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Marin gas logistics
Work package 5
D5-1 The overall aspects of an LNG supply chain
with starting point at Kollsnes and alternative sources
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TABLE OF CONTENTS
1. Summary and conclusions.....................................................................................................4
2. Introduction ...........................................................................................................................5
3. Objectives ...........................................................................................................................5
4. Technical aspects by using LNG as bunker fuel .................................................................6 4.1 LNG availability and trade ...............................................................................................6
4.1.1 The product natural gas and the form of LNG..................................................6 4.1.2 Sources of LNG.................................................................................................8 4.1.3 The distinction of large scale LNG vs. small scale LNG................................10 4.1.4 LNG infrastructure in Norway ........................................................................10
4.2 Transportation and storage of LNG................................................................................12 4.2.1 General design of an LNG-terminal................................................................12 4.2.2 Background .....................................................................................................13 4.2.3 Storage tanks ...................................................................................................13 4.2.4 Filling line .......................................................................................................14 4.2.5 Quay ................................................................................................................14 4.2.6 Gasification unit ..............................................................................................15 4.2.7 Local transportation of LNG...........................................................................15 4.2.8 Terminal lay out ..............................................................................................15 4.2.9 Safety...............................................................................................................18
4.3 LNG/natural gas as ship fuel ..........................................................................................19 4.3.1 LNG characteristics.........................................................................................19 4.3.2 Exhaust emissions ...........................................................................................20 4.3.3 State of the art technology for gas engines .....................................................20 4.3.4 Alternative propulsion systems, mechanical vs. gas electric propulsion ........22 4.3.5 Fuel system......................................................................................................23 4.3.6 Safety system ..................................................................................................24 4.3.7 Rules and regulations ......................................................................................25
4.4 Conclusions – technical issues .......................................................................................25
5. Financial aspects ..................................................................................................................26 5.1 Building costs, gas fuelled ships ....................................................................................26
5.1.1 RORO-ship, gas related costs, /2/ ...................................................................26 5.1.2 ROPAX ship – gas related cost, /2/.................................................................27
5.2 Marine bunker fuel .........................................................................................................27 5.2.1 Future requirements to fuel qualities in SECA areas ......................................27
5.3 Marine Bunker Fuel and Natural gas properties ............................................................27 5.4 Historic price development ............................................................................................27
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5.5 LNG pricing ...................................................................................................................27 5.5.1 A formula for large scale LNG pricing ..........................................................27 5.5.2 European gas prices: What they represent and how they are observed ..........27 5.5.3 Price considerations for LNG supplied as ships’ fuel .....................................27 5.5.4 Determinants of the cost of supplying LNG: Overview .................................27 5.5.5 Market based gas price as a component of LNG costs for bunkering.............27 5.5.6 Supply logistics as a component of LNG costs for bunkering........................27 5.5.7 Indications of overall costs of LNG supplies ..................................................27 5.5.8 Small scale LNG pricing.................................................................................27
5.6 Economic evaluation ......................................................................................................27
6. Loading of LNG to a LNG feeder at a production plant .................................................27 6.1 Introduction ....................................................................................................................27 6.2 The LNG feeder “M/T Pioneer Knutsen” ......................................................................27 6.3 Loading procedure at Kollsnes LNG plant ....................................................................27
7. Transporting of LNG from Kollsnes and alternative origins to terminal ports ............27 7.1 Introduction ....................................................................................................................27 7.2 LNG availability in the Baltic and North Sea ................................................................27 7.3 Objective ........................................................................................................................27 7.4 Logistics possibilities .....................................................................................................27
7.4.1 Transport analysis model for LNG..................................................................27 7.4.2 Scenarios investigation....................................................................................27
7.5 Results .........................................................................................................................27 7.6 Comments to results .......................................................................................................27 7.7 Appendix 1 --- case results.............................................................................................27
8. References 27
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1. Summary and conclusions
This study is carried out under work package 5 of the Magalog project. The study looks into the overall aspects of a small scale LNG chain from a technical and economical point of view.
In the study some basic description and explanations of LNG as a common energy commodity is given, i.e. physical and chemical properties, production methods and common trading routes from a worldwide point of view. This is an important back ground for understanding the challenges and opportunities related to a small scale LNG distribution chain, and the possibilities to introduce LNG as an alternative bunker fuel for commercial short sea shipping. A key issue for introduction of LNG as a bunker fuel is the availability of LNG. This report shows an increasing number of LNG import terminals in Europe, and it can be concluded that LNG as an energy source are available throughout Europe and plans exist for new terminals in the Baltic area. LNG as a bunker fuel is already introduced in Norway and “the Norwegian way“ has been to establish a small scale production and distribution system to support the ships in concern. LNG can be transported either by small LNG ships or by truck from regional LNG production and/or storage terminals. No technological bottlenecks have been identified for these issues. One important factor for a potential customer in a small scale distribution chain is the security of supply. Today there are examples of business agreements between the Norwegian gas company Gasnor and a large import terminal in Spain, which secure a backup delivery of LNG in case of unforeseen incidents related to LNG deliveries. LNG is already introduced as ship fuel today. Several ships are operating on LNG as fuel in Norway. New engines are being developed and LNG storage systems are available from several companies. Rules and regulations have been developed by the classification societies and interim guidelines will be issued by IMO 2009. From the information provided in this report it can be concluded that that no obstacles has been identified for small scale distribution of LNG in Northern Europe from a technical point of view, and LNG is an alternative ship fuel in short sea shipping in the Baltic Sea and the North Sea. The main challenge is to supply LNG to the ship terminals at competitive prices to conventional fuels. The price structure of gas compared to bunker fuels indicates that competitive gas prices can be achieved at high crude oil prices (> 70 USD/Barrel), provided that the LNG logistic chain is well utilized.
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2. Introduction
Introduction of LNG as fuel for short sea shipping meets both technological and financial challenges. The supply of LNG at the customers bunkering station requires a well organized logistic chain which includes LNG production, storage and transportation. In this feasibility study these challenges have been further investigated from a technical and financial point of view. The work is carried out under Work package 5 (WP 5) of the MAGALOG project, and has been a cooperation between Gasnor and MARINTEK.
3. Objectives
This work package was aimed at analyzing the technical and economical aspect by using LNG as fuel in the Baltic Sea and setting the pace for future LNG supply logistics and logistic infrastructure.
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4. Technical aspects by using LNG as bunker fuel
4.1 LNG availability and trade
4.1.1 The product natural gas and the form of LNG
Liquefied natural gas (LNG) is produced by cooling down natural gas below its dew point. This occurs at a very low temperature – around -162°C. Methane usually accounts for about 85-95% of LNG, which may also contain other hydrocarbons such as ethane, a little propane and butane (natural gas liquids) and traces of nitrogen. LNG shares many of the properties of methane, being odourless, colourless, non-corrosive and non-toxic.
Liquefaction offers a unique solution for transporting natural gas located in areas far from a pipeline infrastructure. The volume occupied by liquefied natural gas at atmospheric pressure is about 614 times smaller than its gaseous state. This reduces the space needed to freight a given amount of energy. LNG is shipped in specially-built LNG carriers from the liquefaction plants to large LNG receiving terminals in buyer countries. Typical LNG carriers have a loading capacity from 145,000 to more than 200,000 cubic meters of LNG.
LNG is produced in a cooling process in a set of process units consisting of all equipment necessary to produce LNG from a natural gas feedstock and having a pre-determined design capacity. A simplified LNG production process is illustrated and described in Figure 4.1 and Figure 4.2.
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Figure 4.1 – Simplified LNG production process, ref: http://www.adgas.com/
Figure 4.2 – LNG process steps, /Ref.: The Oxford Princeton Programme, 2004/
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Main properties of LNG
LNG super cooled natural gas (liquefied natural gas)
Temperature: 162 OC
Main component : methane CH4 LNG density: 450 kg/m3 Gas phase density (15OC): 0.75 kg/Sm3 (air: 1.2 kg/m3) Explosion limit: 5 –15 vol % i air Ignition temperature: 595OC Min. ignition energy: 0.30 mJ LNG is a low viscosity, odorless, colorless no toxic liquid
LNG may be stored in insulated pressure tanks. Heat leaks into such tanks will increase evaporation which results in a pressure increase in the tank. The specific volume of LNG increases as it is heated. This demands extra tank volume where the LNG can expand, meaning that a tank cannot be filled 100%. The degree of filling varies between 90-95 % dependant on type of tank and application.
4.1.2 Sources of LNG
Today we see an increasing interest for LNG as a product and LNG is available throughout the world. The main trade routes for LNG (prognoses for 2010) are illustrated in Figure 4.3.
Figure 4.3 – LNG trade prognoses at 2010, /Ref.: The Oxford Princeton Programme, 2004/
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Also in the European market an increasing LNG import is observed. Main existing and planned European LNG import terminals is shown in Figure 4.4.
Figure 4.4 – LNG import terminals in Europe, ref. /King and Spalding/
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LNG availability is a key issue to supply the maritime market in the future. In the import terminals LNG is available in large quantities, and this may be utilized by further distribution to smaller regional storage plants and/or fuel bunkering station. The “Norwegian way” of utilizing LNG in a small scale distribution network is an example on how the LNG from the large import terminals can be used as a backup source for security of supply where the main logistics and supply is local production from smaller LNG plants.
4.1.3 The distinction of large scale LNG vs. small scale LNG
The description above is typical what could be defined as large scale LNG production and distribution, which include large production plants, large ships for LNG transportation and large LNG receiving and re-gasification plants. LNG is supplied to the energy market throughout the world. The MAGALOG project aim to look into alternative fuels for the maritime short sea shipping market, and within such a framework a small scale production and distribution of LNG may a feasible solution, which is the case in Norway.
4.1.4 LNG infrastructure in Norway
4.1.4.1 LNG availability in Norway
In Norway there are four small scale LNG liquefaction plants in three different locations with a total production capacity of approx. 155,000 tons/year (just above 200 million Sm3/year). The plants are listed below: Location/name Capacity (tonnes/yr) Owner/seller Start-up date
Tjeldbergodden 15,000 TLF/Statoil 1997
Snurrevarden 20,000 Gasnor 2003 Kollsnes I 40,000 Gasnor 2003 Kollsnes II 80,000 Gasnor 2007
Table 4.1 - LNG small scale liquefaction plants in Norway
In addition, Lyse/Skangass has recently started the construction of a facility with a production capacity of 300,000 tonnes/year (400 million Sm3/year) in Risavika outside Stavanger. The plant is expected to start operations in 2010. Large scale LNG production is also in operation at Melkøya with an annual export capacity of 4,1 million tons. A filling station for LNG distribution by semi-trailers at Melkøya will also be established, and LNG from Melkøya may also be utilized as bunker fuel. In June 2008 Gasnor has signed a contract with the Spanish energy company Iberdrola to buy LNG from their Huelva regasification plant. The LNG will be distributed with the new Gasnor
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cargo vessel “Coral Methane” with a capacity of 7,500 m3 that is expected to become in operation in the first half of 2009.The agreement is an example of the flexibility in the gas business, where a large scale import terminal shows its ability to meet the needs of small-sized clients as well as carrying out its larger-scale business in trading. The contract will allow Gasnor to meet increasing demand in Scandinavia/North Europe, which is exceeding production capacity at its three liquefaction plants on the west coast of Norway. The supplies from Iberdrola also represent a unique back up for own production, and thus help Gasnor meet supply contracts with its customers. LNG is distributed by ship or semi-trailers, or a combination of the two. So far, the only LNG ship operating in Norway is the 1,000 m3 Pioneer Knutsen. A new gas carrier, Coral Methane, will be in operation in early 2009 (a 7,500 m3 combination vessel). From 2010 additional one or two combined ships (10,000 m3) will be distributing volumes from the Risavika plant. With 14 vehicles, Gasnor has the largest fleet of LNG semi-trailers in Norway. Statoil and some of the local distribution companies also operate their own trailers. Today only three LNG bunkering stations have been established, and all of those are closed to Bergen. (i.e. Kolsnes production plant, CCB Ågotnes offshore base and Halhjem ferry quay) When the Risavika plant will be in production one additional bunkering station will be available, and ships operating from or passing through the Bergen-Stavanger coastline will have alternative bunkering facilities and LNG suppliers. The advantage of buying LNG close to the production plant is that no distribution cost is added to the fuel price, which of course is beneficial for the ship owner. For ships operating from other parts of the Norwegian cost line, special bunkering facilities have to be established. Smaller volumes can be distributed by truck from regional storage plants. For larger volumes which are likely from offshore supply bases, large ferry connections, etc., dedicated bunkering facilities should be established. For these cases, the LNG transportation and storage cost will be added to the gas price. To get competitive prices on the LNG a feasible transport chain is required. This means that the transport system should be optimized to utilize the ship capacity. This is s challenge in a start-up phase with only a few ships in operation. Hence, the bunkering terminals have to be established close to existing regional storage plants.
4.1.4.2 Regional LNG storage and distribution plants in Norway
The LNG infrastructure in Norway has developed rapidly the latest five-six years. Today more than 30 local and regional LNG storage plants are in operation covering the coast of Norway from Oslo to Bodø as shown in Figure 4.5.
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All the ship terminals can in principle be modified to become bunkering terminals at a relative small investment from a technical point of view. Assuming that there are no obstacles (commercial, capacities etc,) to modify these plants, one can conclude that LNG is available as bunkering fuel along most of the Norwegian coastline.
Figure 4.5 – LNG truck and ship terminals in Norway, 2008 (Source: Gasnor)
4.2 Transportation and storage of LNG
4.2.1 General design of an LNG-terminal
As a part of the MAGALOG project five harbours in the Baltic Sea area have been studied to investigate the possibilities to establish LNG bunkering terminals in these harbours. This section gives an introduction to the technical design for a small scale LNG terminal designed to supply natural gas as a fuel to ships.
LNG distribution in Norway
Truck terminals
Ship terminals
Source: Gasnor
LNG production plant
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4.2.2 Background
The most common way to transport natural gas is by pipelines, and in most countries in Europe there is a well established gas grid. This grid is in turn supplied with transmission pipelines from the gas fields. LNG (Liquefied Natural Gas) has been developed as a supplement to the gas grids for storage and transportation purposes. When natural gas is cooled below -160oC, the methane becomes liquid and are compressed 600 times compared with gas form. Thus LNG is a space efficient way to store and transport natural gas when pipelines are not a feasible solution. Norway is a country with deep fjords, high mountains and scattered population. This means that natural gas can not be distributed to the whole country by pipelines in a cost-effective way. As an answerer to this challenge there are developed a technology for small scale LNG distribution. This includes liquefaction plants for production of LNG, small scale LNG ships and road trucks for transportation, and dedicated end user LNG terminals for storage. The LNG distribution system was developed with industrial customers in mind, but this technology has also made it possible to make use of natural gas as a ship fuel in the form of LNG. Today there are several ships operating with LNG as fuel, and there are constructed several LNG terminal with the purpose of supplying ships with this fuel.
4.2.3 Storage tanks
For the storage of LNG there are used cylindrical pressurised tanks. Because of LNG’s low temperature they are built as double shell vessels with highly effective powder-vacuum or multi-layer-vacuum insulation, which ensures long time storage with limited vaporization. The tanks are produced in a variety of dimensions and capacities depending on the storage purpose. The storage
in a bunkering terminal for ships will consist of tanks with a capacity of 500 to 700m3 LNG. These tanks will have a length of about 35 meters and a diameter of about 5,5 meters. In a terminal the tanks are placed in series according to the storage capacity required. Terminals can also be
design so that capacity can be increased over time by adding storage tanks.
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4.2.4 Filling line
An insulated pipeline transports LNG between the storage tanks and the ship. The same pipeline is used for the supply of LNG from a LNG freighter to the terminal and the bunkering of a vessel from the terminal. Because the pipeline is transporting a cryogenic liquid the distance between the terminal and the quay should be as short as possible to minimize boil off. The range should preferably not exceed a maximum of about 250 meters. The pipeline between the quay and the terminal can be placed in an underground culvert and thus allow other activity in the quay area when not bunkering are taking place.
4.2.5 Quay
The quay in use must meet the requirement from the ship supplying the terminal with LNG and preferably also the ships calling at the harbour that is potential users of LNG as fuel. Generally the quay should have a water depth of 10 meters. One of the ships witch will supply LNG to the terminals are the Coral Methane. It has the capacity to transport 7500m3 LNG. The requirements of the ships that will be bunkering LNG must be considered in each case, specially the requirements of passenger ferries and freighters in fixed returning routes, but the quay should also be able to offer bunkering to normal freight vessels witch calls to obtain bunkering service. However, if there are potential users that can not access the quay, dedicated intermediate storage solutions could also be considered.
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The most feasible solution is to use existing quays so that investments in new quays can be avoided. The quay area can be used for other purposes when unloading or bunkering of LNG is not taking place. If an existing quay not can be used and new investments are necessary, a duc d'albe solution could be used instead of a full scale quay structure in order to reduce investments.
4.2.6 Gasification unit
When there are delivery of gas from the LNG-terminal into a gas grid or to a nearby gas customer, the LNG are heated and transformed from liquid to gas form. For the heating there are normally used air based evaporators. This is a stable an efficient way of heating the gas. Alternative solutions are the use of excess heat from industry if that is available nearby. Automation systems and pressure regulators ensure proper gas pressure and temperature in the downstream pipelines. The air based evaporators are operated in two alternating sets, with one set defrosting while the other is in operation. The size and number of evaporators depends on the output effect required from the terminal.
4.2.7 Local transportation of LNG
LNG can be transported from the terminal to ships elsewhere in the harbour, nearby industries or also other harbours in the region with LNG semi-trailers. The trailers have cryogenic tanks constructed after the same principles as the terminal storage tanks. Distribution of natural gas in the form of LNG on road trucks is well established in Norway, and is used to supply a range of industrial and other customers. The trucks in operation in Norway have a transport capacity of 50m3 LNG, but this can vary according to different national transport regulations. Not all shipping routes can call at a bunkering facility for the bunkering. For instance Ropax vessels, such as passenger ferries with daily crossings, will depend upon the bunkering taking place at the ferry terminal. There are established procedures for bunkering of ships directly from semi-trailers that are in operation on passenger ferries in Norway today. Another solution can be that LNG is stored at a smaller buffer tank dedicated for the ship in question, and that this buffer tank is supplied with trailer from the main terminal.
4.2.8 Terminal lay out
A standard LNG-terminal for bunkering purposes will have a lay out with five 700m3 tanks in series. The gross storage capacity will be 3500m3 LNG witch is equal to 2 millions Sm3 of natural gas or 20 GWh energy. The size of this installation will be about 50 by 50 meters. This standard lay-out will be adapted to local conditions such as capacity required, available area and the form
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of delivery from the terminal. There is also possible to prepare the terminal for increased capacity by preparing for installation of additional storage tanks. The terminal is built with all connections and valves in one side and, for safety purposes, there are built an accumulation pool in this end of the terminal. In the low probability of a leakage of LNG the liquid will be collected in this pool. There will be a safety zone of about 30 meters radius around accumulation pool. In this zone there will be restrictions on other activity that can involve ignition sources.
Figure 4.6 - Standard terminal lay-out with five 700m3 storage tanks.
From the terminal there is a pipeline connection to the filling point at the quay and there is a new safety zone around the filling point. There is also an evacuation zone of 100 meters around the terminal. This area will be evacuated in the case of an incident at the terminal.
50 meters
50 meters
Safety zone 30 meters
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Figure 4.7 - Terminal lay-out with pipeline and filling point at the quay.
If there will be deliveries of gas into the local gas grid or to a local on shore consumption the terminal design will include evaporators for the heating of LNG and transforming to gas. Further, if there will be a regional distribution of LNG, the terminal will be equipped with a filling station for LNG road trucks. Figure 4.8 shows a lay out of a terminal with air based evaporators and a filling station for road trucks.
Figure 4.8 - Terminal with evaporators and truck filling.
The technology in this terminal design is used in over 30 terminals in operation in Norway today. Storage capacity, services offered and lay out are design options that vary and will be adjusted to local conditions in each new case, but the main principles are the same.
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The picture shows an example of a standard terminal lay out in operation. This terminal is built in Mosjøen in Norway and the supply of LNG to the terminal is done by ship. The main purpose of this terminal is to supply natural gas to an aluminium plant located near by, but the terminal is also prepared for further regional distribution of LNG by road trucks.
4.2.9 Safety
LNG has been transported and used safely worldwide for roughly 40 years and the industry has an excellent safety record. In Norway there are today over 30 small scale LNG terminals in safe operation. The physical and chemical property of LNG determines the level of reliability and the hazards that are taken into consideration. LNG is odourless, non-toxic, non-corrosive and less dense than water. LNG vapours (primarily methane) are harder to ignite than other types of flammable liquid fuels. Above approximately -110
o
C LNG vapour is lighter than air. If LNG spills on the ground or on water and the vapour does not encounter an ignition source, it will warm, rise and dissipate into the atmosphere. Because of these properties, the potential hazards associated with LNG include heat from ignited LNG vapours and direct exposure of skin or equipment to a cryogenic (cold) substance. The handling of LNG is reliable and safe do to LNGs low temperature, high ignition temperature and narrow range of ignition concentration. Further the operations are conducted according high safety standards. The terminals are designed, built and operated according the standard CEN EN 1473 Installation and equipment for liquefied natural gas - Design of onshore installations, and the Council Directive 96/82/EC on the control of major-accident hazards involving dangerous substances.
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4.3 LNG/natural gas as ship fuel
4.3.1 LNG characteristics
LNG in the fuel tanks has to be evaporated before used as fuel. It is the gas phase with the main component methane that has to be mixed with air to be burned in an engine. Gas phase from LNG is an excellent basis for fuel in a ship engine as the content of heavier hydrocarbons is low. The Table 4.2 below shows different LNG qualities. The methane number is typically above 80 and thereby well suited for ship engine fuel.
Table 4.2 – LNG qualities
Figure 4.9 – Phase diagram of alternative LNG qualities
Characteristics for natural gas from LNG as ship fuel:
- High methane number means: o high power ratio with knocking margin
0
1 0
2 0
3 0
4 0
5 0
6 0
7 0
8 0
9 0
1 0 0
-1 8 0 -1 3 0 -8 0 -3 0
T e m p (°C )
Pre
ss
ure
(b
ara)
S nø hv it
K a rm ø y
K o lsnes
T j.odden
Z eebrügge
B rune i
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- Is easy to mix with air to a homogenous charge, burns with high flame velocity even at high air access. All in all beneficial for obtaining:
o high efficiency o no smoke/particulates o low NOx
- Contains no sulphur, meaning no SOx emission
4.3.2 Exhaust emissions
Natural gas is an excellent fuel for internal combustion engine. The combustion properties of natural gas make it possible to design gas fuelled engines with high efficiency and low exhaust emissions. Comparison of exhaust emissions of natural gas operation and MDO operation shows the differences in exhaust emissions from the two types of bunker fuel.
Figure 4.10 – Specific emissions from ship engines burning MDO or natural gas.
4.3.3 State of the art technology for gas engines
Two main natural gas engines concept are available. This is the Duel fuel (DF) gas engines and the spark ignited (SI) gas engine. Market leader in production of the DF engine is Wärtsilä Finland OY. The Wärtsilä 32DF and Wärtsilä 50DF are designed to operate on both gas and liquid fuel. These engines offer fuel flexibility together with high efficiency, low exhaust gas emissions and safe operation. Dual-fuel engines are capable of switching from one fuel to the other without interruption in
0
6
12
18
g/kWh
MDO 1% S natural gas
0
200
400
600
800
g/kWh
MDO 1% S natural gas
0
0,1
0,2
0,3
0,4
g/kWh
MDO 1% S natural gas
0
2
4
6
g/kWh
MDO 1% S natural gas
CO2
NOx
SO2
Particulates
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power generation. The engines operate on the lean-burn principle: the mixture of air and gas in the cylinder is lean, which means that there is more air than needed for complete combustion. Lean combustion increases efficiency and reduces NOx emissions. Higher output is reached while avoiding knocking or pre-ignition. The NOx emissions of Wärtsilä DF engines in gas operation are approximately 1/10th of those of a standard engine while the CO2 emissions are also low due to the clean gas fuel burned and the high efficiency of the engine.
Dual-fuel engines
Wärtsilä 32DF (2,010 - 6,300 kW)
Wärtsilä 50DF (5,700 - 17,100 kW)
Table 4.3 – Wärtsilä Duel Fuel engines /ref Wärtsilä/
Wärtsilä 32DF (2,010 - 6,300 kW)
The Wärtsilä 32DF engine was developed to set new standards in the market for high-performance, fuel-flexible engines. It is a four-stroke dual-fuel engine that can be run on either natural gas or light fuel oil (LFO). Transfer from one fuel to the other can be made under all operating conditions. The Wärtsilä 32DF is a technically advanced engine for fuel economy and low emission rates. NOx emissions from the Wärtsilä 32DF are extremely low, complying with the most stringent of existing environmental regulations.
Wärtsilä 50DF (5,700 - 17,100 kW) The Wärtsilä 50DF is a four-stroke dual-fuel engine. It can be run on natural gas or light fuel oil (LFO) or alternatively heavy fuel oil (HFO). The engine can smoothly switch between fuels during engine operation and is designed to give the same output regardless of the fuel.
The engine operates on the lean-burn principle. Lean combustion increases engine efficiency by raising the compression ratio and reducing peak temperatures, and therefore also reducing NOx emissions. Both the gas admission and pilot fuel injection are electronically controlled. The engine functions are controlled by an advanced automation system that allows optimum running conditions to be set independent of the ambient conditions or fuel. Wärtsilä Corporation has enhancing the fuel flexibility of its Wärtsilä 50DF dual-fuel engine by offering the possibility to use heavy fuel oil (HFO) in the ‘diesel mode’, and they have introduced double-wall gas piping on the Wärtsilä 50DF dual-fuel engine to simplify the engine room installation and reduce costs.
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Wärtsilä dual-fuel engines have been installed in LNG carriers and on board two FPSOs. Furthermore, the offshore supply vessels Viking Energy and Stril Pioner are equipped with dual-fuel-electric machinery installations and use LNG as fuel. Furthermore more than 23 dual-fuel engines are in service or on order in land-based power plants. (ref. Wärtsilä, October 2006).
SI Engine The lean-burn gas engines(SG) from Wärtsilä feature port admission of gas, prechamber with controlled gas flow as well as individual cylinder control of gas charge and ignition timing. This choice of concept along with extensive research in combustion and combustion control has made it possible to elevate the efficiency from 40% to more than 45% in the bigger engine models. The Wärtsilä 34SG engine has the lean-burn technology and a cylinder configuration from 12 to 20V34SG. The engine is today not available for marine application. The Rolls Royce Bergen KVGS spark-ignited, lean-burn gas engine is installed in more than 150 power plants throughout the world. The lean-burn principle of the engine operation is unique in its combination of high power and high efficiency coupled with reduced exhaust emission. The KVGS engine is being developed for marine application and a total of 16 engines are in operations from 2007 on five Norwegian ferries.
In-line Vee design Output (kW)
Propulsion 6, 8 & 9 cyl 12, 16 & 18 cyl 1215 - 4010
Generator sets
5, 6, 8 & 9 cyl 12, 16 & 18 cyl 885 - 3975
Lean-burn gas engine
6, 8 & 9 cyl 12, 16 & 18 cyl 1053 - 3600
Table 4.4 –K-engines from Rolls Royce Bergen, /Ref: Rolls Royce Marine/
4.3.4 Alternative propulsion systems, mechanical vs. gas electric propulsion
All natural gas powered ships which have been built until 2008 have been design with a gas-electric propulsion plant, (i.e. diesel-electric concept for conventional (non-natural gas) vessels). This concept causes the combustion engines to always operate on a fixed engine speed (rpm) generating electric power at 50 or 60 Hz. It should be noted that this simplifies the regulation of the combustion engine as the engine speed (rpm) shall always remain constant to supply electric power at 50 or 60 Hz. For a diesel-mechanical concept, which is used for most ships today, the engines will have to alter the engine speed (rpm) to achieve the vessel target speed at any time. In a diesel – mechanical (or gas-mechanical) configuration there are dedicated combustion engines providing propulsion
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power to propellers via reduction gears and shaft lines. In addition there are separate auxiliary engines generating electric power to other onboard consumers. A gas-mechanical concept is today under development, and will be available from Wärtsilä and Rolls Royce Marine in 2010/2011.
4.3.5 Fuel system
The fuel system for an LNG fuelled ship is characterized by using large vacuum insulated storage tanks operating at a pressure of app.10 bar. The following systems and/or components are required in a LNG storage system: LNG tank- and bunkering system LNG evaporation system Trim heating system Gas detection system Remote control and monitoring system Ventilation and nitrogen purging system
So far only some 10 gas fuelled ships have been put into operation, and the gas fuelling system has been supplied as a turn key system. Only a few suppliers have been in the market so far, which results in a relatively high price tag on this system. During the last year, new suppliers have flagged their interest for this market, which will result in increased competition and presumably lower unit costs for the gas fuelling system. At the end this will benefit the gas fuelled ship concept. A schematic layout of a LNG system is shown in Figure 4.11.
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Figure 4.11 – Schematic drawing of LNG storage and bunkering system, /Wärtsilä/.
4.3.6 Safety system
The safety of the gas systems on board is of vital importance. This includes all onboard gas systems, including connected piping, ventilation, re-fueling stations, etc. Introduction of LNG as fuel on board shall not influence of the safety level of the ship compared to a conventional design with traditional bunker fuel on board. International and national rules, regulations and guidelines have been developed to secure that gas fuelled ships are being build to the highest safety standard. The IMO’s “Interim guidelines on safety for natural gas-fuelled engine installations in ships” allows for two different design principles for configuration of the machinery spaces when it deals with safety.
These two alternative system configurations are described as follows: 1 Gas safe machinery spaces (inherently safe design): Arrangements in machinery spaces
are such that the spaces are considered gas safe under all conditions, normal as well as abnormal conditions, i.e. inherently gas safe.
2 ESD-protected machinery spaces (ESD design): Arrangements in machinery spaces are
such that the spaces are considered non-hazardous under normal conditions, but under certain abnormal conditions may have the potential to become hazardous. In the event of abnormal conditions involving gas hazards, emergency shutdown (ESD) of non-safe
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equipment (ignition sources) and machinery is to be automatically executed while equipment or machinery in use or active during these conditions are to be of a certified safe type.
Inherently safe main engines are to day being developed by major engine manufacturers, and this seems to be a cost efficient design, which reduces the overall investment cost on a gas fuelled ship compared to the ESD design.
4.3.7 Rules and regulations
4.3.7.1 International regulations
Norway started the process in IMO to develop international regulations in 2005, and a draft IMO guideline was proposed in 2007, which is a somewhat simpler version of similar Norwegian rules. These are being considered for worldwide application through an IMO resolution, and according to normal IMO practice the next step will be issuing guidelines for approving gas as a fuel, expected in 2009. These guidelines are already circulated among IMO member states and are thus known and available for all relevant national administrations in Europe and the world to consider. Other than this the use of gas as fuel (in ships other than LNG carriers which are covered by IGC code) is not covered by international conventions and such installations will therefore need additional acceptance by flag authorities. However, it is not foresee any problems operating such a gas fuelled ship in northern Europe or Europe as a whole since it is expected that relevant flag administrations will give necessary permits based upon the IMO guidelines and/or national rules.
4.3.7.2 Classification rules
Classification societies do have applicable rules and regulations for approving the construction of this vessel. (DnV; Class notation GAS FUELLED, Pt. 6. Ch .13, others societies are also developing rules.)
4.4 Conclusions – technical issues
More than ten gas fuelled ships are already in operation, and several new gas-fuelled ships are under construction. LNG has proven to be a feasible fuel for these projects. Gas storage systems and gas fuelled engines are available from major suppliers. From a technical point of view, an LNG fuelled ship can be built on commercial conditions, and no technical obstacles are identified.
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5. Financial aspects
An LNG fuelled ship is more expensive to build than a conventional ship of the same type. The extra investment cost incurred for a new-building, has to be compensated by lower operation cost to make natural gas as fuel interesting form a commercial point of view. In this chapter typical ship types which operate in the Baltic- and the North Sea has been used as case ships to investigate the feasibility of natural gas as fuel from an economic point of view. Also other aspects related to the development of future fuels are discussed.
5.1 Building costs, gas fuelled ships
Additional cost is added to a gas fuelled ship compared to a traditional fuelled ship using heavy fuel oil (HFO) or marine diesel oil (MDO). The extra cost is related to the following main components/systems:
Fuel storage tank
Gas engine
Safety systems
Approval
5.1.1 RORO-ship, gas related costs, /2/
Studies carried out at MARINTEK show an additional cost for a gas fuelled ship of 10-15% of the total cost of a conventional ship. For a typical RORO ship of 5600 DWT and L= 130 m with installed main engine power of 7 MW, the additional costs for an LNG fuelled ship is approximately 3,2 million €. A typical cost distribution is shown in Table 5.1.
Component and system [Euro]
Cost RORO Base case
(HFO engine)
Cost RORO (DF engine)*
Main engines and auxiliaries 1 600 000
2 700 000
Fuel System and bunkering 360 000
2 200 000
Other systems 300 000
SUM, Euro 1 960 000 5 200 000
Delta price, HFO-DF gas engine
Investment cost increase HFO-gas, €
3 240 000
*Duel Fuel engine
Table 5.1 – Investment costs for alternative machinery systems in RORO ship. Prices are collected in the period: January-June 2007. Exchange rate: USD= 5,4 NOK, €= 8,0 NOK
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For the analysis and benchmarking of the alternative systems with natural gas as fuel the return on investments required for the extra investments for gas operation is the main criteria. Required extra cost compared to the conventional ship is shown in Table 5.1 Prices presented in Table 5.1 are estimates based on discussions with suppliers of gas bunkering and storage systems and on purchase prices based on inquiries to suppliers of main engines and auxiliaries. As can be seen, price estimates for HFO operation are given as reference, and this is compared to the price increase of the gas powered concept.
5.1.2 ROPAX ship – gas related cost, /2/
A typical ROPAX ship operating in regular routes in between North European ports is used as case ship to estimate additional cost for a gas fuelled ROPAX ship. Main particulars, ROPAX ship:
LOA: 210 m
B: 26 m
D: 6,5 m
DWT: 6000 t
Gross tonnage: 35000 t
To estimate the investment cost for a mechanical HFO diesel engine and DF gas engine information is based on price estimate from Wärtsilä and Aker Yards. Based on this information the specific engine cost (€/kW) has been used to estimate the required investment increase for a DF engine assuming that the same power range is available for the various engine types.
Component and system [Euro]
Cost RORO Base case
(HFO engine)
Cost RORO (DF engine)*
Main engines and auxiliaries, (total power 48 MW)
15 700 000
18 000 000
LNG-related components, bunkering, etc (500m3 LNG storage)
0
3 500 000
SUM, Euro 15 700 000 21 500 000
Delta price, HFO-DF gas engine
Investment cost increase HFO-gas, €
5 800 000
Table 5.2 – Investment costs for alternative machinery systems in ROPAX ship. Prices date reference: June-October 2007. Exchange rate: USD= 5,4 NOK, €= 8,0 NOK
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Additional investment for a DF machinery plant is approximately 36% higher than a HFO plant. This will increase the total ship price with some 10%.
5.2 Marine bunker fuel
5.2.1 Future requirements to fuel qualities in SECA areas
In April 2008 revision of IMO MARPOL Annex VI was approved at MEPC 57. New requirements to fuel qualities in SECA areas imply stricter emission limits for NOx- and SOx- emissions from ships. As can be seen from Figure 5.1 the global cap of SOx is reduced from 3,5% to 0,5% effective from 2020. This will probably mean that it is not possible to meet these limits with use of heavy fuel oil (HFO). There is an opening to employ SOx scrubbing techniques.
20082009
20102011
2012201
32014
20152016
20172018
20192020
20212022
20232024
2025
0
0,5
1
1,5
2
2,5
3
3,5
4
4,5
5
SO
x[%
]
Year
IMO Sulphur Reduction
ECA Limit
Global limit
Figure 5.1 - New global limitation of sulphur oxides (SOx) and limitation of SOx in emission control areas (ECA)
Within the ECA (emission control area) the limit of SOx is reduced to 0,1% and this should be combined with a reduction of NOx by 80% compared to today’s level, see Figure 5.2, effective from 2016. This means that HFO will not be possible to use in the ECA’s which will among others be Baltic Sea, North Sea and most of the European waters. To meet such strict limitations in the ECA’s ships has to use low sulphur distillates with NOx exhaust gas cleaning technique (SCR) or switch to LNG as fuel.
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Figure 5.2 - New IMO limitation of NOx. Tier II is a global cap of 20% reduction from today’s level and Tier III means a 80% reduction form today’s level. Tier III will be in force from 2016 in Emission Control Areas (ECA)
The implication of these stricter emissions limits will firstly increase the demand of low sulphur distillates fuel and hence higher fuel price. Ships operating in the ECA’s need to employ NOx exhaust cleaning devices which adds to capital and operation cost. Both increased fuel price and added operation costs due to exhaust cleaning, will be in favor for LNG as fuel.
5.3 Marine Bunker Fuel and Natural gas properties
Price comparison of the various fuels should be on energy basis. Table 5.3 shows the fuel properties for the various fuels in concern.
Bunker Fuel Data* Viscosity v/50°C
Viscosity v/40° C
Density v/15°C
Lower heating value
Lower heating value
Sulphur content
cSt cSt kg/m3 kJ/kg kJ/liter % weight % weight
Max Average Average Average Average Max Marine Gas oil 2,5 3 845 43060 36386 0,10 0,20 "Marine Special
Distillate" 7,3 9,6 870 42710 37158 0,22 0,24
MFO30 30 N/A 933 41630 38841 0,6 0,7 MFO180 180 N/A 968 41000 39688 0,8 1,0 MFO120 120 N/A 955 41430 39566 0,7 0,75 MFO 240 240 N/A 970 41220 39983 0,7 1,00
kg/Sm3 kJ/kg MJ/Sm3
Natural gas ** N/A N/A 0,735 49300 36,3 0 0 * Shell: http://www.shell.com/home/content2/no-no/shell_for_businesses/industri/drivstoff.html ** NVE – Norges vassdrag og Energidirektorat: http://webb2.nve.no/
Table 5.3 – Properties of bunker fuels, crude oil and natural gas
NOx Emission limits IMO
0
2
4
6
8
10
12
14
16
18
0 250 500 750 1000 1250 1500 1750 2000 2250 2500
Speed [RPM]
NO
x [
g/k
Wh
]
Tier I 2000
Tier II 2011
Tier III 2016
ECA limits in 2016
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5.4 Historic price development
Price development on bunker fuel has shown a strong increase from 2004 as shown in Figure 5.3.
Figure 5.3 – Spot price development on bunker fuels in Rotterdam, 1980-2007 /Ref.: OPEC/
5.5 LNG pricing
Natural gas as bunker fuel is today not common and there is no traditional commercial price mechanism for natural gas as bunker fuel. For ships in operation in Norway the gas price is agreed between the gas company and the ship owners on individual basis in separate contracts. However, based on international bunker prices, expected natural gas prices can be estimated. The correlation between crude and bunker oil prices can be expressed by analysing historical data of the prices of these products. The same correlations to crude oil prices can be obtained for LNG pricing, but formulas for LNG pricing will vary from one region to another.
5.5.1 A formula for large scale LNG pricing 1
Information in this section discusses relevant LNG pricing for import to the NZ market. Pricing of LNG in the world varies by region:
(East) Asia imports are based on formulae linked to oil prices, specifically, linked to a basket of crudes referred to as the Japanese Crude Cocktail (JCC). Except for China where
1 A Formula for LNG Pricing, Gary Eng, Independent Consultant. A report prepared for the Ministry of Economic Development, NZ, May 2006
Spot refined products prices in Rotterdam, 1980-2007
0,00
20,00
40,00
60,00
80,00
100,00
1980 1984 1988 1992 1996 2000 2004Year
US
D/b
arre
l
Gasoil 0.2%Sulfur Fuel Oil 3.5% SulfurSource: OPEC
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LNG imports have just commenced, imports do not face competition from either indigenous supplies of natural gas or imports via pipeline.
LNG imports into Europe are also generally linked to oil prices (Brent) but prices are more diverse as they have to compete with pipeline imports and indigenous supplies in many countries.
The USA is a (re-)emerging market for LNG as stable to falling supplies of indigenous natural gas and imports from Canada along with increasing demand need to be supplemented by imports of LNG. The USA has the most dynamic natural gas markets in the world. Most of the LNG imported is being sourced through spot and short-term contracts and are priced accordingly.
To understand the pricing mechanism in one market, awareness of the other markets is useful for understanding how pricing methods may develop or change over time. The general form of the Asian formula is: P(LNG) = ax + b (1) where x is the price of a basket of crudes imported into Japan, the JCC (Japanese Crude Cocktail). Although not as easy to follow as other benchmark crudes such as WTI or Brent, it is a public domain price. More conveniently, US$JCC ~ US$WTI – US$1,00 per barrel. (2) a and b are negotiated slope and intercept respectively, specific to each contract. There are usually less linear tails in a formula, resulting in an “S” curve to mitigate for price extremes, effectively providing for floors and caps on the price. There are also specific “meet & discuss” clauses in any contract to take account of unusual or unanticipated conditions or situations. China’s first LNG project in Guangdong province is generally regarded as having obtained a precedent-setting pricing basis in 2002. The formula provides for lower prices and a weaker linkage to oil prices than in previous contracts. An estimate of the pricing formula is: P(LNGcif ) = 0,052JCC + 2,1133 US$ per mmBTU2 (3) This is in contrast to a more “traditional” formula (4) that is applicable to most of Japan’s imports, a pricing basis that can be assumed to be broadly applicable to contracts in Asia signed prior to 2002. P(LNGcif ) = 0,1226JCC + 1,2367 US$ per mmBTU (4) (3) and (4) are illustrated in the Figure 5.4 below. 2 mmBTU= million British Thermal unit, (1 mmBTU~293 kWh~1,055 GJ (Giga Joule))
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Source: Asia-Pacific Energy Research Centre, 2005. China data estimated by PetroStrategies; Japan LNG prices from IEA Energy Prices and Taxes, JCC prices from EDMC, Institute of Energy Economics of Japan.
Figure 5.4 - LNG Pricing Formulae – fitted /1/
Not surprisingly, neither contract formulae nor specific contract prices are generally available in the public domain. Figure 5.5 below extends the formulae beyond the data that was used to fit the regressions, incorporating a range of oil prices that have prevailed in the last year or so. One recent set of contracts for which there was a range of prices disclosed was for South Korea. For a tranche of 5 million tonnes pa (~250 PJ3, around 3.5% of world LNG consumption and 23% of current Korean consumption), a price range of US$197 – 217 per tonne (US$3.79 – 4.17 per mmBTU, US$3.59 – 3.95 per GJ) at an oil price of US$40 per barrel was agreed upon. This is significantly lower than the US$322 per tonne price under their existing contracts. Both the old and new prices reported for South Korea are well within the range that can be derived from the two above formulae, as is shown (by the 3 markers) in Figure 5.5 below.
3 petajoule (PJ = 1015 J)
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Figure 5.5 - LNG Pricing Formulae – extrapolated values
The above analysis uses a CIF pricing basis, as this has historically been the most common arrangement. The CIF component of (3) is possibly in the region of US$ 0,40. Assuming that NZ will source its LNG from Australia (not a certainty), shipping distances are not too different than for China’s Guangdong project which is sourcing its LNG from the North-West Shelf. That is, (3) is a reasonable formula for New Zealand on a CIF basis. Points to note:
The assessment is that LNG markets have moved from a recent small window of a buyers’ market back towards more of a sellers’ market. Hence, the “new” formula probably represents a sensible lower bound.
The “old” formula would appear to be an upper bound under any circumstances. Importantly, the “new” formula applies for contracts that have just or are yet to come into
force, with Guangdong having just received its first shipment and the new Korean contracts not due to begin supply until 2008. Although average contract lengths are declining, these contracts are typically for terms of 10-20 years.
LNG contracts are becoming more diverse, flexible and generally more attuned to the needs of the customer. For example, destination clauses, that are part of CIF contracts, are becoming less common.
Accordingly, FoB contracts are becoming more common. With a FoB contract, the buyer takes ownership of a cargo once it is loaded, effectively allowing the cargo to be redirected or resold should that suit the circumstances of the buyer.
Albeit small at around 10%of the overall market, the share of the spot market vis-à-vis the long contracted market is increasing. LNG markets will become more liquid and commoditised into the future. However, this will not be to the extent of oil markets.
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5.5.2 European gas prices: What they represent and how they are observed
Globally, the market prices for natural gas are much less uniform and less transparent than the market prices for crude oil. The pricing of natural gas across the world is fragmented, can have large differences in price between different locations and contracts, and is readily observable only in parts. Some short-term trade prices for European natural gas are readily observable, both from the ICE futures exchange in London and as price assessments of physical trade.4 Short-term prices are recorded for next-day deliveries and for specified future periods, with an emphasis on deliveries during the next month.
The readily observable, short term gas prices have the limitation of not reflecting the majority of border-crossing gas trade in Europe, which occurs under long term contracts with price indexation to oil products. Viviés (2003) found that only 5% to 10% of gas requirements in Continental Europe may be covered by short term trading arrangements. The corresponding figure for the UK may be higher. Long term gas contract prices are generally not published. Certain published sources are sometimes referred as approximations of long term natural gas contract prices. This includes monthly price and volume statistics for German imported natural gas published by a German ministry (Bundesministerium für Wirtschaft und Technologie, www.bmwi.de), and average gas sales prices obtained by StatoilHydro for mainly long term sales of Norwegian gas, and reported in the firm’s quarterly reports (Figure 5.6). These prices represent border-crossing intra-European trade in natural gas. Figure 5.6 shows a comparison of short-term UK and US gas prices and the StatoilHydro average prices, in which the latter may serve as an indicator of long term sales prices. The long term prices are linked mainly to gas oil and heavy fuel oil, but with a time lag of a few months. The long term contract prices exhibit less volatility than the short term prices, as evidenced particularly in 2005/2006 when there were sharp price spikes in US gas prices caused by destructive hurricanes and in European gas prices caused by concerns over Russian gas exports. Such gas-specific events hardly affect the long term gas prices at all.
4 Previous day futures prices for UK natural gas can be viewed for free at www.theice.com . Trade in Brent crude oil and several other energy commodities are also found here. Daily price assessments from Platts, Argus and Heren for gas deliveries in the UK, Zeebrugge and certain other locations are available as subscriptions. Historical price series can also be procured at a cost.
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Comparison of natural gas prices, € per MWh
-
10
20
30
40
50
60
jan.03 jan.04 jan.05 jan.06 jan.07 jan.08
€ / MWh (gcv)
Natural gas NYMEX 1st month
Natural gas ICE 1st month
Natural gas StatoilHydro sales
Figure 5.6 - Monthly averages of natural gas prices for next-month delivery on the Henry Hub, USA
(NYMEX) and the UK (ICE). StatoilHydro reported quarterly average gas prices for mainly long term contracts. Converted to € per MWh gross calorific value. Sources: NYMEX, ICE, StatoilHydro.
The typical format of a modern gas contract price formula is as follows:
Pn = P0 + cG wG (Gm-G0) + cF wF (Fm-F0) where Pn is the gas price to be paid for period n ; P0 is the gas price agreed at the outset of the contract; cG and cF are conversion factors for converting the quoted price units of gas oil and fuel oil to
natural gas equivalents by energy content; wG and wF are relative weights given to gas oil and fuel oil in the indexation, defined so that
wG + wF = 1; Gm and Fm are price assessments observed for gas oil and fuel oil for the period m, which is
often an average for several months prior to period n so as to produce a time-lagged oil indexed pricing;
G0 and F0 are the prices for gas oil and fuel oil determined at the outset of the contract. A survey by the European Commission – Competition DG (2007) found that long term gas import contracts in the European Union were, on volume weighted average in 2004, linked 44.8% to gas oil, 29.5% to heavy fuel oil, 9.8% to reported short term natural gas prices, 7.4% linked to other energy prices and 8.5% on fixed prices or indexed to general inflation.
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Figure 5.7 shows a comparison of prices for European gas oil, heavy fuel oil and natural gas, the latter represented by the StatoilHydro prices mentioned above. By this measure, natural gas prices have typically been 55% - 60% of gas oil prices, and near parity with heavy low-sulphur fuel oil on energy basis5, but with large variations especially in times of oil market turbulence due to the lagged indexation of gas prices to oil prices.
International energy prices, € per MWh
-
10
20
30
40
50
60
70
jan.03 jan.04 jan.05 jan.06 jan.07 jan.08
€ / MWh (gcv)
Natural gas StatoilHydro sales
Gasoil ICE 1st month
Fuel oil ARA spot
Figure 5.7 - Monthly averages of prices for European gasoil, low sulphur heavy fuel oil and natural
gas. Converted to € per MWh gross calorific value. Sources: EIA, ICE, StatoilHydro.
The prevailing long term approach to trading described above for European natural gas, applies similarly to world wide trade in LNG, including European imports. LNG deliveries on large (>100.000m3) ships typically operate under 20+ year contracts. Over the past 10 years expectations of a shift towards more short-term LNG trade have frequently been heard. There has indeed been some increase in the frequency of LNG spot trades (each such trade typically covering one ship cargo), but global LNG trade remains predominantly driven by long term agreements. European LNG import contract price formulae are not officially published, but may be widely known within the industry. They also tend to be indexed to oil prices, though often to crude oil rather than refined oil products.
5 The comparisons between gas prices and petroleum fuels prices are made on the basis of gross calorific value (GCV). For a given quantity of fuel, the net calorific value (NCV) is about 5% lower for heavy fuel oil, 6% lower for gasoil and 10% lower for natural gas.
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Figure 5.8 - Comparison of European long-term gas contract prices, 2002-2004. Source: CRE (2004)
quoting data from Heren.
Figure 5.8 shows a comparison of European contracted gas prices from different sources, with Algerian LNG often indicated at a somewhat higher price level than pipeline bound contracts. The market information services6 issue regular reports on the global LNG markets, but spot deals are too few and far between to provide a basis for regular and reliable market price assessments. If and when cargo trade in small scale LNG becomes common at some future time, a distinct market with observable prices for such trade may emerge. Prices for small LNG cargoes in Northern Europe may then deviate from pipeline gas prices to some extent, for both short and long term contracts. Small cargo prices are likely to be higher than pipeline gas prices for most of the time, at least on a delivered basis.7 A somewhat similar phenomenon of differentiated price formation depending on delivery mode and cargo size can be observed in the North European market for liquid petroleum gases (LPG).
5.5.3 Price considerations for LNG supplied as ships’ fuel
In a framework of long term contracting for LNG for bunkering, the price of LNG would be specified in the contract. The agreed price must be commercially sustainable for buyer as well as seller, which entails two requirements: - The use of LNG should not weaken the ship owner’s competitive position relative to using
another fuel; - The LNG seller should be able to recover his cost of supplying it. The challenge in developing and contracting for LNG supplies will be to establish contractual terms which will meet both these requirements simultaneously. The following sections review the factors that influence the cost of supplying LNG, i.e. the second requirement above.
6 Platts, ICIS Heren. Petroleum Argus 7 A somewhat similar phenomenon of differentiated price formation depending on delivery mode and cargo size can be observed in the North European market for liquid petroleum gases (LPG), also reflected in regular price assessment by the market information services.
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It is common in long term sales and purchase contracts to link the contract price as a formula to other observable prices that have a relevance for the parties, for instance prices of crude oil, gas oil or heavy fuel oil as quoted by Platts8. Such price linkages serve to prevent the price under a long term contract from becoming entirely divorced from market realities, which would tend to impose strains on the contractual relationship. There are several ways in which a price formula in a long term LNG supply contract can be structured. In many cases, the long term buyer tends to seek an assurance that LNG will not become uncompetitive against traditional fuels to which LNG is seen as an alternative. If the MARPOL requirements can be met alternatively by using gas oil or LNG, then this would point towards linking the LNG contract price to reported prices for gas oil of a relevant quality. Platts’ price assessments for gas oil deliveries in North West Europe may be a relevant reference. In some cases an LNG buyer may desire a long term fixed price, i.e. avoiding a formula that will cause the price of LNG to increase or decrease with oil prices. It is suggested that this may be achieved by still linking the LNG price to oil prices in the long term contract, while the buyer desiring a different price structure may obtain this by making additional agreements for price risk management. This can be done either by trading directly in futures markets or with financial firms which can provide such arrangements.
5.5.4 Determinants of the cost of supplying LNG: Overview
It can be assumed that suppliers of LNG for bunkering will not be original producers of natural gas, but will procure natural gas or LNG at an established point of supply, and undertake the logistical tasks of making it available as LNG for ships as described above. The cost of supplying LNG then has two main components:
Cost of LNG supply = Market based gas price + Cost of supply logistics Supplies can be obtained from two alternative or supplementary sources; large scale and small scale LNG, with significantly different cost structures. The two main cost components indicated above will be reviewed in the two following sections, based primarily on a small scale supply system (which is already established for similar purposes) but discussing also the possible implications of moving towards supplies from large scale systems, which is a possible future development. Unit costs of supplying LNG are stated below in Euro (€) per MWh, where MWh refers to the energy content of the LNG as gross calorific value (GCV). One tonne of LNG contains approximately 15.1 MWh as gross calorific value.
8 Platts is an information service that provides daily assessments of market prices for a wide range of spot traded products, www.platts.com. Similar services are provided by Petroleum Argus (www.argusonline.com) and ICIS Heren (www.heren.com).
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5.5.5 Market based gas price as a component of LNG costs for bunkering
Small scale producers of LNG in Norway procure natural gas which has been produced at offshore Norwegian fields and landed near a gas processing facility on the Norwegian coast. This gas would otherwise be transported by pipeline to the European continent or UK in order to enter the European pipeline-bound gas market. The price at which natural gas can be purchased for the purpose of small scale LNG production and ultimately for bunkering purposes, will therefore be related to European gas market prices, with a possible discount related to the avoidance of pipeline transport from Norway to the continental or UK markets. If LNG will in the future be purchased at major European import terminal(s) to be supplied as ships’ bunker fuel, then this purchase price is also likely to be related to the European gas market prices. This is because LNG imported to Europe is generally supplied to the European pipeline-bound gas market. In practice therefore, LNG arriving at North European terminals can be assumed to have a market value similar to other natural gas in the region, irrespective of the price at which it is procured from producers overseas. In either case, the long-term prices are more relevant than short-term prices because LNG bunkering and the supply systems set up for this purpose will be long term endeavours, and in order to avoid the extreme variations sometimes encountered in the short term market (Figure 5.6). Long term contracted prices for natural gas have tended to be at 55% - 60% of high quality gas oil prices in Northern Europe, and this can also be indicated as a long term average price range for gas to be purchased either as input for small scale LNG production or as LNG from a large terminal. The latter is more likely to be near the high end of the range, with significant uncertainty since no such purchase agreement has yet been made in Northern Europe.
5.5.6 Supply logistics as a component of LNG costs for bunkering
The costs of supply logistics for making procured gas available as LNG for a bunkering ship must cover the 4 elements as follows: - Small scale LNG production unless sourced from a large terminal; - Freight to a bunkering port; - Terminal at bunkering port; - Bunkering operation from a terminal at bunkering port.
Cost of small scale LNG production The last completed small scale production plant in Norway was the 80.000 tonnes/year second train at Kollsnes (owner: Gasnor), which started operations in 2007. Much of its capacity is already committed for a number of years ahead. One 300.000 tonnes/year project is ongoing in Norway. Firm and updated investment cost figures for these plants have not been published, but based on various public information, it can be put at €50 - €60 million per 100.000 tonnes of annual LNG production capacity allowing for some distortion from recent currency fluctuations.
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In recent years there has been a sharp trend towards higher construction costs in the oil and gas sector, but also in other sectors, driven by rising oil prices and a strong world economy until mid-2008. As of late 2008 there is considerable uncertainty over how the recent sharp global economic downturn and drop in oil prices will affect construction costs including the cost of building new LNG capacity. LNG production requires substantial amounts of energy, usually as electricity which can be obtained from the grid or produced locally from gas. If produced from gas, 10 – 15% of the gas feed is spent for this purpose, resulting in some surplus heat which may be applied to other purposes. The cost of small scale LNG production from future plants may be put at a range of €7 - €12 per MWh, depending on a number of factors including cyclically influenced construction costs, energy costs, utilisation etc. High energy prices will tend to increase the costs. If LNG supply from large terminals is achieved, then the small-scale LNG production costs can be avoided. Instead, somewhat higher ship transportation costs must be expected, because the most likely sources are at a greater distance than Western Norway. An addition of €1 per MWh for transport costs is assumed in the event of LNG sourcing from large terminals.
Freight and terminal costs LNG will have to be moved to the bunkering ports, most likely by LNG carriers such as the 7500m3 vessel described in section Error! Reference source not found., and to be received in a terminal facility with storage capacity. Tank storage capacity must be carefully selected due to its high cost, and this should be optimised together with utilisation of shipping capacity. Discharge of one ship cargo at several terminals is a possibility, and it may be optimal in some ports to build terminal storage capacity of a smaller size than would be needed to fully discharge one ship. MARINTEK has analysed several cases of optimal ship and terminal utilisation based on different assumptions for discharge port combinations, product origins and annual quantities. Figure 5.9 illustrates the outcome of some of the analyses, in which Gothenburg, Lübeck and Stockholm were considered as bunkering ports either separately or in combinations, and Western Norway as the source of LNG. Shipping and terminal costs for tend to be lower with higher annual quantities, and are mostly between €5 and €10 per MWh when annual supply is in excess of 80,000 tonnes per year. For smaller annual volumes, costs per MWh can be significantly higher, and they may also be adversely affected by awkward destination combinations which lead to inefficient use of capacities.
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Cost of bunkering operations The cost of performing bunkering operations, which entails the supply of LNG from a local terminal to the fuel tanks of a ship, can be conducted by truck, barge or fixed line delivery. The costs will depend on local conditions and the solution found for each port, but is expected to be comparatively modest in relation to the other cost components. A cost of €1 per MWh is assumed for this function.
Freight and terminaling costs - LNG for bunkering
0
5
10
15
20
25
- 50 000 100 000 150 000 200 000 250 000
Tons per year supplied
Cost € per MWh 1 discharge port
2 discharge ports
3 discharge ports
Figure 5.9 - Shipping and terminal costs at different discharge port combinations and different annual
quantities. Costs in € per MWh of energy in LNG. Based on calculations by MARINTEK.
5.5.7 Indications of overall costs of LNG supplies
Figure 5.10 gives indications of overall costs of LNG supplied as ships’ fuel in the Baltic region, and the cost of gas oil as a comparison. To allow for the recent wide fluctuations in the price of crude oil, the indications are given at three different crude oil price levels: $30, $90 and $150 per barrel of Brent crude. The costs of supplying LNG are indicated as high to low ranges at each oil price level. The reasons for the high-low ranges in LNG supply costs are explained in the previous sub-sections. For LNG production, the high-end cost represents a high estimate of small-scale LNG costs, whereas the low-end cost represents supply from large-scale terminals without the need for small-scale LNG production but with a modest extra freight cost to allow for longer sailing distance. As can be seen from Figure 5.10, the cost of LNG will tend to vary with the price of crude oil, as do also refined products such as gas oil. Delivered LNG costs will however tend to vary less than crude oil and refined oil products, such as gas oil. As a consequence, the competitive position of LNG against liquid fuels will be stronger at high oil prices than at low oil prices.
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A substantial range of high to low LNG costs is indicated for each oil price scenario. In early stages of LNG supplies for bunkering the costs are likely to be in the higher parts of the range, as supplied volumes are low and drawn mainly from small-scale LNG production. As the systems expands, and with the anticipated introduction of supplies from large-scale plants, there is a potential for bringing costs down towards the lower ends.
Figure 5.10 - Indications of costs of supplying LNG under different crude oil price scenarios.
For comparisons, gas oil costs under different oil prices are established based on regression of historical prices during 2004-2008. Gas oil costs reflect heating oil quality with max 0.1% sulphur in barge trade in the Amsterdam-
Rotterdam-Antwerp range without addition of taxes or surcharges.
The diagram in Figure 5.10 does not fully reflect the comparative costs and benefits of using LNG as a fuel in replacement of gas oil. The construction of LNG-fuelled ships is currently more costly than ships on liquid fuels; on the other hand, ships running on gas oil within the Emission Control Areas will face added costs for keeping emissions within permitted limits.
LNG costs at different crude oil prices
0
10
20
30
40
50
60
70
80
LNG Gasoil LNG Gasoil LNG Gasoil
€ per MWh
Gas purchase price LNG production (or extra freight) Freight and terminal costs Bunkering
$30 crude oil
$90 crude oil
$150 crude oil
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5.5.8 Small scale LNG pricing
For small scale LNG contracts as is the case for the MAGALOG ships the pricing principles described above is valid. Below general description above has been further elaborated with reference values to establish relevant reference curves for small scale LNG pricing. The correlation to natural gas prices is obtained by using information from Platts, and in this way the LNG bunker prices is expressed as a function of crude oil prices on the spot market. Gas prices relevant for benchmarking of the MAGALOG concepts are obtained by the following simplified formula on energy basis
PLNG= a * F(op)+ b (ø/kWh) where
PLNG – Price of LNG, ø/kWh Exchange rates: 1 NOK = 100ø (ø=øre) 1 € = 8,0 NOK (September 2nd 2008) 1 EuroCent = 8 øre a - constant, negotiated in contract. October 2007: a=20 ø/kWh F(op) – function of oil prices, Platts notations of MGO prices
07)(
)()(
oct
n
PlattsMGO
PlattsMGOopF
MGO(Platts)n – Platts MGO price notation in month n MGO(Platts)oct07 – Platts MGO price notation in October 2007 n – actual time for price calculation b – Constant, represent non-oil related cost, (fixed production cost, transportation etc.) October 2007: b=10 ø/kWh Average MGO prices in October 2007 is: MGO(Platts)oct07 = 709,50 US$/ton.
Hence, LNG reference price October 2007 may be calculated as follows:
PLNG(october 07)= 20 * 07
07
5,709
50,709
oct
oct + 10 = 30 [ø/kWh] (2,75 €-Cent/kWh)
Gas pricing versus crude oil price for the small scale and large scale markets are illustrated in Figure 5.11.
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LNG prices vs. Brent crude oil price
0
5
10
15
20
20 30 40 50 60 70 80 90 100
Brent crude, $/barrel
Ga
s p
ric
e,
$/m
BT
U
P(LNGcif)Guangdong$/mmBTU
P(LNGcif) Japan$/mmBTU
P(Smallscale), Europe$/mmBTU
Figure 5.11 – LNG prices vs. Brent crude oil price
The illustration in Figure 5.11 shows the possible price span on LNG represented with LNG prices on the large scale Asian markets and prices which may be obtained in a small scale perspective. Actual prices will probably be in between the Japanese and small scale European prices.
Figure 5.12 – LNG and MGO prices vs. Brent crude oil price on energy basis. (USD/NOK exchange rate 5,4)
From Figure 5.12 it can be seen that the LNG prices on energy basis is equal to MGO market prices in Norway at crude oil price of $ 40/barrel and for MGO spot prices at UD$70 /barrel. Comparing MGO prices to Japanese import prices indicate a potential development of gas price in a more developed market.
LNG and MGO prices vs Brent Crude oil price on energy basis
0200400600800
10001200
20 30 40 50 60 70 80 90 100
Brent crude oil price, $/barrel
Ga
s a
nd
MG
O p
ric
e,
$/t
on
P(Smallscale), Europe$/ton -energy basis
Platts (GO-02)
P(LNGcif) Japan $/ton-energy basis
MGO market price (N)$/ton
US$/NOK exchange.rate: 5,4
US$/NOK exchange.rate: 5,4
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Comparing international fuel prices of HFO and MGO with the market price on LNG in the developed Japanese market, an interesting trend can be observed. Today the LNG price is cheaper than the HFO price on an energy basis as illustrated in Figure 5.13. This indicates that a higher availability of LNG as new production facilities are established will reduce the price of LNG. LNG will be more compatible to other fuels, and the domestic price level for LNG relative to MGO and HFO will probably be lower in the future than it is today.
Figure 5.13 – Comparison of LNG, HFO and MGO prices on energy basis, (Sipilä,Wärtsilä)
5.6 Economic evaluation
The gas price is a key factor in the economic evaluation of a gas fuelled ship and comparison with a conventional HFO fuelled ship. In WP 4 of the MAGALOG project, economic evaluations of a RORO and A ROPAX case ship has been done. Assuming there are no technical and regulative challenges the economic criticality by building a gas fuelled ship as the case ships referred to in this report will always be dependent upon the gas price vs. the price of conventional fuels. Building costs: The actual cost of the gas-engine and propulsion plant may be about 30 % more expensive for the gas version compared to a conventional vessel. For the vessel as a whole this is reduced to about 10 %. Operating costs. Fuel price: Operating costs varies slightly with a number of factors, such as maintenance, manning, and others, but the major issue is of course the price of fuel (gas). For the chosen case ships there is a balancing point around a crude oil price of USD 70/barrel. Above this price (at a certain point in time) the gas solution is advantageous and gives a faster return of investment over a typical project period (15 years used in our studies). The gas price varies with
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the crude oil price and the development of gas and oil price are not directly linked to each other. Uncertain future development of this ratio will be a criticality factor for the success of the gas (or diesel) version. It should be noted to the gas-version’s advantage that the recent decision by IMO to practically ban the use of HFO in MARPOL defined special emission control areas (SECA) such as the Baltic Sea and the North Sea by 2015. From this year onwards all vessels in North Europe will practically have to switch to distillate oils with a price tag of about 80 % above HFO while any gas powered vessels will not experience this jump in fuel costs in 2015. Taxation: Some sources point to possible future taxation of emissions resulting from the operation of combustion engines in the marine market. Such taxations are not yet regulating the international marine market, but it is already effecting domestic Norwegian operations. Taxation or other regulation is heavily debated in IMO and other regulative bodies in Europe and cannot be excluded as a possibility for the future, but is not considered for the RORO and Ro-Pax example vessels. However, compared to conventional fuels the use of natural gas in general leads to less taxable emissions so the concept vessels will not suffer relative to conventional vessels and this is of course not a critical barrier for the concept. Considering these cost and taxation conditions it seems in general that economic criticality is not a barrier for investing in gas powered vessels as it might have been only a few years back. From today’s standpoint with exceptional high fuel oil price (spring 2008) it seems even clearer that a gas powered vessel will compete better than a conventional vessel in an open market like the one the ships are operate d in today. Also in a more regulated market, if this shall be a future scenario, the concept vessels seems more competitive due to the added environmental benefits of natural gas as a fuel compared to conventional bunker fuels. The added costs for building gas powered vessel seem to be a worthwhile investment if the market develops in the expected way, but the uncertainty of future gas (or fuel) prices are of course a critical issue. A vessel designed for switching between fuels would of course also be a safe bet if it could take advantage of the lowest cost of fuel at any given time.
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6. Loading of LNG to a LNG feeder at a production plant
6.1 Introduction
In this section the LNG loading procedure from a LNG production plant to a LNG feeder is described based on experience from operation at Kollsnes LNG production plant and distribution of LNG with the LNG feeder “Pioneer Knutsen”. The objective of this section is to describe how safety precautions are implemented in the operational routines, and to indicate required time frame for loading/unloading of an LNG feeder.
6.2 The LNG feeder “M/T Pioneer Knutsen”
“Pioneer Knutsen” is the world’s smallest LNG tanker with a tank capacity of 1100 m3. The ship is owned by the Norwegian ship owner Knutsen OAS and chartered by Gasnor on a long time contract. Main dimensions of “Pioneer Knutsen” are shown below:
Parameter Value Unit Length overall 68,87 m
Length between 63,40 m Breadth moulded 11,80 m Depth moulded 5,50 m
Draught 3,30 m Gross tonnage 1 687 GT
Net tonnage 817 NT Deadweight 640 ton
Cargo tank 1 100
(2x550) m³ Speed 12 kn
The vessel carries natural gas from the LNG terminal at Kollsnes, outside Bergen to users in along the Norwegian coast. The “Pioneer Knutsen” is operated by a crew of six persons. The LNG tanks have the following instrumentation:
- Temperature sensors in bottom, in mid-section and at top filling level. Example of temperature readings during loading at 90 % load is: Top: -123 ºC, Mid: -153 ºC, bottom: -156 ºC.
- In addition: Temperature sensors in the corners outside of the tanks: Example of temperature reading at 90 % load is: Top: -102 ºC, bottom -154 ºC.
- Level indicator shows the LNG level in the tanks (m3). - The boil off rate (BOR) is calculated to 0,32 % per day. - Two submerged pumps in each tank with a capacity of 2x50 m3/h. - The tanks are loaded at app. 2,5 bar. Safety valves are adjusted to blow at 3,5 bar.
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6.3 Loading procedure at Kollsnes LNG plant
Loading of the LNG feeder follows a standardized safety procedure. The ship is moored to the quay and connected to the loading hoses as shown in Figure 6.1.
Figure 6.1 – Loading of “Pioneer Knutsen” /Source: Gasnor/
The ship brings own filling hoses, and these hoses are always connected to the LNG pipe flanges of the ship. The following refuelling procedure has been established:
1. Connecting the hoses for liquid and gas return to the land terminal flanges, (6-8 bolts connection).
2. Purging of hoses with nitrogen to local discharge point on quay, 1,5 m above man height. 3. Close nitrogen, purging of hoses with LNG to the same discharge point, ( i.e. cooling of
the hoses with cold gas). 4. Start filling of tanks via submerged pumps (200 m3 pr hour) in storage tank onshore
(Storage tank capacity: 6000 m3, one week production). Pumps were operated from shore, radio connection from shore to ship. Pumps have variable flow and the capacity can be adjusted by the operator.
5. Normal filling time is app. 5 hours. Finishing procedure lasts for 1 hour. 6. Filling is stopped when ship tank is full. Automatic stop if tank is overfilled (= 98 %.) 7. The pumps are stopped. 8. Valves on shore and on ship are closed 9. Pressure increases in LNG hose to app. 8 bar.
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10. Valves on ship are opened and the remaining LNG in the hoses is transferred to the ship tank.
11. Repeating point 10 for four times to secure that LNG hose is empty. 12. Nitrogen purge and disconnection of hoses
Other points to be noted:
- Nitrogen is produced on board. - Gas return from the ship is feed into a local CO-GEN plant. - Any remaining LNG in the pipe system is blown back to the storage tank when the
pressure pipe increases due to evaporation of LNG
Irrigation: - During loading of the ship the top deck is irrigated with water as a safety precaution in
case of any leakage.
Remote control - All valves are fully remote controlled from bridge. Shutdown is initiated from bridge and
during shutdown all valves are closed and pumps (on shore) are shut down. - Online measurement of filling level, pressure, and temperature on each tank are shown on
a PC screen at the bridge. Based on the procedure described above the total loading time of the ship is approximately 6-7 hours, all included. The main time consumption is related to the loading of the ship and this is decided by the loading capacity of the ship Discharging LNG from the vessel to a local bunkering terminal would in principle require the same procedure as for loading the ship. Total discharge time is dependant of the pump capacity of the ship, but approximately one hour has to be added due to operational procedures and safety precautions. Bunkering of a gas fuelled ship will need to follow approximately the same routines as for loading of an LNG feeder. To minimize the bunkering time it is important that the bunkering terminal is designed with sufficient pump capacity. This should be based on the design requirements from all involved parties on a case-to-case basis.
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7. Transporting of LNG from Kollsnes and alternative origins to terminal ports
7.1 Introduction
When a ship owner considers LNG as fuel in his fleet he will carefully consider the technical economical feasibility, safety and LNG bunkering possibilities in terminal ports. Availability of LNG as bunkers is of course a premise that has to be in place, not only availability in general but dedicated to terminal ports included in the ship sailing route. An increased number of LNG bunkering facilities are a mutual type of matter. If the driving forces for LNG as ship fuel are strong enough, the number of bunkering facilities will follow more or less automatically. On the other hand the market has to be confident that bunkering will be in place when it is needed. The Baltic Sea is highly interesting when it comes using LNG as ship fuel. The LNG availability in Norway and Northern Europe could be a basis for establishing an LNG bunkering infrastructure in the Baltic Sea.
7.2 LNG availability in the Baltic and North Sea
Today no LNG bunkering facilities for ships outside Norway is known, and it is likely that such facilities will be required in central ports in Northern Europe to increase the availability and flexibility of LNG as bunker fuel. Assuming an increased interest for LNG as bunkers in the North European short sea shipping, a similar infrastructure as already available in Norway should be established. It is not possible to point out where initial bunkering stations should be built. This will be dependant on the project and LNG volumes which can be realized in the various areas. To indicate the price effect of transporting LNG from various production plants to the customers in the Baltic Sea some analysis have been done with a logistic simulation tool developed at MARINTEK. Alternative receiving harbors have been chosen in these cases, Lübeck and Gothenburg and Stockholm. The main source of LNG is assumed to be the Kollsnes LNG production plant and from a planned import terminal in Swinoujscie, Poland. Based on the assumption of required LNG-volumes at specific Baltic harbours, a transport model is used for calculations of transportation cost for various scenarios of supply to the alternative receiving harbours.
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7.3 Objective
This work package of the MAGALOG project investigates by means of logistic simulations the economic aspect of ship transport of LNG to some dedicated terminal ports in the Baltic Sea. The following scenarios have been defined
1. Kollsnes - Lübeck 2. Kollsnes - Gothenburg – Lübeck 3. Kollsnes - Lübeck - Stockholm 4. Kollsnes - Gothenburg - Lübeck - Stockholm 5. Swinoujscie - Lübeck - Gothenburg 6. Swinoujscie - Stockholm
7.4 Logistics possibilities
7.4.1 Transport analysis model for LNG
MARINTEK has developed an excel-based tool for calculation of the transportation cost in an NG chain. This tool can be used to calculate the gas tariff based on defined volumes and routes with alternative storage and ship transport capacities. The model is an adaptation of a previous optimization model developed by MARINTEK. The model is written in Excel and utilizes VBA scripts and macros. This allows compatibility, efficient maintenance and updating of the model. The model optimizes the value chain from LNG production in one or more locations, from shipping operation, to storage and consumption at a number of terminals at selected locations. The model optimizes 1) fleet mix and size by examining routing patterns of vessels, and 2) required storage capacity at terminals. The objective function is cost minimization with respect to BOTH shipping and storage. Dimensioning of necessary buffer at storage terminals is set by the user. The model can be configured manually if the user wants to evaluate rather than optimize a given case. The model incorporates a sensitivity chart and analysis function. This module investigates the influence of variation of main cost/investment parameters of seagoing vessels and storage.
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LNG production
Geographic model
Shipping and storageLogistics system
Sensitivity analysisReporting of costs
• One or multiple production hubs• Terminal location model• Allocation of terminals to production hubs
Scope
• Given production capacity
• Balance vessel costs and storage costs• Fleet mix and size assessment• Logistics optimisation model• Detailed vessel and storage capacity/cost models
• Sensitivitiy and robustness analysis• Cost reporting model
Process
Model objective:1) Minimize total cost or 2) manual over-ride for evaluation of case
LNG production
Geographic model
Shipping and storageLogistics system
Sensitivity analysisReporting of costs
• One or multiple production hubs• Terminal location model• Allocation of terminals to production hubs
Scope
• Given production capacity
• Balance vessel costs and storage costs• Fleet mix and size assessment• Logistics optimisation model• Detailed vessel and storage capacity/cost models
• Sensitivitiy and robustness analysis• Cost reporting model
Process
Model objective:1) Minimize total cost or 2) manual over-ride for evaluation of case
The model includes databases over investment figures for vessels and storage capacity as a function of capacity. Tankers
• Vessel database includes investment figures, costs, operating costs, power requirements and design speed for vessels.
• Database used to calculate time charter rate calculations and voyage dependent costs (port
dues, bunker oil/gas consumption etc).
• Based on budget figures and reference tankers in the LNG market Storage tanks Pressure vessels are considered for capacities up to 8000 m3. Investment figures reflect 2008 prices, and a stainless steel price in the range 3.5 – 4 €/kg. Prices are based on recent price update. For storage capacity above 8000 m3, atmospheric storage is considered. Pricing is based on a few reference costs, and cost curve is obtained based on (exponential best-fit) interpolation. Sailing distances
Obtained using great circle method (with obstacles). The model includes:
- Cost report
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- Investment report - Ship/fleet utilization and cost chart - Sensitivity charts - Results: “Gas price tariff” ---- NOK/ton LNG
7.4.2 Scenarios investigation
Case scenarios are simulated to investigate the economic feasibility of supplying LNG to numerous harbors in the Baltic Sea. LNG is distributed by a given ship to a storage hub in the actual harbor. Typically a low volume scenario and a high volume scenario are simulated. The main output from the simulations is the calculated shipping and storage cost expressed as a rate of NOK/ton LNG handled in the logistic chain. This rate is a clear indicator of the LNG chain feasibility as the shipping and storage cost has a major effect on the final LNG price to the customer. The actual harbors are chosen based on: - the ship traffic basis and thereby possible yearly LNG bunkers volume (refr: WP4.1) - the strategic location and possible LNG market for other industrial purposes Distributions chains with supply from the LNG plant at Kollsnes to possible LNG hubs in Gothenburg, Lübeck, Svinemünde and Stockholm are investigated as case scenarios. The simulation of a LNG chain by ship transport needs a set of general input parameters as shown in Table 7.1.
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LNG vessel
Vessel size 7500m 3 LNG
Capex (and opex) of the 7500 m3 vessel spread on the case volume
Slack in vessel capacity considered idle time
CAPEX parameters
Capital cost ship investment 8 % (real)
Capital cost LNG receiving terminals 8 % (real)
LNG vessel, economic lifespan 20 yrs
LNG terminal, economic lifespan 20 yrs
Operational costs
Port dues NOK 3500/arrival fixed cost
Port commodity tax NOK 3.5/m3 (bulk liquid)
LNG cost (bunker fuel) NOK 4300/tonn
Vessel fuel consumption 180 g/kWh
Pilotage costs NOK 0/arrival
Tugboat costs NOK 0/arrival (vessel is manoeuvrable)
Vessel operation
Expected Queuing Time per vessel, discharge ports 0 hrs (see separate analysis)
Ship loading/unloading rate (< 5000 m3 vessel) 400 m3 / 180 tons per hour
Ship loading/unloading rate (>5000 m3 vessel) 900 m3 / 400 tons per hour
Pre/post-fill/unloading time, loading/discharge ports 2 hrs
Vessel service speed 13 knots (vessels < 6000 m3) 14 knots (vessels 6000 - 18000 m3) 15 knots (vessels > 18000 m3)
Vessel port-fairway sailing speed 5 knots
Vessel operating days/year 350
Vessel fuel LNG / Boil-off / forced boil-off
Natural gas specific parameters
Natural gas specific mass 0.735 kg/m3
Natural gas to LNG volume liquefaction factor 615
Net Calorific Value Natural gas 10,10 kWh/Sm3
Gross Calorific Value Natural gas 11,11 kWh/Sm3
Net Calorific Value, bunker oil (MGO) 42 MJ/kg
Net Calorific Value, LNG 49.5 MJ/kg
Table 7.1 - General parameters
7.5 Results
The simulation results are presented in Table 7.2.
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Case LNG logistic chain -- transport by ship 7500m3 shipping NOK/ton
storage NOK/ton
total NOK/ton
total pr. year MNOK/year
1 a 40 000 tons from Kolsnes to Lübeck
1407 1244 2651 107
1 b 120 000 tons from Kolsnes to Lübeck
538 417 955 115
2 a 80.000 tons from Kolsnes to Lübeck and Gothenburg (roundtrip 40.000 to Lübeck, 40.000 to Gothenburg)
756 407 1163 94
2 b 200.000 tons from Kolsnes to Lübeck and Gothenburg (roundtrip, 120.000 to Lübeck, 80.000 to Gothenburg)
365 164 529 106
3 a 70.000 tons from Kolsnes to Lübeck and Stockholm (40.000 to Lübeck, 30.000 to Stockholm)
890 493 1383 97
3 b 163.000 tons from Kolsnes to Lübeck and Stockholm (roundtrip, 120.000 to Lübeck, 43.000 to Stockholm)
465 258 723 118
3 c 180.000 tons from Kolsnes to Lübeck and Stockholm (direct shipping, 120.000 to Lübeck, 60.000 to Stockholm)
694 611 1305 175
4 a 110.000 tons from Kolsnes to Lübeck, Gothenburg and Stockholm (roundtrip 40.000 to Lübeck, 40.000 to Gothenburg, 30.000 tons to Stockholm)
619 323 942 104
4 b 160.000 tons from Kolsnes to Lübeck, Gothenburg and Stockholm (roundtrip operation, 74.000 tons to Lübeck, 50.000 to Gothenburg and 36.000 tons to Stockholm)
470 215 685 110
5 a 80.000 tons from Svinemünde to Lübeck and Gothenburg (roundtrip, 40.000 to Lübeck, 40.000 to Gothenburg)
708 410 1118 90
5 b 200.000 tons from Svinemünde to Lübeck and Gothenburg (roundtrip, 120.000 to Lübeck, 80.000 to Gothenburg)
313 164 477 95
6 a 30.000 tons from Svinemünde to Stockholm
1807 1669 3476 104
6 b 60.000 tons from Svinemünde to Stockholm
930 835 1765 106
Table 7.2 - Distribution cost to hub
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Comments to Table 7.2: - The storage tank volume at a hub is optimized according to the actual LNG volume
throughput from the hub. - The yearly investment and operational cost for the storage plant is included in the cost
calculation and expressed as a cost pr. ton of the LNG throughput. - The vessel yearly capital cost: 36 MNOK Appendix 1 includes more data from each case.
7.6 Comments to results
To minimize the shipping cost in the Baltic LNG logistic chain it is of major importance, not surprisingly, to utilize the vessel capacity. For the actual vessel with the cargo capacity of 7500m3 LNG and loading at Kolsnes LNG plant, a yearly shipping quantity should be in the range of 160000 to 200000 tons pr. year. For a shorter roundtrip by picking up LNG in Svinemünde, the vessel yearly capacity will be significant higher, close to 400000 ton pr. year. A ship fuel market of this magnitude in the Baltic region is foreseen as a possible scenario (ref. WP4.1) especially with the high and lasting fuel oil prices, but not realistic from day one. To boost the necessary volumes from day one, industrial LNG users in the hub areas will be of great help. The maximum theoretical vessel capacity: - cases 1a, 1b, 2a, 2b: approx. 240000 tons/year - cases 3a, 3b, 4a, 4b: approx. 160000 tons/year - cases 3c: approx. 216000 tons/year - cases 5a, 5b: approx. 420000 tons/year - cases 6a, 6b: approx. 390000 tons/year With the LNG market volume foreseen at the different hubs it is more cost effective to serve the hubs by roundtrip sailing than direct delivery. A hub in Stockholm with assumed capacity of 30000-40000 ton/year can be served at less cost by a roundtrip from Kollsnes via Lübeck than by the same vessel used in direct transport from Svinemünde. The storage cost contributes significant to the total distribution cost and is certainly affected by the throughput volume of LNG. The higher volume, the lower specific storage cost.
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7.7 Appendix 1 --- case results
Case 1 a: Distribution of 40 000 tons from Kollsnes to Lübeck
Case Value
LNG volume (tons/year) 40.000 Max theoretical LNG volume (tons/year) 240.000 Vessel capacity (net, m3) 7.500 Storage capacity (m3) 12.000 Moving storage (maximum), m3: 7.500 Sailing distance, roundtrip (nm) 1344 Roundtrip time (days): 4.9 Roundtrips (no/year) 13.9 Storage costs (NOK/ton): 1244 Shipping costs (NOK/ton): 1407 Total costs (NOK/ton): 2651 Total costs (MNOK/year): 106.7
Cost overview
36 666 795
9 600 000
46 852 016
3 220 000
5 840 000709 485
520 0003 401 740
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
58
222120 / MT22 F09-029 / 2008-11-30
Case 1 b : Distribution of 120 000 tons from Kollsnes to Lübeck
Case Value
LNG volume (tons/year) 120.000 Max theoretical LNG volume (tons/year) 240.000 Vessel capacity (net, m3) 7.500 Storage capacity (m3) 12.000 Moving storage (maximum), m3: 7.500 Sailing distance, roundtrip (nm) 1344 Roundtrip time (days): 4.9 Roundtrips (no/year) 41.5 Storage costs (NOK/ton): 417 Shipping costs (NOK/ton): 538 Total costs (NOK/ton): 955 Total costs (MNOK/year): 114.6
Cost overview
36 666 795
9 600 000
46 852 016
3 220 000
5 840 000
2 115 556
520 000
9 807 127
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
59
222120 / MT22 F09-029 / 2008-11-30
Case 2 a: Distribution of 80.000 tons from Kollsnes to Lübeck and Gothenburg (roundtrip operation, 40.000 to Lübeck, 40.000 to Gothenburg)
Case Value
LNG volume (tons/year) 80.000 Max theoretical LNG volume (tons/year) 238.000 Vessel capacity (net, m3) 7.500 Storage capacity, Gothenburg (m3) 5.500 Storage capacity, Lübeck (m3) 5.500 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 1344 Roundtrip time (days): 4.95 Roundtrips (no/year) 24 Storage costs, Lübeck (NOK/ton): 407 Storage costs, Gothenburg (NOK/ton): 407 Shipping costs (NOK/ton): 756 Total costs (NOK/ton): 1163 Total costs (MNOK/year): 93.6
Cost overview
36 666 795
9 600 000
30 672 532
2 108 032
5 840 000
1 502 439
520 000
6 690 716
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
60
222120 / MT22 F09-029 / 2008-11-30
Case 2 b: Distribution of 200.000 tons from Kollsnes to Lübeck and Gothenburg (roundtrip operation, 120.000 to Lübeck, 80.000 to Gothenburg)
Case Value
LNG volume (tons/year) 200.000 Max theoretical LNG volume (tons/year) 238.000 Vessel capacity (net, m3) 7.500 Storage capacity, Gothenburg (m3) 4.500 Storage capacity, Lübeck (m3) 6.500 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 1344 Roundtrip time (days): 4.95 Roundtrips (no/year) 59.3 Storage costs, Lübeck (NOK/ton): 162 Storage costs, Gothenburg (NOK/ton): 168 Shipping costs (NOK/ton): 365 Total costs (NOK/ton): 529 Total costs (MNOK/year): 105.7
Cost overview
36 666 795
9 600 000
30 672 532
2 108 032
5 840 000
3 728 780
520 000
16 605 141
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
61
222120 / MT22 F09-029 / 2008-11-30
Case 3 a: Distribution of 70.000 tons from Kollsnes to Lübeck and Stockholm (40.000 to Lübeck, 30.000 to Stockholm)
Case Value
LNG volume (tons/year) 70.000 Max theoretical LNG volume (tons/year) 163.000 Vessel capacity (net, m3) 7.500 Storage capacity, Stockholm (m3) 5.000 Storage capacity, Lübeck (m3) 6.500 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 2119 Roundtrip time (days): 7.25 Roundtrips (no/year) 21 Storage costs, Lübeck (NOK/ton): 482 Storage costs, Stockholm (NOK/ton): 496 Shipping costs (NOK/ton): 890 Total costs (NOK/ton): 1383 Total costs (MNOK/year): 96.8
Cost overview
36 666 795
9 600 000
32 080 226
2 204 779
5 840 000
1 311 220
520 000
8 563 101
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
62
222120 / MT22 F09-029 / 2008-11-30
Case 3 b: Distribution of 163.000 tons from Kollsnes to Lübeck and Stockholm (roundtrip operation, 120.000 to Lübeck, 43.000 to Stockholm)
Case Value
LNG volume (tons/year) 163.000 Max theoretical LNG volume (tons/year) 163.000 Vessel capacity (net, m3) 7.500 Storage capacity, Stockholm (m3) 3.000 Storage capacity, Lübeck (m3) 8.000 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 2119 Roundtrip time (days): 7.25 Roundtrips (no/year) 48 Storage costs, Lübeck (NOK/ton): 272 Storage costs, Stockholm (NOK/ton): 229 Shipping costs (NOK/ton): 465 Total costs (NOK/ton): 723 Total costs (MNOK/year): 117.8
Cost overview
36 666 795
9 600 000
39 649 405
2 724 986
5 840 000
3 032 195
520 000
19 802 172
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
63
222120 / MT22 F09-029 / 2008-11-30
Case 3 c: Distribution of 180.000 tons from Kollsnes to Lübeck and Stockholm (direct shipping, 120.000 to Lübeck, 60.000 to Stockholm)
Case Value
LNG volume (tons/year) 180.000 Max theoretical LNG volume (tons/year) 216.000 (direct deliveries) Vessel capacity (net, m3) 7.500 Storage capacity, Stockholm (m3) 12.000 Storage capacity, Lübeck (m3) 15.000 Moving storage (maximum), m3: Lübeck: 12.000, Stockholm: 6.000 Sailing distance, roundtrip (nm) 2119 Roundtrip time (days): 4.9 / 6.6 Roundtrips (no/year) 53.3 Storage costs, Lübeck (NOK/ton): 499 Storage costs, Stockholm (NOK/ton): 835 Shipping costs (NOK/ton): 694 Total costs (NOK/ton): 1305 Total costs (MNOK/year): 174.5
Cost overview
36666795,18
9600000
102904032,1
7070000
5840000
2115555,556
520000
9807127,273
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
64
222120 / MT22 F09-029 / 2008-11-30
Case 4 a: Distribution of 110.000 tons from Kollsnes to Lübeck, Gothenburg and Stockholm (roundtrip operation, 40.000 to Lübeck, 40.000 to Gothenburg, 30.000 tons to Stockholm)
Case Value
LNG volume (tons/year) 110.000 Max theoretical LNG volume (tons/year) 161.000 Vessel capacity (net, m3) 7.500 Storage capacity, Stockholm (m3) 3.000 Storage capacity, Gothenburg (m3) 4.000 Storage capacity, Lübeck (m3) 4.000 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 2119 Roundtrip time (days): 7.33 Roundtrips (no/year) 32.6 Storage costs, Stockholm (NOK/ton): 324 Storage costs, Lübeck (NOK/ton): 316 Storage costs, Gothenburg (NOK/ton): 316 Shipping costs (NOK/ton): 619 Total costs (NOK/ton): 942 Total costs (MNOK/year): 103.6
Cost overview
36 666 795
9 600 000
32 912 003
2 261 944
5 840 000
2 177 019
520 000
13 623 840
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
65
222120 / MT22 F09-029 / 2008-11-30
Case 4 b: Distribution of 160.000 tons from Kollsnes to Lübeck, Gothenburg and Stockholm (roundtrip operation, 74.000 tons to Lübeck, 50.000 to Gothenburg and 36.000 tons to Stockholm) Case Value
LNG volume (tons/year) 160.000 Max theoretical LNG volume (tons/year) 160.000 Vessel capacity (net, m3) 7.500 Storage capacity, Stockholm (m3) 2.500 Storage capacity, Gothenburg (m3) 3.500 Storage capacity, Lübeck (m3) 5.000 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 2119 Roundtrip time (days): 7.33 Roundtrips (no/year) 47.7 Storage costs, Stockholm (NOK/ton): 232 Storage costs, Lübeck (NOK/ton): 201 Storage costs, Gothenburg (NOK/ton): 222 Shipping costs (NOK/ton): 470 Total costs (NOK/ton): 685 Total costs (MNOK/year): 110.3
Cost overview
36 666 795
9 600 000
32 384 946
2 225 721
5 840 000
3 171 816
520 000
19 849 303
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
Under the assumptions, it is theoretically possible to deliver a total of 240 000 tons with the 7.500 m3 vessel if only direct deliveries are done. However, this is impractical due to the resulting storage requirements and thus high storage tariffs.
66
222120 / MT22 F09-029 / 2008-11-30
Case 5 a: Distribution of 80.000 tons from Svinemünde to Lübeck and Gothenburg (roundtrip, 40.000 to Lübeck, 40.000 to Gothenburg) Case Value
LNG volume (tons/year) 80.000 Max theoretical LNG volume (tons/year) 420.000 Vessel capacity (net, m3) 7.500 Storage capacity, Gothenburg (m3) 5.500 Storage capacity, Lübeck (m3) 5.500 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 620 Roundtrip time (days): 2.8 Roundtrips (no/year) 23.7 Storage costs, Lübeck (NOK/ton): 410 Storage costs, Gothenburg (NOK/ton): 410 Shipping costs (NOK/ton): 708 Total costs (NOK/ton): 1118 Total costs (MNOK/year): 89.4
Cost overview
36 666 795
9 600 000
30 672 532
2 108 032
250 407
520 000
3 774 939
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
67
222120 / MT22 F09-029 / 2008-11-30
Case 5 b: Distribution of 200.000 tons from Svinemünde to Lübeck and Gothenburg (roundtrip, 120.000 to Lübeck, 80.000 to Gothenburg) Case Value
LNG volume (tons/year) 200.000 Max theoretical LNG volume (tons/year) 420.000 Vessel capacity (net, m3) 7.500 Storage capacity, Gothenburg (m3) 4.500 Storage capacity, Lübeck (m3) 6.500 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 620 Roundtrip time (days): 2.8 Roundtrips (no/year) 59.3 Storage costs, Lübeck (NOK/ton): 161 Storage costs, Gothenburg (NOK/ton): 166 Shipping costs (NOK/ton): 313 Total costs (NOK/ton): 477 Total costs (MNOK/year): 95.4
Cost overview
36 666 795
9 600 000
30 672 532
2 108 032
5 840 000
623 740
520 000
9 403 029
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
68
222120 / MT22 F09-029 / 2008-11-30
Case 6 a: Distribution of 30.000 tons from Svinemünde to Stockholm Case Value
LNG volume (tons/year) 30.000 Max theoretical LNG volume (tons/year) 393.000 Vessel capacity (net, m3) 7.500 Storage capacity, Stockholm (m3) 12.000 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 720 Roundtrip time (days): 3.0 Roundtrips (no/year) 8.9 Storage costs, Stockholm (NOK/ton): 1669 Shipping costs (NOK/ton): 1807 Total costs (NOK/ton): 3476 Total costs (MNOK/year): 104.3
Cost overview
36 666 795
9 600 000
46 852 016
3 220 000
5 840 00062 222520 000
1 515 101
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
69
222120 / MT22 F09-029 / 2008-11-30
Case 6 b: Distribution of 60.000 tons from Svinemünde to Stockholm Case Value
LNG volume (tons/year) 60.000 Max theoretical LNG volume (tons/year) 393.000 Vessel capacity (net, m3) 7.500 Storage capacity, Stockholm (m3) 12.000 Moving storage (maximum), m3: N/A Sailing distance, roundtrip (nm) 720 Roundtrip time (days): 3.0 Roundtrips (no/year) 17.8 Storage costs, Stockholm (NOK/ton): 835 Shipping costs (NOK/ton): 930 Total costs (NOK/ton): 1764 Total costs (MNOK/year): 105.9
Cost overview
36 666 795
9 600 000
46 852 016
3 220 000
5 840 000124 444
520 0003 030 202
Capital costs, vessel
Manning
Maintenance
LNG fuel
Port dues and fees
Insurance
Capital costs,terminal
Operations cost,terminal
All costs in NOK
Figure: Breakdown of costs involved in the sailing/HUB storage distribution chain
70
222120 / MT22 F09-029 / 2008-11-30
8. References
/1/ Rogde, T.: Short Sea shipping in Europe. Study of ship and transport volums in the Baltic Sea,
the North Sea and on Inland waterways in Europe. MAGALOG WP4 – Delivery D4.1 /2/ Stenersen, Jarslby: D4-2 Economical and Environmental effect of LNG fuelled ships
MAGALOG WP4 – Delivery D4.2 /3/ Stenersen: D4-3 Analysis of competitive strength of LNG as ship fuel compared to fossil fuels
and alternative fuels
