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Transcript
Power System Engineering, Inc. Distributed Generation Testing & Commissioning IEEE Rural Electric Power Conference Jeff M. Triplett, P.E. [email protected] May 2014 Fort Worth, TX Typical Interconnection Process • Application • Preliminary Review • Screening Process • Engineering Studies (as needed) • Study Results and Construction Estimates • Final Go – No Go Decision • Design • Order Equipment and Construction • Inspection, Testing & Commissioning 2 Common Testing & Commissioning Questions • What is required? • Who is responsible for what? • What is the process? • What documentation needs to be provided and maintained? • What about ongoing requirements after initial installation? Responsibilities and requirements of both the interconnecting customer and the utility need to be clearly established in the interconnection policies and agreements. 3 Inspection and Testing Inspection and testing of DG equipment and its associated interconnection system is important for safety and system reliability. Applicable standards and codes should be referenced when developing or adopting procedures. IEEE 1547 IEEE 1547.1 UL 1741 ANSI NEC NESC 4 IEEE 1547.1 IEEE Standard Conformance Test Procedures for Equipment Interconnecting Distributed Resources with Electric Power Systems Specifies, in detail, the type of production tests and field commissioning tests needed to demonstrate that a DG installation conforms with IEEE 1547. 5 Pre-Certification Provides certification that a DG package has been tested and listed by a nationally recognized testing and certification laboratory (NRTL) for compliance with applicable codes and standards. Certification means that factory testing yields plug and play systems that only require limited field testing. If only the interfacing components are certified, then the DG owner needs to show that the generator is compatible with the certified interfacing components and the parameters in which they were tested. 6 UL 1741 UL 1741 is an industry accepted standard for inverters, converters, controllers, and interconnection systems for use in independent power systems. For utility-interactive equipment. Intended to supplement and be used in conjunction with IEEE 1547 Intended to be installed in accordance with the NEC. Does not apply to induction or synchronous generators. 7 Level of Testing Required • Size and type of DG facility will be the primary drivers that determine the testing and commissioning requirements • Smaller and/or pre-certified systems will require less testing be done in the field • Synchronous machines (because of their complex controls) will require more extensive testing and commissioning Note that the terms “larger” and “smaller” used here are relative terms generally referring to the size of the generation capacity compared to the load in the area. 8 Smaller Inverter-Based Systems Field Verification 1. Verify local inspector requirements have been met 2. Verify what has been installed in the field matches application information 3. Verify AC disconnect installation and operation according to utility requirements 4. Verify programmed inverter voltage/frequency trip points and times 9 Smaller Inverter-Based Systems Field Testing 1. Record time for inverter to begin outputting power after normal AC voltage is established to the inverter 2. Measure and record voltages/amperages at relevant locations with and without the inverter operating 3. Conduct a “cease-to-energize” test to verify inverter stops outputting power when utility source lost 4. If inverter is not UL 1741 listed, may wish to do additional testing (harmonics, DC current injection, trip times, etc.) 10 Disclaimer Adding a disclaimer to any utility test documentation is recommended. “Utility’s observation, review, inspection or testing shall be construed neither as an endorsement or confirmation of any aspect, feature, element or condition of the Generation Facility or Interconnection Customer’s protective equipment or the operation thereof, nor as a warranty as to the fitness, safety, desirability or reliability of same.” 11 Larger (Non-Inverter) Systems 12 Field Verification – Prior to Energization Inspection 1. Verify local inspector requirements have been met 2. Verify what has been installed in the field matches supplied documentation 3. Obtain/Verify from Interconnection Customer a. Final as-built diagrams b. Programmed relay settings c. Test reports – CTs, VTs, relays, batteries, etc. 13 Field Verification – Prior to Energization Instrument Transformers Current transformers (CTs) and voltage transformers (VTs) used for monitoring and protection should be tested for correct polarity, ratio and wiring. CTs should be visually inspected to confirm that all grounding and shorting connections have been removed where required. 14 Field Verification – Prior to Energization Trip Checks / Functional Testing Protective relaying should be functionally tested for correct operation of the complete system. Functional testing requires that the complete system be operated by the injection of current and/or voltage to trigger the relay element causing breaker tripping and lockout or provides the correct signal to the next protective device. NOTE: Utility should reserve the opportunity (but not be required) to witness functional testing of customer interconnection protection schemes. 15 Field Testing – Prior to Paralleling • The following testing/commissioning is recommended (as applicable) PRIOR to allowing the generation to parallel with the utility system – Phasing Test – Synchronizing Test 16 Field Testing – Prior to Paralleling Phase Tests For three phase applications, phase rotation between the DG facility wiring and distribution system should be tested and verified. Voltage 0 270 90 360 Time A 180 B C 17 Field Testing – Prior to Paralleling Synchronization Test This test should be performed on the DG paralleling device and any other switching device that can parallel the DG Facility output with the utility system. The test should demonstrate that at the moment of the intended paralleling-device closure, the frequency, voltage and phase angle are within the required ranges stated in IEEE 1547 as well as the manufacturer’s specifications. The test should also demonstrate that if any of the parameters are outside of the ranges stated; the paralleling device will not close. 18 Field Testing – After Paralleling Load Test This test should be performed to verify correct polarity, phasing and magnitudes of all instrument transformer circuit inputs into relays, meters, etc. 19 Field Testing – After Paralleling Anti-Islanding Test This test should demonstrate that the DG facility will cease to energize or isolate itself from the utility system within 2 seconds of the utility source being removed. *Source: IEEE P1527.2/D11 20 Possible Ongoing Testing Power Quality Testing Depending on the type of generation, it may be desirable to verify over time that the generation is not a source of objectionable levels of harmonics or otherwise has a negative effect on power quality such as being a source of voltage transients or fluctuations. Examples: Large wind or solar installations 21 Utility Testing • It is not uncommon for specific utility protection schemes to be needed to safely and reliably accommodate a larger DG facility. – Direct Transfer Trip (DTT) schemes – Directionalized overcurrent protection – Block close schemes – Reverse power schemes • Metering and any monitoring/SCADA equipment and associated communications circuits 22 Other Systems • Smaller non-inverter systems – Synchronous or induction machines – May require same level of testing as larger systems • Larger inverter-based systems – Level of testing can vary – Moderate levels may still allow inverters to provide needed interconnection protection – Higher levels may require additional interconnection protection and correspondingly testing 23 Periodic Testing and Record Keeping The interconnection system should be periodically tested and maintained as stated in the DG Interconnection and Operations Agreement between the utility and DG owner. It is typically recommended that periodic tests are performed no less than every 5 years. Done by DG owner with notification to the utility (utility personnel may witness the testing). 24 Questions? 25 Power System Engineering, Inc. Name: Jeffrey M. Triplett, P.E. Direct: 740-568-9220 Thank You! Mobile: 740-525-0070 Email: [email protected] Website: www.powersystem.org 26