Big Horn Basin Area Study Solutions to Voltage and Thermal Issues January 21, 2014 Studied by Susan Franklin With assistance by Nathan Peters Table of Contents
I.
Executive Summary ..................................................................................................................................................... 3
II.
Study Criteria............................................................................................................................................................... 5
III.
The Big Horn Basin Area 69 kV System ................................................................................................................... 7
IV.
The 115 & 230 kV Big Horn Basin Area System..................................................................................................... 10
V.
Recommendation Summary ..................................................................................................................................... 13
VI.
Cost Estimates ....................................................................................................................................................... 14
Appendices as separate documents:
Appendix A-1 YTS 625 MW
Appendix A-2 YTS 700 MW
Appendix B 69 kV Study Results Table
Appendix C Transmission Results Summary Table
Appendix D Load Growth
Appendix E-1 YTS 625 MATSUM2 Output
Appendix E-2 YTS 700 MATSUM2 Output
Appendix F Matout Contingency List
Appendix G Table 1 Transmission Standards
Appendix H YTS 700 w Garrison Reactors
I.
Executive Summary
This study will provide a comprehensive solution for the 69 and 115 kV issues in the Big Horn Basin area, address
limitations on the Yellowtail South (YTS) path, and provide system improvements required to support the planned YTS
increase to 700 MW, North to South. The YTS is a jointly owned path, currently rated at 625 MW North to South, with
Western Area Power Administration (Western) and PacifiCorp(PACE) sharing allocation. This is not a WECC rated path.
The YTS path is within the Big Horn Basin Area, which has dated infrastructure with significant hydro-generation on the
69 kV, 115 kV, and 230 kV systems. Figure 1 below shows the Big Horn Basin Area electrical system and the YTS cut
plane.
Figure 1
Western owns the majority of the 115 and 69 kV systems while PACE owns most of the 230 kV system in the basin. The
69 kV system between Big George and Lovell substations has been plagued with reliability issues resulting in long
duration winter outages due to condition of facilities and operational inflexibility, constrained by voltage and thermal
limitations. The 115 kV system has construction projects in progress to increase YTS to 700 MW and mitigate N-1
contingencies that cause thermal loading on the 115 kV system. The YTS path and WECC Path 80 Montana Southeast
southbound ratings have been limited by the worst case outage of the Yellowtail PACE (PY)-Yellowtail Western (YT) 230
kV tie line, with the most limiting element being the Lovell (LV)-Nahne Jensen (NJ)-Basin (BA) 115 kV line. This line has
been a thermal limiting element in the last four cycles of Western’s internal Annual Network Integration Transmission
(NIT) Study, and has also been the limiting element in YTS Prior Outage Studies. As a credible N-1 issue and a
component of the increase of YTS to 700 MW, Western’s Capital Investment Plan (CIP) has included and funded the
reconductor of the LV-NJ-BA 115 kV line, in addition to the LV-YT 115 kV #1 & #2 Rebuild project, necessary for the YTS
increase.
In addition to the existing 115 kV projects, this study provided the recommendation to reconductor the Basin-Worland
Tap (WRD) 115 kV line. This is an expected continuation of the reconductor project for the LV-NJ-BA 115 kV line. It has
been seen in previous studies that as load growth occurs in the Big Horn Basin area, the loading on the BA-WRD 115 kV
line has been incrementally increasing. This study resulted in the first exceedance of the line’s normal/thermal rating for
the worst case outage of the YT-PY 230 kV tie line for YTS at 625 and 700 MW.
The Big Horn Basin area has load growth ranging from 1-4% over the next ten-year period. The generation in the basin is
hydro-generation, which has experienced drought conditions in recent years resulting in minimal generation. This
combination of load growth and low generation results in forecasted loading exceeding the system capacity on the 69 kV
system for the loss of either the Lovell or Big George 115/69 kV transformers, and may require up to 17 MW load to be
shed. In order to mitigate the capacity issues, this study recommended an additional 69 kV source be added to the Big
Horn Basin system to mitigate the thermal, voltage, load shedding, and post-contingent voltage deviation issues that
occur with N-1 contingencies. The proposed North Cody (NC) 115/69 kV substation and the Big George-North Cody 115
kV line provide the capacity for the long term, while increasing the reliability and operational flexibility of the 69 kV
system.
In addition to the capacity issue, the 69 kV system between Lovell and Big George has frequently experienced voltages
greater than 1.05 pu. These voltage events can be attributed to the combination of the tap settings on the 115/69 kV
transformers that source the area, the variability of the 69 kV generation, and the load profile of primarily residential
load. Changing the tap settings to nominal will lower system voltages to less than 1.05 pu, however, the higher voltages
are needed during minimum generation and peak load scenarios in preparation for contingencies. This dilemma of
needing the voltage support and exceeding the standard voltage criteria at the Lovell 69 kV bus resulted in this study’s
recommendation to set a voltage System Operating Limit (SOL) on the Lovell 69 kV bus at 1.06 pu and maintain the
current tap settings at Lovell. Utilizing the Big George 115/69 kV transformer as a Load Tap Changing transformer (LTC)
improves the 69 kV voltages up to 17% post contingent and provides effective voltage control for the Big George 69 kV
bus, which also exceeded 1.05 pu with less frequency than LV. While the LTC had minimal impact on the Lovell 69 kV
bus for system in-tact, it provided immediate relief for voltage control on the Big George 69 kV bus, voltage support
during contingencies, and reduced post-contingent voltage deviations. This study recommends operating the Big
George 115/69 kV transformer as an LTC until the North Cody 115/69 kV substation is constructed and in-service.
Operating YTS at 700 MW depends solely on the re-conductor projects currently in progress, the LV-YT #1 & #2 115 kV
Line Rebuild and LV-NJ-BA 115 kV Line Re-conductor Projects, and the newly recommended BA-WRD 115 kV Line Reconductor Project. The rebuild and reconductor of these lines mitigate the thermal issues seen during N-1
contingencies; however additional voltage support was required. This study recommends the placement of a 55 MVAR
capacitor bank at the Yellowtail 115 kV substation and a 15 MVAR capacitor bank at the Nahne Jensen 115 kV
substation.
II.
Study Criteria
•
2013-14 HW Western Electricity Coordinating Council (WECC) Base Case: Reviewed by Rocky Mountain
Operational Study Group (RMOSG) of which the interconnected utilities, Tri-State Generation and Transmission
(TSGT) and PACE are members. Updates include:
o
Transformer tap settings on the BGG 115/69 kV, LV 115/69 kV, YT 230/115 kV transformers.
o
Generation step up transformer settings and generation bus voltage targets at Buffalo Bill, Spirit
Mountain, Shoshone, and Heart Mountain substations.
o
Generation levels at Buffalo Bill, Spirit Mountain, Shoshone, and Heart Mountain plants.
o
Load errors: removal of PACE load on the Nahne Jensen 115 kV bus and removal of Western load from
Thermopolis and Jim Ready 115 kV buses.
o
PACE Oregon Basin 230/69 kV transformer replacement.
o
YT-LV 115 kV #1 & #2, LV-NJ 115 kV, BGG-GDT 69 kV line ratings.
o
PACE Thermopolis-Hilltop 115 kV line rating.
•
Post-Contingent Voltage Deviation: Western does not have an official exception in the study area filed with
WECC, however, the interconnected utilities in the area have listed an acceptable post-contingent voltage
deviation up to 7% as acceptable; Western will accommodate the interconnected utilities’ exceptions by
providing mitigation only where the post-contingent voltage deviation exceeds 7%.
•
NERC TPL Standards, see Table 1 in Appendix G.
•
Voltage: For System in-tact, the 69, 115, and 230 kV has an acceptable range of 0.95 to 1.05 pu. Contingency
range is 0.90 to 1.10 pu. The exception is the 500 kV system in Montana, where the nominal voltage is 525 kV,
1.05 to 1.10 pu for system in-tact. Reactors not fully modeled at the Garrison 500 kV bus are utilized for
contingencies to maintain the 500 kV voltages below 550 kV, 1.10 pu; see Appendix H for reactor impact for
breaker to breaker outage.
•
Transformer Ratings: Western has a 30 minute emergency rating of 120% of the normal transformer rating. This
emergency rating provides 30 minutes for system operators to restore the system or make other system
adjustments to reduce the transformer loading to less than the normal rating.
•
Projects assumed completed in the 69 kV study:
o
LV-YT 115 kV #1 & #2 lines
o
LV-NJ-BA 115 kV Line Reconductor
•
Mobile Transformer: Western has a mobile 115/69 kV transformer, 40 MVA located at Cody, WY.
•
Capacitor Bank Switching: Capacitor bank switching will impact the bus voltage less than 3% per step.
•
Matrix: The Matrix program was utilized for analysis of outages and generation levels. The matout contingency
files for the 69 kV system study and the 115/230 kV system study is shown in Appendix F.
III.
The Big Horn Basin Area 69 kV System
Western’s 69 kV system is operated in parallel to the 115 kV system and has two 115/69 kV, 50 MVA transformers, one
each at Lovell and Big George substations, see Figure 2. Historically, the 69 kV system has experienced high voltages
and high voltage deviations for system in-tact and during normal switching operations. Prior studies with YTS stressed at
625 MW have reflected low 69 kV voltages for system in-tact and low 115 kV voltages with thermal overloads for the
loss of the PY-YT 230 kV tie line. This study identified and corrected modeling errors that had minimal impact on the 115
kV system and significant impact on the 69 kV system, resulting in a model that more closely aligned with real time
voltage issues.
The 69 kV system loads are offset by 30.5 MW maximum total hydro-generation with forecasted loads totaling 48.8 MW
(51.4 MVA) in the winter, and 54.1 MW (56.9 MVA) in the summer. The Big Horn Basin area has had pockets of load
growth up to 4%, see Appendix D for the load growth rates for areas in the basin. While the load has grown, the recent
ten year window has seen regional drought impacting generation patterns, with total generation on the 69 kV system as
meager as 1 MW, and instances of 0 MW of generation due to maintenance and repairs. The winter season typically has
minimal generation on two of the six units, one unit at Buffalo Bill and the lone Shoshone unit. The Heart Mountain and
Spirit Mountain generation units are “seasonal use” units utilizing irrigation, and do not operate in the winter. The
hydro-generation levels were studied at the minimum level of 1 MW and the maximum level of 30.5 MW, with peak
winter loads in a 2013-14 Heavy Winter WECC operating case.
Figure 2
When the 69 kV hydro-generation is at the minimum generation levels during winter, the 69 kV system is in a critical
operating condition, demonstrated when comparing the amount of load in MVA to the transformer capacity in MVA.
The forecasted load for both summer and winter peaks exceeds the normal rating of the LV and BGG transformer by 1.46.9 MVA. The permanent failure of a 115/69 kV transformer or 69 kV line at the Big George or Lovell source would
require load to be shed. This critical condition also limits the ability to remove 69 kV line sections from service for
maintenance, which is currently restricted to time frames of non-peak loading and/or generation levels greater than 5
MW.
Apart from the 115 and 230 kV contingencies that impact the 69 kV system, the loss of either LV or BGG 115/69 kV
transformer are the worst case outages for the 69 kV system. Due to extended replacement times required for a
permanent transformer failure, and the smaller size of the 115/69 kV mobile transformer (40 MVA), this study respected
the 50 MVA normal limit on the transformers and the 0.95 pu voltage limit for these worst case outages, rather than the
60 MVA emergency rating and a 0.90 pu bus voltage typically used for N-1 contingencies. The minimum generation
scenario modeling these worst case N-1 contingencies resulted in an overload on the remaining transformer 8-20 MVA
above the normal transformer rating at Big George and Lovell, post-contingent voltage deviations up to 37%, and low
voltages that would require 10-17 MW of load shedding, as shown in Table 1 below. See Appendix B for the full 69 kV
Study Results Table and Appendix E for the matsum2 files.
Table 1
YTS 625 MW, 1 MW Local Gen
Sampling of Lowest V in Contingency Scenario
Existing 69 kV System
Recond. LV-YTB 115 kV #1&#2
Reconductor LV-NJ-BA 115 kV line
N-0
N-1
N-1
N-1
N-1
N-1
N-1
N-1
SIT
GD-LV 69 kV line
GD-POT 69 kV line
BGG-GDT 69 kV line
HM-GDT 69 kV line
LV 115/69 kV Xfmr
BGG 115/69 kV Xfmr
BGG-NC 69 kV line
BGG 115/69 kV BGG-GDT 69
Xfmr 50/60
kV Line 59.7 LV 115/69 kV Xfmr LV-GD 69 kV
MVA
MVA
50/60 MVA
Line 60 MVA BGG
% of e rate
% of e rate
% of e rate
% e rate 115 kV
no problems
98% (59.1 MVA) 116.50%
0.834
0.877
117.2% (70.3 MVA)
123.00%
98% (58.8 MVA)
115%
0.839
116.9% (70.1 MVA)
122.60%
-
BGG
LV
NC
GD GDT POT MSS lowest Post-Contingent
69 kV 69 kV 69 kV 69 kV 69 kV 69 kV 115 kV gen bus V Deviation*
0.774
0.843
0.698 0.641 0.732 0.642 0.893 0.677 13.9.%<V<32.5%
0.788
0.812 0.745
0.759 9.5%<V<21.7%
0.61 0.749
0.709
0.579 5.7%<V<36.5%
0.895
5.4%<V<7.6%
0.782 0.655 0.709 0.655 0.742 0.656 0.897 0.687 23.3%<V<35.2%
0.607
0.613 0.751 0.607 0.712
0.582 5.8%<V<37.5%
0.863
delta V <7%
To solve the thermal and voltage limitations seen for the minimum generation scenario on the 69 kV system, several
options were considered:
•
Installation of a second 115/69 kV transformer, breakers, and bus work at Lovell and Big George substations.
BGG 2nd 115/69 kV transformer, 1-115 kV breaker/bay, 3-69 kV breakers/bays, bus
LV 2nd 115/69 kV transformer, 1-115 kV breaker/bay, 3-69 kV breakers/bays, bus
Total:
$3,600,000
$3,600,000
$7,200,000
•
Incrementally convert 69 kV substations and lines to 115 kV until the entire 69 kV system became a 115 kV loop.
It has been stated by Western’s preference customers that there is a desire to see the 69 kV system remain intact due to the costs to convert to 115 kV, eliminating the study of this option.
•
Tap PACE’s PY-OB 230 kV line for a new 230/69 kV substation:
•
New 230/69 kV substation, 50 MVA transformer 3-230 kV breakers, ring bus
New 69 kV transmission line-6 miles, 69 kV breaker/bay at NC
Transmission Service from PACE on their PY-OB 230 kV line, 15 MW
Total:
$9,900,000
$3,200,000
annual cost
$13,100,000
New BGG-NC 115 kV line, NC 115/69 kV substation
Add 2nd ckt from BGG-HM, convert HM-NC to 115 kV, BGG 115 kV breaker/bay
NC: 115/69 kV 50 MVA transformer, new 115 & 69 kV breaker/bay
Total:
$2,000,000
$2,100,000
$4,100,000
The least cost option utilizing Western’s existing facilities, a new BGG-NC 115 kV line and a 115/69 kV substation at
North Cody, was studied as a third 69 kV source for the area. The BGG-Heart Mountain (HM) 69 kV line has structures
and ROW designed for a double circuit 115 kV line, with one circuit available, providing the path for a 115 kV line to
enter the area. The HM-North Cody (NC) 69 kV line is built as a 115 kV line, operated at 69 kV, which, if converted to
115 kV, would provide the path to further extend a 115 kV line into the load area of the City of Cody. The NC substation
has adequate land to provide for a new 115/69 kV substation, 50 MVA transformer addition. This option was deemed
cost effective and increased reliability by providing a third 69 kV source. This option was studied and provided a long
term reliable solution and mitigates the thermal and voltage issues within the 69 kV system for YTS at 625 and 700 MW.
Figure 3 provides a detailed scope for the new 115 kV line and 115/69 kV substation.
Figure 3
Regarding the high voltages reported in the 115 kV and 69 kV system, the Big George and Lovell 115 kV buses were
identified as having infrequent high voltages, where the 69 kV system voltage at Heart Mountain, Lovell, and Big George
exceeded 1.05 pu 85-318 instances per year, with the Lovell 69 kV bus seeing the most instances of 318 in a year (R.
Gearhart, System Voltage Study). See Graph 1 below for one year of maximum daily voltages for BGG and LV.
Graph 1
Currently, both the Lovell and Big George transformers are boosting the 69 kV voltage by 2.5%, with Big George’s LTC
functionality bypassed. A short term option to assist in the mitigation of these high voltage issues is to operate the BGG
115/69 kV transformer as an LTC. The LTC has a range of +/- 9.25% for voltage control. As seen in Table 2, the postcontingent voltages improved by 2-17% for the selected outages, shown in yellow, with BGG enabled as an LTC. The
ability of the LTC to maintain higher voltages during the N-1 scenarios, also resulted in the Big George transformer
loading being reduced by 5 MVA and Big George-Glendale Tap 69 kV line loading reduced from 116% to 95%. The post
contingent voltage deviations were also reduced 5-16%, but remained above the accepted 7% level.
Table 2
YTS 625 MW, 1 MW Local Gen, BGG LTC
Existing 69 kV System
Reconductor LV-YTB 115 kV #1 & #2
Reconductor LV-NJ-BA 115 kV line
N-0
N-1
N-1
N-1
N-1
N-1
N-1
N-1
SIT
GD-LV 69 kV line
GD-POT 69 kV line
BGG-GDT 69 kV line
HM-GDT 69 kV line
LV 115/69 kV Xfmr
BGG 115/69 kV Xfmr
BGG-NC 69 kV line
BGG 115/69 kV BGG-GDT 69
Xfmr 50/60
kV Line 59.7
LV 115/69 kV
LV-GD 69 kV
MVA
MVA
Xfmr 50/60 MVA Line 60 MVA
% of e rate
% of e rate
% of e rate
% e rate
93% (54.2 MVA)
91% (54.4 MVA)
-
95.0%
95.0%
-
117.6% (70.5 MVA)
117% (70.4 MVA)
-
123.5%
123.1%
-
Sampling of Lowest V in Contingency Scenario
LV
BGG
69 kV
69 kV
no problems
0.879 ↑4.5%0.910 ↑13.6%
0.898 ↑2.1%
BGG
115 kV
NC
69 kV
GD
69 kV
GDT
69 kV
POT
69 kV
Post-Contingent
V Deviation
0.862 ↑16.4% 0.817 ↑17% 0.883 ↑15.1%0.818 ↑17.6% 10.8%<V<17.8%
0.903 ↑11.5%
0.92 ↑10.8% 0.863 ↑11.8% 7.3%<V<12%
6%<V<40.5%
0.599
0.707
0.746
0.606
0.895
6.1%<V<10.5%
0.881 ↑4.2% 0.912 ↑13% 0.824 ↑16.9% 0.865 ↑15.6% 0.823 ↑16.8%0.886 ↑14.4%0.823 ↑16.7% 8.8%<V<18.9%
0.709
5.9%<V<41.1%
0.748
0.603
0.603
0.609
5.3%<V<9.5%
System in-tact at peak load and maximum generation, voltages on the 69 kV system varied from 1.01 to 1.02 pu with the
LTC function enabled. Reducing the load in the Big Horn Basin area by 30% to represent 12-5 am light loading, voltages
increased to the 1.026-1.046 pu (Lovell). The effect of the BGG LTC at these higher voltages was minimal on the Lovell
69 kV bus: 1.044 pu without the LTC operating versus 1.046 pu with the LTC operating, and highly effective for
maintaining the BGG 69 kV bus voltage less than 1.05 pu.
Mitigation for the high voltages, primarily seen at the Lovell 69 kV bus, could be addressed by changing the Lovell
115/69 kV tap setting to the neutral position. This is an ideal solution for system in-tact, however, this decreases the
voltage and increases the load shedding possibility for multiple N-1 contingencies, and restricts operational flexibility.
Additionally, the voltage support from Lovell is needed in the Garland and Powell areas, as they have the lowest 69 kV
voltages for system in-tact. The operation of the Big George transformer as an LTC with a target of 1.02 pu on the 69 kV
system greatly improved the voltages for half of the contingencies, but had little effect on the Garland, Powell, and
Lovell 69 kV buses.
The recommendation for the immediate operating window for the Big Horn Basin area is to operate the Big George
transformer as an LTC with a target of 1.02 pu, and set an SOL for the Lovell 69 kV bus of 1.06 pu. The recommendation
for the Big Horn Basin 69kV system, for inclusion in Western’s Capital Investment Program, is to install a 115 kV line from
Big George to North Cody substation using existing ROW and facilities, and install a 115/69 kV, 50 MVA transformer at
North Cody substation with a 2016 in-service date.
IV.
The 115 & 230 kV Big Horn Basin Area System
Western’s 115 kV system is sourced from Western’s two Yellowtail 230/115 kV transformers boosting the 115 kV bus
2.5%, PACE and TSGT’s two Thermopolis 230/115 kV LTC transformers, tapped at nominal with LTC control targeting
1.02-1.05 pu on the 230 kV bus, and Western’s Boysen-Thermopolis 115 kV line. In the Big Horn Basin area, Western has
two projects under construction to increase the YTS path to 700 MW: the Yellowtail-Lovell 115 kV #1 and #2 Rebuild
project and the Lovell-Nahne Jensen-Basin 115 kV Re-Conductor project. These projects provide for the increase of YTS
from 625 to 700 MW and mitigate overloads that result from the three worst case N-1 outages in the Big Horn Basin
area: PY-YT 230 kV tie line outage, PY- Sheridan (SHI) 230 kV line outage, and the PY-Oregon Basin (OB) 230 kV line
outage. The in-service date for these projects varies beyond 2015, and for the 115 and 230 kV system studies, these
projects were not modeled in every phase of the transmission portion of this study. Modeling the system as it exists
today, before completion of the two 115 kV projects, provided justification reinforcement for these projects as
mitigation for N-1 contingencies for YTS at 625 MW and as required projects for the YTS increase to 700 MW. As seen in
Table 3, thermal overloads and high post-contingent voltage deviations resulted with today’s existing system with YTS at
625 MW, and with generation on the 69 kV system at low levels.
Table 3
YTS 625 MW
2013-14 HW
EXISTING SYSTEM
N-0
N-1
N-1
N-1
N-1
N-1
N-1
N-1
N-3
N-4
SIT
YTP-OB 230 kV
YTP-YTWEast 230 kV Tie
OB-THE 230 kV
PY-SHI 230 kV
HUNT-CRO 230 kV
LV-YT 115 kV #2
RMRK PS
RMRK-YTP & CRO PST & BLGS PST
YTP-YTWEast 230 kV Tie and All PST
Thermal
LV-NJ 115 kV
NJ-BA 115 kV
118/120 MVA
109/109 MVA
109/109 MVA
118/130 MVA
% of emerg rate
% of emerg rate
% of emerg rate
% of emerg rate
102.4%
106.4%
-
100.8%
BA-WRD 115 kV LV-YT 115 kV #1
no thermal issues
105.9%
110.3%
no thermal issues
no thermal issues
no thermal issues
no thermal issues
no thermal issues
104.2%
Result summary
-
-
-
105.2%
5%<delta V<7.5%
5%<delta V<8.1%
no low V or delta V>7%
no low V or delta V>7%
no low V or delta V>7%
no low V or delta V>7%
-
-
no low V or delta V>7%
no low V or delta V>7%
Multiple configurations of the 115 kV rebuild and re-conductor projects and two 230 kV alternatives were studied to
ensure the best mitigation for N-1 contingencies for YTS at 625 and 700 MW. The alternatives studied were:
• Existing plans to rebuild the LV-YT 115 kV #1 & #2 lines and the LV-NJ-BA 115 kV Re-conductor projects;
• Tie in PY-SHI 230 kV line into Crossover 230 kV substation to provide a second 230 kV interconnection between
PACE 230 kV and Western’s 230 kV systems;
• Tie in PY-SHI 230 kV line into Crossover 230 kV substation and the LV-YT 115 kV #1 & #2 line Rebuild;
• A second PY-YT 230 kV tie;
• A second PY-YT 230 kV tie and the LV-YT 115 kV #1 & #2 line Rebuild.
Regardless of the 230 kV option modeled, the rebuild of the LV-YT 115 kV #1 & #2 lines and the reconductor of the LVBA 115 kV line were still required, eliminating the 230 kV options as viable. The results with these requirements are in
Appendix E, Transmission Results Summary Table. The BA-WRD 115 kV line segment, a continuance of the LV-NJ-BA 115
kV line, has been seen incrementally approaching its thermal rating within the last three Annual NIT Studies for the PYYT 230 kV tie line contingency. Within this study the normal/emergency rating was exceeded for the PY-YT 230 kV
outage shown in Table 4, resulting in the recommendation to further reconductor the LV-NJ-BA 115 kV line from Basin
to the Worland Tap (WRD) with 477 ACSS. Western and PACE interconnect at WRD, and the loading on the remaining
line segment, Western’s WRD-Thermopolis (TH) 115 kV line, is reduced through the parallel operation of the PACE’s
WRD-Hilltop (HTA)-PACE Thermopolis (THE) 115 kV, as shown in Figure 1.
Table 4
YTS 625 MW
2013-14 HW
Thermal
PROJ-1
N-0
N-1
N-1
N-1
N-1
N-1
N-1
N-3
N-4
LV-NJ 115 kV
Reconductor LV-YTB 115 kV #1 & #2
Reconductor LV-NJ-BA 115 kV line
SIT
YTP-OB 230 kV
YTP-YTWEast 230 kV Tie
OB-THE 230 kV
PY-SHI 230 kV
RMRK PST
HUNT-CRO 230 kV
RMRK-YTP & CRO PST & BLGS PST
YTP-YTWEast 230 kV Tie and All PST
NJ-BA 115 kV
162/179 MVA
% of emerg rate
-
BA-WRD 115 kV LV-YT 115 kV #1
162/179 MVA
109/109 MVA
% of emerg rate % of emerg rate
no thermal issues
no thermal issues
101.8%
no thermal issues
no thermal issues
no thermal issues
no thermal issues
no thermal issues
no thermal issues
331 MVA
% of emerg rate
-
Result summary
no low V or delta V>7%
no low V or delta V>7%
no low V or delta V>7%
no low V or delta V>7%
no low V or delta V>7%
no low V or delta V>7%
no low V or delta V>7%
no low V or delta V>7%
no low V or delta V>7%
Similar to the results for YTS at 625 MW, the BA-WRD 115 kV line loaded up to 115% for the three worst case outages
with YTS at 700 MW and resulted voltage issues as well, shown in Table 5 below.
Table 5
YTS 700 MW
2013-14 HW
PROJ-1A:
N-0
N-1
N-1
N-1
N-1
N-1
N-1
N-3
N-4
Reconductor LV-YTB 115 kV #1 & #2
Reconductor LV-NJ-BA 115 kV line
SIT
YTP-OB 230 kV
YTP-YTWEast 230 kV Tie
OB-THE 230 kV
PY-SHI 230 kV
RMRK PST
HUNT-CRO 230 kV
RMRK-YTP & CRO PST & BLGS PST
YTP-YTWEast 230 kV Tie and All PST
Thermal
LV-NJ 115 kV
line
NJ-BA 115 kV BA-WRD 115 LV-YT 115 kV
line
kV line
#1 line
162/179 MVA
% of e rate
162/179 MVA 109/109 MVA
% of e rate
% of e rate
no thermal issues
110.4%
115.0%
no thermal issues
no thermal issues
no thermal issues
no thermal issues
no thermal issues
105.9%
-
-
331 MVA
% of e rate
-
-
Result summary
5%<delta V<9.1%
5%<delta V<9.9%
no V or delta V
5%<delta V<11.7%
no delta V
no delta V
5%<delta V<9.3%
no V or delta V
BGG
LV
NJ
MSS
CM
115 kV 115 kV 115 kV 115 kV 115 kV
0.897
0.887
0.896
0.897
0.891
0.89
0.889
0.897
GD
POT
69 kV 69 kV
no voltage issues
no voltage issues
no voltage issues
0.892 0.888
RST
69 kV
SCY
69 kV
0.895
0.888
PACE Ownership
FRA
OB
Garland
230 kV 230 kV 230 kV
0.862
0.893
0.863
0.855
0.89
0.875
0.884
0.872
no voltage issues
no voltage issues
Modeling the system with the recommended North Cody 115/69 kV substation, the new BGG-NC 115 kV line, and the
BA-WRD 115 kV line re-conductor, various combinations of capacitor bank placements on the 115 and 230 kV system
were studied, including the Wyoming Centric Study’s capacitor placement recommendations. The Wyoming Centric
study identified the placement of capacitors in the Big Horn Basin area to accommodate planned load additions,
composed of a 45 MVAR capacitor bank at Lovell substation and a 30 MVAR capacitor bank at Oregon Basin substation.
In the event the Wyoming Centric study capacitor bank recommendations are not constructed, this study proposes a
115 kV, 55 MVAR (1 x 25 MVAR, 1 x 30 MVAR) capacitor bank at Yellowtail and a 115 kV, 15 MVAR capacitor bank at
Nahne Jensen substation. This studies recommendation or the Wyoming Centric recommendation effectively mitigates
the low voltages seen on the 69, 115, and 230 kV systems for the N-1 contingencies and YTS at 700 MW.
V.
Recommendation Summary
The Big Horn Basin area has experienced high voltages on the 69 kV system during off peak time frames, drought
induced low generation patterns, and a modest load growth. Extensive outages due to facility failures have emphasized
the need for greater operational flexibility within the 69 kV system, sourced by the Lovell 115/69 kV substation and the
Big George 115/69 kV substation. This study evaluated the existing 69 kV system and determined it is limited by voltage
and thermal issues for N-1 contingencies, resulting in the recommendation to construct a new 115 kV line and 115/69 kV
source in the Cody area. This new third source provides increased system reliability, mitigates the voltage and thermal
issues for N-1 contingencies, and was the least costly option for the 69 kV system solutions.
The Big Horn Basin area 115 kV system has two projects under construction to increase the YTS path from 625 MW to
700 MW, the LV-YT 115 kV #1 & #2 Line Rebuild project and the LV-NJ-BA 115 kV Line Re-Conductor project. The LV-NJBA 115 kV line has been considered the most limiting element in the basin for three worst case outages, PY-YT 230 kV tie
line outage, PY-OB 230 kV line outage, and PY-SHI 230 kV line outage. The LV-NJ-BA 115 kV line as the most limiting
element has limited YTS and WECC Path 80 Prior Outage and SOL ratings, and has been an element that commonly
overloads for single contingencies in Westerns Annual NIT Study. As a continuance of the LV-NJ-BA 115 kV line, the BAWRD 115 kV line segment was seen to exceed its normal rating for multiple N-1 scenarios in this study, resulting in the
recommendation to continue the LV-NJ-BA 115 kV re-conductor project another 15 miles from Basin to the Worland tap.
Voltage support on the 115 and 230 kV system was required for the operation of YTS at 700 MW. The Wyoming Centric
study capacitor bank recommendation, 75 MVARs at Oregon Basin and Lovell substations, or the addition of 70 MVARs
on the 115 kV buses at Yellowtail and Nahne Jensen will effectively mitigate low voltages on the 115 kV and 230 kV
system for the worst case outages studied.
This study makes the following recommendations for the Big Horn Basin Area 69, 115, and 230 kV system, also shown in
Figure 5:
1. Operate the Big George 115/69 kV transformer as an LTC, ISD 2014;
2. Issue an SOL of 1.06 pu for the Lovell 69 kV bus, ISD 2014;
3. Re-conductor of the Basin-Worland Tap 115 kV Line with 477 ACSS, ISD 2016;
4. Construct the new North Cody 115/69 kV substation with a 50 MVA transformer, and a new 115 kV line from
BGG to North Cody, ISD 2016;
5. Install a 55 MVAR capacitor bank at Yellowtail 115 kV bus and a 15 MVAR capacitor bank at Nahne Jensen 115
kV bus, ISD 2017 or in conjunction with the implementation of YTS at 700 MW.
Figure 5
VI.
Cost Estimates
ISD 2016
BA-WRD 115 kV Line Reconductor, 15 mi
SUBTOTAL
$ 2,000,000
$ 2,000,000
ISD 2016
BGG 115 kV Line Bay/CB Addition to Ring Bus $700,000
BGG-HM 2nd Ckt, 115 kV, 795 ACSR, 10.8 mi $1,300,000
NC New 115/69 kV sub, 50 MVA Xmfr
$2,100,000
SUBTOTAL
$ 4,100,000.
ISD 2017 OR YTS 700 MW Implementation
NJ 115 kV 2x7.5 MVAR Cap Bank
YT 115 kV 55(1-25,1-30) MVAR Cap Bank
SUBTOTAL
System TOTAL
$225,000
$668,000
$ 893,000
$ 6,993,000