Steam Condenser on Board Vessels: Operation, Maintenance, and Troubleshooting

The steam condenser is a critical component on board vessels that plays a crucial role in the efficiency and operation of boiler and steam-powered systems. It enables the conversion of exhaust steam from the consumers or main propulsion or power generation systems back into water, allowing for reuse and maximizing energy efficiency. In this comprehensive article, we will delve into the correct operation of a steam condenser, highlight the importance of regular maintenance, and provide a troubleshooting guide for common operational malfunctions.

    1. Correct Operation of a Steam Condenser

The correct operation of a steam condenser involves several key steps and considerations:

1.1. Cooling Water Circulation

Adequate cooling water circulation is vital for the efficient operation of the steam condenser. Cooling water is typically drawn from the sea or a freshwater source and circulated through the condenser tubes, absorbing the heat from the exhaust steam. It is crucial to ensure a sufficient flow rate and temperature difference for effective heat transfer.

1.2. Air Extraction

To maintain optimum performance, it is essential to remove non-condensable gases, such as air, from the condenser. This is achieved through air extraction systems that continuously remove air from the condenser, preventing its accumulation and reducing the risk of performance degradation.

1.3. Vacuum Creation

Maintaining a vacuum within the condenser is vital to enhance the efficiency of steam condensation. A vacuum is created by condensing steam, reducing its pressure, and evacuating the condensed water. Efficient vacuum creation is crucial for maximizing power generation and optimizing overall system performance.

    1. Maintenance of a Steam Condenser

Regular maintenance is essential to ensure the reliable and efficient operation of a steam condenser. Neglecting maintenance can lead to reduced performance, increased energy consumption, and even catastrophic failures. Key maintenance activities include:

2.1. Tube Cleaning

Over time, fouling and scaling can accumulate on the condenser tubes, reducing heat transfer efficiency. Regular tube cleaning, using methods such as mechanical brushing, chemical cleaning, or high-pressure water jetting, is necessary to remove deposits and maintain optimal heat exchange.

2.2. Inspection and Repair

Routine inspections of the condenser, including visual checks and non-destructive testing, help identify any corrosion, tube leaks, or structural damage. Prompt repair or replacement of damaged components is crucial to prevent further degradation and ensure the condenser operates at its designed capacity.

2.3. Cooling Water Treatment

Effective treatment of cooling water is essential to prevent scaling, corrosion, and biological growth within the condenser. Regular monitoring and adjustment of water chemistry parameters, such as pH, alkalinity, and dissolved solids, help maintain water quality and prevent detrimental effects on condenser performance.

2.4. Air Extraction System Maintenance

The air extraction system must be inspected regularly to ensure proper functioning. This includes checking air extraction pumps, vacuum breakers, and associated valves for leaks or malfunctions. Any issues should be addressed promptly to maintain efficient air removal from the condenser.

Maintenance is of paramount importance for steam condensers due to the following reasons:

    • Efficiency and Performance: Regular maintenance ensures that the condenser operates at optimal efficiency, maximizing heat transfer and energy conversion. This results in improved overall system performance, reduced fuel consumption, and increased power generation or propulsion efficiency.
    • Equipment Longevity: Proper maintenance helps extend the lifespan of the steam condenser. Regular inspections, cleaning, and repair of components prevent premature wear, corrosion, and deterioration. This not only reduces the risk of costly breakdowns but also contributes to the longevity of the condenser and the entire steam system.
    • Energy Savings: A well-maintained steam condenser can significantly impact energy savings. When the condenser operates efficiently, more steam is converted back into water, reducing the need for additional steam generation. This leads to lower fuel consumption and operational costs, resulting in substantial energy savings over time.

3. Troubleshooting

Despite proper maintenance, steam condensers may experience operational malfunctions. Here is a troubleshooting guide for common issues:

3.1. Insufficient Cooling Water Flow:

      • Check the cooling water intake for any blockages or restrictions.
      • Verify that the cooling water pumps are operating correctly.
      • Inspect and clean the cooling water filters to ensure unrestricted flow.

3.2. Inadequate Vacuum:

      • Check for air leaks in the condenser or associated piping and repair any leaks.
      • Verify the proper functioning of vacuum pumps and vacuum breakers.
      • Ensure proper condensate removal to maintain the desired vacuum level.

3.3. Tube Fouling or Scaling:

      • Conduct a thorough cleaning of the condenser tubes using appropriate methods.
      • Review and adjust cooling water treatment to minimize scaling and fouling.
      • Consider implementing online cleaning systems for continuous tube maintenance.

3.4 Corrosion or Tube Leaks:

      • Perform regular inspections to detect any signs of corrosion or tube leaks.
      • Promptly repair or replace damaged tubes or components.
      • Consider using corrosion-resistant materials or protective coatings where applicable.

In conclusion, steam condensers are integral to the efficient operation of boilers and steam-powered systems on board vessels. Correct operation, regular maintenance, and timely troubleshooting are essential for optimal performance, energy efficiency, and prolonged equipment life. By following proper procedures, conducting routine maintenance activities, and promptly addressing operational malfunctions, ship engineers can ensure the reliable and efficient operation of their steam condensers, contributing to the overall success and safety of their vessels.

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What you need to know about cooling water expansion tanks

When it comes to maintaining efficient and reliable cooling systems, there are several crucial components that must be considered. One such component is the cooling water expansion tank.

Recently, I have been asked, by one of my followers, to write an article about cooling water expansion tank. I found the subject to be interesting and challenging as not many of us is really thinking about the importance of the expansion tank into the cooling water system. This is regarded, most of the time, as a simple tank with not so much importance.

If you want to learn more about engine cooling water system just follow the link in here and in here. Moreover, if you want to learn and understand more about vessel auxiliary equipment just click and have a look to Introduction to Marine Auxiliary Machinery.

Often overlooked, this vital piece plays a significant role in the overall performance and longevity of cooling systems. So, in this blog post, we will delve into the importance of cooling water expansion tanks, their function, and the benefits they offer in ensuring optimal cooling system operation.

Example of a cooling water expansion tank

Understanding the Function of Cooling Water Expansion Tanks

Cooling water expansion tanks are designed to accommodate the thermal expansion of water within a closed-loop cooling system. As water heats up, it expands, and without a proper means of accommodating this expansion, the system can experience excessive pressure buildup. Expansion tanks act as a reservoir for the expanding water, allowing it to safely expand and contract without compromising the integrity of the cooling system.

By providing a space for expanded water, cooling water expansion tanks help regulate system pressure. When the water expands, it enters the tank, reducing the pressure exerted on other components of the cooling system. This pressure regulation prevents potential damage to pipes, valves, pumps, and other system elements caused by excessive pressure. By maintaining a balanced pressure, expansion tanks contribute to the longevity and reliability of the entire cooling system.

Cooling water expansion tanks also play a crucial role in minimizing air and contaminant accumulation within the cooling system. The tanks are typically equipped with an air vent or an air separator, allowing trapped air to be released from the system. Removing air not only prevents airlocks but also enhances the efficiency of heat transfer, as air has a lower heat capacity compared to water. Additionally, expansion tanks can feature filtration systems that help capture contaminants and prevent their circulation within the cooling system.

Corrosion and oxidation pose significant threats to cooling systems, leading to reduced efficiency and potential system failures. Cooling water expansion tanks can include various internal coatings or linings that inhibit corrosion and oxidation processes. These protective measures help extend the lifespan of the expansion tank itself, as well as the overall cooling system.

Properly sized and installed cooling water expansion tanks contribute to enhanced system efficiency and performance. By maintaining optimal pressure levels, preventing airlocks, and reducing the risk of corrosion, expansion tanks ensure that the cooling system operates at its peak efficiency. This, in turn, translates to lower energy consumption, reduced maintenance needs, and increased overall system performance.

Example of expansion tank arrangement and fittings

Operation and Maintenance Guide for Cooling Water Expansion Tanks

Cooling water expansion tanks are crucial components of closed-loop cooling systems. To ensure the longevity and efficient operation of these tanks, proper operation and maintenance practices are essential. In the next paragraphs, we will explore the key aspects of operating and maintaining cooling water expansion tanks, providing valuable insights for engineers and operators.

      1. Regular Inspections: Regular inspections of cooling water expansion tanks are necessary to identify any signs of wear, damage, or leaks. Inspect the tank’s exterior for physical damage such as dents or corrosion. Additionally, check the tank’s connections, including inlet and outlet pipes, for any signs of leakage. Early detection of issues can help prevent costly repairs or potential system failures.
      2. Pressure Monitoring: Monitoring the pressure within the cooling water expansion tank is crucial for its proper operation. Utilize pressure gauges installed on the system to ensure the pressure remains within the recommended range. If the pressure consistently exceeds or falls below the recommended levels, it may indicate an underlying issue in the cooling system that requires investigation and correction.
      3. Ventilation and Air Release: Cooling water expansion tanks often incorporate ventilation systems or air vents to remove trapped air from the system. Ensure that the vents are clear and functioning properly to prevent airlocks, which can hinder the cooling system’s performance. Regularly inspect and clean the vents to maintain their effectiveness and promote efficient heat transfer within the system.
      4. Water Quality Maintenance: Water quality plays a vital role in the longevity and performance of cooling water expansion tanks. Implement appropriate water treatment methods, such as filtration and chemical treatment, to prevent the accumulation of contaminants that could lead to corrosion or blockages within the tank and the cooling system as a whole. Regularly monitor water quality parameters, such as pH levels and dissolved solids, and perform necessary maintenance and treatment actions based on the results.
      5. Periodic Flushing and Cleaning: Over time, sediments, debris, and scale may accumulate within the cooling water expansion tank. Regular flushing and cleaning of the tank will help remove these deposits, ensuring optimal performance. Follow manufacturer guidelines and industry best practices when conducting flushing and cleaning procedures, and use appropriate cleaning agents that are compatible with the tank’s material.
      6. Maintenance of Tank Supports and Mounting: Cooling water expansion tanks are typically supported by brackets or mounting systems. Periodically inspect these supports to ensure they are secure and in good condition. Any signs of wear, rust, or damage should be addressed promptly to prevent potential tank displacement or failure.

Proper operation and maintenance of cooling water expansion tanks are essential for the reliable and efficient performance of cooling systems. By conducting regular inspections, monitoring pressures, ensuring proper ventilation, maintaining water quality, and performing necessary cleaning and maintenance procedures, engineers can prolong the lifespan of the tanks and optimize the overall cooling system performance. Collaborating with maintenance professionals when needed will further enhance the effectiveness of the maintenance efforts, contributing to the long-term success of the cooling water expansion tank and the entire cooling system.

In conclusion, cooling water expansion tanks may be small in size, but their significance in cooling system operation cannot be overstated. From pressure regulation and system protection to minimizing air and contaminant accumulation, these tanks offer numerous benefits that help maintain the efficiency, reliability, and longevity of cooling systems. By understanding the importance of cooling water expansion tanks and incorporating them into cooling system designs and maintenance routines, engineers and operators can ensure optimal performance and maximize the lifespan of their systems.

If you have any questions regarding above, please feel free to use our existing forum Seafarer’s World, Telegram Chief Engineer’s Log Chat or Instagram and will try to answer to all your queries. You can use the feedback button as well!

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What to do in case of oil contamination of marine boilers

Marine boilers play a vital role in powering vessels, providing heat and energy necessary for various operations at sea. However, the occurrence of oil contamination within these boilers can have severe consequences, jeopardizing both the safety and efficiency of maritime operations. In this blog post, we will explore the causes, impacts, and essential steps to address marine boiler oil contamination, ensuring the smooth operation of marine vessels.

Understanding Marine Boiler Oil Contamination

Marine boiler oil contamination refers to the unwanted presence of oil or oil-related substances within the boiler system. This contamination can arise from multiple sources, including fuel supply contamination, leakage from seals or pipes, improper maintenance practices, or even accidental spills. Regardless of the source, the effects of oil contamination can be detrimental and require prompt attention.

Many of you must’ve been heard or encounter an oil contamination of the boiler due different machinery or systems breakdown. The contamination has an immediate and consequential impact on boiler operation and is needless to say that the adverse effects of oil contamination on boiler steel and the plant can never be deemed overemphasized. In some situations, large areas of heat transfer lead to the development of cracks, which in turn leads to a loss of the material’s integrity. The majority of them lead to costly repairs that require a significant amount of time and effort, such as the replacement of pressure parts, chemical-mechanical cleaning, and downtime.

Boiler oil contamination

The most prevalent sources of oil pollution detected on boilers come from leaking heating coils fitting in fuel oil tanks, fuel/lube oil heaters, cylinder lube oil from reciprocating steam engines for pumps, and heating coils in DB tanks allocated for sludge/waste oil tanks. It is not unheard of for cargo tank heating coils and tank cleaning heaters installed on the cargo side to be a contributing factor in some instances of contamination.

On the other hand, main propulsion boiler plants that use a segregated saturated steam system as their primary source of heating medium have the lowest risk of oil contamination.

Minor cracks in HFO heating coils or in other heaters in the engine room or in other places on the ship where steam is utilized for heating can sometimes be the cause of oil leaks that become more severe over time. There are several different pathways by which oil can seep out of an engine room in today’s advanced machinery. It is not usually possible to see very thin coatings of oil. According to past experiences, oil pollution at a level of 15–20 ppm (parts per million) will not be noticeable. If there is an oil pollution level of 25 parts per million, then the steam drum will collect roughly 12 kilograms of oil every single day. The boiler has a capacity of 20 tons of steam per hour. There is a potential for localized overheating of the material and potential damage to the boiler if there are thin layers of oil on the tubes of the boiler or on any of the other directly heated surfaces of the boiler.

Example of oil heater


Impacts of Marine Boiler Oil Contamination

Foaming and carryover in oil-fired boilers due to increased tension at the water surface are two of the immediate effects of oil contamination. Other immediate effects of oil contamination include malfunctioning boiler water level controls and even protective shutdown systems. Carry-over of water and moisture with the steam may even reach the intensity of priming in the worst-case scenarios, wreaking widespread destruction on consumers such as turbines, super heaters, steam pipework, and associated gaskets.

The presence of severe oil pollution causes a decrease in the rate at which heat is transferred through the steel of the boiler, which contributes to the metal temperature being greater than the design value. Even an oil film or deposit as thin as 0.5 millimeters thick on the water side of an auxiliary boiler rated at 7 bar (g) can easily increase the metal temperature on the furnace side from the design value of 250 degrees Celsius to well above 600 degrees Celsius under normal operating conditions. This occurs when the metal temperature on the furnace side exceeds the design value of 250 degrees Celsius. Because of this, there is a domino effect that leads to an exponential decrease in the material’s yield strength. This continues until the pressure parts that are subjected to active heat transfer fail.

In circumstances in which the decrease in strength does not result in an immediate failure, the boiler steel may nevertheless be subjected to a time-dependent creep zone that is difficult to evaluate (if the temperature is higher than 380 degrees Celsius), unless alloying is taken into account during the design stage.

In the case of exhaust gas water tube boilers with an extended surface area that forms part of the system for the generation of steam by forced circulation, this may, in the worst cases, lead to soot fires due to a lack of heat transfer from the gas side and a rise in the temperatures of the metal due to the uncooled boundaries. In addition, this may cause a decrease in the efficiency of the steam generation system. As a result of the differential expansion of the overheated tubes in comparison to the shell, smoke tube exhaust gas boilers are prone to developing cracks on the tube terminations (see the image below for an example).

It is also important to be aware that other long-term impacts include local corrosion of the area that has been exposed to the acidic nature of oil deposits. This is something that should be kept in mind. When hydrocarbon deposits are subjected to high temperatures in the presence of water, they have a propensity to undergo an acidic transformation.

Addressing Marine Boiler Oil Contamination

As an immediate precautionary measure, derating the boiler’s steam generating capacity by reducing the firing rate/heat input in conjunction with the design working pressure is highly  recommended.

Depending of the degree of oil contamination on boiler, sometimes can lead to a requirement of the permanent restoration of the heat-transfer surfaces on the water and steam side prior to the boiler being put back into service.

Rebuilding boiler tube nest

To mitigate the negative impacts of marine boiler oil contamination, it is crucial to follow a systematic approach. Here are the key steps to be taken:

      1. Detection and Confirmation: Regular monitoring and analysis of water samples can help detect contamination. Suspicious characteristics or abnormal levels of impurities should be investigated further to confirm the presence and extent of the contamination.
      2. Isolate the Contaminated System: To prevent the spread of contamination, it is necessary to isolate the affected marine boiler system. This may involve shutting down the boiler or bypassing it temporarily until the issue is resolved.
      3. Identify the Source: Thorough inspection and investigation should be conducted to identify the root cause of the oil contamination. Addressing the source is essential to prevent its recurrence and implement appropriate preventive measures.
      4. Clean the System: Cleaning the contaminated marine boiler system is vital to remove oil residues and contaminants. The cleaning process typically involves flushing the system with specialized cleaning agents or solvents designed for marine boiler systems.
      5. Rinse and Drain: After the cleaning process, the system should be thoroughly rinsed with fresh water to eliminate any remaining cleaning agents or loosened contaminants. Complete drainage is necessary to ensure a clean and oil-free environment.
      6. Inspect and Replace Components: Inspect all components of the marine boiler system for damage or residual contamination. Replace compromised or heavily contaminated components to ensure the integrity and reliability of the system.
      7. Test and Restore: Thorough testing of the marine boiler system is necessary to ensure its proper functioning. Conduct pressure tests, verify temperature control, and monitor performance indicators to restore optimal operation.
      8. Preventive Measures: Implementing preventive measures is crucial to minimize the risk of future oil contamination incidents. This includes regular maintenance, monitoring, and sampling of the marine boiler system, along with adequate crew training in boiler operation and maintenance best practices is essential.

Boiling out the water side of the boiler using recommended chemicals and/or mechanical cleaning are normal procedures undertaken to facilitate satisfactory cleaning. This may be additionally supported by hardness checks and a hydrostatic pressure test at 1.5 times the design working pressure to ensure the expected safety factor at the design temperature.

Boil-out chemicals are highly caustic. Caustic Soda ash will produce a violent flash if introduced to water too rapidly. It is needless to say that the crew involved into this operation and handling the chemicals must wear protective equipment like, goggles, gloves, aprons, and an emergency shower should be nearby. Vinegar can be used as an antidote.

Below there is a recommended boil-out procedure that may be followed:

      1. If the boiler is equipped with prismatic type gauge glasses, replace them with the temporary boil-out glass to prevent chemical attack on the operational gauge glasses.
      2. Remove all manholes and handholes’ covers to verify that tubes and nozzles are not plugged with foreign materials.
      3. Wire brush any heavy scale on drum surfaces and remove them out.
      4. Close all inspection openings such as manholes, handholes, etc.
      5. Fill the boiler to the lower level of the water gauge glasses.
      6. Blow-down valves, scum valves, and gauge cocks should be checked and closed.
      7. Add the chemical and water mixture to the unit slowly and in small amounts to prevent excessive heat and turbulence. Add the mixture through the chemical feed or feed-water connections to a level just above the bottom of the gauge glass.
      8.  Fire the boiler at a very low firing rate.
      9. When the boiler begins to produce steam (as seen through the open vents), allow the unit to steam freely for at least four hours. Watch the level in the gauge glass and always maintain normal water level (midpoint of the gauge glass). It will be necessary to add more boil-out solution when the water level falls.
      10. Close all vents.
      11. Keep the drum pressure at aprox.1 bar.
      12. After 8 hours, increase the pressure up to 20 % of the nominal working pressure.
      13. Continue boil out for at least 48 hours. During this period, open the blowdown valve intermittently and drain an amount of solution equal to one-half of the gauge glass every eight hours. Then refill the unit to the midpoint of the gauge glass with the boil-out solution.
      14. The boil out procedure should be continued until clean blowdown is observed.
      15. If clean blow down is observed, the boiler should be stopped and cool down gradually.
      16. Drain the water in accordance with local, national and international rules and regulations.
      17. Flush the boiler with clean water for at least 2 times.
      18. Fill the boiler with clean distillated water and start the firing up procedure.
      19. Start using treatment chemicals as per manufacturers’ instructions.

For stubborn oil deposits or heavy contamination, manual mechanical cleaning may be required. Use appropriate brushes, scrapers, or cleaning tools to remove the oil residues from internal surfaces, tubes, and components. Be careful not to damage the boiler surfaces during this process.

It’s important to note that the above steps provide a general guideline, and the specific cleaning process may vary depending on the type of marine boiler and the severity of contamination. It is recommended to consult the vessel’s operational and maintenance manuals, follow manufacturer recommendations, and seek expert assistance to ensure a safe and effective cleaning process tailored to your specific marine boiler system.

In conclusion, marine boiler oil contamination poses a significant threat to the efficiency, safety, and environmental sustainability of maritime operation. Timely detection, isolation, and remediation are vital to address this issue effectively. By following a systematic approach and implementing preventive measures, vessel operators can safeguard their marine boilers, reduce operational costs, and ensure a safe and smooth voyage. Prioritizing the elimination of oil contamination is not just an imperative for individual vessels but also for the overall well-being of the marine industry.

If you have any questions regarding above, please feel free to use our existing forum Seafarer’s World, Telegram Chief Engineer’s Log Chat or Instagram and will try to answer to all your queries. You can use the feedback button as well!

If you like my posts, please don’t forget to press Like and Share. You can also Subscribe to this blog and you will be informed every time when a new article is published. Also you can buy me a coffee by donating to this website, so I will have the fuel I need to keep producing great content! Thank you!

What you need to know about steam traps

The evaporation of water into a gas results in the production of steam and in order for the process of vaporization to take place, the water molecules need to be provided with an adequate amount of energy so that the bonds that hold them together (hydrogen bonds, etc.) may be severed. The term “latent heat” refers to the heat that is released when a liquid is converted into a gas. That latent heat is transmitted and used by the medium being heated and after this has been released, the steam condenses. The condensate doesn’t posses the same heating capacity as the steam and if is not quickly removed from the steam piping or heat exchangers, the efficiency of the heating system will drastically drop. (more about steam system can be found by following this link).

I believe that many of you working onboard vessels have encountered, at least once, problems with the steam heating for different systems, problems that were mostly related to the steams traps installed along the steam lines, which most of the time are found to be rusty, seized and replaced with a regular ball-valve.

Steam traps are very important parts of the steam system and they are a form of automatic valve that are designed to prevent steam from escaping while simultaneously removing condensate (also known as condensed steam) and non-condensable gases such as air. Like in any other industry, steam onboard vessels is used for either the purpose of heating or as a driving force for mechanical power. In these kinds of applications, the usage of steam traps is necessary to prevent the loss of steam.

Example of steam trap. Source and credit: Sanmar Enteprises

As per ANSI/FCI 69-1-1989 the steam traps are defined as “self contained valve which automatically drains the condensate from a steam containing enclosure while remaining tight to live steam, or if necessary, allowing steam to flow at a controlled or adjusted rate. Most steam traps will also pass non-condensable gases while remaining tight to live steam.”

Using a ball-valve instead of a steam trap, it might look and sound like a “good” compromise, especially when you don’t have a spare steam trap, but because the valve opening is set to discharge a constant amount of fluid using this method, it is unable to correct for fluctuations in the load of condensate because of this arrangement. This is the method’s most significant drawback. In point of fact, the amount of condensate produced by a particular system is not a constant. When it comes to the piece of machinery in question, the load of condensate that is present during start-up is distinct from that which is present throughout normal operation. Variations in the product load also result in variations in the amount of condensate that is created as a byproduct of the process. Condensate that ought to be discharged will instead pool inside the equipment or the pipe, and the effectiveness of the heating system will suffer as a result, because the manual valve is unable to adapt to fluctuations in condensate load. On the other side, steam leakage will take place when there is a decreased condensate load, which will result in the loss of steam.

There are different types of steam traps used onboard vessel and those mainly are:

    • mechanical traps: float type, inverted bucket type.
    • thermostatic type traps

Example of mechanical steam trap. Source and credit: TLV CO. LTD

In contrast to other types of steam traps, which rely on either a change in temperature or a change in the velocity or phase of the steam, mechanical traps are steam traps that function according to the principle of specific gravity (more specifically, the difference between the specific gravities of water and steam). When it comes to mechanical traps, the movement of a float that rises and lowers in response to the flow of condensate is what causes the valve to open and close.

Example of float type steam trap. Source and credit: TLV Co. LTD

When using float traps, the amount of condensate in the trap has a direct influence on the location of the float inside the trap. The float is sensitive to the flow of condensate and adjusts its position to either open or close the valve in response. A float is typically fastened to the lever that operates the valve in designs known as lever floats. The float will become buoyant as condensate begins to enter the trap. This will cause the lever to move, which will then cause the trap valve to open. On the other hand, because the lever arm has a restricted range of motion, the head of the valve frequently remains in the direction of the flow of condensate. This might result in an additional pulling force being required to close the valve when there is a significant volume of flow.

Example of inverted bucket type. Source and credit: TLV Co. LTD

In steam traps that use an inverted bucket, the bucket itself is coupled to a lever that controls the opening and closing of the trap valve in reaction to the movement of the bucket. The steam causes the bucket to become buoyant and rise to the surface when air or steam enters into the underside of the inverted bucket and condensate surrounds it on the outside. When placed in this position, the bucket will bring about the closing of the trap valve. A vent hole is located at the top of the bucket, and it is there so that a small bit of the vapor can be released into the top of the trap, and then it can be discharged further downstream. When vapor is released through the vent hole, condensate begins to fill the interior of the bucket. This causes the bucket to sink, which enables the lever to open the trap valve and release any condensate that has accumulated.

Mechanical traps are able to function in precise response to the flow of condensate and their performance is unaffected by the majority of the environmental influences that may affect other types of traps. This is one of the distinguishing advantages they have over thermostatic and thermodynamic steam traps.

Steam traps of the thermodynamic type are highly sought after because of their small size and adaptability across a broad pressure range. They could have a straightforward structure and be able to function in either the horizontal or the vertical orientation.
Thermodynamic disc steam traps have an operating characteristic that is cyclical and intermittent at the same time. After opening to allow the discharge of condensate for a few seconds, the valve mechanism, which is made up of a disc and seat rings, subsequently closes for a generally longer period of time until the beginning of a new discharge cycle. The differential in the forces that are exerted on the top and bottom sides of the valve disc is what’s responsible for the opening and closing action that thermodynamic disc traps exhibit. Variations in the kinetic energy and pressure energy of the typical fluids involved, which include air, condensate, and steam, are the fundamental basis for these forces. At the beginning of the operation, incoming fluids at line pressure consisting of air and/or condensate (and even sometimes steam) exert an opening force (lifting force) on the bottom of the valve disc, which causes it to raise and open. Because of this opening force, the disc is lifted off of its seat to provide room for condensate passage.

There are several reason of why a steam trap doesn’t function properly and these can be (if you want to learn more about it follow this link):

    • negative pressure differential – the pressure drop across steam trap must be zero or positive in order steam to be discharged.
    • steam lock – steam locking occurs when the steam is trapped between condensate and the steam trap.
    • group trapping – collecting condensate from different sections of steam heated equipment with different condensate pressure into one condensate line with one steam trap.
    • high backpressure
    • debris or deposits
    • backward installation
    • etc.

As is the case with any mechanical device, a steam trap, regardless of how long-lasting it may be, will at some point require either repair or replacement. When a trap is used for a longer period of time, it has more of a chance to become worn. Because of this wear, the performance of the trap will deteriorate, and it may finally become impossible to use.
Because a trap’s lifecycle can be influenced by a number of factors, such as the steam trap type, application, pressure, condensate load, piping configuration, and steam/condensate quality, determining when a trap will fail is an extremely difficult task. This is due to the fact that a trap’s lifecycle can be influenced by a number of factors. Every vessel that uses steam should implement a steam trap management program to assist prevent premature trap failure and identify failures in a timely way.

If you have any questions regarding above, please feel free to use our existing forum Seafarer’s World and will try to answer to all your queries. You can use the feedback button as well!

If you like my posts, please don’t forget to press Like and Share. You can also Subscribe to this blog and you will be informed every time when a new article is published. Also you can buy me a coffee by donating to this website, so I will have the fuel I need to keep producing great content! Thank you!

Source and Bibliography:

  • YouTube video credit: The Engineer Portal T.E.P; hararat
  • Photo credit: mentioned on every photo

Boiler operation, chemical scale control and defects

On one of my previous posts, we have discussed about Boiler chemical dosing and control and explained how to test the water and dose the chemicals for water treatment. As the water treatment chemicals tend to settle the impurities, these will form deposits at the bottom of the boiler or will float at the surface of the water and need to be removed.

Always operate the boiler in accordance with the instructions provided by the manufacturer of the boiler, which should contain techniques for blowing down the boiler. The boiler will be equipped with either a surface skimmer valve or a bottom blowdown valve.

Example of boiler skimmer valve

In order to keep the operations of a boiler steady, it is vital to manage blowdown control in the appropriate manner and there are a number of different considerations that go into determining how blowdowns should be carried out. The following are the primary goals:

    • Bottom blowdown for the prevention and removal of sludge deposits in the boiler
    • Management of material that is floating on the surface – skimmer
    • Controlling dissolved solids, preventing carryover, and reducing corrosion are all achievable goals with either approach.

If the boiler operates, especially on shore water, calcium phosphate sludge deposits may form on the bottom of the boiler, making it necessary to perform periodic bottom blowdowns. These will frequently settle at the bottom of the boiler, and the periodic operation of the bottom blowdown will assist in the removal of any deposits that may have formed there. In the event that this is not done, the boiler runs the risk of developing excessive amounts of sludge deposits, as well as the potential for the heating surfaces of the boiler to get overheated.

Example of overheated areas in marine boilers

There is a possibility that not all boilers have surface skimmers. If the water is distilled or extremely soft, the requirement for bottom blowdowns may be reduced, and the surface skimmer may be able to control the amount of dissolved solids in the water instead. Conductivity in the boiler water can be automatically maintained by some boilers thanks to built-in automatic devices.

The word “Cycle of concentration” refers to the ratio of the amount of dissolved solids that is present in the feed water to the amount that is present in the boiler water. There are a few approaches to this calculation; one of the more prevalent methods involves measuring the levels of chlorine in both the feed water and the boiler water. A fundamental illustration of a boiler with a 5% blowdown can be seen in the figure below.

Example of cycle of concentration

In this particular scenario, there are a total of 20 cycles of concentration (10 t / 0.5 t). This figure will often fall somewhere in the range of 10 to 30 most of the time.

In addition to an adequate pre-treatment of the boiler feed water, controlled reserves of treatment chemicals need to be maintained in the boiler water. This is necessary in order to guarantee that any traces of deposit-forming compounds, such as salts of calcium, iron, silica, copper, and magnesium, are prevented from forming hard scales or baked-on sludges. Scale buildup can be avoided by the use of a variety of different treatment strategies.

The carbonate cycle control method of treatment is only suggested for package boilers up to 10 bar that do not have any external feed-water treatment. This might potentially provide us with calcium hardness in the feed water of approximately 40 ppm. By adding sodium carbonate, the objective is to keep the carbonate alkalinity in the boiler water at a level of no less than 250 ppm. Because of this, any calcium that may have been present will now precipitate in the majority of the boiler water rather than becoming baked-on scale on the heat transfer surfaces. After that, the fine precipitate is extracted using the blowdown of the boiler. An excessive amount of carbonate will eventually decompose, resulting in the formation of hydroxide, alkalinity, and carbon dioxide. In the event that silica is present in the boiler water, magnesium will either precipitate as magnesium hydroxide or magnesium silicate. It is essential to include dispersants in this program in order to guarantee that precipitated compounds will remain in suspension throughout the blowdown process. This will make the process more simpler.

The phosphate cycle control treatment approach relies on good quality pre-treatment, (usually sea water evaporators) plus the addition of soluble phosphate and hydroxide alkalinity to the boiler-water. These react with any trace calcium, magnesium and silica impurities to form fine precipitates of: Calcium Hydroxyapatite, Serpentine and Magnesium Hydroxide. These compounds have an exceptionally low solubility, which means that they will precipitate in the boiler water. They can then be removed by blowdown after they have done so. Again, it is essential to include dispersants as part of the treatment program to guarantee that precipitated compounds are kept in suspension throughout the treatment process and to make it easier to remove them using blowdown.

When the chemistry of the phosphate cycle is used, it is essential to keep enough amounts of OH alkalinity in the solution. This will ensure that magnesium will precipitate as either magnesium hydroxide or as hydrated magnesium silicate, both of which are inert compounds. In order for us to reach these circumstances, we need to work toward achieving an alkalinity ratio of 0.4:1 for silica to OH and a ratio of 1:10 for phosphorus oxide to OH. Overdosing of phosphate must also be avoided to prevent the formation of phosphate scales.

The application of polymeric conditioning treatments is able to more than adequately maintain control of deposition in situations in which one can rely on appropriate and constant pre-treatment of boiler feed-water. These are often formulated with long chains of negatively charged polymers and co-polymers, and they have an excellent stability at the high temperatures that are present in boiler fluids. These formulations are generally considered to be proprietary.

All polymer treatments can be described to inhibit scales by the following mechanisms:

    • Crystal modification – The dispersant acts on the surface of the scale as it is formed to prevent the formation of large angular crystals which are adherent to the heat transfer This action causes the scale to form in smaller, more rotund particles which are less adherent to surfaces.
  • Example of crystal modification

    • Dispersion – The negatively charged polymers attach to boiler metal and surround particles in the boiler-water. This mechanism sets up repulsive forces that inhibit the particles from agglomerating to form scale or sludge deposits.
  • Dispersation

    • Complexation – Negatively charged polymers can form weak sub-stoichiometric complexes with calcium, magnesium and iron which allow these impurities to exceed their normal solubility levels and acts to inhibit deposition at heat transfer surfaces. For best scale control it is important to maintain an adequate reserve of free polymer in the boiler water at all times.


Typical boiler damages and defects and auxiliary boiler defects on pressure parts are typically related to mechanisms such as:

    • Active local pitting corrosion from the water/steam side
    • Overheating due to deposits, oil, scales, low water level, flame impingement, etc.
    • Poor workmanship during fabrication
    • Soot fires on fin/pin type water tube exhaust gas boilers
    • Cold corrosion from gas side

It has been observed that the majority of boiler defects that are reported are caused by corrosion, which arises out of probable factors related to an inferior water condition, most often as a result of insufficient maintenance. This is the case because corrosion arises out of probable factors related to an inferior water condition.

It would appear that the absence of a stable and passive magnetite layer (oxide) on the water/steam side of metal surfaces is the primary contributory mechanism that causes many of the documented faults.

Example of passive and stable magnetite layer

A smaller number of defects are related to other factors or operational issues.

It has been observed that many ships are struggling to allocate time and arrange acceptable materials and resources to repair the defects after they have occurred or are observed, making the situation even worse.

The following are the most significant things that have been learned as a result of inspections and surveys experience:

    • Enhanced focus on water treatment: The risk of active local and general corrosion of the internal surfaces (steam and water side) is reduced to a minimum by utilizing prescriptive methods to initiate and sustain a passive magnetite layer on steel surfaces, as well as by increasing the frequency of monitoring the water condition. This keeps the risk of corrosion to a minimum. In addition, the heat transfer barriers can be decreased by maintaining the ideal state of the heat transfer surfaces. This can be accomplished by avoiding the accumulation of scale and other impurities, for example. This therefore results in:
        • Improved fuel efficiency
        • Avoidance of thermal strains that could lead to cracks in the material
        • Preventing the wall of the furnace, the top plate, and the screening tubes from becoming overheated
    • Monitoring and maintenance of the boiler plant: Placing a greater emphasis on maintenance and conducting internal inspections reduces the likelihood that other contributing factors may result in a defect or make the likelihood of one occurring more likely (flame impingement from burner, etc.).
    • The risk of water side contamination/excessive dissolved oxygen and defects related to the gas side is minimized by optimizing the design of the feed water system (using things like salinometers, oil content sensors, and hotwell temperatures, for example), as well as monitoring the differential pressure across the exhaust gas boiler.
    • A more flexible class survey – As a consequence of this, a portion of the scope during each alternative boiler survey – which is not connected to the main class renewal survey – can be credited based on the chief engineer’s inspection report, which reflects evidence of a satisfactory internal examination. This is because the main class renewal survey is not connected to the alternative boiler survey.

If you have any questions regarding above, please feel free to use our existing forum Seafarer’s World and will try to answer to all your queries. You can use the feedback button as well!

If you like my posts, please don’t forget to press Like and Share. You can also Subscribe to this blog and you will be informed every time when a new article is published. Also you can buy me a coffee by donating to this website, so I will have the fuel I need to keep producing great content! Thank you!

Source and Bibliography:

  • WSS Water Treatment
  • DNV

What you need to know about engine cooling system – part II

On my previous post we have discussed about how the engine cooling systems can be affected by scaling and corrosion and how different materials behave when they are exposed to corrosive environment. This post is a continuation and would like to discuss about how we can prevent and inhibit the scaling, fouling and corrosion in the engine cooling systems.

The majority of systems are designed and manufactured in such a way that a chemical inhibitor is required in order to control corrosion. This is the case despite the fact that there are many different options available for minimizing corrosion through improved design, the selection of materials, and improved construction techniques.

Example of anode  for corrosion protection purpose

As was said previously, each of the four components of a corrosion circuit needs to be finished in order for corrosion to take place. Therefore, any chemical treatment that is put to the water and stops the anodic reaction will halt corrosion, and any inhibitor that prevents the cathodic reaction will minimize corrosion. This applies to both types of treatments.

On the basis of the manner in which they influence the corrosion cell, corrosion inhibitors are divided into the following three categories:

    • Anodic inhibitors
    • Cathodic inhibitors
    • Combination inhibitors/organic inhibitors

Long-chained carboxylic acids form the foundation for the development of more recently discovered types of inhibitors. These have the benefit of depleting very slowly, which means that after the initial dosage, very little replenishment of the inhibitor is required and this is an advantage. Aluminum, along with the other metals that are frequently employed in a cooling system, is protected by the Organic Acid Technology inhibitors.

Example of Organic Acid Technology Inhibitor

Nitrites, which are good anodic corrosion inhibitors for mild steels, are by far the most frequent type of corrosion inhibitor utilized in engine cooling systems.
Nitrites cause mild steel surfaces to oxidize, which results in the formation of a layer of corrosion product that is exceedingly thin yet highly tenacious. Because of the very large dose rates that are necessary, nitrites are almost exclusively utilized inside of closed systems due to the economic benefits associated with this application method. There is no discernible effect that hydrocarbons or glycols have on the performance of nitrite.

Example of nitrate corrosion inhibitor

At the anode, silicates, which contain the anion SIO32-, react with dissolved metal ions. The gel that is formed as a result of the formation of the metal ion/silicate combination deposits itself on anodic sites. When compared to other regularly used inhibitors, the gel creates a layer that is adherent and essentially unaffected by pH. This layer is formed into a thin layer. The temperature and pH of an environment both contribute to an increase in the inhibitory qualities of silicates. In the normal case, silicates are employed to prevent corrosion of aluminum when the pH level is high (9.5 – 10.5). It is essential to keep the silicate in solution within this pH range in order to forestall any significant precipitation.
It is important to note that in this environment, if localized boiling causes cavitation and concentration mechanisms, then extremely rapid corrosion of the aluminum will occur because the protective oxide layer will be destroyed and the metal will be dissolved by the high pH conditions. This is something that must be taken into consideration.

In the presence of dissolved ferric ions, such as Fe2+, orthophosphate (PO4) can form an insoluble complex with these ions, which then deposits at anodic sites. When compared to other anodic inhibitors, ferric orthophosphate has a greater adhesion and is less sensitive to pH. When the pH is between 6.5 and 7.0, the film develops with more efficiency. Around 10 ppm is considered to be the standard minimum dosage rate in neutral seas.

In order to produce positively charged colloidal particles, polyphosphates must first form complexes with calcium, zinc, and any other divalent ions present. These move to the cathodic sites where they precipitate and form a coating that acts as a corrosion inhibitor. In order for polyphosphates to carry out their intended functions, calcium must be present in concentrations of at least 50 ppm. As is the case with zinc hydroxide, pH extremes have the potential to disrupt the stability of the inhibitor coating.

Zinc ions have a positive charge, which is why they are drawn to the cathodic region of the corrosion cell. Zinc hydroxide (Zn(OH)2) is formed when soluble zinc ions combine with the free OH ions found in the area surrounding the cathode to create a film. This protective coating is sensitive to shifts in the pH of the environment. If the pH is too low, then the film will dissolve and not reform, and if the water conditions are too alkaline, then the zinc hydroxide will precipitate in the bulk of solution rather than at the cathodic site. If the pH is too high, then the film will reform. The pH range that is typically considered acceptable for the use of zinc-based corrosion inhibitors is 7.4 to 8.2.

Phosphonates were at first implemented into the water treatment industry as scale inhibitors in order to take the place of polyphosphates. It has been demonstrated that they are capable of adsorption onto the surface of the metal by the P-O group, particularly in alkaline and hard fluids. In order to achieve the highest efficacy against corrosion, phosphonates are typically utilized in concert with other types of inhibitors.

Benzotriazole (BZT) and Tolytriazole (TTZ) are put to use as corrosion inhibitors that are tailored specifically for copper and brass. They attach themselves to the surfaces of the metals, which breaks the electrochemical circuit. These components are resistant to the temperatures and pH levels that can be encountered in engine cooling systems. They are typically mixed into unique corrosion inhibitor formulations because of their stability in these environments.

Once an appropriate corrosion inhibitor has been chosen and applied to an engine cooling circuit, general testing of the water quality would be carried out to measure the levels of inhibitor, pH and chlorides (as a check for contamination), and hardness salts. This would be done in order to determine whether or not contamination has occurred.

Example of water test kit used onboard vessels

Bacteria are uncomplicated forms of life that can be found in practically all of the water that can be found on Earth, which if they are already present in engine cooling circuits have the ability, under certain conditions, to adapt so that they can feed on the nitrite-based compounds that are employed in corrosion inhibitors and also on oils that are introduced into the cooling circuit as impurities. As a result of the bacteria’s actions, nitrite is converted to nitrate, which results in the loss of corrosion inhibition. This circumstance can result in rapid population increases of bacteria, which can then lead to the creation of insulating biofilms on the internal surfaces of the cooling system as well as the obstruction of filters and control devices. Because of the existence of the deposit, the effectiveness of the cooling system will decrease, and there will be an increased danger of corrosion as a result of the depletion of the corrosion inhibitor. Scale deposits produce the same effect.
The typical manifestation of this condition is the depletion of the nitrite reserve along with a steady or rising trend in the conductivity of the system. This is because the nitrate that has been generated continues to contribute to conductivity.
The high temperatures and pH levels that are generally experienced in engine cooling circuits contribute to the low incidence of microbial fouling that can occur. In the event that microbiological fouling is discovered, a specialized biocide should be used to eliminate the bacteria that are causing the problem and prevent further growth.

Example of biocide

Seawater is used to provide feed-water to the Evaporators, secondary cooling for the Engine Cooling Circuits and in some cases cooling for the Air Charge Coolers. Seawater is introduced into the ship through open inlets and stored in containing tanks called ‘sea-chests’ within the body of the hull. These cooling duties utilize a variety of Heat-exchanger designs which can become severely fouled due to impurities and contamination in the sea-water supply.

Example of seawater filter on the central coolers

As was said previously, corrosion and scaling are two issues that can be caused by the dissolved gases (oxygen and carbon dioxide) and salts of magnesium and calcium that are found in sea water. However, because these cooling systems have a high flow that only goes through them once, it is not economically feasible to continuously apply treatment to inhibit scale and corrosion like it is in boiler cooling circuits and engine cooling circuits. The easiest way to prevent scaling and corrosion is to make sure that the metallurgy of the heat exchanger is chosen correctly and to keep the temperature of the sea water below 50 ºC at all times.

The presence of microorganisms that are found naturally in sea water is the primary cause of the issue known as fouling, which is related with sea-water cooling circuits. The Mussel (Mytilus Edulis) and the Barnacle are the two troublesome species that cause the most issues (Balanus Balanoides).

Example of mussels and barnacles attached to the vessel sea water intake chest

These species are extremely numerous all throughout the world, and their spawning seasons change according to the environmental conditions that are present at the time. When the water temperature rises above 10-15 degrees Celsius, spawning activity begins to take place. Because of this, the majority of boats operating in deep sea environments are prone to pollution and fouling.
Filters and strainers are able to remove mussels and barnacles after they have reached full maturity; nevertheless, it is the newly produced species, known as veliger, that are the source of the issue. These veligers begin their lives in a very small size, making it simple for them to enter the cooling circuit and cause problems. Once they are inside the system’s pipes, they attach themselves to the surfaces utilizing protein fibers that are strong and elastic (Byssus). Once they have attached themselves, they are able to quickly feed and expand. Because of their growing size and population, streams are becoming fouled and blocked more frequently.

The presence of this type of fouling will lead to:

    • Reduced cooling efficiency
    • Risk of under deposit corrosion and failure
    • Risk of cavitation and impingement corrosion
    • Increased pumping and maintenance costs

Due to the fact that the issue organisms are alive, it is possible, in theory, to eliminate them through the use of a number of different biocide additives or the installation of Marine Growth Protection Systems (MGPS).
It has been tried to use chlorine, however it has been shown that fully grown species can require 0.2 to 1.0 ppm free chlorine over a period of up to 10 days, which can be difficult to accomplish on a ship at sea. Additionally, fully matured mussels and barnacles have the ability to recognize the presence of chlorine as an irritant. In response, they will ‘shut up’ and exude a mucous seal that is resistant to the biocide. Eliminating mussels and barnacles while they are in their most defenseless stage (as veligers) and preventing them from attaching and growing is the most effective strategy for dealing with these organisms. This can be achieved through the consistent use of a biocide and anti-foulant that is specific to the company.

If you have any questions regarding above, please feel free to use our existing forum Seafarer’s World and will try to answer to all your queries.

If you like my posts, please don’t forget to press Like and Share. You can also Subscribe to this blog and you will be informed every time when a new article is published. Also you can buy me a coffee by donating to this website, so I will have the fuel I need to keep producing great content! Thank you!

Source and Bibliography:

  • WSS – Water Treatment Technical Manual


What you need to know about engine cooling system – part I

Diesel engines are the most common type of propulsion and power source for ships that are employed in the marine industry and they typically do not burn diesel fuel, despite their name, but rather heavy fuel oil that has been heated and purified by centrifugal filtering before being used. As a byproduct of the combustion processes, significant volumes of waste heat are produced and exhaust gas boilers are used to collect some of the energy that would have been lost as waste heat and put it to use in the production of steam. It is necessary to dissipate the bulk of the heat that is created by combustion in order to avoid the moving parts of the engine, such as the pistons, valves, and associated seals, from overheating and failing. The cooling of the combustion chamber and the cylinder head is made possible thanks to the incorporation of a water cooling circuit into the design of the engine. This allows for the heat to be dissipated more effectively.

Example of engine cooling circuit

The cooling system for the engine is intended to function as a “closed cooling system,” which means that the make-up is typically less than 5% of the total capacity of the system each week. On the other hand, make-up rates can be far greater than anticipated if the system is older, which increases the likelihood of leakage and the requirement for frequent and/or emergency maintenance. If the make-up water comes from the system that handles evaporated water, then scaling is not typically an issue because this water does not include any salts that can cause scale formation. Scale deposition is likely to occur in situations where shore water is used as the make-up water and the makeup rate is high. This might cause operational problems and put the facility at danger of having to shut down for repairs.

Deposits in engine cooling systems are caused when the solubility limits of contaminants dissolved in the make-up water are exceeded, which causes the water to become contaminated and contaminants become insoluble and deposit as the cooling circuit is heated and/or concentrated. This causes the scale to form. Calcium carbonate for example will deposit at 65°C – 70°C. It should be understood that, in general, the creation of scale will tend to be greatest in areas where the heat flux is greatest, such as around the cylinder lining and valve seats. This is something that may be expected. The amount of scale that is generated is proportional to both the rate of water loss and the amount of scale-forming salts that are present in the make-up water. The higher both of these factors are, the more scale will be formed.

Typical scaling contaminants are:

    • Calcium carbonate – scale appears as a pale cream. yellow deposit and is formed by the thermal decomposition of calcium bicarbonate at heat transfer surfaces.
  • Example of calcium carbonate scaling

    • Magnesium silicate – scale is a rough textured, tan to off-white deposit found in cooling circuits where sufficient amounts of Magnesium are present in conjunction with adequate amounts of silicate ions with a deficiency of OH Alkalinity. Silicate deposits are also a risk where silicate additives are used to as corrosion protection for aluminium metal in the cooling circuit. The corrosion mechanism relies on the silicate forming a protective film in the metal surface and the silicate is maintained in solution by maintaining a relatively high pH in the cooling circuit (9.5 – 10.5). If this pH is reduced due to ingress of shore-water or sea-water then the silicate will precipitate in the bulk of the cooling water (as magnesium or calcium silicate) and cause gross fouling of the cooling circuit. It is vital when operating a silicate treatment regime for cooling circuits containing aluminium that the system under consideration should be made up with evaporated or softened water to prevent this problem.
    • Iron oxide deposit like hematite (Fe2O3) – This type of red/brown iron oxide deposit is found because of active corrosion occurring somewhere within the cooling system.
  • Example of iron oxide scaling

    • Copper – The presence of copper deposits in a cooling system presents a very serious corrosion risk because of the initiation of galvanic corrosion mechanisms with steel. The steel in the cooling system is anodic to the copper and rapid loss of metal will occur. It is usual to incorporate specific copper corrosion inhibitors in the formulation of cooling system corrosion inhibitors.

Scale deposits have the function of providing thermal insulation on the water-facing side of a cooling surface and slowing the transfer of heat from the metal to the surrounding water. The only way that the heat can escape is if the temperature of the metal is raised, as well as the temperature of the gas that is being expelled from the engine. The first scenario could put the engine’s structure at risk, while the second scenario will lower the engine fuel economy. The presence of scale on the heat transfer surfaces of the cooling circuit might lead to a situation in which the alkalinity in the system begins to concentrate by evaporation within the scale deposit. This can happen if the scale is allowed to remain for an extended period of time. When present in high quantities, OH alkalinity is capable of corroding boiler steel and, in particular, contributing to the premature failure of aluminum pipe-work and components.

Components made of multiple metals are generally found in the engine cooling system. These metals typically include:

    • mild steel – in and aqueous environment mild steel will rapidly corrode by reaction with oxygen in the water. The variables pH, temperature and the concentration of oxygen affect the rate of corrosion.
      As temperature and/or oxygen levels rise the corrosion rate accelerates. Oxygen corrosion is usually observed as localized pitting on a metal surface often with large tubercles of iron oxide covering the pit. pH is inversely related to corrosion rate. This is why alkaline conditions are maintained in steam boiler systems and closed cooling circuits.
    • stainless steel – these are alloys of steel with variable levels of chromium (over 11%). This alloying process gives the material excellent corrosion and wear resistance compared to mild steel. Oxygen combines with the chromium and iron to form a highly adherent and protective oxide film. If this film is ruptured in an oxidizing environment then the oxide film is rapidly re-formed. Therefore the corrosion resistance of stainless steels is reduced in deaerated waters, which is the opposite to normal steels. The presence of chlorides and other strong ‘de-passivating’ ions can seriously reduce the corrosion resistance of stainless steels. The main drawback of more widespread use of stainless steels is extra cost and susceptibility to stress corrosion cracking in the presence of high chloride levels especially at elevated temperatures.
    • copper and its alloys – copper and its alloys are often used in heat exchangers because of their excellent heat transfer properties and relative low corrosion rate in water systems when compared to mild steel. In oxygenated water the corrosion of copper is slow as the metal forms a protective copper oxide film through which oxygen must diffuse for further corrosion to occur. Because copper is a softer metal than steel, water velocities and the scouring effect of suspended solids can act to disrupt the oxide film and increase corrosion rates. Corrosion of copper in the presence of steels is very serious as the copper can re-deposit on the steel and instigate very rapid galvanic corrosion of the steel and risk of failure. Copper and its alloys can be corroded by weak solutions of ammonia in the presence of oxygen.
    • aluminum – in water containing oxygen, aluminium, like copper and stainless steel is protected by an oxide layer. Aluminium is a amphoteric metal which means that it can be aggressively attacked in an aqueous environment with low or high pH. In water of relatively neutral pH at temperatures up to 180 °C, aluminium is essentially inert. In the engine cooling circuit, like in steam boiler systems, this corrosion mechanism can be exacerbated by localized boiling and the formation of high concentrations of OH ions at the metal surface. This will lead to aggressive corrosion and rapid failure.
    • zinc – is the principal metal used to protect steel as a galvanized coating. Here the zinc is anodic to the iron and preferentially corrodes at a slow rate thus protecting the steel. Zinc corrodes at a rate somewhere between that of iron and copper in most natural waters. Attack will occur in the absence of oxygen as with aluminium. Zinc is also an amphoteric metal and is corroded at high and low pH.

Caution is advised because the catholic-to-anodic connection with iron undergoes a reversion at temperatures above 60 degrees Celsius. When this happens, the steel piping becomes extremely anodic, which leads to rapid galvanic corrosion. Before the system can be put into use, the zinc coating on any galvanized pipework or tanks must be removed using a controlled acid wash because this is an essential aspect of engine cooling circuits. If galvanized pipework or tanks are present, this step is necessary.

When choosing a proprietary corrosion inhibitor, it is important to keep in mind that the mechanisms of corrosion that are specific to each metal are distinct from one another and that these mechanisms must be taken into account.

The factors that are affecting the corrosion rate are:

    • temperature – the pace of most chemical reactions increases by a factor of two for every 10 degree Celsius when the temperature is raised. Since of this, a rise in temperature will hasten the rate at which corrosion occurs because the processes that take place at the cathode will happen more quickly. Up to about 80 degrees Celsius, there is also an increase in the rate of oxygen diffusion. Because oxygen is less soluble in an open system, the rate of corrosion is beginning to decrease, which is why the solubility of oxygen is decreasing.
    • pH/alkalinity – as was said earlier, the rates of corrosion that metals experience with regard to pH might differ based on the electrochemical nature of the metal in question. For instance, the rate at which steel corrodes is significantly increased in acidic environments because these environments hinder the production of a protective oxide layer. As the pH increases up to roughly 13, the decreased solubility of iron oxide causes the corrosion rate of mild steel to decrease. This is because iron oxide is more soluble in lower pH levels. Copper behaves in a similar manner. Because of their amphoteric nature, aluminum and zinc both have elevated rates of corrosion when exposed to extremely low or high pH.
  • Example of aluminium pipe from engine circuit with corrosion damage due to high pH

    • chloride ions – at the anodic sites, small negatively charged ions like chloride ions have a tendency to congregate in order to electrochemically balance the positive ions (Fe2+ etc.) that are created as a result of the oxidation of the metal. These ions boost the locally enhanced conductivity, and as a result, the voltage gap between the anode and the cathode. Because of this action, the atmosphere becomes one in which corrosion can advance more quickly. When pollution of sea water has taken place, it is common practice in the maritime environment to make recommendations for increased amounts of corrosion inhibitor.
      Stainless steels are the most common materials to experience the phenomenon known as stress corrosion cracking owing to chlorides. The chloride ions in this situation are of a size that allows them to enter the atomic matrix of the metal, and the concentration of these ions speeds up the corrosion process and causes fissures to propagate further in the metal. Failure on a catastrophic scale is frequently the result of corrosion mechanisms of this kind.
    • galvanic corrosion – when two different types of metals are joined together and then subjected to an environment containing water, a kind of corrosion known as galvanic corrosion can develop. Because of this, what is known as a “galvanic cell” is created when one metal becomes anodic and the other becomes cathodic. When compared to the cathodic metal, the anodic metal is more likely to show signs of corrosion. The most typical manifestation of this kind of corrosion happens when copper and mild steel are joined together in water at the same time. The corrosion of the mild steel occurs as a result of the mild steel’s transformation into an anodic state, which occurs due to its greater propensity than copper to give up electrons.
    • cavitation – the immediate creation and collapse of vapour bubbles in a liquid that is subject to quick and strong localized pressure changes is an example of cavitation. In essence, this is localized boiling that does not involve an increase in temperature. Cavitation damage occurs when this phenomenon act at the metal surface and the hydrodynamic forces caused by the collapsing vapour bubbles form microscopic “torpedoes” of water, which are capable of reaching speeds of up to 500 meters per second, and when they make contact with a metal surface, they remove the protective oxide layer and deform the metal itself. Cavitation is common in the feed-pumps that are used on steam boiler systems. Additionally, it is becoming more common in engine cooling systems as engine manufacturers move toward producing more compact high efficiency diesel engines with smaller, more compact cooling circuits where the risk of localized boiling is increased. This is because cavitation can cause the water in the cooling circuit to boil more quickly.
  • Example of pump impeller cavitation

    • corrosion fatigue cracking – this particular kind of corrosion develops as a consequence of a combination of being exposed to an environment that is corrosive and being subjected to recurrent tensile stress. The application of stress in a repetitive and cyclical manner leads to metal fatigue, which, when combined with exposure to a corrosive environment, ultimately results in the metal cracking. These fractures typically manifest themselves as groups of fine to large cracks that run perpendicular to the direction in which the tension is being applied and are filled with thick corrosion product. The rate of damage that occurs as a consequence is higher than it would be if only the stress or corrosion mechanisms were taking place.
      Any type of metal can experience corrosion fatigue, and it can happen in a wide variety of corrosive situations.

Example of corrosion fatigue

This is the end of Part I with regard to engine cooling system and in next part we will talk about corrosion inhibition and its mechanisms.

If you have any questions regarding above, please feel free to use our existing forum Seafarer’s World and will try to answer to all your queries.

If you like my posts, please don’t forget to press Like and Share. You can also Subscribe to this blog and you will be informed every time when a new article is published. Also you can buy me a coffee by donating to this website, so I will have the fuel I need to keep producing great content! Thank you!

Source and Bibliography:

  • WSS – Water Treatment Technical Manual

What you need to know about Oily Water Separator (OWS)

The effective cleaning of engine room bilge water is essential to protect the environment and ensure that the ship meets its regulatory obligations. The aim is to remove all of the pollutants from the engine room bilge water, so that only clean water goes into the sea.

The condensate and leakage water collected in the engine room bilges is a mixture of seawater, freshwater, heavy fuel oil, lube oil and other residues.

Although the ways in which various bilge separators work get put in separate categories, in reality of the same processes go on to varying degrees in most types of separators. These ways are:

      • Coalescence – When particles or oil droplets “coalesce” it means that they come together and form one larger droplet which is more easy to separate from water;
      • Flocculation – is a process by which two or more particles aggregate (stick together) without losing their individual boundaries. This can be achieved by using chemical dosing to raise pH as high alkaline promotes flocculation;
      • Gravity – is the process where heavy particles, sludge and dirt, sink to the bottom whilst lighter fractions (oil and scum) float to the top;
      • Centrifugal Force.

The bilge water separators, generally combine these mentioned ways in stages. For example, The TURBULO – MPB Oily water separator operates as a pressure system. The system functions according to the principle of  gravitation supported by oleophilic coalescer inserts called HEC (High Efficiency Coalescer) in the first stage. These coalescer inserts are corrosion resistant and offer a very large surface area at a high free volume. The oily water mixture is passed through the separator by means of a dedicated pump mounted on the first stage. The separated oil is drained out of the collecting space automatically by means of a level control. If the separator is required to process heavy oil, a heating coil is installed in the oil collecting space to support the operation.

Example of coalescer filters inside OWS

The second ‘breaking’ stage utilises mechanically working ‘Hyca Sep’ elements (Hydro Carbon Separation) to separate mechanical emulsions in accordance with IMO-Resolution MEPC 107(49). The ‘Hyca Sep’ elements function by the principle of coalescence.

The bilge separator operates automatically and discharges water overboard or back to the bilge water holding tank depending on the oil content of the discharged liquid and separated oil to the waste oil drain tank. Bilge water is drawn from the bilge main by the attached pump and into the bilge separator where it passes, usually through a two-stage separation process. The separator uses the difference in density and surface tension between oil and water in usually two stages that are housed separately or in the same compartment.

The separator is initially filled with clean water before admitting bilge water.

OWS filled with fresh water after maintenance

The pump supplies the oil water mixture to the first stage where most of the oil is retained. Oil droplets are attracted to the coalescer surface or gravity plates, forming into increasingly larger drops until they float. The coalescer has a very large open pore surface area and a very low pressure loss and is stable against suspended matter found in bilge water, hence these particles have no detrimental effect on the coalescer. This means that the coalescer will still continue to operate effectively even with considerable fouling.
Following separation in the first stage, the water, now with a very low oil content, is passed into the second stage chamber, which contains, usually, a second coalescer filter to separate out any remaining oil particles, leaving water that may now be discharged overboard.
A conductive oil/air sensing probe at the top of the first stage (HEC) chamber constantly monitors the oil level in the separator, the length of the probe’s electrode determining the operating range. When oil (or air) is detected, the valve to the oil drain tank opens and the valve to the second stage chamber closes and the oil is discharged to the oil drain tank. The supply pump remains
running during the oil discharge. When most of the oil has been displaced, the oil sensing probe is again immersed in water and activates the control system to resume the separating operation.
The separator works automatically and will operate as long as there is water in the bilge water holding tank. Heating may be applied to improve separation, but the heater will only operate when the separator is full of liquid. The separator is fitted with sampling valves which allow oil samples to be drawn and enable the oil/water interface level to be determined.

The Oil Content Discharge monitor samples the bilge water as it passes out of the separator. Should the oil content exceed maximum 15ppm, the three-way valve changes the output flow from the overboard discharge to discharge to the bilge water holding tank. An audible alarm sounds to warn the operator of the alarm condition. The 15ppm device setting can be adjusted from 1ppm up to the maximum 15ppm, but cannot be set higher. The monitor sensing element may be, normally flushed through with fresh water when in operation by moving the supply lever from the SAMPLING to the FLUSHING position.
This action automatically operates the three-way valve on the discharge line and returns the water to the bilge holding tank. Nowadays, the monitor contains a memory card recording the monitor readings for a period of 18 months, after which the data is automatically overwritten. The card is not to be removed from the instrument as it records the following information:

      • Time;
      • Date;
      • Oil content greater than 15 ppm;
      • Separator status

Example of an oil monitoring device

The oil content monitor must be checked each month and must be flushed through in order to remove any debris which could influence the reading.

The maximum flow capacity should not be exceeded, as excess flow will prevent effective separation. The bilge pump suction strainer should be kept clean in order to avoid large solid particles entering the separator, as these will have a detrimental effect on the separation process.

It is important to notice that the oily water separator is designed to separate oil from water, not water from oil. Therefore, if the bilge water supply to the separator contains excessive amounts of oil it will render the equipment inoperable and result in unnecessary maintenance.

Same, if the separator uses flocculation chemicals, great  care must be taken when handling the treatment chemicals, as these substances are caustic and can cause chemical burning on contact with skin and will cause severe damage to eyes. The appropriate protective clothing, including eye protection, must be worn when handling the chemicals.

When operating the oily bilge water separator and the overboard oil monitoring
system, the date, quantity and location of the discharge overboard is to be recorded in the Oil Record Book. All pumping operations and discharges are also to be in accordance with the latest MARPOL Regulations, Annex I, Regulations 9, 10, 11 and 16.

Example of an Oil Record Book

The date, operational code and item number needs to be written in appropriate columns and the required particulars should be recorded chronologically in the blank space. For discharges overboard, the ship’s position at the start and end of the discharge should be entered. Each completed operation shall be signed for and dated by the officer or officers in charge of the operation and each completed page must be countersigned by the master of the vessel.

Example on how to record the operation in ORB

Failure to fill in the oil record book in a proper way has led to those onboard and companies being prosecuted.

If you have any questions regarding above, please feel free to use our existing forum Seafarer’s World and will try to answer to all your queries.

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Source and Bibliography:

  • You tube video source and credit: Marine NAV & TECH and Victor Marine

Boiler chemical dosing and control

As discussed in one of my previous posts which can be found if you click in here, analytical tests and chemical treatment must be carried out in line with the chemical manufacturer’s recommendations. To keep the chemical levels within an acceptable range, the treatment must be added, but caution must be exercised, as excessive treatment can frequently cause more severe harm than minimal treatment. The results of the chemical analysis on the boiler water are recorded, and the effects of the added treatment can be tracked over time.

Following the analysis of the boiler water, a decision must be made regarding the amount and type of chemicals to be added to the boiler feed water, if any.
The treatment is, usually, added to a chemical injection tank and from there, it is routed to the boiler feed water lines. Chemicals for direct injection into boilers are combined with water in chemical injection tank. The combination is injected into the boiler water feed line immediately after the feed water control valve by a pump unit and the auxiliary boiler and the exhaust gas boiler share the same feed tank and treated feed water. Chemicals can also be put to the chemical injection tank and pushed from the tank into the boiler feed water lines using pressurized feed water.
The addition of chemicals must be done in line with the manufacturer’s recommendations.

There are several possible dosing points for a boiler system, and the choices depend on several factors like system configuration, boiler pressure and product combinations. Figure below shows typical dosing points for a low pressure system. All chemicals should be dosed with a suitable metering pump.

Example of chemical dosage equipment

This will allow continuous dosage of the products and will minimise the handling of chemicals. Batch or slug dosing is never recommended.

Dosing point 1 is the dosing into the hotwell which is common, and can be used for non-volatile chemicals. Sulphite, alkalinity and scale inhibitors can be dosed here. Neutralising amines and oxygen scavengers based on DEHA, hydrazine or carbohydrazide should not be dosed here as there will be some vaporization in the hotwell. The dosage point should be below the water level, preferably close to a water inlet that can provide some mixing.

Dosing point 2 is the preferred point for volatile oxygen scavengers and neutralising amines. This will provide protection from dissolved oxygen as early as possible in the system, avoiding excessive vaporization in the hotwell.

Dosing point 3 is the dosage point which is used where separate dosing to multiple boilers is necessary. Scale inhibitors and some combined treatment are sometimes dosed here. Keep in mind that when dosing on the pressure side of the feed water pump, the metering pump need to be designed for pumping against a higher pressure.

Because of the constantly changing load on a boiler, daily monitoring of the chemical levels is important to make sure that the system is in good condition. For a small system sampling is typically taken from the boilers and the condensate return. More complex system would require samples from the feed water as well.
All sampling points should have a sample cooler to ensure the sample is at a temperature of 20-25°C when sampled.

Example of a sample cooler

This is important because it will prevent flashing of the volatile components like the amines and DEHA, yielding lower results than actual when sampling. Additionally, this will prevent burn incidents of the personnel. The water sampling procedure and cooler use explanation can be found in here.

When sampling, there should always be used clean sampling bottles. A good practice could be to have pre-labelled bottles so that the same bottle is used for the condensate each time. Trace amounts of boiler water from last sample may very well ‘ruin’ a condensate sample if bottles are mixed. Ideally, the bottle should be flushed with the water to be sampled a few times before the samples are collected.
Cleanliness is important when analyzing the water. Dirty hands and working benches may contaminate the samples. As an example, human sweat contains app. 6000 ppm chlorides, so there is not much needed to contaminate a condensate sample with chloride.

Oxygen control

After due consideration of the feed system the operation of the deaerator (if installed) it is still necessary to apply a chemical oxygen scavenger to eliminate oxygen residuals and assist in the passivation of metal surfaces. There are various types of oxygen scavenger available to carry out this task and selection of the best approach is a function of the amount of oxygen present, risk, feed system design, economics and any particular limitations required by the process using the steam.

For oxygen control the most known chemicals that can be used:

      • Sulphite – Sodium sulphite (Na2SO3) is widely used for oxygen scavenging. Sodium sulphite has been found satisfactory at pressures up to about 62 bar. Above these pressures decomposition products such as H2S and SO2 can affect steam purity.
      • Hydrazine – Hydrazine, unlike sodium sulphite, does not increase the dissolved solids content of the boiler water. Hydrazine is very volatile and should be injected at the earliest possible point in the feed system.
      • DEHA – (DiEthylHydroxylAmine) is an organic oxygen scavenger and metal passivator, enhancing formation of a protective magnetite layer. It is significantly more volatile than hydrazine, resulting in increased protection in the steam and condensate system. Being an amine, it has also some neutralising properties. It is more thermally stable than hydrazine and can be used for all types of boilers from low to high pressures.
      • Carbohydrazide – is a ‘combined form’ of hydrazine. It was designed to minimise exposure to hydrazine vapours during handling. Carbohydrazide and its reaction products will add no dissolved solids to the water. Carbohydrazide can be used as an oxygen scavenger and metal passivator at both high (230 °C) and low (65 °C) temperatures. Carbohydrazide can be applied to boilers up to 170 bar.
      • Erythorbic acid – is another effective oxygen scavenger and metal passivator, it is the only non-volatile scavenger which can be used for spray attemperation. It does not add measurable solids to the boiler water, is non-volatile, and will not jeopardies steam purity. Erythorbic acid can be used in boilers up to 122 bar.

pH control

      • In low and medium pressure boilers it is usual to maintain a level of free OH alkalinity to aid in the prevention of corrosion of steel. The recommended level of free OH alkalinity is dependent on boiler pressure and heat flux and can be found in manufacturer’s manual.
      • In high pressure boilers where there is a risk of caustic concentration and subsequent caustic attack it is common to apply a coordinated or congruent phosphate control program.
      • Hide-out – In high pressure water-tube boiler it is sometimes observed that the concentration of soluble salts, notably phosphate salts, do not rise in line with other salts and when the boiler load reduces their concentrations suddenly rise. This is phenomena termed ‘hide-out’ and is due to the reduced solubility of sodium phosphate at temperatures above 250 °C. As load and temperature at heat transfer surfaces increases then some of the sodium phosphate will precipitate and measured PO4 reserves will fall. When load and temperature reduce the PO4 salts resolubilize and the reserve is seen to increase. When phosphate hide-out occurs there is a risk of permanent scale deposition and/or localized evolution of free caustic which in turn could lead to severe corrosion.

So for pH control, if there is a history of boiler deposits or phosphate hide-out is a recognized problem, it may be prudent to consider an All Volatile Treatment approach (AVT). This approach uses entirely volatile solids free chemicals such as Hydrazine, Carbohydrazide, Erythorbic acid and neutralising amines (Ammonia, Morpholine, Cyclohexylamine) to maintain the boiler pH at a level to high enough to control corrosion and give good passivation of metal surfaces. All steel systems are normally controlled at a pH of 9.2 – 9.6 and those containing copper or its alloys at a pH of 8.8 – 9.2. A drawback is that the boiler water is relatively un-buffered and if contamination occurs the boiler pH can be reduced dramatically. Additionally it is important to be aware of the amount of silica in the system as there is no free OH alkalinity to handle it correctly. High levels of silica in the feed-water will preclude this treatment approach.

If you have any questions regarding above, please feel free to use our existing forum Seafarer’s World and will try to answer to all your queries.

If you like my posts, please don’t forget to press Like and Share. You can also Subscribe to this blog and you will be informed every time when a new article is published. Also you can buy me a coffee by donating to this website, so I will have the fuel I need to keep producing great content! Thank you!

Source and Bibliography:

  • WSS Water Treatment


Boiler feed water system, water sampling and treatment systems explained

The feed water system of the boilers is the component of the steam producing plant that circulates feed water from the cascade tank into the oil-fired auxiliary boiler and the exhaust gas boiler via the boiler feed water pumps and feed water regulators.

A comprehensive video regarding feed water system. Source and credit: International Engineering Training

The feed water regulating valve automatically controls the feed water flow to each boiler in line with the change in water level in the boiler, in order to keep the water level constant. The regulating valves are, generally of pneumatic actuated globe valve type. In the video below you can see how these valves actually works.

How pneumatically valves work. Source and credit: saVRee

Two boiler feed pumps take suction from the cascade tank and provide main and auxiliary feed lines to the oil-fired auxiliary boiler and the exhaust gas boiler. Each boiler’s main lines are equipped with a feed water control valve, which automatically regulates the flow of water to the boiler in order to maintain the proper water level. The auxiliary feed pipes allow for direct feed input in which case human control of the boiler’s water level is required.
Before the feed pump discharge valve, a little amount of water is diverted back to the cascade tank from each feed pump output, thus the discharge line to the drain tank features a number of aperture plates to minimize water pressure.
This water discharge ensures that even when the boiler feed control valve is closed, water flows via the running feed pump.

The boiler feed water is sampled and treated to prevent corrosion and scale formation in the auxiliary and exhaust gas boilers, as well as the degradation of steam quality. Incorrect or insufficient boiler water treatment will severely damage the boilers, necessitating frequent testing and treatment to prevent the risk of damage. Even when distilled water is utilized for boiler feed, there is a risk of corrosion. In service, the pH of the water fluctuates, and oxygen might dissolve in the water where the feed system is exposed to the atmosphere. Although keeping the feed water temperature reasonably high, above 60°C, will reduce the amount of dissolved oxygen, the problem is always present.
Water sampling connections are provided on the auxiliary and exhaust gas boilers, with the outlet from these being sent to a sample cooler that is chilled by water from the service cold water system. Usually, the sample cooler is placed in the workshop or in the close proximity of the boiler. In order to acquire a fully representative sample of water from the boiler, the water must be allowed to run from the boiler for a minute before being sampled. The boiler’s sampling valve is positioned to produce a representative sample, but old water in the pipes and cooler must be purged before the testing sample is drawn. Every day, the boiler water must be tested. To guarantee that the boiler water is properly treated, the directions provided by the water treatment test kit vendors must be strictly followed.

Taking water sample from the boiler. Source and credit: wareboilers

The procedure of taking a water sample from the boiler can be described as follow:

  • Check that the cooling fresh water is available for the water sampler.
  • Open the sample cooler cooling water outlet and inlet valves and check the flow of fresh cooling water through the sample cooler.
  • Open the water sample outlet valve on the sample cooler and
  • Slowly open the sampling valve on the boiler from which a water sample is required and allow boiler water to flow through the sample cooler. Ensure that water is leaving the sample cooler outlet and not a mixture of steam and water. If the temperature of the boiler water leaving the sample cooler is too high, reduce the flow of boiler water to the sample cooler.
  • After the boiler water has been flowing for one minute, collect a sample of the boiler water for analysis.
  • Close the boiler sampling valve and then close the sample cooler cooling water valves and the sample inlet and outlet valves.
  • Analyze the sample of boiler water in accordance with the instructions of the chemical treatment supplier and record the information. Add chemical treatment to the boiler feed water as required.

Analytical tests and chemical treatment must be carried out in line with the chemical manufacturer’s recommendations. To keep the chemical levels within an acceptable range, the treatment must be added, but caution must be exercised, as excessive treatment can frequently cause more severe harm than minimal treatment. The results of the chemical analysis on the boiler water are recorded, and the effects of the added treatment can be tracked over time.

Following the analysis of the boiler water, a decision must be made regarding the amount and type of chemicals to be added to the boiler feed water, if any.
The treatment is, usually, added to a chemical injection tank and from there, it is routed to the boiler feed water lines. Chemicals for direct injection into boilers are combined with water in chemical injection tank. The combination is injected into the boiler water feed line immediately after the feed water control valve by a pump unit and the auxiliary boiler and the exhaust gas boiler share the same feed tank and treated feed water. Chemicals can also be put to the chemical injection tank and pushed from the tank into the boiler feed water lines using pressurized feed water.
The addition of chemicals must be done in line with the manufacturer’s recommendations.

If the level of boiler water dissolved solids is too high, these can be removed on a regular basis using the scum valve on each boiler, whereas dissolved solids can be minimized by blowing some of the water out of the boiler and replacing it with fresh distilled feed water. This is known as boiler blowdown, and it is achieved by opening the boiler blowdown valve for each boiler. The scum and blowdown lines link to the same blowdown pipe, which connects to an overboard discharge placed below the waterline of the ship.

Boiler blow down instruction example. Source and credit: go2atp

The blowdown procedure is as follow and must be performed during boiler low load:

  • Check with the bridge that it is safe to blow down the boiler if the ship is in port.
  • Open the ship’s side blowdown valve
  • Ensure that the boiler is filled to the high water level.
  • Slowly open the boiler scum valve and reduce the water level to the normal position, then close the scum valve.
  • Refill the boiler to the high water level position and blow down the boiler using the blowdown valve. After the blowdown of the boiler, close the boiler blowdown valve and then close the line and ship’s side valves.
  • Test the boiler chemical concentrations and adjust as necessary.

In conclusion, the following precaution must be taken when you are dealing with boiler feed water and treatment chemicals:

  • Caution must be exercised as the sampling lines from the boiler are under boiler pressure and the temperature of the water being drawn from the boiler is high.
  • Care must be taken when operating the sampling equipment. The cooling water supply must be confirmed to be flowing before the boiler sample valve is opened and valves must be opened slowly.
  • Care must be taken when handling boiler water treatment chemicals. Protective equipment must be used.
  • When blowing the boiler down the overboard discharge valve must be opened before the boiler or scum blowdown valves, as opening the boiler valves first will subject the blowdown line to full boiler pressure.
  • When turning down one of the boilers for a short length of time (for example, the exhaust gas boiler while the ship is in port), it is critical to ensure that the water in the boiler has been properly treated. After a shutdown boiler is restarted, a water test should be performed as soon as practicable.
  • It is essential that details of water analysis are recorded together with details of the treatment added. Only with detailed information is it possible to determine the cause of possible future problems.

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