Post on 10-Jan-2016
description
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) 330-0628fletcher.ups@comcast.net
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.
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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
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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
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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
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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
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• 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
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• 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
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FDR 1 – Rural
FDR 2 – Urban & Rural
FDR 3 – Urban & Rural
FDR 4 – Urban & Rural
4. Perform Peak Load Flow Simulations – Existing System
Legend:
FDR 1 FDR 2 FDR 3 FDR 4
Urban Area
1212
FDR 1
FDR 2
FDR 3 FDR 4
4. Perform Peak Load Flow Simulations – Existing System
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
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4. Perform Peak Load Flow Simulations – Existing System
• 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
4. Perform Peak Load Flow Simulations – Existing System
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
4. Perform Peak Load Flow Simulations – Existing System
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
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• Determine Minimum Primary Volts
FDR 1
FDR 2
FDR 3FDR 4
4. Perform Peak Load Flow Simulations – Existing System
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
6. Perform Peak Load Flow Simulations – with Improvements
Perform peak load flow to assess (volt drop):
•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
6. Perform Peak Load Flow Simulations – with Improvements
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
6. Perform Peak Load Flow Simulations – with Improvements
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
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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%
6. Perform Peak Load Flow Simulations – with Improvements
Perform peak load flow to assess (volt drop):
•After Switching Upgrades
2323
123.90.952.2
123.11.573.1
123.61.181.6
123.71.11.4
6. Perform Peak Load Flow Simulations – with Improvements
Perform peak load flow to assess (volt drop):
•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%
6. Perform Peak Load Flow Simulations – with Improvements
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
6. Perform Peak Load Flow Simulations – with Improvements
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%
Perform peak load flow to assess (volt drop):
•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
6. Perform Peak Load Flow Simulations – with Improvements
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
6. Perform Peak Load Flow Simulations – with Improvements
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
1ph to 2ph2/0AA 1.3 mi
2ph to 3ph2/0AA 1.3 mi
2ph to 3ph2/0AA 1.3 mi
2ph to 3ph2/0AA 1.6 mi
2ph to 3ph2/0AA 1.6 mi
1ph to 3ph2/0AA 0.3 mi
1ph to 3ph2/0AA 0.3 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
7. Perform Pre-VO Operation Assessment
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
7. Perform Pre-VO Operation Assessment
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
10. Determine Expected DSE & VO Energy Savings
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
Weighted Adjusted Average Voltage Change (V) = 124.39 - 120.74 = 3.649
Average Voltage Change (pu) on 120 V base = 0.030
3434
10. Determine Expected DSE & VO Energy Savings
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
Weighted Adjusted Average Voltage Change (V) = 124.39 - 120.74 = 3.649
Average Voltage Change (pu) on 120 V base = 0.030
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
10. Determine Expected DSE & VO Energy Savings
Distribution System DSE & VO Total Energy Savings
3636
11. Perform Economic Life-Cycle Cost Evaluation
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
11. Perform Economic Life-Cycle Cost Evaluation
Distribution System DSE & VO Economic Evaluation
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
11. Perform Economic Life-Cycle Cost Evaluation
Distribution System DSE & VO Economic Evaluation
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
Distribution System DSE & VO Economic Evaluation
Customer Benefits and Costs
11. Perform Economic Life-Cycle Cost Evaluation
Robert H Fletcher, PLLCRobert H Fletcher, PLLC
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