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Stage 3 Connection Study Scope
[Insert Customer Name]
[Insert Project Name]
AESO Project Number: [000]
Company Name
Engineer Name P.Eng.
Date
Engineer Signature
Date
Signature
[Studies Consultant]
[AESO (Project Studies Engineer)]
Company Name
Name
[Insert Customer Name]
Document Release [R1]
[insert date]
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Contents
Introduction ......................................................................................................................................... 5
1.1. Project............................................................................................................................................ 5
1.1.1. Project Overview.................................................................................................................... 5
1.1.2. Load Component ................................................................................................................... 5
1.1.3. Generation Component ......................................................................................................... 6
1.2. Study Scope .................................................................................................................................. 7
1.2.1. Study Objectives .................................................................................................................... 7
1.2.2. Study Area ............................................................................................................................. 7
1.2.3. Studies Performed ............................................................................................................... 10
1.2.4. Studies Excluded ................................................................................................................. 11
2. Connection Alternatives Selected for Studies ............................................................................... 12
3. Criteria, System Data, and Study Assumptions ............................................................................. 13
3.1. Criteria, Standards, and Requirements ....................................................................................... 13
3.1.1. Transmission Planning Standards and Reliability Criteria................................................... 13
3.1.2. AESO Rules ......................................................................................................................... 14
3.1.3. Other Requirements ............................................................................................................ 14
3.2. Study Scenarios .......................................................................................................................... 15
3.3. Load and Generation Assumptions ............................................................................................. 15
3.3.1. Load Assumptions ............................................................................................................... 15
3.3.2. Generation Assumptions ..................................................................................................... 16
3.3.3. Intertie Flow Assumptions ................................................................................................... 17
3.3.4. HVDC Power Order (if applicable) ....................................................................................... 18
3.4. System Projects ........................................................................................................................... 18
3.5. Customer Connection Projects .................................................................................................... 19
3.6. Facility Ratings and Shunt Elements ........................................................................................... 19
3.7. Protection Fault Clearing Times .................................................................................................. 21
3.8. Voltage Profile Assumption ......................................................................................................... 21
3.9. Motor Starting Assumptions ........................................................................................................ 22
4. Study Methodology ........................................................................................................................... 22
4.1. Connection Studies Carried Out .................................................................................................. 22
4.2. Load Flow Analysis ...................................................................................................................... 23
4.2.1. Contingencies Studied ......................................................................................................... 23
4.3. Voltage Stability (PV) Analysis .................................................................................................... 23
4.3.1. Contingencies Studied ......................................................................................................... 23
4.4. Transient Stability Analysis ......................................................................................................... 24
4.4.1. Contingencies Studied ......................................................................................................... 25
4.5. Short-Circuit Analysis .................................................................................................................. 25
4.6. Motor Starting Analysis [as required] .......................................................................................... 25
4.7. Effectiveness Factor Analysis Studies [as required] ................................................................... 25
4.8. Sensitivity Studies [as required] .................................................................................................. 25
4.9. Mitigation Measures .................................................................................................................... 26
1.
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Attachments
Attachment A
Transmission Planning Criteria – Basis and Assumptions (Reliability Criteria)
Tables
Table 1.2-1: Summary of System Projects ................................................................................................................... 10
Table 3.1-1: Post Contingency Voltage Deviation Guidelines ...................................................................................... 14
Table 3.2-1: List of the Connection Study Scenarios ................................................................................................... 15
Table 3.3-1: Forecast Area Load (201X LTO at AIL Peak) .......................................................................................... 15
Table 3.3-2: Local Generation (MW) in the Study Cases ............................................................................................. 16
Table 3.3-3: Intertie Assumptions – Example ............................................................................................................... 17
Table 3.3-4: HVDC Power Order by Scenario .............................................................................................................. 18
Table 3.4-1: Summary of System Projects Included in the Study Cases ..................................................................... 19
Table 3.5-1: Summary of Customer Connection Assumptions ..................................................................................... 19
Table 3.6-1: Summary of Transmission Line Ratings in the Study Area (MVA on 138 kV Bases) ............................... 20
Table 3.6-2: Summary of Transformer Ratings in the Study Area ................................................................................ 20
Table 3.6-3: Summary of Shunt Elements in the Study Area ....................................................................................... 21
Table 3.7-1: Summary of Protection Fault Clearing Times ........................................................................................... 21
Table 4.1-1: Summary of Studies Performed ............................................................................................................... 22
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Introduction
1.
This document presents the Project description, connection alternatives to be evaluated, technical criteria,
assumptions and study methodology.
1.1.
Project
1.1.1.
Project Overview
This section is to describe the following:
•
Organization submitting SASR
•
SASR request (load DTS, gen STS, transformer add, breaker add, new POD, …) and why needed
(load growth, new load, new generator, DFO reliability – N-1, feeder loading, …)
•
location
•
Requested In-Service date
[Market Participant Legal Name (Market Participant Short Name)] has submitted a System
Access Service Request (SASR) to the Alberta Electric System Operator (AESO) for [Demand
Transmission Service (DTS) and/or Supply Transmission Service (STS)] of [XXX] MW at
[Project location, e.g., south of the City of Grande Prairie to serve oilfield loads] (the Project).
The requested In-Service Date (ISD) for the Project is [Month, Day, Year of the In-Service date
as per the SASR request].
1.1.2.
Load Component
Describe the load component of the project. Include the following:
•
State existing Demand Transmission Service if applicable.
•
State estimated maximum amount of load to be connected along with the anticipated power factor;
•
Describe the type of load either Residential, Rural, Commercial, Industrial, and/or Oil Sands(these
are the sectors identified in the LTO);
o
Motor sizes if applicable
•
State the magnitude of the potential Demand Transmission Service (DTS) that the Market Participant
intends to apply for; and
•
Comment on possible future expansion plans and anticipated timing for such expansion.
Below are two examples of the write up:
[1. The requested load addition is 17.9 MW by August 17, 2016.
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2. Load Type: Residential, rural, commercial, and light industrial services.
3. DTS contract capacity at South Mayerthorpe 443S to remain at the existing level of 12.5 MW.
4. Currently there is no plan for future expansion.
5. The load will be studied assuming a 0.9 power factor (pf) lagging.]
or
[Current DTS is 14 MW. There will be an addition four 6600 HP motors with three in operation at
any one time. All motors will have dedicated Variable Frequency Drives (VFDs). The requested
DTS increase is for an additional 25 MW for a total DTS 29 MW.]
1.1.3.
Generation Component
Describe the generation component of the project. Include the following:
•
State size of the generator(s) and estimated Maximum Authorized Real Power (MARP) and Maximum
Capability (MC) levels;1
•
Describe type of generator(s);
•
State estimated reactive power capability of the generator(s) when producing MARP. If this value
does not meet the generation interconnection standard specify the intended supplemental strategy. If
available, provide maximum capability curve based on pf/temperature.
•
State the potential magnitude of the Supply Transmission Service (STS) that the Market Participant
intends to apply for and operate at when connected to the grid;
•
State the seasonal generator capacity (if information available);
•
State station service load if applicable; and
•
Comment on possible future expansion plans and anticipated timing for such expansion;
Below is an example of the write up:
[Market Participant Short Name plans to install a co-generation facility consisting of a single
85 MW (nominal) natural gas fuelled combustion turbine-generator. With the addition of this
generator, Market Participant Short Name has requested an anticipated STS capacity of 85
MW.
1. Generators:
Designation
Type
Model
G1
Round Rotor
GE 7A6
2. Supply Transmission Service (STS): 85 MW
3. Rated Nameplate Capacity: 93.9 MVA @ 0.85 pf, nominal
1
Maximum Authorized Real Power (MARP) and Maximum Capability (MC) are defined in the
Consolidated
Authoritative
Document
Glossary
posted
on
the
AESO
website:
http://www.aeso.ca/downloads/Consolidated_Authoritative_Document_Glossary.pdf
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4. Maximum Authorized Real Power (MARP): 100 MW
5. Maximum Capability (MC): 85 MW
6. Reactive Power Capability (preliminary): 48 MVar (0.9 pf lagging) / 33 Mvar (0.95 pf
leading) at MARP,
7. The customer advised that there is no future expansion planned.]
1.2.
Study Scope
1.2.1.
Study Objectives
The objective of the study is as follows:
1. Evaluate the Project connection alternatives based on technical performance.
2. Assess the impact of the Project connection on the AIES by Identifying any pre- and
post-connection constraints
3. Recommend mitigation measures if required.
1.2.2.
Study Area
1.2.2.1.
Study Area Description
Define and describe the Study Area. Include a diagram of the Study Area that clearly shows salient
features such as transmission lines, substations, generating assets, and reactive elements in the area
and indicates their voltage classes. In the Single Line Diagram (the Study Area diagram) show how the
Study Area is connected to the rest of the Alberta Interconnected Electric System (AIES).
The Project is located in the AESO planning area of [AESO planning area, e.g., Grande Prairie
(Area 20)], as part of [The AESO region, e.g., the AESO Northwest (NW) Region].
This section will then describe the Study Area and the ‘Overview of existing system’. Please describe the
Key substations/lines in the Project area and intertie connection with neighbouring areas. Below is an
example of the write up:
[The Study Area for the Project consisted of the Grande Cache (Area 22) and Grande Prairie
(Area 20) areas, including the tie lines connecting the two planning areas to the rest of the
AIES. All transmission facilities within the two planning areas will be studied and monitored for
violations of the Reliability Criteria (defined in Section 3.1.1). The five 144 kV transmission lines
connecting the Grande Cache and Grande Prairie areas to the rest of the AIES (namely
transmission lines 7L73, 7L32, 7L45, 7L46 and 7L40) will also be studied and monitored to
identify any violations of the Reliability Criteria.
The H.R. Milner generation facility, with connection to the H.R. Milner 740S substation,
connects to the Alberta Interconnected Electric System (AIES) through two 144 kV transmission
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lines: one is transmission line 7L20, which connects the HR Milner 740S substation to the Big
Mountain 845S substation in the Grande Prairie area; the other is transmission line 7L80, which
connects the HR Milner 740S substation to the Simonette 733S substation, which further
connects to the Little Smoky 813S substation in the Valleyview planning area (Area 23) via the
144 kV transmission line 7L40.
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Figure 1-1: Existing Study Area Transmission System
]
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1.2.2.2.
Existing Constraints
If Applicable, describe any known constraint(s) in the Study Area. Explain how the constraint(s) are
managed. Discuss any Operating Policies and Procedures (OPPs) and Information Documents
(IDs)/Authoritative Documents (ADs) presently applied in the area. Outline relevant existing manual or
automatic Remedial Action Schemes (RASs) in the Study Area. Below is an example of the write up:
[The existing constraints in [AESO Region where the Project is located, e.g., the Northwest
Region] are managed in accordance with Section 302.1 of the ISO Rules, Real Time
Transmission Constraint Management (TCM).]
1.2.2.3.
AESO Long-Term Transmission Plans (LTP)
Describe the relevant AESO long-term transmission development plans for the Study Area and its vicinity
(either approved NID System Projects or developments identified in the AESO’s most recently published
Long Term Plan). List the anticipated in-service dates of those plans. Use a table. Discuss the known
impact(s) of any delays in the AESO Long-term Transmission Plans (LTP) for the area on the project.
Please specify if the AESO LTP topologies are included in the study scenarios here.
Table 1.2-1: Summary of System Projects
Project
Area
Project Name
1.2.3.
In-Service Date
Studies Performed
Provide a high-level summary of the system conditions (20XX WP for example) and the studies
performed, such as analysis of the existing system before the connection and analysis of the system
performance after the connection. Include the contingency categories applicable to the project. Below is
an example. Please delete the bullets that are not relevant to the project:
The following studies will be performed in the connection study:
•
Load flow analysis (Category A, Category B, and selected Category C5), pre-Project and
post-Project conditions
•
Voltage stability analysis (Category A, Category B, and selected Category C5), post-Project
conditions
•
Transient stability analysis (Category B, and selected Category C5), post-Project conditions
•
Motor starting analysis, post-Project conditions
•
Short-Circuit fault studies, pre-Project and post-Project conditions
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•
In cases where transmission congestion is identified through the connection studies
conducted, the AESO will provide further direction on additional studies to identify mitigation
measures for congestion management under system normal (N-0) and abnormal conditions
(N-1).
1.2.4.
Studies Excluded
Provide a high-level summary of the studies excluded. See below for an example:
[The following studies will not be performed in the connection study:
•
Load flow analysis (Category C)
•
Voltage stability analysis (Category C)
•
Transient stability analysis (Category C)]
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2.
Connection Alternatives Selected for Studies
Describe each connection alternative separately. Only include alternatives that will be studied and
evaluated as part of the NID filing. These alternative numbers should be consisted with the Connection
Assessment Recommendation and Connection Assessment Results reports. For each alternative, include
a connection diagram that shows the main transmission network in the Study Area post-connection.
Provide single-line diagrams (SLDs) for the proposed facilities. Below is an example of such a write up:
[Four alternatives were identified for this Project, two of which were selected for further study.
The details of this connection alternative selection are addressed in the Connection Assessment
Recommendations Report. The following two alternatives will be studied:
Alternative 3: Add a new point of delivery (POD) substation, and connect the new POD
to the existing 144 kV transmission line [Line name] via an in/out connection
configuration.
Alternative 4: Add a new point of delivery (POD) substation, and connect the new POD
to the existing 144 kV transmission line [Line name] via a T-tap connection
configuration.
]
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3.
Criteria, System Data, and Study Assumptions
3.1.
3.1.1.
Criteria, Standards, and Requirements
Transmission Planning Standards and Reliability Criteria
The Transmission Planning (TPL) Standards, which are included in the Alberta Reliability
Standards, and the AESO’s Transmission Planning Criteria – Basis and Assumptions (Reliability
Criteria)2 will be applied to evaluate system performance under Category A system conditions
(i.e., all elements in-service) and following Category B and Category C5 contingencies (i.e.,
single element outage), prior to and following the studied alternatives. Below is a summary of
Category A, Category B and Category C5 system conditions.
Category A, often referred to as the N-0 condition, represents a normal system with no
contingencies and all facilities in service. Under this condition, the system must be able to
supply all firm load and firm transfers to other areas. All equipment must operate within its
applicable rating, voltages must be within their applicable range, and the system must be stable
with no cascading outages.
Category B events, often referred to as an N-1 or N-G-1 with the most critical generator out of
service, result in the loss of any single specified system element under specified fault conditions
with normal clearing. These elements are a generator, a transmission circuit, a transformer, or a
single pole of a DC transmission line. The acceptable impact on the system is the same as
Category A. Planned or controlled interruptions of electric supply to radial customers or some
local network customers, connected to or supplied by the faulted element or by the affected
area, may occur in certain areas without impacting the overall reliability of the interconnected
transmission systems. To prepare for the next contingency, system adjustments are permitted,
including curtailments of contracted firm (non-recallable reserved) transmission service electric
power transfers.
Category C5 events [NOTE: Category C wording may need to be adjusted on a project-by-project
basis] results in loss of two circuits of a multiple circuit tower. All equipment must operate within
its applicable rating, voltages must be within their applicable range, and the system must be
stable with no cascading outages. For Category C5, the controlled interruption of electric supply
to customers (load shedding), the planned removal from service of certain generators, and/or
the curtailment of contracted firm (non-recallable reserved) transmission service electric power
transfers may be necessary to maintain the overall reliability of the interconnected transmission
systems.
The Alberta Reliability Standards include the Transmission Planning (TPL) standards that
specify the desired system performance under different contingency categories with respect to
the Applicable Ratings. The transmission system performance under various system conditions
2
Please refer to Attachment A
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is defined in Appendix 1 of the TPL standards. For the purpose of applying the TPL standards to
this study, the Applicable Ratings shall mean:

Seasonal continuous thermal rating of the line’s loading limits.

Highest specified loading limits for transformers.

For Category A conditions: Voltage range under normal operating condition should
follow the AESO Information Document ID# 2010-007RS. For the busses not listed in
ID#2010-007RS, Table 2-1 in the Reliability Criteria applies.

For Category B and Category C5 conditions: The extreme voltage range values per
Table 2-1 in the Reliability Criteria.

Desired post-contingency voltage change limits for three defined post event timeframes
as provided in Table 3.1-1.
Table 3.1-1: Post Contingency Voltage Deviation Guidelines
Time Period
Parameter and reference point
Post Transient
(up to 30 sec)
Post Auto Control
(30 sec to 5 min)
Post Manual
Control (Steady
State)
Voltage deviation from steady state at
POD low voltage bus.
±10%
±7%
±5%
3.1.2.
AESO Rules
The AESO Voltage Control Practice ID # 2010-007RS will be applied to establish precontingency voltage profiles in the Study Area. The Section 302.1 of the ISO Rules, Real Time
Transmission Constraint Management (TCM) will be followed in setting up the study scenarios
and assessment of the impact of the Project connection. In addition, due regard will be given to
the AESO’s Connection Study Requirements and the AESO’s Generation and Load
Interconnection Standard.
The Reliability Criteria is the basis for planning the AIES. The transmission system will normally
be designed to meet or exceed the Reliability Criteria under credible worst-case loading and
generation conditions.
3.1.3.
Other Requirements
Other AESO requirements to be applied when performing connection studies are outlined below:

if applicable
Describe in detail the application of any other AESO requirements, criteria, standards, rules, practices,
and guidelines (market or otherwise) when the connection studies will be carried out. Use subsection
headings that clearly identify the requirement being discussed or add another bullet.
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3.2.
Study Scenarios
Outline the scenarios (system conditions) studied and the study years. These scenarios should represent
a range of potential system conditions, assumed loading conditions, and assumed generation dispatches
sufficient to allow an analysis of the transmission system performance in the Study Area. The scenarios
may include the following:
•
Low and high loading levels
•
Low and high generation levels
•
Interchange conditions (for example, high, medium, or low export from Alberta to British Columbia or
high, medium, or low import from British Columbia to Alberta)
•
Transmission flow variations, such as South of Keephills/Ellerslie/Genesee (SOK), Fort McMurray
transfer in and out, HVDC power order and other relevant area transfers
[Table 3.2-1 provides a list of the study scenarios. Scenarios 1 and 2 are the pre-Project
scenarios for 2016 SP and WP. Scenarios 3 and 4 are the post-Project scenarios for 2016 SP
and WP with the requested DTS 20 MW addition at the Thornton 2091S. A power factor of 0.9
lagging will be used for the new Project load]
Table 3.2-1: List of the Connection Study Scenarios
Condition
Project
Load (MW)
Project
Generation
(MW)
2016 SP
Pre-project
0
0
2
2016 WP
Pre-Project
0
0
3
2016 SP
Post Project
20
0
4
2016 WP
Post-Project
20
0
Scenario
Year/Season
Load
1
3.3.
3.3.1.
System
Generation
Dispatch
Conditions
High Wind, High
Import
High Wind, High
Import
Load and Generation Assumptions
Load Assumptions
The Study Area and Region load forecasts used for this connection study is shown in Table
3.3-1 and is from [The AESO Forecast specified in the Study Scope, e.g., the AESO 2014 Longterm Outlook (2014 LTO)]. In this study the active power to reactive power ratio in the base case
scenarios will be maintained when modifying the planning area loads.
Table 3.3-1: Forecast Area Load (201X LTO at AIL Peak)
Forecast Peak Load (MW)
Area or Region Name and Season
Area 37 (Provost)
2018
SP
WP
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Forecast Peak Load (MW)
Area or Region Name and Season
2016
2018
SL
SP
WP
Central Region
SL
SP
South Region
WP
SL
SP
AIL w/o Losses
WP
SL
3.3.2.
Generation Assumptions
Describe the generation assumptions (including N-G) and the AESO forecast applied (e.g., 2014LTO).
Present existing and future units for consideration in the project studies (local generators) and the
dispatch level of each. Describe the notable features of the local generators, as required. Below is an
example of the write up:
[The generation conditions for this connection study are described in Table 3.3-2. The study
identified the HR Milner Generator at H.R. Milner 740S substation as the critical generator and it
is turned off to represent the N-G study condition in the Grand Cache area for all analysis
except for the short circuit analysis]
Table 3.3-2: Local Generation (MW) in the Study Cases
Existing/
Future
Unit
Name
Bus
Number
Area
Pmax
(MW)
Existing
Gen A
…
…
…
Gen B
#29
…
…
…
Gen C
…
…
…
Gen D
…
…
…
Gen E
…
…
…
Future
20xx
SL
Unit
Net
Generation3
(MW)
20xx
SP
Unit
Net
Generation
(MW)
20xx
WP
Unit
Net
Generation
(MW)
20yy
SL
Unit
Net
Generation
(MW)
20yy
SP
Unit
Net
Gener
-ation
(MW)
20yy
WP
Unit
Net
Generation
(MW)
Total
3
Unit Net Generation refers to Gross Generating unit MW output less Unit Service Load.
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3.3.3.
Intertie Flow Assumptions
Indicate the assumptions regarding the intertie flow between Alberta and neighbouring jurisdictions.
Below are examples of the write up:
[Intertie assumptions are included for the B.C., MATL, and Saskatchewan interties. Details on
the assumptions can be found in Table 3.3-3.]
or
[The intertie points are deemed to be too far away to have an effect on the assessment of the
proposed connection. The flows in the Study Area are not influenced by the AIES HVDC
facilities. As a result, the intertie and HVDC assumptions are kept consistent with that in the
AESO planning base cases and not adjusted for this study.]
Table 3.3-3: Intertie Assumptions – Example
Intertie
Case No.
Year / Condition
1
2016 SL
Import (+)
/Export (-) to
BC
Import (+) /Export
(-) to
Import (+) /Export
(-) to MATL
-800
-150
0
480
150
300
480
150
300
-800
-150
0
480
150
300
480
150
300
-800
-150
0
480
150
300
480
150
300
Saskatchewan
(Pre-Project)
2
2016 SP
(Pre- Project)
3
2016 WP
(Pre- Project)
4
2016 SL
(Post- Project)
5
2016 SP
(Post-Project)
6
2016 WP
(Post-Project)
7
2018 SL
(Post-Project)
8
2018 SP
(Post- Project)
9
2018 WP
(Post- Project)
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HVDC Power Order (if applicable)
3.3.4.
In general, the majority of connections to the AIES will not require adjustment to the planned load flow
order levels for the WATL and EATL HVDC links during studies. For major projects and where the scoped
study scenarios require adjustments to the pre-set HVDC flow level provided by the AESO in the Base
Cases, the AESO studies engineer will provide guidance as to the new flow settings and associated VAR
adjustments as required. In these cases, below are examples of wording:
[The power orders shown in Table 3.3-4 will be assumed in this Study. HVDC dispatch aligns
with the AESO’s planned HVDC operating procedures. Under some scenarios, EATL will be
dispatched to a higher power order in a South-to-North direction to reduce congestion on the
Central East 138/144 kV existing transmission system. The pre-Project and post-Project
dispatches will be the same for each alternative.]
or
[The HVDC power orders will be set based on the minimum loss per the assumptions in preand post-Project study scenarios.]
Table 3.3-4: HVDC Power Order by Scenario
3.4.
Case No
Scenario
WATL4 (MW)
EATL5 (MW)
1
2016 SL (Pre-Project)
475 N  S6
Blocked
2
2016 SP (Pre- Project)
250 S  N
450 S  N
3
2016 WP (Pre- Project)
475 N  S
Blocked
4
2018 WP (Post- Project)
250 S  N
800 S  N
System Projects
List the relevant transmission facilities that are not in service but will be included in the study cases. Use a
table. Briefly discuss any relevant information regarding system projects, such as developments proposed
for each project. Below is an example of the write up:
[Table 3.4-1 lists the system reinforcement subprojects that are part of the CETD and that have
been included in this study.]
4
Western Alberta Transmission Line (the west HVDC line)
5
Eastern Alberta Transmission Line (the east HVDC line)
6
N  S: HVDC flow direction is North to South
S  N: HVDC flow direction is South to North
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Table 3.4-1: Summary of System Projects Included in the Study Cases
Project
Subproject
1
P850
South and
West
Edmonton
Reinforce
ment
Subproject Name
In-Service Date
Harry Smith Sub
New Saunders Lake 240/138kV Substation; re-terminate 910L,
914L, 780L & 858L at Saunders Lake; build lines between
Nisku & proposed Saunders Lake; and reconfiguration of
affected substations.
New 138kV Lines from 780L to Cooking Lake & 174L; and
reconfiguration of affected substations
2
3
4
133L from Wabamun to 234L tap
5
New Capacitor Bank at Leduc 325S
September 2017
Customer Connection Projects
3.5.
List the relevant customer connection facilities that are not in the existing system but will be included in
the study cases. Use a table. Include relevant information such as size of the load and/or generation for
each project. Below is an example of the write up:
[The list of the customer projects included in the study is shown in Table 3.5-1.]
Table 3.5-1: Summary of Customer Connection Assumptions
Planning
Area
Queue
Position*
Planned
In-Service
Date
Project Name
Project
#
Gen
(MW)
Load
(MW)
Included/Excluded
from Studies
53
54
Jul.
2017
RESL McLaughlin WAGF
1500
47.0
1.0
Included
54
19
Apr.
2016
Lethbridge Chinook NW POD
1260
0
30.0
Included
55
Energize
d
Oct.
2014
Fortis Spring Coulee Upgrade
1338
0
2.0
Included
55
57
Feb.
2017
BowArk Energy Drywood Power
Gas Plant
1522
18.6
1.0
Excluded
* Per the AESO Connection Queue posted in December 2015.
Provide any other relevant information for each project, such as whether it has already been approved by
the Alberta Utilities Commission (AUC).
3.6.
Facility Ratings and Shunt Elements
Include tables that show the facility ratings for key existing and proposed equipment rated XX kV and
above and any other relevant equipment ratings. Show only the most important equipment. Below is an
example of the write up:
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[The Transmission Facility Owner (TFO) provided the ratings of the existing transmission lines
(Error! Not a valid bookmark self-reference.) and the existing transformers (Error!
Reference source not found.) in the Study Area.]
Table 3.6-1: Summary of Transmission Line Ratings in the Study Area (MVA on 138 kV Bases)
Line ID
Line Description
Nominal Rating
(MVA)
Short-term7 Rating
(MVA)
Voltage
Class
(kV)
Summer
Winter
Summer
Winter
7L84
Flyingshot 749S – Crystal 722S
138
142.8
142.8
180
181
7L03
Flyingshot 749S – Elmworth 731S
138
109.3
139
123.6
150.5
7L68
Clairmont Lake 811S – Rycroft 730S
138
94.9 CT8
94.9 CT
94.9 CT
94.9 CT
Table 3.6-2: Summary of Transformer Ratings in the Study Area
Substation Name and Number
Transformer ID
Transformer
Voltages (kV)
MVA Rating
Battle River 757S
912T
240/144
224
Battle River 757S
701T
144/72
75
Nevis 766S
901T
240/144
100
H-M: 33.3
Nevis 766S
701T
144/72/25
X-M: 33.3
Y-M: 16.6
List the shunt elements in the Study area, including shunt element size and status. Use a table. Present
all assumptions made regarding the shunt elements, such as whether they will be switched on or off in the
studies. Below is an example of the write up:
[The details of shunt elements in the Study Area are given in Table 3.6-3.]
7
When line loading in post Category B contingency is observed to exceed nominal rating and is less than
the Short-term (emergency) rating, it is assumed that AESO and TFO operating practices can manage
the constraint within the time requirements of TFO Short-term (emergency) rating.
8
The limitation factor for the line rating is due to a current transformer.
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Table 3.6-3: Summary of Shunt Elements in the Study Area
Capacitors
Substation
Name and
Number
Voltage
Class
(kV)
Number of
Switched
Shunt
Blocks
Status in
Study
(on or off)
Total at
Nominal
Voltage
(MVAr)
138
2017
WP
(MVAr)
(MVAr)
71.9
27
(on)
27
(on)
-
27.17
(off)
(off)
45
45
(both
on)
45
(both
on)
1 x 44.9 MVAr
Tucuman 478S
138
Hill 751S
138
1 x 27.17 MVAr
Number of
Switched
Shunt Blocks
2017S
P
1 x 27 MVAr
Hardisty 377S
Reactors
1 x 20 MVAr
1 x 25 MVAr
Total at
Nominal
Voltage
(MVAr)
Status in
Study
(on or off)
2017
SP
2017
WP
(MVAr)
(MVAr)
-
-
-
-
-
-
-
-
-
-
-
Protection Fault Clearing Times
3.7.
List the fault clearing times used for the transient stability analysis. Use a table. When providing near-end
and far-end fault clearing times, include different directions with the clearing times only when the clearing
times are not the same for faults at each end. Indicate if the fault clearing time assumptions have been
verified by the Transmission Facility Owner (TFO). Below is an example of the write up:
[Fault clearing times for existing facilities are provided by TFO and are listed in Table 3.7-1.]
Table 3.7-1: Summary of Protection Fault Clearing Times
Terminal Location
Line
Nominal
Bus
Voltage
(kV)
9Lxx
240
3.8.
Terminal
1
SUB 1S
Terminal
2
SUB 2S
Total Clearing Time
Terminal
3
SUB 3S
Faulted
Location
State if it is
calculated
(specific)
or
estimated
(generic)
Faulted
Location
Terminal
1
Terminal
2
Terminal
3
SUB 1S
6
7
8
calculated
SUB 2S
6
7
8
calculated
SUB 3S
6
7
9
calculated
Voltage Profile Assumption
Please keep the following description unless any change is required.
The AESO Voltage Control Practice ID # 2010-007RS is used to establish normal system (i.e.,
pre-contingency) voltage profiles for key area busses prior to commencing any studies. Table 2-
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1 of the Reliability Criteria applies for all the busses not included in the ID 2010-007RS. These
voltages will be utilized to set the voltage profile for the study base cases prior to load flow
analysis.
3.9.
Motor Starting Assumptions
The section is to evaluate the potential impacts of motor starting operation on the surrounding system.
The customer must provide details of study assumptions (including how frequent the motor starts and
then find the voltage dip percentage for different voltage levels), motor model, and software used to
perform the studies. Also the type of motor starting equipment and/or starting methodology that would be
implemented must be specified.
Motor starting analysis is no longer required and removes the subsection – The example below assumes
that VFD will be installed with across the line staring capability as backup. If the Market Participant
confirms that the motors in the Project will not start motors across the line, Motor starting analysis is no
longer required.
Below is an example of the write up for motor starting assumption portion:
[The following assumptions were used in conducting motor starting analysis:
4.

The transient voltage dip at the 138 kV transmission bus should not exceed 5% when
starting a single motor.

The motors will not start simultaneously. Only one motor will be allowed to start in VFD
bypass mode while the other motors are running at full load.]
Study Methodology
4.1.
Connection Studies Carried Out
The studies to be carried out for this connection study are identified in
Table 4.1-1:
Please delete the rows that are not applicable to the Project.
Table 4.1-1: Summary of Studies Performed
Scenario and Condition
9
Project 1234
System Conditions
Load
Flow9
Voltage
Stability9
Transient
Stability9
Motor
Starting9
The critical generator identified for this study will be [Name N-G unit, e.g., the H.R. Milner unit].
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Load
(MW)
Generation
(MW)
10
1
2016 SP Pre-project
0
0
Category A and Category B
X
2
2016 WP Pre-Project
0
0
Category A and Category B
X
3
2016 SP Post-Project
20
0
Category A and Category B
X
4
2016 WP Post-Project
20
0
Category A and Category B
X
4.2.
X
X
X
X
Load Flow Analysis
Each project has different load flow analysis methodology based on Study Area characteristics and study
assumptions. Please describe the methodology used in the load flow analysis in this section.
If any abnormal thermal loadings (above 100% thermal loading) are observed, perform Category B load
flow analysis on the identified contingencies by stepping Transformer tap adjustment. The identified
abnormal thermal loadings are still observed, it should be addressed in the load flow results.
Below is an example of the write up:
[Load flow analysis will be completed for all study scenarios to identify any thermal or
transmission voltage violations as per the Reliability Criteria. Transformers taps and switched
shunt reactive compensation devices such as shunt capacitors and reactors will be locked and
continuous shunt devices will be enabled when performing Category B load flow analysis.
POD low voltage bus deviations will also be assessed by first locking all tap changers and area
capacitors to identify any post-transient voltage deviations above 10%. Tap changers will then
be allowed to adjust, while shunt reactive compensating devices remained locked; to determine
if any voltage deviations above 7% would occur in the area. Once all taps and shunt reactive
compensating devices have been adjusted, voltage deviations above 5% will be reported, for
both the pre-Project and post-Project networks.]
4.2.1.
Contingencies Studied
Load flow analysis will be performed for the Category A condition and all Category B
contingencies in [the Study Area, e.g., the Grande Cache (Area 22) and Grande Prairie (Area
20) planning areas], including ties to surrounding areas for all pre- and post-Project scenarios.
4.3.
Voltage Stability (PV) Analysis
If this analysis is not required, please remove the subsection.
The objective of the Power-Voltage (PV) curve is to determine the ability of the network to
maintain voltage stability at all the busses in the system under normal and abnormal system
conditions. The PV curve is a representation of voltage change as a result of increased power
10
Only Category A with all generators in the study area on.
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transfer between two systems. The reported incremental transfers will be to the collapse point.
As per the AESO requirements, no assessment based upon other criteria such as minimum
voltage will be made at the PV minimum transfer. Voltage stability analysis for post-connection
scenarios will be performed. For load connection projects, the load level modelled in postconnection scenarios are the same or higher than in pre-connection scenarios. Therefore,
voltage stability analysis for pre-connection scenarios will only be performed if post-Project
scenarios show voltage stability criteria violations.
Voltage stability (PV) analysis will be performed according to the Western Electricity
Coordinating Council (WECC) Voltage Stability Assessment Methodology. The voltage stability
criteria states, for load areas, post-transient voltage stability is required for the area modeled at
a minimum of 105% of the reference load level for system normal conditions (Category A) and
for single contingencies (Category B). For this standard, the reference load level is the
maximum established planned load.
Typically, voltage stability analysis is carried out assuming the worst case scenarios in terms of
loading. The voltage stability analysis was performed by increasing load in [Study Areas, e.g.,
the Grande Prairie and Grande Cache Areas (AESO planning areas 20 and 22, respectively)],
and increasing the corresponding generation in the following AESO Planning Areas:

[Source area, e.g., the Wabamun planning area (Area 40)]

[Source area]

[Source area]
As per the voltage stability criteria, post transient techniques (all tap changers, all discrete
capacitors locked, but SVCs will be allowed to adjust) will used in applying the criteria and this
information is reflected in all tables and graphs. Also for this analysis, no limits will be selected
for the generation sources, non-negative active power constant MVA loads will be enforced and
the existing power factor for the reference will be maintained.
4.3.1.
Contingencies Studied
Voltage stability analysis will be performed for the Category A condition and all Category B
contingencies in [Study Area, e.g., the Grande Cache (Area 22) and Grande Prairie (Area 20)
planning areas], including ties to surrounding areas for all pre- and post-Project scenarios.
4.4.
Transient Stability Analysis
If this analysis is not required, please remove the subsection.
Transient stability analysis will be performed following the post-Project scenarios using [Study
scenarios, e.g., the 2017 SL and 2017 SP scenarios].
Stability plots for [State Monitoring quantities , e.g., bus voltage, machine relative angle and
active and reactive power outputs…etc] for all available generation units in [Study Area, e.g.,
the Cold Lake (Area 28) planning area] are provided. [State reference generator, e.g., Genesee
#1] will be used as the system reference.
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4.4.1.
Contingencies Studied
Transient stability analysis wil be performed for the Category A condition and all Category B
contingencies in [Study Area, e.g., the Grande Cache (Area 22) and Grande Prairie (Area 20)
planning areas], including ties to surrounding areas for all pre- and post-Project scenarios.
4.5.
Short-Circuit Analysis
Short-circuit analysis will be performed for [Study scenarios, e.g., the 2016 WP pre Project
scenario and 2016 WP and 2025 WP post-Project scenarios] to determine the short-circuit
levels in the vicinity of the Project. The short-circuit analysis includes three phase and single line
to ground faults. Fault levels are provided in the form of currents in kilo amperes and per unit
positive and zero sequence impedances.
4.6.
Motor Starting Analysis [as required]
If this analysis is not required, please remove the subsesction.
This section is to describe the study methodology of motor starting analysis. Below is an example of the
write up:
[Motor starting analysis will be performed for the proposed motors under system normal
(Category A) conditions and worst case contingencies identified in the voltage stability and
power flow analyses. The analysis considered the starting of one motor, with its Variable
Frequency Driver (VFD) out of service, while the other motors will be running at full load.]
4.7.
Effectiveness Factor Analysis Studies [as required]
Effectiveness factor analysis studies are carried out to determine the generator/load
effectiveness factors and identify the most effective generator/load(s) to be curtailed in order to
mitigate the thermal violations observed following some Category B contingencies in the Study
Area.
4.8.
Sensitivity Studies [as required]
Describe the methodology used for any other studies carried out. Use a separate heading for each study.
The headings should match the headings used in section 3.2. Include the intent, the assumptions, and
any relevant discussions regarding the study methodology. Use a table.
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4.9.
Mitigation Measures
If study results indicate transmission constraints associated with or exacerbated by the project
addition, modification to existing procedures and/or Remedial Action Schemes (RAS) or addition
of new procedures and/or RAS may be required.
The Studies Consultant must identify those anticipated constraints in a timely manner to the
AESO as they arise. The AESO Studies Engineer will guide the Studies Consultant to;
-
List study results in the constraint table in Attachment N of the part of the ESR
Template.
-
If N-0 overloads are observed in the post connection system, develop generation or
load effectiveness factor tables based on identified thermal constraints for N-0
system.
-
Develop generation or load effectiveness factor11 tables based on identified thermal
constraints under Category B contingencies.
-
Identify the components of the AESO system development plan which will alleviate
the identified constraint.
Propose adjustments to the original preliminary connection alternatives to avoid
proposing permanent RAS for Category B contingencies.
Study and propose possible modifications to existing RAS to ensure coordination of
proposed protection additions with the existing schemes.
Study and propose new temporary RAS required to ensure system reliability until
such time the planned system reinforcements are in place.
Proper study scenarios with the planned system reinforcements will be studied to
reflect removal of the identified constraints and the temporary nature of the RAS.
-
The AESO Studies Engineer will closely work with the Consultant and guide the development
and/or modifications of the proposed RAS to ensure system reliability, security and compliance
with AESO system access business practices.
11
Effectiveness factor analysis is carried out to determine the generator/load effectiveness factors which are used to
estimate the ability of each generator/load to relieve transmission element constraints. A generator/load’s
effectiveness factor is defined as the change in power flow over a specific line following a change in the generator’s
output power/ the load. As such, the larger the generator/load effectiveness factor the more helpful it can be in
alleviating a thermal violation on the transmission line associated to it.
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Attachment A
Transmission Planning Criteria- Basis and Assumptions
(Reliability Criteria)
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1. Introduction
This document presents the reliability standards, criteria, and assumptions to be used as the
basis for planning the Alberta Transmission System. The criteria, standards and assumptions
identified in this document supersede those previously established.
2. Transmission Reliability Standards and Criteria12
The AESO applies the following Alberta Reliability Standards to ensure that the transmission system is
planned to meet applicable performance requirements under a defined set of system conditions and
contingencies. A brief description of each of these standards is given below:
1. TPL-001-AB-0: System Performance Under Normal Conditions
Category A represents a normal system condition with all elements in service (N-0). All
equipment must be within its applicable rating, voltages must be within their applicable ratings
and the system must be stable with no cascading outages. Under Category A, electric supply to
load cannot be interrupted and generating units cannot be removed from service.
2. TPL-002-AB-0: System Performance Following Loss of a Single BES Element
Category B events result in the loss of any single element (N-1) under specified fault conditions
with normal clearing. The specified elements are a generating unit, a transmission circuit, a
transformer or a single pole of a direct current transmission line. The acceptable impact on the
system is the same as Category A with the exception that radial customers or some local network
customers, including loads or generating units, are allowed to be disconnected from the system if
they are connected through the faulted element. The loss of opportunity load or opportunity
interchanges is allowed. No cascading can occur.
3. TPL-003-AB-0: System Performance Following Loss of Two or More BES Elements
Category C events result in the loss of two or more bulk electric system elements (sequential, N1-1 or concurrent, N-2) under specified fault conditions and include both normal and delayed fault
clearing. All of the system limits for Category A and B events apply with the exception that
planned and controlled loss of firm load, firm transfers and/or generation is acceptable provided
there is no cascading.
4. TPL-004-AB-0: System Performance Following Extreme BES Events
Category D represents a wide variety of extreme, rare and unpredictable events, which may
result in the loss of load and generation in widespread areas. The system may not be able to
reach a new stable steady state, which means a blackout is a possible outcome. The AESO
needs to evaluate these events, at its discretion, for risks and consequences prior to creating
mitigation plans.
5. FAC-014-AB-2: Establishing and Communicating System Operating Limits
The AESO is required to establish system operating limits where a contingency is not mitigated
through construction of transmission facilities.
2.1 Thermal Loading Criteria
12
A complete description of these standards are given in: AESO. Alberta Reliability Standards. Available
from http://www.aeso.ca/rulesprocedures/17004.html
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The AESO Thermal Loading Criteria require that the continuous thermal rating of any transmission
element is not exceeded under normal and post-contingency operating conditions. Thermal limits are
assumed to be 100% of the respective normal summer and winter ratings. Emergency limits are not
considered in the planning evaluations.
2.2 Voltage Range and Voltage Stability Criteria
The normal minimum and maximum voltage limits as specified in the following table are used to identify
Category A system voltage violations, while the extreme minimum and maximum limits are used to
identify Category B and C system violations. Table 2-1 presents the acceptable steady state and
contingency state voltage ranges for the AIES. Table 2-2 provides voltage stability criteria used to test the
system performance.
Table 2-1: Acceptable Range of Steady State Voltage (kV)
Nominal
Voltage
Extreme
Minimum
Normal
Minimum
Normal
Maximum
Extreme
Maximum
500
475
500
525
550
240
216
234
252
264
260 (Northeast
& Northwest)*
234
247
266
275
144
130
137
151
155
138
124
135
145
150
72
65
68.5
75.5
79
69
62
65.5
72.5
76
Table 2-2: Voltage Stability Criteria
Performance
Level
A
B
MW
Margin
(P-V
method)
(5)(6)(7)
MVAr Margin
(V-Q method)
(6)(7)
Any element such as:
One Generator
One Circuit
One Transformer
One Reactive Power Source
One DC Monopole
> 5%
Worst Case
Scenario(8)
Bus Section
> 5%
50% of Margin
Requirement in
Level A
Disturbance (1)(2)(3)(4)
Initiated by:
Fault or No fault
DC Disturbance
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Performance
Level
MW
Margin
(P-V
method)
(5)(6)(7)
Disturbance (1)(2)(3)(4)
Initiated by:
Fault or No fault
DC Disturbance
Any
combination
elements such as:
of
MVAr Margin
(V-Q method)
(6)(7)
two
A Line and a Generator
A Line and a Reactive Power
Source
C
50%
Margin
> 2.5%
Two Generators
Two Circuits
of
Requirement
in Level A
Two Transformers
Two Reactive Power Sources
DC Bipole
D
Any combination of three or
more elements. i.e.:
Three or More Circuits on
ROW
>0
>0
Entire Substation
Entire
Plant
Switchyard
Including
2.3 Transient Stability Analysis Assumptions
Standard fault clearing times as shown in Table 2-3 are used for the new facilities or when the actual
clearing times are not available for the existing facilities. Double line-to-ground faults are applied for the
Category C5 events with normal clearing times. Single line-to-ground faults are applied for Category C6
to C9 events with delayed clearing times as depicted in Table 2-4 and Table 2-5.
Table 2-3: Fault Clearing Times
Nominal
Near End
Far End
kV
Cycles
Cycles
500
4
5
240
5
6
6
8
144/138
with
telecommunications
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144/138
6
without
telecommunications
30
Table 2-4: Stuck Breaker Clearing Times for Lines
Fault Clearing Time
Fault Clearing Time
(Cycles)
(Cycles)
(Cycles)
138/144 kV
240 kV
500 kV
2nd Ckt
Near
End
15
Fault Clearing Time
Far (for C5 Near
End and C7 End
Only)
24
24
Far
End
12
2nd Ckt
2nd Ckt
(for C5 Near Far
and C7 End End
Only)
(for C5
and C7
Only)
6
14
9
5
11
Table 2-5: Stuck Breaker Clearing Times for Transformers
Fault Clearing Time (Cycles)
Fault Clearing Time (Cycles)
240/138 kV
Fault on 240 kV Side
240
kV
138
kV
12
6
2nd Ckt
500/240 kV
Fault on 138 kV Side
138
kV
240
kV
15
5
2nd Ckt
Fault on 500 kV Side
500
kV
240
kV
9
5
2nd Ckt
Fault on 240 kV Side
240
kV
500
kV
12
4
2nd Ckt
(for
(for
(for
(for
Breaker
Breaker
Breaker
Breaker
Side Side
Side Side
Side Side
Side Side
Fail)
Fail)
Fail)
Fail)
14
24
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