Distribution Network Model Readiness For Advanced Distribution Management Systems

Grant Cochenour Senior Engineer

Oklahoma Gas & Electric Energy Corporation Oklahoma City, Oklahoma USA

cochengr@oge.com

Rafael Ochoa, Vijayasekar Rajsekar, Senior Member Smart Grid Practice Area

The Structure Consulting Group Houston, Texas USA

rafael.ochoa@thestructuregroup.com; vijayasekar.rajsekar@thestructuregroup.com

Abstract— This paper addresses the challenges experienced by many utilities during the implementation of an Advanced Distribution Management System (ADMS), especially with incomplete or inaccurate distribution network model data. The authors would like to share their ADMS experience in the implementation of several large projects in the United States. The paper starts by addressing the importance and key issues related to the accuracy of the distribution network model and how it directly affects the implementation of the ADMS. It is very critical for utilities to conduct a thorough data gap-analysis with their existing Geographic Information System (GIS) data model or the corresponding “system of record”. This step is a critical part of the ADMS solution selection process besides validating the accuracy of the utilities’ own GIS network model. The authors have developed a unique distribution network model readiness requirements for advanced distribution application functions such as Automatic Restoration and Switching Analysis (ARSA)/ Fault Localization, Isolation and Service Restoration (FLISR) and Integrated Voltage VAR Control (IVVC). Based on the final data readiness requirements, utilities and the ADMS vendors could agree on a realistic and practical implementation schedule wherein the network model gaps in GIS would be addressed. Index Terms—SCADA systems, Distribution Management Systems

I. INTRODUCTION An Advanced Distribution Management System (ADMS) is

an integrated platform of real-time computer systems comprising of advanced distribution management applications, Distribution Supervisory Control and Data Acquisition (DSCADA) and Outage Management System (OMS) including Trouble Call Management (TCMS) used by operators whose job is to assist in outage identification and restoration of power. An ADMS provides operational and analytical tools that enable an electric utility’s System Operations to efficiently manage the operation of the distribution assets. A typical ADMS coverage will include, at a minimum, starting from the distribution breaker all the way down to the service transformer, including all primary electric lines and equipment. Some ADMS applications may require or would perform better with a

distribution model that starts at the transmission bus inside the substation fence. The inclusion of secondary lines and equipment is uncommon in ADMS models at the present time. The current landscape of ADMS platforms have either evolved from traditional OMS and GIS solutions or from transmission SCADA systems. ADMS platforms based on SCADA has been gaining a large market share due to tighter integration of SCADA and DMS applications with newly developed OMS/ TCMS. Most of the major SCADA-based vendors are pursuing model-based approaches to Distribution Automation and Network Optimisation. Model-based solutions require highly accurate connectivity information of the distribution network combined with significant increases in network state visibility in order to calculate power flows, estimate the network state to “fill-in” visibility gaps, and perform network optimization analyses. The key design challenge of an ADMS is to provide a common graphical user interface with the same look and feel across the three subsystems - OMS, DSCADA and DMS Advanced Applications.

II. GAP ANALYSIS A. Evaluation of Network Model Data

The authors are currently involved in the implementation of several large ADMS in a phased manner, besides successfully completing the implementation of an ADMS at Oklahoma Gas & Electric Company [1, 3]. Utilities who have implemented the model-based solutions have found that the clean-up of their distribution data is a significant undertaking. Giving attention to detail regarding the data requirements is imperative. A risky tendency the authors have seen is to assume that what works for other tools that may use similar models like Distribution Planning may be sufficient. Too often, the assumptions for ADMS are based on past experiences with planning tools and OMS implementations. The margin for error in a planning scenario is typically larger than what can be acceptable for operational purposes. The OMS model only requires a logical connectivity model; there is no need in OMS for a detailed electrical model. But model-based ADMS solutions require significantly more equipment data such as line length, wire size, wire type and phase connectivity. In addition, the current

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vintage of model-based solutions has not evolved to accurately model embedded distributed generation and highly variable loads (e.g., electric vehicles). Without the improved distribution modelling data and an improved ability to model embedded generation and variable loads, the value of advanced distribution applications may be impacted. In addition, the lack of accurate network connectivity information and the corresponding attributes could yield incorrect results from application functions.

B. ADMS Data Readiness Based on the authors’ experience in implementing ADMS,

we have developed a data readiness requirements which can be used as a measure to determine the current preparedness of the utility to realize the benefits and full potential of an ADMS. The readiness requirements could be prepared by conducting a gap analysis of the as-built vs. the as-operated network data. This gap analysis exercise can be undertaken at a planning stage of an ADMS implementation to determine the specific advanced applications which would be utilized. In the early evaluation stages, an effort ought to be made to quantify the effects of data deficiencies. Utilities must decide which deficiencies must be addressed by field survey or inventory and which can be mitigated through “educated” assumptions. As early as possible, effort should be made to test the output of applications that use the model against known test cases and real world data. The authors recommend that, as part of the ADMS vendor selection process, utilities should pick 2-3 typical distribution feeders originating from at least two different substations to execute the necessary modeling exercise. The exercise should be to import and use the geospatial data with the proposed ADMS solution. This step is a critical part of the ADMS solution selection process besides validating the accuracy of the utility’s own GIS network model.

C. Basic Data Requirements The ADMS relies on accurate distribution network data

available on a real-time basis besides the as-built and the as-operated connectivity details. The basic data requirements of an ADMS are:

• Distribution device status for Breakers, Switches, Relays, Capacitor Banks, Regulators, Tap Changer, and Reclosers

• Distribution device and line attributes like impedance, ratings, line lengths, and type of conductor

• Analog electrical values like current, voltage, active/ reactive power, power factor, fault current

• Substation single-line schematics or layout available from data engineering/ modeling tool or imported/ converted from Transmission SCADA systems

• Unique Device IDs of all devices across the ADMS platform

• Network connectivity model as imported from a geospatial database showing the scaled length and orientation

• Outage information and affected areas

D. GIS Data Issues The ADMS maintains a complete network connectivity

model of the as-built network. The ADMS gets its network

connectivity and equipment information (e.g., device attributes) from the GIS. The GIS is the system of record for the as-designed or as-built configuration. An OMS uses the same as-designed or as-built network connectivity model from the GIS. Quality control of the data in the GIS is also very important. The assessment of data deficiencies may reveal gaps in data that is stored, and relationship discrepancies between objects, work flow processes, or between what editors of GIS data can enter and what is actually possible to construct.

Some of the common data problem areas based on the authors’ experience include:

• Inconsistent phasing of devices and transformers with their connected lines

• Customer to transformer connectivity errors • Unknown conductor spacing and conductor style, phase

transposition, and wire sizes for each line segment • Ambiguous connectivity • Zero length line segments • Inaccurate voltage & capacity ratings • Service and step transformer winding connections • Loops between feeders and parallel line segments • Network model starts at the distribution bus instead of

transmission bus • Transformer per unit impedance data and winding ratios

are calculated incorrectly due to off-nominal voltage ratios or are unavailable

• Disconnected features

III. INTERFACES An ADMS is the system of record for the as-operated

network configuration. Through processing inputs from substation SCADA, DA devices and field readings, the ADMS maintains an accurate representation of the as-operated state of the electrical network. The following interfaces and associated data are critical in effectively operating a typical ADMS environment (Refer Fig 1):

• DSCADA – The DSCADA forms the base of an ADMS environment which monitors and controls different distribution sensors and Remote Terminal Units (RTUs). The DSCADA receives analog data like voltage, current, active power, fault current and status information from switch positions, fault-current indicators, and transformer tap position from the devices installed in the primary distribution network. An ADMS cannot keep an accurate record of the as-operated state of the distribution network without an effective DSCADA along with the underlying communications network. The underlying technology of DSCADA is similar to a traditional transmission SCADA system except that the DSCADA is designed to handle a significant number of analog, status and control points from distribution Remote Terminal Units.

Figure 1. Overview of typical ADMS Interfaces • DA Devices – These are the different distribution sensors

and Remote Terminal Units installed on primary and secondary feeders. Typical devices include feeder breakers, reclosers, Fault Current Indicators, voltage regulators, tap changers, capacitor banks, and Bellwether meters. The DSCADA system monitors and controls all DA Devices.

• SCADA/ Energy Management System (EMS) – This system is traditionally referred to as ‘EMS’. The EMS advanced application functions are used by transmission dispatchers to maintain the overall grid security and ensure reliable source of power to all substations and feeders. Currently, the majority of the utilities monitor and control the distribution level from the EMS because the DSCADA is relatively a new system for utilities. With the increasing implementation of Smart Grid technologies like Remote Metering, Load Management and Distributed Generation/ Micro Grids, the utilities are beginning to separate the operations of transmission and distribution (T&D) networks. The first step of this separation is to identify the boundary line where the transmission authority or area of responsibility ends which is typically the secondary side of the sub-transmission transformer, 66 kV and below, while the distribution area of responsibility starts from the outgoing substation feeder breaker and continuing all the way down to the customer premises. The selection of this T&D operational hierarchy is a prerequisite before deciding to implement an ADMS. The existing EMS could be used to monitor and control distribution assets, until a dedicated DSCADA is put in service. Gradually, the monitoring and control of distribution network could be migrated to the ADMS environment thereby giving full authority and control power to the Distribution Control Center.

• GIS – The GIS is a geospatial database containing digitized data covering the utility’s service area and providing a comprehensive asset database. An Enterprise

GIS may contain important utility assets like transmission lines, distribution feeders, transformers, gas lines, substation boundaries, call centers, generation plants, etc. besides land base terrain information like street names, public areas, water bodies, hills, etc. Prior to the implementation of an enterprise-wide GIS, all utilities maintained their spatial data in a customized Computer Aided Design (CAD) environment and had extensive library of tools, interfaces and custom written programs to access and maintain the geospatial data. The GIS is one of the most critical subsystems and interface in operating an ADMS. The GIS is also the source of network connectivity model to OMS. It is very important to have regular updates of network status without making the geospatial data stale. A comprehensive field inventory of distribution assets and importing them to GIS could be undertaken in parallel during the ADMS planning phase since the GIS is the system of record for the as-designed and as-built configuration

• OMS/ TCMS – The OMS/ TCMS are a suite of applications used by distribution operators to identify and manage distribution outages and assist field crew members in restoration of power. The OMS helps in identifying all customers or areas that have experienced outages, prediction and/or locating devices responsible for causing the outage, prioritizing/ managing outage restoration efforts, dissemination and probable estimation time to restore power to affected areas/ customers and finally effective management of outage crews in restoring power at the earliest. Many utilities have standalone or independent OMS in service by having custom built interfaces to EMS and other IT/ OT systems. The OMS requires an accurate as-designed and as-built network connectivity model to effectively manage outage information. The GIS is usually the source of network connectivity model to OMS and regular network update status is very important.

• Customer Information System (CIS) – The CIS is part of the utility’s IT software suite responsible to manage all customer related data like name, physical address, billing information and source of power supply (service transformer feeding the customer premise). The CIS is helpful in maintaining the customer-to-transformer relationship and the identification of priority customers. CIS is usually built into corporate enterprise-wide information network.

• Automated Metering Infrastructure (AMI) – AMI has three types of Smart meters - Feeder, Bellwether and Residential meters. The ADMS requires certain data from feeder and bellwether meters to effectively execute advanced application functions like IVVC, Load Management and FLISR [2]. Bellwether meters are designated as critical measuring points to get feeder loading and voltage levels at a short scanning cycle as compared to regular 15 minute intervals. The analog data from these smart meters could enhance the quality of the

advanced application results by providing more accurate results due to expanded data acquisition coverage.

IV. SUBSTATION MODEL A. Substation Model in GIS

The ADMS advanced applications need to work on an accurate distribution network model to calculate power flows. In order for the results of unbalanced load flow to be accurate, the network source points which the substation should exist in GIS database. Traditionally, many GIS implementations do not have the substation equipment data within the spatial database. Such a network model without accurate source data will not produce correct results for advanced applications like IVVC. In the absence of substation data, the Unbalanced Load Flow analysis (UBLF) algorithm will take a longer time to converge and, often, will not produce good results. Due to this limitation with the GIS data, the ADMS evaluation process should include a checkpoint to verify if the substation data is correctly represented within the spatial database. A remediation exercise is to model substations within the new ADMS database rather than adding in GIS.

B. Substation Model in DMS For the UBLF to converge, the substation as an entity is

modeled within the ADMS database rather than the geospatial database in order to deploy the ADMS in a timely manner. The ADMS substation modeling exercise is usually performed using graphical drawing tools within ADMS environment. Typically, the ADMS substation modeling exercise requires the following substation components:

• SOURCE – newly added source point representing the highest point of the substation

• TRANSFORMER – substation transformers and regulators with all related parameters: impedance ratio, winding connection, Load Tap Changer (LTC)

• SWITCH – such as a circuit breaker or switches that connect the substation model to each feeder

• CAPACITOR – if there are capacitor banks installed in the substation

• NODE – represents the bus bar or connecting point for lines in the substation model

• LINE – line segment connecting the nodes together with the correct length and impedance data

• LOAD – if there are any local spot loads located in the substation model

• METERING – if there is any metering available in DSCADA and defined for the substation then connect it to the substation model.

After a substation is completely modeled in the ADMS

database with all equipment attributes being correctly defined, it is important to develop a GIS post-processing phase to reconcile the incremental GIS update with the new substation boundary. This post-processing phase involves running customized scripts to correctly sync the device IDs, within the substation fence, with that of the larger GIS device information. Without having a correct post processing phase, the recently

modeled substation could get deleted or overwritten with the GIS incremental update

V. ADMS DATA REQUIREMENTS A. Data required for ADMS Advanced Applications

A high level survey of the data required to support the ADMS’ advanced applications such as a UBLF, Fault Location, FLISR, or IVVC is included in Table I. M indicates Mandatory data and D indicates Desirable data.

Table I – Data requirements for Advanced Applications

Network Data FLISR UBLF Fault Location

IVVC

Sequence Impedances for lines, transformers

M M M M

Transmission Bus Equivalent Sequence Impedances

M

Equipment Capacity & Voltage Ratings

M M M

Customer Energy Usage Data

M M M

Min/ Max tap ratios, number of tap steps for transformers (no-load tap and LTC)

M M M M

Transformer and Capacitor Regulation Settings

M M

Transformer Connections M M M M Cap. Bank Size M M M Relay trip settings M M M Fuse sizes M M M Substation Model D D D; equivalent

distribution bus impedances required

M

B. Operational data from SCADA A description of the operational and measurement data

from a SCADA system needed to support the applications calculations in real-time is included in Table II.

Table II – Operational data required from SCADA

Measurement FLISR UBLF IVVC Fault Location

Real & Reactive Power or Current, Voltage & Power Factor

M M M D if ADMS can model pre-fault conditions

Voltage D D D D

Transformer & Regulator Tap Position

D D M D

Fault Current ADMS may need to determine the isolation zone.

NA NA M

Fault Target Requires fault indication from isolation/ restoration devices to determine isolation zone.

NA NA M

Breaker Lockout status

M NA NA NA

Cap. Bank Open/Close Status

D; accurate load flow validation of proposed switching solutions

D; actual status/ modeled status is needed

M NA

C. Quality of Data Utilities have options as to how detailed the modeling is

made. This is dependent on having quality data to model at the specified level of detail and on what an ADMS supports as shown in Table III.

Table III – Quality of required data for ADMS

Data Type Increasing Level of Detail → Line Impedances

Assume same line construction and wire sizes everywhere

Assume balanced transposition; standard structure type for all lines.

Use different impedances for lines based on structure type

Calculate unbalanced sequence impedances with each structure type, wire sizes and known phase rotation.

Transformer Impedances

Assume standard impedances and ratios; positive and zero sequence impedance identical. Include neutral impedances

Use factory test report impedances and nameplate ratios for each specific transformer. Include neutral impedances

Use factory test report impedances and adjust nominal ratio for all no-load tap positions for each transformer. Include neutral impedances.

Use an impedance correction table specifying tested impedances at every no-load tap and LTC tap position.

Customer Energy Usage

Use service transformer KVA rating

Use customer billing records and aggregate to service transformer

Use standard profiles for each customer class. Scale by customer usage and aggregate to transformer

Use specific profiles for each transformer based on actual customer AMI interval usage.

D. Measurement data from SCADA Similarly the utility may have a range of SCADA

measurements available with which to initialize all analysis on the network model as shown in Table IV.

Table IV – Range of data required for ADMS

Measurement Increasing Level of Detail → Real and Reactive Power

3 Φ P & Q at substation transformer

3 Φ P & Q on distribution feeder

Per Φ P & Q at substation transformer/ distribution feeder

Per Φ P & Q inside and outside substation

Transmission Voltage

Assume Balanced; Use local or nearest station measurement

Assumed balanced; Use measurements when available and state estimator for non-measured local voltage

Measure per phase voltage. Use state estimator for non-measured voltages

Fault Current Highest RMS Magnitude

RMS magnitude of each phase or sequence currents

RMS Magnitude and Phase (all line terminals if “looped” topology)

Circuit Breaker Lockout Status

Assume lockout after X seconds of open status

Use status indication from digital or EM relay

Use a status indication from relay and analogs to verify open/ lockout status

Fault Target Include all phases involved and indicate whether ground was involved

VI. CONCLUSIONS

The success of an implementation of an ADMS depends on the data quantity and quality available to feed an ADMS. It is imperative to perform a gap analysis between the data available and the data needed by an ADMS. Without this gap analysis, utilities would not know how much effort it would take to collect or to clean the existing data in order to fully utilize the advanced applications of an ADMS. It is also important to have a long term maintenance plan to continuously update the network model in GIS and ADMS. This paper describes the data needs for a successful implementation of an ADMS.

VII. ACKNOWLEDGMENT The authors gratefully acknowledge the management of

OG&E Energy Corporation and The Structure Consulting Group for all their support and encouragement to publish this paper.

VIII. REFERENCES Papers from Conference Proceedings (Published): [1] Jason Estel, Grant Cochenour and V Rajsekar, “OG&E DMS Going Live” in Distributech Conference, San Diego, California, USA, January 2013 [2] David McLain and V Rajsekar, “SCADA and AMI Integration” in Distributech Conference, San Antonio, Texas USA, February 2011 Unpublished Papers: [3] Grant Cochenour and V Rajsekar, “OG&E DMS Experiences after one year of system operation”, unpublished and to be presented at Distributech Conference, San Antonio, Texas, January 2014