Utility Updates on Projects Presented in 2008 P&E Forum Remote Fault Indication for Distribution...
1
Utility Updates on Projects Presented in 2008 P&E Forum Remote Fault Indication for Distribution Systems The AESO’s objective is to integrate as much wind to the Alberta system as is feasible without compromising system reliability or the fair, efficient and openly competitive operation of the market. Update on Wind Power Development Since the last Consortium meeting in 2008, an additional 66 MW of wind power has come onto the grid with the TransAlta Blue Trail project. Wind power in Alberta has increased from 497 MW to 563 MW of transmission connected wind generation. With approximately 40 MW of distribution connected wind generation Alberta there is over 600 MW of installed wind generation capacity in Alberta. Implementation of the Market and Operational Framework On March 5, 2009, the AESO issued a discussion paper on the Implementation of the Market and Operational Framework. Several topics were discussed as follows. Wind power forecasting: • Implement a Centralized Wind Power Forecasting Service • Proceed with a RFP for a wind power forecasting service provider • Commence consultation on rules, procedures, standards defining obligations to provide wind power forecasts • Develop forecast data management • Process to monitor and improvement forecasting accuracy • Provision forecast data to the market Wind power management: Commence consultation on rules, procedures and standards for wind power management. Supply surplus: Further consultation required on a supply surplus protocols. Update on Wind Power Forecasting On June 23, 2009, the Alberta Electric System Operator issued a Request for Proposal (RFP) for a centralized wind forecasting service in Alberta as part of its continuing efforts to integrate more wind power into Alberta’s Interconnected Electric System. The requirements within 61850 Based Protection and Control Systems This pilot project was initiated to develop a system of remote units that would transfer fault indicator data from EPCOR’s distribution system to the main Control centre. In providing immediate fault data to control operators, they are better able to identify the fault location and more precisely dispatch Trouble crews; resulting in faster system restoration times and therefore shorter customer outages. In 2008, EPCOR completed the implementation of this pilot project, which saw 50 Remote Fault Indication (RFI) units installed on the southern portion of EPCOR’s underground residential distribution system. No further installations have been completed in 2009, as it was decided to conduct an engineering review to observe and evaluate the performance and viability of the new system. One issue that has been encountered is that a few of the units have been found to go dormant and stop communicating. Each of the units is programmed to send a health signal to the SCADA system every three days. Using this, an independent SCADA program was created to monitor these calls, which sends an indication to the EPCOR control centre if a RFI unit is dormant for longer than six days. This data is then passed to field operations for investigation and repair, as required. In almost all cases, the root of this problem has been the battery power supplies. While the logic and functionality of the RFI units has proven effective, the batteries have shown to have a shorter than expected life-span and tend to perform poorly in extreme weather conditions. This has become the primary concern with the project: providing a reliable power source for the units, that is both robust and cost effective. As a result, EPCOR is now reviewing alternate power supply solutions. Of greatest interest is a battery pack with a temperature compensated battery charger. The charger itself would be supplied either by bringing a secondary 120VAC feed, if available, or via a voltage sensor bushing within the cubicle. This solution promises higher reliability and will save on the high cost of field maintenance and battery replacements. Moving forward, when a viable and economical power supply system is found, the existing 50 RFI units will be retrofitted and an additional 35 RFI units are scheduled for installation in the northern section of EPCOR’s underground residential distribution system. [email protected] ATCO is finally planning to look at the 61850 based protection and control systems. We are in the process of selecting a new design for the substation standard and we will be reviewing this system starting next month. We had not anticipated on using this for another 2 years yet; however the benefit of reduced wiring and common standards across various vendors is pushing the development faster than we thought. So we are looking at testing the 6150 platforms for the substation inter-device communications. We will check for the compatibility between various vendors, various devices and its flexibility and ease of implementation. Our biggest benefit we hope for is that this language or protocol will stay an industry standard for 15years or more. This gives us great benefits in reduced training and engineering costs, as well as interoperability and thus better information exchange between different protection and control devices, which previously was either through wiring or protocols plagued with incompatibility and obsolescence problems, just within a few years. [email protected] ALTALINK installed the Dynamic Thermal Line Rating (DTLR) system from The Valley Group (TVG) on 170L, between the Peigan (59S) and Pincher Creek (396S) substations. The installation was done as a pilot to ensure that this system would integrate into AltaLink’s system and provide a safe and reliable increase to the thermal line rating capacity of the line. This pilot allowed AltaLink and the AESO to gain clarity on the complexity of the DTLR system as there were many challenges in trying to integrate the system fully. A number of modifications were required to integrate TVG’s DTLR system into AltaLink’s infrastructure. These included automatic seasonal limits, dual rating thresholds, modified shutdown routine, pre-initialization of points. • Loss of communication between the CAT units and the RTU occurred several times a day. Reconfiguration of the CAT units was completed to address this. • Bi-monthly EMS database updates, still today, cause issues with the DTLR program, and require manual notification to rundown generation in the area. • ICW still needs to be installed as a Windows service rather than an application to meet NERC requirements. • TVG’s system had never been installed in an area that experiences the temperature ranges and wind that are experienced near 170L. Winds parallel to the line can cause errors 0.3% of the time; TVG has proposed a solution to this problem, however the cost of the solution does not outweigh the benefit in this case. Winds perpendicular to the line currently do not cause error in the MVA measurement because of the maximum MVA limit imposed. However, there is potential for error at higher MVA values and therefore in future installations this is to be examined prior to installation. • The DTLR system must be physically installed on the line for one year, so that it is properly calibrated, before the dynamic ratings can be applied. • Jumps in MVA rating caused significant concern – jumps in ratings as much as 50MVA have been seen when switching from a tension based to a temperature based measurement. With work, these have been reduced to a maximum 25MVA jump. • Any physical change to the line would require a recalibration of the system. • On-going maintenance of the system will cost at a minimum 1200USD per load cell per year • (7200USD/year for 170L) – TVG must recalibrate the system every 6 months. This cost does not include any troubleshooting or replacement of any parts of the system. • Since the ICW machine is essentially a black box and all configuration updates can only be done by TVG, this poses a significant operational risk. • System complexity itself creates several potential points of failure, which also adds risk. • There is no redundancy with the load cells or with the ICW machine. If any of these fail, the DTLR system will be turned off. The DTLR system is best used to provide an option during contingency situations. AltaLink does not see TVGs DTLR as the best solution for temporarily increasing line capacity due to the risk, cost, complexity and potential for errors. (Source of information: Review Report prepared by Marie-France Roy of AltaLink, June 2 2009) [email protected] AESO Wind Integration Update Display Another issue that has recently emerged relates to some AMI meter displays resetting, shutting off altogether and in other situations locking up. Initial investigation has shown that this issue is related to power outages, line switches and other power interruptions, most notably due to lightning storms. Radio Frequency Implementation While the current system of transmitting customer consumption data over the existing power lines successfully meets current requirements, it does not provide enough signal capacity in certain higher density areas to support potential industry requirements such as hourly meter readings. A radio frequency (RF) system of communication, which provides much greater signal capacity, will therefore be implemented in these areas. Automated meters on the RF system transmit data via an ultra high frequency radio signal to collection equipment typically set up on poles or street lights. The data is then transmitted via a 3rd party wide area network, such as Telus, to FortisAlberta’s central computer for billing and other purposes. Installation of RF meters and the required infrastructure is scheduled to begin in early 2010. Residential RF meters will be installed in higher density urban and semi-urban locations starting in Airdrie and Sherwood Park. [email protected] How do we measure up? More than half of FortisAlberta’s 460,000 customers have received an automated meter, providing daily reads for monthly billing. 99.7% of customers who are connected to an AMI-enabled substation are receiving AMI meter reads for billing within 65 days, exceeding FortisAlberta’s target of 99% for these meters. Since 2007, AMI, as noted in the graphs, consistently outperforms what can be achieved with a manual meter reading system. AMI Developments Full implementation of AMI meters has been ongoing for just over a year and it is still difficult to gauge the full impact of AMI meters on workload. Customer sites with AMI meters contribute to fewer than 39% of all field Service Investigation Orders (SIOs), even though they represent over half of all meters. Conventionally-metered sites still represent the bulk of SIOs. Failed Finds Some installed AMI meters have not yet begun to transmit readings and are referred to as failed finds. In some cases, failed finds are isolated in groups of meters fed off the same substation, making it clear that the root cause of the issue lies somewhere between the meter and FortisAlberta (e.g. noise on the power lines, bad grounds, etc.) rather than within the meter itself. Another portion of failed finds can be simply attributed to breakers turned off or services disconnected in such a way as to inhibit the meters’ remote reading capability. Failed finds are an expected challenge of the initial substation commissioning, and as each substation- specific issue is resolved, the number of failed finds steadily declines. Update on Dynamic Thermal Line Rating Although electronic meters are inherently more susceptible to power surges, the sporadic nature of the occurrences has made it difficult to pinpoint the exact cause. Since 2007, however, only approximately 600 out of the 250,000 AMI meters installed have needed to be replaced due to a reset issue.
-
Upload
hester-morgan -
Category
Documents
-
view
214 -
download
1
Transcript of Utility Updates on Projects Presented in 2008 P&E Forum Remote Fault Indication for Distribution...
Utility Updates on Projects Presented in 2008 P&E Forum
Remote Fault Indication for Distribution Systems
The AESO’s objective is to integrate as much wind to the Alberta system as is feasible without compromising system reliability or the fair, efficient and openly competitive operation of the market.
Update on Wind Power Development Since the last Consortium meeting in 2008, an additional 66 MW of wind power has come onto the grid with the TransAlta Blue Trail project. Wind power in Alberta has increased from 497 MW to 563 MW of transmission connected wind generation. With approximately 40 MW of distribution connected wind generation Alberta there is over 600 MW of installed wind generation capacity in Alberta.
Implementation of the Market and Operational Framework On March 5, 2009, the AESO issued a discussion paper on the Implementation of the Market and Operational Framework. Several topics were discussed as follows.
Wind power forecasting: • Implement a Centralized Wind Power Forecasting Service • Proceed with a RFP for a wind power forecasting service provider• Commence consultation on rules, procedures, standards defining obligations to provide wind power forecasts • Develop forecast data management • Process to monitor and improvement forecasting accuracy • Provision forecast data to the market Wind power management: Commence consultation on rules, procedures and standards for wind power management. Supply surplus: Further consultation required on a supply surplus protocols.
Update on Wind Power Forecasting On June 23, 2009, the Alberta Electric System Operator issued a Request for Proposal (RFP) for a centralized wind forecasting service in Alberta as part of its continuing efforts to integrate more wind power into Alberta’s Interconnected Electric System. The requirements within the RFP are primarily based on recommendations from the AESO’s Wind Power Forecasting Pilot Project. We received 9 proposals from very experienced wind power forecasters. The RFP is still underway and no vendor has been announced. [email protected]
61850 Based Protection and Control Systems This pilot project was initiated to develop a system of remote units that would transfer fault indicator data from EPCOR’s distribution system to the main Control centre. In providing immediate fault data to control operators, they are better able to identify the fault location and more precisely dispatch Trouble crews; resulting in faster system restoration times and therefore shorter customer outages.
In 2008, EPCOR completed the implementation of this pilot project, which saw 50 Remote Fault Indication (RFI) units installed on the southern portion of EPCOR’s underground residential distribution system. No further installations have been completed in 2009, as it was decided to conduct an engineering review to observe and evaluate the performance and viability of the new system.
One issue that has been encountered is that a few of the units have been found to go dormant and stop communicating. Each of the units is programmed to send a health signal to the SCADA system every three days. Using this, an independent SCADA program was created to monitor these calls, which sends an indication to the EPCOR control centre if a RFI unit is dormant for longer than six days. This data is then passed to field operations for investigation and repair, as required.
In almost all cases, the root of this problem has been the battery power supplies. While the logic and functionality of the RFI units has proven effective, the batteries have shown to have a shorter than expected life-span and tend to perform poorly in extreme weather conditions. This has become the primary concern with the project: providing a reliable power source for the units, that is both robust and cost effective. As a result, EPCOR is now reviewing alternate power supply solutions. Of greatest interest is a battery pack with a temperature compensated battery charger. The charger itself would be supplied either by bringing a secondary 120VAC feed, if available, or via a voltage sensor bushing within the cubicle. This solution promises higher reliability and will save on the high cost of field maintenance and battery replacements.
Moving forward, when a viable and economical power supply system is found, the existing 50 RFI units will be retrofitted and an additional 35 RFI units are scheduled for installation in the northern section of EPCOR’s underground residential distribution system. [email protected]
ATCO is finally planning to look at the 61850 based protection and control systems. We are in the process of selecting a new design for the substation standard and we will be reviewing this system starting next month. We had not anticipated on using this for another 2 years yet; however the benefit of reduced wiring and common standards across various vendors is pushing the development faster than we thought. So we are looking at testing the 6150 platforms for the substation inter-device communications. We will check for the compatibility between various vendors, various devices and its flexibility and ease of implementation. Our biggest benefit we hope for is that this language or protocol will stay an industry standard for 15years or more. This gives us great benefits in reduced training and engineering costs, as well as interoperability and thus better information exchange between different protection and control devices, which previously was either through wiring or protocols plagued with incompatibility and obsolescence problems, just within a few years. [email protected]
ALTALINK installed the Dynamic Thermal Line Rating (DTLR) system from The Valley Group (TVG) on 170L, between the Peigan (59S) and Pincher Creek (396S) substations. The installation was done as a pilot to ensure that this system would integrate into AltaLink’s system and provide a safe and reliable increase to the thermal line rating capacity of the line.
This pilot allowed AltaLink and the AESO to gain clarity on the complexity of the DTLR system as there were many challenges in trying to integrate the system fully.A number of modifications were required to integrate TVG’s DTLR system into AltaLink’s infrastructure. These included automatic seasonal limits, dual rating thresholds, modified shutdown routine, pre-initialization of points.
• Loss of communication between the CAT units and the RTU occurred several times a day. Reconfiguration of the CAT units was completed to address this.
• Bi-monthly EMS database updates, still today, cause issues with the DTLR program, and require manual notification to rundown generation in the area.
• ICW still needs to be installed as a Windows service rather than an application to meet NERC requirements.
• TVG’s system had never been installed in an area that experiences the temperature ranges and wind that are experienced near 170L. Winds parallel to the line can cause errors 0.3% of the time; TVG has proposed a solution to this problem, however the cost of the solution does not outweigh the benefit in this case. Winds perpendicular to the line currently do not cause error in the MVA measurement because of the maximum MVA limit imposed. However, there is potential for error at higher MVA values and therefore in future installations this is to be examined prior to installation.
• The DTLR system must be physically installed on the line for one year, so that it is properly calibrated, before the dynamic ratings can be applied.
• Jumps in MVA rating caused significant concern – jumps in ratings as much as 50MVA have been seen when switching from a tension based to a temperature based measurement. With work, these have been reduced to a maximum 25MVA jump.
• Any physical change to the line would require a recalibration of the system.• On-going maintenance of the system will cost at a minimum 1200USD per load cell
per year• (7200USD/year for 170L) – TVG must recalibrate the system every 6 months. This
cost does not include any troubleshooting or replacement of any parts of the system.
• Since the ICW machine is essentially a black box and all configuration updates can only be done by TVG, this poses a significant operational risk.
• System complexity itself creates several potential points of failure, which also adds risk.
• There is no redundancy with the load cells or with the ICW machine. If any of these fail, the DTLR system will be turned off.
The DTLR system is best used to provide an option during contingency situations. AltaLink does not see TVGs DTLR as the best solution for temporarily increasing line capacity due to the risk, cost, complexity and potential for errors. (Source of information: Review Report prepared by Marie-France Roy of AltaLink, June 2 2009) [email protected]
AESO Wind Integration Update
Display Another issue that has recently emerged relates to some AMI meter displays resetting, shutting off altogether and in other situations locking up. Initial investigation has shown that this issue is related to power outages, line switches and other power interruptions, most notably due to lightning storms.
Radio Frequency Implementation While the current system of transmitting customer consumption data over the existing power lines successfully meets current requirements, it does not provide enough signal capacity in certain higher density areas to support potential industry requirements such as hourly meter readings. A radio frequency (RF) system of communication, which provides much greater signal capacity, will therefore be implemented in these areas. Automated meters on the RF system transmit data via an ultra high frequency radio signal to collection equipment typically set up on poles or street lights. The data is then transmitted via a 3rd party wide area network, such as Telus, to FortisAlberta’s central computer for billing and other purposes. Installation of RF meters and the required infrastructure is scheduled to begin in early 2010. Residential RF meters will be installed in higher density urban and semi-urban locations starting in Airdrie and Sherwood Park. [email protected]
How do we measure up? More than half of FortisAlberta’s 460,000 customers have received an automated meter, providing daily reads for monthly billing. 99.7% of customers who are connected to an AMI-enabled substation are receiving AMI meter reads for billing within 65 days, exceeding FortisAlberta’s target of 99% for these meters. Since 2007, AMI, as noted in the graphs, consistently outperforms what can be achieved with a manual meter reading system.
AMI Developments Full implementation of AMI meters has been ongoing for just over a year and it is still difficult to gauge the full impact of AMI meters on workload. Customer sites with AMI meters contribute to fewer than 39% of all field Service Investigation Orders (SIOs), even though they represent over half of all meters. Conventionally-metered sites still represent the bulk of SIOs.
Failed Finds Some installed AMI meters have not yet begun to transmit readings and are referred to as failed finds. In some cases, failed finds are isolated in groups of meters fed off the same substation, making it clear that the root cause of the issue lies somewhere between the meter and FortisAlberta (e.g. noise on the power lines, bad grounds, etc.) rather than within the meter itself. Another portion of failed finds can be simply attributed to breakers turned off or services disconnected in such a way as to inhibit the meters’ remote reading capability. Failed finds are an expected challenge of the initial substation commissioning, and as each substation-specific issue is resolved, the number of failed finds steadily declines.
Update on Dynamic Thermal Line Rating
Although electronic meters are inherently more susceptible to power surges, the sporadic nature of the occurrences has made it difficult to pinpoint the exact cause. Since 2007, however, only approximately 600 out of the 250,000 AMI meters installed have needed to be replaced due to a reset issue.
