Toronto Hydro-Electric System Limited
EB-2011-0144
Exhibit D1
Tab 12
Schedule 4
Appendix A
(62 pages)
TORONTO HYDRO SYSTEM CONNECTION
CAPACITY AND ENABLING OPTIONS FOR
DISTRIBUTED GENERATION
Presented to
Toronto Hydro-Electric System Limited
500 Commissioners Rd.
Toronto, ON M4M 3N7
MAY 2011
Navigant Consulting Ltd.
1 Adelaide Street East, Suite 3000
Toronto, ON M5C 2V9
416.927.1641
www.navigant.com
TABLE OF CONTENTS
1
EXECUTIVE S UMMARY ........................................................................................................................ 1
2
IN TROD UCTION ................................................................................................................................... 4
2.1
3
4
5
BACKGROUN D AN D POWER S YSTEM O VERVIEW ............................................................................ 7
3.1
Bu lk Pow er System H ierarchy and Ow nership .......................................................................... 7
3.2
Distribu tion System Top ology ...................................................................................................... 9
3.3
Short Circu it Capacity .................................................................................................................. 15
3.4
Feed er Thermal Rating and Transform er Therm al Cap acity .................................................. 16
3.5
Feed er Load Diversity .................................................................................................................. 18
3.6
Generation Cap acity and DG Scenarios ..................................................................................... 19
3.7
Conservation and Dem and Managem ent .................................................................................. 20
3.8
Load Transfer Scenarios ............................................................................................................... 20
3.9
Evolution of the Toronto-Area Distribu tion System ................................................................ 21
3.10
Lim iting Factors to Increased DG Penetration ........................................................................ 22
3.11
Ad d itional Details ....................................................................................................................... 27
D G CON N ECTION CAPACITY LIMITS ............................................................................................. 30
4.1
Derivation of DG Connection Cap acity Limits ......................................................................... 30
4.2
DG Connection Cap acity Lim its: Existing Cond itions ............................................................ 32
4.3
DG Connection Cap acity Lim its: After Leasid e and Manby Up grad es ................................ 35
EN ABLIN G O PTION S TO IN CREASE D G CON N ECTION CAPACITY .............................................. 38
5.1
6
7
Rep ort Contents ............................................................................................................................... 6
Imp act of Other Up grad es to the Area Transmission System ................................................ 42
COSTIN G AN D A PPLICATION OF EN ABLIN G O PTION S ................................................................. 43
6.1
Enabling Op tions for DG Cap acity ............................................................................................. 43
6.2
Pru d ent App roach to Enabling N ew DG Cap acity .................................................................. 46
6.3
Cost Im pact and Cost Recovery of Enabling Op tions .............................................................. 48
CON CLUSION S ................................................................................................................................... 50
A PPEN D IX A: CASE S TUD Y D ESCRIPTION S ............................................................................................ 52
A PPEN D IX B: POWER FLOW S IMULATION A N ALYSIS ............................................................................ 54
B.1 Backgrou nd and Method ology ........................................................................................................ 55
B.2 Short Circu it Analysis ....................................................................................................................... 57
B.3 Voltage Perform ance ......................................................................................................................... 58
A PPEN D IX C: EN ABLIN G O PTION D ETAILS ............................................................................................ 60
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page ii
1
E XECUTIVE S UMMARY
This Navigant study was commissioned by Toronto Hydro-Electric System Limited (THESL) in
response to the Ontario Energy Board’s (“OEB” or the “Board”) request to THESL in its EB2009-0139 decision. Specifically, the Board stated in its decision:
“THESL shall continue its analysis of the incorporation of [Distributed Generation] DG into its
Central and Downtown areas. In that regard it shall file a plan concurrent with its filing
according to its distribution system planning requirements.
The plan will contain an adoption of and justification for the “next steps” listed in the Navigant
study and referenced above, or in the alternative, rationale for an “alternative approach” to
determining the optimal power system configuration for Central and Downtown Toronto.”
The three “next steps” from the previous Navigant study1 referred to in the Board decision
include:
1. Gathering information with respect to the options and costs for upgrading the short-circuit
capabilities of the distribution and transmission system in this area, the effects of Toronto
Hydro's and the City of Toronto’s aggressive Conservation and Demand Management
(CDM) efforts, and an evaluation of the end of Life Asset Replacement plan for the
transmission system serving this area.
2. Further analysis to identify the preferred Local Area Integrated Electrical Service solution
that would serve as a long-term plan for the local subsystem that meets the unique issues
facing Central and Downtown Toronto. This analysis would assess local system impacts
and examine the short-term, midterm and long-term benefits and costs for each option.
3. Development of an implementation plan for the preferred solution that could include
development of additional CDM programs, working with stakeholders to lower barriers to
DG (including incentives as appropriate), reinforcing distribution and transmission system
facilities as necessary (leveraging Smart Grid initiatives where possible) and phasing of
system upgrades to manage short-circuit levels.
Per the Board’s request, THESL has continued its analysis of the incorporation of DG into its
distribution system through follow-on analysis undertaken by Navigant that is the subject of
this report and THESL’s own work in developing its Green Energy Act (GEA) Plan.
1
Central and Downtown Toronto Distributed Generation, Final Report, July 28, 2009, prepared for Toronto Hydro-Electric System
Limited and the Ontario Power Authority by Navigant Consulting Ltd.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 1
Navigant’s analytic approach was broadly consistent with the three “next steps” as identified in
the previous Navigant report with modifications as appropriate to reflect new information and
directions to THESL subsequent to the completion of the previous Navigant report. These key
changes relate to:
The requirement for THESL to prepare a GEA Plan,
The substantial number of connection requests to THESL under the FIT and microFIT
program, and
Hydro One Network Inc.’s (HONI’s) receipt of Board approval for upgrades to Manby and
Leaside TS (scheduled for 2012 or 2013) that will increase DG connection capacity in the
THESL system served through these stations.
Working closely with THESL engineering staff, Navigant assessed the DG connection capacity
across the THESL entire distribution system and identified various enabling options that would
address specific local DG connection constraints.
With respect to DG connection capacity on THESL’s 13.8kV and 27.6kV distribution system,
several feeders and busses were found to have significant DG connection capacity available,
whereas some feeders and busses were found to have very limited or no connection capacity.
In most areas with limited or no capacity, the current HONI transmission system is the limiting
constraint to new DG installations. THESL equipment is the limiting constraint for only a few
feeders and busses.
Navigant’s specific findings with respect to THESL’s DG connection capacity include:
Currently, new DG in downtown Toronto and the eastern section of the City is limited to
2
10 MW for PV (and zero for synchronous DG ) due to short circuit capacity limits at
HONI’s Leaside, Hearn and Manby stations, and transmission limits on the 230kV delivery
system East to Cherrywood station in Pickering,
OEB-approved upgrades to the HONI system over the next few years will increase the DG
connection capacity on THESL’s 13.8kV system to 377 MW for PV or 207 MW for
synchronous DG, and
Without considering the transmission system to which it is connected, THESL’s 27.6kV
system has connection capacity for up to 833 MW of PV or 693 MW of synchronous DG.
2
Inverter-based PV generation has different electrical characteristics than synchronous-based generation (such as for a mediumsized CHP installation), particularly with respect to fault current contribution. Given these differences, the available DG
connection capacity will depend on the type of generation to be connected. For simplicity Navigant refers to the connection
capacity for PV or for synchronous DG, whereas THESL is likely to get connection requests for a combination of generation types
and the connection capacity would likely fall between the values given for PV and synchronous DG.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 2
Considering the transmission system and HONI constraints, the connection capacity is
reduced to 356 MW for PV or 283 MW of synchronous DG.
Navigant and THESL jointly assessed the viability of the various enabling options as identified
by Navigant for potential inclusion in THESL’s GEA Plan. As part of this assessment, Navigant
and THESL estimated the likely range of costs and unit costs ($ / kW of DG enabled) for such
upgrades based on THESL’s system characteristics. Since there are several different types of
constraints, varying system configurations across THESL’s service territory and non-uniform
geographic and temporal distribution of DG connection requests, there is no single “silver
bullet” or option to address all of THESL’s DG connection capacity constraints.
In general, however, where mitigation and upgrades are needed, DG connection capacity can be
increased at a unit cost well below the installed cost of DG capacity. For feeders that are
constrained, the analysis undertaken by Navigant and THESL indicates that additional DG
connection capacity can be installed through a variety of enabling options at an expected cost
less than $300/kW of DG enabled with the following caveats:
Large DG (greater than 10 MW) may require dedicated feeders and station positions that
could cost more than $300/kW of DG enabled,
Local upgrades may still be required to address capacity and voltage constraints, and
Some enabling options require changes or upgrades to HONI system; notably, some
upgrades include replacement of HONI equipment that is 50 or more years old.
THESL’s GEA plan will incorporate appropriate enabling options into several local upgrade
plans that reflect local system constraints and the best available information on current and
forecast DG connection requirements on THESL’s stations and feeders. Together, the upgrade
plans proposed in THESL’s GEA Plan and HONI’s local transmission system upgrades will
significantly increase THESL’s DG connection capacity.
Even with these substantial upgrades, new DG connection applications outside THESL’s
current forecast may still be subject to constraints on certain feeders or buses. It is expected that
many of these constraints can be addressed through the application per THESL’s DG
requirements and cost recovery policy of the enabling options identified within this report.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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2
I NTRODUCTION
On August 28, 2009, Toronto Hydro-Electric System Limited (“THESL” or “Toronto Hydro”)
filed as part of its 2010 rate application (EB-2009-0139) a study by Navigant Consulting Ltd.
(the “previous Navigant study”) entitled “Central and Downtown Toronto Distributed Generation”.
The previous Navigant study concluded that distributed generation (DG) may be able to
provide some future electricity supply for Central and Downtown Toronto, but further analysis
is required to more fully understand how DG could serve the needs of Central and Downtown
Toronto and how it could serve the provincial government's policy objectives.
This current Navigant study was commissioned by THESL in response to the Ontario Energy
Board’s (OEB or Board) request to THESL in its EB-2009-0139 decision. Specifically, the Board
stated in its decision:
“THESL shall continue its analysis of the incorporation of [Distributed Generation] DG into its
Central and Downtown areas. In that regard it shall file a plan concurrent with its filing
according to its distribution system planning requirements.
The plan will contain an adoption of and justification for the “next steps” listed in the Navigant
study and referenced above, or in the alternative, rationale for an “alternative approach” to
determining the optimal power system configuration for Central and Downtown Toronto.”
The three “next steps” from the previous Navigant study3 referred to in the Board decision
include:
1. Gathering information with respect to the options and costs for upgrading the short-
circuit capabilities of the distribution and transmission system in this area, the effects of
Toronto Hydro's and the City of Toronto’s aggressive Conservation and Demand
Management (CDM) efforts, and an evaluation of the end of Life Asset Replacement
plan for the transmission system serving this area.
2. Further analysis to identify the preferred Local Area Integrated Electrical Service
solution that would serve as a long-term plan for the local subsystem that meets the
unique issues facing Central and Downtown Toronto. This analysis would assess local
system impacts and examine the short-term, midterm and long-term benefits and costs
for each option.
3
Central and Downtown Toronto Distributed Generation, Final Report, July 28, 2009, prepared for Toronto Hydro-Electric System
Limited and the Ontario Power Authority by Navigant Consulting Ltd.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 4
3. Development of an implementation plan for the preferred solution that could include
development of additional CDM programs, working with stakeholders to lower barriers
to DG (including incentives as appropriate), reinforcing distribution and transmission
system facilities as necessary (leveraging Smart Grid initiatives where possible) and
phasing of system upgrades to manage short-circuit levels.
Per the Board’s request, THESL has continued its analysis of the incorporation of DG into its
distribution system through follow-on analysis undertaken by Navigant that is the subject of
this report and THESL’s own work in developing its Green Energy Act (GEA) Plan.
Navigant’s analytic approach was broadly consistent with the three “next steps” as identified in
the previous Navigant report with modifications as appropriate to reflect new information and
directions to THESL subsequent to the completion of the previous Navigant report. These key
changes relate to:
The requirement for THESL to prepare a GEA Plan,
The substantial number of connection requests to THESL under the FIT and microFIT
program, and
Hydro One Network Inc.’s (HONI’s) receipt of Board approval for upgrades to Manby and
Leaside TS (scheduled for 2012 or 2013) that will increase DG connection capacity in the
THESL system served through these stations.
The Study covered two “phases” of local transmission and distribution system development:
The first phase (Stage 1) is based on existing and projected conditions as of the end of 2012; the
second phase (Stage 2) assumes that proposed upgrades at HONI’s Leaside 230/115kV
transformer station are in place by the end of 2013.
Given Navigant’s focus on DG connection to THESL’s distribution system, it is important to
note that this study does not address the following:
An assessment of the relative costs and benefits of different types of DG,
Evaluation of the impact of intermittent DG output from renewables on control area
operating reserves, unit ramping and minimum run constraints, and inter-area transfers,
and
An analysis of steady state or dynamic system transmission performance, particularly for
high penetration DG scenarios where a concurrent or cascading loss of major DG could
cause thermal or voltage violations.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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2.1 Report Contents
Subsequent sections of this report present Navigant’s findings. Specifically:
Section 3 provides an overview of the electric power delivery system in the province, the
power system configurations in Toronto and factors that influence the ability to integrate
new distribution generation (DG) under each of these configurations.
Section 4 describes the DG connection capacity limits within THESL’s service territory.
Section 5 describes enabling options to increase THESL’s DG connection capacity limits
that were developed jointly by Navigant and THESL.
Section 6 summarizes Navigant’s analysis of the costing for the enabling options
(expressed on a $ / kW of DG enabled basis) given THESL’s typical feeder configuration
and illustrates how these options could be considered by THESL for DG connection
applications on constrained feeders.
Section 7 presents Navigant’s conclusion with respect to THESL’s DG connection capacity
limits and enabling options to increase these limits.
Navigant understands that THESL’s GEA plan will incorporate appropriate enabling options
into several local upgrade plans that reflect local system constraints and the best available
information on current and forecast DG connection requirements on THESL’s stations and
feeders. Together, the upgrade plans proposed in THESL’s GEA Plan and HONI’s local
transmission system upgrades will significantly increase THESL’s DG connection capacity.
Even with these planned and proposed upgrades, new DG connection applications outside
THESL’s current forecast may still be subject to constraints on certain feeders or buses. It is
expected that many of these constraints can be addressed through the application per THESL’s
DG requirements and cost recovery policy of the enabling options identified within this report.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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3
B ACKGROUND AND P OWER S YSTEM O VERVIEW
This section provides an overview of the electric power delivery system in the Province of
Ontario and comparable electric utilities. It describes the differences in the power system
configurations in Toronto and factors that influence the ability to integrate new distribution
generation (DG) under each of these configurations. It reviews technical constraints including
short circuit capacity, thermal capacity, voltage limits, and other constraints that limit the
amount of new DG that can be installed on THESL’s distribution system. Section 2 describes in
detail the topic of fault current contribution, as it is one of the primary factors that limit DG
penetration, and how production of fault current limits differs depending on source, i.e.,
inverter-based versus synchronous DG. The evolution of the Toronto area distribution and
transmission systems is discussed, followed by a high-level assessment of the impact equipment
and system upgrades may have on allowable amount of DG that can be installed on THESL’s
distribution system.
3.1 Bulk Power System Hierarchy and Ownership
Ontario’s electric power system, like those elsewhere across North America, consists of
generation, transmission, and distribution system assets, each of which serve distinct functions.
Generating stations in the province are both privately and publicly owned and include those
owned by Ontario Power Generation. Electricity produced by these facilities, located
throughout the province, is transmitted over the electric transmission system, the majority of
which is owned and operated by Hydro One Networks, Inc. (HONI). While the transmission
system serves a number of large directly-connected power users, the majority of Ontario’s
electricity customers receive their power through THESL and other Ontario local distribution
companies (LDCs).
The transmission system delivers electricity produced from generating stations located across
the province (or from imports via transmission interfaces to other adjacent provinces and states)
to transmission or sub-transmission system-connected customers, or to various transformer
stations through high voltage lines, which operate at 115 kV, 230 kV, or 500 kV. From these
HONI or LDC-owned transformer stations, power is transmitted through main line and lateral
distribution feeder segments to overhead or pad-mounted distribution transformers.
Distribution transformers are the second last stop in the hierarchy of the electricity transmission
and distribution systems. The distribution transformers provide secondary service to homes or
commercial business at standard utilization voltages (e.g., 480 or 240 volts).
Figure 1 below depicts at a high level the responsibilities, ownership, and operation of the bulk
power system as they relate to this study (THESL elements are highlighted in green). It also
THESL System Connection Capacity and Enabling Options for Distributed Generation
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4
illustrates the points of interconnection between transmission and distribution systems.
Typically, HONI owns all equipment from the low voltage side of the substation step-down
transformers (including the transformer) to the high-voltage side of the generator step-up
transformers; THESL typically owns all equipment from the low side of the substation stepdown transformer to the customer meter. The latter includes 13.8kV and 27.6kV switchgear and
breakers, many of which are located on the same substation site where HONI high voltage
equipment is located.5
Figure 1 - Illustrative Structure of the Bulk Power System and LDC Distribution Systems
Though much of the transmission system operates without constraint, increased demand for
power from consumers and interconnection from FIT-related generators has placed limitations
on certain areas of the system. Hydro One has identified a number of constraints within its
system that have an impact on the investment and interconnection-related decisions of certain
of its downstream customers, including THESL. From Hydro One’s recent rate filing (EB-XXX),
specific technical constraints at both its Manby and Leaside transformer stations were
identified, each having an impact on THESL’s ability to approve requests for DG
interconnection.
Specific constraints include the following (other HONI constraints may apply):
Limited breaker capacity due to short circuit capacity constraints;
4
Figure 1 also seeks to provide clarity to readers by illustrating the hierarchy of the bulk power system from transmission systemconnected generation down through the distribution transformer and into the home.
5
One exception to this rule is THESL’s 230kV/27.6kV Cavanaugh Station, where THESL owns virtually all equipment located
within the substation fence.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Reverse power flow limitations based on transformer thermal capacity;
Reverse power flow limitations based on minimum load requirements; and,
Load transfer scenarios, i.e., Manby to Leaside (and vice-versa) constraints.
Technical constraints also exist within THESL’s distribution system; however, as this study
demonstrates, most technical limitations within the distribution system are subsumed by those
imposed by the transmission system. Constraints within the distribution system that limit the
amount of DG include:
Feeder continuous load thermal ratings;
Short circuit capacity (mostly station equipment); and,
Reverse power limits driven by transformer thermal capacity and minimum load
criteria (this may be deemed to be a transmission-level constraint as the devices are
owned by HONI).
While both short circuit capacity and reverse power flow limits are constraints within the
transmission and distribution systems, they reflect the technical limits of existing transformer
stations or issues that exist farther upstream, i.e., circuit breaker capacity constraints at HONI’s
Leaside, Hearn and Manby stations.
Within the context of this study, constraints at HONI’s Leaside and Manby 230/115kV
transformer stations have imposed limitations on both short circuit and thermal capacity within
the THESL distribution system, and impact THESL’s ability to interconnect new DG in the
13.8kV downtown system. These limitations are described in greater detail in the following
sections of this report.
3.2 Distribution System Topology
Distribution System Voltage Levels and Feeder Vintages
Just as each type of DG unit, whether a photovoltaic (PV) system or synchronous gas generator,
has certain electrical and physical characteristics that require consideration as part of a utility’s
interconnection process, distribution feeders (or circuits) have inherent characteristics that
require additional review as part of the evaluation process. These characteristics are largely
driven by the type of system that an individual feeder is located and may include: voltage level;
feeder length, overhead or underground, feeder type, i.e., radial, network/secondary, or spot;
physical thermal limits; and feeder length. Distribution feeders across North America operate
at one of several standard primary voltage classes: 5kV, 15kV, 25kV, or 35 kV.
Toronto Hydro’s distribution system is comprised of distribution feeders that operate at one of
three nominal distribution primary voltage levels – 4.16 kV, 13.8 kV, or 27.6 kV. Within the
THESL system the primary voltage level of distribution feeders is largely based on feeder
THESL System Connection Capacity and Enabling Options for Distributed Generation
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vintage, which tends to vary geographically.
approximately 900 feeders.
In total, THESL customers are served by
Distribution feeders within the THESL system also vary by length. The length of feeders
considered “long” and operating at the 27.6 kV level ranges between 5 and 6 km whereas
similarly long 13.8 kV feeders range in length between 3 and 4 km. Conversely, “short” feeders
operating at the 27.6 kV level range between 3 and 4 km, compared to similarly short 13.8 kV
feeders, which range between 2 and 3 km. Feeder length itself is not typically an issue when
interconnecting DG units to the distribution system; however, the distance such units are from
the transformer stations bus can be.
Figure 2 depicts how various areas of the City of Toronto are served by HONI transmission
lines that delivery bulk power to THESL stations by voltage level. Most 230kV transmission
lines serve THESL stations with distribution voltages at 27.6kV, whereas all 115kV transmission
lines in the downtown areas serve stations with distribution voltages at 13.8kV (shaded blue).
About 30 percent of THESL’s distribution feeders operate at 27.6 kV (unshaded) and serve
nearly 3000 MW of load across much of the suburban outer ring of the city, while almost 70
percent of feeders operate at 13.8 kV (shaded blue) and serve some 2000 MW of load. The area
shaded in tan is where underground secondary networks serve downtown load centres,
including the financial district and areas near the CN Tower.
Figure 2 – M ap of THESL System by System V oltage
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Distribution Feeder Topologies
Feeders within the THESL system are configured according to one of four distribution system
topologies, which are typical of systems across North America6 and include: radial, loop,
secondary network, and spot network systems. Much of THESL’s distribution system is
organized by feeder voltage as we previously detailed and follows the growth of the City of
Toronto over the past several decades.
The central and downtown core areas of the city are largely served by 13.8kV radial distribution
lines and cables; secondary network and spot network systems serves the core downtown
financial district. The outer suburban area of the city is mostly served by 27.6kV overhead
radial feeders. The three distribution feeder topologies are described in detail below.
Radial Systems
Radial distribution systems are the most common configuration used by electric utilities and are
the least expensive to design, construct, and maintain. However, this configuration is the least
reliable as customers are supplied from a single source at any given time. This type of system
contains no closed “loops” as shown below in Figure 3.
If any part of a given radial feeder system experiences a failure, some or all of the customers
served by that feeder will experience an outage until repair crews are able to repair and restore
the system.
Radial systems are mainly comprised of a transformer substation, a number of radial feeders,
and distribution line transformers that convert the higher voltage (e.g., 13.8 kV or 27.6 kV) to a
customer utilization level (120/240 V, 120/208 V, or 277/408 V). Figure 3 presents a schematic of
a typical radial configuration used in the THESL system.
Figure 3 – Radial Configuration
Substation
HV
Load
Load
Load
Load
Load
6
Secondary networks generally appear only for utilities serving urban or very high load density load centers.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Auto-Loop or “Loop” Network System
An auto-loop, or simply loop, system is an enhanced radial system differentiated by its ability
to serve customers via two radial feeders, as necessary. In looped systems automated or semiautomated equipment at the transformer substation detects when equipment failure has
occurred on one of the two feeders and can either automatically transfer load to adjacent feeders
or alert a control-room operator, who can then manually decide on the appropriate action to
take. Many of THESL’s 13.8kV downtown feeders operate in an auto-loop configuration.
Looped systems can provide utility customers with incremental reliability-related benefits, as
the time needed to restore service to some customers is reduced. Figure 4 illustrates the typical
configuration of a two-feeder loop network. The normally open switch at depicted by the open
dot is where the transfer is enabled, while one or more normally closed switches (or circuit
breakers) is open to ensure all lines operate in a radial manner. Once the fault is cleared and the
faulted line segment is returned to service, the feeders usually are switched back to their
original configuration.
Figure 4 – Looped Feeder Configuration (Radial)
Secondary Network Systems
Secondary network or simply “network” systems are among the most sophisticated distribution
systems used by electric utilities and often serve large central business districts within many cities
across North America. In network systems, customer loads are served by multiple feeders fed via
a number of redundant transformers and network protectors. As a result, they are inherently
more reliable than radial systems; however, they incur higher design, construction, operating and
maintenance costs.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Figure 5 illustrates how customer load is served by the network system via several transformers
simultaneously supplied from different primary feeders. The secondary windings of integrated
network transformers (TX) and network protectors (NP) are interconnected in a parallel
configuration forming what is typically known as a “secondary grid system” – loads are then
served from various locations within this grid. The key feature of grid network systems is that
a loss of any single primary or secondary line segment will not cause an interruption in load.7
Some secondary networks are designed to sustain a loss of two elements without loss of load.
Such is the case for some of the secondary networks in downtown Toronto.
Figure 5 – Secondary Grid N etwork System
Substation
HV
TX & NP
TX & NP
LV
Loads designated
by arrows
Spot Networks
Spot networks are secondary network systems that consist of two or more network transformers
located at a single site. They are similar to secondary grid networks, but usually serve a much
small area. Further, some secondary spot networks are owned by business customers, whereas
virtually all grid networks are owned by the utility. Spot network distribution systems
typically a single site comprised of several buildings or a single large building such as an office
tower. Spot networks are designed to provide highly reliable service to a single site and are
often configured in high load-density areas within large cities.
In a spot network, the secondary network-side terminals of the network transformer units are
connected together by a bus or cable as presented in Figure 6; the resulting interconnection
structure is commonly referred to as a paralleling or collector bus. Should a fault or failure
occur on the paralleling bus, customers on the spot network are likely to experience an outage.
7
The vast majority of secondary network systems are located in underground conduit within high load density sections of urban
areas.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Figure 6 – Spot N etwork Configuration
Substation
HV
TX & NP
TX & NP
LV
Loads
Cases Selected for Distribution Impact Analysis
Navigant’s analysis of the distribution system’s capability to interconnect DG incorporates
results from a detailed fault simulation study based on eight feeder configurations that were
selected as a representative cross-section of the THESL system. In order to fully understand the
impact that any DG may have on the THESL distribution system, detailed power flow and fault
study simulation analyses were undertaken by THESL using its CYME software package.
Working with THESL, Navigant developed eight cases for software simulation that represent a
cross-section of THESL’s feeder system based on voltage level, feeder type, and length. The
eight feeder cases simulated are as follows:
Long 27.6 kV Feeder ( 5-6 km)
Short 27.6 kV Feeder (2-4 km)
Long 13.8 kV Feeder (3-4 km)
Short 13.8 kV Feeder (2-3 km)
Pilot Wire 1
Pilot Wire 2
Bathurst Tie Point (Extended Feeder)
Terauley/G&D Tie Point (Extended Feeder)
The study’s outputs include short circuit profiles, voltage profiles, and cable ampacity profiles.
Simulations were undertaken with DG units connected at three locations: the transformer
station bus, feeder midpoint, and at the end of each distribution feeder. As such, the scenariobased results of the fault study simulation encompass a broad range of feeder and DG
configurations. These results have informed the higher-level modeling work undertaken in Part
2 and Part 3 of this study and provide a sound basis for many of the assumptions used.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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These eight cases were further simulated under four DG operating scenarios that included:
No Connected DG
100% Synchronous DG
100% Photovoltaic DG
DG supply mix across feeders connected to a single bus
Detailed Power-Flow Simulation Cases
A series of power flow simulation analyses using the CYME distribution model were performed
to assess the impact of increasing levels of DG penetration on representative feeders selected for
detailed study. Three performance criteria were evaluated via CYME: (1) thermal loadings; (2)
voltage drop (or rise); and (3) incremental fault current contribution. Case studies included all
DG installed at the beginning (i.e., substation bus), middle, and end of the feeder. For
practicality and simplification of simulation model set up, all DG is assumed to be installed on
the main or trunk line feeders.
For this study, eight case studies were structured to represent typical feeder configurations in
the THESL system. The case studies include long and short feeders operating at 13.8kV and
27.6kV, and specialized cases where feeders operate in parallel to increase capacity limits and to
account for temporary feeder transfers that typical occur during maintenance of outages. These
case studies are listed in the prior sections. A more detailed description of these eight cases
appears in Appendix A. The results of the CYME studies are summarized in Appendix B.
3.3 Short Circuit Capacity
Short circuit capacity limits on both the THESL and HONI systems are important factors in the
determination of how much DG can be installed on THESL’s distribution system. Short circuit
capacity is generally defined as the maximum of current a device is able to withstand without
failure during fault conditions, such as a line-to-line or line-to-ground fault. The source of the
fault current is from all generators connected to the bulk power grid and from any DG
connected to the lower voltage transmission and distribution system8. The level of fault current
is highest when the fault is closest to the device. Accordingly, studies used to calculate the
maximum fault current for equipment and devices susceptible to short circuit capacity limits
assume the fault is located closest to these devices; for example, circuit breakers located within a
station.9 If the amount of fault current contribution from DG located on feeders produces
8
The terms short circuit capacity and maximum fault current have identical meanings and are used interchangeably throughout
the report.
9
To determine the short circuit capacity at stations and other locations on the power delivery system sophisticated power flow
simulation models are employed. These models predict how much fault current will flow to a specific location from generators
located throughout the province. These studies typically are conducted by HONI or the Ontario Power Authority (OPA) to
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 15
sufficient additional fault current to cause total fault current to exceed equipment ratings, then
the DG may not be allowed to interconnect to the system until corrective measures are made to
reduce fault current or upgrade equipment, or both.
Recent studies of the potential for DG in Toronto and recent applications for DG
interconnection underscore the impact of short circuit capacity on allowable DG penetration.
Prior studies confirmed short circuit limits in downtown Toronto can significantly limit DG
installations; in particular, the amount of rotating DG technology (e.g., synchronous
generators)10 currently is constrained in the eastern segment of downtown Toronto due to
limited available fault current at HONI’s Leaside Station. Short circuit capacity is usually
measured in thousands of amperes (e.g., 40kA for a breaker rated to withstand 40,000 amps of
fault current).
THESL Short Circuit Limits
The primary limiting element for short circuit capacity is substation equipment (where fault
current levels are highest); most THESL components subject to fault current limits are
substation low voltage breakers (HONI typically owns high voltage breakers and equipment).
Short circuit capacity at THESL’s downtown stations serving 13.8kV distribution feeders is
generally lower than at the stations serving THESL’s 27.6kV feeders.
HONI Short Circuit Limits
Prior DG studies and recently supplied data from HONI indicate fault current limits are
constrained mostly at the two major 230/115kV supply stations at Leaside and Manby. Leaside
is severely constrained due to the presence of 40kA rated equipment; mostly 115kV circuit
breakers. Recent applications for DG interconnection in downtown Toronto have been denied
11
due to unacceptable fault current contribution.
3.4 Feeder Thermal Rating and Transformer Thermal Capacity
Thermal capacity in both the transmission and distribution systems is largely based on the
physical properties of various types of equipment including the actual cables from which
feeders are constructed and the windings and internal and external equipment from which
primary transformers are built. As power flows through a conductive element the resistance of
determine the short circuit capacity at each station. The presence of DG on distribution feeders can contribute fault current that
can cause station equipment such as circuit breakers to exceed the short circuit capacity limit.
10
Synchronous generators produce up to six per unit or greater fault current, which is far greater than the one to two per unit fault
current produced by inverter-based DG technology such as PV. Further, the duration of fault current is longer for synchronous
DG, as it will continue to produce fault current until the generator breaker opens. The time interval for the DG breaker to open
varies, but can be up to 30 to 60 cycles (or longer). In contrast, inverters typically will produce fault current for three to four cycles
before damping out due to loss of a voltage source.
11
Mostly larger synchronous DG, including a 14 MW generator in downtown Toronto.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 16
that element produces a certain amount of heat, which that element must be able to safely
withstand. Further, lines and equipment that deliver electric power typically are rated to
withstand a threshold level of current when line faults or short circuit conditions exist;
commonly referred to fault duty or capacity. Lines and equipment typically are capable of
carrying very high levels of current for a short time interval; that is, the time typically required
for protective devices to electrically isolate and interrupt a fault before it damages equipment.
As illustrated in Figure 1, transmission system assets including lines and transformer stations
(up to and including the low-side of the station power transformer) are owned by Hydro One.
Distribution system assets such as transformer station low voltage bus and breakers,
distribution feeders (overhead lines and underground cable), distribution transformers, and
metering are owned by Toronto Hydro. While this study identifies the amount of DG that can
be installed on THESL’s distribution system, both transmission and distribution constraints and
impacts must be considered to determine acceptable levels of DG penetration.
Distribution System Continuous Load Feeder Thermal Rating
The continuous load thermal rating of feeders within the distribution system refers to the safe
operation of feeders under continuous full load conditions. Feeders operating within the
distribution system operate at one of three voltages (4.16 kV, 13.8kV, and 27.6 kV) as described
previously. Correspondingly, within each voltage class, feeders are rated at a continuous load
level to withstand the heat produced during the transmission of a given amount of power.
The 4.16 kV, 13.8 kV, and 27.6 kV systems each have feeders rated to operate no higher than 4
MW, 10 MW, and 20 MW, respectively. Within the distribution system, these feeder thermal
rating levels represent a theoretical ceiling on the level of DG that can be safely interconnected.
These thermal limits are analogous to the limits on household wiring circuits. A 240 V circuit
(such as for an electric range) can serve a higher power rating than a 120 V circuit (such as
would supply lights and outlets).
HONI-Owned Transformer Station Capacity Limits
The thermal capacity of HONI Transformer Station (TS or Station) equipment is based largely
on the ability of the station power transformer and ancillary equipment to withstand a predetermined level of reverse power flow. Reverse power limits are based on the configuration of
the transformer, its vintage, and primary winding system. Thermal capacity limits at
transformer stations connected to the THESL system are also affected by upstream issues,
which are beyond THESL’s control and responsibility. Accordingly, HONI calculates thermal
capacity limits at each transformer. Initial discussions with HONI indicate that many
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 17
transformers, particularly those located in stations described as the “Bermondsey” design, have
12
strict reverse power limits.
HONI owns all power transformers in each of its stations serving THESL (Note: THESL owns
the power transformers in the THESL-owned Cavanagh station and will own the power
transformers in the Bremner station currently under development by THESL). HONI also owns
all transmission lines, cable and ancillary equipment located upstream from the high-side of the
transformer. However, Navigant did not determine whether transmission line or cable thermal
limits would be exceeded for increasingly levels of DG, as THESL does not currently operate a
transmission load flow model that would detect thermal (or voltage) violations. Navigant has
assumed that the primary transmission thermal limits are limited to station transformers.
3.5 Feeder Load Diversity
THESL’s distribution system varies by geography, voltage level, and feeder configuration as
detailed previously. Its customers also vary by class, have unique load profiles, and are
comprised of a mix of residential, commercial/institutional, and industrial customers. THESL
distribution feeders range between serving a single commercial or industrial customer, in the
case of a spot network, to serving a diverse mix of customers via one of the other feeder
configurations.
Characteristics of Load Types
Feeders on the THESL system exhibit a range of load shapes depending on location and
customer mix. Residential and mixed commercial loads typically have lower demand at night
versus relatively flat industrial load profiles. A typical load profile for a feeder serving core
downtown load is given in Figure 7.
12
THESL has been notified that the Bermondsey configuration provides for cross-transformer connections to the low-side bus,
resulting in potential circulating power flows and excess heating in these transformers if power flows are reversed; that is, from
the low-side primary distribution into the transmission network.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 18
Figure 7 – Typical Daily Load Profile
1.20
Actual Windsor TS Hourly Load Profile (Bus A3A4)
Normalized Load/Generation
1.00
0.80
0.60
0.40
Min load occurs at
4:30AM
0.20
0.00
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
3.6 Generation Capacity and DG Scenarios
Part 1 of Navigant’s study examines limits associated with DG technologies mostly likely to be
installed on THESL’s distribution system. Locations include DG installations on THESL’s
4.16kV, 13.8kV and 27.6kV distribution feeders, and direct connection to stations via dedicated
feeder connections. The latter option assumes existing feeder capacity is insufficient or the DG
unit is too large to install on distribution lines. While no specific limit is assumed for DG unit
size, feeder thermal capacity effectively establishes limits of 10 MVA and 20 MVA for DG
installations on THESL’s 13.8 and 27.6kV distribution systems, respectively.
Navigant evaluated a range of DG technology combinations, from 100 percent inverter-based to
100 percent rotating machines (i.e., synchronous DG). The intent of evaluating DG over a
spectrum of technology types is to present potential ranges in DG penetration – a single value
based on a pre-defined mix of DG does not realistically portray what actually may be installed
prospectively. Further, it is not possible to determine in advance where DG is most likely to be
installed for each feeder. Accordingly, Navigant evaluated DG under three DG installation
scenarios: (1) at the station bus; (2) mid-feeder; and (3) at the end of the feeder.
Under Navigant’s direction, THESL conducted load flow simulation studies to evaluate
distribution feeder impacts for various combinations of DG technologies and feeder locations.
Findings from these studies led to a determination as to whether DG will cause violations of
thermal loading or voltage criterion described in Section 2.4, and whether the incremental fault
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 19
contribution will exceed station equipment short circuit limits. For the latter, Navigant
13
assumed fault current contribution of 5 to 1 for synchronous generation and 1.5 to 1 for PV.
3.7 Conservation and Demand Management
Over the past several years THESL has instituted several Conservation and Demand
Management (CDM) programs on a system-wide basis. Collectively, these programs have
reduced distribution feeder and substation peak loads, thereby freeing up capacity for other
purposes. The load forecasts used to identify available DG capacity are net of past and
projected CDM programs. As such, the impacts of CDM have been incorporated into the study
findings. Specifically, the available DG capacity, by location, recognized the demand reductions
achieved by CDM. In some instances, the load reduction achieved by CDM actually reduces the
amount of new DG that can be installed, as DG output offsets customer loads. If reverse power
is the primary limiting constraint on a feeder or substation, then available DG capacity may be
reduced due to CDM. To the extent that significantly higher CDM energy and peak demand
reductions are forecast, the analysis used to derive available DG capacity should be adjusted.
Several of the measures described in sections that follow include what could be considered as
“demand management” options for DG, including interruption of DG during critical load
intervals or when emergencies occur. Another option that may prove effective is to offer
customers owning DG an option that would allow THESL to interrupt load in amounts equal to
the size of the DG during emergencies or load transfers. This option would be offered when the
hours of interruption are expected to be very small; for example, less than 100 hours a year. A
variation of the demand management option for DG is to allow THESL to interrupt DG in low
load hours when reverse power limitations constrain DG capacity. The latter option would be
offered when the number of hours of reverse power flow is very low.
3.8 Load Transfer Scenarios
Similar to other LDCs, THESL occasionally will transfer load from one feeder onto an adjacent
feeder, mostly for line or station maintenance. When possible, routine maintenance is
performed when loads are low. Load transfers are also made when station or feeder outages
occur, in which case unfaulted line segments are transferred to adjacent feeders to minimize the
time and duration of outages to THESL customers. Because DG may be connected to both
13
These ratios express the increase in current produced by the generator under fault conditions versus rated output. The ratio
assumed for synchronous generators is consistent with prior studies and industry literature. The level of fault current for PV
tends to have greater variability than synchronous DG, as some studies and measurement show a one-to-one ratio, whereas
others show ratios of two-to-one of higher. For PV, this study applies a value used by HONI, which is more conservative than
lower ratios assumed by others involved in similar studies. Further, the impact of synchronous DG fault is greater than PV due to
longer breaker clearing times. Synchronous generation will continue to produce fault current until the station breaker or line fuse
clears the fault. In contrast, PV fault current dampens out very quickly – usually 2 to three cycles – as the collapse in the voltage
field due to a line fault causes the inverter to cease operation.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 20
feeders, it is highly likely that a single feeder may carry much larger amounts of DG when the
lines are reconfigured for maintenance or outage restoration. The impact of the larger amounts
of DG – even temporarily – is potential voltage or thermal loading violations. Further, if the
14
feeder transfer is from an adjacent station, fault current limits may be exceeded as well.
3.9 Evolution of the Toronto-Area Distribution System
Prior to its amalgamation with neighbouring municipal utilities (such as North York Hydro),
much of THESL’s distribution system operated at 4.16kV or 13.8kV, serving downtown Toronto
and other high load density areas. Amalgamation with the neighbouring utilities (in what is
commonly referred to as the “Horseshoe”) introduced a significant amount of higher rated
27.6kV distribution facilities. Two important differences between the two systems are their load
carrying capacity and their source of supply:
The older 13.8kV system has lower load carrying capability than the newer 27.6kV system.
All 13.8kV stations are served via HONI 115kV lines emanating from Manby or Leaside
supply stations whereas most 27.6kV stations are served from 230kV lines generally
running east-west in the corridor north of Highway 401.
Figure 8 illustrates the 230kV (light blue) and 115kV (green) HONI transmission lines that serve
THESL’s 27.6kV and 13.8kV systems, respectively – THESL’s service area is shaded tan.
Figure 8 – Toronto A rea Transmission Supply
14
Currently, most downtown 13.8kV feeders do not have feeder tie points that would enable station-to-station load
transfer. However, THESL currently is conducting studies to identify cost-effective upgrades that provide for
station-to-station load transfers via its 13.8kV system.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 21
To limit fault current and undesired parallel flows, the 115kV systems serving downtown
Toronto from Manby and Leaside are electrically separated. Any future plans to tie the 115kV
stations would reduce available short circuit capacity, thereby further curtailing DG
installations.
For this study, the thermal capacity of 13.8kV lines is assumed to be 10 MVA; the 27.6kV system
is limited to 20 MVA. Notably, many of the 115/13.8kV downtown stations are over 30 to 40
years old; whereas many 230/27.6kV stations are less than 30 years in age.
3.10 Limiting Factors to Increased DG Penetration
This section presents the operating, capacity and performance factors that can limit new DG
installations on THESL’s distribution system. It excludes factors that impact bulk transmission
operations or planning (e.g., 230kV and 500kV lines that support the interconnected grid) or
IESO control area generation performance. The impact of each of these constraints on the
amount of new DG that can be installed on THESL’s distribution system is presented in Section
4 along with candidate mitigation options and equipment upgrades that may increase DG
capacity limits, including the cost of these options.
Short Circuit Capacity Limits
Prior studies confirm short circuit limits on station equipment as one of the primary limiting
factors on the amount of DG that can be installed in certain areas of the THESL system;
particularly in downtown Toronto. Station equipment – often in the same location – is partly
owned by HONI, and partly by THESL. Typically, HONI owns and operates all equipment
from the low voltage side of station power transformers up to and including higher voltage
transmission equipment. Toronto Hydro typically owns lower voltage station circuit breakers
and switchgear line-ups. Studies results presented in subsequent sections indicate that in some
sections of the city, available short circuit capacity is limited by HONI constraints; in other
sections, THESL equipment is similarly constrained or is the primary limiting factor. Specific
factors that limit available short circuit capacity for THESL and HONI energy delivery systems
are described in greater detail below.
THESL Short Circuit Capacity
Most THESL equipment that is susceptible to fault current restrictions (i.e., short circuit
capacity) is located within the low voltage side of stations where THESL owns and operates
equipment (high voltage station equipment is discussed in the next section). Further, most
THESL station equipment subject to fault current limits is at older 13.8kV stations in downtown
Toronto; a much margin of available short circuit capacity is generally available on THESL’s
27.6kV system. Table 1 list stations where THESL short circuit capacity limits allow no
additional DG, and includes a summary of existing DG connected to each of these stations.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 22
Table 1: THESL Stations with Short Circuit Capacity Limits
(Low Voltage Constraints)
Available Short
Circuit Capacity
(MVA)
Sum of DG & FIT
Generation Capacity
(MW)
Bridgman A5A6H Bus Total
0
0.000
Carlaw A4A5 Bus Total
0
0.088
Carlaw B1B2 Bus Total
0
0.000
Carlaw B3B4 Bus Total
0
0.002
Cecil A1A2 Bus Total
0
6.670
Gerrard A1A2 Bus Total
0
0.219
Leaside A1A2Q1Q2
0
0.000
Leslie BY Bus Total
0
7.352
Richview BY Bus Total
0
1.050
Wiltshire B1B2 Bus Total
0
0.000
Wiltshire A1A2 Bus Total
0
0.057
Wiltshire A3A4 Bus Total
0
1.062
Wiltshire A5A6 Bus Total
0
0.485
Woodbridge BY Bus Total
0
0.000
THESL Station Bus
Many of the constraints on the THESL (and HONI) system that limit the amount of new DG
that can be added are located in downtown and eastern section of Toronto – many of these lines
operate at 13.8kV, the dominant voltage on the THESL system prior to amalgamation. The
27.6kV system that surrounds downtown Toronto – i.e., the “Horseshoe” – has fewer short
circuit capacity constraints. As noted, most short circuit capacity constraints are associated with
station bus or breaker ratings (as opposed to feeder constraints). Generally, THESL 13.8kV
station equipment is rated 500 for MVa, whereas 27.6kV stations, which generally include
newer equipment, is rated for 800 MVa. Each of these limits is specified within the provincial
Transmission System Code (TSC), which THESL follows in the design and operation of its
system.
HONI Short Circuit Capacity
Hydro One short circuit limits in the Toronto area are well documented. Navigant’s
Distributed DG Study and OPA’s 2008 study confirm that limited short circuit capacity in key
230/115kV substations in the eastern part of Toronto significantly constrains the amount of DG
that can be installed in certain downtown 115/13.kV substations. Figure 9 illustrates the three
major HONI in-City stations equipped with devices that are nearing fault current limits. The
limiting equipment is primarily circuit breakers and ancillary equipment rated for 40kA (40,000
amps). Modern devices typically are generally rated for 60kA. Of the three stations, Leaside is
most susceptible to short circuit violations, including those caused by incremental fault current
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 23
contributions from new DG. As noted in recent studies and reports, HONI expects to upgrade
Leaside and replace the breakers with higher rated equipment by the end of 2013.
Figure 9 – Downtown Short Circuits Limits (Transmission Stations)
Note: Short circuit levels near station equipment capability (~40,000 A) at Hearn, Manby and Leaside
Source: Electricity Service to Central and Downtown Toronto, Ontario Power Authority,
September 25, 2008
Figure 10 at the top of the following page illustrates graphically short circuits limits for THESL’s
service territory solely due to constraints at individual stations directly connected to THESL
feeders. The map is color-coded to highlight the boundaries between areas with severe
constraints versus those with ample capacity. The irregularity of the boundaries reflects the
territory served by feeders from stations with bus and breaker limits. Such boundaries usually
are not homogeneous as some feeders are very short in high load density areas, whereas other
feeders can traverse several kilometers in areas where load density is lower.
Until Leaside, Hearn and Manby 115kV breaker and bus upgrades are completed, HONI has set
short circuit capacity limits for new PV at 10 MVA in downtown Toronto and 10 MVA in the
southeastern section of the city (e.g., Scarborough) due to constraints on certain 230kV HONI
transmission facilities that are not directly connected to THESL feeders. Specifically, these
facilities are at HONI’s Manby and Leaside stations and HONI’s 230kV transmission line
running through the southeastern section of the city to Leaside from Cherrywood station east of
Toronto.
Figure 11 at the bottom of the following page illustrates the short circuit capacity limits on the
THESL system at individual stations directly connected to THESL feeders AND the constraints on
certain 230kV HONI transmission facilities that are not directly connected to THESL feeders. The
large red area in Figure 11 represents the areas of Toronto served by these transmission facilities.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 24
Figure 10 – Short Circuit Limits at Individual Stations Directly Connected to THESL Feeders
Figure 11 – Short Circuit Limits at Individual Stations Directly Connected to THESL Feeders and due to
Constraints on Specific HON I 230kV Transmission Facilities
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 25
Feeder Voltages
THESL seeks to limit voltage thresholds with a range (e.g., 115 volts to 125 volts for residential
supply voltage). Feeder voltages can experience unacceptable voltage drop (or rise) due to the
presence of DG. Under high feeder loading, voltages can drop below the acceptable threshold;
whereas large amounts of DG located at the end of a lightly load feeder increases the likelihood
that voltages will rise above the acceptable threshold.
Figure 12 illustrates how voltages can rise as a function of distance for lightly loaded feeders. 15
When DG is located close to the station breaker (left-hand side of X-Axis), voltages vary only
slightly. However, when DG is installed at or near the end of the feeder (8000 meters on left
side of X-Axis), voltages can rise to unacceptable levels. Feeders also can exhibit the opposite
behaviour – that is, low voltages can result when lines are heavily loaded.
Figure 12 – V oltage Rise for Lightly Loaded Feeders
THESL Capacity Constraints
Where the combined output of DG installations at the distribution level exceed the continuous
rating or lines, cables of station equipment, mitigation of these impacts or construction of
dedicated lines may be needed to serve new DG. Although maximum DG size is limited to 10
MVA and 20 MVA on 13.8kV and 27.6kV feeders, respectively, the combined output of several
feeders from a common bus may cause thermal loading violations. Further, large amounts of
DG on feeder laterals also can cause violations, as could combined DG output when DG from
15
THESL performed a voltage analysis on a hypothetical DG unit on a typical distribution feeder.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 26
independent feeders are combined (i.e., via feeder tie points) during maintenance or outage
events.
Protection Constraints
Large amounts of DG have the potential to impact distribution protection coordination. For
larger DG, sophisticated protection and control systems often are essential to enable
interconnection. Further, on secondary network systems, reverse power relay settings can
significantly limit DG penetration; particularly for rotating (synchronous or induction) DG.16
3.11 Additional Details
Other information that is relevant to a determination of DG penetration limits and cost of
mitigation is presented below, including how existing DG is incorporated into the analysis.
Existing DG Installations
Currently, there are several DG installations on THESL’s system, including residential and
commercial behind-the-meter installations. Collectively, the total rating of these devices is just
under 90 MW. Table 2 presents the total capacity of smaller and larger DG in Toronto.
Table 2 – Existing DG Capacity in Toronto (as of 2009)
Size of DG
Number
Power Output ( kW )
Micro (≤ 10kW)
219
726
Small (≤ 1MW)
16
5917
Medium (≤ 10 MW)
21
73,482
Large (>10 MW)
1
11,000
257
91,125
Total
Figure 13 illustrates existing residential DG locations in Toronto, mostly small PV rated less
than 10 kW.
16
Some utilities prohibit the installation of synchronous or induction DG on secondary and spot networks.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 27
Figure 13 – Residential DG Installations in Toronto
Figure 14 illustrates commercial DG installations in Toronto. Typically, commercial DG
installations are much larger than residential DG, including synchronous machines that are not
used in residential applications.
Figure 14 – Commercial DG Installations in Toronto
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 28
Because the residential and commercial DG that appears above is part of the existing system
and their output has already been incorporated into THESL load measurements, they are not
explicitly included in our analysis of DG penetration limits. Further, the aggregate capacity
existing DG is sufficiently low to warrant exclusion from our analysis.
The largest wind DG installation connected to the THESL system, a 750 kW wind turbine
located along the lakeshore, is shown in Figure 15.
Figure 15 – 750 kW W ind Turbine in Downtown Toronto
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 29
4
DG C ONNECTION C APACITY L IMITS
This section presents DG capacity limits on THESL’s 13.8kV and 27kV systems for inverterbased (PV) and synchronous DG as they exist today (Stage 1). This section also presents the
expected increase in DG capacity limits following HONI’s completion of OEB-approved
upgrades on the high voltage system that delivers power from the bulk power system to THESL
stations (Stage 2).
The DG penetration limits presented in this section cover two scenarios: the first assumes 100
percent inverter-based DG is installed; the second assumes 100 percent synchronous-based DG
is installed. Candidate options to increase these limits are presented for each DG technology
type on THESL’s 13.8kV and 27kV system.17
4.1 Derivation of DG Connection Capacity Limits
DG connection capacity limits for each DG technology were estimated by assessing the impact
of each constraint described in Section 2. The methodology Navigant employed to estimate
capacity limits both the 100 percent inverter-based and 100 percent synchronous DG scenarios
is described below.
Methodology
The following step-by-step approach was employed to identify DG capacity limits:
Establish an “Existing Conditions Case” based on a review of THESL’s system
refurbishment and upgrade plans through end of 2012; station loading is net of THESL’s
forecast of CDM impacts. The Existing Conditions Case (Stage 1) assumes upgrades at
HONI’s Leaside, Hearn and Manby Stations are not yet undertaken.
For all equipment on the distribution side of the 35 transformer stations serving THESL’s
service territory, review (and augment as necessary) information that THESL has compiled
with respect to available fault duty limits, single and three phase fault currents and other
station-specific information necessary to perform other tasks.
Identify and characterize feeder and system configurations representative of THESL’s
distribution system. These include the downtown secondary grid network (serving the
financial district), 4 kV and 13.8 kV feeders serving downtown Toronto and 27.6 kV
feeders serving the suburban areas of Toronto (i.e., the “Horseshoe”). Approximate the
17
The study does not explicitly identify mitigation options on THESL’s 4.16kV system, as 4.16kV lines typically are served from unit
stations emanating from THESL’s 13.8kV and 27kV lines, downstream of the station breaker. Accordingly, any upgrades to either
of the higher voltage lines are assumed to increase limits on the 4.16kV lines as well.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 30
percentage of THESL’s distribution system and relative mix of customers served by each of
18
these configurations.
Identify typical “base” generator configurations and their key electrical parameters
(including short circuit contribution) of each DG type. The DG types include synchronous
(such as large CHP), induction (such as small gas engines) and inverter-based equipment
(such as PV).
For each of the feeder and system configuration, identify short circuit constraints within
the THESL system for each of the base DG generation configurations connected: 1) at the
station busbar; 2) midway down the feeder; and 3), at the end of the feeder.
Identify incremental upgrade equipment / bundles and their associated costs to increase
distribution system short circuit capacity levels for each of the representative feeder /
system and DG configurations from above. As appropriate, identify incremental
equipment / bundles and associated costs to increase the ability to connect DG on the
THESL side of each of the transformer stations serving THESL.
The approach outlined above recognizes that factors that limit DG penetration will vary
according to DG size, location and constraints that exist at any particular feeder or substation.
Accordingly, DG limits were derived by identifying the most significant or limiting constraint
for each of the feeders that were analyzed for potential DG interconnection (up to 900 feeders
were analyzed). For example, on some feeders, new DG capacity was constrained by short
circuit capacity limits while others were constrained by reverse power or minimum loading
limits. Further, in some instances (e.g., specific feeders) the constraint was due to limits on the
THESL system; other limits were due to constraints on the HONI system.
This section and Section 4 also include a qualitative discussion of any potential physical or
electrical impacts on upgrades that may be required to address local constraints, including
larger DG that cannot be directly installed on THESL distribution lines or stations.
Key Assumptions
Key assumptions employed in the Existing Conditions Case analysis include:
1. Leaside, Hearn and Manby station short circuit capacity improvements and other
upgrades approved by the OEB are not yet undertaken (Phase 1)
18
This higher level approach avoids the need for a feeder-by-feeder analysis and recognizes that THESL’s system is comprised of a
limited number of relatively homogeneous network “topologies.”
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 31
2. To derive maximum limits, all DG is assumed to be installed at the station bus in order
to produce maximum fault current (fault current contribution at this location from PV is
1:5-to-one and from synchronous generation is five-to-one).
3. All feeders serve an even split of residential, commercial, and industrial customers.
4. All DG is assumed to be distributed “optimally” on the THESL system to fully utilize
the available DG connection capacity on each feeder / bus to the limiting constraint type
(NB - actual DG installations are likely to be clustered at the most suitable and costeffective locations, but there is no way of predicting this over the longer term).
5. Mix of assumed installed DG was evaluated for two scenarios per Section 3.6: 100%
inverter-based PV; and, 100% (rotating) synchronous machine.
6. Thermal limits for 13.6 kV and 27.6 kV feeders are assumed to be 10 MW and 20 MW,
respectively.
7. Zero available short circuit capacity at THESL stations served by 115kV lines connected
to either Leaside or Manby stations.
8. DG operates at or near unity power factor and remains fixed (not allowed to provide
reactive power support).
The results presented in the following section represent a theoretical upper limit on the amount
of DG that THESL could connect to its system based on these assumptions given. The reason
the results represent an upper limit is largely due to Assumption 4 – that the DG is optimally
distributed or deployed within THESL system to fully utilize all available DG connection
capacity up to the connection capacity limits. In simple terms, the results present below
should be viewed as the amount of DG that THESL could connect to its system if 1) THESL had
complete control over where on its system the DG connected, and 2) THESL deployed the DG
to utilize all available DG connection capacity. In reality, local capacity constraints caused by
clustering would likely limit the amount of DG that can be installed at any particular location
and the actual DG connection capacity would be somewhat less than presented below.
4.2 DG Connection Capacity Limits: Existing Conditions
This section presents the case study results for the existing system as it was configured as of
January 2011. These initial results are presented under the assumption that all DG is connected
to the station bus; that is, the worst case given that DG fault current contribution declines as the
DG is located further down the length of the feeder.19 Results are presented for THESL’s entire
19
The location of DG on the feeder does not impact limits caused by thermal capacity, reverse power or minimum load constraints.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 32
distribution system and for the 13.8kV and 27.6kV systems separately. However, the limiting
factor for new DG installations may be due to either THESL or HONI constraints. The
following subsections summarizes DG limits for the total system, followed by a description of
the methods and derivation of DG limits assuming optimal deployment (up to the lowest
constraint on each feeder) of 100 percent PV and 100 percent synchronous DG scenarios.
Approach Used to Derive Capacity Limits Given THESL & HONI Constraints
The analysis of DG capacity limits under existing system conditions started with a review of
available feeder thermal capacity for the THESL system. Available feeder thermal capacity
serves as a theoretical upper limit to how much DG can be connected in an unconstrained case,
assuming no voltage regulation criteria violations exist. Realistically, under no circumstances
could the distribution system support DG penetration at or near this theoretical limit. As such,
its use is solely intended to provide a base upon which to begin the analysis. (Illustratively, this
upper limit totals 11,200 MW and appears as the first row in Table 3 in the following
subsection.)
The available short circuit capacity is then calculated at each THESL station bus by identifying
the nominal short circuit capacity limits less any existing DG and FIT capacity. (THESL stations
with limited or zero available capacity appears in Table 1 of Section 2.) The lower of the THESL
thermal capacity limits versus available short circuit capacity, by feeder, represents the net DG
capacity available.
Next, existing short circuit capacity constraints due to HONI constraints are identified for each
THESL station. A detailed review of information provided to THESL by HONI confirms that
short circuit capacity levels at stations served by either Manby or Leaside TS have had their
short circuit capacity limits restricted to zero – HONI has indicated it will allow up to 10 MW of
PV capacity to be installed prior to station upgrades. This restriction further constrains
available capacity, and the net available DG capacity is reduced on feeders where HONI
available short circuit capacity is lower than THESL thermal capacity or short circuit capacity
limits.
Finally, the analysis assesses the impact that THESL minimum load and reverse power
constraints have on the estimate of available DG. Our review reveals that HONI’s minimum
load restriction – HONI restricts DG capacity on many station transformers to no greater than
20
aggregate minimum load each TS bus - further reduces available capacity for DG. If the
20
For THESL’s distribution system, the reverse power flow constraint is equal to the minimum load at the transformer station bus at
25 percent – a conservative estimate for PV which operates during daytime hours.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 33
amount of available DG capacity given HONI or THESL minimum load or reverse power limits
21
is less than thermal capacity or short circuit limits, then it became the limiting factor.
DG Capacity Limits: 13.8kV & 27.6kV Distribution
Existing limits for new DG capacity, derived via the process described in the prior section, are
presented in subsequent sections. First, DG capacity limits based solely on THESL system
constraints are presented (absent consideration of the HONI system), followed by the limits
based solely on the HONI system (before and after the planned upgrades to Leaside TS and
Manby TS and without consideration of the THESL system). On any given feeder, the
constraining factor could arise due to limits on the THESL system or the HONI system. The
combined limits – reflecting the lower of the THESL or HONI constraints across all of the
feeders analyzed – often are lower than limits based solely on a evaluation either of the two
systems (THESL or HONI) in isolation. Finally, the proportion of the constraints due to
limitations on both the THESL and the HONI systems are presented for both synchronous and
inverter DG technologies.
The amount of capacity available for DG was derived for two technology scenarios: 1) 100
percent PV (inverter technology), the 2) 100% synchronous DG. The primary difference in these
two technologies is the much higher fault current produced by synchronous DG - this further
limits the amounts of DG that can be installed on feeders and at stations where DG capacity is
limited either by THESL or HONI short circuit capacity.
DG Capacity Limits on THESL System in Isolation
Table 3 presents study DG capacity limits given THESL constraints. When evaluated on the
basis of THESL limits only, net available capacity is 1,626 MW for PV, 1,065 MW for
22
synchronous.
21
The models Navigant developed to perform the analysis simultaneously compare each of the constraints at the feeder level. The
net available DG capacity for each feeder is equal to the minimum capacity available considering all of the possible constraints
(i.e., it reflects the limiting constraint). The process in the subsection presents these constraints sequentially to facilitate the
discussion of DG limits that appear in charts and illustrations in section that follow. Further, as a rule, the factors that limit DG
capacity often followed the sequence described in this section; for example, for optimally distributed amounts of DG (and
assumed DG size at less than 10 MW), feeder thermal capacity was never the limiting factor for new DG.
22
In this table and those that follow, the maximum available DG capacity is based on the idealized assumption that DG installations
are optimally distributed on all feeders and substations up to the local DG connection capacity limits. The actual amounts will be
lower in many locations where DG is likely to be clustered and not optimally distributed. Further, larger DG (e.g., greater than 10
MW) typically will require dedicated feeders and substation breakers, which will significantly increase the cost of interconnection,
particularly in areas where distribution lines are located underground. In some locations such Windsor TS, spare distribution
station capacity is not available, which will increase interconnection costs.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 34
Table 3 – DG Capacity by V oltage Level and Technology (THESL System Only)
PV
Synchronous
13.8kV
27.6kV
TOTAL
(MW)
13.8kV
27.6kV
TOTAL
(MW)
Feeder Thermal Limit
5,660
5,460
11,240
5,660
5,460
11,240
Short Circuit Capacity
1,540
3,290
4,830
460
990
1,450
Minimum Load
710
1,110
1,820
570
890
1,460
DG Capacity: Minimum of All Constraints
595
1,031
1,626
371
693
1,065
DG Capacity Limit (THESL)
As discussed in Section 3.6, the fault current contribution of a synchronous machine is far
higher, at five times rated current, than that of an inverter-based device. Accordingly, the
distribution system can accommodate less synchronous DG capacity. Also, PV reverse power
limits are higher than synchronous DG due to the assumption that reverse power equal to 125
percent of minimum load can be accommodated (PV output during minimum hours of
minimum load often is zero).
DG Capacity Limits on HONI System in Isolation under Existing Conditions Case
Table 4 presents DG capacity limits given HONI constraints. Results are presented for PV and
synchronous DG. Results indicate the amount of DG capacity that can be installed given HONI
constraints is significantly lower, primarily due to short circuit capacity constraints at Leaside,
Hearn and Manby. Notably, zero synchronous DG and only 10 MW is available for new DG on
the 13.8kV system. In the following section, the impact of HONI station upgrades on total
available DG capacity is presented.
Table 4 – Base Case DG Capacity Limits (HON I System)
PV
Synchronous
13.8kV
27.6kV
TOTAL
(MW)
13.8kV
27.6kV
TOTAL
(MW)
TS Short Circuit Capacity
10
1,663
1,673
0
499
499
Minimum Load
578
601
1,179
578
601
1,179
Thermal Capacity
669
893
1,562
669
893
1,562
DG Capacity: Minimum of All Constraints
10
386
396
0
310
310
DG Capacity Limit (HONI)
4.3 DG Connection Capacity Limits: After Leaside and Manby
Upgrades
This section describes how OEB-approved upgrades at Leaside, Hearn and Manby, once
completed, will increase DG capacity limits, mostly on 13.8kV circuits in downtown Toronto.
Since these upgrades have been approved and under construction (or scheduled for
construction), this scenario is deemed to be the “Base Case” for purposes of determining the
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 35
most likely level of DG that can be installed on THESL’s distribution system. These upgrades
are scheduled to be completed within the next few years, the time when new DG may be
needed to meet provincial RPS targets. Similar to the Existing Conditions Case, the Base Case
studies evaluate DG capacity limits under the assumption of 100 percent PV versus 100 Percent
synchronous generation.
The additional capacity enabled by the HONI station upgrades occurs solely on the 13.8kV
system. Table 5 presents the increase in DG capacity under the assumption the HONI station
upgrades are in service. Hence, results that appear in Table 4 for the 27 kV system remain
unchanged (Table 3 also is unchanged as DG limits are listed from THESL constraints only).
Notably, both PV and synchronous DG capacity limits increase significantly once the station
constraints are addressed: up to 1,100 MW of PV and 370 MW of synchronous DG will be
enabled upon completion over the next few years. The much higher PV limits are due to the
lower short circuit fault contribution for PV compared to synchronous DG.23
Table 5 – DG Capacity Following HON I TS Short Circuit Upgrades (HON I System Only)
PV
Synchronous
13.8kV
27.6kV
TOTAL
(MW)
13.8kV
27.6kV
TOTAL
(MW)
1,248
1,663
2,992
374
499
898
Minimum Load
578
601
1,179
578
601
1,179
Thermal Capacity
669
893
1,562
669
893
1,562
DG Capacity: Minimum of All Constraints
499
386
884
278
310
588
DG Capacity Limit (HONI)
TS Short Circuit Capacity
Total DG Capacity Limits Considering THESL and HONI System
After Leaside, Hearn and Manby upgrades, total system capacity limits will increase to 490 MW
of synchronous DG or 733 MW of PV assuming optimal deployment to fill available capacity on
each feeder. Table 6 presents these totals by voltage, by technology, and reflect the lowest
amount of DG that can be added for each feeder given THESL and HONI constraints,
whichever is lowest.
Table 6 – Total N et DG Capacity Limits
PV
DG Capacity Limit (HONI &
THESL)
Net DG Limits - Lower of THESL & HONI
Constraints
23
Synchronous
13.8kV
27.6kV
TOTAL
(MW)
13.8kV
27.6kV
TOTAL
(MW)
377
356
733
207
283
490
If PV fault contribution ratio was reduced from 1:5 to 1 to 1:1, the available capacity for PV would increase to approximately 1,500
MW on the 13.8kV system.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 36
DG Limits by System Constraint (THESL or HONI)
For the revised base case, which includes HONI station short circuit upgrades, the relative
contribution of each of the five HONI or THESL constraints to the aggregate system constraints
across all of the THESL feeders evaluated is summarized in Figure 16 and Figure 17. Notably,
of the 870 feeders evaluated, THESL and HONI thermal limits did not appear once as a limiting
factor, an expected result given the assumption of equal allocation of new DG capacity on all
feeders. Further, for PV the greatest constraint is reverse power/minimum load limits at
approximately 71 percent; whereas the largest constraint for synchronous DG is HONI short
circuit capacity at about 41 percent. Each of these results is expected, as synchronous DG
produces much higher fault current than DG. For PV, the primary mitigation option to enable
new DG is to address transformer reverse power constraints; options are presented in the
following subsection.
LimitsConstraints
by Constraint
Figure 16 – ContributionPV
to Capacity
A ggregate System
for PV (After HON I Upgrades)
0% 0%
13%
THESL Feeder Thermal (0%)
16%
THESL Short Circuit
Capacity
HONI Minimum Load
HONI Short Circuit Capacity
71%
HONI Thermal Capacity
(0%)
DG Capacity
by
Figure 17 – ContributionSynchronous
to A ggregate System
ConstraintsLimits
for Synchronous
DG (A fter HON I
Constraint
Upgrades)
0% 0%
THESL Feeder Thermal
(0%)
24%
41%
THESL Short Circuit
Capacity
HONI Minimum Load
HONI Short Circuit
Capacity
35%
HONI Thermal Capacity
(0%)
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 37
5
E NABLING O PTIONS TO I NCREASE DG
C ONNECTION C APACITY
Candidate solutions to address DG penetration limits were identified for each of the constraints
listed in the tables and charts presented in prior sections. These solutions are characterized as
“Enabling Options,” some of which apply to constraints on the THESL system, some of which
apply to the HONI system; and in some instances, may apply both to the THESL and HONI
systems.
The primary categories addressed include:
1. Fault Current Mitigation – options to reduce fault current contribution produced by DG.
Also includes increasing system fault current limits
2. Minimum Load Limits/Reverse Power Limits – options to mitigate reverse power
conditions or to enable reverse power on equipment
3. Thermal Capacity Limits – options to reduce thermal loadings or to avoid overloads
4. Protection Limits and Requirements – upgrades or controls to ensure protections
systems or setting are not compromised
Navigant and THESL conducted an exhaustive review of approaches to mitigate factors that
limit DG capacity, and identified 17 solutions to allow greater DG penetration. These solutions
are characterized as “Enabling Options”. Enabling options include solutions to address
constraints on:
•
THESL’s 13.8kV and 27.6 kV system;
•
HONI stations and lines; and
•
DG technologies (PV and Synchronous DG).
As noted in prior sections, the primary factors or constraints limiting the amount of DG that can
be installed on THESL’s distribution system include:
•
Short circuit capacity (HONI and THESL)
•
Reverse power limits (on HONI transformers)
•
Station thermal capacity limits (HONI and THESL)
•
Feeder thermal capacity limits (THESL)
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 38
A preferred set of enabling options were screened based on:
•
The amount of incremental DG enabled
•
Technical and operational performance
•
Cost (versus other alternatives)
•
Local upgrades will likely be required to mitigate local constraints
Table 7, Table 8 and Table 9 present each of the 17 candidate solutions, with descriptive details,
applications and thresholds, and high-level cost estimates (A more detailed description of these
options appear in Appendix C). As noted, some of these options apply to HONI, THESL, or
both. An explanation of each heading for each column is provided below for each of the four
constraint categories listed above. Certain upgrades apply only to the THESL and HONI
systems, and are designated as such in the following three tables.
Enabling Option – A description of the option intended to address the constraint
Expected Benefits – A qualitative description of the expected benefits; usually in terms of
the additional DG capacity that is enabled. Includes potential disadvantages or trade-offs
High Level Cost Estimate – Estimates of the cost of the solution or option based on
industry data, THESL estimates, or Navigant estimates
Table 7 presents six enabling options that may be suitable choices to mitigate short circuit
capacity constraints. Each of these options generally is suitable for mitigating fault current
contribution for either the THESL or HONI systems.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 39
Table 7 – Enabling Options: Short Circuit Capacity
Item
#
Enabling Option
1
Current limiting fuses
(CLiP) or Fault Fighter
Fuse
- Very fast detection and interruption of
synchronous DG output
- May cause nuisance tripping for local faults
$50-60k per device, including spare fuse
2
In-Line Reactors
- For installation at feeder termination, no
momentary or sustained interruptions are need to
reduce short circuit currents
- Also avoids nuisance tripping for local faults
$100k per installation or $70k each if
installed directly at the generator,
3
In-Line Reactors at the
TS
- For installation at feeder termination, no
momentary or sustained interruptions are need to
reduce short circuit currents
- Also avoids nuisance tripping for local faults
4
Upgrading equipment
short circuit capacity
- Able to accommodate large amounts of DG &
improved protection coordination
- Extensive planning and construction and may take
several years to implement
Highly dependent on location and could
range from $260k for low voltage
replacements to several million dollars for
TS upgrades
5
Install high impedance
step-up transformers
or generator’s
- Lower short circuit currents than standard
transformers, but less than other options
10-15% incremental cost above standard
transformers
6
Feeder
Reconfiguration (e.g.,
feeder cut and tie)
- Enables greater amount of all types of DG (large
and small)
- Eliminates short circuit current for stations at risk
Up to $250k if major upgrades are
needed. Under $30k where adjacent
feeders are close & can be cut over
Expected Benefits
High-level Cost Estimate
$500k per installation or $70k each if
installed directly at the generator
Similarly, Navigant and THESL identified enabling options that address minimum load or
reverse power constraints as potential solutions for increasing DG capacity limits. Table 8
presents five enabling options considered as potential solutions to mitigate minimum load and
reverse power constraints, virtually all of which occur at the station level. All of the enabling
options listed except Item 10 – Replace TS Transformer, can be used to mitigate THESL and
HONI minimum load limits.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 40
Table 8 – Enabling Options: M inimum Load/Reverse Power
Item
#
Enabling Option
Expected Benefits
High-level Cost Estimate
7
Dedicated feeder to station not
constrained by minimum load
Enabling greater amounts of large
scale DG
$2-4M per feeder
8
Increasing renewable output
beyond bus minimum ld condition
Very low cost option for enabling
higher amounts of renewable DG
None, other than monitoring feeder loads in
conjunction with renewable output
9
Interruptible DG
Enabling greater amounts of large
scale DG
$25-50k per DG installation, plus
communications systems where applicable
10
Replace TS Transformer
Reducing the minimum load limitations
caused by substation transformers
High cost may be mitigated for stations with
older transformers or devices near end of life
11
Dedicated substation transformer
and feeder unconstrained by
minimum load
Enabling greater amounts of large
scale DG
$6-8M per transformer and feeder
arrangement
Table 9 presents six options for mitigating or addressing constraints or requirements relating to
protection and controls.
Table 9 – Enabling Options: Capacity, Protection & Controls
Item
#
Enabling
Option
Constraint
Addressed
12
Local or mainline
equipment
replacement
Capacity Limits
Enables greater amounts of large
scale DG or DG in aggregate
Up to $25k for local transformation to
or $250K for single-phase line or
cable upgrade
13
Major substation
upgrade
Substation Capacity
Constraints
Enables greater amounts of large
scale DG or DG in aggregate
Costs range from $250k for single
switchgear replacement to over $3M
for major substation upgrades
14
Transfer-tripping
Capacity Issues
Enables greater amounts of large
scale DG without major system
upgrades
Between $50-150k per transfer-trip
scheme
15
Real-time
monitoring
System Planners and
Operations must
monitor DG for high
amounts of small PV
Enables greater amounts of DG
penetration
- For large devices, assume $25k per
for data communication and control
- For smaller DG, $100 per device to
access THESL smart meters
16
Substation Relay
Upgrades
Protection
Enables greater penetration of large
DG; e.g., synchronous devices
$50k per breaker
17
Transmission
Interconnection
Capacity, voltage,
protection or other
Eliminates local capacity and short
circuit capacity limits. Applicable to
large DG (10 – 20 MW each)
Up to $10M
Expected Benefits
High-level Cost Estimate
Specific enabling options listed in the above three tables are evaluated in further detail in
Section 4 to identify the most likely and cost-effective options. Section 4 also presents an
Implementation Plan that enables THESL and DG owners to balance the cost of options versus
the additional DG capacity enabled as part of the interconnection application process.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 41
5.1 Impact of Other Upgrades to the Area Transmission System
The analyses presented herein assume upgrades to Leaside, Hearn and Manby (Stage 2), but
exclude other major transmission upgrades or a possible third source of supply to Toronto. If
and when completed, any of these other upgrades would likely have a significant impact on the
results presented in this report.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 42
6
C OSTING AND A PPLICATION OF E NABLING
O PTIONS
In this section the enabling options are evaluated with regard to cost versus additional DG
capacity enabled to identify a prudent course of action to be taken to respond to requests for
interconnection to THESL’s distribution system. Because one cannot predict either the location
or amount of DG that will be requested over time, costs are presented for a range of potential
upgrades for both PV and synchronous generation technology. The ability for THESL to select
from one of several candidate enabling options provides a “menu-driven” approach, with
potential costs based on the most appropriate option selected. The approach also recognizes
that specific solutions will be applicable depending on the type and size of DG and nature of the
constraint. Also, the approach does not preclude the very real possibility that additional costs
may be required of applicants for interconnection to address local constraints, or for larger DG
that may require dedicated circuits or substation equipment to enable interconnection with
exceeding distribution capacity limits.
6.1 Enabling Options for DG Capacity
Synchronous DG
For synchronous DG, seven enabling options were selected as the most cost-effective and
suitable solutions to address the two primary limitations for new DG (short circuit capacity and
minimum load/reverse power).
Five options were selected for mitigating short circuit current from synchronous DG under the
“enabled” case, including:
1. Current-limiting devices (CLiP fuses, S&C Fault Fiter fuses);
2. DG-side in-line reactors;
3. TS-side in-line reactors;
4. High impedance step-up transformers and high impedance DG; and,
5. System reconfiguration as it applies to cases in the THESL system.
The applicability and cost of each of the above varies based on technology, size, location and
generator preference. Similarly, Minimum load enabling option costs vary depending on
applicability and solution selected.
The three minimum load-related enabling options evaluated include,
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 43
1. Interruptible DG;
2. TS transformer upgrade/replacement; and,
3. System reconfiguration.
The unit costs ($/kW of DG enabled) to increase synchronous DG capacity limits based on the
seven options and the range of costs associated with these options are presented in Figure 18.
Notably, the range in cost to enable synchronous DG varies significantly, underscoring the
location-specific factors that determine the cost of individual applications for interconnection.
Figure 18 – Enabling Options and Cost for Synchronous DG
Enabling Options Required
CLiP fuses
S&C Fault Fiter fuses
Inline Reactors
High Impendence Step-up
Transformer
System Reconfiguration
Synchronous DG
connection request
on a constrained
feeder or TS
If SC Constraint
Increase DG connection
capacity by selecting from
SC mitigating options
$32 - 197/kW
If Minimum Load Constraint
Interruptible DG
Increase DG connection
capacity by selecting from
min load options
“Enable”
synchronous DG
connection
request
$26 - 202/kW
$26 - 202/kW
Transformer Replacement
System Reconfiguration
• Costing provided does not reflect that in specific cases:
— Short circuit AND minimum load constraints may need to be addressed,
requiring both types of enabling options
— Additional interconnection costs will likely result pending any local
upgrade requirements. Specific local upgrade requirements could also
be uncovered during generator interconnection process
Further, the costs ranges provided above do not reflect case-specific costs that may be needed to
interconnect DG. For example, costs may increase due to,
Short circuit and minimum load constraints may need to be addressed, requiring both
types of enabling options, which could substantially increase costs. However, the second
set of costs would not be needed until the increase in capacity achieved by the first
enabling option.
Additional interconnection costs will likely result pending any local upgrade
requirements. Specific local upgrade requirements could also be uncovered during
generator interconnection process.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 44
Clustering of DG to particular feeders or stations may reduce total DG capacity that can be
installed without upgrades. Given the likelihood that DG will be clustered based on
locality and opportunities (e.g., industries most suitable for synchronous DG for CHP and
rooftop orientation for PV), capacity limits likely will be reached in pockets within the City
and multiple enabling options may need to be deployed.
Photovoltaic (PV)
For PV, solutions are more straightforward as inverter-based technologies do not encounter the
same level of limitations and constraints as those associated with rotating machines such as
synchronous DG. The enabling options for PV include:
Upgrading TS’ to allow up to 25% reverse power flow (25 to 50 MVA)
Reverse power flow lesser of 25% or available short circuit capacity
24
Station transformer upgrades costs varied by station size, quantified below:
$5 million for 100 MVA
$10 million for 200 MVA
$15 million for 400 MVA
Figure 19 presents the ranges of costs applicable to PV. Although fewer options apply to
mitigate capacity constraints, the range in cost to interconnect new DG, where applicable, varies
considerably at different locations on the system.
24
Inline reactors were initially considered to mitigate short circuit current limits for PV; however, reverse power flow at HONI TS’
is the dominant constraint (reverse power limits are reached before short circuits).
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 45
Figure 19 - Enabling Options and Cost for PV
Enabling Options Required
PV connection
request on a
constrained feeder
or TS
Increase PV
penetration up to
125% of min TS load
$10/kW
SC limits
exceeded
?
[Yes]
Install TS-side inline
reactors (suppress
short circuit current)
$500,000 per device
or up to $54/kW
[No]
Transformer Station
upgrades required
(25% Reverse Power
Flow)
$202/kW
“Enable” PV DG
connection
request
$10 - 256/kW
• Costing provided does not reflect that:
— In specific cases additional interconnection costs will likely
result pending any local upgrade requirements
— Specific local upgrade requirements could also be uncovered
during generator interconnection process
The costs ranges provided above do not reflect case-specific costs that may be needed to
interconnect DG. For example, costs may increase due to the following:
Short circuit and minimum load constraints may need to be addressed, requiring both
types of enabling options, which could substantially increase costs. However, the second
set of costs would not be needed until the increase in capacity achieved by the first
enabling option.
Additional interconnection costs will likely result pending any local upgrade
requirements. Specific local upgrade requirements could also be uncovered during
generator interconnection process.
Clustering of DG to particular feeders or stations may require multiple enabling options to
be deployed.
6.2 Prudent Approach to Enabling New DG Capacity
HONI bases maximum PV capacity on minimum TS loading. Navigant believes this constraint
is overly conservative and recommends allowing PV up to 125% of minimum load (which is
still conservative). For example, a snapshot of daily load versus PV output profiles (Figure 20)
illustrate the coincidence of PV output with maximum hourly loads for large DG (> 20MW) for
the month of April 2010 – confirming PV output will get closest to hourly bus load during
shoulder periods on sunny (or high insolation) days with moderate temperatures.
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Figure 20 – PV Output versus Load Profiles (Bathurst Station)
60
Maximum Bus Load in 2010 =
58 MW
Hourly Load/Output (MW)
50
Hourly Load (Bus Y Bathurst TS)
Hourly Output (PV DG)
40
30
20
Minimum Bus Load in 2010 =
14 MW
10
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
Figure 21 illustrates the significant difference between PV capacity versus actual minimum load
on a percentage basis, underscoring the margin between current HONI limits and calculated
limits for the Bathurst “Y” bus (reverse power does not occur until PV output is approximately
200 percent of Y-Bus minimum load).
Figure 21 - N umber of Reverse Flow Hours vs. PV Penetration (as % of M inimum Load)
200
Current HONI Limit
175
Reverse Flow Hours / Year
Proposed Limit = 125% of Min. Load
150
Calculated Limit for
Bathurst Y Bus
125
100
75
50
Incremental PV DG
given coincidence of
loading and PV output
25
0
100%
125%
150%
175%
200%
225%
250%
PV Capacity as % of Minimum Load
275%
300%
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A duration curve showing the bus loading over all hours of 2010 sorted from highest to lowest
with the corresponding PV output for each hourly bus load based on the PV capacity limit of
125% of minimum load is shown in Figure 22. As shown, at no point during the year is PV
output greater than the bus loading.
Figure 22 – Duration Curve of Bus Loading and Coincident PV Output
(PV Capacity = 125% of M inimum Load)
6.3 Cost Impact and Cost Recovery of Enabling Options
THESL’s DG Requirements provide practical guidance and an equitable approach of cost
recovery for renewable generation enabling options per the OEB’s Distribution System Code
(DSC). Specifically:
THESL DG Requirements differentiate between expansions and enhancements
THESL will pay up to $90,000 / MW for expansions and entire cost of enhancements
necessary to enable renewable generation connection
Some enabling options are expansions, others are enhancements and others would likely
be considered enhancements, but are not specifically listed in the DSC
To eliminate uncertainty related to cost recovery of enabling options, Navigant suggests that
THESL seek Board concurrence with the following statement:
If an enabling option for renewable generation is NOT an expansion, then it will be
deemed to be an enhancement (i.e., enhancement list is open-ended)
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As per the DSC, the costs of an enabling option for non-renewable generation (e.g., synchronous
CHP DG), regardless of whether it is an expansion or an enhancement, shall be recovered from
the generator requesting connection. Navigant is aware of significant interest in CHP in
Toronto and elsewhere. Given this interest, the OEB could consider establishing policy with
respect to specific types of non-renewable generation (e.g., those eligible for the OPA’s CHP IV,
CHPSOP and ERSOP generation procurements) that parallels the treatment for renewable
generation but any such change in policy would be outside THESL’s mandate.
It is also important to note that some enabling options can only be undertaken by HONI. Cost
recovery for these options would be subject to the OEB’s Transmission System Code (TSC) and
HONI’s policies reflecting the TSC. These options and policies are outside THESL’s mandate,
but THESL will work with HONI to identify the lowest cost enabling option for each generation
connection request.
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7
C ONCLUSIONS
Navigant’s study of DG connection capacity limits on THESL’s 13.8kV and 27.6kV distribution
system has identified several feeders and busses with significant DG connection capacity
available, whereas some feeders and busses were found to have very limited or no connection
capacity. In most areas with limited or no capacity, the current HONI transmission system is
the limiting constraint to new DG installations. THESL equipment is the limiting constraint for
only a few feeders and busses.
Navigant’s specific findings with respect to THESL’s DG connection capacity include:
Currently, new DG in downtown Toronto and the eastern section of the City is limited to
10 MW for PV (and zero for synchronous DG25) due to short circuit capacity limits at
HONI’s Leaside, Hearn and Manby stations, and transmission limits on the 230kV delivery
system East to Cherrywood station in Pickering,
OEB-approved upgrades to the HONI system over the next few years will increase the DG
connection capacity on THESL’s 13.8kV system to 377 MW for PV or 207 MW for
synchronous DG, and
Without considering the transmission system to which it is connected, THESL’s 27.6kV
system has connection capacity for up to 833 MW of PV or 693 MW of synchronous DG.
Considering the transmission system and HONI constraints, the connection capacity is
reduced to 356 MW for PV or 283 MW of synchronous DG.
Navigant and THESL jointly assessed the viability of the various enabling options as identified
by Navigant for potential inclusion in THESL’s GEA Plan. As part of this assessment, Navigant
and THESL estimated the likely range of costs and unit costs ($ / kW of DG enabled) for such
upgrades based on THESL’s system characteristics. Since there are several different types of
constraints, varying system configurations across THESL’s service territory and non-uniform
geographic and temporal distribution of DG connection requests, there is no single “silver
bullet” or option to address all of THESL’s DG connection capacity constraints.
In general, however, where mitigation and upgrades are needed, DG connection capacity can be
increased at a unit cost well below the installed cost of DG capacity. For feeders that are
constrained, the analysis undertaken by Navigant and THESL indicates that additional DG
25
Inverter-based PV generation has different electrical characteristics than synchronous-based generation (such as for a mediumsized CHP installation), particularly with respect to fault current contribution. Given these differences, the available DG
connection capacity will depend on the type of generation to be connected. For simplicity Navigant refers to the connection
capacity for PV or for synchronous DG, whereas THESL is likely to get connection requests for a combination of generation types
and the connection capacity would likely fall between the values given for PV and synchronous DG.
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connection capacity can be installed through a variety of enabling options at an expected cost
less than $300/kW of DG enabled with the following caveats:
Large DG (greater than 10 MW) may require dedicated feeders and station positions that
could cost more than $300/kW of DG enabled,
Local upgrades may still be required to address capacity and voltage constraints, and
Some enabling options require changes or upgrades to HONI system; notably, some
upgrades include replacement of HONI equipment that is 50 or more years old.
THESL’s GEA plan will incorporate the viable options into several local upgrade plans that
reflect local system constraints and the best available information on current and forecast DG
connection requirements on THESL’s stations and feeders. Together, the upgrade plans
proposed in THESL’s GEA Plan and HONI’s local transmission system upgrades will
significantly increase THESL’s DG connection capacity.
Even with these substantial upgrades, new DG connection applications outside THESL’s
current forecast may still be subject to constraints on certain feeders or buses. It is expected that
many of these constraints can be addressed through the application per THESL’s DG
requirements and cost recovery policy of the enabling options identified within this report.
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A PPENDIX A: C ASE S TUDY D ESCRIPTIONS
The following case studies were analyzed to assess DG capacity limits and enabling options for
THESL’s downtown 13.8kV and the27.6kV system located outside of the downtown area.
Case 1 - Long 27.6 kV Feeder
The long 27.6kV feeder is assumed to be approximately five to six kilometers in length.
This is one of the more common feeder types on THESL’s distribution system,
representing _ percent of the total population of feeders. For simulation purposes,
THESL’s NY85M1 feeder was selected for Case 1.
Case 2 - Short 27.6 kV Feeder
The short 27.6kV feeder is assumed to be approximately two to four kilometers in length.
The short 27.6kV feeder represents _ percent of the total population of feeders. For
simulation purposes, THESL’s NY85M1 feeder was selected for Case 2, as it exhibits
similar performance as the Case 1 27.6kV feeder.
Case 3 - Long 13.8 kV Feeder
The long 13.8kV feeder is assumed to be approximately three to four kilometers in length.
This is one of the more common feeder types on THESL’s downtown distribution system,
representing _ percent of the total population of feeders. For simulation purposes, THESL’s
George & Duke A19GD feeder was selected for Case 3.
Case 4 - Short 13.8 kV Feeder
The short 13.8kV feeder is assumed to be approximately three to four kilometers in length.
This also is one of the more common feeder types on THESL’s downtown distribution
system, representing _ percent of the total population of feeders. For simulation purposes,
THESL’s George & Duke A19GD feeder also was selected for Case 3, as it exhibits similar
performance as the Case 3 13.8kV feeder.
Case 5 – Pilot Wire
The pilot wire arrangement includes multiple 13.8kV feeders operating in parallel (the same
arrangement is possible for 27.6kV feeders), thereby increasing the effective capacity of
combination of lines. A pilot wire protection scheme is necessary to ensure only faulted line
sections trip when a line or cable fault occurs. This provides for greater redundancy and
reliability. The pilot wire scheme at THESL’s Terauley station was selected for simulation
analysis. The pilot wire arrangement is used as needed to accommodate large loads, and
represents _ percent of the total system
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Case 6 – Pilot Wire
Case 6 is a variation of the Case 6 Pilot Wire Scheme.
Case 7 - Bathurst Tie Point (Extended Feeder)
This case includes the transfer of load from an adjacent feeder to another via closure of an
open tie, typically performed for outage events or maintenance. This is uncommon, but
may apply to many feeders on THESL’s system. The significance of this case is that a higher
amount of DG may be fed into a feeder breaker, thereby increasingly the likelihood of short
circuit violations.
Case 8 - Terauley/G&D Tie Point (Extended Feeder)
Case 8 is a variation of Case 7.
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A PPENDIX B : P OWER F LOW S IMULATION A NALYSIS
Appendix B presents THESL’s power flow simulation analysis of Distributed Generation (DG)
penetration scenarios and their impact on the distribution grid. These studies were conducted
to support the results and findings presented throughout this report.
The THESL distribution grid consists of 27.6 kV, 13.8 kV, and 4.16 kV looped-radial and pilotwire feeders. Hence, the feeders chosen for this study (listed below) provide a representative
sample of feeders found on THESL’s distribution grid. These feeders are:
a. 27.6 kV feeder - NY85M1 (Bathurst TS)
b. 13.8 kV feeder - A19GD, A20GD, A310GD (George & Duke TS)
c. 13.8 kV Pilot wire feeders – A23A, A25A, A27A (Terauley TS)
Both synchronous-type and PV-type DG were connected on these feeders at various points
depending upon the feeder types. As an example, the DGs were connected at three points along
the 27.6 kV feeders (close to the bus, end and midpoint of the feeder) while the pilot-wire feeder
only saw DGs connected at the endpoint.
This next section describes the methodology used to conduct this study. The impacts of these
DGs on the distribution grid were evaluated in terms of:
a.
Feeder short circuit profile
b.
Maximum DG permissible given system short circuit constraints (760 MVA– 27.6
kV, 475 MVA – 13.8 kV)
c.
Voltage profile along the feeder
d.
Ampacity profile of load along the feeder
Unless otherwise stated, the results of this study are based on existing civil and electrical
infrastructure.
Subsequent sections of this appendix report present the results of the case studies and the
impact of connecting these DGs to the THESL’s distribution system. Feeder parameters and
data used in the studies also are provided. CYMDIST software platform is used to conduct the
analysis.
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B.1 Background and Methodology
For each of the representative feeders, the following DG technologies are connected along
various points of the feeder:
a. Synchronous-type DGs (6 MW, 12 MW, 20.9 MW)
b. PV-type DGs (500 kW, 2 MW, 5 MW)
For each scenario, the short circuit profile along with the voltage and ampacity profile are
calculated. Further, for each simulation, feeders’ loads are also considered. Based on the feeder
loading profile, the minimum and maximum load of feeder are connected to the feeder as a spot
or a distributed load depending upon the feeder type. The net feeder load flow at the station
breaker is important in assessing the thermal capacity of the feeder and bus. This load assists in
calculating cable ampacity (net power export as result of minimum load). However, the load is
assumed to have no impact on the short circuit profile.
Key study assumptions include:
a. Transformer reactance is assumed to be at 6.25%
b. For PV-type DGs, the fault contribution is assumed at 110% of rated current
c. Power factor of 90% is assumed for load conversion (kVA to kW)
d. For fault current simulations, contributions from both induction and synchronous
motors are factored in the analysis
e. Real power flow direction from bus to the end of feeder is defined as negative
f.
Real power flow direction from end of the feeder to the bus is defined as positive
The case studies are organized as follows:
a. Case Study title - Feeder type (27.6 kV)
1. DG scenario (no DGs/synchronous generators/ PVs/mixed)
1.1. DGs connected at the end of the feeder
1.2. DGs connected at the middle of the feeder
1.3. DGs connected close to the bus
b. Case Study title - Feeder type (13.8 kV/ Pilot-wire)
1. DG scenario (no DGs/synchronous generators/ PVs)
2.1. DGs connected at the end of the feeder (Short Circuit Current, Voltage and
ampacity
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The existing calculations used the nominal voltage values; i.e. 27.6 kV and 13.8 kV instead of the
normal operating voltages (which tend to be up to 5% greater). In addition, the feeder length
and the dominant cable types of the respective feeders are:
a. 27.6 kV – 5.8km (556 Al Overhead bare, 1000 kcmil TRXLPE Underground cable)
b. 13.8 kV – 1.2 km (500 TRXLPE Underground cable)
c. Pilot-wire – 737m (500 PILC H type Underground cable)
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B.2 Short Circuit Analysis
The results of THESL’s CYME short circuit analyses are displayed below for each of the DG
connection scenarios described above and in the main body of this report. It includes fault
circuit levels for DG installed at three locations on representative distribution feeders: (1) at the
substation bus; (2) middles of the feeder; and (3) end of the feeder. Results indicate that fault
current contribution from DG drops significantly as DG location is further from the substation
bus. Case study results presented in this report are based on the assumption that all DG is
installed at the substation bus. Thus, available DG capacity may be higher on feeders where DG
is installed further from the base and where short circuit capacity limits is the primary
constraint.
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B.3 Voltage Performance
In addition to short circuit data, the CYME model also produced feeder voltage profiles for DG
installed at the station bus, middle and the end of each representative feeder. The following
table summarizes results for the end of feeder installations, as these represent the worst case
scenarios. In addition, the voltages include minimum and maximum as derived by CYME
simulation studies, measured at the end of each feeder. Results indicate voltage performance
for all DG case and technologies is robust, as variances are well within limits (+/- 5 percent from
nominal).
CY M E Simulation Study Results - V oltage Profiles
DG Type
Feeder Voltage
Maximum
Load (PU
Voltage
Minimum
Load (PU
Voltage
Base Case
No DG
27.6kV
1.000
1.000
6.0 MW
Synch
27.6kV
0.996
1.001
20.9 MW
Synch
27.6kV
1.007
1.013
2.0 MW
Synch
27.6kV
0.991
0.997
5.5 MW
Synch
27.6kV
0.992
0.998
PV, Synch
27.6kV
0.996
1.001
PV, Synch
27.6kV
1.008
1.014
Base Case
No DG
13.8kV
0.997
0.999
2 MW
Synch
13.8kV
0.998
1.000
9.75 MW
Synch
13.8kV
1.001
1.003
PV
13.8kV
1.000
1.000
Synch
13.8kV
1.001
1.003
Pilot Wire
13.8kV
0.998
1.000
Pilot Wire
13.8kV
0.999
1.001
No DG
4.16kV
1.000
1.000
PV, Synch
4.16kV
1.000
1.000
DG Size (MW)
2 MW PV
6 MW Synch
5.5 MW PV
20.9 MW Synch
2 MW
9.75 MW
2.0 MW PV
2.0 MW PV
18.0 MW Synch
Base Case
0.5 MW PV
0.5 MW Synch
These results indicate that THESL’s short distribution feeders in the downtown area (13.8 kV &
4.16 kV) and higher voltage (27 kV) lines in the “horseshoe” area each contribute to stiff
voltages throughout the service territory. In all cases, voltages varied by no more than two
percent, regardless of DG location. For some feeder types, voltages were relatively unchanged.
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Accordingly, voltage performance is not a limiting factor or primary constraint for DG capacity.
However, voltage performance should be studied for large DG or higher penetration scenarios,
as individual projects may create unacceptable voltage rise under light load or drop under
heavy load. A parametric analysis similar to the results portrayed in the following diagram
would be appropriate. In the example that follows, result indicate very minor shifts in voltage –
less than 1 percent for all cases - for DG installed on a 27.6kV feeder.
27.6 kV feeder - V oltage Profile - PV -DGs Connected at End of Feeder
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A PPENDIX C: E NABLING O PTION D ETAILS
Provided below are detailed descriptions and costs of each of the 17 Enabling Options
evaluated in this study. Table heading descriptions presents each of the candidate solutions,
with descriptive details, applications and thresholds, and high-level costs. As noted, some of
these options apply to HONI, THESL, or both systems.
Constraint Addressed – Corresponds to one of the four constraint categories listed above.
Applies to both THESL and HONI systems
Enabling Option – A high-level title or description of the option intended to address the
constraint
Description – Provides specific details on the type of mitigation or solution proposed,
including location on the THESL or HONI system
Application – Describes the conditions under which the enabling option applies, including
the type of DG where the option applies (PV versus synchronous)
Benefits – A qualitative description of the expected benefits; usually in terms of the
additional DG capacity that is enabled. Includes potential disadvantages or trade-offs
High-Level Cost – Estimates of the cost of the solution or option based on industry data,
THESL estimates, or Navigant estimates
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