Distribution System Efficiency Voltage Optimization

Robert H FletcherRobert H Fletcher 11

Distribution System Efficiency Voltage Optimization

Application to Rural FeedersCase Study

2010

Robert Fletcher, PhD, P.E.Utility Planning Solutions

(425) [email protected]

V3

Rural Feeders

Rural Distribution Substation

Rural Distribution Substation

22

Overhead Rural Feeder

Overhead Rural Feeder

Long Feeders (5 to 15 miles)Long single phase lateralsLow voltage (<114V) at end of feedersLarge neutral currents Large Ampere Phase unbalanceLow Customer Density (<1000 kW per sq mi)Line Regulators are typically applied Feeder wire sizes are small compared to urban

Rural Feeder ConsiderationsRural feeder service infrastructure costs per customer are high compared with urban feeders.

Rural feeder voltage drops are typically higher than urban feeders and typically require line regulators.

Line Regulators are used to establish both non-VO or VO voltage-control-zones. Energy savings are not determined for non-VO control zones.

Significant system reconfiguration, phase upgrade, load balance, capacitors and line regulators are typically needed for VO on rural feeders.

All minimum system thresholds must be applied for all rural feeder VO voltage-control-zones.

33

126

120

Volts

114

Allowed ANSI Service Voltage Range 126 – 114 V (120 V ± 5%)

Rural and Urban FeedersRural and Urban FeedersAverage Customer Service VoltageAverage Customer Service Voltage

With CVR ± 2.5%

Non CVR National Average

44

DSE and VO System Objectives Reduce End-Use energy Consumption (reduce average service voltage)

Increase Distribution System Efficiency (lower losses)

Improve Service Reliability and Voltage Quality (increase backup capability)

1. Gather Substation Area Data

– Substation Annual MWh delivered

– Feeder Peak KW and kVAr hourly load patterns

– Feeder connected kVA and locations

– Feeder phase ampere demands.

– Voltage Control settings for Substation, Line Regulators, and Capacitors

2. Establish System Modeling

– Feeder conductor characteristics (OH & UG) and locations

– Feeder connected kVA and locations

– Line phase configuration locations (i.e. single phase, two phase, three phase)

– Line voltage regulator and shunt capacitor locations

3. Determine System Characteristics

– Indentify system load factor LDF and loss factor LSF

– Determine minimum allowed primary volts (on 120 V base)

Rural Feeder DSE & VO Design Process

55

4. Perform Peak Load Flow Simulation – Existing System

– Perform peak load flow simulation for existing system

– Determine maximum voltage drops for all feeders and voltage-control-zones

– Identify VO system non-compliance with operation thresholds (bal, pf, volt drop)

– Determine existing system peak line loss

5. Perform Average Load Flow Simulation(s) – Existing System

– Perform average load flow iterative simulations to determine solutions to meet (bal and pf) thresholds:

6. Perform Peak Load Flow Simulation(s) – with Improvements

– Perform peak load flow iterative simulations to determine solution(s) to meet (volt-drop) thresholds and optimal VO design:

– Determine maximum volt-drop for each VO voltage-control-zone

– Determine system peak line loss with improvements (Pre-VO) 66

• Load balancing• Phase upgrades

• Revised lateral taps• Var Compensation (Capacitors)

• Switching• Load Transfers

• Reconductoring• Voltage-Control-Zones (new or modified)

7. Perform Pre-VO Operation Assessment

– Identify kVA connected for each voltage-control-zone

– Determine kW load for each VO voltage-control-zoneDetermine kW load for each VO voltage-control-zone

– Identify feeder volt-drop % variance for VO substation feeders

– Indentify Pre-VO voltage control settings for each VO voltage-control-zoneIndentify Pre-VO voltage control settings for each VO voltage-control-zone

– Calculate Pre-VO Weighted Average Voltage

8. Perform Post-VO Operation Assessment

– Indentify Pre-VO voltage control settings for each VO voltage-control-zoneIndentify Pre-VO voltage control settings for each VO voltage-control-zone

– Calculate Post-VO Weighted Average Voltage

– Determine average change in customer voltage

9. Determine System VO Factor

– Identify % of customers with electric space heating for substation area

– Identify % of commercial load for substation area

– Identify climate zone for substation area

– Using ESUE Calculator, determine VO Factor

77

9. Determine Expected DSE & VO Energy Savings

– Distribution System line loss change (MWh/yr)

– Connected kV A no-load loss reduction (MWh/yr)

– VO Energy Savings (MWh/yr)

11. Perform Economic Life-Cycle Cost Evaluation

– Estimate Costs

– Identify Financial Factors

– Determine Economic Impacts

12. Identify Metering and Engineering Analysis Recommendations

88

• Installation Costs• Annual O&M Costs

• Marginal cost of Energy• BPA Incentive Payment

• Inflation Rates• Present Worth Factors

• Utility Net Revenue Requirements• Life Cycle Cost of Energy Saved

• Benefit Cost Ratio• NPV Benefits & Costs

Rural FeedersDSE & VO Case Study

99

• 1-15/20/25 MVA Power Transformers with four feeders• Mix of Rural and Urban Feeders in Climate Zone H2 and C2• Average customer % electric heat is 50%• Substation LTC provides only voltage regulation – Reg Volt Set is 125 V• No Line Voltage Regulators are installed, mix of existing capacitors• Power Factor is poor due to lack of capacitors

Existing Metering Data Peak Load kW kVAr kVA PF(%) Customers Com LoadFDR 1 3323 1089 3497 95.02 665 20%FDR 2 5201 1708 5474 95.01 1040 20%FDR 3 3804 1262 4008 94.92 761 20%FDR 4 7129 2363 7511 94.92 1426 20%Substation 19457 6347 20062 94.87 3891 kW losses 191 Sub MWh/yr = 69882 Load Factor LDF = 0.41 Loss Factor LSF = 0.204

1010

FDR 1

FDR 2

FDR 3FDR 4

Substation Service Area:

• 3806 customers

• Four Feeders

• Mix of Rural and Urban Load

• Service area 10 mile x 7 mile

• Average 300 kW per sq mi

4. Perform Peak Load Flow Simulations – Existing System

Legend:

FDR 1 FDR 2 FDR 3 FDR 4

1111

FDR 1 – Rural

FDR 2 – Urban & Rural




Legend:

FDR 1 FDR 2 FDR 3 FDR 4

Urban Area

1212

FDR 1

FDR 2

FDR 3 FDR 4


Legend:

795 kCM AAC

336 kCM AAC

2/0 AA

• Rural Feeders have mostly 336 kCM AAC

• Urban Areas have 795 kCM AAC conductor as substation get-a-ways

• Laterals are 2/0AA

1313


• Rural Feeders have mostly 336 kCM AAC

• Urban Areas have 795 kCM AAC conductor as substation get-a-ways

• Laterals are 2/0AA

Legend:

795 kCM AAC

336 kCM AAC

2/0 AA

Urban Area

1414

FDR 2

FDR 1

FDR 3 FDR 4


Identify Non-Compliance Issues:

• High Load Unbalance

• Poor power factor

• Low primary voltage

• High voltage drops

• Poor Voltage Variance

Determine peak line loss (191 kW)

118.75.268.4

117.06.6410.9

120.24.0113.3

117.76.129.6

121.03.336.5

120.32.246.8

Legend:

117.0 Volts (lowest phase) 6.64% Volt drop % Accum 10.9 Miles from 3ource

1515


Power Factors at Peak

• FDR 1 95.0%

• FDR 2 95.0%

• FDR 3 94.9%

• FDR 4 94.9%

124.10.672.8

122.61.742.3

123.61.21.4

123.41.312.7

Legend:

117.0 Volts (lowest phase) 6.64% Volt drop % Accum 10.9 Miles from 3ource

Urban Area

Legend:

Voltages below 119.8 V

1616

• Determine Minimum Primary Volts

FDR 1

FDR 2

FDR 3FDR 4


3φ Primary Volt (Min) VD% VoltsSecondary Volt Drop (Max) 4.0 4.8Customer Service Volt (Min) 115.0

Primary 3φ Volt (Min) 119.8

118.75.268.4

117.06.6410.9

120.24.0113.3

117.76.129.6

1717

5. Perform Average Load Flow Simulation(s) – Existing System

Fixed Capacitors needed to achieve 100% power factor for average kW load conditions

Average_kVAr_Demand = Annual_kVArh / 8760 hr

Perform average load flow iterative solution(s) to identify upgrades to meet thresholds (bal, pf):

• Load balancing• Phase upgrades• Revised lateral taps• Var compensation (Caps) Average Load

Flow Scenario P =41% Q = 60%

Fixed Shunt Capacitor Additions Caps Added

(kVAr)FDR 1 600FDR 2 900FDR 3 600FDR 4 1200

Sub Total 3300

1818

122.02.506.5

119.14.9313.1

119.04.9913.3

119.74.449.6

121.62.828.4

122.91.56.8

6. Perform Peak Load Flow Simulations – with Improvements

Perform peak load flow to assess (volt drop):

•After Balance, Phase, and Capacitor Upgrades

Legend:

O Added 11-300 kVAr Capacitors 3 phase

Plan New

1 to 2ph

3 to 2ph

1 to 3ph

2 to 3ph

18 Lat Taps

1919

124.10.792.7

124.50.452.8

123.01.332.3

124.10.731.4



•After Balance and Capacitor Upgrades

Legend:

O Added 300 kVAr Capacitors 3 phase

Urban Area

2020

After adding Balanced and Capacitor upgrades, next identify system reconfigurations to meet (volt drop) thresholds

• Switching• Load transfers• Reconductoring• New feeders• New voltage control zones


Consider Switching to add load to FDR 4 from FDR 2 and FDR 3

2121

The Pre-VO system is how the system looks before initiating VO

Determine distribution of connected kVA

• After Switching


Existing Connected kVA Pre-VO Connected kVA

Connected kVA kW Load Connected kVA kW Load

FDR 1 8251 3323 8251 3313FDR 2 11866 5201 10700 4165FDR 3 11300 3804 6600 2972FDR 4 12700 7129 18566 8977Sub 44117 19457 44117 19427

Pre-VO Operation (with Bal, Caps, and Switching) Peak Load Caps Added kW kVAr kVA PF(%) kVAr

FDR 1 3313 492 3349 98.9% 600FDR 2 4165 452 4189 99.4% 900FDR 3 2972 68 2973 100.0% 300FDR 4 8977 1251 9064 99.0% 1500 Sub 19427 2263 19558 99.33% 3300

kW line losses = 161

Determine peak line loss (161 kW) and power factors

2222

119.14.9313.1

119.04.9913.3

119.74.449.6

121.82.668.6

122.32.256.5

122.41.856.8

Maximum Feeder Volt drops

• FDR 1 4.99%• FDR 2 2.66%• FDR 3 1.85%



•After Switching Upgrades

2323

123.90.952.2

123.11.573.1

123.61.181.6

123.71.11.4



•After Switching Upgrades

Maximum Feeder Volt drops

• FDR 4 1.57%

Urban Area

2424

Consider Additional Voltage Control Zones

Add VO voltage control zone to FDR 1A at 1.86%

Add VO voltage control zone to FDR 1B at 2.05%

Add VO voltage control zone to FDR 2 at 1.55%


After adding Balanced and Capacitor upgrades, next identify system reconfigurations to meet (volt drop) thresholds

• Switching• Load transfers• Reconductoring• New feeders• New voltage control zones

2525


119.14.9310.9

119.04.9913.3

119.74.449.6

121.82.668.6

122.32.256.5

122.41.856.8

Legend:

Accumulated volt drop% 0.0 to 1.5% 1.5 to 2.5% 2.5 to 3.5% 3.5 to 5.0%


•Identify possible locations of voltage control zones

SUB LTC

1.85

%

FDR 1A

1.55%

FDR 2

2.05%

FDR 1B

2626

Simulate system with new control zones for volt drop improvements

•Added three New Voltage Control Zones


Legend:

New Voltage Regulators

Accumulated volt drop% 0.0 to 1.5% 1.5 to 2.5% 2.5 to 3.5% 3.5 to 5.0%

123.01.6010.9

123.01.6813.3

123.61.159.6

122.62.008.6

122.32.256.5

122.71.863.2

123.21.856.8

123.31.553.1

122.72.056.0

123.11.573.1

2727

No Line Regulators added for in urban area

123.71.101.4

123.11.573.1

123.61.181.6

124.10.792.7


Urban Area

Legend:

795 kCM

336 kCM

2/0 AA

2828

18 lateral tap revisions

18 lateral tap revisions

1ph to 2ph2/0AA 1.3 mi








3-219A Line Regulators

3-219A Line Regulators

11-300 kVAr Capacitors

11-300 kVAr Capacitors

Summary of DSE & VO Improvements

Reg & EOL Metering

Reg & EOL Metering

$375,000

Voltage Control Zone Adjusted kW load

Connected kVA kW Load Max VD% VD% Var

Sub LTC FDR 1 2107 846 1.86 0.01 FDR 2 8051 3134 2.25 0.20 FDR 3 6600 2972 1.85 0.02 FDR 4 18566 8977 1.57 0.17 Sub LTC 35324 15929 1.88 FDR 1A Reg 6144 1749 702 2.05 FDR 1B Reg 4395 4395 1765 1.68 FDR 2 Reg 2649 1031 2.00 Total kW 44117 19427

2929

Determine kW load for each voltage-control-zone


Max VD%Max Volt Drop (V)

A

Max Volt Rise (V) B

Reg Volt Set

VFR Average

(V)

Reg Total kW load

Less Control Zones kW load Zone kW Adjusted

V * kW

FDR 1 1.86 2.23 0 125 124.542 3313 2467 846 105365

FDR 2 2.25 2.70 0 125 124.447 4165 1031 3134 389999

FDR 3 1.85 2.22 0 125 124.545 2972 0 2972 370147

FDR 4 1.57 1.88 0 125 124.614 8977 0 8977 1118658

Sub LTC 19427 15929 1984170

FDR 1A Reg 2.05 2.46 0 124 123.496 702 0 702 86727

FDR 1B Reg 1.68 2.02 0 124 123.587 1765 0 1765 218095

FDR 2 Reg 2.00 2.40 0 124 123.508 1031 0 1031 127353

19427 2416345

Weighted Adjusted Voltage = 124.38

3030Reg_Set_Volt – ½ * A * LDF

Assign a fixed 124 V for all new voltage control zones regulation sources


Determine Post-VO Weighted Average Voltage After Capacitors, Reconfiguration, and Regulators Added

Max VD%Max Volt Drop (V)

A

Max Volt Rise (V)

B

Reg Volt Set

LDC Average

(V)

Reg Total kW load

Less Control Zones kW load Zone kW Adjusted

V * kW

FDR 1 1.86 2.23 3.0 120 120.772 3313 2467 846 102176

FDR 2 2.25 2.70 3.0 120 120.677 4165 1031 3134 378185FDR 3 1.85 2.22 3.0 120 120.775 2972 0 2972 358943FDR 4 1.57 1.88 3.0 120 120.844 8977 0 8977 1084815Sub LTC 19427 15929 1924118 FDR 1A Reg 2.05 2.46 3.0 120 120.726 702 0 702 84782

FDR 1B Reg 1.68 2.02 2.0 120 120.407 1765 0 1765 212483

FDR 2 Reg 2.00 2.40 2.0 120 120.328 1031 0 1031 124074

19427 2345457

Weighted Adjusted Voltage = 120.73

3131Reg_Set_Volt + LDF * (½ * A + (B – A))

Assign LDC set voltage of 120 V for all voltage control zones regulation sources

Determine Post-VO Weighted Adjusted Voltage After Capacitors, Reconfiguration, and Regulators Added

8. Perform Post-VO Operation Assessment

9. Determine System VO Factor

Identify % of customers with electric space heating for substation area 50%

Identify % of commercial load for substation area 20%

Identify climate zone for substation area H2 & C2

Using ESUE Calculator, determine VO Factor (pu) 0.450

3232

Weighted Adjusted Average Voltage Change (V) = 124.38 - 120.73 = 3.649

Average Voltage Change (pu) on 120 V base = 0.030

Change in Energy = VO Factor(pu) * Total MWh Load * Average Voltage Change (pu)

3333


Distribution System Efficiency Savings

Distribution System Energy Savings from VO improvements

(1-(1/(1.030))2) * 1159

Distribution System Improvements

Estimate of Energy Savings LSF = 0.85*LDF^2 + 0.15*LDF System Loss Factor LSF = 0.204 Peak Loss Reduction (kW) 30Annual MWH Reduction (MWh/yr) 54

No-Load kW loss Reduction

Assumed average 3 watts of no-load loss per kVA connected

Connected kVA = 44117

Total No Load Loss (kW) = 132

Total No Load Loss (MWh) = 1159

Reduction (MWh) = 67



3434


Distribution System VO Energy Savings

VO Energy Reduction

Change in Energy = VO Factor * Total MWh Load * Average Voltage % Change

VO Factor 0.450 Based on ESUE Calculator end-use factor

Total MWh Load 69882

Avg Volt % Change 0.030

VO Energy Savings 956



DSE & VO Total Energy Saved

MWh/yr

DSE Loss Reduction 54

No Load Loss Reduction 67

VO Energy Savings 956

Total Energy Savings for Sub 1077

3535


Distribution System DSE & VO Total Energy Savings

3636


Utility Inputs

DSE General / Substation - INPUT Scoping Study Cost ($) $8,000 Feasibility Study Cost ($) $15,000

Utility Project Cost of DSE & VO Improvements ($) $375,000 Customers per Substation (#) 3,891

Average Customer Energy Consumption (kWh/yr) 15,000

DSE Savings / Substation - INPUT Total DSE Line Loss Savings (kWh) 54,000

Total DSE No-Load Loss Savings (kWh) 67,000 Total VO Savings (for End-Use) (kWh) 956,000

Total DSE & VO Energy Savings per year 1,077,000 kWh/yr

Financial Factors - INPUT Average Annual Retail Energy Rate ($/kWh) $0.070

Average Marginal Purchase Power Rate ($/kWh) $0.060 or High Tier Rate (BPA)Annual Cost increase for Construction (%/yr) 3.0% Annual Cost increase for kWh Energy (%/yr) 4.0%

Operations, Maintenance, and Insurance (%/yr) 5.0% Present Worth Rate for Cost of Investment (%/yr) 7.0%

Present Worth Rate for Cost of Energy Losses (%/yr) 6.0% Planned life of energy savings (yr) 15

Distribution System DSE & VO Economic Evaluation

BPA Energy Efficiency Incentive Payment to Utility / Substation

DSE & VO Energy Saved 1,077,000 kWh/yr

BPA Energy Efficiency Incentive ($/kWh) $0.25

A - BPA willing to pay First Year $269,250

Utility Project Cost of Improvements $375,000

BPA Energy Efficiency Incentive Rate (pu) 70%

B - BPA willing to pay First Year $262,500

Total BPA Incentive Payment (lower of A or B) $262,500

BPA Benefit Cost Analysis / Substation Scoping Study Reimbursement $8,000

Detail Study Reimbursement $15,000

BPA Incentive Payment $262,500

Total BPA Costs $285,500

BPA Levelized Cost per kWh saved $0.021 per kWh saved

3737

BPA Costs



Utility Benefit Cost Analysis / Substation Utility Project Cost of DSE & VO Improvements $375,000 NPV Operations, Maintenance, and Insurance $208,470

Less BPA Efficiency Incentive Payment ($262,500) Net Utility NPV Investment Costs $320,970

Utility Levelized Cost per kWh Saved (Cost) $0.023 per kWh savedUtility Levelized Purchase Power Costs Avoided per

kWh (Benefit) $0.060 per kWh savedBenefit / Cost Ratio 2.59

Utility Revenue Requirements / Substation

Total NPV Utility DSE & VO Costs $320,970 Less NPV Purchase Power Costs for End Use ($830,319)

Net NPV Utility DSE & VO Costs / Substation ($509,350)Negative shows Reduction

Benefit / Cost Ratio 2.59Present Worth Comparison

Substation Costs per year $28,868

Less Purchase Power Savings per year ($64,620) Net Substation Savings per year ($35,752) Negative shows

Reduction in Requirements

3838

Utility Benefits and Costs



Customer Impact / Substation Average Customer Energy Consumption (before DSE & VO) 15,000 kWh per year

Average Customer Energy Consumption (after DSE & VO) 14,754 kWh per yearAverage Customer Energy Reduction per year 246 kWh per year

Customer Average Annual Bill (before DSE & VO) $1,050.00 per year

Customer Average Annual Bill (after DSE & VO) $1,040.81 per year

Bill Reduction Per Customer per year ($9.19) Negative shows

ReductionCustomer Present Value of Savings $102.16

3939


Customer Benefits and Costs


Robert H Fletcher, PLLCRobert H Fletcher, PLLC

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Distribution System Efficiency Voltage Optimization