Making a Distribution Automation Business Case—Six Steps to Smart Grid Integration

 

Fred Jennings, R. W. Beck

In 2006 less than 10 percent of U.S. electric service points were equipped with advanced meters and less than 20 percent of distribution feeders were managed with digital automation technology, according the Federal Energy Regulatory Commission.

Forecasting rapid adoption, the Department of Energy’s (DOE’s) “Grid 2030: A National Vision for Electricity’s Second 100 Years” suggests nearly all electricity consumers will be able to customize their energy supplies to suit individual behaviors and needs. The adoption of advanced metering and smart grid technologies is moving rapidly across the nation, and in a February 2010 issue brief, the Edison Foundation estimated that nearly 60 million smart meters will be installed and operable by 2019.

Spurred by $3.4 billion in funding for the Smart Grid Investment Grants program through the American Recovery and Reinvestment Act, advanced meters, smart grid opportunities and the potential for dramatic tariff changes are rapidly headed into mainstream utility operations and customers’ households.

Utilities, commissions and other stakeholders recognize the potential to transform traditional electric system operation. A smarter grid involves digitally automating the entire power supply system, from generation to customer meters and beyond, interacting with in-premise devices and appliances. The promise of energy resiliency, security, quality, reliability, efficiency and lowered costs makes smart grid alluring. Many in the industry often cite the smart grid as a transformational, comprehensive solution that will address myriad ills in the current electrical system.

Implementing these features and harvesting the benefits is challenging because of huge volumes of data and the need to touch many applications across the utility business processes and information technology (IT) landscape, in some instances requiring real-time interfaces. These distribution challenges bring technical risk in having to make strategic bets that hold open the greatest opportunity for future needs as they unfold.

Strategic bets have a down side. The breadth, complexity and costs of IT investments associated with full smart grid deployment demand a careful approach to its business integration into the distribution automation arena.

Step 1: Define the Situation

Understand the current IT landscape and plans. Current IT strategic plans, capital budgets and IT blueprints should identify the current and future landscape available to serve smart grid technology requirements. Smart grid planners should start by broadly understanding:

  • Current and planned systems’ changes, including versions and builds,
  • Vendor support and versions requirements,
  • Planned systems, modules and upgrades,
  • Core architectural changes,
  • Operating platforms,
  • Web architecture strategies, especially integration methods and resources,
  • Data storage and retrieval strategies,
  • Distribution of smart grid data and processes across integrated systems, and
  • Cybersecurity methods and resources.

 

Step 2: Anticipate Benefits

Next, utility managers and executives must evaluate future needs. It is most important to stick with “form follows function” in scoping and sequencing technology and process migration to achieve smart grid capabilities. The IT approach, form, should follow the business need, function. Carefully articulating business needs will clarify business integration demands.

Utilities differ widely in what drives their smart grid and advanced metering infrastructure (AMI) initiatives. Most state regulators are involved in AMI and smart grid initiatives because of the high capital costs and utilities’ concerns over cost recovery. In almost all jurisdictions, smart grid initiatives require commitments to benefits, business case results or specific service offerings. These outcomes define what the specific utility smart grid initiative must accomplish and, in turn, the IT functional requirements and impact on IT and business process integration. Utility executives and smart grid planners must define the benefits:

  • Construct a gap analysis by comparing current capabilities with required future services and benefits.
  • Itemize commitments for delivery of planned services and benefits from smart grid to stakeholders including utility customers, management and regulators.
  • Translate defined features and benefits into discrete service offerings and use cases with a sequence and timeframe for delivery.
  • Define the AMI infrastructure, intelligent sensors, monitoring and control components (hardware, software) that comprise the digital smart grid.

 

With smart grid needs identified, a utility can create the blueprint for implementation.

Step 3: Build the Road Map

When performed well, building an IT road map, similar to a strategic IT plan, creates understanding of necessary information and decision-related tools and systems. This effort develops a concise statement of the functional requirements necessary to meet the smart grid goals and defines deliverables necessary to build the foundation for an integrated IT road map. Typically, as the information needs are vetted internally, they become clear and defined. What begins as an uncoordinated set of competing information and process requirements emerges as a coherent, comprehensive description of the requirements for information systems and their integration.

To build this IT road map, subject matter experts must:

  • Understand mission-critical systems, requisite upgrades and versioning and carefully assess vendor-support capabilities,
  • Forecast data storage requirements, especially for data-intensive applications such as meter data management,
  • Evaluate functional requirements identified by service offerings and use cases,
  • Compare current and planned systems interface initiatives with integration requirements,
  • Evaluate needs for information and decision-support tools and systems and necessary data warehousing,
  • Review each functional need identified in Step 2 and discretely map the information sources, and
  • Highlight the needs and timing for system data exchanges. For example, using smart meters to pinpoint outages requires near real-time interfacing with outage management systems, whereas customer-usage analytics presented via a Web portal is typically available the next day.

 

Step 4: Plan Business Integration

Technical road mapping addresses the critical IT architectural integration needs and is imperative to achieve many smart grid benefits. Business processes that require seamless integration with the new smart grid-related information tools often are overlooked. Business integration is challenging for two reasons. First, it relies on the availability and use of new tools and technology. Second, it requires foresight for how business processes will be conducted when enabled by new, unfamiliar, smart grid capabilities.

To prepare, managers should inventory relevant utility business processes by:

  • Plotting a short, simplified business process map and overlaying where IT systems are or must be integrated into the business processes,
  • Identifying how the use cases and service offerings will function and overlaying them on the processes map to highlight information needs, and
  • Prioritizing the informational systems and tool requirements to support the required offerings.

 

Step 5: Identify CriticalStrategy Decisions

The key to success throughout the first five steps is the development of an IT road map with strategic decisions and long-term outlook. Once the plans are laid out, utilities must identify critical strategy decisions related to the integration approach. Utility executives must weigh in on many important decisions:

  • Itemize core applications and the sustainable supporting architecture.
  • Consider long-term integration strategies such as service-oriented architecture, enterprise service bus (ESB) and enterprise application integration (EAI).
  • Anticipate interactions among numerous smart grid applications and plan a framework that will support unforeseen requirements.
  • Identify which applications will perform what activities (for example, deciding how outage prediction will be handled by the coordinated capability among the AMI head-end, geographic information and outage management systems).
  • Evaluate the scope and scale to determine hardware requirements (for example, determining whether the data warehouse must store AMI data or if it also needs to store, extract, manage and analyze interval data and deliver that intelligence to other enterprise systems).

 

Step 6: Finalize Tools and Systems

Utilities must determine how their strategies define their needs for tools and systems. Service offerings and technical capabilities should mirror a utility’s strategic direction. The Smart Grid Investment Grant program offers utilities the opportunity to extend operational sophistication beyond initial visions, but the DOE financial support also brings the risk of poorly integrated systems. Utilities must be strategic in their business process integration.

During this critical step, utility executives can oversee long-term, integration success by:

  • Articulating how smart grid will serve utility needs and the services it will deliver,
  • Deciding where functionality and data will reside among current and new systems,
  • Promoting adherence to the utility’s frameworks for integration and cybersecurity, and
  • Evaluating vendors’ products individually and within a broader context of all the tools and applications anticipated for the smart grid application.

 

Equally important is addressing business process: the delivery of products and services in an efficient, effective and consistent manner as directed by policies, procedures and structure. IT systems are enablers that must be leveraged and integrated. The opportunity to deploy many systems can bring benefit a utility and its stakeholders, but it also can challenge integration and internal process redesign.

Jennings is an executive consultant at R. W. Beck, an SAIC company. He has 30 years of experience in utility industry program design and implementation, strategic and business planning, and cost and performance management.

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