Recipient information | Input |
---|---|
Total number of customers served by utility / utilities supporting the project | 4,395,000 |
Total number of residential customers served by utility / utilities supporting the project | 3,800,000 |
Total number of commercial customers served by utility / utilities supporting the project | 580,000 |
Total number of industrial customers served by utility / utilities supporting the project | 15,000 |
Total number of distribution circuits within utility service territory | 4,664 |
Total number of distribution substations | 1,861 |
Portion of distribution system with SCADA prior to SGIG/SGD program | 0 |
Portion of distribution system with distribution automation (DA) prior to SGIG/SGD program | 0 |
Electric distribution system | % | Description |
---|---|---|
Portion of distribution system with SCADA due to SGIG/SGD program | 95.00% | SCADA is used for monitoring and control of substations and feeders. Percentage calculated by total # of substation feeders with SCADA divided by total # of substation feeders (4,706). Project will not add SCADA to additional substations |
Portion of distribution system with DA due to SGIG/SGD program | 44.20% | Project DA device penetration rate on feeders is calculated as the # of feeders with some type of automated device installed during the project divided by the total # of feeders (4,706). |
DA devices installed and operational | Quantity* | Description | Cost |
---|---|---|---|
Automated feeder switches | 2,193 | # of locally operated or centrally coordinated/operated SCADA switches and reclosers installed. The devices are being deployed at mid-line locations and normal open points of two feeders. The devices will be monitored and controlled by system operators, or function automatically in fault location, isolation and service restoration (FLISR) schemes. NOTE: DA reclosers are reported as complete when field installation work is completed. Reclosers are placed into active SCADA operation normally within 2 months of field work. 2,193 automated feeder switches were installed during the SGIG Project. | $73,754,484 |
Automated capacitors | 1,869 | $26,654,054 | |
Automated regulators | 3,339 | $8,722,605 | |
Feeder monitors | 0 | $1,424,515 | |
Remote fault indicators | 263 | $0 | |
Transformer monitors (line) | 0 | $15,219,659 | |
Smart relays | 848 | ||
Fault current limiter | 0 | $0 | |
Other devices | 8,685 | $24,910,681 |
SCADA and DA communications network | Cost |
---|---|
Communications equipment and SCADA | $7,863,999 |
Distribution management systems integration | Integrated | Description |
---|---|---|
AMI | Yes | |
Outage management system | No | |
Distributed energy resource interface | No | |
Other | No |
Distribution automation features / functionality | Function enabled | Description |
---|---|---|
Fault location, isolation and service restoration (FLISR) | Yes | See Self Healing Network Description. The IDMS at APC will have FLISR functionality. This is under development but not implemented at this time. FLISR at other companies is also being implemented and will be provided by a SEL Restoration Gateway and/or an Automated Computer System restoration application. FLISR applications will automatically open switches to isolate the faulted portion of the feeder, and then close switches to restore power to unaffected line segments. See the comments included above in the Self Healing Networks box. GPC installed 848 distribution feeder breaker relays during the SGIG project that provide Fault Location data to SCADA. Automated Fault Location is now active at GPC and is integrated into GPC's Outage Management System. |
Voltage optimization | No | Voltage Optimization is a feature that will be included in the IDMS system. The project will integrate AMI with the IDMS to enable centrally controlled voltage control and to monitor voltage levels to ensure acceptable voltage levels are maintained. Voltage will be lowered to reduce loading on the system when needed for constrained capacity events. Development of IDMS is continuing & is planned for completion in 2014. APC & Southern Company are committed to the completion of IDMS scope as originally defined. |
Feeder peak load management | Yes | Project will install capacitors and automated voltage regulators to enable peak load demand reduction. Capacitors will reduce losses, flatten the voltage profile, and enable centrally controlled voltage reduction to reduce demand during capacity constrained events. The equipment added on the SGIG project was designed to provide 200 MW peak load reduction at APC & 200 MW peak load reduction at GPC. |
Microgrids | No | |
Other functions | Yes | The Project will provide fault location data to system operators through smart relay and smart substation meters. The development and installation of the Fault Location application at Georgia Power Company will automatically provide rapid location of faults on the distribution circuits. This fault location application will reduce outage times. This functionality came on-line at Georgia Power Company during the 4th Quarter of 2011. Additional feeders were added into this system as additional microprocessor feeder relays were installed. A total of 848 smart feeder relays were installed at GPC during the SGIG project. |
Recipient information | Input |
---|---|
Total miles of transmission line | 26,650 |
Total number of transmission substations | 3,325 |
Number of PMUs installed and operational before SGIG program | 0 |
Number of PDCs installed and operational before SGIG program | 0 |
Electric transmission system | Portion | Description |
---|---|---|
Portion of transmission system covered by phasor measurement systems | 0% |
Phasor measurement systems | Quantity* | Description | Cost |
---|---|---|---|
PMUs | None | $0 | |
Phasor data concentrators | None | $0 | |
Communications network | Additional communication infrastructure is being installed and accounted for in the Distribution portion of the project. | $0 |
Other transmission assets | Quantity* | Description | Cost |
---|---|---|---|
Dynamic Capability Rating System (DCRS) - Transmission Lines | None | $0 | |
Other transmission assets | $0 | ||
Other transmission assets | 0 | $0 | |
Other transmission assets | 0 | $0 |
Angle/frequency monitoring | Operational | Description | Cost |
---|---|---|---|
Angle/frequency monitoring | No | $0 | |
Post-mortem analysis (including compliance monitoring) | No | ||
Voltage stability monitoring | No | ||
Thermal overload monitoring | No | ||
Improved state estimation | No | ||
Steady-state model benchmarking | No | ||
DG/IPP applications | No | ||
Power system restoration | No |
* In some circumstances, costs are incurred before devices are installed resulting in a reported cost where the quantity is zero.
* All dollar figures are the total cost, which is the sum of the federal investment and cost share of the recipient (the recipient cost share must be at least 50% of the total overall project cost).
** In some cases the number of entities reporting is greater than the total number of projects funded by the Recovery Act because some projects have multiple sub-projects that report data. View list of sub-projects.