Session 9: Photovoltaic System Case Studies And Electric Distribution Planning for DER October 21, 2015 Santiago, Chile Michael Coddington National Renewable Energy Laboratory Golden, Colorado, U.S.A.
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Case Study #1 5.2 MVA Located at Colorado State University (Fort Collins, CO, USA) 5.2 MW DC PV System 6.6 miles from substation Installed in 2 phases (2 MW + 3.2 MW) Capacity penetration - 57% (Σ DG / Peak Load)
Case Study #1 5.2 MVA Peak Load on Circuit 9.1 MVA Circuit Voltage 13,200 Volts
Details of PV System and Customer Large Conductors serving Colorado State University West Research Campus Two sets of voltage regulators on circuit and LTC at substation Voltage at campus requested to be ± 1% (per unit) The following steps are to be followed, sequentially, if there are voltage problems (next slide)
Planned Steps if Problems Occured 1. Adjust the voltage regulators to stabilize the voltage levels, and if necessary; 2. The inverters (10 total) will be configured to absorb 100 kvar each to reduce voltage rise, and if necessary; 3. The inverter configurations will be changed so they will absorb 150 kvar each, and if necessary; 4. Request that PV system operator disconnect part or all of the PV system and install a power factor controller or static VAR compensator (SVC)
WHY SMART GRIDS?
Staggered Start for Inverters Required Inverter No. Start-up time Inverter Size 1 230 sec. 500kW 2 260 sec. 500kW 3 290 sec. 500kW 4 320 sec. 500kW 5 350 sec. 500kW 6 380 sec. 500kW 7 410 sec. 500kW 8 440 sec. 500kW 9 470 sec. 500kW 10 500 sec. 500kW
Feeder Load Profile with PV Can you see the Duck Curve shape?
Common PV Penetration Metrics Capacity Penetration* Total PV System MW Peak Load MW Energy Penetration Total DG kwh Total kwh Penetration Screen Fails at 100% MDL or 15% peak load (depending on rules) * This is how Penetration is calculated in Technical Screens
Observations This large PV system behaved well on a typical distribution circuit This distribution feeder circuit is very stiff and has excellent capacity for absorbing DG of this size While this PV system required no system upgrades, most of this size would likely require system modifications
Case Study #2 20 kw Residential PV
Typical Voltage Drop for Utility Loads
Case Study #2 One-Line Diagram
Very High Voltage behind Transformer 131.5 Volts +9.5%
Case Study #2 20 kw Residential PV Voltage rises with minimal local load The ANSI C84.1 (Range A) upper limit is violated at the PV system, and worst violation at the micro-inverters farthest from the service disconnect This facility experienced 127.5 Volts at the utility meter and 131 Volts at the PV array (ANSI Range A upper limit 126 Volts) Local load will affect voltage levels significantly This residential system exports power during the day, which is when most residents are out or using little power. The exported power causes voltage problems locally
Case Study #2 20 kw Residential PV Steady-state voltage can be out of acceptable ANSI C84.1 range A (or B) with even with a small residential PV system This PV system, if only one of a few small PV systems on this feeder, means capacity penetration was <1%, yet there are localized voltage problems. In reality, this system should have failed a review and required mitigation! No other utility customers were negatively impacted by this high voltage example Would you have known there might be a problem with this interconnection application?
Case Study #3 10 MVA Solar PV Carlsbad, New Mexico, US
Case Study #3 10 MVA Solar PV Carlsbad, New Mexico, US Located near Carlsbad, New Mexico 10 MW DC PV System - 3/4 Mile from Substation Capacity Penetration of Approximately 100% based on peak annual load Minimum daytime load on feeder 3.87 MVA (Capacity Penetration ~300%)
Case Study #3 10 MVA Solar PV Carlsbad, New Mexico, US Interconnection with Xcel Energy Distribution voltage 12.47 kv Hopi Substation transformer bank size 16.8 MVA Peak Load on feeder 10 MVA Minimum Daytime Load on feeder 3.87 MVA Circuit conductor ¾ mile 336 ACSR from PV system to substation
Case Study #3 Detailed Impact Studies SynerGEE modeling program utilized for Detailed Impact Studies The following issues were focused on during detailed impact study phase Fault current contribution Protection coordination Voltage profiling studies
Case Study #3 Mitigation Strategies 1. ¾ mile of 336 ACSR feeder conductors installed 2. Additional line protection added to address desensitized relaying 3. Voltage supervised reclosing was added to the substation breakers to address potential problems with PV system size 4. PV owner was required to regulate their output power factor to a fixed value to address possible voltage issues. 5. Additionally the PV owner was required to energize the inverters incrementally in order to avoid large voltage steps.
Case Study #3 Conclusions Detailed Impact Studies were required to interconnect this very large PV system This PV systems exports power to the substation, and back through the substation transformer Load Tap Changer (LTC) Large conductors, short distance to substation were key to the success of this system Mitigation strategies were required The PV system and the utility feeder and substation have operated properly since PV system installation
PV System Size Important Considerations for Siting Locations Distance from Substation (MW-Ω) System Impedance at PV location Distribution Circuit/Substation Design (conductor sizes, regulators, LTCs, etc.) Voltage Regulators & Capacitors Exporting vs. Non-Exporting PV systems Proximity to Other Loads on Circuit Types of Utility Customers on Circuit
Case Study #4 Colorado Convention Center Denver, CO, USA Facility Name: Colorado Convention Center Owner: City and County of Denver Secondary Network Type: Spot PV System Size: 300 kw p DC Type of Interconnection Minimum Facility Load greater than PV System Reverse Power Relay Dynamically Controlled Inverters Utility Company: Xcel Energy (PSCo)
Case Study #4 Colorado Convention Center Denver, CO, USA
Case Study #4 Colorado Convention Center Denver, CO, USA
Network System Integration Approaches Maintain minimum load (MML) Reverse power relays (RPR) Minimum import relays (MIR) Dynamically controlled inverters (DCI)
Maintain Minimum Load Approach Study of historical load data generally supplied by utility (interval recorder data) Evaluate minimum demand during peak PV generation hours (10 AM 2 PM) Interval data estimates demand based on energy usage over 15 minutes (typical) Is an indicator that PV system will be sized smaller than minimum daytime load
Reverse Power Relay Approach Opens circuit breaker tied to PV system if power flows toward utility network Technology is well-known by utility protection engineers Advantages Fairly inexpensive, fast, reliable Disadvantages Manual reset, all-or-nothing
Minimum Import Relay Approach Opens circuit breaker tied to PV system if power into facility drops below threshold (e.g. 25kVA) Similar to reverse power relay utility engineers are familiar with technology Advantages Inexpensive, fast, reliable Better than RPR for network reliability Disadvantages Manual reset, all-or-nothing
Dynamically Controlled Inverter Approach Reduces PV output by % based on actual load of facility (e.g. 25kVA) CTs tie to bus near utility metering Features Very fast response Programmable No resetting of breakers necessary Some loss of energy if activated Inexpensive (~$5k) May not be available on all inverters
DCI (Smart Inverter) Results
Case Study #4 Colorado Convention Center Denver, CO, USA NREL Technical Report NREL/TP-550-45061
Gracias