Project #80
Generation Interconnection System
Impact Study Report
11/13/08
Electric Transmission Planning
Table of Contents
Table of Contents........................................................................................................................... 2
Executive Summary ...................................................................................................................... 3
Network Resource Interconnection Service – Results ................................................................ 3
Energy Resource Interconnection Service – Results ................................................................... 4
Definitions ...................................................................................................................................... 6
Network Resource ....................................................................................................................... 6
Network Resource Interconnection Service ................................................................................ 6
Energy Resource Interconnection Service................................................................................... 7
Generator and Interconnection Data........................................................................................... 8
Study Parameters .......................................................................................................................... 9
Senior Queue Generator Assumptions ........................................................................................ 9
Steady State Power Flow Analysis ............................................................................................. 10
Method....................................................................................................................................... 10
Results ....................................................................................................................................... 10
Mitigation .................................................................................................................................. 10
Transient Stability Analysis ....................................................................................................... 11
Method....................................................................................................................................... 11
Results ....................................................................................................................................... 11
Mitigation .................................................................................................................................. 12
PV & QV Analysis....................................................................................................................... 13
PV Analysis............................................................................................................................... 13
Method................................................................................................................................... 13
Results ................................................................................................................................... 13
Mitigation .............................................................................................................................. 14
QV Analysis .............................................................................................................................. 14
Method................................................................................................................................... 14
Results ................................................................................................................................... 15
Mitigation .............................................................................................................................. 15
Fault Duty Analysis ..................................................................................................................... 16
Method....................................................................................................................................... 16
Results ....................................................................................................................................... 16
Mitigation .................................................................................................................................. 16
Conclusions .................................................................................................................................. 17
N-0 Mitigation ........................................................................................................................... 17
N-1 Mitigation ........................................................................................................................... 17
Next Steps.................................................................................................................................. 17
Executive Summary
NorthWestern Energy (“NWE”) has completed the System Impact Study (“SIS”) for Project #80
(“Generation Project”) near Springdale, MT. NWE studied your project as both a Network
Resource Interconnection Service (“NRIS”) and an Energy Resource Interconnection Service
(“ERIS”). The SIS is an in-depth analysis that examines the response of the transmission system
to a variety of system operating conditions. NWE is responsible for maintaining acceptable
system reliability, and must be certain that system reliability is maintained with the addition of
the Generation Project. NWE uses tolerance levels outlined by FERC, NERC, and/or WECC.
The SIS uses the following types of analyses:
•
•
•
•
•
Steady-State Power Flow
Post Transient Steady-State Power Flow
Transient Stability
Fault Duty
Reactive Margin
The results of the SIS confirm that the addition of 80 MW interconnected to the NWE 161 kV
transmission system at Lower Duck Creek Substation is only feasible with system improvements.
The findings included in this study do not assure the Interconnection Customer that the planned
Generation Project will be allowed to operate at full capacity under all operating conditions.
NWE cannot guarantee that future analysis will not identify additional problems.
Network Resource Interconnection Service – Results
NRIS allows the Interconnection Customer to be designated as a Network Resource, up to the
Large Generating Facility’s full output, on the same basis as existing Network Resources
interconnected to the Transmission Provider’s Transmission System. NRIS does not in and of
itself convey reservation of transmission service. Any network customer under the Tariff can
utilize its network service under the Tariff to obtain delivery of electricity from the Generation
Project in the same manner as it accesses Network Resources.
The NRIS Feasibility Study identified thermal overload problems on the Big Timber 161/50 kV
transformer, and the 50 kV line between Big Timber and Melville. A non-binding cost estimate
to interconnect your project is summarized in Table I.
Table I.
Non-Binding, Cost Estimate
Substation
Relay
Communications
Metering
EMS
Reconductor 50 kV line Segment
Upgrade Big Timber transformer
Total
*TBD
$30,000
$50,000
$12,500
$5,000
$436,500
$800,000
$1,334,000
*The Lower Duck Creek Substation is owned by Park Electric
Cooperative, and they will be responsible for providing the
substation interconnection costs
Energy Resource Interconnection Service – Results
ERIS allows the Interconnection Customer to connect the Large Generating Facility to the
Transmission System and be eligible to deliver the Large Generating Facility’s output using the
existing firm or non-firm capacity of the Transmission System on an “as available” basis. ERIS
does not in and of itself convey any right to deliver electricity to any specific customer or Point of
Delivery.
The ERIS study is designed to answer two questions:
I. What is the maximum allowed output to interconnect without additional network
upgrades?
Answer:
45 MW is the maximum output without additional network upgrades.
The cost of the equipment to interconnect the Generation Project to
NWE’s system is summarized in Table II
Table II
Non-Binding, Cost Estimate
Substation
Relay
Communications
Metering
EMS
Total
*TBD
$30,000
$50,000
$12,500
$5,000
$97,500
*The Lower Duck Creek Substation is owned by Park Electric
Cooperative, and they will be responsible for providing the
substation interconnection costs
II. What are the necessary upgrades to allow for full output of the Generation Project?
Answer:
The necessary upgrades to interconnect the full output of the Generation
Project are the same as the NRIS study improvements. A non-binding
cost estimate to operate the Generation Project at full capacity is
summarized in Table III.
Table III.
Non-Binding, Cost Estimate
Substation
Relay
Communications
Metering
EMS
Reconductor 50 kV line Segment
Upgrade Big Timber transformer
Total
*TBD
$30,000
$50,000
$12,500
$5,000
$436,500
$800,000
$1,334,000
*The Lower Duck Creek Substation is owned by Park Electric
Cooperative, and they will be responsible for providing the
substation interconnection costs
Definitions
Network Resource
Network Resource shall mean any designated generating resource owned, purchased, or leased by
a network customer under the network integration transmission service tariff. Network Resources
do not include any resource, or any portion thereof, that is committed for sale to third parties or
otherwise cannot be called upon to meet the network customer's network load on a noninterruptible basis.
Network Resource Interconnection Service
NRIS shall mean an Interconnection Service that allows the Interconnection Customer to
integrate its Large Generating Facility with the Transmission Provider’s Transmission System (1)
in a manner comparable to that in which the Transmission Provider integrates its generating
facilities to serve native load customers; or (2) in an RTO or ISO with market based congestion
management, in the same manner as all other Network Resources. Network Resource
Interconnection Service in and of itself does not convey transmission service.
NRIS allows the Generation Project to be designated by any network customer under the Tariff
on NWE's Transmission System as a Network Resource, up to the Generation Project's full
output, on the same basis as existing Network Resources interconnected to NWE's transmission
system, and to be studied as a Network Resource on the assumption that such a designation will
occur. Although NRIS does not convey a reservation of Transmission Service, any network
customer under the Tariff can utilize its network service under the Tariff to obtain delivery of
energy from the Generation Project in the same manner as it accesses Network Resources. A
facility receiving NRIS may also be used to provide ancillary services after technical studies
and/or periodic analyses are performed with respect to the Generation Project's ability to provide
any applicable ancillary services, provided that such studies and analyses have been or would be
required in connection with the provision of such ancillary services by any existing Network
Resource. However, if the Generation Project’s facility has not been designated as a Network
Resource by any load, it cannot be required to provide ancillary services except to the extent such
requirements extend to all generating facilities that are similarly situated. The provision of
network integration transmission service or firm point-to-point transmission service may require
additional studies and the construction of additional upgrades. Because such studies and upgrades
would be associated with a request for delivery service under the Tariff, cost responsibility for the
studies and upgrades would be in accordance with the Federal Energy Regulatory Commission’s
(“FERC”) policy for pricing transmission delivery services.
NRIS does not necessarily provide the Generation Project with the capability to physically deliver
the output of its facility to any particular load on NWE's transmission system without incurring
congestion costs. In the event of transmission constraints on NWE's transmission system, the
Generation Project’s facility shall be subject to the applicable congestion management procedures
in NWE's transmission system in the same manner as Network Resources. NWE will follow
regional and sub regional congestion management procedures as they are developed.
Once the Generation Project satisfies the requirements for obtaining NRIS, any future
transmission service request for delivery from the Generation Project’s facility within NWE's
transmission system of any amount of capacity and/or energy, up to the amount initially studied,
will not require that any additional studies be performed or that any further upgrades associated
with the Generation Project’s facility be undertaken, regardless of whether or not the Generation
Project’s facility is ever designated by a network customer as a Network Resource and regardless
of changes in ownership of the facility. However, the reduction or elimination of congestion or
redispatch costs may require additional studies and the construction of additional upgrades. This
philosophy is described in the FERC Order Nos. 2003, 2003-A, 2003-B and 2003-C, which
govern interconnection of large generators to the transmission grid. The pro forma Large
Generator Interconnection Procedures (“LGIP”) and Large Generator Interconnection Agreement
(“LGIA”) required in those orders describe the philosophy that NWE used in performing the
study work for the Generation Project.
To the extent the Generation Project enters into an arrangement for long-term transmission
service for deliveries from the facility outside of NWE's transmission system, such request may
require additional studies and upgrades in order for NWE to grant the request.
NorthWestern Energy is not required to provide certain ancillary services to transmission
customers serving load outside of NorthWestern’s control area.
Energy Resource Interconnection Service
Energy Resource Interconnection Service shall mean an interconnection service that allows the
interconnection customer to connect its generating facility to the transmission provider's
transmission system to be eligible to deliver the facility's electric output using the existing firm or
nonfirm capacity of the transmission provider's transmission system on an “as available” basis.
Energy Resource Interconnection Service in and of itself does not convey transmission service.
Under Energy Resource Interconnection Service (“ERIS”), the Generation Project will be able to
inject power from the facility into and deliver power across NWE’s transmission system on an
“as available” basis up to the amount of MW identified in the applicable stability and steady state
studies to the extent the upgrades initially required to qualify for ERIS have been constructed. No
transmission delivery service from the Generation Project is assured, but the Generation Project
may obtain point-to-point transmission service, network integration transmission service, or be
used for secondary network transmission service, pursuant to NWE’s Tariff, up to the maximum
output identified in the stability and steady state studies. In those instances, in order for the
Generation Project to obtain the right to deliver or inject energy beyond the facility point of
interconnection or to improve its ability to do so, transmission delivery service must be obtained
pursuant to the provisions of NWE's Tariff. The Generation Project's ability to inject its output
beyond the point of interconnection, therefore, will depend on the existing capacity of NWE's
transmission system at such time as a Transmission Service Request (“TSR”) is made that would
accommodate such delivery. The provision of firm point-to-point transmission service or network
integration transmission service may require the construction of additional network upgrades.
Generator and Interconnection Data
The proposed generator and interconnection data used in the studies was based on the information
received from the Interconnection Customer. From the initial application, NWE identified the
following project information.
•
•
•
•
•
•
•
Project Name – Project #80
Size (Rated) -- 80 MW total
Location – North River Road, Springdale, Sweet Grass County, MT
Special Resources/Technology – 48 Vestas V82-1.65 MW Wind Turbine Generators
Proposed Commercial Operation Date – September 18, 2009
Facilities – Connection to the Park Electric Cooperative Lower Duck Creek 161 kV
substation.
Assumptions –
o MW Output = 80 MW
o Scheduled Voltage (pu) = 1.02 at the Point of Interconnection
o The generator is assumed to have operational characteristics either through
internal or external capabilities to operate throughout a power factor range of .95
leading to .95 lagging at the Point of Interconnection. During the study process,
NWE found that if this requirement was not met, system reliability could be
compromised.
Study Parameters
In analyzing the Generation Project, NWE utilized “PSS/E” software to conduct the System
Impact Study with the proposed Generation Project. These studies “connected” the Generation
Project to NWE’s Transmission System in a computer model to simulate the interaction of the
Generation Project with other resources and loads.
Two WECC base cases adjusted to include the NWE Transmission System detail representing
2010 light autumn and 2012 heavy summer loads were used for this study.
Senior Queue Generator Assumptions
In addition to existing generators, senior queue resources were also included in this study. (See
Table IV). Senior queued generation and existing generation dispatch were varied as needed to
emulate stress on the system for various scenarios.
Table IV
Project Number Size (MW)
31
396
32
268
33
52.5
38
81.9
39
22
44
104
46
10
47
20
49
23
53
277
54
100
57
85
58
10
60
20
61
2
62
11.5
63-69
30 (total)
73
100
74
280
75
75.6
76
75.6
77
213
80
80
Point of Interconnection
Wilsall-Shorey Road 230 kV Line
Great Falls 230 kV Switchyard
Martinsdale Substation
Martinsdale Substation
Billings Steam Plant Switchyard
South Cut Bank - Conrad Auto 115 kV line
Loweth - Two Dot 100 kV line
69 kV line at Chester
Rainbow Switchyard
Great Falls 230 kV Switchyard
Wilsall-Shorey Road 230 kV Line
Bradley Creek Substation
Bradley Creek - Three Forks S. 100 kV line
Bradley Creek - Three Forks S. 100 kV line
Phillipsburg - Anaconda 25 kV line
69 kV line between Fairfield and Bole
69 kV line near Sumatra (6 requests, 5 MW each)
Cut Bank 115 kV Substation
ASMI 161 kV Substation
161 kV line appx 5 mi. N of Bradley Creek sub.
100 kV line appx 5 mi. N of Bradley Creek sub.
Mill Creek 230 kV Substation
Lower Duck Creek Substation (Generation Project)
Steady State Power Flow Analysis
The steady-state power flow analysis examines steady state, system normal, operating conditions
with no lines out of service (i.e., N-0 Conditions) and with various lines out of service (i.e., N-1
and N-2 conditions). A power flow simulation is completed before and after the addition of the
Generation Project to identify any unacceptable thermal overloads and voltage excursions the
project may cause.
Method
NWE simulated an extensive set of 500 kV and non-500 kV N-1 and N-2 outages. Power flow
contingencies were simulated for both operating conditions (2010 light autumn and 2012 heavy
summer). The local area contingencies were the primary focus, but major transmission line
outages around the NWE system were also studied.
Results
•
N-0: The addition of the Generation Project to NWE’s Transmission System under N-0
conditions (all lines in service) causes no adverse effects.
•
N-1: The addition of the Generation Project to NWE’s Transmission System under N-1
conditions (one line out of service) causes overloads on the Big Timber 161/50 kV
transformer and the Big Timber to Melville 50 kV line. See Table V
Table V:
Thermal Overloads
%
%
Overload Overload
Before
After
Base
Outage Element
Monitored Element
Project Project
case
2010 HS Lower Duck Creek – Clyde Park 161 kV Clyde Park – L. Duck Cr. 161 kV
76
102
2012 HS Lower Duck Creek – Clyde Park 161 kV Big Timber 161/50 kV Transformer 102
117
Mitigation
In order for the Generation Project to interconnect and operate at full capacity, the following
mitigation is required:
•
•
Upgrade the 161/50 kV transformer at Big Timber from a 25 MVA rating to a 50 MVA
rating.
Reconductor the 50 kV line segment between Big Timber and Melville
Transient Stability Analysis
When a line fault occurs, the protective relaying must respond by opening circuit breakers to
remove the affected transmission line from service. This can result in a system disturbance. The
credible “worst case” fault events must be simulated to determine if the transmission system will
recover to acceptable steady state operating conditions. Events that were studied include singlephase and three-phase faults causing either single or multiple line outages or generator failures.
The dynamic simulations performed for this project include an assortment of events that are
intended to provide a robust test of the impact of the Generation Project.
The results from the Transient Stability Analysis are designed to reveal:
•
•
•
Whether or not regional electric transmission systems remain stable with each event;
Whether or not WECC criteria are met for each outage condition; and
Identify where problems are located on the Transmission System.
Method
NWE simulated an extensive set of 500 kV and non-500 kV faults. The term “fault” refers to a
short-circuit between either a single-phase conductor to ground or all three phases.
Results
The simulated events are summarized in Table VI.
Table VI. Transient Stability Analysis – Simulated Events
Fault type
Voltage
Location
Line Segment Opened
3-phase bus fault
1-phase bus fault
3-phase bus fault
1-phase bus fault
3-phase bus fault
3-phase bus fault
3-phase bus fault
1-phase bus fault
3-phase bus fault
1-phase bus fault
3-phase bus fault
3-phase bus fault
3-phase bus fault
3-phase bus fault
3-phase bus fault
500 kV
500 kV
500 kV
500 kV
500 kV
500 kV
500 kV
500 kV
500 kV
500 kV
500 kV
500 kV
500 kV
230 kV
161 kV
Broadview Bus
Broadview Bus
Broadview Bus
Broadview Bus
Broadview Bus
Broadview Bus
Colstrip Bus
Colstrip Bus
Garrison Bus
Garrison Bus
Garrison Bus
Taft Bus
Taft Bus
Garrison 230 Bus
Lower Duck Creek
Broadview - Colstrip (single circuit)
Broadview - Colstrip (single circuit)
Broadview - Garrison (single circuit)
Broadview - Garrison (single circuit)
Broadview - Garrison (double circuit)
Broadview - Colstrip (double circuit)
Broadview - Colstrip (single circuit)
Broadview - Colstrip (single circuit)
Garrison - Taft (single circuit)
Garrison - Taft (single circuit)
Garrison - Taft (double circuit)
Taft - Bell
Taft - Dworshak
Garrison – Anaconda 230 kV line
L. Duck Creek – Big Timber
Fault type
Voltage
Location
Line Segment Opened
3-phase bus fault 161 kV Lower Duck Creek L. Duck Creek – Clyde Park
no-fault
500 kV n/a
Broadview - Colstrip (single circuit)
no-fault
500 kV n/a
Broadview - Garrison (single circuit)
A table of results is summarized in Table VII.
Table VII. Transient Stability Results
Event
L. Duck Creek – Big Timber 161 kV
L. Duck Creek – Clyde Park 161 kV
Broadview - Colstrip 500 kV (Single Circuit)
Broadview - Garrison 500 kV (Double Circuit)
Colstrip - Broadview 500 kV (Single Circuit)
Garrison - Anaconda 230 kV
Garrison - Taft 500 kV (Double Circuit)
Garrison - Taft 500 kV (Single Circuit)
No Fault, open Broadview - Colstrip 500 kV
No Fault, open Broadview - Garrison 500 kV
Single Phase Broadview - Colstrip 500 kV
Single Phase Broadview - Garrison 500 kV
Single Phase Colstrip - Broadview 500 kV
Single Phase Garrison Taft 500 kV
Taft - Bell 500 kV
Taft - Dworshak 500 kV
WECC Criteria Low Voltage
B
0.83
B
0.83
B
0.90
B
.0.84
B
0.93
B
0.91
B
0.85
B
0.93
B
0.93
B
0.93
B
0.93
B
0.93
B
0.93
B
0.93
B
0.87
B
0.91
Mitigation
No mitigation is required to meet transient stability requirements.
Low Voltage Bus
PRJ80_GN 0.6
PRJ80_GN 0.6
CORETTE 18.0
MONTANA1 13.8
GRAYS_413.8
PRJ31_GN 0.6
GAR1EAST500
GRAYS_413.8
GRAYS_413.8
GRAYS_413.8
GRAYS_413.8
GRAYS_413.8
GRAYS_413.8
GRAYS_413.8
CELILO4230
CELILO4230
PV & QV Analysis
The SIS examined the reactive margin at critical buses on NWE’s Transmission System. In
addition, the PV and QV reactive margin identifies potential voltage collapse issues under
maximum operating conditions. This analysis includes the addition of the Generation Project.
PV Analysis
Voltage security margins were evaluated using PV analysis. For this type of study, the security
margin (distance to the voltage collapse) is defined by the amount of additional power transfer
that can occur before voltage collapse is reached on a predefined bus. Voltage collapse occurs at
the “knee point” of the PV curve where the voltage drops rapidly with an increase in the transfer
power flow. Operation at or near the stability limit is impractical and a satisfactory operation
condition must be ensured to prevent voltage collapse.
Method
The Generation Project was modeled with all co-existing generation projects and their mitigation
requirements. Additional power transfer was simulated on the Montana-Northwest Path (Path 8)
by moving power 5% beyond the initial values into the transmission system. The increased
power output from the Generation Project was offset by reducing generation at Colstrip. The
results show that the available reactive power compensation is sufficient to meet the steady-state
requirements for all scenarios and contingencies analyzed.
Results
The Generation Project is modeled with all co-existing generation projects and their required
mitigation. Results indicate the addition of the Generation Project does not affect the power
transfer capability. The PV curve can be seen in Figure 1.
Figure 1. PV Curve for Wilsall 230 KV bus
Figure 1 shows that there is no “knee point” where the voltage drops drastically. This suggests
that the addition of the Generation Project causes no adverse effects.
Mitigation
No mitigation is required to meet PV requirements.
QV Analysis
QV analysis is used to determine the reactive power injection required at predefined bus in order
to correct the bus voltage to the required value. The curve is obtained through a series of AC load
flow calculations. The voltage at a predefined bus can be calculated for a series of power flows
as the reactive load is increased in steps. The point where the power flow becomes nonconvergent is the point where voltage collapse occurs.
Method
QV curves were obtained for the Generation Project using the QV analysis tools in PSS/E. These
curves were obtained before and after the addition of the Generation Project, and include all N-1
contingencies. The result is a series of QV curves for each bus, which are used to determine the
reactive power margin. The Generation Project is modeled with all senior queue projects and
their mitigation requirements.
Results
The amount of reactive power required to hold the Wilsall 230 kV bus at 0.90 p.u for an N-1
contingency is negative, which shows that NWE’s system has sufficient reactive margin to meet
the requirements with the addition of the Generation Project. (See Figure 2)
Figure 2. QV Curve for Generation Project
Mitigation
No mitigation is required to meet QV requirements.
Fault Duty Analysis
When a fault occurs on a power line, protective relaying equipment detects the fault current
flowing and signals the associated circuit breakers to open. When the circuit breakers open, they
must be capable of interrupting the fault current. If the magnitude of the fault current exceeds the
interrupt rating of the circuit breakers, the fault may not be cleared, and damage to system
equipment and voltage collapse may result.
Method
To perform a fault duty analysis, busses at or near the point of interconnection of this project are
faulted in a PSS/E model to determine the magnitude of fault current anticipated with the
Generation Project in service. The results of this analysis determine whether standard circuit
breaker fault duty ratings would be exceeded with the addition of the Generation Project.
Results
The breakers in the area have sufficient interrupting capability. A breaker interrupt rating of
25,000 amps was assumed. The highest fault current observed was 8,102 amps at the Lower
Duck Creek 161 kV bus.
Mitigation
No mitigation is required to meet fault duty requirements.
Conclusions
The results of this analysis confirm that the addition of 80 MW of generation interconnected to
the NWE 161 kV transmission system at Lower Duck Creek substation is only feasible with
system improvements.
N-0 Mitigation
No mitigation is required to meet N-0 requirements
N-1 Mitigation
•
•
Reconductor the 50 kV line segment between Big Timber and Melville (1.94 miles)
Upgrade the 161/50 kV transformer at Big Timber
Next Steps
NWE will be scheduling a meeting to discuss the findings of the SIS with the Interconnection
Customer. If, after the meeting, the Interconnection Customer wishes to continue with the
project, the Generation Project must designate either ERIS or NRIS. A Facility Study specific to
the project will then be carried out to determine the final details of the interconnection.
This study does not constitute a request for transmission service. The study examined the physics
of the electrical system and does not imply that you will receive any transmission required to
deliver the generation output to load. You must follow the procedures described in the
transmission tariff available on (http://www.oatioasis.com/NWMT/index.html) to request and/or
receive transmission service.