Archive for April, 2010

Smart Grid – A Vision of the future

Wednesday, April 28th, 2010

Smart grid is the term applied to tomorrow’s electricity system. It encompasses a variety of changes that will transform the way electricity is used, delivered and produced, and result in a cleaner more efficient and more interactive electricity system. It represents a paradigm shift for electricity much in the way that mobile phones transformed communications. The concept is broad; it stretches beyond modernization of the transmission and distribution grid to include devices that allow consumers to better manage their electricity use, new ways of creating and storing electricity, and the widespread adoption of electric vehicles.

The power grid shift to move to a culture of conservation and its substantial commitment to renewable energy will also be supported by the smart grid. Smart meters, a major smart grid component, can give consumers timely information on price and consumption. Emerging devices will empower consumers to act on this information automatically while at the same time improving their energy efficiency, comfort and convenience. New sensing, monitoring, protection and control technologies will enhance the ability of the grid to incorporate renewable generation.The institutional structure of the electricity industry makes it easy to look at how the smart grid will impact each piece of the system in isolation, but the most profound impact of a smart grid may be its ability to link these pieces more closely together.

With the regulator OFGEM, we could have a system of applying structured market operator requirements with corporation responsibilities, encouraging longer-term system network planning, and procuring electricity supply and demand resources connected to the network. Both by the electrical shippers, National Grid and and the the regional Distribution Network Operators (DNO’s). but also the Feed in tariff (FIT’s) small generation customers and CHP and renewable end customer/suppliers. While the smart grid will affect each of these segments in different ways, it will affect all of them by increasing their ability to work together to better serve consumers.

Smart Grid Definition
A smart grid is a modern electric system. It uses communications, sensors, automation and computers to improve the flexibility, security, reliability, efficiency, and safety of the electricity system. It offers consumers increased choice by facilitating opportunities to control their electricity use and respond to electricity price changes by adjusting their consumption. A smart grid includes diverse and dispersed energy resources and accommodates electric vehicle charging. It facilitates connection and integrated operation. In short, it brings all elements of the electricity system – production, delivery and consumption closer together to improve overall system operation for the benefit of consumers and the environment. A smart grid is not only information rich, but also has the analytic infrastructure, processes and trained individuals necessary to integrate and act on information in the very short time frames required by the electricity system. It is characterized by clear standards, security protection and open architecture that allow for continued innovation through the development and deployment of new technologies and applications by multiple suppliers. So OFGEM must get it right, undertaking discussions with both the customer and the electrical supply and distribution network industry community.


Driver’s for a smart Grid

The Goverment’s commitment to establishing a culture of conservation and the desire to reduce the environmental footprint of the electricity sector are major drivers for creating a modern grid. The culture of conservation requires the continual search for new ways to encourage all customers to use energy more efficiently and lower consumption during peak periods. The comprehensive provision of smart meters creates the opportunity for all customers to better understand and manage their electricity usage and, for those who wish, to become active providers of demand response, and be rewarded in doing so.

The prominence of renewable energy in the Governments white papers an increased ability to accommodate variable renewable generation from off shore tidal, wind farms, solar, biomass and micro generation. Where today the grid serves primarily as a vehicle to move electricity generated in large central facilities to consumers, in the very near future, the grid will need to do much more. As the number and distribution of smaller generators grow, Micro generation (FITs) come on line, the operational challenge of incorporating these independent generated energy resources, while maintaining safety and reliability, will also grow. Meeting this challenge will require a smart grid. Other features of this arrangement will also also drive the development of a smart grid. DNO’s will need to upgrade, renew or replace a significant amount of the existing electricity infrastructure network load monitoring and reporting real time demand and quality of supply (similar in some ways to end customer smart meters to be rolled out) In addition dynamic load forecasting to request power stations load demand requirements. This need creates an opportunity to use smart grid technology both to maximize the use of existing equipment and to improve the efficiency of the grid as it is replaced. Growth and redevelopment also present opportunities to introduce smart grid technologies in newly developed and reconstructed areas. Demands by industry and consumers for increased reliability and power quality technology are also pushing toward a smarter grid.

Promise, Cost and Timing Of a Smart Grid
There are many potential benefits from a smart grid in the areas of economics, environment and operating performance. The ability of consumers to increasingly participate in the electricity market by adjusting their demand in response to price or other signals will help to defer the need for peaking resources and incorporate additional generation from variable sources. Improved system economics will come from reduced losses during electricity delivery (line losses) and better use of power station and distribution network plant & equipment. Potential reductions in network congestion will also allow greater use of the most cost effective generation and improve the capacity to move generation throughout the electrical supply network. Greater ability to integrate generation and load can also reduce the cost of operating reserve and some ancillary services. Finally, improved analytics and the ability for the grid to automatically restore itself from faults can reduce the scope and duration of outages, lower operations and maintenance costs, and improve service to customers. Many of the identified economic benefits also have associated environmental benefits. Reduced losses not only reduce cost, they allow more of the electricity generated to reach consumers thereby lowering the environmental impacts from generation. Increased ability to incorporate distributed energy resources, including both renewable generation and demand response, will allow us to move more quickly to a cleaner resource mix that everyone generally wishes to be collectively archive. Even if if it is viewed by some, that this is achieved by someone else. Using existing assets more efficiently can defer the need to expand the grid to accommodate growth. The smart grid offers enhanced operational performance. Greater awareness of system conditions can help anticipate and address problems before they lead to outages, minimize the scope of outages that do occur, and enable more rapid restoration of power. With a smart grid, these fixes may increasingly occur automatically so that the grid becomes self healing.

The ability to remotely monitor equipment condition and performance can also enhance security, help better target maintenance and improve the accuracy of replacement decisions. The information provided by a smart grid also can be used to improve power quality, which is increasingly important in operating today’s sophisticated equipment controlled by digital electronics.

By automating functions that are controlled manually today, the smart grid will increase productivity, which will be essential in managing the more complex grid of tomorrow and helpful in addressing the demographic issues facing the electric system as the baby boomer’s retire and new workers need to be hired and trained. Finally, the smart grid can provide significant operational advantages through its ability to improve both public and worker safety by increasing the amount of system information available for protection and control and by enabling remote operation and automation of equipment. The costs of the smart grid are difficult to quantify. They will depend on investment decisions and the pace of implementation by numerous companies and individuals undertaking smart grid expenditures. It is through the analysis underlying these decisions that the benefits and costs of specific smart grid investments will be evaluated. Certain cost elements that support the smart grid have already been incurred. Ontario’s investment in smart meters and advanced metering infrastructure provide an important connection with customers and the beginning of the communications infrastructure necessary for a smart grid. Additional communications, with greater bandwidth, speed and reliability will be needed, for full smart grid implementation. Moreover, much of the distribution infrastructure replaced over the last few years is already smart grid compatible.

Customer support also would be a key factor in evaluating smart grid investment and customer education will be necessary to inform consumers on this issue. Investment at this level would require increased availability of demonstrated smart grid technology and the human resources to install and integrate it. Finally, the costs and benefits of proposed incremental smart grid investments would be evaluated through appropriate regulatory processes. The timing of smart grid development also will depend on individual investment decisions, which in turn will be influenced by external policy drivers. The investment plans by Electrical shippers, distribution network operators, IDNO’s, meter operators and consumers that will largely determine the pace of adoption for smart grid technologies will be based on their individual needs and circumstances, and their available capital. Government policy, implemented through incentives, mandates or regulatory initiatives will be a major factor in influencing the timing of investments. In short, because the smart grid is not a single project, but rather a series of actions by a variety of entities to modernize the electricity system, it is difficult to produce a definitive time line for smart grid development.

When it does come together, and matures, the system as a ‘whole’, will be more resilient, but it will dependable on all parties being dependable on each other. Including the micro generation and independent supply generation supply contribution and working efficiently, otherwise extra power stations will still be required to be built or available, just in case all independent customers disconnect supplies from the network, say as a future government protest action, interrupting the collective electrical supply contribution factored in the ultimate smart generation mesh smart grid arrangement.

In some respectsit is similar to the how the internet developed and matured and came to be more resilient and depended by everyone including the internet backbone and local ISP’s provide the network grid to connect people and systems together.

Another interesting development will be how supply authorities & DNO’s will undertake works on the network.

For the purposes of this blog, assume in simplistic traditionally engineering supply arrangements, that electricity is generated from a remote power station, distribution via the national grid 132KV network to the local DNO network (66 / 33 /11 / 6.6KV substation network to a 230 V rated supply and so onwards the the end customer via the service cutout consumption monitored by the electrical meter / CT arrangement . Generally, electrical only going one way – Power station via DNO’s to the end customer.

So isolation of cabling & equipment only required from local substation supply to be dead supply to enable major upgrade work to be undertaken.

In comes the Smart grid roll out which end customers are encouraged to provide their own renewable energy, with spare capacity connected and used by local network So introducing multiple back-feed supply’s. Always connected, but independently controlled and managed by the customer, supply on and off all the time – generally individually, each micro generation arrangement not resulting a constant dependable supply contribution, only achieved collectively when provided in clusters of connection points.

So back to the final distribution feeder cable supply requiring major works to be undertaken. DNO isolates at substation and is checked and tested that the LV cable was a ‘dead’ cable, but it could become live at any time, thanks to customers micro-generation connected supply.

So how do you isolate the DNO feeder cable, to cut or repair the cable?

OK – Live working methods can be used and will have to be adopted through the LV network from now on.

But the customers generation equipment will also have to be able to provide circuit protective devices from a grid network earth fault or the remote chance that the distribution point may not be connected to the network. But thats a separate subject, as well!

In a joint up world – simple things get complicated – but systems change and adapt to “keep it simple” – to make it more easier to manage and control.

Yorkshire Water deployment of Itron’s automated meter reading system (AMR)

Monday, April 19th, 2010

U.K. water and waste water provider, Yorkshire Water, has signed a contract for the deployment of Itron’s automated meter reading system (AMR). The project includes deployment of up to 500,000 residential water meters as well as commercial water meters. All the meters supplied will be equipped with Itron’s newest generation EverBlu AMR module. Additionally, up to 500,000 EverBlu AMR modules will be supplied for retrofitting to Itron water meters already installed throughout Yorkshire Water’s territory. Itron FC300R handheld units and MV-RS meter reading software will be used to collect manual and AMR reads.

The AMR system will be installed over a five year period and will allow Yorkshire Water to efficiently collect meter reads and provide data to enhance customer service.

The EverBlu AMR module provides a seamless pathway for utilities to migrate from walk-by to fixed network AMR. The enhanced consumption, leakage and alarm data helps utilities efficiently assess the performance of their assets and networks, while providing valuable data to help drive customer service improvements to promote efficient use of water resources and leakage reduction alongside effective billing and query resolution.

“Yorkshire Water is delighted to be taking a lead in the U.K. water industry,” said Andy Clark, metering manager at Yorkshire Water. “We consider the EverBlu AMR platform to represent the best available technology in the AMR industry by delivering excellent read performance, significant operational efficiencies and enhanced customer service.”

Yorkshire Water supplies over 1 billion litres of drinking water per day.

Smart Grid – Smart meters – Opportunities and barriers

Monday, April 19th, 2010

Opportunities and barriers

Smart meters
By creating a potential two-way communication path between consumers and utilities, smart meters provides a cornerstone for future smart grid development. To leverage the potential of smart meters, additional steps are needed. The current approach of setting the minimum functionality of meters through regulation is cumbersome in light of the rapid evolution of smart meter technology. If this approach is retained, however, the minimum functionality should be expanded to include two-way communications, and the ability to detect outages and transmit this information back to distributors (known as “last gasp” functionality).

Two-way communications will allow utilities and other service providers to easily provide price information and, if critical peak pricing is implemented, to notify consumers of critical peak pricing events. “Last gasp” functionality will allow smart meters to help pinpoint outage locations and improve service restoration by ensuring that no consumers are missed because of a secondary outage condition when service is restored to an area. Utilities should continue to be able to seek cost recovery for additional functionality that benefts customers in applications before the OEB.The consumption and price data or other signals provided through smart meters can provide important information for home energy management networks. Customers or their authorized service providers

should be able to access this information from the consumer’s smart meter for use by home energy management systems. More work should be done to extend the benefts of smart meters to those customers who live in multi-unit buildings that are bulk metered. In this arrangement, building residents do not pay for their own usage directly, but instead the electricity costs for the building as a whole are paid by all occupants through rental rates or common area charges. Under current regulations, smart sub-meters may be voluntarily installed in condominiums at the discretion of the individual condominium board or the condominium developer for new buildings. Smart sub-metering activities in condominiums are overseen by the OEB, who in consultation with stakeholders, has developed a Smart Sub-Metering Code to ensure the protection of these consumers. The regulations dealing with condominium corporations are an important frst step in the rollout of smart sub-meters in the multi-unit residential sector and further regulations should be considered for multi-unit rental buildings.

While smart sub-meters may not be appropriate for some multi-unit buildings because of centralized provision of heating and cooling or wiring arrangements, additional work is necessary to promote installation of smart meters whereever they can provide residents with meaningful ability to control their electricity use. Smart sub-metering will help empower Ontarians with the tools to control their energy use so that they are able to become full participants in the culture of conservation.

Generators – Gas and diesel engines can not be used the same way!

Sunday, April 11th, 2010

The simple reason diesel engines respond much faster to load transients than gas engines is because fuel introduction on a diesel engine is done directly into the combustion chamber, at the next engine cycle from a load change, if the control system is fast enough, the different fuel rate can be introduced.  On the gas engine, fuel is introduced upstream, on older engines at the carburator mixer, on newer engine its at the valve, on medium speed gas engines at the inlet port of the cylinder head.  All points of fuel introduction produce delay before the cylinder sees the desired fuel change.

Gas engines do have a number of issues operating “island mode” when compared to diesels.  Properly designed, applied and integrated systems can operate effectively as prime applications, including maintaining very low emissions with installed after-treatment and heat recovery systems.

Transient capability is VERY different between gas and diesel.  Newer design gas engines not only have issues with load acceptance, but in many ratings, have a worse time with load rejection.  Also, gas engines have significant degradation in transient capabilites between “normal” service intervals.  Issues such as valve lash, spark plug condition, and ignition component health, like extenders and transformers, all affect engines ability to respond to load changes and maintain stable operation.  Also, newer engines have very different response characteristics depending on load level, low load pickup on some engines is extremely poor, mid range load pickup can be best if sufficient turbo response is available.  Top end transient response can be erratic as control system limitations, emission control and available turbo response all can fight each other.  So a 25% load transient may be acceptable at 25-50% and 50-75%, but unacceptable at 0-25% and 75-100%.  It is also quite possible the engine will not tolerate a 25% load rejection.

Also be aware that the applied protection settings for voltage and frequency deviation may not allow for desired transient operation, and using volts/Hz for improved recovery may affect operation of system loads like VFD’s and UPS systems.

New gas engines also have a much harder time with running extended periods at “low load”, actual load levels that would be defined as low load can vary, but gas engines suffer increased problems with spark plug life, especially multi-torch type spark plugs due to accelerated deposit levels.  Increased cylinder deposits also affect engine combustion, detonation levels, and emissions outputs, so assuring the engines are properly matched to the system load profiles is essential in maintaining stable plant operations.

As pointed out above, older engine designs with simpler and more robust controls systems were easier to apply in island applications, newer engines needing to meet reduced fuel consumption, reduced emissions and higher power densities have to give up something, and transient response suffers in these engines.

Island mode covers a fairly broad topic, engines can be successfully operated in prime, peaking and non-critical applications. From past experience, I am firmly opposed to using a gas engine as a critical standby unit for life safety.  Current design gas engines have a huge number of shutdowns programmed into their ECM’s, a large number of these designed to protect the engine, adding complexity and reducing reliablity.  Gas engines have ignition systems, spark plugs on cylinders open to the atmoshpere corrode, ignition wiring deteriorates, tranformers get internal faults, and ignition sources, such as magnetos or ignition modules can appear to operate correctly at no or low loads during testing and fail when called to operate at higher loads.  Fuel systems components, such as gas regulators and carburators, can stick and bind, diaphragm materials deteriorate, springs fatigue.  Even newer fuel systems components, such as the Raptor valve have relatively high failure rates.  While no engine is 100% reliable.  Gas engineers are known to have a very large number of fails to start or failure to operate as expected with gas engines in standby service as compared to a much larger population of diesel engines.

Compounding the problems with using a gas engine as a critical standby unit are two issues, in my opinion.  First, planning restraints regarding air quality control in conservation areas and noise in built up area shave greatly reduced the number of available hours a unit can be run for maintenance.  Second, most customers don’t want to run their unit under load, while some do install permanent load banks or do regular site load testing, their number is small compared to the total population.  And since most standby systems are low cost installations, good monitoring and trending systems for engine mechanical or electrical parameters are likely not installed.  So these engines don’t run enough hours at a high enough load in a year to assure their engine systems are functioning correctly.  So if you’re going to apply a gas engine in critical standby service, you have to be aware it has a higher incidence of failure, needs more maintenance, and can have reduced performance in between service intervals than a comparable rated diesel engine

EIKON

Saturday, April 10th, 2010

EIKON – EIKON for WebCTRL is the most advanced graphical programming tool in the industry. With the click of a button, you can build complex control algorithms, diagnose problems and run real-time or simulated operational data to evaluate the performance of a control sequence. EIKON makes it easy to understand control sequences as it does not use cryptic “line by line” computer code.

ARCNet

Saturday, April 10th, 2010

ARCNet an acronym from Attached Resource Computer NETwork, is a local area network (LAN) protocol, similar in purpose to Ethernet or Token Ring. ARCNET was the first widely available networking system for microcomputers and became popular in the 1980s for office automation tasks. It has since gained a following in the embedded systems market, where certain features of the protocol are especially useful.

BACnet

Saturday, April 10th, 2010

BACnet is “a data communication protocol for building automation and control networks.” A data communication protocol is a set of rules developed by the BACnet committee at ASHRAE governing the exchange of data over a computer network. The rules take the form of a written specification that spells out what is required to conform to the protocol.

There are 5 different options for BACnet, each of which fills a particular niche in terms of the price/performance tradeoff. The first is Ethernet, the fastest at 10 Mbps with 100 Mbps also recently available. (“Mbps” stands for “millions of bits per second.”) Ethernet is also likely to be the most expensive in terms of cost per device.

There are two forms of BACnet for Ethernet. One is called BACnet Ethernet for dedicated BACnet lines and there is also a BACnet for TCP called BACnet IP which can run on a non-dedicated Ethernet line.

For devices with lower requirements in terms of speed, BACnet defines the BACnet MS/TP (master-slave/token-passing) network designed to run at speeds of 1 Mbps or less over twisted pair wiring (RS-485). All of these networks are examples of “local area networks” or LANs. BACnet also defines a dial-up or “point-to-point” protocol called BACnet PTP for use over phone lines or hardwired RS-232 connections. A key point is that BACnet messages can, in principle, be transported by any network technology, if and when it becomes cost-effective to do so and FieldServer Technologies has the drivers available for all forms of BACnet.

How to Select a Night Vision Camera

Friday, April 9th, 2010

What you need to know about IR-illumination capabilities of CCTV cameras, and why the “green” movement makes them a new opportunity for security designers and integrators.

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Designers might want to check out the latest technological developments in cameras with built-in IR illumination as a potential add-on sale for both residential and commercial applications.

The night vision camera trend is being spurred partly by “green” initiatives because people don’t want to waste money on electricity to maintain outdoor flood lights.

Indeed, with enlightened ‘green clients’ you can sell the ROI for the installation of a night vision camera for exterior (or interior) security use vs. the cost of lighting.

How IR Illumination Works

Without any light source in some cases, cameras can clearly capture crisp images for use at night, potentially opening up a whole new market. CCTV cameras have always been primarily a commercial offering, but lower cost bullet and discrete dome units are well suited for resi applications.

IR illuminators offer the camera the ability, in essence, to capture the wavelength of light that is not visible to humans.

IR illuminators can be built into the camera or be a separate attachment. Generally there are three wavelengths of IR illuminators for night vision cameras:

  • 730 nm (nanometers) — Produces red glow about half the strength of stop light and offers the best visibility.
  • 830 nm — Most common strength that is used for semi-covert applications and produces a slight red glow.
  • 940 nm — Designed for covert applications. It can produce an image from full blackness, but can only view a short distance.

There are two types of IR illuminators:

  • Thermal IR — These detect heat. They are ideal for detection, but not for identification.
  • Active IR — These detect motion and offer crisper images.

Cameras are available that offer a combination of both technologies.

It’s a myth that if there is no light, there will be no picture. This is a  not generally correct, You can get a picture, but it’s not a good idea due to quality of the recorded images using the general product selection Low-lux cameras that are available for use in low-light situations.

However, these cameras, which do not have IR illuminators, are likely to produce a “noisy and grainy” picture. Also, if the images are being recorded on a DVR, they will take up a lot of space and bandwidth.

Likewise, if the images are being sent over an IP network, they require 40 percent more bandwidth for transmission.

Questions When specifing Low-Light Cameras

There are four key questions to ask with specifing a low-light camera:

  1. How far? Distance needed to capture images will determine focal length, beam angle and IR illuminator width.
  2. How wide? The wider the lens, the shorter the distance.
  3. Is there light at the scene? Some lighting looks good aesthetically, but is not good for image capture.
  4. What is the environment at the scene? Is the camera going to exposed to vibration, heat , saltwater, etc.

Night vision cameras themselves are getting greener. New units draw as little as 25 watts to 45 watts of power to see as far as 700 feet. Those same cameras used to require 500 watts to 1,000 watts.

Finally, designers should know that IR illuminators degrade at about 20 percent per year. Bosch has introduced a new technology called Black Diamond (pdf) to minimize degradation by automatically turning off the power to the illuminator during daylight hours.

Inside an iPad-Controlled Home

Friday, April 9th, 2010

By Steve Crowe
09 April 2010

Lifeware system can be controlled via two iPads for lighting, security, entertainment and more.

iPad-Controlled Home

Apple sold more than , and reports say more than 600,000 have been sold in the first six days.

But how many iPads are being used as the primary interface in a fully automated home?

Paul Hughes, president and founder of Lincroft, N.J.-based HomeBase Systems, claims to have installed the first “fully deployed, working” iPad-controlled home automation system. (See video and photos of the system below).

The residence in Ringwood, N.J., employs a Lifeware automation system that can be controlled via two iPads and one iPhone. The devices can command lighting (individual lights or lighting scenes), security, HVAC, cameras, the pool, two iPod docks, two tuners, three media servers and a Russound audio system.

Hughes says that after the control system was functioning properly, it took only three hours to get basic functionality working on the iPads. He finished the iPad programming by 11:30 on Monday morning, only about 48 hours after Apple’s product launch. “We’re going to go back, of course, and tweak the [iPads] since it’s the first time out of the gate,” says Hughes.

iPad-Controlled Home Automation System
Hughes says the client doesn’t see the value in a dedicated touchscreen. Cost, multitasking and aesthetics were the main reasons for going with the iPad.”Why buy something for $5,000 that has one purpose, when you can buy something that has an infinite purpose for $500,” Hughes says. “It’s a no-brainer. And who wants an in-wall touchscreen that’s outdated the day you put it in? The iPad doesn’t need to go in-wall and won’t hurt the aesthetics of your home.”Count Hughes as one installer who doesn’t think iPads should be installed in the wall. “If something bumps the iPad, we now have an iPad broken on the ground or a docking port that’s mis-shaped and could potentially cause damage,” says Hughes. “The iPad functions well enough on its own, I’m not sure it needs to be wall-mounted. But if there’s a secure way to do that, we’d be open to looking into it.”Hughes says the client has already asked him to program two more iPads. “The client is looking at is this way: if two iPads cost $1,000 and one of them breaks or falls in the pool, it would be nice to have an additional one that would be cheaper than buying a touchpanel,” says Hughes. “If I had $5,000, I could buy 10 iPads instead of one touchpanel. Kind of makes touchpanels obsolete.”So how does Hughes think the iPad will affect the home automation industry?

“My plan is to sell many more automation systems,” he says. “The stumbling block for clients in the past hasn’t been the control system, it’s always been the cost of the user interface. With the iPad, this problem has been completely removed. This is a tremendous victory for the future of my business. I don’t have to sell expensive products that don’t multitask. And I get to charge each time I program an iPad or add one to the system.”

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How to Understand Microgeneration – Solar PV

Friday, April 9th, 2010

Presentation made before smart metering and feed-in tariffs (FITs) now available.

 

 

Instabus Promotion Video KNX EIB

Friday, April 9th, 2010

A Smart Grid for Intelligent Energy Use

Friday, April 9th, 2010

Smarter Energy: Smart Metering presentation

Friday, April 9th, 2010

Smart building – Future house

Friday, April 9th, 2010

Agreement to use DNO’s circuit breaker to protect User’s network

Friday, April 9th, 2010

Preamble
The agreement to allow the use of the DNO’s CB and/or the DNO’s protection relays and systems to protect the User’s network is based on reasonable endeavours by the DNO to accommodate the User’s needs. The agreement can be terminated by either party at any time. The DNO reserves the right to terminate the agreement should alterations to his network preclude the continued delivery of these services.

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The DNO will use reasonable endeavours to find new solutions for continuing to provide the services, but any costs will be charged on a T&M basis to the User.

Cost indicated as x, y, a, b, c, d, e, f would be specified individually by DNOs, possibly in accordance with a revised LC4 statement.

Tripping
The DNO’s CB can be tripped by the User’s protection; on request from the User’s Control Person; or by the User directly via an emergency trip button. There will be no charge for these operations.

Closing
The DNO’s CB will not be used for synchronizing.

The DNO’s CB cannot be closed by the User. Should the User wish the DNO to energize the User’s system, this will be requested in the normal manner by the User’s Control Person.

There will be no charge for the first [] operational closes to energize the User’s system in any financial year. Subsequent closes will be charged at £[x] for closes by telecontrol and £[y] for closes by the DNO’s staff on site.

The DNO and the User may agree to implement an automatic reclosing system for the DNO’s CB. There will generally be no charges for operation of the CB under this system.

Exceptional Maintenance Costs
Any exceptional maintenance costs, such as post-fault maintenance of the DNO CB following the clearance of a fault on the User’s system, will be charged to the User on a T&M basis at £[z] per hour.

Isolation and Earthing
The DNO will provide an isolation and earthing service for the User’s network.

The DNO will attend to effect isolation and or earthing with [] days notice. The charge per attendance will be £[a] for the first hour or part thereof and £[b] for each subsequent hour or part therof.

For an unplanned event, the DNO will endeavour to attend within three hours. During exceptional event periods reasonable endeavours will apply. Attendance for unplanned events will be charged at £[c] per hour during the period 0830 to 1700 Monday to Friday, and £[d] at all other times.

Testing
The DNO will provide services for isolation and earthing as above for the purposes of facilitating the User’s need to test his circuits.

User’s Protection
The User’s Protection can trip the DNO’s CB.

The DNO and the User will agree as to the provision of DC supplies for the User’s protection. Where the DNO provides the DC supplies, the cost of the DC supplies will be shared on an equitable basis.

The User will be solely responsible for monitoring the health of the User’s trip circuit, including any parts of the circuit afforded by DNO equipment.

Co-ordination of Protection
In accordance with DPC4.4.4 the DNO and the User will agree the protection co-ordination arrangements, including specific faults on the User’s system that the DNOs protection will be relied upon to clear. The User will furnish the DNO with a schedule of these specific faults. The User will state for each specific fault if the DNO is required to ensure that the fault will also be protected by the DNO’s back up protection should the DNO’s interface CB fail to trip for any reason. The DNO shall describe the protection systems (including any backup systems) and the settings to be applied and the user shall then make an assessment as to whether the protection provided by the DNO equipment is adequate to meet their statutory obligations and commercial requirements The DNO will charge £[e] for each such protection assessment.

Limitation of DNO’s Liability
The DNO shall [have no liability/agree the liability] to the User for the failure of the DNOs CB, and/or backup protection and/or backup CB, to operate correctly to clear a fault on the User’s system.

The DNO shall [have no liability/agree the liability] for the failure of any DC supplies afforded by the DNO for the purpose of operating the User’s protection.

The DNO shall provide such information about the design, condition and operating characteristics of the DNO’s protection and CB as the User may from time to time request. This information will be collated by the DNO on a T&M basis at a charge of £[f] per hour. The DNO will provide an indicative estimate of the number of hours to collate the information on request

Short Term Infrequent Paralleling Issues

Friday, April 9th, 2010

Short term infrequent paralleling is usually applied to standby power supplies that are designed to support a customer’s islanded network and literature review for dissertation allows for seamless transfer following restoration of supply or for load transfer during routine testing.

Acceptable number of, and duration of paralleling time.
G59/1 allows for the infrequent connection of generation with, (at the DNO’S discretion,) a relaxation in protection requirements. No hard and fast definitions are given for “infrequent” but a figure of once per month is suggested. The number of parallel operations should be at the discretion of the individual DNO based on the capability of the network. However if it is required to test more than once a week then this would no longer be considered as infrequent paralleling.

Once operating in parallel, the generator is allowed to remain in parallel for a maximum of 5 minutes. The duration of the parallel should be kept as short as is reasonably practical for change over to take place. Less than 1 minute is normally achievable with longer times only being required if the equipment is incapable of shorter change over. After this time the parallel has to be broken automatically by a timer. This timer should be a separate device from the changeover control system such that failure of the auto changeover system will not prevent the parallel being broken.

Summary: In order for the generator to be considered as operating as “short term infrequent paralleling”, it must not be allowed to connect in parallel for more than 5 minutes in any month, or more frequently than once per week. If the duration of parallel connection exceeds this period, or this frequency, then the generator must be considered as if it is, or can be, permanently connected.


Protection Requirements

Short term occasional parallel operation requires only basic under /over voltage and under /over frequency protection.

A timer separate from the normal changeover control system should be provided to break the parallel if the normal means of changeover should fail.

This protection only needs to be in operation for the time the generator is operating in parallel.

Loss of mains protection in the form of ROCOF and Vector shift are not required, although many G59 multifunction relays now have this function built in as standard.

Similarly additional requirements such as NVD, intertripping and reverse power are not required.

This is based on the assumption that during the year the generator is only likely to be in parallel for a maximum of 1/8760th of the time and therefore the chance of a genuine loss of mains event coinciding with the parallel is unlikely.

If a coincidence did occur, the possibility of the generation supporting the Island also becomes a factor. Under voltage / under frequency is likely to trip the generation off if the load is greater than the generation capacity. Consideration could be given here to applying different settings for short term parallel connection. As this generation will not be expected to give grid Support or contribute to P2/6 security, more sensitive settings e.g. 49.5 Hz -6%V would compensate for lack of LOM protection?

Ultimately if an island was established the situation would only persist for the duration of the parallel operation timer setting before generation was tripped.(Auto Reclose excepted)

Generator Star point Earthing
For HV connected generation ETR113 Fig 5.6 shows that for short term parallel the star point of the generator should remain connected to earth.
It is recommended that for LV generation operating in short term parallel the same should apply for the following reasons.

• Having switches in the generator earthing circuits, that for the majority of the time will need to remain closed creates an unnecessary complication / risk of failure of leaving an unearthed system.

• Multiple earths on the system could result in circulating third harmonic current around the neutral earth path. This could result in heating of the cables, however as this is a thermal rating issue with a relatively long time constant the short period of parallel operation is unlikely to result in any serious overheating.


Very Short Term Parallel

Some manufacturers are now installing their standby machines with Fast acting Automatic Transfer Switches. These are devices that only make a parallel connection for a very short period of time, typically 100 – 200mS. Under these conditions installing a conventional G59 relay with an operating time of 500mS is not appropriate when the parallel will normally be broken before it has a chance to operate. There is however the risk that the device will fail to operate correctly. Therefore a backup timer should be installed to operate a conventional CB if the parallel remains on for more than 1 Sec.

Contribution to fault level
For short term infrequent parallel there is the need to consider the effect of the generation contribution to fault level. If any problems are identified, then the process for controlling this risk will need to be agreed with the Network Operator.

Voltage Rise / Step Change
Networks should be designed such that the connection of a generator under normal operating conditions does not produce voltage rise in excess of the statutory limits. In general this should not be an issue with most short term parallel operation as at the time of synchronising with the mains most sites will normally be generating only sufficient output to match the site load. Therefore the power transfer on synchronising should be small, with the generator ramping down to transfer site load to the mains. If the generator tripped at this point it could introduce a larger voltage step change than would normally be acceptable for loss of a long term parallel generator but in this event it could be regarded as an infrequent event and a step change of up to 10% would be acceptable*
(* assuming this is the figure the DNO agree to).

Breaker out of phase switching capability
For a new metering point the metering circuit breakers should have an out of phase switching capability.

For an existing installation that does not require replacement of the metering breaker for any other reason, then for short term parallel the risks of out of phase opening are low. Therefore replacement of the metering circuit breaker should not be necessary. It is assumed however that the generator synchronising breaker would have out of phase capability.

What type of elecrical customer are you?

Friday, April 9th, 2010

CATEGORIES OF USERS OF THE DISTRIBUTION SYSTEM

Category AUsers are those having a connection at 1 kV or above (HV)

A1. Embedded Generators including CWOGs having an output capacity of 1 MW and above.

A2. Embedded Generators including CWOGs having an output capacity of less than 1 MW.

A3. Customers without generation having a Demand of 5 MW and above.

A4. Customers without generation having a Demand of less than 5 MW.

The classification threshold of 5 MW is related to the obligations that a DNO has for providing aggregated Demand information to NGC. Generators are further classified by voltage of connection and capacity for the purposes of technical standards.

Category B – Users are those having a connection at below 1 kV (Low Voltage)

B1. Embedded Generators (including CWOGs) irrespective of capacity of fuse(s) or other Protection device(s).

B2. Customers who are the sole Customer with a connection to the Low Voltage side of a High Voltage to Low Voltage transformer, irrespective of the capacity of fuse(s) or other protection device(s).

B3. Customers without generation and having a single or three phase supply protected by fuse(s) or other device(s) rated at more than 100 amps.

B4. Customers without generation having a single phase or three phase supply protected by a fuse(s) or other device(s) rated at 100 amps or less.

B5. Customers with Unmetered Supplies.

B6. Customers who have connected a Generation Set in accordance with ER G83/1-1 and where this is their only Generation Set.

C. Suppliers including licence exempt Suppliers, unless otherwise stated.

D. Other Authorised Distributors connected to the DNO’s Distribution System, being licensed or licence exempt Distributors.

E. Meter Operators (This Distribution Code does not place any direct obligation on Meter Operators other than through the appointment by either a Supplier or a Customer.)

System Frequency – Permitted to your electrical supply

Friday, April 9th, 2010

The Distribution code allows that “In exceptional circumstances, System Frequency could rise to values of the order of 52 Hz or fall to values of the order of 47 Hz. Sustained operation outwith the range 47 – 52 Hz is not taken into account in the design of Plant and Apparatus.”

Definition: Event

Friday, April 9th, 2010

As defined under The Distribution Code of Licensed Distribution Network Operators (UK):

An unscheduled or unplanned (although it may be anticipated) occurrence on or relating to a System including, without imiting that general description, faults, incidents and reakdowns and adverse weather conditions being experienced.

Embedded Generator

Friday, April 9th, 2010

As defined under The Distribution Code of Licensed Distribution Network Operators (UK):

A Generator including a Customer With Own Generation whose Generation Sets are directly connected to the DNO’s Distribution System or to an Other Authorised Distributor connected to the DNO’s Distribution System.
The definition of Embedded Generator also includes the OTSO in relation to any Embedded Transmission System