wpc_cd168

New LNG Receiving Terminal Concepts Block 3, Forum 14 paper

New LNG Receiving Terminal Concepts Boris Ertl, M. W. Kellogg Limited Charles Durr, KBR David Coyle, KBR Isa Mohammed, M. W. Kellogg Limited Stanley Huang, International Process Systems

Abstract:

Liquefied Natural Gas (LNG) is a cost effective route to deliver large volumes of stranded gas to distant markets. The LNG chain is capital intensive, requiring a number of high-cost elements typically including gas production, pipeline to processing plant, liquefaction plant, LNG storage and loading facilities, shipping, LNG receiving facilities, LNG vaporisation and gas delivery to market.

All elements of the supply chain need to be in place for an LNG project to go ahead. The receiving terminal is increasingly becoming a constraint to growth in LNG trade, and designers need to address new challenges with factors including environmental and permitting issues and the need for gas quality compatibility between the imported gas specification and local gas requirements.

New technology is needed to address these new challenges, and to illustrate this point, some novel technologies are presented that provide opportunities for value enhancement in various aspects of the terminal design. This paper describes:

&bullet;Vaporiser concepts; a comparison of available technologies with a focus on environmental performance

&bullet;Heat integration with other facilities; optimal environmental performance is achieved if the LNG vaporizers are integrated with a process that requires cooling

&bullet;Ethane extraction; a novel approach to gas quality control that can potentially provide a valuable by-product

&bullet;Offshore terminals; a brief discussion of the concepts under consideration

Introduction Liquefied Natural Gas (LNG) is a cost-effective technology for transporting high volumes of gas over long distances. The basis of the technology is to condense natural gas by chilling to cryogenic temperatures, thereby reducing its volume by approximately 600 times, compared to gas at atmospheric conditions. This increase in density enables cost-effective shipping.

The overall LNG supply chain is very capital intensive, typically comprising: Gas production in remote / offshore location Pipeline to Onshore plant Onshore gas treating Liquefaction plant LNG Storage and loading facilities LNG shipping LNG receiving terminal; storage and regasification Gas distribution to market

All of these links in the chain need to be in place for an LNG project to progress.

This paper focuses on the LNG receiving terminal. The receiving terminal is constructed close to the intended gas market, for easy connection to the local gas pipeline system, or integration with a local consumer such as a power station.

The receiving terminal is increasingly becoming a constraint to growth in LNG trade, and designers need to address new challenges. As these facilities are necessarily required close

Copyright World Petroleum Congress all rights reserved


to populated areas for access to their intended markets, there is an increasing public awareness of potential safety and environmental aspects of the terminal design. Recent experience, particularly in North America and Europe, is that terminal designs need to comply with increasingly stringent requirements to obtain permits.

In addition to permitting requirements, as the LNG trade becomes more global LNG terminal designs in some cases need to incorporate gas conditioning to adapt the gas quality of LNG sourced worldwide to meet the gas specification requirements of the local market.

New technology is needed to address these new challenges, and to illustrate this point, some novel technologies are presented that provide opportunities for value enhancement in various aspects of the terminal design. This paper describes:

New vaporiser concepts Heat integration with other facilities Ethane extraction Offshore terminals

LNG Value Chain Liquefied Natural Gas, LNG, is the liquid form of natural gas at atmospheric pressure and cryogenic temperatures, around -160C. When natural gas is turned into LNG, its volume shrinks by a factor of about 600, compared to gas at atmospheric pressure.

The purpose of making LNG is to enable economical transport of the gas over long distances although the LNG chain requires very significant capital investment, this route becomes the most economic means to transport high volumes of gas for transport distances over around 2500 km. In cases where the gas production is closer to the market, a pipeline would normally be preferred.

The essential elements of a typical LNG supply chain are Gas production: In the LNG chain this is stranded gas production at a remote and

often offshore location. Pipeline to Onshore plant: The pipeline to a suitable location for onshore processing

and access to suitable shipping channels for export can be an expensive element of the chain. For offshore gas fields the possibility of offshore LNG production has been considered as a means to eliminate this pipeline, though at the time of writing no project is at an advanced stage of development.

Onshore gas treating: Gas from production will not be suitable for liquefaction. The liquefaction process is very sensitive to heavy hydrocarbons and contaminants such as carbon dioxide or water which may freeze, and mercury which might cause corrosion to the aluminium materials. Gas treating is therefore required upstream of the liquefaction plant.

Liquefaction plant: The liquefaction plant is one of the major cost elements of the LNG chain. The technology requires large compressors, drivers and heat transfer surface to achieve the refrigeration required, and consumes significant energy to drive the process.

LNG Storage and loading facilities: Storage is always required, as the liquefaction plant is designed to operate continuously whereas shipping is necessarily intermittent. The volume of storage is determined by shipping studies and needs to account for risks to the supply routes. Loading facilities generally comprise a trestle and jetty with loading arms for interface to the ships.

LNG shipping: Much of the current LNG trade has been negotiated on relatively long term supply contracts and shipping is often by a fleet dedicated to delivery of LNG from a particular supplier to a particular location. Increasingly LNG is being traded on the spot market, and this might change the nature of shipping requirements. The cost of shipping in the LNG supply chain depends on the distance between the supplier and customer, as this affects the number of ships in service to supply the route. For high shipping distances, say over 12,000 km, the cost of the shipping fleet might approach the cost of the treating and liquefaction units.

LNG receiving terminal; storage and regasification: This is the subject of the current paper.



Gas distribution to market: Distribution from the terminal is generally a pipeline connection to the grid, but this could also be a direct supply to a particular energy consumer such as an industrial plant or power station.

Figure 1 shows the essential elements of the LNG supply chain.

Figure 1 LNG Supply Chain

LNG Terminals Typical Current Design Figure 2 shows a simplified schematic of a typical land-based LNG receiving terminal. The main elements are:

The unloading jetty, and trestle connecting piping to shore. LNG storage tanks and low pressure (primary) pumps Boil-Off Gas (BOG) handling and recondenser High-pressure (secondary) pumps and vaporisers

Figure 2 Typical LNG Terminal Block Flow Diagram

The Unloading System The unloading system comprises several loading arms which connect to the ship, and loading lines delivering LNG to the storage tanks and returning displaced vapour and boil off gas to the ship, which replaces the volume vacated by LNG pumped out. Loading lines are usually routed above the sea level on a trestle that connects the jetty to the shore. The design of this system is optimised based on the range of different ships anticipated at the terminal. There are many engineering considerations to ensure safe and efficient operation, in particular the



management of transient periods such as cool-down and the transition from unloading mode to holding mode. The design incorporates recirculation to ensure the system remains cold between unloading operations.

LNG Storage There are various tank designs available for LNG terminals. A typical onshore terminal has two or more cylindrical tanks, as this generally provides the lowest cost per installed volume of storage. Primary pumps are installed in wells within the tank. In particular circumstances other configurations may become attractive, for example for low capacity storage horizontal tanks could be considered, and for offshore designs (discussed later) rectangular designs might become attractive to reduce weight and space requirements.

Boil Off Gas (BOG) System As the LNG is stored at cryogenic temperatures, no matter how well the tank is insulated there will be some degree of heat leak from the surroundings, and this results in generation of Boil Off Gas. As long as the terminal is exporting product gas, this BOG can be exported with the send-out. To eliminate the need to compress the gas from atmospheric pressure to the pipeline pressure, which could be in the order of 100 bar, most terminals include a recondenser. The recondenser uses an intermediate pressure at which the LNG is no longer saturated, and can therefore absorb the BOG into the liquid phase. The combined LNG is then pumped to the export pressure requirement in liquid (dense) phase prior to vaporisation and export. KBR developed and installed the first recondenser at the Trunkline LNG terminal in the USA. This design has since been installed at many terminals around the world.

Gas Vaporisation and Send-Out The secondary (high pressure) pumps generate the required pressure to deliver the LNG, which is vaporised and heated prior to export. There are various options to provide heat for this vaporisation, including:

Water (often sea water) pumped over Open Rack Vaporisers (ORVs) Combustion of fuel gas to heat a water-bath, Submerged Combustion Vaporisers

(SCVs) Air heating of an intermediate fluid to provide vaporisation duty in a heat exchanger Integration with other facilities with a cooling requirement, e.g. air separation plants or

power plants The most commonly used technologies in existing LNG terminals are ORVs and SCVs. Vaporiser technology options and heat integration options are discussed in more detail below.

New Vaporiser Concepts LNG vaporisation practices have undergone few changes; most vaporisers currently operating are based on a small number of conventional designs. However, to comply with environmental regulations, conventional technologies have recently required modifications, and may even become unacceptable at some locations.

Conventional Technology The most widespread current practice is either open rack vaporisers (ORVs) or submerged combustion vaporisers (SCVs). ORVs, as shown in figure 3, use water as the heat source. Water supplied from an overhead distributor flows over the outer surface of long finned tube panels and vaporises the LNG inside the tubes. ORVs are widely used in Asia and Europe, and are well proven in base-load LNG regasification service.



Figure 3 Open Rack Vaporiser typical design (diagrams courtesy of Kobe Steel)

SCVs, shown in figure 4, use low pressure fuel gas from the boil-off gas, augmented by send-out gas. Depending on the vaporiser capacity, single or multiple burners may be used. The combusted gas is sparged into a water bath to utilize the heat of condensing water from the flue gas. The LNG passes through tubes that are submerged in the water bath. The water acts as an intermediate fluid for transferring the heat from the combustion process to the LNG. This also requires electric power to run the combustion air blower.

Figure 4 Submerged Combustion Vaporiser

Generally, ORVs with their water systems require higher capital expenditure than SCVs, but the fuel burned by the SCVs makes them more expensive to operate (the SCV system requires approximately 1.5 % of the total vaporised LNG as fuel). Given that the LNG received is valuable product, it is common to see ORVs used for normal operation and SCVs installed as back-up or peaking service. However, at some sites SCVs provide normal vaporisation because the water available is too cold to provide heating without risk of freezing, or the presence of contaminants in the water jeopardises reliable ORV operation.

Environmental Factors ORVs The primary environmental issues with ORVs are the water outlet temperature, and the water intake velocity and treatment:

Water outlet temperature: The main environmental issue when considering sea water for vaporisation is the effect on Ichthyoplankton (fish larvae and eggs). When using sea water for heating purposes, the World Bank Guidelines state that: The effluent should result in a temperature increase of no more than 3C at the edge of the zone where initial mixing and dilution take place. Where the zone is not defined, use 100 meters from the point of discharge [Ref. 1].

Intake velocity and treatment: Ichthyoplankton is free floating and readily pulled into the water system [Ref. 2]. In the U.S. the water intake system is to be designed and operated in accordance with the guidelines under Section 316(b) of the Clean Water Act. The objective of the regulation is to minimize mortality of all types of marine life due to impingement and entrainment at the water intake structures and establishes strict technology-based performance requirements applicable to the location, design, construction, and capacity of water intake structures for new facilities.

Water treatment chemicals: The water supply requires chlorination to protect the system (especially heat transfer surfaces) against bio-fouling. Chlorination is



generally provided by means of injecting a sodium hypochlorite solution into the suction of the water pumps on a continuous basis.

Environmental Factors SCVs SCVs have environmental issues related to combustion emissions and water bath effluent. The combustion emissions of interest are NOx, CO, CO2 and volatile organic compounds (VOCs). The combustion process makes water which is condensed in the water bath, therefore water is continuously produced. The water is saturated with CO2, and must be neutralized before discharge.

Some development has taken place with the objective of modifying SCVs to reduce emissions. Flue Gas Recirculation (FGR) technology, originally developed and applied to the incineration industry, has been adopted in the design of low emission SCV. Since the flue gas is water saturated and at low temperature, a portion of flue gas recycled to the blower suction lowers the combustion temperature, resulting in 25% lower NOx emission compared to conventional SCV [Ref. 3]. The lower temperature combustion is compensated by an increase in mass volume of combustion gas. Recycling of flue gas reduces combustion capacity by about 6% [Ref. 3]. This can be compensated by an increase in the blower power.

Available technology can reduce the NOx and CO emissions from the SCVs to below 40 ppmv of each component. However, these emission levels do not satisfy the emission restrictions in some environmentally sensitive areas, which makes other measures necessary. In such cases a Selective Catalytic Reduction (SCR) system, which has been widely used in the other industries, can be combined with SCV to comply with the strict emission limitation. By using SCR, NOx level in the flue gas can be reduced below 5 ppm. Figure 5 shows a schematic of a low NOx system using SCR.

Figure 5 Selective Catalyst Reduction System for SCV vent gas

The SCR solution reduces emissions, but there are disadvantages, including decreased thermal efficiency, increased plot space, complexity and costs and limited operating experience (2 units operating at Distrigas in Everett, MA, USA since 2003)

New Technologies Given the site and environmental challenges associated with conventional ORV and SCV technologies, the industry now has a keen interest in alternate LNG vaporisation methods.

The technologies now being developed by equipment vendors and engineering companies are based on either combustion of fuel or ambient air as the heat source. The concept of using ambient air is preferred from an emissions standpoint, though at many locations standby combustion is required for periods of low ambient air temperatures. Some of the processes now under consideration or recently installed are summarized below:

Fired Heater The fired heater design indirectly vaporises LNG by heating a Heat Transfer Fluid (HTF) that is in contact with the LNG through a Shell and Tube Vaporiser.



Inherently high heat transfer coefficients result in a compact design, thus reducing space requirements. Various kinds of heat transfer fluids are available including water, water solutions with ethylene glycol, polyethylene glycol, or methanol. The selection of the type of HTF depends on its physical-chemical properties, operating costs, proven track records, and HSE considerations.

NOx and CO emissions are reduced by 99% or better with the addition of an SCR in the stack, which is the configuration shown in figure 6. One disadvantage of the FH design relative to SCV is that the stack exhaust temperature is higher which means efficiency is lower and the FH will require approximately 10% more fuel. This disadvantage can be overcome, though with additional capital cost, by using a flue gas condensing heat exchanger in the exhaust stack [Ref. 4].

Figure 6 Fired Heater Vaporisation System

Reverse Cooling Tower (RCT) The heat source for this process is ambient air going through a cooling tower; only in this case the tower cools air instead of heating air. An intermediate fluid transfers heat between the tower and the LNG. A standby fired heater is also provided for periods of low temperature. In many cases the fired heater operates for a limited period of time and low NOx burners are not required. A typical RCT process flow schematic is shown in figure 7.

Figure 7 Reverse Cooling Tower

Ambient Air Vaporisers (AAV) Two basic types of ambient air vaporisers can be considered for LNG applications:



The direct air-to-LNG contact vaporiser uses air in either a natural or a forced draft vertical arrangement. Such vaporisers are in service for peak shaving plants at locations where the LNG vaporisation duty and flow rate is relatively small; such an installation is shown in figure 8. Traditionally, these vaporisers have been designed with half of the parallel units on-line while the other half are off-line for defrosting. Large scale installations of air-to-LNG vaporisers would require many individual units manifolded together. Unless adequate space is provided around the vaporisers the cold air would recirculate back to the vaporiser inlet. Under certain atmospheric conditions the units may also generate fog in sufficient quantities to persist beyond the plant fence line. At present there are no large scale units in operation.

Figure 8 Direct Ambient Air Vaporisation

Indirect ambient air vaporisers use an intermediate fluid between a shell-and-tube LNG vaporiser and conventional fin-fan air coolers to reheat the fluid by ambient air, as shown in figure 9. This system has been in operation since early 2004 at the Dahej receiving terminal (India).

Figure 9 Indirect Ambient Air Vaporisation Scheme

Economic Comparison Using a life cycle cost model, KBR evaluated economics for the vaporisation schemes discussed in the previous sections [Ref. 5]. The expenses (capital, maintenance, and operating costs) of each scheme were estimated and used to determine a comparative Net Present Value (NPV) for each scheme.

KBR found that in general, ambient air vaporisation schemes required the highest capital expenditure, but the lowest operating costs, while a fired heater provided the lowest capital expenditure but high operating costs.

The best NPV was achieved by low operating cost schemes, and KBR found that ambient air vaporisation can be a cost-effective scheme, despite relatively higher capital cost, with NPV comparable to the ORV design. However, the results of this study are sensitive to site-specific variables, such as the value of plot space for large-footprint schemes, and the value of fuel gas.



Site-specific studies are required to determine the optimum vaporiser design for a particular site. KBRs work has demonstrated that the more recent technologies such as ambient air vaporisation not only eliminate some of the environmental concerns, but also have the potential to improve project economics in some cases.

Heat Integration with Other Facilities Most base-load LNG terminals to date have vaporised LNG to deliver gas into a distribution network. If the customer is an industrial facility, such as a power station, there is the potential for heat integration. Heat integration means using the cold from vaporising the LNG to provide chilling in the integrated process. There is considerable potential in many cases for improved overall thermal efficiency.

An LNG terminal has a large reservoir of cold energy which is normally dissipated into the sea or the atmosphere. In an export terminal, up to 10% of the throughput may be used to provide the refrigeration to liquefy the gas. A large amount of this energy is transported to the LNG receiving terminal as cold and is technically free to the receiver as gas is priced on heating value. Various schemes have been applied to make use of this cold energy, which include cryogenic power generation, air separation, carbon dioxide solidification, cold storage / frozen foods, cryogenic crushing and sea water desalination.

There are also opportunities to integrate the terminal with facilities with large sources of continuous low grade heat and high temperature heat sinks. An adjacent refinery or power station offers excellent opportunities to realise the inherent synergies of integration using established technology. KBR have developed a number of schemes around these processes, as an example this section concentrates on new KBR initiatives in the integration of terminals with power stations.

MWKL [Ref. 6] studied integrating a cold power station within the terminal; this is a reverse refrigeration process using an expander cycle to capture some of the energy flowing from the warm to cold heat sinks. The MWKL study found that this Rankin cycle has the potential to extract approximately half of the energy thermodynamically available in the heat flow from the warm to cold heat sinks. However, integration with a power station offers greater rewards, with the opportunity to use heat from the power station to vaporise LNG and cold from the terminal to improve power station efficiency. In this case the MWKL study found the theoretical potential to recover up to 90% of the thermodynamically available energy flow, based on exergy analysis.

New Power Station Integration Processes by KBR [Ref. 7] A power plant must reject heat to condense steam and to cool equipment. In addition, power output can be increased by cooling the gas turbine inlet air. This works by increasing the mass throughput and also allowing more fuel to be burnt due to lower compressor discharge temperatures.

Thermal integration processes can be categorised into: LNG Cold Recovery Heat Recovery from the power plant Combination of both heat and cold recovery.

KBR have recently developed new schemes combining both heat and cold recovery. These are based on a terminal with a combined cycle gas turbine power-plant, and integrate GT inlet air chilling and heat recovery from the power plant to vaporise the LNG.

As the power increase effect of GT inlet air chilling depends on ambient conditions, two HTF loops are utilised. One for the inlet air chilling, and the other for waste heat recovery allowing independent control.

Figure 10 shows the basic KBR scheme. The GT inlet air stream is cooled by the LNG via a HTF loop. Cooling water is used to vaporise and heat the LNG and then used to condense the steam at the exit of the steam turbine. Any excess heat is rejected to atmosphere in a wet-type cooler.



Figure 10 KBR Power Plant Heat Integration Scheme 1

A modification of the above is shown in figure 11. In this configuration, all the cooling water passes through the wet-type cooler. This enables the steam to condense at a lower temperature in the surface condenser, which increases the power output from the steam turbine due to the correspondingly lower condensing pressure.


The process configuration in figure 12 consists of a HTF loop for the GT inlet air chilling, double tube bundle vaporiser and the superheater. The HTF is heated by cooling water (CW). This allows a lower condensing temperature for the steam with an increase in power output as stated previously. The HTF vaporises the intermediate fluid in the double tube exchanger which is condensed against the LNG stream. Again excess heat is rejected to atmosphere via a cooling tower.




Benefits KBR integration technology provides the following benefits:

Reducing costs in construction and operation Optimising the use of the LNG facility (storage and re-gasification) Increasing competitiveness in energy markets (gas and power) Shared facilities (utilities, etc.) Enhanced summer peaking capacity Improved environmental performance; lower emissions

Ethane Extraction Currently, the imported LNG into the U.S. accounts for roughly 1% of the domestic demand. With declining domestic gas production, LNG importation is projected to increase to 10 % by 2010. As a result, the issue of gas compatibility has become important [Ref. 8, 9]; re-vaporised LNG must acceptable to all gas users with no credit for blending with gas from other sources.

LNG specifications are subjected to supply-demand negotiations, similar to other commodities. Since Japan imports about 50 % of globally traded LNG, the Japanese gas specification of relatively high ethane and heavier component content will probably continue to be the basis of many future LNG supplies. Consequently, most LNG suppliers produce LNG richer than U.S. pipeline specifications. With LNG imports to U.S. projected to increase, some LNG producers may be willing to produce lean LNG suitable for the U.S. market. Nonetheless, the spot market will remain popular for opportunistic purchasers in the foreseeable future. The capability of a receiving terminal to assure gas compatibility would enhance business opportunities. Ethane extraction is an attractive option to ensure gas compatibility. Other methods involve blending with inert gases; ethane extraction is able to change gas properties over a wide range and also produces an ethane and heavier by-product which may attract a high market value at some locations. Several ethane extraction schemes have been proposed in recent years, and some are protected by patents. All of the commercial extraction schemes are based on fractionation, which leads to the issue that the operating pressures of fractionation towers generally fall below the pipeline delivery pressures, so export compression is required. Various schemes for removing ethane and heavier components in the LNG have been addressed previously by KBR [Ref. 10]. In this work it was found that removing most propane and heavier components with a smaller proportion of the ethane is sufficient to achieve the required gas quality, because the former contribute more to the high heating values (HHV)..

Recently, KBR has received requests by prospective LNG terminal owners to study deeper ethane recovery, at locations where there is a local market for ethane. A number of schemes have been investigated by KBR, pre-screened using various criteria including:



Optimise operating conditions for favourable vapour-liquid equilibrium conditions Optimise use of equipment. Make best use of the LNG cold capacity for providing reflux and offsetting heat input

in the demethaniser reboilers. High ethane recovery rates

The results of these investigations for three categories of process are detailed below:

Category A Residue Compression In the residue compression scheme shown in figure 13, the inlet LNG is pre-heated by a reflux stream before entering the column. The overheads are compressed to send-out pressure and a side stream of the compressor discharge is taken to pre-heat the column feed and to provide reflux. This scheme recovers 95% of the ethane in the feed.

Figure 13 Simplified Residue Compression with Enhancement for Ethane Recovery (KBR Design)

Category B Residue Compression and Condensing In the residue compression and condensing scheme shown in figure 14, the inlet LNG is pre-heated before entering the column. The overheads are compressed and then condensed in the feed pre-heater. The re-liquefied stream is pumped to send-out pressure, then vaporised for export. Immediately upstream of the vaporiser, a slip-stream is taken out to provide reflux to the demethaniser column. This scheme has a 95% ethane recovery rate.

Figure 14 Residue Compression and Condensing

Category C Residue Condensing In category C there are two schemes. Figure 15 shows a simplified scheme of a process with pre-heated LNG entering the column. The overheads from the column are used to pre-heat the column feed and are completely condensed before entering the reflux drum. From the drum, reflux is provided for the column and the remainder is pumped to send-out pressure, vaporised and exported. This scheme can achieve ethane recovery of 90%.



Figure 15 Residue Condensing with Reflux Drum attached to Demethaniser (KBR Design).

Figure 16 shows a similar process, except the overheads are only partially condensed before entering the reflux drum. The vapour from the reflux drum is compressed via a much smaller compressor compared to the residue compression and condensing scheme of figure 14. The compressed vapour is condensed against the column feed before re-entering the reflux drum. This scheme achieves 95% ethane recovery. The working principle is similar in some aspects to the Ortloff Cold Residue Reflux process (CRR) [Ref. 11].

Figure 16 Residue Condensing with Reflux Drum Attached to Demethaniser and Enhancement for Ethane Recovery

(KBR Design).

Process Comparison In general, the simple residue compression scheme offers the simplest process with the best flexibility and best ethane recovery theoretically possible, though at the highest capital and operating cost due to large compressors. The residue condensing schemes have lower capital and operating cost but poor flexibility, for example increased sensitivity to LNG inlet conditions. Hence this scheme is more suited to a terminal with little variation in send-out rates. As the residue condensing schemes involve multiple phase changes, exergy loss (the irreversible loss of energy from the process) is higher and ethane recovery is reduced. The residue condensing and compression scheme offers an intermediate option.

Selecting the best process for a specific project is a trade-off between the capital and operating cost of the plant required versus the revenue achievable from the ethane and heavier product stream. Local factors such as availability of a heat source for the reboiler, unit cost of power and send-out patterns will also influence the process selection. Optimisation of the terminal may steer the process selection towards reducing reboiler duties by lowering operating pressures or process heat integration.

Offshore Terminals There is a high level of interest in building facilities offshore, due to environmental and permitting issues, particularly in the US. Offshore installations could also be attractive in locations with poor shipping access at the coastline.



Several companies have proposed concepts for offshore storage and regasification terminals, though there is little practical experience at this stage. The essential elements of an offshore terminal are all proven technology: e.g. offshore platform or vessel substructures, onshore regasification design and LNG transportation. Offshore terminals will require a successful integration of these proven elements.

Offshore terminal concepts can be classified as: Gravity Based Structures (GBS) Floating Storage and Regasification Unit (FSRU) Other concepts

Concept selection for a particular site will depend on site conditions such as water depth, sub-sea soil, sea conditions etc. Each of the terminal concepts presents particular technical challenges, and to date offshore LNG terminals have been found to require higher investment cost than an equivalent conventional land-based design. Project economics will favour an offshore design when the incremental cost is less than the cost of building the terminal further from the market to circumvent permitting or environmental requirements.

Safety is an important aspect of all LNG installation designs, and offshore structures present new considerations; Quantitative Risk Assessment (QRA) of offshore installations needs to consider the risk of events such as ship impact to the facilities. As offshore designs are likely to be more congested, KBR pays careful attention to mitigation measures to offset the risk of escalation and higher consequences in terms of economic loss and casualties. Owners and operators will set high standards and expect comparable safety performance to the excellent record of the onshore LNG industry.

A brief review of the main offshore concepts follows:

Gravity Based Structures (GBS) A number of companies have been developing GBS concepts, and the first LNG GBS import Terminal is under development by affiliates of ExxonMobil, Qatar Petroleum and Edison in the Adriatic Sea 17 km offshore Venice. [Ref. 12]

Challenges need to be addressed to construct GBS LNG terminals, and designers will over time refine their design to address these issues, including:

Design and construction of offshore LNG storage: Rectangular tanks are favoured for GBS designs, as the geometry is more conducive to achieving a compact layout. Designers face the challenge of minimising weight, which is an important factor in offshore design. ExxonMobils Modular LNG (MLNG) Tank uses internal trusses made from 9% nickel to reduce the wall thickness of the tank.

Various options can be addressed, for example the storage tanks can be used as the base to mount other processing equipment, or alternately storage can be mounted on a separate structure to the regasification plant. The major considerations in this assessment are safety and economics; the technology is new and designers are still considering a range of concepts.

Design for extreme meteorological and ocean conditions: A GBS is likely to be exposed to more severe conditions than an onshore plant, and it may be necessary to consider construction of separate breakwater structures to improve conditions at the tanker interface.

Design of the loading arms need to allow for more movement at the interface due to exposed ocean conditions. Loading Arm vendors such as FMC of France have been developing prototype systems to improve functionality in extreme conditions. FMSs Cable Targeting System" (CTS) uses cable connection technology to allow the offloading arm to be connected to vessel manifolds undergoing relative motions substantially higher than those allowed for offloading arms fitted with standard hydraulic controls. Some operators are interested in developing large-bore cryogenic hoses; hoses up to 20 have been tested with liquid nitrogen.



Design of large support structures The support structures for GBS designs are generally based on large concrete caissons that can be towed to the project site and grounded on the sea bed. There is experience of designing such structures in the industry, and designers are aware of constraints imposed by local factors such as meteorological, ocean and seismic conditions.

The GBS is constructed onshore and installed offshore, typical concrete quantities in the structures considered to date are in excess of 100,000 m3. The scale of these structures might be limited by the ability to build them, or the draft during towing.

A typical GBS architecture is illustrated in figure 17

Figure 17 GBS Terminal; artists impression

Floating Storage and Regasification Unit (FSRU) Floating designs present similar challenges to gravity based offshore designs, but with the additional aspect of movement, and the potential for transient non-horizontal periods. FRSU motion is multidimensional and will affect structures, equipment and people. The degree of motion is affected by hull dimensions and dynamics, sea conditions and the mooring system. FRSU design requires a thorough sea-keeping analysis to optimise design and provide input to design of the topsides facilities. The challenge of designing for motion affects several aspects of the terminal design including:

Storage Tanks Various designs have been considered. One of the major challenges in floating storage design is to mitigate the impact of sloshing, particularly for membrane-type tanks. Designers need to consider operation of partially full tanks, and ensure that transient sloshing loads as well as long term fatigue are properly assessed.

Vaporisers ORVs and SCVs are not favoured on a moving platform. The ORV requires a very good verticality, some vendors suggest tolerance less than 0.5. The SCV includes a water bath in which no liquid motion is allowed. This means that the FSRU requires the development of new process schemes based on heat exchangers insensitive to motion.



Several solutions have been considered using either an intermediate fluid or water directly. As the floating terminal is likely to have its own electrical power production based on gas turbine generators, turbine exhaust gas heat may be recovered to perform the vaporisation although the heat amount recovered on the gas turbine will likely not be sufficient on its own to vaporise the nominal flow rate for LNG.

Other Concepts A more recent development has been consideration of LNG Regasification Vessels. Daewoo Shipbuilders [Ref. 13] have recently completed the first such vessel, based on a conventional LNG tanker design with regasification equipment mounted on the ship to deliver gas via SPM or loading jetty directly to market. The Exmar Energy Bridge is based on a tanker carrying 138,000 m3 of LNG and capable of delivering approx 13 MMNm3/d into a pipeline system at up to 100 bar a. [Ref. 14] This project uses the Advanced Production Loading AS (Norway) proprietary Submerged Turret Loading (STL) system.

Another offshore concept is to provide a SPM at an offshore location, with cryogenic pipeline to a remote facility. This could be a transfer to onshore LNG storage, in circumstances where a cryogenic transfer line is an economic alternate to a conventional jetty or some authors have considered transfer via an offshore regasification unit to salt cavern storage [Ref. 15]. Krekel & Prescott [Ref. 16] point out that the concept of using SPM is well established in the oil industry. The major technical development required to extend the SPM concept to LNG terminals is confidence in sub-sea cryogenic piping systems.

Conclusions The LNG terminal is just one element in a very capital intensive supply chain required to deliver high volumes of stranded gas to distant markets. All links in this chain need to be in place before any LNG project can proceed, and obtaining approval to build LNG terminals is becoming a challenging link in this chain.

There are dozens of LNG terminals around the globe, and designers like KBR have several decades of experience with their design. Most terminals have a similar design concept; the traditional terminal is predominantly an onshore plant with a jetty, trestle, two or more storage tanks and vaporisation by open rack vaporisers (ORVs) using sea or river water as heating medium depending on location, with submerged combustion vaporisers (SCVs) as back-up.

This paper has shown that no matter how simple the traditional terminal design might look, there are plenty of opportunities to apply technical innovation to address the environmental, social and economic concerns that might otherwise create the bottleneck in the LNG supply chain. To illustrate this point, the paper considered the following technology areas:

LNG Vaporisers: Traditional terminals have been dominated by just 2 alternate vaporiser designs, the Open Rack Vaporiser (ORV) and the Submerged Combustion Vaporiser (SCV). The authors anticipate a trend towards more environmentally acceptable schemes using ambient air to provide heating in preference to fuel gas or water, and have found that the NPV of an investment in ambient air vaporiser schemes can be favourable.

Heat Integration: Exploiting the synergies of integration of LNG receiving terminals and power plants lead to large increases in energy recovery and reductions in CO2 emissions. The configuration of the new KBR processes overcomes the concerns on GT inlet air chilling (ambient conditions, compressor suction losses) due to the flexibility in transferring the source of heat for vaporisation between chilling the GT inlet air and condensing the exhaust from the steam turbine.

Ethane Extraction: The world trade in LNG has been dominated by Japan as the major importer. As a result, the specification of most traded LNG (such as higher heating value, HHV) suits Japanese market requirements. In some new markets such as the US, where lower HHV is required, there may be a requirement to remove ethane and heavier components to achieve the gas specification. This paper has reviewed several process schemes that can provide deep ethane recovery, with the opportunity to sell an additional value added product in locations with a local demand.



Offshore Terminals: The paper has provided a brief review of offshore terminal concepts. In short, building onshore is generally at lower cost. However, in some markets there are local social and environmental concerns that make it impractical to obtain the permit to build onshore; in such cases it might be economical to build offshore.

References [1] World Bank Group: Table 4, Liquid Effluent from Onshore Oil and Gas Production, Oil and Gas

Development, Pollution Prevention and Abatement Handbook (1998). [2] Sinking Feeling : Offshore U.S. Terminal Developers Run into Cost, Environmental Challenges,

LNG Express, Vol. XIV, No. 10, p. 2-3, 2004. [3] Personal communication with Ed Vogel at Selasfluid. [4] Web page, http://www.chxheat.com/perform.html. [5] Joseph H. Cho, Gopal Mathur, Heinz Kotzot, Charles Durr, Limitations in LNG Vaporization Process

Selection AIChE 2005 Spring National Meeting, 2005. [6] Townsend, B., Khaligh, B., Opportunities for Elegant Power Systems Design in LNG, SMi LNG

Conference, February 2005 [7] Cho, J.H., Patel, H., Coyle, D.A., Durr, C.A., A Case Study for Integrated LNG-to-Power: Technical

Comparison of Available Cost Reduction Methods, AIChE Spring National Meeting, 2004 [8] Rogers, D.R., Gas Interchangeability and Its Effects on U.S. Import Plans, Pipeline and Gas journal,

September (2003a) [9] Rogers, D.R., Long-term Solution Needed to Embrace Imports with Pipeline Gas, Pipeline and Gas

journal, September (2003b) [10] Huang, S., Coyle, D., Cho, J., and Durr, C., Select the Optimal Extraction Method for LNG

Regasification, Hydrocarbon Processing, July 2004. [11] Campbell, R.E., Wilkinson, J.D., Hudson, H.M., Hydrocarbon Gas Processing, U.S. Patent

4,889,545. [12] Roger D. Leick Adriatic LNG Terminal ExxonMobil Development Company. Presented to

Gastech 2005 March 15, 2005 [13] Hochung Kim, JungHan Lee, Design and Construction of LNG Regasification Vessel.

Presented to Gastech 2005 [14] Patrick Janssens, Energy Bridge The Worlds First LNG Offshore Solution. Presented to

Gastech 2005 [15] OTV 16152 Offshore Salt Cavern Based Mega LNG Receiving Terminal, By M.M. McCall et

al, OTC Conference, May 2004 [16] Max Krekel, Neal Prescott, Ship to Shore Transfer of LNG a New Approach Presented to

Gastech 2005


wpc_cd168

Documents

facilities lng shipping

lng chain

lng trade

lng project

liquefied natural gas

lng vaporisation

lng vaporizers

paper new lng