DEFINING THE VALUE OF THE GRID

Transcription

1 INTEGRATING DISTRIBUTED ENERGY RESOURCES WITH THE POWER GRID DEFINING THE VALUE Early in the 20th century, George Westinghouse and Thomas Edison debated and competed on the merits and benefits of AC versus DC. Later, Samuel Insull and Franklin D. Roosevelt sparred over regulatory structure. Today, technology and emerging regulatory policy are allowing the possibility of an integrated grid and transactive energy. The integrated grid uses our legacy electric generation, transmission and distribution systems as a platform for the integration of new distributed energy resource technologies such as demand response, energy storage and distributed generation (DG). The legacy system allows planners and engineers to develop and apply these new technologies that are physically and financially connected to the legacy electric grid at a scale and level of performance otherwise impossible. A safe, reliable and affordable grid is foundational to a robust economy. But does everyone believe that? Can we establish a value for the very system that will make the integrated grid and transactive energy possible? Can we leverage the integration of distributed energy resources and demand response to improve the utilization of grid assets? This paper will: 1. Define DG and how it benefits from the existing grid. 2. Explore the system planning, design, and operational impacts of DG installations. 3. Identify the risks and opportunities these benefits and impacts bring to the grid owner and operators in the future. Defining Distributed Generation DG is defined as a generator that is located close to the particular load that it is intended to serve. General, but non-exclusive, characteristics of these generators include: an operating strategy that supports the served load and interconnection to a distribution or sub-transmission system (138 kv or less). It is a subset of the larger group of resources known as distributed resources or distributed energy resources (DER). Typical DER systems include: Solar photovoltaic (PV) Landfill gas Kenneth B. Bowes Mike Beehler, PE Vice President Vice President Connecticut Light & Power Burns & McDonnell A Northeast Utilities Company Transmission & Distribution Services boweskb@nu.com mbeehler@burnsmcd.com PO Box Ward Parkway Hartford, CT Kansas City, MO PAGE 1 OF 9

2 Waste-to-energy (or biomass) Wind turbine Small hydroelectric Fuel cell Combustion turbine and microturbine Reciprocating engine Other non-generating technologies such as demand response or load reduction technologies or energy storage with thermal, water, compressed air/gas or battery storage Combined heat and power (CHP, or cogeneration) that uses thermal energy in addition to electric generation Vehicle-to-energy (reverse power flow from electric vehicles) There are two primary ways DG benefits from the legacy grid: operational and economic. Operational Benefits for DG Customers The operational benefits of a connection to a distribution system include: reliability, load following capabilities, voltage regulation, reactive power support, harmonic distortion, and frequency regulation. In fact, most DG is incapable of operation without the parallel connection to the utility distribution system. Reliability: A typical utility customer receives reliability better than %. Utilities most often use the System Average Interruption Duration Index (SAIDI) to define what the average customer experiences for minutes of power interruption per year. A SAIDI of less than 120 minutes per year is typical. This highly reliable parallel utility connection can eliminate more than 99% of the potential power interruptions that a standalone DG installation would experience. Thus a highly reliable utility system serves the DG customer with the obvious operational benefit of excellent uptime. Load-Following Capabilities: A parallel utility distribution connection allows the customer load to vary up to and beyond 100% of the DG output limits seamlessly and without regard to solar or wind conditions or fuel availability considerations Voltage Regulation: The low source impedance of the utility service (typically less than 5%) results in a strong source able to handle load steps and motor starts without wide swings in the facility voltage levels. The high source impedance of the DG (typically 20% or higher) results in a weak source prone to voltage fluctuations and flicker when not connected to the parallel utility distribution system. Reactive Power Support: During operation of the DG in parallel with the utility system, the DG may only be generating real power (kw) for consumption and not provide reactive support (kvar 1 ) for internal load requirements. The reactive support may be supplied solely from the utility system or by derating the output of the DG to satisfy the internal customer needs. 1 VAR refers to volt-amp-reactive and is necessary in order to maintain proper power flow and system voltage levels. PAGE 2 OF 9

3 Depending on the generator design, type and loads at the site, this can lead to significant capacity cost savings for the DG. Harmonic Distortion: The lower source impedance of the utility system with respect to harmonics means that nonlinear loads (consumer electronics, computers, phone chargers, compact fluorescent lights, etc.) result in far less voltage distortion than if a standalone DG had to drive them. This leads to a comparatively clean source of power and extends equipment life. Frequency Regulation: A parallel utility distribution connection should hold frequency to within +/-0.5 Hertz except during very unusual system conditions. A DER, if even capable of independent operation, will have difficulty maintaining +/- 2 Hertz of 60 Hertz during load fluctuations. Economic Benefits The economic benefits of a connection to a utility system include: efficiency, optimal sizing cost savings, the ability to deliver excess power to the distribution system, and the ability to receive full backup power and capacity from the distribution system. Efficiency: Operation of the DG in parallel with the utility system will enable benefits to all types of generation sources: solar and wind can operate to maximize their output based upon peak atmospheric conditions; heat engine devices (internal combustion engines and combustion turbines) can operate at a point on their loading curve that saves significant amounts in fuel per kilowatt-hour produced; and in cogeneration and fuel cell applications, the DG can be sized and operated to match the site thermal needs, which significantly improves efficiency. Optimal Sizing Cost Savings: The parallel connection with the utility system allows the DG to be designed with less capacity margin, saving significantly on costs. The DG can be sized for base electric or thermal load, on standard rooftop/inverter configurations for PV, or on standard fuel cell parameters. Therefore, the DG may be sized based upon the optimal equipment costs, and the utility covers any deficiency/excess in capacity or power flows. Ability to Deliver Excess Energy and Receive Energy: The parallel connection to the utility distribution system allows the DG to deliver excess power to the utility during certain times while receiving the full load requirements for power at other times. This bidirectional flow supports the economic viability of most connected DG. Capacity on Demand: Having standby capacity at the full rating of the customer s service entrance equipment 24 hours a day, seven days a week allows the user the flexibility for operating all equipment without concern for DG output capabilities. The ability to start large motor loads or operate multiple types of equipment simultaneously are benefits from the connection to the distribution grid. This connection also allows the customer to maintain DG equipment. PAGE 3 OF 9

4 Effects of DG on the Utility System The system impacts of new DG installations can be subdivided into three areas: distribution planning studies, distribution system design and distribution system operation. Distribution Planning Studies When DG is considered on a distribution system, a large number of possible system impacts must be evaluated and studied as part of the utility distribution planning process. These items include: Equipment that may encounter reverse power flow that affects the operation of the equipment. For example, substation transformers may experience increased heat. Protection and control methods necessary for safe operation and fault mitigation, including the impact(s) on existing system protections as power flows in both directions through protection zones depending upon time of day and generation levels. Metering issues that occur as the output of DG masks the underlying loads on the system. Fault current rating of equipment, more commonly associated with larger generation units, at the point of common coupling. Thermal ratings of utility equipment, which may be stressed as larger power flows occur on traditionally lightly loaded areas (end of line situations). Voltage fluctuations and voltage control, because specific types of DG (like PV) have variable and intermittent output. System VAR control, because most distributed generation provides only real power while absorbing reactive power from the grid. Harmonic injection from inverter-based technologies that may affect overall voltage distortion on the utility system. The transmission system in aggregate, especially as DG exceeds the local loads during portions of the day. The evaluations and studies are necessary to determine the effect of DG on protection and control systems. Fault duty levels can increase with the addition of DG units on the system. Therefore, calculations are performed to determine: the impact on coordination of system protective equipment; the effect higher fault duty levels will have on system arc flash hazard levels; and whether the withstand or interrupting capabilities of system equipment have been exceeded. The presence of DG on the distribution circuit can be adversely affected by normal distribution automation systems such as automatic reclosing, recloser loop schemes and substation automatic bus transfer schemes. As the distribution system becomes more automated to improve reliability and resiliency, DG customers will have to adapt their systems to remain compatible. Automatic reclosing and recloser loop schemes are two methods used to restore customers affected by a temporary outage. In order for these systems to operate properly, DG units in the outage area must recognize PAGE 4 OF 9

5 the interruption and trip off-line to prevent an islanding 2 condition from occurring and to allow the utility to properly restore the area. Some DG units may require additional anti-islanding equipment to ensure that they will trip off-line. Planning studies will determine the need for and type of equipment required for compliance. Anti-islanding protection is required of all DG that could potentially form an unintentional island (a disconnected electric system) with other DG or with other nearby system load. In some cases, information, in the form of a signal, is required from the utility to ensure that the DG can respond to an island that it may otherwise be unable to detect. This signal needs to be transmitted by the owner of the distribution system and received by the DG whenever the interconnected portion of the circuit containing the DG has become separated from the legacy system supply. In order to produce this signal, the system owner may need to gather real-time status indication from one or more line devices along the supplying circuit to account for all potential points of separation. The status information from equipment is required not only for one specific DG, but potentially for other DGs served by the line that requires an anti-island signal. Therefore, while the signal between the utility and the DG is specific to that DG facility, the equipment used to gather the status of in-line utility devices may be required for multiple DG interconnections on the circuit to make the circuit DG compatible. Utility system operations that require modifications because of DG may include substation bus transfer schemes. Substation automatic bus transfer schemes are designed to immediately resupply multiple distribution feeders simultaneously upon loss of a major system component such as a transmission line or a bulk supply transformer. Historically, these occur immediately, without any intentional time delay. This results in a nearly imperceptible momentary outage a fraction of a second in duration. However, rotating generation on the distribution system can be damaged by mechanical stresses caused by this type of short duration outage and rapid re-energizing. Substation control scheme modifications may be required to delay the bus transfer scheme long enough for the generation to trip off-line. Under-frequency load shedding (UFLS) schemes may also be compromised when DG is installed on distribution feeders. UFLS systems are designed to quickly operate in response to a degrading system frequency, an indication that not enough generation is available from the interconnected system to supply the connected system load. The purpose of the UFLS system is to shed (instantaneously disconnect) just enough load to maintain system stability, while retaining a predictable load that can be served by the available generation, preventing a cascading system outage. When DG is added to the system, care must be taken to ensure that any generation on circuits selected to ride through an under-frequency event continue to generate, and do not trip off-line, thereby intensifying the generation-deficient condition. Ensuring this balance is maintained by interconnecting DG units complicates the annual process of administering the UFLS program, a North America 2 System islanding refers to an abnormal situation on the power system where local generation, along with local load, has been separated ( islanded ) by loss of all interconnecting ties to the remaining interconnected power system. PAGE 5 OF 9

6 Electric Reliability Corp. (NERC) compliance issue. These modifications can adversely impact the quality of service to thousands of customers supplied from these substations. Distribution System Design In contrast with past distribution design practice, today s distribution design efforts require detailed review of existing DG systems. When distribution system changes are proposed, the impact of the proposed change must be applied to the DG. In addition to the studies performed during the DG impact study phase, the system owner must also: Maintain an accurate and current assessment of DG installed. Develop and maintain design tools necessary to model DG. Weigh system upgrade impacts to DG versus system benefits. Develop standardized implementation and equipment for DG installations (such as monitoring and control technology). Perform continual research of new DG products and technologies. Determine what criteria and assumptions to use for availability of DG to defer capital capacity investments. Analyze the impacts due to loss of DG from transmission system events such as UFLS and undervoltage load shedding (UVLS). The costs of these additional studies and the costs associated with more expensive distribution system upgrades necessitated by the existence of DG within the distribution system may not be part of a traditional rate design structure. Distribution System Operations DG may also cause system operational challenges. The distribution owner needs to be concerned and watchful of generation systems causing unintentional islanding together, or along with, nearby system load. This is a significant safety concern for field teams. System islanding also causes unstable local system voltages and system frequencies to the affected customers in the islanded system. After local distribution system islanding occurs, for example, it can become virtually impossible for the distribution owner to adequately maintain the required system voltage and frequency specified by state and federal regulatory bodies or codes. In addition to the system islanding concerns, as the amount of DG installed or embedded with the distribution system increases, it becomes increasingly difficult to adequately maintain voltage within acceptable limits. Associated with this issue is the increased wear and tear on legacy distribution system voltage control equipment due to an excessively high number of operations. This effect on the electric distribution system has been identified in modeling. Moreover, when an outage occurs, the DG is also lost. This creates a condition on the distribution system where excessive cold-load pick-up problems may occur. Based upon system modeling, this is especially problematic when the distribution system experiences an under-frequency or under-voltage load shedding event. During PAGE 6 OF 9

7 such an event, the protective relaying on the DG will take the generation offline while maintaining the load at the site. This may create the net effect of worsening the event and its effect on the system. In the past, DG has not been given a priority for system restoration during major events. If the utility changes its distribution system operating priorities more toward a transmission system-centric methodology, it may become necessary to prioritize DG with load in order to maintain system stability. If the utility assumes the generation is in operation for capacity planning, then failure of this generation may adversely affect reliability to other customers. If the utility does not assume this generation is in operation, it will need to build additional distribution capacity into its system that may never be needed, tying up capital that could improve system reliability to other customers. All of these issues can result in utility operations teams devoting increasing amounts of time to monitoring and controlling DG resources. The costs of these additional real-time requirements allocated to monitoring, studying and preventing these undesirable system effects, necessitated by the existence of DG within the distribution system, may not be included in the current rate design structures. Good practices for incorporating new DG into the legacy system might include: 1. Integration of the DG locations within the utility customer information system (CIS) to enable improved communication to the customer. 2. Providing a unique identifying note or symbol for DG in the electronic geographic information system (GIS), to provide a visual indication for all DG on the distribution system. This also allows the DG to be incorporated into the electric system model. 3. Screening all DG installations using an electrical power flow system modelling tool. 4. Developing effective standards for when the distribution system owner will require real-time monitoring and control of DG installations. 5. Establishing limits on the amount/type of interconnected DG in order to maintain safe and reliable service to other nearby customers. Technologies such as volt/var control, energy storage, controllable loads and real-time thermal ratings for equipment may be used effectively to increase the penetration rates of DG. 6. Modifying interconnection agreement provisions to ensure the DG customer is responsible for system operation, maintenance and upgrades. Other components of the integrated grid pose challenges and opportunities as well. Advances in energy storage could dramatically change the operation of the distribution system. Some of these potential benefits are: load leveling for peak load management, frequency regulation and voltage support; reduction of voltage flicker from PV systems; spinning reserve from instantaneous real power injection; and backup or emergency power. This could also lead to new ancillary services on the distribution system similar to what is available at the transmission system level today. In addition, the distribution owner will need to develop control systems, such as an advanced distribution management system (ADMS), which will interface with existing systems. The integration with the outage management system and distribution SCADA systems, to provide real-time optimization of the distribution system while controlling the DG and other DER, can improve service to all customers. The utility has a unique PAGE 7 OF 9

8 opportunity to be seen as enabling the desire of the customer to take advantage of DG value. By aggregating and controlling these resources, the utility could provide a suite of new services that would benefit all customers on the interconnected grid. Conclusion A smooth transition to a more integrated grid can only occur within the context of the legacy grid that has served us safely, reliably and affordably for so many decades. This grid has value! Without it the public policy initiatives and regulatory directives for large penetration rates of distributed generation cannot be achieved. As we continue to invest in the distribution grid by deploying advanced technologies, upgrading decades-old lines and substations, hardening our systems against natural disasters, and improving physical and cyber security of our assets, we provide a platform for the future. That platform will bring many new opportunities for transactive energy and a truly integrated grid. As we develop a successful understanding of how these new resources can be effectively integrated, this new grid will benefit the public policy, regulatory and reliability expectations of many stakeholders. REFERENCES The Integrated Grid, Realizing the Full Value of Central and Distributed Energy Resources, Electric Power Research Institute (EPRI), Palo Alto, Calif., 2014 Common Functions for Smart Inverters, Version 3, Electric Power Research Institute (EPRI), Technical Update, Palo Alto, Calif., February 2014 Benefits Provided to Distributed Generation by a Parallel Utility System Connection, Electric Power Research Institute (EPRI), Palo Alto, Calif., 2003, Final Interim Solar PV Forecast, Independent System Operator New England, Distributed Generation Forecast Working Group, April 2, 2014 Technical Solutions Supporting the Large Scale Integration of Photovoltaic Systems in the Future Distribution Grids, CIRED, 22 nd International Conference on Electricity Distribution, Stockholm, June 2013 From ISO to DSO, Imagining a New Concept An Independent System Operator for the Distribution Network, Rahimi Farrokh, Mokhtari Sasan, Public Utilities Fortnightly, June 2014, pgs Renewable Integrations and their Effects to the Grid, Are You Prepared, Dr. Bernd Koch, IC SG EA MG, Siemens Smart Grid Software Leadership Conference, May 2014 Comments of the Joint Utilities on Track 1 Policy Issues in Response to Questions Posed in the June 4, 2014 Administrative Ruling, Case 14-M-0101, Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, July 18, 2014 PAGE 8 OF 9

9 BIOGRAPHIES Kenneth B. Bowes, Vice President-Engineering for Connecticut Light and Power Company (CL&P), a subsidiary of Northeast Utilities (NU) and Connecticut's largest electric utility, is responsible for engineering activities for the electric distribution system, including: distribution planning, distribution engineering and design, substation engineering, protection and control engineering, telecommunications engineering, and GIS for electric and gas operations. Bowes establishes the reliability, asset management and system resiliency strategies for the annual program development and the five-year capital program. He also manages the distributed generation, microgrid, new technology and R&D activities for the company. Additionally, he executes the System Resiliency Program and the Stamford and Greenwich Infrastructure Improvement Projects. Bowes serves as the lead witness for regulatory proceedings and serves as the CL&P Incident Commander for system restoration activities. A native of New Hampshire, Bowes joined NU in July 1984 in the System Test department. He has held several engineering and management positions in the NU Energy Delivery organizations becoming Director- Transmission and Distribution Maintenance in 1999, Director-Transmission Construction, Test & Maintenance in 2002, Director-Transmission Projects in 2004, Vice President-Customer Operations in 2008, and Vice President of Energy Delivery in Bowes earned a Bachelor of Electrical Engineering degree from the University of New Hampshire and a Master of Electrical Engineering degree from Rensselaer Polytechnic Institute. Bowes is the past chairman of the Edison Electric Institute s Transmission Committee and presently serves on the EEI Transmission and EEI Security Committee. Mike Beehler, PE, Vice President, joined Burns & McDonnell as a senior transmission engineer and project manager in 1995, after 14 years with investor-owned electric utilities in Tucson, Ariz., and Honolulu. In the late 1990s, Beehler developed the application of reliability-centered maintenance to the transmission industry, and in late 2001, he helped lead the company s initial development of the critical infrastructure security practice. Beehler has written and presented several papers on reliability-centered maintenance, security and, in 2003, the application of program management in the transmission industry. Subsequently, Burns & McDonnell has been involved in the program management of numerous projects throughout the United States. Beehler has written and presented extensively about the smart grid and has initiated the Sustainable Electric Energy Design (SEED ) process for substation design. He received his Bachelor of Science degree in civil engineering from the University of Arizona in 1981 and a Master of Business Administration degree from the University of Phoenix in He is a registered professional engineer in eight states, a member of IEEE and a fellow in the American Society of Civil Engineers. PAGE 9 OF 9