TYPES OF GAS TANKERS AND CARGO CONTAINMENT CHARACTERISTICS Gas Tankers Some Historical Milestones 1953 – Classification of first modern pressurised LPG carrier built in Europe 1958 – Classification of first semi-pressurised LPG carrier 1960 – Classification of first fully refrigerated LPG carrier 1962 – Prototype tests of experimental LNG carrier 1964 First LNG ship in operation 1995 – First membrane LNG carrier built in Korea 2000 950 LPG tankers in service (13 million cubic metres) 2005 – World’s first LNG regasification vessels (193 LNG tankers in service) 2006 – World’s first diesel electric LNG carriers World’s first CS1 containment system 2010 March, 337 LNG tankers in service
General In addition to complying with the all the safety and pollutions regulations for all tankers, gas carriers must comply with the Gas Codes and national regulations. The temperature, pressure, tank liquid level and gas monitoring equipment carried on gas tankers together with their associated alarms and complementary systems make this type of vessel among the most sophisticated in service. A feature of the gas tanker is that the cargo is kept under positive pressure to prevent air from entering the cargo system. The cargo tanks contain only cargo liquid and vapour, an atmosphere much too rich to be flammable. All gas carriers load and discharge under closed cargo conditions, with venting to atmosphere not being allowed. The risk of cargo being released to the atmosphere and being ignited is greatly reduced. Vapour return lines (VRL) are always used in the liquefied natural gas (LNG) trade. These lines are used to transfer the vapour displaced by the cargo transfer. The vapour return line is not always available or used in the LPG trade. The reliquefaction plant on board fully refrigerated ships is used to retain the vapour on board. The different containment methods gas tankers can be described as pressurized, semi pressurised, fully insulated and fully refrigerated.
An analysis of the year of build of LNG Tankers in service in August 2011. Decade of 1970’s 1980’s 1990’s 2000’s 2010’s Build Percentag 8% 5% 12% 66% 8% e of fleet
LPG Tankers Pressurised Pressurised gas carriers with capacity in the range 500 to 6000 m3 are used for the shipment of propane, butane and chemical gases at ambient temperature. These are a simple, cost effective way of transporting LPG to smaller terminals, coastal trade. These vessels are fitted with a number of horizontal cylindrical or spherical tanks. Recent fully pressurised LPG tankers up to 11,000m3 have been built with the thick, heavy steel required to sustain the pressure being replaced by much lighter nickel steels.
Fully Refrigerated Fully refrigerated sea going tankers with capacities over 100,000 m3 are suitable for carrying large volumes of LPG, ammonia and vinyl chloride long distances. Fully refrigerated gas tankers carry liquefied gases at low temperature and atmospheric pressure between terminals equipped with fully refrigerated storage tanks. These tankers have prismatic-shaped cargo tanks fabricated from 3.5% nickel steel which allows for the carriage of liquefied gases at temperatures as low as -48°C (a little below the boiling point of pure propane).
Very Large Gas Carrier (VLGC) The majority of existing fully refrigerated LPG ships are in the 20,000 to 60,000m3 capacity range. The preferred sizes for recent orders have been the 35,000 to 38,000m3 and the 56,000 to 60,000m3 capacity range. Fully refrigerated gas tankers of capacity 75,000m3 and over are called VLGCs.
Semi Refrigerated This type of tanker was developed because of advances made with metals capable of containing liquefied gases at low temperatures. The majority are sized in the 10,000 to 22,500m3 capacity range. The Independent Type ‘C’ cargo tank steels can withstand temperatures of -48°C for LPG and -104°C for ethylene. The combination of a
reliquefaction plant, insulation of the cargo tanks and use of the special steels allowed for a reduction in the weight of pressure vessels corresponding to the reduced thickness of the steel used. These very flexible tankers are able to carry cargoes in a fully refrigerated condition at atmospheric pressure or at temperatures corresponding to a storage pressure in the range 5 to 9 bar. This means these ships can discharge into both refrigerated and pressurised reception facilities. The tanks can be cylindrical, spherical or bi-lobe in shape. The semi pressurised gas tanker’s cargo tanks and associated equipment are designed for a working pressure of approximately 5 to 7 barg and a vacuum of 0.3 barg.
LNG Tankers An analysis of the cargo capacity of LNG Tankers in service in August 2011. Capacity Range (m3) Percentage of fleet by vessel Less than 20,000 1% 20,000 to 50,000 1% 50,000 to 100,000 4% 122,000 to 135,000 16% 135,000 to 140,000 21% 140,000 to 150,000 21% 150,000 to 156,000 13% 160,000 to 165,000 5% 170,000 to 177,000 5% 210,000 to 217,000 (Q Flex) 8% 261,000 to 266,000 (Q Max) 3%
Q Flex These membrane type LNG tankers have cargo tank capacity in the range 210,000 to 216,000 m3. These vessels started being delivered in 2007 out of the shipyards of Hyundai Heavy Industries, Samsung Heavy Industries and Daewoo Shipbuilding & Marine Engineering. The first batch of Q Flex vessels are propelled by two slow diesel engines with LNG boil-off gas being treated by an onboard reliquefaction plant. The combination of the slow speed diesel engines and the reliquefaction plant compared with the boil off gas driven steam turbines, leads to claims that the carbon footprint of a Q Flex tanker is 40% of that of ‘conventional’ LNG tanker.
Q Max This membrane type LNG tanker has cargo tank capacity around to 266,000 m3. The ‘max’ refers to the maximum size of LNG tanker that can be accommodated at the Qatar LNG terminal. These vessels started being delivered in 2008 out of the shipyards of Hyundai Heavy Industries, Samsung Heavy Industries and Daewoo Shipbuilding & Marine Engineering. The first batch of Q Max vessels is propelled by two slow diesel engines with LNG boil-off gas being treated by an onboard re-liquefaction plant. The combination of the slow speed diesel engines and the reliquefaction plant compared with the boil off gas driven steam turbines, leads to claims that the carbon footprint of a Q Max tanker is 40% of that of ‘conventional’ LNG tanker.
Typical Tanker Particulars Capacity m³
Membrane Tanker 145,700 216,000
Length m Breadth m Depth m Tank top above keel Loaded draft m Displacement tonnes
277.2 43.4 26.0 31.0 12.3 116,941
303.0 50.0 27.0 33.2 12.5 151,599
Double bottom height m Double side width m Outer side plate thickness mm Inner side plate thickness mm Transverse frame space mm Cargo Tank Dimensions Length m Height m Breadth m Tank diameter Approximate volume m³
3.2 2.2 17-18
3.4 2.6 16-21
Spherical Tanker 125,000 235,00 0 282.0 328.5 41.6 55.0 25.0 32.5 37.7 49.9 11.5 12.5 99,130 178,24 7 1.4 1.6 2.4 3.0 19 18-20
14-18
18-19
14-18
2,800
4,105
4,180
14.516.5 4,130
47.6 27.7 39.0
41.0 29.8 44.8
43,504
48,174
35 22,449
46 50,965
Cargo Containment Systems The cargo containment system consists of:
(1)The primary barrier (the part of the cargo tank in contact with the cargo) (2)The secondary barrier (for cargoes with temperature between -10°C and -55°C the ships hull may act as the secondary barrier) (3)Associated thermal insulation (4)Intervening spaces, and (5)Adjacent structure supporting the preceding elements.
Pressurised Deck Storage Tanks
Gas Carrier Cargo Tank Types The basic types of cargo tanks on board gas carriers are: (1)Independent type ‘A’ – used in fully refrigerated applications (2)Independent type ‘B’ – used in LNG applications (3)Independent type ‘C’ – used in fully pressurized applications (4)Membrane – used in LNG applications
Independent Tanks The International Gas Code defines the three types ‘A’, ‘B’ and ‘C’ based mainly on design pressure. Independent tanks are completely self-supporting and do not form part of the ship’s hull structure or contribute to the strength of the hull. Independent tanks are supported by the inner bottom on stools saddles or skirts.
Independent Type ‘C’ Tanks The tanks of a typical fully pressurized gas tanker, where the cargo is carried at ambient temperature, will have a maximum working pressure around 18 barg. Type ‘C’ tanks are designed and built to conventional pressure vessel codes and correspondingly be analysed accurately for stress. Design stresses are kept low and there is no need for secondary barriers for Type ‘C’ tanks.
Independent Type ‘A’ Tanks These are usually self-supporting, prismatic tanks constructed primarily of flat surfaces and requiring conventional internal stiffening. The material used for Type ‘A’ tanks is not resistant to crack propagation. Secondary containment system in the form of a secondary barrier is required for all fully refrigerated tankers carrying cargoes in the range -10°C to -55°C, to ensure safety in the event of a leak. The secondary barrier must be a complete barrier capable of
containing the whole tank volume at a defined angle of heel and may form part of the ship’s hull. The appropriate parts of the ship’s hull must be constructed of special steel capable of withstanding low temperatures and contain a tank leakage for up to 15 days (IGC Code). The space between the primary and secondary is called the hold space. The primary tank can be covered in foam insulation or the whole hold space filled with perlite insulation. When flammable cargoes are being carried, the hold space is filled with inert gas to prevent a flammable atmosphere being created in the event of a leak from the cargo tank. The maximum allowable tank design pressure in the vapour space of Type ‘A’ tanks is 0.7 barg. Cargoes must be carried at or near atmospheric pressure, 0.25 barg.
Internal Insulation Tanks Internal Insulation tanks use insulating material to contain the cargo. The insulation is fixed inside the ship’s inner hull or to an independent load-bearing surface. This system eliminates the need for an independent tank and is capable of carrying cargos down to about -55°C. These tank have proved to be unsatisfactory in service.
Semi-Membrane Tanks This is a variation of the membrane tank system. The primary barrier is much thicker than the membrane system and has flat sides and roundish corners. The tank is self-supporting when empty but not when loaded. When loaded, the liquid and vapour pressures acting on the primary barrier are transmitted through the insulation to the inner hull like with the membrane system. The corners and edges are designed to accommodate the expansion and contraction. Semi-membrane tanks were developed for the carriage of LNG but never used, the system has been used on some fully refrigerated LPG tankers.
Integral Tanks Integral tanks form a structural part of the ship’s hull and are subjected to the same loads and stresses as the hull structure. Integral tanks are not normally allowed for the carriage of liquefied gas cargoes below -10°C. Certain tanks on a limited number of (Japanese-built) LPG tankers are integral tanks dedicated to the carriage of fully refrigerated butane.
LNG Tanker Tank Designs Independent Type ‘B’ Tanks Type B tanks can be constructed of flat surfaces or be spherical. The most common arrangement of the Type ‘B’ tank is the spherical, Kvaerner Moss design. Type ‘B’ tanks are subject to a more stringent stress, fatigue and crack propagation analysis. These design parameter means the Type ‘B’ tank needs only a partial secondary barrier in the form of a drip tray. The hold space in this design is usually filled with inert gas. The hold space may be filled with dry air provided the space can be filled inert if the gas detection system shows cargo leakage. A protective steel weather cover in the shape of a dome covers the insulated primary barrier above the deck. Prismatic shaped Type ‘B’ tanks exist in LNG service and have the benefit of maximizing tanker-hull volumetric efficiency. When Type ‘B’ tanks are prismatic in shape, the maximum design vapour space pressure is limited to 0.7 barg.
IHI SPB The Self-supporting, Prismatic-shape, Type ‘B’ offers robustness, antisloshing design, wide and flat upper deck, easy operation and maintenance and tanks fit snugly into required hull shape. This tank type is the best solution for LNG carriers engaged in partial (any level) loading, multi-port loading/unloading and operation in harsh environment seas. It is also suitable to FPSO/FSRU applications.
Membrane Tanks In membrane ships the containment is attached to the complete inner hull of the vessel. These tanks are not self-supporting like independent tanks, an inner hull forms the load bearing structure. The membrane containment system is based on a 0.7mm to 1.5mm membrane which is supported through the insulation. Membrane containment systems must always be provided with a secondary barrier to ensure the integrity of the total system in the event of primary barrier leakage. The membrane is designed to compensate for expansion and contraction without over-stressing the membrane itself. There are two main types of membrane systems in use in the LNG industry, both named after the companies that developed them. These two companies have now combined into one. There are four types of membrane tanks, three designed by Gaz Transport & Technigaz (GTT).
Membrane Tank Types GTT (TGZ) Mark III The GTT Mk III system has a primary barrier of 1.2mm, stainless steel having raised corrugations or waffles to allow for expansion and contraction. The Mark I design had laminated balsa wood panels between two plywood layers supporting the primary barrier membrane. The outer plywood formed the secondary barrier. The balsa wood panels were interconnected with specially designed joints comprising PVC foam wedges and plywood scabs and were supported on the inner hull of the tanker by wooden grounds. In the Mark III design the balsa wood has been replaced by reinforced cellular foam containing a fiberglass cloth/aluminum laminate acting as a secondary barrier.
GTT (GT) No.96 This system comprises of a primary barrier made of Invar. Invar is a stainless steel alloy containing approximately 36% nickel and 0.2 % carbon and having a low coefficient of expansion. The primary barrier is attached to inner side of perlite-filled, 200mm to 300mm thick plywood boxes. The outer side of the perlite-filled plywood boxes is attached to another layer of Invar, which forms the secondary barrier. The low coefficient of expansion of the Invar makes expansion joints or corrugation in the primary or secondary barriers unnecessary. Newer incarnations of the GTT No.96 design utilizes Invar membranes 0.7mm thick in strakes 0.5m wide and strengthened plywood boxes to hold the silicon-treated, water-impervious perlite. The thickness of the insulation boxes is adjustable and has an effect on the amount of boil-off that occurs.
CS1 Combined system number 1, the CS1 membrane system is cryogenic liner directly supported by the ship’s inner hull. The primary membrane is made of the same Invar alloy described in the No.96. The insulation consists of prefabricated panels in reinforced polyurethane foam including both primary and secondary insulation. This is a load-bearing system where the panels are bonded to the inner hull by resin ropes, which anchor the insulation and spread the loads evenly. The secondary barrier is made of a composite laminated material: a thin sheet of aluminum between two layers of glass cloth and resin. It is positioned inside the prefabrication insulation panels between the two insulation layers.
KC1 Developed by the Korean Gas Corporation in collaboration with HHI, DSME and SHI. The main characteristic is the simplicity in the containment structure. The basic concept of the KC1 system is to minimize the effect on the insulation system by the hull and primary barrier deformation. No insulation panels are bonded to the inner hull. The membrane panels are prefabricated at a shop by plasma arc butt welding and installed at yards by plasma arc lap welding.
Independent Type ‘C’ Tanks These, up to about 30,000m3, have in the last few years, been used for LNG
GT No.132 In development, this is similar to the GT96 but has lighter plywood boxes with corrugated diagonal bulkheads for greater strength which go one way in the secondary barrier and the other in the primary barrier, making a much stiffer structure. The insulation material is aerogel.
The Containment Cycle LNG gasifies violently when directly introduced into a cargo tank at ambient temperature, rapidly increases the internal pressure of the cargo tank and makes the atmosphere into a flammable condition. In addition, the cargo tank is rapidly cooled, resulting tremendous thermal stress on cargo tank skins and cargo piping systems. To avoid such damages, the preparatory work for cargo loading after dry docking must be done in the following sequence. During dry dock all the compartments of an LNG carrier are kept gas free. After leaving the dry dock the vessel has to be prepared to load cargo, for that the following points to be considered with priority.
Drying During dry docking or inspection, cargo tanks which have been opened and contained humid air, must be dried to avoid the formation of ice when they are cooled down and the formation of corrosive agents if the humidity combines with sulfur and nitrogen oxides which might be present in excess in the inert gas. The drying operation need not be performed independently by using dry air, instead during inerting operation by supplying dry inert gas, drying operation can be achieved. During such operation special
attention is required to the delivery temperature of inert gas to prevent condensation of humid air inside the tank. It is essential that cargo tanks are thoroughly inspected for cleanliness, free of liquid, any loose objects and all fittings are properly secured. Once this inspection has been completed, the cargo tank should be securely closed and drying operation can be started. During drying operation, the atmosphere must be measured at different levels at regular intervals. When the dew point of the cargo tank drops below than the planned temperature, finish the drying operation.
Inerting After drying, the cargo tanks are filled with inert gas or nitrogen. To go into service, the tanks must first be inerted. The inert gas is blown into the cargo tanks to displace the fresh air until the oxygen content reaches 4%. This removes the risk of an explosive or flammable atmosphere in the tanks.Before introducing the cargo into the tanks, the moisture content and oxygen content in the tanks shall be reduced simultaneously. Cargo tanks filled with air shall be dried and inerted with inert gas supplied from the inert gas generator on board. Inert gas shall be led into the bottom of the cargo tank through the liquid filling line and displaced air shall be vented to the atmosphere through the vapour line and the vent mast. Drying and inerting shall be finished when the dew point and also the oxygen content in the cargo tank are less than the planned level.
Gassing If the purging has been done with inert gas, the cargo tanks have to be gassed up and cooled down when the vessel arrives at the loading terminal. This is because, inert gas contains about 14% carbon-dioxide, which will freeze at around -60ºC and produces a white powder which can block valves, filters and nozzles. During gassing up, the inert gas in the cargo tanks is replaced with warm LNG vapor. This is done to remove carbon dioxide and to complete drying of the tanks. LNG liquid is supplied from the terminal to the liquid manifold where it passes to the stripping/spray header via the appropriate ESDS liquid valve. It is then fed to the main vaporizer and the LNG vapour produced is passed at a temperature warmer than the dew point temperature existing within the cargo tanks through the vapor header and into each tank via the vapor suction fitted in the upper part of the tank. This method of gassing up is called “Piston Flow Method”. In this the lighter specific gravity LNG vapor is injected from top and the heavier IG is displaced from bottom.
In the cargo cycle, the inert gas must be displaced by vapour to create the hydrocarbon rich atmosphere and as a precursor to cooling the cargo tank. Liquid gas is brought on board (or taken from the pressure vessel of the LPG tanker if available) and passed through a vaporizer which evaporates the liquid to vapour before it passes through a gas heater.
Requirement to purge with Nitrogen At the start of the operation, the piping system and main vaporizer contain inert gas. Consequently to avoid the formation of water condensate or solid CO2, the supply line to the vaporizer from the manifold has to be first purged with Nitrogen either by using the ships or shore supplying.
Completion criteria When 5% methane (% figure will be specified by the particular port authority) is detected at the vent mast riser, the exhaust gas is directed ashore. The operation is considered complete when the methane content, as measured at the top of the cargo filling pipe, exceeds 98% by volume. Due to local regulations on venting methane gas to the atmosphere, some port authorities may require the entire operation to be carried out with the exhaust gases being returned to shore facilities.
Cooling Cool down is an operation to pre-cool cargo tanks and lines required before taking on cryogenic LNG. Cargo tank cool down is carried out by spraying LNG through the spray nozzles of each cargo tank, using LNG received from the shore terminal. The cool down operation from an ambient temperature (from a condition after gassing up) to a planned temperature, is called ‘initial cool down’ and is to be differentiated from an ordinary cool down operation carried out on ballast voyage. Before LNG can be introduced into the cargo system of an LNG vessel, the system, and in particular the cargo tanks, have to be cooled down to a temperature close to that of the LNG which is to be loaded. The reasons for this are as follows: If LNG is introduced directly into warm tanks, the LNG will almost immediately turn into vapour. LNG has a liquid to gas expansion ratio 1: 600. Therefore, to enable the liquid to be loaded into the tank at a reasonable loading rate, necessity of large compressors would be required to remove the vapour generated in the process. By reducing the cargo tank temperature, the amount of heat that is
available to transfer into and heat the LNG is minimized. Consequently the amount of vapour generated can be maintained within reasonable limits.
Loading Operation LNG is loaded via the loading manifolds to the liquid header and then to each tank filling line. The boil-off and displaced vapour leave each tank via the vapour suction to the vapour header. The vapour is initially free-flowed to shore via vapour crossover manifold and, as tank pressure rises, one compressor is brought into operation to increase the gas flow to shore and limit the vapour main and cargo tank pressure. As the loading rate increases, it is important to monitor the tank pressures and to start one HD compressor. If the compressors are unable to cope with the volume of boil-off and displaced gas, it will be necessary to reduce the loading rate.
Loading Limits/Sloshing As a general rule LNG membrane tanks maintain levels higher than 80% of the height of the tank or lower than 10% of the length of the tank.
Loaded Sea Passage This is mainly boil-off gas management and depends on the type of propulsion system in use on the LNG carrier.
Discharge Operation During a normal discharge, the main cargo pumps will be used and a quantity of cargo will be retained on board for keeping the cargo tanks cold on the ballast passage. The quantity to be retained on board depends on the duration of the ballast passage. During discharge, LNG vapour is supplied from shore to maintain pressure in the cargo tanks. The main cargo pumps discharge LNG to the main liquid header and then to shore via the midship liquid crossover manifold connection. After an initial rise in tank pressure, the pressure decreases and it becomes necessary to supply LNG vapour from ashore via the manifold, crossover and vapour header into the cargo tank domes in order to maintain pressure 109kPa absolute. Each tank is discharged down to about 0.2m level and the heel tank will be at a level depending on the duration of the ballast passage, expected elapsed time before loading and the volume of BOG estimated to be required by the ship’s boilers.
If the ship has to warm up tanks for technical reasons, the stripping/spray pumps will be used to discharge the remaining cargo on completion of the bulk discharge with the main cargo pumps.
Ballast Passage A characteristic of membrane tanks is that temperature at the top of the tank will remain below -50˚C as long as there is liquid in the bottom of the tank. If the ballast voyage is too long the lighter parts of the LNG will evaporate leaving the warmer heavier LPG parts.
Preparing for Dry Dock Tank Warm up Tanks are warmed up by recirculating heated LNG vapour. The vapour is recirculated with the two HD compressors and heated with the cargo heaters to about 80˚C. Initially, hot vapour is introduced through the filling lines to the bottom of the tank to assist with the evaporation of any liquid remaining in the tank after discharge. After temperature gauges at the bottom, aft end of the tank indicate that liquid puddles have evaporated, hot vapour is introduced through vapour piping at the top of the tanks. Excess vapour generated during the warm-up is vented to atmosphere at sea and sent ashore in port. Warm-up continues until the warmest part of the insulation space barrier of each tank reaches +5˚C. Expected duration of the warm-up depends on the (1) amount and (2) composition of the liquid remaining in the tanks, (3) initial temperature of the tank, (4) temperature of the insulation spaces and at sea, (5) pitching and rolling of the vessel. Typical warmup operation time on a 136,000 m³ membrane tanker is about 30 hours.
Purging After warming up the tanks, the LNG vapour has to be displaced with inert gas. IG from the inert gas generator is introduced at the bottom of the tank through the LNG loading line. Gas from the tanks is vented from the top of the tank through the forward vent riser (at sea) or to shore, if in port. The operation is continued until the hydrocarbon content is reduced to less than 2.5% (50% of LEL). Typical purging operation time on a 136,000 m³ membrane tanker is about 20 hours.
Aerating Before personnel can enter the cargo tanks, the inert gas must be replaced with air. The IG/dry air system is switched to dry air production and dry air with dew point -55˚C to -65˚C is introduced to the cargo tanks. The dry air enters the cargo tank via the vapour
header. The IG/dry air mixture is removed from the bottom of the tanks to the atmosphere via the loading pipes, liquid header and forward vent riser. The operation continues until (1) the O2 content is 20% by volume, (2) the methane content is less than 0.2% volume, (3) the dew point is below -40˚C, (4) carbon monoxide is less than 50ppm and (5) carbon dioxide is less than 0.5% by volume. Typical aerating operation time on a 136,000 m³ membrane tanker is about 20 hours.
LNG Cycle In Normal Service Pre Loading Meeting Before loading operations begin, the pre-operational ship/shore procedures must be thoroughly discussed and followed. Appropriate information exchange is required and the relevant parts of the ship/shore safety check list should be completed.
Line Cool Down Prior to commencing the loading operation the cargo pipelines have to be cooled. The primary reasons for cooling the cargo lines are: i) To minimize the possibility of leaks being created at joints with valves or other sections of pipeline as they contract when cargo is passed. ii) To reduce the possibility of sudden shock loadings on bellows as pipes contract rapidly iii) To avoid the formation of vapor locks in the pipelines when cargo is introduced. If LNG is introduced into a warm pipeline the initial cargo will vaporize, create a large pressure that can ‘block’ the loading of the liquid. It is then possible that this vapour will then condense very rapidly as the temperature reduces below the condensation point, allowing the liquid to surge along the pipeline possibly resulting in damage to the pipelines, valves or connections.
Cold Maintenance During Ballast Passage Short Voyages The normal amount of cargo left on board, after discharge, on a membrane tanker is sufficient for the tanker to arrive load ready after a short voyage. The level must never be above 10% of the length of the tank. A boil-off rate around 0.18% per day should be anticipated. The aim should be to arrive at the load port with at least 10 cm of liquid spread evenly over the whole surface of the tank bottom (vessel even keel). Actual quantities will be worked out after a few voyages.
With this method, the tank bottom temperature should be -150˚C and the top -50˚C, the tank is load ready.
Longer Ballast Voyages During longer ballast voyages, the lighter parts of the liquid in the tanks will evaporate, practically leaving LPG warmer than -100˚C in the bottom of the tank, and a great likelihood of positive temperatures at the top. In this event the tanks will have to be cooled before loading can occur.
Tank Cooling Cool down is achieved by introducing LNG to the tanks via the two spray rails/rings in each cargo tank. The method used for cooling the cargo tanks depends on the operating condition of the ship. (a) Tanks can be cooled just before arrival at the loading terminal. A quantity of LNG heel (not exceeding 10% of tank length) is retained in on cargo tank on completion of discharge. (b)The cargo tanks are kept cold by periodically spraying the tanks with LNG to maintain -120˚C to -130˚C inside the tanks. Expected boil-off rates for heel quantities are 50%. (c) Cool down the cargo tanks with LNG supplied from ashore.
Air purge of loading arms After the connection of loading arms, air should be purged from the loading arms and the tips of manifold pipes. N2 gas is lead into the loading arms from injection lines connected to the arms, and then pressurize up to about 4 to 6 kg/cm2G. After pressurization, the ship’s liquid manifold vent valve and vapor manifold vent/drain valve are opened to release air and N2 gas into the atmosphere. While this operation is repeated two or three times, a leak test (with soap solution) is conducted at the same time. Air purge comes to an end when the oxygen content of the purged gas has dropped below 2%.
Loading Arms Cool Down The cool down of the loading arms is performed from shore side by use of a small capacity pump. At a discharge port, the arms are cooled down by sending in LNG by ship’s spray pump.
Containment-associated Machinery Inert Gas System Inert -
gas is used for several purposes: to maintain neutral atmosphere in hold and inter barrier spaces to eliminate cargo vapour from cargo tank for gas freeing to eliminate oxygen from cargo tank before loading to dry hold and inter barrier spaces to achieve a neutral atmosphere and to prevent corrosion in the spaces - to place a neutral vapour above the cargo (like a ‘blanket’) Inert gas generators have the advantages of being available at sea or in port and being cheaper than purchasing liquid nitrogen. IG produced by the careful combustion of diesel results in reduced oxygen content (1%) in the products of combustion. The Gas Codes require the continuous oxygen monitoring in the inert gas stream. High oxygen content should trigger an alarm and cause the gas to be diverted to atmosphere via a vent riser.
IG Generators The IG generator has three main parts: Combustion chamber (with scrubbing and cooling) This type of generator must be located outside the cargo area with permanent piping to the hold spaces but temporary or removable or blank fitted connections to the cargo system. Two non-return valves are fitted to the IG main line to prevent back-flow of cargo vapour to the combustion chamber. The burner is designed to produce minimal oxygen residue in the water-jacketed combustion chamber. The hot gas next enters the scrubber, where it is sprayed with seawater. Scrubbing removes soluble acid gases (sulphur dioxide and nitrogen oxides. The gas leaves the scrubber about 5° warmer than seawater temperature, free from oxides but saturated with water vapour. Refrigerated drier In the refrigerated drier the IG is cooled to about 4°C causing the condensation of much of the water vapour. Absorption drier The absorption drier consists of two towers filled with activated alumina or silica gel. One tower is on drying duty while the other is being regenerated. Drying in the absorption drier reduces the dew point of the IG to -40°C or lower. Typical cycle time is six hours.
Dry Air System Dry air, with a dewpoint of -70ºC to -40ºC, can be produced by the onboard Inert Gas Generator system. The dew point shall be
periodically measure by a portable instrument at the sampling lines in way of cargo tank dome.
Heat Exchangers Heat exchange is required throughout the operation of the cargo and containment systems and machinery of gas tankers. The heat exchangers can be heaters or condensers. The heat exchangers must be designed and tested for the products they are to carry. Heat exchangers are subject to pressure testing and certification from classification societies.
Purge Gas Condenser System In LPG applications, if the gas from the compressor discharge is required for spraying liquid in the tanks it needs to be condensed. Sometimes all the gases are not condensed in the main condenser and a second, purge gas condenser which, through the use of expansion valves, separates the gases incapable of being condensed to the vent riser.
Tube Heat Exchangers Shell & Tube Vaporisers (STV) in cargo heater application are fitted on an incline with Liquefied Gas introduced on the low end and vapour emerges on the high end. The advantages of STV design are: - Proven technology - Sea water – no intermediate fluids - Ease of operation (heating on first/off last - Simplified control system (minimal monitoring of temperatures and flow rates; minimal throttling of flows - Compact design - Offshore compatibility - Fast start-up and shutdown - Infinite turndown capability The vapour from the vaporizer is warmed up in the gas heater before being blown into the tank to displace the inert gas.
Plate Heat Exchangers Plate heat exchangers are built with thin plates with double liquid channels. The plates are installed with the flat sides toward each other. The cooling medium and the product are pumped each way in the channels to achieve the best possible cooling or heating. Plate heat exchangers are also used as condensers on newer cargo cooling plants aboard gas tankers.
Piping Cargo Lines The cargo lines on a gas carrier: liquid lines, vapour lines and lines to vent riser have the same requirements as the pressure vessels regarding the temperature and pressure they should be able to handle. Cargo lines less than 25mm in diameter can be connected with threads. All cargo lines with diameter exceeding 25mm must be flanged or welded. All welding on pipes, flanges and spool pieces exceeding 75mm diameter and 10mm wall thickness must be x-rayed and classed. The material used for cargo lines outside the cargo tank must have melting point not less than 925°C. Cargo lines designed for product less than -10°C must be insulated from the ship’s hull to prevent the ship’s hull being cooled below design temperature. All thermally insulated lines must be electrically bonded to the hull with steel wire or steel bands. On each flange on lines and pipes where gaskets are used there must be electrical bonding with steel wire or steel band from flange to flange.
Drip Trays The hull has to be protected against cold cargo spill under spool pieces and valves, this is done with planks or plywood. To prevent cold cargo spill on the hull plates, a drip tray is placed below the manifold flanges. All cargo lines that might contain liquid must be fitted with a safety valve. Vapour from the safety valve outlet must pass to the cargo tank or the vent riser. The pipe leading to the vent mast must be equipped with a liquid collector to prevent liquid going up the riser.
Tank Dome and Pipe Tower construction All the pipework connections to tanks beneath the deck must be through the cargo tank dome. The tower which supports the pipe-work within the tank is constructed of stainless steel bars. If subjected to rapid cooling thermal stress within the material can be excessive, leading to the material cracking.
Spray Cooling Lines
Strainers Manifold connections are fitted with strainers for loading and discharging. The strainers are intended to protect cargo handling plant and machinery from damage by foreign objects.
Valves Gas tankers utilize ball, globe, gate or butterfly valves. The valves are usually fitted with pneumatic or occasionally hydraulic actuators. Valves must be fire safe type. The Type C (Pressurised tanks with MARVS greater than 0.7 barg) cargo tanks are required to have double valves on all liquid and main lines except relief valve connections. This double valve arrangement comprises a manually operated globe valve in series with a remotely operated isolation valve. Type A (Fully refrigerated) and Type B (non-membrane LNG) tanks with MARVS less than 0.7 barg must have shut off valves for liquid and vapour connections. These valves must be capable of local and remote operation.
Emergency Shut Down (ESD) Pneumatic vent valves or electric push buttons are provided at the cargo control room, compressor room, gangway, bridge front and emergency control stations. These switches when operated close remotely operated valves and stop cargo pumps and compressors. ESD should also occur upon loss of electrical or control power, valve actuator power (fail safe) and fire at the tank domes or manifold (via suitably located fusible elements). Individual tank filling valves are designed to close automatically upon actuation of an overfill sensor in the same tank.
Surge Pressure The possibility of surge pressure generation exists when the ship’s ESD system is activated during loading. The situation varies depending on characteristics of the terminal and is a function of the loading rate, the length of the pipeline, the closure rate of the valve and the type of valve. The effects of surge pressure can be extreme and affect harm loading arm joints or rupture hoses or even cause movement in the loading line. Terminals may need to check ship manifold valve timing. Loading rates and or valve times may need to be adjusted.
Pressure relief and Vacuum protection valves IMO Codes require at least two pressure relief valves of equal capacity to be fitted to any cargo tank greater than 20m3 in capacity. Less than 20m3, one PV valve is enough. IMO Codes also require for all pipelines or components which may be isolated when full of liquid to be provided
with relief valves to allow for thermal expansion of the liquid. These valves can relieve either into the cargo tanks or to the vent riser via liquid collecting pots. Spring loaded relief valves are used on Type C (MARVS >0.7 barg) tanks only. Pilot-operated valves are found on Types A, B and C tanks.
Pumps Cargo Pumps Cargo pumps fitted on board refrigerated gas tankers are normally of the centrifugal type, either deepwell or submerged. The transfer pumps are installed in the ship’s tanks. There is often also a booster pumps on LPG carriers. The in-tank cargo pumps can be operated alone or in series with a deck mounted booster pump where cargo heating is required for discharge to pressurised storage. Some fully pressurised ships discharge by pressurizing tanks and using booster pumps to assist in transferring cargo ashore.
Submerged Pumps These pumps are used on all LNG carriers and on many of the larger fully refrigerated LPG carriers. The pump assembly and electric motor are close coupled and installed at the bottom of the cargo tank. Power is supplied to the pump motor through copper or stainless steel sheathed cables passing through a gastight seal in the tank dome and terminate in a flameproof junction box. Submerged pumps and there motors are cooled and lubricated by the cargo and therefore susceptible to loss of flow rate damage.
Deepwell Pumps These are very common on LPG carriers. The pump is operated electrically or hydraulically by a flange mounted motor outside the tank. The drive shaft is guided in carbon bearings inside the discharge tube, the bearings are cooled and lubricated by cargo flow up the discharge tube. The impeller assembly is at the bottom of the tank is either a two or a three stage impeller with a first stage inducer.
Booster Pumps Booster pumps are centrifugal pumps on the appropriate discharge line and can be deck-mounted, vertical, in-line pumps driven by intrinsically safe electric motor or can be horizontal, installed on deck or in the cargo compressor room driven by an electric motor in the electric motor room. The electric motor room is fitted with double door airlock
for entry by personnel, the motor shaft is attached to the pump through the gas tight bulkhead between the two rooms.
Stripping Pump Spray Pump A low capacity pump installed in some gas carriers. Function may vary but they are generally used for spray cooling tanks to reduce temperatures sufficiently to allow loading to proceed. Can also be used for cooling lines or stripping lines before warm-up. Spray pump used on some steam turbine LNG carriers to supply LNG to a forcing vaporizer to provide additional boiler gas fuel
Gas Fuel Pump A smaller version of a spray pump, optimized to supply LNG to a forcing vaporizer, to supplement natural gas boil off being used as fuel for vessels with dual-fuel diesel engines.
Gas Compressors Compressors are used as vapour pumps to either compress or move cargo vapour. The compressors need to be protected against the possibility of liquid entering and seriously damaging the compressor. A compressor suction liquid separator is installed on the compressor suction line from the cargo tanks. The pot on this liquid separator is fitted with a high level sensor which sets of an alarm and trips the compressor. Mechanically, some of the different types of compressor are: piston compressors, double-acting compressors, single-acting compressors, screw compressors and oil-free screw compressors.
Vapour Return Compressor (High Duty) Gas compressor fitted on board the ship to return the gas displaced during loading to shore during cargo loading. Also used to circulate the containment system during warm up. Peak demand will typically require the use of two compressors operating in parallel.
Gas Fuel Compressor (Low Duty) The low-capacity compressor used to transfer boil-off gas to the gas burning system in an LNG carrier.
Boil-off Gas Compressor BOG compressor is a gas fuel compressor, the primary function of which is to transfer boil-off gas to the cryogenic heat exchanger of an on board reliquefaction plant.
Reliquefaction System Compressor Gas compressors used in cargo reliquefaction systems
Volumetric Compressor A reciprocating or positive displacement compressor capable of producing excessively high discharge pressures if run against a shut valve.
Nitrogen System LNG ships used have storage facilities for liquid nitrogen but newer designs include a nitrogen generation plant. They are mainly fitted for inter barrier space inerting and most do not have the enough volume for tank inerting operations. The most common system for the production of nitrogen on ships is an air separation process. Air is separated into its component gases by passing compressed air over hollow fibre membranes. The membranes divide the air into two streams: one for nitrogen and the other for oxygen, carbon dioxide and some trace gases. This system can produce nitrogen of about 96% purity. This quality of nitrogen is inadequate for oxygen-critical cargoes. Pure nitrogen is taken from either road tank wagon or barge.
Gas Detection System Hold Space Ventilation System Hold Space Stripping
Containment Management Activities LPG Reliquefaction Systems Reliquefaction plant is fitted to all except fully pressurized LPG tankers. The plant is used to: (1) cool down the cargo tanks and cargo pipe work before loading, (2) reliquefy the cargo vapour produced by flash evaporation, liquid displacement and boil-off during loading when there is no vapour return line to shore and (3) to maintain or reduce cargo temperature and pressure within the prescribed design limits of the cargo system during the sea passage.
The most common type of LPG reliquefaction plant in use is called direct cycles and involves the evaporated cargo vapour being compressed, condensed and returned to the tank.
Single-stage direct cycle Single-stage direct cycle is suitable where suction pressures are relatively high, as with semi-refrigerated products. Boil-off vapours are drawn from the cargo tank by the compressor and compressed. The compression process increases the pressure and temperature of the vapour allowing it to be condensed against seawater in the condenser. The condensed liquid is flashed back to the tank via a float controlled expansion valve. The liquid/vapour mixture returned to the tank may be distributed at the top of the tank (if full) or taken to the bottom of the tank (if empty) to discourage revaporisation.
Two-stage direct cycle The two-stage cycle is used where suctions pressures are low and compression ratios are correspondingly high compared to single-stage. When two-stage compression with inter-stage cooling is used, it is sometimes necessary to limit compressor discharge temperatures, which increase significantly with increasing compression ratio.
Cascade direct cycle The single-stage compression of cargo vapour is the same as the single-stage compression. The cascade system uses a refrigerant e.g. R22 instead of seawater to condense the cargo vapours. The (condensing) cargo evaporates the liquid R22 and the R22 vapours are taken through a conventional closed refrigeration cycle. Cascade cycle is useful for fully refrigerated cargoes and plant capacity is not affected by seawater temperature changes.
LNG Boil-off Gas Management Steam Turbine Propulsion The boil-off gas (BOG) on ‘conventional’ LNG tankers are compressed and burned in boilers to provide steam for the steam-turbine propulsion system. The boilers are equipped with heavy oil and natural gas burners. Excess BOG could be disposed of directly in the boiler and the excess steam produced being to the sea water cooled condenser rather than to the propulsion turbine via a bypass valve towards the condenser. Disadvantages of steam turbine propulsion: • Equipment bulkier compared with other propulsion modes, consequently reduces cargo carrying capacity for same hull size
• •
Fuel efficiency is 30% instead of 45% Maintenance and crewing increasingly challenging due to depletion of steam propulsion expertise Since 2005, LNG carriers with direct drive slow speed dual fuel diesel engine(s) propulsion, electric propulsion with medium speed dual fuel diesel engines and electric propulsion with dual fuel gas turbine(s) have come into service. These propulsion alternatives were not addressed in the IMO Gas Code.
Steam Turbine
Fuel
Dual Fuel Diesel Electric
Slow Speed Diesel with Reliquefa ction
Gas/Liquid Fuel
Gas/Liquid Fuel
Liquid Fuel
Low
Relatively High
High
Emission
Relatively Low
Low
High
BOG Treatment
LD Compressor (1 barg)
LD Compressor (5.5 barg)
Reliquefaction Plant
Boiler
Engine
CAPEX and Maintena nce Cost
Low
High
Relatively Low
Fuel Flexibility
Yes
Yes
No
Fuel Efficiency
Boil-off Gas Management A boil-off gas utilisation system is an arrangement of BOG consumers (DFDE, GCU, DFGT or reliquesfaction units) intended for controlling cargo tank pressure and maintaining it below the maximum allowable relief valve (MARV) setting. Any BOG Utilisation Unit should have the following equipment and features: 1. Automatic Gas Shut-off Valve The BOG supply to each gas utilization unit located outside of the cargo area is to be provided with its own individual gas shut-off valve arranged for automatic closure.
2. Automatic Purge The piping between the automatic gas shut-off valve and the gas utilization unit to be purge automatically with inert gas in the event of closure of the automatic gas shut-off valve. 3. Master Gas Valve Additional to the automatic gas shut-off valve(s) and operable from CCR or any machinery space and should close automatically in the event of: high-high level in the cargo tank, black-out, fire on deck or the compressor room, fire in the area of the fuel gas line outside the accommodations, low temperature in gas header to the engine room. 4. Pressure Surge Protection In the piping system including downstream of the compressor
Gas Combustion Unit (GCU) A Gas Combustion Unit (also called Thermal Oxidiser) is a system used for controlling the pressure in the cargo tanks by burning the boil-off gas from the cargo tanks inside an enclosed combustion chamber under controlled and safe conditions. GCU • • • • • • • • •
system will generally contain the following major components: Boil-off gas compressors Heaters Automatic gas shut-off valve and associated pipework Piping in the safe areas where the GCU is located aft of the cargo block Gas valve enclosure and venting of the enclosure Gas burner unit including oil pilot burner and burner management system which offers a wide operating range in terms of BOG flow and N2 content; Combustion chamber which contains the flame and dilutes the combustion gases with fresh air; Forced draft fans provide air for combustion of the BOG and cooling by dilution the corresponding hot gases; Exhaust trunk from the GCU
Preferred location of the GCU is at the aft of the vessel above the main engine room, within the engine exhaust pipe casing.
LNG Reliquefaction on LNG Tankers A Reliquefaction Unit is a system used for taking the boil-off gas from cargo tanks and condensing it in a refrigeration system. LNG is returned to the cargo tanks. A typical reliquefaction plant will comprise
an electric motor-driven boil-off gas compressor, cryogenic heat exchangers, pre-coolers, separator, nitrogen storage tanks, an LNG transfer system, electric-driven refrigeration compressors/expanders with interstage stage coolers, a discharge cooler and associated control systems. The Q Flex and Q Max vessels use shipboard reliquefaction to process boil-off gas (BOG) in order to balance and achieve the efficiency gains of using slow-speed diesel propulsion. The Q Flex and Q Max vessels have a boil-off rate averages around 0.14% of the cargo volume per day (for pure methane). The actual boil-off rate is affected by ambient temperature, weather, sea state. Immediately after loading, the boil-off rate can be 1.5 times the normal rate. Reliquefaction systems are very sensitive to these fluctuations in BOG conditions. Q Flex Q Max Hamworthy Gas Systems Cryostar EcoRel System BOG from the cargo tanks is preBOG is compressed in a two-stage, cooled by heat exchange with a integrally-geared centrifugal small stream of reliquefied BOG compressor. Both compressors (condensate). The condensate is have Diffuser Guide Vanes (DGV) vaporized in the heat exchanger to control BOG flow through the and mixed with incoming BOG system. from the cargo tanks. Incoming BOG is cooled by a nitrogen intercooler on the BOG compressor. Pre-cooled BOG is compressed in a Compressed BOG is cooled in a two-stage, integrally-geared shell-and-tube heat exchanger centrifugal compressor. Both (BOG desuperheater) compressors have Diffuser Guide Vanes (DGV) to control BOG flow through the system. Compressed BOG enters a plateCompressed BOG then condensed fin heat exchanger where it is in a plate-fin heat exchanger cooled and condensed against the cold nitrogen stream. Reliquefied BOG is collected in a The reliquefied BOG is slightly separator to remove nonsubcooled and can be returned condensable gases (if present). directly to the tanks without Pressure in the separator is forces requiring the separator. the reliquefied BOG back to the (for high N2 cargoes, the BOG cargo tanks and to the precooler. condenser is routed through the separator to remove N2 rich vapour to either cargo tank or GCU) N2 Compander Unit - HGS Mark I
N2 Compander Unit - EcoRel
N2 is compressed from 13.5 barg to 57 barg by a three stage compressor The heat of compression is removed by two freshwater intercoolers and an aftercooler N2 is precooled to approx. -110°C in the plate-fin heat exchanger then expander 14.5 barg and -163°C for reliquefying BOG
N2 is compressed by a three stage compressor Compressed N2 is precooled in separate plate-fin heat exchanger called the N2 counter-current exchanger After precooling N2 is expanded and sent to the BOG condenser and BOG desuperheater A small stream of cold N2 is drawn off from between the two heat exchangers to supply cooling for the BOG compressor intercooler. After BOG condenser and BOG desuperheater, the streams are rejoined and passed through the N2 counter-current exchanger before returning to the first stage of compressor suction.
Hold space Atmosphere Management The drying operation of a hold space is carried out in order to prevent tank insulation damage due to condensation of moisture inside it prior to initial cool down operation and periodically during a voyage. Fresh air is dehumidified by the IGG and sent to a hold space as dry air with a dew point of -70ºC to -40ºC through its bottom section, humid air inside the hold space is released through the vent pipe provided in the upper portion of the tank. The hold space should be maintained at a higher pressure than the atmospheric pressure. Operation procedures and precautions: i) Before delivering dry air into a hold space, completely dry up the bottom section of the hold space, particularly the bilge well. ii) When drying a hold space after completing the inerting operation of a cargo tank, purge relevant equipments and inerting/aerating lines with dry air to prevent the ingress of inert gas into the hold space. This is because the hold space holding dry air sent into it is kept almost sealed till the next dry docking and, in addition, about 15% CO2 gas is present in the inert gas, which may corrode aluminum cargo tanks and destroy insulation materials.
iii) During drying operation, measure the atmosphere at different levels at regular intervals. When the dew point of the hold space drops below than the planned temperature, finish the drying operation.
Inerting of Annular Space for Moss type vessels The space between the surface of a cargo tank and insulation is called annular space, insulation space or wedge space. Annular Space is inerted with nitrogen gas and continuously supplied from N2 generator through the N2 bleed line in service in order to ensure adequate path in the insulation space for the gas detection system. A safety valve is installed in the N2 bleeding line of each hold in order to avoid over pressure of the insulation space.
Inerting Inter Barrier Spaces (IBS) and Insulation Spaces (IS) for Membrane type vessels The space between the primary and the secondary barrier is called inter-barrier space (IBS). The space between the secondary barrier and the inner hull is called insulation space (IS). The pressure in these spaces shall be regulated at a pressure slightly above atmospheric pressure in order to prevent any air ingress. In normal operation, IBS and IS shall be purged with nitrogen in relation with atmospheric pressure variations and cooling or warming of the spaces during loading or unloading, and IBS should be continuously purged with nitrogen if gas is detected by micro-leakage of the membrane. The Nitrogen provides a dry and inert medium for the following purposes: i) To prevent formation of flammable mixture in the event of any LNG leak. ii) To permit easy detection of an LNG leak through a barrier iii) To prevent corrosion In addition each space shall be protected against over pressure by two (2) pilot operated safety valves.
During cargo loaded, as normal procedure, maintain the IBS pressure at or below cargo tank pressure and maintain the IS pressure at or above the IBS pressure.
Containment Materials Brittle Fracture Brittle fracture was way too common in the early welded ships built in the 1940s. The use of improved grades of steel has reduced but not eliminated the problem. Cryogenic liquid in contact with carbon steel can cause brittle fracture of carbon steel ship structures. LNG spilling on the hull structure or the cargo hold area will likely produce brittle fracture of the hull steel plates causing local failure of the hull, the bulkheads and the bottom structure.
Tank Material Most metals and alloys, except aluminum, become brittle below a certain temperature. The choice of cargo tank materials is dictated by the minimum service temperature and compatibility of the cargoes to be carried. Low temperature toughness is very important. Cargo Tank Materials Propane Fully killed?, fine grain, carbon-manganese steel, alloyed with 0.5% nickel Ethylene Nickel-alloyed steels or Stainless steels (e.g. Invar) or aluminum LNG Nickel-alloyed steels or Stainless steels (e.g. Invar) or aluminum
LNG Tank Material Most cargo tanks are constructed of stainless steel which is a material that retains its flexibility and strength characteristics over the temperature range being considered (-180°C - 50°C). However problems could occur if the material is subjected to very local and rapid cooling such as when a small droplet of LNG comes into contact with a warm tank wall. Because of the transfer of the heat from the wall into the liquid, the temperature at the particular point will decrease rapidly causing large thermal stresses to arise between the
point and the surrounding material. This could lead to stress cracking.
Insulation Thermal insulation must be fitted to refrigerated cargo tanks to: - Minimise boil-off by reducing heat flow into cargo tanks - Protect the tanker structure around the cargo tanks from the effects of low Temperature Insulation materials should have the following characteristics: - Low thermal conductivity - Load bearing ability - Resistance to mechanical damage - Lightweight - Resistant and non reactive with cargo liquid and vapour
Perlite Perlite is a siliceous volcanic rock that pops like popcorn when heated and increases to 4 to 20 times its original volume. On popping, it turns white, can be as light as 2 pounds per ft³, is chemically inert and has a pH of approximately 7. Perlite is less than 1% soluble in water and therefore does not absorb water. ideal
Construction Materials – Barriers
Cargo Measurement General The formula for calculating the LNG transferred depends on the contractual sales conditions. For Free On Board (FOB) sales, the energy transferred and invoiced for will be made at the load port. For FOB contracts, the buyer is responsible to provide and maintain the custody transfer measurement systems on board the vessel for volume, temperature and pressure measurement. The seller is responsible to provide and maintain the custody transfer measurement systems at the loading terminal e.g. sampling and gas analysis. For Cost Insurance and Freight (CIF) and Delivery Ex Ship (DES) sales, the energy transferred and invoiced for will be made at the discharge port. For CIF and DES contracts, the seller is responsible to provide and
maintain the custody transfer measurement systems on board the vessel for volume, temperature and pressure measurement. The buyer is responsible to provide and maintain the custody transfer measurement systems at the loading terminal e.g. sampling and gas analysis. The determination of the transferred energy usually happens in the presence of one ore more surveyors, the ship’s chief officer and the terminal representative. The buyer can also have a representative. The transferred energy can be calculated using the formula: E = (VLNG x DLNG x GCVLNG) - Egas displaced ± Egas to ER, if applicable E=
the total net energy transferred from the loading facility to the LNG tanker, or from the LNG tanker to the facility. It is most frequently expressed in MMBTU
VLNG =
the volume of LNG loaded or discharged in m³
DLNG =
the density of LNG loaded or discharged in kg/m³
GCVLNG = the gross calorific value of LNG loaded or discharged in MMBTU/kg Egas displaced = the net energy of displaced gas, either sent back onshore by the LNG tanker during loading (volume of gas in cargo tanks displaced by same volume of loaded LNG) or gas received by the LNG tanker in its tanks when discharging in replacement of the volume of discharged LNG Egas to ER =
if applicable, the energy of the gas consumed in the LNG tanker’s engine room during the time between opening and closing custody transfer surveys. + for loading or – for discharging
Cargo measuring equipment needs to be recalibrated periodically e.g. at each dry docking.
LNG Volume The standard method for measuring the volume of LNG transferred is based on the tanker’s instruments: level gauges and calibration tables. Recently built LNG tankers can produce reports of the on board quantity at any time during transfer. The ship’s computer can convert the measured LNG level in the tank to the corresponding volume and apply correction factors for trim, list and temperature and total the volumes of each of the tanks.
Cargo Transfer Surveys (CTS) The opening CTS is the initial one taken before transfer commence. The closing CTS is the final one taken on completion of transfer. The difference between the two is the volume of liquid transferred. It is recommended that the LNG piping, from the manifolds to the tanks, on the tanker be in the same condition for opening and closing CTS, either completely filled with LNG or completely drained. The recommended good practice is that initial level gauging should be done after line connection but before the vapour or liquid manifold valves are opened. The final gauge readings shall be made immediately after transfer with the liquid and vapour manifold valves closed. Level correction tables are to be used to make allowances for trim, list and temperature. In the event of failure of the primary level gauging device, an auxiliary device should be used.
Cargo Volume Measurement Equipment Calibration Tables The tables for the main and secondary gauges for each tank and: the different correction tables allowing for trim and list variances (if any), tank contraction tables for Moss-type and SPB-type cargo containment systems and other correction tables dependent on the type of level measuring device. Level Gauge Systems Each tank usually has two level gauge systems installed, one designated as ‘main’ or ‘primary’ and the other as ‘secondary’. Capacitance and radar (microwave) level gauging systems are widely used as the primary CTS system on board LNG tankers, the secondary system is usually a floating gauge system. A nitrogen bubbler system can be found on older ships. Temperature Probes Temperature probes are distributed throughout the height of the LNG tanker’s tanks Draft Gauges And other measuring devices for applying correction factors.
LNG Density The density of LNG is determined by calculation from the measured composition of the LNG transferred and the temperature measured in the LNG tanker’s tanks.
Density Measurement Equipment The average composition of the LNG is de achieved by continuous or discontinuous sampling of LNG in the LNG transfer lines between the ship and the terminal and gas chromatographic analysis followed by a calculation based on the average composition of the LNG, the average temperature and the coefficients given by a recognised bureau of standards.
LNG Gross Calorific Value The composition of the LNG is used to calculate the gross calorific value.
Gross Calorific Value Measurement Equipment The average composition of the LNG is achieved by continuous or discontinuous sampling of LNG in the LNG transfer lines between the ship and the terminal and gas chromatographic analysis followed by a calculation based on the average composition of the LNG and characteristics of elementary components (GCV, molar volume, molar weight) given by reference tables or standards for the GCV.
Gas Displaced during Transfer The energy of this gas is calculated according to the composition and volume of the gas displaced and the pressure and temperature of the gas inside the tanks before loading or after discharge.
Measuring the Energy of Displaced Gas The energy of the displaced gas is determined by sampling the gas displaced, taking a gas chromatographic analysis of the sample and calculating the GCV factor in pressure and temperature measurements from the cargo tanks.
Gas Consumed in ER Parties may agree to allow gas burning in the tanker’s engine room between opening and closing CTS. It is recommended that the LNG tanker has proper measuring equipment and an approved procedure.
Offshore Gas Terminals The use of floating offshore LNG facilities for production, export, import, regasification and gas to liquids (GTL) could help avoid some of the political and ‘not in my back yard’ (NIMBY) issues surrounding the locating of LNG facilities ashore. Offshore floating units are in use in the oil sector. The technology already exists in the shipbuilding industry.
Offshore LNG Facility Issues Location and sea condition Type of vessel and containment Mooring at the facility Mooring of the import/export vessels Access for export/import vessels (tugs and pilotage) Method of transfer of cargo Type of plant, liquefaction/regasification Deck congestion What if the LNG vessel has to leave partially filled?
Shuttle And Regasification Vessel SRVs have been in development since 2001. They are modified LNG vessels fitted with regasification plant, natural gas unloading system and natural gas odorisation and metering capability. SRVs supply gas to shore via risers and a subsea connecting pipeline. They are easy to locate offshore, environmentally friendly, usable in harsh wave environments and economically competitive in small to medium volumes over small to medium distances.
STL Buoy The deep water port (DWP) facility will have one or more submerged turret loading (STL) buoys. The buoys are tethered to the seabed and connected to the subsea pipeline end manifolds via gas risers and umbilicals. The SRV connects to the STL to discharge.
Buoy Compartment The STL buoy is pulled up, by ship’s winch, from its submerged position into a recess arrangement in the SRV’s bow. Once the connection is secure, regasification by the shipboard regasification units commences. The natural gas is discharged at high pressure, utilizing the ship’s gas production pumps via the STL buoy and a subsea pipeline to the shore gas grid.
High Pressure Pumps and Vaporisers The regasification (vaporizer) units are based on a closed loop process that uses steam as the medium for vaporizing the LNG and incorporates an intermediate closed water/glycol loop.
Floating Storage and Regasification Unit FSRUs are enlarged versions of the SRVs described above. They are permanently moored on an unloading buoy. They receive cargo from LNG carriers via ship to ship transfer system. These are economically competitive for medium to large volumes over medium to large distances.
Compressed Natural Gas Methane cannot be liquefied by pressure alone. There are several containment systems proposed for CNG, they include: steel tube, steel pressure vessels and composite pressure vessels. In each case the pressure containment vessel is located in the hold of the ship and sometimes above deck under cover. The trade is limited to about 2500 nautical miles.
Systems for the carriage of CNG Sea NG Coselle steel, coiled, 275 bar, ambient
Knutsen Steel, vertical pipes, 250 bar, ambient
EnerSea Steel, vertical pipes, 130 bar, -29°C
Statoil, Teekay, Hoegh Steel, horizontal pipes, 200 bar, ambient
Trans Ocean Gas Composite
TransCanada Wrapped steel liner
Institute Francais du Petrole (IFP) Steel/GRP composite hybrid, 130 - 135 bar, -35°C
CNG Tanker Issues Design of the containment system Reliability of the production method of the containment Access to the internal hull structure for survey Location of the control valves and piping Handling of any condensate Safety in event of leakage or rupture Fire protection and extinguishing Temperature control of the hold space
Hazards to the Surveyor Liquefied Gas Flammability Toxicity Asphyxia Anaesthesia Frostbite
Confined Space Entry Pressurised Systems
Flammability The flammability range of methane in air is between 5.3% and 14% by volume. Theoretically an explosion cannot occur in a methane-mix atmosphere with less than13% oxygen but as a safety precaution the air is diluted with inert gas or nitrogen until the oxygen content is reduced to 2%.
The auto ignition temperature (the lowest temperature to which the gas needs to be heated to cause self sustained combustion without ignition by spark or flame) of methane is 595ºC.
Vapour The volumetric expansion at the liquid/vapour phase is 600-620 times the liquid volume. Considering the volumetric expansion draining down should always be thoroughly checked to avoid liquid being trapped between valves. LNG vapour is lighter than air at vapour temperatures above -110ºC (depending on LNG composition). If vapour is vented to atmosphere, the vapour rises above the vent outlet and is rapidly dispersed. When cold vapour is mixed with ambient air, due to the condensation of the moisture in the air, the vapour-air mixture will appear as a white cloud. It is normally safe to assume that the flammable range of the vapourair mixture does not extend beyond the perimeter of the white cloud.
Hazards In most industrial environments where there is the risk of explosion or fire because of the presence of flammable gases or vapours, a mixture of compounds is likely to be encountered. In the petrochemical industry, the raw materials are a mixture of chemicals many of which are decomposing naturally or are being altered, by the processes. For example crude oil is 'cracked' to produce many simpler materials. In order for gas to ignite there must be an ignition source typically a spark, or flame or hot surface. For ignition to take place there must be an explosive mixture. This means the concentration of gas or vapour in air must be at a level such that the 'fuel' and oxygen can react chemically. The power of the explosion depends on the 'fuel' and its concentration in the atmosphere. Not all concentrations of flammable gas or vapour in air will burn or explode. The LOWER EXPLOSIVE LIMIT (LEL) is the lowest concentration of 'fuel' in air which will burn and for most flammable gases and vapours it is less than 5% by volume. So there is a high risk of explosion even when relatively small concentrations of gas or vapour escape into the atmosphere. The UPPER EXPLOSIVE LIMIT (UEL) is the maximum concentration of 'fuel' in air which will burn. Concentrations above the UEL will not burn because there is insufficient atmospheric oxygen available. Flammable liquids generally have a low FLASH POINT. This is the lowest temperature at which vapour is given off at sufficient rate to form an explosive mixture with air. Liquids with flash points below normal ambient temperatures automatically release vapour in sufficient volume to provide an explosive mixture, so leakage of such liquids is potentially as dangerous as a flammable gas leak.
VAPOUR DENSITY is a measure of the density of a gas or vapour relative to air. Gases or vapours with a vapour density of less than one are lighter than air and they tend to rise from the point of escape and may therefore be readily dispersed (or they may be trapped at a higher level). Gases or vapours with a vapour density of greater than one are heavier than air and tend to sink to lower levels and can spread around forming concentrations between the LEL and UEL. Such heavy gases can remain trapped for a long time in ducts, inspection pits, etc, ready to explode as soon as a source of ignition is introduced. When an explosive mixture of gas or vapour and air has developed, it can be ignited either by a spark of sufficient energy or if it is exposed to a surface at a sufficiently high temperature. The lowest temperature, which will cause a mixture to burn or explode, is called the IGNITION TEMPERATURE. Areas where there is the possibility of the presence of an explosive mixture of flammable gas or vapour and air are known as 'hazardous' and other areas as 'safe' or 'non hazardous'. Any electrical equipment used in hazardous areas, including gas detection equipment, must be specially tested and approved to ensure that, in use even under a fault condition, it cannot initiate an explosion. In Europe, hazardous areas are generally defined as follows: Zone 0 An area where an explosive mixture is likely to be present at all times under normal operating conditions. Zone 1 An area where an explosive, mixture is likely to occur in normal operation. Zone 2 An area where an explosive mixture is not likely to occur in normal operation, and if it does it is only for short periods. In the United States, hazardous areas are classified by two Divisions. Division 1 equates to Zone 0 and Zone 1 and Division 2 equates to Zone 2. in Europe gas detection equipment, certified for use in hazardous areas in Europe, normally falls into one of the following categories. Intrinsically Safe
denoted as EEx ia or EEx ib
For use in Zones 0, 1 or 2 Zones 1 or 2
Flameproof
denoted asEEx d
For use in Zones 1 or 2
Increased Safety
denoted as EEx e
For use in Zones 1 or 2
Intrinsic safety differs from other forms of protection because it is based on the principle that the equipment is electrically safe. The definition of an intrinsically safe circuit is generally one that does not
contain sufficient electrical energy, even under fault conditions, to cause a spark or generate sufficient heat to ignite a combustible gas mixture. Other forms of protection are based on mechanical safety and for flameproof equipment the equipment enclosure should be capable of containing an explosion within it, thereby avoiding the possibility of the system becoming an external ignition source. When selecting intrinsically safe equipment for a particular application it is necessary to know what the IGNITION TEMPERATURE of the gas or vapour is and in what GAS GROUP it is. An explosimeter is a device which is used to measure the amount of combustible gases present in a sample. The device operates on the principle of resistance proportional to heat -- a wire is heated, and a sample of the gas is introduced to the hot wire. Combustible gases burn in the presence of the hot wire, thus increasing the resistance and disturbing a Wheatstone bridge, which gives the reading. A flashback arrestor is installed in the device to avoid the explosimeter igniting the sample external to the device.
Gas Laws General Pressure Back Pressure Backpressure usually refers to the pressure exerted on a moving fluid by obstructions or tight bends in the confinement vessel along which it is moving, such as piping. Back pressure in the automotive exhaust sense of the term, is usually termed as being a "bad thing" for performance. Most process facilities require a minimum system pressure to operate efficiently. The pressure within a system is caused by fluid friction or an induced resistance to flow through the system. The Loading Specification form makes reference to pressure The SI unit for pressure is the pascal (Pa), equal to one newton per square metre (N·m-2 or kg·m-1·s-2). The Pounds per square inch (psi) is still in widespread use in the US and Canada, notably for cars. A letter is often appended to the psi unit to indicate the measurement's zero reference; psia for absolute, psig for gauge, psid for differential. Atmospheric pressures are usually stated using kilopascal (kPa), or atmospheres (atm), except in American meteorology where the hectopascal (hPa) and millibar (mbar) are preferred. The bar (symbol bar), decibar (symbol dbar) and the millibar (symbol mbar, also mb) are units of pressure. They are not SI units,
nor are they cgs units, but they are accepted for use with the SI. The bar is still widely used in descriptions of pressure because it is about the same as atmospheric pressure. The bar, decibar and millibar are defined as: 1 bar = 100 kPa (kilopascals) = 1,000,000 dynes per square centimeter (baryes) 1 dbar = 0.1 bar = 10 kPa = 100,000 dyn/cm² 1 mbar = 0.001 bar = 0.1 kPa = 1,000 dyn/cm² (A pascal is one newton per square meter.) Atmospheric air pressure is often given in millibars where "standard" sea level pressure is defined as 1013.25 mbar (hPa), equal to 1.01325 bar. Despite millibars not being an SI unit, they are still used locally in meteorology in some countries to describe atmospheric pressure. The SI unit is the pascal (Pa), with 1 mbar = 100 Pa = 1 hPa = 0.1 kPa. Meteorologists worldwide have long measured air pressure in millibars. After the introduction of SI units, many preferred to preserve the customary pressure figures. Therefore, some continue to use millibars under their own name, while others use hectopascals (which are equivalent to millibars) so they could stick to the same numeric scale. Similar pressures are given in kilopascals in practically all other fields, where the hecto prefix is hardly ever used. In particular, Canadian weather reports use kilopascals (which could also be called centibars).
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