modern age MODERN AGE

Modern age is referred to as the science age because of the changes qualitative and q2uantitative

THE QUANTUM MACHINE
Until MARCH 2010 all man made objects had moved according to the laws of classical mechanics. Back in MARCH a group of researchers

http://www.archive.org/details

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Performance Evaluation of New and In-Service Turbine Oils


•



For any power generation facility, the turbine is considered the lifeblood of the operation. Any problem requiring an unexpected shutdown of the main turbine is likely to cause a significant unplanned outage, potentially resulting in millions of dollars of downtime costs. According to a 1991 study by General Electric (GE), turbines contribute on average 20 percent of all forced outages in a conventional power plant. Among this 20 percent, GE noted that 19 percent of turbine/generator problems were associated with the lube oil system. For this reason, monitoring turbine oils has become commonplace in the power generation industry.

Figure 1. Contributors to Costly Forced Outage

Turbine oils, particularly those used in steam turbines, are expected to last around 10 to 20 years. For this reason, careful monitoring of both lube oil physical and chemical properties is required, together with common contaminants such as water and solid particles. This is true not just of in-service oils, but also for new oils, which must meet rigorous performance specifications prior to selection and use in a new application.

The testing of turbine oils is of such significance that ASTM has developed a standard devoted exclusively to this area, specifically ASTM D4378-97 “Standard Practice for In-Service Monitoring of Mineral Turbine Oils for Steam and Gas Turbines.” Some of the tests important to the evaluation of new and used turbine oils are detailed in the following discussion.

Viscosity ASTM D445 and Viscosity Index D2270

Viscosity is the most important characteristic of a turbine oil because the oil film thickness under hydrodynamic lubrication conditions is critically dependent on the oil’s viscosity characteristics. Turbine blade clearances are critical to power plant efficiency and reliability. These blade clearances are directly impacted by lubricant viscosity. Changes in oil viscosity can result in unwanted rotor positioning, both axially and radially. Axial movements directly impact turbine blade efficiency and in extreme cases can lead to blade damage. Radial movements caused by changes in viscosity can result in oil whip, where the rotor does not settle into one radial position. Oil whip can often be identified from vibration analysis, but is often a direct result of high viscosity.

For in-service turbine oils, the viscosity should remain consistent over years of service, unless the oil has become contaminated or severely oxidized. ASTM D4378-97 identifies a five percent change from the initial viscosity as a warning limit. It is important to note that this is a change with respect to a new oil baseline, not the typical value reported on the lube oil supplier’s spec-sheet. Testing for viscosity should be conducted on a quarterly basis, at a minimum.

The Viscosity Index (VI) is an indication of the oil’s change in viscosity with a change in temperature. Most gas and steam turbine OEMs require a turbine oil with a VI of

at least 90, which is met by most turbine oil suppliers. The VI for turbine oils should not vary in-service, because turbine oils typically do not contain VI improvers and therefore do not need to be tested routinely.

Rotating Pressure Vessel Oxidation

Test (RPVOT) - ASTM D2272

Formerly known as the RBOT test, the RPVOT test (Figure 2) was developed for the monitoring of in-service oils to warn of a loss in oxidation resistance. Oxidation is driven by heat and exposure to contaminants like water, entrained air and catalytic metals. As a turbine oil degrades, it forms weak organic acids and insoluble oxidation products that adhere to governor parts, bearing surfaces and lube oil coolers. After a period of time, these oxidation by-products and carbon insolubles cure on surfaces causing a significant change in critical clearances, and in some instances prevent the oil from providing adequate cooling to the bearings and fouling turbine control elements and heat exchangers.

This accelerated oxidation test is an industry standard for identifying oxidation stability problems with in-service turbine oils. ASTM D4378-97 identifies an RPVOT drop to 25 percent of the new oil RPVOT value with a concurrent increase in Acid Number (AN) as a warning limit. Many turbine OEMs simplify this by using the 25 percent of initial RPVOT without reference to AN, while others list a 100-minute RPVOT minimum. It should be noted that the RPVOT test is designed to determine a lubricant’s suitability for continued use, not to compare competitive oils. Competitive oil comparisons should be evaluated on the basis of RPVOT longevity, rather then the absolute RPVOT value.

In gas turbines that utilize a common lube oil sump for bearings and system hydraulics the use of ultra centrifuge testing should be used in conjunction with RPVOT as a means to determine varnish formation.

Typically, an oil that has reached its minimum allowable RPVOT values needs to be changed. However, as a short-term measure, the so-called “bleed and feed” method of turbine oil rejuvenation is suitable to extend the life of the turbine oil for a limited time.

Efforts to readditize a severely oxidized turbine oil with oxidation inhibitor can put equipment at risk. An oil that has a RPVOT value below 100 minutes more than likely has diminished its inherent base stock oxidation stability, making readditizing a nonpractical solution. In such cases, readditization may temporarily boost the RPVOT value but given the diminished nature of the base stock may sharply reduce the time frame before heavy varnishes and sludges are formed. Without the use of special filters such as Fuller’s Earth, to strip all polar materials, contaminants and additives, followed by complete readditization, the rejuvenation of a degraded turbine oil is inadvisable.

In steam and gas turbines, RPVOT testing should be conducted on an annual basis with an increased frequency as the turbine oil approaches 25 percent of its initial value. Some utilities time the test just before scheduled outages, to allow time to plan for an oil change if necessary.

Turbine Oil Stability Test (TOST) ASTM D943

The TOST test attempts to determine the expected turbine oil life by subjecting the test oil to oxidative stress using oxygen, high temperatures, water and metal catalysts, all of which increase sludge and acid formation. This test was developed to evaluate the anticipated new turbine oil performance. However, because it is impossible to simulate actual in-service conditions in a lab, correlation between test results and actual field performance is difficult. Most turbine OEMs utilize TOST in their specifications to screen out high-risk turbine oils.

Current gas turbine OEM specifications for TOST range from 2,000 to 4,000 hours with new gas turbine technology specifications at 7,000 hours. All TOST reporting above 10,000 is done through non-ASTM test modifications that may not correctly represent a turbine oil’s performance. Reporting of TOST values greater than 10,000 hours is not possible within ASTM D943 procedures due to the limited initial 300 ml test oil sample volume that is depleted during AN testing.

Because a TOST test can take up to a year or more to complete, it is impractical as an in-service oil test and is rarely performed for this reason.

Water by Karl Fischer

Titration - ASTM D6304

Testing for water, particularly in steam turbines, is important because water is a precursor to oil oxidation and rust formation (Figure 3).




Figure 3. Laboratory Moisture Test - Karl Fischer

Excessive water will also alter an oil’s viscosity, which reduces its load-carrying capacity. Studies also warn that water levels above 250 ppm in hydrogen-cooled generator windings may lead to stress corrosion cracking of generator rotor retainer rings. Water in a turbine oil in warm storage tanks, where the oil is typically stagnant, can promote the spread of microbial growth that will foul system filters and small-diameter gauge and transducer line extensions.

ASTM D4378-97 identifies 1000 ppm or 0.1 percent of water as a warning level, while some gas and steam turbine OEMs have identified 500 ppm. In hydrogen-cooled generators, an upper limit of 250 ppm should be maintained. Because free and emulsified water are the most harmful, it is advisable to keep water levels below saturation, typically 100 to 200 ppm depending on base oil types, additive formulation and age. Testing for water should be conducted on a quarterly basis, at a minimum using coulometric Karl Fischer Titration (ASTM D6304), complete with codistillation.

Acid Number (AN) - ASTM D664

Sharp increases in AN may indicate contamination or a severely oxidized oil. Organic acids formed by oxidation can corrode bearing surfaces and should be addressed in a timely manner. ASTM D4378-97 offers guidelines of 0.3 to 0.4 mg KOH/g above the initial value as an upper warning level. However, many oil analysts view an upward movement in AN as small as 0.1 as worthy of concern.

Testing for AN should be conducted at least on a quarterly basis using the potentiometric titration method (ASTM D664).

ISO 4406:99 Cleanliness Code

Turbine journal bearing clearances (10 to 20 microns) and hydraulic servovalve clearances (3 to 5 microns) dictate the need for clean oil. Excessive bearing wear and servovalve sticking can result if tight cleanliness standards are not maintained.

Typical OEM recommended turbine oil cleanliness levels are ISO (4406:99) 18/16/13 or an NAS 1638 cleanliness level of 7, although significant component life extension can be achieved by keeping cleanliness levels significantly lower than these limits.

Testing for ISO cleanliness should be conducted on a quarterly basis at the very least.

Rust ASTM D665 A

Rust particles act as oxidation catalysts and can cause abrasive wear in journal bearings. Rust inhibitors are normally kept at proper levels through the addition of makeup oil. Rust inhibitors can impact water separation so field readditization is generally not recommended.

In-service oil testing should be conducted with distilled water as identified in D665 A. ASTM D4378-97 considers a light fail as a warning limit.

Testing for rust should be conducted on an annual basis, or if the lube oil system is exposed to water.

Demulsibility ASTM D1401

Water shedding characteristics are important to lube oil systems that have had direct contact with water. This is particularly true for steam turbines where gland seal leakage is inevitable. The ability of the oil to shed water will have a direct impact on its long-term oxidation stability. Demulsibility can be compromised by excessive water contamination or the presence of polar contaminants and impurities. Demulsibility can be tested using ASTM D1401, in which a known volume of oil is mixed with water, and the time taken for the two to separate measured in minutes; the faster the separation, the better the demulsibility.

ASTM D4378-97 does not offer warning limits for demulsibility although some turbine OEMs identify levels of 3 ml emulsion after 30 minutes on new oils. In-service oil warning limits of 15 ml or greater of emulsion after 30 minutes should serve as a warning limit.

The impact of demulsibility depends on the system residence time and anticipated levels of water contam-ination. Demulsibility testing can show failure in the lab, but with sufficient residence time, the turbine oil may shed water at an acceptable rate that does not impact turbine oil performance. Small sumps with lower residence times will require better demulsibility performance than larger sumps. Testing for demulsibility should be conducted on an annual basis, or if the lube oil system is exposed to water.

Foam ASTM D892

A turbine oil sample will often test for foam higher than turbine OEM initial suggested levels, but typically present no field foaming issues because of the position of the suction line relative to the lube oil surface, where foam accumulates. If the foam level in the turbine sump is six inches or less and does not overflow the sump or cause level-monitoring issues, then turbine oil foaming is not usually a major cause for concern, although a sudden increase in foaming may indicate a more serious problem.

Lube oil at the turbine sump surface should show at least one clear area (no bubbles) and larger breaking bubbles should be seen at this interface.

ASTM D4378-97 offers warning limits for Sequence I of the foam test of 450 ml for foaming tendency, defined as the volume of foam generated after blowing for 5 minutes at 75°F (24°C), and a foam stability of 10 ml, defined as the residual foam left after a 10-minute settling period. A foam stability of less than 5 ml is a good indication that foam bubbles are breaking and the turbine should not experience foam operational problems.

When addressing a foam problem, cleanliness, contamination or mechanical causes should be investigated before field defoamant readditization can be considered. Excessive readditization can result in an even greater problem with increased air entrainment. Dirt is a leading cause of foam, so ISO cleanliness should be tested as a likely cause.

Testing for foam should be conducted only when foaming presents an operational problem and for product compatibility testing.

Air Release ASTM D3427

Some steam and gas turbine OEMs specify air release limits in their new oil specification requirements. These limits can be as low as four minutes, defined as the time for the air entrained during the test procedure to detrain to 0.2 percent by volume. This is typically not a problem for most ISO VG 32 turbine oils, but can be an obstacle for ISO VG 46 oils, due to the higher viscosity. In turbines with small sumps and minimal residence time, entrained air mixtures could be sent to bearings and critical hydraulic control elements causing film strength failure problems, loss of system control, particularly in EHC systems and an increased rate of oxidation.

Air release of turbine oils should not vary with in-service time and therefore may not need to be tested for condition assessments routinely, unless a specific problem is suspected.

FZG Gear Test - ASTM D5182

Turbines with geared shaft connections to the generator often require antiwear or extreme pressure additives to support gear tooth loading. Industry standard testing for gear load performance is the FZG Gear Test, with results reported as Failure Load Stage (FLS). Typical R&O ISO 32 turbine oils carry an FZG failure load stage of 6 or 7. ISO VG 32 R&O oils with antiwear or extreme pressure additives can give an FZG failure load stage of 10, which meets all major turbine OEM specifications.

FZG Gear Tests on turbine oils should not vary with in-service time and do not need to be tested for condition routinely unless a specific wear related problem is encountered.

Flash Point - ASTM D92

Flash point testing is done primarily to confirm product integrity from contamination.

Figure 4. Flash Point Testers

ASTM D4378-97 identifies a drop in 30°F (17°C) from the new oil flashpoint as a warning limit.

Flash point testing is required only if product contamination from a different oil or solvent is suspected.

Lube Oil Analysis Test Packages

Turbine oil lube oil analysis test packages should be assembled in a manner that provides pertinent, cost-effective information. Specific turbine oil test packages for regular trend analysis and suitability for continued use are described as follows:

Regular Trend Analysis (Monthly/Quarterly)

• Viscosity ASTM D445

• Water by Karl Fischer Titration ASTM D1744 (or D6304)

• Acid Number ASTM D664

• Cleanliness Code ISO 4406:99

• Elemental analysis

Suitability for Continued Use (“Turbine Annual”)

• Viscosity ASTM D445

• RPVOT ASTM D2272

• Water by Karl Fischer Titration ASTM D1744 (or D6304)

• Acid Number ASTM D664

• Cleanliness Code ISO 4406:99

• Rust ASTM D665 A (if exposed to water)

• Demulsibility ASTM D1401 (if exposed to water)

• Foam ASTM D892 Sequence I

• Elemental analysis

Figure 5. Laboratory Kinematic Viscometers



Onsite Checks

Often the most valuable and timely information is right in your hand at the time of sampling. Don’t pass up a great opportunity to assess key performance parameters on turbine oils. The use of clear, clean sample containers will allow for quick and easy quality checks as identified below:

• Color - Unusual and rapid darkening can indicate contamination or excessive degradation.

• Odor - Sour smelling oil can indicate contamination or excessive degradation.

• Air entrainment - Air bubbles in the body of the lube oil sample should clear within 15 minutes.

• Foam - After a vigorous shake, foam from the surface should clear within 10 minutes.

• Water - Turbine oil samples should be transparent. If you cannot read printing through a clear sample container, then water levels above 300 ppm may be present. A simple crackle test can also prove useful in determining if any free or emulsified water is present.

• Solids - Look for solids settling out as signs of external and internal contamination.

Additional onsite lube oil checks can be conducted by a lubricant supplier. These tests might include viscosity, filter patch for particulate, water concentration and thermography.

Knowledge of your turbine oil and its limitations will set the stage for years of reliable service. Keys to this knowledge include having the right tool for the job, and a solid understanding of lube oil analysis for new turbine oil evaluation and in-service oil condition monitoring. By following a few simple rules, like keeping the oil cool, dry and clean and by monitoring with regular, routine oil analysis, turbines oils should provide many years of continued service.

References

1. AISE Association of Iron and Steel Engineers. (1996). The Lubrication Engineers Manual - Second Edition. Pittsburgh, PA.

2. Bloch, H. P. (2000). Practical Lubrication for Industrial Facilities. The Fairmont Press. Lithburn, GA.

3. ExxonMobil Corporation. Turbine Inspection Manual. Fairfax, VA.

4. Swift, S.T., Butler, D.K., and Dewald, W. (2001). Turbine Oil Quality and Field Applications Requirements. Turbine Lubrication in the 21st Century ASTM STP 1407. West Conshohocken, PA.

5. ASTM. (1997). Standard Practice for In-Service Monitoring of Mineral Turbine Oils for Steam and Gas Turbines ASTM D4378-97. Annual Book of ASTM Standards Vol. 05.01.

Practicing Oil Analysis (3/2002)

Related Articles

• Oil Cleanliness in Wind Turbine Gearboxes

• Turbine Oil Reclamation and Refortification

• Lube System Modifications Boost Reliability

• Estimating Turbine Oil Oxidation

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EMF EQUATION OF THREE PHASE SYNCHRONOUS MACHINE

EMF EQUATION


Let P= No of Poles F= Flux per pole in webers, N= speed in RPM, f= frequency in Hz


Z ph = No of conductors connected in series in phase


Tph= No of turns connected in series per phase


Kc= Coil span factor Kd= Distribution factor


Flux cut by each conductor during one revolution=PF webers


Time taken to complete one revolution= 60/N sec


Average emf induced per conductor= PF/60/N= PFN/60 volts


Averagw emf induced per phase= (PFN/60)*Zph= PFN/60x 2 Tph= 4 Ff Tph


RMS value of EMF induced per phase= average value x form factor = 4.44 FTpf f


Form factor = 1.11


Taking into consideration the coil span factor and distribution factor of the winding Actual EMF induced per phase
E ph= 4.44 Kc Kd f F Tph

Coil span factor K c
The ratio of induced emf in a coil when the winding is short pitched to the induced emf in the same coil when it is full pitched is called a coil span factor or pitch factor or chorded factor. It is generally denoted by Kc and its value is always less than unity

Distribution factor Kd
The ratio of induced emf in the coil group when the winding is distributed in number of slots to the induced emf in the coil group when the winding is concentrated in one slot is called a distribution factor or breadth factor.

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Under ground water: Well and Spring water, Artesian well.
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Suspended impurities: These impurities are turbidity, color, odour, to water. It may be inorganic ( clay , sand, etc) or organic vegetables, etc
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Prob: A hydrocarbon fuel gave a flue gas
CO 2 % 13.53, O2 % 3.56 , rest nitrogen 82.91 %
a)determine composition of fuel by weight
b)the excess air percentage
c) volume of air supplied per kg. of fuel




soln:
Combustion reaction of Carbon (C)
C + O2 = CO2

This indicates that moles of carbon (C) = moles of CO2=moles of Oxygen (O)

Assuming let dry flue gas is 100 KMOL , so CO2= 13.53 KMol
Thus amount of O 2 in flue gas
= 13.53 ( from CO2) + 3.56( from free O2 in flue gas) = 17.09 K Mol
Given amount of N2 in the flue gas = 82.91 kmol
we know that in 100 kmol 79 Kmol N2 is present

Thus amount of air supplied for combustion = (100/79) X82.91= 104.95 Kmol
Amount of O2 supplied= 104.95x21/100= 22.039= 22.04 kmol
Amount of O2 that has combined with H2= 22.04-17.09= 4.95 kmol
the combustion equation for H2 is H2 +1/2 O2= H2O
So amount of H2 burnt= 2X 4.95= 9.9 Kmol
So amount of H2 burnt= 9.9X2= 19.8 Kg
As 100 kmol of flue gas containing 13.53 kmol of CO2 or 13.53 kmol of C
So of Carbon in the fuel= 13.53 x 12 = 162.36 kg.

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FORCE
Suppose a body is at rest or of uniform motion , their status of rest or motion is not going to change or tends to change unless a force is applied to the body.
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make up water

there are always losses of condensate and water in the water steam circuit. the water added in the feed water to make up for the losses generally termed as makeup water or simply makeup.

percentage of make up = (quantity of make up water/quantity of feed water) x 100

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Dear Friend fro Ludhiana ,India

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My dear friend from Kolkata India,
What is pH
Molecules of water, when splits into ions H2O = H + + OH -
The product of the concentrations of this ions if expressed in g-ion/litre at the given temperature Kw = C (OH-).C(H+) is constant, At 298 degree Kelvin Kw = 10 (-14)

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Hide out corrosion

Dear friend, Hide out corrosion occurs under the layers of sludges on water side surfaces . suppose suspended substances form the solid phase. with hide out corrosion the metal suffers local damage. The pits or cavities that form on the metal takes the shape of a shell . Damage of this kind usually occurs underneath the layers.

Steam Water Balance

Dear friend from Bangladesh,
When considering the basic flow diagram of a thermal power plant following flows of feedwater system can be considered a) turbine condensate b)heat distribution system heaters c) regenerative systems condensate d) chemically treated water from water treatment plant. Turbine condensates which is recycled back is also chemically treated rather termed as water conditioning to suit boiler, turbine,heaters, and other equipments metallurgical and variable process requirements to protect against scaling & corrosion,

Turbine Condensate

Dear friend Shrutt
1.Let a natural circulation boiler having Steam Pressure of 40 Kg/Cm2, hardness of turbine condensate must not be over 10 microgram-equivalent/kg.
2. When steam pressure is in between 40 Kg/Cm2 to 100 kg/cm2 hardness of turbine condensate should be restricted to 5 microgram-equivalent/Kg
3. When it is greater than above two cases hardness must not exceed 1 microgram-equivqalent/Kg
4. for once through system it is restricted to 0.5 microgram-equivalent/Kg

Water Chemistry {Prevention of Corrosion}

Dear Mr. Pathak
About High Alkalinity correction method (treatment with ammonia only)
Appreciably this method differs from the alkaline one in that a high Ph value 9.4 -9.5 is maintained in the water condensate circuit at the expence of high ammonia concentration in water. Replacement of the brass tubes is necessary by steel tubes ( made by pearl tic grade).
Please remember at Ph>9.1 corrosion of copper tubes proceed at higher rates and concentration of copper in feedwater increases .Turbine blades are deposited with copper settles . Steam turbine efficiency decreases.

There are many effective and informative e-zine articles, E Books are available in the internet which are free to read for the above and related issues .

Water Treatment preliminary learning

STANDARD SOLUTION PREPARATION:
1. N/50 EDTA SOLUTION: - 3.724 gm. OF ETHYLENE DIAMINE TETRAACETIC ACID DISODIUM SALT DISSOLVED IN 1000 ml DISTILLED WATER.
2. N/50 HCL SOLUTION: - 1.8 ml OF CONC. HCL MIXED WITH 1000 ml. OF DISTILLED WATER.
3. N/50 AgNO3 SOLUTION: - 3.398 gm. OF SILVER NITRATE DISSOLVED IN 1000 ml. OF DISTILLED WATER.
4. AMMONIA BUFFER SOLUTION: - 67.6 gm. OF AMMONIUM CHLORIDE AND 568 ml. OF AMMONIUM HYDRAUXIDE MIXED UP IN 1000ml. OF DISTILLED WATER.
5. ERIOCHROME BLACK T INDICATOR: - 0.25 ERIOCHROME BLACK T AND 0.25 gm OF HYDRAUXL AMMONIUM HYDROCHLORIDE DISSOLVED IN 50 ml ETHANOL.
6. PHENOPTHALEIN INDICATOR SOLUTON:- 0.25 gm OF PHENOPTHALEIN DISSOLVED IN 50 ml. OF WATER
7. METHYL ORANGE INDICATOR SOLUTION:- 0.1 gm. METHYL ORANGE DISSOLVED IN 100 ml. WATER
8. POTASSIUM CHROMATE SOLUTION :- 5 gm. OF POTASSIUM CHROMATE DISSOLVED IN 100 ml. OF DISTILLED WATER.
9. MUREDIX INDICATOR :- 0.5 gm. OF MUREDIX WITH 100 gm. NaCl
10. HCL SOLUTION :- 100 ml. HYDROCHLORIC ACID MAKE UP IN 100 ml. OF DISTILLED WATER.
11. 10% AMMONIUM MOLYBDATE SOLUTION :- 20 gm. AMMONIUM MOLYBDATE DISSOLVED IN 200 ml. DISTILLED WATER.
12. 10% OXALIC ACID SOLUTION:- 20 gm. OF OXALIC ACID DISSOLVED IN 200 ml. DISTILLED WATER.
13. A.N.S.A. SOLUTION:- 0.25 gm. AMINO NAPTHOL SULPHONIC ACID , 0.5 gm. SODIUMSULPHATE AND 8.25 gm. SODIUM META BI SULPHITE DISSOLVED IN 200 ml. DISTILLED WATER.
14. PHOSPHATE 1 SOLUTION:- 0.85 ml. NITRIC ACID 63 ml. SULPHURIC ACID AND 7.85 gm. AMMONIUM MOLYBDATE DISSOLVED IN 200 ml. DISTILLE WATER.
15. PHOSPHATE 2 SOLUTION:- 0.15 gm. AMINO NAPTHOL SULPHONIC ACID , 8.4 M. SODIUM SULPHITE & 14 gm. SODIUM META BI SULPHITE DISSOLVED IN 200ml. WATER
16. HCL SOLUTION:- 20 ml. CONC. HCL AND DISTILLED WATER 200 ml. MIX.
17. P-DIMETHYL AMINO BENZELDEHYDE SOLUTION :- 15 gm. PDAB DISSOLVED IN CONC. HCL AND MAKE UP WITH DISTILLED WATER UP TO 500ml.

INDICATIVE TYPICAL WATER QUALITY PARAMETES;


PARAMETERS
RAW WATER
SOFT WATER
D.M.WATER

Ph
7.8- 8.0
7.8-8.0
6.8-7.2

CONDUCTIVITY
1000-1100
1000-1100
< 1

TDS IN ppm
670-750
670-750
< 1

TOTAL HARDNESS AS CACO3 IN ppm
250-300
0-50
NOT DETECTABLE

CALCIUM HARDNESS AS CACO3 IN ppm
200 MAX
35 MAX
NOT DETECTABLE

MAGNESIUM HARDNESS AS CACO3 IN ppm
100 MAX
10 MAX
NOT DETECTABLE

TURBIDITY IN NTU
<1
<1
<1

P ALKALINITY AS CACO3 IN ppm
NIL
NIL
NIL

M ALKALINITY AS CACO3 IN ppm
200- 220
200-220
NIL

CHLORIDE AS CACO3 IN ppm
250-300
250-300
NIL

SILICA AS SIO2 IN ppm
5-10
5-10
<0.02






ABOVE PARAMETERS ARE INDICATIVE ONLY IT WILL VARY PLACE TO PLACE AND SOURCE OF WATER. .WATER QUALITY PARAMETERS ARE TO BE CHECKED BEFORE DECIDING WATER TEATMENT PROCESS SELECTION AND APPLIATION OF SUITABLE TECHNOLOGY





THE PROCESS OF DEMINERALISATION:

THE MOST BASIC PROCESS OF DEMINERALISATION THROUGH ION EXCHANGE IS TWO STAGE DEMINERALISATION . THE FIRST STAGE IS REMOVAL OF CATION FOLLOWED BY REMOVAL OF ANIONS.
THE CATION EXCHANGE UNIT CONTAINS A STRONG ACID CATION EXCHANGER IN A REGENERATED FORM. THE EXCHANGER TAKES UP CATIONS IN WATER IN EXCHANE OF HYDROGEN IONS WHICH IT GIVES UP .

THE CATIONS LIKE CALCIUM, MAGNESIUM, AND SODIUM EXIST IN THE FORM OF CHLORIDE, SULPHATE CARBINATE AND BICARBONATE SALTS WHICH GETS CONVERTED TO THEIR EQUIVALENT ACIDS.

CHEMICAL REACTION

NACL + RH = R NA + HCL
SODIUM HYDROGEN SODIUM
CHLORIDE EXCHANGER EXCHANGER

MGSO4 + RH = R2 MG + H2SO4
MAGNESIUM HYDROGEN MAGNESIUM
SULPHATE EXCHANGER EXCHANGER

CA(HCO3) + RH = R2CA + H2CO3
(CO2+H20)



RENEGERATION

RNA + HCL = RH + NA, CA MG CHLORIDESALTS
RCA + H2SO4 = RH + NA, CA MG
SULPHATE
SODIUM, MAGNESIUM, ACID
CALCIUM EXCHANGER






ANION EXCHANGE

HCL + ROH = RCL + H20
HYDRAUXIL CHLORIDE
EXCHANGER EXCHANGER
H2SO4 + ROH = R2SO4 + H20
HYDRAUXIL
EXCHANGER

REGENERATION

RCL + NAOH = ROH + NACL

R2SO4 + 2NAOH = 2ROH + NA2SO4


CARBONATES /BICARBONATES IN THE CATION EXCHANGE PROCESS ARE CONVERTED TO CARBONIC ACID WHICH DISSOCIATES AS IT IS A WEAK ACID, INTO CABONDIOXIDE AND WATER. THIS CARBON DIOXIDE IS REMOVED BY DEGASSED AIR. OTHERWISE IT WOUL BE ABSORBED BY THE STRONG BASE ANON EXCHANGER.
THE STRONG ACID CATION, WEAK BASE ANION,AND STRONG BASE ANION EXCHANGERS ARE REGENERATED WITH SPECIFIC QUALITIES OF ACID AND ALKALI.TO GET A SPECIFIC EXCHANGE CAPACITY . WHEN THIS CAPACITY IS EHAUSTED THE QUALITY OF TREATED WATER DETERIORATES, POINTING TO THE NEED FOR REGENERATION.

WATER SOFTENING

WHEN RAW WATER PASSES THROUGH THE ION EXCHANGE WATER SOFTENER CALCIUM AND MAGNESIUM IONS IN THE RAW WATER ARE EXCHANGED FOR SODIUM IONS.
THERE IS NO DESCREASE IN THE TOTAL DISSOLVED SOLIDS CONTENT OF THE TREATED WATER.
THERE IS NO CHANGE IN THE PH OR TOTAL ALKALINITY CONTENT.
THE SPECIFIED OUTPUT OF THE SOFTENER IS BASED ON SPECIFIED RAW WATER HARDNESS, IF THERE IS AN INCREASE IN RAW WATER HARDNESS THERE WILL BE A PROPORTIONATE DECREASE IN CAPACITY.
THE RAW WATER HARDNESS MUST BE CHECKED PERIODICALLY.
TREATED WATER HARDNESS MONITORING IS REQUIRED AT THE END OF THE RINSE

BRIAN TRACY UNIVERSITY

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