The Challenge
A critical 115/12.47 kV utility substation with electromechanical protection relays from the 1970s was experiencing increasing maintenance costs and providing limited monitoring capabilities. The utility needed to modernize protection systems to improve reliability, reduce outage times through better fault location, integrate with SCADA, and support future smart grid initiatives. The substation serves 12,000 customers including a hospital and could not tolerate extended outages during the upgrade.
Our Solution
We designed and implemented a comprehensive protection system modernization using microprocessor-based relays with IEC 61850 communications. Our approach maintained protection at all times during the transition while adding capabilities not available with the legacy system.
Key Components
Implementation Phases
Phase 1: Engineering and Design (Months 1-4)
Detailed protection system design and preparation for implementation.
- •Protection coordination study with new relay settings
- •IEC 61850 system architecture design
- •Single-line and three-line drawings
- •Panel layouts and wiring diagrams
- •Communications network design
- •Protection settings calculations
- •Detailed cutover procedures minimizing outage time
- •Factory acceptance test procedures
Phase 2: Equipment Procurement and FAT (Months 5-7)
Equipment procurement and factory acceptance testing.
- •Microprocessor relay procurement (17 relays)
- •Communication equipment and network switches
- •Factory acceptance testing of all relays
- •Settings file validation
- •SCADA integration testing at manufacturer
- •Spare parts and test equipment
- •Training on new equipment for utility staff
Phase 3: Installation and Cutover (Months 8-12)
Phased installation minimizing customer outages.
- •Panel installation and wiring during outages
- •Relay installation bay-by-bay approach
- •Point-to-point wiring verification
- •Communications network installation
- •Parallel operation of old and new systems where possible
- •Controlled cutover with backup procedures
- •Individual relay commissioning testing
- •System integration verification
Phase 4: Testing and Validation (Months 13-14)
Comprehensive system testing and performance validation.
- •Complete protection system testing per NETA standards
- •End-to-end communication testing
- •SCADA integration verification
- •Fault simulation and recording validation
- •Coordination verification between zones
- •Remote access and security testing
- •As-built documentation and settings records
- •Operations and maintenance training
- •Final acceptance and system turnover
Results & Impact
Improved from 2-mile uncertainty to pinpoint location within 500 feet, dramatically reducing outage investigation time.
Annual relay maintenance costs reduced from $47,000 to $15,000 through self-diagnostics and reduced testing requirements.
Over 100 system parameters now available for real-time monitoring versus 6 with old system.
Total customer outage time during entire 14-month project, equivalent to just 0.048% unavailability.
Client Testimonial
"The modernization has transformed how we operate this substation. We now have visibility into system conditions we never had before, and our operators can diagnose problems remotely that used to require site visits. ClarkTE's careful planning ensured we maintained service to our customers throughout the project."
Technical Details
Equipment Replaced
- ▸Transformer differential relays (2): SEL-787
- ▸Transformer overcurrent relays (2): SEL-751
- ▸Feeder protection relays (8): SEL-751A
- ▸Bus differential relay: SEL-487E
- ▸Breaker failure relays: Integrated in feeder relays
- ▸Voltage relays (2): SEL-710
- ▸Communications processors: SEL-3355
- ▸Network switches: Ruggedized industrial grade
IEC 61850 Implementation
- ▸GOOSE messaging for high-speed protection schemes
- ▸MMS for SCADA integration and remote access
- ▸Sampled values for future digital instrument transformer integration
- ▸Time synchronization via IRIG-B and PTP
- ▸Redundant communications network for reliability
- ▸Cybersecurity per IEC 62351 standards
- ▸Self-describing configuration via SCL files
Enhanced Capabilities
- ▸Oscillography with 64 samples per cycle
- ▸Sequence of events with 1 ms resolution
- ▸Fault location within 500 feet
- ▸Load profiling and thermal monitoring
- ▸Power quality monitoring (harmonics, unbalance)
- ▸Remote relay setting changes with approval workflow
- ▸Automated testing and self-diagnostics
- ▸Integration with utility asset management system
Lessons Learned
- Detailed cutover procedures with backup plans were essential for minimizing customer outages
- Factory acceptance testing caught configuration issues early when they were easy to fix
- Having both old and new relays operational during transition provided security
- Extensive testing of communications before relying on them prevented issues
- Training utility staff early helped them participate effectively in commissioning
- Documentation of settings rationale helps future engineers understand decisions
Have a Similar Challenge?
Our experienced team can help you solve complex power system challenges. Let's discuss your specific needs.
Contact Our TeamRelated Case Studies
Manufacturing Facility Electrical Safety Program Implementation
Implementing a comprehensive electrical safety program for a large manufacturing facility, including training, procedures, and safety assessments.
Data Center Power Reliability Enhancement
How we improved power reliability and reduced downtime for a critical data center through system analysis and strategic equipment upgrades.