Key Challenges faced by Distribution Utilities approaching towards effective Distribution Automation
Presently the distribution utilities across the world are either implementing or has implemented distribution automation solutions for fulfilling one or more of these business objectives:
- Better monitoring & control of their distribution assets
- To reduce their Aggregate Technical and Commercial (AT&C) losses
- As part of their Smart Grid compliance put by the regulation
But in the process of implementing Distribution Automation, they learned the key challenges and issues that need careful consideration at each step of the SCADA/DMS system lifecycle to realize its true benefits.
I will be discussing those issues and challenges in little detail here outlining my experience in this industry. In this paper I will be referring to electric utility specific experiences only.
Supervisory Control and Data Acquisition System (SCADA)
SCADA systems are globally accepted as a means of real-time monitoring and control of electric power systems, particularly for generation, transmission and distribution systems. RTUs (Remote Terminal Units) are used to collect analog and status telemetry data from field devices, as well as communicate control commands to the field devices. Installed at a centralized location, such as the utility control center, are front-end data acquisition equipment, SCADA software, operator GUI (graphical user interface), engineering applications that act on the data, historian software, and other components.
Recent trends in SCADA include providing increased situational awareness through improved GUIs and presentation of data and information; intelligent alarm processing; the utilization of thin clients and web-based clients; improved integration with other engineering and business systems; and enhanced security features.
Distribution Management Systems (DMS)
DMS application assists the distribution operator managing the distribution system operations effectively. DMS is typically associated with receiving real-time status and analog inputs from the distribution system, and the generation of supervisory control commands to various control devices such as distribution breakers, switches and reclosers, switched capacitor banks, voltage regulators, ring main units (RMU's) and on load tap changers (OLTCs) etc.
The importance of DMS will increase as additional amounts of customer generation, energy storage, and demand response are placed on distribution systems. DMS is receiving a lot of attention because it can provide solutions to many challenges distribution organizations face today.
Table 1 below contains a listing of DMS applications, functionality and benefits:
Challenges in the DMS Implementation:
The key issues and challenges faced by the Distribution Utilities are listed below:
- Insufficient Data & it's Quality
- Isolated Utilities IT/OT/ET applications
- Communication Infrastructure
- Modernization of the existing switchgear
- Change of existing business process
- Enterprise wide uniform naming convention
1. Insufficient Data & its Quality
All the baseline Distribution Automation modules need significant electrical network data for doing network analysis in form of load calibration, load flow calculation, short circuit calculations etc. This data needs to be incorporated in network operational model as and when there are changes / updation in the field, for Distribution Automation modules to provide correct proposals / decision making support to network operator.
This aspect is posing potential challenge to a Distribution Utility where lots of network changes are carried out in a daily/weekly/monthly basis. The present need is to pick up the appropriate data from the field source, validate the quality and consistency of the incremental data, populate the data in the central data repository and ensure that all the IT/OT/ET applications are using the updated data.
Present utilities are following Smart business processes for asset data quality and connectivity validation using Personal Digital Assistant (PDA) based application provided to their field staff. For incremental data, field staff is uploading the data directly in the PDA application at site, which checks the validity of data quality and its connectivity based on set business rules. Once the field staff is back in their office they upload the PDA files in the Central data repository.
Figure 1 shows the process of data validation using PDA application:
2. Isolated Utilities IT/OT/ET applications
Presently many utilities across the world are operating with isolated IT/OT/ET applications with multiple data sources. The use of multiple data sources not only increases the effort of data validation but also results in inconsistency in the management reporting via various applications across the utility.
The need for identification and to maintain "Single Source of Truth" for all the data sources has been realized by the global utilities. The evolution of CIM (Common Information Model) is considered to be a significant breakthrough in this direction. Now, global utilities are trying to deploy CIM compliant interfaces / products to integrate its various IT/OT/IT solutions going towards Enterprise Business Architecture.
Legend: IED-Intelligent Electronic Device, LAN-Local Area Network, ERP-Enterprise Resource Planning
3. Communication Infrastructured
Communication infrastructure is one of the prime backbones of distribution automation. The key challenge in this area is to select appropriate communication infrastructure for acquiring various field data based on their criticality, periodicity & volume of data transfer etc.
Presently Global Utilities is looking for an efficient at the same time a cost effective solution for their communication needs. The solution which addresses such a need comes in form of hybrid model comprising of various communication mediums e.g point to point connection via FOT / Copper / Lease Line from service providers, wireless connection via GPRS / CDMA / Radio / V-Sat etc.
Legend: RCS - Remote Communication Server, RTU -- Remote Terminal Unit
While designing the communication schema for a distribution automation project, we shall also consider design of data acquisition / event handling module which comes as part of the SCADA/DMS package. For example : In case the utilities likes to deploy a combination of wired & wireless communication schema, shall be careful about communication delays of the data coming from these communication channels to Central System specially for the time tagged field information.
4. Modernization of the existing switchgear
Every distribution automation project essentially needs modernization of utilities existing switchgear to make that adaptable to automation requirements. This modernization of the existing switchgear comes with heavy capital investments.
Working within the regulated and competitive environment, present utilities is finding this challenging to go for complete automation to start with. Based on the business requirements, utilities identify the strategic locations for automation within their operational area critical to meet the business needs of the customer.
Present automation projects gets executed in various phases, starting with automating the critical locations identified by the utility in the phase 1, realizing the benefits and automating rest of them in subsequent phases with limited capital budget approved by the regulator.
5. Change of existing business process
The Distribution Automation projects also needs significant change in the existing business processes of the utility with support made available for decision making and management reporting.
In the present day's electric utilities, the integrated business process in an automated scenario looks like...
As depicted in the figure 5, an integrated DMS/OMS solution (referred as DOMS Solution) eliminates redundant processes for maintaining the network model and also improves operational efficiencies.
Integration of SCADA and the DOMS permits advanced DMS applications to access data from SCADA, analyze the real-time DOMS network model, and provide increased operator efficiencies.
Integration with other utility systems, such as Geographical Information System (GIS), Mobile Workforce Management (MWFM), Advance Metering Infrastructure (AMI) etc, provide additional means to leverage the available data across the organization.
6. Enterprise wide uniform naming convention
Asset naming convention is one of the key aspects during the deployment of distribution automation solutions across the utility. Normally utility follows several asset naming conventions across its various regional operational units from their inception. But with implementation of distribution automation it necessitates the use of enterprise wide uniform asset naming conventions, which normally poses huge challenge to the utility.
Present utilities follows the below mentioned approach to address the challenge of Uniform Asset Naming Convention across the various IT/OT applications.
Present utilities are following ADH (Asset Data Hierarchy) concept for addressing their need of uniform Enterprise Asset naming convention. For implementation of ADH, utility determines the base application which maintains the source for ADH e.g GIS, SAP or any other asset management applications. The base application maintains all the existing assets as well as assets getting added progressively by the utility. All the other system maps their asset data with this base application to get updates as and when there is a change in the asset base for maintaining uniform asset naming convention.
Today's utilities with increasing focus on improvement of operational efficiency, greater focus on customer satisfaction with control over AT&C losses have adopted one or more approaches listed above to deploy efficient Distribution Automation systems.
References International Standard IEC 61968-1 First Edition 2003-10
International Standard IEC 61968-1 First Edition 2003-10