by Joseph Sottnik, Enspiria Solutions Inc.
Smart grid initiatives are focusing on rebuilding utility infrastructure and the business processes we have become comfortable with during the past century. Advanced metering infrastructure (AMI) and meter data management systems (MDMS) are ripping up the foundations of utility meter reading and billing processes and replacing them with a new foundation akin to the transformation from Ma Bell-era telephone service to the modern wireless.
A Phased Approach to Integration
Let’s get the basics in first. The initial focus must be on the customer information system (CIS). This is not a baby step. Careful planning ensures a smooth upgrade and successful integration between your new AMI head end or MDMS and the CIS.
If you are upgrading your existing CIS—already fraught with risk—you might consider completing that before adding AMI complexities. Why is it complex? The additional data being tracked will be substantial. Your old monthly read provides one meter read per customer each month. The new AMI will capture 720 reads (based on one channel of data read at hourly intervals for 30 days).
Many utilities will opt for more data based on the use of additional channels or shorter intervals. The new requirements associated with data validation, estimation and editing (VEE) will add complexity to this initial deployment.
Utilities should consider phased deployment. There are probably some ancillary integrations you must address, depending on the business needs and specific systems you are buying. The AMI deployment might require geographic positioning system (GPS) locations for meters.
If so, you might need to address asset management or geographic information system (GIS) integrations in this first phase to properly support build out of the AMI communications network and deployment of meters. Key account information must be shared between the system of record (typically CIS) and AMI head end or MDMS. Identifying the data that must be synchronized is lengthy and critical in the initial integration.
If an installation contractor will support the meter deployment, you will have additional integrations to that vendor’s logistical systems. You can add more integrations to phase 1, but there are benefits in keeping phase 1 as simple as possible.
Subsequent phases of your AMI integration could focus on capturing key business benefits, then multiplying benefits based on widespread deployment of AMI meters.
Some systems will require a critical mass of meters before you see any substantial benefits from integration. The outage management system (OMS) is an example. The meter deployment strategy might be based on meter read routes or geographic areas (zip codes). Neither guarantees that you will get complete feeders upgraded with AMI meters early in the deployment.
The ability to resolve down to a localized outage depends on having comprehensive data relating to the connectivity model in the OMS. Many experts say that the benefit of AMI to an OMS is your knowing when customer power has been restored, opposed to knowing that power has been lost via a meter’s last-gasp message. Knowing that power has been restored to all affected customers will preclude the need for additional truck rolls. You’ll need full deployment of new meters over feeders to accurately gauge power restorations.
The table on page 27 lists systems you might want to integrate with your AMI or MDMS. The schedule of efforts has been broken into a fictitious, three-phase project to spread risks and capture benefits of a deployment over two to three years. The figure on page 26 illustrates a sample of integration architecture.
The pace at which AMI technology is evolving is exciting. Most leading providers of this technology have developed their products to meet the custom needs of their first few customers. These customers got custom solutions to their requirements.
As the next generation of AMI adopters surveys the technology landscape, they are specifying requirements that draw on best-of-breed capabilities from all AMI technology providers. The requirements being put in front of suppliers are forcing a convergence of features between suppliers that originally built those custom systems for their first clients. This is great for users and integrators because the feature set of AMI and MDM systems is exploding. It poses some logistical hurdles that must be overcome, however.
The features you might want to implement in your integration might not be available in the current release of AMI head end or MDMS software. Plan for and coordinate a certain amount of vaporware that is in each vendor’s development roadmap. Allow for delivery slips if you expect to take advantage of features being added to the systems you are implementing.
Many utilities are expecting to receive negawatt benefits from AMI deployments as a result of conservation from time-of-use rates, critical peak pricing and demand response programs (rebates or active control of customer loads through usage limiting or device control). This requires that the utility has a critical mass of deployed meters to reap the benefits of widespread conservation. This critical mass might not exist in the early integration phases and might be delayed until meter deployments reach a substantial percentage of your customer counts.
For a utility planning to implement time-of-use rates, it is safe to wait on these particular integrations. If you are implementing meters with remote disconnect capability, you might want to wait to control those disconnects until phase 2 to minimize the step change customer service representatives will encounter.
Measures of success are as varied as the utilities that undertake AMI projects. They will include some financial measures that are generally accepted as objective. Careful planning of deployment schedule will ensure financial benefits are realized early. Coordinate your integrations with this deployment schedule to ensure the systems from which you expect to receive benefits are in place at the right time.
Utilities can’t get too much information to plan deployment and integration effectively. Talk to trusted partners, vendors, other utilities and consultants regarding work they have implemented. Participate in symposia, conventions, webinars and internal workshops to glean knowledge about the complex interfaces utilities will face.
Professional Engineer Joseph Sottnik is a program manager with Enspiria Solutions Inc. He manages large-scale system integration and implementation projects for utilities across North America. He has a master’s degree in systems engineering and a bachelor’s degree in mechanical engineering.