Requirements of Line Protection Relay Commissioning

Bilateral (trilateral) protection scheme between any generation station or switching station and the utility station(s) on the other side of the utility transmission line(s) is called tele-protection and is achieved through identical line protection relays at the stations.

In order to ensure compatibility between the stations, it is important that not only the make and model of the relays but also the firmware revision number and its boot revision number is the same, since the boot revision number might be different from the firmware revision number.

The single line diagram, the DC schematics of the line protection relays, as well as a copy of uploaded files to the relays are to be sent to the utility company for approval. At the end of commissioning the as left files shall also be sent to the utility for their approval and records.

Prior to direct transfer trip (DTT) testing, the communications equipment and devices are to be installed and commissioned.  BERT tests (Bit Error Rate Test) are to be conducted to make sure the communication channels are working properly. Then an end to end testing would wrap up the communication tests. 

It is also important to verify that the communication medium and all communication devices such as multiplexers are:

• Capable of working at the data transfer (bit rate) required by the protection relays.
• Have the same fiber optic wavelength.
• All are single mode or multi-mode.

A BERT typically consists of a test pattern generator and a receiver that can be set to the same pattern. They can be used in pairs, with one at either end of a communication chanell, or singularly at one end with a loopback at the remote end.

A loopback test is a test used for debugging physical connection problems in communication channel components in which a signal in sent from a communications device and returned (looped back) to it as a way to identify a failing node in a network. A comparison of the returned signal with the transmitted signal conveys the integrity of the transmission path. One type of loopback test is performed using a special plug, called a Wrap Plug, that is inserted in a port on a communications device.

A wrap plug, also known as a loopback plug, is a special plug that can be inserted into a port on a communications device to perform a diagnostic test called a loopback test. The effect of a wrap plug is to cause transmitted (output) data to be returned as received (input) data, simulating a complete communications circuit using a single computer. There are numerous possible configurations, depending on the hardware and the nature of the test to be performed.

The purpose of the communications channel is to transmit information about the system conditions from one end of the protected line to the other, including requests to initiate or prevent tripping of the remote circuit breaker. The former arrangement is generally known as a 'transfer tripping scheme' while the latter is generally known as a 'blocking scheme'. 

DTT Tests are generally done in two phases:

• Dead Zone Transfer Trip, DZTT
• Live Zone Transfer Trip, LZTT

DZTT is the set of tests done before the energization of the station. During DZTT the trip situations are simulated and signals are sent from either side to verify the intended operation is initiated on the other side. This would verify that the transfer trip equipment are effectively talking to each other and can operate in live conditions.

LZTT is the set of tests implemented after the energization of the station. The signals sent during LZTT actually trip the circuit breaker on each side of the line and de-energize the station and the transmission line.

References:

•          Communication Networks NSD570 – Teleprotection Equipment, ABB
•          SEL-2595 Teleprotection Terminal
•          https://en.wikipedia.org/wiki/Loopback
•          http://searchnetworking.techtarget.com/
•          https://www.techopedia.com/
• 
  
• 
  

CSA Approval Requirements for High Voltage Equipment in Ontario

Canadian Standards Association (CSA) is a non for profit organization accredited for Standard Council of Canada (SCC) to develop Canadian codes and standards. Electrical equipment sold in the market and installed in Ontario shall bear a CSA label which means they have been manufactured and tested according to the relevant CSA standard.

Custom made electrical equipment that are not type tested for mass production, can be factory tested or field tested by CSA, ESA (Electrical Safety Authority in Ontario) or other testing and inspection companies accredited by SCC.

ESA is the electrical safety authority in Ontario responsible for the inspection and approval of all electrical installations in the province.

Conformance with CSA is generally included in the specifications prepared for electrical equipment. However, CSA sticker is not mandatory for high voltage equipment.

For high voltage electrical equipment, the following two provisions are generally included in the specifications in order to meet the code requirements:

1- The high voltage equipment name plate shall include the CSA and/ or other internationally recognized standard the equipment is manufactured and tested to.

2- The control panel(s) shall bear a sticker of an accredited testing facility (CSA or others) to verify the compliance with the applicable CSA standard.

In some cases, the requirement of a CSA blue sticker is added to the purchase order to comply with the second provision above. 

The Blue Sticker indicates that the electric product is tested and meets CSA Group Special Publication SPE-1000. As such, the control panel should have blue sticker otherwise, the product does not meet PO requirement. 

Here is the typical sample of blue sticker affixed on control panel.

CSA Blue sticker is a special inspection label which indicates that the electric, non-healthcare product was tested and has met CSA Group Special Publication SPE-1000, Model Code for the Evaluation of Electrical Equipment, and the Canadian Electrical Code for installations and use. However, the CSA blue sticker is one of the labels that can be used to ensure the control panel meets the relevant code requirements.  

There is a CSA red sticker/ label - shown below- that can also be used for this application. CSA Red sticker is another special inspection label which indicates that the control panel was tested and has met CSA Group Special Publication SPE-1000, Model Code for the Evaluation of Electrical Equipment, and the Canadian Electrical Code for installations and use.

As stated above, there are a number of facilities that can inspect the control panel(s) of high voltage equipment and provide their relevant sticker which would be acceptable by ESA. 

According to ESA product approval card, the recognized certification markings are as follows:

According to the same document the following are the recognized panel-only field evaluation markings:

For example, for any HV transformer installed in Ontario, recognized inspection stickers would be needed for control panel(s) only. As far as the control panel is certified and the transformer nameplate refers to the applicable standards the transformer is built and tested to, the transformer would meet the requirements and will be approved and pass the inspection by the local ESA inspector.

Orange sticker issued by Electrical Safety Authority (ESA), or stickers issued by QPS or Entela depicted above can also be used in lieu of a CSA blue sticker and will be acceptable by local ESA inspector at site.

The certification agencies recognized by ESA are as follows: 

Canadian Standards Association (CSA)Curtis-Straus LLCElectrical Safety Authority Field Evaluation (ESAFE)FM ApprovalsIAPMO R&T, IncIntertek Testing ServicesLab Test Certification IncMet Laboratories Inc. (MET)NemkoNemko CanadaNSF InternationalOMNI Environmental Services Inc.QPSQuality Auditing InstituteSGSTUV AmericaTUV RheinlandUnderwriters Laboratories of Canada (ULC)Underwriters' Laboratories Inc.

The following is the list of field evaluation agencies recognized by ESA. 

Canadian Standards Association (CSA)Electrical Safety Authority Field Evaluation (ESAFE)Intertek Testing ServicesLab Test Certification IncMet Laboratories Inc. (MET)NemkoQPSQuality Auditing InstituteTUV AmericaTUV RheinlandUnderwriters Laboratories of Canada (ULC)

References:

  -  ESA Bulletin 36-1-21

  -  CSA Website: http://www.csagroup.org/services-industries/marks-labels/csa-marks/

  -  Standard Council of Canada Website: https://www.scc.ca/

NERC Requirements for Generation Stations

There are number of standards where NERC (North American Electricity Reliability Corporation) dictates specific requirements for the equipment, protection, control and operation of the transmission facilities. The below NERC standards can be referred to for this specific requirement: 

·         NERC PRC 023-2 (Transmission Relay Loadability)

·         NERC FAC-008-3 (Facility Ratings)

·         NERC PRC-025-1 (Generator Relay Loadability)

Although the current industry accepted design based on transmission code -referred to as "Good Utility Practice"- would inherently meet normal NERC requirements, the Engineer shall ensure all the requirements are met since the Client (Generator) would be subject to a NERC audit for compliance after the installation and commissioning of the generation station. 

The Engineer, needs to focus on the design requirements. However, there are more operational requirements that the Generator shall be responsible for and shall be taken into account. In other words, once the Engineer's design meets NERC requirements for reliability, that is where their obligations end.

The existing facilities that do not comply with the latest NERC requirements are allowed to continue to operate. But any major retrofit project or expansion to the existing facilities shall include additional equipment / systems to comply with the new requirements.

Our engineering and design of stations in Ontario -which is based on Ontario Energy Board's Transmission System Code- generally complies with NERC requirements. Two important aspects of generation stations that are mandatory and need to be taken into account during the initial estimate and subsequent design are as follows:    

1- There shall be two battery banks for protection and control equipment. Unlike load stations one common battery bank with two chargers would not be acceptable for generation stations.

2- There shall be a circuit breaker for switching at the switching station. Unlike load stations motorized disconnect switch would not suffice.

Those are the major two features that affect the generation stations. Other NERC requirements shall be similar to those of load stations and would not have a significant impact on the project estimate and the design.

The concern here for generation stations in wind power projects is that while in some cases the generators are derated to suit project requirements, NERC PRC 023-2 and NERC PRC-025-1 require 150% setting on transmission, transformer protection, 130% of rated nameplate of the generator (not de-rated).

This shall be dealt with closely as it could mean that the station and collector system shall be so designed to carry nameplate rated load. This will have a huge impact on the equipment while it can never happen in practice.

In wind generation facilities, loadability is limited by inherent current-limit in WTG's and the cables / transformers will not be overloaded however the relays are generally set to 10%-15% above maximum load per worst case scenario identified in the power flow study and fault overcurrent protections would be based on the fault fed from the grid. If WTG's are derated and the derated MVA has been the base for the design of stepup transformers and the collector cables, then the settings have to be selected for derated equipment loadability again by the power flow study.

The NERC standard has observation to synchronizing generator plants and transmission grid loadability which have 130% generation capability. In wind power projects with Type-4 Generator / Inverters, each generator is able to run up to 105% of its nominal rating then a 130% setting is not effective. If the design is based on /contracted for the derated WTG then the system is registered / recognized to the utility for the derated MVA not nominal generator MVA. Regardless, the generation is limited by generator manufacturer’s setting to the derated MVA.

If the generation is comparable to the grid MVA at the POI (point of interconnection), then the system stability is critical and loadability is important. In most of windfarm projects the source is considered weak-infeed and has no impact on stability then the loadability is more important to the client as profitability!    

links:
http://www.nerc.com/pa/Stand/Reliability%20Standards/PRC-025-1.pdf

http://www.nerc.com/pa/Stand/Project%202010132%20Phase%202%20Relay%20Loadability%20Generati/PRC_023_3_Transmission_Relay_Loadability_2013_06_20_Draft_3_(Clean).pdf

Bare Copper Conductor in Concrete

Bare Copper Conductor in Concrete

Some professionals are reluctant to use bare copper conductor embedded in concrete. They argue that the basic nature of concrete would be a source of corrosion. However this is not a proven argument and different codes and standards have allowed the use of bare copper embedded in concrete as a ground electrode.

The following excerpts of codes can clarify this issue\;

NEC

National electrical code  Article 093, Section E.5 only rules out Aluminum conductor for direct burial in concrete for grounding purposes:

“5. Metals used for grounding, in direct contact with earth, concrete, or masonry, shall have been proven suitable for such exposure.

NOTE 1: Under present technology, aluminum has not generally been proven suitable for such use.

NOTE 2: Metals of different galvanic potentials that are electrically interconnected may require protection against galvanic corrosion.”

NEC article 094, section B.6 specifically refers to copper conductor for use as concrete encased electrode application:

“A metallic wire, rod, or structural shape, meeting Rule 93E5 and encased in concrete, that is not insulated from direct contact with earth, shall constitute an acceptable ground electrode. The concrete depth below grade shall be not less than 300 mm (1 ft), and a depth of 750 mm (2.5 ft) is recommended. Wire shall be no smaller than AWG No. 4 if copper, or 9 mm (3/8 in) diameter or AWG No. 1/0 if steel. It shall be not less than 6.1 m (20 ft) long, and shall remain entirely within the concrete except for the external connection. The conductor should be run as straight as practical.”

CSA

Canadian electrical code Section 10 item 10-700 accepts concrete encased copper conductor as a grounding electrode.

“10-700  Grounding electrodes (see Appendix B)

(3) A field-assembled grounding electrode shall consist of

(a) a bare copper conductor not less than 6 m in length, sized in accordance with Table 43 and encased within the bottom 50 mm of a concrete foundation footing in direct contact with the earth at not less than 600 mm below finished grade”

Also in item 10-806:

“(6) Notwithstanding Subrule (2), a grounding conductor No. 6 AWG or larger shall be permitted to be embedded in concrete provided that the points of emergence are located or guarded so as not to constitute exposure to mechanical damage.”

And in table 43, the size of bare copper conductor is specified for different ampacities of the service conductor:

Table 43

Minimum conductor size for concrete-encased electrodes

(See Rule 10-700.)

Ampacity of largest service conductor or equivalent for multiple conductors, A	Size of bare copper conductor, AWG
165 or less	4
166–200	3
201–260	2
261–355	0
356–475	00
Over 475	000

Metring Plan

Ontario Transmission Code requires a Metering Service Provider (MSP) to be hired by load or generator customers for metering services. MSPs are third parties certified for the design, installation, commissioning and operation of metering equipment in HV stations.

AS a first step, MSP prepares a metering single line diagram (SLD) and sends to IESO for approval. MSP also prepares a metering plan to be submitted to IESO for approval. However, MSP does not submit the metering plan directly to the IESO as it needs to come from the Metered Market Participant (MMP). The plan needs to be updated with all the information including the MECs.

Once the SLD is approved IESO will then request package 2 to be submitted which will include the EITRP (Emergency IT Restoration Plan) and the MEC documents.  The secondary cable distances between IT's and the metering cabinet is required in order to complete the MEC calculations.

The Network Management System (NMS)

The Network Management System (NMS)

The Network Management System (NMS) is the supervisory control and data acquisition tool. It performs the following functions:

1- SCADA, 

2- The Real Time Network Analysis

3- The Study Network Analysis.

4- Training Simulation.

It provides the real time voltage and loading on the transmission system as well as monitoring and control of the status of the switches and breakers connecting the equipment to form the integrated network for the purpose of safe and reliable operation of the transmission system.

The NMS also provides predicative assessment tools which help in providing awareness of the situation of different elements of the electrical transmission grid to the operator. 

-------------------
Reference: Hydro One Operations Capital

IESO Requirements

  

In Ontario, the protection and control as well as the communication block diagram of any new high voltage substation shall be sent to IESO (Independent Electricity System Operator) for approval. The same applies to the plans for the protection systems upgrades at existing stations.

In case the existing remote trip relays are out of date (say Statrel RT8B ), they shall be replaced with ABB NSD 570 relays and Bell S4T4 (Schedule 4 Type 4) phone circuits. Dual A and B protections for each line shall be provided to communicate with the relays at upstream Hydro One station.

The existing line impedance relay - if out of date - shall be replaced with SEL-421 relays. Reverse power protection may also be required to prevent embedded generation of feeding the grid or back feed of one line by the other in the case of distributed generation stations.

The expected in-service date for the new equipment shall be communicated to the IESO as well.

The IESO shall review the design and onfirm that the proposed upgrades will not result in a material adverse impact on the reliability of the integrated power system.

In any case, the requirements of Transmission System Code issued by Ontario Energy Board shall be satisfied.

February 14th. 2014