LNG Import Terminals — Time for a Step Change?

David Haynes & Dr Carol HumphreysBG Technology

Gas Research & Technology Centre, Loughborough, UK

Dr Anthony ActonBG International

100 Thames Valley Park Drive, Reading, UK

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LNG Import Terminals — Time for a Step Change?

Introduction

In 1964, BG (formerly British Gas) built and operated the world s first LNG import terminal at CanveyIsland in the UK, Figure 1. Since then BG has investigated building LNG import terminals elsewhere inthe UK and in other parts of the world. BG International is responsible for bringing these projects tofruition and is supported by BG Technology who provides technical and engineering support to theproject staff. Currently the company is proposing to build a terminal in India at Pipavav1 and is assessingthe options for a LNG import terminal in the Italian port of Brindisi.

BG is probably best known in the industry for its innovative commercial approach to the Atlantic LNGliquefaction project in Trinidad2. Lessons learnt here can be carried forward under the same costreduction banner, however import terminals present different challenges. This paper reviews current andnear future design features of LNG import terminals and examines the breaking technologies and the risksand benefits they will bring to the industry.

Figure 1: Canvey Island, UK - The World s First LNG Import Terminal in 1964

Industry Drivers

The LNG importation industry has changed significantly since Canvey Island started operation. In theCanvey world credit worthy buyers bought LNG to provide security of supply to large gas distribution

networks. This can still be seen today in Japan, North America and in parts of Western Europe.

The challenge today is to supply lower credit rated customers in developing markets where the mainemphasis is on the generation of power. This market change has been the result of technical innovation -the design and successful commercialisation of combined cycle gas turbine (CCGT) units. These lowcost, quick build, high efficiency power plants have resulted in a step change in electricity economics anduse gas as their preferred fuel. Environmental considerations are reinforcing the pre-eminent position ofthe technology in the market place with probably only fuel diversity considerations leading to thecontinuing construction of coal, oil and nuclear equivalents.

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Enron has completed an IPP style LNG import terminal in Puerto Rico and a second is being developed atDabhol in India. Others are being developed or are planned for Spain, Turkey, Brazil and India.

The pace of change from the early 1960s has been phenomenal. The so-called Third World is nowlargely industrialised and in many areas has caught up with the leading industrial nations. This is leadingto energy shortages and many new opportunities for LNG. However, on the down side, most of the goodterminal sites have already been taken by other developing industries or have become embedded in areaswith large populations. In the past, LNG tanks were always thought of as the high cost, long scheduleitem in import terminal construction. Nowadays, the marine facilities are often as expensive andsometimes more so. Since BG published its assessment of the costs of import terminals3 much haschanged and marine facility costs have escalated from perhaps US$ 20-30 million for a typical project toas much as US$ 80-100 million for the more exposed facilities. Storage tank costs have remainedrelatively constant over this period and on some projects have actually reduced as a result of keencompetition.

Marine Facilities

Marine facilities are getting more expensive as the sites available for development are less ideal, eitherwith more exposed marine conditions or in regions with large areas of shallow water. The increase incosts can result from a longer jetty, increased dredging and/or the need for a breakwater. Beyond a lengthof 1 km design considerations such as pressure drop, particularly for vapour return lines and heat ingressbecome increasingly important.

The impact of jetty length and exposure to more severe marine conditions were examined by BG using aspecialist contractor during the site selection stage for the Pipavav import terminal in India. The resultsare summarised in the table below where it can be clearly seen that jetty lengths were considerable andthe need for breakwaters significantly increased both investment cost and schedule.

Table 1: Effect of Marine Exposure on Terminal Jetty Costs

Site 1 Site 2 Site 3(rejected)

Site 4

Jetty Length 4 km 2.4 km 1.1 km 2.4 kmDredging Not required 0.4 million m3 Not required 4.5 million m3

Breakwater length 1.8 km 2 km 1.1 km Not requiredSchedule 80 months 80 months Uncertain 36 monthsCapital cost ratio 4.9 4.6 Not calculated 1.0

A comparison of the jetties built at Canvey Island in 1964 and Atlantic LNG in Trinidad in 1999 showsvery little change in the design and construction practices used. This suggests that there has been verylittle alteration in jetty design in 30 years. This is not strictly correct, as Trinidad, Figure 2, was adeliberate attempt to simplify the more recent jetty head designs typified by many import and exportterminals in South-East Asia.

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Figure 2: The Jetty At Atlantic LNG in Trinidad

To examine whether there was scope to use alternative and hopefully cheaper solutions, BG Technologyin conjunction with a well known firm of marine consulting engineers4, compared the conventional rigidpiled deck jetty with other piling systems, gravity base structures, tunnel and bridge technology andfloating structures.

This generic study suggested that savings of 10% in civils costs could be achieved by careful design of amodified piling system and that other technologies were of similar cost to conventional piled methods andshould therefore be considered, particularly where site specifics might make their application attractive.The results were interesting, but not as originally envisaged for the economics of the alternative designs,but for how a conventional jetty should be specified.

The study forced a re-evaluation of what a jetty needed to do. The conclusions were that a jetty needed tobe able to anchor a ship so that loading/unloading of LNG can take place and provide an alternativeescape route for the ship crew in the event of an emergency. Every other function of a jetty could, inideal circumstances, be removed. The following areas of jetty design should therefore be reassessed:

• Access requirements need to be challenged for load weight and frequency of use; a roadway isnot necessarily required.

• The means of corrosion assessment and the equipment inspection and replacement regime needscareful consideration.

• Fire-fighting can probably best be accomplished through the use of tugs, as per SIGTTOguidelines.

• Contracting strategy needs detailed assessment and comparison with plant wide systems.

The new Ohgishima jetty head in Japan5 and Cove Point in the USA demonstrate the reduction in accessrequirements. The jetty head in both cases is, of necessity, isolated from the terminal by a tunnel andaccess is thereby restricted for both personnel and maintenance purposes.

Can a trestle-less jetty therefore be envisaged? The two tunnel based systems described above were builtfor environmental reasons and would not be contemplated elsewhere on grounds of cost. Designs andcosts developed by BG Technology suggest that tunnels are 6.5 - 7.5 times more expensive than normalmarine facilities. To have a trestle-less jetty therefore suggests that the LNG pipelines must be laidon/under the seabed or in the water. BG and BP have been working together to assess whether there areany outstanding technical hurdles to such a concept. Various concepts have been developed from thisproject such as:

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• How the pipe should be anchored.• How expansion/contraction should be handled.• How the pipe should be insulated.• How the pipeline should be protected from third party damage.

The study ultimately aims to test one or more designs of pipework, probably including designs developedby others (e.g. Logstor Ror6, Figure 3), in a purpose designed experimental rig at BG Technology sSpadeadam test site in northern England. The experimental programme will aim to prove that LNG canflow consistently in a submerged pipeline.

Figure 3: The Logstor Ror Prototype Subsea LNG Pipeline. (reproduced with kind permission of Logstor Ror)

The elimination of the trestle is the first step toreplacing the jetty head with a single point mooring(SPM). Moving to this standard oil industry technologywould open up a whole new range of opportunities forthe LNG industry as extensive harbour facilities wouldno longer be a pre-requisite. However, the technicalchallenges remain significant. Chief amongst them isthe need for a flexible hose capable of connecting thebuoy to a LNG carrier and a flexible riser to connect theSPM to the subsea LNG pipeline. Progress has beenmade by both Coflexip7 and Senior Flexonics/Exxon-Mobil who are working to develop a flexible hosesolution for offloading liquefaction FPSO s.

Exxon-Mobil8 has proposed SPMs for unloading gas from LNG carriers after the LNG has beenvaporised using steam from the ship s boilers. This solution is technically feasible, the technology beingan extension of swivels and turrets already in use for well fluids on oil and associated gas FPSOs. Therestraints on the implementation are the result of design limitations on the existing ships and commerciallimitations on the ship trades. The technical issues that need to be addressed are:

• Space limitations on Moss type ships.• Steam pipe routing on existing ships.• Retrofitting a bow loading system.

Commercially the loss of flexibility and availability of these specialised ships, which will demand highercharter rates and limit spot trades, may prove more of a hurdle than the technical issues.

LNG Tanks

LNG storage tank design is tied to construction and operational standards, which limit, to a large extent,the scope for significant change. However, questions must still be asked as to whether they can be builtcheaper and quicker. If the design cannot change significantly then the methods of management,engineering, construction and operation must be optimised.

The Canvey tanks were 10,000m3 double metal (single containment) designs with aluminium inner tankand carbon steel outer. The inner tanks were constructed to fully contain the liquid and vapour, the outertanks were surrounded by earthen and concrete bunding and each took approximately 24 months to build.

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In terms of capacity, there was a significant step change in the size of tanks being built from the start ofthe 1960s (10,000 m3) to the end of the 1960s (35,000-50,000 m3). During the 70s and 80s the typicalcapacity rose from 60,000 m3 to 95,000 m3, whilst the largest tank constructed in the 1990s was 200,000m3. The typical size being constructed today is of order of 100,000-110,000 m3 based on the economicsof construction, the limitations of material thickness for the inner tanks and the load bearing ability of thesupporting base. Larger tanks are now being proposed again, for example the expansion at Atlantic LNGin Trinidad includes construction of a 160,000 m3 LNG storage tank. Furthermore, matching of tankeravailability with send out provides an important factor in setting tank capacity. For example a totalstorage capacity of 200,000 m3 will typically cost approximately $6 million less than a 220,000 m3 totalcapacity.

The trend in tank design, particularly in Europe, has been to move to double and full containment mainlyto save space. However, the single containment tank is still the most prevalent design, comprising some55% of those in operation. It is built where space is available, recently in the USA and Japan, and has alsobeen selected and approved by the authorities for BG International s Pipavav import terminaldevelopment. The reason for this is that they often provide the lowest cost and, perhaps of greaterimportance, the quickest safe design option.

Table 2: Relative Tank Costs

Containment Construction Relative CostSingle 9% Ni steel inner, carbon steel outer, metal roof 100 %Double 9% Ni steel inner, concrete outer, metal roof 111 %

Full 9% Ni steel inner, concrete outer, concrete roof 117 %Membrane Stainless steel membrane, concrete outer, concrete roof 122 %Concrete Concrete inner, concrete outer, concrete roof 106 %

In Table 2, costs for single and full containment tanks have been derived from the literature9 and othersfrom recent bids and conversations with tank manufacturers. The final value given above is for theKvaerner tank design that is a revision of the Preload concept of an inner and outer concrete tank and isonce again being bid on projects. Tanks with inner concrete LNG containers are currently in service inSpain, with two 40,000 m3 and one 80,000 m3 capacity tanks at the Enagas Barcelona import terminal. Aspart of its watching brief on tank technologies, BG Technology is investigating the schedule and costsavings claimed over the more conventional double containment tank design with a 9% Nickel Steel innertank.

Some in the industry have argued that single containment tanks are actually more expensive than doubleor full containment tanks as a result of the land area they require for installation. The area of landrequired by a LNG tank depends on mitigating the design hazards defined by the construction standardsor precedents taking into account the equipment and buildings within the site and the area immediatelyoutside the site boundary. BG Technology recently completed a generic study into the land requirementsfor a site containing 4 x 100,000 m3 LNG tanks (70m diameter, 30m high) equally spaced on a squarepitch using the NFPA 59A and BS EN 1473 scenarios and consequence assessments using in-househazard analysis software. For example, Table 3 shows the calculated distance to a thermal radiation levelof 5kW/m2 from different fire scenarios.

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Table 3: Thermal radiation levels from different LNG fire scenarios.

Tank type Scenario Distance from tank centre (m) to radiationlevels of 5 kW/m2

Single with squareimpoundment area

Pool fire in impoundment region150m by 150m

515

Double Roof failure & pool fire in tankouter

263

Full No tank failure considered — use the consequences from theignition of the design spill .

This consequence information can be combined with the regulations to define the minimum land areaneeded for a site, which is in an area that requires a thermal radiation below this 5 kW/m2 level at theboundary (see NFPA 59A for definitions). The area of land required is calculated to be 83 hectares for asite with single containment tanks, 28 hectares for site with double containment tanks and 21 hectares fora site with full containment tanks. Considering land costs of US$ 200,000 — 333,000 per hectare, sitepreparation costs of 25% of land costs (including bunding), a double containment tank cost of $35 millionper tank and the single and full containment tanks factored according to the relative costs above; then thetotal cost would be as shown in the following table:

Table 4: Relative Costs of Tanks and Land for Single, Double and Full Containment

Total Tank and Land costs ($US millions)TankType

RelativeCost for

Tank

Cost of 4 tanks($US millions)

Total siteland required

(hectares)$333,000 per

hectare$250,000 per

hectare$200,000 per

hectare

Single 100% 126.0 83 160.5 151.9 146.8

Double 111% 140.0 28 151.6 148.8 147.0

Full 117% 147.0 21 155.7 153.6 152.3

From the above table it can be seen that cost differences are within 8% for all cases and that doublecontainment is the cheapest for land prices greater than $200,000 per hectare, when single containmentbecomes more cost effective. However, the above conclusion is for a simple square pitch arrangementwith bunds around each tank and land requirements can be reduced for a single containment site if it ispractical to use a bunding arrangement that is remote from both the tanks and a sensitive site boundary.

Tanks can be built close together with an outer to outer spacing of D/2. However, it is desirable from asafety point of view that any small spill from one tank does not adversely affect the neighbouring tank.There are different approaches that can be taken, either installing active systems (such as water deluge orfoam) to mitigate the effect of thermal radiation from any ignited release of LNG, or the passive approachwhich includes allowing more room between the tanks and careful design of the impoundment areas toensure that any small spills are channelled away. The cost benefit balance between the two is playing offthe cost/availability of land against the installation and maintenance of foam and deluge systems.

Since the late 1960s, 9% nickel steel has been preferred to aluminium for inner tank construction due tothe higher material costs of aluminium. The method of construction and quality assurance (QA) testing asspecified in standards (radiographic examination of 100% of welds required to meet NFPA 59A) is such

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that the inner tank construction becomes both a time consuming and labour intensive operation.Radiography is intrusive in that no other construction operation can be carried out in its vicinity and itlags welding by 8 to 16 hours which can have implications on QA and lead to delays as repairs are carriedout. Ultrasonic examination techniques do not require clear areas and can more closely follow thewelding process. BG is actively involved in bringing ultrasonic examination methods into tank weldtesting through its representation on standards committees.

The installation of tank base insulation is a labour intensive operation and has remained relativelyunchanged in both the method and material used. The industry standard is Pittsburg Corning s Foamglasbut alternative insulation materials (e.g. Divinycell) are now available and are being assessed as a part ofFEED and EPC bid development. Developments in producing larger block sizes of Foamglas areunderway and this should help to improve the installation schedule.

The main change in tank design since Canvey has been the move from a vapour containing inner tankwith a domed roof to a suspended insulated deck where the vapour is contained by the outer tank. Theinner tank roof is now typically of aluminium construction with fibreglass and perlite insulation. Duringconstruction, the inner tank roof is used as a walkway and the insulation material can only be installedfollowing the hydrotest to avoid water ingress. This is a time consuming activity towards the end of theconstruction. The construction of the inner roof using a water resistant load bearing insulation is beinginvestigated as an alternative to improve schedule.

The integrity of the inner tank construction and tank settlement checks are carried out using a hydrotest.The BS 7777 Standard has recently included a guidance note that recommends a minimum hydrotestheight to give a 125% load at the base of the tank, thereby bringing it in line with the recommendations inAPI 620. The quantities of water required can be a major cost, especially in remote locations with littleexisting infrastructure, and BG is considering the economics of using seawater and the consequences forthe inner tank and connections and disposal as opposed to conventional use of potable water.

Finally, in considering contractors demarcation and harmonisation, where does the tank end and the restof the plant begin? Consideration should be given to the boundary between the tank and pipework andminimisation of equipment on the tank roof (eg passive rather than active leak and fire protection) as partof the FEED and EPC processes. Inevitably with contract interfaces, improving definition and interactioncan lead to cost savings.

Boil Off Gas

Boil off gas is produced as a result of heat ingress into LNG storage tanks during normal operation aswell as from flash and displacement gas during ship unloading. The conventional solutions for handlingboil off gas involve liquefaction or recondensation back into the LNG stream and direct compression intothe export line. The provision of equipment for dealing with this gas represents a significant capital andoperating cost. However one of the main problems associated with boil off gas handling is the largefluctuation between the normal and peak rates and systems therefore have to be designed for the highergas rates.

Alternative processing options for boil off gas might include on-site power generation, with the prospectof surplus power export, or use in submersed combustion vaporisers. Calculations performed by BGTechnology have shown that on-site power generation looks attractive for most combinations of gas andpower prices but is highly dependent on these factors. However both solutions would still require peakrate handling equipment to be installed. Another option identified by BG Technology is the use of theliquid jet compressor (LJC) as a potentially attractive alternative to the reciprocating compressors used fornormal boil off gas handling10. LJCs are a type of jet booster in which the low pressure boil off gas is

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entrained by the higher pressure LNG from thein-tank pumps. The pressure recovery obtainedwithin the device ensures that the outlet flow is asingle liquid phase so it therefore combines thefunctions of the boil off gas compressor andrecondenser in a single piece of equipment.Preliminary calculations have shown that theconcept is feasible and a suitable unit wouldrealise significant capital and operating costsavings. A commercialisation programme for thisequipment item is now under consideration.

Figure 4: Liquid Jet Compressor

A number of terminals, for example those of Gaz de France11, have been concentrating on reducing boiloff gas generation by modifying their tank filling regimes and by developing controlled tankpressurisation and depressurisation procedures. Changing the tank pressure allows the boil off gas to beeffectively stored within the vapour space of the tank and allows a degree of control on the volumes ofboil off going to the compressors. The economics between installation of a larger boil off gascompression system and a thicker walled tank requires careful consideration.

In the medium term, reliquefaction of the boil off gases and their return to the LNG storage tank is likelyto become a viable option. Kvaerner Maritime12 has already developed a reliquefaction system for itsMoss design of LNG ship based on conventional refrigeration machinery. This is however based on anitrogen expansion cycle so will have a significant parasitic power demand. Development of a moreefficient small scale liquefaction process using conventional refrigerants is underway.

In the long term, acoustic liquefaction technology, such as that being developed by Chart Denver13

(formerly known as Cryenco), may offer a compact solution with good turndown and potentiallycomparable (or better) through life costs. The Chart Denver programme has progressed to developing andbuilding prototype devices capable of liquefying the equivalent of hundreds of gallons of LNG per day.The technology needs further development until it is suitable for large scale applications such as boil offgas handling, though there is large degree of confidence that further scale up and efficiency improvementwill be feasible within a reasonable time scale (3-4 years).

LNG Cold

Much has been written over the years about the potential to use the cold energy stored in the LNG forother process and industrial applications. There are several examples of integrated processes operatingwithin the industry particularly in Japan where Rankine power cycles and air separation units arecommon. Air separation units are also found in some plants in Europe and Australia. Other Japaneseintegrations include carbon dioxide liquefaction plants, Carbon 13 separation and refrigerant supplies tocold store type warehousing.

Leaving Japan to one side because of the special economic conditions that apply to this historically highlyregulated market, there has been little use of these technologies elsewhere in the world. The two mostlikely reasons that these energy recovery schemes have not been taken forward are the difficulty ofdefining a mutually beneficial commercial arrangement between the operators of the two facilities and thehigh investment costs and poor returns associated with some of the complex equipment required.

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Air separation units (ASUs) can benefit significantly from integration of the LNG vaporisers with theASU through an interchanger. In the Australian Dandenong14 plant this integration results in an overallsite power saving of about 33% through the reduction in size of the ASU refrigerant compressors. Similarlevels of power savings have been reported from Japanese plants. The impact on the LNG plant is thereduction or elimination of the vaporiser equipment. Capital and operating costs of sea water systems canbe significantly reduced or alternatively gas consumption as fuel in submerged combustors can bedecreased. The main issue is balancing the loads. At Dandenong 115 te/d of LNG can produce 230 te/dof liquid nitrogen but rarely can the full LNG load be accommodated by the ASU. To be successful, thetwo plants must be able to operate consistently close to their optimum levels.

The second major consumer of LNG cold is Rankine power cycles. Here LNG is vaporised at pressure bycondensing a refrigerant, usually propane. The refrigerant can be pumped to pressures of typically 50 barbefore being vaporised and expanded to produce power. The vaporised LNG may also be expanded in asecond cycle to generate further power. These plants have been installed to generate electricity for on-siteuse at several Japanese terminals. The main difficulty with Rankine cycles is the need for significantcapital investment in relatively complex, cryogenic rotating equipment, for example:

Table 4: Comparison of Power Generation Economics

Rankine Cycle Open Cycle Gas TurbineMachine EGT Tornado Gas TurbinePower Generation (ISO conditions) 7.3 MW 6.7 MWCapital Cost (US$/kWe) 1960 407Operating cost ($/kWh) 3.63 3.80

Power generation or lack of power use is the key driver for these cold recovery systems. As can be seenfor the Rankine cycle economics above the commercialisation of gas turbine technology has produced astep change in power generation costs. The future use of cold energy recovery will therefore be throughthe interaction with gas turbines.

There are three main options:

• Chilling of the air entering the gas turbine.• Cooling the steam turbine condenser temperature to pull a higher vacuum.• Turbine waste heat recovery into submerged combustion vaporisers.

The performance of gas turbine power generation systems declines with increasing ambient temperature.CCGT power plants in places such as India and other parts of South-East Asia could therefore benefitsignificantly if the air to the gas turbine could be chilled using LNG cold. BG Technology examined arange of inlet air chilling systems for a power plant that could be sited adjacent to BG s Pipavav terminalin India and for a the Santa Rita power plant in Batangas Bay, the Philippines, Figure 5. A closed loopcooling system based on water or glycol solutions was developed to link finned heat exchangers in theinlet air ducts with open rack and shell and tube LNG vaporisers. For the Philippine case, a modest capitalinvestment in the chiller system led to an output increase for the CCGT power station of 2.9% whichequated to an enhanced revenue of US$ 10-15 million pa. A range of software was subsequentlydeveloped to optimise the LNG terminal/power station interaction for a range of meteorologicalconditions, site separation distances and economic conditions. Commercialisation in this area is nearlycomplete with integrated inlet air chiller/LNG vaporisation technology installed at Penuelas in PuertoRico15 and being developed for Dabhol in India.

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Figure 5: Inlet Air Chilling System for CCGT Power Stations

Integrating a steam turbine condenser with the LNG vaporiser is a much less attractive option. Thedifficulty here is usually the mismatch in thermal loads with the LNG vaporiser being relatively tinycompared to the condenser (one project considered 23 MW of LNG vs 160 MW of condenser).Condenser performance is therefore only improved by a fraction of a degree Celsius. Considering theproblem in reverse has more merit. Now a LNG vaporiser has a warm water sink which has no impact onthe environment and can be theoretically recycled ad infinitum. This could be interpreted as aneffectively closed system open rack vaporiser with potentially less ecological impact. Co-siting of thetwo facilities is essential and therefore severely limits the number of projects where this technique can beapplied.

The third energy recovery scheme uses low temperature waste heat in the gas turbine exhaust to reducethe amount of gas fired in submerged combustors. This technique has been successfully employed at theZeebrugge terminal16 for some time. BG s calculations suggest that the economics for this option varydepending on the relative ratio of gas to electricity prices. For Belgium the economics are good but theyare not always repeatable elsewhere in the world.

Safety

Safety is often seen as an additional cost item or as being prohibitive in allowing innovation. However,including safety studies at the earliest stages of a project may result in both safety improvements and costsavings.

Challenging the established approach and application of advances in technology should be used toconstantly quantify, maintain and improve site safety. Why should a particular item be included justbecause it was used in the last project? Just as the economical push is for more compact import terminals,sited in busy ports with reduced manning levels, an innovative approach to ensuring that the site isacceptably safe should be allowed.

To reap the benefits of novel solutions to improving site safety, you need

• Accurate methods for quantifying the actual risks and assessing the impact of any proposedchanges.

• An understanding of regulatory frameworks that allows for novel approaches to be implementedprovided their worth has been demonstrated.

Santa Rita Power Station, The Philippines

Inlet Air System Finned Exchanger

Santa Rita Power Station, The Philippines

Inlet Air System

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One of the roles of BG Technology is to provide robust methods for assessing the consequences ofcredible hazards and the effectiveness (or otherwise) of hazard reduction or mitigation methods. This isachieved through realistic scale experiments and the use of computer based mathematical models.

Computer based mathematical models provide a quick, and simple way to assess a large number ofpotential hazards. Importantly the accuracy of the models must be quantified. The BG Technology modelshave typically been validated against medium and large-scale experimental data. For example, a recentseries of spreading experiments were specifically designed to provide data to validate the LSMS17

spreading model used for LNG releases. Figure 6 shows one of the experimental configurations used.

Figure 6: Liquid Spill Test Configuration for Validation of LSMS Model

It has been demonstrated on numerous occasions that foam and water deluge systems can be effective atmitigating the effect of low momentum hydrocarbon fires (Figure 7 shows a recent pool fire water delugeexperiment). As such they are widely used particularly in the offshore industry where space is at apremium and all the equipment is packed into a relatively small area. However, on a large open onshoresite the advantages of a fire fighting system are less obvious, even though the initial cost is only a tinyfraction of the whole site cost. In particular, fire protection systems require regular testing andmaintenance throughout the lifetime of the installation which can be expensive and can lead to corrosionof other equipment items.

Figure 7:Large Scale Fire Test at BG Technology s Spadeadam Test Facility.

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The issues that need to be addressed when considering an import terminal include:

• The advantages of passive fire protection measures are that they are always available and needlittle maintenance, but require a larger initial investment. Conversely active systems requiretesting, maintenance and can fail on demand due to either inherent unreliability or as aconsequence of other equipment failures.

• What is a credible release scenario? The impoundment and bunding requirements around a LNGstorage tank are sized for a full tank failure, is this credible? Should they be more focused oncontaining small spills?

• What is the impact of weather conditions and existing/future facilities outside the site boundaryon plot layout?

• Fires are a very infrequent occurrence at LNG sites so, when does the cost of maintaining (andtesting) complex foam and dry powder system out-weight the potential benefit? Would it bebetter to design the site so that any small LNG spill were channelled away from other equipmentwhere it can then disperse safely or in the case of ignition burn without endangering the rest ofthe facility?

Offshore LNG

A combination of a growing interest in smaller scale power generation applications, the need for quick,low cost project start-ups to establish the market, or in some cases environmental issues, has led a numberof potential projects to consider the use of an offshore regasification terminal. In some respects the use ofoffshore processing facilities has been well proven in the oil industry but for LNG this represents a moreradical approach and one which provides a greater engineering challenge than conventional onshoreplants.

For an LNG import terminal, the concept can reduce the impact of any port restrictions, localenvironmental concerns and tidal issues. The entire facility, which might be of modular construction, canbe built and fitted out away from the site, eliminating the need for a labour intensive project in remotelocations. In addition, if used as part of a start-up strategy, it could then be relocated to further projects.In adopting this type of solution the distance to shore and length of the subsea pipeline required are keyfactors as is the need to embrace offshore working practices and logistics of manning and maintenance.

A number of proposals and concepts have appeared in recent years, including Kvaerner Maritime18, IHI19

and Edison/Mobil20. In addition, Project Azure21 — a EU funded development programme led byBouygues Offshore - is currently assessing the viability of a fully floating LNG chain. Each of theseconcepts has incorporated a number of features with respect to their construction and the basic options aresummarised in the following table:

Table 6: Summary of Offshore LNG Import Terminal Concepts

Vessel Type Floater Gravity base (GBS)Mooring System Spread moored or weather-vaning Seabed

Hull Concrete or steel ConcreteStorage Spherical, prismatic or membrane

Offloading Side to side or tandemTransfer System Fixed or flexible

A GBS system, Figure 8, might be more attractive than a floater in shallow waters and has the potential ofbeing expandable but beyond this there would appear to be no dominant sub-system. Each selection

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would not be taken in isolation and would be dependent on the harshness of the environment and thenature of the seabed. Other issues to be considered would be resistance of the structure to explosion, fire,spillage and collision damage. Sloshing in part filled membrane tanks is of concern, but work is in hand toaccess the loads involved and verify their suitability21. A number of suitable offloading systems based onboth fixed or flexible transfer lines are also under development.

Figure 8: Gravity Base LNG Import Terminal by Bouygues Offshore

(reproduced with kind permission of Technigaz)

Safety of any offshore installation is paramount and special consideration needs to be given to avoidcatastrophic incidents that might result in the exposure of personnel to risk and loss of the vessel. Bynecessity more compact plant is required for offshore applications, whereas the industry mindset is basedon large distance separations. Therefore a key issue is to decide which standards to apply when anormally onshore-based industry moves offshore, or conversely, will the designs proposed meet therelevant existing safety requirements?

Major naval classification societies have experience in developing standards with respect to oil FPSOs inwhich offshore and shipping standards played a major role. The LNG industry has an outstanding safetyrecord and there is no reason why a marriage of safety regulations cannot work for LNG as it did for oil.The necessary development of such rules and codes for design and operation is being considered as partof Project Azure. Generic safety studies on LNG FPSO systems by BG Technology, in collaboration withBP, Chevron and Texaco are also relevant to the import case as are detailed safety assessmentsundertaken by Shell22.

The role of the classification societies is an interesting one. Their recommendations on the design ofFPSOs for liquefaction, so far, has been based on a fairly strict interpretation of the InternationalMaritime Organisation s (IMO) Gas Codes and LNG import terminals could expect the same treatment.The need for mezzanine decks for equipment and separation distances from tank domes are two keyrecommendations. The Gas Codes, of course only apply to ships and therefore only to floating LNGimport terminals. The GBS designers, such as Bouygues Offshore, have designed their structures usingthe same techniques as for traditional land based import terminals. The overriding design features aretherefore based on qualitative risk assessment such as BS EN 1473 rather than the proscriptive IMO GasCodes. Some designs of GBS have placed equipment such as vaporisers on the tank structures. It cantherefore be argued that this flexibility of design approach will favour the use of GBS import terminalswherever the water depth and seabed conditions permit.

Cost is the main driver that will determine whether the offshore option will ever materialise. On a genericbasis the costs and schedule of a GBS and a conventional terminal appear very similar. Some of the

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proponents of the technology suggest that offshore regasification could be cheaper, maybe by 30% butthis remains to be established. As the civil engineering costs for the tanks and jetty or the seabedconditions for the GBS dominate the designs and cost, only time and detailed site specific studies will tell.

There is a lot of activity within the industry, particularly on engineering solutions common to LNGimport and export facilities, with designs at a point that could be taken into a FEED study. A shallow,benign location would prove suitable for first demonstration that might ultimately see the offshore LNGconcept become reality.

Conclusions

The challenges of siting a LNG import terminal and receiving regulatory consents are becomingincreasingly difficult. This has stimulated the LNG industry to consider technical innovations moreseriously than it has for some time. The integration of CCGT power stations with LNG import terminalsis happening in more places and in more ways as regasified LNG is increasingly used for fuel.

Major work is being performed on revolutionising the way that LNG is unloaded from ships with theconstruction of a trestle-less jetty probably possible within 2 years. The use of subsea LNG pipelineshas the potential to completely change the way that LNG terminals are sited and therefore theireconomics.

LNG storage tank design has, except for economies of scale, remained essentially unchanged for sometime. But even in this Standards based area, small innovations are starting to appear to meet the costreduction demands of the LNG industry. The concrete inner tank has been re-launched, NDT inspectionmethods are being revised and insulation systems are being challenged which represents considerablemovement for a set in stone design.

Even offshore LNG may happen before too long but it is not yet a panacea for the industry and may neverbe. Many of the changes mentioned in this paper will prevent offshore LNG becoming the preferredsolution for sometime to come as each of them will drive down costs and widen terminal siting options. Itis potentially a niche technology that the industry will use to control costs or enable projects to proceed.

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