Reliability Guideline - PPMV for Inverter-Based … Plant Modeling and... · Web viewThe North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory

Table of Content

NERC | Report Title | Report DateI

Reliability GuidelinePower Plant Model Verification for Inverter-Based Resources

sPreface..................................................................................................................................................................... iv

Executive Summary..................................................................................................................................................v

Preamble.................................................................................................................................................................vi

Purpose...................................................................................................................................................................vii

Chapter 1: Introduction............................................................................................................................................1

Verification Applicability of Inverter-Based Resources.........................................................................................1

Verification Approaches.......................................................................................................................................1

Staged Testing...................................................................................................................................................1

Disturbance-Based Verification.........................................................................................................................2

Verification Documentation..............................................................................................................................2

Chapter 2: Inverter-Based Technologies and Models...............................................................................................1

Inverter-Based Technologies................................................................................................................................1

Modeling Inverter-Based Resources.....................................................................................................................2

Chapter 3: MOD-025 Capability Testing...................................................................................................................4

Chapter 4: PPMV for Type 1 and Type 2 Wind Power Plants....................................................................................5

Type 1 and 2 WTGs...............................................................................................................................................6

Model Validation for Type 1 and 2 WTGs.............................................................................................................7

Other Types of WTG.............................................................................................................................................9

Chapter 5: PPMV for Inverter-Based Power Plants................................................................................................10

Voltage Reference Step Test...............................................................................................................................10

Reactive Power Reference Step Test..................................................................................................................10

Shunt Capacitor (or Reactor) Switching Test......................................................................................................10

Frequency Play-In...............................................................................................................................................11

Other Verification Methods – Disturbance Monitoring......................................................................................11

Type 3 Wind Power Plant Examples....................................................................................................................12

Example 1 - Plant Test and Model Validation..................................................................................................12

Type 4 Wind Power Plant Examples....................................................................................................................16

Solar PV Power Plant Examples..........................................................................................................................18

Low/High Voltage Ride-Through and Low/High Frequency Ride-Through and Other Aspects of the Models....25

Chapter 6: Summary and Conclusions....................................................................................................................26

References..............................................................................................................................................................27

Appendix XXX: Disturbance-Based Verification Examples......................................................................................29

Appendix XXX: Capability Testing for Other Dynamic Reactive Resources.............................................................30

NERC | Power Plant Model Verification for Inverter-Based Resources | _____ 2017ii

Table of Contents

Contributors...........................................................................................................................................................31

Example Heading................................................................................................................................................32

Example Subheading.......................................................................................................................................32

Highlight Box Example........................................................................................................................................34

NERC | Power Plant Model Verification for Inverter-Based Resources | _____ 2017iii

Preface

The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority whose mission is to assure the reliability of the bulk power system (BPS) in North America. NERC develops and enforces Reliability Standards; annually assesses seasonal and long term reliability; monitors the BPS through‐ system awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the continental United States, Canada, and the northern portion of Baja California, Mexico. NERC is the electric reliability organization (ERO) for North America, subject to oversight by the Federal Energy Regulatory Commission (FERC) and governmental authorities in Canada. NERC’s jurisdiction includes users, owners, and operators of the BPS, which serves more than 334 million people.

The North American BPS is divided into eight Regional Entity (RE) boundaries as shown in the map and corresponding table below.

The North American BPS is divided into eight Regional Entity (RE) boundaries. The highlighted areas denote overlap as some load-serving entities participate in one Region while associated transmission owners/operators participate in another.

FRCC Florida Reliability Coordinating Council

MRO Midwest Reliability Organization

NPCC Northeast Power Coordinating CouncilRF ReliabilityFirst Corporation

SERC SERC Reliability Corporation

SPP RE Southwest Power Pool Regional EntityTexas RE Texas Reliability Entity

WECC Western Electricity Coordinating Council

NERC | Power Plant Model Verification for Inverter-Based Resources | _____ 2017iv

Executive Summary

Text

NERC | Power Plant Model Verification for Inverter-Based Resources | _____ 2017v

Preamble

It is in the public interest for NERC to develop guidelines that are useful for maintaining or enhancing the reliability of the Bulk Electric System (BES). The Technical Committees of NERC; Operating Committee (OC), Planning Committee (PC) and the Critical Infrastructure Protection Committee (CIPC) per their charters 1 are authorized by the NERC Board of Trustees (Board) to develop Reliability (OC and PC) and Security Guidelines (CIPC). These guidelines establish a voluntary code of practice on a particular topic for consideration and use by BES users, owners, and operators. These guidelines are coordinated by the technical committees and include the collective experience, expertise and judgment of the industry. The objective of this reliability guideline is to distribute key practices and information on specific issues critical to maintaining the highest levels of BES reliability. Reliability guidelines are not to be used to provide binding norms or create parameters by which compliance to standards is monitored or enforced. While the incorporation of guideline practices are strictly voluntary, reviewing, revising, or developing a program using these practices is highly encouraged to promote and achieve the highest levels of reliability for the BES.

NERC as the FERC certified ERO2 is responsible for the reliability of the BES and has a suite of tools to accomplish this responsibility, including but not limited to: lessons learned, reliability and security guidelines, assessments and reports, the Event Analysis program, the Compliance Monitoring and Enforcement Program and mandatory reliability standards. Each entity as registered in the NERC compliance registry is responsible and accountable for maintaining reliability and compliance with the mandatory standards to maintain the reliability of their portions of the BES. Entities should review this guideline in detail in conjunction with the periodic review of their internal processes and procedures and make any needed changes to their procedures based on their system design, configuration and business practices.

1 http://www.nerc.com/comm/OC/Related%20Files%20DL/OC%20Charter%2020131011%20(Clean).pdf http://www.nerc.com/comm/CIPC/Related%20Files%20DL/CIPC%20Charter%20(2)%20with%20BOT%20approval%20footer.pdf http://www.nerc.com/comm/PC/Related%20Files%202013/PC%20Charter%20-%20Board%20Approved%20November%202013.pdf2 http://www.ferc.gov/whats-new/comm-meet/072006/E-5.pdf

NERC | Power Plant Model Verification for Inverter-Based Resources | _____ 2017vi

Ryan Quint, 07/28/17,

Check chapter numbers, figure numbers, table numbers, formatting, etc.

http://www.ferc.gov/whats-new/comm-meet/072006/E-5.pdf

http://www.nerc.com/comm/PC/Related%20Files%202013/PC%20Charter%20-%20Board%20Approved%20November%202013.pdf

http://www.nerc.com/comm/CIPC/Related%20Files%20DL/CIPC%20Charter%20(2)%20with%20BOT%20approval%20footer.pdf

http://www.nerc.com/comm/OC/Related%20Files%20DL/OC%20Charter%2020131011%20(Clean).pdf

Executive Summary

This Reliability Guideline is intended to raise industry awareness and utilization of dynamic disturbance recorders (DDRs) such as Phasor Measurement Units (PMUs) and synchrophasor data for dynamic model verification of power plant models. This guideline presents one method of disturbance based verification that may be used to perform verification of dynamic models and focuses on the use of synchrophasor data as one form of DDR data for performing power plant model verification (PPMV); it does not discuss the use of PMUs for system-wide model verification or comparison, and briefly discusses other complementary methods such as generator baseline testing3 for completeness. It is meant to provide utilities that have PMUs located at the terminals of generating units or the Point of Interconnection (POI) of power plants with guidance and appropriate technical reference material such that they can effectively and efficiently pursue model verification using synchronized measurement data. While the use of PMU data is the primary focus of this guideline, it is noted that other techniques for model verification exist. The methodologies outlined herein also apply to other types of disturbance monitoring data such as data from triggered digital fault recorders (DFR) and digital relays that provide this measurement function.

The concepts presented here are generic and do not necessarily pertain to specific implementations or software tools; however, the appendix material highlights some of the commercially available tools that enable PMU-based model verification. The Reliability Guideline, as mentioned, does not provide binding norms or create parameters by which compliance to NERC Reliability Standards is monitored or enforced. However, it does provide insight into those standards for which PMUs can be used for verifying that the model performance matches actual response for system events.

The Reliability Guideline applies primarily to Transmission Planners (TP) and Generator Owners (GO). While the GO is ultimately responsible for ensuring accuracy and usability of the dynamic models, both the TP and GO play a key role in developing and verifying these models used for planning and operating the bulk power system (BPS). The TP, in coordination with the Transmission Owner (TO) and/or the GO, may own the PMU that measures the plant performance to grid events. Transmission Operators (TOP) and Generator Operations (GOP) are also involved in unit dispatch and operation of the power plant, particularly during generator testing, and can play an important role in supporting responsible entities’ activities under Reliability Standards MOD-026 and MOD-027.

“The purpose of model [verification] does not necessarily mean a “perfect” match between the measured and simulated response, but rather an adequate match that clearly demonstrates capturing the relevant dynamics, proper representation of the plant’s dynamic response and ability to account for possible discrepancies”.4

3 Generator baseline testing refers to performing select tests (such as step tests, V-curve tests, rejection tests, etc.) and capturing response with instrumentation within the plant. This guideline provides high-level supplementary material on this type of testing as background; however, this type of verification is not the main focus of this guideline.4 Model Validation for Wind Turbine Generator Models, “IEEE Transactions on power systems” IEEE PES working group on Dynamic Performance of Wind Power Generation of the IEEE PES Power System Stability Controls Subcommittee of the IEEE PES Power System Dynamic Performance Committee.

NERC | Power Plant Model Verification for Inverter-Based Resources | _____ 2017vii

Ryan Quint [2], 05/22/17,

Placeholder. Will be switched out later.

Chapter 1: Introduction

Since the influx of large levels of wind generation into the bulk power system began worldwide in the early 2000s, there has been a need for publicly available, standardized, flexible and openly documented models to represent wind power plant technologies that can be used in commonly used power system simulation software platforms. Several organizations attempted these efforts in the early 2000s (e.g., CIGRE Working Group C4.601 [1], and the early efforts did much to document clearly the dynamic performance of these technologies. However, they were not able to bring detailed public and standard models (referred to here as “generic” models) to fruition. At the time, there was still much concern around the proprietary nature of the data and it was difficult to acquire detailed information from a sufficiently large number of equipment vendors.

In 2004, WECC commissioned a task force under the Modeling and Validation Work Group (MVWG) named the Wind Generation Modeling Task Force. That task force started through communication with the CIGRE WG, but then led the way to produce the first generation of generic wind turbine generator (WTG) models within WECC [14]. Shortly after the release of these first-generation WTG generic models, in 2010, several concerns were raised with regard to the first-generation models. Namely, that the Type 3 and Type 4 WTG models catered primarily to one vendor’s type of equipment (this was not a surprise since at the time of development of the first-generation generic models only one vendor had been forthcoming with data) and that there were some issues with the performance of the pitch controller model associated with the Type 1 and Type 2 WTGs. At the same time, NERC issued a special report highlighting the need for generic generic models of variable energy resource technologies (e.g., wind and solar photovoltaic (PV)) [2]. The WECC TF was renamed to the Renewable Energy Modeling Task Force (REMTF), and the International Electrotechnical Commission (IEC) started a working group (IEC TC88 WG27) charged with the charter of creating an international standard document specifying generic stability models for wind turbine generators.

Thus, the WECC REMTF began the task of creating the second-generation generic models, this time for renewable energy systems to include both wind and solar PV, and possible future technologies. Since many of the US members of the IEC group were also key members of the WECC REMTF, from early on the two groups collaborated and the core of the models for WTGs are essentially the same. A recent publication [3], highlights the similarly and subtle differences of the WECC and IEC models. The differences are due to the differences in European grid codes [3]. It should be noted than many of these differences were studied and presented to the WECC REMTF [4, 5], but WECC decided not to adopt them due to the added complexity without yielding added fidelity in the aspects of the dynamic performance of the WTGs that were of particular interest at the time to WECC. However, since both groups adopted a modular approach for developing the models, these differences may be accommodated in the second-generation models, if desired in the future, by the addition of some alternative modules. The culmination of the second generation models is reported in [6] and [7] – additional references are [8], [9], [10], [11] and [12].

While the WECC and the REMTF developed these models and gained experience with using these models, other interconnections in the NERC footprint continued to use the first-generation renewable models. This has caused a disconnect between state-of-the-art generic modeling of renewable energy systems and current modeling practices used by GOs and TPs. Further, with the implementation of MOD-026-1 and MOD-027-1 NERC Reliability Standards, GOs with renewable resources or TPs with these resources in their footprint are beginning to explore model verification activities to ensure the models reasonably represent the dynamic behavior of the installed BES resources.

This document guideline provides reference material and several examples of model verification for inverter-based resources as well as non-inverter-based renewable energy systems (e.g., Type 1 and 2 wind power plants (WPPs)).

NERC | Power Plant Model Verification for Inverter-Based Resources | _____ 20171


Lead: RyanSupport:

Chapter 4: PPMV for Inverter-Based Power Plants

Detailed accounts of the technologies for wind generation can be found in [1], much of which is equally applicable today. Likewise, documentation can also be found on photovoltaic (PV) technologies. Here we offer a brief over-view simply to identify some of the challenges and issues around modeling and model verification.

Inverter-Based TechnologiesRenewable energy systems range from hydroelectric generation to wind, solar photovoltaic, wave, and tidal energy systems5. The focus of this document is on inverter-based resources connected to the BPS, predominantly wind and solar PV resources. Wind generation may be categorized into four main technologies, as shown in Figure 2.1. The Type 1 WTGs are based on passive induction generators. That is, the electrical generator runs at essentially constant speed, and is unable to control megawatts, megavars or voltage. It is a squirrel-cage induction machine running at super-synchronous speed [1] and thus always absorbs reactive power from the grid and has no electrical controls. Most smaller Type 1 WTGs are associated with a stall wind turbine, which means that the blades are in a fixed position [1], and thus the WTG is truly a passive device with no active controls. In that case of active-stall [1]. Type 2 WTGs are not very different from an electrical response characteristic to a Type 1 WTG, the only difference being the wound rotor of the induction machine, together with a controlled variable resistance in order to flatten and extend the torque-speed characteristic of the machine and thus allow some level of variable speed operation. Both these technologies will require additional electrical equipment at the turbine level, and in the collector system (typically at the substation/POI) to compensate for the reactive power consumption of the induction generators, and to facilitate voltage control/regulation at the POI. This is typically done in the form of a combination of shunt switched capacitor banks and some sort of smoothly-controlled dynamic shunt reactive device (e.g., SVC or STATCOM). Type 1 and 2 WTGs do exist in the US, and many other countries in the world, and do presently constitute a significant mix of the installed base of wind generation. However, one of the major manufacturers of type 2 WTGs has discontinued that line of product since several years ago, and since the past several years, almost all the WTGs going into the system in North America are either type 3 of type 4 WTGs, which are inverter based technologies, and fully capable of providing all the typical ancillary services provided by other conventional generation, such as reactive support, voltage regulation, primary frequency response. PV generation also is equally able to provide all these functionalities [We can give a bunch of references on WTG/PV functionalities etc. including stuff that is shown in [12]]

5 Hydroelectric generation is not discussed in this guideline since hydro power plants are typically based on synchronous machine technologies. However, there are exceptions of inverter-interfaced hydroelectric generation for pumped storage, but again that is not covered here. Please see ___________ – a good reference is [IEEE TF work – will get reference].



Type 1 – Conventional Induction Generator

Type 2 – Variable Rotor-Resistance Induction

Generator

To Grid

To Grid

Type 3 – Doubly-Fed Asynchronous Generator

To Grid

ac/dc dc/ac

Type 4 – Full-Converter Unit

To Grid

ac/dc dc/ac

Can be gearless;generator can be induction, synchronous or permanent

magnet generator

Figure 2.XXX: Wind Turbine Technologies (Source: EPRI reference [10])

[Add solar oneline from integrating VER to weak grids doc]



Ryan


Figure 2.XXX: One Line Diagram of a Solar PV Plant [Source: WECC6]

Steady-State Modeling of BPS Wind and Solar Power PlantsFigure XXX in chapter 1 shows the four main technologies of WTGs. Most of the major WTG manufacturers now supply primarily Type 3 and Type 4 WTGs, with some of the major vendors of Type 1 and Type 2 WTGs no longer supplying those technologies. There are several reasons for this, including the drop in costs of inverter-based technologies in recent years as well as the advancement in controls, stability, and the ability to provide essential reliability services to the BPS. For example, variable speed operation of a WTG, flexibility in solar PV inverter controls, grid-supportive functionality, and efficiency have all improved operational performance of inverter-based technologies over the recent years. However, there is still an installed base of Type 1 and Type 2 WTGs in North America that, if BES resources, need to provide verified models as per the NERC Reliability Standards. At some point, these resources will likely be phased out of grid operation, which may yet be a decade or more.

WTG

To system m

odel

R, X, B Equivalent Feeder Model

EquivalentGenerator

Step-up Transformer

SubstationTransformer

Aggregated WTG model

Pf correctionMSCs

(for type 1 and 2 only)

SubstationMSCs SVC / STATCOM

(typically use for type 1 and 2 WTG wind plants only)

Figure 1.XXX: Aggregated model of a wind power plant

6 https://www.wecc.biz/Reliability/WECC%20Solar%20Plant%20Dynamic%20Modeling%20Guidelines.pdf


https://www.wecc.biz/Reliability/WECC%20Solar%20Plant%20Dynamic%20Modeling%20Guidelines.pdf


Figure 1.XXX: Aggregated model of a wind power plant

For power system stabilities studies, the most widely accepted approach for modeling a wind power plant (or a PV plant) is that shown in Figure 1. That is:

A aggregated model of the WTGs; this is the model of one WTG, scaled up by the MVA of the plant (i.e. if there are 100 WTGs of 2 MVA each, then the aggregate model is the model of one WTG in per unit, with the aggregate model having an MVA based of 100 × 2 = 200 MVA, assuming all WTG are on-line and operating).

An aggregated model of the pad-mount step-up transformer, again scaled up by MVA. An equivalent feeder model – the feeder impedance being calculated using the NREL7 approach the

detailed collector system model. And the substation transformer being explicitly modeled. Furthermore, for type 1 and 2 WTGs there are typically power factor correction shunt capacitors at the

terminals of the WTGs, which are again modeled explicitly, and often a combination of an SVC / STATCOM and mechanically switched shunt capacitors (MSCs) at the substation, which again should be explicitly models. The SVC / STATCOM can often be modeled using one of the recently develop svsmo1 or svsmo3 models available in the major commercial software platforms89.

The above aggregated model for a wind power plant, can as easily be applied for modeling a PV power plant, and to other WTGs technologies (Type 3 and Type 4). In the case of PV, type 3 and type 4 WTG plants, there are no shunt capacitors at the terminals of the generating units, since these technologies have reactive power capability (as opposed to Type 1 and 2 WTGs which always consume reactive power at the turbine-level), and there is rarely a need for an SVC or STATCOM at the POI, thought this is possible and may be done in some cases.

Dynamic Modleing of Inverter-Based ResourcesWith inverter-based resources, as with any other equipment, there are typically several levels of models:

7 E. Muljadi, C. P. Butterfield, A. Ellis, J. Mechenbier, J. Hochheimer, R. Young, N. Miller, R. Delmerico, R. Zavadil, and J. C. Smith, “Equivalencing the collector system of a large wind power plant,” in Proc. IEEE Power Eng. Soc. General Meeting, Montreal, QC, Canada, Jun. 2006.8 https://www.wecc.biz/Reliability/WECC-Static-Var-System-Modeling-Aug-2011.pdf 9 P. Pourbeik, D. J. Sullivan, A. Boström, J. Sanchez-Gasca, Y. Kazachkov, J. Kowalski, A. Salazar, A. Meyer, R. Lau, D. Davies and E. Allen, “Generic Model Structures for Simulating Static Var Systems in Power System Studies—A WECC Task Force Effort”, IEEE Transactions on PWRS, August 2012.


https://www.wecc.biz/Reliability/WECC-Static-Var-System-Modeling-Aug-2011.pdf


Extremely detailed vendor-specific 3-phase models, that for wind-turbine generation, may also include detailed models of the mechanical side as well. These models are used for design studies by the vendor and may often be implemented practically in source code and then integrated into tools such as PSCAD®, MATLAB®, EMTP-RV, etc. These models are owned and developed by the original equipment manufacturer (OEM) and are proprietary and typically not shared

Reduced order vendor specific 3-phase models. These models are based on the detailed equipment design models, but represent only the key elements of the equipment as they pertain to the electrical grid and so certain aspects of the full scale detailed model made be simplified or hard-coded as dlls. Again, these models are owned and developed by the OEM and are proprietary, but may be shared with owners of plants etc., through an NDA, for the purpose of detailed studies relating to the design of the power plant and its potential interactions with other nearby equipment.

Reduced order vendor specific stability models. These models are typically benchmarked by the OEM against the high level models described above, for the bandwidth of stability analysis (typically, 0.1 to 10 Hz or so and dealing with transients in the fraction of a second to many seconds time frame, for simulations ranging up to 10 to 30 seconds). These models are typically implemented in positive sequence stability programs such as GE PSLFTM, Siemens PTI PSS®E, PowerWorld Simulator or PowerTech Labs TSAT, or other similar tools. Some vendors make these models openly available in these commercial tools, while others make them available through an NDA.

Generic stability models. These are open source, publicly available model structures, with the latest version available in North America being the so-called 2nd generation generic renewable energy system (RES) models [6], [7], [10]. These are generic model structures, which when parameterized appropriately can emulate the general dynamic behavior of a variety of RES. These are positive sequence models for use in large scale stability simulations for power system planning.

All of the various models described above have their benefits and disadvantages, and all have limitations in their applicable range of studies. The models that are used in BES planning studies are the latter models described above, and NERC requires the use of public and open models such as the 2 nd generation generic models, since they are available to all the various stakeholders, and have been benchmarked for consistency across all the major commercial software platforms.

The goal of model validation, whether it is based on staged testing or disturbance monitoring, is to demonstrate that the appropriately parameterized generic models can adequately simulate the measured/observed dynamic behavior of the actual RES plant.

Verification Applicability of Inverter-Based ResourcesDescribe how the standards are applicable to these types of resources

1 Excitation control system or plant volt/var control function:a. For individual synchronous machines, the generator excitation control system includes the generator,exciter, voltage regulator, impedance compensation and power system stabilizer.b. For an aggregate generating plant, the volt/var control system includes the voltage regulator & reactivepower control system controlling and coordinating plant voltage and associated reactive capable resources.

1 Turbine/governor and load control or active power/frequency control:a. Turbine/governor and load control applies to conventional synchronous generation.b. Active power/frequency control applies to inverter connected generators (often found at variable energy plants).



Lead: Ryan


Verification ApproachesThere are a number of different approaches that can and should be considered when performing model verification of any generating resource. Particularly for inverter-based resources, these activities can be categorized into: staged testing, online disturbance monitoring, and review and verification of documentation. These approaches are each described below in more detail. An important note is that not all of these activities need to be performed to verify a model; however, whoever is performing the verification may need to explore any of these options based on the equipment installed, the verification results obtained, and the type and manufacturer of the equipment.

Staged Testing for MOD-026-1NERC MOD-026-1 focuses on verification activities for the excitation control system or plant volt/var control function model. As stated above, there may be multiple tests that can be performed to verify the overall performance of the dynamic model used to represent the aggregate response of the resource. Specifically for inverter-based resources, these types of staged tests are often used:

Voltage Reference Step Test: In the case of inverter-based renewable energy power plants, there are several ways in which voltage and/or var control may be effected, namely (1) voltage control, (2) power factor control, or (3) constant var control. In all cases, the control may also employ deadband and/or some form of current compensation. In general, however, if voltage control is performed voltage is ultimately controlled at the POI, with an over-arching plant controller (modeled using the generic models with either the repc_a or repc_b model, see [10]). In this case one can test and validate the model of the plant controller (and to a great extent the electrical controls of the individual inverters, reec_a, reec_b or reec_c models) by injecting a voltage reference step into the voltage reference set-point of the automatic voltage regulator at the plant level. Then by recording the response of the plant at the POI, and simulating the same in an aggregated model (see Figure 1), the comparison of the simulated and measured response can be used to validate the model. The step should typically be no more than 2 to 3%, and care must be taken to ensure that the voltage at the POI is not pushed too high, for example, typically a step down in voltage might be performed. Also, the step must be allowed to last for at least several minutes, before being removed to allow for the dynamics to full play out. In the case of wind power plants, it is typical to slow down the plant level voltage control such that it take a few tens of seconds to completely settle down.

Reactive Power Reference Step Test: Another means of testing the response of the plant controller is to perform a reactive power reference step test. This test is particularly useful if the plant is typically operated in ether reactive power control mode or constant power factor control mode. In this test, a step is injected in the reactive power reference for the power plant. Again, a relatively small step should be injected, ensuring not to cause excessive changes in voltage at the POI or within the collector system.

Shunt Capacitor (or Reactor) Switching Test: Another means of testing the voltage/var response of the plant controller is to switch a shunt capacitor (or reactor) either at the POI (in the substation within the plant) or nearby on the transmission system. In this case the switching of the shunt device will invoke the volt/var control system of the power plant to react to either regulate voltage at the POI, or power factor. Thus, again the response of the plant can be recorded and compared to the simulated response for model validation purposes.

Staged Testing for MOD-027-1NERC MOD-027-1 focuses on verification activities for the turbine-governor and load control or active power-frequency control model. As stated above, there may be multiple tests that can be performed to verify the overall performance of the dynamic model used to represent the aggregate response of the resource. Specifically for inverter-based resources, these types of staged tests are often used:



Frequency Play-In: At the time writing this guideline, very few inverter-based wind and solar PV power plants in the US have primary frequency response capabilities installed and active. This is not to say that the technologies are not capable of such a response, but simply that since there are no requirements for these technologies to provide frequency response, such controls were never installed on these plants. The one exception is the region of ERCOT10, where all generation installed is required to have frequency response capability. Therefore, what is described in this section is only applicable as a test for plants that have this feature. If the plant does not have the functionality for performing primary frequency response, then there is no need to test this capability. A system disturbance recording would easily confirm that the plant has no frequency response capability (see Figure 3).

Figure 3: Place holder for Pouyan (have cases, need to get permission to share)

The primary objective of the frequency response test is to verify, (i) droop, (ii) intentional programed deadband in the controls, and (iii) response time of the resource.

The simplest way to perform this test is to play-in a frequency signal at power plant controller by deliberately over-riding the frequency reference. Thus, the inverters are exposed to a signal as if a real frequency event has happened at the grid and provide the desired frequency response. The played-in signal can be (i) a real-time frequency signal measured from a system wide frequency event, or (ii) a synthetic frequency signal mimicking a large frequency dip or rise, or (iii) simply a step change in frequency up or down.

Disturbance-Based VerificationText

An alternative way to perform both MOD26 (volt/var) and MOD27 (frequency response) model verification is to performed disturbance monitoring. That is, to monitor at a high rate (60 samples per second or more) the real power (MW), reactive power (MVar), bus voltage (kV) and bus frequency (Hz) at the POI with a PMU, DFR or similar digital recording device. Then assuming adequate voltage and frequency events are captured, this data may be used to verify the models.

Reviewing and Verifying DocumentationText

Not everything can be tested. Some has to be collected by other means:- Ride-through- Reference step tests- Review manufacturer information

Digital controls – go look up the values in the logic controllerTesting and model parameters should be based on actual settings in the equipment, not based on optimization techniques to derive a set of parametersLook up the values and start from there as a model starting pointIf you find errors/differences, explore possible interactions, bad data, etc., and reperform the tests or simulations.

10 http://www.nerc.com/_layouts/PrintStandard.aspx?standardnumber=BAL-001-TRE-1&title=Primary Frequency Response in the ERCOT Region&jurisdiction=United States



Highlight this as applicable to all types of resources and ensuring that the simulated behavior matches actual response for large-scale disturbances.Gordon, Dmitry, Steve


Response rate of pitch controls – some of these types of parameters should not be tested, they should be collected from the vendor and ensure that it’s accurately implemented in the model (abstracted (or removed) from grid response functions)

Intent of the standard is not necessarily to verify all the subsystems of the model, trying to capture the overall plant’s response.

For some of the subsystems, it may not be prudent to test for these parameters. In these cases, these parameters should be collected from the vendor and proved by gathered documentation.



Refer to Pouyan and Matthew on this subject

Chapter 2: MOD-025 Capability Testing

Text

Go through MOD-025-2 and describe at what loads testing needs to perform, call out the exemptions in the standard, discuss any ambiguities

- Make point on time duration it should be held (not one hour)-

What does “all applicable Facilities”? Make clear that this is aggregate.- Show aggregate and data sheet for one of the inverter

Applicability

Don’t have MW dependency on reactive power – main thing is having enough turbines/inverters online

Need something that describes this concept in more detail. What is really required for testing and what is hopefully provided by testing…



Nuances and specific issues associated with these types of resources and reaching reactive capabilityDifferences in MOD-025 with variable resourcesHolding the operating pointClarify any issues in the standard that are not clear (or reasonable/possible)


Lead: MatthewSupport: Vladimir



Chapter 3: PPMV for Type 1 and Type 2 Wind Power Plants

Type 1 and 2 WTGsAs articulated above, type 1 and 2 WTGs are generally not manufactured nor installed in large BES wind power plant applications anymore. Most major vendors for large transmission connected wind power plants have moved away from these technologies. Thus, in general there is little avenue for obtaining additional factory tests, detailed 3-phase models etc. for such technologies, other than what already exists in the archives of the original equipment manufacturers (OEM) for these equipment.

Type 1 WTGs are essentially passive devices. That is, the electrical generator is a fixed-speed squirrel-cage induction generator with no controls at all. Furthermore, smaller (typically less than 1 MW) and older type 1 WTGs were in many cases stall controller turbines [1], that is the turbine blades are bolted to the rotor at a fixed pitch angle and thus the turbine is also a passive device. As such, the type 1 WTG reduces typically to two models:

1. A model of the electrical generator – which is a typical model for an induction machine, and2. A model of the two-mass shaft dynamics (i.e. turbine-rotor mass and electrical generator mass, with a

representation of the effective spring constant between the two and the damping).

In the generic models, these amount to the wt1g and the wt1t models, respectively [6], [10]. The old 1st

generation generic pseudo-governor model for Type 1 and Type 2 WTGs (wt1p and wt2p) should not be used, as they do not truly represent the pitch-controls used in these WTG technologies. The new 2 nd generation generic model wt1p_b active-pitch controller more appropriately represents the action of the active-pitch controllers when used on these types of WTGs. Namely, that on larger type 1 WTGs with active-pitch controls, some vendors would initiate a ramp down in mechanical power (by pitching the blades) when a severe voltage dip, together with acceleration in the turbine speed, was detected in order to prevent the generator from exceeding its pull-out torque on thus going unstable (see [1] for a more detailed explanation).

In the case of a Type 2 WTGs, the induction generator is a wound-rotor induction machine, again directly coupled to the grid and running as an induction machine at super-synchronous speed 11. In this case, there is a variable external resistance connected to the wound-rotor winding, which is controlled to change the effective rotor resistance over the operating range of the machine. This has the effect of flattening out the torque-speed curve of the machine and thus allowing the machine to run over a range of speeds, typically from a super-synchronous slip of 1% to about 8 – 10%. Thus, the type 2 machines were the first step towards variable speed machines, which yield greater efficiency in converting the incident wind to electrical power [1].

Thus in the case of the Type 2 WTG we have one additional generic model, the wt2e model, which emulates the controls associated with the controlling of the external rotor resistance, be increasing the resistance with increasing electrical output of the machine to allow for a higher slip-speed.

11 An induction machine is an induction-motor and comsumed real power to provide mechanical torque to serve a load, when it is run an sub-synchronous speed. If, however, the same machine is run an super-synchronous speed by a turbine running its rotor and thus providing mechanical power, then the machine becomes an electrical generator and generates real power. However, in both cases the induction machine consumes a large amount of reactive power, which is the source of power maintaining the rotating magnetic field within the machine that is the means of magnetic “induction” between the rotor and stator windings.


Pouyan, 07/25/17,

So here is my promised write up on Type 1 and 2 – give me your comments.


Model Validation for Type 1 and Type 2 WTGsFrom the brief discussion above we can see the following facts:

1. Type 1 and 2 WTGs are essentially passive devices, particularly the Type 1 WTG.2. The core model in both cases is the electrical induction machine (wt1g), which is the standard one-cage

(transiency only) or two-cage (transiency and subtransiency) model of an induction machine. Table 1 shows the parameters of this model for one of the typical commercial tools.

3. The second model in both cases is the two-mass model of the turbine-generator shaft (wt1t). Table 2 shows the parameters for this model.

4. In the case of the type 2 WTG, in the major commercial tools, the wt2g model, which is the electrical model of the induction machine, is only a one-cage (transiency only) model. The additional model that is then employed is the wt2e model which represents the control/change in the external rotor resistance as a function of power and speed. The parameter list for wt2e is shown in Table 3.

Finally, as stated above the old wt1p (wt2p) model should not be us, and where data is available, and the turbine has active-pitch controls, the new wt1p_b model should be used [6], [10]. If such data is not available, it is conservative (plant will be less stable) to not include the wt1p_b model. For stall controlled turbines, there is no pitch-control and none should be modeled.

Table 1: Parameters for wt1g Model for Modeling WTG Induction GeneratorPARAMETER EXPLANATIONLs Synchronous reactanceLp Transient reactanceRa Stator resistanceTpo Transient rotor time-constantSe1 Saturation factor at 1 pu fluxSe2 Saturation factor at 1.2 pu fluxAcc Acceleration factor (for numerical stability), typically = 0.5Lpp Subtransient reactanceLl Stator leakage reactanceTppo Subtransient rotor time-constantndelt Time step subdivision factor (for numerical stability), typically = 10wdelt Speed threshold for applying ndelt (for numerical stability), typically = 0.8

Table 2: Parameters for wt1t Model for Modeling WTG Drive-TrainPARAMETER EXPLANATIONH Total shaft inertiaD Not used for two-mass modelHtfrac Turbine inertia fraction (i.e. Hturbine/Htotal)Freq1 OEM provided frequency of the torsional mode (Hz)Dshaft Shaft damping factor (typically 1 pu/pu)

Table 3: Parameters for wt2e ModelPARAMETER VALUE (PU)Tw Time constantKw GainTp Time constantKp GainKpp Proportional gain



Kip Integral gainRmax Maximum external resistanceRmin Minimum external resistanceSlip1

Piece-wise linear curve of slip versus power

Slip2Slip3Slip4Slip5Powr1Powr2Powr3Powr4Powr5

Now consider the above models and model parameters. It is evident from this information that these WTGs are passive devices for the most part and it is thus not possible to perform any safe and meaningful tests in the field to verify the parameters for these models. For example, consider the electrical parameters of the electrical generators. To test these units and derive in a meaningful way the electrical parameters one would have to do short-circuit type tests or test that would expose the electrical machines to large and sudden changes in voltage. Such tests are not viable or safe to be performed in the field within an operating wind power plant. Similarly, to excite the torsional modes of the turbines to measure the torsional frequency one would have to get the turbine with a sudden and large electrical disturbance – again not viable in the field.

Thus, the only feasible and practical means of model validation/verification for type 1 and 2 WTGs is to obtain the design data from the OEM and thus derive establish the model parameters. Namely,

The parameters for wt1t come from the OEM design data. The H constant can be calculated, as with synchronous generation, from the OEM detailed calculations of the moment of inertia of the shaft (H = ½ J o

2) The parameter for the wt1g (wt2g) electrical generator must also be obtained from the OEM. In many

cases the OEM will provide the single-cage equivalent circuit parameters of the machine (see Figure 2). These can be converted to the operational impedance parameters in Table 1, as shown below:

Ls = Lm+La

Lp = La + 1/(1/Lm + 1/L1))

Ll = La

Tpo = (L1 + Lm)/(2π60.R1))

In most commercial software platforms, Tppo = 0 and Lpp = Lp will eliminate the subtransient circuit and model the induction machine as a single-cage machine.

Finally, the engineer may use the induction machine model to calculate the pull-out torque and rated power factor of the machine and compare these with the OEM provide numbers as a final verification of the model.



Ra La

LmR1s

L1

Figure 4.2: Single-Cage Equivalent-Circuit Model of an Induction Machine

In the case where some form of digital monitoring device (e.g. PMU or DFR) might be installed at the POI of the wind power plant, and high fidelity (60 samples or more per second) data is captured of the real power (MW), reactive power (MVar), voltage (kV) and frequency (Hz) at the POI, this might afford a means of further model verification/validation. However, it should be understood that an evident sufficiently significant enough (e.g. close in fault) may not be common enough so as to yield an adequate validation means. Furthermore, all these models being positive sequence models, unbalanced faults, which are far more common, may also not be adequate for model validation.

Other Types of WTGAlthough, to our knowledge, there are no installations to date of such technologies in the US, there is a fifth type of WTG that has been discussed in the literature many times (see Appendix C of [1] for a detailed account). These are synchronous generator based WTG, which use a unique patented mechanical drive system that allows for variable speed mechanical torque conversion. That is, the while the turbine is running at variable speed, the mechanical system is able to convert this to a torque delivered to the generator shaft at constant speed. In these cases, the models and model validation process for the electrical generator and its controls are likely no different than any other synchronous generator.



A sufficient event may not happen commonly enough… Don’t wait for a fault somewhere near (literally at the POI) the plant…


There are multiple types of verification tests that can be conducted to support verification of the dynamic model for an inverter-based resource related to MOD-026-1 and MOD-027-1. This chapter describes the verification tests, activities, and concepts related to inverter-based resources.

Presently, and since perhaps several year ago, by far the majority of renewable energy systems being installed on the BPS are inverter-based generation. This includes type 3 and 4 WTGs, photovoltaic (PV) generation and other resources such as battery energy storage. In almost all cases the interface between the grid and the generating device is a voltage-source converter, namely a power converter based on insulated-gate bipolar transistors (IGBTs), or similar devices, which means that the converter in self-commutating and thus the switching is completely controlled allowing the device to both generate or absorb reactive power independently of the real power transfer, as long as the device is operating within it current ratings. For this reason inverter-based technologies are fully capable, if designed and operated properly, of providing voltage control/regulation and independent control of reactive and active power. As such, since they are active devices with closed-loop control, it is quite feasible to perform model validation of the volt/var controls (MOD 26) and the frequency response (MOD27), if any, using standard techniques used in the case of synchronous generation. The following sections we will first explain each test, all of which are equally applicable to any inverter based generation technology, and then in subsequent subsections give a few examples of each test for some of these technologies (e.g. type 3 WTG, type 4 WTG and PV).

Type 3 Wind Power Plant Examples

Example 1 - Plant Test and Model ValidationThere are several approaches to validating the installed equipment. One is to record the response of the equipment under test to naturally occurring grid events. While the benefit of this approach is that the test coordination is simplified, the disadvantage is that a significant grid event must occur while there is sufficient wind strength for the power plant to be online and there is potential for nearby plants or transmission assets to interact and confound the response to the initiating event. An alternative approach pursued for this validation is to stage the tests [15].

Conducting staged field tests for wind farms can be more challenging than that of their thermal counterparts due to the unavoidable presence of environmental variables. Grid conditions, ambient temperature, and the fluctuations in active power due to wind speed changes, are examples of variables beyond the operator’s control that affect the performance of a wind power plant during a staged test.

This section outlines the test procedure, plant model, and model validation results for a Type 3 wind power plant.

Test ProcedureThe following tests were conducted according to NERC Model Validation Standards:

1. Voltage Reference Online Step Tests (MOD-026-1)2. Frequency Reference Step Test (MOD-027-1)

The voltage step tests were performed using two different methods. The first test was conducted by stepping the voltage reference of the plant controller; the second test consists of switching in and out a capacitor bank at the wind power plant.

The frequency reference step test was performed by injecting a test signal step into the measured grid frequency signal that is used by the plant controller. Based on the configuration settings, the plant controller will change the active power command to the turbines under its control as a response to changing frequency



Wind Power Plant Model

The topology of the wind power plant is shown in Figure 5.??. The plant consists of an equivalent aggregate wind turbine generator model (Equivalent WTG), a plant level controller (Plant Controller), an aggregate pad mount transformer model (Equivalent Unit Transformer), an aggregate collector system model (Equivalent Collector System), and an aggregate sub-station transformer model.

The wind power plant was modeled in GE’s PSLF transient stability program, the generic second-generation generic Type 3 Wind Turbine Models were used to represent the Equivalent WTG. This representation involves six modules: electrical control, torque control, pitch control, drive-train, aerodynamics, and generator/converter. In addition, a low/high voltage ride through protection module was included in the plant representation. The associated block diagrams and their interconnection have been described in several references (e.g., reference [16]).

Figure 5.XXX: Wind Power Plant Simplified Oneline Diagram

Model Validation Tests

The model validation tests provide the means to tune model parameters and verify that the validity of the transient stability models. The validity of the models is established by comparing their dynamic against the response of the actual system response for different types of stimuli.

Three model validation tests are considered here:

Voltage step test – A step is applied to the voltage reference of the plant controller (Figure 5.??)

Capacitor bank switch test – A capacitor bank at the wind power plant is switched on and off (Figure 5.??)

Frequency step test: A step is applied to the frequency reference of the plant controller (Figure 5.??)

Figures 5.XXX and 5.XXX compare the voltage and the real and reactive power of the model versus the system at the POI response; Figure 5.XXX compares the real power and frequency at the POI. The results obtained in these tests show a good match between the transient stability models and the dynamic response of the actual system and demonstrate the validity of the models.



Juan will develop some block diagrams showing the plant-level controller and where the injection points are for each of the tests.


Figure 5.XXX: Voltage Reference Step Test. Simulated (Red) vs. Measured Response (Blue)

GE example of bad match and what was done to correct

If you have a problem, go check the gains, time constants, other controls/devices interacting, etc.



Matthew Richwine


Figure 5.XXX: Capacitor Bank Switch Test. Simulated (Red) vs. Measured Response (Blue)



Figure 5.XXX: Frequency Injection Step Test. Simulated (Red) vs. measured response (Blue)

1.2. Senvion example (Samer)3. Other examples (Pouyan, Song, Nathan)


Pouyan, 07/25/17,

Will provide an example here in due course.


Type 4 Wind Power Plant ExamplesText

1. Siemens example (Joergen)2. BPA example (Steve/Gordon/Dmitry) – disturbance monitoring examples using PMU data

Disturbance Based Model Validation:

Below are two separate examples of model validation for a type 4 WTG (both are of the same OEM). The first cases is MOD26 volt/var validation. Here we see a system event that caused a significant change in the volt/var response of the wind power plant at the POI. The active power does not match well because during the 50 seconds of recording the wind speed was also significantly changing, while in the simulated generic models we assume constant wind speed. In this example, the recorded voltage was played back into the model and the MW/MVar response of the aggregated WTG model compared between measurement and simulation.

Figure 5.ZZZ: Measured (blue) vs. Simulated (red) Response of a Type 4 Wind Power Plant [Source: IEEE©2016 [12]]

The second case below is the validation of the primary frequency response capability of a wind power plant of type 4 (same vendor as above) in the ERCOT system. What is shown is the actual and simulated response of the wind power plant to an actual frequency disturbance on the grid. The measured frequency was played back into the model to simulate the plant response.



Figure 5.ZZZZ: Aggregated single equivalent generator representation of a wind power plant, and the comparison of the simulated model response to actual

measured response of the plant to a frequency event on the system. The plant consists of type 4 wind turbine generators, with primary frequency response

controls. This plant is in ERCOT. [Source: IEEE ©2016 [12]]

Example of frequency response for a plant that does not have frequency response controls enabled – demonstrate using actual grid events to show non-response

- Primary option: Recommendation to use historical data to show evidence that the plant is non-responsive to frequency events

- Secondary option: For plants that don’t have access, pull documentation and prove with documentation that the unit will not respond to frequency response

- Additional step: Inject a step and know nothing happens just to prove the point – long way to go to get the result we already know. Although this may not be required if the secondary option is performed… (May be dependent on whether or not there is somewhere to inject the frequency step signal – if the controls are installed, then the injection point may not exist)



Solar PV Power Plant ExamplesVoltage Reference Step Test:

Here is an example for a voltage reference test on a PV plant. A step change in the voltage reference in the power plant controller is introduced which is controlling the voltage at the POI. An example for voltage reference step test is shown in Figure 5.XXX. It can be seen in Figure 5.XXX, that when a change in voltage set point from 1.0 p.u to 0.997 p.u. was introduced in power plant controller (PPC), inverters immediately throttled down to an lower reactive power level to maintain desired voltage set point. Reactive power transition to new level was achieved in a ramped fashion depending upon the set ramp rate of reactive power set in PPC.

Figure 5.XXX: Text

Reactive Power Reference Step Test:

An example of reactive power control test that includes change in reactive power reference points is illustrated here. The PPC is set to respond to the reactive power command when the reference set point for reactive power was changed from 0 MVar to 1.6 MVar and back to 0 MVar as steps in SCADA human-machine interface (HMI). PPC calculated the reactive power commands to be distributed to inverters to achieve the desired set point. It is important to note that capacitor/ reactor banks were not engaged to meet the desired reactive power set point during this test. The response of the plant measured at the POI to the commanded reactive power set point and change in voltage at POI is shown in Figure 5.XXX below.


Pouyan, 07/25/17,

This is all Sachin’s stuff, which I moved to this section.


Figure 5.XXX: PV Plant Actual and Simulated Response for Change in Reactive Power Reference (Source: First Solar)

Another example of reactive power control test performed on a 250 MW solar PV plant is shown in figure xxx. For this particular plant reactive power target was changed from 0 MVar to 13.5 MVar at 102 sec. Results verify that desired reactive power target was met.

Figure 5.XXX: Text



Figure 5.XXX: Text

Reactive power control test was conducted once again on the same 250 MW solar PV plant when the MW output level was within 75% -100% of plant output rating. Reactive power set points in SCADA HMI were changed from 55 MVAr to 73 MVAR in a step resulting in plant reaching the full VAR limits in over-excited mode, and finally bringing the reactive power to 37 MVAr in steps. Simulation model closely followed the plant real-time recorded response.

Figure 5.XXX: Text

Another similar possible test is to change the power factor set point in the SCADA HMI. PPC will calculate the derived reactive power set points to be sent to individual inverter using plant active power and commanded power factor set point. With the repc_a model this test cannot be simulated, since it does not model plant level



power factor control, but this can be simulated with the repc_b model which does model plant level power factor control.

Switched Capacitor Bank Test:

Another staged test includes using an external physical stimulus is to change the status of capacitor/reactor bank(s) located on medium voltage collector system within PV plant. In this test, a capacitor bank located at one of the medium voltage feeders (34.5 kV) is engaged automatically by the PPC, when the desired reactive power target at POI is set higher than the net sum of cumulative reactive power capability of all inverters online during test period and reactive power losses within plant.

When target reactive power is set in SCADA HMI, inverters respond immediately to achieve the set point by ramping-up the reactive power within power factor limits. When the desired set point cannot be reached by inverter(s) alone, the PPC sends a command to engage a capacitor bank of 4.75 MVAR automatically at nearly 44 sec. Inverters ramped-down following the capacitor switching to maintain the desired set point target. The plant is commanded to maintain 0 MVar at POI at 55 sec, -3.5 MVAr at 88 sec back to 0 MVAr at 118 sec.

Capacitor bank switching dynamics and response of the plant measured at the POI in terms of voltage and reactive power is shown in Figure 5.XXX below.

Figure XXX: PV Plant Actual and Simulated Response for Capacitor Bank Switching Test (Source: First Solar)

Disturbance Based Model Validation:Text – First Solar once results are obtained

Frequency Response Test:

For the first test, the frequency time series from an actual event in ERCOT measured on November 29, 2011, was provided to the PPC to emulate its frequency response. This particular event was caused by the loss of 1.365 GW of generation during the period of 30.07 GW load. In this particular test, the responsive load reserve was activated to arrest further frequency decline. For test purpose, plant was set to operate with a very aggressive



1.67% droop setting, and plant was operated in curtailed mode at the level of approximately 12 MW when the event started (nearly 50% of actual MW capacity). In response to the emulated frequency decline, plant started increasing its active power. Measured and simulated response of the plant during this event is shown in Figure xxx below.

Figure XXX: PV Plant Actual and Simulated Response to Under-Frequency Event (Source: First Solar)

Similar under-frequency droop test was conducted on a 250 MW PV plant in the Western Interconnection of the US. For this plant, tests was conducted for both over- and under-frequency control, by playing into the PPC a simulated over-frequency, as well as an under-frequency signal. Under-frequency test was conducted during the mid-day with plant operating at a curtailed level of 178 MW. Under-frequency event time series shown in figure xxx was provided to the PPC, so that plant can demonstrate frequency response as if it is exposed to a real frequency event. The plant active power response to the frequency time series was measured by the PMU at the plant POI. Plant response to played-in under-frequency time series is shown in Figure 5.XXX. From Figure 5.XXX a linear dependence between frequency and plant active power can be observed once the frequency deviation exceeds the dead band of ±36 mHz.



Figure 5.XXX: Text

Figure 5.ZZZZ: Under-frequency test on a 250 MW Solar PV plant in WECC [Source: reference [13]]

Frequency droop tests for over-frequency event was conducted during post-noon hours on same 250 MW PV plant. Plant response to played-in over-frequency time series is shown in Figure 5.XXX. MW plot shows that the plant reduces its power output linearly with the frequency when it fall outside the ±36 mHz dead band, and then gradually returns to its original level as frequency returned to its normal pre-fault level.



Figure 5.XXX: Text

Figure ZZZZ: Over-frequency test on a 250 MW Solar PV Plant in WECC [Source: reference [13]]

Other Modeling AspectsText

Low/High Voltage/Frequency Ride-Through ModelsThis is unique for asynchronous because they are explicitly programmed in the logic. Similar, yet different, than synchronous machines. (lhvrt lhfrt) – data for these models should be provided

Need a brief write-up (Pouyan will work on it soon) to explain that we cannot test LHVRT and LHFRT and other aspects (e.g. turbine inertia) in the field. These have to come from OEM factory tests and design specifications etc. We can give some examples from reference [12] on validation of LVRT etc. from factory test results.


Chapter 5: Summary and Conclusions

Text

- Type 1 & 2 – hard to really validate based on tests; monitoring might be an option, but hard pressed to capture any events that will really exercise significant dynamics (e.g. 3-phase fault right close to turbines)

- Type 3 & 4 – can stage test (voltage reference step tests) or disturbance monitor- PV – same story as type 3 & 4 WTG; can test with voltage/Q step tests or disturbance monitoring- MOD 27

o Type 1 and 2 inherently have some inertial response.o Type 3 and 4 (and PV) do not have any inherent inertial response or primary frequency

response. However, all can provide very decisive, fast (and more reliable than conventional generation) frequency response (will show in examples in previous section), but this requires two things: (i) additional control features, (ii) for primary frequency response one needs to “spill” incident energy which has economic implications.

o The generic models can capture (well) the primary frequency response when the feature/controls exist (examples will be shown in prior section). The generic models presently do not have a feature to model “synthetic inertia” for WTGs

o Presently, neither of these features are activated/available on the majority of WTGs in North America, with the exception of ERCOT and Quebec.

o We should thus allow for WTG (and PV) that do not have the primary frequency response activated to pass MOD 27 by simply saying so and moving on, since there is nothing to model and in the models, you just turn frqflag to 0.



Lead: Support:

References

[1] CIGRE Technical Brochure 328, Modeling and Dynamic Behavior of Wind Generation as it Relates to Power System Control and Dynamic Performance, August 2007http://www.e-cigre.org/Search/download.asp?ID=328.pdf

[2] North American Electric Reliability Corporation, Standard Models for Variable Generation, Special Report, May 18th, 2010.http://www.nerc.com/files/Standards%20Models%20for%20Variable%20Generation.pdf

[3] Ö. Göksu, P. Sørensen, J. Fortmann, A. Morales, S. Weigel, P. Pourbeik, “Compatibility of IEC 61400-27-1 Ed 1 and WECC 2nd Generation Wind Turbine Models”, Conference: 15th International Workshop on Large-Scale Integration of Wind Power into Power Systems as well as on Transmission Networks for Offshore Wind Power Plants, November 2016.

[4] WECC Type 3 Wind Turbine Generator Model – Phase II, January 23, 2014https://www.wecc.biz/Reliability/WECC-Type-3-Wind-Turbine-Generator-Model-Phase-II-012314.pdf

[5] WECC Type 4 Wind Turbine Generator Model – Phase II, January 23, 2014https://www.wecc.biz/Reliability/WECC-Type-4-Wind-Turbine-Generator-Model-Phase-II-012313.pdf

[6] WECC Second Generation Wind Turbine Models, January 23, 2014https://www.wecc.biz/Reliability/WECC-Second-Generation-Wind-Turbine-Models-012314.pdf

[7] WECC Generic Solar Photovoltaic System Dynamic Simulation Model Specification, September 2012https://www.wecc.biz/Reliability/WECC-Solar-PV-Dynamic-Model-Specification-September-2012.pdf

[8] WECC Wind Plant Dynamic Modeling Guidelines, May 2014https://www.wecc.biz/Reliability/WECC%20Wind%20Plant%20Dynamic%20Modeling%20Guidelines.pdf

[9] WECC Solar Plant Dynamic Modeling Guidelines, April 2014https://www.wecc.biz/Reliability/WECC%20Solar%20Plant%20Dynamic%20Modeling%20Guidelines.pdf

[10] Model User Guide for Generic Renewable Energy System Models, Product ID 3002006525, EPRI, Palo Alto, CA, June 18, 2015http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000003002006525

[11] WECC Renewable Energy System Models Webcast, July 16th, 2015https://www.wecc.biz/Administrative/WECC_Renewable_Energy_System_Models_Webcast_071615.pdf

[12] P. Pourbeik, J. Sanchez-Gasca, J. Senthil, J. Weber, P. Zadehkhost, Y. Kazachkov, S. Tacke and J. Wen, “Generic Dynamic Models for Modeling Wind Power Plants and other Renewable Technologies in Large Scale Power System Studies”, To be published in IEEE Trans. on Energy Conversion, Available on-line since December 2016; DOI: 10.1109/TEC.2016.2639050; http://ieeexplore.ieee.org/document/7782402/

[13] P. Pourbeik, S. Soni, A. Gaikwad and V. Chadliev, “Providing Primary Frequency Response from Photovoltaic Power Plants”, CIGRE Symposium 2017, Dublin, Ireland, May 2017.

[14] A. Ellis, Y. Kazachkov, E. Muljadi, P. Pourbeik, J.J. Sanchez-Gasca,, “Description and Technical Specifications for Generic WTG Models – A Status Report”, Proc. IEEE PES 2011 Power Systems Conference and Exposition (PSCE), March, 2011, Phoenix, AZ.

[15] Matthew P. Richwine, Juan J. Sanchez-Gasca, Nicholas W. Miller, “Validation of a Second Generation Type 3 Generic Wind Model”, Proc. IEEE PES General Meeting 2014, Washington, DC, USA, July 2014.

[16] A. Ellis, P. Pourbeik, J.J. Sanchez-Gasca, J. Senthil, J. Weber, “Generic Wind Turbine Generator Models for WECC – A Second Status Report”, Proc. IEEE PES General Meeting 2015, Denver, CO, USA, July 2015.


http://ieeexplore.ieee.org/document/7782402/

https://www.wecc.biz/Administrative/WECC_Renewable_Energy_System_Models_Webcast_071615.pdf

http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000003002006525

https://www.wecc.biz/Reliability/WECC%20Solar%20Plant%20Dynamic%20Modeling%20Guidelines.pdf

https://www.wecc.biz/Reliability/WECC%20Wind%20Plant%20Dynamic%20Modeling%20Guidelines.pdf

https://www.wecc.biz/Reliability/WECC-Solar-PV-Dynamic-Model-Specification-September-2012.pdf

https://www.wecc.biz/Reliability/WECC-Second-Generation-Wind-Turbine-Models-012314.pdf

https://www.wecc.biz/Reliability/WECC-Type-4-Wind-Turbine-Generator-Model-Phase-II-012313.pdf

https://www.wecc.biz/Reliability/WECC-Type-3-Wind-Turbine-Generator-Model-Phase-II-012314.pdf

http://www.nerc.com/files/Standards%20Models%20for%20Variable%20Generation.pdf

http://www.e-cigre.org/Search/download.asp?ID=328.pdf

Appendix XXX: Disturbance-Based Verification Examples

Text


Appendix XXX: Capability Testing for Other Dynamic Reactive Resources

MOD-025-2 is only applicable to generating resources and synchronous condensers, as outlined in the Applicability section of the standard. However, the penetration of power electronic dynamic reactive resources such as STATCOMs and SVCs continues to increase to support the changing resource mix of the grid and maintain acceptable pre- and post-contingency voltages. Yet, there are no requirements that TOs test and report the capability of these resources. It is recommended that TOs test their dynamic reactive resources greater than 20 MVA (gross nameplate rating) that are directly connected to the BES, to ensure consistency with the other dynamic reactive resources that fall under the MOD-025-2 applicability. STATCOMs and SVCs provide many of the same voltage functions and attributes as synchronous condensers including:

They provide dynamic reactive power to support system voltages They should be modeled in steady-state power flow simulations as a continuous range of reactive power

from a minimum to a maximum capability with a voltage set point Planners and operators rely on these resources to ensure sufficient reactive power is available to

maintain steady-state and post-contingency voltage levels Static excitation systems controlling field quantities use power electronics (e.g., thyristor bridge), similar

to the power electronic controls for SVCs that control the firing angles on thyristor-controlled reactors (TCRs) and thyristor-switched capacitor (TCS)

Inaccurate representation of the capability of these resources for reactive power planning and operation has the same effect on grid performance as these errors in generators and synchronous condensers. When used in determination of operating limits such as SOLs and IROLs, these resources have a direct impact on grid reliability and should be modeled with accurate capability.


Recommendation: TOs should test their dynamic reactive resources greater than 20 MVA (gross nameplate rating) that are directly connected to the BES, to ensure consistency with the other dynamic reactive resources that fall under the MOD-025-2 applicability. The NERC PC and OC should consider the reliability impacts of not requiring capability verification of other types of devices such as SVCs and STATCOMs, and determine if addition action is necessary to make this a standard requirement for TOs.

Appendix XXX: List Acronyms

The following acronyms are used throughout this guideline.


Contributors

NERC gratefully acknowledges the invaluable contributions and assistance of the following industry experts in the preparation of this guideline.

Name EntitySigrid Bolik SenvionNathan Etzel PacifiCorpSamer El Itani SenvionVladimir Chadliev First SolarGordon Kawaley Bonneville Power AdministrationJoergen Nygaard Nielsen SiemensShawn Patterson U.S. Bureau of ReclamationPouyan Pourbeik PEACEMatthew Richwine General ElectricJuan Sanchez-Gasca General ElectricJay Senthil Siemens PTISachin Soni First SolarSpencer Tacke Modesto Irrigation DistrictSong Wang PacifiCorpSteve Yang Bonneville Power AdministrationBob Zavadil EnernexMohamed Osman North American Electric Reliability CorporationRyan Quint North American Electric Reliability Corporation


Contributors

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Example SubheadingThis is example text that you can use for proper formatting; delete or replace before publication. This is example text that you can use for proper formatting; delete or replace before publication. This is example text that you can use for proper formatting; delete or replace before publication. This is example text that you can use for proper formatting; delete or replace before publication.

Example SubheadingThis is example text that you can use for proper formatting; delete or replace before publication. This is example text that you can use for proper formatting; delete or replace before publication. This is example text that you can use for proper formatting; delete or replace before publication. This is example text that you can use for proper formatting; delete or replace before publication.

Table 2.1: Report Template Formatting

Font Size Typeface Space Before Space After Color

Cover Page

Title Tahoma 48 Bold 0 0 white

Subtitle Tahoma 24 Roman 0 0 white

Internal Pages

Chapter Title Tahoma 16 Bold 0 0 dark blue

Section Heading Tahoma 14 Bold 0 0 black

Sub-Heading 1 Tahoma 11 Bold 0 0 black

Sub-Heading 2 Tahoma 11 Bold, Italic 0 0 black

Body Text Calibri 11 Roman, Justified 0 0 black


Contributors

Header/Footer Calibri 9 Bold, Centered 0 0 dark blue

Footnotes Calibri 9 Roman 0 0 black


Contributors

Figure 2.1: Unavailability of NERC Transmission Transformers by Outage Type (2010–2013)

Highlight Box Example


A highlight box is used to emphasize key terms, facts, figures, etc. Always use NERC Light Blue as the fill color. Refer to the NERC Style Guide (Chapter 6 – Formatting) for guidance on other NERC corporate colors.

Documents

Reliability Guideline - PPMV for Inverter-Based … Plant Modeling and... · Web viewThe North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory