When storage resources are deployed on the grid to avoid distribution system impacts at particular times, or to offer services at critical times, it is essential that utilities have confidence that they will operate according to the established schedules. The project team surveyed a handful of utilities in states with active ESS markets and utilities in states such as California, New York, and Massachusetts all indicated that they would need adequate assurance that the control systems used by customers would perform as intended.((See, e.g.,NY Interconnection Technical Working Group, Industry & JU, CESIR Analysis Methodology Review for Hybrid PV & Battery Energy Storage Systems (Sept. 9, 2021), https://www3.dps.ny.gov/W/PSCWeb.nsf/96f0fec0b45a3c6485257688006a701a/def2bf0a236b946f85257f71006ac98e/$FILE/2021-09-09%20ITWG%20CESIR%20Analysis%20Methods%20Review%20for%20PV+BES%20Systems%20v1__JU%20Responses.docx [dps.ny.gov]  (“Granting permission for projects to operate outside of operating limits determined by studying worst-case scenarios is dependent on the implementation of advanced operational technologies such as ADMS and DERMS. These systems and associated investments can enable greater utility visibility and control of DER. Ensuring that customer control systems perform as needed is an issue that will need to be addressed as standardization and deployed system configurations reinforce engineering designs and produce expected outcomes, especially with respect to performance during tail events.”).))

Trust in the operational performance of interconnected resources can be established in several ways. Where standards are in place, test protocols have been established, and real-world performance is well understood, acceptance of equipment covered by these standards follows. However, since scheduled operation of energy storage is not yet covered by standards, trust presently must be established in other ways. This section first discusses the need for standards and the likely steps necessary to get standards in place that enable scheduling for storage. It then examines potential alternative methods for establishing confidence in scheduled operation that could be explored while the standards development process is underway.

1. Establishing Standards and Certification for Scheduling Capabilities

One major task for incorporating scheduling into interconnection study processes is the development of standards that describe scheduling of energy storage operations, especially time-specific import and export limitations. Standards do not yet exist today that establish performance requirements for operating schedules within Power Control Systems (PCS) or other technologies. As discussed in Chapter III and Appendix B, the UL 1741 CRD establishes test standards for the export and import control capabilities of PCS. However, under the existing CRD, these limits are static and apply at all times, thus further work is needed to incorporate scheduling functions.

Optimally, the following steps would need to be taken to establish standards to support scheduled operation of ESS and other DERs.

UL 1741, the primary standard for the certification of inverter functionality, would need updating. The UL 1741 Standards Technical Panel has discussed the need for UL 1741 to address scheduled operations and plans to begin working on incorporating PCS scheduling into the standard. The proposed modification to UL 1741 would enable recurring fixed schedules by implementing time-bound values for the export and import limits or operating modes. This process could potentially be completed by mid-to-late-2022, but the development process is open-ended.

A task group has been formed to introduce scheduling into the UL CRD for PCS. The task group has developed a draft scope of scheduling requirements and will work to create test language to evaluate those concepts. This language could be incorporated into the existing proposal for inclusion of PCS tests in UL 1741. The Standards Technical Panel for UL 1741 will eventually vote on whether or how to incorporate this language directly in the UL 1741 standard. The process of testing products for scheduling functionality can be accelerated if UL first updates the CRD for scheduling prior to full incorporation into the standard.

In addition to incorporating scheduling into UL 1741, it may be desirable to update the testing procedures specified by IEEE 1547.1 or other standards to validate operation in compliance with scheduling requirements for non-inverter or non-PCS systems. Because IEEE 1547.1 is based upon the requirements of IEEE 1547, the latter would first need to be updated to include scheduling requirements. The most efficient pathway to testing non-PCS systems is currently unclear, so it is not certain whether IEEE 1547 would take on this task. Other standards could potentially be developed as necessary to support scheduling apart from IEEE 1547 and 1547.1. Additionally, since storage system configurations can vary and often cannot be lab tested as an integrated system, the creation of a validation procedure for field certification by a NRTL, as well as a normalized witness testing methodology for utilities, may facilitate implementation. The process for including schedule capabilities in 1547 and 1547.1 or other standards would likely take multiple years and has not yet begun.

The standards development process may consider many aspects as part of scheduling DER operations beyond import and export power limits. However, at a minimum, for the purposes of interconnections, the standards should address definitions of time-specific import and export limits and tests to verify compliance. One of the challenges to developing standards is that it may be difficult to determine exactly what the standard should be designed to cover, and in what manner, if there have been few pilot deployments or preliminary uses of schedules in the field to inform the standards development process. The following subsections describe some steps regulators can take to help facilitate greater use in the field while the standards development process is underway.

a. Recommendations for Supporting and Accelerating Standards Development

Overall, developing standards for scheduled ESS operations is of critical importance to enabling ESS to avoid interconnection upgrades and to provide critical grid services when they are needed. However, the standards development process is lengthy and it can take multiple years to complete under the best conditions. It also takes additional time once standards are complete for equipment to be tested and deployed in the field, for interconnection procedures to incorporate use of the new standards, and for utilities to gain comfort with evaluating the newly certified equipment. It is very likely that some states will need or desire ESS that can perform according to operating schedules on a much faster timeline than the traditional standards development process can support. For this reason, regulators may want to engage proactively in support of expedited standards development while also supporting the exploration of other methods of providing utilities with assurance of schedule performance.

Although regulators do not have direct control or authority over the standards development bodies or processes, regulators can create a sense of urgency and expectation. Incorporating scheduling functionality into interconnection rules, with implementation dates set based upon standard publication, can provide a powerful signal to the parties participating in the standards development process and can motivate market participants to actively engage to ensure the standards are being developed properly. Regulators can also allow the use of equipment that conforms to proposed or draft standards such as has been done by states in the case of the UL CRD for PCS.

Finally, regulators can support the development of standards by convening working groups to discuss the use of DER schedules and the associated interconnection rules and requirements. These working group processes can be used to better define the specific schedule needs and capabilities which can help ensure that the standards development discussions are supported by information about the real market and regulatory needs. Conducting these working group proceedings concurrently with the standards development process can also enable regulators to put into place interconnection rules that can take full advantage of schedule capabilities once the standards are approved. These working groups will want to both consider the requirements for new projects being proposed with an operating schedule and also any transition issues associated with existing projects shifting toward scheduled operations. Eliminating the lag time between standards completion and the incorporation of those standards into interconnection rules is one process that regulators have direct control over.

2. Alternate Approaches for Safe and Reliable Utilization of Operating Schedules

In light of the potentially long road ahead for the development of standards that govern scheduling performance in the interconnection process, regulators will likely want to consider other methods for providing utilities with adequate assurance of ESS scheduling capabilities.  The BATRIES project team has identified several different approaches that could be explored for enabling safe and reliable use of schedules absent standards. The following subsections discuss the concepts and their potential pros and cons. It is recommended that regulators evaluate these options more thoroughly to identify those that might be most practical to deploy to meet scheduling needs in particular circumstances.

a. Field Testing

Another way to expedite implementation is the parallel development of a field test program to validate performance of a deployed system to a fixed operating schedule or profile. Since storage system configurations can vary and often cannot be lab tested as an integrated system, creation of field test procedures and the establishment of entities to conduct them would enable a wider variety of systems to be validated. The regulator could either actively develop such a test procedure or simply encourage said development. This pathway could potentially be leveraged for field certification by a NRTL. However, due to the cost and complexity of field testing every deployed system, this option would likely only be potentially practical for large systems. This would also still require the development of detailed test specifications.

Additionally, harmonized commissioning testing methodologies for utilities may facilitate implementation. Depending on the level or type of testing available for a given ESS system, more or fewer commissioning steps are needed to validate the installation. These procedures are often determined by utility engineers in consultation with the developer and manufacturer documentation. As no guidance yet exists on how to perform such tests for scheduling functions, developing typical commissioning steps could save effort at the individual utility and/or interconnection level.

b. Regional Test Standard

Regulators can also help to inform the standards development process, while creating a more immediate pathway for scheduled operation of ESS in their state, by developing their own interim testing protocol that can be utilized while national standards are under development. This can be a resource-intensive process to undertake and requires expert input and preferably manufacturer engagement, but it could be valuable for one or more states with a large market to consider development of interim test protocols. Ultimately, manufacturers prefer not to develop multiple bespoke products that need to be tested to different standards, but these initial efforts can help identify scheduling needs and functionalities on a faster schedule than national efforts.

The structure of who performs the tests and who the “certifying body” is could vary. Manufacturers could submit in-house test data to either a utility or potentially a body designated by the regulator which could review the data to ensure the equipment is in compliance. Otherwise, NRTLs could be employed to provide attestations as is normally done with standard test protocols. This can be a time-intensive process both to develop the test protocol (though potentially faster than a full standards process) as well as to verify compliance for bodies that do not normally serve that function. However, since detailed test procedures can be used, the verification is more robust and the process may be seen as more trustworthy.

This type of process has been utilized by Hawaiian Electric to implement their “TrOV-2” qualification which tests for the ability of inverters to avoid damaging load rejection overvoltage. Manufacturers submit their data to the utility along with other certifications and attestations in order to be listed on the qualified equipment list.((The test procedure is based on one developed by the Forum on Inverter Grid Integration Issues and tested by NREL before being adopted by Hawaiian Electric. It eventually served as the basis for the IEEE 1547.1-2020 tests for load rejection overvoltage.))

Early regional developments can inform national standards and test protocol development as parallel activities. In order to enhance this work, pilot programs to investigate and trial the verified fixed operating schedules could be conducted in regions of critical interest. Such programs can help to foster trust in these scheduled operations through demonstration of performance.

c. Monitoring and Backup Control

Either with or without any of the previously mentioned verification strategies, monitoring for compliance with a schedule can be achieved with equipment that is commonly available today. One way this can be done is through the application of a monitoring device that the utility has an interface to. This may be a site controller (or “gateway”), or it may be a utility-owned node, sometimes referred to as a remote terminal unit (RTU). Depending on the monitoring capabilities of the utility, the level of other verification used, or other assurances such as contractual obligations and ramifications for non-compliance, monitoring of compliance may be deemed sufficient to ensure schedules are adhered to. Due to the typically high cost of implementing a communication system, this pathway may only be feasible for large projects. Large projects, however, may already be required to connect to a communications channel (i.e., SCADA or telemetry) as a requirement of interconnection, in which case this may not add significant additional costs. In some instances, cheaper and/or slower communication may be sufficient for the particular use case of monitoring schedule compliance, making it more affordable for smaller systems. However, utilities will need the resources and capability to process all the data.

Utilities may desire more direct control due to a lack of certainty or potential for highly adverse effects due to schedule mis-operation. In this case, similar communications channels may provide for control in addition to monitoring. The RTU may be leveraged where it hierarchically sits above the site control and has the ability to override the site controller in the event that the operating schedule is not followed or if abnormal operating conditions occur. In this way, an RTU can provide assurance to a utility that ESS operations can be prevented from causing negative grid impacts.

Some larger solar and storage projects have used and continue to use customized site controls, such as Real Time Automation Controllers (RTAC) and RTUs to gain acceptance for interconnections that might otherwise have required additional upgrades. For example, the California Independent System Operator certified the SEL RTAC as a remote intelligent gateway serving this purpose in 2015.((Schweitzer Engineering Laboratories, California ISO Certifies SEL RTAC as a Remote Intelligent Gateway (July 23, 2015), https://selinc.com/company/news/111520/.)) These controls are typically built on utility-grade hardware and have to be validated by project-specific agreement with the utility. EPRI is conducting research and development((Electric Power Research Institute, Applications of the Local Distributed Energy Resource (DER) Gateway: Low Cost, Secure DER Network Gateways for Integration of Smart Inverters (June 11, 2021),  https://www.epri.com/research/products/000000003002018673.)) on utility reference gateways for DERs that may help to normalize the specification and lower the cost of such devices.

Protective relay arrangements are also often utilized to prevent negative grid impacts in the event ESS controls do not function correctly. Such relays are well known and trusted by utilities to prevent operations in excess of limits. Even though these additional layers of control and protections can add cost, time, and complexity to a project, they are viable ways of securing interconnections in critical locations. Protective relay schemes, RTUs, RTACs, and other forms of utility-recognized control can be leveraged presently through negotiated interconnection agreements and provide an interim pathway while development of streamlined processes continues.

d. Attestations

Vendor attestations may be an avenue to provide utilities with some performance assurance while standards are in development. This method has been used by some states and utilities in the past to allow manufacturers to “self-certify” that their equipment meets a certain set of requirements. For instance, before certification test requirements were available for PCS, manufacturer attestations (generally signed by an officer of the company) were accepted by the Hawaiian Electric utilities as a means of verifying compliance to be added to the utility’s qualified equipment list. The attestations stated that the equipment complied with Hawaiian Electric’s inadvertent export requirements in Rule 22 Customer Self-Supply. A similar tack was taken by the California investor-owned utilities for certain advanced inverter features in Rule 21 while certification to IEEE 1547.1-2020 was still unavailable.

This is the simplest method of verification and manufacturers that have compliant products can likely turn around signed attestations in much less time than typical certifications through a NRTL. However, since the manufacturers’ capabilities are neither checked against a standard test protocol nor verified by a third party, there are potential risks. Without a detailed test specification, there can be no guarantee that different products behave in similar ways in response to a wide range of conditions. There is no real way around this drawback, but detailed, clear performance requirements can help ensure the required capabilities are not interpreted differently between different companies or individuals. It would be important for manufacturers to take part in the development of the performance requirements to ensure they are well understood by those that will implement them.

Since the manufacturer is providing the attestation, there is no check from a third-party to ensure the equipment capability is actually in line with requirements, potentially leading to equipment mis-operating once installed in the field. Market dynamics may be enough of a deterrent to ensure manufacturers do not willfully misrepresent their equipment. Additionally, if a manufacturer were to intentionally misstate their equipment’s capabilities, the utility could impose compliance penalties on the manufacturer, such as by no longer accepting its attestation.

As discussed above, if one or more states were to pursue this avenue it might provide useful information to inform the standards development process, while also enabling ESS systems to begin providing the benefits associated with operating schedules. 


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