20180329PAC to Staff UT Q810SIS.pdf

PACIFICORP
Large Generator Interconnection
System Impact Study Report
Completed for
("Interconnection Customer")
Q0810
Proposed Point of Interconnection
Q0715 Point of Interconnection Substation (on Canyon Compression-
Railroad 138 kV line)
February 9,2018
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System Impact Study Report
TABLE OF CONTENTS
1.0 DESCRIPTION OF THE GENERATING FACILITY .............................................1
2.0 SCOPE OF THE STUDY.....................................................l
3.0 TYPE OF INTERCONNECTION SERVICE ..............................................1
4.0 DESCRIPTION OF PROPOSED INTERCONNECTION...............................................l
5.0 STUDY ASSUMPTIONS....................................................................................3
6.0 ENERGY RESOURCE (ER)INTERCONNECTION SERVICE...............................................4
6.1.1 Requirements 4
6.1.2 Cost Estimate 9
6.1.3 Schedule 10
6.1.4 Maximum Amount of Power that can be deliveredinto NetworkLoad,with No Transmission
Modifications(for informationalpurposes only)10
6.1.5 Additional Transmission ModificationsRequired to Deliver 100%of the Power into Network
Load (for informationalpurposes only)10
7.0 NETWORK RESOURCE (NR)INTERCONNECTION SERVICE.............................................10
7.1.1 Requirements 10
7.1.2 Cost Estimate 10
7.1.3 Schedule 10
8.0 PARTICIPATIONBYAFFECTEDSYSTEMS.............................................11
9.0 APPENDICES..................................................................................11
9.1 Appendix 1:HigherPriority (PriorQueued)Requests ...............................................12
9.2 Appendix 2:Property Requirements.............................................13
9.3 Appendix 3:Study Results...............................................15
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1.0 DESCRIPTION OF THE GENERATING FACILITY
("Interconnection Customer")proposed interconnecting 101 MW of new generation to
PacifiCorp's ("Transmission Provider")Canyon Compression -Railroad 138 kV line located in
Uinta County,Wyoming.The project ("Project")will consist of 44 GE 2.3 inverters for a total
output of 101 MW.The requested commercial operation date is July 1,2019.
Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by
the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Transmission Provider has assigned the Project "Q0810."
2.0 SCOPE OF THE STUDY
The interconnection system impact study shall evaluate the impact of the proposed interconnection
on the reliability of the transmission system.The interconnection system impact study will
consider Base Case as well as all generatingfacilities (and with respect to (iii)below,any identified
network upgrades associated with such prior queued interconnections)that,on the date the
interconnection system impact study is commenced:
(i)are directlyinterconnected to the transmission system;
(ii)are interconnected to Affected Systems and may have an impact on the interconnection
request;
(iii)have a pending prior queued interconnection request to interconnect to the transmission
system;and
(iv)have no Queue Position but have executed an LGIA or requested that an unexecuted
LGIA be filed with FERC.
This interconnection system impact study will consist of a short circuit analysis,a stability
analysis,and a power flow analysis.The study will state the assumptions upon which it is based;
state the results of the analyses;and provide the requirements or potential impediments to
providing the requested interconnection service,includingpreliminaryindication of the cost and
length of time that would be necessary to correct any problems identified in those analyses and
implement the interconnection.The study will also provide a list of facilities that are required as a
result of the Interconnection Request and a non-binding good faith estimate of the cost
responsibility and a non-binding good faith estimated time to construct.
3.0 TYPE OF INTERCONNECTION SERVICE
The Interconnection Customer has selected Network Resource (NR)Interconnection Service,but
has also elected to have the interconnection studied as an Energy Resource (ER).The
Interconnection Customer will select NR or ER prior to the facilities study.
4.0 DESCRIPTION OF PROPOSED INTERCONNECTION
The Interconnection Customer's proposed Generating Facility is to be interconnected through the
Interconnection Customer Interconnection Facilities to be constructed for the Q0715 project.
Figure 1 below,is a one-line diagram that illustrates the interconnection of the proposed
Generating Facility to the Transmission Provider's system.
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Whitney
Canyon Inlet
i Canyon Compression
0.3 miles
/Q0715 POI
Substation
Point of
Interconnection
\Q0810
/Project Sub
34.5 kV
138 kV 68/90/112 MVA -
138 -34.5 kV
Z =9 %
Tie-Line Substation(Customer-owned)
I 34.5 kV
6 Miles
Change of 84/112/140MVA
138 -34.5 kVOwnershipZ=9 %
i
M
Q0715
Project Sub
Railroad
Figure 1:Simplified System One Line Diagram -Point ofInterconnection
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5.0 STUDYASSUMPTIONS
All active higher priority transmission service and/or generator interconnection requests
will be considered in this study and are listed in Appendix 1.If any of these requests are
materiallymodified or withdrawn,the Transmission Provider reserves the right to restudy
this request,and the
Results and conclusions could significantlychange.
For study purposes there are two separate queues:
o Transmission Service Queue:to the extent practical,all network upgrades that are
required to accommodate active transmission service requests will be modeled in
this study.
o Generation Interconnection Queue:Interconnection Facilities associated with prior
queued interconnection requests will be modeled in this study.
The Interconnection Customer's request for energy or network resource interconnection
service in and of itself does not convey transmission service.Only a Network Customer
may make a request to designate a generating resource as a Network Resource.The
provision of transmission service may require additional studies and the construction of
additional upgrades.
Under normal conditions,the Transmission Provider does not dispatch or otherwise
directly control or regulate the output of generating facilities.Therefore,the need for
transmission modifications,if any,which are required to provide Network Resource
Interconnection Service will be evaluated on the basis of 100 percent deliverability(i.e.,
no displacement of other resources in the same area).
This study assumes the Project will be integrated into the Transmission Provider's system
at agreed upon and/or proposed Point of Interconnection.
The Interconnection Customer will construct and own any facilities required between the
Point of Change of Ownership and the Project unless specifically identified by the
Transmission Provider.
Line reconductor or fiber underbuild required on existing poles will be assumed to follow
the most direct path on the Transmission Provider's system.If during detailed design the
path must be modified it may result in additional cost and timing delays for the
Interconnection Customer's project.
Generatortripping may be required for certain outages.
All facilities will meet or exceed the minimum Western Electricity Coordinating Council
("WECC"),North American Electric Reliability Corporation ("NERC"),and the
Transmission Provider's performance and design standards.
The Q0715 project must be complete before or simultaneously with this Project.
The Jordanelle-Midway 138 kV line is assumed to be in service (2019).
The Energy Gateway West,Aeolus-Bridger/Anticlinesub-segment D.2,is assumed to be
in-service by year end 2020.
This report is based on information available at the time of the study.It is the
Interconnection Customer's responsibility to check the Transmission Provider's web site
regularlyfor Transmission System updates at http://www.pacificorp.com/tran.html
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6.0 ENERGY RESOURCE(ER)INTERCONNECTION SERVICE
Energy Resource Interconnection Service allows the Interconnection Customer to connect its
Generating Facility to the Transmission Provider's Transmission System and to be eligible to
deliver electric output using firm or non-firm transmission capacity on an as available basis.
6.1.1 Requirements
6.1.1.1 GeneratingFacility Modifications
All interconnecting synchronous and non-synchronous generators are required to design their
Generating Facilities with reactive power capabilities necessary to operate within the full power
factor range of 0.95 leading to 0.95 lagging.This power factor range shall be dynamic and can be
met using a combination of the inherent dynamic reactive power capability of the generator or
inverter,dynamic reactive power devices and static reactive power devices to make up for losses.
For synchronous generators,the power factor requirement is to be measured at the Point of
Interconnection.For non-synchronousgenerators,the power factor requirement is to be measured
at the high-side of the generator substation.
The generating facility must provide dynamic reactive power to the system in support of both
voltage scheduling and contingency events that require transient voltage support,and must be able
to provide reactive capability over the full range of real power output.
If the generating facility is not capable of providing positive reactive support (i.e.,supplying
reactive power to the system)immediately followingthe removal of a fault or other transient low
voltage perturbations,the facility must be required to add dynamic voltage support equipment.
These additional dynamic reactive devices shall have correct protection settings such that the
devices will remain on line and active during and immediately followinga fault event.
Generators shall be equipped with automatic voltage-control equipment and normally operated
with the voltage regulation control mode enabled unless written authorization (or directive)from
the Grid Operator is given to operate in another control mode (e.g.constant power factor control).
The control mode of generating units shall be accurately represented in operating studies.The
generators shall be capable of operating continuouslyat their maximum power output at its rated
field current within +/-5%of its rated terminal voltage.
As required by NERC standard VAR-001-la,the Transmission Provider will provide a voltage
schedule for the Point of Interconnection.In general,Generating Facilities should be operated so
as to maintain the voltage at the Point of Interconnection,or other designated point as deemed
appropriated by Transmission Provider.The Transmission Provider may also specify a voltage
and/or reactive power bandwidth as needed to coordinate with upstream voltage control devices
such as on-load tap changers.At the Transmission Provider's discretion,these values might be
adjusted depending on operating conditions.
Generating Facilities capable of operating with a voltage droop are required to do so.Voltage
droop control enables proportionate reactive power sharing among generation facilities.Studies
will be required to coordinate voltage droop settings if there are other facilities in the area.It will
be the Interconnection Customer's responsibility to ensure that a voltage coordination study is
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performed,in coordination with Transmission Provider,and implemented with appropriate
coordination settings prior to unit testing.
For areas with multiplegenerating facilities additional studies may be required to determine
whether or not critical interactions,including but not limited to control systems,exist.These
studies,to be coordinated with Transmission Provider,will be the responsibility of the
Interconnection Customer.If the need for a master controller is identified,the cost and all related
installation requirements will be the responsibility of the Interconnection Customer.Participation
by the generation facility in subsequent interaction/coordination studies will be required pre-and
post-commercial operation in order ensure system reliability.
To facilitate collection and validation of accurate modeling data to meet NERC modeling
standards,PacifiCorp,as the Planning Coordinator,requires Phasor MeasurementUnits (PMUs)
at all new GeneratingFacilities with an individual or aggregate nameplate capacity of 75 MVA or
greater.In addition to owning and maintaining the PMU,the Generating Facility will be
responsible for collecting,storing and retrieving data as requested by the Planning Coordinator.
Data must be collected and be able to stream to Planning Coordinator for each of the Generator
Facility's step-up transformers measured on the low side of the GSU at a sample rate of at least 30
samples per second and synchronizedwithin +/-2 milliseconds of the CoordinatedUniversal Time
(UTC).Initially,the followingdata must be collected:
Three phase voltage and voltage angle (analog)
Three phase current (analog)
Data requirements are subject to change as deemed necessary to comply with local and federal
regulations.
All generators must meet the Federal Energy Regulatory Committee (FERC)and WECC low
voltage ride-through requirements as specified in the interconnection agreement.
As the Transmission Provider cannot submit a user written model to WECC for inclusion in base
cases,a standard model from the WECC Approved Dynamic Model Library is required 180 days
prior to trial operation.The list of approved generator models is continually updated and is
available on the http://www.WECC.bizwebsite.
6.1.1.2 Transmission System Modifications
Q0810 is responsible to eliminate the credible N-2 outage of the Transmission Provider's Ben
Lomond-Birch Creek and Ben Lomond-Naughton 230 kV transmission lines,which share
common structures for approximately eight miles as they exit Ben Lomond substation.This will
require construction of a new approximately seven-mile 230 kV line (2-795 ACSR)in a separate
right of way,in order for both 230 kV circuits to be on separate structures.
6.1.1.3 Transmission/Distribution Line Modifications
Construct a 230 kV single circuit transmission line beginning approximately one mile outside of
Ben Lomond substation to structure 525 for the Ben Lomond-Naughton #1 line.
This line segment will replace the current Ben Lomond-Naughton #1 circuit which resides on the
north side of the 7 mile long lattice tower double circuit with the Ben Lomond-Birch Creek 230
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kV transmission line.This new line will require the procurement of additional rights-of-ways
which the Interconnection Customer will be responsible to obtain on behalf of the Transmission
Provider.The corridor near Ben Lomond substation where the new transmission line must be
constructed is congested.The Transmission Provider anticipates that the procurement of the
necessary rights-of-waycould be difficult and may add significant cost and potential delays to
the Project.
6.1.1.4 Existing Circuit Breaker Upgrades -Short Circuit
The increase in the fault dutyon the system as a result of the addition of the Generating Facility
with 44 -GE 2.3 MW wind turbine generators fed through 44 -2.5 MVA 34.5 kV -690 V
transformers with 5.75%impedance then fed through one 138 -34.5kV 68/90/112 MVA step-up
transformer with 9%impedance will not push the fault duty above the interruptingrating of any
of the Transmission Provider's existing fault interruptingequipment.
6.1.1.5 Protection Requirements
The Interconnection Customer's line relays at the collector substation will need to respond to the
combination of the 138 kV fault current being contributed from both the Q0715 and the Q0810
generationprojects for faults on the 138 kV tie line and trip both 138 kV breakers for the two
projects.
As this Project will be interconnectedthrough the same facilities planned to be constructed for
the Q0715 project it will be included in the bus differential relay system that will trip the 138 kV
breaker in the tie line substation to be installed as part of the Q0715 project.
The relay to be installed at the Q0715 POI substation as part of the Q0715 project will monitor
the voltage magnitude and frequency of the Q0810 Project.If the magnitude or frequency of the
voltage is outside of normal range of operation a signal will be sent to trip the tie line 138 kV
breakers.
New line relay settings will be developed for the Naughton -Ben Lomond and Birch Creek -
Ben Lomond 230 kV lines due to the rebuilding of the seven mile section of those lines.
6.1.1.6 Data (RTU)Requirements
Data for the operation of the power system will be needed from the Interconnection Customer's
collector substation.Listed is the data that will be acquired from the collector substations.
From the Q0715 collector substation:
Analogs:
Net GenerationMW
Net GeneratorMVAR
Interchangemetering kWH
From the Q0810 collector substation:
Analows:
Net GenerationMW
Net GeneratorMVAR
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Interchangemetering kWH
34.5 kV Real power F1
34.5 kV Reactive power Fl
34.5 kV Real power F2
34.5 kV Reactive power F2
34.5 kV Real power F3
34.5 kV Reactive power F3
34.5 kV Real power F4
34.5 kV Reactive power F4
34.5 kV Real power F5
34.5 kV Reactive power F5
Average Wind Speed
Average Plant Atmospheric Pressure (Bar)
Average Plant Temperature (Celsius)
Status:
138 kV line breaker
34.5 kV breakerFl
34.5 kV breakerF2
34.5 kV breakerF3
34.5 kV breakerF4
34.5 kV breakerF5
6.1.1.7 Substation Requirements
Q810 Collector Station
The followingmajor equipment has been identified as being required and may change during
detailed design:
3 -138 kV CT/VT combination metering units
1 -Control house
The Interconnection Customer will provide a separate graded,groundedand fenced area along the
perimeter of the Interconnection Customer's GeneratingFacility for the Transmission Provider to
install a control house for metering equipment.This area will share a fence and ground grid with
the Generating Facility and have separate,unencumbered access for the Transmission Provider.
DC power for the control house will be supplied by the Transmission Provider.AC station service
for the control house will be provided by the Interconnection Customer.
Q715 Collector Station
The followingmajor equipment has been identified as being required and may change during
detailed design:
3 -138 kV CT/VT combination metering units
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6.1.1.8 Communication Requirements
The Transmission Provider will need to make minor modifications at its primary and secondary
control centers to account for the additional generation of this phase in addition to the Q0715
project.
6.1.1.9 Metering Requirements
InterchangeMetering -00715 POI substation:
The Q0715 generation metering to be located at the Q0715 POI substation will be reassigned as
an interconnection customer intertie with the Transmission provider for the combined Q0715 and
Q0810 generation projects
Q0715 and Q0810 collector substations:
The generationand backfeed metering for both Q0715 and Q0810 projects will be located at the
Interconnection Customers'respective collector substations.The generation metering will be
located at the 138 kV high side of the Interconnection Customer's transformers and will be loss
adjusted to the Transmission Provider's Q0715 POI substation.
The Transmission Provider will specify and order all interconnection revenue metering
equipment,includingthe 138 kV instrument transformers,metering panels,junction boxes,and
secondary metering wire.The current transformers shall be extended range for high accuracy
metering with current ratio of 500/5 (0.15%extended range accuracy).The voltage transformers
will have a voltage ratio of 700/1 (0.3%accuracy).
The metering design package will include four revenue quality meters and supporting hardware.
The meters will output DNP real-time digital data terminated at a metering interposition block.
The metering design package will include all SCADA metering data terminated at a metering
interposition block.The metering data will include bidirectional KWH and KVARH revenue
quantities.The metering data will also include PF,MW,MVAR,MVA,per phase voltages,and
per phase amps.The interconnection customer may request data outputs from the meters,but the
request must be made prior to final design.
An Ethernet phone line is required for retail sales and generationaccounting via the MV-90
meter data management system.
Station Service/Construction Power
Prior to construction,Interconnection Customer must arrange construction power with the
Transmission Provider.The metering shall conform to the Six State Electric Service
Requirements manual as the site is within the Transmission Provider's service territory.
Please note that prior to back feed,Interconnection Customer must arrange transmission retail
meter service for electricityconsumed by the Project and arrange back-up station service for
power that will be drawn from the transmission or distribution line when the Project is not
generatmg.
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Interconnection Customer must call the PCCC Solution Center at 1-800-625-6078to arrange this
service.Approval for back feed is contingent upon obtaining station service
6.1.2 Cost Estimate
The followingestimate represents only scopes of work that will be performed by the Transmission
Provider.Costs for any work being performed by the Interconnection Customer are not included.
Direct Assigned
Q0810 Collector Substation $413,000
Metering and Control House
Q0715 Collector Substation $413,000
Meteringand Control House
Q0715 Point of Interconnection Substation $30,000
Relay and Communication Modifications
Transmission Provider Control Centers $13,000
Communication Modifications
Total Direct Assigned $869,000
Network Upgrades
Ben Lomond-Naughton#1 Transmission Line $25,785,000
Remove from existing double circuit and construct new 7 mile line
Grand Total $26,654,000
*Any distribution line modifications identified in this report will require a field visit analysis in
order to obtain a more thorough understandingof the specific requirements.The estimate provided
above for this work could change substantially based on the results of this analysis.Until this field
analysis is performed the Transmission Provider must develop the project schedule using
conservative assumptions.The Interconnection Customer may request that the Transmission
Provider perform this field analysis,at the Interconnection Customer's expense,prior to the
execution of an Interconnection Agreement in order to obtain more cost and schedule certainty.
Note:Costs for any excavation,duct installation and easements shall be borne by the
Interconnection Customer and are not included in this estimate.This estimate is as accurate as
possibly given the level of detailed study that has been completed to date and approximates the
costs incurred by Transmission Provider to interconnect this GeneratorFacility to Transmission
Provider's electrical distribution or transmission system.A more detailed estimate will be
calculated during the Facilities Study.The Interconnection Customer will be responsible for all
actual costs,regardless of the estimated costs communicated to or approvedby the Interconnection
Customer.
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6.1.3 Schedule
The Transmission Provider estimates it will require approximately 24-30 months to permit,design,
procure and construct the facilities described in the Energy Resource sections of this report
followingthe execution of an Interconnection Agreement.The schedule will be further developed
and optimized during the Facilities Study.
Please note,the time required to perform the scope of work identified in this report appears to
result in a timeframe that does not support the Interconnection Customer's requested Commercial
Operation date of July 1,2019.
6.1.4 Maximum Amount of Power that can be delivered into Network Load,with No
Transmission Modifications (for informational purposes only)
One hundred one (101)MW can be delivered on a firm basis to the Transmission Provider's
network loads assuming all requirements outlined in this report are complete and all
requirements of Q0786 are complete.
6.1.5 Additional Transmission Modifications Required to Deliver 100%of the Power into
Network Load (for informational purposes only)
See section 6.1.1.2.
7.0 NETWORK RESOURCE(NR)INTERCONNECTION SERVICE
Network Resource Interconnection Service allows the Interconnection Customer to integrate its
Generating Facility with the Transmission Provider's Transmission System in a manner
comparable to that in which the Transmission Provider integrates its generating facilities to serve
native load customers.The transmission system is studied under a variety of severely stressed
conditions in order to determine the transmission modifications which are necessary in order to
deliver the aggregate generation in the area of the Point of Interconnection to the Transmission
Provider's aggregate load.Network Resource Interconnection Service in and of itself does not
convey transmission service.
7.1.1 Requirements
7.1.1.1 GeneratingFacility Modifications
See Section 6.1.1.1
7.1.1.2 Transmission System Modifications
See Section 6.1.1.2
7.1.2 Cost Estimate
No additional costs are anticipated other than those listed in section 6.1.2.
7.1.3 Schedule
See section 6.1.3.
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8.0 PARTICIPATION BY AFFECTED SYSTEMS
Transmission Provider has identified the followingaffected systems:None.
9.0 APPENDICES
Appendix 1:Higher Priority (Prior Queued)Requests
Appendix 2:Property Requirements
Appendix 3:Study Results
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9.1 Appendix1:HigherPriority (Prior Queued)Requests
All active higher priority transmission service and/or generator interconnection requests will be
considered in this study and are identified below.If any of these requests are materiallymodified
or withdrawn,the Transmission Provider reserves the right to restudy this request,as the results
and conclusions containedwithin this study could significantlychange.
Transmission/GenerationInterconnection Queue Requests considered:
Q0715 (120 MW)
Q0720 (80 MW)-QF
Q0786 (100 MW)-ER/NR
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9.2 Appendix2:Property Requirements
Property Requirementsfor Point of Interconnection Substation
Requirementsfor rights of way easements
Rights of way easements will be acquired by the Interconnection Customer in the Transmission
Provider's name for the construction,reconstruction,operation,maintenance,repair,replacement
and removal of Transmission Provider's Interconnection Facilities that will be owned and
operated by PacifiCorp.Interconnection Customer will acquire all necessary permits for the
project and will obtain rights of way easements for the project on Transmission Provider's
easement form.
Real Property Requirementsfor Point of Interconnection Substation
Real property for a point of interconnection substation will be acquired by an Interconnection
Customer to accommodate the Interconnection Customer's project.The real property must be
acceptable to Transmission Provider.Interconnection Customer will acquire fee ownership for
interconnection substation unless Transmission Provider determines that other than fee
ownership is acceptable;however,the form and instrument of such rights will be at Transmission
Provider's sole discretion.Any land rights that Interconnection Customer is planning to retain as
part of a fee property conveyance will be identified in advance to Transmission Provider and are
subject to the Transmission Provider's approval.
The Interconnection Customer must obtain all permits required by all relevantjurisdictionsfor
the planned use includingbut not limited to conditional use permits,Certificates of Public
Convenience and Necessity,California Environmental QualityAct,as well as all construction
permits for the project.
Interconnection Customer will not be reimbursed through network upgrades for more than the
market value of the property.
As a minimum,real property must be environmentally,physically,and operationally acceptable
to Transmission Provider.The real property shall be a permitted or permittable use in all zoning
districts.The Interconnection Customer shall provide Transmission Provider with a title report
and shall transfer property without any material defects of title or other encumbrances that are
not acceptable to Transmission Provider.Property lines shall be surveyed and show all
encumbrances,encroachments,and roads.
Examples of potentiallyunacceptable environmental,physical,or operational conditions could
include but are not limited to:
1.Environmental:known contamination of site;evidence of environmental
contamination by any dangerous,hazardous or toxic materials as defined by any
governmental agency;violation of building,health,safety,environmental,fire,
land use,zoning or other such regulation;violation of ordinances or statutes of
any governmental entities having jurisdiction over the property;underground or
above ground storage tanks in area;known remediation sites on property;ongoing
mitigation activities or monitoring activities;asbestos;lead-based paint,etc.A
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phase I environmental study is required for land being acquired in fee by the
Transmission Provider unless waived by Transmission Provider.
2.Physical:inadequate site drainage;proximity to flood zone;erosion issues;
wetland overlays;threatened and endangered species;archeological or culturally
sensitive areas;inadequate sub-surface elements,etc.Transmission Provider may
require Interconnection Customer to procure various studies and surveys as
determined necessary by Transmission Provider.
Operational:inadequate access for Transmission Provider's equipment and vehicles;existing
structures on land that require removal prior to building of substation;ongoing maintenance for
landscaping or extensive landscape requirements;ongoing homeowner's or other requirements or
restrictions (e.g.,Covenants,Codes and Restrictions,deed restrictions,etc.)on property which
are not acceptable to the Transmission Provider.
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9.3 Appendix3:Study Results
Power Flow Study Results
A Western Electricity Coordinating Council (WECC)approved 2021-22 Heavy winter and 2022
Heavy summer cases were used to perform the power flow studies using PSS/E version 33.7.
Power flow studies were performed on both peak and off-peak load cases.The off-peak load case
was chosen to demonstrate the stress on the higher kV transmission system under light load
conditions.The Rock Springs/Firehole West path was stressed to 640 MW.The local 230 kV and
138 kV transmission system outages were considered during the study.
N-0 Results:No N-0 thermal or voltage issues were observed in the studies.
N-1 Results:Assuming the 2.35 miles of the Railroad -Croydon 138 kV line is rebuilt and the
jumpers at Canyon Creek and Carter Creek are upgradedby the prior Q0786 project,no additional
issues were observed.
N-2 Results:
The credible N-2 of the Ben Lomond -Birch Creek and Ben Lomond -Naughton 230 kV lines
can overload the Naughton -Treasureton 230 kV line and/or the Railroad -Croydon -Coalville
-Silver Creek -Synderville -Cottonwood 138 kV lines.The Ben Lomond -Birch Creek and
Ben Lomond -Naughton 230 kV circuits share common structures for approximately eight miles.
The project cannot be integrated into the Naughton Remedial Action Scheme (RAS)as it exceeds
the maximum amount of generation tripping (600-700 MW)to be dropped as a part of RAS.
Therefore,elimination of the specific 230 kV N-2 is required.As there is a double circuit 138 line
that runs parallel to the 230 kV double circuit in the area,one of the 230 kV circuits can be
swapped with one of the 138 kV circuits,reducing the impact of this outage.Approximatelyseven
miles of structures on the 138 kV segment would need to be replaced to accommodate the weight
of the 230 kV circuit.
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