The Reemergence of Microgrids - Part 2
Below is the secd part of this paper. The first part was posted yesterday (link below).
1.Integrating Microgrids and Utility Grids
I am going to digress to my comfort zone and consider investor-owned utilities (IOUs) and grid management primarily as they exist in California (where I reside). That is, very large IOUs that are closely regulated by the Public Utility Commission, and smaller publically-owned utilities that participate in IOU/PUC processes. California has a large state-wide Independent System Operator that is involved in these processes. We also have the California Energy Commission that participates and frequently supports regulatory actions with development activities. And (of course) there are several consumer advocate groups that also participate, as do major utility vendors.
Thus all regulatory actions, and projects that lead to processes are large, complex and slow. The good news is most voices are heard and reasonably considered, and most regulatory changes are by consensus.
The main impacts to this document that will come from using the above process as a model is that: (1) we will assume the evolution of the relationships between microgrids and grids will be a rational process; (2) this process and the resulting regulatory framework will serve the best interests society in general; (3) the needs of most stake-holders will be considered, and (4) this process will follow past processes in the way it plays out.
The procedures and environment in other states may be different from the above process.
The table below lists potential stake-holders as well as the benefits that they could derive from a large facility’s microgrid. Note that the facility owner and manager are included for comparison.
Potential Benefits from Microgrid
Facility owner/ manager
Operational and financial efficiency
Low energy cost
High energy reliability
Sustainable business practices
Generation utility or electric service provider (ESP)
Financial success, sales of electricity
Offerings with the flexibility to maximize the value of on- and off-site energy production and storage
Potential collaboration in developing on-site energy and tighter relationship with facility owner/manager
Distribution electric utility
Financial success, reliability of service, positive public relations
Voltage regulation service
Defer substation upgrades
Transmission electric utility
Financial success, reliability of service, positive public relations
Frequency regulation service
Spinning reserve service
Defer substation upgrades
Alleviate transmission constraints
Grid efficiency and reliability
Same as transmission electric utility
Utility regulator/ PUC/other state government entities
Rate-fairness, public safety, public perception
Model for more efficient energy usage, thus moderating rates
Sustainable electricity & gas delivery
Enhanced public safety
Other electricity users
Low-cost, high availability and quality power
Microgrid functions extended out from facility to support other loads
Voltage regulation service
If we look at all of the secondary stake-holders (that is, all of the above but the facility owner/manager), and the benefits they might derive from the advanced energy system, the common theme is collaboration to extend the benefits of these systems outside of the host facilities.
Microgrids’ operations are generally driven by the following goals:
- Minimizing the average cost of energy
- Assuring reliable energy supply, especially to energy users with the most critical need
- Effective use of renewable energy
In the simplest model these are measured from the viewpoint of the host facility. However, in the prior subsection we introduced the idea that these metrics could extend outside of the facility’s fence-line, and fulfill similar needs by external entities. However methods of collaboration and communication must be defined and codified in order for this collaboration to occur.
There are several questions that need to be answered to define the collaboration methods. These include:
- What is the incentive for the facility owner/manager to provide services for external entities?
- What mechanism will quantify the incentives and services? Specifically:
- What service is to be provided?
- When is it to be provided?
- How is the service measured?
- When and by whom is the incentive to be provided?
- How is the contract defining the above put in place?
- What is the process for:
- Evaluating potential services/incentives to determine if they are beneficial and practical?
- If the above evaluation determines services/incentives are worthy, how is a legal, regulatory and contractual framework created to allow the stake-holders for each service/incentive to implement these?
- For each instance of the delivery of a service and provision of an incentive:
- What triggers the provision of the service?
- Is some negotiation or market for the service and incentive required?
- If not, what entity establishes the metrics for the service and incentive payback?
The current electric-utility model (at least for California) for incenting ongoing behavior and performance of specific activities are via tariffs and one-time incentives. These mechanisms are generally put in place via the actions of the law-makers and regulators acting in conjunction with the regulated utilities, system operator, and other stake-holders. Once a specific incentive is adopted, the regulated utility administers the tariff or incentive payments.
There is one mechanism that seems to follow a different somewhat process. With services that are requested by the system operator (CA-ISO) such as frequency regulation services or spinning reserve, the services must be provided by or through a certified Scheduling Coordinator. For large facilities this will frequently be an electric service provider (ESP), especially if the facility is a Direct Access customer (purchases their electric energy through an ESP). There also appears to be a mechanism for an end energy user to submit virtual bids through Scheduling Coordinator. In order to do this each facility owner/manager needs to register with CA-ISO as a Convergence Bidding Entity.
The subsections below examine some mechanisms that might be used to facilitate collaboration between facility owner/managers and external entities. This collaboration will seek to extend benefits from the microgrids' host facilities to these external entities.
Two types of mechanisms are examined: those that already exist, and can provide a framework for future collaboration, and potential new mechanisms.
Future methods for collaboration among potential energy stake-holders should be reasonable extensions of current methods, and should be largely administered by existing regulated utilities.
126.96.36.199.Existing Demand Charges and Energy Pricing
Existing tariffs, like PG&E’s E20, have peak demand charges and peak-day energy charges to provide strong incentives to reduce a specific facility’s demand during periods when overall demand is high. These can potentially provide incentives for further reductions when on-site generation and/or storage resources are available to offset facility loads.
If we accept the electric utility as the best middleman for extending the benefits of microgrids beyond their consumer-facilities' boundaries, it is reasonable to also accept mechanisms similar to demand charges and dynamic energy pricing for these extensions. The incentives provided by these mechanisms to reduce demand during peak periods currently reduces stress on the grid and the requirement to use expensive peaking resources. These reductions benefit all electric consumers that use the grid.
One possible mechanism would be to allow on-site generation to completely offset the host-facility’s load during critical peaks. There may be other circumstances when a facility’s demand response plus generation resources can allow power to flow back into the grid in a controlled manner.
I do not mean to minimize the administrative or engineering challenges in achieving the above goals. This will take much work to identify a framework that allows both facilities with microgrids and other stake-holders to benefit.
188.8.131.52.Open ADR Protocol
One existing technology can be extended to provide a communication infrastructure for new advanced energy collaboration – the OpenADR Interface. The OpenADR interface was developed by Lawrence Berkeley National Laboratory in 2002, and currently considered to be the primary interface that will be used in the U.S. for all future automated demand response programs. The specification for this interface is currently managed by the OpenADR Alliance. Per their mission statement: “The mission of the OpenADR Alliance is to foster the development, adoption, and compliance of the Open Automated Demand Response (OpenADR) standards through collaboration, education, training, testing and certification.”
The current Version of the OpenADR Specification is 2.0, initially released in 2012. Open ADR uses the Internet Protocol and Web Services (primarily XML) to support all of its applications.
Services provided include:
- Registration of entities that use OpenADR
- Enrollment in OpenADR programs
- Discovery of program rules, reports, etc.
- Notification of an event requiring performance under a transaction
- Distribution of pricing (dynamic price structures)
- Reporting on the state of the response to an event
- Reporting on the availability of a resource to respond to an event
These services are extensible. For instance, new types of programs and events can be defined.
The current version of OpenADR should be able to provide communication for the extension of microgrid functions onto the grid, and if not, straightforward extension of the standard should be able to support this.
The addition of on-site generation and storage can provide a much wider range of response to operational requirements outside of current demand response. Some extensions are suggested below.
Mitigation of spontaneous local overloads or congestion (beyond current energy and demand): The cause and effect of supply/demand imbalances in a given community or neighborhood can be different than those for the grid as a whole, and occur at different times. These might include:
- The loss of a major grid component caused by some combination of natural, accidental and/or intentional (malicious) events
- A local disaster (fire, flooding, etc.)
- Common mode failure of grid components (for instance, loss of one transformer during high ambient temperature, causing high loads on the backup and its eventual failure)
The good news is that these should be very rare events. A large facility with substantial generation and storage should be able to respond to these events with those resources plus extraordinary load reduction to help mitigate the supply imbalance.
Local voltage support service: A sudden change in load on a distribution substation can cause a brief voltage excursion. If one or more feeders are operating close to their capacity, the end-of-line voltage can drop below the regulatory range. A similar scenario can be caused by fluctuation in PV arrays’ output where these have a high penetration in the area served by a substation.
A large facility with fast-responding generation and/or storage could respond to voltage fluctuations by reducing its load (or even injecting power into the grid) to provide voltage support services.
Deferring capital improvements: In the above "local voltage support service", in the absence of support services from facilities, the only remedy for chronic voltage fluctuation is upgrading the feeders or the whole substation. Of course there are many other conditions that would require these upgrades, including:
- Temporary overloads during extraordinary peak demand conditions
- Temporary overloads caused by equipment failures
- Power-factor excursions caused during unusual conditions
Many of these conditions could be mitigated by cooperating large facilities.
Correct power factor using inverter-based energy sources: Many sources of electric energy in facilities use inverters in their output. These include:
- Photovoltaic arrays
- Battery energy storage systems
- Fuel cells
- Some wind turbines
IEEE 1547 requires all facility inverters to operate at unity power factor and not participate in VAR control of the distribution circuit. Yet several studies by EPRI and Caltech/SCE (referenced) have indicated that there are advantages in both power-delivery efficiency and grid stability is using inverter-based VAR control. 
Migration of Services to Smaller Facilities: Most, if not all of the services described in this subsection will be developed and refined in large facilities. However, just as microgrids and payback mechanisms evolve into standard systems suitable for smaller facilities, so will the methods of collaboration.
Furthermore, there is a bridging customer that will provide support for this transition: the multi-facility organization. Many corporations have facilities of different sizes. However many very large corporations are primarily built on smaller facilities (Hilton, McDonald’s, and most grocery store chains for instance). Furthermore, many of these have adopted standard designs for each facility. Also, organizations like municipal governments and school districts have multiple similar facilities in one region. Thus it will be worthwhile to invest in microgrids and roll these out in large volumes with relatively low cost per facility. The total payback is likely to be comparable to larger facilities, and the overall cost of implementation in the same range.
Frequency Regulation and Spinning Reserve Services: There are rather elaborate procedures for bidding into these markets currently (described at the end of section 4.2). An alternative is suggested: a facility’s resources be made available to the local utility (and, in turn, the ISO) through a tariff-based mechanism where payments are paid to make the resources available and additional payments are provided if the resources are used.
 California Independent System Operator Corporation Fifth Replacement FERC Electric Tariff, Dec 3, 2013, Section 4.14.
 Masoud Farivar and Steven H. Low, Department of Electrical Engineering, California Institute of Technology; K. Mani Chandy, Department of Computer Science, California Institute of Technology; Christopher R. Clarkey, Southern California Edison, Rosemead, CA; “Inverter VAR Control for Distribution Systems with Renewables”, 2011.
 Masoud Farivary, Southern California Edison, Rosemead, CA, USA and Department of Electrical Engineering, Caltech, CA, USA; Russell Nealy and Christopher Clarke y, Southern California Edison, Rosemead, C; Steven Low, Department of Electrical Engineering, Caltech, CA; “Optimal Inverter VAR Control in Distribution Systems with High PV Penetration”, December, 2011.
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