Quick Contact Info

Your energy transition and small scale LNG experts.

Contact us today to speak to one of our professionals.

icon_widget_image Level 9, 182 St Georges Terrace, Perth, Western Australia 6000 icon_widget_image +61 408 466 282 icon_widget_image info@berconsulting.com.au
Image Alt

BE&R Consulting

  /  Floating Production   /  Marine Fuel Oil To LNG Conversion

Marine Fuel Oil To LNG Conversion


The International Maritime Organization’s (IMO) Tier III regulations require ships to cut NOx emissions by 80% from the Tier I level within Emission Control Areas (ECAs) and follow a 0.5% cap on the sulphur content in fuel from 2020. Conventional heavy fuel oil (HFO) used by marine vessels contains 3.5% sulphur, meaning ship owners must either buy expensive low sulphur fuel or install SOx scrubbers to meet the cap.
Currently, the only way for ships with diesel engines to meet the 80% reduction in NOx emissions is to install selective catalytic reduction (SCR) units. These units will now be required in all ships with keel laying in the North American Emission Control Areas (ECA) in 2016 and in the North European ECA in 2021. But scrubbers and SCRs increase the cost of both building and operating ships. For instance, pumps require electricity, and sludge needs to be removed in port. In addition, SCR units require maintenance.
Interest in LNG as an alternate Marine fuel is growing around the world. Using LNG as a Marine fuel will have following environmental benefits:

  • A lower carbon content of LNG compared to traditional ship fuels enables a 20-25% reduction of carbon dioxide (CO2) emissions. Any slip of methane during bunkering or usage needs to be avoided to maintain this advantage.
  • Gas or dual-fuel engines running on gas have 25% lower CO2 emissions, while NO x emissions are 85% lower than for a diesel engine. This enables compliance with the IMO Tier III levels without the need for an SCR.


The main drivers for converting Fuel Oil marine engines to LNG are the significant emission reductions, the consequential reduced fees, and the reductions in fuel costs. For shipowners and charterers operating within ECAs, there are mainly three solutions available: low sulphur fuel (MDF), SOx scrubbers, or liquid natural gas (LNG).

The two bottlenecks for LNG use have been bunkering availability and price. There are barely more than 100 LNG-fuelled vessels, most operating in northern Europe. According to a recent report, (IMO MEPC 70/INF.6), the price spread between 0.5% sulphur fuel and 3% sulphur fuel is USD 130 per tonne, indicating that the payback time for SOx scrubbers will be short compared with running on 0.5% sulphur fuel. SOx scrubbers or LNG are likely to be more economical in new marine builds than running on low sulphur fuel, even though the building costs will be higher. 


Wartsila in 2018, conducted a cost comparison between SOx scrubbers and LNG machinery on Kamsarmax bulk carriers. It showed that the initial investment cost of an LNG system is significantly higher, mainly due to the cost of the fuel system. For the investment to be viable, operational costs must be lower than for SOx scrubbers. According to the study, for a Heavy Fuel Oil (HFO) price of 500 USD per tonne, it would be cheaper to operate on LNG given that the price is lower than USD 12.3 /mmBTU, assuming a payback period of ten years. The corresponding LNG price for 12.3 USD/mmBTU in tonnes is approximately USD 575 tonne, but the energy content of LNG is more than 20% greater than for conventional HFO. Taking the projected fuel prices into consideration, operation on LNG looks very attractive on a long-term basis.


A key factor in the success of a LNG conversion is finding enough space for storing the gas onboard the marine vessel. Gas storage in the form of LNG can be considered the most attractive alternative due to the high energy density of LNG and, therefore, the relative compactness of the storage required. Currently, LNG is also being developed for use in road vehicles with considerably less installed power, and it can be anticipated that LNG will increasingly dominate the marine market.

Daily gas consumption can easily be calculated based on the existing operating profile. In order not to incur unnecessarily high capital costs, the LNG storage tank should be kept as small as possible and instead more frequent bunkering intervals should be considered. The existing liquid fuel storage system would continue to work as a backup system if necessary.

The LNG storage location can be freely selected onboard the vessel and either vertical or horizontal tanks, on open deck or below deck, can be selected. When storage is above deck, the requirements set by the classification societies are slightly lower. Additionally, for the conversion, installation on an open deck is very straightforward, and some of the system ventilation requirements can be circumvented. The LNG storage tanks, and any additional steel structures may have an impact on the vessel’s stability. These marine vessel stability with new LNG tanks installed, LNG bunkering infrastructure, Small Scale LNG can be analysed in-house by BE&R as part of the initial feasibility study. 


Specific Fuel Oil Consumption is specified for different engine loads and fuels as specified by MANEnergy. 

A lower number of specific fuel consumption (SFC) means higher efficiency of engine. The control concept of the MANEnergy ME-GI engines comprises three different fuel modes:

  • The fuel-oil-only mode is well-known from the ME engine and in this mode, the engine operates on fuel oil only and the engine is considered to be “gas safe”.
  • The minimum fuel mode has been developed for gas operation. In this mode, the system controls the amount of gas fuel, combined with the use of a minimum preset amount of fuel oil (pilot oil) which is set at 5% approximately. Both heavy fuel oil and marine diesel oil can be used as pilot oil. The minimum pilot oil percentage is determined from 100% engine load. When the engine passes the lower load limit, the engine returns to fuel-oil-only mode. If a failure occurs in the gas system, this will result in a gas shutdown and a return to the fuel-oil only mode.
  • Specific fuel mode, where any mix of gas and fuel oil is possible.


A significant step in the process of LNG conversion is to check whether the existing marine engines onboard can be converted or if they should be exchanged for new dual-fuel (DF) engines. Converting an existing engine is recommended and is economically more feasible than installing new ones, especially when keeping in mind that a conversion basically brings the same benefits as new engines. For example, the same warranty is granted as for a brand-new engine, in addition to this there are also savings to be made on maintenance costs since the running hours are reset. However, with smaller generating sets, say below 2 MW, it might be more cost effective to install new engines. If the existing engines are not suitable for conversion, the only option is to replace them with new ones. When doing this one may need to replace the gearbox and some of the auxiliary equipment as well, should it prove that the capacity of the existing equipment is not enough.

Unless it is a question of replacing old engines with new ones, a DF-conversion will usually mean a lowering of the total output onboard. If the utilisation of the available power onboard is normally in the lower range, this is in most cases acceptable. In other cases, it may prove to be quite critical and has to be compensated for in some way, like for instance, omitting the use of shaft generators.

Another important consideration is the age of the installation. A DF conversion is a fairly large investment, and if the vessel is near the end of its service life, there is a big risk that a conversion would never pay itself back.


  • 12% – Surveys, engineering, project management, naval architecture & system   engineering integration
  • 31% – Installation work and material (Shipyard)
  • 6% – Automation and Control System
  • 31% – Fuel gas system (LNG storage, bunkering, process equipments)
  • 20% – Engine conversion and auxiliary system components


A case study performed by MAN and GL in 2012, concluded that the use of LNG as a ship fuel promises a lower emission level and given the right circumstances, lower fuel costs. A model was developed to predict costs and benefits for LNG systems, scrubbers and WHR systems on-board container vessels of various sizes. 

It was found out in the study that the attractiveness of LNG as ship fuel compared to scrubber systems was dominated by three parameters:

  • Investment costs for LNG tank system
  • Price difference between LNG and HFO
  • Share of operation inside ECA.

With a 65% ECA exposure, the LNG system payback time below 2 years is predicted for the smaller vessel sizes (using the standard fuel price scenario). For the 2,500 TEU vessel, a comparison of payback times for the scrubber and for the LNG system and varying LNG prices, shows that the LNG system is attractive as long as LNG (delivered to the ship) is as expensive as or cheaper than HFO when the fuels are compared on their energy content.

For larger vessels typically operating at smaller ECA shares, e.g. a 14,000 TEU vessel, the LNG system has the shortest payback time (using the standard fuel price scenario) and the use of a Waste heat recovery (WHR) system further reduces the payback time.

The price of LNG delivered to the ship is difficult to predict. Base LNG prices vary from the USA to Japan by a factor of four. European base LNG prices appear attractive at around 10 USD/mmBTU even with small-scale distribution costs added. It was found out that LNG price of up to 15 USD/mmBTU could give LNG systems a competitive advantage against scrubbers in terms of payback for the smaller vessels considered in the study.

Considering the still not widely available LNG supply infrastructure for ships, changes in LNG distribution costs are considered to affect the payback time for LNG systems. In general, the payback time for larger vessels with relatively larger LNG system costs depends strongly on the LNG price (delivered to the ship). At price parity of HFO and LNG, based on the energy content, the payback time for larger vessels is longer than 60 months.


A recent study is conducted by BE&R on to establishing small scale LNG facility in Port Hedland and to review potential LNG demand, bunkering infrastructure costs and economic viability for bunkering operations in Port Hedland. The part of the study is to understand if Port Hedland based LNG bunkering business servicing marine bulk ore carriers can be commercially viable and offer an internationally competitive service.

COST COMPARISON WITH CONVENTIONAL FUELS: Fuel costs per tonne of Iron Ore shipped have been compared for four different options as summarised below:

  • The comparison is based upon 8-month average for LNG and MGO bunkered in Singapore and Qingdao (China).
  • The LNG price at Port Hedland is based upon estimated project costs from the study with the addition of $1/mm BTU for Feed gas. Owner profit margin is excluded.
  • The Singapore option includes for the additional sailing distance via Singapore every second trip.
Bunker Fuel SourcePrice Per Tonne (US$)Fuel Cost per tonne of Iron Ore (US$)
LNG-Spot Market Price (Singapore)353 (*)N/A
LNG price at Port Hedland- 0.25MTPA LNG Plant Production Rate373$2.16
LNG Price at Port Hedland- 2MTPA LNG Plant Production Rate213$1.23

(*) Source: S&P Platts (Average from September to April 2020) 

A screenshot of a cell phone  Description automatically generated

   Source: SEA-LNG.ORG (January 2020)

Building block costs per train capacity (MTPA)
LNG PLANT CAPACITYUnits0.1250.250.51.0Comments / Assumptions
6000m3 capacity Bunker vesselUS$ million40Based upon a PSV Conversion of a 10-year old vessel
12000m3 capacity Bunker vesselUS$ million64Newbuild estimate
20000m3 capacity Bunker vesselUS$ million74Newbuild estimate

The study included various model options like different bulk ore carrier sizes, route profiles, on board LNG tank configurations, on site LNG storage, plant & jetty loading, LNG bunkering infrastructure.

It is concluded from the study that there could be enough demand for 0.5 MTPA LNG within 5 years which could grow to 1.0 to 2.0 MTPA by 2034 considering 15 years of bulk carrier’s life expectancy from vessel date of construction. A 2.0 MTPA LNG plant would support a fleet of LNG powered bulk carriers transporting 65% of the iron ore shipped from Port Hedland, with a potential fuel cost saving in excess of USD 1 billion pa. LNG plant 2.0 MTPA capacity LNG plant could deliver LNG at a cost of $2.93 per mmbtu. LNG bunker vessel size 6,000m3 LNG capacity can support a fleet of 60 bulk carriers each of 2500m3 capacity.


The key driver in the increasing interest in LNG as a marine fuel, on a global level is the increased focus on reducing emissions. For new marine builds today, IMO emissions legislation is a game changer. As the price of low sulphur fuels will most likely be high, LNG is an attractive option for marine fuel. LNG fuelled ships will be expensive to build, although costs continue to decrease as the technology becomes more mature. The increase in LNG supply will most likely mean lower LNG prices. The use of LNG as a fuel provides significant cost savings per tonnage of bulk carriers. Therefore, the use of LNG as fuel is appealing in the long term, even with the higher investment costs at initial stages considered. Proven gas engine technology, increased flexibility and cost optimisation are some of the factors for choosing four-stroke engine over two-stroke engines for LNG-fuelled.

DSME LNG-fuelled container ship