Obama Announces $3.4 Billion Investment to Spur Transition to Smart Energy Grid

Obama Announces $3.4 Billion Investment to Spur Transition to Smart Energy Grid
Oct 27, 2009 2:10 PMDOE

President Barack Obama today announced the largest single energy grid modernization investment in U.S. history, funding a broad range of technologies that will spur the nation’s transition to a smarter, stronger, more efficient and reliable electric system. The end result will promote energy-saving choices for consumers, increase efficiency, and foster the growth of renewable energy sources like wind and solar, according to Obama.
The $3.4 billion in grant awards are part of the American Reinvestment and Recovery Act, and will be matched by industry funding for a total public-private investment worth over $8 billion. Applicants state that the projects will create tens of thousands of jobs, and consumers in 49 states will benefit from these investments in a stronger, more reliable grid. Full listings of the grant awards by category and state are available An analysis by the Electric Power Research Institute estimates that the implementation of smart grid technologies could reduce electricity use by more than 4 percent by 2030. That would mean a savings of $20.4 billion for businesses and consumers around the country, and $1.6 billion for Florida alone -- or $56 in utility savings for every man, woman and child in Florida.
One-hundred private companies, utilities, manufacturers, cities and other partners received the Smart Grid Investment Grant awards today, including FPL, which will use its $200 million in funding to install over 2.5 million smart meters and other technologies that will cut energy costs for its customers. In the coming days, Cabinet Members and Administration officials will fan out to awardee sites across the country to discuss how this investment will create jobs, improve the reliability and efficiency of the electrical grid, and help bring clean energy sources from high-production states to those with less renewable generating capacity. The awards announced today represent the largest group of Recovery Act awards ever made in a single day and the largest batch of Recovery Act clean energy grant awards to-date.
Today’s announcement includes:
Empowering Consumers to Save Energy and Cut Utility Bills -- $1 billion. These investments will create the infrastructure and expand access to smart meters and customer systems so that consumers will be able to access dynamic pricing information and have the ability to save money by programming smart appliances and equipment to run when rates are lowest. This will help reduce energy bills for everyone by helping drive down “peak demand” and limiting the need for “stand-by” power plants – the most expensive power generation there is. Making Electricity Distribution and Transmission More Efficient -- $400 million. The Administration is funding several grid modernization projects across the country that will significantly reduce the amount of power that is wasted from the time it is produced at a power plant to the time it gets to your house. By deploying digital monitoring devices and increasing grid automation, these awards will increase the efficiency, reliability and security of the system, and will help link up renewable energy resources with the electric grid. This will make it easier for a wind farm in Montana to instantaneously pick up the slack when the wind stops blowing in Missouri or a cloud rolls over a solar array in Arizona. Integrating and Crosscutting Across Different “Smart” Components of a Smart Grid -- $2 billion. Much like electronic banking, the Smart Grid is not the sum total of its components but how those components work together. The Administration is funding a range of projects that will incorporate these various components into one system or cut across various project areas – including smart meters, smart thermostats and appliances, syncrophasors, automated substations, plug in hybrid electric vehicles, renewable energy sources, etc. Building a Smart Grid Manufacturing Industry -- $25 million. These investments will help expand our manufacturing base of companies that can produce the smart meters, smart appliances, synchrophasors, smart transformers, and other components for smart grid systems in the United States and around the world – representing a significant and growing export opportunity for our country and new jobs for American workers.
The planned effect of the investments announced today, when the projects are fully implemented, will:
Create tens of thousands of jobs across the country. These jobs include high paying career opportunities for smart meter manufacturing workers; engineering technicians, electricians and equipment installers; IT system designers and cyber security specialists; data entry clerks and database administrators; business and power system analysts; and others. Leverage more than $4.7 billion in private investment to match the federal investment. Make the grid more reliable, reducing power outages that cost American consumers $150 billion a year -- about $500 for every man, woman and child in the United States. Install more than 850 sensors - called ‘Phasor Measurement Units’ - that will cover 100 percent of the U.S. electric grid and make it possible for grid operators to better monitor grid conditions and prevent minor disturbances in the electrical system from cascading into local or regional power outages or blackouts. This monitoring ability will also help the grid to incorporate large blocks of intermittent renewable energy, like wind and solar power, to take advantage of clean energy resources when they are available and make adjustments when they’re not. Install more than 200,000 smart transformers that will make it possible for power companies to replace units before they fail thus saving money and reducing power outages. Install almost 700 automated substations, representing about 5 percent of the nation’s total that will make it possible for power companies to respond faster and more effectively to restore service when bad weather knocks down power lines or causes electricity disruptions. Power companies today typically do not know there has been a power outage until a customer calls to report it. With these smart grid devices, power companies will have the tools they need for better outage prevention and faster response to make repairs when outages do occur. Empower consumers to cut their electricity bills. The Recovery Act combined with private investment will put us on pace to deploy more than 40 million smart meters in American homes and businesses over the next few years that will help consumers cut their utility bills. Install more than 1 million in-home displays, 170,000 smart thermostats, and 175,000 other load control devices to enable consumers to reduce their energy use. Funding will also help expand the market for smart washers, dryers, and dishwashers, so that American consumers can further control their energy use and lower their electricity bills. Put us on a path to get 20 percent or more of our energy from renewable sources by 2020. Reduce peak electricity demand by more than 1400 MW, which is the equivalent of several larger power plants and can save ratepayers more than $1.5 billion in capital costs and help lower utility bills. Since peak electricity is the most expensive energy – and requires the use of standby power generation plants – the economic and environmental savings for even a small reduction are significant. In fact, some of the power plants for meeting peak demand operate for only a few hundred hours a year, which means the power they generate can be 5-10 times more expensive than the average price per kilowatt hour paid by most consumers.

Some Latest NEWS

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For years, researchers have been in search of an economically feasible method of converting nuclear energy directly into electricity. Now, University of Missouri researchers are developing an energy conversion system that uses relatively safe isotopes to generate high-grade energy. A system that directly converts nuclear energy into electricity would be cheaper than current nuclear conversion technology.

Venice to use algae for 50% of its electricity-

The city of Venice has announced a plan to utilize algae in a different way than we're used to hearing about. The Italian city plans to produce 50 percent of its electricity needs from an algae-based power plant instead of fossil fuels.
http://green.yahoo.com/blog/ecogeek/...ectricity.html

Decentralize the Grid: Practical or Unrealistic?-
The US electrical grid is a century-old “machine” built for a singular purpose: to power the development and industrialization of the nation’s economy. It is designed to deliver electrons from centralized power producing plants through transmission wires to end consumers. This archaic, unidirectional architecture is unreliable, inefficient, and unsafe.
http://blog.cleantechies.com/2009/03...r-unrealistic/

A Field of Light Sabers, Powered By Ambient Electricity-
Richard Box was an artist in residence in the physics department at Bristol University, and he got the idea to plant his fluorescent crop after hearing a colleague describe playing light saber games with a fluorescent tube beneath power lines in his backyard. So he arranged with a local farmer into letting him set up this extraordinary scene, to recreate the light saber game times a thousand.
http://io9.com/5204842/a-field-of-li...nt-electricity

Electricity Grid in U.S. Penetrated By Spies-
Cyberspies have penetrated the U.S. electrical grid and left behind software programs that could be used to disrupt the system, according to current and former national-security officials.
The spies came from China, Russia and other countries, these officials said, and were believed to be on a mission to navigate the U.S. electrical system and its controls. The intruders haven't sought to damage the power grid or other key infrastructure, but officials warned they could try during a crisis or war.
http://online.wsj.com/article/SB123914805204099085.html
http://news.yahoo.com/s/nm/20090408/...yberattack_usa
http://theitsecurityguy.blogspot.com...ower-grid.html

Estimation of life expectancy of Transformers

Estimation of life expectancy of Transformers :
The evaluation of the life expectancy of a transformer is a key reason for having follow-up and diagnosis systems. This preoccupation is closely related to the need of the suppliers of electricity to predict the time of replacement in order to maximize the useful life of the equipment, as well as minimizing the risks of failure leading to power reliability problems.

The ultimate question to answer is how many years are left before the equipment has a failure?

The evaluation of the life expectancy is often subject to a number of erroneous interpretations .First, it is important to define what we agree upon as end of life.

The end of life is attained when the transformer is incapable of fulfilling its functions. Certain organizations distinguish between technical, planned and economical end of life. The tendency is to give too much importance to the technical end of life. It is rare that a transformer is replaced for only technical reasons; the main reasons to retire a transformer from service are related to costs. The operational expenses must be minimized. These reasons are of a planning nature (modification to load profile, voltage changes, etc.)

Second, we should distinguish between the life expectancy of the insulation and that of the transformer. It has often been the case where the transformer was kept in service several years after the insulation was classified obsolete. It is implicit that the life expectancy of the insulation is not that of the life expectancy of the transformer.

The technical life expectancy of a transformer is determined by several factors. It depends upon design, historical events, operating conditions, its actual state and future conditions.

Most of the present methods put too much emphasis on the condition of the insulating material. We could easily appreciate that not only temperature, load and water content have an effect on the capacities of a transformer to fulfill its functions but also the number of short-circuits, over-voltage, design weakness, repairs and moving, etc.. To be able to use a multi-factor evaluation, it is necessary to have an indepth understanding of the interrelations between the internal components. Once this is acquired, the historical information of the transformer will be needed. It is, therefore, important to gather the information as quickly as possible at the time in order to easily access it.

The eternal question is, "How long will my transformer last?". In order to answer this question we have extracted data from a survey of 251 transformers used by small and medium sized industries. From this survey, we have the transformer size and age profile with which we can estimate the life span of your transformer.

Figure 4 represents the transformer size profile of the survey. It indicates that most transformers in use by small to medium sized industries are in the 500- 2500 kVA range.

From Figure 5 the variations which we observe are probably due to cycles in the economy. Characteristically, these small to medium sized industries are more prone to these economical cycles.

The decrease in the number of transformers more than fifty years old is probably due to the closing of small and medium sized industries. If the decrease was cause by a mechanism failure, the curve would have been less abrupt. Instead, the decrease would be spread over two decades The author is warning you not to use the curves from that reference for estimating the probable life span of your transformers.
In many countries power transformer kept off from service after completion of 20 or 25 years although with satisfactory test results. It is safe practice.

NUMERICAL RELAYS

NUMERICAL RELAYS
The distinction between digital and numerical relay rests on points of fine technical detail, and is rarely found in areas other than Protection. They can be viewed as natural developments of digital relays as a result of advances in technology. Typically, they use a specialised digital signal processor (DSP) as the computational hardware, together with the associated software tools.
The input analogue signals are converted into a digital representation and processed according to the appropriate mathematical algorithm. Processing is carried out using a specialised microprocessor that is optimised for signal processing applications, known as a digital signal processor or DSP for short. Digital processing of signals in real time requires a very high power microprocessor. In addition, the continuing reduction in the cost of microprocessors and related digital devices (memory, I/O,
etc.) naturally leads to an approach where a single item of hardware is used to provide a range of functions (‘one-box solution’ approach). By using multiple
microprocessors to provide the necessary computational performance, a large number of functions previously implemented in separate items of hardware can now be
included within a single item. Table 7.1 provides a list of typical functions available, while Table 7.2 summarises the advantages of a modern numerical relay over the static equivalent of only 10-15 years ago. Figure 7.7 shows typical numerical relays, and a circuit board is shown in Figure 7.8. Figure 7.9 provides an illustration of the savings in space possible on a HV feeder showing the space requirement for relays with electromechanical and numerical relay technology to provide the same functionality. Because a numerical relay may implement the
functionality that used to require several discrete relays, the relay functions (overcurrent, earth fault, etc.) are now referred to as being ‘relay elements’, so that a single relay (i.e. an item of hardware housed in a single case) may implement several functions using several relay elements. Each relay element will typically be a software routine or routines.

The argument against putting many features into one piece of hardware centres on the issues of reliability and availability. A failure of a numerical relay may cause
many more functions to be lost, compared to applications where different functions are implemented by separate hardware items. Comparison of reliability and availability between the two methods is complex as interdependency of elements of an application provided by separate relay elements needs to be taken into account.
With the experience gained with static and digital relays, most hardware failure mechanisms are now well understood and suitable precautions taken at the design
stage. Software problems are minimised by rigorous use of software design techniques, extensive prototype testing and the ability to download amended software into memory (possibly using a remote telephone link for download). Practical experience indicates that numerical relays are at least as reliable and have at least as good a record of availability as relays of earlier technologies.

Substation Control and Automation (SCADA)

SCADA System :
RTU (Remote Terminal Unit) installed in distribution & transmission substations and SCADA system can make substations unmanned and remote monitoring and controlling substations possible. In Power Systems SCADA has widespread application in generation, transmission, distribution and substation automation.

SCADA Technology
1. High ReliabilitySCADA system design can realize high reliability & availability.
2. Monitoring SubstationsAutomatic monitoring and displaying of substation condition can be conducted based on the information from RTUs.
3. Operation of Substation equipmentManual operation by operators and automatic operation by SCADA system are possible.
4. Automatic MessageSCADA system can edit messages about fault information, etc. and messages are reported to related offices automatically.
5. Substation Operation Supporting FunctionVarious information needed for substation operation (operation record, load status record, etc.) can be generated automatically.

ADVANTAGES:
1. Eliminates operators working on shifts in substations. Assuming 8 operators in 132 KV substations. The annual expenditure per operator is about Rs. 2 lakh.
2. Eliminates manual error in meter reading and calculations.
3. Eliminates data transmission by post or fax.
4. Automation, state of art technology and reliability
5. remote operation on circuit breakers and line isolators.On line real time monitoring of substation at HQ.

The Hardware
The substation control system, being responsive to a plurality of status input signals from various power system assemblies includes a plurality of input/output modules, each having a fiber-optic transceiver capability, wherein wire connections are used to communicate the status signals from the power system assemblies to input contacts of the respective I/O modules. The output signals from the I/O module are applied to a fiber-optic line. The system also includes a plurality of logic processors, each responsive to the signals on a fiber-optic line from a plurality of input-output modules for application to a plurality of protective relay devices, which provide protection operations and generate output signals. The logic processors also have a part in the overall protection arrangement. The output signals are communicated back to the power system assemblies for local control and protection thereof and to SCADA systems for remote control thereof. If the control panel have electronic meter with optical port/RS232 port it can be connected to SCADA computer through serial data transmission port with mux/demux.

The Software
The complete engineering and SCADA development is through a single software running on Windows. The software has unlimited tags, trends, graphical displays and has a built in Sequence - of - Events recording (SOE), which is very essential for fault diagnosis. The data such as KWH, KVA, KW, FREQ, VOLTAGES, LOAD CURRENT, KVAR etc are displayed on Excel Spread sheet. The data can be stored and displayed on the intervals as desired (instantaneous, real-time, every 15 minutes, half hourly, hourly, daily etc).Different curves such as voltage profile , load duration are also displayed. The SCADA Software will be linked with EMS/RMS software so that the system is more versatile.

EARTHING PRACTICE AT SUBSTATION

Earthing Practices At Substations

Introduction

Earthing practices adopted at Generating Stations, Substations, Distribution structures and lines are of great importance. It is however observed that this item is most often neglected. The codes of practice, Technical Reference books, Handbooks contain a chapter on this subject but they are often skipped considering them as too elementary or even as unimportant. Many reference books on this subject are referred to and such of those points which are most important are compiled in the following paragraphs. These are of importance of every practicing Engineer in charge of Substations.

OBJECTIVE OF EARTHING

Prime Objective of Earthing is to provide a Zero potential surface in and around and under the area where the electrical equipment is installed or erected.

To achieve this objective the non-current carrying parts of the electrical equipment is connected to the general mass of the earth which prevents the appearance of dangerous voltage on the enclosures and helps to provide safety to working staff and public.

Importance of Earthing & Practices

· The earthing is provided for
a) Safety of Personnel
b) Prevent or atleast minimise damage to equipment as a result of flow of heavy fault currents.
c) Improve reliability of Power supply

· The earthing is broadly divided as
a) System earthing (Connection between part of plant in an operating system like LV neutral of a Power Transformer winding and earth).
b) Equipment earthing (Safety grouding)
Connecting frames of equipment (like motor body, Transformer tank, Switch gear box, Operating rods of Air break switches, etc) to earth.

· The system earthing and safety earthing are interconnected and therefore fault current flowing through system ground raises the potential of the safety ground and also causes steep potential gradient in and around the Substation. But separating the two earthing systems have disadvantages like higher short circuit current, low current flows through relays and long distance to be covered to separate the two earths. After weighing the merits and demerits in each case, the common practice of common and solid (direct) grounding system designed for effective earthing and safe potential gradients is being adopted.

· Factors that change the requirement of earth electrode
a) If an electrical facility can expand in system, it creates different routes in the electrode. What was formerly a suitable low earth resistance can become obsolete standard.
b) More number of metallic pipes, which were buried underground become less and less dependable as effective low resistance ground connection.
c) Most of the location, the water table gradually falling. In a year or two, area end up with dry earth of high resistance.
d) These factors emphasize the importance of a continuous, periodic program of earth resistance testing.

· The earth resistance shall be as low as possible and shall not exceed the following limits:

Power Stations - 0.5 Ohms
EHT Substations - 1.0 Ohms
33KV Stations - 2.0 Ohms
D/t Structures - 5.0 Ohms
Tower foot resistance - 10.0 Ohms

Step Potential

Step Potential is the difference in the voltage between two points which are one metre apart along the earth when ground currents flowing.

Touch Potential

Touch Potential is the difference in voltage between the object touched and the ground point just below the person touching the object when ground currents are flowing.

Specification of Earthing

Depending on soil resistivity, the earth conductor (flats) shall be buried at the following depths.

Soil Resistivity in ohms/metre Economical depth of Burial in metres
1) 50 – 100 0.5
2) 100 – 400 1.0
3) 400 – 1000 1.5

To keep the earth resistance as low as possible in order to achieve safe step and touch voltages, an earth mat shall be buried at the above depths below ground and the mat shall be provided with grounding rods at suitable points. All non-current carrying parts at the Substation shall be connected to this grid so as to ensure that under fault conditions, none of these part are at a higher potential than the grounding grid.

Plate Earths

· Taking all parameters into consideration, the size of plate earths are decided as

Power Stations & EHT Station - Main - 100 x 16mm
Auxiliary - 50 x 8mm
Small Stations - 75 x 8mm

· The complete specifications for providing earth mats at EHT & 33KV Substations, Distribution transformers & Consumers premises are reproduced below.

Specification for Earthing System

I) EHT Substation

Earthing of equipment’s in the sub-stations is taken of as discussed below:

1. Power transformers:
i. The transformer body or tank is directly connected to earth grid. In addition, there should be direct connection from the tank to the earth side of the lightning arresters.
ii) The transformer track rail should be earthed separately.
iii) The neutral bushing is earthed by a separate connection to the earth grid.

2. Potential and current transformers :
The bases of the CTs and Pts. are to be earthed. All bolted cover plates of the bushing are also to be connected the earth grid.

3. Lightning arresters :
The bases of the L.As. are to be earthed with conductors as short and straight as Possible (for reducing impedance). The earth side of the L.As. are to be connected directly frolJ1 the equipment to be protected. Each L.A. should have individual earth rods, which are in turn connected to earth grid.

4. Circuit breakers:
The supporting structures, C.T. chambers, P.T. tanks, Cable glands etc., are to be connected to earth.


5. Other equipment’s:
All equipment’s, structures, and metallic frames of switches and isolators are to be earthed separately.

6. Fences:
Providing separate earth or connecting to the station earth depends upon the distance of the fence the station earth. If the distance is within feet, an inter-connection made to the station earth. If not, the metallic fences are earthed by means of earth rods spaced at not more than 200 feet. The gates and support pans may be earthed through an earth rod. The cable wires passing under “metallic fence are to be buried below at a depth qf 2’6 or are to bc enclosed in a insulating pipe (P. V.C or asbestos cement) for a distance of not less than 5 feet on each side of the fence.

7. Ground wires :
The ground wires over the station arc connected to the station earth. In order that the station earth potentials during fault condition5 arc not applied to transmission line ground wires and towers, all ground wires coming to the stations shall be broken !It an insulated on the fir5t tower external to station by means of strain disc. insulators.

The followings are the important features in earthing:

1. The earth mat shall be as per the approved layout. The earth mat shall be formed with the steel flats buried in the ground at a depth of 750mm on edge.

2. The earth mat shall extend over the entire switchyard as per the layout.

3. All the junctions of the steel flats while forming the earth mat and taking risers from the earth mat for giving earth connections to equipment, steel structures, conduits cable sheaths shall be properly welded. All joints shall be provided with suitable angle pieces for proper contact between flats.

4. Provisions shall be made for thermal expansion of the steel flats by giving smooth circular bends. Bending shall not cause any fatigue in the material at bends.

5. The earth mat shall be formed by welding 50x8 mm steel flat to the 100 x 16mm peripheral earth conductor. The grounding grid shall be spaced about 5 meters i.e in longitude and about 5 meters in the transverse directions. After the completion of earth mat, the earth resistance shall be measured. In case the earth resistance is more than one ohm the earth mat shall be extended by installing extra electrodes, so that the earth resistance is less than one ohm.

6. All fence corner posts and gate posts shall be connected to the ground by providing 32mm dia M.S rods of 3 metre length near the posts and connected to the main grounding mat.

7. All paint enamel and scale shall be removed from surface of contact on metal surface before making ground connection.

8. The risers taken along the main switchyard structures and equipment structures (upto their top) shall be clamped to the structures at an interval of not more than one metre.

9. 50 x 8mm ground conductor shall be run in cable routes and shall be connected to the ground mat at an interval of 10 metres.

10. Grounding electrodes of 32mm dia 3mtr. long MS rods shall be provided at the peripheral corners of the earth mat. The grounding rods shall be driven into the ground and their tops shall be welded to clamp and the clamp together with the grounding rods shall be welded to the ground mat.

11. Lightening arrestors shall be provided with earth pits near them for earthing.

12. Cast iron pipes 125mm dia and 2.75 metres long and 9.5mm thick shall be buried vertically in the pits and a mixture of Bentonite compound with Black cotton soil a ratio of 1:6 is to be filled 300 mm dia and the pipe for the entire depth. Where it is not possible to go to a depth of 2.75 metres, 1.3 x 1.3 MMS plates, 25mm thick shall be buried vertically in pits of 2 metres depth and surrounded by Bentonite mixture atleast 2 metre away from any building or structure foundation. The plates shall be atleast 15 metres apart. These earth pits in turn shall be connected to the earth mat.

II) Earthing at 33KV Substations

1. Providing of earth pit and earth matting include the following connected works:

a) Excavation of earth pits of size 21/2ft x 21/2ft x 9ft in all type of soils.
b) Providing of CI pipe of 3 inch diameter 9ft length with flange. All connections to CI pipe shall be with GI bolts and nuts.
c) Filling of earth pit excavated with Bentonite with Black cotton soil (1:6) in alternate layers.
d) Providing of cement collar of size 2ft diameter 2ft height 1 inch below the ground level.
e) The top of the CI earth pipe should be at the surface level of the ground.


2. Providing of earth matting with MS flat 75 x 8mm including the following connected works:
a) Excavation of trench in all types of soils of size 2½ ft depth and 1 ft. width.
b) Laying of M.S flat 75 x 8mm in the excavated trench.
c) Inter connecting all earth pits and welding properly at jointing location and junctions.
d) Back filling of earth completely.

Maintenance Management

two types of maintenance management:
(1) Run-to-failure, or (2) Preventive maintenance.
Run-to-Failure ManagementThe logic of run-to-failure management is simple and straightforward. When a machine breaks, fix it. This ‘‘if it ain’t broke, don’t fix it’’ method of maintaining plant machinery has been a major part of plant maintenance operations since the first manufacturing plant was built, and on the surface sounds reasonable. A plant using run-to-failure management does not spend any money on maintenance until a machine or system fails to operate. Run-to-failure is a reactivemanagement technique that waits for machine or equipment failure before any maintenance action is taken. It is in truth a no-maintenance approach of management. It is also the most expensive method of maintenance management.
Few plants use a true run-to-failure management philosophy. In almost all instances, plants perform basic preventive tasks (i.e., lubrication, machine adjustments, and other adjustments) even in a run-to-failure environment. However,in this type of management, machines and other plant equipment are not rebuilt nor are any major repairs made until the equipment fails to operate. The major expenses associated with this type of maintenance management are:
(1) high spare parts inventory cost (2) high overtime labor costs(3) high machine downtime and (4) low production availability.
Since there is no attempt to anticipate maintenance requirements, a plant that uses true run-to-failure managementmust be able to react to all possible failures within the plant. This reactive method of management forces the maintenance department to maintain extensive spare parts inventories that include spare machines or at least all major componentsfor all critical equipment in the plant. The alternative is to rely on equipment vendors that can provide immediate delivery of all required spare parts. Even if the latter is possible, premiums for expedited delivery substantially increase the costs of repair parts and downtime required for correcting machine failures. To minimize the impact on production created by unexpected machine failures, maintenance personnel must also be able to react immediately to all machine failures.
The net result of this reactive type of maintenance management is higher maintenance cost and lower availability of process machinery. Analysis of maintenance costs indicates that a repair performed in the reactive or run-to-failuremode will average about three times higher than the same repair made within a scheduled or preventive mode. Scheduling the repair provides the ability to minimize the repair time and associated labor costs. It also provides the means of reducing the negative impact of expedited shipments and lost production.
Preventive Maintenance Management
There are many definitions of preventive maintenance, but all preventive maintenance management programs are time driven. In other words, maintenance tasks are based on elapsed time or hours of operation. The following figure illustrates an example of the statistical life of a machine-train. The mean time to failure (MTTF) or bathtub curve indicates that a new machine has a high probability of failure, because of installation problems, during the first few weeks of operation. Afterthis initial period, the probability of failure is relatively low for an extended period of time. Following this normal machine life period, the probability of failure increases sharply with elapsed time. In preventive maintenance management, machine repairs or rebuilds are scheduled on the basis of the MTTF statistic.
The Bath Tub Curve
The actual implementation of preventive maintenance varies greatly. Some programs are extremely limited and consist of lubrication and minor adjustments. More comprehensive preventive maintenance programs schedule repairs, lubrication, adjustments, and machine rebuilds for all critical machinery in the plant. The common denominator for all of these preventive maintenance programs is the scheduling guideline. All preventive maintenance management programs assume that machines will degrade within a time frame typical of its particular classification. For example, a single-stage, horizontal split-case centrifugal pump will normally run 18 months before it must be rebuilt. When preventive management techniques are used, the pump would be removed from service and rebuilt after 17 months of operation.
The problem with this approach is that the mode of operation and system or plant-specific variables directly affect the normal operating life of machinery. The mean time between failures (MTBF) will not be the same for a pump that ishandling water and one that is handling abrasive slurries. The normal result of using MTBF statistics to schedule maintenance is either unnecessary repairs or catastrophic failure. In the example, the pump may not need to be rebuilt after 17 months. Therefore the labor and material used to make the repair was wasted. The second option, use of preventive maintenance, is even more costly. If the pump fails before 17 months, we are forced to repair by using run-to-failure techniques. Analysis of maintenance costs has shown that a repair made in a reactive mode (i.e., after failure) will normally be three times greater than the same repair made on a scheduled basis.

MP TRANSCO ENGINEERS

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This blog provide all kinds of technical informations related to Transmission, EHV Substations design operation & maintenace, testing and commisioning , erection , installation, Related ISI codes, Grid codes and regulations.