Supervisory Control and Data Acquisition (SCADA) has been a mainstream mission critical utility real-time system for decades, primarily used to monitor and control the generation and transmission system in real-time. Most utilities did not expand the reach of SCADA down the distribution network, since the operation of radial and ‘passive’ distribution networks was historically straightforward.

Recent changes drive the need for utilities to reevaluate their real-time operational systems strategies and to consider migrating to a common technology solution for transmission and distribution SCADA to support Energy Management Systems (EMS), advanced Distribution Management Systems (DMS) and Outage Management Systems (OMS). Common technology solution refers to a common transmission and distribution SCADA system provided by a single vendor – this can take the form of either a single instance of the vendor’s SCADA software or separate instances of the same vendor’s SCADA software (one for transmission and one for distribution).

Drivers for common SCADA technology include:

• Smart grid technologies provide utilities with the opportunity to gather significantly more data from the transmission and distribution grids.
• New technologies at the customer side of the meter (e.g., electric vehicles and distributed generators) make the distribution network increasing more complex to operate.
• Pressure on utilities to restore power more quickly and minimize customer outages during storms is driving some utilities to install more automated field devices on the feeders to pick up customers on unfaulted sections of the feeders more quickly.
• Advanced DMS power applications such as unbalanced power flow, distribution state estimation, integrated volt/var control, and fault location, isolation, and service restoration are now starting to become important applications in distribution operations to manage, operate, optimize, and restore the grid in real-time.

These changes, along with the effect of such trends as the aging workforce on operations and support, will lead some utilities to consider the benefits and costs of whether or not to consolidate to a common transmission and distribution SCADA system to support EMS, DMS, and OMS. Before considering a move to a common vendor SCADA system solution each utility should revisit their real-time systems roadmap based on their unique situation, answering key questions and assessing potential benefits and costs of a common SCADA system technology approach.

REAL-TIME OPERATIONAL SYSTEMS
SCADA systems have been core utility systems for many years. SCADA systems allow operators in control rooms to monitor the flows in the power system and to remotely control substation equipment, issuing control commands via the utility’s communication network. Other fundamental components of a SCADA system include functionality to alarm abnormal conditions, tag devices for safety and information purposes, and archive real-time data.

The SCADA system communicates with Remote Terminal Units (RTUs) (or substation data concentrators fed by substation intelligent electronic devices) located within substations. Most current deployments of SCADA systems have been used to monitor and control equipment on the transmission and sub-transmission network as well as distribution transformers and feeder head devices located within the substations. However, electric utilities are facing new challenges that may be best addressed by a common technology solution for both transmission and distribution SCADA to support EMS, advanced DMS and OMS.

Energy Management
The energy management system (EMS) manages the operation of the bulk power grid. It is considered a mission critical system since the potential consequences of losing visibility and control of bulk power grid operations are so severe. The SCADA system retrieves the real-time measurements and status conditions reflecting the topology of the power system for use by automatic generation control (AGC) and advanced power network applications such as state estimation, operator power flow, and contingency analysis.

The AGC application uses generator and tie line measurements to adjust generation to match load to maintain the appropriate frequency at 60 Hz while maintaining scheduled tie flows. The SCADA system provides real-time measurements to the state estimator to allow it to compute voltages and flows for the entire power grid including substations that do not have RTUs to provide operators with a picture of the current state of the power system. The state estimator results are then used by the contingency analysis application to run many contingencies (e.g., removing a line or generator, etc.) to provide a picture of what could happen to the power system (e.g., losing a transmission line could create an overload situation on another line), if that contingency occurs.

Distribution Management
Advanced distribution management system power applications such as unbalanced power flow, distribution state estimation, integrated volt/var control, and fault location, isolation, and service restoration are now starting to become important applications in distribution operations to manage, operate, optimize, and restore the grid in real-time.

Many utilities started with pilot projects to get a better understanding of the realizable benefits of advanced distribution management applications such as integrated volt/var optimization, and centralized and distributed control to speed up the process of locating, isolating, and restoring power to unfaulted feeder sections. These pilot projects have shown the potential benefits of these applications, resulting in a number of utilities moving from the pilot stage to full procurement and implementation of DMS to provide distribution operators with visibility and control of their distribution network. The integration of the real time data with data obtained from advanced metering infrastructure (AMI) devices and other feeder devices in some of the pilots has helped to improve the accuracy of fault isolation leading to faster restoration times. The integration of SCADA and DMS into a single system provides the operators with a common user interface to use in restoration of the network. As utilities move to SCADA for distribution and the ability to bring back a significantly larger amount of data, assessing the advantages and disadvantages of using common SCADA technology will be an important action to take.

Outage Management
Recent major storms have created pressure on utilities to implement process changes to restore power more quickly and to minimize customer outages during storms. This is driving some utilities to install more automated field devices. Another trend is the consolidation of separate OMS and DMS into a single fully integrated system. The combined functionality enables the distribution operator to view the latest customer outage information, distribution equipment status information, and crew availability on a single screen, vastly improving overall situational awareness and management of outage events.

Devices being added along the feeders are often connected to the SCADA system to bring back telemetry and provide control. By having a common system for the field devices and the substation, an operator can easily navigate between the two environments without having to deal with the differences in operations. Switching orders generated via the OMS use the SCADA system to issue the control actions for remotely controllable devices.

Smart Grid Technologies
As smart grid technologies continue to be deployed on circuits yielding a plethora of data, the SCADA will interact with RTUs, smart devices, and sensors on the distribution circuits. While AMI will be used separate from the SCADA system to monitor consumption at the customer premises and allow for ‘pinging’ the meter to ensure the customer’s service is restored after an outage, SCADA provides the necessary real-time information to execute generation control, transmission power network analysis, and distribution network analysis applications.

Smart grid data can be used to either supplement or improve the solution of applications designed to monitor and control the power grid. The key element to consider is whether the data can be provided in real time for the applications or for after the fact studies. If in real time, the SCADA system becomes the best vehicle to get the data into the applications already used by the operators. Data not needed from these devices for the real time control of the system is better used by non SCADA systems outside the control room. This data, however, with some manipulation can be used to improve the network models in the EMS and DMS system (for example, in improving the load models of transformers in substations or distribution feeders).

Smart grid also brings increased complexity of the distribution network due to new technologies on the customer side of the meter (e.g., electric vehicles and Distributed Energy Resources (DER)). Much of the activity in distribution grid modernization is centered on DERs, which include distributed generators (DG), distributed renewables (wind and solar power), energy storage units, and controllable loads (i.e., demand response). The distribution SCADA system can provide monitoring and transfer tripping of larger (utility scale) DG units. As the industry gets deeper into managing DERs, the distribution SCADA system will interact with a Distributed Energy Resource Management System (DERMS) that is managing and controlling customer premises equipment (e.g., electric vehicles, solar PV and demand response) which generally do not use SCADA protocols and standards. The advanced distribution power applications in the DMS will need the information from these types of applications directly from SCADA or via an interface between the DERMS and the SCADA for the DERMS to provide the data.

KEY CONSIDERATIONS FOR COMMON SCADA TECHNOLOGY
Utilities have several options for their real-time systems roadmap:

1. Separate SCADA systems from different vendors: A transmission SCADA system for the transmission and sub-transmission network and a distribution SCADA system for the distribution system.
    
2. Common SCADA system technology from the same vendor: This system scans and controls all of the utility’s equipment and provides the data to EMS, DMS or OMS applications that need it. This option also includes running two different instances of the same SCADA vendor technology.

The option that a utility chooses will have impacts on operators, maintenance and support staff, engineers that need to data for reliability studies and after the fact analysis, vendor contract management, and the utility’s cost and flexibility to adapt to changes that will inevitably come about during the entire system life cycle.

Table 1 highlights some of the key considerations that should be evaluated for each SCADA system option as part of a SCADA system roadmap effort. Each utility needs to understand its own needs and priorities by discussing the questions below with a diverse team of staff including operators, business analysts, power network analysts, and support staff. Discussions are needed to understand how the utility priorities align with the benefits and costs of each option and the overall utility vision for its real-time systems over the next decade or more.

Table 1: Key Considerations for Evaluating Common SCADA Technology

 

DEFINING THE SCADA SYSTEM ROADMAP
Key activities for making a decision on which SCADA system option to pursue include understanding business needs, delineating current and future SCADA functions, assessing impacts of each option, and analyzing the benefits (where many benefits may be subjective in nature), as well as developing a good understanding of the life cycle costs. Figure 1 below highlights the components of this decision process.

Figure 1: Approach for Defining SCADA System Roadmap

 

Business Needs
The initial step in the process is to understand the business needs. To do so requires discussions with the utility executives on their vision of the utility’s future, system operators and dispatchers, business analysts, other groups that need SCADA data, operations engineers, power network analysts, and support staff. By identifying and prioritizing the business needs from a diverse set of utility staff, the team can evaluate how well each alternative meets their needs. Developing the business needs requires understanding the business drivers that the utility will be faced with (e.g., need for improved system resiliency, regulatory requirements, resource needs, cost pressures, etc.). Since the SCADA system will need to support the needs of the utility over a long period of time, it is important to understand the short term needs as well as longer term needs.

SCADA Functions
This may seem straightforward since SCADA has been used for many years. However, it is important to understand how SCADA will fit in your plans for the next 10 – 15 years. For example, will you be adding more automated field equipment (smart devices, sensors, Phasor measurement units (PMUs), etc.) that includes the capability to bring back additional measurements or needs to interact with distributed energy controls or microgrid control systems? Will SCADA need to interface to a DERMs? Will SCADA need to provide information for any company initiative related to grid analytics? Will SCADA be tied to components of asset management? These requirements will also include the user preferences on how to visualize the system for situational awareness, intelligent alarming, improved safety coordination and interaction with distributed control systems, automatic “self-healing” applications, and cybersecurity. Each of the SCADA system options needs to be evaluated related to the set of SCADA functions and needs.

Impacts
The questions in Table 1 can be used as a starting point to explore the impacts on the users and support staff as well as the ability to leverage your investments in smart grid technologies cost effectively and efficiently. Understanding the impacts is needed to relate them to benefits and costs of one option versus another.

For instance, will a particular option require additional staff for support resulting in higher life cycle support cost? In assessing the impacts, consider the possible remedies to minimize these impacts. The impact assessment should include a measurement of the degree to which the issue impacts the costs or the benefit. For example, a common set of SCADA maintenance tools will have a significantly higher benefit to the support staff than having different tools to maintain different systems) along with the associated higher costs of two tools versus one.

Benefits and Costs
A good life cycle cost analysis for the two different options needs to be prepared in order to understand the full cost impacts of having a common SCADA system versus separate SCADA systems.

Each SCADA system option will have areas that are of benefit to the utility, based on the utility’s specific needs and requirements. It is important to understand how those benefits align with the utility’s business needs and priorities. It is important to consider benefits that are quantifiable (e.g., reduced cost of maintenance for common versus separate vendor systems) as well as subjective benefits (e.g., ease of use for the operators by using a common user interface). The team needs to also develop the life cycle costs (e.g., maintenance and support costs, staffing costs, etc.) for both options to understand the differences between the two options. By evaluating the benefits and costs of each option, the utility can determine the best option that fits its specific circumstances.

Roadmap
The final roadmap will provide the utility with a path forward for its SCADA system strategy that is aligned with its needs and smart grid vision. The roadmap defines the required actions to execute on the best option for the utility including expected expenditures throughout the expected life of the system. The roadmap will be aligned with the cash flows needed to either have separate SCADA systems or move to a common SCADA system vendor solution and then to keep the SCADA system updated over a defined life cycle period (e.g., 10 years).

SUMMARY
Emerging trends and changing dynamics are affecting how electric utilities monitor, operate, and control their assets. More and more utilities are seeing the potential benefits of DMS and smart grid, with SCADA being a key provider of real-time telemetry. It is a prudent step for utilities to evaluate how SCADA will support their transmission and distribution systems by developing a SCADA strategy that will meet the utility’s needs in the short and long term.

About the Author

Joe Moran is Senior Vice President of Consulting and Design at UISOL, an Alstom Company. He has 29 years of utility industry experience across real-time system technology and strategic planning. Prior to joining UISOL, he led the EMS/SCADA/ DMS and NERC Compliance groups at DNV Kema. Moran holds BS and MS degrees in electrical engineering and an MBA, and is a registered PE.