20180329PAC to Staff UT Q706SIS.pdf

PACIFICORP
TRANSMISSION
Large Generator Interconnection
System Impact Study Report
Completed for
Invenergy Wind DevelopmentLLC
("Interconnection Customer")
Q0706
Carbon County 1
Proposed Point of Interconnection
PacifiCorp's proposed Aeolus substation at 230 kV
July 28,2016
PAciFICORP
TRANSMISSION
System Impact Study Report
TABLE OF CONTENTS
1.0 DESCRIPTION OF THE GENERATING FACILITY.............................................l
2.0 SCOPE OF THE STUDY ....................................................1
3.0 TYPE OF INTERCONNECTION SERVICE ...............................................1
4.0 DESCRIPTION OF PROPOSED INTERCONNECTION..............................................l
4.1 Other Options Considered...............................................3
5.0 STUDY ASSUMPTIONS..........................................................3
5.1 Energy Resource (ER)Interconnection Service..............................................4
5.1.1 Requirements 5
5.1.2 Cost Estimate 11
5.1.3 Schedule 12
5.1.4 Maximum Amount of Power that can be deliveredinto NetworkLoad,with No Transmission
Modifications(for informationalpurposes only)12
5.1.5 Additional Transmission ModificationsRequired to Deliver 100%of the Power into Network
Load (for informationalpurposes only)13
5.2 NetworkResource (NR)Interconnection Service.............................................13
5.2.1 Requirements 13
5.2.2 Cost Estimate 13
5.2.3 Schedule 14
6.0 PARTICIPATION BY AFFECTED SYSTEMS..............................................14
7.0 APPENDICES ..........................................................14
7.1 Appendix 1:HigherPriority Requests .............................................15
7.2 Appendix 2:Property Requirements..............................................16
7.3 Appendix 3:Study Results................................................18
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1.0 DESCRIPTION OF THE GENERATING FACILITY
InvenergyWind Development LLC ("InterconnectionCustomer")proposed interconnecting 250
MW of new generation to PacifiCorp's ("Transmission Provider")proposed Aeolus substation at
230 kV located in Carbon County,Wyoming.The Carbon County 1 project ("Project")will
consist of 125 GE 2.0-116 turbines for a total output of 250 MW.The requested commercial
operation date is November 1,2018.
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 "Q0706."
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 generating facilities (and with respect to (iii)below,
an identified network upgrades associated with such higher queued interconnection)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 higher 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.
The interconnection system impact study will consist of a short circuit analysis,a stability
analysis,and a power flow analysis.The interconnection system impact 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
interconnection system impact study will 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 elected to have the interconnection studied as an Energy
Resource (ER)and a Network Resource (NR).The Interconnection Customer will select NR or
ER prior to the Facilities Study.
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4.0 DESCRIPTION OF PROPOSED INTERCONNECTION
The Interconnection Customer's proposed Generating Facility is to be interconnected through a
new 230 kV bay at the proposed Aeolus substation.The Interconnection Customer will construct
a seven-to eight-mile 230 kV transmission line into the Aeolus substation from their 230 kV
collector substation.Based on the data provided by the Interconnection Customer,the Project
consists of two 230 -34.5 kV transformers with the rating of 84/112/140 MVA each.Each one
of the 230 -34.5 kV transformers is connected to two separate 34.5 collector systems.The first
collector system has sixty-two (62)2.0 MW GE turbines connected to it totaling 124 MW and
the second collector system has sixty-three (63)2.0 MW GE turbines connected to it totaling 126
MW.The total maximum output of the Project shall not exceed 250 MW.
Figure 1 below is a one-line diagram that illustrates the interconnection of the proposed
Generating Facility to the Transmission Provider's system.
7-8 mile 230 kV line to the Collector
Substation Customer owned,operated
&protected breaker
outside Aeolus Substation
230 kV to
Aeolus 500 500/230 kV
Windstar
kV Sub 230 kV to
Future QO706
I
230 kV 230 kV to
Aeolus 500 500/230 kV Shirley Basin
I
kV Sub
Aeolus 500 500/230 kV 230 kV
Aeolus 230 kV i svc Fut re
230 kV
I Substation 230kVto
Freezeout
Figure 1:Simplified System One Line Diagram
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4.1 Other Options Considered
The followingalternative options were considered as potential Points of Interconnection
("POI")for this Project:None.
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
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 higher
queue 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 generatingresource as a Network Resource.Because the queue
of higher priority transmission service requests may be different when a Network Customer
requests network resource designation for this Generating Facility,the available capacity or
transmission modifications,if any,necessary to provide Network Resource interconnection
service may be significantlydifferent.Therefore,the Interconnection Customer should regard
the results of this study as informational rather than final.
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 evaluatedon 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
the proposed Aeolus 230 kV substation.
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.
Generatortripping will 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 most current transmission facility ratings were used for the analysis.
All existing and proposed Remedial Action Schemes (RAS)are assumed to be in service for
this study.
A synchronous condenser at Standpipe substation is planned to be in service in June 2016
and is assumed to be in service for the study.
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The Energy Gateway West (2024)and Energy Gateway South (2024)projects are assumed to
be in service;the Dave Johnston to Amasa (future)to Heward (future)to Aeolus (future)230
kV line is assumed to be rebuilt as part of the Gateway projects.Note that these dates are
inconsistent with the Q0706 Project's planned in-service date.A RAS that will drop up to
600 MW of generation for the followingoutages is assumed to be in-service:
o Aeolus -Anticline 500 kV line
o Anticline -Populus 500 kV line
o Aeolus -Clover 500 kV line
o Clover 500/345 kV auto transformer
All system improvements associated with the prior queued projects are assumed to be in-
service before Q0706.
Based on the Federal Energy Regulatory Commission's proposed revisions to the Pro Forma
Large Generator Interconnection Agreement (Docket No RM16-1-000),the followingpower
factor requirement was assumed for the Project:
"9.6.1 Power Factor Design Criteria.Interconnection Customer shall design
the Large Generating Facility to maintain a composite power delivery at
continuous rated power output at the POI at a power factor within the range
of 0.95 leading to 0.95 lagging,unless Transmission Provider has
established different requirements that apply to all generators in the Control
Area on a comparable basis.Non-synchronous generators shall only be
required to maintain the above power factor when their output is above 10
percent of the Generating Facility Capacity."
The 2.0 MW GE wind turbines for Q0706 were assumed to have a +/-0.9 power factor at
turbine terminals.
Network generators in southern Utah were re-dispatched in order to interconnect and
accommodate Q0706 as a network resource.
Transmission Provider reserves the right to restudy the Project if any of the above mentioned
assumptions are changed or if any of the required mitigations are not in service at the time of
mterconnection.
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 regularly for
Transmission System updates at http://www.pacificorp.com/tran.html
5.1 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.
Energy Resource Interconnection Service in and of itself does not convey transmission
service.
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5.1.1 Requirements
5.1.1.1 Generating Facility Modifications
Transmission Provider will require the facility to operate in voltage control mode
with the ability to deliver power output to the POI within the range of +/-0.95 power
factor.(Please see Standard Large Generator Interconnection Agreement,article 9.6.1
and 9.6.2 in OATT.)Any additional reactive compensation must be designed such
that the discrete switching of the reactive device,if required,does not cause step
voltage changes greater than ±3%at any load serving bus on the Transmission
Provider's system.
As required by NERC standard VAR-001-la,the Transmission Provider will provide
a voltage schedule for the POI.In general,Generating Facilities should be operated so
as to maintain the voltage at the POI,or other designated point as deemed appropriate
by Transmission Provider,between 1.00 per unit to 1.04 per unit.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.
At low output levels,the Project needs to ensure that it maintains the power factor
within ±0.95 at the POI and minimize the reactive power flow towards the
transmission system to prevent high voltages.Transmission Provider has experienced
high voltages in the Wyoming area when the transmission system is lightly loaded
with low wind conditions in the area.With low wind conditions the wind farms tend
to supply reactive power into the transmission system,increasing the voltage.
Generating Facilities capable of operating with a voltage droop are required to do so.
Voltage droop control enables proportionate reactive power sharing among
Generating 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 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.
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Phasor MeasurementUnits (PMUs)will be required at any Generating Facilities with
an individual or aggregate nameplate capacity of 75 MVA or greater.
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 backfeed.The list of approved generator models
is continuallyupdated and is available on the http://www.WECC.bizwebsite.
5.1.1.2 Transmission System Modifications
Assuming the partial bay and two breakers at Aeolus are constructed and in-
service as shown in Figure 1,the followingimprovements are necessary at Aeolus
substation:
o Completion of the partial bay
o One new 230 kV breaker and associated switches to interconnect the Project
to the ring-bus
Additionally,a 230 kV circuit breaker adjacent to the Aeolus substation will be
required to provide protection on the Interconnect Customer's 230 kV line.
Aeolus
Substation *
'230kV
Q0706
Substation
84/112/140 MVA 84/112/140 MVA230-34.5 kV 230-34.5 kVZ=9%Z=9%
4.5 V 4.5 V
Collector Circuits Collector Circuits
Figure 2:Simplified System One Line Diagram for the Collector Substation
5.1.1.3 Transmission/Distribution Line Modifications
The Transmission Provider will review the Interconnection Customer's design of the
proposed new transmission line connection to the Aeolus substation structure for
general conformance with Transmission Provider's construction standards.
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5.1.1.4 Existing Circuit Breaker Upgrades -Short Circuit
The increase in the fault duty on the system as a result of the addition of the
Generating Facility with 125 GE 2.0-116 2 MW wind turbine generators fed through
125 2,222 kVA 34.5 kV -690 V transformers with 5.75%impedance then fed
through two 230 -34.5kV 83/112/140 MVA step-up transformers with 9%
impedance will not push the fault duty above the interruptingrating of any of the
existing fault interrupting equipment.
5.1.1.5 Protection Requirements
The Interconnection Customer's tie line substation (a single 230kV circuit breaker
and associated equipment)will be adjacent to Aeolus substation with a common fence
between the two facilities.With this configuration the ground mats of the two
substations will be tied together.The line between the tie line substation and Aeolus
substation will be a short section of bus and will be protected with redundant bus
differential relay systems.The bus differential relays will be located in Aeolus
substation.The Interconnection Customer will need to provide the output from two
sets of current transformers to be fed into the bus differential relays with a maximum
current transformer ratio matching the maximum CT ratio of the breakers at Aeolus
substation.If a fault is detected,both the 230 kV breakers in Aeolus substation and
the 230 kV breaker in the Interconnection Customer's tie line substation will be
tripped.
The detection and clearing of faults on the tie line between the tie line and the
collector substations will be the responsibility of the Interconnection Customer.
Facilities must be installed to detect and isolate the line if it is faulted in five cycles or
less.
A relay at Aeolus substation will monitor the voltage magnitude and frequency.If
the magnitude or frequency of the voltage is outside of normal range of operation a
signal will be sent over the communication system to the collector substation.At the
collector substation this signal is to trip open all of the 34.5 kV feeder breakers to
disconnect the wind turbine generators.By tripping the 34.5 kV breakers instead of
the 230 kV breakers the station service to the wind electric plant is maintained to
facilitate the restoration of the generation.This relay will also have phase and
ground directional overcurrent elements set to operate for faults in the line between
Shirley Basin substation and the Interconnection Customer's collector substation
and serve as a back-up to the main protection installed by the Interconnection
Customer as indicated in the previous paragraph.
5.1.1.6 Data (RTU)Requirements
In addition to the need for operational data and control at Aeolus substation,data for
the operation of the power system will be needed from the collector substation.This
data can be acquired by installingRTUs at the collector substation.
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Listed below is the data that will be acquired from the collector substation and at
Aeolus substation.
From Aeolus substation:
Analows:
Net Generationreal power
Net Generator reactive power
Interchangeenergy register
From Tie Substation Adjacent to Aeolus
Status:
230 kV breaker
From the Q0706 collector substation:
Analows:
Transformer #1 real power
Transformer #1 reactive power
Real power flow through 34.5 kV line feeder breaker Tl-1
Reactive power flow through 34.5 kV line feeder breaker Tl-1
Real power flow through 34.5 kV line feeder breaker Tl-2
Reactive power flow through 34.5 kV line feeder breaker Tl-2
Real power flow through 34.5 kV line feeder breaker Tl-3
Reactive power flow through 34.5 kV line feeder breaker Tl-3
Real power flow through 34.5 kV line feeder breaker Tl-4
Reactive power flow through 34.5 kV line feeder breaker Tl-4
Real power flow through 34.5 kV line feeder breaker Tl-5
Reactive power flow through 34.5 kV line feeder breaker Tl-5
Transformer #2 real power
Transformer #2 reactive power
Real power flow through 34.5 kV line feeder breaker T2-1
Reactive power flow through 34.5 kV line feeder breaker T2-1
Real power flow through 34.5 kV line feeder breaker T2-2
Reactive power flow through 34.5 kV line feeder breaker T2-2
Real power flow through 34.5 kV line feeder breaker T2-3
Reactive power flow through 34.5 kV line feeder breaker T2-3
Real power flow through 34.5 kV line feeder breaker T2-4
Reactive power flow through 34.5 kV line feeder breaker T2-4
Real power flow through 34.5 kV line feeder breaker T2-5
Reactive power flow through 34.5 kV line feeder breaker T2-5
A phase 230 kV transmission voltage
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B phase 230 kV transmission voltage
C phase 230 kV transmission voltage
Average Wind speed
Average Plant Atmospheric Pressure (Bar)
Average Plant Temperature (Celsius)
Status:
230 kV breaker Tl
34.5 kV collector circuit breaker Tl-1
34.5 kV collector circuit breaker Tl-2
34.5 kV collector circuit breaker Tl-3
34.5 kV collector circuit breaker Tl-4
34.5 kV collector circuit breaker Tl-5
230 kV breaker T2
34.5 kV collector circuit breaker T2-1
34.5 kV collector circuit breaker T2-2
34.5 kV collector circuit breaker T2-3
34.5 kV collector circuit breaker T2-4
34.5 kV collector circuit breaker T2-5
5.1.1.7 Substation Requirements
Aeolus Substation
Complete construction of one transformer bay to terminate the tie line in.Three (3)
feet of panel space will be required in the 230 kV control house.The following
equipment will be installed:
(1)-230 kV circuit breaker
(3)-230 kV CCVT
(2)-230 kV group operated breaker disconnect switch
(1)-230 kV group operated line disconnect switch,with ground blade,with
motor operator
(3)-144 kV MCOV surge arrester
Tie Line Substation
The Interconnection Customer will construct a separate fenced area directly adjacent
to Aeolus substation to house their 230 kV circuit breaker.The two yards will share a
common ground grid.Conduit will be installed between the two yards.A CDEGS
grounding analysis will be required by the Interconnection Customer.
Q0706 Collector Substation
The Interconnection Customer will provide a separate graded,grounded and fenced
area along the perimeter of the Interconnection Customer's Generating Facility for
the Transmission Provider to install a control house for any required metering,
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protection,or communication equipment.This area will share a fence and ground grid
with the Generating Facility and have separate,unencumbered access for the
Transmission Provider.AC station service power for the control house will be
supplied by the Interconnection Customer.A CDEGS grounding analysis will be
required by the Interconnection Customer.230 kV metering units will be installed.
Conduit will be installed as required.
5.1.1.8 Communication Requirements
OPGW optical fiber cable is to be installed between Aeolus substation and the
collector substation on the new transmission line with nodes and channel banks at
both ends.This fiber is to be installed by the Interconnection Customer and upon
acceptance will be owned and maintained by Transmission Provider.Channels will be
crossed at Aeolus substation to the back bone communication system.The new
substation batteries will be sized to carry the communication equipment with DC to
DC converters.At the collector location a router will be installed on the substation
network to interface the meters and substation equipment.
5.1.1.9 Metering Requirements
InterchangeMetering
Point of Interconnect will be Aeolus substation,the interchange metering will be
designed bidirectional and rated for the total net generation of the project including
metering the retail load (per tariff)delivered to the Interconnection Customer.The
Transmission Provider will specify and order all interconnection revenue metering,
includingthe instrument transformers,metering panels,junction box and secondary
metering wire.The primary metering transformers shall be combination CT/VT
extended range for high accuracy metering with ratios to be determined during the
design phase of the project.
The metering design package will include two revenue qualitymeters,test switch,
with DNP real time digital data terminated at a metering interposition block.One
meter will be designated a primary SCADA meter and a second meter will be used
designated as backup with metering DNP data delivered to the alternate control
center.The metering data will include bidirectional KWH KVARH,revenue
quantities includinginstantaneous PF,MW,MVAR,MVA,includingper phase
voltage and amps data.
An Ethernet connection is required for retail sales and generation accounting
via the MV-90 translation system.
Collector Q0706 Metering
Revenue metering is required for each of the two Interconnection Customer power
transformers and will be located on the high side of each of the step-up transformers.
The primary metering transformers shall be combination CT/VT extended range for
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high accuracy metering with ratios to be determined during the design phase of the
project.
The Transmission Provider will design and procure the collector revenue metering
panels.The panels shall be located inside the collector control house.The collector
substation metering panel shall include two revenue quality meters,test switches,and
all SCADA metering data terminated at a metering interposition block.
An Ethernet phone line is required for retail sales and generation accounting via the
MV-90 translation system.
Station Service/Construction Power
Prior to construction,Interconnection Customer must arrange construction power
with the Transmission Provider.The Project is within the Transmission Provider's
service territory and both station service and temporary construction power metering
shall conform to the Six State Electric Service Requirements manual.
Please note that prior to back feed,Interconnection Customer must arrange
distribution voltage retail meter service for electricity consumed 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 generating.Interconnection Customer must
call the PCCC Solution Center 1-800-640-2212 to arrange this service.Approval for
back feed is contingent upon obtaining station service.
5.1.2 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.
Energy Resource
Interconnection -Direct AssignmentFacilities
Q0706 collector substation -Add RTU $467,000
Q0706 collector substation -Add metering $450,000
Aeolus substation -Add metering $239,000
Sub-total Direct AssignmentCosts $1,156,000
Interconnection -Network Upgrade Costs
Aeolus substation -Add 230 kV line position $1,642,000
Tie line substation -Add relay settings and grounding $64,000
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Sub-total Network Upgrade Costs $1,706,000
Total Cost -ER Interconnection Service -Interconnection Only $2,862,000
*Any distribution line modifications identified in this report will require a field visit
analysis in order to obtain a more thorough understanding of 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 Generator
Facility 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.
5.1.3 Schedule
The requirement for the Transmission Provider's Energy Gateway projects to be
complete prior to interconnection of the Interconnection Customer's Project does not
support the Interconnection Customer's requested commercial operation date of
November 1,2018.
If the Energy Gateway projects were complete,the Transmission Provider estimates it
would require approximately 18 months to 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.
5.1.4 Maximum Amount of Power that can be delivered into Network Load,with
No Transmission Modifications (for informational purposes only)
Zero (0)MW can be delivered on a firm basis to the Transmission Provider's network
loads without system improvements.
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5.1.5 Additional Transmission Modifications Required to Deliver 100%of the
Power into Network Load (for informational purposes only)
In order to deliver 100%of the power into Network Load,the followingtransmission
modifications are necessary:
The Energy Gatewayprojects must be in service
A RAS to drop up to 600 MW of generation in Wyoming for the Gateway outages
(this project may be included)
The system improvements associated with prior queued projects must be in service
Allocation of 250 MW of Gateway capacity to serve network loads by this Project
A new partial bay at the proposed Aeolus substation with a new 230 kV breaker and
associated switches
5.2 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 POI to the Transmission
Provider's aggregate load.Network Resource Interconnection Service in and of itself does
not convey transmission service.
5.2.1 Requirements
5.2.1.1 Generating Facility Modifications
See Section 5.1.1.1
5.2.1.2 Transmission System Modifications
In order to deliver 100%of the Q0706 power output to Network Load,the following
transmission modifications are necessary:
The Energy Gatewayprojects must be in service
A RAS to drop up to 600 MW of generationin Wyomingfor the Gateway outages
(this project may be included)
The system improvements associated with the prior queued projects must in
service
Allocation of 250 MW of Gateway capacity to serve network loads by this Project
A new partial bay at the proposed Aeolus substation with a new 230 kV breaker
and associated switches
5.2.2 Cost Estimate
No additional estimated costs assuming all Energy Resource requirements are complete
and all upgrades identified in section 5.2.1.2 are complete.
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5.2.3 Schedule
Please note that the requirement for the Transmission Provider's Energy Gateway
projects to be complete prior to interconnection of the Interconnection Customer's
Project does not support the Interconnection Customer's requested commercial operation
date of November 1,2018.
6.0 PARTICIPATION BY AFFECTED SYSTEMS
No Affected Systems were identified.
7.0 APPENDICES
Appendix 1:Higher Priority Requests
Appendix 2:Property Requirements
Appendix 3:Study Results
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7.1 Appendix1:HigherPriority 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 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:
Q0199 (200 MW)
Q0200 (100 MW)
Q0201 (100 MW)
Q0267 (88 MW)
Q0290 (252 MW)
Q0306/335 (80 MW)
Q0375 (230 MW)
Q0409 (320 MW)
Q0542 (240 MW)
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7.2 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 Transmission Provider.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 POI 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
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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
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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7.3 Appendix3:Study Results
Power Flow Study Results
A Western Electricity Coordinating Council (WECC)approved 2017 Heavy Summer case was
used to perform the power flow studies using PSS/e version 33.5.Power flow studies were
performed on both peak and off-peak load cases.The off-peak load case was chosen for study to
demonstrate the stress on the higher kV transmission system under light load conditions.
The study was performed assuming the Energy Gateway Project is in-service.The local 345 kV,
230 kV,and 115 kV transmission system outages were considered during the study.
Result for Aeolus POI:
N-0 Results:Assuming Energy Gateway is in service,no N-0 thermal or voltage issues were
observed in the studies.Injection of approximately 9.4 MVAr into the transmission system was
observed if the collector system was connected with no generation from the Project.Figure 2
shows the MVArs being injected into the system.The Project should be able to control the
voltage at the POI within the required voltage range provided by the Transmission Operator.
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Q0706 -250 MW Interconnection at Aeolus
O
-E 3 -6 9
Aeolus South (1700 inV)=1040 1 MW
-319 -1225 5
ÆOA Aeolus West [2570 MW =1288.0 MW
1 x 6 I 05 Bridger/Antichne West (4100 MW)3042 4 MW
235 2 TOT4A Post Gateway(2175 MW)=1024 4 MW
N-1 Results:Assuming Energy Gateway is in-service,no N-1 thermal or voltage issues were
observed in the studies.
N-2 Results:Assuming Energy Gateway is in-service,no N-2 thermal or voltage issues were
observed in the studies.
N-1-1 Results
The Customer may be required to curtail generation dependingon operating conditions for an N-
1-1 outage of any two out of three 500/230 kV auto transformers at Aeolus.Depending on real
time operating conditions,other N-1-1 outage may also require the curtailment of this Project
output.
Invenergy Wind Development LLC Page 19 July 28,2016
Carbon County 1,Q0706
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Large Generator Interconnection
System Impact Study Report
Stability Study
Completed for
Invenergy Wind DevelopmentLLC
("Interconnection Customer")
Q0706
Carbon County 1
Proposed Interconnection
PacifiCorp's proposed Aeolus substation at 230 kV
July 28,2016
PACIFICORP
A MIDAMERlCAN ENERGY HOLDINGS COMPANY
Table of Contents
Executive Summary ...................................................................................................................4
GeneratorFacility Modifications......................................................................................4
Description of Project ................................................................................5
Study Assumptions ..................................................................................................................6
Transient Analysis .............................................................................................................7
Conclusions................................................................................................................10
Appendices..............................................................................................................................11
Appendix A:Transient Stability Plots ...................................................................................12
3
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Executive Summary
InvenergyWind Development LLC ("InterconnectionCustomer")proposed interconnecting 250
MW of new generation to PacifiCorp's ("Transmission Provider")proposed Aeolus substation at
230 kV located in Carbon County,Wyoming.The Carbon County 1 project ("Project")will
consist of 125 GE 2.0-116 turbines for a total output of 250 MW.The requested commercial
operation date is November 1,2018.
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 "Q0706."
Transient stability analysis was simulated for various local area disturbances in the 500 kV,345
kV and 230 kV transmission network with 2018 system conditions modeled.Results identified
that with the GE 2.0-116 turbine generator model provided by the Interconnection Customer,the
wind farm will ride through ALL simulated local area contingencies.
Generator Facility Modifications
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 from the Grid
Operator is given to operate in another control mode (e.g.constant power factor control).The
control mode of the 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.
Note,project modeling is based on data provided by the Interconnection Customer and/or the
Interconnection Customer's equipment suppliers.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 backfeed.The list of approved
generator models is continuallyupdated and is available on the http://www.WECC.bizwebsite.
4
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Description of Project
The Interconnection Customer has proposed interconnecting a wind farm in Carbon County,
Wyoming,to the Transmission Provider's proposed Aeolus 230 kV substation.The
Interconnection Customer will build a four mile long 230 kV transmission line from the collector
substation to the Point of Interconnection.The Project includes two three-winding 230/34.5/13.8
kV,84/112/140 MVA (ONAN/ONAF/ONAFrating)collector transformers with 9%impedance
based on the self-cooled MVA rating.The X/R ratio is 40 as provided by the Interconnection
Customer.A preliminary electrical single line diagram depicting the Project's interconnection at
the new substation is shown in Figure 1.
It is proposed to interconnect 125 GE 2.0-116 wind turbine generators (WTG).Power from each
WTG inverter will be stepped up to 34.5 kV through a 690 V:34.5 kV (WYE:DELTA),2.3
MVA pad-mounted transformer.As per the one-line diagram submitted by the Project,each pad
mounted transformer has the impedance rating of 5.75%.A 34.5 kV collection system will bring
the combined power output to the collector substation where the power will be further increased
to 230 kV through a 230/34.5 kV transformer.
Shirley Basin Change of 4 Miles 230 kV
Ownership Q0706
-,Substation
Seven Mile Hill
84/112/140 MVA 84/112/140 MVAPointof230-34.5 kV 230 -34.5 kVInterconnectionZ=9 %Z =9 %
Collector Circuits Collector CircuitsFreezeout
Substation
Standpipe ,
QO409
Figure 1.Preliminary Single Line Diagram
5
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Study Assumptions
The PSS/E version 33.7 program was used to evaluate system stability for each of the faults
described in Table 1.In addition,the followingassumptions were used in performing this study.
Study Period:The 2015 WECC approved Heavy Summer case modified to represent the 2018
system conditions both during peak and off-peak was used to for this analysis.
Study Area:The study area was limited to the Project and the surrounding 500 kV and 230 kV
transmission system in Wyoming.
The followingstudy assumptions were made while performing this analysis:
A synchronous condenser at Standpipe substation is planned to be in service in June 2016
and is assumed to be in service for the study.
The Energy Gateway West (2024)and Energy Gateway South (2024)projects are
assumed to be in service;the Dave Johnston to Amasa (future)to Heward (future)to
Aeolus (future)230 kV line is assumed to be rebuilt as part of the Gateway projects.Note
that these dates are inconsistent with the Q0706 Project planned in-service date.
A RAS that will drop up to 600 MW of generation for the followingoutages is assumed
to be in-service:
o Aeolus -Anticline 500 kV line
o Anticline -Populus 500 kV line
o Aeolus -Clover 500 kV line
o Clover 500/345 kV auto transformer
All system improvements associated with the prior queued projects are in service before
Q0706.
Contingencies:The study simulated disturbances tabulated in Table 1.
Table 1.Transient StabilityAnalysis Contingencies
No.ContingencyDescription
1
Three-phase fault at Aeolus 500 kV bus followed by
loss of the Aeolus 500/230 auto transformer #1 (4 cycles).
2 Three-phase fault at the Aeolus 500 kV bus followed by
loss of the Aeolus -Anticline 500 kV circuit (4 cycles)and loss of 600 MW of generation
as part of the RAS.
3 Three-phase fault at the Aeolus 500 kV bus followed by
loss of the Aeolus -Clover 500 kV circuit (4 cycles)and loss of 600 MW of generation as
part of the RAS.
4 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Freezeout 230 kV circuit (5 cycles).
5 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Q0199 Collector 230 kV circuit (5 cycles)and loss of 400 MW of
generation(Q0199,Q0200,Q0201)
6
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
6 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Q0706 Collector 230 kV circuit (5 cycles)and loss of 250 MW of
generation(Q0706)
7 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Shirley Basin 230 kV circuit (5 cycles).
8 Three-phase fault at the Aeolus 230 kV bus followed by breaker failure at Aeolus and
delayed clearing (15 cycles)of the Aeolus -Shirley Basin 230 kV circuit (15 cycles).
9 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus SVC (5 cycles).
10 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Windstar 230 kV circuit (5 cycles).
11 Three-phase fault at the Anticline 500 kV bus followed by
loss of the Anticline -Populus 500 kV circuit (4 cycles)and loss of 600 MW of generation
as part of the RAS.
12 Three-phase fault at the Anticline 500 kV bus followed by
loss of the Anticline 500/345 kV PST (4 cycles).
13 Three-phase fault at the Bridger 345 kV bus followed by simultaneous loss of the Bridger -
Populus #1 and Bridger -Populus #2 345 kV lines (4 cycles)and loss of two Bridger units
as part of RAS.
14 Three-phase fault at the Bridger 345 kV bus followed by simultaneous loss of the Bridger -
Populus #1 and Bridger -Threemile Knoll 345 kV lines (4 cycles)and loss of two Bridger
unit as part of RAS.
15 Three-phase fault at the Dave Johnston 230 kV bus followed by the loss of Dave Johnston -
Amasa 230 kV circuit (5 cycles)and loss of Q0306 as part of the RAS for this outage.
7
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Other Assumptions:
Data provided for the collector system 230/34.5/13.8 kV transformer was 84/112/140
MVA (ONAN/ONAF/ONAF)with 9.0%impedance on 84 MVA base.
Transient stability simulations were performed out to 10 seconds in order to determine
system damping.
The 2.0 MW GE wind turbines for Q0706 were assumed to have a +/-0.9 power factor at
turbine terminals.
The GE 2.0 MW turbine is required to have voltage ride-through protection capability as
per PRC-024;therefore,the turbine is designed to stay connected to the grid in the case
of severe faults.Figure 2 illustrates the voltage ride-through capability as per PRC-024.
Table 2 shows the voltage ride through capability modeled for the GE wind turbines for
this Project.The voltage protection model is based on the data provided by the
Interconnection Customer.
Table 2:V iltage Ride throughParameters modeled for this Project
HighVoltage Ride Low Voltage Ride
ThroughDuration ThroughDuration
Voltage (pu)Time (sec)Voltage (pu)Time (sec)
1.3 0.01 0.2 1.0
1.2 0.1 0.4 1.7
1.175 0.2 0.6 2.2
1.15 0.5 0.75 3.0
1.1 1.0 0.85 10
0.9 600
8
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Voltage Ride-Through
Time Duration Curve
.1.30
|1.25
1.101.05
1.00
--No Trip Zone 0.95
0.850.80 20.75 Ë
1 |||
0.70 =
0.55 a.0.50 -
0.45 o0.40 C)0.35 m0.30 2
0.25 O0.20 >
0.15 -
0.10 00.05 0.
|0.00
0 0.5 1 1.5 2 2.5 3 3.5 4
Time (sec)
---High Voltage Duration -Low Voltage Duration
Figure 2.Voltage Ride-through Capability Curve based on PRC-024
9
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Transient Analysis
The Generating Facility is required to ride through all 3-phase faults with normal clearing or
single line-to-ground faults with delayed clearing for any event that doesn't disconnect the
Generating Facility.
Transient stability results identified that with the model provided,the ALL wind turbines will
ride through all simulated local area disturbances.A summary of contingency performance is
provided in the followingtable.
The PSS/E version 33.7 program was used to evaluate the transient stability performance of the
system for each of the contingencies described in Table 3.The 2015 Heavy Summer WECC case
(15hslap.sav)modified to 2018 system conditions was used for this analysis.The study area was
limited to local area in Wyoming and Gateway contingencies that extend out of Wyoming.Both
peak and off-peak cases were considered for this analysis.Senior queue generator projects that
are senior to this Project were also modeled in the study.
Table 3.Transient StabilityResults -Carbon County 1.
Off-Peak
No.ContingencyDescription peak Case
Case Stable
Stable (Yes/
(Yes/No)
No)
1
Three-phase fault at Aeolus 500 kV bus followed by
loss of the Aeolus 500/230 auto transformer #1 (4 cycles).Yes Yes
2 Three-phase fault at the Aeolus 500 kV bus followed by
loss of the Aeolus -Anticline 500 kV circuit (4 cycles)and loss of Yes Yes
600 MW of generation as part of the RAS.
3 Three-phase fault at the Aeolus 500 kV bus followed by
loss of the Aeolus -Clover 500 kV circuit (4 cycles)and loss of 600 Yes Yes
MW of generation as part of the RAS.
4 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Freezeout 230 kV circuit (5 cycles).Yes Yes
5 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Q0199 Collector 230 kV circuit (5 cycles)and Yes Yes
loss of 400 MW of generation(Q0199,Q0200,Q0201)
6 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Q0706 Collector 230 kV circuit (5 cycles)and Yes Yes
loss of 250 MW of generation(Q0706)
7
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
7 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Shirley Basin 230 kV circuit (5 cycles).Yes Yes
8 Three-phase fault at the Aeolus 230 kV bus followed by breaker
failure at Aeolus and delayed clearing (15 cycles)of the Aeolus -Yes Yes
Shirley Basin 230 kV circuit (15 cycles).
9 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus SVC (5 cycles).Yes Yes
10 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Windstar 230 kV circuit (5 cycles).Yes Yes
11 Three-phase fault at the Anticline 500 kV bus followed by
loss of the Anticline -Populus 500 kV circuit (4 cycles)and loss of Yes Yes
600 MW of generation as part of the RAS.
12 Three-phase fault at the Anticline 500 kV bus followed by
loss of the Anticline 500/345 kV PST (4 cycles).Yes Yes
13 Three-phase fault at the Bridger 345 kV bus followed by simultaneous
loss of the Bridger -Populus #1 and Bridger -Populus #2 345 kV Yes Yes
lines (4 cycles)and loss of two Bridger unit as part of RAS.
14 Three-phase fault at the Bridger 345 kV bus followed by simultaneous
loss of the Bridger -Populus #1 and Bridger -Threemile Knoll 345 Yes Yes
kV lines (4 cycles)and loss of two Bridger unit as part of RAS.
15 Three-phase fault at the Dave Johnston 230 kV bus followed by the
loss of Dave Johnston -Amasa 230 kV circuit (5 cycles)and loss of Yes Yes
Q0306 as part of the RAS for this outage.
Transient stability plots are provided in AppendixA.
Transient stability results identified that with the model provided,all the wind turbines will ride
through all simulated local area disturbances.
The transient analysis showed high transient over voltage at the generator terminal (1.19 pu),
Q706 collector bus (1.15 pu),Q0706 230 kV bus (1.11 pu)for the loss of the Aeolus -Shirley
Basin 230 kV line.Similar high voltages were also observed for other simulated contingencies as
well.The transient high voltage last for a very short period of time.Figure 4 below shows the
voltage at the POI,at the Project collector bus and Project's machine terminal for the loss of
Aeolus to Shirley Basin 230 kV line.The simulation was run for 10 seconds but to observe the
high voltage,the plot is only from 0.0 sec to 2.5 sec.
8
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
lllllllll -F¯F¯F¯T*
I o
I
I :2 2So
1.e o.scono .aë·O L 5000 2.0000 2.5000
c
0.25004 0.75000 L.2500 1.7500 2.2500 THU,JUN 30 2016 16:08TIME(SECONDSI VOLTAGE 00706
While this may be a model problem,the Interconnection Customer should ensure that Project's
equipment is capable of handling the high voltage transient during the outages.If the
Interconnection Customer is unable to handle such high voltage without tripping the Project,
other mitigation should be implemented to mitigate the high voltage.If this is a model issue,the
Customer must submit a corrected model.
The wind turbines are connected electricallynear transmission lines that have series capacitors,
hence studies to consider sub-synchronous control interactions (SSCI)are highly
recommended.If such interactions occur,it is the responsibility of the Project to provide
remedies and adequate protection to ensure the sub-synchronous interactions are mitigated.
Transmission Provider requires written confirmation that the interconnection customer
has considered this issue and taken action as necessary.
9
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Conclusions
The followingconclusions have been reached through this analysis:
Based on simulation results,the addition of 125 GE 2.0-116 wind turbine generators
interconnecting to the proposed Aeolus 230 kV substation does not result in transient instability
and all wind turbines will ride through all simulated local area contingencies.
High voltage at the POI,collector bus and the machine terminal bus were observed for the
outage of Aeolus -Shirley Basin 230 kV line as well as other simulated contingencies.While
this may be a model issue,the Interconnection Customer will need to confirm that the equipment
used by the Interconnection Customer is capable of handling that voltage level or ensure other
mitigation is performed to mitigate the high voltage.
Simulation results are based on data provided by the Interconnection Customer as well as other
model data available at the time of the study.The results can be used to help determine whether
or not the Project facilities will meet the performance criteria including ride-through
requirements which will be defined in the Interconnection Agreement,and,in some cases,may
indicate that additional equipment is required in order to meet these requirements.However,
ultimately it is the Interconnection Customer's responsibility to meet these requirements during
actual operation on a daily basis and failure to do so can result in loss of interconnection
privileges.Therefore,the results of these simulations should be regarded as informational rather
than definitive,and do not relieve the Interconnection Customer of any performance
responsibilities.
Finally,if the assumptions utilized in this study significantly change,the Transmission Provider
reserves the right to perform a re-study.Significant changes include,but are not limited to,
development of new models which may impact performance as well as changes to the base case
assumptions for planned future but as yet uncommitted transmission line and generation
facilities.
10
PACIFICORP
A MIDAMERlCAN ENERGY HOLOlNGS COMPANY
Appendices
11
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Appendix A:Transient Stability Plots
Plotted Quantities in every plot in the Appendix
Sr.No.Trace Color Plotted Quantity
1 Black Q0706 Phase A MW
2 Blue Q0706 Phase A MVAR
3 Red Q0706 Terminal Voltage (pu)
4 Pink Dave Johnston Unit #4 Terminal Voltage (pu)
5 Cyan Aeolus 230 kV Voltage (pu)
6 Green Jim Bridger 345 kV Voltage (pu)
Figure ContingencyDescription
1
Three-phase fault at Aeolus 500 kV bus followed by
loss of the Aeolus 500/230 auto transformer #1 (4 cycles).
2 Three-phase fault at the Aeolus 500 kV bus followed by
loss of the Aeolus -Anticline 500 kV circuit (4 cycles)and loss of 600 MW of generation as part
of the RAS.
3 Three-phase fault at the Aeolus 500 kV bus followed by
loss of the Aeolus -Clover 500 kV circuit (4 cycles)and loss of 600 MW of generation as part of
the RAS.
4 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Freezeout 230 kV circuit (5 cycles).
5 Three-phase fault at the Aeolus 230 kV bus followedby
loss of the Aeolus -Q0199 Collector 230 kV circuit (5 cycles)and loss of 400 MW of generation
(Q0199,Q0200,Q0201)
6 Three-phase fault at the Aeolus 230 kV bus followedby
loss of the Aeolus -Q0706 Collector 230 kV circuit (5 cycles)and loss of 250 MW of generation
(Q0706)
7 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Shirley Basin 230 kV circuit (5 cycles).
8 Three-phase fault at the Aeolus 230 kV bus followed by breaker failure at Aeolus and delayed
clearing (15 cycles)of the Aeolus -Shirley Basin 230 kV circuit (15 cycles).
9 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus SVC (5 cycles).
10 Three-phase fault at the Aeolus 230 kV bus followed by
loss of the Aeolus -Windstar 230 kV circuit (5 cycles).
11 Three-phase fault at the Anticline 500 kV bus followed by
loss of the Anticline -Populus 500 kV circuit (4 cycles)and loss of 600 MW of generationas part
of the RAS.
12
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
12 Three-phase fault at the Anticline 500 kV bus followed by
loss of the Anticline 500/345 kV PST (4 cycles).
13 Three-phase fault at the Bridger 345 kV bus followed by simultaneous loss of the Bridger -
Populus #1 and Bridger -Populus #2 345 kV lines (4 cycles)and loss of two Bridger units as
part of RAS.
14 Three-phase fault at the Bridger 345 kV bus followed by simultaneous loss of the Bridger -
Populus #1 and Bridger -Threemile Knoll 345 kV lines (4 cycles)and loss of two Bridger unit as
part of RAS.
15 Three-phase fault at the Dave Johnston 230 kV bus followed by the loss of Dave Johnston -
Amasa 230 kV circuit (5 cycles)and loss of Q0306 as part of the RAS for this outage.
13
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Off-peak Case Plots
14
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014 U)
s1ENENs PowERTscamoLoozEsINTERNATIonAva
FILE:...\LightLoadOutputFiles\17HS LL QO706 AeolusPOI 3ph AE500230.out
CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]1.5000 +¯------+o.soooo
CHNL#1111:[VOLT 99721 [QO706A GEN 0.6900]]
1.5000 *-----------0.50000
CHNL#334:[VARS 99721[Q0706A GEN 0.690011]
1.5000 ----1.000
CHNL#222:[POWR 99721[Q0706A GEN 0.690011]
2.5000 0.0
I
I
o
o
I
I
IIII|1|||:
Figure 1
15
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTEH AELECTRICITY ECOORI NATA
E DE
lCV[BER5,2014
TEcHNoLoo1Es
F ..\LightLoadOutputFiles\17HS LL QO706 AeolusPOI 3ph AEANT500.out
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CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
1.5000 +------*o.soooo O
CHNL#1111:[VOLT 99721 [QO706A GEN 0.6900]]
1.5000 *----------o.soooo
CHNL#334:[VARS 99721[QO706A GEN 0.6900]1]
1.5000 -1.000
CHNL#222:[POWR 99721[QO706A GEN 0.6900]1]
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Figure 2
16
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WIŒTEHEAELECTRICITYCOORDINA ANE
DE MBER 5,2014
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ersa-zo-...\LightLoadOutputFiles\17HSLL QO706 AeolusPOI 3ph AECL500.out
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CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
1.5000 ------*o.Soooo Ro O
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1.5000 +-----------e o.soooo c'
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CHNL#222:[POWR 99721[QO706A GEN 0.6900]l]
2.5000 0.0
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Figure 3
17
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTEHR AELECTRICITY COORDINATA
E DE
lCVIBER5,2014
cHuoLoo1Es
I ...\LightLoadOutputFiles\17HS_LL_Q0706 AeolusPOI 3ph AEFZ230 .out
CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
1.5000 +------+o.soooo O
CHNL#1111:[VOLT 99721 [Q0706A GEN 0.6900]]
1.sooo *-----------0.50000
CHNL#334:[VARS 99721[QO706A GEN 0.6900]1]
1.5000 +----1.000
CHNL#222:[POWR 99721[QO706A GEN 0.690011]
2.5000 0.0
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Figure 4
18
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014 *O
szEMENs PowER 
TscHuoroozes oINTERNArroNAna
FILE:17HS LL QO706 AeolusPOI 3ph AEQ0199POI230.out
CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
1.5000 +------*o.soooo
CHNL#1111:[VOLT 99721 [QO706A GEN 0.6900]]1.5000 +-----------e o.soooo
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1.5000 ----1.000
CHNL#222:[POWR 99721[QO706A GEN 0.690011]2.5000 0.0
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Figure 5
19
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014
s1EmNs PowERreemosoozesINTERNATIoNAn
FILE:17HS LL QO706 AeolusPOI 3ph AEQO706POI230.out
CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
1.5000 +------0.50000
CHNL#1111:[VOLT 99721 [Q0706A GEN 0.6900]]
1.5000 +----------o.soooo
CHNL#334:[VARS 99721[Q0706A GEN 0.6900]1]
1.5000 ----1.000
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Figure 6
20
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014
s1EMENs PowERTscswoLoozesINTERNATIoNAn2
FILE:...\LightLoadOutputFiles\17HS LL QO706 AeolusPOI 3ph AESB230.out
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CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
1.5000 +------+o.soooo
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i.sooo +-----------e o.soooo
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1.5000 ----1.000
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Figure 7
21
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014 LO
s1EMENs PowERTEcHNonoozesINTERNATIonAna
FILE:17HS LL Q0706 AeolusPOI 3ph AESB230DL15CYC.out
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CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 8
22
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014
s1EMENs PowERTEcHuoLoozEsINTERNATIoNAna
FILE:...\LightLoadOutputFiles\17HS LL QO706 AeolusPOI 3ph AESVC230.out
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CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
i.sooo +------+o.soooo
CHNL#1111:[VOLT 99721 [QO706A GEN O .6900]]i.sooo +-----------+o.soooo
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Figure 9
23
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014 |O
s1EMENs PowER "
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FILE:...\LightLoadOutputFiles\17HS LL QO706 AeolusPOI 3ph AEWS230 .out
CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
1.5000 +------+o.soooo
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Figure 10
24
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014
FILE:...\LightLoadOutputFiles\17HS LL Q0706 AeolusPOI 3ph ANTPOP500.out
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CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 11
25
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014 L
s1EMENs PowER "
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Figure 12
26
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WIŒTEHR AELECTRICITY COORDINA
A E
ICE lCVIBER5,2014
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CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
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1.5000 ----1.000
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Figure 13
27
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
E AELE R ITY COORI NA
A E DE MBER 5,2014
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CHNL#1004:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 14
28
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014 |>
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FILE:...\LightLoadOutputFiles\17HS LL QO706 AeolusPOI 3ph DJAMSA230 .out ©
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Figure 15
29
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
Peak Case Plots
30
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014 U)
FILE:...\HeavyLoadOutputFiles\17HS HL QO706 AeolusPOI 3ph AE500230.out
CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 16
31
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014 *|>
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FILE:...\HeavyLoadOutputFiles\17HS HL Q0706 AeolusPOI 3ph AEANT500.out
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CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 17
32
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014
SIEMENs PowERTECHNoLOGIES
FILE:...\HeavyLoadOutputFiles\17HS HL Q0706 AeolusPOI 3ph AECL500.out
s-I I
CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 18
33
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014
s1EMENs PowERTEcHNoLoo1Es C)
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CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 19
34
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014
FILE:17HS HL QO706 AeolusPOI 3ph AEQOl99POI230 .out
CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 20
35
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014
szEMENs PowERTscHuotoezas
FILE:17HS HL Q0706 AeolusPOI 3ph AEQ0706POI230.out
CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
1.sooo *------+o.soooo MOCHNL#1127:[VOLT 99721 [QO706A GEN 0.6900]]
1.5000 *-----------o.soooo e
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Figure 21
36
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014
srEMENs PowERTEcHuoLos1Es
F ...\HeavyLoadOutputFiles\17HS HL QO706 AeolusPOI 3ph AESB230.out
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CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 22
37
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014 L
s1EMENs PowERTscHuoLoozEsINTERNATIonAna
FILE:17HS HL QO706 AeolusPOI 3ph AESB230DL15CYC.out
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CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 23
38
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014
FILE:...\HeavyLoadOutputFiles\17HS HL QO706 AeolusPOI 3ph AESVC230.out
CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 24
39
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014 °O
s1EMENs PowER ''
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Figure 25
40
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014 °O
sImmENs PowsR "
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CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 26
41
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014 °L
s1EMENs PowER ''
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Figure 27
42
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL
2015 HEAVY SUMMER OPERATING CASE DECEMBER 5,2014
SIEMENs PoWERTECHNoLOGIESINTERNATIonAva
FILE:...\HeavyLoadOutputFiles\17HS HL Q0706 AeolusPOI 3ph BRGPOP12.out
s-I I
CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
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Figure 28
43
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
W TER AELECTRICITY COORIJINACA
E DE lCVIBER5,2014
recHuoroozes oINTERNxr10NAna
FILE:17HS HL Q0706 AeolusPOI 3ph BRGPOP1 BRGTMK1.out
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i.sooo +------+0.50000 MOCHNL#1127:[VOLT 99721 [QO706A GEN O.6900]]
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Figure 29
44
PACIFICORP
A MIDAMERICAN ENERGY HOLDINGS COMPANY
WESTERN ELECTRICITY COORDINATING COUNCIL2015HEAVYSUMMEROPERATINGCASEDECEMBER 5,2014
s1EMENs PowERTEcaroLoozEsINTERNATIoNAna
FILE:...\HeavyLoadOutputFiles\17HS HL Q0706 AeolusPOI 3ph DJAMSA230.out N
CHNL#1020:[VOLT 65445 [DAVEJON4 22.000]]
i.sooo +------+o.soooo
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Figure 30
45