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APPENDIX A CONNECTION ASSESSMENT

ATCO Electric

Connection Engineering StudyReport for AUC ApplicationATCO City of Grande Prairie New POD

File No. 7505

Revision: 7

Revision Date: 2016-06-23

Name Date Signature

Prepared by: Amanda Robertson, P. Eng. 3ne -i.aoh3

Reviewed by: Sharon Morganson, P. Eng.

APEGA Permit to Practice P0850

Connection Engineering Study Report for AUC Application: ATCO City of Grande Prairie New POD

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Executive Summary

Project Overview

ATCO Electric Ltd. (ATCO), in its capacity as the legal owner of distribution facilities (DFO), submitted a system access service request (SASR) to the Alberta Electric System Operator (AESO), to serve predicted residential and commercial load growth in the City of Grande Prairie.

The SASR includes a new Rate DTS, Demand Transmission Service, contract capacity of 15.5 MW and a request for transmission development in the City of Grande Prairie area (collectively, the Project). Specifically, the DFO requested a new POD substation with one 144/25 kV 30/40/50 MVA LTC transformer, in addition to provisions for a second transformer and associated equipment.

The requested in-service date (ISD) for the Project is December 1, 2018.

This report presents the results of the study that assesses the impact of the Project on the Alberta interconnected electric system (AIES).

Existing System

Geographically, the Project is located in the AESO planning area of Grande Prairie (Area 20) which is part of the AESO Northwest Planning Region. The Grande Prairie area (Area 20) is surrounded by the planning areas of Peace River (Area 19), Valleyview (Area 23), Fox Creek (Area 24), and Grand Cache (Area 22).

From a transmission system perspective, the Grande Prairie area (Area 20) is served by a 144 kV transmission system and local generation. The area is mainly supplied from the 240/144 kV Little Smoky 813S substation via three 144 kV transmission lines (7L32, 7L45, and 7L46). One 144 kV transmission line (7L20) also connects the Grande Prairie area (Area 20) to the AESO planning area of Grande Cache (Area 22) and another 144 kV transmission line (7L73) connects the Grande Prairie area (Area 20) to the AESO planning area of Peace River (Area 19).

Existing constraints in the Northwest Planning Region are managed in accordance with the procedures set out in Section 302.1 of the ISO rules, Real Time Transmission Constraint Management (TCM Rule).

Study Summary

Study Area for the Project

The Study Area for the Project consists of the Grande Prairie area (Area 20) and the tie lines connecting the Grande Prairie area (Area 20) to the rest of the AIES, which include the 144 kV transmission lines 7L20, 7L32, 7L45, 7L46, and 7L73. All transmission facilities within the Study Area were studied and were monitored to assess the impact of the Project on the AIES, including any violations to the Reliability Criteria (as defined in Section 2.1.1).


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Studies Performed for the Project

Power flow analysis were performed for the 2018 winter peak (2018 WP) and the 2019 summer peak (2019 SP) pre- and post-Project scenarios.

Voltage stability analysis was performed for the 2018 WP Post-Project scenario.

Results of the Pre-Project Studies

The following is a summary of the pre-Project study results.

Category A conditions

Under Category A conditions, no Reliability Criteria violations were observed for any of the pre-Project scenarios.

Category B conditions

No voltage range or voltage stability Reliability Criteria violations were observed under Category B contingency conditions. In addition, no POD bus voltage deviations were observed.

Four thermal criteria violations were identified on certain 144 kV transmission lines under two Category B conditions. These are shown in Table E-1 below.

Transmission Alternatives Selection

The AESO, in consultation with the legal owner of the transmission facilities (TFO) and DFO, determined that a new 144/25 kV LTC transformer with a minimum transformation capacity of 17.22 MVA and four feeders would be required in the City of Grande Prairie area to meet ATCO DFO’s request for system access service. Three transmission alternatives were identified:

Transmission Alternative 1 – Upgrades to the Crystal Lake 722S substation: Add a third 144/25 kV LTC transformer, four feeders, and associated equipment to the Crystal Lake 722S substation;

Transmission Alternative 2 – Upgrades to the Flyingshot Lake 749S substation: Add a third 144/25 kV LTC transformer with a minimum transformation capacity of 17.22 MVA, four feeders, and associated equipment to the Flyingshot Lake 749S substation; and

Transmission Alternative 3 – Addition of a new POD substation: Add a new POD substation, to be named the Hughes 2030S substation. The proposed Hughes 2030S substation would include a new 144/25 kV LTC transformer with a minimum transformation capacity of 17.22 MVA, four feeders, provisions for a second transformer, and associated equipment.

Transmission Alternative 3 was selected for further examination. According to both the TFO and DFO this alternative provides more operational flexibility than the other alternatives identified. Transmission Alternatives 1 and Transmission Alternative 2 would result in high capacity distribution feeder corridors resulting in an unacceptable reliability risk for ATCO DFO. In addition, ATCO TFO has advised that Transmission Alternative 1 and Transmission Alternative 2 present greater operational risk than Transmission Alternative 3. These transmission alternatives were not selected for further study.


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Connection Alternatives Selection

The AESO, in consultation with the TFO and DFO, examined six alternatives to connect the proposed Hughes 2030S substation (Transmission Alternative 3) to the AIES.

Connection Alternative 1 – In-and-out configuration on the 144 kV transmission line 7L22. Connect the proposed Hughes 2030S substation to the 144 kV transmission line 7L22 using an in-and-out configuration. This would require the addition of two 144 kV circuits, each approximately 15 km long, and three 144 kV circuit breakers at the proposed Hughes 2030S substation.

Connection Alternative 2 – In-and-out configuration on the 144 kV transmission line 7L39: Connect the proposed Hughes 2030S substation to the 144 kV transmission line 7L39 using an in-and-out configuration. This would require the addition of two 144 kV circuits, each approximately 9 km long, and three 144 kV circuit breakers at the proposed Hughes 2030S substation.

Connection Alternative 3 – T-tap configuration on the 144 kV transmission line 7L03: Connect the proposed Hughes 2030S substation to the 144 kV transmission line 7L03 using a T-tap configuration. This would require the addition of one 144 kV circuit, approximately 10 km long, and one 144 kV circuit breaker at the proposed Hughes 2030S substation.

Connection Alternative 4 – Radial configuration to the existing Mercer Hill 728S substation using one circuit: Connect the proposed Hughes 2030S substation radially with one circuit to the existing Mercer Hill 728S substation. This would require the addition of one 144 kV circuit, approximately 14 km long, a 144 kV circuit breaker at the Mercer Hill 728S substation, and a 144 kV circuit breaker at the proposed Hughes 2030S substation.

Connection Alternative 5 – In-and-out configuration on the 144 kV transmission line 7L03: Connect the proposed Hughes 2030S substation to the 144 kV transmission line 7L03 using an in-and-out configuration. This would require the addition of two 144 kV circuits, each approximately 12 km long, and three 144 kV circuit breakers at the proposed Hughes 2030S substation.

Connection Alternative 6 – Radial configuration to the existing Flyingshot Lake 749S substation using two circuits: Connect the proposed Hughes 2030S substation radially to the existing Flyingshot Lake 749S substation using two circuits. This would require the addition of two 144 kV circuits, each approximately 21 km long, two 144 kV circuit breakers at the Flyingshot Lake 749S substation, and three 144 kV circuit breakers at the proposed Hughes 2030S substation. The Flyingshot Lake 749S substation would need to be expanded to accommodate the additional breakers.

Connection Alternative 1 meets the DFO reliability criteria for substations that serve residential and commercial load. In addition, ATCO TFO also performed a high level routing assessment of Connection Alternative 1 and found no major routing concerns.

Connection Alternative 3 and Connection Alternative 4 have a tapped or a radial (with one circuit) connection configuration that do not satisfy the DFO’s distribution planning criteria; therefore, the DFO determined that these connection alternatives were not technically acceptable. Connection Alternative 3 and Connection Alternative 4 were not selected for further study.

Connection Alternative 2 and Connection Alternative 5 were rejected by the TFO due to routing constraints. Connection Alternatives 2 and 5 were not selected for further study.


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Connection Alternative 6 would involve increased transmission development and hence, additional cost compared to Connection Alternative 1. Connection Alternative 6 was not selected for further study.

Results of the Post-Project Studies

The following is a brief summary of the post-Project study results. The post-Project study results and applicable mitigation measures are shown in Table E-1 below.

Category A conditions

Under Category A conditions, no Reliability Criteria violations were observed for any of the post-Project scenarios.

Category B conditions

No voltage range or voltage stability Reliability Criteria violations were observed under Category B contingency conditions. In addition, no POD bus voltage deviations were observed.

Similar to pre-Project scenarios, four thermal criteria violations were identified on certain 144 kV transmission lines under two Category B conditions. These are shown in Table E-1 below.

Conclusions and Recommendation

Analysis Conclusions

Table E-1 provides analysis of, and conclusions about, the impact of the Project for Category B contingencies, including mitigations for observed Reliability Criteria violations. The Project has only a marginal impact on the performance of the AIES.

Table E-1: Overview of System Performance under Studied Scenarios and Mitigation Measures

Identified Reliability Violation Occur in Pre- and

Post-Project

Impact Level

System Condition

Mitigation Measure Violation

Type Violation Contingency

Thermal violations

above nominal

continuous rating

144 kV transmission line 7L32 segment (Clairmont

Lake 811S - South Bezanson 862S tap

point)

144 kV transmission line 7L45 (Big

Mountain 845S - Little Smoky

813S)

Yes Marginal 2019 SP Real-time

operational practices

144 kV transmission line 7L32 segment (South

Bezanson 862S tap point - Little Smoky 813S)




Bezanson 862S tap point - Clairmont Lake 811S)


Mountain 845S - Little Smoky

813S)




Bezanson 862S tap point - Little Smoky 813S)




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Recommendation

It is recommended to proceed with the Project using Transmission Alternative 3 and Connection Alternative 1, which includes adding the proposed Hughes 2030S substation, including a 144/25 kV transformer, with a minimum transformation capacity of 17.22 MVA, three 144 kV circuit breakers, four feeders, provisions for a second transformer, and associated equipment; and connecting the proposed Hughes substation to the 144 kV transmission line 7L22 using an in-and-out configuration.

A transformer size of 30/40/50 MVA would be recommended based on good electric industry practice and under advisement from the TFO regarding their asset management and inventory practices. It is also recommended that the two new 144 kV circuits (between the Hughes 2030S substation tap point and the Hughes 2030S substation) have a minimum rating equal to or greater than the existing 144 kV transmission line 7L22.


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Contents

Executive Summary ................................................................................................................................... 1 1. Introduction ......................................................................................................................................... 8

1.1. Project ........................................................................................................................................... 8 1.1.1. Project Overview .................................................................................................................... 8 1.1.2. Load Component ................................................................................................................... 8 1.1.3. Generation Component ......................................................................................................... 8

1.2. Study Scope .................................................................................................................................. 8 1.2.1. Study Objectives .................................................................................................................... 8 1.2.2. Study Area ............................................................................................................................. 9 1.2.3. Studies Performed ............................................................................................................... 11

1.3. Report Overview .......................................................................................................................... 11 2. Criteria, System Data, and Study Assumptions ............................................................................. 12

2.1. Criteria, Standards, and Requirements ....................................................................................... 12 2.1.1. Transmission Planning Standards and Criteria ................................................................... 12 2.1.2. AESO Rules ......................................................................................................................... 13

2.2. Load and Generation Assumptions ............................................................................................. 13 2.2.1. Load Assumptions ............................................................................................................... 13 2.2.2. Generation Assumptions ..................................................................................................... 14 2.2.3. Intertie Flow and HVDC Assumptions ............................................................................. 15

2.3. System Projects ........................................................................................................................... 16 2.4. Customer Connection Projects .................................................................................................... 16 2.5. Facility Ratings and Shunt Elements ........................................................................................... 16 2.6. Voltage Profile Assumptions ....................................................................................................... 19

3. Study Methodology ........................................................................................................................... 19 3.1. Study Scenarios .......................................................................................................................... 19 3.2. Connection Studies Carried Out .................................................................................................. 19 3.3. Power Flow Analysis ................................................................................................................... 20

3.3.1. Contingencies Studied ......................................................................................................... 20 3.4. Voltage Stability Analysis ............................................................................................................ 20

3.4.1. Contingencies Studied ......................................................................................................... 21 4. Pre-Project System Assessment ..................................................................................................... 21

4.1. Pre-Project Power Flow Analysis ................................................................................................ 21 4.1.1. Scenario 1: 2018 WP Pre-Project Scenario ........................................................................ 21 4.1.2. Scenario 2: 2019 SP Pre-Project Scenario ......................................................................... 21

5. Alternatives Identified ....................................................................................................................... 22 5.1. Overview ...................................................................................................................................... 22 5.2. Transmission Alternatives ........................................................................................................... 23

5.2.1. Transmission Alternatives Description ................................................................................ 23 5.2.2. Transmission Alternative Selected ...................................................................................... 23

5.3. Connection Alternatives .............................................................................................................. 24 5.3.1. Connection Alternatives Description .................................................................................... 24 5.3.2. Connection Alternatives Selected for Further Studies ......................................................... 29 5.3.3. Connection Alternatives Not Selected for Further Studies .................................................. 29

5.4. Alternative Selected for Further Study ........................................................................................ 30


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6. Post-Project Technical Analysis ...................................................................................................... 30 6.1. Power Flow Analysis ................................................................................................................... 30

6.1.1. Scenario 3: 2018 WP Post-Project Scenario ....................................................................... 31 6.1.2. Scenario 4: 2019 SP Post-Project Scenario ........................................................................ 31

6.2. Voltage Stability Analysis ............................................................................................................ 32 6.2.1. Scenario 3: 2018 WP Post-Project Scenario ....................................................................... 32

7. Project Dependencies ....................................................................................................................... 32 8. Conclusion and Recommendations ................................................................................................ 32

Attachments

Attachment A Pre-Project Power Flow Plots (2018 WP and 2019 SP)

Attachment B Alternative 1 Post-Project Power Flow Plots (2018 WP and 2019 SP) and Voltage Stability Curves

Figures

Figure 1.2-1 Study Area Transmission System Single Line Diagram ........................................................................... 10 Figure 5.3-1: Connection Alternative 1 Single Line Diagram ........................................................................................ 24 Figure 5.3-2: Connection Alternative 2 Single Line Diagram ........................................................................................ 25 Figure 5.3-3: Connection Alternative 3 Single Line Diagram ........................................................................................ 26 Figure 5.3-4: Connection Alternative 4 Single Line Diagram ........................................................................................ 27 Figure 5.3-5: Connection Alternative 5 Single Line Diagram ........................................................................................ 28 Figure 5.3-6: Connection Alternative 6 Single Line Diagram ........................................................................................ 29

Tables

Table 1.2-1: 2015 Long-term Transmission Plan’s Grande Prairie Area Near-Term Components .............................. 11 Table 2.1-1: Post-Contingency Voltage Deviations Guidelines for Low Voltage Busses .............................................. 13 Table 2.2-1: Forecast Peak Load (2014 LTO at Alberta Internal Load (AIL) Peak) ...................................................... 14 Table 2.2-2: Dispatch Levels of Existing Generators in the Vicinity of the Study Area ................................................. 14 Table 2.2-3: Intertie Assumptions ................................................................................................................................. 15 Table 2.2-4: 500 kV HVDC Power Order by Scenario .................................................................................................. 15 Table 2.5-1: Key Transmission Line Ratings in the Study Area (Based on 240 kV and 144 kV Nominal Voltages (MVA)) .......................................................................................................................................................................... 17 Table 2.5-2: Summary of Transformer Ratings in the Study Area ................................................................................ 18 Table 2.5-3: Key Shunt Elements by Substation (Based on 25 and 138 kV) ............................................................... 18 Table 3.1-1: List of Study Scenarios ............................................................................................................................ 19 Table 3.2-1: Summary of Studies Performed ............................................................................................................... 20 Table 4.1-1: Thermal Flows Above the Continuous Rating for 2019 SP Pre-Project Under Category B ..................... 22 Table 6.1-1: Thermal Flows Above the Continuous Rating for 2019 SP Pre- and Post-Project Scenarios Under Category B ................................................................................................................................................................... 31 Table 6.2-1: Post-Project Voltage Stability Analysis Results (Minimum Transfer = 20.3 MW) ..................................... 32


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1. Introduction

This report details the system performance studies conducted to assess the impact of the Project (as defined below) on the Alberta interconnected electric system (AIES).

1.1. Project

1.1.1. Project Overview

ATCO Electric Ltd. (ATCO), in its capacity as the legal owner of distribution facilities (DFO), submitted a system access service request (SASR) to the Alberta Electric System Operator (AESO), to serve predicted residential and commercial load growth in the City of Grande Prairie.

The SASR includes a new Rate DTS, Demand Transmission Service, contract capacity of 15.5 MW and a request for transmission development in the City of Grande Prairie area (collectively, the Project). Specifically, the DFO requested a new POD substation with one 144/25 kV 30/40/50 MVA LTC transformer, in addition to provisions for a second transformer and associated equipment.

The scheduled in-service date for the Project is December 1, 2018.

1.1.2. Load Component

The Project includes a load component:

Rate DTS Requested: 15.5 MW

Load type: residential and commercial (including a new hospital)

Power factor (PF): 0.9 pf (lagging) has been assumed

1.1.3. Generation Component

There is no generation component associated with the Project.

1.2. Study Scope

1.2.1. Study Objectives

The objectives of the study are as follows:

• Assess the impact of the Project on the performance of the AIES.


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• Evaluate the technical performance of the selected Project alternatives.

• Assess any violations of the relevant criteria, standards or requirements of the AESO, both pre-Project and post-Project.

• Recommend the Project alternative and any mitigation measures to address system performance concerns, if any, to enable the reliable integration of the Project into the AIES.

1.2.2. Study Area

Geographically, the Project is located in the AESO planning area of Grande Prairie (Area 20) which is part of the AESO Northwest Planning Region. The Grande Prairie area (Area 20) is surrounded by the planning areas of Peace River (Area 19), Valleyview (Area 23), Fox Creek (Area 24), and Grand Cache (Area 22).

1.2.2.1. Study Area Description

The Study Area for the Project consists of the Grande Prairie area (Area 20) and the tie lines connecting the Grande Prairie area (Area 20) to the rest of the AIES, which include the 144 kV transmission lines 7L20, 7L32, 7L45, 7L46 and 7L73.

From a transmission system perspective, the Grande Prairie area (Area 20) is served by a 144 kV transmission system and local generation. The area is mainly supplied from the 240/144 kV Little Smoky 813S substation via three 144 kV transmission lines (7L32, 7L45 and 7L46). One 144 kV transmission line (7L20) also connects the Grande Prairie area (Area 20) to the AESO planning area of Grande Cache (Area 22) and another 144 kV transmission line (7L73) connects the Grande Prairie area (Area 20) to the AESO planning area of Peace River (Area 19).

Figure 1.2-1 shows the existing transmission system configuration in the Study Area.


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Figure 1.2-1 Study Area Transmission System Single Line Diagram

1.2.2.2. Existing Study Area Constraints

Existing constraints in the Northwest Planning Region are managed in accordance with the procedures set out in Section 302.1 of the ISO rules, Real Time Transmission Constraint Management (TCM Rule).

1.2.2.3. AESO Long-Term Plan

The AESO 2015 Long-term Transmission Plan (2015 LTP)1 anticipates system upgrades in the Northwest Planning Region in the near-term, medium-term, and long-term, none of which will be

1 The 2015 LTP document is available on the AESO website.


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in service prior to the Project ISD. Consequently the Project studies did not include any system upgrades, as shown in Section 2.3. Included for reference, are the near term components of the 2015 LTP for the Grande Prairie area (Area 20) in Table 1.2-1 below.2

Table 1.2-1: 2015 LTP Grande Prairie Area Near-Term Components

Time Frame Development

Near-term

Add new 240 kV line from Little Smoky substation to Big Mountain substation south of Grande Prairie

Expand Big Mountain substation to include 240 kV facilities

Add new 144 kV line from Big Mountain substation to Poplar Hill substation northwest of Grande Prairie

Add voltage support at Big Mountain substation

Add voltage support in Rycroft area

1.2.3. Studies Performed

The following studies were performed in the connection study:

• Power flow analysis for pre- and post-Project; and

• Voltage stability analysis for post-Project.

1.3. Report Overview

The Executive Summary provides a high-level summary of the report and its conclusions. Section 1 provides an introduction of the Project and describes the study scope. Section 2 describes the criteria, system data, and other study assumptions used to complete this assessment. Section 3 describes the study methodology. Section 4 discusses the Pre-Project assessment of the system. Section 5 presents the alternatives examined and studied. Section 6 provides a technical analysis of the alternative selected for further study. Section 7 presents any dependencies the Project may have on other AESO plans to expand or enhance the transmission system. Section 8 presents a conclusions and recommendations of this assessment.

2 The 2015 LTP identifies the transmission developments in the Grande Prairie-Grande Cache subregion on page 51-52.


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2. Criteria, System Data, and Study Assumptions

2.1. Criteria, Standards, and Requirements

2.1.1. Transmission Planning Standards and Criteria

The Transmission Planning (TPL) Standards, which are included in the Alberta Reliability Standards, and the AESO’s Transmission Planning Criteria – Basis and Assumptions3 (collectively, the Reliability Criteria) were applied to evaluate system performance under Category A system conditions (i.e., all elements in-service) and following Category B contingencies (i.e., single element outage), prior to and following the studied alternatives. Below is a summary of Category A and Category B 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.

The TPL standards, TPL-001-AB-0 and TPL-002-AB-0 have referenced Applicable Rating when specifying the required system performance under Category A and Category B events. For the purpose of applying the TPL standards to the studies documented in this report, Applicable Ratings are defined as follows:

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 per AESO Information Document ID# 2010-007RS, General Operating Practices – Voltage Control, which relates to Section 304.4 of the ISO rules, Maintaining Network Voltage. For the busses not listed in ID#2010-007RS, Table 2-1 in the Transmission Planning Criteria – Basis and Assumptions applies.

3 Filed under a separate cover


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For Category B conditions: The extreme voltage range values per in the Transmission Planning Criteria – Basis and Assumptions.

Desired post-contingency voltage change limits for three defined post event timeframes as provided in Table 2.1-1 below.

Table 2.1-1: Post-Contingency Voltage Deviations Guidelines for Low Voltage Busses

Parameter and Reference Point

Time Period

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 low voltage bus ±10% ±7% ±5%

2.1.2. AESO Rules

The AESO Voltage Control Practice ID# 2010-007RS will be applied to establish pre- contingency voltage profiles in the Study Area. The Section 302.1 of the ISO Rule, 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 Customer Connection Study Requirements Document and the Generation and Load Interconnection Standard.

The transmission system will normally be designed to meet or exceed the Reliability Criteria under credible worst-case loading and generation conditions.

2.2. Load and Generation Assumptions

The study area and region forecasts used for this connection study are based on the AESO 2014 Long-term Outlook (2014 LTO).The study area and region forecasts used for this connection study are based on the AESO 2014 Long-term Outlook (2014 LTO). As part of its planning responsibilities, the AESO updates its corporate forecasts routinely to ensure they reflect the latest economic projects, factors and timing. While the AESO has updated its regional forecasts since the connection studies were performed, the use of the current AESO forecast, the AESO 2016 Long-term Outlook, would not materially alter the connection study results or affect the conclusions and recommendations in this report.

2.2.1. Load Assumptions

Table 2.2-1 presents the load conditions and assumptions used in the connection studies. In this study the active power to reactive power ratio in the Base Cases was maintained when modifying the loads.


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Table 2.2-1: Forecast Peak Load (2014 LTO at Alberta Internal Load (AIL) Peak)

Planning Area/Region Study Case

Forecast Peak Load (MW)

Grande Prairie (Area 20) 2018 WP 405.3

2019 SP 375.2

Northwest Planning Region 2018 WP 1481.8

2019 SP 1367.7

AIL without Losses 2018 WP 13369.5

2019 SP 12459.0

2.2.2. Generation Assumptions

Table 2.2-2 provides the area generation assumptions used in this connection study. Lowe Lake generator (NPP1) is considered to be the critical generating unit for the purpose of the studies, and is assumed offline for the power flow and voltage stability analyses.

Table 2.2-2: Dispatch Levels of Existing Generators in the Vicinity of the Study Area

Existing/Future Plant Name Bus

Number

AESO Planning

Area

Unit Net Generation

(MW)

Dispatch Level in the

Study Scenarios

(MW)

2018 WP

2019 SP

Existing Bear Creek 19142_2 20 15 12 12

Existing Bear Creek 18142_1 20 79 OFF OFF

Existing Gold Creek 19145_1 20 5 5 4

Existing Grande Prairie EcoPower 17101_2 20 27 18 11

Existing HR Milner 1148_1 22 144 80 OFF

Existing Northstone Power

20134_5 20134_6 20134_7 20134_8

20134_10

20 12 OFF OFF

Existing Northern Prairie Power 17120_1 20 93 OFF OFF

Existing Poplar Hill 16118_1 20 48 15* 15*

Existing Weyhaeuser Power 1146_1A 20 48 41 34 * The Poplar Hill (bus 16118) generation dispatch was originally set at zero (off line). Further studies identified voltage stability criteria violations under the Category B contingency of both 7L45 and 7L46. Poplar Hill generation as Transmission Must Run unit (TMR) was dispatched to on line and 15 MW in order to provide voltage support and meet voltage stability criteria.


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2.2.3. Intertie Flow and HVDC Assumptions

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.

Intertie assumptions are included for the British Columbia-Alberta (BC-AB), Saskatchewan-Alberta (SK-AB), and Montana-Alberta (MATL) interties. Details on the assumptions can be found in Table 2.2-3. The intertie points were determined to be too far away to have any material impact on the connection assessment; therefore, these export and import assumptions are consistent with AESO’s base cases were used.

Table 2.2-3: Intertie Assumptions

Scenario

Intertie

Import (-) /Export (+) to

BC (MW)

Import (-) /Export (+) to

Saskatchewan (MW)

Import (-) /Export (+) to MATL (MW)

2018 WP

Pre-Project 2.3 0 0

2019 SP

Pre-Project 519.1 0 0

2018 WP

Post-Project -1.1 0 0

2019 SP

Post-Project 520.9 0 0

The Western Alberta Transmission HVDC Line (WATL) and the Eastern Alberta Transmission HVDC Line (EATL) assumptions were expected to have minimal impact for the connection studies. Therefore, HVDC assumptions are kept consistent with that in the AESO planning base cases and not adjusted for this study. The 500 kV high voltage DC (HVDC) power orders are shown below in Table 2.2-4.

Table 2.2-4: 500 kV HVDC Power Order by Scenario

Scenario

Western Alberta

Transmission Line 4 (MW)

Eastern Alberta

Transmission Line5 (MW)

2018 WP Pre- Project Blocked 340 (S N)

2019 SP Pre- Project Blocked 580 (S N)

4 Western Alberta Transmission Line (the west 500 kV HVDC line)

5 Eastern Alberta Transmission Line (the east 500 kV HVDC line)


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Scenario

Western Alberta

Transmission Line 4 (MW)

Eastern Alberta

Transmission Line5 (MW)

2018 WP Post- Project Blocked 340 (S N)

2019 SP Post- Project Blocked 580 (S N)

2.3. System Projects

No system projects were included in the study scenarios.

2.4. Customer Connection Projects

There are no customer projects in the Study Area that are ahead of the Project in the AESO Customer Connection Queue. As a result, no customer projects were included in the study scenarios.

2.5. Facility Ratings and Shunt Elements

Table 2.5-1 shows the ratings of the key existing transmission lines in the Study Area, which have been provided by the TFO.


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Table 2.5-1: Key Transmission Line Ratings in the Study Area (Based on 240 kV and 144 kV Nominal Voltages (MVA))

Line Line Description

Voltage (kV)

Nominal Rating (MVA) Emergency Rating (MVA)

Summer Winter Summer Winter

7L03 Elmworth 931S -

Flyingshot Lake 749S 144 114 145 129 149

7L07 Poplar Hill 790s - Goodfare 815S

144 114 146 129 149

7L10 Rycroft 730S - Ksituan

754S 144 49 49 49 49

7L13 Big Mountain 845S –

Proctor & Gamble 808S 144 74 74 74 74

7L20 HR Milner 740S - Big

Mountain 845S 144 150 150 150 150

7L22 Poplar Hill 790S -

Clairmont Lake 811S 144 114 146 129 149

7L32 Little Smoky 813S -

Clairmont Lake 811S 144 114 146 129 149

7L33 Flyingshot Lake 749S -

Big Mountain 845S 144 147 187 167 199

7L34 Goodfare 815S - Updike

886S 144 114 146 129 149

7L39 Clairmont Lake 811S -

Crystal Lake 722S 144 114 146 129 149

7L40 Little Smoky 813S -

Simonette 733S 144 114 146 129 157

7L44 Flyingshot Lake 749S -

Big Mountain 845S 144 147 187 167 199

7L45 Little Smoky 813S - Big

Mountain 845S 144 145 187 167 199

7L68 Rycroft 730S -

Clairmont Lake 811S 144 99 99 99 99

7L69 Goodfare 815S - Elmworth 731S

144 114 146 129 149

7L73 Friedenstal 800S -

Rycroft 730S 144 99 99 99 99

7L80 HR Milner 740S - Simonette 733S

144 114 145 129 157

7L84 Crystal Lake 722S -

Flyingshot Lake 749S 144 149 149 188 189

9L02/9L05 Little Smoky 813 - Louise Creek 809S

240 498 498 498 498

9L11 Wesley Creek 834S -

Little Smoky 813S 240 498 498 498 498

The TFO provided the ratings of the existing transformers (Table 2.5-2) in the Study Area.


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Table 2.5-2: Summary of Transformer Ratings in the Study Area

Substation Name and Number Transformer ID Transformer Voltages (kV)

MVA Rating

(MVA)

Little Smoky 813S 901T/902T 240/144/25 H-X 200 H-Y 66

Wesley Creek 834S 901T/902T 240/144/25 H-X 300 H-Y 66.7

Mercer Hill 728S 701T 144/25 41.6

Flyingshot Lake 749S 701T/702T 144/25 50

Poplar Hill 790S 701T 144/25 33.3

Poplar Hill 790S 702T 144/25 33

Goodfare 815S 701T 144/25 41.56

Elmworth 731S 701T 144/25 33

Table 2.5-3 provides a summary of the shunt elements modelled in the Study Area.

Table 2.5-3: Key Shunt Elements by Substation (Based on 25 and 138 kV)

Substation Name and Number

Voltage Class (kV)

Capacitors Reactors SVC

Number of

Switched Shunt Blocks (MVAr)

Total at Nominal Voltage (MVAr)

Status in Study (on or off)

Number of

Switched Shunt Blocks

Total at Nominal Voltage (MVAr)

Status in Study (on or off) Total at

Nominal Voltage (MVAr)

2017SP (MVAr)

2017WP (MVAr)

2017SP (MVAr)

2017WP

(MVAr)

Big Mountain 845S

138 1x27.55 27.55

Switched as required

- - - - -

Clairmont Lake 811S

138 1x22.98 22.98 - - - - -

Goodfare 815S

138 2x13.78 27.56 - - - - -

Ksituan River 754S

138 1x13.77 13.77 - - - - -

Proctor & Gamble 808S

138 1x6

1x11 17 - - - - -

Little Smoky 813S

138 3x30 90 - - - - -

34.5 - - - - - - - - +/-100

25 - - - - 2x20 40 Switched as

required

Poplar Hill 790S

138 1x22.67 22.67

Switched as required

- - - - -

25 2x1.2 2x2.4 1x5.4

12.6 - - - - -

Note: “-“ Means not applicable in the table above.


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2.6. Voltage Profile Assumptions

The AESO ID 2010-007RS was used to establish normal system (i.e., pre-contingency) voltage profiles for key area busses prior to commencing any studies. Table 2-1 of the Transmission Planning Criteria – Basis and Assumptions applies for all the busses not included in the ID# 2010-007RS. These voltages were utilized to set the voltage profile for the study base cases prior to power flow analysis.

3. Study Methodology

3.1. Study Scenarios

The requested ISD for the Project is December 1, 2018. Hence, the study was conducted for 2018 winter peak (WP) and 2019 summer peak (SP) scenarios.

The study scenarios used for this connection assessment are shown in Table 3.1-1.

Table 3.1-1: List of Study Scenarios

Scenario No.

Year/Season Pre-Project/ Post-Project Project Load (MW)

1 2018 WP Pre-Project 0

2 2019 SP Pre-Project 0

3 2018 WP Post-Project 15.5

4 2019 SP Post-Project 15.5

3.2. Connection Studies Carried Out

The following studies were performed for the pre-Project analysis:

Power flow analysis (Category A and Category B)

The following studies were performed for the post-Project analysis:

Power flow analysis (Category A and Category B)

Voltage stability analysis (Category A and Category B)

Table 3.2-1 summarizes the studies that were carried out for this connection assessment.


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Table 3.2-1: Summary of Studies Performed

Scenario(s) Studied

Studies Performed System Condition Included

1, 2, 3, 4 Power Flow Category A and B

3 Voltage Stability Category A and B

3.3. Power Flow Analysis

The power flow analyses performed in this connection assessment were completed using PTI PSS/E version 33.

Power flow analysis was conducted to identify thermal overloads or transmission voltage violations in the Study Area for the pre-Project and post-Project scenarios, as per the Reliability Criteria.

In addition, POD low voltage bus deviations were also assessed by first locking all tap changers and shunt reactive compensating devices in the Study Area to identify any post-transient voltage deviations above 10%. Tap changers were then allowed to adjust while shunt reactive compensating devices remained locked; to determine if any voltage deviations above 7% were found in the area. Once all taps and shunt reactive compensating devices have been adjusted, voltage deviations above 5% were reported for both the Pre-Project and Post-Project scenarios.

3.3.1. Contingencies Studied

Power flow analysis was performed for all Category B contingencies within the Study Area, including the tie lines connecting the Study Area to surrounding planning areas, for all pre- and post-Project scenarios.

3.4. Voltage Stability Analysis

The objective of the voltage stability analysis is to determine the ability of the network to maintain voltage stability at all of the busses in the system under normal and abnormal system conditions. The power-voltage (PV) curve is a representation of voltage change as a result of increased power 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 was performed according to the Western Electricity Coordinating Council (WECC) Voltage Stability Assessment Methodology. WECC 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)”. According to this standard, the reference load level is the maximum established planned load.


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The analyses performed in this connection assessment were completed using PTI PSS/E version 33.

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 the Grande Cache (Area 22) and by increasing the corresponding generation in the AESO planning areas of Wabamun (Area 40) and Sheerness (Area 43).

3.4.1. Contingencies Studied

Voltage stability analysis was performed for all Category B contingencies in the Study Area, including the tie lines connecting the Study Area to surrounding planning areas. Voltage stability analysis was performed for the 2018 WP post-Project scenario only (Scenario 3).

4. Pre-Project System Assessment

4.1. Pre-Project Power Flow Analysis

This section provides the results of the pre-Project power flow studies. The analysis of these results, including mitigations for observed Reliability Criteria violations, is provided in Section 8. The results of the power flow analysis are illustrated by the power flow plots in Attachments A.

4.1.1. Scenario 1: 2018 WP Pre-Project Scenario

Category A

No Reliability Criteria violations were observed under Category A conditions.

Category B

No Reliability Criteria violations or POD bus voltage deviations were observed under Category B conditions.

4.1.2. Scenario 2: 2019 SP Pre-Project Scenario

Category A


Category B

No voltage range violations or POD bus voltage deviations were observed under Category B conditions.

Thermal loading above nominal continuous ratings, though below the emergency rating, were observed and are shown in Table 4.1-1.


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Table 4.1-1: Thermal Flows Above the Continuous Rating for 2019 SP Pre-Project Under Category B

Contingency Limiting Branch

Line Rating

Continuous/ Emergency

(MVA)*

Pre-Contingency Post-Contingency %

Difference Power Flow

(MVA)*

% Loading

Power Flow

(MVA)*

% Loading

7L46 (Big Mountain 845S - Little Smoky

813S)

7L32 segment (Clairmont Lake

811S - South Bezanson 862S

tap point)

109.3 / 123.6

84.2 77.0 112.9 103.3 26.3

7L32 segment (South Bezanson 862S tap point -

Little Smoky 813S)

109.3 / 123.6

92.9 85.0 120.6 110.3 25.3


813S)

7L32 segment (Clairmont Lake

811S - South Bezanson 862S

tap point)

109.3 / 123.6

84.2 77.0 110.5 101.1 24.1

7L32 segment (South Bezanson 862S tap point -

Little Smoky 813S)

109.3 / 123.6

92.9 85.0 118.2 108.1 23.1

* Line ratings and power flow (MVA) is current expressed as MVA based on 138 kV (ie. S =√3 x 138 x Iactual)

5. Alternatives Identified

5.1. Overview

This report identified three primary transmission alternatives: upgrading the Crystal Lake 722S substation; upgrading the Flyingshot Lake 749S substation; and adding a new POD, to be named the Hughes 2030S substation.

For the new POD transmission alternative, six connection alternatives were identified.


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5.2. Transmission Alternatives

5.2.1. Transmission Alternatives Description

Below is a description of the developments associated with the transmission alternatives that were examined for the Project.6 All three transmission alternatives would require the addition of, at minimum, 17.22 MVA of transformation capacity and four feeders.

Transmission Alternative 1: Upgrade the existing Crystal Lake 722S substation

Transmission Alternative 1 involves upgrading the existing Crystal Lake 722S substation by adding a third 144/25 kV LTC transformer, four 25 kV feeders, and associated equipment. This would require an expansion of the substation.

Transmission Alternative 2: Upgrade the existing Flyingshot Lake 749S substation

Transmission Alternative 2 involves upgrading the existing Flyingshot Lake 749S substation by adding a third 144/25 kV LTC transformer, four 25 kV feeders, and associated equipment. This would require an expansion of the substation.

Transmission Alternative 3: New Hughes 2030S substation

Transmission Alternative 3 involves adding a new POD substation, to be named the Hughes 2030S substation. The Hughes 2030S substation would include: one 144/25 kV LTC transformer with a minimum transformation capacity of 17.22 MVA, four 25 kV feeders, provisions for a second transformer, and associated equipment. The site of the proposed Hughes 2030S substation would be located northwest of the City of Grande Prairie, close to the predicted load growth and the site of the new Grande Prairie Hospital.

5.2.2. Transmission Alternative Selected

Transmission Alternative 3 was selected for further studies because it meets the DFO reliability criteria for serving residential and commercial load. According to both the TFO and DFO this alternative provides more operational flexibility than the other alternatives identified.

Transmission Alternatives 1 and Transmission Alternative 2 were not selected for further study because ATCO DFO has advised that if either the Crystal Lake 722S substation or the Flyingshot Lake 749S substation were expanded, the new distribution feeders would be routed through existing distribution line corridors within the City of Grande Prairie. This would create high capacity corridors, which, according to ATCO DFO, would present an unacceptable level of risk to distribution system reliability. In addition, ATCO TFO has advised that Transmission Alternative 1 and Transmission Alternative 2 present greater operational risk than Transmission Alternative 3.

6 These alternatives reflect more up to date engineering design than the alternatives identified in the ATCO Distribution Deficiency Report, City of Grande Prairie New POD, which is filed under a separate cover.


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5.3. Connection Alternatives

5.3.1. Connection Alternatives Description

The AESO, in consultation with the TFO and DFO, examined six alternatives to connect Transmission Alternative 3, the proposed Hughes 2030S substation, to the AIES.

Connection Alternative 1: In-and-out configuration on the 144 kV transmission line 7L22

Connection Alternative 1 involves connecting the proposed Hughes 2030S substation to the 144 kV transmission line 7L22 (between the Clairmont Lake 811S substation and the Saddle Hills 865S substation tap point) using an in-and-out configuration, as is shown in Figure 5.3-1. This connection alternative would require the addition of two 144 kV circuits, each approximately 15 km long, and three 144 kV circuit breakers at the proposed Hughes 2030S substation.

Figure 5.3-1: Connection Alternative 1 Single Line Diagram

Disclaimer: This diagram contains a simplified version of the system configuration. Technical detail has been simplified for illustration purposes. This diagram does not indicate geographical locations of facilities.


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Connection Alternative 2 involves connecting the proposed Hughes 2030S substation to the 144 kV transmission line 7L39 (between the Crystal Lake 722S substation and the Mercer Hill 728S substation tap point) using an in-and-out configuration, as is shown in Figure 5.3-2. This connection alternative would require the addition of two 144 kV circuits, each approximately 9 km long, and three 144 kV circuit breakers at the proposed Hughes 2030S substation.




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Connection Alternative 3: T-tap configuration on the 144 kV transmission line 7L03

Connection Alternative 3 involves connecting the proposed Hughes 2030S substation to the 144 kV transmission line 7L03 (between the Flyingshot Lake 749S substation and the Wapiti 823S substation tap point) using a T-tap configuration, as is shown in Figure 5.3-3. This connection alternative would require the addition of one 144 kV circuit, approximately 10 km long, and a 144 kV circuit breaker at the proposed Hughes 2030S substation.




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Connection Alternative 4: Radial configuration to the Mercer Hill 728S substation using one circuit

Connection Alternative 4 involves connecting the proposed Hughes 2030S substation to the existing Mercer Hill 728S substation using a radial connection configuration with one circuit, as is shown in Figure 5.3-4. This connection alternative would require the addition of one 144 kV circuit, approximately 14 km long, a 144 kV circuit breaker at the proposed Hughes 2030S substation, and a 144 kV circuit breaker at the Mercer Hill 728S substation.




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Connection Alternative 5 involves connecting the proposed Hughes 2030S substation to the 144 kV transmission line 7L03 (between the Flyingshot Lake 749S substation and the Wapiti 823S substation tap point) using an in-and-out configuration, as is shown in Figure 5.3-5. This connection alternative would require the addition of two 144 kV circuits, each approximately 12 km long, and three 144 kV circuit breakers at the proposed Hughes 2030S substation.




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Connection Alternative 6: Radial configuration to the Flyingshot Lake 749S substation using two circuits

Connection Alternative 6 involves connecting the proposed Hughes 2030S substation to the existing Flyingshot Lake 749S substation through two new 144 kV circuits, as is shown in Figure 5.3-6. This connection alternative would require the addition of two 144 kV circuits, each approximately 21 km long, three 144 kV circuit breakers at the proposed Hughes 2030S substation and two 144 kV circuit breakers at the Flyingshot Lake 749S substation. The Flyingshot Lake 749S substation would need to be expanded to accommodate the additional 144 kV circuit breakers.



5.3.2. Connection Alternatives Selected for Further Studies

Connection Alternative 1 was selected for further study because it meets the ATCO Electric’s distribution planning criteria, which stipulates that the loss of any single transmission facility (N-1) should not cause the loss of supply to residential and commercial load.

ATCO TFO also performed a high level routing assessment of Connection Alternative 1 and found no major routing concerns. The routing assessment indicated that Connection Alternative 1 presents the greatest routing flexibility compared to the other Connection Alternatives examined.

5.3.3. Connection Alternatives Not Selected for Further Studies

Connection Alternative 3 and Connection Alternative 4 include a tapped and a radial (with one circuit) connection configuration, respectively. T-tap and radial (with one circuit) connection


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configurations do not meet the ATCO Electric distribution planning criteria described above. Therefore, Connection Alternatives 3 and 4 were not selected for further study.

Connection Alternative 2 and Connection Alternative 5 were rejected by the TFO due to routing constraints. The TFO has advised that Connection Alternative 2 would require routing through an existing residential and commercial development and through the Hamlet of Clairmont.

The TFO performed a high level assessment of Connection Alternative 5 and identified a number of constraints. Connection Alternative 5 would be in close proximity to the Grande Prairie airport and require crossing of the four-lane highway, Highway 43. There are environmentally sensitive areas between the 144 kV transmission line 7L03 and the proposed site of the Hughes 2030S substation; therefore, Connection Alternative 5 has limited routing options when compared to Connection Alternative 1.

Connection Alternative 2 and Connection Alternative 5 were not selected for further study.

Connection Alternative 6 would involve increased transmission development when compared to Connection Alternative 1 including longer transmission lines and expansion of the existing Flyingshot Lake 749S substation to allow for the addition of two 144 kV circuit breakers, which results in additional cost compared to Connection Alternative 1. As a result, Connection Alternative 6 was not selected for further study.

5.4. Alternative Selected for Further Study

After examination of the transmission and connection alternatives, the AESO, in consultation with the DFO and the TFO, selected Transmission Alternative 3 and Connection Alternative 1 for further study.

This alternative includes a new POD substation, to be named the Hughes 2030S substation with a 144/25 kV 30/40/50 MVA LTC transformer, three 144 kV circuit breakers, four 25 kV feeders, provisions for a second transformer, and associated equipment.

The proposed connection configuration for the Hughes 2030S substation would be an in-and-out configuration on the 144 kV transmission line 7L22 between the Clairmont Lake 811S substation and the Saddle Hill 865S substation tap point. The connection alternative requires the addition of two 144 kV circuits, each approximately 15 km long.

6. Post-Project Technical Analysis

This section includes the post-Project results of Transmission Alternative 3 and Connection Alternative 1 described in Section 5.

6.1. Power Flow Analysis

This section provides the results for the post-Project power flow studies. The analysis of these results, including mitigations for observed Reliability Criteria violations, is provided in Section 8. The 2018 WP post-Project power flow results are presented below and the related power flow plots are provided in Attachment B.


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6.1.1. Scenario 3: 2018 WP Post-Project Scenario

Category A


Category B

No Reliability Criteria violations or POD bus voltage deviations were observed under Category B conditions.

6.1.2. Scenario 4: 2019 SP Post-Project Scenario

Category A


Category B

No voltage criteria violations or POD bus voltage deviations were observed under Category B conditions.

Thermal loading above nominal continuous ratings, though below the emergency rating, were observed. Table 6.1-1 presents these Reliability Criteria violations and a comparison to the pre-Project results.

Table 6.1-1: Thermal Flows Above the Continuous Rating for 2019 SP Pre- and Post-Project Scenarios Under Category B

Contingency

Overloaded Line Pre- Project Post- Project % Loading

Difference (Post-

Project/ Pre-Project)

Limiting Branch

Line Rating

Continuous/ Emergency

(MVA)*

Power Flow

(MVA)*

% Loading

Power Flow

(MVA)*

% Loading


813S)

7L32 segment (South Bezanson 862S tap

point - Clairmont Lake 811S)

109.3 / 123.6

112.9 103.3 114.0 104.0 0.7

7L32 segment (South Bezanson 862S tap point - Little Smoky

813S)

109.3 / 123.6

120.6 110.3 121.0 110.7 0.4


813S)

7L32 segment (Clairmont Lake 811S - South Bezanson 862S

tap point)

109.3 / 123.6

110.5 101.1 111.4 102.0 0.9

7L32 segment (South Bezanson 862S tap point - Little Smoky

813S)

109.3 / 123.6

118.2 108.1 118.8 108.7 0.6

* Line ratings and power flow (MVA) is current expressed as MVA based on 138 kV (ie. S =√3 x 138 x Iactual)


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6.2. Voltage Stability Analysis

Voltage stability analysis was conducted for the 2018 WP post-Project scenario to investigate the system active power margins post-Project under Category A conditions and the worst five Category B contingency conditions. The results are provided in Attachment B.

6.2.1. Scenario 3: 2018 WP Post-Project Scenario

As shown in Table 2.2-1, the reference load level for the Grande Prairie (Area 20) is 405.3 MW. The minimum incremental load transfer for the Category B contingencies is 5.0% of the reference load, or 20.3 MW, to meet the voltage stability criteria (0.05 x 405.3 = 20.3 MW). Table 6.2-1 summarizes the voltage stability transfer margins results for Category A and for the five worst contingencies under Category B system conditions.

The voltage stability margin is met for all studied conditions.

Table 6.2-1: Post-Project Voltage Stability Analysis Results (Minimum Transfer = 20.3 MW)

Contingency Line Description Maximum

incremental transfer (MW)

Meets 105% Load

Criterion? Category A 96 Yes

7L197 Hughes 2030S – Clairmont

Lake 811S 30 Yes

7L20 Big Mountain 845S – H.R.

Milner 740S 51 Yes

7L03 Flyingshot Lake 749S –

Elmworth 731S 52 Yes

7L73 Rycroft 730S – Friedenstal

800S 57 Yes

7L32 Clairmont Lake 811S –

Little Smoky 813S 58 Yes

7. Project Dependencies

The Project is not dependent on any AESO plans to expand or enhance the transmission system including those outlined in the 2015 LTP.

8. Conclusion and Recommendations

The studies showed that the Project only marginally worsened the existing thermal violations. These violations can be mitigated using real time operational practices since they are below the lines’ emergency ratings.

The studies did not identify any voltage stability or voltage range criteria violations and did not identify any POD bus voltage deviations.


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Table 8-1 provides analysis of and conclusions about the impact of the Project, including mitigation for observed Reliability Criteria violations. The Project has only a marginal impact on the performance of the AIES.

Table 8-1: Project Impact and Mitigation Measures

Identified Reliability Violation Occur in Pre- and Post-

Project

Impact Level

System Condition

Mitigation Measure Violation

Type Violation Contingency

Thermal violations

above nominal

continuous rating

144 kV transmission line 7L32 segment

(Clairmont Lake 811S - South

Bezanson 862S tap point)


Mountain 845S - Little

Smoky 813S)




(South Bezanson 862S tap point -

Little Smoky 813S)




(South Bezanson 862S tap point - Clairmont Lake

811S)


Mountain 845S - Little

Smoky 813S)




(South Bezanson 862S tap point -

Little Smoky 813S)



It is recommended to proceed with the Project using Transmission Alternative 3 and Connection Alternative 1, which includes adding the proposed Hughes 2030S substation, including a 144/25 kV transformer, with a minimum transformation capacity of 17.22 MVA, three 144 kV circuit breakers, four 25 kV feeders, provisions for a second transformer, and associated equipment; and connecting the proposed Hughes 2030S substation to the 144 kV transmission line 7L22 using an in-and-out configuration.

A transformer size of 30/40/50 MVA would be recommended based on good electric industry practice and under advisement from the TFO regarding their asset management and inventory practices. It is also recommended that the two new 144 kV circuits (between the Hughes 2030S substation tap point and the Hughes 2030S substation) have a minimum rating equal to or greater than the existing 144 kV transmission line 7L22.

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ATTACHMENT A

Pre-Project Power Flow Plots (2018 WP and 2019 SP)

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A-1 Pre-Project System Power Flow Plots

The Pre-Project power flow diagrams for Category A and selected Category B contingencies are provided in this section. The following table presents a list of the power flow diagrams for the worst five contingencies.

Table A-1: List of Pre-Project Power Flow Plots

Scenario Power Flow Diagram Diagram

2018 WP

N-G, System Normal Condition A-1

N-1-G, Loss of 7L45 A-2





2019 SP

N-G, System Normal Condition A-7






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ATTACHMENT B

Alternative 1 Post-Project Power Flow Plots (2018 WP and 2019 SP) and Voltage Stability Curves

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B-1 Post-Project System Power Flow Plots Results for Alternative 1

The Post-Project power flow plot for Category A and selected Category B contingencies are provided in this section. The following table presents a list of the power flow plots.

Table B-1: List of Post-Project Alternative 1 Power Flow Plots

Scenario Power Flow Diagram Diagram

2018 WP

N-G, System Normal Condition B-1

N-1-G, Loss of 7L45 B-2





2019 SP

N-G, System Normal Condition B-7






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B-2 Post-Project System Voltage Stability Analysis Results for Alternative 1

Scenario 3: 2018 WP Post-Project (Alternative 1)

The following PV curves for the Category B contingencies 7L197, 7L20, 7L03, 7L73, and 7L46 in the Post-Project Alternative 1 for scenario 3 (2018 WP) are included below.

Figure B‐1: PV Curve for the Contingency of 7L197 from Hughes 2030S to Clairmont Lake 811S

80

90

100

110

120

130

140

150

0.000 5.000 10.000 15.000 20.000 25.000 30.000 35.000

144 kV Bus Voltage (kV

)

Incremental Transfer (MW)

Hughes Clairmont Lake Poplar Hill

Saddle Hills 5% Margin = 20.3 MW


Figure B‐2: PV Curve for the Contingency of 7L20 from Big Mountain 845S to H.R. Milner 740S

Figure B‐3: PV Curve for the Contingency of 7L03 from Flyingshot Lake 749S to Elmworth 731S

120

125

130

135

140

145

150

0.000 10.000 20.000 30.000 40.000 50.000 60.000


)




115

120

125

130

135

140

145

150

155

0.000 10.000 20.000 30.000 40.000 50.000 60.000


)





Figure B‐4: PV Curve for the Contingency of 7L73 from Rycroft 730S to Friedenstal 800S

Figure B‐5: PV Curve for the Contingency of 7L46 from Big Mountain 845S to Little Smoky 813S

125

130

135

140

145

150

0.000 10.000 20.000 30.000 40.000 50.000 60.000


)




120

125

130

135

140

145

150

0.000 10.000 20.000 30.000 40.000 50.000 60.000 70.000


)




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