Drew Marine Division
SHIPBOARD WATER TREATMENT MANUAL 4.1 Edition
ENGINE COOLING SYSTEM
EVAPORATOR/ DISTILLER SYSTEM
BOILER SYSTEM
EXHAUST SYSTEM
TM-WT-1 (11/01)R7
SHIPBOARD WATER TREATMENT MANUAL 4.1 EDITION
Marine Chemical Products BOILER WATER TREATMENT ®
ADJUNCT B phosphate boiler water treatment AGK ® 100 boiler and feedwater treatment AMERZINE ® corrosion inhibitor CATALYZED SULFITETM corrosion inhibitor DREWTM BWT-3 boiler water treatment DREW BWT-4 boiler water treatment GCTM concentrated alkaline liquid SLCC-ATM condensate corrosion inhibitor LIQUID COAGULANT TM boiler sludge conditioner
PERFORMANCE BOILER WATER TREATMENT DREWPLEX ® AT boiler water treatment DREWPLEX OX corrosion inhibitor
EVAPORATOR TREATMENT AMEROYAL ® evaporator treatment AMEROYAL ® CF concentrated evaporator treatment AMEROYAL CF/HG concentrated evaporator treatment
MAINTENANCE CHEMICALS (cont'd) FERROCLEAN ® cleaning agent HDE-777TM heavy duty emulsifier NEVAMELTTM wire rope conditioner O&GRTM oil and grease remover OSD/LTTM oil spill dispersant SAF-ACIDTM descaling compound
ENVIRONMENTAL CHEMICALS DREW ELECTRIC TM 2000 motor and parts cleaner DREWCLEAN 2000 quick breaking degreaser SNCTM 2000 carbon remover
SANITATION PRODUCTS AMEROID ® MSD-PAK organic waste treatment BIOTAL1 MDS 2000 shipboard waste treatment BIOTAL MDS 2000C shipboard waste systems treatment concentrate
TANK CLEANERS COOLING WATER TREATMENT ®
AMERSPERSE 280 seawater cooling treatment DEWT ® NC diesel engine water treatment DREWSPERSE ® SWD seawater dispersant FERROFILM ® corrosion and erosion inhibitor MAXIGARD ® diesel engine water treatment LIQUIDEWTTM cooling water treatment
FUEL ADDITIVES AMERGIZE ® deposit modifier/combustion improver AMERGY ® 222 fuel oil conditioner AMERGY 1000 combustion improver AMERGY 5000 combustion improver AMERGY 5800 PLUS deposit modifier/combustion improver AMERSTAT ® 25 microbiocide fuel treatment DREWCLEAN ® EST economizer soot treatment F.O.T.TM fuel oil treatment LT SOOT RELEASETM low temperature soot remover SOOT RELEASETM soot combustion catalyst
MAINTENANCE CHEMICALS ACC-9TM air cooler cleaner ACC/ME ® air cooler cleaner AMEROID ® DC disc cleaner AMEROID ® OSC one-step cleaner AMEROID ® OWS quick separating degreaser AMEROID ® RSR rust stain remover CARBON REMOVERTM solvent cleaner CILTM corrosion inhibitor DESCALE-ITTM liquid acid descaler DREW FC filter cleaner DREWCLEAN EOSD enviro oil spill dispersant ENVIROMATE ® 2000 general purpose cleaner
DREW ABD alkaline based degreaser DREW AF air freshener DREW BC buffering cleaner DREW CTC coal tar cleaner DREW LPA liquid pickling agent DREW NBD neutral based degreaser DREW PL passivating liquid DREW TC SEA tank cleaner EDGE ® heavy duty cleaner LACTM liquid alkaline cleaner TC#4TM tank cleaner
SPECIALTY PRODUCTS MUD CONDITIONER TM ballast tank water treatment
TECHNICAL PRODUCTS DREWFRESH ® 2000 heavy duty cleaner
CORROSION COATINGS DREWTANTM RC rust converter DREW PD anticorrosion coating MAGNAKOTE ® rust preventative MAGNAKOTE PLUS rust preventative
MISCELLANEOUS MOTORGARDTM total motor vessel protection program ULTRAMARINESM water treatment program
FOREWORD to them. Efficient operation of the marine power plant depends significantly on the quality of the water that it receives. Contaminants such as dissolved minerals, gases, oil, and even the water itself can cause serious damage to power plant equipment unless proper control steps are taken.
This manual is intended for use by persons who are concerned with the chemical testing, dosing, and control of a shipboard water treatment program. Included are explanations of why water treatment is required and a description of the methods used in modern marine practice. The purpose and application of each of the Drew Marine water treatment chemicals is explained. This edition has been updated to include the newest treatments and tests in our line.
Testing is an important part of any water treatment program because the test results are the primary means of controlling the program and of detecting problems. All test procedures are described in this manual after discussion of the applicable treatment program. We refer the reader to the section entitled "General Information" which should be read before conducting tests. Here, recommendations are provided for proper sampling, general testing and recording techniques.
The power plants of modern steam and motor vessels are more efficient today than at any other time in history. Boilers and diesel engines are designed to extract the greatest possible amount of energy from the fuel and to turn that energy into work. Turbines, generators and auxiliary equipment are designed to make the most effective use of the steam or mechanical energy that is supplied
CREDITS FOR ILLUSTRATIONS We wish to acknowledge the sources of some of the illustrations used in this manual. Reference
Page(s)
CHEMetrics, Inc., Calverton, VA 46, 48, 49, 55, 56, 57, 58, 63 MARINE ENGINEERING, Roy L. Harrington, ed., The So Society o off Na Naval Ar Architects a an nd Ma Marine En Engineers, NY, NY 19 1971
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Nirex, Alfa-Laval Group, Fort Lee, NJ
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Riley-Beaird, Inc., Shreveport, LA
12, 13 i
Table of Contents FOREWARD ............................ ........................................... .............................. .............................. ............................. ............................. ............................ ............. i GENERAL INFORMATION ............................. ........................................... ............................. .............................. ............................. .................... ...... • Introduction ............................. ........................................... ............................. .............................. ............................. ............................. ..................... ...... • Water Sampling Procedures Procedures ..... ......... ......... .......... .......... .......... .......... .......... .......... ......... ......... .......... .......... .......... .......... .......... ......... .... • Analytical Techniques ............................. ........................................... ............................. ............................. ............................. .................... ..... • Expression Expression of Chemical Chemical Results .... ........ ......... .......... ......... ......... .......... ......... ......... .......... ......... ......... .......... .......... ......... ......... ....... ..
1 1 2 4 7
BOILER WATER SYSTEMS AND TREATMENT .......................... ....................................... ........................... ..................... ....... 9 • Introduction ............................ .......................................... ............................. ............................. ............................. ............................. ...................... ........ 9 • Production Production of High Quality Quality Distillate Distillate .... ........ ......... .......... ......... ......... .......... .......... .......... ......... ......... .......... .......... .......... ......... ...... 10 • Boiler Water System Circulation Circulation ..... ......... ......... .......... .......... ......... ......... .......... .......... .......... ......... ......... .......... .......... .......... ......... .... 14 • Corrosion of Metals ............................. ............................................ .............................. .............................. ............................... ...................... ...... 16 • Chemical Treatment .............................. .............................................. ................................ ............................... ............................... .................. .. 19 • Composition and Formulation of Deposits ............ .......................... ............................ ............................ ...................... ........ 21 • Special Operating Conditions ........................... .......................................... ............................. ............................ ......................... ........... 24 • Boiler Water Treatment Treatment Chemicals Chemicals .... ........ ......... .......... .......... .......... ......... ......... .......... .......... ......... ......... .......... .......... .......... ....... 25 • Boiler Water Water Treatment Treatment Chemical Chemical Applications Applications and Controls Controls .... ......... ......... ........ ......... ......... ........ ....... ... 26 • Introductio Introduction n to Water Treatment Treatment Control Tests .... ......... .......... ......... ......... .......... .......... ......... ......... .......... ......... ....... ... 34 Alkalinity: • Hydr Hydrat ate e (AGK (AGK ® 100 and DREWPLEX ® AT) .............................. .............................................. ........................... ........... 35 • Medium to Low Pressure .............................. ............................................. .............................. .............................. ........................ ......... 36 • High Pressure .............................. .............................................. ................................ ................................ ............................... ....................... ........ 37 • Conversion Conversion Table (high, medium and low pressure) .... ........ ........ ......... ......... ......... ......... ........ ......... ......... .... 38 Ammonia (condensate, high pressure) ........................... ......................................... ............................. ......................... .......... 39 Chloride: • HP Test Kit ............................... ............................................... ................................ ................................ ............................... .......................... ........... 40 • Mercuric Nitrate Burette Titration .............................. ............................................ ............................. ............................ ............. 41 • LMP Test Kit .............................. .............................................. ................................ ................................ ............................... ......................... .......... 42 • Silver Nitrate Burette Titration .............................. ............................................. .............................. .............................. ................. .. 43 • Conversion Conversion Table (high, medium and low pressure) .... ........ ........ ......... ......... ......... ......... ........ ......... ......... .... 44 Conductivity (all pressures) ............................. ............................................ .............................. .............................. ......................... .......... 45 DEHA/DREWPLEX OX corrosion inhibitor Ampoule Test ............ ......................... ......................... .............. 46 Hardness: • Ampoule Method (high pressure) ............................ .......................................... ............................. .............................. ............... 47 2 • Titret method ............................... ................................................ ................................. ................................ ................................. ..................... .... 48 HYDRAZINE/AMERZINE: • (High to low pressure) .............................. ............................................. ............................... ............................... ............................ ............. 49 pH: • Colormetric (high pressure boilers) ........................... .......................................... ............................. ........................... ............. 50 • Meter (high pressure boilers) ............................ ........................................... .............................. .............................. .................... ..... 51 • Condensate Condensate (AGK 100 and DREWPLEX DREWPLEX AT) .... ........ ......... ......... ......... .......... ......... ......... .......... ......... ......... ........ ... 52 • Condensate Condensate (standard (standard treatment) treatment) .... ......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... ....... .. 53 • Condensate Condensate (high pressure) pressure) .... ........ ......... .......... .......... .......... ......... ......... .......... .......... .......... .......... .......... .......... ......... ......... ........ ... 54
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Phosphate: • (High Pressure) ............................. ............................................. ................................ ................................ ............................... ..................... ...... 55 • (Medium (Medium to low pressure) pressure) .... ......... .......... ......... ........ ......... ......... ......... .......... .......... .......... .......... ......... ........ ......... ......... ......... .......... ..... 56 Silica (high pressure) .............................. ............................................. .............................. .............................. .............................. .................. ... 57 Sulfite (medium to low pressure) .............................. ............................................ ............................. ............................. ................. ... 58
COOLING WATER SYSTEMS AND TREATMENT ............ .......................... ........................... ........................... .................. .... 59 • Introduction ............................ ........................................... .............................. ............................. ............................. .............................. ..................... ...... 59 • Cooling Water System Circulation ............................ ........................................... ............................. ............................. ................. .. 59 • Corrosion of Metals ............................. ............................................ .............................. .............................. .............................. ...................... ....... 60 • Composition Composition and Formation Formation of Deposits Deposits .... ......... .......... .......... ......... ......... .......... ......... ......... .......... ......... ......... .......... ........ ... 61 • Cooling Cooling Water Treatment Treatment Chemicals Chemicals ..... .......... .......... ......... ......... .......... ......... ......... .......... ......... ......... .......... .......... ......... ....... ... 62 • Cooling Cooling Water Treatment Treatment Chemical Chemical Applications Applications and Controls Controls .... ........ ......... ......... ........ ......... ......... .... 62 • Cooling Cooling Water Water Treatment Treatment Control Control Tests Tests and Dosage Requirements ............................ ........................................... .............................. .............................. ....................... ........ 62 2 CWT Test (Titret Method) ................................ ................................................ ................................. ................................. ..................... ..... 63 ® DEWT NC ................................ ................................................ ................................ ................................ ................................ ............................ ............ 64-65 Reference Tests: Chloride (treated water) .............................. ............................................. .............................. .............................. .......................... ........... 42 Chloride Sample Pretreatment Pretreatment ............................. ........................................... ............................. ............................. ................ 66 Hardness .............................. .............................................. ............................... ............................... ............................... ............................... ................ 47
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GENERAL INFORMATION INTRODUCTION Proper testing techniques are necessary to assure a well controlled water treatment program. This section describes the best methods for obtaining water samples and conducting chemical tests. Because test results must be recorded
using the correct units of mass, volume and concentration measurements, a section entitled "Expression of Chemical Results" has been included for your reference.
PROPER RECORD KEEPING An important part of an analytical program is the keeping of legible and accurate logs. Complete information is essential for an accurate evaluation of the progress of the treatment program. When recording the test data, remember the following pertinent points: •
•
Use the proper proper Onboar Onboard d Graphin Graphing g Logs Logs for for the the system system being treated.
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Reco Record rd all all info inform rmat ation ion leg legib ibly ly..
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Distribute Distributecopiesto Drew's Drew'sTechnical Technical Department Department,, owner's owner's office and ship's records as indicated in the instructions on the log. All Drew Onboard Graphing Logs are printed on NCR paper so that carbon paper is not needed.
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Fill in all require required d informa information tion tto o identify identify the s ship, hip, the s ship's hip's operating company, the voyage number, the equipment being tested, the date of the the review period, the boiler type and pressure, and inport or full steaming conditions.
Record Record ttest est results results and and treat treatment ment dosages, dosages, marking marking proper units of measurement on the Onboard Graphing Log. The colored band will indicate the satisfactory range for each control test. Reference test results should be recorded in the appropriate boxes.
IMPORTANT: IMPORTANT : Decimal points must be placed correctly to eliminate misunderstandings and inaccurate evaluations. •
Any additional additional relevant relevant informatio information n relatin relating g to the condition of the vessel, the equipment being treated, or the treatment program should be recorded in the appropriate space.
EXPRESSION OF CHEMICAL DOSAGES CONVERSIONS (M = METRIC, METRIC, E = English)* UNITS
M to M M to M E to E M to E M to E E to M E to M
MEASUREMENT
kilogram gram pound gram kilogram ounce pound
SYMBOL MULTIPLY BY MASS (weight)
kg gm lb gm kg oz lb
1000 1000 16 0.035 2.2 28 0.45
TO FIND
SYMBOL
gram milligram ounce ounce pound gram kilogram
gm mg oz oz lb gm kg
milliliter fluid ounce cup pint quart fluid ounce pint quart gallon milliliter liter liter liter liter
ml fl oz c pt qt fl oz pt qt gal ml ltr ltr ltr ltr
VOLUME M to M E to E E to E E to E E to E M to E M to E M to E M to E E to M E to M E to M E to M E to M
liter cup pint quart gallon milliliter liter liter liter fluid ounce cup pint quart gallon
ltr c pt qt gal ml ltr ltr ltr fl oz c pt qt gal
1000 8 2 2 4 0.03 2.1 1.06 0.26 30 0.24 0.47 0.95 3.785
*NOTE: The U.S. version of the English units units is used in these calculations. 1
WATER SAMPLING PROCEDURES The main purposes of routine water testing are:
Makeup Water Sampling
1. To ensure ensure that the proper proper residuals residuals of treatment treatment chemichemicals are maintained at all times.
The sampling line for this water may be located in one or two positions:
2. To detect the the presence presence of contaminant contaminants s in the water that that may be injurious to the boiler, diesel engine, and other equipment.
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In the the line between between the the distille distilled d water water storage storage tank and the the point of entrance of makeup water to the condensate system.
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Direct Directly ly from from the distil distillat late e conden condenser ser..
Test results are meaningful and useful only when the samples tested are representative of the water in the system at the time of testing. Recommended procedures for obtaining representative representati ve samples of boiler water, condensate, makeup water, feedwater, and cooling water circuits are discussed in the following sections.
SAMPLING EQUIPMENT Before testing, boiler water, hot condensate and feedwater samples must be cooled to 25 OC (77OF) by collecting through a sample cooler for safety and to prevent flashing which concentrates the sample. Stainless steel sample coolers should be used except where seawater is used for cooling. Where seawater is the only coolant, contact your Drew Marine representative for proper handling procedures or a special coil.
RECOMMENDED LOCATION FOR SAMPLING CONNECTIONS Boiler Water Sampling
Stainless steel piping or tubing used for sample lines should be installed with the least possible number of fittings and/or sharp bends. This is a precaution against plugging the lines with solid contaminants. The stainless steel sampling lines must meet international pressure code requirements. requirements. Tubing size should be 1.0 cm (3/8 in.) O.D.; nominal pipe size should be 1.0 cm or 1.27cm (3/8 in. or 1/2 in.). Stainless steel is recommended to prevent contamination of sample by corrosion from the lines.
Normally you can use the sampling connections provided by the boiler manufacturer. The sampling line is usually located in the steam drum, just above the generating tubes. In order to get proper results, it should be as far as possible from the internal feedwater line and the chemical feed line. Samples drawn for routine boiler water tests should be tested ONBOARD THE VESSEL. Boiler water samples for laboratory analysis should be taken only in special cases. Boiler water samples are not normally submitted for iron and copper analyses since results are not representative of the corrosion rate in the system. This is because of the boiler water alkalinity conditions and the tendency to collect iron and copper deposits from other parts of the system than in the boiler.
OBTAINING SAMPLES FOR SHIPBOARD TESTS 1. Allow the sample sample stream stream to to run for 5-10 minutes minutes in order to thoroughly flush out the line before taking a sample for testing. 2. A conveni convenient ent and and desira desirable ble proce procedur dure e is to open open the sample valve and allow the stream to run throughout the testing period. Appropriate samples for each individual test may be taken from the sample stream as needed. Testequipment,graduatedcylinders,evaporatingdishes, etc., should be clean and rinsed with the water to be tested and thoroughly drained.
Condensate and Feedwater Sampling Stainless steel sampling lines should be installed at three locations: •
Directly Directly afte afterr theMain Condensat Condensate e Extract Extraction ion Pump. Pump. This This line is to be used when the plant is under normal steaming conditions.
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Direct Directly ly after after the Auxili Auxiliary ary Conden Condensat sate e Extract Extraction ion Pump. Pump. This line should be used only when the plant is under port operating conditions.
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The deaera deaerator tor outlet line or from from the the suction suction or dischar discharge ge of the main feedwater pump.
3.
If analysi analysis s of a sample sample must must be be delayed delayed for for any any reason, reason, the sample should be kept tightly capped in a clean sample bottle which has been thoroughly rinsed with water from the sample stream. After a long delay, resample. Test results for pH, alkalinity, hydrazine, sulfite or ammonia will be less accurate if testing is delayed because of the effect of air on these treatments.
OBTAINING SAMPLES FOR LABORATORY TESTING
The latter is the best position for samples drawn for iron and copper tests; these samples will give a direct indication of the amounts of metal oxides entering the boiler with the feedwater. These connections may be used for obtaining samples for dissolved oxygen tests if they are ever required.
The following special procedures are to be followed when obtaining samples for testing at shoreside laboratories: 1. A boiler boiler water water sample sample for laboratory laboratory analysis analysis should should be collected in a glass bottle. Minimum sample volume for boiler water analysis is 1,000 ml (one U.S. quart).
On motor vessels or for LPSG's, condensate samples should be taken after the condensor or condensate cooler and before the feed or cascade tank to avoid recirculation from the feed pump. See page 31.
2. Condensat Condensate e and feedwater feedwater samples samples ffor or iron iron and and co copper pper analyses must be collected in special high purity plastic bottles. The minimum sample volume required for iron and copper analyses is 120 ml (4 oz.) 2
4. Draw samples samples while while boilers boilers are operating operating under under full or normal steaming conditions.
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:
5. Flush the sample sample line for for 5-10 minutes minutes prior prior to obtaining obtaining a sample for testing. Flush for a longer time if i f the line is rarely used.
MBW - Boiler water analysis MCW - Cooling water analysis MBAL - Ballast water analysis MPD - Boiler deposit sample analysis MCD - Cooling deposit sample analysis MFD - Fireside deposit analysis MHP - High purity feed and/or condensate analysis
6. The sample sample container container should should be thoroughly thoroughly rinsed rinsed with the water being tested and completely filled to overflowing so there will be no air space at the top of the sample bottle. However, if there is a danger of freezing, leave some freeboard in the bottle for expansion; otherwise, the bottle will burst. Tightly seal and properly label the sample bottle with the following information: vessel name, source of the sample, date of sampling, and information which describes the reason for sampling and any existing problems. This information is essential in order to determine what tests should be conducted and in the evaluation of results.
In Sections I through IV, please fill out the particulars of the equipment, symptom of the problem, if applicable, and anything else that can help us in interpreting the analysis results. Reports will be issued to the Account Executive responsible for your owner or manager. Distribution of these reports will be left to the discretion of your owner or manager.
Request for Analysis Forms In order to assure that the samples you are taking are analyzed promptly, Drew Marine has developed ISO 9002 forms that accompany the Sample Paks. The instructions for filling out the form follow: Please print clearly the following information in the space provided: • • • • •
Vessel Name Owner or Manager Name Date Sample was drawn or collected Date Sa Sample was la landed to be se sent to Laboratory Port where Sample was landed
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ANALYTICAL TECHNIQUES READING CALIBRATED GLASSWARE
Accurate analytical testing procedures are essential for proper control of chemical treatment programs. This section briefly describes the basic information common to all treatment programs and the procedures which should be followed for each of the analytical control tests.
Meniscus
PREVENT CONTAMINATION AND STORE REAGENTS PROPERLY
Line of Measurement
To ensure accurate test results, the analyst should take the necessary precautions to prevent contamination of the testing equipment before, during and after each test. It is imperative to have clean hands, a clean working surface, and, most important, clean test equipment and uncontaminated reagents within their normal shelf life.
When filling or reading liquid levels in calibrated glassware such as burettes and graduated cylinders, read the level where the bottom of the concave liquid surfaces reaches the line of measurement. The concave surface of a water solution is called the meniscus. Calibrated Glassware
BURETTE TITRATION
CARE OF REAGENTS
Proper titration technique is important to assure accurate test results. The titrating solution should be slowly added to the sample while stirring until the desired endpoint is reached. Addition of titrant should be slowed to one drop at a time as the endpoint approaches to avoid overshooting the endpoint. The approaching endpoint is signaled by temporary color change where the titrant enters the sample. The first permanent color change throughout the sample is the endpoint.
Reagents by their nature are reactive. Care must be taken to prevent contamination and deterioration.Closeall reagent bottles tightly with their original stoppers or caps. Use separate clean, dry spoons or droppers for each reagent to prevent cross-contamination cross-contamination of reagents. Never Never return excess reagent solution or powder to storage bottles.
MEASURING SPOON
To ensure freshness, periodically replace reagents. Store spare chemical supplies in a clean, cool cabinet, preferably outside of hot, humid areas. Air-conditioned rooms are a good environment for reagents. Powdered reagents can absorb moisture if stored in refrigerators so storage in an airconditioned area is preferable.
The brass measuring spoon has been specially selected to make the addition of reagent easy. It is used for delivering a specified amount of reagent to a cooling water sample when running the DEWT ® NC test procedure. It is also used for adding Gallic Acid to neutralize boiler water when testing conductivity.
Some reagents are light sensitive so it is a good general rule to store them in the original bottles in which they are supplied in closed closets.
USE OF COLORIMETRIC EQUIPMENT
Code:
For accurate results using the color comparator slides, the path of light through the viewing tubes must be free of dirt or other obstructions. Before inserting the viewing tubes into the comparator, gently tap the tubes against the palm of your hand to dislodge any gas bubbles from the test solution. Clean the outer surface of each tube to remove water droplets and fingerprints. The outside surface of the comparator slide and color standards should also be clean.
0224-01-4
Description: Measuring Spoon, Brass
There should be sufficient lighting behind the comparator when running the test to obtain accurate color comparison and uniform results. Daylight fluorescent light is preferred.
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6. Move the the slide back and forth, forth, while while observing observing the colored ovals that will appear in the mirror. Continue until the color of the middle oval matches that of one of the side ovals. Note that the comparison can be made only when one of the arrows on the slide is opposite the middle tube.
WATER ANALYZER BASE GENERAL INSTRUCTIONS INSTRUCTIONS INSTRUCTIONS The Water Analyzer is used to determine boiler pH in the ULTRAMARINESM program. The Water Analyzer consists of a base structure (A), three glass tubes (B)(C)(D), and one or more comparator slides (E) fitted with transparent color standards (F). The tubes are modified "Nessler" tubes, and each has an etched mark (G) at 150 mm or 250 mm above the bottom. The base has a compartmented holder (H) for the tubes, which supports them at a 45O angle above a mirror (J) set into the base. The slides move in a slot in the base (K) above the mirror and beneath the tubes.
7. When a color compari comparison son is obtained, obtained, read the test test result (in pH) from the numbers on the slide.
USE OF THE WATER ANALYZER 1. Set the appropriate appropriate comparator comparator slide for for the desired 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 from above the mirror. 2. Fill the two outer outer tubes tubes (B & D) to the etched etched mark with with reference blanks according to the instructions for the particular test. Place these tubes in the two outer compartments in the base. 3. Add reagent chemicals to another portion portion of the sample, sample, according to the instructions for the particular test. 4. Fill the middle middle tube (C) to to the etched mark mark with the the treated sample and place it in the middle compartment in the base. 5. Set the base on a fla flatt surface surface so that the mirror mirror faces faces the operator and a light shines into the open ends of the tubes.
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FILTER PAPER Filtration is required in some test procedures. This is especially true if suspended solids appear in the sample. Failure to filter a sample when required or the repeated use of the same filter will result in an incorrect value. There is one exception to this rule. If a sample remains cloudy after the first filtering, the sample should be refiltered through the same filter paper since the filter becomes more retentive on the second filtration.
Some filter papers are specially prepared to minimize contaminanats. (Drew specifies a Whatman #5 filter paper). The most simple technique for folding filter paper is:
Fold the paper in half (Step 1) and then in half again (Step 2). Step 1
Step 2
Step 3 Pull three-quarters of the paper to one side and crease to hold the cone shape (Step 3). Insert the tip of the cone into the funnel (Step 4). Step 4
Pour the sample into the center of the cone. Do not fill the funnel above the upper surface edge of the filter paper. Sample which flows between the paper and funnel will add unwanted materials to the filtered sample.
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EXPRESSION EXPRES SION OF CHEMICAL CHEMI CAL RESULTS RESULTS REPORTING OF QUANTITY Values below 7.0 are increasingly acidic, and those above 7.0 are increasingly alkaline. In common practice, pH can be determined by electrical instruments, color indicators, or specially treated test paper.
When reporting the results of an analysis, it is necessary to express the quantity of each constituent that is determined. In the analysis of most materials, the quantity of each constituent is given in terms of percent--the amount of each constituent per 100 parts of the material. For example, an analysis of a metallic sample may show 60 percent copper which would mean that every 100 parts of the sample contain 60 parts of copper.
Alkalinity is defined as the state of being alkaline or "basic". The alkalinity is determined by the concentrations of hydroxide, carbonate, and certain other chemicals, such as phosphate and silicate.
Reporting by percent is not practical in water analysis since the amounts of the materials determined are extremely small. For example, the silica content of natural waters, if expressed 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 used in water analysis. The terms ppm and ppb are utilized by Drew Marine in its publications and reports.
Phenolphthalein ("P") Alkalinity is a measure of the alkalinity above a pH of 8.2-8.3. All of the hydroxide, one-half of the carbonate, and one-third of the phosphate, plus all other alkali-producing materials present in a water sample such as silicate are included in the Phenolphthalein Alkalinity. Total ("T") Alkalinity is a measure of the alkalinity above a pH of 4.2-4.3. All of the hydroxide, all of the carbonate, and twothirds of the phosphates, plus all other alkali materials are included in the Total Alkalinity.
Parts Per Million (ppm) One part per million (ppm) is an expression of the relationship of one part of a substance to one million parts of another. As examples, if a water contains one ppm of silica, there would be one part of silica in 1,000,000 parts of the sample. In a 1 gram silica 1,000,000 grams (1 metric ton)
REPORTING OF DISSOLVED SOLIDS CONCENTRATION AS CONDUCTIVITY In boiler water, dissolved salts consist of contaminants, treatment chemicals, and naturally occurring chemical constituents. Dissolved salts ionize and conduct an electric current. The amount of current that a water sample carries from one electrode to another at a specific temperature is termed its conductivity. The concentration of ionized dissolved solids in any water is proportional to its electrical conductance. For example, distilled water has a very low conductivity; in contrast, seawater has a very high conductivity. Therefore, the amount of dissolved solids can be estimated by the water's conductivity. A conductivity meter, which records conductance in micromhos (µmhos), is used to measure this characteristic of the water.
= 1 ppm silica
million grams (1 metric tonne) of this water, there would be one gram of silica; or in a million pounds of water, there would be one pound of silica. sili ca. Expressing results in terms of parts per million is a simple method to use, and for most determinations, the results are given in whole numbers. Parts Per Billion (ppb) One part per billion (ppb) is used to express the relationship of one part of a known substance to one billion parts of another. For example, a sample of water may contain one part of silica to one billion (1,000,000,000) parts of water. As indicated above for "ppm", "ppb" may be applied to quantities expressed in any unit of measure.
REPORTING OF pH Acidity, Neutrality, Alkalinity An aqueous solution can be either acidic, neutral or alkaline. The accepted manner of expressing this condition is pH. pH is the reciprocal of the logarithm of the hydrogen ion (H+) concentration in solution, -log[H+] on a scale of 0 to 14. The midpoint pH at 7.0 is considered "neutral".
7
(Neutralization is required before testing the conductivity of boiler 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 high reading.
Dilution of a sample should always be done with distilled water. If a sample is diluted, the test result must be multiplied by the appropriate factor. Examples follow: EXAMPLE: EXAMPLE: Phosphate Test
The sample should be a cooled sample, its temperature taken and the temperature compensation dial on the meter, if there is one, should be properly set before taking the conductivity reading.
1.Draw 1. Draw a 25 ml sample of water. water.
DILUTION OF WATER SAMPLES
3.Conduct 3. Conduct phosphate test. (Result = 45 ppm phosphate)
There are two conditions under which dilution of a sample may be necessary:
4.Multiply 4. Multiply test result by a factor of 2. (45 ppm x 2 = 90 ppm phosphate)
• When a sample is highly colored, colored, even after filtration, which would make it impossible to determine a colorimetric end point.
5.Final 5. Final test result = 90 ppm phosphate
2.Dilute 2. Dilute sample with 25 ml of distilled water. (Total volume = 50 ml)
*Avoid dilution of a sample when testing for an oxygen scavenger. When testing for oxygen scavenger, the water used to dilute the sample should be deoxygenated.
• When the the initial test test result is exceeding exceedingly ly high or beyond beyond the normal range of the test procedure.
The following dilution and multiplication factors can be used for any sample. The accuracy of the result, however, is dependent upon the care taken in making the dilution.
WATER SAMPLE 25 ml 50 ml 10 ml 20 ml 10 ml
+
DISTILLED WATER DILUTION
=
25 ml 50 ml 40 ml 80 ml 90 ml
TOTAL VOLUME 50 ml 100 ml 50 ml 100 ml 100 ml
8
MULTIPLE TEST RESULT BY FACTOR OF: 2 2 5 5 10
BOILER WATER SYSTEMS AND TREATMENT INTRODUCTION A boiler converts the chemical energy in fuel to heat energy in steam for the purpose of doing work. There are many types of boiler plants, but all of them function on the same basic principles of thermodynamics. A complete discussion of either plant design or thermodynamics is beyond the scope of this presentation. However, some basic concepts will be presented here to introduce the systems which we will discuss in the sections below.
contains dissolved gases which have been absorbed from the air or formed by decaying organic matter. They can be mechanically removed by deaeration, thermally reduced by increased feedwater temperature and/or chemically scavenged. An effective water treatment program minimizes scale and corrosion in the boiler system. Since distillation and mechanical/thermal deaeration cannot remove all of the contaminants, routine chemical treatment programs are necessary for the efficient maintenance of all steam generating and cooling system equipment.
In the world fleets today, we see some ships which operate boilers for propulsion (some at pressures over 60 kg/cm 2, (850 psig) and motor vessels equipped with auxiliary oil-fired and waste heat boilers which operate at lower pressure levels (7-24 kg/cm2, 100-350 psig).
The primary goals of a controlled water treatment program in any power generating plant are:
All boilers operate on the common premise that heat is transferred to water to create steam which is then used to do work onboard. Diesel engines depend on scale-free heat transfer surfaces for cooling. They share common problems of scale formation and corrosion, although some forms of corrosion will be more evident in high pressure boilers and others are more often seen in engines.
• To maintain maintain clean, scale-f scale-free ree waterside waterside heat heat transfer transfer surfaces in steam generating and cooling water systems. • To prevent prevent metal loss due due to corro corrosion. sion. • To ensure ensure efficient efficient producti production on of steam in boiler boiler systems systems without priming, foaming, or carryover contamination. • To prevent prevent formation formation of deposits deposits in steam/co steam/condens ndensate ate systems. • To minimize minimize heat loss loss from the the system system due to excessiv excessive e blowdown from boilers. • To keep all power power generating generating and and auxiliary auxiliary equipment, equipment, and associated water and steam systems at their most efficient levels and thereby minimize costs.
The water used onboard, for whatever purpose, comes primarily from the sea. In order for seawater to be safely used for steam production, the salts and other contaminants must be removed from the water. An evaporator or distiller is generally installed for the purpose of purifying the water until it contains only trace levels of minerals. Seawater also
9
PRODUCTION OF HIGH QUALITY DISTILLATE The water used on ships, for whatever purpose, comes primarily from the sea. In order for seawater to be used for steam production, the salts and other contaminants must be separated from the water to minimize scale formation and corrosion in boiler water and steam circuits. Mechanical and chemical technology is used in combination to do both. This section will discuss the production of high quality water, corrosion and scale mechanisms, mechanical and chemical corrections for these conditions before moving on to the test procedures used to control the chemical treatments and monitor the contamination.
the salts in seawater pose a challenge to these units. The most common ion exchange units must be regenerated with sodium chloride brines which can contribute chloride ions to the contamination. Ion exchange resin beds must be designed in such a way to prevent channels which will allow water to flow through untreated. Reverse osmosis is an effective means of desalination. However, a single pass unit will not produce water of sufficient quality for use in marine systems and further demineralization is necessary. A number of units in series could theoretically produce an effluence of acceptable quality and quantity for boiler feedwater.
Distillation, ion exchange, and reverse osmosis (RO) are processes which may be used for the desalination of seawater. In the marine industry, distillation is the most widely used method because of its relative simplicity and cost effectiveness. Brief descriptions of the other methods follow.
The normal process of osmosis involves two solutions of different dissolved solids concentration that are in a single container, separated by a semipermeable membrane. The common solvent in both solutions is water. The water flows from the more dilute solution through the membrane to the more concentrated solution. In time, the equalizing effect creates equal dissolved solids concentration in both compartments.
Ion exchange: Cation ion exchange units will effectively remove hardness constituents (calcium and magnesium) from water but not the anions, i.e., chloride and sulfate ions or other contaminants. The extremely high concentrations of
SOLUTION WILL RISE TO THIS POINT WHICH IS HEAD EQUAL TO APPARENT OSMOTIC PRESSURE SEMI-PERMEABLE MEMBRANE
MORE CONCENTRATED SOLUTION
LESS CONCENTRATED SOLUTION WATER FLOW
OSMOSIS
PRESSURE
SEMI-PERMEABLE MEMBRANE
MORE CONCENTRATED SOLUTION
LESS CONCENTRATED SOLUTION
WATER FLOW
REVERSE OSMOSIS 10
When the bubbles burst, droplets containing concentrated salts are thrown into the vapor space and are carried over into the distillate. This results in reduced water quality.
The reverse osmosis process is created when pressure is exerted upon the more concentrated solution so that the water flows in the reverse direction through the semipermeable membrane from the concentrated side to the dilute side, leaving the majority of the dissolved solids behind.
Foaming also may be caused by "organic" substances in the water, which are formed by the decay of organic materials or contamination with petroleum products.
When reverse osmosis is used to produce fresh water from seawater, a reverse osmotic pressure is created to force the water from the brine (seawater side) into the fresh water compartment. Theoretically, the only energy required is that which is needed to overcome the osmotic pressure and pump the feed water. In practice, much higher pressure (between 60-70 kg/cm2, 850-1000 psig) are required to produce useful volumes of water per unit area of membrane.
Mechanical Control Foaming and carryover from evaporators can be minimized by proper management of the water level and salinity (brine) control. • Improper Improper water water level control control is often due to th the e malfunction malfunction of the automatic controls and alarms. Automatic equipment and alarms should be maintained in good operating condition.
Generally, the reverse osmosis process is not as widely used onboard ship as distillation.
DISTILLATION (EVAPORATION PROCESS)
• Salinity Salinity control control is an important important factor factor in the prevention prevention of scale deposits as well as carryover. Salinity management refers to the continuous removal of concentrated brine from the evaporator in order to control the amount of dissolved solids buildup. Normally the brine concentration should be maintained at 1.5 (1.5/32nds) concentrations, although some vapor compression units operate at 2.0 (2.0/32nds) concentrations or more.
A marine evaporator is normally used to provide high quality distillate from seawater for the vessel's water systems. There are many types of evaporators, but they are all designed for the same purpose. Hot cooling water or auxiliary steam is often used as a heat source increasing cost effectiveness. In some type of evaporators, seawater is heated or flows over a series of coils or tubes through which auxiliary steam is passed. Heat is transferred to the seawater under vacuum, vaporizing a major portion of the water. The resulting vapor is scrubbed by a mist eliminator as it leaves the evaporator unit to remove entrained moisture which contains a small amount of dissolved solids.
Chemical Treatment The problems of scale formation and foaming can be minimized by the addition of chemical treatments containing polymeric scale inhibitors and antifoams. The polymer molecules attach themselves to the scale-forming minerals to disrupt the densely packed crystalline structure. This prevents hard scale from building up on the heat transfer surfaces. Instead, nonadherent, suspended crystals are formed which will easily flow overboard with the brine discharge.
The vapor is then cooled in a condenser to produce pure distillate. It is pumped to storage tanks for use as boiler water makeup, engine cooling water, potable water and other domestic purposes. The majority of dissolved solids are left behind, accumulated and concentrated in the brine section of the unit for overboard discharge. The purified water now contains only traces of minerals which can be easily handled with boiler and cooling water treatment chemicals.
Polymer treatments can remove existing scale from heat transfer surfaces by the same action. If treatment is used, water production can be maintained, and acid cleaning to remove scale can be minimized. Modern formulations include an antifoam ingredient which reduces the surface tension of the water and allows vapor to escape without the formation of foam. This helps to maintain water quality.
Evaporator Scaling During the evaporation process, the solubility of most of the dissolved minerals, which remain in the evaporator brine, is exceeded and precipitation occurs, forming scale deposits on heat transfer surfaces. The three most common scales formed in an evaporator are calcium sulfate, calcium carbonate, and magnesium hydroxide. These are effecient heat transfer barriers. Reduced heat transfer results in reduced water production. Eventually, distillers must be shut down and cleaned to remove the insulating scale.
Drew Evaporator Treatments AMEROYAL ® evaporator treatment is a liquid combination of an active polymer with a highly hi ghly effective antifoam agent. It is effective in seawater and brackish water. The antiform agent in AMEROYAL treatment reduces surface tension and, thereby, prevents foaming and carryover. AMEROYAL treatment is the most widely used evaporator treatment in the marine industry.
Evaporator Foaming and Carryover
AMEROYAL CF concentrated evaporator treatment is a concentrated liquid formulation of active polymers and antifoam agents developed specifically to prevent scale deposition and carryover in high temperature, high production multi-stage evaporators. AMEROYAL CF treatment has been proven capable of significantly reducing the amount of acid cleaning required to maintain design distillate production.
The higher concentration of dissolved solids in the brine increases the surface tension of the water, acting like an elastic skin at the water level. The increased surface tension hinders the release release of vapor bubbles bubbles and gases and promotes foaming.
11
EXAMPLES OF EVAPORATOR UNITS LOW-PRESSURE SUBMERGED HEATING ELEMENT DISTILLER AMEROYAL
VAPOR-COMPRESSION DISTILLER
AMEROYAL CF
12
TWO-STAGE VACUUM-FLASH DISTILLER AMEROYAL
Air Ejectors Steam Supply to Air Ejectors
After Condenser Steam Supply to Feed Heater
Condensers
Distillate Cooler
Salinity Indicator
Sea Water Pump
Sea Feed Heater
Drain Vacuum Chamber #2
Reject Water to Waste
Vacuum Chamber #1
Drain Return
Brine Steam Distillate
Distillate to Storage
Distillate Pump Brine Pump
Brine Overboard
Condensate Pump
Sea Water Temperature Control Valve
LOW PRESSURE THIN-FILM DISTILLER
CONDENSER
IN
SEA WATER OUT
DEMISTER OUT
JACKET WATER
EVAPORATOR
IN AMEROYAL ELECTRIC PANEL
ORIFICE SALINOMETER
OVER BOARD
FRESH W. PUMP
BRINE EJECTOR
AIR EJECTOR
TO BILGE TO FRESH W. TANK EJECTOR PUMP
13
FROM SEA
BOILER WATER CIRCULATION A boiler is designed to convert the chemical energy contained in fuel to heat energy in the steam. This steam is then available to do work in a variety of systems onboard. The figure below illustrates the circulation pattern of a water tube boiler system. (While only one design is shown, all marine oilfired boilers function in a similar pattern).
is added, increasing the energy in the steam. The superheated steam is then passed through a high pressure turbine and possibly a low pressure turbine where a major portion of steam's thermal energy is converted to mechanical energy. Before the steam is condensed and returned to the feed system, part of it may be bled bl ed off from the turbine system for feedwater heating and similar processes so that its thermal energy can be fully utilized.
In a water tube boiler, the furnace is surrounded by tube tanks which are connected through headers to the upper and lower drums. The fuel is burned in the furnace and the heat is passed by radiation to the surrounding generating tubes. The heat energy is passed by conduction to the recirculating boiler water in the tubes. In this way, the tube metal is cooled and steam is generated.
After passing through any auxiliary systems, the steam enters the condenser where it is condensed to form water which is pumped back to the feed line, completing the boiler/ feed system circuit.
As the water is heated, its density decreases and it tends to rise. Colder heavier water tends to sink. As the hot water/ steam rises in the generating tubes and the colder water sinks in the downcomer tubes, a natural circulation results in the boiler curcuit.
In systems operating at lower pressure levels without superheaters, the steam simply leaves the boiler from the steam drum and passes throughout the steam system before being condensed and returned as condensate to the feed equipment.
As the steam/water mixture reaches the upper drum (steam drum), it separates. The steam passes to the upper half of the drum, then leaves the top of the drum to the superheater or directly to where it is needed as saturated steam. The recirculating water remains in the lower half of this drum, mixes with incoming feedwater and again passes through the complete water circuit.
On motor vessels, there are usually two steam generating systems: a waste heat economizer drawing its heat energy from the diesel engine exhaust gases and an auxiliary oil fired boiler. The waste heat economizer functions when the engine is in operation, and the auxiliary boiler functions when the ship is in port and the main engine secured. Although their design is different from the boilers used for propulsion, these boiler systems function under the same principles of heat transfer and are subject to many of the same problems due to scale and corrosion.
In boilers fitted with superheaters, the steam which is released into the top of the steam drum passes out of the boiler through the steam line to the superheater where more heat
STEAM OUT
WATER IN
T A E H
14
15
CORROSION CORROS ION OF MET ME TALS GASEOUS CORROSION
Ferrous and non-ferrous alloys are commonly used metals of construction in marine power plants although other metals are also being used. All of these metals will corrode slowly in contact with water, unless the water is properly treated. High temperatures and pressures increase the rate of corrosion. The purpose of any complete water treatment program is to protect all the preboiler, boiler and afterboiler auxiliary equipment and systems against corrosion, both during operation and during out-of-service periods.
Three gases are of primary concern in a water treatment program: oxygen, carbon dioxide and ammonia. Oxygen gas is one of the most undesirable contaminants which enters the preboiler/boiler/afterboiler water system. Oxygen dissolves in water and causes corrosion at an excessive rate. The severity of the oxygen attack depends on the concentration of the dissolved oxygen, pH value, and temperature of the water.
CHARACTERISTICS AND TYPES OF CORROSION Corrosion is defined as the deterioration of a metal or alloy or its properties due to reaction with its environment. Characteristics of the damage caused by corrosion include the following:
Oxygen reacts with the ferrous metal surfaces to form red iron oxide (Fe2O3). Because this red iron oxide (ferric oxide) or rust is porous and does not protect the metal surface, the corrosion process continues. Ultimately, the entire metal structure will be converted to ferric oxide unless corrective measures are taken.
• Pitting Pitting - A selective, selective, localized localized metal metal attack characte characterized rized by the formation of rounded deep cavities in a metal surface. Pitting is considered to be one of the most serious forms of corrosion and often associated with oxygen attack.
The corrosion is often localized which results in pitting. Unless stopped by chemical or thorough mechanical cleaning, the corrosion reaction will proceed beneath a cap of porous oxide until it pierces the metal.
• General General corrosion corrosion - Thinning Thinning or metal metal loss in which which the thickness of the metal is evenly reduced over a large surface area.
Carbon Dioxide: Dioxide: Most of the carbon dioxide in marine power plant water systems is formed in the evaporators. Heat causes carbonate (CO3=) and bicarbonate (HCO3-), which are dissolved in the seawater, to break down to carbon dioxide gas (CO2).
• Underdepo Underdeposit sit - Accelerated Accelerated corros corrosion ion that takes takes place under scale or sludge deposits. Underdeposit corrosion is accelerated since alkalinity left behind can become extremely concentrated. • Caustic Caustic Cracking Cracking - A localized localized form of corrosion corrosion or physical physical destruction in which a facturing of the metal following grain boundaries occurs due to stress.
Carbon dioxide gas leaves the evaporator with the vapor and dissolves in the distillate. The carbon dioxide reacts with water to form carbonic acid which reduces the pH of the water and accelerates general corrosion in the feedwater and ultimately in the boiler steam-condensate system.
• Embrittlem Embrittlement ent - An effect effect of corrosion corrosion that changes changes the physical properties of a metal, its crystalline and intercrystalline structure, causing the metal to lose its i ts strength and ductility, thereby becoming brittle and weak.
The carbonic acid (H2CO3), a weak acid, attacks the steel in the feed and condensate lines to form ferrous bicarbonate (Fe(HCO3)2). Ferrous bicarbonate is a highly soluble compound that has no protective or passivating effect.
• Dealloying Dealloying - The selectiv selective e dissolution dissolution of one metal metal from from an alloy.
Carbonic acid produces a general type of corrosion, which is typified by grooving along the bottom of a pipe, overall metal thinning and, particularly, loss of metal at stressed areas such as pipe bends and threaded sections.
CAUSES OF CORROSION REACTION AND PREVENTATIVE MEASURES
Ammonia: The cooper-based metals are subject to attack by ammonia in the presence of oxygen. It is only the combined action of these gases which is corrosive. By eliminating the oxygen, the corrosive potential of ammonia is minimized.
Corrosion is a result of chemical and electrolytic action of water or air on a metal. The corrosion rate is influenced by the impurities in the metal and the water. Properly treated high purity water and metals reduce the rate of corrosion. All of these metals will corrode in water unless the water is properly treated.
Ammonia is formed by the decomposition of organic material or the breakdown of excessive hydrazine.
The most common causes of corrosion in boiler systems are dissolved gases, improper pH levels, chloride ion, and mechanical conditions. Brief discussions of the specific corrosion reactions follow.
Mechanical Removal of Gases: Air naturally dissolved in the makeup water, in-leakage and the breakdown of other compounds introduces oxygen, carbon dioxide, and ammonia. Air can enter through any opening such as makeup, drain or cascade tanks and especially systems under vacuum such as turbine seals and condensers. 16
To deal with this problem, marine steam systems are equipped with air ejectors, hot wells and sometimes, deaerating heaters. The efficient operation of this equipment is essential for the removal of a high percentage of the non-condensible gases which enter the system.
• Check for for inefficient inefficient operation operation of the deaerati deaerating ng heater. heater. One thermometer should be installed in the steam space and another in the w water ater space of the deaerator. deaerator. When the unit is operating efficiently, the temperatures in the water space and in the steam space should be within one to two degrees Centigrade of each other. If not, check thermometers for accuracy and replace if necessary. If the temperature difference is confirmed, the unit should be opened and inspected at the first opportunity to determine the cause of the problem. (See "Pressure/Temperature Table for Deaerator Checks," which follows).
The following is a list of the main points to check in plant operation to reduce the entry of corrosive oxygen (O2) and carbon dioxide (CO2) gases: • Check Check all points points of possible possible air in-leakage in-leakage in the condensing and vacuum sections of the plant (i.e., defective flanges, condensing and vacuum sections of the plant, (i.e., defective flanges, gaskets, valve packing, cracked valve bonnets, open return line drain valves, insufficient steam pressure on gland seals, malfunctioning steam traps, etc.)
• Provide Provide adequate adequate venting venting of gases from from the deaerat deaerating ing heater directly to the atmosphere. The vent line must be open; and if an orifice is installed, it must be large enough to adequately remove the noncondensate gases. If the vent line is run to the gland seal exhauster, the fan on this unit must be in operation continually while the vessel is in port and when at sea. If the fan should fail, the auxiliary vent to the atmosphere on the deaerating heater must be opened until the fan is again in operation.
• Check Check the temperatur temperature e of the water in tanks tanks operating operating at atmospheric pressure. Since O2 and CO2 gases readily dissolve in cool water, the water in all atmospheric water tanks should be heated to the highest temperature posssible without creating a vapor lock at the pump suction.
• Check for for clogged, clogged, worn, worn, or broken broken spray nozzles nozzles or or springs in the deaerator. Poor atomization will result in poor deaeration regardless of the temperature.
NOTE: NOTE: In motor vessel systems without deaeration equipment, the feed-cascade-hot well tanks must be kept at as high a temperature as possible (90 OC) in accordance with boiler manufacturers' recommendations to liberate the maximum amount of dissolved oxygen. Tanks which are covered must have vent lines fitted to carry away vented gases. Many ship systems have feed pumps functioning continuously with feedwater excess recirculated back to the feed tank. As the returning water may be simply dumped into the tank, any volatile chemicals which may have been dosed to the feedwater before the recirculation off-take can be lost from the system. To minimize this condition, the treatment chemicals are often dosed "downstream" of the off-take point by means of a dosing pump.
• When taking taking on extra extra feed feed water: water: a) Take on on feed feed as slowly slowly as possible. possible. If the the feed feed is taken taken on too quickly, the deaerating heater may be overloaded, making it impossible to efficiently minimize the O2 and CO2 concentrations. b) A higher higher water water temp temperatu erature re in the makeup makeup feed tank will reduce the absorption of O2 and CO2. • Use chemical chemical treatment treatment for for maximum maximum protection protection against against the remaining O2 and CO2. While mechanical deaeration of the feed water is a major step in eliminating dissolved oxygen and other corrosive gases such as ammonia and carbon dioxide, it needs the assistance assistance of chemical treatment.
• Avoid piping piping drains drains with high oxygen oxygen concentra concentrations tions to drain tanks or to any point where they may be used as boiler makeup.
17
Pressure/Temperature Table for Deaerator Checks Malfunction of the deaerating heater will allow gases to remain in the feedwater which will result in fluctuations in the oxygen scavenger residual in the boiler water and cause condensate pH control difficulties. An indication of proper deaerator operation is provided by the operating temperatures and pressures. The steam and water space tempertures
should be nearly equal. If the temperature difference is greater than 1OC or 2OF, the thermometers should be checked for accuracy and, if necessary, repaired or replaced. At the same time, the system should be checked for malfunctioning atomizing nozzles, steam inlet valves, vents, etc.
DEAERATOR SHELL PRESSURES AND CORRESPONDING SATURATION TEMPERATURES
Deaerator Shell Pressures kg/cm2 psig 0.0 0.11 0.28 0.43 0.58 0.69 0.86 0.99 1.12 1.26 1.41 1.56 1.72 1.83 1.97 2.10 2.25 2.34 2.54 2.68 2.82 2.96 3.10 3.24 3.38 3.52 3.80 3.94 4.08 4.22
Correct Saturation Temperatures O O C F
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 54 56 58 60
100 103 107 110 113 115 118 120 122 124 126 128 130 131 133 134 136 137 139 140 141 143 144 145 146 148 150 151 152 153
18
212 218 224 230 235 239 244 248 252 255 259 262 265 268 271 274 277 279 282 284 287 289 291 294 296 298 302 304 305 307
CHEMICAL TREATMENT An alternative oxygen scavenger is sodium sulfite (Na 2SO3). This compound readily combines with oxygen in solution to form a more stable compound, sodium sulfate (Na 2SO4). This process efficiently removes oxygen from solutio n, but it does add dissolved solids to the water. As a result, it is not generally recommended for high pressure boilers where minimum dissolved solids levels are critical.
Removal of Oxygen Any dissolved oxygen remaining after deaeration can be completely scavenged by the addition of a chemical oxygen scavenger, such as hydrazine, diethylhydroxylamine or sodium sulfite, to the boiler feed water. The reaction produts of the hydrazine treatment are water and nitrogen gas which is inert and will not attack the metal in the system. These reaction products will not add solids to the boiler water as do the reaction products of other oxygen scavengers such as sodium sulfite. N2H4 + O2
Sulfite is not volatile and it is not a metal passivator. It remains in the boiler water and does not offer protection for the condensate system. Na2SO3 + (Sod (Sodiu ium m Sulf Sulfit ite) e) +
→ 2H2O + N2
Hydrazine has added benefits. After a boiler system has been operating for a short time with proper chemical control and adequate hydrazine concentrations, a protective film of black magnetic iron oxide oxid e (Fe3O4, magnetitite) forms. At the same time, any non-protective red iron oxide, (Fe2O3, hematite), is slowly converted to magnetite. This magnetite film passivates the metal surfaces.
Control of Condensate pH As discussed above, CO2 gas reacts with the condensate to form carbonic acid. Without chemical treatment, this acid reduces the pH of the condensate. The pH can be controlled within a specified non-corrosive range by the continuous dosage of a neutralizing amine, such as morpholene or cyclohexylamine.
If the hydrazine residual is allowed to be depleted, oxygen will not be removed from the system. At this point the magnetite film will be converted to hematite, and corrosion of the base metal will begin.
ACIDIC CORROSION - ACID ATTACK Acid attack of boiler tubes and drums is usually in the form of general thinning of all metal surfaces.
Since hydrazine is volatile, some of it will carry over with the steam. In this way, the metals of the condensate system also can be protected. In a series of reactions similar to those described above for ferrous metals , nonferrous metals are rendered less sussceptible to corrosion. For example, cupric oxide (CuO) is converted to a protective form, cuprous oxide (Cu 2O) 4CuO + N2H4
1 /2 O 2 → Na2SO4 (Oxy (Oxyge gen) n) (Sod (Sodiu ium m Sulf Sulfat ate) e)
Acidic conditions, exclusive exclus ive of those created by the presence of CO2, occur when the boiler feed water becomes contaminated by evaporator carryover or seawater inleakage at the condenser. When magnesium chloride (MgCl2), a seawater salt, is introduced to a boiler water system, it dissociates into ions of magnes ium (Mg+2) and chloride (Cl-). The chloride ions (Cl-) react with the hydrogen ions, which lowers the pH of the water and attacks the metal surfaces.
→ 2Cu2O + 2H2O + N2
The most recent volatile oxygen scavenger introduced to the marine industry is diethylhydroxylamine, also known as DEHA. In addition to oxygen scavenging, DEHA forms a passive magnetite film providing a protective barrier against corrosion.
The magnesium ions (Mg+2) react with the phosphate (PO4-3) and hydroxyl ions (OH -), if these treatments are present, to form sludge. Magnesium ions may react only with the phosphate ions to form magnesium phosphate, a soft, adherent deposit which tends to bind all other deposits to the tube surfaces.
The oxidation reaction products of DEHA are acetic acid, nitrogen and water. In a boiler water environment, the hydroxide alkalinity neutralizes the acetic acid and is removed by blowdown as sodium acetate.
Any deposits on metal surfaces can be heat transfer barriers and can lead to overheating and increasingly destructive conditions. Water trapped beneath these deposits on high heat transfer surfaces will concentrate the acid or caustic. When this occurs, the corrosion rates become extremely high and serious localized damage occurs in a very short time.
4(C2H5)2NOH + 9O 2→ 8CH3COOH + 2N 2 + 6H2O Another feature of DEHA is its volatility, which is simi lar to morpholine. It extends throughout the feedwater, boiler and into the condensate system where it scavenges oxygen, passivates metal surfaces and any remaining DEHA contributes to condensate pH neutralization.
19
HYDROGEN ATTACK
CORROSION FATIGUE
This type of corrosion results in embrittlement or cracking of the tube metal, damaging of the internal structure of the metal.
Corrosion fatigue manifests itself as a series of fine cracks in the tube wall. These cracks are aggravated by other corrosive conditions within the boiler which will ultimately result in tube failure. This form of corrosion usually attacks the tube walls of high pressure boilers. It occurs generally in the high temperature areas of the tubes where irregular water circulation has been experienced and alternating stresses have been set up in the tube material.
Hydrogen ions are generated by the concentration of acids under a hard dense deposit. The hydrogen ions i ons (H+) are the smallest of all elements and can penetrate the grain boundaries of the tube metal. They react with carbon atoms present in the steel to form methane.
MECHANICAL CORRECTION
Methane (CH4) is a large gas molecule which exerts pressure within the metal. The high pressure combined with the weakening caused by degraphiting forces the grains of steel to separate. Eventually, Eventual ly, cracks in the metal develop.
The evaporator should be operated properly to avoid carryover which will introduce contaminants as described above. Condenser piping must be maintained to prevent leaking condenser tubes which will introduce seawater.
Hydrogen attack can occur very rapidly. Tube metal fails and ruptures when the section can no longer withstand the internal pressure.
The boiler should be operated within the design specifications in order not to overload the steam production produ ction capacity which leads to steam blanketing.
CAUSTIC CORROSION Proper burner alignment and correct atomization of the fuel oil are essential to avoid flame impingement of hot spots.
Caustic attack is characterized by irregular patterns of gouging of the metal. It is often referred to as "caustic gouging".
CHEMICAL TREATMENT Caustic corrosion results from the presence of an excess of free hydroxide (OH) in the boiler water, indicated by a very high pH.
Acidic corrosion can be prevented by the maintenance main tenance of a proper boiler water alkalinity. Adequate dosages of an alkaline material such as sodium hydroxide (GCTM concentrated alkaline liquid) will maintain the recommended alkalinity range and eliminate the possibility of acid attack. Please note: The alkalinity level may be measured directly in "ppm" or indirectly using the corresponding pH ranges. Maintain the recommended range of alkalinity or pH according to the treatment program.
Much like an acid, caustic corrosion may occur beneath layers of deposits which have formed on heat transfer surfaces allowing the hydroxide to concentrate and thereby causing severe localized corrosion. Caustic corrosion also will occur in the horizontal or inclined tubes when the interior surfaces become steam blanketed because of excessive boiling (hot spots) or separation of steam and water. Boiler water containing hydroxide can splash onto the steam blanketed surface, and as the water flashes off, the hydroxide remains and concentrates on the metal.
Caustic corrosion readily takes place in ultra high pressure boilers (60 kg/cm2, 850 psig and over) in the presence of free caustic. The Drew ULTRAMARINE SM coordinated phosphate-pH boiler water treatment program used in high pressure boilers eliminates free hydroxide (OH -) in the boiler water. (This program will be described in detail later in this book). Maintain the balance of treatment chemicals to minimize free caustic.
CAUSTIC CRACKING CORROSION Corrosion caused by caustic cracking is a type of intercrystalline cracking. When highly caustic (alkaline) water comes in contact with steel under stress, intercrystalline cracking crackin g can result. (Metals can be stress relieved, that is reheated at low temperatures to relieve internal stresses). This type of corrosion occurs along the crystal boundaries of a metal or an alloy.
The application of the ULTRAMARINE coordinated phosphate-pH boiler water treatment will also assist in inhibiting hydrogen embrittlement, embrittle ment, primarily by the buffering action of the phosphate and the pH control in the boiler water.
20
COMPOSITION AND FORMATION OF DEPOSITS Since water is a universal solvent, it dissolves practically all materials which it contacts to a certain extent. However, materials have differing solubilities in water depending upon the temperature, pressure, pH, mineral composition, and contact time. Solubilities are grouped into three general categories: very soluble solids, slightly soluble solids, and relatively insoluble solids. Under certain operating conditions, any one of these may produce undesirable deposits which will reduce operating efficiency.
Salts may enter the boiler system as poor quality evaporator distillate, seawater in-leakage, in-le akage, or shore water makeup. Some are very soluble and cause few problems because of their relative solubility. For example, sodium salts are very soluble compounds. However, contaminants can volatilize and carry over with the steam and deposit on superheater tubes or on turbine blading. Slightly soluble solids are soluble at atmospheric conditions; however, an increase in the temperature and pressure will cause precipitation and/or deposition. The primary examples of this type of solid are salts of calcium and magnesium. For example, the solubility of calcium sulfate increases up to approximately 38OC (100OF) but then decreases rapidly as the temperature is increased above this level.
DISSOLVED INORGANIC SOLIDS are materials which dissociate in water into their ionic parts (cations and anions). Most organic materials are not highly ionized (see discussion later in this section). The major minerals encountered in seawater are combinations of the following dissolved (ionized) constituents: Positive Ions (Cations) Calcium+2 Magnesium+2 Sodium+1 Potassium+1
Only a very small quantity of the so-called insoluble solids will dissolve in water. Suspended solids, solids, which do not dissolve, will deposit or disperse and circulate with the water. Following is a list of these materials that are most likely to be found as boiler water suspended solids:
Negative Io Ions (A (Anions) -2 Carbonate Bicarbonate-1 Sulfate-2 Silicate-2 Chloride-1
Material
Composition
Source
Red iron oxide Magnetic iron
Fe2O3 Fe3O4
Copp Copper er me meta tall and and copp copper er oxid oxides es Clay Calcium carbonate
Cu, Cu, Cu Cu2O and and CuO Complex silicates of Al, Fe, and Mg CaCO3
Calcilum silicate Tricalcium phosphate
CaSiO3 Ca3(PO4)2)
Calcium hydroxyapatite* Magnesium hydroxide* Magnesium silicate* ("Serpentine") Magnesium phosphate
3Ca3(PO4)2Ca(OH) 2 Mg(OH2) 3MgO•2SIO2•2H2O
Oily sludge
Organic Mixtures
Corrosion of feed or return lines or boilers. Corrosion of return lines or boilers or conversion of suspended Fe2O3. Corro orros sion ion of of cond conden ense serr tub tubes es and and ev evapor aporat ator ors. s. Introduced by contamination of feed water with seawater, low quality shore or brackish water. Introduced by seawater contamination as a reaction product formed by heating water that contains calcium bicarbonate. Reaction product from water that contains calcium and silica Formed when water is overtreated with phosphate and undertreated with sodium hydroxide, and this material is very likely to adhere to metal surfaces. Formed when proper treatment controls are maintained. Formed when proper treatment controls are maintained. For Forme med d in in wat water er that that cont contai ains ns silic ilica a whe when n pro prop per trea treattment ent controls are maintained. Formed when water is overtreated with phosphate. This material is very likely to adhere to metal surfaces. Formed when any of the above solids absorb oil present in the system.
Mg3(PO4)2
*Starred items are minerals that may be produced as a result of normal chemical water treatment and which are the least likely to form adherent sludge deposits. Of the suspended solids in the boiler boil er water, these substances are preferred since they easily can be removed by blowdown.
21
In addition to the above, there are metallic oxides and salts of iron and copper which enter the boiler as corrosion products. The sources of iron may be from corrosion in steam systems and in return lines. Some oxides are from internal corrosion in boiler generating tubes, the drum surfaces or feed line. Corrosion of the main and auxiliary condensers or of evaporator condensers is one of the sources of the copper and copper oxide materials. (See the previous section on "Formation of Oxides").
Continuous or surface blowdown (blowdown from the upper areas of the boiler) removes circulating boiler water which contains a high percent of the dissolved solids. This blowdown location keeps the concentration of dissolved solids under control.
Organic contamination may enter the boiler system via leaks in the cargo or fuel heating coils or other auxiliary feed lines. Types of organics include petroleum products (e.g., oil or lubes), cargo liquids (e.g., organic chemicals), or microorganisms (e.g., bacteria). Organic materials tend to decompose and can act as binders for the suspended solids so that they adhere to the interior tube metal walls.
Chemical Treatment
Header blowdown (an intermittent blow from a header location) reduces accumulated, suspended or floating solids, and also removes high dissolved solids concentrations.
Not all contaminants can be removed naturally by blowdown but require chemical assistance. The formation of undesirable deposits can be prevented by treating the water with chemicals that convert the undesirable dissolved hardness constituents to harmless suspended solids. These solids gradually settle out in the mud drum of the boiler as a nonadherent fluid sludge which can be removed by blowdown. The standard treatment used is a combination of soluble phosphate(ADJUNCT ® B phosphate boiler water treatment) and an alkaline liquid (GCTM concentrated alkaline liquid). Some one drum combination products, such as AGK ® 100 boiler and feedwater treatment, combine phosphate, alkali, oxygen scavenger amines and other water conditions into a complete treatment. AGK 100 treatment is not a "one-shot" treatment but rather a complete package which must be fed continuously to provide complete protection. (Also, see the section on "Coordinated Phosphate-pH Treatment" that follows).
DEPOSIT FORMATION AND PREVENTATIVE MEASURES Scale:A Scale: A "true" scale is a crystalline solid which is found at the point in the boiler system at which it is formed. Scale materials are formed by oversaturation and precipitation of hardness constituents (calcium and magnesium) on heat transfer surfaces. Metal oxide deposits are formed by the reaction of an aggressive solution or gas in contact with the metal surface at the point where the oxide is found. It may come from another part of the system and accumulate at that location. Metal oxides can combine with other contaminants to form deposits. This is another reason why corrosion should be controlled by mechanical as well as chemical methods. (See previous section on "Corrosion of Metals").
Any existing hardness scales are not rapidly removed by the boiler water treatment chemicals and special chemical cleaning methods should be employed. (See the section entitled "Chemical Cleaning").
Sludge is generally a mixture of loose fluid particles composed of organic, inorganic and/or corrosion products. The sludges that result from water treatment reactions are preferred to the scale that would otherwise form.
If the water treatment program is controlled within the limits set for the phosphate and alkalinity, the sludges which will develop will not be sticky and will not adhere to the metal surfaces.
Sludges must be removed on a regular schedule or the accumulation of sludges at the low flow points may block the water flow patterns. Restriction of this flow may cause "starvation" of some areas and ultimately the overheating of metal.
If feedwater becomes contaminated by oil, LIQUID COAGULANT TM boiler sludge conditioner should be dosed to the boiler to coagulate the oil droplets. These conditioned suspended solids will settle to the low points of the boiler where they are removed by blowdown, thus preventing foaming and carryover and lowering deposit adherence characteristics.
Scales and baked-on sludges in any heat transfer area can act as "insulators". Interference with heat transfer results in reduced fuel efficiency and potentially tube failure.
Coordinated Phosphate-pH Program(ULTRAMARINE Program (ULTRAMARINESM) Caustic corrosion is one of the most frequent and most serious causes of metal damage in high pressure boilers (over 60 kg/cm2, 850 psig). This type of corrosion results from the action of "free caustic" at heat transfer surfaces causing severe corrosion and metal loss. The caustic conconcentrates in crevices or localized areas beneath porous metal oxide deposits or where thin films of steam are formed leaving concentrated caustic behind on the metal surface. This localization of caustic can cause severe corrosion and may be the result of some physical features of the boiler such as design or the mode of operation.
Mechanical Correction Blowdown is the method used to remove the dissolved and suspended solids from the boiler systems, and blowdown procedures should be based on boiler manufacturers' instructions. 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 have settled out of the water. If these contaminants are not removed regularly, they will build up until they hinder circulation patterns.
22
The Drew ULTRAMARINE SM program has been specifically designed to minimize "free caustic" conditions in high hi gh pressure boilers by adjusting and controlling the chemical balance of pH and phosphate in the boiler boil er water. The Drew ULTRAMARINE Program is a coordinate phosphate-pH boiler water treatment program. The addition of Drew GC TM concentrated alkaline liquid and ADJUNCT ® B boiler water treatment establishes an equilibrium in the boiler boil er water as shown in the equation below: Na2HPO4 + NaOH disodium + sodium (ortho) hydroxide phosphate
The alkalinity or pH range is controlled so that it protects the boiler steel in a passivated state and coordinates with the phosphate concentration to insure the formation of fluid non-adherent sludges. These levels are coordinated in a balance that will prevent a condition of excess or "free caustic". (See the graph of coordinated phsophate-pH control below). All the other water treatment controls must be monitored closely because high pressure boilers have lower tolerances for variations in chemical levels and total dissolved solids. This lower tolerance for chemicals and solids does not distinguish between treatment chemicals and contaminants so overall control of all critical boiler water chemistry is a necessity.
Na3PO4 + H2O trisodium + water (ortho) phosphate
PPM PO4 (DERIVED FROM TSP) ULTRAMARINE COORDINATED PHOSPHATE-----pH CURVE
23
SPECIAL SPECIA L OPERATING OPERATING CONDITIONS CONDITI ONS Special attention must be given to operating conditions which are unusual or those which are not no t directly related to normal steaming conditions. The water treatment procedures which are employed during "slow-speed" steaming are just as important as the chemical treatment program during the normal boiler operations. The following situations should be given full consideration.
If the boiler has been drained, the AMERZINE inhibitor should be added as it is filled to the normal level leve l and fired up. The boiler must be operated long enough to provide sufficient circulation to obtain a uniform concentration of the oxygen scavenger throughout the boiler water to eliminate the oxygen. If the boiler has been in operation, dose 1.3 liters of AMERZINE inhibitor for each ton of boiler capacity at the test level (100% full).
LOW SPEED STEAMING If a boiler is to be operated at substantially reduced reduce d loads, the correct water treatment chemical concentrations must be maintained at all times. This is because excessive corrosion and deposition conditions may be exaggerated by the decreased water circulation rates especially in high heat input areas and reduced efficiency of pre-boiler equipment such as deaerations.
After inspection or cleaning, a boiler should not be allowed to stand open or wet since atmospheric corrosion or o r "flash rusting" will occur. In addition, boilers should not be returned to service if residual corrosion products or deposits are present. They should be cleaned before their return to service.
CHEMICAL CLEANING
A potentially more serious situation occurs when firing rates are reduced, which disrupts temperature gradients across all of the boiler sections. In effect, some generating tubes which normally are risers may become stagnan t or even downcomers.
Efficient operation of the boiler system, as with all equipment, is dependent upon cleanliness and freedom from obstructions in the water or gas pass circuits. Precommission cleaning of new equipment is required to remove oils, corrosion products, millscale and debris which may have accumulated during construction.
At extremely reduced steaming conditions, many tubes can become stagnant since they are in a transition zone where they are neither risers nor downcomers downc omers but rather "percolate" in a static condition. conditi on. If percolation occurs, the lack of circulation in high heat input areas tends to permit steam blanketing and tube overheating, thereby concentrating the dissolved solids solid s at the metal-water interfaces. To help alleviate this condition in a two boiler system, it may be advisable to put one boiler in standby and operate the other at a more normal load condition.
Carefully controlled treatment programs can keep most systems trouble-free; however, in certain conditions an emergency cleaning action may be necessary because of accidental contamination, tube failure, or accumulations of deposits and oxide deposits. All chemical treatment programs require strict adherence to the recommended procedures to produce the desired results. Chemical cleaning solutions, their byproducts, and residuals must be removed before returning the system to service, thereby avoiding any additional contamination or corrosion.
STANDBY AND IDLE BOILERS Boiler water chemical levels (non-volatile) in standby boilers should be kept within the same ranges that are indicated for the full steaming conditions. When any boiler is off-line for extended periods of time, proper dry or wet layup procedures are essential to prevent corrosion. Successful dry layup procedures depend upon the elimination of all moisture from inside the boiler. boil er. Corrosion will not occur if moisture is eliminated. However, it is almost impossible to eliminate all moisture; therefore, the use of "wet" layup procedures is the most practical and preferred corrosion control method for all but very extended layup periods. Boilers placed in "wet" layup are not maintained under pressure. During these periods adequate protection against oxygen gas corrosion must be employed by introd ucing a high concentration of AMERZINE ® corrosion inhibitor (approximately 150-200 ppm or 1.3 liter/ton).
24
BOILER WATER TREATMENT CHEMICALS LIQUID COAGULANT TM boiler sludge conditioner: conditioner: LIQUID COAGULANT conditioner is a colorless, high molecular weight solution used in both medium and low pressure boilers to prevent sludge deposits. It is especially useful when feedwater becomes contaminated by oil. Dosing LIQUID COAGULANT COAGULANT conditioner to the boiler coagulates the oil droplets, causing these suspended solids to settle to the low points of the boiler where they are removed from blowdown.
ADJUNCT ® B phosphate boiler water treatment: ADJUNCT B treatment is a specially formulated powdered phosphate used in conjunction with GCTM liquid in both high and low pressure boilers to control scale formation due to hardness. The soluble phosphate from ADJUNCT B treatment in alkaline boiler water combines with the incoming hardness to form a soft, nonadherent sludge. neutralizes GCTM concentrated alkaline liquid: liquid: GC liquid neutralizes acid and controls corrosion. GC liquid provides a suitable pH environment for the efficient reaction of the phosphate treatment with the hardness constituents to maintain the resulting sludges in a fluid state.
AGK ® 100 boiler and feedwater treatment: treatment: AGK 100 treatment is a unique multi-functional liquid formulation of organic sludge conditioners, coagulants, oxygen scavengers, and inorganic contaminant dispersing and precipitating agents. AGK 100 treatment controls waterside scale and sludge deposits and corrosion conditions in low pressure boilers using distilled water as makeup (up to 32 kg/cm2, 450 psig). The single multi-functional production formulation of the Drew AGK 100 treatment program can replace multiproduct conventional water treatments in these systems.
AMERZINE ® corrosion inhibitor: inhibitor: AMERZINE inhibitor is a liquid catalyzed oxygen scavenger used to minimize oxygen corrosion in boiler steam and condensate systems. AMERZINE (hydrazine) prevents the corrosion of iron and copper by oxygen and promotes the formation of protective iron and copper oxide films.
DREWPLEX ® AT 100 boiler water treatment: treatment: DREWPLEX AT treatment is a phosphate-based treatment combined with synthetic polymers providing the ultimate in simplicity, system flexibility and treatment control for all motor vessel auxiliary and exhaust gas economizer boilers. DREWPLEX AT boiler water treatment provides a cleaner boiler by allowing greater tolerance of feedwater quality fluctuations.
SLCC-ATM condensate corrosion inhibitor: inhibitor: SLCC-A inhibitor is a volatile liquid organic amine designed to minimize corrosion in steam and condensate systems. SLCC-A inhibitor condenses with the steam, providing a pH environment which neutralizes the corrosive effects of carbon dioxide (Carbonic Acid).
DREWPLEX OX corrosion inhibitor: inhibitor: DREWPLEX OX corrosion inhibitor is a safe-to-use, unique, and an d fast-acting catalyzed oxygen scavenger scavenge r for use in low, medium and high pressure steam generating systems. Because DREWPLEX OX corrosion inhibitor is volatile, excess in the feedwater will be carried through the boiler with the steam and into the condensate system, thereby protecting the entire boiler system from oxygen corrosion. The catalyst in DREWPLEX OX corrosion inhibitor accelerates the rate of oxygen removal in the feedwater, thereby improving corrosion protection in the preboiler section.
25
BOILER WATER TREATMENT CHEMICAL APPLICATIONS AND CONTROLS Control Limits for Boiler Water and Condensate ULTRAMARINESM program: Boiler Pressure Pressure 60-84 kg/cm2 (850-1200 psig) Boiler Water Tests
Treatment
Control Limits
Phosphate pH HYDRAZINE/AMERZINE ® Chloride Conductivity Si l i c a
ADJUNCT ® B GCTM AMERZINE Blowdown Blowdown Blowdown
1 5 - 2 5 p pm 9.8 - 10.2 0.03 - 0.10 ppm 16 ppm max. 120 µmhos max. 6 ppm max.
SLCC-ATM Deaeration
8.6 - 9.0 0.5 ppm max.
Condensate Tests pH Ammonia
STANDARD: Boiler Pressure 32-60 kg/cm2 (450-850 psig) Boiler Water Tests
Treatment
Control Limits
Phosphate P. Alkalinity T. Alkalinity HYDRAZINE*/AMERZINE Sulfite Chloride Conductivity
ADJUNCT B GC GC AMERZINE CATALYZED SULFITE Blowdown Blowdown
2 0 - 4 0 p pm 90 - 130 ppm Less than 2 x P. Alkalinity 0.03 - 0.10 ppm 10 - 15 ppm 36 ppm max. 700 µmhos max.
SLCC-A
8.3 - 8.6
Condensate Tests pH
STANDARD: Boiler Pressure 0-32 kg/cm2 (0-450 psig) Boiler Water Tests
Treatment
Control Limits
Phosphate P. Alkalinity T. Alkalinity HYDRAZINE*/AMERZINE Sulfite Chloride Conductivity
ADJUNCT B GC GC AMERZINE or CATALYZED SULFITE Blowdown Blowdown
2 0 - 4 0 p pm 100 - 150 ppm Less than 2 x P. Alkalinity 0.03 - 0.10 ppm 20 - 30 ppm 300 ppm max. 700 µmhos maximum
SLCC-A
8.3 - 8.6
Condensate Tests pH
NOTE: Hardness tests of boiler water are not necessary when the phosphate 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
BOILER WATER TREATMENT PHOSPHATE: Dosage of ADJUNCT ® B phosphate boiler water treatment per ton boiler water.
0-32 kg/cm2 (0-450 psig)
Phosphate Test Results (ppm)
P r e s s u r e R a n g e 32-60 kg/cm2 60-84 kg/cm2 (450-850 psig) (850-1200 psig) Dosage Requirements
0 3 6 9 12 15 18 2 0 - 25 2 5 - 40 40+
30 gm (1 oz.) 30 gm (1 oz.) 30 gm (1 oz.) 30 gm (1 oz.) 15 gm (.5 oz.) 15 gm (.5 oz.) 15 gm (.5 oz.) Satisfactory Satisfactory Blowdown
30 gm (1 oz.) 30 gm (1 oz.) 30 gm (1 oz.) 30 gm (1 oz.) 15 gm (.5 oz.) 15 gm (.5 oz.) 15 gm (.5 oz.) Satisfactory Satisfactory Blowdown
30 gm (1 oz.) 30 gm (1 oz.) 26 gm (1 oz.) 22 gm (1 oz.) 18 gm (1 oz.) 14 gm (1 oz.) 9 gm (1 oz.) Satisfactory Satisfactory Blowdown
GCTM concentrated alkaline liquid per ton boiler water CAUSTIC: CAUSTIC : Dosage of GC
P. Alkalinity Test Results (ppm)
2
0-32 kg/cm (0-450 psig)
P r e s s u r e R a n g e 32-60 kg/cm2 (450-850 psig) Dosage Requirements
0 - 20 3 0 - 50 6 0 - 80 9 0 - 130 100 - 150 1 30+ 150+
0.15 liter 0.10 liter 0.05 liter -Satisfactory -Blowdown
0.15 liter 0.10 liter 0.05 liter Satisfactory -Blowdown --
GCTM concentrated alkaline liquid per ton boiler water CAUSTIC: CAUSTIC : Dosage of GC Pressure Range 60-84 kg/cm2 (850-1200 psig)
pH Boiler Water Test Results 8.6 or less 9.0 9.0 - 9.3 9.4 - 9.5 9.6 9. 7 9. 8 10.0 10.1 10.2 10.3 or above
Dosage Requirements 14 ml 13 ml 12 ml 11 ml 10 ml 9 ml 8 ml 7 ml 5 ml Satisfactory Blowdown
27
SULFITE: Dosage of CATALYZED SULFITETM corrosion inhibitor
BOILER PRESSURE PSI kg/cm2 (a) Up to 450 (b) 450-850
Up to 32 32-60
(a) or (b) (a) or (b)
RESIDUAL RANGE (ppm as SO3)
DOSAGE REQUIREMENTS
20-30 10-15
Satisfactory Satisfactory
Below satisfactory, Increase 25% Above satisfactory, Decrease 25%
HYDRAZINE/AMERZINE: Continuous Dosage of AMERZINE ® corrosion inhibitor Treatment
Pressure Range
Hydrazine Test Result
Standard
0-60 kg/cm2 (0-850 psig)
Increase dosage by 25% Maintain Decrease dosage by 25%
ULTR ULTRAM AMAR ARIN INE E
60-8 60-84 4 kg/ kg/cm cm2 (850-1200 psig)
Increase dosage by 25% Maintain Decrease dosage by 25%
less than 0.03 0.03 - 0.10 greater than 0.10 Initial dosage is 0.15 liters per ton of boiler water.
less than 0.03 0.03 - 0.10 greater than 0.10 Initial dosage is 0.10 liters per ton of boiler water.
AMERZINE Dosage
CONDENSATE pH: Continuous Dosage of SLCC-ATM condensate corrosion inhibitor Treatment
Pressure Range
Condensate pH
Standard
0-60 kg/cm2 (0-850 psig)
Increase dosage by 25% Maintain Decrease dosage by 25%
ULTR ULTRAM AMAR ARIN INE E
60-8 60-84 4 kg/ kg/cm cm2 (850-1200 psig)
Increase dosage by 25% Maintain Decrease dosage by 25%
less than 8.3 8.3 - 8.6 greater than 8.6 Initial dosage is 0.15 liters per ton of boiler water.
less than 8.6 8.6 - 9.0 greater than 9.0 Initial dosage is 0.10 liters per ton of boiler water.
28
SLCC-A Dosage
AGK ® 100 treatment Supplemented with AMERZINE ® treatment AGK 100 Treatment Initial Dosage:
2.5-5 liters per ton of water in the boiler system
Cont Contin inuo uous us Dosa Dosage ge::
Main Ma inta tain in 40-6 40-65 5 ppm ppm hydr hydrat ate e alk alkal alin init ity y and and 1010-20 ppm ppm pho phosp spha hate te in the the boi boile lerr wat water er..
AGK AGK 100 Dosage Adjustment Hydrate Alkalinity is the primary primar y parameter for adjusting AGK 100 Dosage HYDRATE ALKALINITY
<40 ppm
HYDRATE ALKALINITY
HYDRATE HYDRATE ALKALINITY ALKALI NITY
40 - 65 ppm
>65 ppm
PO4 <10ppm
Increase do dosage by by 2 25 5% and check for seawater or shor shore e wat water er or in-l in-lea eaka kage ge..
Dosage ad adjustment ma may b be e necessary. Check for poss possib ible le hard hardne ness ss in-l in-lea eaka kage ge..
Reduce do dosage by by 10%. Check for shor shore e wat water er in-l in-lea eaka kage ge..
PO4 10 20 ppm
Increase ase do dosag sage by by 20% 20% Check condensate for acidic material in-leakage.
Norm ormal con cond ditio ition n. No dos dosage age adjustment necessar y. adjustment
Reduce uce do dosag sage by by 20% 20% Check for shore water in-leakage.
Increase dosage by 20% Check condensate fo for acidic m ma aterial in in-leakage. Make Ma ke up and/ and/or or feedw eedwat ater er volume may be low or quality may be better than usual.
Dosage adjustment may be necessary. Check fo for a ac cidic material in-leakage. Alka Alkali lini nity ty ma may y be be des destr troy oyed ed by acid contamination. Make up and/or feedwater volume may be low or quality may be better than usual.
Reduce dosage by 25%. Feedwater quality ma may be better tth han us usual.
PO4 >20ppm
NEUTRALIZED CONDUCTIVITY in µmhos
BLOWDOWN ADJUSTMENT
Up to 700 700
Sati Satisf sfac acttory ory
Norma ormall mai maint nten enan ance ce blow lowdown down is suff suffic icie ient nt.. Regul egular ar flas flash h blo blowd wdo own to remove suspended solids should be carried out a minimum of once per week.
Above 700
High
Increase frequency of blowdown.
Boiler Water Hydrazine in ppm
Above 0.10 0 . 0 3 - 0 .1 0 Below 0.03
AMERZINE DOSAGE ADJUSTMENT Dosage is necessary only when HYDRAZINE test results are low with AGK 100 dosage alone. Initial Dosage: Dosage: 100 ml/day
High Satisfactor y Low
Decrease No Change Increase
29
DREWPLEX ® AT boiler water treatment and DREWPLEX OX corrosion inhibitor for Motor Vessels DREWPLEX AT/DREWPLEX OX Treatment Initial Dosage: 2.5-5 liters per ton of water in the boiler system Cont Contin inuo uous us Dosa Dosage ge::
Main Ma inta tain in 40-6 40-65 5 ppm ppm hydr hydrat ate e alk alkal alin init ity y and and 10-2 10-20 0 ppm ppm phos phosph phat ate e in in the the boil boiler er water ater
DREWPLEX AT AT Dosage Adjustment Hydrate Alkalinity is the primary parameter for adjusting DREWPLEX AT AT Dosage HYDRATE ALKALINITY ALKALINITY HYDRATE ALKALINITY ALKALINITY
<40 ppm Increase dosage by 25% and check PO4 <10ppm for seawater or shore water or in-leakage. Increase do dosage by by 20%. Check condensate for acidic mate ma teri rial al in-l in-lea eaka kage ge..
PO4 10 20 ppm
Increase dosage by 10%. Check condensate for acidic material PO4 >20ppm in-leakage. Make up and/or feedwa dwater volum lume may be low or quality may be bet better than usual. ual.
NEUTRALIZED CONDUCTIVITY in µmhos
HYDRATE HYDRATE ALKALINITY
40 - 65 ppm
>65 ppm
Dosage adjustment may be necessary. Check for possible hardness in-leakage.
Reduce dosage by 10%. Check for shore water in-leakage.
Normal condition. No dosage adjustment nece necess ssary ary..
Reduce do dosage by by 10%. Check for shore water in-leakage.
Dosage adjustment may be necessary. Check for acidic material in-leakage. Alkalinity may be destroyed by acid contamination. Makeup and/or feedwater volume may be lo low or q qu ualit ality y ma may be better than usual.
Reduce dosage by 25%. Feedwater quality may be better than usual.
BLOWDOWN ADJUSTMENT
Up to to 70 700
Satisfactor y
Normal maintenance blowdown is is sufficient. Regular flash blowdown to remove suspended solids should be carried out a minimum of once per week.
Above 700
High
Increase frequency of blowdown.
Feedwater DEHA in ppm Above 0.8 0.4 - 0.8 Below 0.4
DOSAGE ADJUSTMENT DREWPLEX OX Continuous Dosage Initial Dosage: 0.4 liters/ton of water in the boiler system
High Satisfactor y Low
Decrease No Change Increase
30
DREWPLEX ® AT boiler water treatment/AMERZINE ® corrosion inhibitor for Motor Vessels DREWPLEX AT/AMERZINE treatment Initial Dosage: 2.5-5 liliters p pe er tto on of of wa water in in th the bo boiler sy system Cont Continu inuou ous s Dosa Dosage: ge:
Maint Ma intain ain 4 400-65 65 ppm ppm hydrat hydrate e alkali alkalinit nity y and 10-2 10-20 0 ppm pho phosph sphat ate e in the the boiler boiler wat water er
DREWPLEX AT AT Dosage Dosag e Adjustment Hydrate Alkalinity is the primary parameter for adjusting DREWPLEX AT AT Dosage HYDRATE ALKALINITY ALKALINITY HYDRATE ALKALINITY ALKALINITY
<40 ppm Increase dosage by 25% and check PO4 <10ppm for seawater or shore water or in-leakage. Increase d do osage b by y 20%. Check condensate for acidic mate ma teri rial al in-l in-lea eaka kage ge..
PO4 10 20 ppm
Increase dosage by 10%.Check condensate for PO4 acidic material >20ppm in-leakage. Make up and/or feed eedwate ater volum lume may be low or quality may be better than han usu usual.
NEUTRALIZED CONDUCTIVITY in µmhos
HYDRATE HYDRATE ALKALINITY ALKALI NITY
40 - 65 ppm
>65 ppm
Dosage adjustment may be necessar y. y. Check for possible hardness in-leakage.
Reduce dosage by 10%. Check for shore water in-leakage.
Normal condition. No dosage adjustment nece necess ssar ary y.
Reduce d do osage b by y 10%. Check for shore water in-leakage.
Dosage adjustment may be necessary. Check for acidic material in-leakage. Alkalinity may be destroyed by acid contamination. Makeup and/or feedwater volume may be low or or qua qualit lity may be better than usual.
Reduce dosage by 25%. Feedwater quality may be better than usual.
BLOWDOWN ADJUSTMENT
Up to to 70 700
Satisfactor y
Normal maintenance blowdown is is su sufficient. Regular flash blowdown to remove suspended solids should be carried out a minimum of once per week.
Above 700
High
Increase frequency of blowdown.
Boiler Water Hydrazine in ppm Above 0.10 0 .0 3 - 0 . 1 0 Below 0.03
DOSAGE ADJUSTMENT AMERZINE Continuous Dosage Initial Dosage: 0.15 liters/ton of water in the boiler system
High Satisfactor y Low
Decrease No Change Increase
31
Dosage of LIQUID COAGULANTTM boiler sludge conditioner LIQUID COAGULANT COAGULANT boiler sludge conditioner is "slugfed" daily at a dosage of 30 mls (1 oz.) per ton of boiler water capacity to minimize the effects of oil contamination. When dosing LIQUID COAGULANT conditioner, both bottom flash blowdowns and fast surface blowdowns are recommended.
For systems experiencing severe oil contamination, locate and secure the the leak. Then an off-line cleaning is recommended. Consult your Drew Marine representative representative for specific maintenance chemicals. After the equipment is cleaned, LIQUID COAGULANT conditioner should be dosed at 30 mls (1 oz.) per ton of boiler water capacity per day for two weeks or until complete oil removal is accomplished.
Do not continue to operate a boiler system with severe oil contamination.
LIQUID COAGULANT COAGULANT conditioner should not be used in high pressure boilers.
MAKEUP TURBO ALTERNATOR AUX. CONDENSER
L.O. COOLER BOILER
L.P. TURBINE
H.P. TURBINE
MAIN CONDENSER
DISTILLER
GLAND EXHAUST CONDENSER L.P. HEATER
H.P. HEATERS
FEED PUMP
DEAERATOR
DRAINS RETURN TANK
HEATING SERVICES OBSERVATION TANK
STEAM PROPULSION SYSTEM 1. AMERZINE 2. SLCC-A INJECTION POINTS 3. ADJUNCT B INJECTION POINTS 4. GC INJECTION POINTS
32
33
Boiler Water Treatment Control Tests In Alphabetical Order (pages 35-58)
Cooling Water Treatment Control Tests In Alphabetical Order (pages 63-66)
34
HYDRATE ALKALINITY TEST FOR AGK 100 and DREWPLEX® AT TREATMENTS ®
Before testing, boiler water, hot condensate, and feedwater samples must be cooled to 25 OC (77OF) by collecting through a sample cooler for safety and to prevent flashing which concentrates the sample. Read MSDS before running these tests. NOTE: If the sample is colored or turbid, filter before running the test. If the sample remains cloudy after the first filtering, the sample should be refiltered through the same filter paper since the filter becomes more retentive on the second filtration. (Filter paper is supplied separately). HYDRATE ALKALIN ALKALINITY ITY TEST KIT (PCN #0388-01-8)
APPARATUS
REAGENTS
1 Plastic Titration Vial Marked at 12ml 1 Dropper Pipette Marked at 0.5 and 1.0ml
7 x 60ml Barium Chloride 10% 3 x 60ml Sulfuric Acid N/10 1 x 30ml Phenolphthalein
PROCEDURE
1. Rinse and fill the plastic titration titration vial to to the line (12 ml) with cooled boiler water sample. 2. Pipette Pipette 2 ml of Barium Chloride Chloride 10% into into the vial and and swirl swirl to mix.
12 ml
1 2
3. Add 2 drops of Phenolph Phenolphthalei thalein n Indicator Indicator and swirl. swirl. IF THE SAMPLE DOES NOT TURN PINK, the Hydrate Alkalinity level is zero. Record zero on the Onboard Graphing Log and adjust dosage to increase hydrate hydrate alkalinity. IF THE SAMPLE TURNS PINK, counting the drops, add Sulfuric Acid N/10 until the sample is colorless (disregard the eventual reappearance of a pink color). Swirl the vial between drops. 4. Calculate Calculate the Hydrate Hydrate Alkalinity concentra concentration tion as follows: follows: Number of drops of Sulfuric Acid N/10 x 5 = ppm Hydrate Alkalinity as OH.
5. Record the Hydrate Hydrate Alkalinity level level on the Onboard Graphing Log. Make dosage adjustments as needed.
3
5
CONTROL LIMITS Hydrate Al Alkalinity Below 40 ppm 40-65 ppm Above 65 ppm
Dosage Increase No change Decrease
35
ALKALINITY TITRATION FOR MEDIUM TO LOW PRESSURE BOILER SYSTEMS Read the MSDS before performing this test procedure. Before testing, samples must be cooled to 25 OC (77OF) by collecting through a sample cooler for safety and to prevent flashing which concentrates the sample.
APPARATUS
REAGENTS
LP Alkalinity Titration Assembly Graduated Cy Cylinder, 50 ml Evaporating Dish Plastic Stirring Rod
PCN 0380-01-4 PCN 0237-02-5 PCN 0218-01-7 PCN 0417-01-5
PROCEDURE
N/10 Sulfuric Acid, 500 ml Phenolphthalein Indicator, 120 ml Total Alkalinity Indicator GP, 120 ml
PCN 0319-09-6 PCN 0311-01-9 PCN 0355-19-9
1.
Fill the the burette burette by by squeezing squeezing the plastic plastic bottle bottle of N/10 N/10 Sulfuric Sulfuric Acid. Acid. Allow Allow the solusolution in the burette to settle to the 0.0 mark.
2.
Measure Measure 50 ml of of cooled cooled sample sample using using a graduated graduated cylinder cylinder..
3.
Transfer ransfer the measure measured d samp sample le into into an evapo evaporati rating ng dish. dish.
Phenolphthalein Endpoint
2
1
4.
Add 4 drops drops of of Phenolpht Phenolphthalei halein n to the the sample. sample. If the the solution solution turns turns pink, pink, proceed proceed to step 5. If the solution does not turn pink, record Phenolphthalein Alkalinity as 0.0 on the Onboard Graphing Log and refer to the GC Dosage Chart for immediate dosage of GC.
5.
Turning the the stopcock stopcock on the burett burette, e, add N/10 N/10 Sulfuric Sulfuric Acid to to the sample sample drop drop by drop while stirring continuously until the pink color disappears and the sample is back to its original color. color. This is the Phenolphthalein Phenolphthalein Endpoint. NOTE: Do not dispose of the sample in the evaporating evaporating dish or refill the burette. This same sample is used for the Total Total Alkalinity Test Test and the total amount of acid added must be measured.
6.
Read the the level level of the N/10 N/10 Su Sulfuric lfuric Acid Acid solution solution on the the burette burette.. Refer Refer to the Medium Medium to Low Pressure Alkalinity Conversion Table on Page 36 and find the number which corresponds to the burette reading. Beside this number you will find find the equivalent Phenolphthalein (P) Alkalinity Alkalinity expressed in parts per million (ppm). (ppm). The parts per million Phenolphthalein Alkalinity can also be calculated as follows:
3
ppm Phenolphthalein Alkalinity = mls of N/10 Sulfuric Acid x 100 7.
Record the the Phenolpht Phenolphthalei halein n (P) Alkalini Alkalinity ty as ppm on on the Onboard Onboard Graphi Graphing ng Log. Con Control trol Lim Limit its: s:
0-32 -32 kg/ kg/cm2 32-60 kg/cm2
100-150 ppm 90-130 ppm
Total Alkalinity Endpoint
4&8
8.
Using the same same water water sample sample in the evapora evaporating ting dish, dish, add 4 drops of Total Total Alkalin Alkalinity ity Indicator Indicat or GP. The sample will turn tur n a blue green color.
9.
Without Without refillin refilling g the burette burette,, turn the stopcoc stopcock k and add N/10 N/10 Sulfuric Sulfuric Acid Acid drop by drop stirring continuously. continuously. A pinkish purple color will begin to form around the drops as they fall into the the sample. Continue titrating and stir stir until a permanent pinkish purple color develops throughout the sample. This is the Total Total Alkalinity Endpoint.
10. Read the level level of the N/10 Sulfuric Acid solution solution on the burette. Refer to the Medium to Low Pressure Alkalinity Conversion Table and find the number closest to the burette reading. Beside this number you will find the equivalent Total Total (T) Alkalinity in the sample expressed in parts per million (ppm). The parts per million Total Total Alkalinity can also be calculated as follows: ppm Total Total Alkalinity = mls of N/10 Sulfuric Acid x 100 11. Record the Total (T) Alkalinity Alkalinity as ppm on the Onboard Graphing Graphing Log. 12. 12. Refer Refer to the Control Control and Dosing Dosing Chart for instructi instructions ons on dosing dosing GCTM concentrated alkaline liquid. The total alkalinity endpoint test is only a reference test and should determine GC dosage adjustment only if the T. T. Alkalinity is out of balance. 5&9
6 & 10
Control Limits: 0-60 kg/cm2
36
< 2 P Alkalinity
ALKALINITY TITRATION FOR HIGH PRESSURE BOILER SYSTEMS Read the MSDS before performing this test procedure. Before testing, samples must be cooled to 25 OC (77OF) by collecting through a sample cooler for safety and to prevent flashing which concentrates the sample.
APPARATUS (included in PCN 0441-04-8)
REAGENTS (included in PCN 0437-04-7)
HP Alkalinity Titration Assembly Graduated Cylinder, 50 ml Evaporating Dish Plastic Stirring Rod
PCN 0379-01-7 N/50 Sulfuric Acid, 1000 ml PCN 0237-02-5 Phenolphthalein Indicator, 60 ml PCN 0218-01-7 Total Alkalinity Indicator GP, 60 ml PCN 0417-01-5
PCN 0485-01-2 PCN 0311- -- PCN 0355- -- -
PROCEDURE
1.
Fill the the burette burette by squeezin squeezing g the plastic plastic bottl bottle e of N/50 N/50 Sulfuric Sulfuric Acid. Acid. Allow Allow the solution in the burette to settle to the 0.0 mark.
2.
Measure Measure 50 ml of cooled cooled sample sample using using a graduated graduated cylinder cylinder..
3.
Transfer ransfer the the measured measured sample sample into an evapo evaporati rating ng dish. dish.
Phenolphthalein Endpoint 4.
Add 4 drops of Ph Phenolph enolphthale thalein in to the sample sample.. If tthe he solutio solution n turns pink, proceed to step 5. If the solution does not turn pink, record Phenolphthalein Phenolphthalein Alkalinity as 0.0 on the Onboard Graphing Log and proceed to step 8.
5.
Turning the the stopcock stopcock on the the burette burette,, add N/50 N/50 Sulfuric Sulfuric Acid Acid to the sample sample drop by drop while stirring continuously until the pink color disappears and the 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 the burette. burette . This same sample is used for the Total Total Alkalinity Alkalini ty Test and the total amount of acid added must be measured.
6.
Read the the level level of the N/50 Sulfuri Sulfuric c Acid solution solution on the b burett urette. e. Refer Refer to the the High Pressure Alkalinity Conversion Table on Page 36 and find the number which corresponds to the burette burette reading. Beside this number you will find find the equivalent Phenolphthalein (P) Alkalinity expressed in parts per million (ppm). The parts per million Phenolphthalein Alkalinity can also be calculated as follows:
2
1
3
ppm Phenolphthalein Alkalinity = mls of N/50 Sulfuric Acid x 20 7.
Record the Phenol Phenolphtha phthalein lein (P) Alkali Alkalinity nity as ppm on the the Onboard Onboard Graphing Log.
Total Alkalinity Endpoint 4&8
8.
Using the the same water water sample sample in the evapo evaporatin rating g dish, add add 4 drops of Total Alkalinity Alkalini ty Indicator GP. GP. The sample will turn a blue green color.
9.
Without Without refilli refilling ng the burett burette, e, turn turn the stopcock stopcock and and add N/50 N/50 Sulfuri Sulfuric c Acid drop by drop stirring continuously. continuously. A pinkish purple color will begin to form around the drops as they fall fall into the sample. As the titration continues a slate gray color will be observed. Continue titrating and stir stir until a permanent pinkish purple color develops throughout the sample. This is the Total Total Alkalinity Endpoint.
10. Read the level of the N/50 Sulfuric Acid solution on the burette. Refer to to the High Pressure Alkalinity Conversion Table Table and find the number closest to the burette reading. Beside this number you will find the equivalent Total (T) Alkalinity in the sample sample expressed in parts per million (ppm). The parts per million Total Total Alkalinity can also be calculated as follows: 5&9
6 & 10
ppm Total Total Alkalinity = mls of N/50 Sulfuric Acid x 20 11. Record the Total (T) Alkalinity Alkalinity as ppm on the Onboard Graphing Graphing Log. 12. The alkalinity tests are conducted conducted only as reference tests tests for high pressure boiler systems.
37
ALKALINITY TESTS HIGH PRESSURE BOILERS (Pressure Range: 60-84 kg/cm2 (850-1200 psig) Titrated with N/50 Sulfuric Acid Phenolphthalein and Total Alkalinity Control Tests
Conversion Table mls of titrant (N/50 Sulfuric Acid
ppm Alkalinity as CaCO3
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.2 1.4 1.6 1.8 2.0 2.4 2.6 2.8 3.4 4.0 4.6 5.2
2 4 6 8 10 12 14 16 18 20 22 28 32 36 40 48 52 56 68 80 92 1 04
MMEDIUM TO LOW PRESSURE BOILERS (Pressure Range: Up to 60 kg/cm2 (850 psig) Titrated with N/10 Sulfuric Acid Phenolphthalein and Total Alkalinity Control Tests
Conversion Table mls of titrant (N/10 Sulfuric Acid) 0 .1 0 .2 0 .3 0 .4 0 .5 0 .6 0 .7 0 .8 0 .9 1 .0 1 .1 1 .2 1 .3 1 .4 1 .5 1 .6 1 .7 1 .8 1 .9 2 .0 2 .1 2 .2 2 .3 2 .4 2 .5
ppm Alkalinity
mls of titrant (N/10 Sulfuric Acid)
10 20 30 40 50 60 70 80 90 10 0 11 0 12 0 13 0 14 0 15 0 16 0 17 0 18 0 19 0 20 0 21 0 22 0 23 0 24 0 25 0
2 .6 2 .7 2 .8 2 .9 3 .0 3 .1 3 .2 3 .3 3 .4 3 .5 3 .6 3 .7 3 .8 3 .9 4 .0 4 .1 4 .2 4 .3 4 .4 4 .5 4 .6 4 .7 4 .8 4 .9 5 .0
38
ppm Alkalinity as CaCO 3 2 60 2 70 2 80 2 90 3 00 3 10 3 20 3 30 3 40 3 50 3 60 3 70 3 80 3 90 4 00 4 10 4 20 4 30 4 40 4 50 4 60 4 70 4 80 4 90 5 00
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 Ampoules 1 Snapping Cup 1 Color Comparator Card Included in the ULTRAMARINE 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 prevent flashing which concentrates the sample.
1. Fill the the snapping snapping cup complet completely ely with with cooled cooled condensate condensate.. SNAPPING CUP FILL COMPLETELY
2.
Place the tapered tapered tip of an ammonia ammonia ampou ampoule le into into one of the holes in the snapping cup. Keeping the tip immersed in the sample, break the tip by tilting the ampoule towards the opposite wall of the snapping cup and allow the ampoule to fill completely.
3.
Remove Remove the ampou ampoule le from from the snapping snapping cup cup.. Mix the contents by inverting the ampoule back and forth several times for 30 seconds.
1 2
3
15:00
Ashland Specialty Chemical Drew Marine Division AMMONIA, ppm
4 0
0.1
0.3
5
0.5
0. 7
4. Wait 15 minutes for full color development.
5. Compare Compare the the color color of the the ampoule ampoule with with the the color color standards standards.. Report the ammonia level on the ULTRAMARINE ULTRAMARINE Onboard Graphing Log as ppm ammonia.
Control Limit 60-84 kg/cm2 (850-1200 psig) 0.5 ppm maximum
39
CHLORIDE TEST FOR HIGH PRESSURE BOILER SYSTEMS
DREW CHLORIDE HP TEST KIT (PCN 0372-01-1) INCLUDES: 1 Glass Flask for Sample 1 Plastic Dropper Plug for Mixed Chloride Indicator 1 White Plastic Bottle Cap for Mixed Chloride Indicator 2 x 60 ml (2 oz.) Mercuric Nitrate 1 x 30 ml (1 oz.) Nitric Acid N/5 1 x 30 ml (1 oz.) Mixed Chloride Indicator Solution 1 Glass Vial Powder Indicator This test kit is included in the ULTRAMARINESM 6 Month Reagent Set (PCN 0437-04-7).
... ... ... ...
Prepare the Mixed Chloride Indicator as follows: a
Mixed Chloride Indicator
b
Dropper Plug
c
Mixed Chloride Indicator
Mixed Chloride Indicator
a. Unscrew Unscrew the black caps caps of the small small glass vial and the 1 oz. plastic plastic bottle labeled "Mixed Chloride Indicator". b. Pour the powder powder contents contents of the small small glass vial into the liquid liquid contents of the 1 oz. plastic bottle.
d
Mixed Chloride Indicator
Mixed Chloride Indicator
c. Screw the the black cap back onto onto the Mixed Chloride Chloride Indicator Indicator bottle bottle and mix for 5 seconds. d. Remove Remove the black screw screw cap. Insert Insert the plastic dropper dropper plug into the the mouth of the plastic bottle and screw the white cap onto the bottle. Proceed with the test.
PROCEDURE
1
1. Prepare the sample flask by flask by rinsing the glass flask and fill to the mark (24 ml) with the water to be tested.
2
2. Adjust the color of the sample by adding 6 drops of Mixed Chloride Indicator and swirl to mix. The resulting color will be light red. Nitric Acid Acid
3. Adjust the pH by adding Nitric Acid N/5 dropwise, swirling between drops until the sample is yellow. Add 1 more drop.
3
Mercuric Nitrate Nitrat e
4
4. Counting the drops, drops, hold the glass flask in a vertical position and add Mercuric Nitrate dropwise with swirling until the color turns to a permanent purple. 5. Calculate the chloride concentration Number of drops of Mercuric Nitrate x 1 = ppm chloride as Cl 6. Record Record results as ppm chloride chloride on the Onboard Onboard Graphing Graphing Log. Control Limit 16 ppm maximum 40
CHLORIDE TITRATION FOR 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 prevent flashing 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 first first filtering, the sample should be refiltered through the same filter paper since the filter becomes more retentive on the second filtration.
This procedure is preferred for systems which are expected to contain low chloride l evels because it is more sensitive than 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 Graduated Cylinder, 50 ml Evaporating Dish Plastic Stirring Rod
PCN 0382-01-0 PCN 0237-02-5 PCN 0218-01-7 PCN 0417-01-5
PROCEDURE
Mercuric Nitrate, 500 ml N/5 Nitric Acid, 120 ml Mixed Chloride Indicator Solution, 100 ml Mixed Chloride Indicator Powder, 5 caps
PCN 0475-09-6 PCN 0479-19-7 PCN 0477-19-1 PCN 0478-01-7
1. At lea least st every every four four weeks weeks prepar prepare e fresh fresh Mixed Mixed Chloride Chloride Indicator Solution. Discard any Mixed Chloride Indicator Solution that that is more than than four weeks old. Prepare new solution as follows: a. Empty a capsule capsule of Mixed Mixed Chlorid Chloride e Indicato Indicatorr Powder Powder into into the bottle of Mixed Chloride Indicator Solution. b. Cap and mix mix by swirling swirling or or shaking shaking the bottle bottle gently. gently.
1
2. Fill the the burette burette by by squeezing squeezing the plastic plastic bottle of Mercuri Mercuric c Nitrate. Allow the solution in the burette to settle to the 0.0 mark.
2
3. Measure Measure 50 ml of cooled sample using a graduated graduated cylinder. cylinder. 50 ml
4. Transfer Transfer the measured measured s sample ample into an evapora evaporating ting dish. 4
5. Add 10 10 drops drops of prepared prepared Mixed Mixed Indicat Indicator or Solution Solution and stir. stir.
3
6. Add N/5 N/5 Nitric Nitric Acid, Acid, drop drop by drop, stirring stirring continuou continuously sly until until the sample just turns yellow. Add 5 more drops of acid. 7. Turning Turning the stopcock stopcock on the burett burette, e, add Mercuric Mercuric Nitrat Nitrate e to the sample drop by drop while stirring stirring continuously. The endpoint is reached when the color changes to a permanant violet.
5&6
8. Read the level level of the Mercur Mercuric ic Nitrate Nitrate solution solution on the burett burette. e. Refer to the Chloride/Mercuric Nitrate Conversion Table on Page 42 and find the number which corresponds to the burette reading. Next to this number you will find the equivalent chloride content expressed in parts per million million (ppm). The parts per million chloride can also be calculated as follows: ppm chloride = mls of Mercuric Nitrate x 10 9. Record Record result results s as ppm ppm chloride chloride on the Onboard Onboard Graph Graphing ing Log. Log. 7
Control Limit: 16 ppm maximum
41
CHLORIDE TEST FOR 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 Nitrate 1 x 30 ml (1 oz.) Sulfuric Acid N/10 1 x 30 ml (1 oz.) Phenolphthalein 1 x 60 ml (2 oz.) Potassium Chromate This test kit is included in the Alkalinity/Chloride Reagent Set (PCN 0301-02-8).
PROCEDURE 1. For samples less than 100 ppm chloride Rinse the plastic vial and fill to the mark (10 ml) with sample to be tested. 1
or
plastic vial
glass tube
For samples greater than 100 ppm chloride Rinse the tall glass test tube and fill to the mark (2 ml) with sample to be tested. 2. Neutralize the sample by adding 3 drops of Phenolphthalein Phenol phthalein Indicator to the sample. Swirl to mix. If the sample turns pink, add Sulfuric Acid N/10 dropwise with swirling until the sample turns clear. Add 1 more drop. If the sample does not turn pink, add 1 drop of Sulfuric Sul furic Acid N/10. 3. Adjust the color of the sample by adding 6 drops of Potassium Chromate. The sample will be yellow. 4. Counting the drops, drops, add Silver Nitrate N/10 dropwise. Swirl between drops until the sample turns orange.
2, 3, 4, 5
5. Calculate the Chloride Concentration If 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 Record results as ppm chloride chloride on the Onboard Onboard Graphing Graphing Log.
Control Limits 0-32 kg/cm2 32-60 kg/cm2 (0-450 psig) (450-850 psig) 300 ppm max.
40 ppm max.
NOTE: This test can be used to detect chloride in makeup water and cooling water treated with DEWT ® NC diesel engine water treatment. THIS METHOD IS NOT RECOMMENDED FOR COOLING WATER TREATED WITH MAXIGARD ® diesel engine water treatment or LIQUIDEWTTM cooling water treatment WITHOUT SAMPLE PRETREATMENT. See page 66 for sample pretreatment procedure.
42
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 prevent flashing 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 first filtering, the sample should be refiltered through the same filter paper since the filter becomes more retentive on the second filtration.
This procedure is generally recommended for chloride determinations on all waters. An accurate chloride determination can be made only with water having a pH below the Phenolphthalein Alkalinity A lkalinity Indicator end point (pH 8.3).
APPARATUS
REAGENTS
LP Chloride Titration Assembly Graduated Cylinder, 50 ml Evaporating Dish Plastic Stirring Rod
PCN 0381-01-2 PCN 0237-02-5 PCN 0218-01-7 PCN 0417-01-5
N/10 Silver Nitrate, 500 ml Potassium Chromate, 120 ml Phenolphthalein, 120 ml N/10 Sulfuric Acid, 120 ml
PCN 0315-09-4 PCN 0313-19-7 PCN 0311-19-1 PCN 0319-19-5
PROCEDURE 1. Fill the the burette burette by squeezin squeezing g the plastic plastic bottle bottle of Silver Nirate. Allow the solution in the burette to settle to the 0.0 mark. 1
2. Measur Measure e 50 ml of cool cooled ed sampl sample e using using a graduat graduated ed cylinder.
50 ml
Step 2
3. Transfer Transfer the measured measured sample sample into into an evaporating evaporating dish.
3
4. Add 4 drops drops of of Phenolp Phenolphth hthale alein in to the the sample. sample. IIff the sample turns pink, add N/10 Sulfuric Acid dropwise until the pink disappears. If the sample does not turn pink, proceed to step 5. 5. Add one one dropper dropperful ful of Pota Potassi ssium um Chrom Chromate ate tto o the sample. This will turn the sample a yellow color. 6. Turnin Turning g the stopc stopcock ock on the the bu buret rette, te, add add Silver Silver Nitrate to the sample drop by drop while stirring continuously. The endpoint is reached when the color changes to a permanent light red. Do not "overtitrate" to a "brick red" color as this will result in an erroneously high determination.
6 4&5
7. Read Read the level level of the the Silver Silver Nitr Nitrate ate s solu olutio tion n on the burette. Refer to the the Chloride/Silver Nitrate Conversion Table on Page 42 and find the number which corresponds to the burette burette reading. Next to this number you will find the equivalent chloride content expressed in parts per million (ppm). 8. Record Record resu results lts as as ppm chlo chlorid ride e on th the e Onboar Onboard d Graphing Log. Control Limits
43
0-31 kg/cm2 (0-450 psig)
32-60 kg/cm2 (450-850 psig)
300 ppm max
40 ppm max
CHLORIDE TESTS HIGH PRESSURE BOILERS Pressure Range: 60-84 kg/cm2 (850-1200 psig) Titrated with Mercuric Nitrate
Conversion Table mls of Titrant (Mercuric Nitrate)
ppm Chloride
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.2 1.4 1.6 1.8 2.0 2.4 2.6 2.8 3.0 4.0 4.6 5.2
1 2 3 4 5 6 7 8 9 10 12 14 16 18 20 24 26 28 30 40 46 52
MEDIUM TO LOW PRESSURE BOILERS Pressure Range: Up to 60 kg/cm2 (850 psig) Titrated with Silver Nitrate
Conversion Table mls of Titrant (Silver Nitrate) 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0 2.1 2.2 2.3 2.4
ppm Chloride
mls of Titrant (Silver Nitrate)
ppm Chloride
7 14 21 28 36 43 50 57 64 71 78 85 92 99 107 114 121 128 135 142 149 156 163 170
2.5 2.6 2.7 2.8 2.9 3.0 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 4.0 4.1 4.2 4.3 4.4 4.5 4.6 4.7
178 185 192 199 206 213 220 227 234 241 248 256 263 270 277 284 291 298 305 312 319 326 334
44
mls of Titrant (Silver Ni Nitrate) 4.8 4.9 5.0 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 5.9 6.0 6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9 7.0
ppm Chloride 341 348 355 362 369 376 383 390 398 405 412 418 426 434 440 447 455 461 468 476 483 490 497
CONDUCTIVITY TEST FOR HIGH TO LOW PRESSURE BOILER SYSTEMS CONDUCTIVITY CONDUCTIVITY KIT (PCN 0173-01-3) INCLUDES: APPARATUS
REAGENTS
Conductivity Meter Low Ra Range Ce Cell (W (White Ba Band) High Range Cell (Black Band) Condu onduct ctiv ivit ity y Cyl Cylin inde derr, Pla Plast stic ic Dial Thermometer Brass Spoon, 0.2gm
PCN 0156-01-9 PCN 0117-01-1 PCN 0116-01-3 PCN PCN 023 02322-02 02--5 PCN 0143-02-4 PCN 0224-01-4
Gallic Acid, 100 gm Phenolphthalein Indicator, 480ml (1 (16 oz.) (Not provided in PCN 0173-01-3)
PCN 0309-01-4 PCN 0311-01-9
PROCEDURE NOTE: Neutralization (Steps 3 and 4) is necessary for boiler water. It is not necessary for high purity waters such as condensate or 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. 1. Press the the power power switch switch and allow allow the meter meter to warm warm up for for one minute. minute. 2. Connect Connect the conducti conductivity vity cell cell for the appropria appropriate te testing testing range. range. • White band (inner scale) for condensate and low conductivity waters. • Black band (outer scale) for boiler water and other high hi gh conductivity solutions. 3. For a boiler water water sample, sample, add two two drops of Phenolph Phenolphthalei thalein n Indicator Indicator to the sample and stir. If the sample remains clear, go to Step 5. 3
Gallic Acid
4
4. a. If tthe he sample sample turns turns pink, pink, neutralize neutralize by by adding adding Gallic Gallic Acid, Acid, one one level level spoonful spoonful at at a time, stirring after each spoonful, until the pink color just disappears. NOTE: Do not add excess Gallic Acid, Failure to neutralize sample or addition of excess acid beyond the end point will cause erroneously high conductivity readings. b. If Liquid Neutralizing Neutralizing solution is being used, the the first drops will turn turn the solution pink. Continue to add solution dropwise until the pink color disappears. 5. Submerge Submerge the cell in the the water sample sample to a depth depth to cover the the vent holes. holes. Agitate Agitate the cell to vent all trapped air bubbles from the cell interior. 6. Measure Measure the temperatu temperature re of the sample sample and set the temperat temperature ure knob to this this value. 7. Rotate Rotate the conductivity conductivity knob knob until both the the red and the green indicator indicator lamps lamps are lighted at the same time.
7
8. Read the the conductiv conductivity ity value value on the appropr appropriate iate scale. scale. 9. Record Record the test test result result on on the Onboar Onboard d Graphing Graphing Log Log (µmhos). Control Limits 0-60 kg/cm2 60-84 kg/cm2 (0-850 psig) (850-1200 psig) 700
mhos os ma max x µmh
120 120 µmhos max
10. Remove the cell from the sample and rinse it with with clean water. 11. Press the power switch to shut off the meter. meter. 12. Compare results to the Control Control and Dosing charts and adjust blowdown schedule as required. 45
DEHA/DREWPLEX ® OX corrosion inhibitor Ampoule Test DREWPLEX OX Ampoule Test Kit (PCN 0387-01-0) INCLUDES:
APPARATUS
REAGENTS
1 Comparator 1 Snap Cup
Activator Solution Ampoule Refill
PCN 0387-03-6 PCN 0387-02-8
PROCEDURE Read MSDS before performing this test procedure. NOTE: Before testing, samples must be cooled to 25 OC (77OF) by collecting through a sample cooler for safety and to pevent flashing which concentrates the sample. If the sample is colored or turbid, filter before running this test. mL 25
1. Fill the sample sample cup to the 25 ml ml mark with cooled cooled feedwater sample.
20 15 10 5
1
3
2
10:00
5
4
2. Add 2 drops of Activator Solution. Stir gently with the tip of an ampoule from the DREWPLEX ® OX corrosion inhibitor Ampoule Test Test Kit to mix the contents of the sample cup. 3. Immediately snap the tip of the ampoule by pressing the ampoule against the side of the sample cup. The sample will fill the ampoule and begin to mix with the reagent, leaving a small bubble to facilitate the mixing. 4. Remove the ampoule from the cup. Mix the contents of the ampoule by inverting it several times, allowing the small bubble to travel from end to end each time. 5. Wipe all liquid liquid from the exterior exterior of the the ampoule and WAIT EXACTLY 10 MINUTES for full color development.
6 7 CONTROL LIMITS 0-32 kg/cm2 0-450 psig 0.4 - 0.8 ppm in feedwater
6. When using the comparator comparator,, be sure it is illuminated by a white light directly above the comparator. comparator. The filled DEHA ampoule should be placed between the color standards for viewing. It is important impor tant that the DEHA ampoule be compared by placing it on both sides of the standard tube before concluding that it is darker, darker, lighter or equal to the standard. 7. Record Record the results results on the Onboard Onboard Graphing Graphing Log and adjust the DREWPLEX OX corrosion inhibitor dosage as necessary.
46
HARDNESS TEST, TOTAL FOR 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 and fill the the snapping snapping cup with with the sample sample to to be tested. tested.
SNAPPING CUP FILL COMPLETELY
1
2. Place the the tip of the hardness hardness ampoule ampoule into into one of the holes holes in the bottom bottom of the snapping cup.
3. While applying applying downwar downward d pressure, pressure, break break the tip by tilting tilting the ampoule ampoule toward the edge of the snapping cup. Keep the tip immersed in the water while drawing sample.
3
4. Mix by inverting inverting the the hardness hardness ampoule ampoule back and and forth forth to dissolve dissolve the reagent.
5. Wa Wait it 3 30 0 seco second nds. s.
6. Place the the ampoule in front front of a white white background background and view the the color. A pure pure blue color indicates less than 0.1 ppm hardness. A pink color indicates hardness is present.
7. To confirm confirm a pure blue blue color, run run a zero standard standard by by performing performing the test test on distilled water.
8. Record Record results results on the Onboard Onboard Graphing Graphing Log.
Control Limit 60-84 kg/cm2 (850-1200 psig) <0.1ppm
47
HARDNESS TEST TITRET2 METHOD This test may be used on treated waters as well as makeup water.
TOTAL HARDNESS TITRETS2 (PCN 0378-01-9) INCLUDES: 50 Titrets 30 Valve Assemblies
1 Sample Cup
PROCEDURE NOTE: If the sample is colored or turbid, it should be filtered before testing. 1. Fill the sample cup to the 25 ml ml mark with with sample sample (Figure (Figure 1). 1).
2. Slide the the open end end of the valve assembl assembly y over the the tapered tapered tip of the Titret so that it fits snugly to the Reference Line (Figure 2).
1
3. Snap the the tip of the Titret Titret at the Score Score Mark Mark (Figure (Figure 3). 3). Valve Assembly
←
4. With the the tip of the valve valve assembly assembly immerse immersed d in the sample, sample, squeeze squeeze the 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 added to the Titret. CAUTION: CAUTION : Do not squeeze the bead valve unless the tip of the valve is immersed below the surface of the liquid.
Bead Valve
Score Mark 3
Reference Line Ampoule
5. Rock the Titret Titret to mix mix the contents. contents. The The contents contents of the Titret Titret will turn turn a BLUE color.
2
6. Continue Continue to add small small amounts amounts of sample sample until until the liquid liquid in the Titret Titret turns from BLUE TO PINK. PINK. Be sure to rock the Titret to mix the contents after each addition of sample. When the color of the liquid liqui d in the Titret changes to PINK, PINK, the end point has been reached. Stop the test, hold the Titret with its tip pointed upward and read the scale opposite the liquid level to obtain the test results in ppm total hardness as calcium carbonate, CaCO 3 (Figure 5).
4
7. Record Record results results on the the Onboard Onboard Graphing Graphing Log. Log. Read Here
→
5
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.
48
HYDRAZINE/AMERZINE TEST FOR HIGH TO LOW PRESSURE BOILER SYSTEMS
AMERZINE ® CORROSION INHIBITOR INHIBITOR AMPOULE TEST KIT (PCN 0369-01-8) INCLUDES: 1 Cylindrical Comparator 1 Sample Cup 1 Set of Instructions 30 Ampoules
AMERZINE CORROSION INHIBITOR INHIBITOR AMPOULE REFILL (PCN 0369-02-6) INCLUDES: 30 Ampoules This test kit and refills are included in the ULTRAMARINE ULTRAMARINESM 6 Month Reagent Set (PCN 0437-04-7)
PROCEDURE
1. To insure accurate results, the sample should be collected with minimum contact to air and tested te sted promptly. promptly. A sample cooler should be used for sampling boiler boi ler water. 1 & 2
3
2. Fill the sample cup to to the 25ml mark with with sample. sample.
3. Place the AMERZINE AMERZINE corrosion inhibitor inhibitor ampoule's tapered tapered tip into one of the four depressions in the bottom of the sample cup. Snap the tip by squeezing the ampoule ampou le toward the side of the cup. Keep the tip immersed in the water while drawing sample. The sample will fill the ampoule and begin to mix with the reagent.
4. Remove the AMERZINE AMERZINE corrosion inhibitor ampoule from the cup. Mix the contents of the ampoule ampoul e by inverting it several times, allowing the bubble to travel travel from end to end each time.
5
Control Limit 0-84 kg/cm2 (0-1200 psig)
5. Wipe all liquid from the exterior of the ampoule and wait 10 minutes for for full color development.
6. Place the AMERZINE corrosion corrosion inhibitor ampoule, flat end downward downward into the center tube of the comparator. Direct the comparator toward a source of bright white light while viewing from the bottom. Hold the comparator in a nearly horizontal position and rotate it until the color standard below the AMERZINE corrosion inhibitor ampoule shows the closest match. 7. Record the AMERZINE level level on the Onboard Graphing Log. Results are expressed as ppm hydrazine.
0.03-0.10 ppm
49
pH TEST (COLORMETRIC) FOR HIGH PRESSURE BOILER SYSTEMS
Not a Required Test for Medium to Low Pressure Boilers.
APPARATUS Included in the ULTRAMARINE ULTRAMARINESM Glassware Set (PCN 0441-04-8) Water Analyzer Base Phthalein Red Comparator Slide (8.6 to 10.2 pH range) Tolyl Red Comparator Slide (10.0 to 11.6 pH range) Nessler Tubes, 3 Short, 150mm Graduated Cylinder, 100ml, Plastic Drop Droppe perr Pipe Pipett ttes es,, Plas Plasti tic, c, mark marked ed at 0.5m 0.5mll (cc) (cc) and 1.0ml (cc) Stirring Rod, 150 mm, Plastic Bottle, 60ml (2 oz.), Glass, with dropper (for Phthalein Red Indicator) Bottle, 60 ml (2 oz.), Glass, with dropper (for Tolyl Red Indicator)
PCN 0427-01-4 PCN 0422-01-4 PCN 0425-01-8
REAGENTS
PCN 0423-01-2 PCN 0410-01-9 PCN PCN 041 04111-01 01-7 -7
Included in the Ultratest ® 6 Month Reagent Set (PCN 0437-02-1) 1 x 500m 500mll Phth Phthal alei ein n Red Red 1 x 500ml Tolyl Red
PCN PCN 048 04811-01 01-0 -0 PCN 0486-01-0
PCN 0417-01-5 PCN 04 0433-01-1 PCN 0434-01-9
PROCEDURE 1. Fill the two two outside Nessler Nessler Tubes Tubes (end (end tubes B&D) B&D) to the 150 mm mark mark with untreated sample water and place in the outside compartments of the Water Analyzer Base. 2. Rinse the the center Nessler Nessler Tube Tube (C) with with a small amount amount of boiler water. water. 3. Measure Measure exactly exactly 75 ml of sample sample in the 100 100 ml graduated graduated cylinder, cylinder, and and add to this exactly 0.5 ml (cc) of the appropriate pH indicator (using dropper pipette). Stir thoroughly with the stirring rod to obtain uniform color throughout.
3
U n re C o t r te e d n d e a t n s a at e e
D
1 &4
e e d e r r e a t t e U n t n d e n s a o C
4. Put treated treated sample sample (from Step Step 3) into the center center Nessler Nessler Tube (C), (C), adding only enough to bring the level in the tube to the 150 mm mark. Place this tube in the center compartment. 5. Place the appropr appropriate iate pH comparat comparator or slide in the the slot in the support support base. base. Determine the pH according to the General Instructions for the Water Analyzer on page 5. 6. Record Record the pH pH value value on the the Onboard Onboard Graphing Graphing Log. 7. Compare Compare test results results to to those on the the Control Control and Dosing Dosing Chart. Chart. Adjust Adjust the TM pH of the boiler water with GC concentrated alkaline liquid as necessary.
Control Limits 60-84 kg/cm2 (850-1200 psig) 9.8-10.2 boiler water
50
pH TEST (METER) FOR HIGH PRESSURE BOILER SYSTEMS Not a Required Test for Medium to Low Pressure Boilers
APPARATUS PORTABLE pH METER Low Maintenance Triode pH Electrode
REAGENTS PCN 0246-01-8 PCN 0246-02-6
pH Buffer 7 (500ml) pH Buffer 10 (500 ml) pH Elec Electtrode rode Stor Storag age e Sol Solut utio ion n (500ml)
PCN 6255-09-6 PCN 6444-09-5 PCN PCN 024 02466-03 03-4 -4
PROCEDURE (Boiler Water) Two Point Autocalibration (Weekly) 1. 2. 3. 4. 5. 6.
Attach Attach the pH Electro Electrode de to the the meter. meter. Press the the "power" "power" button button to turn the the meter on. on. Place the electr electrode ode into pH buff buffer er 7 solution. solution. Press the "mode" "mode" button button until CALIBRA CALIBRATE is displayed. displayed. Press the the "no" button button until the the buffer buffer sequence sequence 7-10 is displayed and then press the "yes" button. The buffer buffer chosen chosen will be displayed displayed in the main field, 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 buffer calibration using a pH buffer 10 solution. 8. Rinse the electrode with distilled water water and place into pH buffer 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. 2. 3. 4.
Rinse the the electrode electrode with distilled distilled water water.. Place the the electrode electrode into into the sample sample.. Record Record the the readi reading ng when when ready is displayed. Both the temperature temperature corrected pH reading and temperature reading are displayed. displayed.
Electrode Storage For short-term (up to one week) electrode storage, soak the electrode in pH El ectrode Storage Solution. For long-term (greater than one week) electrode storage, rinse the electrode with distilled water and remove any salt buildup or deposits. Cover Cover the end of the electrode with the protective cap and store dry. dry. Consult the Orion Instruction Manual for more information.
Control Limits 60-84 kg/cm2 (850-1200 psig) 9.8-10.2 boiler water
51
pH TEST CONDENSATE MEDIUM AND LOW PRESSURE BOILER SYSTEMS USING STANDARD TREATMENT
This test can be performed with the indicators and acids already available in the testing program. The procedures differ 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 of construction. This pH is in the same range as the endpoint of phenolphthalein. If the addition of phenolphthalein turns the sample pink, then it is sufficiently alkaline. To be sure that the water is not excessively alkal ine, we back titrate with acid. If a very small amount of acid is needed to reach the endpoint in these titrations, then we can say that the pH of the condensate is in the proper range.
APPARATUS
REAGENTS
LP Alkalinity Titration Assembly Graduated Cylinder, 50 ml Evaporating Dish Plastic Stirring Rod
PCN 0380-01-4 PCN 0237-02-5 PCN 0218-01-7 PCN 0417-01-5
N/10 Sulfuric Acid, 500 ml Phenolphthalein Indicator, 120 ml
PCN 0319-09-6 PCN 0311-01-9
PROCEDURE 1. Collect 50ml cooled cooled condensate condensate sample sample and pour into evaporating dish. 1
2. Add 3 drops drops phenolphthalein phenolphthalein.. Sample should turn turn pink.
3. Add sulfuric sulfuric acid N/10 drop drop by drop drop until pink color color disappears.
4. Record results results on the the Onboard Onboard Graphing Log Log and adjust TM SLCC-A treatment dosage as necessary.
2
3
Control Limit 0-60 kg/cm2 (0-850 psig) 1-2 drops or pH 8.3-8.6
53
pH TEST CONDENSATE FOR HIGH PRESSURE BOILER SYSTEMS
APPARATUS
REAGENTS
(1) Beaker, 100ml , PCN 0247-01-6 (1) Stirring Rod, PCN 0417-01-5
(1) Phenolphthalein, 120ml, PCN 0311-19-1 (1) N/50 Sulfuric Acid, 1000ml, PCN 0485-01-2
PROCEDURE 1. Obta Obtain in a cool cooled ed 50ml condensate sample and add 2-3 drops of phenolphthalein.
1
2. Add N/50 Sulfuric Sulfuric Acid Acid dropwise, dropwise, counting counting drops, drops, until the pink color disappears.
3. Record results on the Onboard Graphing Log.
3
4. Record results on the Onboard Graphing Log and adjust SLCC-ATM treatment dosage as necessary.
Control Limit 60-84 kg/cm2 (850-1200 psig) 1-2 drops or pH 8.6-9.0
54
PHOSPHATE TEST FOR HIGH PRESSURE BOILER SYSTEMS PHOSPHATE VACU-VIALS2 TEST KIT (PCN 0390-01-3) INCLUDES: 1 Photometer 30 Vacu-Vials (PCN 0390-02-1) 1 Sample Cup 1 Light Shield 1 Test Tube 1 Blank Vacu-Vial
PROCEDURE Read Material Data Sheet before using. Do not snap the ampoule tip in air or in any liquid except water water.. NOTE: Filter a cooled boiler water sample before before running this test. Filter paper and funnel are supplied separately. separately.
1. Fill the the sample sample cup to to the 25 25 ml mark mark with cooled, cooled, filtered filtered boiler water. 2. Place the phosphate phosphate VACU-VI ACU-VIALS ALS ampoule in the sample cup. Snap the tip by pressing the ampoule against the the side of the cup. The ampoule will fill, leaving a small bubble to facilitate mixing. 1
2
05:00
3
3
4
Control Limit 60-84 kg/cm2 (850-1200 psig) 15-25 ppm
3. Mix the contents contents by inve inverting rting the ampoule ampoule,, showing showing the bubble to travel travel from end to end. Wipe all liquid from the exterior. Wait 5 minutes. 4. Press ON. When the display display shows shows “---” ---”, the photometer is ready rea dy.. 5. Zero the the photomet photometer er by inserting the VACU-VIAL ACU-VIALS S blank blank ampoule into the cell compartment, aligning the vertical line on the ampoule with the water droplet on the photometer. Cover the ampoule with the light shield. Press the ZERO button. The display will show “S1P” S1P” momentarily, then it will read “-0.0-” -0.0-”.
5
6. After the 5 minute minute wait required required in step step 3, insert the phosphate VACU-VIALS VACU-VIALS ampoule with proper cell alignment into the cell compartment. Cover Cover the ampoule with the light shield. Press the READ button. button. The meter will show “S1P” S1P” momentarily, momentarily, then it will display the test result in ppm ortho phosphate as PO4. 7. Record Record the result results s on the the Onboard Onboard Graphing Graphing Log and adjust the ADJUNCT ® B treatment dosage as necessary.
55
PHOSPHATE TEST FOR MEDIUM TO LOW PRESSURE BOILER SYSTEMS Before testing, sample must be cooled to 25 OC (77OF) by collecting through a sample cooler for safety and to prevent 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 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 Pa Paper, box o off 100 s sh heets Funnel, Plastic
P/C #0225-01-2 P/C #0221-01-0
PROCEDURE 1. Fill the sample sample cup to to the 25 ml mark mark with with sample (Figure (Figure 1). 1). 2. Place the Boiler Phosphate Phosphate ampou ampoule le’’s tapered tip into one of the four depressions in the bottom bottom of the sample cup. Snap the 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).
mL 25 20 15 10 5
Figure 1 Figure 2
3. Remove Remove the the Boiler Phospha Phosphate te ampoule ampoule from the cup. cup. Mix the contents of the ampoule by inverting it several several times allowing the bubble to travel travel from end to end each time (Figure 3). 4. Wipe all liquid liquid from the the exterior exterior of the the ampoule ampoule and wait wait 5 minutes for full color development (Figure 4).
Figure 3
05:00
Figure 4
5. When using using the comparat comparator or,, be sure it is illuminate illuminated d by a white light directly above the comparator. comparator. The filled Boiler Phosphate ampoule should be placed between the color standards for viewing. viewing. It is important that the ampoule be compared by placing it on both sides of the standard tube before concluding that it is darker, darker, lighter or equal to the standard (Figure 5). 6. Record Record the results results on the Onboard Onboard Graphi Graphing ng Log and adjust adjust product dosage as necessary. necessary.
Figure 5
Control Limits AGK 100 & DREWPLEX ® AT Programs 10-20 ppm Standard Treatment Programs 0-60 kg/cm2 (0-850 psig) 20-40 ppm ®
56
SILICA TEST FOR HIGH PRESSURE BOILER SYSTEMS Not a Required Test for Medium to Low Pressure Boilers.
SILICA AMPOULE TEST KIT (PCN 0376-01-3) INCLUDES: 30 Ampoules 2 x A-9000 Neutralizer Solution 2 x A-9001 Activator Solution 1 Cylindrical Comparator, 0-1 ppm 1 Flat Comparator, 1-10 ppm 1 Sample Cup Included in the ULTRAMARINESM 6 Month Reagent Set (PCN 0437-04-7)
PROCEDURE NOTE: NOTE: If the sample is colored or turbid, it should be filtered before testing. 1. Fill the the sample sample cup cup to the the 15 ml ml mark with sample (Figure 1). 2. Add 10 drops drops of A-9001 A-9001 Activat Activator or Solution Solution (Figure (Figure 2). Cap the sample cup and shake it to mix the contents well. Wait Wait 4 minutes. 3. Add 5 drops of A-9000 A-9000 Neutral Neutralizer izer Solution Solution (Figure (Figure 2). 2). Cap Cap the sample cup and shake it to mix the contents well. Wait Wait 1 minute. 1
2
4. Place the the silica ampoul ampoule's e's tapered tapered tip tip into one of the four four depressions in the bottom of the sample cup. Snap the tip by squeezing the ampoule toward the side of the cup. The sample will fill the ampoule and begin to mix with reagent (Figure 3). 5. Remove Remove the silica silica ampoule ampoule from the the cup. Mix the contents contents of of the ampoule by inverting it several times allowing the bubble to travel from end to end each time. 6. Wipe all liquid liquid from from the exterio exteriorr of the the ampoule ampoule and wait wait development. 2 minutes for full color development.
4
3
7. After 2 minutes minutes,, use the compara comparator tor to determine determine the level level of silica in the sample. a. When using using the lowe lowerr range range comparato comparatorr (0-1.0 (0-1.0 ppm), ppm), place the silica ampoule, flat end downward into the center tube of the comparator. Direct the comparator toward a source of bright white light li ght while viewing from the bottom. Hold the comparator in a nearly horizontal position and rotate it until the color standard below the silica ampoule shows the closest match (Figure 4).
5
Control Limit 60-84 kg/cm2 (850-1200 psig) 6 pm maximum
b. When using using the the high range range comparato comparatorr (1-10 (1-10 ppm), ppm), be sure it is illuminated by a white light directly above the comparator. comparator. The filled silica ampoule should be placed between the color standards for viewing. It It is impor tant that the silica ampoule be compared by placing it on both sides of the standard tube before concluding that it is darker, lighter or equal to the standard (Figure 5). 8. Record Record the results results on the Onboard Onboard Graphing Graphing Log. 57
SULFITE FOR MEDIUM AND LOW PRESSURE BOILER SYSTEMS
DREW MARINE SULFITE TITRETS TITRETS2 (P/C #0377-01-1) INCLUDES: • • •
30 Titrets 30 Valve Assemblies 1 A-9600 Neutralizer Solution
• 1 Sample Cup • 1 Set of Instructions
PROCEDURE NOTE: NOTE: If the sample is colored or turbid, it should be filtered before testing. 1. Fill the the sample sample cup to to the 25 ml mark with sample sample (Figure (Figure 1). 2. Add 5 drops of of A-9600 Neutr Neutralize alizerr Solution Solution (Figure (Figure 2). Stir lightly lightl y and briefl b riefly y. Wait 30 seconds. seconds.
Figure 1
3. Slide the open open end of the valve valve assemb assembly ly over over the tapered tapered tip tip of 1 the Titrets so that it fits snugly to the Reference Line (Figure 3). 4. Snap the the tip of the Titrets Titrets at the the Score Score Mark (Figure (Figure 4). 5. With the the tip of the the valve valve assembly assembly immerse immersed d in the sample, sample, squeeze the bead valve briefly to add a small amount of sample to the Titrets (Figure 5). The colorless indicator i ndicator in the valve assembly will also be added to the Titret. CAUTION: CAUTION: Do not squeeze the bead valve unless the tip of the valve assembly is immersed below the surface of the liquid.
Valve → Assembly
Figure 2 Bead
Score Mark → Reference → Line
← Valve
Figure 3
6. Rock Rock the Titret Titrets s to mix the contents. contents. The contents contents of the Titrets will turn a DEEP BLUE color. Wait 30 seconds. seconds. 7. Continue Continue to add small small amounts amounts of sample sample until until the the liquid in in the Titrets turns from BLUE TO TO COLORLESS COLO RLESS.. Be sure to rock the Titret to mix the contents after each addition addi tion of sample. When the color of the liquid in the Titrets changes to COLORLESS, COLORLESS , the end point has been reached. Stop the test, hold the Titrets with its tip pointed upward and read the scale opposite the liquid level to obtain the test results in ppm sulfite as SO3 (Figure 6).
Figure 4
8. Record Record the results results on the the Onboard Onboard Graphing Graphing Log Log and adjust adjust product dosage as necessary. necessary.
Figure 5 Figure 6
Control Limit 0-32 kg/cm2 36-60 kg/cm2 (0-450 psig) (450-850 psig) 20-30 ppm
10-15 ppm
58
COOLING WATER SYSTEMS AND TREATMENT INTRODUCTION Cooling water circuits on motor vessels encompass several different types of systems. Of primary concern to us are the cooling water systems for main and auxiliary engines and air conditioning systems. systems. While we will mention refrigeration brine systems briefly in our discussions, we will not include them or seawater cooling systems except to say that fouling of these units will lead to overheating and ultimate system failure. Chemical and mechanical treatments* of these systems are available, but will not be discussed at this time.
bination with the variety of metals in use have created a challenge for the efficiency of the cooling water systems and the capability of chemical treatments formulated for them. The higher engine temperatures result in accelerated mineral deposition rates on the water side. side. Because of the design of diesel engines, the use of high quality makeup water is the best means of controlling scale formation. formation. As a result, the use of distilled water as the coolant has become essential. However, untreated untreated distilled water is many times more corrosive to metals than a water with a degree of contamination and it has therefore become an operational and economic necessity to treat the engine cooling water with a corrosion inhibitor.
Marine diesel engines have continually undergone improvement in performance ratings and power to weight ratios. These design changes often increase the complexity of the system. Where ferrous and some cuprous metals were the standard of the past construction for medium and slow speed engines, today’ today’s designs are beginning to utilize a wider variety of metals including aluminum components.
Testing of treated cooling water is a vital part of the treatment program and the required test procedures will be discussed at the end of this section.
Improved performance characteristics have subjected the cylinder liners, covers and pistons to higher temperatures, pressures and heat transfer rates. rates. These factors in com-
Contact your local Drew representative for more informai nformation about the use of corrosion inhibitors and AMERSPERSE ® 280 seawater cooling treatment in these systems.
COOLING WATER SYSTEM CIRCULATION The cooling water enters at a low point in the cooling circuit and flows upward to exit at the top of the engine. engine. This arrangement minimizes the formation of air pockets which prevent the proper wetting of metal surfaces. This interrupts proper heat transfer and allows overheating to occur.
The importance of an efficient engine cannot be overstated. The temperature of the gases produced during combustion exceed the melting point of case iron and, without cooling, the piston and other metal parts would fuse and eventually seize. This is the result of overheating in the the extreme. However, even if actual melting does not occur there can be substantial loss of the metal’ metal’s strength and ductility which can lead to premature premature failure. failure. Lube oil films also can be destroyed by overheating, leading to wear, deposits and premature system failure.
The hot water is extracted and passed through a heat exchanger system where the heat energy is passed to a secondary coolant, often seawater. The cooled water is then recirculated back to the engine to complete the “closed” closed” circuit.
Diesel engines can be cooled with water or air heat exchange equipment. The most commonly used medium in the commercial marine market is water. Its treatment is of primary concern to us.
This heat exchange process also can provide heat for evaporators and auxiliary systems. Many modern motor vessels are equipped with evaporators that use the diesel engine cooling water as a primary heat source to generate distilled water at minimum minimum cost. After passing through the evaporator, the cooling water may continue through another heat exchanger to further utilize the energy available and control the water inlet inl et temperature to the diesel engine systems. Because of the space considerations and economic factors, the design of marine plants often interrelates a number of systems to maximize the efficiency which could be discussed at length. However, that is not the central topic of this discussion. Instead, the prevenprevention of scale and corrosion in these various systems is.
There are three main systems in a diesel engine which require cooling: the engine jacket, the piston areas and the fuel valves. The cooling water system can be one large closed loop with main circulating pumps and a common head tank or there can be three separate cooling water circuits employed to independently cool the cylinder jacket, piston, and fuel valve. The systems can be cross-concross-connected in the event of equipment failure so that the cooling load can be picked up by another system. Conversely, cooling circuits also can be isolated if contamination is encountered. Consideration of each system design and the metals of construction is important in deciding on the type of treatment to be used and how and where it should be dosed. 59
CORROSION OF METALS TYPES OF CORROSION AND PREVENTATIVE MEASURES
Chemical Treatment Inhibitors are chemicals that protect metals by creating a barrier between the water and the metal or by reacting with the metal surface to form a thin protective or passivation film which makes the metal underneath more resistant to attack.
Distilled water is desirable for scale prevention but it is very aggressive aggressive in itself. itself. In addition, other corrosion corrosion mechanisms are at work in the system. Oxygen Pitting: Dissolved oxygen is a primary cause of corrosion and is involved in practically all corrosion processes.
Soluble oil is a barrier type inhibitor which functions well up to the point of breakdown when deposits may form. Other barrier-type inhibitors, such as silicates which function well in ambient temperatures, interfere with heat transfer and are not applicable in engine cooling systems.
Cooling water is not deaerated. Although there are air release units in the circuit, the water usually contains a much higher concentration of dissolved oxygen than does boiler feed water. The cooling water is exposed to the air while in open head tanks and air contains 20% (200,000 ppm) oxygen.
Most protective films are so thin that they cannot be seen and they do not interfere with heat transfer. They are formed by the chemical combination of the inhibitor and the metal surface and and tightly adhere to the the metal. The film can be damaged or torn away by water water flow. However, a residual of inhibitor is maintained in the water so that if the protective film is damaged in any way, the film is rapidly repaired.
The amount of oxygen that the water contains is dependent upon the temperature of the water since cold water will dissolve more oxygen than hot water. Some oxygen is brought in by makeup water additions and inleakage at seals or other points throughout the mechanical system.
Modern chemicals are normally a nitrite-borate-organic mixture. Nitrite is a film forming inhibitor. The nitrite primarily protects against corrosion of the ferrous metals in a cooling water system. Other inhibitors are included in the formulation designed to minimize corrosion of nonferrous metals. Borate is included to adjust pH to to aid in corrosion inhibition and to provide the proper environment for the reaction of nitrite.
Cavitation: Because of engine vibrations and high impingement flow conditions, metal parts of the cooling system can be damaged by cavitation corrosion/erosion. corrosion/erosion. Cavitation damage appears as shallow pitting or gouging of the metal surface, but, unlike oxygen attack it is caused by mechanical as well as chemical conditions. High frequency vibration, high velocity flow conditions, or changes in temperature which cause a localized reduction in water pressure below the vapor pressure can lead to cavitation/erosion. cavitation/erosi on. In these areas of low pressure, bubbles of vapor will form next to the metal surface. As the pressure returns to normal, the bubble collapses striking the metal with great force (hundreds of kilograms/centimeter2 or thousands of pounds/inch2). The protective film is destroyed leading to further corrosion. This action is repeated in a cycle that erodes the metal surfaces.
Where cavitation erosion is known to exist, there is some evidence that large doses of corrosion inhibitors will reduce the erosion. Special formulations are available for medium and highspeed diesel engines which combine nitrite-borate organic corrosion inhibitors and polymeric scale inhibitors. In the past, buffered chromate treatment was the primary inhibitor but this approach has lost favor due to environmental concerns and the toxicity of chromate. Chromate is still used in refrigeration brine systems where other inhibitors are not very effective.
Acid Attack: Acid attack is brought about by low pH water. Some minerals and gases can, when dissolved in the water, produce acid which lowers the pH and causes corrosion. Not only will the acidic water be more corrosive corrosive to the metal, it will not be an environment in which the modern cooling water corrosion inhibitors will be effective.
In systems where glycol antifreezes are needed, nitrite borate treatments should be used because they are compatible with the glycol. Chromate should not be used with glycol because of a reaction which forms a “curd-like” curd-like” precipitate.
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COMPOSITION AND FORMATION OF DEPOSITS DEPOSIT FORMATION AND PREVENTATIVE TREATMENT
The cooling water may become contaminated by fuel or lubricating oils. The insulating effects of oil deposits on heat transfer surfaces are the same as mineral scale deposits.
Scale Deposits: The diesel engine has a very low tolerance for mineral mineral scale buildup. Calcium and magnesium magnesium compounds will form scale in high heat transfer sections of the cooling water system. system. Calcium carbonate and sulfate salts are the first to deposit because their solubility decreases as the water temperature increases.
As with all other contaminants, the source of oil inleakage should be located and eliminated. The entire cooling system should be cleaned with a solvent cleaner at the earliest opportunity. HDE-777TM heavy duty emulsifier is an effective cleaner for the purpose. Light to medium oily deposits combined with scale and oxide deposits can be removed using AMEROlD ® OSC one-step cleaner. (There are other maintenance chemical cleaner choices. Consult your local Drew Marine representative for specific speci fic recommendations.)
Mineral scales are hard and dense and are excellent insulators. Their presence drastically drastically reduces heat transfer. For example, one mm of calcium sulfate (CaSO (CaSO4) scale is equivalent as a heat transfer barrier to 40 mm of metal. The effect of scale on heat transfer characteristics is illustrated in the following diagram.
Mechanical Correction
Effect of Scale
The only means of mechanically preventing scaling is by removing minerals before the makeup water enters the engine system. The evaporator, a bank of reverse osmoosmosis units or a demineralizer must be operated efficiently to provide high quality make up. Shore water can be used if the needed volume of high quality water is not available, but, as stated above, it is not preferred because its quality is poor and so variable around around the world. However, if it is used, an analysis of the water should be obtained from the supplier and/or a local governmental office.
Scale often allows corrosion to progress underneath the deposits which can ultimately lead to system failure. failure. This type of corrosion is more fully described i n the Boiler Water Systems and Treatment section. Scale-forming minerals may be introduced by seawater inleakage or by the use of poor quality makeup. Distilled water is the recommended makeup to minimize scale formation. On ships which do not produce or have an inadequate supply of distilled water, fresh water from a shore supply is used. Shore water is not preferred because because it contains varying amounts of scale-forming constituents and other contaminants.
Chemical Correction The antiscalant chemicals used in boiler boi ler water treatment are not applicable for diesel engine engi ne systems because there is no practical method to blow down a diesel cooling water system to remove the normal sludges formed by a boiler water treatment treatment process. The sludges can block small cooling passages in the system restricting water flow and compounding the problems of overheating.
Oil Deposits: Soluble oils are used as treatments in some cooling systems, especially in the piston cooling circuits. If overheating occurs due to reduced circulation or overload conditions, the soluble oil may decompose and can form deposits. These oils are not truly “soluble,” soluble,” but are emulsions which breakdown in time with the same undesirable result as any oil contamination would cause in a cooling system.
COMBUSTION SIDE
Treatments are now available which contain polymeric antiscalants which can sequester and disperse a certain amount of hardness. Unlike the phosphate-alkalinity treatments common to boiler water treatments, the polymers in modern cooling water treatments will hold hardness constituents in suspension until unti l they can be removed by bleed off.
WATER SIDE TEMP GRADIENT ACROSS 25 MM LINER
WATER SIDE 570OC
270OC
COMBUSTION SIDE
TEMP TEMP GRADIENT GRADIENT ACROSS ACROSS 1 MM 25 MM SCALE LINER
70OC (B) 1mm Mineral Scale on Waterside
(A) Clean Cylinder Wall
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COOLING WATER TREATMENT CHEMICALS DEWT ® NC diesel engine water treatment is a nitriteborate type corrosion inhibitor used in closed cooling water systems. This low toxicity product is particularly applicable in diesel engine cooling water circuits, where the jacket water is the heat source for the evaporators which produce potable water. DEWT NC treatment has no deleterious effects on glands, seals, rubber hoses, valve packing, etc. It is compatible with antifreeze materials and will not form objectionable sludges.
systems in medium and high speed diesel engines. It is suitable for distilled or fresh water systems with or without antifreeze chemicals. MAXIGARD treatment treatment is safe for use in systems where jacket water is the heat source for the evaporators which product potable water supplies. LIQUIDEWT TM cooling water treatment is a multifunctional liquid blend of nitrite-borate-organic corrosion inhibitor and mineral deposit modifiers for scale prevention. LIQUIDEWT treatment is formulated for use in medium speed diesel engines. This product can be used in both distilled and shore waters. It has low toxicity and is compatible with glycol antifreezes. Glycol is used as an antifreeze only--it is not a corrosion inhibi tor.
MAXIGARD ® diesel engine water treatment is a multifunctional liquid blend of nitrite-borate-organic corrosion inhibitor and mineral deposit modifiers. MAXIGARD treatment is specially formulated for the closed cooling water
COOLING WATER TREATMENT CHEMICAL APPLICATIONS AND CONTROLS SYSTEM
APPLICATION
CONTROL LIMITS
High and medium speed diesel engines
MAXIGARD cooling water treatment to minimize corrosion and prevent deposition compatible with glycol antifreeze.
MAN/B&W Medium Speed 4-Stroke Engines (L&V32/40; L40/54; L&V48/60; L58/64) Medium and slow speed diesel engines
40-43,000 ppm
DEWT NC cooling water treatment to minimize corrosion compatible with glycol antifreeze.
MAN/B&W Medium Speed 4-Stroke Engines (L&V32/40; L40/54; L&V48/60; L58/64) Medium and slow speed diesel engines
20,000 ppm
3,000 - 4,500 ppm
4,500-4,900 ppm
LIQUIDEWT cooling water treatment to minimize corrosion and prevent deposition. Compatible with glycol antifreeze.
MAN/B&W Medium Speed 4-Stroke Engines (L&V32/40; L40/54; L&V48/60; L58/64)
10,000 ppm
15-17,000 ppm
COOLING WATER TREATMENT CONTROL TESTS AND DOSAGE REQUIREMENTS taken. Refer to the General Information Information section before before proceeding with any of the tests.
Because the cooling water system is an essential part of the diesel engine, a carefully controlled water treatment program is essential for the efficient operaton of the engine. The water treatment program program is monitored by means of a few simple tests. The control tests are the basis on which the chemical dosage is adjusted.
Testing Frequency Testing and chemical dosing should be done on a regular basis. The test should be conducted conducted 24 hours after the initial dosage and once a week thereafter unless a problem is suspected.
The following pages outline the test procedures which are used in conjunction with the Drew cooling water treatments. In some instances, an additional chloride determidetermination of the water may be desirable. The chloride test procedure on page 42 can be used for DEWT NC treated systems. This method is not recommended for cooling water treated with MAXIGARD diesel engine water treatment or LIQUIDEWT cooling water treatment without Sample Pretreatment. See page 66 for Sample Pretreatment procedure.
If abnormal water loss and makeup or other problems are known to exist, then the test results will probably be low and should be used compared with a control and dosing chart to increase treatment levels. Dose, allow time for circulation (approximately 30 minutes) and retest until treatment levels are satisfactory. If treatment levels are high, suspend dosage. Although not normally necessary, you may wish to bleed off some cooling water and makeup with untreated water to dilute. dil ute.
As in the steam generating system, the accuracy of the test results is dependent upon proper sampling, testing, and recording procedures as well as the corrective action 62
CWT TEST TITRET2 METHOD For use with LIQUIDEWTTM cooling water treatment, MAXIGARD ® diesel engine water treatment, and DEWT ® NC diesel engine water treatment.
CWT TITRETS (PCN 0367-01-2) INCLUDES: 1 Titrettor3 30 Titrets (contains reagent) 1 Sample Vial 1 Instruction Sheet 30 Valve Assemblies (contains reagent)
PROCEDURE 1. Slide the the open end end of the valve assembl assembly y over the the tapered tapered tip of of the Titret so that it fits snugly to the Reference Line. Valve Assembly
2. Snap the tip tip of the Titret Titret at the Score Score Mark Mark and proceed proceed with the the regular regular test instructions below or use the Titrettor assembly as covered on page 5.
Snap the tip at the score mark
3. With the the tip of the the sample sample pipe immerse immersed d in the sample, sample, squeeze squeeze the the bead valve briefly to pull in a small amount of sample. CAUTION: CAUTION : Do not squeeze the bead valve unless the sample pipe is immersed below the surface of the liquid or vacuum will be lost and the test ruined.
Score Mark Reference Line Ampoule
2
4. Rock the the Titret to mix mix the contents. contents. The The first addition addition of sample sample will pull pull in the reagent in the ampoule. The contents of the ampoule will turn a GREEN color.
1
5. Continue Continue to add small small amounts amounts of sample sample water water until the the liquid in the Titret turns from GREEN to a bright ORANGE.* When the ORANGE color appears, the end point has been reached. Stop test, hold the Titret with its tip pointed upward and read liquid level. Check the control and dosing chart below for the appropriate product concentrations. *NOTE: Immediately before the end point is reached, the contents will turn BLUE. Make further additions with care. To test makeup water for hardness using the Titret method, see page 48.
Satisfactory Ranges Product
Scale
PPM, Product
LIQUIDEWT MAXIGARD DEWT NC
1.2-1.8 1.6-3.5 3.5-5.0
10,000-15,000 20,000-40,000 3,000- 4 ,5 ,500
Control and Dosing Chart Initial Dosage
8 ltr/ton (2.13 gal/ton) 16 lt ltr/ton (1 (1.6 ga gal/ton) 3.2 kg/ton (7 lbs/ton)
Below low Sa Satisf isfactory Satisfactory Abov Above e Sati Satisf sfac acto torry
MAN/B&W Medium-Speed 4-Stroke Engines Models: L&V32/40
L40/54
L&V48/60
L58/64
Satisfactory Ranges Product
Scale
PPM, Product
LIQUIDEWT MAXIGARD DEWT NC
1.8-2.0 3.3-3.6 5.6-5.8
15,000-17,000 40,000-43,000 4,500 - 4,900 63
Initial Dosage 3.0 ltr/ton 3.3 ltr/ton 4.5 kg/ton
Increase Do Dosage Maintain Dosage Decre ecreas ase e Dosag osage e
TEST FOR DEWT® NC diesel engine water treatment DEWT NC TEST KIT (PCN 0302-01-8) INCLUDES: Grad Gradua uate ted d Cyl Cylin inde der, r, with with Stop Stoppe per, r, 50 ml Brass Measuring Spoon, 0.2 gm
PCN PCN 0236 0236-0 -011-9 9 PCN 0224-01-4
DEWT DEWT NC Reag Reagen entt No. No. 1, 100 100 gms gms PCN PCN 030 03066-01 01-0 -0 DEWT NC Reagent No. 2, 100 gms PCN 0307-01-8
PROCEDURE 1. Draw a cooling cooling water water sample sample from a full full flowing flowing part of the the system into the graduated mixing cylinder to the 25 ml mark. 2. Add 5 level level measuring measuring spoons spoons of DEWT NC NC Reagent Reagent No. No. 1 and mix mix until all of the reagent is dissolved. 3. Add 1 level level measuring measuring spoon spoon of DEWT DEWT NC Reagent Reagent No. 2, stopper stopper the mixing cylinder, and thoroughly mix. 4. If the sample sample turns turns purple-r purple-red ed and the the color lasts lasts for for at least least 30 seconds, the test indicates that the treatment level is i s below 50 ppm. However, if the color disappears within 30 seconds, add additional Reagent No. 2, one level measuring spoon at a time (counting spoonfuls) with thorough mixing until the purple-red color persists for over 30 seconds. 5. To determine determine the the concentrati concentration on of DEWT DEWT NC, count count the total total number of measuring spoons of Reagent No. 2 added and convert to ppm. Calculation: ppm DEWT NC NC = (number (number of spoons -1) x 500 6. Record Record results results as pm DEWT DEWT NC on on the onboard onboard graphing graphing log. log. 7. Determine Determine the the dosage of DEWT NC diesel diesel engine engine water water treatment treatment required per ton of circulating water as indicated on the Dosage Requirement Chart which follows:
DOSAGE REQUIREMENT CHART - DEWT NC TOTAL NUMBER OF MEASURING SPOONS OF REAGENT NO. 2 USED 1 2 3 4 5 6 7 8 9 10 11
ppm OF DEWT NC RECORDED None 500 1000 1500 2000 2500 3000 3500 4000 4500 5000
DOSAGE REQUIREMENT PER TON OF CIRCULATING WATER 3.2 kg (7 lbs.) 2.7 kg (6 lbs.) 2.3 kg (5 lbs.) 1.8 kg (4 lbs.) 1.4 kg (3 lbs.) 0.9 kg (2 lbs.) Satisfactory - No Dose Required. Satisfactory - No Dose Required. Satisfactory - No Dose Required. Satisfactory - No Dose Required. High - No Dose Required.
64
TEST FOR DEWT® NC diesel engine water treatment (continued)
DEWT NC TEST KIT (PCN 0302-01-8) 0 302-01-8) INCLUDES: Grad Gradua uate ted d Cyl Cylind inder er,, wit with h Sto Stopp pper er,, 50 50 ml ml Brass Measuring Spoon, 0.2 gm
PCN PCN 0236 0236-0 -011-9 9 PCN 0224-01-4
DEWT DEWT NC Reag Reagen entt No. No. 1, 100 100 gms gms PCN PCN 030 03066-01 01-0 -0 DEWT NC Reagent No. 2, 100 gms PCN 0307-01-8
MAN/B&W Medium-Speed 4-Stroke Engines Models: L&V32/40
L40/54
L&V48/60
L58/64
DOSAGE REQUIREMENT CHART - DEWT NC TOTAL NUMBER OF MEASURING SPOONS OF REAGENT NO. 2 USED 1 2 3 4 5 6 7 8 9 10 11 12 13 14
ppm OF DEWT NC RECORDED None 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500
DOSAGE REQUIREMENT PER TON OF CIRCULATING WATER 4.5 kg (10.0 lbs.) 4.0 kg (8.8 lbs.) 3.5 kg (7.7 lbs.) 3.0 kg (6.6 lbs.) 2.5 kg (5.5 lbs.) 2.0 kg (4.4 lbs.) 1.5 kg (3.3 lbs.) 1.0 kg (2.2 lbs.) 0.5 kg (1.1 lbs.) Satisfactory - No Dose Required. Satisfactory - No Dose Required. High - No Dose Required. High - No Dose Required. High - No Dose Required.
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Chloride Sample Pretreatment
SAMPLE PRETREATMENT SHOULD BE USED WHEN TESTING FOR CHLORIDE IN COOLING WATER TREATED WITH MAXIGARD ® DIESEL ENGINE WATER WATER TREATMENT TREATMENT OR LIQUIDEWT LI QUIDEWT TM COOLING WATER TREA TRE ATMENT. APPARATUS AND REAGENTS Drew Chloride LMP Test Kit Sample Pretreatment, 50 gm (includes 0.5 gm scoop) Filter Paper, Box of 100 Funnel, Plastic Stirring Rod, Plastic, 150mm
PCN 0373-01-9 PCN 0374-02-5 PCN 0225-01-2 PCN 0221-01-0 PCN 0417-01-5
PROCEDURE 1. Add one scoop scoop (0.5 gm) gm) of Sample Pretrea Pretreatment tment to to approximate approximately ly 70 ml of cooling cooling water and and stir well. well. 2. Let stand stand for two two minutes minutes to allow allow precipita precipitate te to to settle. settle. 3. Filter the the sample and proceed proceed with with the chloride chloride determinatio determination n using the Drew Chlorid Chloride e LMP Test Kit as shown shown on page 42.
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All statements, information and data presented herein are believed to be accurate and reliable but are not to be taken as a guarantee, express warranty or implied warranty of merchantability or fitness for a particular purpose, or representation, express or implied, for which seller assumes legal responsibility, and they are offered solely for your consideration, investigation and verification. Statements or suggestions suggestions concerning possible use of this product are are made without representation or warranty that any such use is free of patent infringement and are not recommendations recommendations 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 American Chemistry Council in the U.S., of the Canadian Chemical Producers ’ Association in Canada and of different entities in other countries. 1 Registered trademark of Biotal, Inc. 2 Registered trademark of CHEMetrics, Inc. 3Trademark of CHEMetrics, Inc.
One Drew Plaza Boonton, NJ 07005 USA Telephone: (973) 263-7600 FAX: (973) 263-4491/7463 Web Site: www.drew-marine.com E-mail:
[email protected] Emergency Safety #: (1-800-ASHLAND) U.S. Outside U.S.: (606) 324-1133
Printed in U.S.A. TM-WT-1 (11/01)R7
