Substation Monitoring By the Numbers
Kansas City Power & Light Co. (KCP&L, Kansas City, Missouri, U.S.) has 169 substations scattered throughout its bi-state service territory. One hundred of these substations require a connection to the company's energy management system (EMS).
Traditionally, the information transmitted from the substations to the EMS has focused around real-time operations and not around ongoing maintenance and operations activities. However, as equipment loads are reaching levels never before experienced, equipment replacement costs are increasing as well. These constricting factors, along with manpower and equipment expertise considerations, led KCP&L to the decision to use developing technologies to better maintain and operate its substation system.
The best solution to deal with these issues is to install a substation monitoring system. Such a system provides the necessary information to allow KCP&L to make near-real-time decisions about operations, which enables the best use of the utility's maintenance dollars and manpower. However, at this point, KCP&L had not yet developed justification for the system.
The utility's need for the monitoring system was apparent, so the requirements were ascertained and the costs compiled. The resultant business case that follows is based on benefits that can be broken down into three categories:
Those that lend themselves to solid economic analysis, such as: reassignment of inspection personnel to more critical tasks; reduced maintenance costs; deferred capital costs associated with load growth; reduced repair costs resulting from the ability to predict major equipment failures; and automated distribution capacitor control (not evaluated in this business case because KCP&L has an existing system already in place).
Those that lend themselves to assumed future savings, including reduced insurance claim cost and reduced lost revenue caused by major equipment failures.
Those that are tangible but difficult to analyze on a solid economic basis, including: increased customer retention and enhanced financial results with performance-based regulation through increased reliability; improved environmental safety and security using video monitoring; enhanced personnel safety through awareness of activity within the substation; optimized design and operating practices; and improved planning for scheduled outages from additional transformer and feeder loading information; and backup provided to EMS at certain locations with the addition of a redundant communications channel and monitoring equipment
The first two categories present an economic analysis. The approach used during this analysis is to quantify the yearly savings and future savings for a target group of six substations. A justification period of 20 years is used for the economic evaluation, with an underlying assumption that all installations will be completed and in service by the end of the first year.
Reassignment of Personnel
KCP&L uses a guideline of one-month intervals for inspecting its substations. The information normally received from these inspections includes:
Physical characteristics of the substation, including open gates, washed-out gravel areas, compromised fence locations and environmental issues.
Transformer temperature, tap-changer operations, including fan/pump functionality, oil levels, oil leaks, ground locations and nitrogen system status.
HV breaker operations, including location of SF
6 bottles, ground conditions, porcelain conditions and hydraulic leaks.LV breaker operations, including relay targets, switchgear voltage and control light condition.
To accomplish monthly system inspections, two employees must spend 90% of their time working on this task. Given the loaded wage of a substation operator electrician (SOE), the cost savings of eliminating these monthly inspections is:
Loaded wage rate: $36 per hour
Number of SOEs: 2
90% of 8 hours per day for one year: 2080 hours × 0.9 = 1872 hours
$36 × 2 × 1872 = $134,784 per year
Reduced Maintenance Costs
The substation department has a maintenance management system (EMPAC) in place to set maintenance schedules for all of the major equipment used throughout KCP&L's system. In addition to the information obtained from substation inspections, the department uses information gained from manual breaker timings to establish maintenance intervals for its substation breakers. This timing requires one SOE and one customer service lineman and takes approximately 39 weeks a year to accomplish. The installation of a monitoring system eliminates about one quarter of this work, as most breakers are remotely timed. The remaining breakers, which have not operated during the inspection period, still have to be manually timed. Given the loaded wages of the two employees involved, the cost savings of this enhancement is:
Loaded wage rate: $36 per hour
Number of employees: 2
25% of 8 hours per day for 39 weeks: 1560 hours × 0.25 = 390 hours
$36 × 2 × 390 = $28,080 per year
Better information about the operating parameters of its breakers and tap changers allows KCP&L to use a more predictive approach to maintenance scheduling. The monitoring system installation lets the utility track additional information about the health of its equipment and allow its EMPAC system to better establish an individual maintenance schedule for each piece of equipment. In general, this system allows KCP&L to shift the time component of its maintenance guidelines out and permits factors such as fault duty, timing and temperature differential to become the critical components in setting maintenance intervals. The calculations in Table 1 reflect the cost savings of extending KCP&L's maintenance intervals.
Deferred Capital Costs
The ability to use a monitoring system to better track critical indicators associated with major equipment becomes more important as a company's infrastructure ages. The figure on page 22 depicts the age of the transformers currently in service throughout KCP&L's system. Superimposed on this graph is the industry standard for the prediction of transformer failures based on age. The graph indicates that KCP&L has a growing percentage of in-service transformers that fall into the critical category of likely failures. In fact, 37% of the transformers in service today, with a primary voltage of 161 kV or greater, are 30 years of age or older. By industry standards, these transformers are classified as worn out. The lower line graph in Figure 1 indicates that the installation of a monitoring system lowers the likelihood of a transformer failure, thus extending the unit's life.
| Type of Equipment | Existing Yearly Maintenance Cost | Projected Yearly Maintenance Cost | Savings |
|---|---|---|---|
| Oil circuit | $33,696 |
$16,848 |
$16,848 |
| Air circuit | $12,787 |
$7992 |
$4795 |
| Vacuum circuit | $1070 |
$749 |
$321 |
| Total savings for breakers | $21,964 | ||
| Tap changer | $2592 |
$1,814 |
$778 |
| Total savings for breakers and tap changers | $22,742 | ||
Parameters such as thermal aging are not available today. However, through the use of an intelligent monitoring system, valuable information is provided about the cumulative effect of overloading on a transformer's life expectancy. The cost savings of delaying the purchase of a large piece of equipment is significant. The following analysis is based on the ability to delay the purchase of two 30-MVA transformers for four years at different points spread out over the 20-year span of the evaluation period of this business case.
Transformer cost:
Material — $430,000
Installation — $30,000
Assumed replacement years:
without monitoring: 2, 8
with monitoring: 6, 12
Assumed interest rate: 8.25%
Present value without monitoring: $702,026
Present value with monitoring: $511,260
Net cost savings: $190,766 or $20,000 per year
Reduced Repair Costs
One of the most prominent advantages of using a substation monitoring system is its ability to help mitigate the effects of a catastrophic failure of substation equipment. Presently, KCP&L has the ability to detect a slow-evolving fault through devices such as winding temperature gauges and testing methods like dissolved gas analysis. A monitoring system enables us to detect the presence of faults that evolve over a shorter period of time. While there will be some faults of an instantaneous nature that no type of monitoring can detect, an intelligent monitoring system increases KCP&L's ability to lessen the effects of a failure. Even though a failure can be costly, the probability of a failure is small. To evaluate the potential cost impact of the installation of a monitoring system, the utility must calculate the incremental opportunity for such a savings, assuming:
If the fault is major, the unit needs to be removed from service and repairs need to be made on its active parts.
Typical annual failure rates for transformers range from 0.5% for reliable equipment to 3% for problematic equipment. During the last 10 years, KCP&L's failure rate has been 1.2%. A figure of 1% is used for these calculations. Twelve transformers are in the target group.
The level of detection with current sensing devices — gas accumulation relays and hot spot indicators — is 30%.
It is assumed that even a quality monitoring system cannot detect 100% of the remaining 70% of total faults. This calculation assumes that 60% of the remaining faults will be detected.
It is further assumed that 90% of those faults detected with a monitoring system will be non-catastrophic.
Table 2 summarizes the calculations for annual cost savings associated with the installation of a monitoring system for transformers. Average repair costs for transformers in each circumstance are assumed to be:
Non-catastrophic failure — $300,000
Catastrophic failure — $700,000
Early detection — $65,000
| Failure Type | Without Monitoring | With Monitoring |
|---|---|---|
| Non-catastrophic Undetected failure repair cost |
$1890 (0.9 × 0.007 × 300,000) |
$756 (0.9 × 0.0028 × 300,000) |
| Early detection repair cost | $176 (0.9 × 0.003 × 65,000) |
$246 (0.00378 × 65,000) |
| Catastrophic Undetected failure repair cost |
$490 (0.1 × 0.007 × 700,000) |
$196 (0.1 × 0.0028 × 700,000) |
| Early detection repair cost | $20 (0.1 × 0.003 × 65,000) |
$27 (0.00042 × 65,000) |
| Total annualized failure cost | $2576 | $1225 |
| Annual cost savings (per transformer) | $1351 | |
| Total annual cost savings for the 12 subject transformers | $16,212 | |
Reduced Insurance Claim Cost
Historically, insurance claims related to incidents within the substation fence have cost utilities millions of dollars. The addition of a camera that provides near-real-time video of the equipment and its surroundings has several benefits. One major advantage of a camera is the ability for personnel to detect situations that could be dangerous to employees and the public.
For the purposes of this business case, it is assumed that the installation of a monitoring system eliminates one insurance claim during the evaluation period of 20 years. The claim value is conservatively assumed to be $100,000, and the event is assumed to occur eight years into the evaluation period.
Net present value = $53,037 or $5500 per year
Reduced Lost Revenue
One of the negative impacts of a major equipment failure is the interruption of power to and revenues from its customers. In addition to direct loss of revenues, customer claims are also a by-product of these outages. Historically, short interruptions in power caused little more than a nuisance to customers. Today, many operations come to a standstill after a momentary interruption in power. For this study, it is assumed that the installation of a monitoring system eliminates lost revenue and customer claims in the amount of $700 per year over the evaluation period.
Net present value = $6747 or $700 per year
Cost
The cost associated with the installation of a substation monitoring system will vary from substation to substation based on the points to be monitored. The subject of information overload is important to consider. Vendors exist who provide costly systems that include every possible piece of information about the equipment being monitored. The approach suggested here is to install a monitoring system that allows the user to determine what pieces of information are necessary, and then to install the monitoring to support that decision.
Following are some of the features of the monitoring system used for economic evaluation purposes:
Web-based system
Application service provider (ASP) approach to minimize internal IT requirements
Able to bring IT platform inside the utility
Use of low cost, discrete and third-party sensors
Ability to communicate with any distributed network protocol device
Provides a Web-based camera system
Interfaces with multiple communication systems
Intelligent notification system based on user-defined limits and events
Provides user-defined historical trends.
Economic Evaluation
The following assumptions are made about the installation of a monitoring system in six substations with a useful life of 20 years:
One central collection node is required to communicate via 900 MHz radio to those substations that do not presently have a network connection.
The six monitoring systems are installed in year one of the evaluation period.
There is an annual license fee in the amount of $1500 per substation to support the ASP contract. Total cost per year will be $9000.
Annual time required to maintain the monitoring equipment is estimated to be two man-days per year per installation. Total cost per year will be $3600. (Table 3)
Table 4 summarizes the savings associated with this project on a yearly basis. The 20-year net present value of the EVA savings is $899,720, which equates to an overall benefit/cost ratio for the project of 3.13.
KCP&L installed its first Internet-based monitoring system in August 2001 at one of its newer distribution substations. After specifying the project, the utility asked several vendors to bid. In the end, KCP&L awarded the purchase order to Cannon Technologies Inc. (Minneapolis, Minnesota, U.S.), whose price was one-third less than the other competing vendors.
| Installation Component | Cost |
|---|---|
| Basic monitoring system (6) | $240,000 |
| Central collection node (1) | $6000 |
| Installation materials | $48,000 |
| Design engineering (30 man-days) | $13,650 |
| Installation (120 man-days) | $43,200 |
| Field testing (60 engineers/man-days, 125 field/man-days) | $72,300 |
| Total cost | $423,150 |
Cannon's Esubstation product provides an integrated hardware/software system, based on its Yukon
| Evaluation Component | NPV |
|---|---|
| I. Reassignment of inspection personnel | $134,784 |
| II. Reduced maintenance cost | $50,822 |
| III. Deferred capital cost | $20,000 |
| IV. Reduced failure replacement cost | $16,212 |
| V. Reduced insurance claim cost | $5500 |
| VI. Reduced lost revenue | $700 |
| Total yearly savings | $228,018 |
Since its installation, KCP&L has used the system to detect a variety of problems, including incorrect wiring in the transformer tap-changer controls and incorrect wiring in the SF
Now supervisors can go online and view conditions and alarms that exist at the monitored substations and make informed decisions about crew dispatching, work assignments, work priorities and maintenance cycles. KCP&L is in the process of installing Internet-based monitoring systems at eight additional substations located throughout the greater Kansas City area. The utility is also working on a monitoring solution for its smaller, portal substations located in the rural areas that surround the city.
The business case for the installation of a substation monitoring system in existing substations can be compelling. The ability to offset transformer purchases, better predict maintenance schedules and equipment failures, as well as reduce insurance and customer claims, can bring a large payback to a utility willing to consider all aspects of the potential savings from such an installation.
Christopher A. Kurtz earned the bachelor's of science degree in electrical engineering from the University of Missouri at Rolla in 1984 and the master's of business administration degree from Rockhurst University in 1999. He has worked in several areas of the Kansas City Power & Light Co., including substation engineering, dispatching and relaying. Currently, Kurtz is manager of Substation Operations and Maintenance and has overall responsibility for the substations that service the area in and around Kansas City, Missouri. He is a member of IEEE and a registered professional engineer in Missouri.
Chris.Kurtz@kcpl.com
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