2014 LOCAL TRANSMISSION PLAN:
TRANSMISSION COORDINATION AND PLANNING COMMITTEE
ANNUAL TRANSMISSION ASSESSMENT
FOR THE
COMMON USE TRANSMISSION SYSTEM
PREPARED BY
BLACK HILLS CORPORATION
TRANSMISSION PLANNING
January 30, 2015
Executive Summary
In December of 2007, the Common Use System (“CUS”) participants filed with FERC Attachment
K to the Joint Open Access Transmission Tariff (“JOATT”) to meet the requirements outlined in
FERC Order 890. Through their Attachment K filing, the CUS participants created the
Transmission Coordination and Planning Committee (“TCPC”) as the forum to conduct long-range
planning studies while promoting stakeholder input and involvement. This report, intended to
serve as the 2014 Local Transmission Plan (“LTP”), outlines the 2014 study cycle and presents the
findings of the planning study. The report also serves as evidence of compliance with the NERC
TPL Standards.
The 2014 TCPC study consisted of a series of analysis methods to determine the long-term
adequacy of the transmission system. These methods included steady-state power flow and
transient stability performed on short term and long term scenarios to provide a comprehensive
understanding of expected future transmission system performance.
The 2014 study confirmed the need for several projects that were previously identified and planned
for completion within the 10-year planning horizon, and a new potential reliability concern at the
tail-end of the planning horizon was identified for future consideration. A brief summary of study
results is included below:
•
•
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•
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A second 230/69 kV transformer at Yellow Creek Substation should continue as planned to
address transformation capacity concerns in the northern Black Hills area. The expected inservice date is 2018. (BHP)
Local transmission providers should finalize an agreement for an exemption from the
frequency limits specified in the WECC Disturbance-Performance Table (Table W-1) of
Allowable Effects on Other Systems. (BHP/BEPC)
More transformation capacity in the Osage 69 kV area is needed in winter scenarios due to
expected load growth. (BHP/PREC)
The need for more transformation capability in the Wyodak 69 kV area was confirmed due
to expected load growth and the retirement of the NSS1 power plant. (BHP)
The TCPC should continue to monitor the 230/69 kV transformation capability at Lange
and South Rapid as Rapid City load growth requires. (BHP)
The South Rapid-West Hill 230kV line rebuild should continue as planned with an inservice date of 2019 to mitigate overloading. (BHP)
Out-of-step relaying is recommended on Wyodak-area generators and should be discussed
with affected parties. (BHP)
The contingency that overloads South Rapid-West Hill 230 kV line should be added to the
new RAS that was studied by BEPC on 12/30/2013.
The Teckla-Osage and Osage-Lange 230 kV lines should proceed as planned with an
expected in-service date of 2016. (BHP)
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
2
This report serves as the 2014 Local Transmission Plan and meets the requirements of Attachment
K to the BHBE JOATT, as well as the requirements of the NERC TPL Standards and WECC
System Performance Criteria.
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
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Table of Contents
1.
2.
3.
4.
5.
Introduction ............................................................................................................................... 6
1.1.
Common Use Transmission System Background .............................................................. 6
1.2.
Stakeholder Participation .................................................................................................... 6
Study Methodology ................................................................................................................... 8
2.1.
Study Criteria ...................................................................................................................... 8
2.2.
Study Area .......................................................................................................................... 9
2.3.
Study Case Development .................................................................................................. 10
2.4.
Transmission Planning Assumptions ................................................................................ 11
Evaluation of the Common Use Transmission System ........................................................ 11
3.1.
Steady-State Analysis ....................................................................................................... 12
3.2.
Category D Extreme Outage Analysis .............................................................................. 13
3.3.
Transient Stability Analysis .............................................................................................. 15
3.4.
Results Summary .............................................................................................................. 18
Transmission System Expansion ........................................................................................... 19
4.1.
Previously Identified/Existing Projects ............................................................................ 19
4.2.
Recommended Projects..................................................................................................... 19
Conclusions .............................................................................................................................. 20
Appendix A ..................................................................................................................................... A-1
Appendix B ..................................................................................................................................... B-1
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
4
List of Tables
Table 1: CUS Interconnection Points ............................................................................................... 10
Table 2: Study Case Naming Convention......................................................................................... 12
Table 3: 2019HW Category D Outage Summary ............................................................................. 14
Table 4: 2019LW Category D Outage Summary ............................................................................. 15
Table 5: Transient Stability Analysis Fault Summary ...................................................................... 17
List of Figures
Figure 1: Existing Common Use Transmission System ..................................................................... 7
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
5
1. Introduction
In December of 2007, the Common Use System (“CUS”) participants filed with FERC Attachment
K to the Joint Open Access Transmission Tariff (“JOATT”) to meet the requirements outlined in
FERC Order 890. Through their Attachment K filing, the CUS participants created the
Transmission Coordination and Planning Committee (“TCPC”) as the forum to conduct long-range
planning studies while promoting stakeholder input and involvement. This report, intended to
serve as the 2014 Local Transmission Plan (“LTP”), will outline the 2014 study cycle and present
the findings of the planning study.
1.1.
Common Use Transmission System Background
Black Hills Power, Inc., Basin Electric Power Cooperative and Powder River Energy Corporation
(referred to hereinafter as the Transmission Provider) each own certain transmission facilities with
transmission service pursuant to a FERC-approved Joint Open Access Transmission Tariff
(“JOATT”). The Transmission Provider commonly refers to these facilities as the Common Use
System (“CUS”). A diagram of the CUS is shown in Figure 1.
1.2.
Stakeholder Participation
All interested parties were encouraged to participate in the 2014 TCPC study process. An open
stakeholder kick-off meeting was held via webinar on March 13, 2014 to inform stakeholders of the
proposed study plan and to provide an opportunity for suggestions and feedback on the study
process. Requests for data pertaining to the modeling and evaluation of the transmission system
were made by the Transmission Provider. Additional stakeholder meetings were held on June 13,
2014, September 25, 2014, and December 17, 2014. All meeting notices were distributed via email
and posted along with presentation materials in the ‘Transmission Planning’ folder on the Common
Use System/BHBE OASIS page at http://www.oatioasis.com/BHBE.
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
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Figure 1: Existing Common Use Transmission System
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
7
2. Study Methodology
The Common Use transmission system was evaluated with planned system additions for 2019
under both peak winter and off-peak winter load levels to identify any deficiencies in system
performance. Steady state voltage and thermal analyses, as well as transient and voltage stability
analysis was performed. Additional upgrades were identified and modeled as necessary to mitigate
any reliability criteria violations. The steady-state portion of the analysis was repeated for the 2025
peak summer load scenario to validate any upgrades identified in the near-term study as well as
assess the long-term integrity of the transmission system. A list of prior and forced outages used in
the 2014 LTP study process was included in Appendix A.
2.1.
Study Criteria
The criteria used in this analysis are consistent with the NERC TPL Reliability Standards, the
WECC System Performance Regional Criterion (TPL-001-WECC-CRT-2.1) and Colorado
Coordinated Planning Group’s Voltage Coordination Guide. Pre-existing voltage and thermal
loading violations outside the localized study area were ignored during the evaluation. Worst-case
Category D outages were evaluated in the 2019HW and LW scenarios for risk and consequence.
2.1.1. Steady State Voltage Criteria
Under system intact conditions (NERC/WECC Category A), steady state bus voltages must remain
between 0.95 and 1.05 per unit. Following a NERC/WECC Category B or C contingency, bus
voltages must remain between 0.90 and 1.10 per unit.
2.1.2. Steady State Thermal Criteria
All line and transformer loading must be less than 100% of their established continuous rating for
system normal conditions (NERC/WECC Category A). All line and transformer loadings must be
less than 100% of their established continuous or emergency rating under outage conditions
(NERC/WECC Category B and C).
2.1.3. Transient Voltage and Frequency Criteria
NERC Standards require that the system remain stable and within applicable thermal ratings and
voltage limits for Category A, B, and C disturbances. The WECC Disturbance – Performance
Table of Allowable Effects on Other Systems states the following requirements:
•
Category B: Any transient voltage dip must not exceed 25% at load buses or 30% at nonload buses. The dip also must not exceed 20% for more than 20 cycles at load buses.
Frequency must not drop below 59.6 Hz for 6 or more cycles at a load bus, including
generation station service load.
• Category C: Any transient voltage dip must not exceed 30% at load buses or 30% at nonload buses. The dip also must not exceed 20% for more than 40 cycles at load buses.
Frequency must not drop below 59.0 Hz for 6 or more cycles at a load bus, including station
service load.
Based in part on the NERC/WECC requirements, the following criteria were used to determine
acceptable transient system performance:
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
8
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All machines in the system shall remain in synchronism as demonstrated by their relative
rotor angles.
System stability is evaluated based on the damping of the relative rotor angles and the
damping of the voltage magnitude swings.
For central, northern and eastern Wyoming and western South Dakota, the following
dynamic stability guidelines have been established: Following a single contingency
disturbance with normal fault clearing, the transient bus voltage swing on all buses should
not be lower than 0.70 per unit, and the system should exhibit positive damping.
The frequency criteria specified in Table W-1 of the WECC Disturbance-Performance
Table of Allowable Effects on Other Systems was utilized for the analysis. However, CUS
transmission providers and neighboring transmission providers may adopt a less stringent
requirement than the NERC/WECC Planning Standard. See Section 4.1.3 for details
regarding this proposed change.
2.1.4. Cascading
NERC Standards require that the system remain stable and no Cascading occurs for Category A, B,
and C disturbances. Cascading is defined in the NERC Glossary as “The uncontrolled successive
loss of system elements triggered by an incident at any location. Cascading…… cannot be
restrained from sequentially spreading beyond an area predetermined by studies.” A potential
triggering event for Cascading will be investigated upon one of the following results:
•
•
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2.2.
A generator pulls out of synchronism in transient stability simulations. Loss of synchronism
occurs when a rotor angle swing is greater than 180 degrees. Rotor angle swings greater
than 180 degrees may also be the result of a generator becoming disconnected from the
BES; or
A transmission element experiences thermal overload and the minimum transmission relay
load-ability threshold is exceeded. Thermal overloads of greater than 130% will be further
investigated to determine the risk of Cascading by manually removing those facilities in
sequence until the outage is contained or Cascading is confirmed.
Negative margin occurs in voltage stability simulations.
Study Area
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
9
The 2014 LTP study area will include all CUS transmission equipment as well as neighboring
transmission system elements bound by TOT4B to the northwest, TOT4A to the southwest, Dave
Johnston and Stegall to the south, and Rapid City to the east. Points of interconnection between the
CUS and neighboring utilities are shown in Table 1.
Table 1: CUS Interconnection Points
Interconnecting Utility 1
City of Sheridan, PAC
PAC
PAC
PAC
PAC
WAPA-RMR, PAC, MBPP
WAPA-RMR, MBPP
WAPA-UGPR
Interconnection Name
Sheridan
Carr Draw
Wyodak
Antelope
Windstar
Dave Johnston
Stegall
Rapid City DC Tie
2.3.
Study Case Development
The baseline cases for the 2014 LTP Study were chosen to ensure that a range of forecasted CUS
demand levels and critical conditions were analyzed. They were also chosen based upon
availability of updated regional study cases, planned transmission system and resource upgrades,
and previously completed planning studies. A complete list of individual case changes for each
scenario is available upon request.
2.3.1. 2019 Heavy Winter and Light Winter Study Cases
The 2019 heavy winter scenario was chosen for the near-term analysis. The winter demand levels
have historically been the most critical of the seasonal load patterns in some of the study areas as
compared to summer demand levels which studied in the 2013 study cycle. The case originated as
the 2019HW CCPG case.
The 2019 light winter scenario was chosen to allow for an assessment of the light end of demand
levels within the CUS at the latter end of the near-term study time frame. The starting case was the
2019LW CCPG case.
Updates to the case loads, resources, and topology were solicited from TCPC members as well as
neighboring systems and applied to the models.
Significant changes to the existing 2014 Common Use transmission system to create the 2019
models included:
1
PAC means PacifiCorp; WAPA means Western Area Power Administration; MBPP means Missouri Basin Power
Project
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
10
•
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•
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addition of the planned Teckla-Osage-Lange 230 kV line
retirement of the Osage power plant
retirement of the Ben French power plant
retirement of the NSS1 power plant
addition of the Cheyenne Prairie Generation Station
addition of a second 230/69kV transformer at Yellow Creek
addition of the Bill Durfee substation
2.3.2. 2025 Heavy Summer Study Case
The 2025 heavy summer time scenario was chosen to allow for an assessment of the peak demand
level within the CUS in the far-term study time frame. The starting case was the DEEP (Douglas,
Elbert, El Paso, and Pueblo Counties) 25HS base case. As with the 2019 cases, current load and
resource forecasts were modeled, as well as expected system topology for that time frame. There
was no major transmission system projects modeled in addition to those included in the 2019
scenarios.
2.4.
Transmission Planning Assumptions
The 2014 LTP study was performed for both the 5 and 10-year time frames with the following
assumptions:
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•
•
All existing and planned facilities and the effects of control devices and protection systems
were accurately represented in the system model.
All normal CUS Operational Procedures were included in the system model.
Projected firm transfers were represented per load and resource updates from each
stakeholder.
Existing and planned reactive power resources were modeled to ensure adequate system
performance.
There were no specific planned outages identified for the 2019 and 2025 study periods. A
series of prior and forced outages on facilities deemed to be most critical by the
transmission planner was simulated to identify potential risks associated with such outages
in the study time frame. A list of the evaluated prior and forced outages is included in
Appendix A.
For system intact solutions, transformer taps and switched shunts were allowed to adjust.
Following a contingency, adjustment of these devices was disabled unless designed to allow
such operation. For all solutions, area interchange control and phase shifter adjustments
were disabled, while DC tap adjustment was enabled. A fixed slope decoupled Newton
solution method was utilized through the analysis.
System load and generation dispatch assumptions are included in Appendix B.
3. Evaluation of the Common Use Transmission System
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
11
3.1.
Steady-State Analysis
The steady-state analysis was performed with several case options for each load scenario. The first
option allowed for various prior outages to be applied to the study case. The second option altered
the flow across the Rapid City DC Tie to reflect maximum bi-directional transfers as well as the
zero-transfer condition. The third option changed the status of the normal-open points on the Black
Hills 69 kV system from open to closed. This was done to represent the existing operating practice
of closing the normal-open points for certain prior outages. Study case designations were formatted
according to the selected options as shown in Table 2.
Table 2: Study Case Naming Convention
Prior Outage_RCDC Tie_69kV Configuration
Prior Outages:
See Appendix A
RCDC Tie Transfers:
0E-W
200E-W
200W-E
RCDC Tie blocked
200 MW east-to-west
200 MW west-to-east
RADIAL
69TIED
Black Hills N.O. Points Open
Black Hills N.O. Points Closed
69 kV Configuration:
This LTP study was not performed to define RCDC RAS Runback procedures, and any violations
mitigated through operation of the existing RAS were not included in the results summary.
Simulations of the N-0 (Category A) and N-1 (Category B) contingencies did not identify any
criteria violations in the scenarios studied.
3.1.1. Wyodak 230/69kV Transformer Overload
The Wyodak 230/69 kV transformer loaded to 146% of the 100 MVA continuous rating following
the N-1-1 loss of the other 100 MVA Wyodak 230/69 kV transformer and the NSS2 plant in the
19HW timeframe. It also overloaded to 107% in the 19LW and 125% in the 25HS timeframes
following the same contingency as the 19HW. This overload was seen in previous studies due to
the retirement of the NSS1 power plant. A separate study to evaluate solutions to this overload was
initiated in 2014.
3.1.2. Osage 230/69kV Transformer Overload
The Osage 230/69 kV transformer loaded to 122% of the 70 MVA continuous rating following the
N-1-1 loss of the Hughes 230/69 kV transformer and the Wyodak-Hughes 69 kV line in the 19HW
timeframe. The overload was not observed in the 19LW or 25HS timeframe and is dependent on
system configuration. A separate study in 2015 will be conducted to address this overload.
_________________________________________________________________________________________________________________
Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
12
3.1.3. West Hill-South Rapid 230kV Line Overload
The West Hill-South Rapid 230kV line loaded to 117% of its 318 MVA continuous rating
following the N-1-1 loss of the Osage-Lange 230kV line and the Lookout-Lange 230kV lines in the
19HW timeframe. It also overloaded in the 25HS timeframe to 126%. The overload only occurs
when the RCDC tie is flowing 200 MW west-to-east. The overload can be mitigated through
RCDC Tie RAS runbacks and/or dispatching must-run generation in Rapid City.
3.1.4. Lange-Lookout 230kV Line Overload
The Lange-Lookout 230kV line loaded to 124% of its 318 MVA continuous rating following the
N-1-1 loss of the West Hill-South Rapid 230kV line and the Osage-Lange 230kV lines in the 25HS
timeframe. The overload only occurs when the RCDC tie is flowing 200 MW west-to-east. The
overload can be mitigated through RCDC Tie RAS runbacks and/or dispatching must-run
generation in Rapid City.
3.1.5. Rapid City 230/69 kV Transformation Overloads
The South Rapid and Lange 230/69 kV transformers both experienced overloads in the scenarios
studied. The South Rapid transformer (150 MVA) overloaded to 102% in the 19HW and 107% in
the 25HS timeframes which was the result of the N-1-1 contingency of both 230/69 kV Lange
transformers. The Lange transformer #1 (100MVA) overloaded to 120% in the 19LW, 152% in
the 19HW, and 165% in the 25HS timeframes following the N-1-1 contingency of the 230/69 kV
Lange transformer #2 and the Lange-South Rapid 230 kV line. Similarly, the Lange transformer
#2 (150MVA) overloaded to 102% in the 19HW and 107% in the 25HS timeframes following the
N-1-1 contingency of the 230/69 kV Lange transformer #1 and the Lange-South Rapid 230 kV line.
3.1.6. Yellow Creek 230/69 kV Transformation Overloads
There was no significant need identified for the second Yellow Creek transformer in the 19HW and
LW timeframe. This is attributed to light winter loading in the northern hills area, which is
typically a summer peaking load area. However, there was a need for the second Yellow Creek
transformer in the 25HS timeframe due to the N-1-1 contingency of both Lookout 230/69 kV
transformers.
3.2.
Category D Extreme Outage Analysis
Several significant steady-state Category D outages were selected to identify the impacts of each
outage on the transmission system. The outages were selected from all valid Category D events
based on past study results and working understanding of the criticality of the associated system
elements. Bus outages were simulated by disconnecting the bus and all associated network
elements at the each of the non-radial CUS 230 kV substations. A summary of consequential load
and generation loss for each outage in the 2019HW scenario is shown in Table 3 and a summary
for the 2019LW scenario is shown in Table 4. The scenario with the 69 kV system normal-open
points closed was summarized below since it minimized the amount of consequential load loss over
a radial system configuration. The steady-state analysis did not have evidence of instability or
cascading following the Category D contingencies.
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
13
Table 3: 2019HW Category D Outage Summary
Bus Outage
1_Lange 230 Bus
2_Lookout 230 Bus
3_S Rapid City 230 Bus
4_Westhill 230 Bus
5_Minnekhata 230 Bus
6_Yellowcreek 230 Bus
7_Osage 230 Bus
8_Hughes 230 Bus
9_Wyodak 230 Bus
10_Dry Fork 230 Bus
11_Donkey Creek 230 Bus
12_Carr Draw 230 Bus
13_Barber Creek 230 Bus
14_Pumpkin Buttes 230 Bus
15_Teckla 230 Bus
16_Reno 230 Bus
17_Leiter Tap 230 Bus
18_Tongue River 230 Bus
19_Sundance 230 Bus
Consequential Load Loss
42 MW (Station Service)
35 MW (Station Service)
26 MW (Station Service)
10.3 MW
50 MW
27 MW
66 MW
80 MW
2.1 MW
19 MW
-
Consequential Gen Loss
RCDC Tie Transfer
375 MW
420 MW
303 MW
-
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
14
Table 4: 2019LW Category D Outage Summary
Bus Outage
1_Lange 230 Bus
2_Lookout 230 Bus
3_S Rapid City 230 Bus
4_Westhill 230 Bus
5_Minnekhata 230 Bus
6_Yellowcreek 230 Bus
7_Osage 230 Bus
8_Hughes 230 Bus
9_Wyodak 230 Bus
10_Dry Fork 230 Bus
11_Donkey Creek 230 Bus
12_Carr Draw 230 Bus
13_Barber Creek 230 Bus
14_Pumpkin Buttes 230 Bus
15_Teckla 230 Bus
16_Reno 230 Bus
17_Leiter Tap 230 Bus
18_Tongue River 230 Bus
19_Sundance 230 Bus
Consequential Load Loss
42 MW (Station Service)
35 MW (Station Service)
26 MW (Station Service)
6 MW
30 MW
16 MW
39 MW
48 MW
1.3 MW
12 MW
-
Consequential Gen Loss
RCDC Tie Transfer
375 MW
300 MW
303 MW
-
The dynamic analysis was performed only for the 2019HW and LW scenarios and had the RCDC
Tie transfers of 0MW and 200 MW in both direction and the 69 kV normal-open points both closed
and open. The Category D events listed in Table 3 and Table 4 were previously evaluated by
modeling a 3-phase 5-cycle fault at the appropriate bus before clearing the bus in past studies.
However, considering the impacts of a Category D stuck-breaker contingency, it was decided to
simulate a 15-cycle stuck-breaker contingency on the buses in Table 3 and 4 since this was more
severe. The results were more severe by observing instability on the Wyodak area generators
following a 3-phase stuck-breaker on 230 kV substations adjacent to the Wyodak and Donkey
Creek substations. Since the 3-phase stuck breaker resulted in instability, single phase stuckbreaker events were also simulated on the same buses. All of the single-phase stuck-breaker
contingencies were simulated without instability or cascading. Other than the afore mentioned
instability issues there was no evidence of cascading in the 2019HW and LW scenarios during the
Category D transient stability outage analysis.
3.3.
Transient Stability Analysis
Transient analysis was performed to evaluate the dynamic characteristics of the transmission
system in proximity to the CUS footprint following various disturbances. With the exception of
Powder River Energy Corp. loads, system loads were modeled using the WECC generic motor load
at a penetration of 20 percent, with the under voltage load shedding function disabled to provide a
worst-case representation of system performance. The non-coal bed methane (“CBM”) PRECorp
loads were modeled as 30 percent motor load and the CBM loads were modeled as 80 percent
motor load.
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
15
The 2019HW and LW scenarios that were evaluated included RCDC Tie transfers of 0 MW and
200 MW in both directions and the 69 kV normal-open points were both closed and open. The
critical outage combinations evaluated in the transient analysis were selected based on significance
with respect to proximity to local generation, clearing of a CUS tie line, or performance during
steady state analysis. The 3-phase faults listed in Table 5 were simulated for the 2019HW and LW
system intact scenarios.
For each ten second simulation, plots including bus voltages and generator rotor angles at various
points on the transmission system were created, as well as simulation summary reports. Due to the
large quantity of files created, they are not included in this report but are available upon request.
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
16
Table 5: Transient Stability Analysis Fault Summary
Fault Type
Faulted Bus
(230 kV)
Cleared Element
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
3Φ
None
Carr Draw
Osage
Minnekahta
West Hill
Donkey Creek
Donkey Creek
Donkey Creek
Dryfork
Dryfork
Dryfork
Dryfork
South Rapid City
Reno
Windstar
Wyodak
Wyodak
Wyodak
Wyodak
Wyodak
Osage
Wyodak
Teckla
Lookout
Lookout
Lange
Lange
None
Carr Draw-Buffalo 230
Minnekahta-Osage 230
Minnekahta-West Hill 230
West Hill-Stegall 230
Donkey Creek-Pumpkin Buttes 230
Donkey Creek-Reno 230
Donkey Creek-Wyodak 230
Dry Fork-Carr Draw 230
Dry Fork Plant
Dry Fork-Hughes 230
Dry Fork-Tongue River 230
South Rapid City-Westhill 230
Reno-Donkey Creek 230
Windstar-P. Buttes 230 & Windstar-Teckla 230
Wyodak-Carr Draw 230
Wyodak-Donkey Creek 230
Wyodak-Hughes 230
Wyodak-Osage 230
Wyodak Plant
Osage-Lange 230
Wyodak-Osage 230
Teckla-Osage 230
Sundance-Hughes 230
Lookout-Sundance 230
Lange-South Rapid City 230
Lange-Lookout 230
Fault
Duration
(cycles)
N/A
4.25
4.25
4.25
4.25
3.5
4.25
4.25
4.25
3.5
4.25
4.25
4.25
4.25
5.0
4.25
4.25
4.25
4.25
4.25
5.0
5.0
4.25
5.0
5.0
5.0
5.0
3.3.1. 2019HW Transient Stability Results
Post-contingent frequency criteria violations occurred at the Wygen1-3, NSS CT 1-2 and NSS2
13.8 kV terminal buses following 3-phase N-1 faults at the Wyodak, Donkey Creek, and Hughes
230 kV buses. The worst-case frequency dip for the 2018HW scenario occurred at the NSS2 13.8
kV bus following a 3-phase fault at the Wyodak 230 kV bus and the loss of the Wyodak-Osage 230
kV line. The frequency reached a minimum of 59.1 HZ and remained below the 59.6 HZ threshold
for 13.2 cycles.
With the exception of the single issue mentioned above, all dynamic simulations resulted in
acceptable results for each evaluated study scenario. There were no additional post-contingent
voltage or frequency criteria violations, and all system oscillations were adequately damped.
3.3.2. 2019LW Transient Stability Results
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
17
The 2019LW results were consistent with the 2019HW results, with the exception of the worst-case
frequency dip reaching 59.3 HZ and remaining below the 59.6 HZ threshold for 13.8 cycles instead
of the 19HW 13.2 cycles.
With the exception of the single issue mentioned above, all dynamic simulations resulted in
acceptable results for each evaluated study scenario. There were no additional post-contingent
voltage or frequency criteria violations, and all system oscillations were adequately damped.
3.4.
Results Summary
All evaluated scenarios confirmed a known issue of N-1 frequency dips below the 59.6 HZ
threshold for a period longer than 6 cycles at generator terminal buses in the Wyodak area. This
issue has been discussed with the affected parties, and they understand there is no risk of underfrequency load shedding action related to the phenomenon. It is expected that an exemption to the
System Performance TPL-001-WECC-CRT-2.1 Regional Criterion will be finalized and adopted in
the near future. The exemption will be crafted to accommodate the system performance through
the 10-year planning horizon without impacting existing protection settings in the affected area.
The addition of a second transformer at the Yellow Creek 230/69 kV substation proved to be
effective in mitigating the N-1-1 overloads on the Lookout 230/69 kV transformers in summer
loading, and should continue as planned.
Overloads on the South Rapid-West Hill and Lookout-Lange 230kV lines were identified along
with the Lange and South Rapid 230/69 kV transformers was as an issue. All of the overloads can
be was mitigated by dispatching Rapid City gas-fired generation. The 230kV line overloads can
also be mitigated by a runback of the RCDC tie. It is recommended that Rapid City load growth
continue to be monitored closely to avoid future transformer overloads.
The planned rebuild of the South Rapid-West Hill 230 kV line in 2019 should continue as planned
and the CT limitation on the Lookout-Lange 230 kV line should be removed. It should also be
considered to add the contingencies that cause these 230 kV overloads to the new RCDC tie RAS
since the overloads occur when the tie is flowing 200 MW W-E.
The Osage 230/69 kV transformer overloaded the 70 MVA continuous rating following the N-1-1
loss of the Hughes 230/69 kV transformer and the Wyodak-Hughes 69 kV line in the 19HW
timeframe. The overload was not observed in the 19LW or 25HS timeframe and is dependent on
system configuration. A separate study in 2015 will be conducted to address this overload.
The Wyodak 230/69 kV transformer exceeded the 100 MVA continuous rating following the N-1-1
loss of the other Wyodak 100 MVA transformer and the NSS2 plant in multiple scenarios. This
overload was seen in previous studies. A separate study to evaluate solutions to this overload was
initiated in 2014.
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
18
Instability was identified following certain Category D, stuck-breaker contingencies on Wyodak
area generators. It is recommended that out-of-step relaying be implemented at the affected plants,
and will be discussed further with affected parties.
4. Transmission System Expansion
4.1.
Previously Identified/Existing Projects
The following projects have been previously identified and are currently planned projects for the
CUS 230 kV transmission or 69 kV sub-transmission system.
4.1.1. Yellow Creek 230/69 kV 150 MVA Transformer (BHP)
The addition of a Yellow Creek 150 MVA transformer is currently in the Strategic Plan for 2018.
The estimated cost of the Yellow Creek transformer is $3,538,817 and will take approximately 1824 months to complete.
4.1.2. Exemption from NERC/WECC Regional Criterion (BHP/BEPC)
CUS members and neighboring utilities are developing an agreement for an exemption from the
WECC Disturbance-Performance Table (Table W-1) of Allowable Effects on Other Systems as it
pertains to minimum frequency dips following a Category B event. The stated exemption will
make current system performance acceptable and will nullify performance criteria violations. It is
expected that the agreement will be enacted and submitted to WECC in 2015.
4.2.
Recommended Projects
The following transmission projects are recommended for possible future inclusion in the BHBE
LTP. Further analysis of the expected load growth and completion of other system upgrades is
necessary to confirm the need and expected in-service date of these projects.
4.2.1. Additional Wyodak-Area Transformation Capacity (BHP)
Several scenarios identified insufficient transformation capacity to serve the Wyodak-area 69 kV
load following a single N-1-1 outage. The retirement of NSS1 has compounded this issue and
should be addressed in the near term. Options for additional transformation capacity in the area are
being considered among affected parties.
4.2.2. Additional Osage-Area Transformation Capacity (BHP)
The 19HW scenario identified insufficient transformation capacity to serve the Osage-area 69 kV
load following a single N-1-1 outage. Options for additional transformation capacity in the area are
being considered, and a dedicated study effort will commence in 2015.
4.2.3. South Rapid – West Hill 230 kV Line Rebuild (BHP)
Several scenarios identified overloads on the South Rapid-West Hill 230 kV line following a single
N-1-1 outage. The overload only occurs when the RCDC Tie is flowing 200 MW west-east and
can be mitigated by a runback to 0 MW or Rapid City generation. The line is tentatively scheduled
to be rebuilt in 2019 due to age of the line, and should continue as planned.
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
19
4.2.4. RCDC Tie Runback (BHP)
As identified in 4.2.3 the South Rapid-West Hill 230 kV line overloads following a single N-1-1
outage with the RCDC Tie flowing 200 MW west-east. The identified runback contingency should
be added to the new RAS that was studied by BEPC on 12/30/2013.
4.2.5. Wyodak-Area Generator Out-of-Step Protection (BHP)
Instability was identified following certain Category D, stuck-breaker contingencies on Wyodakarea generators. It is recommended that out-of-step relaying be implemented at Neil Simpson II,
WyGens I-III, and the Neil Simpson CTs, and will be discussed further with affected parties.
5. Conclusions
An open and transparent process was utilized in conducting the 2014 Local Transmission Plan
study. Stakeholders were provided several opportunities for involvement and input into the study
process and scope. Through this process, the TCPC participants believe they have fulfilled the
requirements of Attachment K to the Joint Open Access Transmission Tariff (JOATT).
A review of expected load growth and planned resource development should continue to be
incorporated in the development of the next ten-year LTP.
Solutions for the Wyodak and Osage area transformer overloads will continue to be addressed
through continued coordination with affected stakeholders in 2015.
Also, the critical nature of the loss of a 230/69 kV transformer on the CUS system, in conjunction
with the considerable lead time necessary to replace one, should instigate a discussion on the
philosophy of maintaining a spare transformer.
Assessment of the identified system enhancements will continue through additional transmission
planning studies and the next TCPC study cycle. Active stakeholder involvement will be a key
component as the process continues. This will ensure the CUS will effectively meet the long-term
requirements for all transmission customers.
All identified violations of NERC and WECC TPL criteria were accompanied by a suggested
mitigation plan, including estimated cost and implementation schedule when available. It was
determined that this analysis satisfied the requirement of the TPL-001 through 004 Standards for
CUS transmission providers.
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
20
Appendix A
Prior and Forced Outage Lists
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
A-1
Steady-State Prior Outages
LABEL
SYSINT
230-1
230-2
230-3
230-4
230-5
230-6
230-7
230-8
230-9
230-10
230-11
230-12
230-13
230-14
230-15
230-16
230-17
230-18
230-19
230-20
230-21
230-22
230-23
230-24
230-25
230-26
230-27
230-28
230-29
230-30
230-31
230-32
230-33
230-34
230-35
230-37
230-38
230-39
230-40
PO 230 SERIES
DESCRIPTION
System Intact
Goose Crk-Sheridan
Buffalo-Sheridan
Buffalo-Kaycee
Casper-Claimjpr
Casper-DJ
Sheridan-T. River
T. River-Arvada
Arvada-Dryfork
Dryfork-Carr Draw
Dryfork-Hughes
Buffalo-Carr Draw
Wyodak-Carr Draw
Carr Draw-Barber Creek
Barber Creek-PButtes
Windstar-PButtes
PButtes-Teckla
Teckla-Antelope
Yellowcake-Windstar
Windstar-Dave Johnston
Windstar-Aeolus
Teckla-Osage
Osage-Lange
Reno-Teckla
Donkey Creek-Reno
Donkey Creek-Pumpkin
Wyodak-Donkey Creek #1
Wyodak-Osage
Wyodak-Hughes
Hughes-Sundance
Yellow Creek-Osage
Lookout-Yellow Creek
Osage-Minnekhata
Westhill-Minnekhata
Lange-Lookout
Lange-South Rapid City
South Rapid City-Westhill
RCDCW-South Rapid
Westhill-Stegall
Sundance-Lookout
PO GEN SERIES
LABEL
DESCRIPTION
GEN-1 Wyodak Unit
GEN-2 Dryfork Unit
GEN-3 Wygen3 Unit
GEN-4 LRS Unit
GEN-5 DJ Unit #4
LABEL
XFMR-1
XFMR-2
XFMR-3
XFMR-4
XFMR-5
XFMR-6
XFMR-7
XFMR-8
XFMR-9
XFMR-10
XFMR-11
XFMR-12
XFMR-13
PO X SERIES
DESCRIPTION
Wyodak XFMR 1
Wyodak XFMR 2
Westhill XFMR
Osage XFMR
Hughes XFMR
Lange XFMR 1
Lange XFMR 2
Lookout XFMR 1
Lookout XFMR 2
Yellow Creek XFMR 1
South Rapid XFMR
Yellow Creek XFMR 2
Minnekhata XFMR
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
A-2
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
A-3
Appendix B
Load and Resource
Assumptions
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
B-1
Table B1: Load and Resource Assumptions
BUS #
GENERATOR
NAME
GROSS GENERATOR OUTPUT
(MW)
2019HW
2019LW 2025HS
66730
WYODAK
375
375
377
73289
RCCT1
17
0
12
73291
RCCT2
9
0
12
73292
RCCT3
0
0
12
73293
RCCT4
0
0
11
73341
NSS2
93
93
90
73520
BFDIESEL
0
0
0
74014
NSS_CT1
0
0
40
74015
NSS_CT2
0
0
40
74016
WYGEN
93
93
90
74017
WYGEN2
100
100
100
74018
WYGEN3
110
110
110
74029
LNG_CT1
40
0
40
74060
CPGSTN
180
30
180
76301
ARVADA1
0
0
0
76302
ARVADA2
0
0
0
76303
ARVADA3
0
0
0
76305
BARBERC1
0
0
0
76306
BARBERC2
0
0
0
76307
BARBERC3
0
0
0
76309
HARTZOG1
0
0
0
76310
HARTZOG2
0
0
0
76311
HARTZOG3
0
0
0
76404
DRYFORK
420
300
420
76502
SPFSHPRK
0
0
0
1437
981
1101
625
1534
1092
TOTAL CUS GENERATION:
TOTAL CUS LOAD + LOSSES:
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Common Use System:
Transmission Coordination and Planning Committee
2014 Local Transmission Plan
January 30, 2015
B-2