Category Archives: Marine Fuels

Hydrogen Fuel Cells Revolutionize Maritime Industry: Green Propulsion Takes the Helm

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Date: August 30, 2023

By: Daniel G. Teleoaca – Marine Chief Engineer

The maritime industry is experiencing a monumental shift as hydrogen fuel cells emerge as a game-changing technology, propelling vessels towards a more sustainable and environmentally friendly future. This revolutionary development is poised to reshape the way ships are powered, offering a cleaner alternative to traditional fossil fuels.

Sailing into the Future with Hydrogen Fuel Cells

In a landmark achievement, marine engineers and researchers have successfully harnessed the power of hydrogen fuel cells to drive ships, marking a watershed moment for the maritime sector. Hydrogen, when combined with oxygen in these cells, produces electricity with the only byproduct being pure water vapor. This clean and emission-free process offers a significant advantage over conventional propulsion systems that contribute to greenhouse gas emissions and air pollution.

Maiden Voyage of the Hydrogen-Powered Ship

Breaking new ground, the world recently witnessed the inaugural journey of the first-ever hydrogen-powered commercial vessel. This monumental event took place as a consortium of visionary shipping companies came together to launch the pioneering container ship. Named “EcoVoyager,” the vessel embarked on its maiden voyage, showcasing the viability and potential of hydrogen fuel cell technology in real-world maritime operations.

Source and Credit: Green Car Congress

The EcoVoyager’s successful journey underscores the commitment of the maritime industry to embrace innovative solutions that align with global sustainability goals. The vessel’s emission-free operation, quiet propulsion, and reduced environmental impact exemplify a future where clean energy sources drive the world’s shipping fleets.

Addressing Challenges and Unlocking Potential

While hydrogen fuel cells hold great promise, challenges remain on the road to widespread adoption. Infrastructure for producing, storing, and distributing hydrogen needs to be expanded to support the demands of the shipping industry. Additionally, advancements in fuel cell efficiency and durability are essential to ensure economic viability and operational reliability.

Governments, research institutions, and industry stakeholders are collaborating to overcome these hurdles. Investment in research and development is accelerating the evolution of fuel cell technology, with a focus on optimizing performance, cost-effectiveness, and safety.

Pioneering a Cleaner Tomorrow

The integration of hydrogen fuel cells into maritime propulsion systems presents an unprecedented opportunity to reduce the industry’s carbon footprint. As the international community intensifies efforts to combat climate change, the maritime sector has a critical role to play in achieving global emission reduction targets.

The success of the hydrogen-powered vessel demonstrates that the future of marine engineering is firmly rooted in innovation, sustainability, and a commitment to leaving behind a healthier planet for future generations. As the maritime industry embraces hydrogen fuel cells, it propels itself into a new era of clean, efficient, and responsible shipping that not only meets current environmental challenges but also helps pave the way for a brighter, greener future.

Methanol as a marine fuel

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Methanol, also known as “wood alcohol” as previously was made by pyrolysis of wood, is produced from various feedstocks, but natural gas is currently the most economical method. It is worldwide available as a marine fuel, cost effective and significantly reduces emissions of sulphur oxides, nitrogen oxides, CO2 and particulate matter.

Source: Methanol Institute

Methanol is a biodegradable, water soluble, clear liquid with the chemical formula CH3OH, is the simplest alcohol, containing the least carbon and the most hydrogen of any liquid fuel. It is a liquid at atmospheric pressure that ranges between 176 and 338 K (–93°C to +65°C), making storage less expensive than LNG, H2, and NH3. Because of its density and lower heating value (19.5 MJ/kg), methanol necessitates approximately 2.5 times larger fuel tanks than MGO per energy unit, and similar or smaller fuel tanks than LNG.

Methanol has a good combustion, a good energy efficiency and low emission, but to be used in diesel engines requires an ignition enhancer which is a small amount of diesel oil. There are other approaches as well, like glow plug ignition which enables the compression ignition engine to run solely on methanol, without requirement of a pilot fuel to serve as the ignition source. Another solution, especially as a retrofit option is to introduce methanol into engine’s intake ports by adding a low-pressure methanol fueling system and port fuel injectors.

MAN B&W ME-LGI 2stroke dual fuel engine can run on methanol, fuel oil, marine diesel oil, ammonia or gas oil and they have the ability to achieve Tier III NOx standards (2-4 g/kWh) without after-treatment.

Source: MAN Energy Solution

The new injection concept enables the exploitation of more low flash point fuels such as methanol, ethanol and LPG and the engine ability to run on these sulphur-free fuels offers great potential for ship operation within SECA zones.

Source: MAN Diesel

Since the LGI is an add-on to the electronically controlled ME engine, converting an existing diesel engine into a dual-fuel engine capable of using both diesel and, for example, methanol is possible. The diesel fuel system is not majorly changed compared to a standard ME engine. As is the case for the ME-GI, the ME-LGI fuel system can change over to fuel mode, burning diesel oil or HFO from one stroke to the other without any limitation in speed or load.

Methanol is hygroscopic which means that will absorb water vapours directly from atmosphere, which will dilute its fuel value. Also, it contains soluble and insoluble contaminants and chloride ions which have a large effect on the corrosivity by chemically attack of metals causing pitting and by increasing fuel conductivity which leads to electric and galvanic corrosion.

Moreover, methanol is toxic in high concentrations as ingestion of 10 ml can cause blindness and 60-100 ml can be fatal. Due its volatility it is not necessary to be ingested to be dangerous since the liquid can be absorbed through the skin and vapours through the lungs. Methanol is much safer when is blended with ethanol.

Same as for ammonia, the use of methanol will lead to major changes in engine room, as the entire treatment of HFO will disappear (settling tanks, purifiers, heaters, booster pumps, viscometers, filters etc.), but new system will need to be installed specific for methanol use.

Ammonia as a fuel

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Another fuel alternative which is taken into consideration is Ammonia which recently has gained increased attention as a possible marine fuel that could help accelerate the decarbonization process.

Ammonia is also interesting in the context of a growing hydrogen economy because it is the cheapest way to transport hydrogen over long distances and in large quantities. It is a fundamental chemical that is traded and produced on a global scale which has been primarily used in the production of fertilizer to date.

Ammonia is a toxic, carbon-free energy carrier which can be used as a marine fuel in both internal combustion engines and fuel cells. Ammonia or ammonia mixtures combustion can result in the emission of nitrogen oxides (NOx), nitrous oxide (N2O), and direct ammonia (NH3). It is colourless gas at atmospheric conditions, lighter than the air, strong smell and caustic.

Because ammonia (sometimes called “the other hydrogen”) is a hydrogen (H2) carrier, it has gained attention in the context of a future hydrogen economy. It is a zero-carbon synthetic energy carrier that may be useful for decarbonizing a variety of sectors that require alternative energy carriers, such as hydrogen-based fuels.

Haber-Bosch, the established process for producing ammonia, revolutionized fertilizer use over a century ago. However, the process is extremely energy-intensive.

Ammonia is produced today by feeding natural gas into a steam methane reformer in order to generate hydrogen. The hydrogen is used as an input to the Haber-Bosch process, which uses a catalyst to convert it, along with nitrogen (N2) from the air, into ammonia.

To produce ‘green’ ammonia using renewable energy, the hydrogen for the Haber-Bosch process is generated using renewable electricity via water electrolysis, and the nitrogen is supplied via cryogenic air separation (Oeko-Institut 2019a).

No marine ammonia engines have been built to date, but there are projects already started and some of the shipping companies together with shipbuilders and engine manufacturers are already taking the lead in this direction.

Among the liquid ammonia’s properties is its energy density of approximately 18.6 MJ/kg, is significantly less expensive than modern marine fuels, as well as natural gas and liquefied petroleum gas. As a result, ammonia has a low energy density, but the primary advantage of ammonia is that it can be stored in liquid form at elevated temperatures and atmospheric pressure. It is a liquid that is slightly cryogenic which require –33,4 degrees at atmospheric pressure. Also requires approximately 10 bar pressure at ambient temperatures of 20 degrees.

The graph below illustrates the pressure versus boiling temperature relationship for ammonia.

Source: Bureau Veritas Marine & Offshore

Using ammonia as a fuel is quite new in marine industry, but due to its high toxicity new safer systems need to be designed. Therefore, ammonia will require bigger storage tanks which will potentially “eat” from the cargo space, all below deck piping will likely need to be double-walled, as burning ammonia will produce a lot of NOx emissions, under actual regulations an SCR (Selective Catalytic reduction) need to be installed and engine room will require new safety equipment like emergency ventilation or gas absorption in the event of a ammonia leak.

For now, the most suitable vessel to burn ammonia are the one which use to carry ammonia as a cargo, similarly with vessel experience using LNG, LPG or methanol. The only main issues will be to adapt and install a new the fuel system dedicated to ammonia and to retrofit/upgrade the engines.

For vessels which are not carrying ammonia as a cargo, a system for loading and storing it onboard, new fuel system dedicated to ammonia need to be installed and engine upgrade needs to be done. The most suitable systems for storage are the C type pressurized tanks as they can store product at the ambient temperature and does not require reliquification system, they are can be installed on deck and can be easily integrated on a commercial vessel. The only inconvenient is that they are suitable for vessel with short routes as their limit of applicability is around 2000 m3.

The flammability of ammonia is relatively limited, with high auto-ignition temperature, low flame speed and for its combustion will requires very high compression rate and temperature or a pilot fuel valve, thus dual fuel engines will be the most probably way for ammonia to enter the maritime industry as a fuel. These types of engines are expected by 2024 and MAN Diesel is working towards burning ammonia in their ME-GI engines.

The use of ammonia will lead to major changes in engine room, as the entire treatment of HFO will disappear (settling tanks, purifiers, heaters, booster pumps, viscometers, filters etc), but new system will need to be installed specific for ammonia use.

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LNG as a fuel

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Although the marine industry relies heavily on fuel oils for the majority of its power generation, stricter emission regulations and the plan to “go green” are convincing operators to consider alternatives. To comply with the new emissions standards known as IMO 2020, a growing number of the world’s shipping companies, builders, and operators are turning to LNG as a cleaner alternative fuel source. The LNG is safe, reasonably priced, plentiful, emits small amount of the sulfur oxide, reduces carbon emission and other fuel pollutants and is generally regarded as a source of transition throughout the world. In comparison to heavy fuel oil (HFO), LNG enables significant reductions of more than 99% of sulphur emissions, 80% of nitrogen oxides, the majority of particulate matter, and up to 20% of carbon dioxide emissions.

Thus, LNG is regarded as the greenest fossil fuel and a true technological breakthrough in terms of meeting compliance while maintaining competitiveness.

Liquefied natural gas (LNG) is primarily composed of methane (CH4), the hydrocarbon fuel with the lowest carbon content and thus the greatest potential for CO2 emission reduction. However, methane is a potent greenhouse gas, and methane release must be controlled to ensure that greenhouse gases emissions are reduced when LNG is used.

LNG is produced through a cryogenic process in which natural gas is filtered and cooled to -1620 C, resulting in a volume reduction of up to 600 times. This process converts the gas to a liquid, making it easier to store and transport. In its liquid state, LNG will not ignite. As a result, LNG must be stored in insulated tanks for cryogenic applications, which are expensive in comparison to traditional petroleum-based fuel storage and supply systems.

Impurities, water, and other associated liquids are present in natural gas extracted from the ground.

Natural gas is first processed to remove impurities. It travels through a series of pipes and vessels, where gravity aids in the separation of the gas from some of the denser liquids. Additional impurities are then removed. After that the natural gas is injected into a water-based solvent, which absorbs carbon dioxide and hydrogen sulphide. Normally, these would freeze when the gas is cooled, resulting in blockages and therefore any remaining water is drained, as it will freeze.

Finally, the remaining lighter natural gas liquids – primarily propane and butane – are extracted for sale or use as a refrigerant during the cooling process. Mercury traces are also filtered out.

Now that the natural gas has been purified – methane with a trace of ethane – it is ready to be liquefied and this process takes place in large heat exchangers. A coolant, chilled by massive refrigerators, absorbs the natural gas’s heat. It cools the gas to -162°C, effectively halving its volume. This converts it to a clear, colorless, non-toxic liquid known as liquefied natural gas, or LNG, which is significantly easier to store and transport. The LNG is stored in insulated tanks until it is ready to be loaded onto an LNG ship or carrier designed specifically for the purpose.

Source: Shell – LNG process flow diagram

LBG (Bio-LNG) and liquefied synthetic methane (from the Power-To-Gas process) are fully compatible drop-in replacements for gas engines and the LNG distribution system. The material properties are very similar to those of LNG and can be considered identical in all practical ways.

LNG bunkering requires special infrastructure for supply, storage and delivery to the vessels. Presently there are not so many ports worldwide capable to offer LNG bunker as infrastructure is limited, but as the demand is increasing exponentially most of the major port are developing the necessary infrastructure.

The technology needed to use LNG as a ship fuel is readily available and MAN Diesel and Wartsila are already on the market with their dual fuel engines and half of all newbuildings after 2025 will be equipped with this type of engines.

A large number of vessels in the current ocean going fleet have the potential for conversion, but retrofitting existing ships seems to be less desirable on certain type of vessels, because of the impossibility for fitting special and larger fuel tanks.

Fuel oil properties and effects – Part III

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Source: Lintec Testing Services Ltd

Compatibility

In the simplest terms, residual fuel oil is a suspension of asphaltenes in a carrier fluid. Asphaltenes in a compatible fuel remain suspended, but they agglomerate and settle out as sludge in an incompatible fuel.

In practical terms, a fuel blend is called “incompatible” if the quantity of sludge-type sediment formed after blending two oils surpasses the quantities of sludge in the two oils before mixing.

Although the chemistry of this phenomenon is exceedingly complicated, it may be simplified by examining the mixing of two fuels with distinct hydrocarbon groups. The resulting combination, as a result of the altered carbon/hydrogen ratio, may be unstable and incapable of suspending the asphaltenes. The disturbance of the blend’s equilibrium may be relatively “mild,” in which case the oil will layer or “STRATIFY” in the mixing tank, depending on the densities and viscosities of the constituent components.

In extreme situations, the mixture’s asphaltene concentration may precipitate as a carbonaceous sludge. When this occurs, it is claimed that the oil is “INCOMPATIBLE.”

Sludge production, particularly with cracked fuels, is accelerated by heating and oxidation and is very variable depending on the degree of “cracking” performed in the refinery. Fuel mixed at a refinery to achieve a commercial viscosity grade is often manufactured to provide a stable product, as refinery operators are typically aware of the sources of the oils utilized and have control over the cracking processes. However, as economic markets dictate, refineries are increasingly selling residual fuels to one another for additional cracking procedures, resulting in a loss of control over the end product’s stability. As contrast to “refiners” or “suppliers,” oil “vendors” are frequently simply involved in mixing purchased-in stocks to meet client specifications, resulting in a greater risk of unreliable deliveries.

Mixing fuels on board a ship may be challenging, as the sources and refinery processes are unknown to the ship’s crew. Adding a distillate, such as gas oil, to an incompatible mixture of heavy oils in an attempt to spread the sludge may actually aggravate the difficulties, since the fuels’ primary hydrocarbon groups are likely to be different, increasing the instability.

Typical symptoms of incompatible or unstable fuels include problems with bunker tank pumping, sludge buildup in filters and fuel lines, fouling and blockage of separator and engine fuel oil heaters, overloading of separator bowls, viscosity control fluctuations (noticeable as temperature fluctuations on viscotherm units), fouling of combustion spaces, exhaust valves, scavenging ports, fouling of injection equipment, and poor combustion coupled with higher than normal exhaust.

Incompatibility will most likely manifest itself initially as overburdening the separator equipment as a result of the high volumes of sludge deposited in the bowls. If the sludge discharge frequency is insufficient to cope or is not raised, sludge carryover to the main engine is possible. If this sludge finally enters the combustion area, the extended ignition and higher heat loading on the cylinder surfaces caused by the high carbon sludge may result in the disintegration of the cylinder lubrication oil layer and, in extreme situations, severe engine damage.

It’s worth noting that there are other possible reasons of fuel oil sludge; sludge is not conclusive evidence of incompatibility or instability. Sludge may also occur as a result of stable oil/water emulsions, waxy precipitates, or excessive depositions of dirt, sand, iron, gums, and other substances.

Calorific value

The calorific value of a fuel may be determined in two ways, by measurement or by calculation and the method used should always be stated into bunker delivery receipt.

It is worth noting that in general the variation in calorific value over the whole range of fuel oils from light gas oil to heavy residual oil is less than 5%. This small variation is due to the relative amounts of carbon and hydrogen present which affects the density of the fuel, and the amount of non-combustible material, mainly sulphur. Thus, high density fuels tend to have a slightly lower calorific value than low density fuels, while the greater the percentage of sulphur present the lower the calorific value.

For performance monitoring purposes it should be noted that most engine test bed results are obtained and quoted using a diesel oil.

Calculated Carbon Aromaticity Index (CCAI)

“Ignition Quality” it related to a fuel aromaticity, as aromatic fuels are known to increase ignition delay. Aromaticity is not easy to measure but fortunately further studies has established a correlation between carbon – aromaticity and the density and viscosity of the fuel. CCAI value was developed by Shell and is a measure of carbon – aromaticity, the relation with ignition delay being empirically confirmed.

Additionally, the “Boiling Range” or a high asphaltene content, which may or may not be reflected in a high Micro Carbon Residue can be indicative of ignition problems. Combustion properties of residuals are dependent on the distribution of light and heavy hydrocarbons in the fuel, the heavy fractions, such as asphaltenes, needing a longer ignition time and producing higher temperatures. Insufficient combustion results in soot formation and the source of the fuel and the refinery processes radically affect the behavior of the fuel.

Advancing the fuel injection timing can sometimes, by providing a longer ignition period, improve the combustion properties of poor burning fuels.

The “Cetane Index” is generally only quoted for distillate fuels, it is a measure of ignition quality. The higher the cetane number, the better the ignition quality, and the less the tendency to “Knock”. Fuels with a higher cetane number generally have better performance characteristics in the majority of marine diesel engines.

Thermal stability

Fuels supplied to the vessel must not only be stable when delivered or blended but must remain stable at the elevated temperatures necessary for pre-treatment and injection. Heavy fuels, depending on viscosity, may have to be heated to 130-140 deg C for correct atomization. The symptom of thermal instability of a fuel, like incompatibility, is the increasing tendency of the oil to precipitate sludge, in this case sludge deposition will generally occur in heaters. This sludge is again the product of asphaltene precipitation.

Unfortunately, clogging of heater surfaces eventually leads to a reduction in fuel flow rate which effectively retains fuel in the heater for a longer dwell time and thus causes overheating with even more carbonaceous deposition with cracking of the fuel at the surface of the heaters. These deposits can be very difficult to remove. Not all sludging in fuel heaters can be attributed directly to the lack of thermal stability. If for example a fuel system is designed so that under normal conditions a single fuel heater is capable of maintaining the desired temperature and then because of difficulties in maintaining this outlet temperature a second heater is brought into use in parallel with the first, the reduction in flow rate may be sufficient to cause sludging due to overheating. The “difficulty” referred to is the effects of heater blockage caused by thermal instability of the fuel, in which case the “cure” actually has the opposite effect and will greatly increase the problem. Reduction in flow rate can also occur if the inlet viscosity of the fuel is too high.

-The End-

Fuel oil properties and effects – part II

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Asphaltene, carbon residues and sediments

Asphaltenes are complex suspended solids in fuel that have high melting points and high carbon/hydrogen ratios. The proportion of asphaltenes in a fuel appears to increase as secondary refinery processes are more widely used. They have poor combustion properties and burn very slowly.  If these formations precipitate, they can have a negative effect on blended fuel stability and can cause too much sludge into filters and separators. If the fuel is not stable, particles accumulate at the bottom of the tank.

To reduce risks, make sure that bunkers from different suppliers and sources are not mixed in the ship’s storage tanks. Also, be cautious when heavy fuel oil is mixed on board to reduce viscosity. When paraffinic distillate is added to a low-stability heavy fuel oil, it can cause asphaltenes to collect, resulting in heavy sludge.

A high Micro Carbon Residue content could be a sign of a high asphaltene content. The Micro Carbon Residue is typically expressed on fuel specifications as a percentage of weight and in current fuel oils, it can range from 3 to 18 percent, but due to secondary refinery conversion processes, values as high as 22 percent have been reported. If the fuel preparation equipment is properly adjusted, HFO can contain up to 14 percent asphaltenes and will not cause ignition or combustion problems in 2-stroke engines.

Conradson carbon measures the amount of carbon residue that remains after the combustion of a fuel under specified conditions. It is used to describe a fuel’s predilection to form carbon deposits during operation, which can clog fuel nozzle tips, piston ring grooves, and exhaust valves or scavenging ports of diesel engines, as well as boiler burner nozzle tips and deflectors.

Residual fuels with high carbon content burns at a slower rate, which can result in higher exhaust temperatures and fouling of combustion space and fuel injector’s nozzle, as well as the possibility of incomplete combustion, which can result in smoke or the impingement of incompletely burned fuel on the cylinder wall or piston, resulting in the formation of additional hard carbon deposits.

Combustion can sometimes be improved by advancing ignition, resulting in a longer burning time. It may also be necessary, due to increased cylinder deposits, to increase cylinder oil lubrication in order to maintain free piston rings and clean ports.

Ash

The ash forming constituents of crude oil tend to be concentrated in the residue left after distillation. Fuel oils, which are usually under blended form of this residue and a cutter stock, have a measurable ash content which rarely exceeds 0.1%. The prediction in future fuels is for this value to increase as different oil fields are exploited and as refinery techniques change.

Ash forming components are those elements present in the fuel as various organic and inorganic compounds that leave the combustion space of the engine in a solid or semi-solid state. Several different elements have been identified in this form, the most common being silicon, aluminum, calcium, iron, nickel, sodium, vanadium, phosphorus etc.

Usually nickel and vanadium are present only in oil soluble forms. Apart from the fuel sodium natural content, contamination may introduce further quantities of sodium from seawater, iron from rusty storage tanks and pipelines and from dust and dirt.

Harmful ash forming compounds may cause damage to the vessel’s engine. Wear damage to the engine will be experienced due to elevated levels of Cat Fines (Aluminium & Silicon) so that efficient purification is require to reduce the levels prior to injection. Vanadium – Sodium compounds will result in post combustion problems and complexes formed with Sulphur addition will be prevalent.

Recent updates on the Marine fuel oils specification ISO 8217 includes new parameters and specification limits to control the mixing of Used Lube Oils into bunkers. Contamination with Used Lube Oils in bunkers causes concern as the lube oil will carry a lower density and lubricants work against the centrifugal forces adversely affecting a ships fuel treatment plant efficiency and fuel oil purifiers. The concern lays on the forming of an emulsion. This is of extreme concern to engine crew or manufacturers because there is a distinct possibility that any water or abrasives present in the fuel would not be reduced.

Removal from the fuel of insoluble matter can be achieved by centrifugal separation. Oil soluble ash components, however, notably vanadium, cannot be removed from the fuel by this means or by any other method which is practical onboard ship. Sodium on the other hand, being water soluble, can be removed in the water phase from the separator. In view of the problems mentioned previously the removal of salt water is important. Additionally, if fuels are suspected of having a high vanadium content, it is necessary to ensure engine valves, pistons, etc. are maintained at normal operating temperatures through good combustion in order to minimize vanadium ash corrosion. Fuel treatment chemicals (e.g Fuel care) can be used to elevate stiction temperatures and hence reduce corrosion attributed to the vanadium compounds.

Sulphur

The sulphur is present as an organic compound and depends entirely on its crude oil origin and the amount of distillate removed and the contents can be up to 4 – 5 % and cannot be removed by any vessel conventional treatment systems.

When a fuel burns, the sulphur content is converted into sulphur dioxide and mostly is exhausted from the engine without any reaction, but a small amount oxidizes in the presence of the other combustion gases products and form sulphur trioxide. Although the sulphur trioxide content of exhaust gases is relatively low, this is a highly reactive gas and a strong oxidizing agent. When it combines with water vapours will form sulphuric acid which has a dewpoint in the region of 140/150 deg C, which will condense therefore on various metal surfaces, including portions of the cylinder liner during normal operation.

Sulphur trioxide also combines with combustion ashes lowering their melting points and causing them to become more adhesive to metal surfaces.

The use of high-quality alkaline lubricating oils decreases the risk of corrosion to cylinder liners, piston rings and associated engine components and increasing operation temperatures further helps by preventing condensation of the sulphuric acid within these areas.

In general, low speed marine diesel engines run quite satisfactorily on fuels with a sulphur content of up to 4% when correctly lubricated.

For each percentage increase in sulphur content of the fuel oil the calorific value reduces by approximately 80 Kcal/kg.

Occasionally, there is another aspect associated with the sulphur content of fuel, and that is the occurrence of fuels with very low sulphur content (for example 0.5% and below), being used for prolonged periods in engines using highly alkaline cylinder oils (commonly a TBN of around 70). The effect is high cylinder and piston rings wear rates due to the formation and build-up of abrasive alkaline ashes in the areas of high thermal load.

Vanadium

Vanadium is a metallic contaminant that is present in all crude oils and the amount of vanadium in any given fuel is dependent on two factors, the source of the crude and the severity of the refining process. In places like Venezuela and Mexico the crudes have a vanadium content of 300-400 ppm whereas in other parts of the world the levels vary up to about 150 ppm. However, these contents can be greatly increased in the refinery, as the light distillates are removed from the crude feedstock the metallic contaminants become concentrated in increasingly smaller volumes of residuals. Unfortunately, there is no economical method to remove the vanadium, and being oil soluble centrifugal separation will not remove it on board ship.

During combustion vanadium is oxidized to various compounds. The most important of these, when the vanadium is not in contact with sodium, is vanadium pentoxide. When in the presence of sodium (and sulphur) vanadium forms sodium-vanadate compounds.

Vanadium pentoxide has a relatively low melting point, 680°C, and in the molten state causes corrosive attack on steel surfaces (“hot” corrosion). The vanadate compounds have a much lower melting point (the “stiction” temperature) which, dependent on the relative amounts of sodium ash (sodium sulphate) and vanadium ash (vanadium pentoxide) can be as low as 330°C. These vanadate compounds are extremely corrosive in the molten state and adhere easily to steel surfaces. It is not solely the vanadium level which is critical, but the combination of vanadium and sodium, the most dangerous ratio being approximately 3:1.

Sodium

The vast majority of any sodium content of a fuel is inorganic in nature, oil insoluble, and is present as seawater contamination. Sodium in seawater occurs as common salt, sodium chloride, and being water soluble it is possible to largely remove it by onboard purification. This operation is vital if seawater contamination has occurred because of the risk of highly corrosive sodium – vanadium ashes forming during combustion.

Iron

Traces of iron can be found in fuel from a number of sources. The most obvious source of contamination with the iron present as inorganic oil insoluble particles is rust flakes or scale from pipelines, tanks, etc. However, iron also occurs naturally in some oils as small amounts of organic oil soluble compounds in the form of complex porphyrins. It should be remembered that some fuel additives added to bunker, settling or service tanks contain iron.

Water

Water can be present in oil either as fresh water or as salt water, depending on its source. Common sources of fresh water contamination are condensation inside a tank or steam coil leakage. Seawater may find its way into fuel from tank leakage, through cracked hull plates or via unsecured sounding pipe caps during heavy weather or even during deck washing operations.

If the water is allowed to remain in the fuel may result into damage to fuel pumps and injectors, poor fuel atomization and consequently reduced combustion efficiency. Salt water is especially harmful as it is more corrosive than fresh water and the sodium component of the salt content produces fouling in combustion spaces and more dangerously may combine with vanadium compounds present in the fuel to form a highly corrosive molten ash.

Apart from the physical difficulty of removing the water this effect will tend to produce reasonably stable oil/water emulsions. An appreciable water content (in the region of 1.0% or above) also intensifies the problems of incompatibility or instability.

-End of Part II-

Fuel oil properties and effects – Part I

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Into the following posts I will explain about fuel oil properties and their effects from operational point of view.  I will not write and show any mathematical formulas as these formulas can be found in dedicated manuals and anyone who is interested in depth theoretical knowledge can search for the same. The properties described in these posts are explained in order to gain a better understanding of the complexities of fuel oil behavior. Very good supervision, engine maintenance and fuel treatment equipment is necessary especially when the properties of the fuel used is near the permitted maximum and minimum limits. Poor quality fuels or insufficient or inadequate preparation can lead to problems in handling and/or combustion. This will itself lead to higher maintenance requirements, shorter service intervals and possibly shorter service life of various components of the equipment.

Density

The term “density” is essentially synonymous with the older terms “specific gravity” or “relative density” numerically. Both of these terms are devoid of units because they refer to the mass of a given volume of oil in relation to the mass of the same volume of water at specified temperatures. Because density varies with temperature, the higher the temperature – the lower the density, densities must be compared at the same temperature, which is typically 15 degrees Celsius nowadays. Density is not a direct indicator of fuel quality, nor is it necessary to associate high density with high viscosity. A high density shows a high aromatic content. A precise understanding of fuel density (information is provided on the bunker receipt) is critical for several reasons:

  • It enables the verification of the actual weight of oil supplied;
  • the accurate determination of specific fuel consumption;
  • operationally, the optimal selection of gravity discs for purification equipment (although nowadays modern purification equipment doesn’t require a selection and replacement of gravity discs anymore).

Densities of the order of 0.991 and higher are expected, but with the new low sulphur fuels, the density is now lower than this value. As the density of the fuel approaches that of water, water removal by centrifugal separators becomes increasingly difficult. The 0.991 limit is imposed by the use of conventional separators used as purifiers with a water seal. At operating conditions, the density differential between the oil and the water must be 4 percent or greater, corresponding to an oil with an upper density of 0.991 kg/m3. However, improved separator design allows some modern vessels to operate with fuel oils with densities as high as 1010 Kg/m3. 

Viscosity

The viscosity of a fluid is a measure of its resistance to flow. Viscosity decreases as temperature rises and increases when pressure rises dramatically. While viscosity should not cause any operational issues as long as the proper temperatures for handling and combustion are maintained, it should be noted that the viscosity quoted on the fuel delivery note frequently only refers to the maximum viscosity ordered (e.g. IFO380 is 380 cSt @ 50 deg C) and the actual viscosity of the fuel delivered may be different. It was common practice in the past for the delivered fuel to be much lower viscosity than requested, making it easier to handle and burn. However, due to cost, the fuel has recently tended to be closer to the quoted viscosity, and in some cases even higher. It should be noted that the majority of heavy fuel supplied as ship bunker is a blend of extremely high viscosity residual oil (possibly in the region of 500-600 cST at 50 degrees Celsius) and a low viscosity “cutter stock” to achieve the desired viscosity. Certain fuel blends may have a tendency to “layer” in storage tanks, causing issues with bunker handling, treatment, and combustion. The marine industry has traditionally used viscosity to determine the price of fuel oils. Although higher viscosity fuels are less expensive, they are not always of lower quality than lower viscosity products. Viscosity is not a good indicator of fuel quality on its own.However, it should be noted that viscosity has a direct relevance on the ease with which a fuel can be burned (though it does not define the combustion properties of the fuel), as correct atomization of the fuel at the injectors in terms of drop size, penetration, and spray pattern requires that the viscosity at the injector be kept within the engine manufacturer’s recommended limits. In practice as some companies are using high viscosity fuels (RMK 750) due lower price, a recommended injection viscosity between 13 mm2/s cSt and 17 mm2/s (cSt) is impossible to achieve  taking into consideration the safe injection temperature of 150 deg. C.In my practice we use to run RT-Flex engines on RMK 750 cSt fuels at 148 deg.C with a viscosity of 22 cSt to 23 cSt, obviously with company’s approval. 
The viscosity index is defined as “an arbitrary number used to characterize the variation of the kinematic viscosity of a petroleum product with temperature” by standard test procedures (ASTM D2270/IP226). For oils with similar kinematic viscosity, the higher the viscosity index, the less effect temperature has on its kinematic viscosity. The vast majority of viscosity-temperature conversion diagrams are based on fuel with a viscosity index of approximately 70. Historically, this has been found to be sufficiently accurate for day-to-day conversions, but some of the more severely processed fuels now available have viscosity indices that differ significantly from the accepted norm.In the absence of any knowledge of the viscosity index, fuel of this type will cause viscotherm temperature readings to deviate from the “normal” expected value for a specific viscosity fuel. The set temperatures are maintained on thermostatically controlled heaters, but the actual viscosity of the fuel at these temperatures does not correspond to the charts – this may affect injection viscosity and purification conditions.Higher-than-expected viscosities at low temperatures should not be confused with the effects of wax crystallization, which causes the fuel to behave in a non-Newtonian manner, rendering standard measuring techniques invalid. 

Flash Point

Residual fuels are typically supplied with a “minimum flashpoint of 60°C,” with the actual value not usually quoted at delivery.The flashpoint of a liquid fuel is the temperature at which the fuel emits enough inflammable vapour to form an explosive mixture with air that ignites or “flashes” when it comes into contact with a small flame.The flashpoint temperature can be expressed as “closed” or “open,” depending on the type of test method used.For many years, a minimum flash point has been an international requirement. SOLAS (Safety of Life at Sea) regulations state that fuel with a flash point lower than 60°C renders the vessel not seaworthy. The flash point of the fuel is another criterion established by Maritime Insurers. As high temperatures are required for purification/clarification, in combination with the design of these systems, may result in high service tank temperatures. It is sometimes necessary to have an accurate knowledge of the flashpoint in order to comply with classification society and/or company regulations concerning upper allowable tank temperatures in relation to flashpoint temperatures. 

Pour point

The terms upper (or maximum) pour point and lower (or minimum) pour point refer to the ASTM D97 procedure for testing. Pour point is strictly defined as the lowest temperature (expressed in multiples of 3°C) at which the oil flows when cooled and examined under specified conditions.In practice, this means that the pour point temperature of a fuel is the temperature at which wax crystallization prevents the oil from flowing, to the nearest 3°C. It is thus useful as a guide to the lowest permitted bunker storage temperature in order to avoid handling difficulties. However, it should be noted that the lowest permissible pumping viscosity is in the region of 1000 cSt, but the temperature corresponding to this viscosity is unrelated to the pour point temperature.The pour point temperature is usually a good indicator of the amount of wax present.Pour points ranging from 30°C to 45°C are becoming available as a result of the discovery of high pour point African fuels, which have a higher wax content. Because wax has a low coefficient of heat transfer, allowing a high pour point fuel to cool and solidify in storage tanks makes re-liquefying by subsequent heating nearly impossible. As a result, double bottom and wing tanks containing high pour point fuel should be kept at a temperature above the oil’s pour point and the fuel used as soon as possible. Experience has shown that a small amount of wax is enough to cause a significant reduction in the pour point temperature of a fuel. In the absence of written confirmation of pour point temperature on the bunker receipt/delivery note, the delivery temperature may serve as a guide, as if bunkers are delivered at an unusually high temperature, there is a possibility that it has a high pour point. 
 

-End of Part I –

Marine Fuels

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There are different types of marine fuels available today on the market and marine industry will go into a major change sooner or later, as a response to the continuous change of the environmental rules and regulations. Therefore, the marine industry, among other industries, must respond and adapt to the changing and more strict regulations and become more efficient with regard to fuel consumption and emissions.
Many companies are researching and developing new types of fuels in liaison with engine manufacturers and shipyards. Some of the engine manufacturers strive to adapt and retrofit their existing engines to the new fuels, when possible, as it proves to be more economically practical. However, new built vessel will have to be equipped with new designed and versatile engines which can be used on dual fuels or new different type of fuels.
Fuel for marine operations of marine fuels is comprising of heavy fuel oils, distillates, LNG, ammonia, hydrogen, methanol, fuel cells and others. In the case of distillates, a distinction is made between marine gas oil (MGO) and marine diesel oil (MDO).

Residual Fuels

Residual fuel oil accounts for the vast majority of the fuel oil used by the world’s merchant fleet. This also applies to the vast majority of large diesel engines used on land. By definition, residual fuel oils are the byproducts of refinery processes that remain after the distillate or lighter fractions have been removed. These residues are complex mixtures that vary depending on the source of the crude oils processed and the refinery’s complexity.
After 2020 sulphur cap compliance regulation all conventional vessels are forced to use HFO + scrubber or LSFO and these fuels perform well on most parameters. There were some concerns about the availability of these fuels after 2020, but they are still significantly available than alternative fuels. The primary disadvantage of these fuels is their low environmental performance.

Scrubbers incur high investment and operating costs, but these are negligible in comparison to the costs of alternative fuels.

Fuel oil was initially derived from the residue of the atmospheric or vacuum distillation process in the early days of refining. By and large, the product entering the market for fuel oil was of consistent quality, with few issues. As demand for distillate products increased, refiners implemented secondary refining processes, altering the market characteristics of fuel oil. The secondary refining processes have some side effects like lesser amount of residual fuel, higher micro-carbon value, stability and sediment problems, higher density and catalyst fines contamination problems.

Individual country-specific product demand is extremely diverse, and cannot be met solely through crude oil selection due to the sheer volume required. Additionally, within a single geographical area, a variety of crude oil sources and refinery process configurations are used. As a result, fuel for industrial and marine markets exhibits considerable variation in its properties on a global scale. While this has been the case for the most part throughout history, the variations can be more pronounced than in the past.

An oil refinery can be thought of as a factory that transforms crude oil into a variety of useful products. It is designed to meet market demands in the most cost-effective and efficient manner possible. The first step in the manufacture of petroleum products is the atmospheric distillation of crude oil into its major fractions. When crude oil is heated, the lightest, most volatile hydrocarbons evaporate first, followed by the heaviest, least volatile hydrocarbons. After cooling, the vapors are condensed back into liquids. A fractionating column is used to carry out this distillation process. The column is divided into chambers by perforated trays that condense the vapors and allow the liquids to flow into storage tanks at each stage. The crude oil is preheated to a maximum of 350°C to avoid thermal cracking.

The residue from atmospheric distillation is sometimes referred to as long residue, and additional distillation at a reduced pressure and high temperature is used to recover more distillate product. This vacuum distillation process is critical for optimizing crude oil upgrading. The vacuum distillation residue, sometimes referred to as short residue, is used as a feedstock for further processing or as a component of a fuel. Unlike the fractionating column used in atmospheric distillation, the low-pressure vapors are condensed using a system of packed beds rather than trays.

Refineries that rely solely on atmospheric and vacuum distillation are referred to as “straight run” refineries, and the fuel oil produced is essentially either long or short run residue. The residue percentage varies according to the composition of the crude processed. The residue is 28 % for a typical “light” North African crude and up to 85 % for a “heavy” Venezuelan crude. The proportion of products produced does not always correspond to the demand for them and is largely determined by crude oil.

Additional refining processes were introduced to meet product demand. Apart from atmospheric and vacuum distillation, a modern refinery may also include secondary refining processes such as cracking, which may be thermal or catalytic. Below is an illustration of a typical modern refinery installation.

Copyright: researchgate.org

Thermal cracking is the oldest and, in theory, the simplest method of refinery conversion. It is carried out at temperatures ranging from 450 to 750°C and pressures ranging from atmospheric to 70 bar. Temperature and pressure are determined by the type of feedstock and the desired product. At these elevated temperatures, the large hydrocarbon molecules become unstable and self-destruct. Another critical factor in the process is the length of stay.

The feedstock can be either atmospheric or vacuum distillation residue, or a combination of the two. The thermal cracking process has three primary applications in modern refineries: visbreaking, thermal gas oil units, and coking. Visbreaking is the most critical process in the production of residual fuel oil. It is a relatively mild type of thermal cracking that is frequently used to reduce the viscosity of straight-run residual fuels. Typically, such fuels are extremely viscous and must be blended with a relatively high-value distillate to meet the finished product specification. Visbreaking significantly reduces the amount of distillate required as diluent or “cutter stock,” which can then be diverted to a more profitable product stream.

A thermal gas oil unit’s primary objective is to produce and recover the maximum amount of gas oil possible. In extreme cases, the residues viscosity may exceed that of the feedstock. Coking is a form of thermal cracking that is quite severe. It is intended for the conversion of straight-run residues to more valuable products such as naphtha and diesel oil. Additionally, gas and coke are produced, and as a result, this process is not used in the production of residual fuel oils.

In the petroleum refining industry, catalytic cracking has become the primary process for converting heavy hydrocarbon fractions, primarily into high-quality gasoline and fuel oil components. These are more valuable than the feedstock because they are lighter and less viscous. There are numerous catalytic cracker designs, however, the final product output can be separated into gases, gasoline blending components, catalytically cracked cycle oils, and cycle oil slurry in all cases. Cycle oils are critical in relation to residual fuel oil because they act as cutter stocks, reducing the viscosity of residues. Prior to being used as a cutter stock, the cycle oil slurry must be treated to remove any entrained catalyst particles.

There are numerous residues and diluents available in a modern refinery for the production of fuel oil. Typically, the fuel is made up of visbroken residue that has been diluted with cycle oils and trace amounts of other distillates. Below figure depicts the major feedstock, diluent, and residue streams in a modern refinery. 

Copyright: researchgate.org

Obviously, if a refinery lacks a thermal cracking facility (visbreaker or thermal gas oil unit), the fuel oil will be derived from long or short residue. Apart from the primary residual fuel streams in a modern refinery, it is worth noting that additional developments have been made to maximize the amount of gasoline, kerosene, and diesel produced from a barrel of oil. One of these is through residue hydro conversion, which converts residual fractions into feedstock that can then be processed further in conventional crackers to yield lighter products. Production optimization for lighter products is accomplished at the expense of residual fuel oil.

The British Standard Institute was the first to issue a specification for ship fuels in 1982 (BS MA 100). It was developed collaboratively by suppliers and engine manufacturers, with quality and price trade-offs.

The International Maritime Organization (IMO) initiated ISO 8217 “Petroleum products – Fuel (class F)” in 1987, which has since become the general standard. The standard makes a distinction between residue fuels (RMA, RMB, RMC…, RMK) and distillates (DMX, DMA, DMB and DMC). It categorizes residue fuels based on viscosity and establishes class-specific limits (maxima for density, flash point, pour point, coke residue, water, ash content, and sulphur content). Viscosity classes are defined as viscosity values of 30, 80, 180, 380, and 700 mm2/s at 500 C.

Critical values for “cat fines” (80mg/kg for aluminum plus silicon) and a test for quantifying possible total sedimentation content were adopted in March 1996 and we will talk about “cat fines” on a later post.