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OTC 20683

Converting Existing LNG Carriers for Floating LNG ApplicationsDavid Franklin - Mustang; Henry Reeve - Alan C McClure Associates; Brad Hubbard - Mustang

Copyright 2010, Offshore Technology Conference

This paper was prepared for presentation at the 2010 Offshore Technology Conference held in Houston, Texas, USA, 3–6 May2010. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract

Despite the recent economic downturn and reduced need for LNG, long-term demand will be strong and opportunities toconvert existing LNG carriers (LNGC) into floating LNG plants are growing. Costs, schedules, and permitting challenges foronshore LNG production facilities have trended upward making it difficult for project developers to get financing. Costreduction strategies across the LNG value chain have resulted in significant changes in LNG shipping. To increase fuelefficiency, LNGC capacity has doubled in the past 30 years, and propulsion technology has migrated from steam to highefficiency diesel and dual fuel engines. Smaller, less efficient LNGCs are being displaced by new ships and the owners of theolder LNGCs are seeking new roles for their vessels. This paper explores the opportunities and challenges of convertingexisting LNGCs for Floating LNG Liquefaction FPSOs (FLNG), Floating Storage and Regasification Units (FSRU) andFloating Storage and Offloading Vessels (FSO) service.

The costs of onshore LNG terminals with storage facilities, protected jetty, and cargo transfer equipment have increasedsharply whereas converting an LNGC for liquefaction, regasification or storage creates a self-contained LNG terminal thatcan reduce overall LNG terminal cost by 30% to 50% compared to onshore alternatives.

Converting LNGCs into floating LNG plants raises myriad design challenges when developing a project. Specific projectrequirements will lead LNG project developers to choose the appropriate LNGC for conversion. Below is a partial list oftopics, taken from experience, that require engineering study. These will be discussed further in this paper.

• Delivery flow rate and composition requirements

• Products to be marketed

• Project location specifics

• Gas pre-treatment or LNG processing requirements

• Appropriate ship type and size from available vessels

• Liquefaction or regasification technologies

• Equipment space requirements

• Vessel motion impact on process and storage

• Mooring and berthing systems

• Offloading configuration and methods

• Fitness for service and life extension, Class requirements

• Required utilities and integration with ship systems

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Introduction

The economics of the LNG value chain have driven the base load LNG industry to design increasingly larger LNG trains andcarriers. The older, smaller MOSS and membrane carriers are being displaced with a new generation of larger vessels. Thenew LNGCs have been optimized to carry larger cargoes, minimize cargo losses with onboard boil-off-gas (BOG)reliquefiers, reduce transit times with more fuel efficient propulsion systems, and reduce required crews with manyautomated and remote control functions. The majority of the older vessels have been maintained in good condition

throughout their service life. These older vessels are now being released from time charters and the owners and operators areseeking new and alternate uses for these assets.

The table below lists LNGCs that may soon be available and have sufficient capacity to be considered for conversion.Contract expiration dates range from 2010 through 2014.

Table 1World LNG Carrier Fleet

(Courtesy LNG Journal, Jan. 2010)

LNG Carrier Name Owner Capacity m3 Cargo System Contract

Arctic Spirit Arctic LNG Shipping 89,880 IHI SPB 2014Banshu Maru J3 Consortium 125,542 MOSS 2011Bishu Maru J3 Consortium 125,000 MOSS 2011

Dwiputra Humpuss Consortium 127,385 MOSS 2010

Ebisu Kaiun Kaishi 147,547 MOSS 2010Edouard L.D. Dynagas 129,300 Membrane 2013

Ekaputra Humpuss Consortium 136,400 MOSS 2014Granosa Golar LNG 145,958 Membrane 2011

Gimi Golar LNG 126,277 MOSS 2010Gracillis Golar LNG 138,830 Membrane 2011Grandis Golar LNG 145,700 Membrane 2011Khannur Golar LNG 126,360 MOSS 2011

Larbi Ben M’Hidi SNTM-Hyproc 129,750 Membrane 2014LNG Capricorn MOL/LNG Japan 126,300 MOSS 2010

LNG Flora J3 Consortium 127,700 MOSS 2014LNG Gemini MOL/LNG Japan 126,300 MOSS 2010

LNG Leo MOL/LNG Japan 126,400 MOSS 2010LNG Libra MOL/LNG Japan 126,400 MOSS 2010

LNG Taurus MOL/LNG Japan 126,300 MOSS 2010LNG Vesta Tokyo Gas Consortium 127,547 MOSS 2014LNG Virgo MOL/LNG Japan 126,400 MOSS 2010Polar Spirit Polar LNG Shipping 89,880 IHI SPB 2014

Ramdane Abane SNTM-Hyproc 126,130 Membrane 2013Senshu Maru J3 Consortium 125,000 MOSS 2011Tenaga Lima MISC 130,000 Membrane 2010

Over the past decade, many midscale and small scale LNG projects have been proposed and studied and some are currentlycoming to fruition. The projects include floating liquefaction units for mid-tier/low cost gas reserves and small to midscalefloating regasification units. These projects provide a synergistic opportunity for older displaced LNG carriers. Golar LNGhas pioneered LNGC conversions for FSRU service with the Golar Spirit, Golar Freeze, Golar Frost, Golar Winter and proposed Granatina. Shell, Petrobras, PETRONAS, FLEX LNG, Golar LNG, BWO, SBM, Teekay and others arespearheading the FLNG and FSRU development effort with help from Mustang Engineering, Hamworthy, Kanfa Aragon,MOSS Maritime and others. The authors of this paper have worked with multiple clients on LNGC conversions and havefound multiple LNGC conversion opportunities. Both offshore and onshore LNG projects can find LNGC conversionsattractive for FLNGs, FSRUs and as FSO vessels.

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Fig. 2 Golar Freeze Conversion to FSRUFig. 1 Golar Freeze MOSS Carrier

There are several incentives for developers, investors and operators to consider converted LNGCs for floating LNGapplications:

1. Low cost of the older vessels - Used LNGCs are currently available at 10%-25% of the cost of new build LNGhulls. A 150,000 m3 onshore full containment storage tank facility with all the associated piping systems will costapproximately US$100-$150 million. A new LNG hull of the same capacity will cost ~$200 million (LNG World

Shipping Dec 2009). A new hull on a FLNG project could represent 25-40% of the cost of the entire project.Recent reported pricing for a 125,000 m3 MOSS carrier is in the $25 to $50 million range which can reduce theoverall cost of an FLNG project by as much as 25%.

2. Schedule - New build onshore tanks and hulls will normally require 3-4 years to design and fabricate and are nearlyalways on the critical path for LNG projects. Retiring LNGCs are available immediately and may reduce the overallschedule of a floating LNG project by 1-2 years.

3. Permitting - The existing ships have been through Class and are generally well maintained. Permitting of the project using existing LNGCs for offshore service should prove to be an advantage over obtaining permits foronshore projects.

4. Mobility of the asset - The floating facility can be refitted and relocated to continued productive service if thecurrent gas field becomes less attractive due to reduced field production, changes in composition, geopolitical unrestor other reasons.

It is clear that there are numerous existing LNG carriers that will be replaced, and could be converted to floating LNG

development projects. These carriers offer advantages for the project owners with lower overall cost, shorter project schedule, permitting advantages, and asset mobility.

Project Development for an LNGC Conversion

Before the LNGC conversion design work can start, critical project and design basis questions must be answered in order toassure the project “value chain” is intact and will be economically viable. As an example, key questions to answer for anFLNG project will include the following:

Gas Reserves:

• Are recoverable reserves and predicted production rate sufficient to justify the project?

• What is the cost per mmscf of gas at the FLNG inlet?

• Can additional fields be added to extend the project life?

• Can the facility be designed for refit and relocation to another field to enhance economics?

LNG Market:

• Can a LNG market be secured for sufficient quantity and acceptable price?

• Does the FLNG owner have a portfolio of LNG supplies so that the market can be assured of deliveries?

• Will intermittent delivery of LNG or relatively small cargoes be allowed?

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Gas Quality:

• What are the gas composition, pressure and temperature to be processed?

• Are there significant C5+ hydrocarbons available to justify the added complexity of condensate and LPG recovery?

• Are there markets within economic range of the facility to sell LPG and condensate products?

• What contaminants must be removed, stored and disposed to assure a marketable quality LNG? CO2, N2, Hg, H2S,organic sulfur

• Can the heavy hydrocarbons or contaminants be disposed in the fuel gas?

Project Location:

• Is the gas supply offshore, near shore or onshore?

• If the gas supply is offshore, what water depth, bathometry and metocean conditions will prevail and what mooringsystem will the FLNG need to provide greatest availability?

• If the FLNG is near shore in shallow water, can a breakwater or protected harbor be constructed to protect it?

• If onshore, is shoreside property available and affordable to house some (or all) of the pre-treatment, processing andstorage components?

• What LNG offloading system can be used, e.g. ship-to-ship, side-by-side or tandem; ship-pier-ship; hoses or hardarms?

Similar questions will need to be answered for projects expecting to use LNGCs converted into FSRU or FSO. A successful project will have the entire project ‘value chain’ questions clearly answered so that financing, whether internal to the gas

owner or from banks and investors can be assured.

Selection of the Appropriate LNGCs for Conversion

Fig. 3 Aquarius Class LNGC Retiring in 2010

The majority of LNGCs currently available for conversion are of the 125,000 to140,000 m3 BOG fueled, steam driven MOSSvariety. In addition, older 120,000 to 140,000 m3 membrane ships and two 87,500 m3 Self-supporing Prismatic IMO Type B(SPB) vessels may be available. The MOSS style carriers have very robust spherical IMO Type B independent cargo(containment) tanks that are resistant to damage by sloshing at any tank filling level. The MOSS tanks are ideally suited foropen sea environments. However, the tanks and insulation covers project through the deck and limit space available for placing topsides process equipment. The membrane style carriers have considerably more deck space available for topsides process modules but the cargo tanks are made of very thin stainless steel or Invar sheet and are designed for transit only inthe full or empty condition. The membrane tanks cannot tolerate the severe sloshing effects that can occur in the partially

filled condition with ship motions associated with an open sea environment. The conversion of a membrane carrier for anFLNG application would only be acceptable if located at a near shore, protected or sheltered location where it will not besubjected to significant vessel motion.

Two 87,000 m3, ice class, SPB carriers have been serving Japan from an LNG facility in Kenai, Alaska. One of these hasrecently been released from charter as the Kenai plant is nearing the end of plant and field life. The authors have beeninvolved in FLNG conversion concept studies for this vessel. SPB tanks can handle sloshing loads from partial loading.

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Fig. 4 Teekay’s 87,000 m3 Arctic Spirit Fig. 5 Arctic Spirit FLNG Conversion Concept

Selection of the LNGC from the available inventory at the time of project development is a major consideration. Projectconcept study, Pre-FEED and FEED schedules can consume 1-1.5 years and the engineering and design are dependent onknowing the LNGC vessel design details and capability. Unless a number of similar class vessels are available, there is a riskthat the LNGC used as the basis of engineering work may not be available when the project is funded. The client musttherefore own the vessel outright or have some contractual arrangement to assure availability when needed.

When considering a LNGC for conversion, the following questions should be considered:

• Will the vessel be moored in an open, unprotected location (MOSS or SPB) or in protected or sheltered waters(MOSS, SPB or Membrane)?

• Is there enough space on deck for the modules (dependent on the complexity and throughput of the process)?

• What is the capacity of the LNG shuttle carriers? Is there enough capacity in the LNGC to service the proposedshuttle carrier? Is there sufficient port/berth availability for staying connected and allowing the shuttle to be filledover a longer period? Would the shuttle carrier be capable of taking (or delivering) a partial load to/from theconverted LNGC?

• What is the condition of the LNGC to be converted and how much repair and life extension modifications arerequired to prepare the vessel for conversion?

• Can a LNGC offer supplemental or long term floating storage to the facility without modification?

• Can the existing utilities on the LNGC be utilized for the topsides e.g. power generation, fire water, inert gasgenerators, steam production, fresh water? What supplemental equipment is required?

• How much reserve stability does the vessel have to accommodate the additional weight of the above deck processequipment?

Fig. 6 Membrane LNG Carrier Conversion for FSRU

The choice of the right LNGC for conversion depends on several criteria to meet the project needs and the site specific userequirements for deck space, LNG containment integrity, mooring, LNG shuttle size, service life and utilities.

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Liquefaction and Regasification Technologies

Several LNG technologies are available and the application of the appropriate technology will be unique to the project,economics and operability. LNG regasification technologies for floating applications include direct seawater exchangers,indirect intermediate fluid heat exchangers exchanging heat with air, seawater or a heated fluid (steam or fired heater) ordirect ambient air vaporizers. Open Rack Falling Film Vaporizers and Submerged Combustion Vaporizers are not acceptableselections for floating applications subjected to ship motion.

The LNG liquefaction technologies for LNGC conversion applications include turbo-expander based refrigeration using openor closed cycle natural gas, nitrogen refrigerant processes and Single Mixed Refrigerant processes. Large, complex, multi-loop refrigeration processes with multiple coldboxes or spiral wound exchangers are not likely to fit on the deck of anexisting LNGC and are more appropriate for onshore plants and large built-for-purpose hulls.

Fig. 7 Dual Expander NitrogenProcess Module

Fig. 8 Single Mixed RefrigerantProcess Module

One of the primary considerations in determining the appropriate technology is the ability to meet the required productionrate and expected run time given the available deck space, deck loading capability and stability of the LNGC. Minimumcomplexity is typically consistent with maximizing the production rate as the simpler process will tend to have a smallerfootprint than a complex process, allowing more production on the available deck space. Further, a liquefaction train withfewer major pieces of equipment will generally have a lower CAPEX than a more complex plant of the same capacity andhave greater availability. That is, it will be operational more days per year. If sufficient gas is available, increasing production has significant impact on project profitability.

Safety is another major consideration. A process that minimizes fired equipment and the use of flammable fluids for

refrigerants will be more favorable to the client, operators, regulators, investors, insurers, and Class. A regasification facilitythat utilizes seawater or air as the heat source is safer than one that uses a boiler or fired heater. A liquefaction technologythat uses an inert refrigerant such as nitrogen is considered safer than one using propane or mixed hydrocarbons asrefrigerants.

Efficiency of the process should be considered. Minimizing the operating costs will contribute to the financial success of aFRSU or FLNG. A regasification process that utilizes the ambient heat from the environment (air or seawater) will have amuch lower operating cost than a process that consumes fuel to vaporize the LNG. Gas fired regasification processes canconsume 1-2% of the LNG stream and create significant emissions. Intermediate fluid and direct ambient vaporizers utilizethe environment heat available in the air or seawater and can reduce the fuel consumption and emissions significantlydepending on the project location and average annual air/seawater temperature and humidity.

All liquefaction processes require considerable power for refrigeration compression typically derived by combustion of

approximately 5% to 8% of the inlet natural gas stream. However, the efficiency of an LNG liquefaction technology doesnot have as much economic impact on the project viability as one might expect. To illustrate the point, compare twoliquefaction processes, each liquefying 1.0 MTPA and having the same 94% availability and the same hull, inlet separation, pretreatment and compression and CAPEX of $500 million. One LNG process is a more complex and more efficientconsuming only 5% of the inlet gas as fuel (95% efficiency) and costing $250 million ($750 million total CAPEX). Thesecond LNG process is simpler with less equipment consuming 8% of the inlet gas as fuel but only costs $150 million ($650million total CAPEX). To allow for the differences in efficiency, assume a field life of 20 years to depletion with the moreefficient LNG process staying on station 3% longer (20.6 years) than the less efficient LNG process (20 years). Assume thatthe net tolling fee for FLNG is $3/MMBtu or $150 million/year and a discount rate of 15%. The Net Present Value ( NPV)and Internal Rate of Return (IRR) for the higher CAPEX, more efficient LNG process is $146 million and 19.4%respectively, with the lower cost, less efficient process having a $247 million NPV and 22.6% IRR. This information isshown in the table below.

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Table 2Liquefaction Economics

Complex Process Simple ProcessLiquefaction Capacity 1.0 MTPA 1.0 MTPA Availability 94% 94%CAPEX exclusive of liquefaction $500 million $500 millionCAPEX of liquefaction $250 million $150 millionTotal CAPEX $750 million $650 millionLiquefaction fuel consumption 5% of inlet gas 8% of inlet gasField life 20.6 years 20 yearsFLNG net tolling fee $150 million / yr $150 million / yrDiscount rate 15% 15%

Net Present Value (NPV) $146 million $247millionInternal Rate of Return (IRR) 19.4% 22.6%

The lower cost, simpler and less efficient LNG process has a greater NPV and IRR than the more efficient, more complexand higher cost LNG process. It is readily apparent that higher efficiency will never overcome the higher initial CAPEX ofthe more complex process during the service life of the facility.

The choice of liquefaction and regasification technology for floating applications will be driven by the lower CAPEX andimproved operability associated with simpler processes rather than production efficiency.

Project Location Considerations

When evaluating the project location and the options for a floating LNG facility based on a converted LNGC, key factors toconsider include:

• Does the offshore project site have any access to infrastructure?

• How severe and what is the annual variation of the metocean conditions, i.e. wind, wave, current, temperature andhumidity?

• Is the project site near shore where facilities such as piers, breakwaters, harbor and pipelines may be available oreasily constructed?

• Are there bathymetry, dredging or geologic issues?

• Are there seawater or air environmental issues?

•

Are there geopolitical concerns?

As a result of consideration of these issues, a suitable option for the floating LNG facility terminal may be selected from thefollowing:

• Floating LNG terminal berthed at a fixed pier;

• Floating LNG terminal near shore in moderate depth (approximately 30 meters), on either a single point turretmooring or spread mooring system.

• Floating LNG terminal far offshore, in deep waters (say 500+ meters), most likely on a single point turret mooring.

Site specific project evaluation is essential in deciding what LNGC and conversion options can be pursued. The gas supplyor demand may be onshore, near shore or offshore and the LNGC conversion will be different for mooring at fixed pier,shallow water or offshore deepwater.

Vessel Motion Considerations

For terminals in which the converted LNGC is going to be exposed to wind, waves and current, the effect of the elements onthe vessel’s motions needs to be carefully considered.

The vessel motions will directly affect the following components:

• LNG containment system loads specifically in the partially filled condition

• Process equipment performance – Motions and acceleration limits on processes – Dynamic loads at the foundations supporting the topside equipment

• Mooring system loads and design

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The issue of impact loads due to sloshing in partially filled tanks is well documented elsewhere. For the LNGC applicationunder consideration, a suitable containment system is a requirement. For membrane LNGCs, the integrity of the containmentwalls, pump towers and other LNG transfer components will have to be evaluated. Significantly improving the strength of amembrane LNG containment system without a costly and time consuming complete replacement would be unlikely.

The impact of the vessel motions on the process equipment needs to be evaluated for two reasons. Many of the gas pre-treatment process equipment components on a FLNG vessel are sensitive to motions, and have acceleration and roll limits

and maximum angle of heel and trim limits. These effects may be amplified since the equipment may be elevated above themain deck to fit around the containment system. The process engineers and naval architects need to jointly ensure that themotions of the vessel are within acceptable limits. The second issue of importance is the evaluation of the dynamic loadsimparted by the process equipment on the supporting structure in the hull. The original design intent of the decks of anLNGC conversion was not to support significant loads. The deck was essentially a non-structural covering of the areassurrounding the containment system, perhaps with some structural elements for lateral support of the spheres in a MOSSsystem. Designing adequate foundations for modules and process equipment, and tying them into the original vesselstructure (or enhancing the vessel structure), is a critical task. Significant work is required to properly locate and support process equipment and topsides modules on the deck.

Fitness for Service and Life Extension Considerations

As with all projects in which an older ship is converted to a floating storage unit, significant effort is required to evaluate thecandidate vessel for fitness for service. In the ideal case, the hull structure of the will be in excellent condition, will have been well maintained, and have sufficient strength to meet the structural requirements for the design life of the installation.

The more likely scenario, however, is that some steel renewal will be required in the hull to extend the life of the vessel. Theextent of renewal will depend on several factors including the site-specific metocean conditions and the design life of the project. Additional consideration will have to be made for areas of the hull which need to be modified for the new use.Areas which may need to be modified include:

• Bow region for addition of an external turret

• Stern region for addition of a stern yoke (for tandem offloading)

• Side shell strengthening to accommodate fender loads for side-by-side mooring

• Side shell and deck strengthening for accommodating loading arms for side-by-side loading / offloading

• Bow and stern region modification and strengthening for installation of fairleads (for a spread moored vessel)

•

Deck structural stiffening and module support framing for receiving the topsides process module

Fig. 9 Design and Installation of Bow Fairleads for Spread Mooring

For LNGC conversions, the condition of the containment system is of special concern. LNG is a harsh liquid to handle, andearly LNGCs available for conversion have likely suffered some degradation in the containment system. There may bestructural issues due to fatigue and use, or the effectiveness of the insulation may have degraded (or not been very goodinitially). The impact of the topsides loading on the integrity of the LNG containment system is also a consideration not to beoverlooked.

The impact of adding elevated process modules on the vessel stability must be evaluated as part of the conversion effort. Theequipment weight may be as much as 20% of the LNGC cargo capacity, so its placement well above the main deck will

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dramatically affect the loaded VCG. It may be necessary to add permanent ballast low in the hull to improve vessel stability.However, the added weight of both the process equipment and the ballast weight will increase the vessel lightship, therebyreducing the allowable deadweight unless stability (and structural) site-specific analyses allow for increasing the vesselloadline draft.

In Situ Maintenance vs. Shipyard Maintenance

Floating storage vessels are intended to stay on station continuously for the design project life. For older converted vessels,this can be a problem, as they require more maintenance as they age. Careful evaluation of the site specific environmentalloads may necessitate extensive renewal of the structure.

A unique issue with LNG storage vessels is the difficulty in carrying out in situ maintenance and repair of the containmentsystems. This is particularly acute for membrane LNGCs. Bringing an LNG tank up to ambient temperature and gas free sothat it can be entered is difficult and time consuming. Likewise, the process to take it back down to cryogenic temperatures istime consuming and requires significant cooling capacity, possibly beyond the capability of the existing equipment. Whilethis problem is shared with new build LNG storage vessels, they will have been designed with this in mind, where as anLNGC would not.

Required Utilities and Integration with Ship Systems

In most conversion projects, the ship’s power plant and other systems are not well suited to support the process equipment.Often, for oil tanker projects, the main engines are removed and replaced with generators to provide power. Older LNGcarriers were powered using steam turbines, with boil off gas from the containment system as the fuel. Depending on thetype of process equipment on the converted vessel, there may be a requirement for steam in the process stream. In this case,the steam boilers may be utilized. However, for most installations, additional power will be required, and generators willhave to be located on the vessel. The new topsides process may also have requirements for water, nitrogen, or other utilities,which are beyond the capabilities of the legacy ship systems.

Class and Regulatory Issues

Beyond the regulatory challenges associated with gaining overall project approval for LNG projects, the uniqueness ofconversion of an aging LNG carrier for use as a floating LNG unit with process equipment may present challenges on theregulatory front. As such projects become more common, the regulatory pathway will become better defined and lessuncertain. All major Class societies are producing guidelines and rules in anticipation of the floating LNG industry.

The regulatory issues will center on the containment system and the supporting structure as the converted LNGC will besubjected to partial load sloshing for which it was not originally designed.

The others areas of particular importance to a conversion project are likely to be:

• Design Plans and Data for Position Mooring Systems

• Design Plans and Data for the loading and unloading systems

• Details of all cargo and vapor handling systems

A risk assessment to identify significant hazards and accident scenarios that may affect the installation, and consideration forrisk control options, will be required elements of the project development. A safety assessment of the process facilities will be required to ensure that sufficient safeguards are in place. Additional safety systems will be required to provide protection

to life, property, and the environment. The safety systems should provide protection against the risk of fire or explosion andreduce the consequence of fire.

Target Applications for LNGC Conversion Projects

The following three sections are examples of the types of projects for which the authors have examined the use of a convertedLNGC as the basis for the terminal.

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Floating LNG Terminal Berthed at a Fixed Pier

This option is particularly suitable when onshore coastal space for a terminal is limited and protected or partially protectedlocations for piers are available. Examples include the floating facility providing gas to a coastal community (FSRU), or being used as an export terminal for an inland gas field (FLNG). Locating the LNG storage on the vessel, along with processequipment, eliminates the cost and delay associated with appropriating large amounts of typically overcrowded coastal land.Standard loading arms or hoses, mounted on the fixed pier, are used to transfer of LNG between the shuttle carrier and the

floating terminal. If the floating facility can be located within an existing protected harbor and use an existing pier, projectcosts and schedule can be minimized. More likely, a new pier will have to be built and located away from other facilities tominimize any risk of LNG storage and transport. If local metocean conditions are benign, and never challenge the vesselmooring arrangement to the pier, the decision is easy. However, if there are metocean conditions which will causeunacceptable mooring loads and create large motions for the moored vessel, mitigation alternatives need to be considered.One alternative is to build a partial breakwater to shield the moored vessel (and any visiting shuttle tanker) from the worstseas. This will greatly increase total project costs and schedule. The new pier and breakwater could be located where mostsuited for the project needs, including being slightly further out to sea (not connected to land) mitigating the need fordredging and offering some security for the terminal.

One may consider taking the terminal vessel out to sea in the event that near shore conditions exceed specified limits. For aFSRU, this would disrupt the supply of gas to the community, which may not be acceptable according to the contract. Thisalternative would also require the vessel to maintain Class as an LNGC, and to have a captain and crew available.

The fixed pier option offers the most flexibility in configuring the arrangement of the storage and process equipment. Thefloating vessel will provide LNG storage, but since the carrier is at a pier, some processing equipment, either regasification orliquefaction, may be located on shore or on the pier adjacent to the LNG vessel. Alternatively, there may be room for asimple barge moored at the pier, or alongside the vessel to house equipment. Either of these options would help if the proposed vessel for conversion does not have the capability to house all of the required process equipment.

Near Shore Floating LNG Terminal on Turret or Spread Mooring

The near shore option is suitable as a regasification facility supplying gas to a coastal community (FSRU), as a FloatingStorage Offloading facility (FSO) delivering LNG to shuttle tankers, or as an FLNG for either an onshore or offshore gasfield. The near shore facility does not require the infrastructure of a coastal installation, so is suitable for less developedlocations where there is no available coastline for a new facility or locations where some separation from the coast provides ameasure of security for the terminal. The relatively shallow water depths in the near shore region make both spread and

turret moored vessels practical options. A converted LNGC is suitable for either option, either through the addition offairleads and mooring equipment or the addition of a bow mounted turret.

Metocean conditions at the near shore location will influence the mooring system decision. As the moored vessel will befully exposed to the conditions, the motions response of the vessel and the resulting sloshing loads in partially filled LNGtanks may require the vessel to adjust heading to minimize motions. The type of containment system is critical in thisevaluation.

The choice of LNG offloading between the shuttle carrier and the FSRU or FSO may also influence the mooring systemdecision. The LNG transfer options are:

• Side-by-side transfer through loading arms or cryogenic hoses

• Tandem transfer through aerial cryogenic hoses suspended from a stern mounted yoke

• Floating cryogenic hoses for tandem transfer are also being developed

The side-by-side transfer option (and to a lesser extent the aerial tandem option) will require additional deck space on theconverted carrier for the transfer system to be mounted. For candidate carriers on which deck space is already limited, thismay become a significant concern.

Offshore Deepwater Floating LNG Terminal

This option is most likely for an FLNG application where it is not practical to transfer the produced gas to shore through a pipeline. It may also be used for an FSRU installation where metocean, hydrographic, or political considerations require thefacility to be located offshore. Deeper water at these locations, make a single point turret moored vessel most likely. The

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options for LNG transfer to or from shuttle carriers are the same as for the near shore moored vessel. The containmentsystem for this application will have to be fully capable of handling sloshing loads in partially filled tanks.

Conclusion

Over the next decade, an array of LNG carriers will be replaced by more modern vessels and will offer attractiveopportunities for floating LNG project developers in alternate use. In the appropriate application, these retiring LNGCs,

already equipped with cryogenic storage and in good condition can be converted for use as FLNGs, FSRUs or FSOs. Theycan be used in various applications including a terminal berthed at a fixed pier, a near shore terminal on turret or spreadmooring, and offshore deepwater terminals. Technical and economic issues associated with choosing the appropriate LNGCfor conversion for the right application must be identified and evaluated by skilled engineers, designers, naval architects and project developers. LNGC owners, operators, LNG project developers, engineers and financiers have begun and shouldcontinue, to consider the use of these high value, low cost assets to improve schedules and overall project economics.

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