# Kansas State University

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## Electrical & Computer Engineering

### Project 1

Due:

• Individual Report: Monday, September 15, 1997
• Group Report: Monday, September 22, 1997

The objective of this project is to determine benefit/cost of implementing distribution automation(DA) functions. A report containing detailed models for the DA functions is available from your instructor. The list given below contains all the parameters which are required for running PC-ADAM . Typical values of these variables are given in brackets. You have to start by choosing a value for each of these variables based on your own judgment. You may choose a value outside of the suggested values if you desire. If you do so, include a justification in your report. However, this should not discourage you from going outside of the box. Using these values run PC-ADAM to determine benefit/cost of the DA functions. Run sensitivity analysis to find the top ten variables that have the most influence on the benefit/cost ratio. Prepare a report on your findings and submit a copy of this report to me. Also, give a copy of this report to your project partner. It is very possible that your partner obtained very different results. If that is the case, you have to discuss each discrepancy with your partner to arrive at a concensus. This may mean adjusting values of some of the parameters. After you have sorted out all the differences, I would like you to run another case. Based on the results of the final case make recommendations on implementing DA functions in a team report. In particular, I would like a summary describing which functions should be implemented and which should not be implemented and why?

Submit input and output of your runs with the reports. The report can either be submitted via the WWW or in the print form. All of you will be required to make a short oral presentation after the due date.

Note: A distribution system can have any number of substation. A very small town may have only one substation whereas a big city may have many substations. Further, each substation has upto 4 transformers and each transformer has upto 4 feeders. Each feeder feeds 500 to 1000 customers of 6 to 12 kW each. While entering values for the above mentioned variables make sure to enter the total numbers for the systems. For example, if your system has 2 substations with 2 transformers each and each transformer feeding 3 feeders, the total number of feeders in the system is 12. Also, let each feeder feed 800 customers with average diversified demand of 8 kW. Then each feeder will feed a load of 6400 kW and the normal load on each transformer will be 19.2 MW. Generally, transformers are selected with some extra capacity for emergencies. Therefore, the size of the transformer can be selected to be 25 MVA. Typical sizes available for transformers are 9.5 MVA, 20 MVA, 25 MVA, 40 MVA, and 50 MVA. Make sure that you enter the total dollar value of the transformer in the data sheets.

#### Data Form 1: General Utility & Problem Data

D% = the appropriate percentage discount rate for the utility (i.e., the value of money to the utility)[10-12]
FCR% = the percentage fixed charge rate (%) for the utility used to give the levelized annual revenue requirements over YRS.FCR years needed to capitalize an equipment purchase [14-18]
YRS.FCR = the number of years used for amortizing a capital purchase (i.e., the number of years used in the definition of the fixed charge rate %FCR)[10-15]
YRS.STUDY = number of years over which the automation options are to be analyzed [10-15]
NO.SUBS = number of substations in the system under study [1-10]
NO.CKTS = number of feeder circuits in the system under study [1-4 per transformer]
NO.CUST = number of customers served from feeders under study [500-1000 per feeder]
GEN$/KWH = average cost of electrical generation ($/kWh) [$0.015-0.035/ kWh] PGEN$/KW = peak cost of generation facilities per kW as reflected to distribution level ($/kW) [$200-400/kW]
TRA$/KW = peak cost transmission facilities per kW as reflected to distribution system ($/kW) [$40-80/kW] NET$/KWH = average electrical energy cost to the utility customer minus the average generation cost ($/kWh) [$0.02-0.05/kWh]
AVG.DMD = average diversified customer demand (kW) [6-12kW]
LC$/MHR = cost of labor for a line or substation crew ($/man-hour) [$35-$50]
$BASE = purchase and installation costs of base-line equipment, software, and training. This cost generally will increase slightly with the number of automation functions selected ($)[100,000-300,000]
$INTG.DA = the annual value of intangible or unforeseen benefits from having an automated distribution system. This value depends on the mix of automation functions selected.($)[5,000-15,000]
$OM.BASE = annual operating and maintenance expense for the base-line equipment. Software updating costs should also be included in this item. ($/y)[5,000-15,000]
$PLANNING = cost of initial management and technical planning for implementing all selected automation functions. Generally this cost will increase with the number of options. ($)[5,000-15,000]

#### Data Form 2: Annual Escalation Rates

ESCGW = annual escalation rate for the value of customer goodwill, or, equivalently, for the cost of a customer complaint for service interruption or low voltage [2-6]
ESCCAP = annual escalation rate for generation and transmission capacity[2-6]
ESCEQUIP = annual escalation rate for equipment costs[2-6]
ESCLAB = annual escalation rate for labor costs (assumed the same for line crews, substation workers, dispatchers, engineering services, etc.)[2-6]
ESCOM = annual escalation rate for O\&M costs [2-6]
ESCP = annual escalation rate for average energy costs (sales or fuel costs) [2-6]
ESCRPR = annual escalation rate for equipment repair costs [2-6]

#### Data Form 3: Fault Location and Service Restoration (1)

$BASE.AFS = cost of additions to the central base-line equipment needed for fault detection and distribution system restoration ($) [5,000-15,000]
$/AFS = cost of each automated feeder sectionalizing device (including installation and less any salvage value of replaced equipment) ($) [10,000-15,000]
$/SENS = purchase and installation cost of each fault detection sensor ($) [30-150]
$/TRDC = purchase and installation cost of each load transducer ($)[100-300]
$AFS.PGM = incremental cost (above base system) of software for implementing the fault isolation and service restoration option and any associated training ($)[2,000-10,000]
CKT.MILES = total linear circuit miles under automation (mi)[1-6 miles per feeder]
AFS/CKT = number of automated feeder sectionalizing devices installed per feeder circuit [1-4]
LOC/FAULT = number of isolation points per primary fault [1-2]
TRDC/CKT = average number of load transducers per feeder circuit [1-2]
MSWT/CKT = number of non-automated feeder switching devices per circuit [0-2]
SENS/CKT = average number of fault detection sensors per feeder circuit [10-50]
FAIL/CK.MI = average number of faults per year per distribution circuit mile that require restoration effort (faults/y/mi) [0.2-0.4]
%SYS.LOST = average percentage of the distribution system lost during a typical outage (%) [5-20 % of system]
SWTS/FAULT = number of switching operations needed for service restoration per primary feeder fault [2-5]
HR/OUT = average decrease in the outage hours per event afforded by automated system restoration (i.e., difference in outage duration between non-automated and automated system (h)[0.5-2]
INT.COMPL = average number of customer interruption complaints per year per 1000 customers served (without automation) [\# calls per year]
[10-50]
CMPL.RAT = ratio of the number of customer complaints for service interruption with restoration automation to the number without automated restoration [0.2-0.8]

#### Data Form 4: Fault Location and Service Restoration (2)

FAIL/SENS = failure rate per fault detection sensor (no. failures per year) [0.02-0.05]
FAIL/TRDC = failure rate per load transducer (number of failures per year) [0.02-0.05]
FR.ASWT = annual failure rate per automated feeder (failures/y) switching system (failures/year) [0.03-0.05]
FR.MSWT = annual failure rate per non-automated feeder switching system (failures/year) [0.02-0.04]
MHR/ISOL = decrease in the number of dispatcher man-hours needed to isolate a distribution primary feeder fault using automated isolation technology compared to conventional isolation methods (man-hours)[1-5]
OP.MHR/FLT = decrease in the number of dispatcher man-hours needed to locate a distribution feeder primary fault using automated fault-location technology compared to conventional location methods (man-hours)[1-10]
MHR/FAULT = man-hours required to locate distribution feeder fault without the aid of distribution automation (man-hours) [4-10]
MHR/REST = decrease in dispatcher man-hours needed to perform service restoration with automated distribution technology compared to conventional restoration methods (man-hours) [1-5]
$OM/ASWT = annual O\&M cost for each automated feeder switching device ($/y) [20-50]
$OM/MSWT = annual O\&M cost for each non-automated feeder switching device ($/y) [100-200]
$OM/SENS = annual O\&M cost per fault detection sensor ($/y) [2-5]
$OM/TRDC = annual O\&M cost per load transducer ($/y)[5-10]
$RPR/ASWT = repair or replacement cost of a failed automated feeder switching system ($)[50-200]
$RPR/MSWT = repair or replacement cost of a failed non-automated feeder switching system ($)[100-500]
$RPR/SENS = cost of repairing or replacing a failed fault detection sensor ($)[10-50]
$RPR/TRDC = cost of repairing or replacing a failed load transducer ($)[20-80]

#### Data Form 5: Feeder Reconfiguration and Transformer Balancing

The parameters in this {\em Data Form} are use for Option 2, which presupposes that Option 1 has been selected, i.e., Option 2 cannot be used without Option 1.

MHR/SWT = man-hours needed for one manual switching operation of the feeders (man-hours) [2-5]
OPER$/MHR = dispatcher cost to operate the automation system ($/man-hour) [20-30]
$BASE.FRTB = initial cost of software and personnel training needed for automated feeder reconfiguration and transformer balancing functions ($)[2,000-10,000]
LOSS% = average power loss per substation in the primary feeders and the substation transformers as a percent of the load (%)[2-5]
REDUCT% = percent reduction in feeder and substation transformer losses as a result of automated feeder reconfiguration capability over and above loss reduction afforded by manual reconfiguration (%)[1-10]
MHR/RECON = decrease in the number of dispatcher man-hours to perform feeder reconfiguration with the aid of an automated distribution system compared to conventional reconfiguration methods (man-hours)[2-8]
RECON/Y = average number of manual reconfigurations per feeder circuit per year (/y)[0.1-1]
SWTS/RECON = average number of manual switching operations required per feeder reconfiguration [2-5]
FR.HRS/YR = estimated number of hours per year automated feeder reconfiguration and load balancing is in effect (hrs/y)[4,000-8,760]

#### Data Form 6:Extension of Transformer Lifetimes

NO.XFRS = number of substation transformers whose load could be better controlled when remote temperature sensors are installed [1-4 per substation]
$BASE.XFR = initial incremental cost of software and training (above base-line costs) for transformer overload analysis ($)[1,000-8,000]
$SENS/XFR = purchase and installation costs of overload sensors (and any associated communication equipment) for each substation transformer ($)[1,000-5,000]
$/XFR = purchase cost of a new replacement substation transformer when an old one reaches end of life (fails) ($) [$18,000-24,000/MVA]$INSTL/XFR = installation cost for a new substation transformer and for removing the old transformer ($) [$8,000-15,000]
XFR.LIFE = expected substation transformer lifetime (y) [25-35]
LIFE.EXT = expected total life extension (in years) due to overload prevention actions [1-6]
$OM/XSENS = annual O\&M cost for testing and maintaining transformer sensors used for overload protection including repair costs of failed sensors ($/y)[100-500]

#### Data Form 7: Recloser/Breaker Monitor/Control

NO.AR = number of digital automated reclosing (AR) systems used to replace existing conventional electro-mechanical or electronic systems [1-2 per feeder]
$BASE.AR = initial incremental cost for specialized software and training over base-line costs to implement the automated breaker reclosing function ($)[1,000-8,000]
$/AR = initial purchase and installation cost of each digital automatic reclosing (AR) system (less any salvage value of replaced conventional system) ($) [$1,000-5,000]$/RESET = cost of resetting the timing on a conventional electro-mechanical or electronic relay for substation breakers ($)[$20-50]
$/BR.RECON = cost of reconditioning a breaker at a substation ($) [$5,000-15,000] RESET/Y = frequency with which each conventional electro-mechanical or electronic relays are reset (resets/y/ relay) [0.1-0.3] DEL.RECON = decrease in reconditioning frequency per breaker afforded by monitoring of breaker operation history (= number of refurbishments per year without monitoring minus the number of refurbishments per year with monitoring) (number/y/breaker) [0.05-0.1] F.AR/Y = yearly failure rate per automated system for breaker control (failures/y) [0.03-.05] F.EMR/Y = yearly failure rate per conventional electro-mechanical or electronic reclosing system (failures/y) [0.02-0.04] OM$/AR = yearly O\&M costs per automated system for breaker control ($/y)[20-50] OM$/EMR = yearly O\&M costs per conventional electro-mechanical or electronic reclosing system ($/y)[40-100]$RPR/AR = repair cost for a automated system for breaker control ($) [$100-500]
$RPR/EMR = repair cost for a conventional electro-mechanical or electronic reclosing system ($) [$200-1,000] #### Data Form 8: Capacitor Voltage/Var Control (1) This is the first of two Data Forms specifying parameters for the remote capacitor voltage/var control of Option 5. CAP/SUB = average number of capacitor controllers installed per substation [1-4] CAP/CKT = average number of capacitor controllers per feeder circuit [0.1-1]$BASE.CAP = initial incremental cost of any hardware, software, and training additions to the central base system (above base-line costs) required for automated capacitor control ($) [$4,000-15,000]
$/ACAP = purchase and installation cost of automated capacitor controller (less salvage value, if any, of replaced controller) ($) [$1,000-5,000] KW.CAP/CKT = average difference in losses (kW) between the automated capacitor controlled distribution system and a conventionally controlled system per feeder circuit (kW/circuit) [0.5-2] KWP.CAP/CK = average difference in peak losses (kW) between the automated capacitor controlled distribution system and a conventionally controlled system per feeder circuit (kW/circuit) [1-10] NO.CMPL.LV = average number of customer complaints per year about low voltage per 1000 customers served (without automated capacitor control) [5-20/month] LV.CMPL.C = ratio of number of customer complaints for low voltage with automated capacitor control to the number received with conventional control. (Conventional regulator control is assumed for both) [0.1-0.5]$/COMPLNT = cost per customer interruption complaint for either an outage or low voltage complaint ($) [$50-200]
$/CAP.FAIL = incremental value of early automated detection of a failed feeder capacitor bank or controller compared to conventional detection methods ($) [$500-2000]$/S.CAP.F = incremental value of early automated detection of a failed substation capacitor bank or controller compared to conventional detection methods ($) [$2,000-6,000]
F.ACAP/Y = yearly failure rate for automated capacitor controller and sensor (failures/y) [0.03-0.05]
FAIL/CAP/Y = yearly failure rate for a conventional capacitor assembly (controller and switch) (failures per year) [0.04-0.10]
F.CAP/Y = yearly failure rate for conventional capacitor controller and sensor (failures/y) [0.02-0.04]

#### Data Form 9: Capacitor Voltage/Var Control (2)

This {\em Data Form} is a continuation of the data needed for Option 5, the remote capacitor voltage/var control function.

$OM/ACAP = annual O&M cost per automated capacitor assembly (controller and sensor) ($/y) [50-200]
$OM/CAP = annual O&M cost per conventional capacitor assembly (controller and sensor) ($/y) [100-400]
$RPR/ACAP = repair/replacement cost for a failed automated capacitor system (controller and sensor) ($) [$500-2,000]$RPR/CAP = repair/replacement cost for a failed conventional capacitor system (controller and sensor) ($) [$1,000-3,000]

#### Data Form 10: Regulator Voltage Control

Data for Option 6 (remote regulator voltage control) is entered in this Data Menu . Note this option assumes that Option 5 has been selected as well.

REGS/CKT = average number of regulator controllers per feeder circuit [0.1-0.3]
$/REG = initial purchase and installation cost per automated regulator controller (less salvage value, if any, of replaced controller) ($) [$1,000-4,000]$BASE.REG = incremental initial cost of hardware, software, and training additions (above base-line costs) needed to provide automated regulator control ($) [$2,000-8,000]
LV.CMPL.R = ratio of number of customer complaints for low voltage with automated regulator control to the number received with conventional regulator control (Automated capacitor control is assumed for both) [0.1-0.5]
$/VISIT = cost of a visit to a substation to change transformer taps or to override automatic local controllers ($) [$50-200] VSTS.REG/Y = average number of visits to each substation in a year that could be avoided with automated regulator control [2-10]$OM/AREG = annual O&M cost per automated regulator assembly (controller and sensor) ($/y)[$50-200]
$OM/REG = annual O&M cost per conventional regulator assembly (controller and sensor) ($/y) [$100-300]$RPR/AREG = repair/replacement cost for a failed automated regulator assembly (controller and sensor) ($)[$200-1,000]
$RPR/REG = repair/replacement cost for a failed conventional regulator assembly (controller and sensor) ($) [$500-2,000] F.AREG/Y = yearly failure rate for automated regulator controller and sensor (failures/y) [0.03-0.05] F.REG/Y = yearly failure rate for conventional regulator controller (failures/y) [0.02-0.04] #### Data Form 11: Automated Transformer LTC Control XFRS/SUB = average number of power transformers per substation [1-4]$BASE.LTC = initial incremental cost of hardware, software, and training (above base-line costs) needed to implement the automated LTC function ($)[$2,000-10,000]
$/ALTC = purchase and installation cost of each automated controller for a load tap changer on a substation transformer (less any salvage of replaced controls) ($)[$2,000-8,000] F.ALTC/Y = yearly failure rate for automated LTC controller and sensor (failures/y) [0.03-0.05] F.LTC/Y = yearly failure rate for conventional LTC controller (failures/y) [0.02-0.04] VSTS.LTC/Y = average number of visits to each substation in a year that could be avoided with automated LTC control [2-10]$OM/ALTC = annual O&M cost per automated LTC controller-sensor assembly ($/y)[50-200]$OM/LTC = annual O&M cost per conventional LTC controller assembly ($/y) [100-400]$RPR/ALTC = repair/replacement cost for a failed automated LTC controller-sensor system ($) [$200-1,000]
$RPR/LTC = repair/replacement cost for a failed conventional LTC controller-sensor system ($) [$500-2000] #### Data Form 12: Distribution System Monitoring (1) This is the first of two {\em Data Forms} for Option 8, the remote monitoring of the distribution system.$BASE.SM = purchase, installation, and training costs (above base line costs) needed to add distribution system monitoring. This cost depends on the mix of the three suboptions (ADF, DLM, and DL) selected. ($)[$5,000-15,000]
$ADF/NODE = installation and purchase cost of analog data freeze transducers at each measurement node or location ($)[$2,000-8,000]$DL/NODE = installation and purchase cost of data logging transducers at each measurement node or location ($)[$2,000-8,000]
$DLM/NODE = installation and purchase cost of distribution line monitoring transducers at each measurement node or location ($) [$2,000-8,000] MHR/DL = man-hours per substation visit required to retrieve data when there is no automated data logging subfunction (h) [1-5] MHR/DLM = man-hours per substation visit required to retrieve data when there is no automated distribution line monitoring subfunction (h) [1-5]$SUB/MHR = substation operator rate ($/man-hour) [$20-35]
DLM.VSTS/Y = estimated number of visits per year per substation that the distribution line monitoring subfunction would eliminate [10-100]
DL.VSTS/Y = estimated number of visits per year per substation that the data logging subfunction would eliminate [10-100]
$P.ADF/SUB = estimated worth for planning purposes of data from the analog data freeze (ADF) function per year per substation ($/y)[1,000-10,000]
$P.DLM/SUB = estimated worth for planning purposes of data from the data monitoring (DM) function per year per substation ($/y)[1,000-10,000]
$P.DL/SUB = estimated worth for planning purposes of data from the data logging (DL) function per year per substation ($/y)[1,000-10,000]
ADF/SUB/Y = estimated number of occurrences per substation per year for which the analog data freeze function would be used to help in system restoration [4-12]