Reliability Considerations for
BA Communications with
Increased Variable Generation
NERC IVGTF Task 2.2 Report
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Table of Contents
Table of Contents .............................................................................................................................ii
1.
Introduction ............................................................................................................................ 1
2.
Communications and Load Balancing ..................................................................................... 4
2.1
3.
Lessons Learned from the European Grid ........................................................................ 5
Current Practices in Areas with Significant Wind Penetration ............................................... 8
3.1
Areas with Market Structured.......................................................................................... 8
3.1.1
ERCOT ........................................................................................................................ 8
3.1.2
NYISO ...................................................................................................................... 10
3.1.3
PJM .......................................................................................................................... 11
3.1.4
BPA .......................................................................................................................... 12
3.2
Non-Market Areas .......................................................................................................... 15
3.2.1
3.3
4.
AESO ........................................................................................................................ 17
3.3.2
BC HYDRO ............................................................................................................. 18
3.3.3
Hydro-Quebec ...................................................................................................... 18
Additional Considerations ..................................................................................................... 19
IEC Standard 61400-25 ................................................................................................... 19
Registry Criteria and FERC 661A ........................................................................................... 20
5.1
6.
Canadian Markets .......................................................................................................... 17
3.3.1
4.1
5.
Hawaii ..................................................................................................................... 15
FERC Order 661A ............................................................................................................ 20
Specific Recommendations ................................................................................................... 22
6.1
Communication Recommendations for Wind Resources .............................................. 22
6.2
Recommendations for NERC Standards ......................................................................... 23
Appendix I: International Markets ............................................................................................... 24
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United Kingdom ........................................................................................................................ 24
Ireland (ESB) .............................................................................................................................. 24
Spain.......................................................................................................................................... 26
Denmark.................................................................................................................................... 27
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Chapter # — Chapter Title
1.
Introduction
Variable generation, especially wind and solar, is a growing part of the generation mix
throughout North America. Increased variability will require a robust communication network
between Balancing Authorities (BAs) and plant operators, to ensure the grid continues to
operate reliably.
Improved forecasting accuracy and expanded back-up generation facilities (i.e., natural gas
plants) with expedient ramp rates can help to alleviate these disadvantages. However, in order
for wind generation to provide power plant control capabilities, it must be visible to the system
operator and able to respond to dispatch instructions during normal and emergency conditions.
Accordingly, enhanced communication protocols will be needed to ensure wind resources can
continue to become a more significant part of the North American generation mix, without
compromising grid reliability.
Real-time communication capabilities for system operators will continue to play in instrumental
role, especially during system restoration efforts that require increased coordination between a
given Balancing Area and the Transmission System Operator (TSO). The TSO’s inability to access
up-to-date information on the output of variable generation resources have caused
consequences such as those seen during an event in November 2006, when the European grid
experienced power disruption to over 15 million households [2]. It was determined that grid
operators lacked the capability to communicate output data for variable wind resources – most
of which were reconnecting to the distribution system automatically (as system conditions
allowed). The lack of real-time visibility of these resources ultimately counteracted the TSO’s
efforts to effectively balance the system.
Communication protocols used by wind plants and other variable generation can range from
basic telephone calls and emails to different SCADA (supervisory control and data acquisition)
systems. Currently, no industry-wide protocols have been established. This paper will explore
some of the Balancing Area (BA) communication protocols used in North America, with a focus
on the effectiveness of these protocols in the absence of conformity. Before exploring these
different protocols, it is important to first understand the purpose and functions of a BA.
The North American Electric Reliability Corporation (NERC) is responsible for ensuring the
reliability of the bulk power system in North America. Anticipating the growth of Variable
Energy Resources (VERs), in December 2007, the NERC Planning and Operating Committees (PC
and OC) created the Integration of Variable Generation Task Force (IVGTF), charging it with
preparing a report to identify the following:


1
Technical considerations for integrating variable resources into the bulk power system,
and
Specific actions, practices and requirements, including enhancements to existing or
development of new reliability standards.
Report Title – Month 2011
One of the identified follow-up tasks involved the examination of common practices and
existing criteria in systems with high penetration of VERs. IVGTF Subgroup 2-2 was charged with
providing the following work plan (Table 1):
Table 1: IVGTF Task 2.2 Work Plan
Objective
To ensure that Balancing Areas have sufficient
communications for monitoring and sending dispatch
instructions to variable resources.
Abstract
Adequate communication of data from variable
generation is not only a vital reliability requirement, but
also such communications are necessary to support the
data analysis posed by other recommended actions. The
NERC Operating Committee should undertake a review
of COM-002, FAC-001 and registry criteria to ensure
adequate communications are in place. Further, as NERC
Standards’ Project 2006-06 is reviewing COM-002, input
to this review should be provided. If these standards are
found to be inadequate, action should be initiated to
remedy the situation (e.g. a SAR).
Lead
Ad Hoc group: Members from IVGTF - Planning and
Operating
Deliverables
Review of NERC’s Facilities Design, Connections and
Maintenance, (FAC) Standard FAC-001-0 to ensure that
the following are addressed: (1) establish appropriate
interconnection procedures and standards; (2) ensure
adequate communications considering COM-002-2 and
registry Criteria; (3) provide input to NERC Standards’
Project 2006-06, 0 which is reviewing COM-002.
Objective
To ensure that Balancing Areas have sufficient
communications for monitoring and sending dispatch
instructions to variable resources.
This report focuses on the operating timeframe – from real-time to day ahead, and out to 48
hours in advance. Forecasting of variable generation resources is important in all timeframes,
and there are many uses for longer-range forecasts from days and weeks (e.g., transmission
outage planning and minimum generation issues) to years (e.g., integrated resource planning,
where resource flexibility and ramping capabilities should be increasingly valued, and the
generation mix if not appropriately planned can raise bigger challenges/issues during operating
timeframe). Such longer-term schedules are adjusted as they get closer to real-time and the
critical operating impacts to bulk power system reliability tend to be closer to real time.
Therefore, again in the interests of focus and expediency, this report primarily discusses the
IVGTF Task 2.2 Report – Month 2012
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Chapter # — Chapter Title
forecasting requirements for the coming 48 hours and particularly considers how forecasting
information can be delivered to the system operator in a useful and actionable way.
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2.
Communications and Load Balancing
The continuous balancing of generation and demand is essential in maintaining the reliability of
the bulk power system, which is designed to meet customer demand in real-time. With
conventional generation, fuels are delivered or stored on-site (i.e., coal, natural gas, nuclear)
and offer added certainty in terms of generation output projections. This characteristic is
absent from most renewable resources, especially wind plants with inherent output variability.
The impact of variability magnifies the importance of adequate communication between the BA
and plant operators to balance output and load. The information necessary to perform
generation dispatch responsibilities can vary from one resource type to another. However,
there are certain outputs that are common to each resource, including the following data
points:

Voltage

Megawatt (MW)

Mega-Var (Mvar)

Control status (dispatch availability)

Breaker status (on- or off-line)

Fuel flow

Fuel pressure (gas-fired units)
For most traditional thermal power plants, other data may include the per-unit incremental
heat rate, ramp rate, low operating limits, and high operating limits. This information is used to
calculate the desired set point for the unit – a critical piece of information for system operators.
Additional data can be requested for reliability purposes from certain plants, including the
status of automatic voltage regulating equipment. Hydro plant operators often require
additional information for economic dispatch control such as water flow and reservoir levels
needed to control output to meet environmental and contractual limitations. This information
is primarily designed to be transmitted and received between the generation units,
transmission components, and distribution elements and the utility’s Supervisory Control and
Data Acquisition (SCADA) systems that control the power system using Distribution Network
Protocols (DNP). With the migration to Regional Transmission Organizations (RTO) that
maintain responsibility for coordinating utility operations within a given area of jurisdiction
(usually the respective BA), there is a need to transfer all relevant utility-wide data to the RTO
SCADA systems.
Additionally the introduction of regional markets and the increase of market activity during the
late 1990s has lead RTOs to require additional capabilities to determine the impact of energy
schedules between Regions. This information is primarily transmitted through an Inter-Control
Center Communications Protocol (ICCP) over a wide area network (WAN).
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Basic ICCP functionality, specified as “Conformance Blocks,” include all tools used to convey
data. Many of these the following examples are defined in various parts of IEC 60870-6:

Periodic System Data: Status points, analogue points, quality flags, time stamp, change
of value counter, protection events. Association objects to control ICCP sessions.

Extended Data Set Condition Monitoring: Provides report by exception capability for the
data types that block 1 is able to transfer periodically.

Block Data Transfer: Provides a means transferring Block 1 and Block 2 data types as
block transfers instead of point by point. In some situations this may reduce bandwidth
requirements.

Information Messages: Simple text and binary files.

Device Control: Device control requests: on/off, trip/close, raise/lower etc and digital
setpoints. Includes mechanisms for interlocked controls and select-before operate.

Program Control: Allows an ICCP client to remote control programs executing on an ICCP
server.

Event Reporting: Extended reporting to a client of error conditions and device state
changes at a server.

Additional User Objects: Scheduling, accounting, outage and plant information.

Time Series Data: Allows a client to request a report of historical time series data
between a start and end date from a server.
As US markets are developed into regional markets with centralized economic dispatch,
additional information will become available, such as minimum dispatch, maximum dispatch,
offer curve, and ramp rates. These tools will replace traditional tactics that utilities were using
for dispatch only within their control area. While some markets can communicate directly with
generating plants, many are still using the host utility or scheduling entities with SCADA systems
to perform constrained economic dispatch control. This communication is still being performed
primarily with ICCP.
With the increase of variable generation in these developed markets, requirements have been
developed to help incorporate increasing levels of variable generation into BA operations to
optimize dispatching activities. Market operators have recognized the importance of
forecasting to better understand the output of variable generation and extreme events that can
cause reliability issues, as well as the need for additional review to enhance situational
awareness during times of system stress. This report will review current information and
communication requirements in some of the established markets and BAs.
2.1 Lessons Learned from the European Grid
Real-time communications capabilities for system operators will continue to play an
instrumental role, especially during system restoration efforts that require increased
coordination between a given BA and the Transmission System Operator (TSO). The TSO’s
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inability to access up-to-date information on the output of variable generation resources have
caused consequences such as those seen during an event in November 2006, when the
European grid experienced an event that resulted in the European grid being separated into
three distinct areas and resulting in disruptions for more than 15 million households. The two
major causes to the event were identified as violation of N-1 criteria and insufficient inter-TSO
coordination. Although wind was not a direct cause of the event, it impacted the event enough
for the issue of variable generation to be recognized.
At the time of the event, most of the wind generation in Europe was connected directly to the
distribution system. Consequently, the TSO lacked the necessary real-time wind output data to
make informed decisions on these resources. Initially, strong wind output in Germany was
being transferred to the Netherlands. A request for an outage of the double circuit ConnefordeDiele 380kV line was submitted on September 18, 2006 and approved on October 27, 2006,
with an initially scheduled outage period between 00:00-06:00 on November 5, 2006. On
November 3, 2006, the shipyard requested that the outage be rescheduled to 22:00 on the 4th
and approval was given with no N-1 violations projected in an updated analysis.
However, the short notice did not allow enough time for the reduction of the exchange
program between Germany and The Netherlands. The day-ahead action rules indicated that
these flows were considered firm by 08:00 and no additional analysis was performed to
consider the potential TSO impacts of the modified schedule.
At 19:00 on November 4, 2006, E.ON informed TenneT and RWE TSO about the modified
scheduled and the neighboring TSO granted permission at 19:30 to perform the switch, under
the assumption that TenneT and RWE systems would be secure.
After switching of the double circuit Conneforde-Diele line was completed at 21:39, the flows
on the Landesbergen-Wehrendorf line were approaching the safety limit value of 1,795 amps.
A subsequent investigation revealed that the E.ON TSO was unaware that the RWE TSO relay
had been set at 2,100 amps, compared to 3,000 amps at the E.ON terminal. At approximately
22:05 the flows on the Landesbergen-Wehrendorf line exceeded the limit of 1,795 amps, and
an alarm was triggered, requiring E.ON to take immediate action to reduce the flow on the line.
At 22:10, the E.ON Netz operator coupled the bus at Landesbergen in an attempt to reduce
flow on the line. Unfortunately, this had an opposite effect of increasing flow, which lead to
the tripping of the Landesbergen-Wehrendorf line and subsequent cascading trips of multiple
interconnected transmission facilities. Ultimately, the grid became separated into three
islands: the West zone, South East zone, and the North West zone.
The North zone experienced over-frequency, while the West and South East zones experienced
under-frequency, with the more severe declines in the West zone, decreasing to approximately
49 Hz, when normal operation is at 50 Hz. Prior to the decline in frequency and ultimate
separation, the power flow into the West zone was approximately 8,900 MW.
IVGTF Task 2.2 Report – Month 2012
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Chapter # — Chapter Title
The resulting under-frequency resulted in the interruption of 18,600 MW of load (1,600 MW of
pumping load) due to an additional 10,900 MW of generation tripping in the West zone (most
of was connected to the distribution system). 4,892 MW of tripped generation included wind
resources that were essentially invisible to the TSO in the West zone, that lacked real-time
output data. Moreover, relays at the distribution level had been calibrated without adequate
coordination with bulk power system operations to yield the necessary response to automatic
load reduction settings. This resulted in further complications to system restoration efforts, as
wind resources at the distribution level were automatically set to reconnect without the
visibility of the TSO.
Simultaneously, the North East zone was experiencing a similar problem, but in a reverse
scenario as the TSO’s efforts to recover from over-frequency operations were hindered by wind
in northern Germany. Wind resources attempting to automatically reconnect were
counteracting the actions of the TSO. Operators were eventually able to resynchronize the
three zones on November 6, 2006, at 22:49.
This event highlighted the impact that distributed generation can have on bulk system
operations – especially when the generation has high variability. Automatic reconnection
configurations can also have unintended consequences – especially during restoration efforts.
Most importantly, the inability of a given TSO to control, or at least monitor the output of
generation specifically connected to the distribution system, can pose a significant threat to the
reliability of the bulk power system.
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3.
Current Practices in Areas with Significant
Wind Penetration
3.1 Areas with Market Structured
There are various aspects to the current communication protocols between system operators,
Balancing Authorities, Reliability Coordinators, and individual generating units throughout
North America. This section will explores current practices in four market-structured
ISOs/RTOs: ERCOT, NYISO, PJM, and BPA.
3.1.1 ERCOT
The Electric Reliability Council of Texas (ERCOT) has a market designed to allow the
Independent System Operator (ISO) to communicate directly with resource entities through
market participants known as Qualified Scheduling Entities (QSEs). ERCOT has installed a Wide
Area Network (WAN) with an Inter-Control Center Communications Protocol (ICCP) to provide
communication services for real-time telemetry data, operational voice communications and
other necessary exchanges. Established communication protocols are used daily or hourly, to
ensure balanced generation and load.1
Figure 1: ERCOT WAN Communications System Overview
Router
CSU/DSU
Firewall
Router
MPLS
Network
CSU/DSU
ERCOT Austin
Participant
CSU/DSU
ERCOT Taylor
DACS
Network
CSU/DSU
Router
Firewall
Router
CSU/DSU
1 Electric Reliability Council of Texas, Inc., “Telemetry and Communication,” http://www.ercot.com/mktrules/guides/noperating/cur, July 2007.
IVGTF Task 2.2 Report – Month 2012
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Chapter # — Chapter Title
All required information must been provided for all resources participating in the ERCOT
market. Currently, BA-interconnected electric power providers are able to sell electric power as
needed by the system.
For all wind-powered generation resources, the necessary real-time telemetry data includes,
but is not limited to:
 Net and Gross MW and MVAR output
 Meteorological data (wind speed and direction, temperature, and barometric pressure)
 High and Low Sustained Limit (HSL and LSL)
 Normal and emergency ramp rate capabilities
 Resource status and turbine availability
This data must updated and be sent to the ISO with a frequency of 10 seconds or less.
Meteorological data is primarily used for wind power forecasting purposes. The real-time HSL
represents the current net output capability of the facility. This measurement has been of
particular importance for the ERCOT Region, particularly during periods when the output of a
given wind plant has been reduced in response to instructions from the ISO. In these instances,
it is critical that the respective dispatch systems accurately represent the potential of each wind
plant in order to reliably balance load and manage congestion.
In addition to the telemetry data, other information in also necessary to ensure reliable
operation, planning, and modeling activities, including:
 Resource schedules
 Projected outage information
 Physical resource parameters (e.g., total capacity, start-up times, minimum offline
times)
 Wind turbine type and size
 Geographical location (longitude and latitude)
 Hub height of the turbines
It is important for the ERCOT ISO to also provide information to the wind plants and QSEs, such
as real-time dispatch instructions (linearly ramped and stepped set points), price information,
wind forecasts, and flags to indicate the severity of dispatch instructions.
These communication requirements seek to provide reliable wind integration in ERCOT,
especially as existing nameplate capacity amounts to over 9 GW, with projections for an
additional 1.3 GW by 2019.2
2 North American Electric Reliability Corporation, “2010 Long-Term Reliability Assessment,” http://www.nerc.com/files/2010_LTRA_v2-.pdf,
October 2010.
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3.1.2 NYISO
Similar to the ERCOT ISO, ICCP is used for real-time telemetry data communication between the
NYISO and Transmission Owners (TO) that represent wind plants. The TOs collects data from
given points of interconnection using a Remote Terminal Unit (RTU) data concentrator. Various
methods have been developed to incorporate TO dispatch instructions from RTUs into
respective SCADA systems. The NYISO provides additional data requirements for wind plants in
the Wind Plant Operation Data Guide.3
Static information, including plant location, turbine output, and other data are also collected
during the initial registration of a given plant. Additional required data can be categorized as
follows:
1.
Real-time
2.
Plant outages
3.
Plant availability
Real-time data includes meteorological figures as well as the maximum available generation
(MW) of the plant. Some data requests are optional and each plant operator must decide
whether or not to provide these optional data elements.
Both the required and optional data elements are shown in the table below:
Table 3: NYISO Wind Plant Operator Data Guide - Real-Time Data Requested from
Each Wind Plant
Measurement
Type
Required/
Optional
Height of
Measure
ment
Unit
Precision (to
the
nearest…)
Max Available
Megawatts
SCADA
R
N/A
MW
0.1 MW
Wind Speed
Meteorol
ogical
R
Hub
Meters/Secon
d (m/s)
0.1 m/s
Wind Direction
Meteorol
ogical
R
Hub
Degrees from
True North
1 degree
Ambient Air
Temperature
Meteorol
ogical
O
2m and
Hub
Degrees
Centigrade (°C)
0.1° C
Ambient Air
Dewpoint
Meteorol
ogical
O
2m
Degrees
Centigrade (°C)
0.1° C
3 NYISO Wind Plant Operation Data Guide, http://www.nyiso.com/public/webdocs/documents/guides/Wind_Plant_Operator_Data
_Guide_2010.pdf, June 2010.
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Chapter # — Chapter Title
Ambient Air
Relative
Humidity
Meteorol
ogical
O
2m
(Percentage)
1.0 %
Barometric
Pressure
Meteorol
ogical
O
2m
HectoPascals
(HPa)
60 Pa
Plant outages and availability is also provided by wind plant operators through a NYISO web
interface. The expectation is that planned outage information will be reported at least two
operating days in advance. The reporting of unplanned outages is also required to be submitted
as soon as practical.
While the data provided by wind plants is of great importance, there have also been significant
efforts by the NYISO to review and verify this data. For wind plants that support automatic
output reduction response to dispatch instructions, direction from the ISO that ramps smoothly
from one set point to the next will likely be the most efficient. In specific situations when
manual action is required by a wind plant operator, it may be more useful to provide the wind
plant with a specific desired output level and allow the plant operator to take the necessary
action reach it.
Wind plants may also benefit from advisory instructions for areas that have dispatch engines
with long-term forecasting capabilities. This may allow these wind plant added opportunity to
be prepared for such ISO dispatch instructions.
Similar to ERCOT, the NYISO also provides wind plants with a flag indicating the severity of
dispatch instructions from the ISO. This flag is only set during periods when it is not economic
to run a given wind plant.
3.1.3 PJM
PJM requires both voice and data circuits. These requirements are typically met through a
Market Operations Center (MOC) that communicates with each individual plant, acting as an
interface to PJM.4 SCADA systems are used to communicate directly with individual generators
and smaller control centers. A data concentrator (e.g., Remote Terminal Unit (RTU) or
Generator Control System) is located at a given member’s site. After collecting data from the
industrial metering equipment, the data concentrator sends applicable information through
SCADA using either DNP 3.0, Level 2 or an ICCP consistent with the PJM Control Center
Requirements Manual.5
Every interconnected generator that is synchronized with the transmission system is required
to continually coordinate ongoing operations with the PJM ISO and Local Control Center. All
necessary and requested information – including the status of all equipment – is provided to
4 PJM “Manual 14D: Generator Operational Requirements,” http://pjm.com/~/media/documents/manuals/m14d.ashx. July 2011.
5 PJM “Manual 01: Control Center and Data Exchange Requirements, http://pjm.com/~/media/documents/manuals/m01.ashx. October 2011.
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ensure the electrical system can be operated in a safe and reliable manner. This coordination
includes, but is not limited to:
 Supplying low side generator net-MW and MVAR output;
 Supplying meteorological data (wind speed and direction are required, temperature,
pressure, and humidity are optional);
 Scheduling the operation and outages of facilities including providing advanced
notification;
 Coordinating the synchronization and disconnection of the Wind Plant with PJM and
Transmission Owner;
 Providing data required to operate the system and to conduct system studies;
 Providing documented start-up and shutdown procedures, including ramp-up and rampdown times;
 Following PJM-directed plant operation during emergency and restoration conditions;
 Following PJM-directed operation during transmission-constrained conditions.
Additionally, all generation facilities are required to install meteorological towers that provide
real-time weather forecasts to the BA. Specific data requirements for these towers include (but
are not limited to):
 Wind speed
 Wind direction
 Temperature
 Pressure
 Humidity
3.1.4 BPA
BPA uses ICCP or SCADA for real-time telemetry data communication between BA control
centers and wind plant energy management systems. In accordance with the business practices
of BPA Transmission Services, wind plants may provide data to the BA on a system- or
individual-resource basis. Wind plants exchange other types of data, such as schedules,
generation estimates, and meter readings, with BPA Transmission Services using the WECC
Electronic Industrial Data Exchange (EIDE) protocol or Customer Data Entry (CDE).
Customer Data Entry (CDE) is a BPA Transmission Services access point that allows transmission
customers to obtain information pertaining to its Ancillary Services, Loss Return obligations,
portfolio manager, and contract portfolio manager. CDE provide customers, including wind
plants, with access to data including: a) loss reports, b) portfolio management, c) Transmission
Service Requests, e-Tags, and contract information, d) shared path summaries and intertie uses,
and e) ancillary service use, including load estimates, generation estimates, self-supply
operating reserves integrated delivery amounts, and self-supply operating reserves obligations.
Outages are planned in accordance with the WECC 45-day outage planning process.
IVGTF Task 2.2 Report – Month 2012
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Chapter # — Chapter Title
Planned outage information can be accessed from Oasis or the BPA Transmission Services
website.6
BPA has modified its Technical Requirements for Interconnection to the BPA Transmission Grid
to include new data requirements for Wind Generators located in the BPA Balancing Authority
Area. Below is a summary of these data requirements.
Plant Operational Data Requirements – Statistic Data
 Number of turbines, total rated MW
 For each turbine:
o Model/type, nameplate capacity
o Turbine identification number (string/collector line if available)
o Individual turbine coordinates (Latitude/Longitude)
 Plant Telemetry Data via BPA SCADA/ICCP, every 2 sec
 Plant output (MW)
 Available capacity (MW, updated within 10 minutes of any change)
 High wind cutout (MW total)
 Plant control limit (MW, when output of plant is limited)
 Plant Planning Data
 Planned outages via email to Gen Dispatcher desk with dates, capacity limitations and
duration.
Plant Meteorological Data via web service, every minute
Data from the wind plant’s weather anemometers needs to be submitted to BPA via web
service as outlined in Attachment 2 and posted or refreshed every minute. Although one
minute averages would be preferred, instantaneous readings every minute will also be
accepted.
 Anemometer coordinates (Latitude/Longitude/height)
 Wind speed (mph, integer)
 Wind direction (degrees of north, integer)
 Temperature (degrees F, integer)
 Humidity (relative %, integer)
 Pressure (inches of Mercury, in Hg)
Nacelle Cluster Meteorological Data via web service, every ten minutes
Weather model grid resolution will become finer (12km down to 1-4km) as BPA improves the
forecasting system. For larger wind projects, it will be necessary to model the project as a
number of clusters. The selection of designated turbines representative of the clusters within a
wind project site will result from a collaborative process between BPA and the wind project.
The typical cluster will be a five blade diameter square with a center turbine designated to
provide met data. The data needs to be submitted to BPA via web service as outlined in
6 http://transmission.bpa.gov/ts_business_practices//business_practices_pdf.pdf.
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attachment 2 and posted or refreshed every ten (10) minutes. Although ten (10) minute
averages are preferred, instantaneous reading every 10 minute will also be accepted.






Select turbine number and coordinates (Latitude/Longitude)
Wind speed (mph, integer)
Wind direction (degrees of north, integer)
Temperature (degrees F, integer)
Humidity (relative %, integer)
Pressure (inches of Mercury, in Hg)
Historical data, last 2 years or as available, if less than 2 years in service7
 Available Capacity (hourly average)
 Plant meteorological data (10 minute average. Although ten (10) minute averages is
preferred, instantaneous reading every 10 minute will also be accepted.)
 Anemometer coordinates (Latitude/Longitude/height)
 Wind speed (mph, integer)
 Wind direction (degrees of north, integer)
 Temperature (degrees F, integer)
 Humidity (relative %, integer)
 Pressure (inches of Mercury, in Hg)
Communication Methods - Tool Selection8
The wind generator’s underlying web service tool must be a Business Intelligence tool such as
Microsoft Web Services, Windows Communication Foundation, BizTalk or an equivalent tool for
Enterprise-level data transfer.
Web Service Description Language9
The wind generator must provide a Web Services Description Language (WSDL) to BPA that
defines the following:
 The XML schema used to send the data
 Methods that will be used
 Variables/arguments that will be passed in those methods
7 Data to be emailed to BPA in excel or mutually acceptable format.
8 The tool cannot be FTP-based.
9 Note that acceptable methods will include a BPA Pull or Push (i.e., the wind generator will post data for BPA to pull or will receive data that
BPA pushes). The wind generator will not push data to BPA.
IVGTF Task 2.2 Report – Month 2012
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Chapter # — Chapter Title
3.2 Non-Market Areas
3.2.1 Hawaii
The electric utilities in Hawaii are operated as autonomous island systems by regulated public
utilities on the main islands, under the ownership of Hawaiian Electric Company (HICO) and its
subsidiaries. Kauai is supplied by the Kauai Island Utility Cooperative (KIUC).
Wind plants in Hawaii are planned and operated through negotiated purchase power contracts.
The communication and interconnection capabilities are determined by specific contracts.
Forecasting and control requirements for reactive and real power were developed prior to
2005.
There is a 30 MW wind plant on the island of Maui, and two smaller wind plants (20.5 MW and
10.25 MW) on the island of Hawaii. The loads of the both systems are very similar, each
peaking at approximately 195 MW, twice the minimal load. Additional facilities are also in the
planning phases.
Wind resources have significant impacts on the islands of Maui and Hawaii in particular,
specifically with regards to frequency control. This is due to the combination of the variable
output, which creates frequency issues, partially due to the large influx of variable generation.
During minimum load conditions, conventional generators are backed-down and provide
frequency-response as necessary. However response capabilities are reduced during periods of
over-frequency.
The Maui and Hawaii systems have been successful in the integration of wind resources, largely
because the system operators have additional generation resources that can be quickly
dispatched in real-time. This is necessity to supplement changes in wind output and ensure a
constant balance of load and demand. The variability of the wind plants directly impacts the
amount of regulating reserves that are required, which were historically minimized and based
solely on the sub-hourly variability of the load and higher production costs on the islands.
Ultimately, the intra-hour variability determines the amount of regulating reserves necessary to
keep maintain a reliable system.
The current control requirements for wind plants on Maui and Hawaii are as follows:
Active Power Control – Curtailment Interface
Wind plants accept a signal from the system operator to restrict the output (MW) to a specified
maximum level. This maximum level is echoed back to the control room, along with a digital
indication that the plant has been curtailed. The wind plant then must immediately respond to
active power controls, with the controlled ramp rate not to exceed 2 MW per minute.
Curtailment is used primarily to reduce wind plant output during the following conditions:
1.
During excess energy conditions;
2.
To address specific system constraints (i.e., line overload);
3.
To mitigate frequency control issues caused by wind variability;
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4.
To minimize variability impacts during system restorations.
These active power controls are not automatic and require implementation by the system
operator.
Excess energy occurs routinely, and the reduction in output results in lost potential sales to the
supplier. Accordingly, these excess energy losses are recognized in the initial contract. Existing
variable producers, including wind and run-of-river hydro, are curtailed according to a “priority
order” for curtailment, based on a date at which the entity came online. This method has
proven administratively burdensome and not practical for a large number of producers.
Reactive Power Control
Plants are required to control the voltage at the point of interconnection. The target voltage is
specified by the system operator through the SCADA/EMS system.
Wind Speed Indication
A wind speed analog reading from the wind plant is required by contract and provides an
aggregate reading for each wind plant. All wind plants also offer a direct anemometer reading.
Currently there are no specific requirements for wind plants to provide the location at the
plant, height and other information, such as wind speed and direction. This data would be
especially useful for system operators in near-term forecasting and allows them to determine
the recent variability of a given wind plant, which is useful in evaluating the necessary reserves
to counter variability. Specifically, it allows lower reserves when wind speeds are in excess of
those needed for maximum output, which results in steady wind output, as opposed to
conditions where wind speeds are in the steeper part of the power curve.
There are also no requirements for the operating wind plants to provide forecasts for power
output. There is no mechanism within the power purchase contracts to implement additional or
modified technical requirements. In order to allow for improved forecasting capabilities, the
following information would be helpful, which was not required in the existing power purchase
contracts:
 Wind speed and direction, provided at turbine hub height
 Breaker status and status indication allowing capture of how many turbines are
available and online. This information is necessary to refine the forecasting.
 Require temperature, dew point, barometric pressure
 Day ahead and week ahead maintenance plans
 Indication from the wind plant when one or more wind turbine(s) approach high windspeed cut-out or is below minimum production
 Maximum available wind power
Fortunately, demand behavior on these two islands is more predictable, primarily because of
minimal industrial load, which can be more volatile. However, improved near-term wind
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forecasts could help planners determine the optimal level of reserves to improve efficiency
without threatening reliability.
3.3 Canadian Markets
3.3.1 AESO
In recent years considerable wind generation has been added to the Alberta Interconnected
Electric System (AIES), with plans for additional resources currently in development. The
Alberta Electric System Operator (AESO) has been working with wind generation developers
and stakeholders to address integration issues related to wind power. This effort has involved
the multiple technical studies that have examined the operational impacts of wind generation
and its technical characteristics and variable output.10
Voltage regulation setpoints within AESO are maintained between 95 to 105 percent of the
rated voltage through SCADA, and with the control of either AESO or TFO. Over-frequency
curtailment provisions have provided by AESO, stating that Underfrequency and overfrequency
relaying will automatically disconnects generators from the AIES will not operate for
frequencies in the range of >59.4 to <60.6 Hz.11
Interconnecting to the TFO is provided with functionality and by remote control to trip only the
interconnection breaker(s) at the POI, or collector buss feeder breakers. If tripped, the WPF
connection will require authorization by the AESO system controller.
A provision for MW control states that if no MW control is available, then trip control may be
exercised to reduce load and the facility is required to remain disconnected during the system
operating constraints.
Load then must be effected within 10 miutes of the operator’s instruction, or it may be subject
to a disconnection. Maximum ramp rates of all WPF must not exceed 10% of all aggregated per
minute MW capacity.
SCADA requirements for AESO are outlined in the “Electric Facility Data and Data for the Albert
Control Area” 0pp-003.1:
 Wind speed (from a single point of measurement at the WPF)
 Wind Direction (from a single point of measurement at the WPF),
 Voltage setpoint
May require provisions for system disturbance monitor that complies with the AESO
requirements for PMU. When required, it will measure 3 phase voltages and currents:
 All collector bus voltages, phase to ground measurement
10 http://www.aeso.ca/gridoperations/13902.html.
11 http://www.aeso.ca/downloads/OPP_804.pdf.
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All collector currents, or currents on the low side of the transmission step-up
transformers if CT unavailable on individual feeders
Transmission system voltages phase to ground measurement
Transmission system currents
Transmission system frequency measured on the transmission system side of the stepup transformer.
3.3.2 BC HYDRO
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Telemetry/control interface necessary for MW curtailment signal, 15 MW average may
not exceed, through SCADA or other means of contact with the wind plant operator.
MW output, megavar output
Number of turbines offline due to high wind
Number of turbines offline due to electrical or mechanical problems
Breaker status for substation transformer and all shunt compensation devices
Tap position of the wind plant substation transformer, if fitted with on-load tap
changers
Turbine availability data such as turbines offline or online due to high winds, lack of
wind, or cut out due to disturbance (through SCADA)
Average wind speed and direction at the site to facilitate use in forecast
Telemetry/control interface for specifying voltage regulation setpoints at the POI
between the wind farm and transmission grid
3.3.3 Hydro-Quebec
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4.
Additional Considerations
4.1 IEC Standard 61400-25
The International Electro-technical Commission's (IEC) Technical Committee 57 (TC57)
developed a protocol for electric substation control and communications called IEC 61850. This
standard protocol permits control of the elements in a substation over Ethernet or other
communications networks. The latency is very small and may be used for protective purposes,
such as relay tripping of circuit breakers.
That standard was adapted or extended to wind turbines through an additional standard, IE
61400-25, by the IEC TC88. There are several parts of this standard, including:
 IEC 61400-25-1 -- Wind turbines - Part 25-1: Communications for monitoring and control
of wind power plants - Overall description of principles and models
 IEC 61400-25-2 -- Wind turbines - Part 25-2: Communications for monitoring and control
of wind power plants - Information models
 IEC 61400-25-3 -- Wind turbines - Part 25-3: Communications for monitoring and control
of wind power plants - Information exchange models
 IEC 61400-25-4 -- Wind turbines - Part 25-4: Communications for monitoring and control
of wind power plants - Mapping to communication profile
A conceptual drawing of the communications needed to and within a wind power plant is
provided in Figure 3 below. The blocks represent the different parties that need to
communicate with other parties, and the solid lines represent that communication.
The standard is intended to facilitate all of these communications. The standard may be
extended by manufacturers to accommodate their own needs or capabilities. Application-toApplication interface information flow is included, and future considerations are also included.
The detail included in the standard is shown in 61400-25-2, in their diagram of a wind turbine.
Each of the functional areas (shown in yellow as part of the wind turbine) is described in detail
in the standard for purposes of collecting data. For example, the rotational speed of each
turbine has a specific name. The data may be communicated to data collection systems using
that name. The data collection system may be manufactured or programmed by anyone, and
the data will be readable by any other system using the same protocol.
The IEC 61400-25 standard is relatively new, and in 2011 was undergoing its first revision. New
logical nodes are being added and even more detail will be available in the future versions. The
protocol will be extended to describe the operation of multi-unit wind plants as a unit, in
addition to describing the individual turbines. IEC 61400-25 is offered as an example of an
internationally accepted standard method for communication with a wind plant.
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5.
Registry Criteria and FERC 661A
5.1 FERC Order 661A
In December of 2005, FERC issued Order 661A that required public utilities that own, control, or
operate facilities for transmitting electric energy to enhance their open access transmission
tariffs to include standard procedures and technical requirements for the interconnection of
large wind generation. This order added Appendix G to the Large Generation Interconnection
Agreement (LGIA) for generators above 20 megawatts. This order focused on three different
areas of concern. First was for the generators to demonstrate low voltage ride through
capability at the point of interconnection. The second requirement was for the generation
facility to maintain a power factor between .95 leading to .95 lagging at the point of
interconnection, if shown to be required in an interconnection study. The third requirement
was for the generation facility to provide supervisory control and data acquisition (SCADA)
capability to transmit data and receive instructions from the transmission provider. The
Transmission Provider and the wind plant Interconnection Customer shall determine what
SCADA information is essential for the proposed wind plant. Depending on the Transmission
Provider and the Interconnection Customer, these requirements could vary dramatically from
one Transmission Provider to another. Several Regional Transmission Operators that operate
markets have, as outlined in this report, published detailed requirements for all generation
within their market footprint.
5.2 NERC Functional Model
Currently NERC is on Revision 5.0 of the Statement of Compliance Registry Criteria. This
criterion is utilized to see if an entity is responsible for meeting the NERC reliability standards.
The criterion identifies the Generator Owner/Operator as the entity that owns and maintains
the generating units as well as the entity that operates the facilities and performs the functions
of supplying energy and interconnected operations services. Entities are excluded from the
requirement to meet NERC reliability requirements if they do not satisfy certain generation
criteria. The compliance requirements for generators are as follows:
 Any generator that meets any of the following criteria is required to comply;
 Individual generating unit > 20 MVA and is directly connected to the bulk power system,
or;
 Generating plant/facility > 75 MVA (gross aggregate nameplate rating) or when the
entity has responsibility for any facility consisting of one or more units that are
connected to the bulk power system at a common bus with a total generation of 75
MVA gross nameplate rating, or;
 Any generator, regardless of size, that is a black start unit material to and designated as
part of a transmission operator entity’s restoration plan, or;
 Any generator, regardless of size, that is material to the reliability of the bulk power
system.
Most wind facilities that in aggregate are less than 75 MVA, are not registered in the
compliance registry as a generator owner/operator and therefore not subject to compliance
audits from the regional entities. The fourth bullet above allows the inclusion of smaller
generators in the compliance program, but usually individual generators by themselves are not
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significant to the system reliability. There is usually a reluctance to have smaller generators
register in the NERC compliance registry. However, several smaller generators in the same
general area can impact the transmission system. It is not uncommon for a number of smaller
generators, in aggregate, to have a significant impact on transmission flows within a Balancing
Authority area.
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6.
Specific Recommendations
6.1 Communication Recommendations for Wind Resources
A range of data that would enhance the reliability of the bulk electric system has been
identified. Specific data and associated communication requirements identified are already
required in developed markets. These data and communication capabilities should be provided
to the BA by all generation operating in the BA which has an impact on the reliability of the BES.
These are listed as follows:
 Net and Gross MW and MVAR output
 Meteorological data (wind speed, wind direction, temperature, and barometric
pressure)
 High and Low Sustained Limit
 Normal and emergency ramp rate capability
 Turbine availability
 Breaker Status
 Modeling data (static information)
o Tower height
o Relay settings (including UFR settings)
o Type of turbines
 Voice circuit
o Available communication to plant operator
o Communication to address real time operational issues
 Set point and curtailment communication (to Balancing Areas)
Currently, most of these requirements are not applicable for a significant number of smaller
wind farms (less than 75 MW) unless they are covered in the interconnection agreement or the
market rules (if applicable). Generators connected to the Distribution system usually do not
have these data and communication requirements in their interconnection agreements either,
but as discussed in the section 1.8, can have a significant impact on the transmission system.
Several smaller wind farms, regardless of the interconnection to the transmission system or the
distribution system, can in aggregate have a significant impact on a specific area of the BES. For
these reasons we make the following recommendation: :
All generators 10 MW or greater within a BA regardless of interconnection point shall provide:
 Breaker status to the BA/TOP (FAC-001)
 Current MW and MVAR output (FAC-001)
 Voice circuit for communication of real time instruction (COM-002)
o Remote control of resources is adequate but should be capable of handling real
time operational issues.
 Coordination of relay settings, specifically under-frequency coordination (FAC-001)
The following should also be required for all generators 10 MW or greater within a BA
regardless of interconnection point, if a significant impact has been identified in an
interconnection study:
 Resource schedules with outage information (FAC-001)
 Meteorological data for forecasting (FAC-001)
 Availability (FAC-001)
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High and Low Sustained Limit (FAC-001)
o Including high wind cutout
o Temperature limitations
o Any other operational restrictions
6.2 Recommendations for NERC Standards
In order to implement these changes , the following standards will have to be reviewed and
updated:
 FAC-001: Transmission Operator would list their specific requirements for generation
not only for generation connected to the transmission system but also any generation in
the footprint that is within the area operated by the Transmission area that will impact
the operation of the Balancing Authority and Bulk Electric Transmission System.
 COM-002: Consider applying the standard to all generation 10 MW or greater. This
improvement in communication will not only improve data communication but also
require the generator operator to be available to address real time operational issues.
This can be accomplished with manned resources or remote control and monitoring of
the facilities.
 PRC-001:
Under requirement 3, make this requirement applicable to facilities 10
MW or greater. This will ensure that the necessary relay coordination has taken place to
reduce the reliability impact of un-expected relay operation, specifically operation of
under and over frequency relays. The generation should be set lower that the under
frequency load shedding relays in the region to ensure generation tripping does not
compound under frequency operation similar to the European event.
 TOP-001:
Under requirement 3, require all generation facilities 10 MW or greater
to have to comply to reliability directives from the Balancing Authority or the
Transmission Operator. Under requirement 7, all generation facilities 10 MW or greater
provide notice to the Balancing Authority and the Transmission Operator before
removing generation facilities from service to reduce the reliability impact to the
system.
 TOP-002-2b Under requirement 3, require all generation facilities 10 MW or greater
to provide its current, next day, and seasonal operations with the host Balancing
Authority and Transmission Provider. This will improve the reliability studies of the Bulk
Electric system.
 TOP-003-1
For generation facilities 10 MW or greater require outage coordination of
generation facilities including telemetering equipment and voltage regulation
equipment so that interconnected operations is coordinated between Balancing
Authorities, Transmission Operators, and Reliability Coordinators.
These changes should be reviewed and implemented in the next review cycle. Adding these
requirements to the functional requirements with audit oversight will ensure the operators
have the tools necessary for not only normal operations but also for abnormal operation and
system restoration.
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Appendix I: International Markets
United Kingdom
Table I: United Kingdom – Guidance Notes for Power Park Developers (September
2008)
Title
Unit
Total Power Plant
MW
Total Power Plant
Mvar
Line-line voltage at POI or User System Entry Point as appropriate
kV
System frequency
Hz
Injected signal or test logic signal
Hz/Volts
Available Power
MW
Wind Speed
m/s
Wind Direction
m/s
Plant Voltage
Voltage control instructions (issued to all Balancing Marker
participants). For power park modules the usual instruction is
Target Votlage Setpoint. Bilateral agreement will include any
variations to the requirements in the Grid Code applicable to an
individual site.
(MW)(kV)
N/A
Any other signals as agreed between the user and the National Grid
or as specified in the bilateral agreement
Ireland (ESB)
In Ireland, a controllable Wind Farm Power Station (WFPS) is a site containing at least one wind
turbine generator (WTG) which can automatically act upon a remote signal from the TSO to
change its active power output. The following points outline the current parameters of
operation for all WFPS in Ireland:
 Controllable WFPS grid code provisions are applicable to grid connected controllable
WFPS, that also must comply with most requirements for conventional generation (with
some exceptions).
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Active Power Control set-point sent by the TSO , commence implementation of setpoint within 10 seconds of the receipt of the signal. The rate of change of output no less
than the maximum ramp rate settings of the WFCS, as per WFPS1.5.3.12
Frequency response system signals: a control signal defining which power-frequency
response curves (1 or 2); which is to change between the two curves within one minute
from receipt of the signal from the TSO. The curve parameters may be changed, but are
not required to be settable in real-time and must be specified to the TSO at least two
weeks prior.
The wind farm control systems shall be capable of controlling the ramp rate of the
active power output with a maximum MW per minute ramp rate set by the TSO. There
is a maximum ramp rate over one minute and the maximum ramp rate over 10 minutes.
Falling wind speed or frequency response may cause either of the maximum ramp rates
to be exceeded. This may be specified by the TSO but requires two weeks of notice and
does not need to be changed online.
Voltage target setpoint: defined as a change to reactive power in response to a
modified voltage target setpoint, required within 20 seconds of the setpoint being
received.
List of signals from WFPS to TSO (Under 10 MW):
o Active Power output (MW) at the low side of the grid connected transformer
o Reactive power output at the low side of the grid connected transformer
o Voltage (in kV) at the low side of the transformer
o Available active power (MW) at the low side of the transformer
o Transformer tap positions
o Voltage regulation setpoint (in kV)
o On/off status for all reactive power devices exceeding 5 Mvar
o Circuit breaker and disconnect position; may include indications from MV circuit
breakers on the individual WTG circuits. Signals from individual WTG circuitbreakers shall not be required.
o A minimum of four sets of normally open potential free aux contacts in each grid
connected transformer lower voltage bay for fault indications,
o On/off status of TSO remote control enable switch, which disables the ability of
the TSO to send commands to the controllable WFPS
o If the POI is the high side of the grid transformer, then the active and reactive
power and voltage will also be required from the high side of the transformer.
o Controllable WFPS greater than 10 MW must provide meteorological data signals
at the designated TSO telecommunication interface cabinet:
 Wind speed at hub height
 Wind direction at hub height
 Air temperature
 Air pressure
These are to be provided by a dedicated meteorological mast located at the controllable
WFPS site or, where possible to do so, data from a means of the same or better
12 http://www.eirgrid.com/media/Register%20of%20Derogations%20WFPS1%20Nov09%20incl%20Extent%20of%20Compliance%20v4.pdf.
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accuracy. If the WTG are widely dispersed over a large area, meteorological data may
be required from
List of signals from WFPS to TSO (Over 10 MW):
o multiple sources by turbine groupings to reflect conditions for those groups.
o Controllable WFPS availability (0-100%)
o Percentage of WTG shutdown due to high wind (0-100%)
o Percentage of WTG not generating due to low-wind (0-100%)
o Active power control setpoint value (MW)
o Active power control in effect indication (ON/OFF)
o Frequency response system mode signal
o Frequency System response system status indication (on/off)
o Active power control setpoint
o Remote enable/disable of the active power control setpoint
o Frequency response system signal to change from power curve 1 to power curve
2
o Remote enable/disable of frequency response system
o Voltage regulation setpoint (form of analog value and a pulse to enable)
o Black start shutdown – disconnection of the WFPS by the TSO and prevent
reconnection in the event of a black start. In receipt of this signal, the WFPS
shall be required to trip the circuit breakers at the controllable WFPS connection
point and shutdown the WFPS in a controlled manner. Reconnection permitted
only following instruction from the TSO.
A designated responsible operator shall be contactable by the TSO at all times for
operational matters within 15 minutes and must be present at the connection point
within one hour and capable of taking any required actions. Available 24 hours a day
and 365 days a year.
If the active power control, frequency response or voltage regulation facilities for the
WFPS become unavailable, the TSO is to be contacted.
Grid codes and interconnection requirements are continually reviewed and updated. The
results below are based upon the cited references, which in some cases are drafts or codes
under revision. In addition, the entity responsible for defining operational interconnection
criteria is under transition. For the most recently issued requirements are often available in
electronic format on the responsible entity’s web sites. Where available, these links are
provided.
Spain
Appropriate physical devices or procedures will be installed to guarantee compliance with all
limits on exchanged power established by the system operator and the transmission system
operator:
 Subject to technical requirements of “primary regulation complementary service” which
is applicable to all generation production entities
 Voltage control – subject to voltage control technical requirements for production
entities defined in section 8 of the present operational procedure
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An agreement is required between the transmission company and the connecting entity
covering the specific procedures for maintenance, duration and periodicity of outages,
and other operational issues.
Plant personnel or designated agent, able to make real-time operational decisions
regarding the plant interconnection, available 24-hours a day.
Remote trip capability, emergency disconnections
Ability for system operator apply ramp up/down limits (not related to decrease in
primary energy source).
Maximum real power export specified by system operator (curtailment)
Difference between potential active power production and curtailment set point limit
Activation/deactivation of power frequency regulation service, specification of reserve
power setpoints (up and down reserve separately).
Denmark
Active power control limit through single central signal, fast (less than two seconds)
Active power control limit (slow) for thermal constraints, 15 minutes
Plant status, i.e. high wind speed cutout, low wind speed cutout, turbine availability.
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