TEAM HANFILCO
1. PROJECT OVERVIEW
1.1. Stakeholders: Sponsor: Idaho Power Client: Dave Angell Advisor/Capstone Instructor: Brian Johnson / Herb Hess Consultants: Kelly Hulse (Engineer, Idaho Power) 1.2. Project Background: The increased presence of non-linear loads, typically Variable Frequency Drives (VFDs), on the Idaho Power Company (IPCo) distribution system have resulted in increased harmonic currents. In some areas these currents have resulted in improper operation of several distribution devices, primarily relay equipment mis-coordination. Additionally, they are interacting with power factor correction capacitors on IPCo’s distribution system. This interaction result in voltage distortions in excess of those recommended by IEEE 519-1992 table 11.1. In several areas, standard solutions (e.g. re-sizing or moving the cap banks) fail to mitigate the resonant conditions. Idaho Power wants to investigate whether a distribution system with multiple power factor correction capacitor and voltage levels may be tuned to block or filter the harmonic currents so they flow in a portion of the system where they do not adversely affect other distribution devices. 1.3. Deliverables: Design Documentation Research Documentation Presentation Materials Simulation Results Hardware demonstration with the analog power system in BEL G10.
2. Project Justification
2.1. Needs: Idaho Power needs a method to mitigate the harmonic current flows and reduce their effects upon the power distribution system. The induced voltage harmonics are exceeding the standards IEEE 519, impacting the operation of equipment sensitive to power fluctuations. In addition, the transformers, which need to be de-rated for harmonic loading
as per ANSI C57.110-1998, suffer from excess heat which potentially reduces their life span.
2.2. Benefits:
Idaho Power would benefit from greater customer satisfaction and increased longevity for its transformers. Idaho Power customers would be supplied with cleaner power resulting in less equipment outages and commercial downtime. The project will continue the relationship between the University of Idaho and Idaho Power who may sponsor future capstone design projects. The team members will have an opportunity to gain experience working on a real-world project.
2.3. Investments & Costs: Investments: Financial contribution of the client: Costs: To be estimated in next phase.
2.4. Return on Investment (ROI): Idaho Power will receive options for mitigating the harmonic flows along with their anticipated impact on the distribution system.
3. TEAM FORMATION
Goal: To provide a mitigation method that exceeds the expectations of Idaho Power and the project advisors while learning more about power quality issues and the design process. Expectations: We all want to have a good working team relationship with good communication and trust. We want a team where everyone is a valuable contributor to the final design. Accountability: We will probably use an informal system combining good communication, guilt trips and small financial punishments (i.e. buying pizza etc.). Roles: Team Contact: Dennis Heitmann Webmaster: Angelo Neglia
Assessment: We plan to have a meeting where we devote time specifically to assessment of teamwork after each completed phase of the project.
Rules: Do what you say you’re going to do Meet your deadlines Be open-minded Give notice to decline or schedule a meeting
4. EXPLORING THE PROJECT
4.1. Client and Stakeholder Interview Questions:
People: Q: Who do we deal with? Just Kelly or anyone else? _ You can contact Kelly Hulse as your main contact: o Kelly Hulse o Senior PQ Engineer – Harmonic Mitigation o 1221 W. Idaho St., Boise, ID 83702 o Phone: 208-388-6442 o Cell: 208-861-3579 o Fax: 208-433-3578 o E-mail: Khulse@idahopower.com Q: Who at Idaho Power makes decisions for the project if we have questions? Kelly Hulse Q: Who will provide the system data? What format will it be in? Kelly Hulse. The format can be discussed. Currently, all system models are in an Access Database that interfaces with a program called SynerGEE from Advantica.
Need: Q: What is being done now to mitigate the harmonics? Can you show us? Currently, we focus on bank relocation or elimination. If the issue is a zero sequencing problem we may work with the affected customer to de-tune the bank. Q: How are the capacitor banks switched in and out? We have several methods available. In the area we intend for study it is a combination of fixed, radio controlled, and radio controlled banks with voltage over ride. Our radio controlled capacitor banks, known as ACC (Automatic Capacitor Control) are controlled via an algorithm that is designed to maintain a leading PF of 99% on the substation transformer when the system is at peak. It uses a look-up table to determine the sequence of energization/de-energization for each bank. In areas where we have these issues the meter systems that supplied the VAR measurement were mis-reporting system VAR’s. For example a 1200 KVAR bank would energize and the metering would tell the algorithm that a 2700KVAR bank had just energized. This was due to the rms calculations in the meter and the assumption that the standard power triangle would provide true VAR measurements. When this happened the
the ACC system would oscillate. Resulting in multiple capacitors switching, that resulted in equipment failure, and loss of load. We are now using a new metering scheme that will correctly report VARs as well as maintain system harmonic information related to cap bank switching. This metering will be available for this study. Additionally, it supplies a 1024 sample/cycle waveform capture for all transients and 128 samples/cycle for all sag/swell data. Q: When are the capacitor banks switched in and out? – All fixed banks are usually on-line. Voltage over-ride banks will switch if a low voltage condition is needed. All other switching is done by the ACC based on the substation transforms VARs and a trend line that defines VAR needs based on WATT demand on the transformer. Additionally, ACC banks with voltage over-ride will refuse to switch on if a high voltage is detected. Q: Are the harmonics monitored? If so how? – As mentioned earlier we have install metering in the substation on each feeder in the area of study. The meter we are using is the PML 7650 ION. We have also installed single phase metering systems in the system’s primary. We have two of these in locations that were deemed strategic to the monitoring scheme. We are contemplating making these 3-phase monitoring sites. At these sites we have been monitoring with a Fluke RPM PQ monitor. For this project we can continue with the RPM or move to the Dranetz PX5 (my preference). Q: Is the goal to eliminate the harmonics or bring them within a certain tolerance? If the latter, what is the tolerance? Elimination would be great. However, I do not believe it possible. We would like to see the voltage distortion brought into compliance with IEEE 519-1992 table 11.1. Which is <5% THD with <3% harmonic distortion on any individual voltage harmonic. Q: At what point in the distribution system are you looking at for mitigating the harmonics? What voltage / current levels? We need to get the voltage distortions along the whole feeder in compliance. When these conditions are at worst case we see ~10% voltage distortion about 8 miles from the substation (at our monitoring sites last year) The currents involved in these distortions are about 27 amps @ the 5th harmonic with Irms~ 80amps (34.5 kVLL at site). The feeder in question here has two voltage levels 34.5kVLL and 12.47 kVLL with a max current ~ 390 Amps per phase at the station bus.
Constraints: Q: Are there any mitigation methods you want to exclude? No. Q: How are the capacitor banks configured? 3-phase Grounded - Wye Q: Do we have any constraints on the type of simulation software used? I would prefer SyneerGEE, however we can work with anything. Would you supply a copy of your preferred simulation program if the University of Idaho doesn’t have it or if it isn’t available for free? Yes.
Functions: Q: How would the filters be controlled? We would like kVAR controlled devices. Q: How would the mitigation scheme be integrated into the system? Depends on what the scheme will be.
Scope: Q: Which specific feeder would you like us to focus on? Pleasant Valley 43 (PTVY-043), Toponis 41 (TPNS-041) -as a secondary choice
Existing knowledge: Q: Do you have any lessons learned from previous attempts? Relocation of capacitor banks appears to be not an option. Q: Do you know of similar distribution systems that have successfully mitigated harmonics? No.. Q: Can we see some of the documentation/data you have for the distribution system and the harmonic monitoring? Yes. Q: Would it be useful for team members to visit a candidate substation? Yes
Expectations: Q: How often would you like progress updates? Open, currently a monthly report would be fine. Q: Web page desires? None Q: What information do you want in the final report? An option of methods would be preferable. However a single solution would be adequate or a finding that given known technologies no solution is available. Q: Do you want an onsite presentation at the end of the project? Yes Q: Is there anything else we’ve forgotten to address that you can think of? I think you got most of it..
4.2. Research & Learning Needs:
Technical Knowledge: Read ANSI C57.110-1998 document Read IEEE Standard 519 - 1992 Read “Electrical Power Systems Quality” by Dugan, McGranaghan, and Beaty Learn EasyPower Program for simulation ( SynerGEE)
5. Client Interview
Current Procedure Desired Procedure
6. Assessment of Phase Zero
6.1. Strengths 6.2. Improvements 6.3. Insights
7. Phase Zero Sign-off
Preliminary review/assessment by Instructor/Technical Advisor: March 3rd Approval of final draft by team: March 8th Final review/approval of Instructor/Technical Advisor: Brian Johnson Team Approval: Instructor/Faculty Advisor: Brian Johnson William Armstrong _______________________________________ Dennis Heitmann _________________________________________ Angelo Neglia ____________________________________________