Fig 1 Schematic of typical LNG vaporiser system

Vaporiser systems

The submerged combustion vaporiser system includes the burner(s) a high temperature flue gas distributor or a downcomer the bath/exchanger section concrete pit or metal tank and the exit stack. The hot combustion product after leaving the high heat release burner(s) is exhausted through either a downcomer or a distributor into the spargers designed and arranged to prevent direct impingement of combustion products on the tube bundle providing direct contact heating of water bath.
After leaving the bath tank the flue gas enters the disengagement section to remove by gravity the larger water droplets before it exits the stack. Water entrainment of exhaust should be reduced limiting the stack velocity and a mist eliminator pad may be added near the stack base.

Fig 2 Exhaust burner vaporiser

Fig 3 Semi-submerged single burner vaporiser

Heat and mass transfer

Submerged combustion vaporisation uses water as the heat transfer medium between the products of combustion and the process LNG. The total mechanism of heat transfer can be defined in three steps:
—Heat and mass transfer between the combustion products and the water bath
—Heat transfer between froth and process tubes
—Heat transfer between process tubes and process fluid.
The products of combustion are discharged into the liquid bath below the liquid level achieving safer operation higher efficiency and greater temperature distribution than direct fired heaters and steam heating. The LNG enters the vaporiser under subcooled conditions with a typical temperature range between –320°F and –260°F. The vaporiser transfers the heat to the LNG in three phases:
—Liquid phase where the liquid is heated to the bubble point
—Two-phase flow (vaporisation) where all the liquid is vaporised at the dew point
—Superheat vapour to send-out temperature.
LNG is typically composed by 97 per cent methane and 3 per cent other paraffins and nitrogen each with a different boiling point but boiling at a temperature between bubble point and dew point requiring more heat to vaporise the heavier paraffins. For pressures above the critical pressure Pc there is no distinct point of phase change from subcooled liquid to superheat vapour.
High heat flux – 40000 to 50000 Btu/hr-ft2 for vaporisation and 60000 to 80000 Btu/hr-ft2 for liquid heating with low approach temperature – is an important design advantage of this system. Heat transfer efficiency is maximised because of the direct contact heating of the water and condensation in the water bath of water produced from combustion of the hydrogen content in the fuel.
The froth created by the combustion products and the recirculating water flows at high velocity on the outside surface of the heat exchanger tubes due to the weir confining area. The outside heat transfer coefficient is fairly constant within a 3:1 turndown range in the 1000 to 1400 Btu/ft2-hr-°F range with a very small fouling factor of 0.001 ft2-hr-°F/Btu.
Finned tubes do not need to be utilised due to the very high outside heat transfer coefficients sometimes even higher than calculated.
Water in the combustion gases is condensed in the bath not freezing on the tube bundle surface with bath temperature of 128°F and having ice formation of less than 1 per cent on the tube bundle surface with a bath temperature of 80°F. The bath temperature throughout the tube bundle is practically uniform within 2°F.
Fuel efficiency is a function of the water bath temperature combustion stoichiometry fuel composition and ambient temperature. The required burner fuel consumption is 1.5 to 2.0 per cent of the LNG vaporised due to the high vaporiser efficiencies based on the high heating value from 90–93 per cent with water bath temperature ranging from 100 to 122°F on peak shaving operation to 95–99 per cent on base load operation due to the larger exchanger surface area design and operating with a bath temperature as low as 60°F. Another rule of thumb is to vaporise 1lb of LNG which requires about 385Btu of fuel.
The intense contact between the combustion products and the liquid bath results in heat and mass transfer as follows:
—Very high thermal exchange rate. A 20in submergence will ensure a temperature equilibrium between the gas bubbles and the water bath. Below 12in submergence the products of combustion will be hotter than the water bath not reaching equilibrium
—Mass transfer results in the absorption of both the carbon dioxide and sulphurous oxide if sulphur is present in the fuel
—Mass transfer between combustion products of hydrogen content fuels and the water bath will result in condensation of combustion water or evaporation of water bath depending on the bath temperature. Equilibrium will occur when the condensed combustion water mass is equal to the evaporated bath

Fig 4 Heating efficiency curve: submerged combustion based on typical natural gas fuel

Safety

LNG plants sometimes located in populated places and handling large flow rates should be considered a hazardous area requiring safely systems to avoid serious fires or explosions. The system needs to be very reliable throughout the year at base load facilities as well as when required under emergency demand at peak shaving facilities.
Submerged combustion combines the safety of steam heating with the response characteristic of a direct fired heater outperforming both in thermal efficiency and uniform temperature distribution. To improve reliability of plant a spare unit is often used resulting in for example two 100 per cent units or three 50 per cent units.
The normal operating water bath temperature is in the range of 60–122°F and there is no contact of flame with the LNG process tube bundle. In the unlikely event of a tube rupture the process gas is below the auto-ignition temperature and exits the stack together with the quenched inert flue gas. Submerged exhaust of the hot flue gas allows checkout and operation of burners without process flow in the tubes.
The outlet process piping must be protected with both pressure relief and low temperature shutdown devices to prevent excessive pressure or cryogenic temperature fluid to flow into the natural gas distribution header to avoid embrittlement and possible fracture. If bath agitation is kept by the use of the combustion air blower the heat capacitance of the water bath can be utilised to vaporise extra LNG minimising the liquid carry-over during emergency shutdown and also fast start-up with small variation of the LNG send-out temperature.

Monitoring

The vaporiser system is controlled by maintaining a constant process outlet temperature because water bath temperature is a slow response control system. These vaporiser systems should offer continuous and automatic operation with reliable instrumentation requiring minimum supervision. The instrumentation should be kept simple but with sufficient accuracy.
The basic vaporiser input variables like pressure temperature and flow of combustion air and fuel gas are processed in the burner management system through a control system. Multiple burner systems are controlled in the same manner as single burner systems but with all burners operating in parallel. Increasing the system turndown beyond normal burner turndown can be accomplished by varying the number of operating burners.
To start up the vaporiser system the following steps are taken after the required permissives have been met:
—Purge the system with a minimum of four volumes of the system
—Light off pilot(s)
—Light off burner(s) with fuel gas
—Attain all the permissives for process flow
—Introduce process flow.
The following conditions designed to protect the equipment lead to process flow shut-off also after previous alarms:
—High water bath temperature
—Low water bath temperature
—Low water bath pH
—Low water level
—High stack temperature¡
—High process side inlet pressure
—Low process side outlet temperature
—Low quench/recycle water flow.
The following conditions lead to immediate system shut-down:
—Power failure
—Loss of instrumentation air
—Lack of flame recognition
—Low fuel gas pressure
—High fuel gas pressure
—Low combustion air pressure
—High stack H/C (process tube bundle leaking)
—Loss of quench water/recycle flow
Any of the following conditions if continuous emission monitor (CEM) is included lead to process shut-off after previous warnings:
—High stack H/C per cent
—High stack CO per cent
—Low stack O2 per cent
The burner excess air can be determined by the O2 per centage content at the stack using the following expression:
% XS air = 95 * Y / (21 – Y)

Case studies conclusions

The utilities are very satisfied with the high thermal efficiency fast response and reliability of the submerged exhaust vaporiser. Information from the operation of more than 40 LNG facilities with over 150 units through direct contact service reports and surveys has provided some facts and results listed here.
The majority of peak shaving units operate less than three months from a few hours to 60 days while base load units operate on an average of about five to six months.
Submerged combustion units operate with a higher thermal efficiency than predicted resulting in lower fuel costs or higher LNG vaporisation capacities.
Most utilities spend 10 minutes from start-up including purge and pilot ignition to burner ignition. Full rate of LNG is generally reached after an additional 15 minute operation.
Modern units are supplied with corrosion resistant items like tank weir deck stack etc to reduce maintenance costs and to increase life expectancy.
Recirculation/combustion chambers of HV burners have been redesigned to improve reliability and reduce maintenance costs.
Metal burner throat of semi-submerged type burners have been redesigned to avoid heat distortion improving burner operation.
To increase safety H/C combustible analysers have been added not only in the stack but also in the combustion air inlet to detect natural gas (NG) leaks in the tube bundle assembly or the presence of NG in the combustion air due to other external leaks to atmosphere.

Economics and design factors

The operating cost for a peak shaving operation is not a major factor due to the yearly brief send-out periods but it is a very important factor to consider for base load applications. A base load LNG vaporiser facility can justify a higher investment because of continuous or almost continuous operation requirements demanding service reliability and low maintenance in excess of 8000 hours/year.
Base load facilities need back-up systems like the submerged combustion vaporiser designed for seasonal peak or stand-by use. Hybrid vaporiser systems utilise a mix of two or more types of vaporiser to handle efficiently seasonal requirements as well as peak shaving.
Several factors are involved in selecting the type and design of an LNG vaporiser. Ambient type vaporisers using sea or river water as the heat source are expensive but very effective on large continuous base load operation due to the growing cost of energy.
Ambient type vaporisers using air as the heat source have the highest initial cost with limited capacity although with very low operating and maintenance costs.
Process heated vaporisers are integrated with other thermodynamic or chemical process plants being typically used as refrigerant units with a more useful application for base load systems. Remote heated vaporiser systems use a fired heat exchanger to heat an intermediate fluid as the heat medium which circulates through the LNG vaporiser heat exchanger located near the pumps/tanks and the fired equipment can be located away in a safer area.
Water-glycol is the most common heat medium but if steam is available the vaporising system becomes inexpensive to operate although it becomes more expensive if dedicated steam generators are required.
Integral heated vaporisers can either make direct use of the products of combustion to heat the LNG or utilise a quench water to supply the required heat like the submerged combustion vaporiser with a burner fuel consumption about 1.5–2.0 per cent of the LNG vaporised due to the high vaporiser thermal efficiencies.
Submerged combustion units are ideal for peak shaving emergency or stand-by operation as well as being economically feasible for base load or seasonal facilities especially when designed with a higher thermal efficiency.
If either hot water or steam is available the submerged combustion units provide the flexibility to operate without fuel requiring only the combustion air blowers to supply the agitation and the gas lift over the tube bundle. The process and operation advantages of submerged combustion vaporisers are very low initial and maintenance costs with a high thermal efficiency in a safe reliable fast response and compact design.

Presently, Olavo Cunha Leite is Principal Consultant for THERMICA Technologies, USA. Previously he was chief engineer /engineering manager for the T-Thermal Company Division of Selas Fluid Processing Corporation Blue Bell Pennsylvania USA. He holds a Diploma in Mechanical Engineering from the Technical University of Lisbon and has published papers on combustion and incineration. E-mail: THERMICATECH@yahoo.com