Tap 115/46 kV transformer to 0.975 was required to assist in maintaining
reliable voltages along the 12.4 mile radial line connecting the Project to the VELCO 115 kV
transmission system. Delta-V for the 5.4 MVAr capacitor banks at the Jay Tap 46 kV Substation
is under the 3% limit specified by VELCO. Post-project transmission configuration has the 12W
switch open, which isolates the North Troy 46 kV substation and points east (Newport area) from
the shunt capacitors located at Jay Tap Switching Substation. Adding a 5.4 MVAr cap at the
Newport-B2 bus provides needed support to maintain area voltages at pre-project levels due to
the 12W switch being open.
Short-circuit fault duties are below 5,000 A and expected to be well within the momentary and
interrupting duties of standard equipment rated for 46 kV. No upgrades due to short-circuit are
expected since the short-circuit current contribution is low for system fault conditions from wind
turbine generators.
VEC provided a cost estimate of approximately $1,184k to construct the necessary required
network upgrades. The cost projections are based on “installed costs” and do not include the
cost for environmental assessment, permitting or temporary facilities required for outage
protection. VEC has communicated that subject to receipt of timely regulatory approval, the
upgrades can be implemented in time to fit the planned commercial operations schedule for the
Project.
With the addition of the upgrades listed above to the Project as currently defined, the Project
poses no significant adverse impact on the reliability and operating characteristics of the VELCO
or VEC transmission systems, the transmission facilities of another Transmission Owner, or the
system of a Market Participant.
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Appendix A - Project Information
Included in Appendix A:
Appendix A-1: QP 311 Interconnection request
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Appendix B - Study Methodology
Included in Appendix B:
Appendix B-1: General Study Methodology
Appendix B-2: Steady State Analysis Methodology
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Appendix C - Preliminary One-Line Diagram
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Appendix D - Steady State Contingency List
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Appendix E - Steady State Base Case Summaries
Included in Appendix E:
Appendix E-1: 2013 Summer Shoulder Load – D1 Dispatch
Appendix E-2: 2013 Summer Peak Load – D2 Dispatch
Appendix E-3: 2013 Summer Peak Load – D3 Sensitivity Dispatch
Appendix E-4: 2013 Summer Peak Load – D4 Sensitivity Dispatch
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Appendix F - Steady State Base Case Draw Files
Included in Appendix F:
Appendix F-1: Dispatch A - Baseline Pre-Project
o Summer 2013 Shoulder Load – D1 Dispatch
o Summer 2013 Peak Load – D2 Dispatch
o Summer 2013 Peak Load – D3 Sensitivity Dispatch
o Summer 2013 Peak Load – D4 Sensitivity Dispatch
Appendix F-2: Dispatch B - No Redispatch
o Summer 2013 Shoulder Load – D1 Dispatch
o Summer 2013 Peak Load – D2 Dispatch
Appendix F-3: Dispatch C - Redispatch Against Remote Generation (Western Massachusetts)
o Summer 2013 Shoulder Load – D1 Dispatch
o Summer 2013 Peak Load – D2 Dispatch
o Summer 2013 Peak Load – D3 Sensitivity Dispatch
o Summer 2013 Peak Load – D4 Sensitivity Dispatch
Appendix F-4: Dispatch D - Redispatch Against local generation (Sheffield and Swanton)
o Summer 2013 Shoulder Load – D1 Dispatch
o Summer 2013 Peak Load – D2 Dispatch
o Summer 2013 Peak Load – D3 Sensitivity Dispatch
o Summer 2013 Peak Load – D4 Sensitivity Dispatch
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Appendix G - Steady State Contingency Voltage Results
Included in Appendix G:
Appendix G-1: 2013 Summer Shoulder Load – D1 Dispatch
Appendix G-2: 2013 Summer Peak Load – D2 Dispatch
Appendix G-3: 2013 Summer Peak Load – D3 Sensitivity Dispatch
Appendix G-4: 2013 Summer Peak Load – D4 Sensitivity Dispatch
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Appendix H - Steady State Contingency Thermal Results
Included in Appendix H:
Appendix H-1: 2013 Summer Shoulder Load – D1 Dispatch
Appendix H-2: 2013 Summer Peak Load – D2 Dispatch
Appendix H-3: 2013 Summer Peak Load – D3 Sensitivity Dispatch
Appendix H-4: 2013 Summer Peak Load – D4 Sensitivity Dispatch
QP 311 Feasibility Study
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Contains Critical Energy Infrastructure Information