20180307PAC to Staff UT Q810FEAS.pdf

PACIFICORP
Large Generator Interconnection
Feasibility Study Report
Completed for
("Interconnection Customer")
Q0810
Proposed Primary Point of Interconnection
Q0715 Point of Interconnection Substation
(shared tie-line with Q0715)
Proposed Alternate Point of Interconnection
Q0715 Point of Interconnection Substation
(separate tie-line from Q0715)
September 8,2017
V PACF I CORP
s...;g¡¡¡gystudy Report
TABLE OF CONTENTS
1.0 DESCRIPTION OF THE GENERATING FACILITY ..............................................................1
2.0 SCOPEOFTHESTUDY ...............................................................................................................1
3.0 TYPE OF INTERCONNECTION SERVICE..............................................................................1
4.0 DESCRIPTION OF PROPOSED INTERCONNECTION.........................................................1
4.1 OTHER OPTIONSCONSIDERED(NERC REQUIREMENT)...............................................2
5.0 STUDY A SSUMPTI ONS ...............................................................................................................4
6.0 ENERGY RESOURCE(ER)INTERCONNECTION SERVICE..............................................5
6.1 REQUIREMENTS-PRIMARY POINT OF INTERCONNECTION...............................................5
6 1.1 Generating Facility Modifications............................................5
6 1.2 Transmission System Modifications.............................................7
6 1.3 Existing Circuit Breaker Upgrades -Short Circuit...........................................7
6 1.4 Protection Requirements...........................................7
6 1.5 Data (RTU)Requirements .........................................................................7
6.2 COST ESTIMATE -PRIMARY POINT OF INTERCONNECTION.................................................S
6.3 SCHEDULE-PRIMARY POINT OF INTERCONNECTION.....................................................................9
6 3.1 Maximum Amount o Power that can be deliveredinto NetworkLoad,with No Transmission
Modifications(for in ormationalpurposes only)............................................................................9
6 3.2 Additional Transmission ModificationsRequired to Deliver 100%o the Power into NetworkLoad
(or in ormationalpurposes only)...................................................................9
6.4 REQUIREMENTS-SECONDARYPOINT OF INTERCONNECTION ..............................................9
6 4.1 Generating Facility Modifications............................................9
6 4.2 Transmission System Modifications..............................................11
6 4.3 Existing Circuit Breaker Upgrades -Short Circuit............................................12
6 4.4 Protection Requirements...........................................12
6 4.5 Data (RTU)Requirements ..............................................................................13
6.5 COST ESTIMATE -SECONDARYPOINT OF INTERCONNECTION...............................................14
6.6 SCHEDULE-SECONDARYPOINT OF INTERCONNECTION ...............................................................14
6 6 1 Maximum Amount o Power that can be deliveredinto NetworkLoad,with No Transmission
Modifications(or in ormationalpurposes only).........................................................................15
6 6 2 Additional Transmission ModificationsRequired to Deliver 100%o the Power into NetworkLoadin
addition to the ER requirements and with all assumed upgrades in service(forin ormational
purposes only).............................................................15
7.0 NETWORK RESOURCE (NR)INTERCONNECTION SERVICE .......................................15
7.1 REQUIREMENTS................................................15
7 1.1 Generating Facility Modifications............................................15
7 1.2 Transmission System Modifications...........................................15
7.2 COST ESTIMATE................................................15
7.3 SCHEDULE..............................................16
8.0 PARTICIPATION BY AFFE CTED SYSTEMS........................................................................16
9.0 APPEND ICES ...............................................................................................................................16
9.1 APPENDIX 1:HIGHER PRIORITY REQUESTS................................................17
9.2 APPENDIX 2:PROPERTYREQUIREMENTS..............................................18
9.3 APPENDIX 3:STUDY RESULTS ..............................................20
Page i September 8,,2017
,Q0810
Y PACIFICORP
Feasibility Study Report
1.0 DESCRIPTION OF THE GENERATING FACILITY
("InterconnectionCustomer")proposed interconnecting 101 MW of new generationto the Point
of Interconnection substation proposed to be constructed on PacifiCorp's ("Transmission
Provider")Whitneytap of the Canyon Compression-Railroad as part of the Q0715 project located
in Uinta County,Wyoming.The Interconnection Customer's primary Point of Interconnection is
an addition to the Q0715 project.The Interconnection Customer has also proposed interconnecting
the new generationin a new position at the Q0715 Point of Interconnection substation.The project
("Project")will consist of 44 GeneralElectric 2.3 MW turbines 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 Feasibility Study ("Study")report shall provide the followinganalyses for the
purpose of identifying any potential adverse system impacts that would result from the
interconnection of the GeneratingFacility as proposed:
preliminaryidentification of any circuit breaker short circuit capability limits exceeded as
a result of the interconnection;
preliminaryidentification of any thermal overload or voltage limit violations resulting
from the interconnection;and
preliminarydescription and non-binding estimated cost of facilities required to
interconnect the Generating Facility to the Transmission Provider's Distribution or
Transmission System and to address the identified short circuit and power flow issues.
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 GeneratingFacility is to be interconnecteddirectly
with the Q0715 project via the same interconnection point.Figure 1 below,is a one-line diagram
that illustrates the interconnection of the proposed Generating Facility to the Transmission
Provider's system at the primary Point of Interconnection.
Page 1 September 8,,2017
,Q0810
V PAGRCORP
s...ystudyReport
Whitney
Ca on
i CanyonCompression
Q0715 POI
Sub a ion
Interconnection
138 kV
Railroad
Change of
Ownership
6 Miles
68/90/112MVA138-34.5kV
Z =9 %
Q0810 34.5 kVCollector
Substation
34.5 kV
C le tor
Q0715 Collector
Substation
Figure 1:Simplified System One Line Diagram -Primary Point ofInterconnection
4.1 Other Options Considered (NERC Requirement)
The followingalternative Point of Interconnection will be considered in this report:
The Interconnection Customer's proposed GeneratingFacility is to be interconnectedvia a
new line position in the Point of Interconnection substation proposed to be constructed by the
Q0715 project.
Page 2 September 8,,2017
,Q0810
V PACR CORP
s...;g¡¡¡¡y study Report
Figure 2 below,is a one-line diagram that illustrates the interconnection of the proposed
Generating Facility to the Transmission Provider's system at the alternate Point of
Interconnection.
Whitney
Canyon
i Canyon Compression
/Q0715 POI
138 kV
Q0715Railroad
Change of
Ownership
6 Miles
68/90/112 MVA
138 -34 5 kV
Z =9 %
Q0810 34.5 kVCollector
Substation
Figure 2:Simplified System One Line Diagram -Alternate Point ofInterconnection
Page 3 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
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,
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 generation 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 Transmission Provider's system at
agreed upon and/or proposed Point of Interconnection ("POI").
The Interconnection Customer will construct and own any facilities required between the POI
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 ReliabilityCorporation ("NERC"),and the Transmission
Provider's performance and design standards.
All system improvements associated with the prior queued projects are in service before
Q0810.
The Q0715 project must be complete prior to the interconnection of this Project.
The Energy Gateway West (2024)and Energy Gateway South (2024)projects are assumed to
be in service;the Dave Johnston to Amasa 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 Q0810
Project planned in-service date.
Page 4 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
A Remedial Action Scheme ("RAS")that will drop up to 600 MW of generation (whichmay
include this project)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
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
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 Requirements-PrimaryPoint of Interconnection
6.1.1 Generating Facility 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-synchronous
generators,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 generatingunits shall be accuratelyrepresented
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.
Generating Facilities capable of operating with a voltage droop are required to do so.
Page 5 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
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 performed,in coordination with Transmission Provider,and
implemented with appropriate coordination settings prior to unit testing.
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 appropriatedby 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.
For areas with multiple generating facilities additional studies may be required to
determine whether or not critical interactions,includingbut 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 Measurement Units
(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 GeneratorFacility'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 Coordinated Universal 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 continuallyupdated and is available on the http://www.WECC.biz
website.
Page 6 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
6.1.2 Transmission System Modifications
No additional modifications to the POI substation are required beyond those identified
by Q0715.The modifications identified in Q0715 must be completed prior to
commissioning this facility.
Modify the existing Naughton West RAS to integratethe Q0810 Project.If the average
of the flows West of Naughton &West of Railroad is above approximately 1250 MW,
Q0810 will be armed to trip for the N-1-1 and N-2 outages of either the Ben Lomond
-Birch Creek and Ben Lomond -Naughton 230 kV lines or the Naughton -Birch
Creek and Ben Lomond -Naughton 230 kV lines.
o Capability to trip Q0810 Project if necessary under N-1-1 and N-2 outages
described above.
o Requires redundant communication from the RAS controller to the Project.
All improvements below must be in service prior to this facility being commissioned:
o The Energy Gateway West (2024)and Energy Gateway South (2024)projects
o The Dave Johnston to Amasa to Aeolus (future)230 kV line must be rebuilt as part
of the Gateway projects.(Note that these dates are inconsistent with the Q0810
Project planned in-service date.)
o A Remedial Action Scheme ("RAS")that will drop up to 600 MW of generation
(whichmay include this project)for the followingoutages:
Aeolus -Anticline 500 kV line
Anticline -Populus 500 kV line
Aeolus -Clover 500 kV line
Clover 500/345 kV auto transformer
6.1.3 ExistingCircuit Breaker Upgrades -Short Circuit
The increase in the fault duty on 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
interrupting rating of any of the Transmission Provider's existing fault interrupting
equipment.
6.1.4 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 projects for faults on the 138 kV tie line and trip both 138 kV breakers for the
two projects.The tie line relays at the Q0715 POI substation's voltage and frequency
elements will trip the tie line 138 kV breakers for under or over out of tolerance conditions.
Those relays will also operate in a step distance mode to respond to faults on the tie line to
the collector substation.
6.1.5 Data (RTU)Requirements
Data for the operation of the power system will be needed from the collector substation.
Listed is the data that will be acquired from the collector substation.
Page 7 September 8,,2017
,Q0810
V PAGRCORP
s...ystudyReport
From the Q0715 collector substation:
Analogs:
Net GenerationMW
Net GeneratorMVAR
Interchangemetering kWH
From the Q0810 collector substation:
Analogs:
Net GenerationMW
Net GeneratorMVAR
Interchangemetering kWH
34.5 kV Real power Fl
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
6.2 Cost Estimate -Primary Point of Interconnection
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,Communication Coordination,Control House
Q0715 Collector Substation $413,000
Metering,Communication Coordination,Control House
Page 8 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
Q0715 Point of Interconnection Substation $30,000
Relay and Communication Modifications
Naughton Substation $30,000
ModifyRAS
Grand Total $886,000
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
calculatedduring the System Impact Study.The Interconnection Customer will be responsible for
all actual costs,regardless of the estimated costs communicated to or approved by the
Interconnection Customer.
6.3 Schedule -PrimaryPoint of Interconnection
The Transmission Provider estimates it will require approximately 12 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
developedand optimized during the System Impact Study.
Please note,the Transmission Provider's Gateway Projects,which are required for this Project,
are currently assumed to be in service in 2024 which does not support the Interconnection
Customer's requested commercial operation date of July 1,2019.In addition,the
Interconnection Facilities described and required for Q715 must be in-service either prior to,
or concurrent with,Q810.
6.3.1 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 after the system improvements outlined in section 6.1.2 are done and
assuming all improvements identified in section 5.0 are in service.
6.3.2 Additional Transmission Modifications Required to Deliver 100%of the
Power into Network Load (for informational purposes only)
Assuming the improvements identified under the Section 5.0 Study Assumptions of this
report are in service,no additional modifications beyond improvementsmentioned in 6.1.2
are required.
6.4 Requirements-Secondary Point of Interconnection
6.4.1 Generating Facility Modifications
All interconnecting synchronous and non-synchronous generators are required to design
their Generating Facilities with reactive power capabilities necessary to operate within the
Page 9 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
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-synchronous
generators,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 equippedwith automatic voltage-
control equipment and normallyoperated 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,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.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 performed,in
coordination with Transmission Provider,and implemented with appropriate coordination
settmgs prior to unit testing.
For areas with multiple generating facilities additional studies may be required to
determine whether or not critical interactions,includingbut 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
Page 10 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
interaction/coordination studies will be required pre-and post-commercial operation in
order ensure system reliability.
Phasor Measurement Units (PMUs)will be required at any Generating Facilities with an
individual or aggregate nameplate capacity of 75 MVA or greater.To facilitate collection
and validation of accurate modeling data to meet NERC modeling standards,PacifiCorp,
as the Planning Coordinator,requires Phasor Measurement Units (PMUs)at all new
Generating Facilities 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 synchronized within +/-2 milliseconds
of the Coordinated Universal 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.The Interconnection Customer is responsible for the protection
of the transmission line between the Generating Facility and the POI substation.In order
to provide this protection the Interconnection Customer shall construct and own a tie-line
substation to be located at the change of ownership (separate fenced facility adjacent to the
Transmission Provider's POI substation)and include an Interconnection Customer owned
protective device and associated transmission line relaying/communications.The ground
grids of the Transmission Provider's POI substation and the Interconnection Customer's
tie-line substation will be connected to support the use of a bus differential protection
scheme which will protect the overhead bus connection between the two facilities.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.
6.4.2 Transmission System Modifications
(See Figure 2 for a one-line diagram of the POI and surrounding system)
Install a 138 kV circuit breaker at the Q0715 POI substation to create a new bus
position.
Install a RMP 138 kV meter on the line between the POI and the tie-line substation
(customer-owned).
The modifications identified in Q0715 must be completed prior to commissioning this
facility.
Modify the existing Naughton West RAS to integratethe Q0810 Project.If the average
of the flows West of Naughton &West of Railroad is above approximately 1250 MW,
Page 11 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
Q0810 will be armed to trip for the N-1-1 and N-2 outages of either the Ben Lomond
-Birch Creek and Ben Lomond -Naughton 230 kV lines or the Naughton -Birch
Creek and Ben Lomond -Naughton 230 kV lines.
o Capability to trip Q0810 Project if necessary under N-1-1 and N-2 outages
described above.
o Requires redundant communication from the RAS controller to the Project.
All improvements below must be in service prior to this facility being commissioned:
o The Energy Gateway West (2024)and Energy Gateway South (2024)projects
o The Dave Johnston to Amasa to Aeolus (future)230 kV line must be rebuilt as
part of the Gatewayprojects.(Note that these dates are inconsistent with the
Q0810 Project planned in-service date.)
o A Remedial Action Scheme ("RAS")that will drop up to 600 MW of generation
(whichmay include this project)for the followingoutages:
Aeolus -Anticline 500 kV line
Anticline -Populus 500 kV line
Aeolus -Clover 500 kV line
Clover 500/345 kV auto transformer
6.4.3 ExistingCircuit Breaker Upgrades -Short Circuit
The increase in the fault duty on 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
interrupting rating of any of the Transmission Provider's existing fault interrupting
equipment.
6.4.4 Protection Requirements.
The ground mats of the Interconnection Customer's tie line substation and the Q0715 POI
substation must be tied together so that metallic control cables can be used between the
two facilities.Bus differential relays will be applied to detect faults on this connection.
With this arrangement the Interconnection Customer must install line relays systems that
will detect and clear all faults on the tie lines in 5 cycles or less.A set of non-pilot step
distance line relays that will detect faults on the tie line will also be applied at the Q0715
POI substation.Should the Interconnection Customer desire a potential alternative to the
tie line substation in order to provide adequate protection to its tie line,the Interconnection
Customer may petition the Transmission Provider for an exemption to this
arrangement.The Transmission Provider must review and approve the Interconnection
Customer's proposed alternative.Without approval of the proposed alternative the tie line
substation configuration will be required.The Generation Interconnection Customer will
still need is to supply and maintain sets of line relays to be installed at Q0810 collector
substation that will detect faults on the 138 kV line back to the Q0715 POI substation.
These line relays can be time coordinated with the relays detecting faults on the
transmission network and will not communicate with the line relays to be installed at the
Q0715 POI substation for the tie line.
Page 12 September 8,,2017
,Q0810
V PAC F1CO RP
s..syg¡¡¡gy study Report
Protective relay elements in the line relays at the Q0715 POI substation will monitor
voltage and frequency.If the voltage,magnitude or frequency is outside of the normal
operation range,this relay will trip the 138 kV breakers for the tie line at the Q0715 POI
substation.
A modification to the Naughton West RAS is planned for the Q0715 project.As part of
that project the 138 kV breakers at the Q0715 POI substation on the tie line to that project
will be tripped for the loss of transmission lines west of the Naughton.For this project
signals will be added to the RAS to trip the breakers at the Q0715 POI substation for the
tie line to the Q0810 collector substation.
6.4.5 Data (RTU)Requirements
The RTU that is planned to be install in the new Q0715 POI substation which will make is
possible for the Transmission Provider to remotely monitor and operate the breakers at the
POI substation will be used to control and monitor the new 138 kV breaker at that
substation.Data for the operation of the power system will also be needed from the
Collector substation.In addition to the control and indication of the 138 kV breakers in
POI substation the followingdata will be acquired through the RTU.Also listed is the data
that will be acquired from the Collector substation.
From the POI Substation:
Analogs:
Net GenerationMW
Net GeneratorMVAR
Interchangemetering kWH
From the Q0810 collector substation:
Analogs:
138 kV A phase voltage
138 kV B phase voltage
138 kV C phase voltage
34.5 kV Real power Fl
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)
Page 13 September 8,,2017
,Q0810
V PAGF\CORP
s...ystudyReport
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
From the Q0810 tie line substation:
Status:
138 kV breaker
6.5 Cost Estimate -Secondary Point of Interconnection
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 and Tie Line Substations $45,000
Communications and Protection &Control Coordination
Q0715 POI Substation $1,800,000
Create line position,Metering,Communications and Protection &Control
Naughton Substation $30,000
ModifyRAS
Grand Total $1,875,000
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
calculatedduring the System Impact Study.The Interconnection Customer will be responsible for
all actual costs,regardless of the estimated costs communicated to or approved by the
Interconnection Customer.
6.6 Schedule -Secondary Point of Interconnection
The Transmission Provider estimates it will require approximately 24 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
developedand optimized during the System Impact Study.
Page 14 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
Please note,the Transmission Provider's Gateway Projects,which are required for this Project,
are currently assumed to be in service in 2024 which does not support the Interconnection
Customer's requested commercial operation date of July 1,2019.In addition,the
Interconnection Facilities described and required for Q715 must be in-service either prior to,
or concurrent with,Q810.
6.6.1 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 after the system improvements outlined in section 6.4.2 are done and
assuming all improvements identified in section 5.0 are in service.
6.6.2 Additional Transmission Modifications Required to Deliver 100%of the
Power into Network Load in addition to the ER requirements and with all
assumed upgrades in service (for informational purposes only)
Assuming the improvements identified under the Section 5.0 Study Assumptions of this
report are in service,no additional modifications beyond improvementsmentioned in 6.4.2
are required.
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 varietyof severely stressed
conditions in order to determine the transmission modifications which are necessary in order to
deliver the aggregate generationin 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
7.1 Requirements(Primaryand Secondary POI)
7.1.1 Generating Facility Modifications
(See section 6.1.1 or section 6.4.1 as applicable)
7.1.2 Transmission System Modifications
(See section 6.1.2 or section 6.4.2 as applicable)
7.2 Cost Estimate
No additional costs are anticipated should all improvements identified for Energy Resource
Interconnection Service and all assumed improvements be completed for the applicable POI
option.
Page 15 September 8,,2017
,Q0810
Y PACIFICORP
Feasibility Study Report
7.3 Schedule
Please note,the Transmission Provider's Gateway Projects,which are required for this Project,
are currently assumed to be in service in 2024 which does not support the Interconnection
Customer's requested commercial operation date of July 1,2019.
8.0 PARTICIPATION BY AFFECTED SYSTEMS
Transmission Provider has identified the followingas Affected Systems:None
9.0 APPENDICES
Appendix 1:Higher Priority Requests
Appendix 2:Property Requirements
Appendix 3:Study Results
Page 16 September 8,,2017
,Q0810
Y PACIFICORP
Feasibility Study Report
9.1 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:
Q0290 A-C (252 MW)-ER
Q0409 A-D (320 MW)-QF
Q0542 (240 MW)-QF
Q0706 (250 MW)-ER
Q0707 (250 MW)-ER
Q0708 (250 MW)-ER
Q0712 (520 MW)-ER
Q0713 (350 MW)-ER
Q0715 (120 MW)-ER
Q0719 (280 MW)-QF
Q0720 (80 MW)-QF
Q0783 (30 MW)-QF
Q0784 (80 MW)-ER/NR
Q0785 (100 MW)-ER/NR
Q0786 (100 MW)-ER/NR
Q0789 (74.9 MW)-QF
Q0795 (20 MW)-QF
Q0796 (20 MW)-QF
Q0801 (80 MW)-QF
Q0802 (80 MW)-ER/NR
Q0807 (75.9 MW)-QF
Q0809 (20 MW)-QF
Page 17 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
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
Page 18 September 8,,2017
,Q0810
Y PACIFICORP
Feasibility Study Report
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.
Page 19 September 8,,2017
,Q0810
V PACI F\CORP
s..syg¡¡¡gy study Report
9.3 Appendix3:Study Results
Power Flow Study Results
A Western Electricity Coordinating Council (WECC)approved 2016 Heavy Summer case was
used to perform the power flow studies using PSS/E version 33.7.The 2016 Heavy Summer case
was modified for the study.The study was performed assuming the Energy Gateway Projects are
in-service.The local 230 kV and 138 kV transmission system outages were considered during
the study.
N-0 Results:Assuming Energy Gateway,the system improvements associated with the prior
queued projects,and the system improvements deemed necessary in this study are in service,no
N-0 thermal or voltage issues were observed in the studies.
N-1 Results:Assuming Energy Gateway,the system improvements associated with the prior
queued projects,and the system improvements deemed necessary in this study are in service,no
N-1 thermal or voltage issues were observed in the studies.
N-1-1 Results:Assuming Energy Gateway and the system improvements associated with the
prior queued projects are all in service there are a number of N-1-1 thermal issues that occur in
the ER study if generation in the Naughton/Railroad 138 kV system is not reduced between
outages.
These N-1-1 outage issues are caused by the loss of one of the lines or transformers in the three
systems listed below,as well as a second loss of a different piece of equipment in one of those
systems after the system returns to steady state:
All 138 kV lines between Naughton and Railroad
The three 230-138 kV transformers at Naughton and Railroad
The 230 kV line from to Birch Creek to Naughton
The 230 kV line from to Birch Creek to Railroad
The 230 kV line from Ben Lomond to Birch Creek
The 230 kV line from Ben Lomond to Naughton
The 138 kV line between the Q0786 POI and Silver Creek
The 138 kV line between Jordanelle and Midway
The thermal issues that occur during the N-1-1 outage situations are overloads of the following
lines:
Naughton -Carter Creek -Canyon Compression (35.0 miles)
Naughton -Glenco -P204 -MuddyCreek (36.3 miles)
Canyon Compression -WhitneyTap -Q0715/Q0810 POI (1.4 Miles)
Q0715/Q0810 POI-Railroad (13.7 miles)
Longhollow-Painter -Painter Tap (10.9 miles)
Silver Creek -Snyderville Tap (9.5 miles)
Page 20 September 8,,2017
,Q0810
Y PACIFICORP
Feasibility Study Report
Without projects to rebuild and/or reconductor all of these lines these issues will require Grid
Operations to trip generationprojects in the area after some outages to prepare for a second
outage.Q0810 may be taken offline in these situations for this reason.
No N-1-1 voltage issues were observed in the studies.
N-2 Results:Assuming Energy Gateway,the system improvements associated with the prior
queued projects,and the system improvements deemed necessary in this study are in service,no
N-2 thermal or voltage issues were observed in the studies.
Page 21 September 8,,2017
,Q0810