The Infosys Utilities Blog seeks to discuss and answer the industry’s burning Smart Grid questions through the commentary of the industry’s leading Smart Grid and Sustainability experts. This blogging community offers a rich source of fresh new ideas on the planning, design and implementation of solutions for the utility industry of tomorrow.

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March 30, 2011

The Impact of the Economy on Smart Grid...and not the other way around

As part of my blog I intended to profile the economic growth as a result of our efforts to advance our utility infrastructure. Sitting in the front lines on smart grid projects, I theorized that US-based smart grid projects took off on the allocation of ARRA funds in 2009. As smart grid efforts and expenses grew and economic distress persisted, the rationale for these projects lost effectiveness. We then saw the reigning in of future projects and roadmapsfrom 5-10 year plans to a seamingly endless highway stretching 10-15 years.



This is purely conjecture based on my perspective, which is the wonderful thing about blogging. I get to make wild assertions and leave out substantiation. I'd love to leave it at that, but the the engineer in me had to appraise that assessment.

As I sifted through various information sources (in other words "googled") on the economic impact produced by smart grid, I was left wanting for more information. By my accounts, since 2009, I am only able to find only one study that discusses the capital expenditures of utility companies based on smart grid projects and that was published in 2010. Newton-Evans published a report in early 2010 that analyzed the capital expenditures of the various utilities in 2010 and 2011. The important take away was that the majority of utilities increased capital expenditures based on smart grid initiatives. Downside was that the large minority that decreased capital expenditures did so in response to economic concerns.

Unfortunately that report only takes us up to 2010. Since that snapshot in time last year, we have seen multiple potential derailing incidents with smart grid that might skew these capital expenditures. We have seen mounting cost overruns, customer pushback and the effects of a 3 year recession that carried through 2011. I spoke previously about the adoption cycle for smart grid, but the aforementioned incidents in concert with the "chasm" effect of the adoption cycle could be detrimental to progress of smart grid.

There are some great economic reports coming out in April. In my next post I hope to add to this discussion with additional insights and substantiation. I also look forward to any comments in the meantime.

March 18, 2011

GIS as an imperative for a smart Grid

Geographic Information System (GIS) serves two critical purposes beyond what an enterprise asset management (EAM) tool can provide. These two are: spatial location and network connectivity. Whereas EAM owns the physical characteristics of an asset, the needs of a Smart Grid can only be met when GIS and EAM sync together.

From an automation perspective, EMS, DMS, OMS or Substation SCADA can subscribe to the network connectivity built within a GIS. A single spatial data model could form the backbone for managing the operations of the entire grid. GIS typically would be the repository of the "as-built". Real time changes brought about by day-to-day operations shall remain within the smart systems meant for automation until they become permanent changes or as-built.

Implementing this backbone of information flow goes beyond the T&D operations into Customer Service (CS) and Power Procurement (PP). A customer service representative who receives a call from a customer on an individual outage can in real-time view the network issue that caused the outage on a map. Also hovering over the issue on the map the representative can view EAM data describing the work-order with status and expected time of completion.

PP can leverage the combination of GIS and EMS to find the capacity margins of each Transmission circuit for monthly, daily or hourly power scheduling. GIS will have the as-built capacity information for each transmission line and EMS would supplement this with the current load and available margins.

GIS can tie all protection devices - transducers, measuring devices, control circuitry and relays to their geographic location in a substation. Critical equipment drawings and inspection videos could be stored or hyperlinked against the asset representation on a map.

This list can go on, but the message that I'd like to convey is that GIS-EAM together become a complete repository of asset information and have a foundational role to play in building the smart grid information infrastructure.

The following picture was part of a paper-presentation we did at DistribuTECH conference in 2009. It visually depicts the value-impact of GIS across the utility value chain:


Next Generation Integration Architecture for Smarter Grids

This is one of the favorite topic all across the board. Each and every utility is brainstorming and each and every vendor is proposing next generation Integration Architecture.

Reason? Well the roadmap of smart grids begin with integration of heterogeneous applications, systems and blurring line between OT and IT applications and systems. Hence the obvious challenge is what should be the integration architecture to achieve the goal of reaching Smart Grid Vision 20XX (is it 2020 or 2030).

There are several reference architectures available in the market place and each one addresses some unique challenges, but they all go on tangent at some point of time depending on the objective.

I would like to share my thoughts and provide food for thoughts for discussion in this (and perhaps other industry) forum(s).

As per my experience and understanding it is premature to say what will be the next generation integration architecture, but we definitely can say what is required out of the next generation integration architecture. At least my background is not in Enterprise System Architecture hence I will focus more on the requirements rather than suggesting the integration architecure itself. But we at infosys are investing on the next generation integration architecture for smarter grids and I would like to present the thought process behind our next gen integration platform in this and future blogs.

Let's take a step back, and think what is really required here? Few general requirements to name:

1. Interoperability between IT and OT systems and subsystems within IT and OT world

2. Scalability

3. Performance

4. Security

Now are these not the same requirements exist in any integration problem? So what's different? The difference in the context of the Power Systems Domain is that the IT systems as well as OT systems are fragmented due to the fact that many IT systems were developed in-house, almost all of the OT systems have their own legacy. It is getting more complex with the fact that newer concepts and systems are being introduced both in IT as well as OT side of the world in phase-wise approach.

Very soon we will see newer systems with the objective of interoperability but won't be able to interoperate within themselves forget about the legacy systems. OK, some of the reader will say, "This is exactly what we are addressing in newer implementation", but is that 100% correct?

In order to complete current phase of the project on time, aren't we ignoring the interoperability between the integration systems being implemented in a parallel phase or next phase? The schedule and budget pressures have always been the enemy of the interoperability and homogeneous system implementation.

Let's come back to the objective of this blog, to list the properties or requirement of the next generation integration architecture.

  • The integration in smarter grids won't be just based on data exchanges but will have to be based on events that are flowing between the systems and subsystems. Hence the next generation integration architecture must be even centric, i.e. the Complex Event Processing is going to be the key component of the integration architecture.
  • The data coming from the field devices is no longer just the real-time data but also the data relevant to the enterprise systems, hence the integration architecture must support the differentiation of data and information integration based on the following time-line and usage:
    • Near Real-time
    • Real-time
    • Enterprise
  • The time critical data coming from field devices and systems will contain high volume transactional data that means the integration architecture should incorporate the data convergence, aggregation and disaggregation features.
  • Another aspect is the analytics (near real-time and real-time) requirements, hence the integration architecture should provide the data in such a way that it enables analytics to be built seamlessly.
  • The most important part is interoperability. Now this is critical because no matter how much efforts are put in interoperability, we are at least 5-7 years away from the plug and play kind of interoperability. And even that to be achieved the onus is on the integration architecture. Apart from providing support for all interoperability standard based protocols, in my opinion CIM is most important component. The integration architecture should have it's own CIM based data model so that as and when CIM enabled systems are implemented the integration becomes seamless.

Some of the aspects I did not touch in this blog, but I will write more about next generation integration architecture in next blog, hence would like to stop here for the comments, feedback and discussions on this very important topic.

March 12, 2011

Who is your GTO ?

In a recent editorial in the reputed Electric Energy Online (, Michael A. Marullo draws attention towards the fact that Smart Grid initiatives should broaden their base beyond Smart Metering and focus on larger issues. Hence the term for the initiaitves, he suggests, should be "Grid Transformation". Kudos to Michael, yet another very well written article!

 As the Utility industry marches forward with Grid Transformation (or Smart Grid ) initiatives, there is a growing realization that some of the traditional roles and business lines find themselves struggling to make the right decisions in a timely manner. I believe this is one of the many reasons why projects run slow and so many "pilot" projects are done and redone. The traditional organizational boundaries within Utilities are blurring and the roles are overlapping. The data, information and knowledge required to make some of the far-reaching decisions traverse the functional units of Generation, Power Supply, Transmission Distribution, and Customer Service. This is a transformational journey for Utilities as they embrace digital technology to modernize the power grid. The pressure to re-organize or re-align is quite visible. This applies to all Utilities - big or small, private or public, operating in regulated market or competing in a deregulated world.

 Is there, therefore, a need to create a horizontal role that focuses on taking accountability for these cross-unit decisions and providing executive sponsorship to the Grid Transformation programs?  Will it ensure efficiency in decision making if a horizontal cross-unit organization took charge of the integration and introduced new ideas, solutions and services to the traditional business units? More importantly, how do Utilities operationalize the creation of such a role and a team? The responsibilities of the Grid Transformation Officer (GTO) in a Utility could, at the minimum, include -

 1. Ensuring all stakeholders(internal and external) understand the changes introduced through the programs

2. Driving Cross unit collaboration and decision making

3. Defining key performance metrics for the Grid Transformation initiatives

4. Helping business lines define "next" practices and preserving "best" practices

5. Building a long term sustenance plan for the new processes and infrastructure

6. Sponsoring talent management and a partner strategy

While there is no one-size-fits-all for such a critical role, it will have to bring the ability to move faster.

So, who is your GTO ?



March 7, 2011

Power Quality & Voltage Regulation Not Included in AMI Business Cases

I have looked at many AMI business cases filed with the Regulators, but I have yet to see the savings from reduction of truck rollouts to check Power Quality and Voltage Regulations. The main reason given why it so is that until AMI is fully deployed and integrated with other systems, these benefits are still hard to quantify.

Generally a utility does not know about Power Quality (PQ) issues unless someone calls about equipment failure or flickering lights.  Then, they send a technician with Harmonic & Voltage Monitoring equipment to the site to monitor it for some time.  It takes time to collect data, analyze it and find a solution.    Many years ago, when I worked for GE as a design engineer, our Elevator Motors were failing in Miami's tallest Bank building and one can imagine the urgency of the situation.  I installed Dranetz's Power Monitoring equipment to find the problems.  It took us a month to find the problem but today we could have found the problem with a Three Phase AMI Meter and saved lots of time, money and inconvenience.

Today, many three phase meters are capable of capturing THD (Total Harmonic Distortion) and if installed they can send data when the meter sends data and or on demand.  However neither the Head End software provided by AMI vendors nor MDMs have features to accept the PQ data.  This beneficial feature can be added very easily.  When I worked for a company who was providing AMI, we used to discuss it, but we never had enough resources to add such advance functions and always settled for adding simple functions such as adding voltage monitoring and blinks, etc.

Voltage is an important function as a utility has to maintain it with in + 5% (126V to 114V).  Generally the AMI helps monitor the voltage and spot problems immediately.

Also, SAIDI, SAIFI, MAIFI, CAIFI type indices are calculated by collecting data from several collection points such as Substation (SCADA), OMS and Customer Service and is a very cumbersome process. This information is reported to the Regulators.  All of these benefits can be easily quantified and materialized with additional IT tools and Integration.   We will continue to discuss additional benefits in future blogs.