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.
A merchant ship is designed and constructed to transport tons of cargo between ports and in addition to cargo, the ship must transport in its own tanks, fuel oil, diesel oil, and various grades of lubricating oil in bulk for the propulsion plant and other auxiliary machinery systems.
Example of vessel arrangement plan
Ships also have strategically placed ballast water tanks on both sides to stabilize the vessel when oil or cargo is being loaded or unloaded. Tanks are also supplied for the storage of potable water or feed water for the system.
In order to maintain the ship’s stability, and safety, it is required to monitor the fluid levels at regular intervals. The technique of determining the fluid level in a ship’s various tanks is known as “sounding” of the tanks.
During bunkering operation is is imperious to check the fluid level in tanks at regular intervals, using vessel remote sounding instrumentation or by using a sounding tape. Sounding tape is a measuring tape (in meter or inch) normally made up of brass and steel with a weighted bob attached at the end of the tape using a strap hook.
Example of a sounding tape
Despite of vessel in-built sounding method, at the end of bunkering operation the sounding tape value is subsequently utilized in the calculation of the final sounding value, which is determined using the sounding table, taking into account the list and trim of the ship and the temperature at which the fluid (particularly oil) is stored as density of oil is effected by temperature.
Example of a sounding table
Example of heel correction table
Sounding table is a table containing capacity and most importantly the volumetric content of the tank at given depth of sounding or ullage and all vessels have their own specific sounding table documents for each tank containing fluid in bulk. The sounding table is compiled to show the volumetric quantity of fluid at various trims and list for the particular sounding depth in cm.
On board ship, it is essential to maintain an accurate record of the amount of liquids (in all forms) contained in each tank. A ship is equipped with several forms of automatic and hydraulic/ pneumatic/ mechanical sounding measurement systems, allowing the liquid level to be monitored remotely or locally without the need for manually measuring and calculating the amount of liquid within the tank.
However, one cannot rely solely on automation and mechanical devices and manual sounding is always favored in order to reconfirm the fluid level in the tanks, assuring that the tanks will never overflow or run dry.
Malpractices by bunker suppliers during bunkering operations have a significant influence on your Company’s fuel expenses and it is a direct loss that can be prevented with careful observation and attention from the vessel’s crew. It is critical that the vessel’s bunker operating staff takes barge tank measurements carefully, applying the necessary trim/list before and after bunkering, recording the actual temperature of the bunker fuel before/after delivery, and so on. You can read about bunkering operation in here!
In order to learn how to correctly do the tank sounding, regardless of their destination, please watch patiently the below self explanatory video which capture the entire sounding and calculation process.
After you have learned how to correctly perform the bunker tank soundings, the next step is to convert these readings in quantity using, as specified above, the sounding tables applying trim/list and temperature correction.
For exemplification purpose only, let’s consider that vessel receives bunker in only one tank (if vessel receives in multiple tanks the calculation is similar, but quantities must be added up for final quantity). In order to make an accurate calculation of how much fuel has been received, usually below procedure applies:
take soundings or ullages of all the tanks that have received fuel;
we first need to know the volume received, vessel trim and heel and the observed temperature of the fuel. We will use the below sounding and correction tables for exemplification only.
for exemplification purpose, let’s pretend that our ullage reading is 473 cm (so sounding will be 800 cm or 8 m), temperature of delivered fuel is 43 °C. and ship’s condition at the time of sounding is assumed to be as follow:
Forward draft: 8 m
Mid draft (P): 8.70 m
Mid draft (S): 9,30 m
Aft draft: 10 m
Heel to starboard: 0.60 m
from the above data:
vessel trim: 8 -10 = 2.0 m (by the stern). As per table if vessel trim is by stern the reading is -2.0 m.
Sounding depth corrected for heel is: 8 + (- 0.014) = 7.986 m
the volume of the tank is calculated from the “Sounding Table” and in our case having a trim of 2 m by the stern and as per attached above sounding table , the actual volume of the tank will be:
So, our measured volume with heel and trim correction is: 504.06 m³, at a temperature of 43 ºC.
now, after determining the observed volume, you must correct it to the standard of 15 0C and for this you will need to know the density @ 15 ºC of the delivered fuel which can be find into the Bunker Delivery Note (BDN). In our case let’s pretend, for exemplification purpose that the density @ 15 ºC is 996 kg/m³
once we know the observed volume, temperature and density the next step is to multiply the observed volume with the temperature correction factory (VCF) found in tables such as ASTM 54B or by using a dedicated app or software.
In our case, through interpolation, the VCF will be: 0.9826
So as per above, the gross standard volume is: 504.06 x 0.983 = 495.490 m³ @ 15 ºC.
as the density is an absolute relationship between mass and volume in a vacuum, it will not be the same as weight to volume in air. So the amount of tones received is:
495.490 x 0.996 = 493.508 Mt in vacuum
to find the correct density in air, we must multiply the given density with a Weight Correction Factor which can be found in table ASTM 56.
In our case the correct density in air is:
0.996 x 0.99895 = 0.9949 kg/m³
once this is done, we can multiply the standard volume @ 15 ºC with the corrected density to find the amount of tons of fuel received. So, in our case this will be:
495.490 x 0.9949 = 492.963 Mt in air
It’s critical to have an accurate figure of the density of the fuel, which can later be confirmed by the testing laboratory.
In conclusion, it is of utmost importance that a proper sounding is carried out, applying the necessary trim/list before and after bunkering, recording the actual temperature of the bunker fuel before/after delivery, and so on. Simply measuring temperature correctly can save a lot of money!
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In my previous post, we have discussed about pre-bunkering preparation and bunkering operation in particular and the described procedure applies in every port where the vessel intend to bunker. However, there are some specific requirements with regard to oil transfer onboard vessels and US authorities issue a set of rules that must be followed if the vessel intends to bunker in any of US ports.
Bunker barge alongside vessel
The Master of the vessel must notify the port authority of the intention to bunker well in advance, stating the location, type of bunker, oil to be transshipped, and the expected time of bunkering.
C/E will hold a meeting with all ship’s staff who will be involved with or responsible during bunkering on a bunkering plan at least 24 hours prior to bunkering operations, where the following will be discussed and agreed upon:
Roles and responsibilities specific to assigned task of each individual
Tanks that will be made available for bunkering
Plan on extent of filling of each tanks
Valves to be lined up for the operations
Closing of scuppers on deck
Communications between supply vessel and receiving vessel
Flow rate
Frequency of checking tank soundings
Spill response
Pre-bunker meeting held onboard vessel
The above is intended as a guide and does not exclude any other possible scenarios that the C/E and his engine room staff would like to implement.
Pre-bunkering Check list is to be filled in for compliance. All check lists are to be maintained on board at least for a minimum period of two years from date of bunkering or as per company management system instructions.
Example of pre-bunker checklist
As mentioned in my previous post (which can be found in here) before bunkering begins, the Chief Engineer must double-check all details on the delivery papers as presented by the barge supplier’s representative to ensure that the bunkers delivered match the quantity and specifications stated in the prior Bunker Confirmation message.
Chief engineer and his / her designated engineers shall verify that the following is also complied with prior to commencement of bunkering.
All self closing devices on sounding pipes operate correctly and easily, and closed after use.
Prior to bunkering air pipes from all tanks are in order. This includes checking that the safety gauze is not blocked with paint thus reducing the air flow. Where Press/Vac valves are fitted, they shall be checked for free movement.
Heavy fuel oil vapours are measured for Hydrogen Sulphide (H2S), preferably on board the barge. The acceptance level of H2S in the tank atmosphere is up to 200 ppm. If H2S in the tank
atmosphere is found in excess of 200 PPM, the fuel should be rejected and the parties in barge of vessel’s bunker supply notified accordingly. About H2S will discuss on a later post.
Apart from above, below there is a summary description of the USCG requirements pertaining oil transfer operations.
Code of Federal Regulations 33
For whoever is interested the code can be found in here.
As per USCG 33 CFR 156.120 Requirements for transfer a transfer is considered to begin when the person in charge on the transferring vessel or facility and the person in charge on the receiving facility or vessel first meet to begin completing the declaration of inspection, as required by §156.150 of this part. Therefore, no person shall conduct an oil or hazardous material transfer operation unless:
The vessel’s moorings are strong enough to hold during all expected conditions of surge, current, and weather and are long enough to allow adjustment for changes in
draft, drift, and tide during the transfer operation;
Transfer hoses and loading arms are long enough to allow the vessel to move to the limits of its moorings without placing strain on the hose, loading arm, or transfer piping
system;
Each hose is supported to prevent kinking or other damage to the hose and strain on its coupling.
Each part of the transfer system is aligned to allow the flow of oil or hazardous material;
Each part of the transfer system not necessary for the transfer operation is securely blanked or shut off;
The end of each hose and loading arm that is not connected for the transfer of oil or hazardous material is blanked off using the closure devices required by §§154.520 and
155.805 of this chapter;
The transfer system is attached to a fixed connection on the vessel and the facility except that when a vessel is receiving fuel, an automatic back pressure shutoff nozzle may be used;
Each overboard discharge or sea suction valve that is connected to the vessel’s transfer or cargo tank system is sealed or lashed in the closed position; except when used to receive or discharge ballast in compliance with 33 CFR Part 157;
Each transfer hose has no unrepaired loose covers, kinks, bulges, soft spots, or any other defect which would permit the discharge of oil or hazardous material through the
hose material and no gouges, cuts, or slashes that penetrate the first layer of hose reinforcement (“reinforcement” means the strength members of the hose, consisting of
fabric, cord and/or metal);
Each hose or loading arm in use meets §§154.500 and 154.510 of this chapter, respectively;
Each connection meets §156.130;
Any monitoring devices required by §154.525 of this chapter are installed and operating properly;
The discharge containment equipment required by §154.545 of this chapter is readily accessible or deployed as applicable;
The discharge containment required by §§154.530, 155.310, and 155.320 of this chapter, as applicable, is in place and periodically drained to provide the required capacity;
Each drain and scupper is closed by the mechanical means required by §155.310;
All connections in the transfer system are leak free except that a component in the transfer system, such as the packing glands of a pump, may leak at a rate that does not
exceed the capacity of the discharge containment provided during the transfer operation;
The communications required by §§154.560 and 155.785 of this chapter are operable for the transfer operation;
The emergency means of shutdown required by §§154.550 and 155.780 of this chapter, as applicable, is in position and operable;
There is a person in charge on the transferring vessel or facility and the receiving vessel or facility except as otherwise authorized under §156.115;
Each person in charge required by paragraph (s) of this section:
(a) Is at the site of the transfer operation and immediately available to the transfer personnel;
(b) Has in his or her possession a copy of the facility operations manual or vessel transfer procedures, as appropriate; and
(c) Conducts the transfer operation in accordance with the facility operations manual or vessel transfer procedures, as appropriate;
The personnel required, under the facility operations manual and the vessel transfer procedures, to conduct the transfer operation:
(a) Are on duty; and
(b) Conduct the transfer operation in accordance with the facility operations manual or vessel transfer procedures, as appropriate;
At least one person is at the site of the transfer operation who fluently speaks the language or languages spoken by both persons in charge;
The person in charge of the transfer on the transferring vessel or facility and the person in charge of it on the receiving vessel or facility have held a conference, to ensure
that each person in charge understands:
(a) The identity of the product to be transferred;
(b) The sequence of transfer operations;
(c) The transfer rate;
(d) The name or title and location of each person participating in the transfer operation;
(e) Details of the transferring and receiving systems including procedures to ensure that the transfer pressure does not exceed the maximum allowable working pressure (MAWP) for each hose assembly, loading arm and/or transfer pipe system;
(f) Critical stages of the transfer operation;
(g) Federal, state, and local rules that apply to the transfer of oil or hazardous material;
(h) Emergency procedures;
(i) Discharge containment procedures;
(j) Discharge reporting procedures;
(k) Watch or shift arrangement;
(l) Transfer shutdown procedures; and,
(m) If the persons use radios, a predetermined frequency for communications during the transfer, agreed upon by both.
(n) The person in charge of transfer operations on the transferring vessel or facility and the person in charge of transfer operations on the receiving vessel or facility agree to
begin the transfer operation;
As per USCG 33 CFR – 156.125 Discharge cleanups the following should be taken into account:
Each person conducting the transfer operation shall stop the transfer operation whenever oil or hazardous material from any source is discharged:
(a) In the transfer operation work area; or
(b) Into the water or upon the adjoining shoreline in the transfer area.
Except as permitted under paragraph (c) of this section, no person may resume the transfer operation after it has been stopped under paragraph (a) of this section, unless:
(a) Oil or hazardous material discharged in the transfer operation work area is cleaned up; and
(b) Oil or hazardous material discharged into the water or upon the adjoining shoreline is cleaned up, or is contained and being cleaned up.
The COTP may authorize resuming the transfer operation if it is deemed appropriate.
USCG 33 CFR – 156.130 Connections
Each person who makes a connection for transfer operations shall:
(a) Use suitable material in joints and couplings to ensure a leak-free seal;
(b) Use a bolt in at least every other hole, and in no case less than four bolts, in each temporary bolted connection that uses a flange that meets American National Standards
Institute (ANSI) standard flange requirements under §154.500(d)(2) of this chapter;
(c) Use a bolt in each hole in each temporary bolted connection that uses a flange other than one that meets ANSI standards;
(d) Use a bolt in each hole of each permanently connected flange;
(e) Use bolts of the correct size in each bolted connection; and
(f) Tighten each bolt and nut uniformly to distribute the load and sufficiently to ensure a leak free seal.
A person who makes a connection for transfer operations must not use any bolt that shows signs of strain or is elongated or deteriorated.
Except as provided in paragraph (d) of this section, no person may use a connection for transfer operations unless it is
A bolted or full threaded connection; or
A quick-connect coupling acceptable to the Commandant.
No person may transfer oil or hazardous material to a vessel that has a fill pipe for which containment cannot practically be provided unless an automatic back pressure shutoff nozzle is used.
USCG 33 CFR 156.150 Declaration of inspection
No person may transfer oil or hazardous material to or from a vessel unless each person in charge, designated under §§154.710 and 155.700 of this chapter, has filled out
and signed the declaration of inspection form described in paragraph (c) of this section.
No person in charge may sign the declaration of inspection unless he or she has determined by inspection, and indicated by initialing in the appropriate space on the declaration of inspection form, that the facility or vessel, as appropriate, meets §156.120.
The declaration of inspection may be in any form but must contain at least:
The name or other identification of the transferring vessel or facility and the receiving vessel or facility;
The address of the facility or location of the transfer operation if not at a facility;
The date and time the transfer operation is started;
A list of the requirements in §156.120 with spaces on the form following each requirement for the person in charge of the vessel or facility to indicate by initialing that
the requirement is met for the transfer operation; and
A space for the date, time of signing, signature, and title of each person in charge during transfer operations on the transferring vessel or facility and a space for the date, time of signing, signature, and title of each person in charge during transfer operations on the receiving facility or vessel certifying that all tests and inspections have been completed and that they are both ready to begin transferring product; and
The date and time the transfer operation is completed.
The form for the declaration of inspection may incorporate the declaration of inspection requirements under 46 CFR 35.35-30.
The vessel and facility persons in charge shall each have a signed copy of the declaration of inspection available for inspection by the COTP during the transfer operation.
The operators of each vessel and facility engaged in the transfer operation shall retain a signed copy of the declaration of inspection on board the vessel or at the facility for at least 1 month from the date of signature.
USCG 33 CFR 156.160 Supervision by person in charge
No person may connect or disconnect a hose, top off a tank, or engage in any other critical procedures during the transfer operation unless the person in charge, required by §156.120(s), supervises that procedure.
No person may start the flow of oil or hazardous material to or from a vessel unless instructed to do so by either person in charge.
No person may transfer oil or hazardous material to or from a vessel unless each person in charge is in the immediate vicinity and immediately available to the transfer personnel.
In addition, for vessels entering the North American ECA, should notify all relevant authorities in cases of fuels that does not reach the sulphur requirements of the ECA. This should be done in any of the following cases:
BDN is non-compliant
BDN is compliant, but post-test analysis is non-compliant
Compliant fuel is not available.
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Bunkering is a process of transferring fuel oil or lube oil in which two vessels positioned alongside each other supply fuel oil from one to another.
Bunker barge alongside vessel
Damage from poor bunkers and financial loss from insufficient bunker supply are key issues for the marine sector, and this because there is a lot of money involved due of the big amount of fuel oil that is frequently bunkered.
Because the fuel is given in volume but paid for by weight, you must know the exact density of the fuel to determine how many tones your vessel receives. The cappuccino effect makes the volume of fuel appear greater than it is if the fuel contains a lot of air. As a result, if the quantity determination process is not controlled properly, your company may suffer significant financial losses.
Cappuccino effect on bunker
On the other hand, bunkering process involves several environmental hazards, most notably oil spills, which are not only hazardous to the environment but also unlawful and as a result, local law enforcement teams are particularly focused on monitoring any spill, because any vessel found to be in violation of laws may face huge fines.
Vessel oil spill during bunkering operation
Emission Control Areas (ECA) are also very essential since they enforce rigorous airborne emission standards, and ships now trading in ECA areas must use fuel with no more than 0.01 % sulphur content and the maximum sulphur limit outside ECA’s is 0.5 % unless the vessel is fitted with an approved Exhaust Gas Cleaning System, therefore checking the quality of bunkered fuel has become even more crucial, due to the fact that Port State Control inspectors may scrutinize fuel inventory records to ensure the ship utilized the correct fuel within an ECA or an EU Community port and complied with other national sulphur standards. MARPOL Annex VI, Singapore’s Standard Code of Practice for Bunkering, EU Sulphur Directives, and other national rules may apply, therefore it is a good practice to consult with the vessel’s local agent before vessel arrival in port.
Most ships have bunkering checklists and procedures in place, but if your vessel does not have one, the IMO has created a “Bunkering Precautions including Bunkering Checklist” in the document “Updated recommendations for the safe transport of dangerous cargoes and related operations in port areas.”
Example of a bunker checklist
This will be useful while planning a bunker operation or drafting a bunker plan for the ship. It includes general advice on maintaining efficient two-way contact with a responsible person on board the bunker barge. It also suggests that you ensure that fire hoses, fire fighting equipment, and oil spill equipment are available for use, as well as that scupper plugs are properly fitted and drip trays are appropriately positioned under connections and bunker tank vents.
Drip tray under bunker hose connection
Preparing scuppers on deck
Prior bunkering operation, the Chief Engineer should create a bunkering plan that specifies which tanks would be used for bunkering and to achieve an efficient and safe operation, all staff must be fully aware of this before the operation begins. There should also be enough known-quality fuel on hand to use until the newly bunkered fuel is tested by a certified laboratory. As part of pre-bunkering preparation you must check the following:
All tank lids are closed and locked, and that all bunker tank air vents are open and clear.
Overflow tanks must be empty
All level gauges, high-level alarms, and remote-controlled valves on bunker tanks must be operational.
Check that manual sounding tapes are available and that the soundings pipes are not clogged or obstructed.
Check that all valves to the receiving bunker tanks are properly aligned and that all other valves are closed.
Check the filters and safety valves on the bunker lines, if installed.
All bunker lines and transfer hoses should be pressure tested, and safe operating pressures should not be exceeded.
Check that the bunkering hose is properly and securely connected to the ship manifold.
Check ahead of time that you have the proper equipment to take a sample before bunkering: a continuous drip feed sampler (which must be a MARPOL Annex VI compliant line sampling device), a cubitainer to collect the sample, and lots of clean sample bottles will be included.
Example of bunker sampling equipment
During bunkering operations, the hose connection must remain intact and leak-free, and this must be checked regularly during the operation, especially when the barge switches tanks and pressure is dropped for a brief period of time. If the fuel is not homogeneous, the bunker line pressure may also fluctuate. To sample properly, we must employ adequate equipment to collect representative samples that are acceptable to all parties involved. The dependability of test results from fuel quality analysis and the fuel density used in quantity measurement calculations is based on proper sample methods being followed.
The sampling device is installed at the point of Custody Transfer, which is typically at the ship bunker manifold, which is the preferred location for joint sampling in agreement with the fuel supplier (this is very important in case to any future quality disputes).
Sample cubitainer installed on the bunker line
The Chief Engineer must examine the quality of the fuel given by the bunker barge supplier when the barge first arrives. They accomplish this by validating the quality and quantity of fuel mentioned on the Bunker Delivery Note (B.D.N).
Example of a Bunker Delivery Note
“Details of fuel oil for combustion purposes delivered to and utilized on board shall be recorded by means of a Bunker Delivery Note,” according to MARPOL standards. As a result, a BDN should be presented for each delivery and fuel grade delivered, and it should be stored on board and easily accessible for inspection at all times. The ship and the provider are both required to keep it for three years after the fuel oil has been delivered. The BDN must include information such as the receiving ship’s name and IMO number, the bunkering port, the date the bunkering began, the name, address, and phone number of the marine fuel oil supplier, the product name and grade, the quantity in metric tones, the density at 15 0C in kg/m3, and the sulphur content in percentage by mass. The IMO further suggests to include the seal number of the MARPOL Annex VI fuel sample on the BDN for cross-referencing reasons, as well as a declaration signed and validated by the supplier’s representative declaring that the fuel complies with MARPOL Annex VI. The BDN may be prepared prior to delivery in some situations, but this will not reflect the realities of the delivery.
It is very important to note that you should NEVER sign the BDN, sample labels, or any other document until the bunkering operation is complete.
The Chief Engineer will decide which tanks will receive the fuel before the barge arrives, and the contents of each receiving tank should then be measured and documented. These should ideally be empty, as different types of fuel may not be compatible. Blending fuels should be avoided unless absolutely necessary, as it can cause operational issues. Because some vessels lack a remote level measuring technology, you may need to use a sounding tape.
Bunker tank measurement using measuring tape
Check that the barge’s documentation show the correct grade and quantity of fuel, and agree on sample protocols when it arrives. Careful measurements of the barge tank contents must be taken before connecting the bunker hose. Use your own sounding tape or ensure that the equipment onboard the barge is in good working order and has not been tampered with.
Example of rigged measuring tape used to cheat on bunker measurement
Some barges will feature calibration tables for ullages and others for tank content soundings. Check that the right reference point on deck is being utilized for taking ullages as this information should be available in the barge calibration tables.
Always accompany the Barge Master while taking ullages or soundings of any barge tanks. It is critical that all of the tanks on board barge are dipped and their levels recorded and this includes tanks that have been reported empty as well as those that may contain fuel for another vessel. After taking each measurement, make a note of it and double-check that the barge operator agrees with your reading as these are critical measurements in determining the amount discharged by the barge, and both parties should sign the opening measurement records. Temperature readings of each tank are also critical, because the volume of bunkers rises with temperature. Temperature changes can create considerable mistakes in calculations, hence thermometers should be checked on a regular basis.
Typically, the terms and conditions of the sale indicate that the quantity of fuel delivered will be determined by shore meters or barge outturn measurement. The Chief Engineer or a representative from the ship should be present at the bunkering barge to observe the opening and closing meter readings, barge soundings, and temperature readings.
Fuel sampling should be carried out by continuous drip method for the entire duration of the bunkering process. The sample is first collected in a cubitainer which is screwed onto the drip sampler and secured with a seal in order to prevent any unauthorized changes in the adjustment of the drip rate during sampling. Barge Master and the Chief Engineer should be invited to witness the adjusted drip-rate and sealing process and security seal number should be recorded. To ensure that the sample represents all of the fuel bunkered, the sample needle valve should be adjusted to collect enough of each fuel type for all of the required fuel samples without overfilling the cubitainer, which needs to be able to hold enough oil for all of the samples that you may need:
a MARPOL sample
a retained sample for the ship to keep
a retained sample for the barge to keep
a retained sample for the testing laboratory
if the vessel is utilizing a bunker surveyor, an extra sample may be required.
The ship should also be given a retained sample from the bunker supplier, which should be taken properly on the bunker barge.
If the sample cannot be obtained from the ship manifold for any reason (vacuum in the line, extreme weather, etc.), the cause should be recorded in the ship’s log book and the sample taken elsewhere.
Throughout the bunkering operation, specific crew members should be appointed to ensure that there is always one vessel representative overseeing the activity (monitoring the bunker manifold and the sampling equipment, continuously checking for leakages etc.). Record any start and stop times as well. All of the above responsibilities can be overseen by an experienced and certified bunker quantity surveyor, who can assist the Chief Engineer in ensuring proper bunkering and sampling procedures are followed.
When the delivery is complete, the vessel representative should witness the closing soundings on the barge in order to determine and validate the actual volume provided. To accurately calculate how much fuel has been received the following steps should apply:
check the volume received and the observed temperature of the fuel.
take soundings or ullages of all tanks that have received fuel and correct the soundings or ullage according with the vessel’s trim and list.
after correction the observed volume you have received can then be calculated. It should be noted that vessel calibration tables for fuel storage tanks are rarely approved by recognized bodies, but bunker barge calibration tables are routinely reviewed and certified by local authorities.
after determining the observed volume, you must correct it to the standard of 15 0C.
to determine the correct Volume Correction Factor (VCF), you must first check the density of the fuel at 15 0C, which will be provided by the supplier.
the observed volume is then multiplied by the temperature correction factor contained in tables such as ASTM 54B to determine the standard volume at 15 0C.
because density in a vacuum is an absolute relationship between mass and volume, it will not be the same as weight to volume in air. To calculate the right density in air, multiply the supplied density by a Weight Correction Factor, which may be found in ASTM 56 table.
after that, we can multiply the standard volume at 15 0C by the corrected density to determine the number of tons of fuel received.
Many fuel testing laboratories discover that the density on the BDN is frequently exaggerated, implying that the supplied weight was less than it seemed. If the density cannot be found from a representative sample, the BDN should only be signed for volume at the observed temperature, but if the supplier insists on a signature for weight, add “For volume only – weight to be determined after density testing of a representative sample” to the Remarks section in the BDN.
When the delivery is finished, the surveyor should concur with the Chief Engineer and Cargo Officer that the bunker delivery is completed. When the bunkering is finished and the cubitainer is full of fuel, close it and shake it for a few minutes to completely mix the sample. Because we will frequently be preparing at least four samples, fill all of the sample bottles one-third at a time, making repeated passes to fill each bottle evenly.
Example of filling the fuel sample bottles
Close and seal the sampling bottles, and record the seal numbers on the Sample Details Form.
Example of sealed and labeled sample bottle
Sign the labels on the fuel quality testing samples with the supplier representative. and put a label on each bottle with both signatures.
Under no circumstances should you sign any blank labels or accept any samples that have been created or supplied in advance of the bunkering process.
It is critical that you keep one sample on board in a secure area since this may be the only sample remaining that accurately represents the fuel delivered to the ship. If the supplier provides a sample but it was not witnessed, apply the mark “Only for receipt. Unknown source” on its label. The fuel supplier is required to give you a representative MARPOL sample, which must be sealed and signed by a representative of the company. This MARPOL sample must be kept under the ship’s control until the fuel oil is considerably depleted but not for less then twelve months after delivery.
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Vessel’s bunker line pressure test is a procedure of the outmost importance which cannot be emphasizes enough, although is ignored and avoided by many engineers sometimes due lack of time, lack of knowledge or fear that something would go wrong during test. Is very important to remember that the whole purpose of this periodical test is exactly to find if something is wrong with the fuel oil bunkering system and to take all necessary actions to remediate the faults and defects within.
Chief Engineer is responsible for performing the pressure test of the bunker line on an annual basis when each transfer pipe onboard a vessel must be tested under static liquid pressure, at least 1.5 times the maximum allowable working pressure (MAWP). Special attention should be paid to flange joints, valve gland packing, pump seals etc.
Hydrostatic test is a test conducted by filling a space with a liquid to a specified head. Unless another liquid is approved, the hydrostatic test consists of filling a space with either fresh or sea-water, whichever is appropriate for the space being tested. This kind of test is usually performed during vessel’s periodical special survey (dry docking) using fresh water, but sometimes needs to be done also onboard.
Bunker line hydrostatic test performed in dry dock
MAWP is considered to be the design relief valve pressure setting of the relief valve on the bunker transfer pump. In the absence of the relief valve the MAWP should be taken to be 5.0 kg/cm2.
Bunker line tested @5 kg/cm2
In order to perform the test onboard the following should be taken into consideration:
A “Permit to Work” should be issued and a “Risk Assessment” must be carried out.
Before conducting the test, all scuppers should be sealed and adequate oil spill equipment should kept ready on deck.
The test should be performed for a period of 10 minutes under a constant hydrostatic load.
The pressure rating for pipe line material should not be exceeded. This pressure can be found and verified into the vessel’s bunker plan and/or piping diagram.
During testing onboard bunker transfer pump may be employed for the test. If the transfer pump is a positive-displacement type, it may be stopped when the required test pressure is reached as it should not permit backflow, therefore valves before and after pump should be closed after desired pressure has been reached. If a centrifugal pump is used for testing, constant running is required to ensure the necessary pressure is maintained.
The test should be conducted while underway at sea at least 200 nm from shore during day light.
Similar test procedure applies for fuel oil and lube oil bunker lines.
After the test, the date and test pressure should be stenciled on the pipe lines and deck at prominent locations.
The stencil should be: ”Hydro Test Date: xx/xx/xxxx Pressure: xx kg/cm2.
The actual testing procedure should comprises of the following steps:
Minimum pressure test must be 4 kg/cm2.
The bunker line relief valve if fitted must be removed and a blank with a drain valve must be fitted. As an alternative, the relief valve set pressure can be increased and test the bunker line pressure to a value at least 1.5 times, the normal operating set pressure of the relief valve. In the absence of the relief valve the MAWP should be taken to be 5.0 kg/cm2.
At the bunker station, fit a flange, fitted with pressure gauge and a connection for a suitable hand pump. The connection should be fitted with a gauge/cock for pressure monitoring. You must ensure that the gauge is verified and calibrated.
A communication between engine room and deck must be established and personnel must be arranged to monitor for any leaks on deck and engine room.
Use the transfer pump to fill bunker lines up to the manifold. Purge the lines via valves/cocks on manifold.
After the line is filled with oil, the pump valves and system valves must be closed. A hydraulic hand pump can be connected to the manifold to build up the pressure or same can be done with the transfer pump but caution must be taken in order not to damage the pump.
Maintain the pressure for 10 minutes and check the entire system for leaks.
Failure bunker line on deck during annual pressure test
After completion of test drain the pressure into the overflow tank through the relief valve connection or by slowly opening the valve to an empty bunker tank.
It is very important to remember that it is not allowed to test the system by air and by doing so it will makes the test worthless and void. If vessel intend to bunker in United States, it must provide the written records of the date and result of the most recent hydrostatic test and inspection of the bunker lines/transfer system as required by 33 Code of Federal Regulations (CFR) 156.170.
The Coast Guard recognizes that achieving the test pressure of 1.5 times MAWP for annual bunkering test on vessels is often impractical while vessel are in service or outside shipyards where special equipment may not be available. Therefore, the Coast Guard will continue to accept alternatives as described below:
Compliance with the requirement is economically or physically impractical
The vessel operator submits a written request for the alternative at least 30 days before operations under the alternative proposed, unless the Captain of the Port authorizes a shorter time.
The alternative provides an equivalent level of safety and protection from pollution by oil or hazardous material, which is documented in the request.
The US Coast Guard allows for acceptance of alternative test pressure of not less than 100% MAWP for annual bunker test, provided that a 150% MAWP test of the piping is conducted at least twice in any five years period. It is envisioned that the 150% MAWP test will be conducted during vessel’s drydock periods at the discretion of the owners or operators.
In conclusion, periodical test of bunker lines are very important and it must be done diligently and be a part of vessel’s periodical safety checks. Although is a Chief Engineer responsibility, every engineer must be familiar with the legal and testing procedure requirements as they are involved into the daily vessel’s operation and bunkering process. As I said, it can be emphasized enough the importance of performing the test, as failure to do so can lead to serious consequences for the vessel and crew.
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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.
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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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.
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.
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.
