ENGINECOOLINGSYSTEM

EVAPORATOR/DISTILLERSYSTEM

BOILERSYSTEM

EXHAUSTSYSTEM

Drew Marine DivisionSHIPBOARD WATERTREATMENT MANUAL4.1 Edition

TM-WT-1 (11/01)R7

SHIPBOARD WATERTREATMENT MANUAL

4.1 EDITION

Marine Chemical Products

MAINTENANCE CHEMICALS (cont'd)FERROCLEAN® cleaning agentHDE-777TM heavy duty emulsifierNEVAMELTTM wire rope conditionerO&GRTM oil and grease removerOSD/LTTM oil spill dispersantSAF-ACIDTM descaling compound

ENVIRONMENTAL CHEMICALSDREW ELECTRICTM 2000 motor and parts cleanerDREWCLEAN 2000 quick breaking degreaserSNCTM 2000 carbon remover

SANITATION PRODUCTSAMEROID® MSD-PAK organic waste treatmentBIOTAL1 MDS 2000 shipboard waste treatmentBIOTAL MDS 2000C shipboard waste systems treatment concentrate

TANK CLEANERSDREW ABD alkaline based degreaserDREW AF air freshenerDREW BC buffering cleanerDREW CTC coal tar cleanerDREW LPA liquid pickling agentDREW NBD neutral based degreaserDREW PL passivating liquidDREW TC SEA tank cleanerEDGE® heavy duty cleanerLACTM liquid alkaline cleanerTC#4TM tank cleaner

SPECIALTY PRODUCTSMUD CONDITIONERTM ballast tank water treatment

TECHNICAL PRODUCTSDREWFRESH® 2000 heavy duty cleaner

CORROSION COATINGSDREWTANTM RC rust converterDREW PD anticorrosion coatingMAGNAKOTE® rust preventativeMAGNAKOTE PLUS rust preventative

MISCELLANEOUSMOTORGARDTM total motor vessel protection programULTRAMARINESM water treatment program

BOILER WATER TREATMENTADJUNCT® B phosphate boiler water treatmentAGK® 100 boiler and feedwater treatmentAMERZINE® corrosion inhibitorCATALYZED SULFITETM corrosion inhibitorDREWTM BWT-3 boiler water treatmentDREW BWT-4 boiler water treatmentGCTM concentrated alkaline liquidSLCC-ATM condensate corrosion inhibitorLIQUID COAGULANTTM boiler sludge conditioner

PERFORMANCE BOILER WATER TREATMENTDREWPLEX® AT boiler water treatmentDREWPLEX OX corrosion inhibitor

EVAPORATOR TREATMENTAMEROYAL® evaporator treatmentAMEROYAL® CF concentrated evaporator treatmentAMEROYAL CF/HG concentrated evaporator treatment

COOLING WATER TREATMENTAMERSPERSE® 280 seawater cooling treatmentDEWT® NC diesel engine water treatmentDREWSPERSE® SWD seawater dispersantFERROFILM® corrosion and erosion inhibitorMAXIGARD® diesel engine water treatmentLIQUIDEWTTM cooling water treatment

FUEL ADDITIVESAMERGIZE® deposit modifier/combustion improverAMERGY® 222 fuel oil conditionerAMERGY 1000 combustion improverAMERGY 5000 combustion improverAMERGY 5800 PLUS deposit modifier/combustion improverAMERSTAT® 25 microbiocide fuel treatmentDREWCLEAN® EST economizer soot treatmentF.O.T.TM fuel oil treatmentLT SOOT RELEASETM low temperature soot removerSOOT RELEASETM soot combustion catalyst

MAINTENANCE CHEMICALSACC-9TM air cooler cleanerACC/ME® air cooler cleanerAMEROID® DC disc cleanerAMEROID® OSC one-step cleanerAMEROID® OWS quick separating degreaserAMEROID® RSR rust stain removerCARBON REMOVERTM solvent cleanerCILTM corrosion inhibitorDESCALE-ITTM liquid acid descalerDREW FC filter cleanerDREWCLEAN EOSD enviro oil spill dispersantENVIROMATE® 2000 general purpose cleaner

FOREWORD

This manual is intended for use by persons who areconcerned with the chemical testing, dosing, and controlof a shipboard water treatment program. Included areexplanations of why water treatment is required and adescription of the methods used in modern marine prac-tice. The purpose and application of each of the DrewMarine water treatment chemicals is explained. Thisedition has been updated to include the newest treat-ments and tests in our line.

The power plants of modern steam and motor vessels aremore efficient today than at any other time in history.Boilers and diesel engines are designed to extract thegreatest possible amount of energy from the fuel and toturn that energy into work. Turbines, generators andauxiliary equipment are designed to make the most effec-tive use of the steam or mechanical energy that is supplied

to them. Efficient operation of the marine power plantdepends significantly on the quality of the water that itreceives. Contaminants such as dissolved minerals, gases,oil, and even the water itself can cause serious damage topower plant equipment unless proper control steps aretaken.

Testing is an important part of any water treatment pro-gram because the test results are the primary means ofcontrolling the program and of detecting problems. All testprocedures are described in this manual after discussionof the applicable treatment program. We refer the readerto the section entitled "General Information" which shouldbe read before conducting tests. Here, recommendationsare provided for proper sampling, general testing andrecording techniques.

i

CREDITS FOR ILLUSTRATIONS

We wish to acknowledge the sources of some of the illustrations used in this manual.

Reference Page(s)

CHEMetrics, Inc., Calverton, VA46, 48, 49, 55, 56, 57, 58, 63

MARINE ENGINEERING, Roy L. Harrington, ed., The Society of Naval Architects and Marine Engineers, NY, NY 1971 12

Nirex, Alfa-Laval Group, Fort Lee, NJ 13

Riley-Beaird, Inc., Shreveport, LA 12, 13

FOREWARD ................................................................................................................... i

GENERAL INFORMATION ............................................................................................. 1• Introduction ............................................................................................................ 1• Water Sampling Procedures .................................................................................. 2• Analytical Techniques ............................................................................................ 4• Expression of Chemical Results ............................................................................ 7

BOILER WATER SYSTEMS AND TREATMENT ............................................................ 9• Introduction ............................................................................................................ 9• Production of High Quality Distillate ....................................................................... 10• Boiler Water System Circulation ............................................................................ 14• Corrosion of Metals ................................................................................................ 16• Chemical Treatment ............................................................................................... 19• Composition and Formulation of Deposits .............................................................. 21• Special Operating Conditions ................................................................................. 24• Boiler Water Treatment Chemicals ........................................................................ 25• Boiler Water Treatment Chemical Applications and Controls ................................. 26• Introduction to Water Treatment Control Tests ...................................................... 34

Alkalinity:• Hydrate (AGK® 100 and DREWPLEX® AT) ......................................................... 35• Medium to Low Pressure .................................................................................... 36• High Pressure ..................................................................................................... 37• Conversion Table (high, medium and low pressure) ........................................... 38Ammonia (condensate, high pressure) .................................................................. 39Chloride:• HP Test Kit ......................................................................................................... 40• Mercuric Nitrate Burette Titration ........................................................................ 41• LMP Test Kit ....................................................................................................... 42• Silver Nitrate Burette Titration ............................................................................. 43• Conversion Table (high, medium and low pressure) ........................................... 44Conductivity (all pressures) .................................................................................... 45DEHA/DREWPLEX OX corrosion inhibitor Ampoule Test ...................................... 46Hardness:• Ampoule Method (high pressure) ........................................................................ 47• Titret2 method ..................................................................................................... 48HYDRAZINE/AMERZINE:• (High to low pressure) ......................................................................................... 49pH:• Colormetric (high pressure boilers) ..................................................................... 50• Meter (high pressure boilers) .............................................................................. 51• Condensate (AGK 100 and DREWPLEX AT) ..................................................... 52• Condensate (standard treatment) ....................................................................... 53• Condensate (high pressure) ............................................................................... 54

Table of Contents

ii

Phosphate:• (High Pressure) .................................................................................................. 55• (Medium to low pressure) ................................................................................... 56Silica (high pressure) ............................................................................................. 57Sulfite (medium to low pressure) ............................................................................ 58

COOLING WATER SYSTEMS AND TREATMENT ......................................................... 59• Introduction ............................................................................................................ 59• Cooling Water System Circulation .......................................................................... 59• Corrosion of Metals ................................................................................................ 60• Composition and Formation of Deposits ................................................................ 61• Cooling Water Treatment Chemicals ..................................................................... 62• Cooling Water Treatment Chemical Applications and Controls .............................. 62• Cooling Water Treatment Control Tests

and Dosage Requirements ................................................................................. 62CWT Test (Titret2 Method) ...................................................................................... 63DEWT® NC ............................................................................................................ 64-65Reference Tests:

Chloride (treated water) ...................................................................................... 42 Chloride Sample Pretreatment ......................................................................... 66Hardness ............................................................................................................ 47

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1

GENERAL INFORMATION

INTRODUCTION

Proper testing techniques are necessary to assure a wellcontrolled water treatment program. This section describesthe best methods for obtaining water samples and conduct-ing chemical tests. Because test results must be recorded

using the correct units of mass, volume and concentrationmeasurements, a section entitled "Expression of ChemicalResults" has been included for your reference.

PROPER RECORD KEEPING

An important part of an analytical program is the keeping oflegible and accurate logs. Complete information is essentialfor an accurate evaluation of the progress of the treatmentprogram. When recording the test data, remember thefollowing pertinent points:

• Use the proper Onboard Graphing Logs for the systembeing treated.

• Record all information legibly.

• Distribute copies to Drew's Technical Department, owner'soffice and ship's records as indicated in the instructions onthe log. All Drew Onboard Graphing Logs are printed onNCR paper so that carbon paper is not needed.

• Fill in all required information to identify the ship, the ship'soperating company, the voyage number, the equipmentbeing tested, the date of the the review period, the boilertype and pressure, and inport or full steaming conditions.

• Record test results and treatment dosages, markingproper units of measurement on the Onboard GraphingLog. The colored band will indicate the satisfactory rangefor each control test. Reference test results should berecorded in the appropriate boxes.

IMPORTANT: Decimal points must be placed correctly toeliminate misunderstandings and inaccurate evaluations.

• Any additional relevant information relating to the condi-tion of the vessel, the equipment being treated, or thetreatment program should be recorded in the appropriatespace.

EXPRESSION OF CHEMICAL DOSAGESCONVERSIONS (M = METRIC, E = English)*

UNITS MEASUREMENT SYMBOL MULTIPLY BY TO FIND SYMBOL MASS (weight)

M to M kilogram kg 1000 gram gmM to M gram gm 1000 milligram mgE to E pound lb 16 ounce ozM to E gram gm 0.035 ounce ozM to E kilogram kg 2.2 pound lbE to M ounce oz 28 gram gmE to M pound lb 0.45 kilogram kg

VOLUME

M to M liter ltr 1000 milliliter mlE to E cup c 8 fluid ounce fl ozE to E pint pt 2 cup cE to E quart qt 2 pint ptE to E gallon gal 4 quart qtM to E milliliter ml 0.03 fluid ounce fl ozM to E liter ltr 2.1 pint ptM to E liter ltr 1.06 quart qtM to E liter ltr 0.26 gallon galE to M fluid ounce fl oz 30 milliliter mlE to M cup c 0.24 liter ltrE to M pint pt 0.47 liter ltrE to M quart qt 0.95 liter ltrE to M gallon gal 3.785 liter ltr

*NOTE: The U.S. version of the English units is used in these calculations.

2

WATER SAMPLING PROCEDURES

The main purposes of routine water testing are:

1. To ensure that the proper residuals of treatment chemi-cals are maintained at all times.

2. To detect the presence of contaminants in the water thatmay be injurious to the boiler, diesel engine, and otherequipment.

Test results are meaningful and useful only when the samplestested are representative of the water in the system at thetime of testing. Recommended procedures for obtainingrepresentative samples of boiler water, condensate, makeupwater, feedwater, and cooling water circuits are discussed inthe following sections.

RECOMMENDED LOCATIONFOR SAMPLING CONNECTIONS

Boiler Water Sampling

Normally you can use the sampling connections provided bythe boiler manufacturer. The sampling line is usually locatedin the steam drum, just above the generating tubes. In orderto get proper results, it should be as far as possible from theinternal feedwater line and the chemical feed line.

Samples drawn for routine boiler water tests should be testedONBOARD THE VESSEL. Boiler water samples for labora-tory analysis should be taken only in special cases. Boilerwater samples are not normally submitted for iron andcopper analyses since results are not representative of thecorrosion rate in the system. This is because of the boilerwater alkalinity conditions and the tendency to collect ironand copper deposits from other parts of the system than inthe boiler.

Condensate and Feedwater Sampling

Stainless steel sampling lines should be installed at threelocations:

• Directly after the Main Condensate Extraction Pump. Thisline is to be used when the plant is under normal steamingconditions.

• Directly after the Auxiliary Condensate Extraction Pump.This line should be used only when the plant is under portoperating conditions.

• The deaerator outlet line or from the suction or dischargeof the main feedwater pump.

The latter is the best position for samples drawn for iron andcopper tests; these samples will give a direct indication of theamounts of metal oxides entering the boiler with the feedwater.These connections may be used for obtaining samples fordissolved oxygen tests if they are ever required.

On motor vessels or for LPSG's, condensate samples shouldbe taken after the condensor or condensate cooler andbefore the feed or cascade tank to avoid recirculation fromthe feed pump. See page 31.

Makeup Water Sampling

The sampling line for this water may be located in one or twopositions:

• In the line between the distilled water storage tank and thepoint of entrance of makeup water to the condensatesystem.

• Directly from the distillate condenser.

SAMPLING EQUIPMENT

Before testing, boiler water, hot condensate and feedwatersamples must be cooled to 25OC (77OF) by collecting througha sample cooler for safety and to prevent flashing whichconcentrates the sample. Stainless steel sample coolersshould be used except where seawater is used for cooling.Where seawater is the only coolant, contact your DrewMarine representative for proper handling procedures or aspecial coil.

Stainless steel piping or tubing used for sample lines shouldbe installed with the least possible number of fittings and/orsharp bends. This is a precaution against plugging the lineswith solid contaminants. The stainless steel sampling linesmust meet international pressure code requirements. Tubingsize should be 1.0 cm (3/8 in.) O.D.; nominal pipe size shouldbe 1.0 cm or 1.27cm (3/8 in. or 1/2 in.). Stainless steel isrecommended to prevent contamination of sample by corro-sion from the lines.

OBTAINING SAMPLES FOR SHIPBOARD TESTS

1. Allow the sample stream to run for 5-10 minutes in orderto thoroughly flush out the line before taking a sample fortesting.

2. A convenient and desirable procedure is to open thesample valve and allow the stream to run throughout thetesting period. Appropriate samples for each individualtest may be taken from the sample stream as needed.Test equipment, graduated cylinders, evaporating dishes,etc., should be clean and rinsed with the water to betested and thoroughly drained.

3. If analysis of a sample must be delayed for any reason,the sample should be kept tightly capped in a cleansample bottle which has been thoroughly rinsed withwater from the sample stream. After a long delay,resample. Test results for pH, alkalinity, hydrazine,sulfite or ammonia will be less accurate if testing isdelayed because of the effect of air on these treatments.

OBTAINING SAMPLES FORLABORATORY TESTINGThe following special procedures are to be followed whenobtaining samples for testing at shoreside laboratories:

1. A boiler water sample for laboratory analysis should becollected in a glass bottle. Minimum sample volume forboiler water analysis is 1,000 ml (one U.S. quart).

2. Condensate and feedwater samples for iron and copperanalyses must be collected in special high purity plasticbottles. The minimum sample volume required for ironand copper analyses is 120 ml (4 oz.)

4. Draw samples while boilers are operating under full ornormal steaming conditions.

5. Flush the sample line for 5-10 minutes prior to obtaininga sample for testing. Flush for a longer time if the line israrely used.

6. The sample container should be thoroughly rinsed withthe water being tested and completely filled to overflowingso there will be no air space at the top of the sample bottle.However, if there is a danger of freezing, leave somefreeboard in the bottle for expansion; otherwise, the bottlewill burst. Tightly seal and properly label the sample bottlewith the following information: vessel name, source of thesample, date of sampling, and information which de-scribes the reason for sampling and any existing prob-lems. This information is essential in order to determinewhat tests should be conducted and in the evaluation ofresults.

Request for Analysis Forms

In order to assure that the samples you are taking areanalyzed promptly, Drew Marine has developed ISO 9002forms that accompany the Sample Paks. The instructions forfilling out the form follow:

Please print clearly the following information in the spaceprovided:

• Vessel Name• Owner or Manager Name• Date Sample was drawn or collected• Date Sample was landed to be sent to Laboratory• Port where Sample was landed

3

In addition, fill in the line(s) that ask for sample identification(e.g., Port boiler water, Main engine jacket cooling, etc.)Check the box that is appropriate for the sample:

MBW - Boiler water analysisMCW - Cooling water analysisMBAL - Ballast water analysisMPD - Boiler deposit sample analysisMCD - Cooling deposit sample analysisMFD - Fireside deposit analysisMHP - High purity feed and/or condensate analysis

In Sections I through IV, please fill out the particulars of theequipment, symptom of the problem, if applicable, andanything else that can help us in interpreting the analysisresults.

Reports will be issued to the Account Executive responsiblefor your owner or manager. Distribution of these reports willbe left to the discretion of your owner or manager.

ANALYTICAL TECHNIQUES

Accurate analytical testing procedures are essential forproper control of chemical treatment programs. This sectionbriefly describes the basic information common to all treat-ment programs and the procedures which should be fol-lowed for each of the analytical control tests.

PREVENT CONTAMINATIONAND STORE REAGENTS PROPERLY

To ensure accurate test results, the analyst should take thenecessary precautions to prevent contamination of the test-ing equipment before, during and after each test. It isimperative to have clean hands, a clean working surface,and, most important, clean test equipment and uncontami-nated reagents within their normal shelf life.

CARE OF REAGENTS

Reagents by their nature are reactive. Care must be taken toprevent contamination and deterioration.Closeall reagentbottles tightly with their original stoppers or caps. Use sepa-rate clean, dry spoons or droppers for each reagent toprevent cross-contamination of reagents. Never return ex-cess reagent solution or powder to storage bottles.

To ensure freshness, periodically replace reagents. Storespare chemical supplies in a clean, cool cabinet, preferablyoutside of hot, humid areas. Air-conditioned rooms are agood environment for reagents. Powdered reagents canabsorb moisture if stored in refrigerators so storage in an air-conditioned area is preferable.

Some reagents are light sensitive so it is a good general ruleto store them in the original bottles in which they are suppliedin closed closets.

USE OF COLORIMETRIC EQUIPMENT

For accurate results using the color comparator slides, thepath of light through the viewing tubes must be free of dirt orother obstructions. Before inserting the viewing tubes into thecomparator, gently tap the tubes against the palm of yourhand to dislodge any gas bubbles from the test solution.Clean the outer surface of each tube to remove waterdroplets and fingerprints. The outside surface of the com-parator slide and color standards should also be clean.

There should be sufficient lighting behind the comparatorwhen running the test to obtain accurate color comparisonand uniform results. Daylight fluorescent light is preferred.

When filling or reading liquidlevels in calibrated glasswaresuch as burettes and graduatedcylinders, read the level wherethe bottom of the concave liquidsurfaces reaches the line ofmeasurement. The concavesurface of a water solution iscalled the meniscus.

READING CALIBRATED GLASSWARE

BURETTE TITRATION

Proper titration technique is important to assure accurate testresults. The titrating solution should be slowly added to thesample while stirring until the desired endpoint is reached.Addition of titrant should be slowed to one drop at a time asthe endpoint approaches to avoid overshooting the endpoint.The approaching endpoint is signaled by temporary colorchange where the titrant enters the sample. The first perma-nent color change throughout the sample is the endpoint.

MEASURING SPOON

The brass measuring spoon has been specially selected tomake the addition of reagent easy. It is used for delivering aspecified amount of reagent to a cooling water sample whenrunning the DEWT® NC test procedure. It is also used foradding Gallic Acid to neutralize boiler water when testingconductivity.

Code: 0224-01-4

Description: Measuring Spoon, Brass

4

CalibratedGlassware

Line ofMeasurement

Meniscus

5

WATER ANALYZER BASEWATER ANALYZER BASEWATER ANALYZER BASEWATER ANALYZER BASEWATER ANALYZER BASEGENERAL INSTRUCTIONSGENERAL INSTRUCTIONSGENERAL INSTRUCTIONSGENERAL INSTRUCTIONSGENERAL INSTRUCTIONS

The Water Analyzer is used to determine boiler pH in theULTRAMARINESM program.

The Water Analyzer consists of a base structure (A), threeglass tubes (B)(C)(D), and one or more comparator slides (E)fitted with transparent color standards (F). The tubes aremodified "Nessler" tubes, and each has an etched mark (G)at 150 mm or 250 mm above the bottom. The base has acompartmented holder (H) for the tubes, which supportsthem at a 45O angle above a mirror (J) set into the base. Theslides move in a slot in the base (K) above the mirror andbeneath the tubes.

USE OF THE WATER ANALYZER1. Set the appropriate comparator slide for the desired test

in the slot in the base. The row of numbers on the slide(corresponding to pH values, ppm silica or ammonia,etc.) should be visible when the slide is viewed fromabove the mirror.

2. Fill the two outer tubes (B & D) to the etched mark withreference blanks according to the instructions for theparticular test. Place these tubes in the two outercompartments in the base.

3. Add reagent chemicals to another portion of the sample,according to the instructions for the particular test.

4. Fill the middle tube (C) to the etched mark with thetreated sample and place it in the middle compartmentin the base.

5. Set the base on a flat surface so that the mirror faces theoperator and a light shines into the open ends of thetubes.

6. Move the slide back and forth, while observing thecolored ovals that will appear in the mirror. Continueuntil the color of the middle oval matches that of one ofthe side ovals. Note that the comparison can be madeonly when one of the arrows on the slide is opposite themiddle tube.

7. When a color comparison is obtained, read the testresult (in pH) from the numbers on the slide.

FILTER PAPER

Filtration is required in some test procedures. This is es-pecially true if suspended solids appear in the sample.Failure to filter a sample when required or the repeated useof the same filter will result in an incorrect value. There is oneexception to this rule. If a sample remains cloudy after the firstfiltering, the sample should be refiltered through the samefilter paper since the filter becomes more retentive on thesecond filtration.

Some filter papers are specially prepared to minimizecontaminanats. (Drew specifies a Whatman #5 filter paper).

The most simple technique for folding filter paper is:

Pour the sample into the center of the cone. Do not fill thefunnel above the upper surface edge of the filter paper.Sample which flows between the paper and funnel will addunwanted materials to the filtered sample.

6

Fold the paper in half (Step 1) andthen in half again (Step 2).

Pull three-quarters of the paperto one side and crease to holdthe cone shape (Step 3). Insert thetip of the cone into the funnel (Step4).

Step 1

Step 2

Step 3

Step 4

REPORTING OF QUANTITY

When reporting the results of an analysis, it is necessary toexpress the quantity of each constituent that is determined.In the analysis of most materials, the quantity of eachconstituent is given in terms of percent--the amount of eachconstituent per 100 parts of the material. For example, ananalysis of a metallic sample may show 60 percent copperwhich would mean that every 100 parts of the sample contain60 parts of copper.

Reporting by percent is not practical in water analysis sincethe amounts of the materials determined are extremelysmall. For example, the silica content of natural waters, ifexpressed in percent, would be in the range from 0.0001%to 0.01%. To avoid the use of very small numbers, the terms"parts per million" (ppm) and "parts per billion" (ppb) are usedin water analysis. The terms ppm and ppb are utilized byDrew Marine in its publications and reports.

Parts Per Million (ppm)

One part per million (ppm) is an expression of the relationshipof one part of a substance to one million parts of another. Asexamples, if a water contains one ppm of silica, there wouldbe one part of silica in 1,000,000 parts of the sample. In a

1 gram silica 1,000,000 grams (1 metric ton) = 1 ppm silica

7

EXPRESSION OF CHEMICAL RESULTS

million grams (1 metric tonne) of this water, there would beone gram of silica; or in a million pounds of water, therewould be one pound of silica. Expressing results in terms ofparts per million is a simple method to use, and for mostdeterminations, the results are given in whole numbers.

Parts Per Billion (ppb)

One part per billion (ppb) is used to express the relationshipof one part of a known substance to one billion parts ofanother. For example, a sample of water may contain onepart of silica to one billion (1,000,000,000) parts of water. Asindicated above for "ppm", "ppb" may be applied to quanti-ties expressed in any unit of measure.

REPORTING OF pHAcidity, Neutrality, Alkalinity

An aqueous solution can be either acidic, neutral or alkaline.The accepted manner of expressing this condition is pH. pHis the reciprocal of the logarithm of the hydrogen ion (H+)concentration in solution, -log[H+] on a scale of 0 to 14. Themidpoint pH at 7.0 is considered "neutral".

Values below 7.0 are increasingly acidic, and those above7.0 are increasingly alkaline. In common practice, pH can bedetermined by electrical instruments, color indicators, orspecially treated test paper.

Alkalinity is defined as the state of being alkaline or "basic".The alkalinity is determined by the concentrations of hydrox-ide, carbonate, and certain other chemicals, such as phos-phate and silicate.

Phenolphthalein ("P") Alkalinity is a measure of the alkalinityabove a pH of 8.2-8.3. All of the hydroxide, one-half of thecarbonate, and one-third of the phosphate, plus all otheralkali-producing materials present in a water sample such assilicate are included in the Phenolphthalein Alkalinity.

Total ("T") Alkalinity is a measure of the alkalinity above a pHof 4.2-4.3. All of the hydroxide, all of the carbonate, and two-thirds of the phosphates, plus all other alkali materials areincluded in the Total Alkalinity.

REPORTING OF DISSOLVED SOLIDSCONCENTRATION AS CONDUCTIVITY

In boiler water, dissolved salts consist of contaminants,treatment chemicals, and naturally occurring chemical con-stituents. Dissolved salts ionize and conduct an electriccurrent. The amount of current that a water sample carriesfrom one electrode to another at a specific temperature istermed its conductivity. The concentration of ionized dis-solved solids in any water is proportional to its electricalconductance. For example, distilled water has a very lowconductivity; in contrast, seawater has a very high conduc-tivity. Therefore, the amount of dissolved solids can beestimated by the water's conductivity. A conductivity meter,which records conductance in micromhos (µmhos), is usedto measure this characteristic of the water.

8

The following dilution and multiplication factors can be used for any sample. The accuracy of the result, however, is dependentupon the care taken in making the dilution.

MULTIPLE TESTDISTILLED WATER RESULT BY

WATER SAMPLE + DILUTION = TOTAL VOLUME FACTOR OF:

25 ml 25 ml 50 ml 250 ml 50 ml 100 ml 210 ml 40 ml 50 ml 520 ml 80 ml 100 ml 510 ml 90 ml 100 ml 10

(Neutralization is required before testing the conductivity ofboiler water samples because strong bases (or strong acids)conduct more than a proportional amount of electricity)based on their actual solids concentration, giving a false highreading.

The sample should be a cooled sample, its temperaturetaken and the temperature compensation dial on the meter,if there is one, should be properly set before taking theconductivity reading.

DILUTION OF WATER SAMPLES

There are two conditions under which dilution of a samplemay be necessary:

• When a sample is highly colored, even after filtration, whichwould make it impossible to determine a colorimetric endpoint.

• When the initial test result is exceedingly high or beyondthe normal range of the test procedure.

Dilution of a sample should always be done with distilledwater. If a sample is diluted, the test result must bemultiplied by the appropriate factor. Examples follow:

EXAMPLE: Phosphate Test

1.Draw a 25 ml sample of water.

2.Dilute sample with 25 ml of distilled water.(Total volume = 50 ml)

3.Conduct phosphate test. (Result = 45 ppm phosphate)

4.Multiply test result by a factor of 2. (45 ppm x 2 = 90 ppmphosphate)

5.Final test result = 90 ppm phosphate

*Avoid dilution of a sample when testing for an oxygenscavenger. When testing for oxygen scavenger, the waterused to dilute the sample should be deoxygenated.

9

BOILER WATER SYSTEMS AND TREATMENT

INTRODUCTION

A boiler converts the chemical energy in fuel to heat energyin steam for the purpose of doing work. There are many typesof boiler plants, but all of them function on the same basicprinciples of thermodynamics. A complete discussion ofeither plant design or thermodynamics is beyond the scopeof this presentation. However, some basic concepts will bepresented here to introduce the systems which we willdiscuss in the sections below.

In the world fleets today, we see some ships which operateboilers for propulsion (some at pressures over 60 kg/cm2,(850 psig) and motor vessels equipped with auxiliary oil-firedand waste heat boilers which operate at lower pressurelevels (7-24 kg/cm2, 100-350 psig).

All boilers operate on the common premise that heat istransferred to water to create steam which is then used to dowork onboard. Diesel engines depend on scale-free heattransfer surfaces for cooling. They share common problemsof scale formation and corrosion, although some forms ofcorrosion will be more evident in high pressure boilers andothers are more often seen in engines.

The water used onboard, for whatever purpose, comesprimarily from the sea. In order for seawater to be safely usedfor steam production, the salts and other contaminants mustbe removed from the water. An evaporator or distiller isgenerally installed for the purpose of purifying the water untilit contains only trace levels of minerals. Seawater also

contains dissolved gases which have been absorbed fromthe air or formed by decaying organic matter. They can bemechanically removed by deaeration, thermally reduced byincreased feedwater temperature and/or chemically scav-enged.

An effective water treatment program minimizes scale andcorrosion in the boiler system. Since distillation andmechanical/thermal deaeration cannot remove all of thecontaminants, routine chemical treatment programs arenecessary for the efficient maintenance of all steam gener-ating and cooling system equipment.

The primary goals of a controlled water treatment program inany power generating plant are:

• To maintain clean, scale-free waterside heat transfersurfaces in steam generating and cooling water systems.

• To prevent metal loss due to corrosion.• To ensure efficient production of steam in boiler systems

without priming, foaming, or carryover contamination.• To prevent formation of deposits in steam/condensate

systems.• To minimize heat loss from the system due to excessive

blowdown from boilers.• To keep all power generating and auxiliary equipment, and

associated water and steam systems at their most efficientlevels and thereby minimize costs.

10

PRODUCTION OF HIGH QUALITY DISTILLATE

The water used on ships, for whatever purpose, comesprimarily from the sea. In order for seawater to be used forsteam production, the salts and other contaminants must beseparated from the water to minimize scale formation andcorrosion in boiler water and steam circuits. Mechanical andchemical technology is used in combination to do both. Thissection will discuss the production of high quality water,corrosion and scale mechanisms, mechanical and chemicalcorrections for these conditions before moving on to the testprocedures used to control the chemical treatments andmonitor the contamination.

Distillation, ion exchange, and reverse osmosis (RO) areprocesses which may be used for the desalination of seawa-ter. In the marine industry, distillation is the most widely usedmethod because of its relative simplicity and cost effective-ness. Brief descriptions of the other methods follow.

Ion exchange: Cation ion exchange units will effectivelyremove hardness constituents (calcium and magnesium)from water but not the anions, i.e., chloride and sulfate ionsor other contaminants. The extremely high concentrations of

the salts in seawater pose a challenge to these units. Themost common ion exchange units must be regenerated withsodium chloride brines which can contribute chloride ions tothe contamination. Ion exchange resin beds must be de-signed in such a way to prevent channels which will allowwater to flow through untreated.

Reverse osmosis is an effective means of desalination.However, a single pass unit will not produce water of suffi-cient quality for use in marine systems and further deminer-alization is necessary. A number of units in series couldtheoretically produce an effluence of acceptable quality andquantity for boiler feedwater.

The normal process of osmosis involves two solutions ofdifferent dissolved solids concentration that are in a singlecontainer, separated by a semipermeable membrane. Thecommon solvent in both solutions is water. The water flowsfrom the more dilute solution through the membrane to themore concentrated solution. In time, the equalizing effectcreates equal dissolved solids concentration in both com-partments.

SOLUTION WILL RISE TO THISPOINT WHICH IS HEAD EQUALTO APPARENT OSMOTIC PRES-SURE

LESSCONCENTRATEDSOLUTION

MORECONCENTRATEDSOLUTION

LESSCONCENTRATEDSOLUTION

MORECONCENTRATEDSOLUTION

SEMI-PERMEABLEMEMBRANE

PRESSURE

OSMOSIS

WATER FLOW

SEMI-PERMEABLEMEMBRANE

WATER FLOW

REVERSE OSMOSIS

11

The reverse osmosis process is created when pressure isexerted upon the more concentrated solution so that thewater flows in the reverse direction through the semiperme-able membrane from the concentrated side to the dilute side,leaving the majority of the dissolved solids behind.

When reverse osmosis is used to produce fresh water fromseawater, a reverse osmotic pressure is created to force thewater from the brine (seawater side) into the fresh watercompartment. Theoretically, the only energy required is thatwhich is needed to overcome the osmotic pressure andpump the feed water. In practice, much higher pressure(between 60-70 kg/cm2, 850-1000 psig) are required toproduce useful volumes of water per unit area of membrane.

Generally, the reverse osmosis process is not as widely usedonboard ship as distillation.

DISTILLATION (EVAPORATION PROCESS)

A marine evaporator is normally used to provide high qualitydistillate from seawater for the vessel's water systems. Thereare many types of evaporators, but they are all designed forthe same purpose. Hot cooling water or auxiliary steam isoften used as a heat source increasing cost effectiveness.

In some type of evaporators, seawater is heated or flows overa series of coils or tubes through which auxiliary steam ispassed. Heat is transferred to the seawater under vacuum,vaporizing a major portion of the water. The resulting vaporis scrubbed by a mist eliminator as it leaves the evaporatorunit to remove entrained moisture which contains a smallamount of dissolved solids.

The vapor is then cooled in a condenser to produce puredistillate. It is pumped to storage tanks for use as boiler watermakeup, engine cooling water, potable water and otherdomestic purposes.

The majority of dissolved solids are left behind, accumulatedand concentrated in the brine section of the unit for overboarddischarge. The purified water now contains only traces ofminerals which can be easily handled with boiler and coolingwater treatment chemicals.

Evaporator Scaling

During the evaporation process, the solubility of most of thedissolved minerals, which remain in the evaporator brine, isexceeded and precipitation occurs, forming scale depositson heat transfer surfaces. The three most common scalesformed in an evaporator are calcium sulfate, calcium carbon-ate, and magnesium hydroxide. These are effecient heattransfer barriers. Reduced heat transfer results in reducedwater production. Eventually, distillers must be shut downand cleaned to remove the insulating scale.

Evaporator Foaming and Carryover

The higher concentration of dissolved solids in the brineincreases the surface tension of the water, acting like anelastic skin at the water level. The increased surface tensionhinders the release of vapor bubbles and gases and pro-motes foaming.

When the bubbles burst, droplets containing concentratedsalts are thrown into the vapor space and are carried over intothe distillate. This results in reduced water quality.

Foaming also may be caused by "organic" substances in thewater, which are formed by the decay of organic materials orcontamination with petroleum products.

Mechanical Control

Foaming and carryover from evaporators can be minimizedby proper management of the water level and salinity (brine)control.

• Improper water level control is often due to the malfunctionof the automatic controls and alarms. Automatic equip-ment and alarms should be maintained in good operatingcondition.

• Salinity control is an important factor in the prevention ofscale deposits as well as carryover. Salinity managementrefers to the continuous removal of concentrated brinefrom the evaporator in order to control the amount ofdissolved solids buildup. Normally the brine concentrationshould be maintained at 1.5 (1.5/32nds) concentrations,although some vapor compression units operate at 2.0(2.0/32nds) concentrations or more.

Chemical Treatment

The problems of scale formation and foaming can be mini-mized by the addition of chemical treatments containingpolymeric scale inhibitors and antifoams. The polymer mol-ecules attach themselves to the scale-forming minerals todisrupt the densely packed crystalline structure. This pre-vents hard scale from building up on the heat transfersurfaces. Instead, nonadherent, suspended crystals areformed which will easily flow overboard with the brine dis-charge.

Polymer treatments can remove existing scale from heattransfer surfaces by the same action. If treatment is used,water production can be maintained, and acid cleaning toremove scale can be minimized.

Modern formulations include an antifoam ingredient whichreduces the surface tension of the water and allows vapor toescape without the formation of foam. This helps to maintainwater quality.

Drew Evaporator Treatments

AMEROYAL® evaporator treatment is a liquid combination ofan active polymer with a highly effective antifoam agent. It iseffective in seawater and brackish water. The antiform agentin AMEROYAL treatment reduces surface tension and,thereby, prevents foaming and carryover. AMEROYAL treat-ment is the most widely used evaporator treatment in themarine industry.

AMEROYAL CF concentrated evaporator treatment is aconcentrated liquid formulation of active polymers andantifoam agents developed specifically to prevent scaledeposition and carryover in high temperature, high produc-tion multi-stage evaporators. AMEROYAL CF treatment hasbeen proven capable of significantly reducing the amount ofacid cleaning required to maintain design distillate produc-tion.

12

VAPOR-COMPRESSION DISTILLER

AMEROYAL

AMEROYAL CF

LOW-PRESSURE SUBMERGEDHEATING ELEMENT DISTILLER

EXAMPLES OF EVAPORATOR UNITS

INSEA WATER

OUT

OUT

IN

JACKET WATER

CONDENSER

DEMISTER

EVAPORATOR

BRINE EJECTOR

AIR EJECTOR

FROMSEA

EJECTOR PUMP

TO FRESH W.TANK

TOBILGE

ORIFICEELECTRICPANEL

SALINO-METER

FRESHW. PUMP

OVERBOARD

AMEROYAL

LOW PRESSURE THIN-FILM DISTILLER

TWO-STAGE VACUUM-FLASH DISTILLER

Air Ejectors After Condenser

Steam Supplyto Feed Heater

Sea Feed Heater

Drain Return

Condensate Pump

Sea Water Temperature Control Valve

Brine Overboard

Brine Pump

Distillateto Storage

DistillatePump

SalinityIndicatorSea Water Pump

VacuumChamber #2

VacuumChamber #1

Drain

Condensers

Steam Supplyto Air Ejectors

Distillate Cooler

Distillate

Steam

Brine

Reject Water to Waste

AMEROYAL

13

14

BOILER WATER CIRCULATION

A boiler is designed to convert the chemical energy con-tained in fuel to heat energy in the steam. This steam is thenavailable to do work in a variety of systems onboard. Thefigure below illustrates the circulation pattern of a water tubeboiler system. (While only one design is shown, all marine oil-fired boilers function in a similar pattern).

In a water tube boiler, the furnace is surrounded by tube tankswhich are connected through headers to the upper and lowerdrums. The fuel is burned in the furnace and the heat ispassed by radiation to the surrounding generating tubes. Theheat energy is passed by conduction to the recirculatingboiler water in the tubes. In this way, the tube metal is cooledand steam is generated.

As the water is heated, its density decreases and it tends torise. Colder heavier water tends to sink. As the hot water/steam rises in the generating tubes and the colder watersinks in the downcomer tubes, a natural circulation results inthe boiler curcuit.

As the steam/water mixture reaches the upper drum (steamdrum), it separates. The steam passes to the upper half of thedrum, then leaves the top of the drum to the superheater ordirectly to where it is needed as saturated steam. Therecirculating water remains in the lower half of this drum,mixes with incoming feedwater and again passes throughthe complete water circuit.

In boilers fitted with superheaters, the steam which is re-leased into the top of the steam drum passes out of the boilerthrough the steam line to the superheater where more heat

is added, increasing the energy in the steam. The super-heated steam is then passed through a high pressure turbineand possibly a low pressure turbine where a major portion ofsteam's thermal energy is converted to mechanical energy.

Before the steam is condensed and returned to the feedsystem, part of it may be bled off from the turbine system forfeedwater heating and similar processes so that its thermalenergy can be fully utilized.

After passing through any auxiliary systems, the steamenters the condenser where it is condensed to form waterwhich is pumped back to the feed line, completing the boiler/feed system circuit.

In systems operating at lower pressure levels without super-heaters, the steam simply leaves the boiler from the steamdrum and passes throughout the steam system before beingcondensed and returned as condensate to the feed equip-ment.

On motor vessels, there are usually two steam generatingsystems: a waste heat economizer drawing its heat energyfrom the diesel engine exhaust gases and an auxiliary oil firedboiler. The waste heat economizer functions when theengine is in operation, and the auxiliary boiler functions whenthe ship is in port and the main engine secured. Although theirdesign is different from the boilers used for propulsion, theseboiler systems function under the same principles of heattransfer and are subject to many of the same problems dueto scale and corrosion.

STEAM OUT

WATER IN

HE

AT

15

16

CORROSION OF METALS

Ferrous and non-ferrous alloys are commonly used metalsof construction in marine power plants although other metalsare also being used. All of these metals will corrode slowly incontact with water, unless the water is properly treated. Hightemperatures and pressures increase the rate of corrosion.The purpose of any complete water treatment program is toprotect all the preboiler, boiler and afterboiler auxiliary equip-ment and systems against corrosion, both during operationand during out-of-service periods.

CHARACTERISTICS AND TYPES OF CORROSION

Corrosion is defined as the deterioration of a metal or alloy orits properties due to reaction with its environment. Character-istics of the damage caused by corrosion include the follow-ing:

• Pitting - A selective, localized metal attack characterizedby the formation of rounded deep cavities in a metalsurface. Pitting is considered to be one of the most seriousforms of corrosion and often associated with oxygenattack.

• General corrosion - Thinning or metal loss in which thethickness of the metal is evenly reduced over a largesurface area.

• Underdeposit - Accelerated corrosion that takes placeunder scale or sludge deposits. Underdeposit corrosion isaccelerated since alkalinity left behind can become ex-tremely concentrated.

• Caustic Cracking - A localized form of corrosion or physicaldestruction in which a facturing of the metal following grainboundaries occurs due to stress.

• Embrittlement - An effect of corrosion that changes thephysical properties of a metal, its crystalline and inter-crystalline structure, causing the metal to lose its strengthand ductility, thereby becoming brittle and weak.

• Dealloying - The selective dissolution of one metal from analloy.

CAUSES OF CORROSION REACTIONAND PREVENTATIVE MEASURES

Corrosion is a result of chemical and electrolytic action ofwater or air on a metal. The corrosion rate is influenced by theimpurities in the metal and the water. Properly treated highpurity water and metals reduce the rate of corrosion. All ofthese metals will corrode in water unless the water is properlytreated.

The most common causes of corrosion in boiler systems aredissolved gases, improper pH levels, chloride ion, andmechanical conditions. Brief discussions of the specificcorrosion reactions follow.

GASEOUS CORROSION

Three gases are of primary concern in a water treatmentprogram: oxygen, carbon dioxide and ammonia.

Oxygen gas is one of the most undesirable contaminantswhich enters the preboiler/boiler/afterboiler water system.Oxygen dissolves in water and causes corrosion at anexcessive rate. The severity of the oxygen attack depends onthe concentration of the dissolved oxygen, pH value, andtemperature of the water.

Oxygen reacts with the ferrous metal surfaces to form rediron oxide (Fe

2O

3). Because this red iron oxide (ferric oxide)

or rust is porous and does not protect the metal surface, thecorrosion process continues. Ultimately, the entire metalstructure will be converted to ferric oxide unless correctivemeasures are taken.

The corrosion is often localized which results in pitting.Unless stopped by chemical or thorough mechanical clean-ing, the corrosion reaction will proceed beneath a cap ofporous oxide until it pierces the metal.

Carbon Dioxide: Most of the carbon dioxide in marine powerplant water systems is formed in the evaporators. Heatcauses carbonate (CO

3=) and bicarbonate (HCO

3-), which

are dissolved in the seawater, to break down to carbondioxide gas (CO

2).

Carbon dioxide gas leaves the evaporator with the vapor anddissolves in the distillate. The carbon dioxide reacts withwater to form carbonic acid which reduces the pH of the waterand accelerates general corrosion in the feedwater andultimately in the boiler steam-condensate system.

The carbonic acid (H2CO

3), a weak acid, attacks the steel in

the feed and condensate lines to form ferrous bicarbonate(Fe(HCO

3)

2). Ferrous bicarbonate is a highly soluble com-

pound that has no protective or passivating effect.

Carbonic acid produces a general type of corrosion, which istypified by grooving along the bottom of a pipe, overall metalthinning and, particularly, loss of metal at stressed areassuch as pipe bends and threaded sections.

Ammonia: The cooper-based metals are subject to attackby ammonia in the presence of oxygen. It is only thecombined action of these gases which is corrosive. Byeliminating the oxygen, the corrosive potential of ammonia isminimized.

Ammonia is formed by the decomposition of organic materialor the breakdown of excessive hydrazine.

Mechanical Removal of Gases: Air naturally dissolved inthe makeup water, in-leakage and the breakdown of othercompounds introduces oxygen, carbon dioxide, and ammo-nia. Air can enter through any opening such as makeup, drainor cascade tanks and especially systems under vacuumsuch as turbine seals and condensers.

17

To deal with this problem, marine steam systems are equippedwith air ejectors, hot wells and sometimes, deaerating heat-ers. The efficient operation of this equipment is essential forthe removal of a high percentage of the non-condensiblegases which enter the system.

The following is a list of the main points to check in plantoperation to reduce the entry of corrosive oxygen (O

2) and

carbon dioxide (CO2) gases:

• Check all points of possible air in-leakage in the con-densing and vacuum sections of the plant (i.e., defectiveflanges, condensing and vacuum sections of the plant,(i.e., defective flanges, gaskets, valve packing, crackedvalve bonnets, open return line drain valves, insufficientsteam pressure on gland seals, malfunctioning steamtraps, etc.)

• Check the temperature of the water in tanks operating atatmospheric pressure. Since O

2 and CO

2 gases readily

dissolve in cool water, the water in all atmospheric watertanks should be heated to the highest temperature posssiblewithout creating a vapor lock at the pump suction.

NOTE: In motor vessel systems without deaeration equip-ment, the feed-cascade-hot well tanks must be kept at ashigh a temperature as possible (90OC) in accordance withboiler manufacturers' recommendations to liberate themaximum amount of dissolved oxygen. Tanks which arecovered must have vent lines fitted to carry away ventedgases. Many ship systems have feed pumps functioningcontinuously with feedwater excess recirculated back tothe feed tank. As the returning water may be simplydumped into the tank, any volatile chemicals which mayhave been dosed to the feedwater before the recirculationoff-take can be lost from the system. To minimize thiscondition, the treatment chemicals are often dosed "down-stream" of the off-take point by means of a dosing pump.

• Avoid piping drains with high oxygen concentrations todrain tanks or to any point where they may be used asboiler makeup.

• Check for inefficient operation of the deaerating heater.One thermometer should be installed in the steam spaceand another in the water space of the deaerator. When theunit is operating efficiently, the temperatures in the waterspace and in the steam space should be within one to twodegrees Centigrade of each other. If not, check thermom-eters for accuracy and replace if necessary. If the tempera-ture difference is confirmed, the unit should be opened andinspected at the first opportunity to determine the cause ofthe problem. (See "Pressure/Temperature Table forDeaerator Checks," which follows).

• Provide adequate venting of gases from the deaeratingheater directly to the atmosphere. The vent line must beopen; and if an orifice is installed, it must be large enoughto adequately remove the noncondensate gases. If thevent line is run to the gland seal exhauster, the fan on thisunit must be in operation continually while the vessel is inport and when at sea. If the fan should fail, the auxiliary ventto the atmosphere on the deaerating heater must beopened until the fan is again in operation.

• Check for clogged, worn, or broken spray nozzles orsprings in the deaerator. Poor atomization will result in poordeaeration regardless of the temperature.

• When taking on extra feed water:

a) Take on feed as slowly as possible. If the feed is takenon too quickly, the deaerating heater may be over-loaded, making it impossible to efficiently minimize theO

2 and CO

2 concentrations.

b) A higher water temperature in the makeup feed tankwill reduce the absorption of O

2 and CO

2.

• Use chemical treatment for maximum protection againstthe remaining O

2 and CO

2. While mechanical deaeration of

the feed water is a major step in eliminating dissolvedoxygen and other corrosive gases such as ammonia andcarbon dioxide, it needs the assistance of chemical treat-ment.

18

Pressure/Temperature Table for Deaerator Checks

should be nearly equal. If the temperature difference isgreater than 1OC or 2OF, the thermometers should bechecked for accuracy and, if necessary, repaired or re-placed. At the same time, the system should be checked formalfunctioning atomizing nozzles, steam inlet valves, vents,etc.

Malfunction of the deaerating heater will allow gases toremain in the feedwater which will result in fluctuations in theoxygen scavenger residual in the boiler water and causecondensate pH control difficulties. An indication of properdeaerator operation is provided by the operating tempera-tures and pressures. The steam and water space tempertures

DEAERATOR SHELL PRESSURESAND

CORRESPONDING SATURATION TEMPERATURES

Deaerator Shell Pressures Correct Saturation Temperatureskg/cm2 psig OC OF

0.0 0 100 2120.11 2 103 2180.28 4 107 2240.43 6 110 2300.58 8 113 2350.69 10 115 2390.86 12 118 2440.99 14 120 2481.12 16 122 2521.26 18 124 2551.41 20 126 2591.56 22 128 2621.72 24 130 2651.83 26 131 2681.97 28 133 2712.10 30 134 2742.25 32 136 2772.34 34 137 2792.54 36 139 2822.68 38 140 2842.82 40 141 2872.96 42 143 2893.10 44 144 2913.24 46 145 2943.38 48 146 2963.52 50 148 2983.80 54 150 3023.94 56 151 3044.08 58 152 3054.22 60 153 307

19

CHEMICAL TREATMENT

An alternative oxygen scavenger is sodium sulfite (Na2SO

3).

This compound readily combines with oxygen in solutionto form a more stable compound, sodium sulfate (Na

2SO

4).

This process efficiently removes oxygen from solution, butit does add dissolved solids to the water. As a result, it isnot generally recommended for high pressure boilerswhere minimum dissolved solids levels are critical.

Sulfite is not volatile and it is not a metal passivator. Itremains in the boiler water and does not offer protectionfor the condensate system.

Na2SO

3 + 1/2 O

2 Na

2SO

4 (Sodium Sulfite) + (Oxygen) (Sodium Sulfate)

Control of Condensate pH

As discussed above, CO2 gas reacts with the condensate

to form carbonic acid. Without chemical treatment, thisacid reduces the pH of the condensate. The pH can becontrolled within a specified non-corrosive range by thecontinuous dosage of a neutralizing amine, such asmorpholene or cyclohexylamine.

ACIDIC CORROSION - ACID ATTACK

Acid attack of boiler tubes and drums is usually in the formof general thinning of all metal surfaces.

Acidic conditions, exclusive of those created by the pres-ence of CO

2, occur when the boiler feed water becomes

contaminated by evaporator carryover or seawater in-leakage at the condenser. When magnesium chloride(MgCl

2), a seawater salt, is introduced to a boiler water

system, it dissociates into ions of magnesium (Mg+2) andchloride (Cl-). The chloride ions (Cl-) react with thehydrogen ions, which lowers the pH of the water andattacks the metal surfaces.

The magnesium ions (Mg+2) react with the phosphate(PO4

-3) and hydroxyl ions (OH-), if these treatments arepresent, to form sludge. Magnesium ions may react onlywith the phosphate ions to form magnesium phosphate, asoft, adherent deposit which tends to bind all other depos-its to the tube surfaces.

Any deposits on metal surfaces can be heat transferbarriers and can lead to overheating and increasinglydestructive conditions. Water trapped beneath these de-posits on high heat transfer surfaces will concentrate theacid or caustic. When this occurs, the corrosion ratesbecome extremely high and serious localized damageoccurs in a very short time.

Removal of Oxygen

Any dissolved oxygen remaining after deaeration can becompletely scavenged by the addition of a chemical oxygenscavenger, such as hydrazine, diethylhydroxylamine orsodium sulfite, to the boiler feed water.

The reaction produts of the hydrazine treatment are waterand nitrogen gas which is inert and will not attack the metalin the system. These reaction products will not add solidsto the boiler water as do the reaction products of otheroxygen scavengers such as sodium sulfite.

N2H

4 + O

2 2H

2O + N

2

Hydrazine has added benefits. After a boiler system hasbeen operating for a short time with proper chemicalcontrol and adequate hydrazine concentrations, a protec-tive film of black magnetic iron oxide (Fe

3O

4, magnetitite)

forms. At the same time, any non-protective red iron oxide,(Fe

2O

3, hematite), is slowly converted to magnetite. This

magnetite film passivates the metal surfaces.

If the hydrazine residual is allowed to be depleted, oxygenwill not be removed from the system. At this point themagnetite film will be converted to hematite, and corrosionof the base metal will begin.

Since hydrazine is volatile, some of it will carry over withthe steam. In this way, the metals of the condensatesystem also can be protected. In a series of reactionssimilar to those described above for ferrous metals, non-ferrous metals are rendered less sussceptible to corro-sion. For example, cupric oxide (CuO) is converted to aprotective form, cuprous oxide (Cu2O)

4CuO + N2H

4 2Cu

2O + 2H

2O + N

2

The most recent volatile oxygen scavenger introduced tothe marine industry is diethylhydroxylamine, also knownas DEHA. In addition to oxygen scavenging, DEHA formsa passive magnetite film providing a protective barrieragainst corrosion.

The oxidation reaction products of DEHA are acetic acid,nitrogen and water. In a boiler water environment, thehydroxide alkalinity neutralizes the acetic acid and isremoved by blowdown as sodium acetate.

4(C2H

5)

2NOH + 9O

2 8CH

3COOH + 2N

2 + 6H

2O

Another feature of DEHA is its volatility, which is similar tomorpholine. It extends throughout the feedwater, boilerand into the condensate system where it scavengesoxygen, passivates metal surfaces and any remainingDEHA contributes to condensate pH neutralization.

→

→

→

→

HYDROGEN ATTACK

This type of corrosion results in embrittlement or crackingof the tube metal, damaging of the internal structure of themetal.

Hydrogen ions are generated by the concentration ofacids under a hard dense deposit. The hydrogen ions (H+)are the smallest of all elements and can penetrate thegrain boundaries of the tube metal. They react with carbonatoms present in the steel to form methane.

Methane (CH4) is a large gas molecule which exerts

pressure within the metal. The high pressure combinedwith the weakening caused by degraphiting forces thegrains of steel to separate. Eventually, cracks in the metaldevelop.

Hydrogen attack can occur very rapidly. Tube metal failsand ruptures when the section can no longer withstand theinternal pressure.

CAUSTIC CORROSION

Caustic attack is characterized by irregular patterns ofgouging of the metal. It is often referred to as "causticgouging".

Caustic corrosion results from the presence of an excessof free hydroxide (OH) in the boiler water, indicated by avery high pH.

Much like an acid, caustic corrosion may occur beneathlayers of deposits which have formed on heat transfersurfaces allowing the hydroxide to concentrate and therebycausing severe localized corrosion.

Caustic corrosion also will occur in the horizontal orinclined tubes when the interior surfaces become steamblanketed because of excessive boiling (hot spots) orseparation of steam and water. Boiler water containinghydroxide can splash onto the steam blanketed surface,and as the water flashes off, the hydroxide remains andconcentrates on the metal.

CAUSTIC CRACKING CORROSION

Corrosion caused by caustic cracking is a type ofintercrystalline cracking. When highly caustic (alkaline)water comes in contact with steel under stress,intercrystalline cracking can result. (Metals can be stressrelieved, that is reheated at low temperatures to relieveinternal stresses). This type of corrosion occurs along thecrystal boundaries of a metal or an alloy.

CORROSION FATIGUE

Corrosion fatigue manifests itself as a series of fine cracksin the tube wall. These cracks are aggravated by othercorrosive conditions within the boiler which will ultimatelyresult in tube failure.This form of corrosion usually attacks the tube walls ofhigh pressure boilers. It occurs generally in the hightemperature areas of the tubes where irregular watercirculation has been experienced and alternating stresseshave been set up in the tube material.

MECHANICAL CORRECTION

The evaporator should be operated properly to avoidcarryover which will introduce contaminants as describedabove. Condenser piping must be maintained to preventleaking condenser tubes which will introduce seawater.

The boiler should be operated within the design specifica-tions in order not to overload the steam production capac-ity which leads to steam blanketing.

Proper burner alignment and correct atomization of thefuel oil are essential to avoid flame impingement of hotspots.

CHEMICAL TREATMENT

Acidic corrosion can be prevented by the maintenance ofa proper boiler water alkalinity. Adequate dosages of analkaline material such as sodium hydroxide (GCTM con-centrated alkaline liquid) will maintain the recommendedalkalinity range and eliminate the possibility of acid attack.Please note: The alkalinity level may be measured directlyin "ppm" or indirectly using the corresponding pH ranges.Maintain the recommended range of alkalinity or pHaccording to the treatment program.

Caustic corrosion readily takes place in ultra high pres-sure boilers (60 kg/cm2, 850 psig and over) in the presenceof free caustic. The Drew ULTRAMARINESM coordinatedphosphate-pH boiler water treatment program used inhigh pressure boilers eliminates free hydroxide (OH-) inthe boiler water. (This program will be described in detaillater in this book). Maintain the balance of treatmentchemicals to minimize free caustic.

The application of the ULTRAMARINE coordinatedphosphate-pH boiler water treatment will also assist ininhibiting hydrogen embrittlement, primarily by the buffer-ing action of the phosphate and the pH control in the boilerwater.

20

21

COMPOSITION AND FORMATION OF DEPOSITS

Since water is a universal solvent, it dissolves practically allmaterials which it contacts to a certain extent. However,materials have differing solubilities in water depending uponthe temperature, pressure, pH, mineral composition, andcontact time. Solubilities are grouped into three generalcategories: very soluble solids, slightly soluble solids, andrelatively insoluble solids. Under certain operating condi-tions, any one of these may produce undesirable depositswhich will reduce operating efficiency.

DISSOLVED INORGANIC SOLIDS are materials whichdissociate in water into their ionic parts (cations and anions).Most organic materials are not highly ionized (see discussionlater in this section). The major minerals encountered inseawater are combinations of the following dissolved (ion-ized) constituents:

Positive Ions (Cations) Negative Ions (Anions)Calcium+2 Carbonate-2

Magnesium+2 Bicarbonate-1

Sodium+1 Sulfate-2

Potassium+1 Silicate-2

Chloride-1

Salts may enter the boiler system as poor quality evaporatordistillate, seawater in-leakage, or shore water makeup. Someare very soluble and cause few problems because of theirrelative solubility. For example, sodium salts are very solublecompounds. However, contaminants can volatilize and carryover with the steam and deposit on superheater tubes or onturbine blading.

Slightly soluble solids are soluble at atmospheric condi-tions; however, an increase in the temperature and pressurewill cause precipitation and/or deposition. The primary ex-amples of this type of solid are salts of calcium and magne-sium. For example, the solubility of calcium sulfate increasesup to approximately 38OC (100OF) but then decreases rapidlyas the temperature is increased above this level.

Only a very small quantity of the so-called insoluble solidswill dissolve in water. Suspended solids, which do notdissolve, will deposit or disperse and circulate with the water.Following is a list of these materials that are most likely to befound as boiler water suspended solids:

Material Composition Source

Red iron oxide Fe2O

3Corrosion of feed or return lines or boilers.

Magnetic iron Fe3O

4Corrosion of return lines or boilers or conversion ofsuspended Fe

2O

3.

Copper metal and copper oxides Cu, Cu2O and CuO Corrosion of condenser tubes and evaporators.

Clay Complex silicates of Introduced by contamination of feed water withAl, Fe, and Mg seawater, low quality shore or brackish water.

Calcium carbonate CaCO3

Introduced by seawater contamination as a reactionproduct formed by heating water that contains calciumbicarbonate.

Calcilum silicate CaSiO3

Reaction product from water that contains calcium and silicaTricalcium phosphate Ca

3(PO

4)2) Formed when water is overtreated with phosphate and

undertreated with sodium hydroxide, and this material isvery likely to adhere to metal surfaces.

Calcium hydroxyapatite* 3Ca3(PO4)2•Ca(OH)2 Formed when proper treatment controls are maintained.Magnesium hydroxide* Mg(OH2) Formed when proper treatment controls are maintained.Magnesium silicate* 3MgO•2SIO

2•2H

2O Formed in water that contains silica when proper treatment

("Serpentine") controls are maintained.Magnesium phosphate Mg

3(PO

4)

2Formed when water is overtreated with phosphate. Thismaterial is very likely to adhere to metal surfaces.

Oily sludge Organic Mixtures Formed when any of the above solids absorb oil presentin the system.

*Starred items are minerals that may be produced as a result of normal chemical water treatment and which are the least likelyto form adherent sludge deposits. Of the suspended solids in the boiler water, these substances are preferred since they easilycan be removed by blowdown.

22

Continuous or surface blowdown (blowdown from the upperareas of the boiler) removes circulating boiler water whichcontains a high percent of the dissolved solids. This blowdownlocation keeps the concentration of dissolved solids undercontrol.

Header blowdown (an intermittent blow from a header loca-tion) reduces accumulated, suspended or floating solids, andalso removes high dissolved solids concentrations.

Chemical Treatment

Not all contaminants can be removed naturally by blowdownbut require chemical assistance. The formation of undesir-able deposits can be prevented by treating the water withchemicals that convert the undesirable dissolved hardnessconstituents to harmless suspended solids. These solidsgradually settle out in the mud drum of the boiler as anonadherent fluid sludge which can be removed by blowdown.The standard treatment used is a combination of solublephosphate (ADJUNCT® B phosphate boiler water treatment)and an alkaline liquid (GCTM concentrated alkaline liquid).Some one drum combination products, such as AGK® 100boiler and feedwater treatment, combine phosphate, alkali,oxygen scavenger amines and other water conditions into acomplete treatment. AGK 100 treatment is not a "one-shot"treatment but rather a complete package which must be fedcontinuously to provide complete protection. (Also, see thesection on "Coordinated Phosphate-pH Treatment" thatfollows).

Any existing hardness scales are not rapidly removed by theboiler water treatment chemicals and special chemical clean-ing methods should be employed. (See the section entitled"Chemical Cleaning").

If the water treatment program is controlled within the limitsset for the phosphate and alkalinity, the sludges which willdevelop will not be sticky and will not adhere to the metalsurfaces.

If feedwater becomes contaminated by oil, LIQUIDCOAGULANTTM boiler sludge conditioner should be dosedto the boiler to coagulate the oil droplets. These conditionedsuspended solids will settle to the low points of the boilerwhere they are removed by blowdown, thus preventingfoaming and carryover and lowering deposit adherencecharacteristics.

Coordinated Phosphate-pH Program (ULTRAMARINESM)

Caustic corrosion is one of the most frequent and mostserious causes of metal damage in high pressure boilers(over 60 kg/cm2, 850 psig). This type of corrosion results fromthe action of "free caustic" at heat transfer surfaces causingsevere corrosion and metal loss. The caustic conconcentratesin crevices or localized areas beneath porous metal oxidedeposits or where thin films of steam are formed leavingconcentrated caustic behind on the metal surface. Thislocalization of caustic can cause severe corrosion and maybe the result of some physical features of the boiler such asdesign or the mode of operation.

In addition to the above, there are metallic oxides and saltsof iron and copper which enter the boiler as corrosionproducts. The sources of iron may be from corrosion in steamsystems and in return lines. Some oxides are from internalcorrosion in boiler generating tubes, the drum surfaces orfeed line. Corrosion of the main and auxiliary condensers orof evaporator condensers is one of the sources of the copperand copper oxide materials. (See the previous section on"Formation of Oxides").

Organic contamination may enter the boiler system via leaksin the cargo or fuel heating coils or other auxiliary feed lines.Types of organics include petroleum products (e.g., oil orlubes), cargo liquids (e.g., organic chemicals), or microor-ganisms (e.g., bacteria). Organic materials tend to decom-pose and can act as binders for the suspended solids so thatthey adhere to the interior tube metal walls.

DEPOSIT FORMATION ANDPREVENTATIVE MEASURES

Scale: A "true" scale is a crystalline solid which is found at thepoint in the boiler system at which it is formed. Scale materialsare formed by oversaturation and precipitation of hardnessconstituents (calcium and magnesium) on heat transfersurfaces.

Metal oxide deposits are formed by the reaction of anaggressive solution or gas in contact with the metal surfaceat the point where the oxide is found. It may come fromanother part of the system and accumulate at that location.Metal oxides can combine with other contaminants to formdeposits. This is another reason why corrosion should becontrolled by mechanical as well as chemical methods. (Seeprevious section on "Corrosion of Metals").

Sludge is generally a mixture of loose fluid particles com-posed of organic, inorganic and/or corrosion products. Thesludges that result from water treatment reactions are pre-ferred to the scale that would otherwise form.

Sludges must be removed on a regular schedule or theaccumulation of sludges at the low flow points may block thewater flow patterns. Restriction of this flow may cause"starvation" of some areas and ultimately the overheating ofmetal.

Scales and baked-on sludges in any heat transfer area canact as "insulators". Interference with heat transfer results inreduced fuel efficiency and potentially tube failure.

Mechanical Correction

Blowdown is the method used to remove the dissolved andsuspended solids from the boiler systems, and blowdownprocedures should be based on boiler manufacturers' in-structions. There are three types of blowdown--bottom,header and continuous--each used for a specific purpose.

Bottom blowdown (blowdown from the bottom of the boiler)removes suspended solids and residual sludges that havesettled out of the water. If these contaminants are notremoved regularly, they will build up until they hinder circula-tion patterns.

The Drew ULTRAMARINESM program has been specifi-cally designed to minimize "free caustic" conditions in highpressure boilers by adjusting and controlling the chemicalbalance of pH and phosphate in the boiler water. The DrewULTRAMARINE Program is a coordinate phosphate-pHboiler water treatment program. The addition of Drew GCTM

concentrated alkaline liquid and ADJUNCT® B boiler watertreatment establishes an equilibrium in the boiler water asshown in the equation below:

Na2HPO

4 + NaOH Na

3PO

4 + H

2O

disodium + sodium trisodium + water (ortho) hydroxide (ortho)phosphate phosphate

The alkalinity or pH range is controlled so that it protects theboiler steel in a passivated state and coordinates with thephosphate concentration to insure the formation of fluidnon-adherent sludges. These levels are coordinated in abalance that will prevent a condition of excess or "freecaustic". (See the graph of coordinated phsophate-pHcontrol below).

All the other water treatment controls must be monitoredclosely because high pressure boilers have lower toler-ances for variations in chemical levels and total dissolvedsolids. This lower tolerance for chemicals and solids doesnot distinguish between treatment chemicals and contami-nants so overall control of all critical boiler water chemistryis a necessity.

23

PPM PO4 (DERIVED FROM TSP)ULTRAMARINE COORDINATED PHOSPHATE-----pH CURVE

Special attention must be given to operating conditionswhich are unusual or those which are not directly relatedto normal steaming conditions. The water treatment pro-cedures which are employed during "slow-speed" steam-ing are just as important as the chemical treatment pro-gram during the normal boiler operations. The followingsituations should be given full consideration.

LOW SPEED STEAMING

If a boiler is to be operated at substantially reduced loads,the correct water treatment chemical concentrations mustbe maintained at all times. This is because excessivecorrosion and deposition conditions may be exaggeratedby the decreased water circulation rates especially in highheat input areas and reduced efficiency of pre-boilerequipment such as deaerations.

A potentially more serious situation occurs when firingrates are reduced, which disrupts temperature gradientsacross all of the boiler sections. In effect, some generatingtubes which normally are risers may become stagnant oreven downcomers.

At extremely reduced steaming conditions, many tubescan become stagnant since they are in a transition zonewhere they are neither risers nor downcomers but rather"percolate" in a static condition. If percolation occurs, thelack of circulation in high heat input areas tends to permitsteam blanketing and tube overheating, thereby concen-trating the dissolved solids at the metal-water interfaces.To help alleviate this condition in a two boiler system, itmay be advisable to put one boiler in standby and operatethe other at a more normal load condition.

STANDBY AND IDLE BOILERS

Boiler water chemical levels (non-volatile) in standbyboilers should be kept within the same ranges that areindicated for the full steaming conditions.

When any boiler is off-line for extended periods of time,proper dry or wet layup procedures are essential toprevent corrosion.

Successful dry layup procedures depend upon the elimi-nation of all moisture from inside the boiler. Corrosion willnot occur if moisture is eliminated. However, it is almostimpossible to eliminate all moisture; therefore, the use of"wet" layup procedures is the most practical and preferredcorrosion control method for all but very extended layupperiods.

Boilers placed in "wet" layup are not maintained underpressure. During these periods adequate protection againstoxygen gas corrosion must be employed by introducing ahigh concentration of AMERZINE® corrosion inhibitor(approximately 150-200 ppm or 1.3 liter/ton).

SPECIAL OPERATING CONDITIONS

If the boiler has been drained, the AMERZINE inhibitorshould be added as it is filled to the normal level and firedup. The boiler must be operated long enough to providesufficient circulation to obtain a uniform concentration ofthe oxygen scavenger throughout the boiler water toeliminate the oxygen.

If the boiler has been in operation, dose 1.3 liters ofAMERZINE inhibitor for each ton of boiler capacity at thetest level (100% full).

After inspection or cleaning, a boiler should not be allowedto stand open or wet since atmospheric corrosion or "flashrusting" will occur. In addition, boilers should not bereturned to service if residual corrosion products or de-posits are present. They should be cleaned before theirreturn to service.

CHEMICAL CLEANING

Efficient operation of the boiler system, as with all equip-ment, is dependent upon cleanliness and freedom fromobstructions in the water or gas pass circuits.Precommission cleaning of new equipment is required toremove oils, corrosion products, millscale and debriswhich may have accumulated during construction.

Carefully controlled treatment programs can keep mostsystems trouble-free; however, in certain conditions anemergency cleaning action may be necessary because ofaccidental contamination, tube failure, or accumulationsof deposits and oxide deposits.

All chemical treatment programs require strict adherenceto the recommended procedures to produce the desiredresults. Chemical cleaning solutions, their byproducts,and residuals must be removed before returning thesystem to service, thereby avoiding any additional con-tamination or corrosion.

24

25

BOILER WATER TREATMENT CHEMICALS

ADJUNCT® B phosphate boiler water treatment:ADJUNCT B treatment is a specially formulated powderedphosphate used in conjunction with GCTM liquid in both highand low pressure boilers to control scale formation due tohardness. The soluble phosphate from ADJUNCT B treat-ment in alkaline boiler water combines with the incominghardness to form a soft, nonadherent sludge.

GCTM concentrated alkaline liquid: GC liquid neutralizesacid and controls corrosion. GC liquid provides a suitable pHenvironment for the efficient reaction of the phosphate treat-ment with the hardness constituents to maintain the resultingsludges in a fluid state.

AMERZINE® corrosion inhibitor: AMERZINE inhibitor is aliquid catalyzed oxygen scavenger used to minimize oxygencorrosion in boiler steam and condensate systems.AMERZINE (hydrazine) prevents the corrosion of iron andcopper by oxygen and promotes the formation of protectiveiron and copper oxide films.

SLCC-ATM condensate corrosion inhibitor: SLCC-A in-hibitor is a volatile liquid organic amine designed to minimizecorrosion in steam and condensate systems. SLCC-A inhibi-tor condenses with the steam, providing a pH environmentwhich neutralizes the corrosive effects of carbon dioxide(Carbonic Acid).

LIQUID COAGULANTTM boiler sludge conditioner:LIQUID COAGULANT conditioner is a colorless, high mo-lecular weight solution used in both medium and low pres-sure boilers to prevent sludge deposits. It is especially usefulwhen feedwater becomes contaminated by oil. DosingLIQUID COAGULANT conditioner to the boiler coagulatesthe oil droplets, causing these suspended solids to settle tothe low points of the boiler where they are removed fromblowdown.

AGK® 100 boiler and feedwater treatment: AGK 100treatment is a unique multi-functional liquid formulation oforganic sludge conditioners, coagulants, oxygen scaven-gers, and inorganic contaminant dispersing and precipitatingagents. AGK 100 treatment controls waterside scale andsludge deposits and corrosion conditions in low pressureboilers using distilled water as makeup (up to 32 kg/cm2, 450psig). The single multi-functional production formulation ofthe Drew AGK 100 treatment program can replace multi-product conventional water treatments in these systems.

DREWPLEX® AT 100 boiler water treatment: DREWPLEXAT treatment is a phosphate-based treatment combinedwith synthetic polymers providing the ultimate in simplicity,system flexibility and treatment control for all motor vesselauxiliary and exhaust gas economizer boilers. DREWPLEXAT boiler water treatment provides a cleaner boiler byallowing greater tolerance of feedwater quality fluctua-tions.

DREWPLEX OX corrosion inhibitor: DREWPLEX OXcorrosion inhibitor is a safe-to-use, unique, and fast-actingcatalyzed oxygen scavenger for use in low, medium andhigh pressure steam generating systems. BecauseDREWPLEX OX corrosion inhibitor is volatile, excess inthe feedwater will be carried through the boiler with thesteam and into the condensate system, thereby protectingthe entire boiler system from oxygen corrosion. Thecatalyst in DREWPLEX OX corrosion inhibitor acceler-ates the rate of oxygen removal in the feedwater, therebyimproving corrosion protection in the preboiler section.

BOILER WATER TREATMENT CHEMICAL APPLICATIONS AND CONTROLS

Control Limits for Boiler Water and Condensate

ULTRAMARINESM program: Boiler Pressure 60-84 kg/cm2 (850-1200 psig)

Boiler Water Tests Treatment Control Limits

Phosphate ADJUNCT® B 15 - 25 ppmpH GCTM 9.8 - 10.2HYDRAZINE/AMERZINE® AMERZINE 0.03 - 0.10 ppmChloride Blowdown 16 ppm max.Conductivity Blowdown 120 µmhos max.Silica Blowdown 6 ppm max.

Condensate TestspH SLCC-ATM 8.6 - 9.0Ammonia Deaeration 0.5 ppm max.

STANDARD: Boiler Pressure 32-60 kg/cm2 (450-850 psig)

Boiler Water Tests Treatment Control Limits

Phosphate ADJUNCT B 20 - 40 ppmP. Alkalinity GC 90 - 130 ppmT. Alkalinity GC Less than 2 x P. AlkalinityHYDRAZINE*/AMERZINE AMERZINE 0.03 - 0.10 ppmSulfite CATALYZED SULFITE 10 - 15 ppmChloride Blowdown 36 ppm max.Conductivity Blowdown 700 µmhos max.

Condensate Tests

pH SLCC-A 8.3 - 8.6

STANDARD: Boiler Pressure 0-32 kg/cm2 (0-450 psig)

Boiler Water Tests Treatment Control Limits

Phosphate ADJUNCT B 20 - 40 ppmP. Alkalinity GC 100 - 150 ppmT. Alkalinity GC Less than 2 x P. AlkalinityHYDRAZINE*/AMERZINE AMERZINE or 0.03 - 0.10 ppmSulfite CATALYZED SULFITE 20 - 30 ppmChloride Blowdown 300 ppm max.Conductivity Blowdown 700 µmhos maximum

Condensate Tests

pH SLCC-A 8.3 - 8.6

NOTE: Hardness tests of boiler water are not necessary when the phosphate is above the lower limit of the control range.

*Use of either hydrazine or sulfite is recommended for oxygen scavenging. Use of both scavengers is not necessary.

26

27

BOILER WATER TREATMENT

PHOSPHATE: Dosage of ADJUNCT® B phosphate boiler water treatment per ton boiler water.

P r e s s u r e R a n g e Phosphate 0-32 kg/cm2 32-60 kg/cm2 60-84 kg/cm2

Test Results (ppm) (0-450 psig) (450-850 psig) (850-1200 psig)

Dosage Requirements

0 30 gm (1 oz.) 30 gm (1 oz.) 30 gm (1 oz.) 3 30 gm (1 oz.) 30 gm (1 oz.) 30 gm (1 oz.) 6 30 gm (1 oz.) 30 gm (1 oz.) 26 gm (1 oz.) 9 30 gm (1 oz.) 30 gm (1 oz.) 22 gm (1 oz.) 12 15 gm (.5 oz.) 15 gm (.5 oz.) 18 gm (1 oz.) 15 15 gm (.5 oz.) 15 gm (.5 oz.) 14 gm (1 oz.) 18 15 gm (.5 oz.) 15 gm (.5 oz.) 9 gm (1 oz.)20 - 25 Satisfactory Satisfactory Satisfactory25 - 40 Satisfactory Satisfactory Satisfactory 40+ Blowdown Blowdown Blowdown

CAUSTIC: Dosage of GCTM concentrated alkaline liquid per ton boiler water

P r e s s u r e R a n g e P. Alkalinity 0-32 kg/cm2 32-60 kg/cm2

Test Results (ppm) (0-450 psig) (450-850 psig)

Dosage Requirements

0 - 20 0.15 liter 0.15 liter 30 - 50 0.10 liter 0.10 liter 60 - 80 0.05 liter 0.05 liter 90 - 130 -- Satisfactory 100 - 150 Satisfactory -- 130+ -- Blowdown 150+ Blowdown --

CAUSTIC: Dosage of GCTM concentrated alkaline liquid per ton boiler water

Pressure RangepH Boiler Water 60-84 kg/cm2

Test Results (850-1200 psig)

Dosage Requirements 8.6 or less 14 ml 9.0 13 ml 9.0 - 9.3 12 ml 9.4 - 9.5 11 ml 9.6 10 ml 9.7 9 ml 9.8 8 ml10.0 7 ml10.1 5 ml10.2 Satisfactory10.3 or above Blowdown

SULFITE: Dosage of CATALYZED SULFITETM corrosion inhibitor

BOILER PRESSURE RESIDUAL RANGE DOSAGEPSI kg/cm2 (ppm as SO3) REQUIREMENTS

(a) Up to 450 Up to 32 20-30 Satisfactory(b) 450-850 32-60 10-15 Satisfactory

(a) or (b) Below satisfactory, Increase 25% (a) or (b) Above satisfactory, Decrease 25%

HYDRAZINE/AMERZINE: Continuous Dosage of AMERZINE® corrosion inhibitor

Treatment Pressure Range Hydrazine Test Result AMERZINE Dosage

Standard 0-60 kg/cm2 less than 0.03 Increase dosage by 25%(0-850 psig) 0.03 - 0.10 Maintain

greater than 0.10 Decrease dosage by 25%Initial dosage is 0.15 liters per ton of boiler water.

ULTRAMARINE 60-84 kg/cm2 less than 0.03 Increase dosage by 25%(850-1200 psig) 0.03 - 0.10 Maintain

greater than 0.10 Decrease dosage by 25%Initial dosage is 0.10 liters per ton of boiler water.

CONDENSATE pH: Continuous Dosage of SLCC-ATM condensate corrosion inhibitor

Treatment Pressure Range Condensate pH SLCC-A Dosage

Standard 0-60 kg/cm2 less than 8.3 Increase dosage by 25%(0-850 psig) 8.3 - 8.6 Maintain

greater than 8.6 Decrease dosage by 25%Initial dosage is 0.15 liters per ton of boiler water.

ULTRAMARINE 60-84 kg/cm2 less than 8.6 Increase dosage by 25%(850-1200 psig) 8.6 - 9.0 Maintain

greater than 9.0 Decrease dosage by 25%Initial dosage is 0.10 liters per ton of boiler water.

28

29

AGK® 100 treatment Supplemented with AMERZINE® treatment

AGK 100 TreatmentInitial Dosage: 2.5-5 liters per ton of water in the boiler system

Continuous Dosage: Maintain 40-65 ppm hydrate alkalinity and 10-20 ppm phosphate in the boiler water.

HYDRATE ALKALINITY HYDRATE ALKALINITY HYDRATE ALKALINITY <40 ppm 40 - 65 ppm >65 ppm

PO4 Increase dosage by 25% Dosage adjustment may be Reduce dosage by<10ppm and check for seawater or necessary. Check for 10%. Check for

shore water or in-leakage. possible hardness in-leakage. shore water in-leakage.

PO4 Increase dosage by 20% Normal condition. No dosage Reduce dosage by 20% 10 - Check condensate for adjustment necessary. Check for shore water20 ppm acidic material in-leakage. adjustment in-leakage.

Increase dosage by 20% Dosage adjustment may be Reduce dosage by 25%.Check condensate for necessary. Check for acidic Feedwater quality may beacidic material in-leakage. material in-leakage. better than usual.

PO4 Make up and/or feedwater Alkalinity may be destroyed>20ppm volume may be low or by acid contamination. Make

quality may be better up and/or feedwater volumethan usual. may be low or quality may be

better than usual.

AGK 100 Dosage AdjustmentHydrate Alkalinity is the primary parameter for adjusting AGK 100 Dosage

NEUTRALIZED CONDUCTIVITY in µµµµµmhos BLOWDOWN ADJUSTMENT

Up to 700 Satisfactory Normal maintenance blowdown is sufficient. Regular flash blowdown toremove suspended solids should be carried out a minimum of once perweek.

Above 700 High Increase frequency of blowdown.

Boiler Water AMERZINE DOSAGE ADJUSTMENT Hydrazine Dosage is necessary only when HYDRAZINE test results are low in ppm with AGK 100 dosage alone.

Initial Dosage: 100 ml/day

Above 0.10 High Decrease0.03 - 0.10 Satisfactory No ChangeBelow 0.03 Low Increase

30

DREWPLEX® AT boiler water treatment and DREWPLEX OX corrosion inhibitor for Motor Vessels

DREWPLEX AT/DREWPLEX OX TreatmentInitial Dosage: 2.5-5 liters per ton of water in the boiler system

Continuous Dosage: Maintain 40-65 ppm hydrate alkalinity and 10-20 ppm phosphate in the boiler water

HYDRATE ALKALINITY HYDRATE ALKALINITY HYDRATE ALKALINITY <40 ppm 40 - 65 ppm >65 ppm

Increase dosage Dosage adjustment Reduce dosage by PO4 by 25% and check may be necessary. 10%. Check for<10ppm for seawater or Check for possible shore water in-leakage.

shore water hardnessor in-leakage. in-leakage.

Increase dosage by Normal condition. Reduce dosage by PO4 20%. Check No dosage 10%. Check for 10 - condensate for acidic adjustment shore water in-leakage.20 ppm material in-leakage. necessary.

Increase dosage Dosage adjustment Reduce dosage byby 10%. Check may be necessary. 25%. Feedwatercondensate for Check for acidic quality may be better

PO4 acidic material material in-leakage. than usual.>20ppm in-leakage. Alkalinity may be

Make up and/or destroyed by acidfeedwater volume contamination.may be low or Makeup and/orquality may be feedwater volume maybetter than usual. be low or quality may

be better than usual.

DREWPLEX AT Dosage AdjustmentHydrate Alkalinity is the primary parameter for adjusting DREWPLEX AT Dosage

NEUTRALIZED CONDUCTIVITY in µµµµµmhos BLOWDOWN ADJUSTMENT

Up to 700 Satisfactory Normal maintenance blowdown is sufficient.Regular flash blowdown to remove suspendedsolids should be carried out a minimum ofonce per week.

Above 700 High Increase frequency of blowdown.

Feedwater DOSAGE ADJUSTMENT DEHA DREWPLEX OX Continuous Dosage in ppm Initial Dosage: 0.4 liters/ton of water

in the boiler system

Above 0.8 High Decrease 0.4 - 0.8 Satisfactory No ChangeBelow 0.4 Low Increase

31

DREWPLEX® AT boiler water treatment/AMERZINE® corrosion inhibitor for Motor Vessels

DREWPLEX AT/AMERZINE treatmentInitial Dosage: 2.5-5 liters per ton of water in the boiler system

Continuous Dosage: Maintain 40-65 ppm hydrate alkalinity and 10-20 ppm phosphate in the boiler water

HYDRATE ALKALINITY HYDRATE ALKALINITY HYDRATE ALKALINITY <40 ppm 40 - 65 ppm >65 ppm

Increase dosage Dosage adjustment Reduce dosage by PO4 by 25% and check may be necessary. 10%. Check for<10ppm for seawater or Check for possible shore water in-leakage.

shore water hardnessor in-leakage. in-leakage.

Increase dosage by Normal condition. Reduce dosage by PO4 20%. Check No dosage 10%. Check for 10 - condensate for acidic adjustment shore water in-leakage.20 ppm material in-leakage. necessary.

Increase dosage Dosage adjustment Reduce dosage byby 10%.Check may be necessary. 25%. Feedwatercondensate for Check for acidic quality may be better

PO4 acidic material material in-leakage. than usual.>20ppm in-leakage. Alkalinity may be

Make up and/or destroyed by acidfeedwater volume contamination.may be low or Makeup and/orquality may be feedwater volume maybetter than usual. be low or quality may

be better than usual.

DREWPLEX AT Dosage AdjustmentHydrate Alkalinity is the primary parameter for adjusting DREWPLEX AT Dosage

NEUTRALIZED CONDUCTIVITY in µµµµµmhos BLOWDOWN ADJUSTMENT

Up to 700 Satisfactory Normal maintenance blowdown is sufficient.Regular flash blowdown to remove suspendedsolids should be carried out a minimum of onceper week.

Above 700 High Increase frequency of blowdown.

Boiler Water DOSAGE ADJUSTMENT Hydrazine AMERZINE Continuous Dosage in ppm Initial Dosage: 0.15 liters/ton of water

in the boiler system

Above 0.10 High Decrease0.03 - 0.10 Satisfactory No ChangeBelow 0.03 Low Increase

STEAM PROPULSION SYSTEM

1. AMERZINE

2. SLCC-A INJECTION POINTS

3. ADJUNCT B INJECTION POINTS

4. GC INJECTION POINTS

32

Dosage of LIQUID COAGULANTTM

boiler sludge conditioner

LIQUID COAGULANT boiler sludge conditioner is "slug-fed" daily at a dosage of 30 mls (1 oz.) per ton of boilerwater capacity to minimize the effects of oil contamination.When dosing LIQUID COAGULANT conditioner, bothbottom flash blowdowns and fast surface blowdowns arerecommended.

Do not continue to operate a boiler system with severe oilcontamination.

For systems experiencing severe oil contamination,locate and secure the leak. Then an off-line cleaning isrecommended. Consult your Drew Marine representativefor specific maintenance chemicals.

After the equipment is cleaned, LIQUID COAGULANTconditioner should be dosed at 30 mls (1 oz.) per ton ofboiler water capacity per day for two weeks or untilcomplete oil removal is accomplished.

LIQUID COAGULANT conditioner should not be used inhigh pressure boilers.

H.P.TURBINE

BOILER L.P.TURBINE

TURBOALTERNATOR

MAKEUP

GLAND EXHAUSTCONDENSER

DRAINSRETURN

TANK

OBSERVATIONTANK

H.P. HEATERS DEAERATOR

DISTILLER

HEATINGSERVICES

L.P. HEATER

FEEDPUMP

MAINCONDENSER

AUX.CONDENSER

L.O. COOLER

33

Boiler Water Treatment Control TestsIn Alphabetical Order

(pages 35-58)

Cooling Water Treatment Control TestsIn Alphabetical Order

(pages 63-66)

34

HYDRATE ALKALINITY TESTFOR AGK® 100 and DREWPLEX® AT TREATMENTS

CONTROL LIMITS

Hydrate Alkalinity Dosage

Below 40 ppm Increase 40-65 ppm No change Above 65 ppm Decrease

PROCEDURE

35

Before testing, boiler water, hot condensate, and feedwater samples must be cooled to 25OC (77OF) by collectingthrough a sample cooler for safety and to prevent flashing which concentrates the sample. Read MSDS before runningthese tests.

NOTE: If the sample is colored or turbid, filter before running the test. If the sample remains cloudy after the firstfiltering, the sample should be refiltered through the same filter paper since the filter becomes more retentive on thesecond filtration. (Filter paper is supplied separately).

HYDRATE ALKALINITY TEST KIT (PCN #0388-01-8)

APPARATUS REAGENTS

1 Plastic Titration Vial Marked at 12ml 7 x 60ml Barium Chloride 10%1 Dropper Pipette Marked at 0.5 and 1.0ml 3 x 60ml Sulfuric Acid N/10

1 x 30ml Phenolphthalein

1. Rinse and fill the plastic titration vial to the line (12 ml) with cooled boilerwater sample.

2. Pipette 2 ml of Barium Chloride 10% into the vial and swirl to mix.

3. Add 2 drops of Phenolphthalein Indicator and swirl. IF THE SAMPLEDOES NOT TURN PINK, the Hydrate Alkalinity level is zero. Record zeroon the Onboard Graphing Log and adjust dosage to increase hydratealkalinity. IF THE SAMPLE TURNS PINK, counting the drops, addSulfuric Acid N/10 until the sample is colorless (disregard the eventualreappearance of a pink color). Swirl the vial between drops.

4. Calculate the Hydrate Alkalinity concentration as follows: Number of drops of Sulfuric Acid N/10 x 5 = ppm Hydrate Alkalinity as OH.

5. Record the Hydrate Alkalinity level on the Onboard Graphing Log. Makedosage adjustments as needed.

1

3

5

2

12 ml

36

1. Fill the burette by squeezing the plastic bottle of N/10 Sulfuric Acid. Allow the solu-tion in the burette to settle to the 0.0 mark.

2. Measure 50 ml of cooled sample using a graduated cylinder.

3. Transfer the measured sample into an evaporating dish.

Phenolphthalein Endpoint

4. Add 4 drops of Phenolphthalein to the sample. If the solution turns pink, proceed tostep 5. If the solution does not turn pink, record Phenolphthalein Alkalinity as 0.0on the Onboard Graphing Log and refer to the GC Dosage Chart for immediatedosage of GC.

5. Turning the stopcock on the burette, add N/10 Sulfuric Acid to the sample drop bydrop while stirring continuously until the pink color disappears and the sample isback to its original color. This is the Phenolphthalein Endpoint. NOTE: Do notdispose of the sample in the evaporating dish or refill the burette. This samesample is used for the Total Alkalinity Test and the total amount of acid addedmust be measured.

6. Read the level of the N/10 Sulfuric Acid solution on the burette. Refer to the Mediumto Low Pressure Alkalinity Conversion Table on Page 36 and find the number whichcorresponds to the burette reading. Beside this number you will find the equivalentPhenolphthalein (P) Alkalinity expressed in parts per million (ppm). The parts permillion Phenolphthalein Alkalinity can also be calculated as follows:

ppm Phenolphthalein Alkalinity = mls of N/10 Sulfuric Acid x 100

7. Record the Phenolphthalein (P) Alkalinity as ppm on the Onboard Graphing Log.

Total Alkalinity Endpoint

8. Using the same water sample in the evaporating dish, add 4 drops of Total AlkalinityIndicator GP. The sample will turn a blue green color.

9. Without refilling the burette, turn the stopcock and add N/10 Sulfuric Acid drop bydrop stirring continuously. A pinkish purple color will begin to form around the dropsas they fall into the sample. Continue titrating and stir until a permanent pinkishpurple color develops throughout the sample. This is the Total Alkalinity Endpoint.

10. Read the level of the N/10 Sulfuric Acid solution on the burette. Refer to the Mediumto Low Pressure Alkalinity Conversion Table and find the number closest to theburette reading. Beside this number you will find the equivalent Total (T) Alkalinity inthe sample expressed in parts per million (ppm). The parts per million Total Alkalin-ity can also be calculated as follows:

ppm Total Alkalinity = mls of N/10 Sulfuric Acid x 100

11. Record the Total (T) Alkalinity as ppm on the Onboard Graphing Log.

12. Refer to the Control and Dosing Chart for instructions on dosing GCTM concentratedalkaline liquid. The total alkalinity endpoint test is only a reference test and shoulddetermine GC dosage adjustment only if the T. Alkalinity is out of balance.

Control Limits: 0-60 kg/cm2 < 2 P Alkalinity

2

3

4 & 8

5 & 9 6 & 10

1

ALKALINITY TITRATIONFOR MEDIUM TO LOW PRESSURE BOILER SYSTEMS

PROCEDURE

Read the MSDS before performing this test procedure.Before testing, samples must be cooled to 25OC (77OF) by collecting through a sample cooler for safety and to prevent flashingwhich concentrates the sample.

APPARATUS REAGENTS

LP Alkalinity Titration Assembly PCN 0380-01-4 N/10 Sulfuric Acid, 500 ml PCN 0319-09-6Graduated Cylinder, 50 ml PCN 0237-02-5 Phenolphthalein Indicator, 120 ml PCN 0311-01-9Evaporating Dish PCN 0218-01-7 Total Alkalinity Indicator GP, 120 ml PCN 0355-19-9Plastic Stirring Rod PCN 0417-01-5

Control Limits: 0-32 kg/cm2 100-150 ppm32-60 kg/cm2 90-130 ppm

37

PROCEDURE

Read the MSDS before performing this test procedure.Before testing, samples must be cooled to 25OC (77OF) by collecting through a sample cooler for safety and to preventflashing which concentrates the sample.

APPARATUS (included in PCN 0441-04-8) REAGENTS (included in PCN 0437-04-7)

HP Alkalinity Titration Assembly PCN 0379-01-7 N/50 Sulfuric Acid, 1000 ml PCN 0485-01-2Graduated Cylinder, 50 ml PCN 0237-02-5 Phenolphthalein Indicator, 60 ml PCN 0311- -- -Evaporating Dish PCN 0218-01-7 Total Alkalinity Indicator GP, 60 ml PCN 0355- -- -Plastic Stirring Rod PCN 0417-01-5

1. Fill the burette by squeezing the plastic bottle of N/50 Sulfuric Acid. Allow thesolution in the burette to settle to the 0.0 mark.

2. Measure 50 ml of cooled sample using a graduated cylinder.

3. Transfer the measured sample into an evaporating dish.

Phenolphthalein Endpoint

4. Add 4 drops of Phenolphthalein to the sample. If the solution turns pink,proceed to step 5. If the solution does not turn pink, record PhenolphthaleinAlkalinity as 0.0 on the Onboard Graphing Log and proceed to step 8.

5. Turning the stopcock on the burette, add N/50 Sulfuric Acid to the sampledrop by drop while stirring continuously until the pink color disappears andthe sample is back to its original color. This is the Phenolphthalein Endpoint.NOTE: Do not dispose of the sample in the evaporating dish or refill theburette. This same sample is used for the Total Alkalinity Test and thetotal amount of acid added must be measured.

6. Read the level of the N/50 Sulfuric Acid solution on the burette. Refer to theHigh Pressure Alkalinity Conversion Table on Page 36 and find the numberwhich corresponds to the burette reading. Beside this number you will findthe equivalent Phenolphthalein (P) Alkalinity expressed in parts per million(ppm). The parts per million Phenolphthalein Alkalinity can also becalculated as follows:

ppm Phenolphthalein Alkalinity = mls of N/50 Sulfuric Acid x 20

7. Record the Phenolphthalein (P) Alkalinity as ppm on the OnboardGraphing Log.

Total Alkalinity Endpoint

8. Using the same water sample in the evaporating dish, add 4 drops of TotalAlkalinity Indicator GP. The sample will turn a blue green color.

9. Without refilling the burette, turn the stopcock and add N/50 Sulfuric Aciddrop by drop stirring continuously. A pinkish purple color will begin to formaround the drops as they fall into the sample. As the titration continues aslate gray color will be observed. Continue titrating and stir until a permanentpinkish purple color develops throughout the sample. This is the Total Alka-linity Endpoint.

10. Read the level of the N/50 Sulfuric Acid solution on the burette. Refer to theHigh Pressure Alkalinity Conversion Table and find the number closest to theburette reading. Beside this number you will find the equivalent Total (T)Alkalinity in the sample expressed in parts per million (ppm). The parts permillion Total Alkalinity can also be calculated as follows:

ppm Total Alkalinity = mls of N/50 Sulfuric Acid x 20

11. Record the Total (T) Alkalinity as ppm on the Onboard Graphing Log.

12. The alkalinity tests are conducted only as reference tests for high pressureboiler systems.

5 & 9 6 & 10

12

3

4 & 8

ALKALINITY TITRATIONFOR HIGH PRESSURE BOILER SYSTEMS

ALKALINITY TESTS

HIGH PRESSURE BOILERS(Pressure Range: 60-84 kg/cm2 (850-1200 psig)

Titrated with N/50 Sulfuric AcidPhenolphthalein and Total Alkalinity Control Tests

Conversion Table mls of titrant ppm(N/50 Sulfuric Acid Alkalinity as CaCO3

0.1 20.2 40.3 60.4 80.5 100.6 120.7 140.8 160.9 181.0 201.2 221.4 281.6 321.8 362.0 402.4 482.6 522.8 563.4 684.0 804.6 925.2 104

MMEDIUM TO LOW PRESSURE BOILERS(Pressure Range: Up to 60 kg/cm2 (850 psig)

Titrated with N/10 Sulfuric AcidPhenolphthalein and Total Alkalinity Control Tests

Conversion Table mls of titrant ppm mls of titrant ppm(N/10 Sulfuric Acid) Alkalinity (N/10 Sulfuric Acid) Alkalinity as CaCO3

0.1 10 2.6 2600.2 20 2.7 2700.3 30 2.8 2800.4 40 2.9 2900.5 50 3.0 3000.6 60 3.1 3100.7 70 3.2 3200.8 80 3.3 3300.9 90 3.4 3401.0 100 3.5 3501.1 110 3.6 3601.2 120 3.7 3701.3 130 3.8 3801.4 140 3.9 3901.5 150 4.0 4001.6 160 4.1 4101.7 170 4.2 4201.8 180 4.3 4301.9 190 4.4 4402.0 200 4.5 4502.1 210 4.6 4602.2 220 4.7 4702.3 230 4.8 4802.4 240 4.9 4902.5 250 5.0 500

38

AMMONIA TEST(CONDENSATE)

FOR HIGH PRESSURE BOILER SYSTEMS

Not a Required Test for Medium to Low Pressure Boilers

AMMONIA TEST AMPOULES (PCN 0384-01-6) INCLUDES:

30 Ampoules1 Snapping Cup1 Color Comparator Card

Included in the ULTRAMARINESM 6-Month Reagent Set (PCN 0437-04-7)

PROCEDURE

Before testing, samples must be cooled to 25°C (77°F) by collecting through a sample cooler for safety and to preventflashing which concentrates the sample.

39

1. Fill the snapping cup completely with cooled condensate.

2. Place the tapered tip of an ammonia ampoule into one ofthe holes in the snapping cup. Keeping the tip immersed inthe sample, break the tip by tilting the ampoule towards theopposite wall of the snapping cup and allow the ampoule tofill completely.

3. Remove the ampoule from the snapping cup. Mix thecontents by inverting the ampoule back and forth severaltimes for 30 seconds.

4. Wait 15 minutes for full color development.

5. Compare the color of the ampoule with the color standards.Report the ammonia level on the ULTRAMARINE OnboardGraphing Log as ppm ammonia.

SNAPPINGCUP FILL

COM-PLETELY

1

4

15:00

2

5

3

Ashland Specialty ChemicalDrew Marine Division

AMMONIA, ppm

0 0.1 0.5 0.70.3

Control Limit 60-84 kg/cm2

(850-1200 psig) 0.5 ppm maximum

CHLORIDE TESTFOR HIGH PRESSURE BOILER SYSTEMS

DREW CHLORIDE HP TEST KIT (PCN 0372-01-1) INCLUDES:

1 Glass Flask for Sample1 Plastic Dropper Plug for Mixed Chloride Indicator1 White Plastic Bottle Cap for Mixed Chloride Indicator2 x 60 ml (2 oz.) Mercuric Nitrate1 x 30 ml (1 oz.) Nitric Acid N/51 x 30 ml (1 oz.) Mixed Chloride Indicator Solution1 Glass Vial Powder IndicatorThis test kit is included in the ULTRAMARINESM 6 Month Reagent Set (PCN 0437-04-7).

MixedChlorideIndicator

MixedChlorideIndicator

DropperPlug

MixedChlorideIndicator

d c

...

.........

b MixedChlorideIndicator

a

1

2

MixedChlorideIndicator

Prepare the Mixed Chloride Indicator as follows:

a. Unscrew the black caps of the small glass vial and the 1 oz. plasticbottle labeled "Mixed Chloride Indicator".

b. Pour the powder contents of the small glass vial into the liquidcontents of the 1 oz. plastic bottle.

c. Screw the black cap back onto the Mixed Chloride Indicator bottleand mix for 5 seconds.

d. Remove the black screw cap. Insert the plastic dropper plug into themouth of the plastic bottle and screw the white cap onto the bottle.Proceed with the test.

PROCEDURE

1. Prepare the sample flask by rinsing the glass flask and fill to themark (24 ml) with the water to be tested.

2. Adjust the color of the sample by adding 6 drops of Mixed ChlorideIndicator and swirl to mix. The resulting color will be light red.

3. Adjust the pH by adding Nitric Acid N/5 dropwise, swirling betweendrops until the sample is yellow. Add 1 more drop.

4. Counting the drops, hold the glass flask in a vertical position andadd Mercuric Nitrate dropwise with swirling until the color turns to apermanent purple.

5. Calculate the chloride concentrationNumber of drops of Mercuric Nitrate x 1 = ppm chloride as Cl

6. Record results as ppm chloride on the Onboard Graphing Log.

3

NitricAcid

Mercuric Nitrate

4

Control Limit 16 ppm maximum

40

41

1

2

3

50 ml

CHLORIDE TITRATIONFOR HIGH PRESSURE BOILER SYSTEMS

Read MSDS before performing this test procedure.

Before testing, samples must be cooled to 25°C (77°F) by collecting through a sample cooler for safety and to preventflashing which concentrates the sample.

Note: If the sample is colored or turbid, it should be filtered before testing. If the sample remains cloudy after the firstfiltering, the sample should be refiltered through the same filter paper since the filter becomes more retentiveon the second filtration.

This procedure is preferred for systems which are expected to contain low chloride levels because it is more sensitivethan the method for medium to low pressure boiler systems.

THIS TEST IS NOT RECOMMENDED FOR USE ON TREATED COOLING WATER.

APPARATUS REAGENTS

HP Chloride Titration Assembly PCN 0382-01-0 Mercuric Nitrate, 500 ml PCN 0475-09-6Graduated Cylinder, 50 ml PCN 0237-02-5 N/5 Nitric Acid, 120 ml PCN 0479-19-7Evaporating Dish PCN 0218-01-7 Mixed Chloride Indicator Solution, 100 ml PCN 0477-19-1Plastic Stirring Rod PCN 0417-01-5 Mixed Chloride Indicator Powder, 5 caps PCN 0478-01-7

PROCEDURE

4

5 & 6

7

1. At least every four weeks prepare fresh Mixed Chloride Indi-cator Solution. Discard any Mixed Chloride Indicator So-lution that is more than four weeks old. Prepare new solutionas follows:a. Empty a capsule of Mixed Chloride Indicator Powder into

the bottle of Mixed Chloride Indicator Solution.b. Cap and mix by swirling or shaking the bottle gently.

2. Fill the burette by squeezing the plastic bottle of Mercuric Ni-trate. Allow the solution in the burette to settle to the 0.0mark.

3. Measure 50 ml of cooled sample using a graduated cylinder.

4. Transfer the measured sample into an evaporating dish.

5. Add 10 drops of prepared Mixed Indicator Solution and stir.

6. Add N/5 Nitric Acid, drop by drop, stirring continuously untilthe sample just turns yellow. Add 5 more drops of acid.

7. Turning the stopcock on the burette, add Mercuric Nitrate tothe sample drop by drop while stirring continuously. The end-point is reached when the color changes to a permanant vio-let.

8. Read the level of the Mercuric Nitrate solution on the burette.Refer to the Chloride/Mercuric Nitrate Conversion Table onPage 42 and find the number which corresponds to the burettereading. Next to this number you will find the equivalent chlo-ride content expressed in parts per million (ppm). The partsper million chloride can also be calculated as follows:

ppm chloride = mls of Mercuric Nitrate x 10

9. Record results as ppm chloride on the Onboard Graphing Log.

Control Limit: 16 ppm maximum

1. For samples less than 100 ppm chlorideRinse the plastic vial and fill to the mark (10 ml) with sample to be tested.

For samples greater than 100 ppm chlorideRinse the tall glass test tube and fill to the mark (2 ml) with sample to betested.

2. Neutralize the sample by adding 3 drops of Phenolphthalein Indicator tothe sample. Swirl to mix.If the sample turns pink, add Sulfuric Acid N/10 dropwise with swirlinguntil the sample turns clear. Add 1 more drop.

If the sample does not turn pink, add 1 drop of Sulfuric Acid N/10.

3. Adjust the color of the sample by adding 6 drops of PotassiumChromate. The sample will be yellow.

4. Counting the drops, add Silver Nitrate N/10 dropwise. Swirl betweendrops until the sample turns orange.

5. Calculate the Chloride ConcentrationIf the plastic vial was used in Step 1: Number of drops of Silver Nitrate x 10 = ppm chloride

If the glass test tube was used in Step 1: Number of drops of Silver Nitrate x 50 = ppm chloride as Cl

6. Record results as ppm chloride on the Onboard Graphing Log.

1 or

glass tubeplastic vial

2, 3, 4, 5

NOTE: This test can be used to detect chloride in makeup water andcooling water treated with DEWT® NC diesel engine water treatment. THISMETHOD IS NOT RECOMMENDED FOR COOLING WATER TREATEDWITH MAXIGARD® diesel engine water treatment or LIQUIDEWTTM

cooling water treatment WITHOUT SAMPLE PRETREATMENT. Seepage 66 for sample pretreatment procedure.

Control Limits 0-32 kg/cm2 32-60 kg/cm2

(0-450 psig) (450-850 psig)

300 ppm max. 40 ppm max.

CHLORIDE TESTFOR MEDIUM TO LOW PRESSURE BOILER SYSTEMS

DREW CHLORIDE LMP TEST KIT (PCN 0373-01-9) INCLUDES:

1 Plastic Vial (10 ml mark)1 Glass Tube (1 ml mark)2 x 60 ml (2 oz.) Silver Nitrate1 x 30 ml (1 oz.) Sulfuric Acid N/101 x 30 ml (1 oz.) Phenolphthalein1 x 60 ml (2 oz.) Potassium ChromateThis test kit is included in the Alkalinity/Chloride Reagent Set (PCN 0301-02-8).

PROCEDURE

42

43

CHLORIDE TITRATION FOR MEDIUM TO LOW PRESSURE BOILER SYSTEMS

Read MSDS before performing this test procedure.

Before testing, samples must be cooled to 25°C (77°F) by collecting through a sample cooler for safety and to preventflashing which concentrates the sample.

Note: If the sample is colored or turbid, it should be filtered before testing. If the sample remains cloudy after the firstfiltering, the sample should be refiltered through the same filter paper since the filter becomes more retentive on thesecond filtration.

This procedure is generally recommended for chloride determinations on all waters. An accurate chloride determination canbe made only with water having a pH below the Phenolphthalein Alkalinity Indicator end point (pH 8.3).

APPARATUS REAGENTS

LP Chloride Titration Assembly PCN 0381-01-2 N/10 Silver Nitrate, 500 ml PCN 0315-09-4Graduated Cylinder, 50 ml PCN 0237-02-5 Potassium Chromate, 120 ml PCN 0313-19-7Evaporating Dish PCN 0218-01-7 Phenolphthalein, 120 ml PCN 0311-19-1Plastic Stirring Rod PCN 0417-01-5 N/10 Sulfuric Acid, 120 ml PCN 0319-19-5

PROCEDURE1. Fill the burette by squeezing the plastic bottle of Silver

Nirate. Allow the solution in the burette to settle to the0.0 mark.

2. Measure 50 ml of cooled sample using a graduatedcylinder.

3. Transfer the measured sample into an evaporatingdish.

4. Add 4 drops of Phenolphthalein to the sample. If thesample turns pink, add N/10 Sulfuric Acid dropwiseuntil the pink disappears. If the sample does not turnpink, proceed to step 5.

5. Add one dropperful of Potassium Chromate to thesample. This will turn the sample a yellow color.

6. Turning the stopcock on the burette, add SilverNitrate to the sample drop by drop while stirringcontinuously. The endpoint is reached when the colorchanges to a permanent light red. Do not "overtitrate"to a "brick red" color as this will result in an errone-ously high determination.

7. Read the level of the Silver Nitrate solution on theburette. Refer to the Chloride/Silver Nitrate Conver-sion Table on Page 42 and find the number whichcorresponds to the burette reading. Next to thisnumber you will find the equivalent chloride contentexpressed in parts per million (ppm).

8. Record results as ppm chloride on the OnboardGraphing Log.

Control Limits

0-31 kg/cm2 32-60 kg/cm2

(0-450 psig) (450-850 psig)

300 ppm max 40 ppm max

1

3Step 2

50 ml

4 & 5

6

MEDIUM TO LOW PRESSURE BOILERSPressure Range: Up to 60 kg/cm2 (850 psig)

Titrated with Silver Nitrate

Conversion Table

44

CHLORIDE TESTS

HIGH PRESSURE BOILERSPressure Range: 60-84 kg/cm2 (850-1200 psig)

Titrated with Mercuric Nitrate

Conversion Table mls of Titrant ppm(Mercuric Nitrate) Chloride

0.1 10.2 20.3 30.4 40.5 50.6 60.7 70.8 80.9 91.0 101.2 121.4 141.6 161.8 182.0 202.4 242.6 262.8 283.0 304.0 404.6 465.2 52

mls of Titrant ppm(Silver Nitrate) Chloride

0.1 70.2 140.3 210.4 280.5 360.6 430.7 500.8 570.9 641.0 711.1 781.2 851.3 921.4 991.5 1071.6 1141.7 1211.8 1281.9 1352.0 1422.1 1492.2 1562.3 1632.4 170

mls of Titrant ppm(Silver Nitrate) Chloride

2.5 1782.6 1852.7 1922.8 1992.9 2063.0 2133.1 2203.2 2273.3 2343.4 2413.5 2483.6 2563.7 2633.8 2703.9 2774.0 2844.1 2914.2 2984.3 3054.4 3124.5 3194.6 3264.7 334

mls of Titrant ppm(Silver Nitrate) Chloride

4.8 3414.9 3485.0 3555.1 3625.2 3695.3 3765.4 3835.5 3905.6 3985.7 4055.8 4125.9 4186.0 4266.1 4346.2 4406.3 4476.4 4556.5 4616.6 4686.7 4766.8 4836.9 4907.0 497

CONDUCTIVITY TESTFOR HIGH TO LOW PRESSURE BOILER SYSTEMS

7

1. Press the power switch and allow the meter to warm up for one minute.

2. Connect the conductivity cell for the appropriate testing range.• White band (inner scale) for condensate and low conductivity waters.• Black band (outer scale) for boiler water and other high conductivity solutions.

3. For a boiler water sample, add two drops of Phenolphthalein Indicator to thesample and stir. If the sample remains clear, go to Step 5.

4. a. If the sample turns pink, neutralize by adding Gallic Acid, one level spoonful ata time, stirring after each spoonful, until the pink color just disappears. NOTE:Do not add excess Gallic Acid, Failure to neutralize sample or addition ofexcess acid beyond the end point will cause erroneously high conductivityreadings.

b. If Liquid Neutralizing solution is being used, the first drops will turn the solutionpink. Continue to add solution dropwise until the pink color disappears.

5. Submerge the cell in the water sample to a depth to cover the vent holes. Agitatethe cell to vent all trapped air bubbles from the cell interior.

6. Measure the temperature of the sample and set the temperature knob to thisvalue.

7. Rotate the conductivity knob until both the red and the green indicator lamps arelighted at the same time.

8. Read the conductivity value on the appropriate scale.

9. Record the test result on the Onboard Graphing Log (µmhos).

10. Remove the cell from the sample and rinse it with clean water.

11. Press the power switch to shut off the meter.

12. Compare results to the Control and Dosing charts and adjust blowdown scheduleas required.

3

GallicAcid

4

Control Limits 0-60 kg/cm2 60-84 kg/cm2

(0-850 psig) (850-1200 psig)

700 µmhos max 120 µmhos max

CONDUCTIVITY KIT (PCN 0173-01-3) INCLUDES:

APPARATUS REAGENTS

Conductivity Meter PCN 0156-01-9 Gallic Acid, 100 gm PCN 0309-01-4Low Range Cell (White Band) PCN 0117-01-1 Phenolphthalein Indicator, 480ml (16 oz.) PCN 0311-01-9High Range Cell (Black Band) PCN 0116-01-3 (Not provided in PCN 0173-01-3)Conductivity Cylinder, Plastic PCN 0232-02-5Dial Thermometer PCN 0143-02-4Brass Spoon, 0.2gm PCN 0224-01-4

PROCEDURE

NOTE: Neutralization (Steps 3 and 4) is necessary for boiler water. It is not necessary for high purity waters such as condensateor for feedwater. The other steps of the procedure are the same.

Before using the meter, be sure the voltage switch is set for the proper voltage.CAUTION: ALWAYS DISCONNECT THE METER FROM THE POWER SOURCE BEFORE OPENING THE CASE.

45

DEHA/DREWPLEX® OX corrosion inhibitorAmpoule Test

DREWPLEX OX Ampoule Test Kit (PCN 0387-01-0) INCLUDES:

APPARATUS REAGENTS

1 Comparator Activator Solution PCN 0387-03-61 Snap Cup Ampoule Refill PCN 0387-02-8

PROCEDURE

Read MSDS before performing this test procedure.

NOTE: Before testing, samples must be cooled to 25OC (77OF) by collecting through a sample cooler for safety and topevent flashing which concentrates the sample. If the sample is colored or turbid, filter before running this test.

46

2

1

4

6

3

5

10:00

1. Fill the sample cup to the 25 ml mark with cooledfeedwater sample.

2. Add 2 drops of Activator Solution. Stir gently with the tipof an ampoule from the DREWPLEX® OX corrosioninhibitor Ampoule Test Kit to mix the contents of thesample cup.

3. Immediately snap the tip of the ampoule by pressing theampoule against the side of the sample cup. Thesample will fill the ampoule and begin to mix with thereagent, leaving a small bubble to facilitate the mixing.

4. Remove the ampoule from the cup. Mix the contents ofthe ampoule by inverting it several times, allowing thesmall bubble to travel from end to end each time.

5. Wipe all liquid from the exterior of the ampoule andWAIT EXACTLY 10 MINUTES for full color develop-ment.

6. When using the comparator, be sure it is illuminated by awhite light directly above the comparator. The filledDEHA ampoule should be placed between the colorstandards for viewing. It is important that the DEHAampoule be compared by placing it on both sides of thestandard tube before concluding that it is darker, lighteror equal to the standard.

7. Record the results on the Onboard Graphing Log andadjust the DREWPLEX OX corrosion inhibitor dosage asnecessary.

7

15

10

20

25

5

mL

CONTROL LIMITS

0-32 kg/cm2

0-450 psig0.4 - 0.8 ppm in feedwater

HARDNESS TEST, TOTALFOR HIGH PRESSURE BOILER SYSTEMS

(MAKEUP and FEEDWATER)

HARDNESS TEST AMPOULES INCLUDES:

2 boxes of 30 Ampoules (PCN 0365-01-6)

This test material is included in the ULTRAMARINESM 6-Month Reagent Set (PCN 0437-04-7).

PROCEDURE

1. Rinse and fill the snapping cup with the sample to be tested.

2. Place the tip of the hardness ampoule into one of the holes in the bottom ofthe snapping cup.

3. While applying downward pressure, break the tip by tilting the ampouletoward the edge of the snapping cup. Keep the tip immersed in the waterwhile drawing sample.

4. Mix by inverting the hardness ampoule back and forth to dissolve thereagent.

5. Wait 30 seconds.

6. Place the ampoule in front of a white background and view the color. A pureblue color indicates less than 0.1 ppm hardness. A pink color indicateshardness is present.

7. To confirm a pure blue color, run a zero standard by performing the test ondistilled water.

8. Record results on the Onboard Graphing Log.

SNAPPINGCUP FILL

COM-PLETELY

1

3

47

Control Limit 60-84 kg/cm2

(850-1200 psig) <0.1ppm

NOTE: If the sample is colored or turbid, it should be filtered beforetesting.

1. Fill the sample cup to the 25 ml mark with sample (Figure 1).

2. Slide the open end of the valve assembly over the tapered tip of theTitret so that it fits snugly to the Reference Line (Figure 2).

3. Snap the tip of the Titret at the Score Mark (Figure 3).

4. With the tip of the valve assembly immersed in the sample, squeezethe bead valve briefly to add a small amount of sample to the Titret(Figure 4). The red indicator in the valve assembly will also be addedto the Titret.CAUTION: Do not squeeze the bead valve unless the tip of the valveis immersed below the surface of the liquid.

5. Rock the Titret to mix the contents. The contents of the Titret will turna BLUE color.

6. Continue to add small amounts of sample until the liquid in the Titretturns from BLUE TO PINK. Be sure to rock the Titret to mix thecontents after each addition of sample. When the color of the liquidin the Titret changes to PINK, the end point has been reached. Stopthe test, hold the Titret with its tip pointed upward and read the scaleopposite the liquid level to obtain the test results in ppm total hardnessas calcium carbonate, CaCO

3 (Figure 5).

7. Record results on the Onboard Graphing Log.

Hardness should not exceed 170 ppm in waters used as makeup to diesel engine cooling systems treated with MAXIGARD®

diesel engine water treatment or LIQUIDEWTTM cooling water treatment.

This test may be used on treated waters as well as makeup water.

TOTAL HARDNESS TITRETS2 (PCN 0378-01-9) INCLUDES:

50 Titrets 1 Sample Cup30 Valve Assemblies

PROCEDURE

HARDNESS TESTTITRET2 METHOD

ValveAssembly

Score Mark

Reference Line

Ampoule 2

1

3

BeadValve←

ReadHere →

4

5

48

HYDRAZINE/AMERZINE TESTFOR HIGH TO LOW PRESSURE BOILER SYSTEMS

AMERZINE® CORROSION INHIBITOR AMPOULE TEST KIT (PCN 0369-01-8) INCLUDES:1 Cylindrical Comparator1 Sample Cup1 Set of Instructions30 Ampoules

AMERZINE CORROSION INHIBITOR AMPOULE REFILL (PCN 0369-02-6) INCLUDES:30 Ampoules

This test kit and refills are included in the ULTRAMARINESM 6 Month Reagent Set (PCN 0437-04-7)

PROCEDURE

1. To insure accurate results, the sample should be collected withminimum contact to air and tested promptly. A sample coolershould be used for sampling boiler water.

2. Fill the sample cup to the 25ml mark with sample.

3. Place the AMERZINE corrosion inhibitor ampoule's tapered tip intoone of the four depressions in the bottom of the sample cup. Snap thetip by squeezing the ampoule toward the side of the cup. Keep the tipimmersed in the water while drawing sample. The sample will fill theampoule and begin to mix with the reagent.

4. Remove the AMERZINE corrosion inhibitor ampoule from the cup. Mixthe contents of the ampoule by inverting it several times, allowing thebubble to travel from end to end each time.

5. Wipe all liquid from the exterior of the ampoule and wait 10 minutes forfull color development.

6. Place the AMERZINE corrosion inhibitor ampoule, flat end downwardinto the center tube of the comparator. Direct the comparator toward asource of bright white light while viewing from the bottom. Hold thecomparator in a nearly horizontal position and rotate it until the colorstandard below the AMERZINE corrosion inhibitor ampoule shows theclosest match.

7. Record the AMERZINE level on the Onboard Graphing Log. Resultsare expressed as ppm hydrazine.

Control Limit 0-84 kg/cm2

(0-1200 psig)

0.03-0.10 ppm

49

1 & 2

3

5

pH TEST (COLORMETRIC)FOR HIGH PRESSURE BOILER SYSTEMS

Not a Required Test for Medium to Low Pressure Boilers.

APPARATUS

Included in the ULTRAMARINESM Glassware Set (PCN 0441-04-8)Water Analyzer Base PCN 0427-01-4Phthalein Red Comparator Slide PCN 0422-01-4 (8.6 to 10.2 pH range)Tolyl Red Comparator Slide PCN 0425-01-8 REAGENTS (10.0 to 11.6 pH range)Nessler Tubes, 3 Short, 150mm PCN 0423-01-2 Included in the Ultratest® 6 Month Reagent SetGraduated Cylinder, 100ml, Plastic PCN 0410-01-9 (PCN 0437-02-1)Dropper Pipettes, Plastic, marked at 0.5ml (cc) PCN 0411-01-7 1 x 500ml Phthalein Red PCN 0481-01-0 and 1.0ml (cc) 1 x 500ml Tolyl Red PCN 0486-01-0Stirring Rod, 150 mm, Plastic PCN 0417-01-5Bottle, 60ml (2 oz.), Glass, with dropper PCN 0433-01-1 (for Phthalein Red Indicator)Bottle, 60 ml (2 oz.), Glass, with dropper PCN 0434-01-9 (for Tolyl Red Indicator)

PROCEDURE

1. Fill the two outside Nessler Tubes (end tubes B&D) to the 150 mm mark withuntreated sample water and place in the outside compartments of the WaterAnalyzer Base.

2. Rinse the center Nessler Tube (C) with a small amount of boiler water.

3. Measure exactly 75 ml of sample in the 100 ml graduated cylinder, and addto this exactly 0.5 ml (cc) of the appropriate pH indicator (using dropperpipette). Stir thoroughly with the stirring rod to obtain uniform color through-out.

4. Put treated sample (from Step 3) into the center Nessler Tube (C), addingonly enough to bring the level in the tube to the 150 mm mark. Place this tubein the center compartment.

5. Place the appropriate pH comparator slide in the slot in the support base.Determine the pH according to the General Instructions for the WaterAnalyzer on page 5.

6. Record the pH value on the Onboard Graphing Log.

7. Compare test results to those on the Control and Dosing Chart. Adjust thepH of the boiler water with GCTM concentrated alkaline liquid as necessary.

Control Limits 60-84 kg/cm2

(850-1200 psig)

9.8-10.2 boiler water

D

UntreatedCondensate

3

1 & 4

Untreated

Condensate

50

pH TEST (METER)FOR HIGH PRESSURE BOILER SYSTEMS

Control Limits 60-84 kg/cm2

(850-1200 psig)

9.8-10.2 boiler water

51

APPARATUS REAGENTS

PORTABLE pH METER PCN 0246-01-8 pH Buffer 7 (500ml) PCN 6255-09-6Low Maintenance Triode pH Electrode PCN 0246-02-6 pH Buffer 10 (500 ml) PCN 6444-09-5

pH Electrode Storage Solution PCN 0246-03-4 (500ml)

PROCEDURE (Boiler Water)

Two Point Autocalibration (Weekly)

1. Attach the pH Electrode to the meter.2. Press the "power" button to turn the meter on.3. Place the electrode into pH buffer 7 solution.4. Press the "mode" button until CALIBRATE is displayed.5. Press the "no" button until the buffer sequence 7-10 is displayed and then press the "yes" button.6. The buffer chosen will be displayed in the main field, P1 will be displayed in the lower field, and an arrow in the bottom

of the display will point to "7".7. When ready is displayed, press the "yes" button. P2 will then be displayed in the lower field and an arrow in the bottom

of the display will point to "10". This indicates that the meter is ready for the second buffercalibration using a pH buffer 10 solution.

8. Rinse the electrode with distilled water and place into pH buffer 10 solution.9. When ready is displayed, press the "yes" key. The meter will automatically advance to the MEASURE mode.

Sample pH Measurement (Daily)

1. Rinse the electrode with distilled water.2. Place the electrode into the sample.3. Record the reading when ready is displayed.4. Both the temperature corrected pH reading and temperature reading are displayed.

Electrode Storage

For short-term (up to one week) electrode storage, soak the electrode in pH Electrode Storage Solution.

For long-term (greater than one week) electrode storage, rinse the electrode with distilled water and remove any saltbuildup or deposits. Cover the end of the electrode with the protective cap and store dry.

Consult the Orion Instruction Manual for more information.

Not a Required Test for Medium to Low Pressure Boilers

pH TESTCONDENSATE

MEDIUM AND LOW PRESSURE BOILER SYSTEMSUSING STANDARD TREATMENT

Control Limit 0-60 kg/cm2

(0-850 psig)

1-2 drops orpH 8.3-8.6

This test can be performed with the indicators and acids already available in the testing program. The proceduresdiffer slightly because of acid strengths.

The desired pH in a condensate system is 8.3-8.6 because this is the least corrosive pH for nonferrous metals ofconstruction. This pH is in the same range as the endpoint of phenolphthalein. If the addition of phenolphthaleinturns the sample pink, then it is sufficiently alkaline. To be sure that the water is not excessively alkaline, we backtitrate with acid. If a very small amount of acid is needed to reach the endpoint in these titrations, then we can saythat the pH of the condensate is in the proper range.

APPARATUS REAGENTS

LP Alkalinity Titration Assembly PCN 0380-01-4 N/10 Sulfuric Acid, 500 ml PCN 0319-09-6Graduated Cylinder, 50 ml PCN 0237-02-5 Phenolphthalein Indicator, 120 ml PCN 0311-01-9Evaporating Dish PCN 0218-01-7Plastic Stirring Rod PCN 0417-01-5

PROCEDURE

53

1. Collect 50ml cooled condensate sample and pour intoevaporating dish.

2. Add 3 drops phenolphthalein. Sample should turn pink.

3. Add sulfuric acid N/10 drop by drop until pink colordisappears.

4. Record results on the Onboard Graphing Log and adjustSLCC-ATM treatment dosage as necessary.

1

2

3

pH TESTCONDENSATE

FOR HIGH PRESSURE BOILER SYSTEMS

54

APPARATUS REAGENTS

(1) Beaker, 100ml , PCN 0247-01-6 (1) Phenolphthalein, 120ml, PCN 0311-19-1(1) Stirring Rod, PCN 0417-01-5 (1) N/50 Sulfuric Acid, 1000ml, PCN 0485-01-2

PROCEDURE

1. Obtain a cooled 50ml condensate sample and add2-3 drops of phenolphthalein.

2. Add N/50 Sulfuric Acid dropwise, counting drops,until the pink color disappears.

3. Record results on the Onboard Graphing Log.

4. Record results on the Onboard Graphing Log andadjust SLCC-ATM treatment dosage as necessary.3

1

Control Limit 60-84 kg/cm2

(850-1200 psig)

1-2 drops or pH 8.6-9.0

PHOSPHATE TESTFOR HIGH PRESSURE BOILER SYSTEMS

Control Limit 60-84 kg/cm2

(850-1200 psig) 15-25 ppm

PHOSPHATE VACU-VIALS2 TEST KIT (PCN 0390-01-3) INCLUDES:

1 Photometer30 Vacu-Vials (PCN 0390-02-1)1 Sample Cup1 Light Shield1 Test Tube1 Blank Vacu-Vial

PROCEDURE

Read Material Data Sheet before using. Do not snap the ampoule tip in air or in any liquid except water.NOTE: Filter a cooled boiler water sample before running this test. Filter paper and funnel are supplied separately.

55

1 2

33

4 5

05:00

1. Fill the sample cup to the 25 ml mark with cooled, filteredboiler water.

2. Place the phosphate VACU-VIALS ampoule in the samplecup. Snap the tip by pressing the ampoule against theside of the cup. The ampoule will fill, leaving a smallbubble to facilitate mixing.

3. Mix the contents by inverting the ampoule, showing thebubble to travel from end to end. Wipe all liquid from theexterior. Wait 5 minutes.

4. Press ON. When the display shows “---”, the photometeris ready.

5. Zero the photometer by inserting the VACU-VIALS blankampoule into the cell compartment, aligning the verticalline on the ampoule with the water droplet on the photom-eter. Cover the ampoule with the light shield. Press theZERO button. The display will show “S1P” momentarily,then it will read “-0.0-”.

6. After the 5 minute wait required in step 3, insert thephosphate VACU-VIALS ampoule with proper cell align-ment into the cell compartment. Cover the ampoule withthe light shield. Press the READ button. The meter willshow “S1P” momentarily, then it will display the test resultin ppm ortho phosphate as PO

4.

7. Record the results on the Onboard Graphing Log andadjust the ADJUNCT® B treatment dosage as necessary.

PHOSPHATE TESTFOR MEDIUM TO LOW PRESSURE BOILER SYSTEMS

Before testing, sample must be cooled to 25OC (77OF) by collecting through a sample cooler for safety and toprevent flashing which concentrates the sample.

NOTE: Filter the boiler water sample before running this test. Filter paper and funnel are supplied separately.

APPARATUS

Boiler Phosphate Ampoule Test Kit (Product Code #1AA0003) contains:• 1 comparator • 1 set of instructions• 1 snap cup • 30 ampoules

Boiler Phosphate Ampoule Refill (Product Code #1AA0004) contains:• 30 ampoules

Filter Paper, box of 100 sheets P/C #0225-01-2Funnel, Plastic P/C #0221-01-0

PROCEDURE

56

1. Fill the sample cup to the 25 ml mark with sample (Figure 1).

2. Place the Boiler Phosphate ampoule’s tapered tip into one ofthe four depressions in the bottom of the sample cup. Snapthe tip by squeezing the ampoule toward the side of the cup.The sample will fill the ampoule and begin to mix with reagent(Figure 2).

3. Remove the Boiler Phosphate ampoule from the cup. Mix thecontents of the ampoule by inverting it several times allowingthe bubble to travel from end to end each time (Figure 3).

4. Wipe all liquid from the exterior of the ampoule and wait 5minutes for full color development (Figure 4).

5. When using the comparator, be sure it is illuminated by awhite light directly above the comparator. The filled BoilerPhosphate ampoule should be placed between the colorstandards for viewing. It is important that the ampoule becompared by placing it on both sides of the standard tubebefore concluding that it is darker, lighter or equal to thestandard (Figure 5).

6. Record the results on the Onboard Graphing Log and adjustproduct dosage as necessary.

Figure 1

Figure 2

05:00

Figure 4

Figure 5

15

10

20

25

5

mL

Figure 3

Control LimitsAGK® 100 & DREWPLEX® AT Programs

10-20 ppmStandard Treatment Programs

0-60 kg/cm2

(0-850 psig)20-40 ppm

SILICA TESTFOR HIGH PRESSURE BOILER SYSTEMS

Not a Required Test for Medium to Low Pressure Boilers.

SILICA AMPOULE TEST KIT (PCN 0376-01-3) INCLUDES:

30 Ampoules2 x A-9000 Neutralizer Solution2 x A-9001 Activator Solution1 Cylindrical Comparator, 0-1 ppm1 Flat Comparator, 1-10 ppm1 Sample Cup

Included in the ULTRAMARINESM 6 Month Reagent Set (PCN 0437-04-7)

PROCEDURE

NOTE: If the sample is colored or turbid, it should be filtered before testing.

57

1. Fill the sample cup to the 15 ml mark with sample(Figure 1).

2. Add 10 drops of A-9001 Activator Solution (Figure 2). Capthe sample cup and shake it to mix the contents well. Wait 4minutes.

3. Add 5 drops of A-9000 Neutralizer Solution (Figure 2). Capthe sample cup and shake it to mix the contents well. Wait 1minute.

4. Place the silica ampoule's tapered tip into one of the fourdepressions in the bottom of the sample cup. Snap the tip bysqueezing the ampoule toward the side of the cup. Thesample will fill the ampoule and begin to mix with reagent(Figure 3).

5. Remove the silica ampoule from the cup. Mix the contents ofthe ampoule by inverting it several times allowing the bubbleto travel from end to end each time.

6. Wipe all liquid from the exterior of the ampoule and wait2 minutes for full color development.

7. After 2 minutes, use the comparator to determine the level ofsilica in the sample.

a. When using the lower range comparator (0-1.0 ppm),place the silica ampoule, flat end downward into thecenter tube of the comparator. Direct the comparatortoward a source of bright white light while viewing fromthe bottom. Hold the comparator in a nearly horizontalposition and rotate it until the color standard below thesilica ampoule shows the closest match (Figure 4).

b. When using the high range comparator (1-10 ppm), besure it is illuminated by a white light directly above thecomparator. The filled silica ampoule should be placedbetween the color standards for viewing. It is importantthat the silica ampoule be compared by placing it on bothsides of the standard tube before concluding that it isdarker, lighter or equal to the standard (Figure 5).

8. Record the results on the Onboard Graphing Log.

4

5

3

21

Control Limit 60-84 kg/cm2

(850-1200 psig) 6 pm maximum

SULFITEFOR MEDIUM AND LOW PRESSURE BOILER SYSTEMS

58

DREW MARINE SULFITE TITRETS2 (P/C #0377-01-1) INCLUDES:

• 30 Titrets • 1 Sample Cup• 30 Valve Assemblies • 1 Set of Instructions• 1 A-9600 Neutralizer Solution

PROCEDURE

NOTE: If the sample is colored or turbid, it should be filteredbefore testing.

1. Fill the sample cup to the 25 ml mark with sample (Figure 1).

2. Add 5 drops of A-9600 Neutralizer Solution (Figure 2). Stirlightly and briefly. Wait 30 seconds.

3. Slide the open end of the valve assembly over the tapered tip ofthe Titrets1 so that it fits snugly to the Reference Line (Figure 3).

4. Snap the tip of the Titrets at the Score Mark (Figure 4).

5. With the tip of the valve assembly immersed in the sample,squeeze the bead valve briefly to add a small amount ofsample to the Titrets (Figure 5). The colorless indicator in thevalve assembly will also be added to the Titret.

CAUTION: Do not squeeze the bead valveunless the tip of the valve assembly is immersed below thesurface of the liquid.

6. Rock the Titrets to mix the contents. The contents of theTitrets will turn a DEEP BLUE color. Wait 30 seconds.

7. Continue to add small amounts of sample until the liquid inthe Titrets turns from BLUE TO COLORLESS. Be sure torock the Titret to mix the contents after each addition ofsample. When the color of the liquid in the Titrets changes toCOLORLESS, the end point has been reached. Stop thetest, hold the Titrets with its tip pointed upward and read thescale opposite the liquid level to obtain the test results in ppmsulfite as SO3 (Figure 6).

8. Record the results on the Onboard Graphing Log and adjustproduct dosage as necessary.

Figure 1

Figure 4

Figure 2

Figure 5

Figure 6

ReferenceLine

ScoreMark

BeadValve

ValveAssembly

Figure 3

→→

←

→

Control Limit0-32 kg/cm2 36-60 kg/cm2

(0-450 psig) (450-850 psig)

20-30 ppm 10-15 ppm

COOLING WATER SYSTEMS AND TREATMENTINTRODUCTION

Cooling water circuits on motor vessels encompass sev-eral different types of systems. Of primary concern to usare the cooling water systems for main and auxiliary en-gines and air conditioning systems. While we will mentionrefrigeration brine systems briefly in our discussions, wewill not include them or seawater cooling systems exceptto say that fouling of these units will lead to overheatingand ultimate system failure. Chemical and mechanicaltreatments* of these systems are available, but will not bediscussed at this time.

Marine diesel engines have continually undergone im-provement in performance ratings and power to weightratios. These design changes often increase the com-plexity of the system. Where ferrous and some cuprousmetals were the standard of the past construction for me-dium and slow speed engines, today’s designs are begin-ning to utilize a wider variety of metals including alumi-num components.

Improved performance characteristics have subjected thecylinder liners, covers and pistons to higher temperatures,pressures and heat transfer rates. These factors in com-

bination with the variety of metals in use have created achallenge for the efficiency of the cooling water systemsand the capability of chemical treatments formulated forthem.

The higher engine temperatures result in accelerated min-eral deposition rates on the water side. Because of thedesign of diesel engines, the use of high quality makeupwater is the best means of controlling scale formation. Asa result, the use of distilled water as the coolant has be-come essential. However, untreated distilled water is manytimes more corrosive to metals than a water with a degreeof contamination and it has therefore become an opera-tional and economic necessity to treat the engine coolingwater with a corrosion inhibitor.

Testing of treated cooling water is a vital part of the treat-ment program and the required test procedures will bediscussed at the end of this section.

Contact your local Drew representative for more informa-tion about the use of corrosion inhibitors andAMERSPERSE® 280 seawater cooling treatment in thesesystems.

The importance of an efficient engine cannot be overstated.The temperature of the gases produced during combus-tion exceed the melting point of case iron and, withoutcooling, the piston and other metal parts would fuse andeventually seize. This is the result of overheating in theextreme. However, even if actual melting does not occurthere can be substantial loss of the metal’s strength andductility which can lead to premature failure. Lube oil filmsalso can be destroyed by overheating, leading to wear,deposits and premature system failure.

Diesel engines can be cooled with water or air heat ex-change equipment. The most commonly used medium inthe commercial marine market is water. Its treatment is ofprimary concern to us.

There are three main systems in a diesel engine whichrequire cooling: the engine jacket, the piston areas andthe fuel valves. The cooling water system can be one largeclosed loop with main circulating pumps and a commonhead tank or there can be three separate cooling watercircuits employed to independently cool the cylinder jacket,piston, and fuel valve. The systems can be cross-con-nected in the event of equipment failure so that the cool-ing load can be picked up by another system. Conversely,cooling circuits also can be isolated if contamination isencountered. Consideration of each system design andthe metals of construction is important in deciding on thetype of treatment to be used and how and where it shouldbe dosed.

The cooling water enters at a low point in the cooling cir-cuit and flows upward to exit at the top of the engine. Thisarrangement minimizes the formation of air pockets whichprevent the proper wetting of metal surfaces. This inter-rupts proper heat transfer and allows overheating to oc-cur.

The hot water is extracted and passed through a heatexchanger system where the heat energy is passed to asecondary coolant, often seawater. The cooled water isthen recirculated back to the engine to complete the“closed” circuit.

This heat exchange process also can provide heat forevaporators and auxiliary systems. Many modern motorvessels are equipped with evaporators that use the dieselengine cooling water as a primary heat source to gener-ate distilled water at minimum cost. After passing throughthe evaporator, the cooling water may continue throughanother heat exchanger to further utilize the energy avail-able and control the water inlet temperature to the dieselengine systems. Because of the space considerationsand economic factors, the design of marine plants ofteninterrelates a number of systems to maximize the efficiencywhich could be discussed at length. However, that is notthe central topic of this discussion. Instead, the preven-tion of scale and corrosion in these various systems is.

COOLING WATER SYSTEM CIRCULATION

59

Chemical Treatment

Inhibitors are chemicals that protect metals by creating abarrier between the water and the metal or by reactingwith the metal surface to form a thin protective or passiva-tion film which makes the metal underneath more resis-tant to attack.

Soluble oil is a barrier type inhibitor which functions wellup to the point of breakdown when deposits may form.Other barrier-type inhibitors, such as silicates which func-tion well in ambient temperatures, interfere with heat trans-fer and are not applicable in engine cooling systems.

Most protective films are so thin that they cannot be seenand they do not interfere with heat transfer. They areformed by the chemical combination of the inhibitor andthe metal surface and tightly adhere to the metal. The filmcan be damaged or torn away by water flow. However, aresidual of inhibitor is maintained in the water so that if theprotective film is damaged in any way, the film is rapidlyrepaired.

Modern chemicals are normally a nitrite-borate-organicmixture. Nitrite is a film forming inhibitor. The nitrite pri-marily protects against corrosion of the ferrous metals ina cooling water system. Other inhibitors are included inthe formulation designed to minimize corrosion of nonfer-rous metals. Borate is included to adjust pH to aid in cor-rosion inhibition and to provide the proper environment forthe reaction of nitrite.

Where cavitation erosion is known to exist, there is someevidence that large doses of corrosion inhibitors will re-duce the erosion.

Special formulations are available for medium and high-speed diesel engines which combine nitrite-borate organiccorrosion inhibitors and polymeric scale inhibitors.

In the past, buffered chromate treatment was the primaryinhibitor but this approach has lost favor due to environ-mental concerns and the toxicity of chromate. Chromateis still used in refrigeration brine systems where other in-hibitors are not very effective.

In systems where glycol antifreezes are needed, nitriteborate treatments should be used because they are com-patible with the glycol. Chromate should not be used withglycol because of a reaction which forms a “curd-like” pre-cipitate.

60

TYPES OF CORROSIONAND PREVENTATIVE MEASURES

Distilled water is desirable for scale prevention but it isvery aggressive in itself. In addition, other corrosionmechanisms are at work in the system.

Oxygen Pitting: Dissolved oxygen is a primary cause ofcorrosion and is involved in practically all corrosion pro-cesses.

Cooling water is not deaerated. Although there are airrelease units in the circuit, the water usually contains amuch higher concentration of dissolved oxygen than doesboiler feed water. The cooling water is exposed to the airwhile in open head tanks and air contains 20% (200,000ppm) oxygen.

The amount of oxygen that the water contains is depen-dent upon the temperature of the water since cold waterwill dissolve more oxygen than hot water. Some oxygen isbrought in by makeup water additions and inleakage atseals or other points throughout the mechanical system.

Cavitation: Because of engine vibrations and high im-pingement flow conditions, metal parts of the cooling sys-tem can be damaged by cavitation corrosion/erosion. Cavi-tation damage appears as shallow pitting or gouging ofthe metal surface, but, unlike oxygen attack it is causedby mechanical as well as chemical conditions.

High frequency vibration, high velocity flow conditions, orchanges in temperature which cause a localized reduc-tion in water pressure below the vapor pressure can leadto cavitation/erosion. In these areas of low pressure,bubbles of vapor will form next to the metal surface. Asthe pressure returns to normal, the bubble collapses strik-ing the metal with great force (hundreds of kilograms/cen-timeter2 or thousands of pounds/inch2). The protectivefilm is destroyed leading to further corrosion. This actionis repeated in a cycle that erodes the metal surfaces.

Acid Attack: Acid attack is brought about by low pH wa-ter. Some minerals and gases can, when dissolved in thewater, produce acid which lowers the pH and causes cor-rosion. Not only will the acidic water be more corrosive tothe metal, it will not be an environment in which the mod-ern cooling water corrosion inhibitors will be effective.

CORROSION OF METALS

COMPOSITION AND FORMATION OF DEPOSITS

DEPOSIT FORMATIONAND PREVENTATIVE TREATMENT

Scale Deposits: The diesel engine has a very low toler-ance for mineral scale buildup. Calcium and magnesiumcompounds will form scale in high heat transfer sectionsof the cooling water system. Calcium carbonate and sul-fate salts are the first to deposit because their solubilitydecreases as the water temperature increases.

Mineral scales are hard and dense and are excellent in-sulators. Their presence drastically reduces heat trans-fer. For example, one mm of calcium sulfate (CaSO

4) scale

is equivalent as a heat transfer barrier to 40 mm of metal.The effect of scale on heat transfer characteristics is illus-trated in the following diagram.

Effect of Scale

Scale often allows corrosion to progress underneath thedeposits which can ultimately lead to system failure. Thistype of corrosion is more fully described in the Boiler Wa-ter Systems and Treatment section.

Scale-forming minerals may be introduced by seawaterinleakage or by the use of poor quality makeup. Distilledwater is the recommended makeup to minimize scale for-mation. On ships which do not produce or have an inad-equate supply of distilled water, fresh water from a shoresupply is used. Shore water is not preferred because itcontains varying amounts of scale-forming constituentsand other contaminants.

Oil Deposits: Soluble oils are used as treatments in somecooling systems, especially in the piston cooling circuits.If overheating occurs due to reduced circulation or over-load conditions, the soluble oil may decompose and canform deposits. These oils are not truly “soluble,” but areemulsions which breakdown in time with the same unde-sirable result as any oil contamination would cause in acooling system.

The cooling water may become contaminated by fuel orlubricating oils. The insulating effects of oil deposits onheat transfer surfaces are the same as mineral scale de-posits.

As with all other contaminants, the source of oil inleakageshould be located and eliminated. The entire cooling sys-tem should be cleaned with a solvent cleaner at the earli-est opportunity. HDE-777TM heavy duty emulsifier is aneffective cleaner for the purpose. Light to medium oilydeposits combined with scale and oxide deposits can beremoved using AMEROlD® OSC one-step cleaner. (Thereare other maintenance chemical cleaner choices. Con-sult your local Drew Marine representative for specific rec-ommendations.)

Mechanical Correction

The only means of mechanically preventing scaling is byremoving minerals before the makeup water enters theengine system. The evaporator, a bank of reverse osmo-sis units or a demineralizer must be operated efficiently toprovide high quality make up. Shore water can be used ifthe needed volume of high quality water is not available,but, as stated above, it is not preferred because its qualityis poor and so variable around the world. However, if it isused, an analysis of the water should be obtained fromthe supplier and/or a local governmental office.

Chemical Correction

The antiscalant chemicals used in boiler water treatmentare not applicable for diesel engine systems because thereis no practical method to blow down a diesel cooling watersystem to remove the normal sludges formed by a boilerwater treatment process. The sludges can block smallcooling passages in the system restricting water flow andcompounding the problems of overheating.

Treatments are now available which contain polymericantiscalants which can sequester and disperse a certainamount of hardness. Unlike the phosphate-alkalinity treat-ments common to boiler water treatments, the polymersin modern cooling water treatments will hold hardness con-stituents in suspension until they can be removed by bleedoff.

61

COMBUSTIONSIDE

(A) Clean Cylinder Wall

WATERSIDE

COMBUSTIONSIDE

TEMPGRADIENTACROSS

25 MMLINER

570OC

270OC

70OC

TEMPGRADIENTACROSS

25 MMLINER

TEMPGRADIENTACROSS

1 MMSCALE

(B) 1mm Mineral Scale onWaterside

WATERSIDE

DEWT® NC diesel engine water treatment is a nitrite-borate type corrosion inhibitor used in closed cooling watersystems. This low toxicity product is particularly applicablein diesel engine cooling water circuits, where the jacketwater is the heat source for the evaporators which producepotable water. DEWT NC treatment has no deleteriouseffects on glands, seals, rubber hoses, valve packing, etc.It is compatible with antifreeze materials and will not formobjectionable sludges.

MAXIGARD® diesel engine water treatment is a multi-functional liquid blend of nitrite-borate-organic corrosioninhibitor and mineral deposit modifiers. MAXIGARD treat-ment is specially formulated for the closed cooling water

systems in medium and high speed diesel engines. It issuitable for distilled or fresh water systems with or withoutantifreeze chemicals. MAXIGARD treatment is safe foruse in systems where jacket water is the heat source forthe evaporators which product potable water supplies.

LIQUIDEWTTM cooling water treatment is a multi-functional liquid blend of nitrite-borate-organic corrosioninhibitor and mineral deposit modifiers for scale preven-tion. LIQUIDEWT treatment is formulated for use inmedium speed diesel engines. This product can be usedin both distilled and shore waters. It has low toxicity andis compatible with glycol antifreezes. Glycol is used as anantifreeze only--it is not a corrosion inhibitor.

COOLING WATER TREATMENT CHEMICALS

COOLING WATER TREATMENTCHEMICAL APPLICATIONS AND CONTROLS

SYSTEM APPLICATION CONTROL LIMITS

High and medium speed MAXIGARD cooling water treatment to 20,000 ppmdiesel engines minimize corrosion and prevent deposition

compatible with glycol antifreeze.MAN/B&W Medium Speed4-Stroke Engines 40-43,000 ppm(L&V32/40; L40/54; L&V48/60; L58/64)

Medium and slow speed DEWT NC cooling water treatment to 3,000 - 4,500 ppmdiesel engines minimize corrosion compatible with

glycol antifreeze.MAN/B&W Medium Speed4-Stroke Engines 4,500-4,900 ppm(L&V32/40; L40/54; L&V48/60; L58/64)

Medium and slow speed LIQUIDEWT cooling water treatment to 10,000 ppmdiesel engines minimize corrosion and prevent deposition.

Compatible with glycol antifreeze.MAN/B&W Medium Speed4-Stroke Engines 15-17,000 ppm(L&V32/40; L40/54; L&V48/60; L58/64)

COOLING WATER TREATMENT CONTROL TESTS AND DOSAGE REQUIREMENTS

Because the cooling water system is an essential part ofthe diesel engine, a carefully controlled water treatmentprogram is essential for the efficient operaton of theengine. The water treatment program is monitored bymeans of a few simple tests. The control tests are thebasis on which the chemical dosage is adjusted.

The following pages outline the test procedures which areused in conjunction with the Drew cooling water treat-ments. In some instances, an additional chloride determi-nation of the water may be desirable. The chloride testprocedure on page 42 can be used for DEWT NC treatedsystems. This method is not recommended for coolingwater treated with MAXIGARD diesel engine water treat-ment or LIQUIDEWT cooling water treatment withoutSample Pretreatment. See page 66 for Sample Pretreat-ment procedure.

As in the steam generating system, the accuracy of thetest results is dependent upon proper sampling, testing,and recording procedures as well as the corrective action

taken. Refer to the General Information section beforeproceeding with any of the tests.

Testing Frequency

Testing and chemical dosing should be done on a regularbasis. The test should be conducted 24 hours after theinitial dosage and once a week thereafter unless a prob-lem is suspected.

If abnormal water loss and makeup or other problems areknown to exist, then the test results will probably be lowand should be used compared with a control and dosingchart to increase treatment levels. Dose, allow time forcirculation (approximately 30 minutes) and retest untiltreatment levels are satisfactory.

If treatment levels are high, suspend dosage. Althoughnot normally necessary, you may wish to bleed off somecooling water and makeup with untreated water to dilute.

62

63

For use with LIQUIDEWTTM cooling water treatment, MAXIGARD® diesel engine water treatment, andDEWT® NC diesel engine water treatment.

CWT TITRETS (PCN 0367-01-2) INCLUDES:

1 Titrettor3

30 Titrets (contains reagent)1 Sample Vial1 Instruction Sheet30 Valve Assemblies (contains reagent)

PROCEDURE

ValveAssembly

Score Mark

Reference Line

Ampoule 1

Snap thetip at thescore mark

2

1. Slide the open end of the valve assembly over the tapered tip of theTitret so that it fits snugly to the Reference Line.

2. Snap the tip of the Titret at the Score Mark and proceed with the regulartest instructions below or use the Titrettor assembly as covered onpage 5.

3. With the tip of the sample pipe immersed in the sample, squeeze thebead valve briefly to pull in a small amount of sample. CAUTION: Donot squeeze the bead valve unless the sample pipe is immersed belowthe surface of the liquid or vacuum will be lost and the test ruined.

4. Rock the Titret to mix the contents. The first addition of sample will pullin the reagent in the ampoule. The contents of the ampoule will turn aGREEN color.

5. Continue to add small amounts of sample water until the liquid in theTitret turns from GREEN to a bright ORANGE.* When the ORANGEcolor appears, the end point has been reached. Stop test, hold the Titretwith its tip pointed upward and read liquid level. Check the control anddosing chart below for the appropriate product concentrations.

*NOTE: Immediately before the end point is reached, the contents willturn BLUE. Make further additions with care.

CWT TESTTITRET2 METHOD

Satisfactory Ranges

Product Scale PPM, Product Initial Dosage

LIQUIDEWT 1.2-1.8 10,000-15,000 8 ltr/ton (2.13 gal/ton)MAXIGARD 1.6-3.5 20,000-40,000 16 ltr/ton (1.6 gal/ton)DEWT NC 3.5-5.0 3,000- 4,500 3.2 kg/ton (7 lbs/ton)

Control and Dosing Chart

Below Satisfactory Increase DosageSatisfactory Maintain DosageAbove Satisfactory Decrease Dosage

MAN/B&W Medium-Speed 4-Stroke EnginesModels: L&V32/40 L40/54 L&V48/60 L58/64

Satisfactory RangesProduct Scale PPM, Product Initial Dosage

LIQUIDEWT 1.8-2.0 15,000-17,000 3.0 ltr/tonMAXIGARD 3.3-3.6 40,000-43,000 3.3 ltr/tonDEWT NC 5.6-5.8 4,500 - 4,900 4.5 kg/ton

To test makeup water for hardness using the Titret method, see page 48.

TEST FOR DEWT® NCdiesel engine water treatment

1. Draw a cooling water sample from a full flowing part of the systeminto the graduated mixing cylinder to the 25 ml mark.

2. Add 5 level measuring spoons of DEWT NC Reagent No. 1 and mixuntil all of the reagent is dissolved.

3. Add 1 level measuring spoon of DEWT NC Reagent No. 2, stopperthe mixing cylinder, and thoroughly mix.

4. If the sample turns purple-red and the color lasts for at least 30seconds, the test indicates that the treatment level is below 50 ppm.

However, if the color disappears within 30 seconds, add additionalReagent No. 2, one level measuring spoon at a time (countingspoonfuls) with thorough mixing until the purple-red color persistsfor over 30 seconds.

5. To determine the concentration of DEWT NC, count the totalnumber of measuring spoons of Reagent No. 2 added and convertto ppm.

Calculation: ppm DEWT NC = (number of spoons -1) x 500

6. Record results as pm DEWT NC on the onboard graphing log.

7. Determine the dosage of DEWT NC diesel engine water treatmentrequired per ton of circulating water as indicated on the DosageRequirement Chart which follows:

DEWT NC TEST KIT (PCN 0302-01-8) INCLUDES:

Graduated Cylinder, with Stopper, 50 ml PCN 0236-01-9 DEWT NC Reagent No. 1, 100 gms PCN 0306-01-0Brass Measuring Spoon, 0.2 gm PCN 0224-01-4 DEWT NC Reagent No. 2, 100 gms PCN 0307-01-8

PROCEDURE

DOSAGE REQUIREMENT CHART - DEWT NC

TOTAL NUMBER OF ppmMEASURING SPOONS OF OF DEWT NC DOSAGE REQUIREMENT PER REAGENT NO. 2 USED RECORDED TON OF CIRCULATING WATER

1 None 3.2 kg (7 lbs.) 2 500 2.7 kg (6 lbs.) 3 1000 2.3 kg (5 lbs.) 4 1500 1.8 kg (4 lbs.) 5 2000 1.4 kg (3 lbs.) 6 2500 0.9 kg (2 lbs.) 7 3000 Satisfactory - No Dose Required. 8 3500 Satisfactory - No Dose Required. 9 4000 Satisfactory - No Dose Required.10 4500 Satisfactory - No Dose Required.11 5000 High - No Dose Required.

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TEST FOR DEWT® NCdiesel engine water treatment

(continued)

65

DEWT NC TEST KIT (PCN 0302-01-8) INCLUDES:

Graduated Cylinder, with Stopper, 50 ml PCN 0236-01-9 DEWT NC Reagent No. 1, 100 gms PCN 0306-01-0Brass Measuring Spoon, 0.2 gm PCN 0224-01-4 DEWT NC Reagent No. 2, 100 gms PCN 0307-01-8

DOSAGE REQUIREMENT CHART - DEWT NC

TOTAL NUMBER OF ppmMEASURING SPOONS OF OF DEWT NC DOSAGE REQUIREMENT PER REAGENT NO. 2 USED RECORDED TON OF CIRCULATING WATER

1 None 4.5 kg (10.0 lbs.) 2 500 4.0 kg (8.8 lbs.) 3 1000 3.5 kg (7.7 lbs.) 4 1500 3.0 kg (6.6 lbs.) 5 2000 2.5 kg (5.5 lbs.) 6 2500 2.0 kg (4.4 lbs.) 7 3000 1.5 kg (3.3 lbs.) 8 3500 1.0 kg (2.2 lbs.) 9 4000 0.5 kg (1.1 lbs.)10 4500 Satisfactory - No Dose Required.11 5000 Satisfactory - No Dose Required.12 5500 High - No Dose Required.13 6000 High - No Dose Required.14 6500 High - No Dose Required.

MAN/B&W Medium-Speed 4-Stroke EnginesModels: L&V32/40 L40/54 L&V48/60 L58/64

Chloride Sample Pretreatment

SAMPLE PRETREATMENT SHOULD BE USED WHEN TESTING FOR CHLORIDE IN COOLING WATERTREATED WITH MAXIGARD® DIESEL ENGINE WATER TREATMENT OR LIQUIDEWTTM COOLING WA-TER TREATMENT.

APPARATUS AND REAGENTS

Drew Chloride LMP Test Kit PCN 0373-01-9Sample Pretreatment, 50 gm PCN 0374-02-5 (includes 0.5 gm scoop)Filter Paper, Box of 100 PCN 0225-01-2Funnel, Plastic PCN 0221-01-0Stirring Rod, Plastic, 150mm PCN 0417-01-5

PROCEDURE

1. Add one scoop (0.5 gm) of Sample Pretreatment to approximately 70 ml of cooling water and stir well.

2. Let stand for two minutes to allow precipitate to settle.

3. Filter the sample and proceed with the chloride determination using the Drew Chloride LMP Test Kit as shown onpage 42.

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All statements, information and data presented herein are believed to be accurate and reliablebut are not to be taken as a guarantee, express warranty or implied warranty of merchantabilityor fitness for a particular purpose, or representation, express or implied, for which sellerassumes legal responsibility, and they are offered solely for your consideration, investigationand verification. Statements or suggestions concerning possible use of this product are madewithout representation or warranty that any such use is free of patent infringement and are notrecommendations to infringe on any patent.

©2001 Inc. All Rights Reserved.®Registered trademark, TMTrademark of Ashland Inc. SMService Mark of Ashland Inc.*Responsible Care and the Responsible Care logo are registered service marks of the AmericanChemistry Council in the U.S., of the Canadian Chemical Producers’ Association in Canada andof different entities in other countries.1Registered trademark of Biotal, Inc. 2Registered trademark of CHEMetrics, Inc. 3Trademark of CHEMetrics, Inc.

One Drew PlazaBoonton, NJ 07005 USATelephone: (973) 263-7600FAX: (973) 263-4491/7463Web Site: www.drew-marine.comE-mail: drewmarine@ashland.comEmergency Safety #: (1-800-ASHLAND) U.S.Outside U.S.: (606) 324-1133

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