2.4–1

A COMPETITIVE OFFSHORE LNG SCHEME UTILISINGA GRAVITY BASE STRUCTURE AND IMPROVED

NITROGEN CYCLE PROCESS

UN PROJET COMPETITIF DE GNL OFFSHORE UTILISANTUNE STRUCTURE DE GRAVITE DE BASE ET UN PROCEDE

PERFECTIONE DE CYCLE DE NITROGENE

Chris DubarSenior Engineering Specialist

Timothy ForceyPrincipal Process Engineer

Vaughan HumphreysSenior Engineering Specialist

BHP Petroleum120 Collins St, Melbourne, Victoria 3000, Australia

Dr. Hans SchmidtSenior Process Engineer, Linde AG

Dr.-Carl-von-Linde-Strasse 6-14, D-82049Hoellriegelskreuth/Germany

ABSTRACT

A feasible and economic means has been developed using proven technologyelements, to produce and export LNG from remote marginal gas fields. The cLNGTM

liquefaction process is introduced, which is particularly suitable for offshoredevelopments, on fixed or floating structures.

This paper addresses the specific design developed for the Bayu-Undan gas /condensate field that is located offshore in the Timor Sea Zone of Cooperation betweenAustralia and Indonesia.

Key features of the Bayu-Undan design include:

• the cLNGTM nitrogen cycle liquefaction process, developed from a process proven inLNG peak-shaving operations, but with gas conversion efficiency similar toconventional base-load plants;

2.4–2

• a fixed concrete Gravity Base Structure, or man-made island, placed on the seabedthat supports all topsides facilities including the pre-stressed concrete full-containmentLNG storage tanks and cLNGTM plant;

• conventional land-based-type LNG carrier mooring and loading facilities.

Detailed model testing, and safety and reliability studies confirm the future safe andreliable operation of all aspects of the LNG facility. Detailed cost estimates confirm thatoffshore LNG production in the range of two to three million tonnes per year iscompetitive with larger land-based LNG facilities on a cost per tonne of LNG basis.Sufficient design, safety review, and cost estimating work, along with independentauditing, has been done to conclude that the cLNGTM process is ready for LNG base-loadapplications that would result in the commercialisation of remote marginal gas fields.

RESUME

Un moyen faisable et économique a été développé en utilisant des élémentstechnologiques prouvés pour produire et exporter le GNL des puits des gaz retirés etmarginaux. Le procédé cLNG™ de liquéfaction est introduit sur des structures stabiliséesou flottantes et est particulièrement convenable pour des dèveloppements offshore.

Cette étude s’adresse au project développé spécifiquement pour le gaz de Bayu-Undandomaine condensé qui est situé au large dans la zone de co-opération entre l’Australie etl’Indonésie dans la mer du Timor.

Les traits clé du développement comprennent:

• Le procédé cLNG™ de nitrogène cycle de liquéfaction, développé d’un procédéprouvé dans l’opération GNL quand il y a des grandes demandes avec un changementefficace de gaz semblable aux méthodes conventionelles;

• Une structure de gravité de base fixe ou une île artificielle placé ou fond de la mer quisupporte toutes les infrastructures et facilités, comprenant les réservoirs GNL qui sontaccentués par du béton;

• Des moyens conventionnelles á terre de transpsortation GNL de mouillages et dechargement.

Des tests de modèle détaillés des études de sûretés confirment la sûreté et la qualité del’opération sur toutes les aspects de la structure GNL. Des coûts estimés confirment quela production du GNL au large est de 2 à 3 millions de tonnes par an et est compétitif avecdes plus grandes structures de GNL, à un coût par tonne de base de GNL. Des plans, desrevues de sûretés suffisants et des coûts estimés avec des vérifications indépendantes ontété faites pour conclure que le procédé cLNGTM est prêt pour la commercialisation despuits de gaz éloignés marginaux.

2.4–3

A COMPETITIVE OFFSHORE LNG SCHEME UTILISINGA GRAVITY BASE STRUCTURE AND IMPROVED

NITROGEN CYCLE PROCESS

THE POTENTIAL ADVANTAGES OF OFFSHORE LNG PRODUCTIONVERSUS ONSHORE

Over the past several years, BHP [1] and others [2-5] have investigated thecommercialisation of offshore static gas resources. Options studied for these fields includemethanol, synthetic fuels, and LNG. LNG production offshore, such as shown in Figure 1,could have significant cost advantages over onshore, some of which are listed here.

Figure 1 - cLNGTM Plant onGravity-Base-Structure in Shallow Water

GRAVITY BASE STRUCTURESEABED

cLNGTM PLANT

An offshore facility would require only a short gas transmission pipeline, with minimalgas transmission costs. Gas can be made available at higher pressure.

Compared with an onshore plant, no land is needed for the plant site, eliminating theassociated site development costs and environmental impacts. Costly infrastructuredevelopment in remote areas is not required, such as community facilities, roads,construction wharf, construction camps, or harbour facilities. The offshore facility may beconstructed at lower cost and with greater quality control at established fabrication yards,rather than importing high cost labour to the remote onshore plant site.

Good quality seawater for process cooling is readily accessible offshore. Channeldredging, a jetty, and extensive cryogenic piping for the transfer of LNG from storage tothe loading terminal is eliminated. For the offshore loading terminal, there are no LNGcarrier operations in crowded harbours, nor any associated delays. In some cases, the

2.4–4

offshore facility may be geographically closer to the customer, compared with the nearestsuitable onshore plant site, thereby reducing shipping costs.

cLNGTM DESIGN DEVELOPED FOR BAYU-UNDAN GAS RESOURCE

The Bayu-Undan gas / condensate resource is located in the Timor Sea Zone ofCooperation (ZOC) between Australia and Indonesia which is shown in Figure 2.

I

AUSTRALIA ZOC

INDONESIA

Figure 2 - Zone of Cooperation (ZOC)

The offshore cLNGTM design developed specifically for Bayu-Undan could have manyapplications elsewhere around the world. The current upstream development plans forBayu-Undan call for a condensate and LPG stripping operation. Initially, a lean gas wouldbe re-injected into the reservoir until downstream gas utilisation facilities, of whichcLNGTM is one option, come on-line.

Weather conditions in the Timor Sea are dichotomous, that is, they are generallybenign, and yet are subject to relatively immature tropical cyclones. It is in this area thatBHP successfully pioneered the use of dis-connectable and purpose-built FloatingProduction Storage and Off-loading (FPSO) oil facilities. These FPSO’s, specificallydeveloped for the cost effective commercialisation of marginal offshore oil fields, wereforerunners in the industry. FPSO’s are now common-place, even in far harsher weatherconditions than those of the Timor Sea.

Similar to the evolution of FPSO’s for the commercialisation of marginal oil fields,cLNGTM technology is now ready to use for the commercialisation of marginal offshoregas fields.

2.4–5

SHALLOW WATER SITES ARE SUITABLE FOR cLNGTM PLANTSMOUNTED ON MAN-MADE ISLANDS

cLNGTM technology may one day be used on floating LNG facilities. However,floating facilities require the future development of a safe and reliable cryogenic off-loading system for the transfer of LNG from one floating vessel to another.

Fortunately for the near term, the availability of shallow water sites in the Timor Seanear undeveloped gas resources [6], allows the cost-effective use of cLNGTM plants onGravity Base Structures (GBS). Such a man-made-island would sit firmly on the seabed.This enables the use of conventional loading arms for LNG transfer. As shown in Figure 3,no new LNG off-loading technology is required.

Figure 3 - LNG Carrier Being Loaded with Conventional Loading Arms from Fixed GBS

LOADING WITHCONVENTIONALARMS

IMPROVED NITROGEN CYCLE PROCESS

Safety Considerations for Compact Offshore LNG Process

One of the critical aspects to consider in the selection of a liquefaction process for usein an offshore environment is safety. Although conventional liquefaction processesavailable today have been very successful in base-load plants, their extensive use ofhydrocarbon refrigerants makes them less than ideal for use offshore. These processeshave large inventories of liquefied hydrocarbon gases, contained at high pressure, whichwould constitute a significant fire and explosion hazard for offshore applications.

2.4–6

A major concern is that such refrigerants could be involved in events such asBLEVE’s (Boiling Liquid Expanding Vapour Explosions). These hazards are managed ina land based plant by maintaining adequate separation distances between the equipment inthe process plant, storage and off-loading areas, adjacent trains and control room areas.However, in an offshore plant it is not possible to maintain those same separationdistances without the offshore plant becoming prohibitively expensive.

A basic principle of loss prevention and process safety is that the designer should aimto use small quantities of hazardous materials or substitute a less hazardous material ifpossible [7,8]. Thus BHP considered the inherently safer nitrogen cycle process as a goodcandidate for offshore LNG. By using nitrogen as the refrigerant, the inventories ofliquefied hydrocarbons contained in the process are greatly reduced. Furthermore, thereare fewer equipment items and systems handling flammable hydrocarbons, andconsequently fewer potential points for hazardous materials to leak from flanges,compressor seals, etc. Each of these aspects reduces risk on the offshore LNG facility.

The nitrogen expander cycle process has been suggested by others for offshore LNGproduction, [2,3] but it has generally been dismissed as being too inefficient for use in abase-load LNG plant.

Description of Simple Nitrogen Cycle Process Used in LNG Peak-Shaving Plants

The base-load LNG technologies in use today are very efficient in terms of therefrigeration power required to produce each tonne of LNG. On the other hand, in anLNG peak-shaving plant, this high efficiency is not as important because the plant mayonly run for part of the year and the plant capacity is much lower.

The simple nitrogen cycle process, as shown in Figure 4A, has been used successfullyin a number of these peak-shaving plants. A description of this process follows. As in anyLNG process, the natural gas supply to the plant passes through a pretreatment sectionwhere carbon dioxide and water are removed. The gas is cooled, heavy hydrocarbons areremoved (if required), and then the gas is liquefied in a series of exchangers. The nitrogenrefrigerant is a gas (i.e., single-phase) at all times. The heat exchangers used are usuallyaluminium plate-fin exchangers installed in a cold box. Because the heat transfer process ismuch simpler than the complex two-phase heat transfer involved with mixed- refrigerantbased LNG technologies, the design of this equipment is relatively straightforward.

Cold refrigerant is generated by a nitrogen expander cycle in which compressednitrogen is pre-cooled in exchanger E1. Then the majority of the flow is expanded byturbo-expander X2 which results in the required low temperature nitrogen stream. Thiscold nitrogen is then used to provide the bulk cooling of the natural gas in exchangers E2and E1. Optionally, a small stream of pre-cooled nitrogen is further cooled in exchangerE2 and is then letdown in pressure through a valve to produce some very cold gas and / orliquid nitrogen. This stream is used to provide the sub-cooling of the LNG in exchangerE3. In some plants, methane is added to the nitrogen refrigerant to improve the efficiencyof the process. The warmed nitrogen leaving exchanger E1 is compressed by compressorC1 and is further compressed by the booster compressor C2 driven by turbo-expander X2.

2.4–7

While other liquefaction processes such as the mixed-refrigerant cycle have been usedfor recent peak-shaving plants, the nitrogen cycle process is well proven and is very simpleto operate. One Linde peak-shaving plant is designed for unattended operation, whileothers operate unattended at night.

PretreatmentSection

Coolant

C1

X2/C2

E2

E3

Separation ofHeavy

Hydrocarbons

Natural Gas

LNG

E1

HeavyHydrocarbons

Pretreatment

Section

Separation ofHeavy

Hydrocarbons

Natural Gas

LNG

Coolant

C1

X2/C2

E1

E2

E3

HeavyHydrocarbons

X3/C3

Figure 4A - Simple Nitrogen Cycle Processfor LNG Peak-Shaving Plant

Figure 4B - BHP Optimised N2 CycleProcess for cLNGTM Base-Load Plant

Figures 4A & 4B - Simple & Optimised Nitrogen Cycle Processes

The only change to the Simple Nitrogen Cycle is the addition of a second expander.

Inherently Safer Nitrogen Cycle Process Attractive for Offshore Use

The nitrogen cycle process has a number of attractions for offshore LNG production.The simple design, using a single refrigeration cycle operating in the single phase gasregion, means that there are relatively few equipment items. The liquefaction section of theplant consists of a single compressor, a turbo-expander, a cold box and three heatexchangers for the compressor coolers. This reduces the complexity and spacerequirements for the plant. No compressor suction or refrigerant surge drums are required,nor their associated piping, valves and instrumentation.

cLNGTM Process Boosts Efficiency of Nitrogen Cycle for Base-Load Plants

The disadvantage of using this nitrogen cycle process for a much larger base-loadLNG plant is, however, the relatively low process efficiency of the cycle. Table 1 showsthat the refrigeration power requirement (per kmol of LNG liquefied) for a typical small-size LNG peak-shaving plant using a nitrogen cycle (Case 1) is over three times that of abase-load LNG plant using a mixed-refrigerant cycle (Case 4). It is clear that it would notbe competitive to use a nitrogen cycle with this process efficiency for a base-load LNGplant. Furthermore, even if the large industrial ‘Frame 7’ gas turbine were used as thecompressor driver, the maximum throughput of each train would be rather small, becauseof this poor efficiency. The low efficiency of the nitrogen cycle process used in peak-

2.4–8

shaving units is partly caused by the relatively low throughput of these units compared tobase-load plants, rather than being entirely due to the lower process efficiency of thenitrogen cycle process itself. The efficiencies of the small rotating equipment used in peak-shaving plants are significantly lower than those of the larger equipment that would beused in a base-load plant. In addition, the feed gas pressure available to a peak-shavingplant may also be lower than the 55 bar pressure typically used in a base-load plant. Thisresults in lower thermodynamic efficiency and contributes to the high refrigeration powerrequirement of the process.

Table 1, Case 2 illustrates the improvement in efficiency if the simple nitrogen cycleprocess was increased in size to a much larger capacity and the feed gas pressure increasedto 55 bar. Using typical efficiencies for large rotating machinery improves the cycleefficiency to approx. 11 kW/kmol/hr. However this is still significantly more than for aconventional mixed-refrigerant cycle.

Table 1 - Specific Power Requirements for Liquefaction Processes

Nitrogen Cycle Process FeedgasPressure(bara)

LNGRate

(kmol/hr)

PowerRequired

(kW)

SpecificPower

(kW/kmol/hr)Case 1: Peak-Shaving Plant -

Simple Nitrogen Cycle8.2 86 1,920 22.3

Case 2: Base-Load Plant -Simple Nitrogen Cycle

55.0 6,267 68,565 10.9

Case 3: Base-Load Plant -cLNGTM Process

55.0 6,267 47,659 7.6

Case 4: Base-Load Plant -Propane Pre-Cooled Mixed Refrig

55.0 - - ~ 5.5 to 6.0

One significant inefficiency in the nitrogen cycle is the use of the expansion valve inthe nitrogen supply to the coldest exchanger. The adiabatic expansion across this valveresults in a loss of ability to produce work from this high pressure stream. In a small LNGpeak-shaving unit, this loss of work is quite small in absolute terms and attempting torecover it is not justified. For the larger scale base-load plant however, the improvednitrogen cycle that BHP and Linde have developed recovers this lost work by using asecond, so-called “cold” expander in place of the expansion valve. This results in asignificant improvement in efficiency as shown in Table 1, Case 3 above. Figure 4B showsthe basic difference in configuration between the proven, simple nitrogen cycle processused in peak-shaving plants and the optimised nitrogen cycle used in the cLNGTM process.

Pre-cooling the feed gas via a small auxiliary refrigeration cycle is another known wayof increasing the efficiency of the nitrogen cycle, and this has been found to be the case forthe cLNGTM process also — especially in applications with high ambient temperatures.The auxiliary refrigeration system is relatively small. Conventional chiller packages with“ozone-friendly” Freon refrigerants are used rather than a propane system. This maintainsthe safety philosophy for offshore applications.

2.4–9

By adding the cold expander, and by optimising the temperature levels and load splitbetween the warm and cold expander duties, a much closer matching of the heating andcooling curves between the feed gas and nitrogen refrigerant can be obtained. This resultsin higher thermodynamic efficiency. See Figures 5 and 6, which correspond to Cases 2 and3 from Table 1 above.

The cumulative effect of these improvements is to reduce the specific powerrequirements to a competitive level for small to medium LNG plant capacities, and yet toretain all of the inherent safety and simplicity advantages of the simple nitrogen cycle.

-200.0

-150.0

-100.0

-50.0

0.0

50.0

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0

HEAT DUTY

Tem

p [

°C]

NITROGEN REFRIGERANT

HEATING

E1

NATURAL GAS AND NITROGEN

COOLING

E2

E3

Figure 5 - Simple Nitrogen Cycle Process: Heating / Cooling Curve

2.4–10

-200.0

-150.0

-100.0

-50.0

0.0

50.0

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0

HEAT DUTY

Tem

p [

°C]

E3

E2NITROGEN

REFRIGERANT HEATING

NATURAL GAS AND NITROGEN

COOLINGE1

Figure 6 - cLNGTM Process: Heating / Cooling Curve

Description of cLNGTM Process for Bayu-Undan

A block flow diagram for the cLNGTM process as specifically designed for the Bayu-Undan gas resource is given as Figure 7. A single train of pretreatment removes acidgases, water and mercury from the lean feed gas. Two independent trains of liquefactionand refrigeration provide good overall availability and each train is capable of producingup to 1.5 million tonnes per annum of LNG using a single gas turbine driver per train.

CoolingSystem /Train 2

HeatingSystem

Fuel GasSystem

Electricity Generation

System

Flare andBlow Down

System

Instrument Airand UtilityAir System

Nitrogen Generation

System

Oily WaterSystem

Sweet WaterSystem

Fire FightingSystem

CoolingSystem /Train 1

Feed GasReception

Feed GasPretreatment

aMDEACO2 Wash

Feed GasPretreatmentH2O and Hg

RemovalFeed Gas

LiquefactionCold Box /

Train 2

Feed GasLiquefactionCold Box /

Train 1

toFuel Gas System

Fuel GasCompression

NitrogenCycle

RefrigerationTrain1

NitrogenCycle

RefrigerationTrain2

Figure 7 - Block Flow Diagram for Bayu-Undan cLNGTM Process

2.4–11

The lean feed gas is transported to the plant from the Bayu-Undan upstream facilitiesby a high pressure pipeline operating at an inlet pressure of up to 180 bar. Because the gashas already been processed to remove condensate and LPG in the field, the C5+ content ofthe lean feed gas is very low. Gas can therefore be liquefied without reducing the gaspressure for removal of C5+ hydrocarbons. Of course the recovery of make-uphydrocarbon refrigerants, as is usually required for a mixed-refrigerant process, is notrequired for the nitrogen cycle process. Thus the cLNGTM process can take fullthermodynamic advantage of the high feed gas pressure. The bulk of the feed gas is cooledat a pressure of approx. 83 bar.

Figure 8 is a simplified process flow schematic for the liquefaction / refrigeration unitfor one train and illustrates the simplicity of the cLNGTM process. Feed gas enters the topof the coil-wound heat exchanger and is cooled to approx. -90°C by nitrogen refrigerantflowing on the shell side of a coil-wound-heat-exchanger (CWHE). A CWHE was chosenfor Bayu-Undan because of the high feed gas pressure, as well as the high reliability of thistype of exchanger. For lower feed gas pressures, brazed aluminium heat exchangersinstalled in a cold box could also be used.

The cooled, high-pressure natural gas is then reduced in pressure and sub-cooled withthe coldest level of nitrogen refrigerant in two cores of brazed aluminium heat exchangersinstalled in a cold box. A nitrogen stripper column and reboiler is required to reduce thenitrogen content of the LNG product to less than 1 mol% because of the high nitrogencontent of the feed gas. For feeds with less nitrogen, a simple flash drum would beadequate. Flash gas from the top of the nitrogen stripper column is warmed with nitrogenrefrigerant to recover the refrigeration potential of the stream and is then re-compressed tofuel gas pressure.

The cLNGTM process maintains the simplicity of the nitrogen cycle used in LNG peak-shaving units. Nitrogen refrigerant at a pressure of approx. 18 bar is compressed by asingle nitrogen compressor in two stages to approx. 50 bar. Seawater is used for inter-cooling and after-cooling. Both nitrogen compression stages are incorporated in a single-case centrifugal compressor directly driven by an aero-derivative gas turbine. For Bayu-Undan, the large aero-derivatives such as the GE ‘LM-6000’ or Rolls Royce ‘Trent’ gasturbines may be used to produce up to 1.5 mtpa of LNG per train. Inlet air cooling with achilled water system is used to maximise the power output of the gas turbines at the warmambient air temperature encountered at the Bayu-Undan site.

The use of inlet air cooling to maintain a nearly constant inlet temperature to the gasturbine has an added benefit as the LNG production rate is nearly insensitive to daily andseasonal variations in ambient air temperature. The majority of the process cooling is donewith seawater which only varies over a small temperature range at this location.

2.4–12

Treated Natura l Ga s

To Fuel

Fuel Ga s

Com pressor

Nitrogen

Strip

C olum n

Cold

B ox

LNG Trans fe r Pum p

G as Turb ine

LNG Storage

Tank

C hilling

W a rm

E xpander/Booster

C old Expander/B ooster

Cycle

C om pressor

C ooling

C ooling

Figure 8 - Process Schematic for Bayu-Undan cLNGTM Process

The nitrogen refrigerant is further compressed to approx. 84 bar by the boostercompressors of the warm and cold expander / booster units. The high pressure nitrogen isthen cooled with seawater and chilled water to approx. 10°C. The chilled water system iscomprised of electrically driven Freon refrigeration units and supplies chilled water forcooling of the high pressure nitrogen, treated feed gas and inlet air to the gas turbines.

Cooled high pressure nitrogen then flows to the nitrogen tube pass of the main CWHEwhere it is pre-cooled with low pressure nitrogen to approx. -15°C in the first tube bundle.This cold nitrogen stream is then split into two portions and the larger portion flows to thewarm expander / booster units where it is expanded to low pressure and temperature. Thiscold nitrogen stream flows to the shell-side of the main CWHE to provide the bulk of thecooling of the natural gas and high pressure nitrogen refrigerant.

The smaller portion of cooled high pressure nitrogen is then further cooled in thenitrogen tube pass of the main CWHE to approx. -90°C in the second tube bundle. Thiscold high pressure nitrogen stream then flows to the cold expander/booster unit where it isexpanded to low pressure and a temperature of approx. -150°C which provides the sub-cooling of the natural gas in the brazed aluminium cores in the cold box. The nitrogenleaving the cold box joins the larger nitrogen steam coming from the discharge of thewarm expander / booster units and flows to the shell side of the main CWHE.

The machines used for both the warm and cold expander/booster units for this trainsize are large, but are still within proven experience ranges for the manufacturers.

2.4–13

Gas Conversion Efficiency of cLNGTMProcess for Bayu-Undan

The gas conversion efficiency (heating value of the LNG product to storage divided bythe heating value of the feed gas) of the above process is 92 - 93%. This result is verysatisfactory given that the specific power requirements of the process are still approx. 25%higher than a typical onshore base-load plant.

The reason for this high conversion efficiency can be explained by the relatively highfuel efficiency of the aero-derivative gas turbines used for the main drivers. The efficiencyof turbines such as the Rolls Royce ‘Trent’ or GE ‘LM6000’ is significantly higher thanthe efficiency of the industrial type gas turbines presently used in onshore LNG plants.

cLNGTM PROCESS MODULE

A 3-D computer aided drawing of the cLNGTM Process Module for Bayu-Undan isgiven as Figure 9. Included on the module is the equipment comprising a single train ofgas pretreatment (acid gas removal and dehydration), two trains of liquefaction, electricitygeneration and other utilities. Studies show that process facilities for the production oftwo to three mtpa of LNG per year can be fabricated in a single process module thatweighs approx. 10,000 tonnes. Such a module is similar in size to other offshore modulesthat have been constructed in a number of fabrication yards around the world.

The module is loaded out from the fabrication yard onto a heavy lift barge on multi-wheeled trailers, such as has been done for other modules of similar size. The processmodule can then be transported to the GBS for installation using the same multi-wheeledtrailers used for the load-out. The module is never lifted and is always supported at anumber of points. As a result, the amount of structural steel required is much less than onsome other large offshore modules. One advantage of this method of construction is thatextensive pre-commissioning and testing can be carried out on the completed processmodule in the fabrication yard, in order to minimise offshore hook-up and installation.

GasTreating

Cold Boxes Spiral-WoundHeat Exch.

Gas Turbines

Figure 9 - cLNGTM Process Module

2.4–14

cLNGTM RELIABILITY EXPECTED TO BE SIMILAR TO OTHERFACILITIES

The LNG industry demands a high level of supply reliability, and actual reliabilityperformance of existing plants and design methods have been documented [9,10,11,12].The cLNGTM processing plant as designed for Bayu-Undan has been the subject of adetailed Reliability, Availability, and Maintainability (RAM) study, using state-of-the-artcomputer tools and equipment reliability databases. An average availability of over 96% isexpected for the cLNGTM processing plant itself. This is on par with world-class LNGplants in operation today.

Features of the cLNGTM process that contribute to its high reliability include:

• the relative simplicity of the pretreatment process required for the lean gasproduced from Bayu-Undan,

• the relative simplicity of the nitrogen cycle liquefaction process, which requires onlyone main driver,

• the provision of dual (2 x 50%) liquefaction trains,

• the inherent ability of the cLNGTM process to maintain LNG production, albeit atreduced capacity, while parts of the nitrogen cycle are shutdown,

• the selection of proven equipment provided by vendors with established references,

• the rapid maintenance turnarounds possible with aero-derivative gas turbines,

• the provision of adequate design margins,

• the provision of redundant equipment, such as spare pumps, heat exchangers,power generation facilities, utility equipment, etc.

2.4–15

CONVENTIONAL CONCRETE GRAVITY BASE STRUCTURESUPPORTS LNG PLANT, TOPSIDES FACILITIES AND STORAGETANKS

The cLNGTM facility proposed for Bayu-Undan is shown in Figures 1 and 3 in a typicalconfiguration for two to three mtpa LNG production. The cLNGTM process module isshown centred between the two LNG storage tanks. The personnel accommodationmodule is safely positioned at one end, away from the process, flare, incoming gas riser,and loading terminal. The entire facility is supported on a concrete gravity base structure(GBS) which rests directly on the seabed in relatively shallow water (~27 m). ConcreteGBS’s have been used for many years in the North Sea and at far greater depths rangingup to 300 meters. More recently, three GBS based production facilities have been installedin Australian waters, two in the Bass Strait (West Tuna and Bream B) and one on theNorth West Shelf (Wandoo).

The GBS required to support the cLNGTM facilities is relatively simple in design andconstruction terms, and is heavily based on proven offshore technology. Figure 10 shows acutaway sketch of the GBS supporting structure. The simple rectangular cell arrangementis evident. The wave protection wall with wave deflector lip extends above the top slab todeflect extreme waves away from the topsides equipment during the cyclonic storms. Theprestressed concrete LNG tanks are constructed on the top slab, which also incorporatesthe embedment plates as foundations for the other modularised topsides equipment.

At the seabed level, there is an extra buoyancy structure, or “cantilever”. This is addedto provide the buoyancy necessary to allow the GBS structure, complete with all pre-commissioned topsides equipment, including the LNG tanks, to float out of the castingbasin in which it is constructed. Once out of the casting basin and in deeper water, thecantilever is flooded, and the GBS is towed to the offshore site at deeper draught. At thecorrect location, and in the correct orientation, the GBS is gently flooded down to theseabed. Every cell is flooded, and many cells are then partly filled with iron ore ballast, toensure adequate weight on the seabed for wave resistance.

Like all offshore structures, the GBS configuration and detail design is heavilydependent on site specific conditions and the construction method. The structure shown,and the figures listed in Table 2, reflect the Bayu-Undan design. The basis of design data,such as metocean conditions, geotechnical conditions at the proposed site, seismic criteria,etc., have been gathered for this project. The particularly critical design input parameterswhich govern the overall configuration for such a GBS application are:

• water depth and tidal range at the offshore location;• geotechnical conditions at the offshore location;• casting basin and tow-out channel water depths;• topsides size and weight for float out and tow to the offshore location.

2.4–16

Figure 10 - GBS Cutaway View

Some design parameters have greater sensitivity for this offshore LNG GBSapplication, and these were carefully considered for Bayu-Undan. For example, the largetopsides weight of nearly 200,000 tonnes (when the LNG tanks are full), must beaccommodated. The topsides weight will vary during operation as the LNG tanks arerepeatedly filled and emptied. However, the loads during LNG tank hydrotesting maygovern the design. The potential for LNG to “slosh” inside the tanks, because of verysmall movements of the GBS during extreme storms waves, must be considered. As LNGtank construction is critical path, early access to the GBS is required. Fendering andmooring points must be provided for the integral loading terminal. The geometry andstrength of these must be suitable to berth standard LNG Carriers with standardequipment. Room is provided on the GBS for future expansion via an additional LNGtrain, since the GBS offers great capability to support additional topsides equipment.Finally, abandonment of the GBS must be considered: the facility may be removed andpossibly re-used at the end of the project life.

Table 2 - Key Dimensions for the Bayu-Undan GBS Substructure.

Length - at seabed, at waterline 274m, 249mWidth - at seabed, at waterline 111m, 86mHeight - seabed to top slab 35mTypical Cell Size 12 x 12 mConcrete Volume 100,000 m3

Steel Reinforcement 27,700 tonnesPrestressing Reinforcement 3,700 tonnesSolid Ballast (iron ore) 350,000 tonnesTop and Bottom Slab Thickness 600 to 900 mmWall Thickness (varies) 400 to 600 mm

2.4–17

LNG STORAGE TANKS AND OFFLOADING TERMINAL ARE STATE-OF-THE-ART

The LNG tanks selected are of the latest design and highest integrity “land-based” typefull containment tanks as used for the most recent Japanese tank constructions. Theyconsist of a 9% nickel-steel inner tank and a 800 mm thick pre-stressed concrete outertank, with a domed, reinforced concrete roof.

These tanks simply sit on the GBS top concrete slab, which is at all times above thewaterline. A concrete outer wall was selected based on safety considerations in order togive unsurpassed protection from potential external events such as dropped objects andblast over-pressures. For Bayu-Undan, the storage volume selected is 170,000 m3 total, intwo equal-sized tanks. The outer concrete tank diameter is 66m, the inner steel tankdiameter is 62m, and the wall height is 34m.

Offloading of LNG from the storage tanks to standard LNG Carriers takes place at theterminal integral to the GBS. This incorporates a steel platform which supports theloading arms at the correct height, a fendering system attached to the side of the GBS, andmooring platforms with quick release hooks and capstan winches. All this equipment isstandard and proven, albeit the latest available, with the best automatic type facilities forgood operability and safety performance.

Four, 400 mm (16”) diameter loading arms are provided, with a total loading capacityof 10,000 m3/hour. These are standard arms, as supplied by either FMC or Niigata, andincorporate the hydraulic control package, emergency shutdown system, a double-ball-valve powered-emergency-release-coupling, a quick connect / disconnect coupler, and aposition monitoring system. The operating envelope is selected to exceed the relativemotions expected to be seen at the Carrier manifold.

The five main berthing fenders are Yokohama Air Block type, with soft energyabsorption characteristics, and long stroke to allow Carrier berth velocities of up to 0.3knots These have been used at similar exposed location terminals for similar applications.

The mooring system developed for operating the LNG Carriers (125,000 m3 or larger)at the GBS terminal is fully in accordance with the universally adopted Oil CompaniesInternational Marine Forum (OCIMF) guidelines. The arrangement is similar to that usedfor ship-to-ship loading. The breasting lines are almost perpendicular to the Carrier axis,providing extra stiffness for firm lateral control of ship movement.

RELIABLE LNG CARRIER LOADING AT THE INTEGRAL GBSTERMINAL

Reliable LNG Carrier loading, with availability equivalent to inshore terminals, is apre-requisite for an offshore LNG facility. As mentioned above, the technology required toreliably load LNG Carriers from a floating LNG plant is still under study and requiresdevelopment. However, the static GBS based LNG plant allows conventional type LNGloading systems to be used. In order to confirm this for Bayu-Undan, a comprehensiveseries of model tests and simulations have been completed. These were done at MARIN

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for the moored condition, and at MSCN and the Australian Maritime College (AMC) forthe berthing procedures and limits. Additionally, advice was sought from experiencedLNG Carrier Masters and Operators to conclude with workable solutions and equipment.

Initial computer based mooring simulations and fast-time berthing studies concludedthat in order to achieve high availability, it would be necessary to berth and remainmoored at higher seastates than normal for inshore terminals. It was also concluded that astandard LNG Carrier could not berth at the GBS in these seastates without externalassistance from tugs or thrusters. Once moored, the mooring system would need to bemore robust than the moorings used at inshore terminals. These studies proposed that aseastate of Hs = 2.6m was a practical limit for the moored condition, and that this wascompatible with tug handling limits for the berthing procedures.

The physical model testing performed at MARIN aimed to confirm the computerresults and to assess the availability of the LNG Carrier whilst moored at the berth. Awhole series of tests were performed with different wave heights and directions simulated,together with wind and current effects. See Figure 11.

The GBS orientation was altered, and Carrier motions, mooring line tensions andfender loads measured and recorded. A number of conclusions were reached:

• the GBS should be oriented east-west at Bayu-Undan for maximum mooredavailability;

• fender loads and motions were not exceeded, and therefore did not govern;• loading manifold motions were within the capability of existing loading arms;• the mooring line loads would govern the availability while moored.

Figure 11 - Wave Tank Test of LNG Carrier Mooring

To assess the berthing limit and the availability of berthing, the complete Carrierapproach and mooring-up procedure was simulated. MSCN performed fast-time computersimulations. These were checked by real-time simulations performed at AMC, attended by

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an experienced LNG Carrier Master and experienced pilots. A view of the full-scale LNGCarrier bridge at AMC and simulated GBS is given as Figure 12.

Figure 12 - Virtual Reality Simulation of CarrierBerthing at the GBS Based cLNGTM Plant

A number of simulations were run under a variety of extreme operating conditions.The results were very positive, finding favour and acceptance from the Mariners, and twomain conclusions were made. The seastate of Hs 2.6m was confirmed to be the upper limitfor the tugs and Carrier. If the Carrier is fitted with bow thrusters and a high lift rudder,no tugs are required. Two tugs would be needed if the Carrier were not so outfitted.

Based on the results of the model tests and simulations, Marin performed an overallreal time downtime analysis based on realistic seastates. This effectively takes true accountof the time the LNG Carriers are at the berth, and accounts for each and every part of theberthing, mooring, loading, unmooring, and departing procedures. The results of this workfor Bayu-Undan show that a 98% availability for the LNG Carrier loading operations atthe integral GBS berth is achievable.

SAFETY AND DESIGN APPRAISAL

The results of a Quantitative Risk Analysis (QRA) show that the risk to workers at theGBS based cLNGTM facility is lower than industry guidelines and comparable to otheroffshore operations. Features that reduce risk include:

• the selection of inert nitrogen gas as the refrigerant,• the supply of only lean gas to the facility, thereby eliminating the need for

handling LPG’s or heavy hydrocarbons anywhere on the GBS,• the selection of full-containment prestressed-concrete LNG storage tanks,• the provision of a relatively un-congested cLNGTM process module which limits

explosion overpressures,

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• the selection of the safest locations for the accommodation module and otherancillary equipment on the GBS,

• extensive use of safety systems such as gas detection and fire-protection.

State-of-the-art tools such as computational fluid dynamics (CFD) and three-dimensional gas dispersion and explosion modelling have been used to predict the impactof gas and LNG releases. When compared to another LNG facility that may use mixedhydrocarbon refrigerants (containing heavy LPG components) or a heavy feed gas, theadvantages of using nitrogen, which is inert, and feed gas that is predominantly methane,are clear. Methane’s physical properties are more favourable than heavier hydrocarbons,with respect to dispersion, flammability in air, and the potential explosion over-pressuresthat could result from an ignited gas cloud.

One design constraint was that the LNG storage tanks should be able to withstand themaximum credible explosion over-pressures caused by large gas releases from the processmodule or LNG loading area. From extensive CFD, explosion, and structural analysis, thishas been confirmed. Furthermore, the essentially inanimate LNG storage tanks can thenact as a blast wall to protect the personnel accommodation module, which houses thecontrol room, recreation and sleeping quarters, and so forth. Modelling has shown that theover-pressures that extend around the storage tank to the accommodation module areinsufficient to cause structural damage or loss of life.

Some of the results of the QRA are given in Figure 13. This shows that the IndividualRisk Per Annum (IRPA) for each worker group (production worker, support staff, etc.) iswithin acceptable industry limits and comparable with other offshore facilities. The risklevels fall within the “as low as reasonably practicable” (ALARP) region, where furtherrisk reduction measures will be considered during the course of project development.Further studies will be conducted in accordance with the Safety Case development inorder to show that risk has been reduced to as low as reasonably practicable. As iscommonly seen for remote offshore operations, a breakdown of the contributors topersonnel risk highlights the risks associated with transporting workers to the facility viahelicopter and transferring the mooring master to the shuttling LNG carriers (if thisposition is in fact required). The QRA results show that the risks to personnel ofhelicopter operations probably exceed any special risks associated with LNG processing.

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MANAGEMENT SUPPORTSTAFF

MAINTENANCEWORKER

PRODUCTIONWORKER

MARINELOGISTICS

MOORING MASTER

WORKERGROUPS

BHP / INDUSTRYMAXIMUMACCEPTABLE RISKLIMIT(> 1 E-03)

OCCUPATIONALHAZARDS

TRANSFER OFMOORING MASTER TOLNG CARRIER

HELICOPTEROPERATIONS

VESSEL IMPACT

OTHER PROCESS

LNGPROCESS

RISK AREAS

Figure 13 - QRA Results: Individual Risk Per Annum (IRPA)

The feasibility design documents for the Bayu-Undan Offshore LNG Facility have beenappraised in accordance with Det Norske Veritas’ (DNV) rules for Classification of FixedOffshore Installations for technical progress relative to the current (feasibility design)milestone of the project and for the use of applicable rules and regulations.

As a result of this review of the key areas of the design, DNV confirm that technicaldevelopment of the project has been satisfactorily achieved for this milestone, and thatthere is no impediment to continuing the process to achieve Certification. Furthermore,there are no areas requiring significant new research and development in order to achievea safely operable facility within the normal time frame and quality standards of majoroffshore and LNG projects. This assessment reflects the extensive amount of work carriedduring this extended feasibility stage.

CONCLUSION

A feasible and economic means to produce and export LNG from remote marginal gasfields has been developed, using cLNGTM technology. The design cost effectively utilisesproven technology elements brought together specifically by the need to commercialiseremote gas resources. Detailed model testing, and safety and reliability studies confirm thesafe and reliable operation of all aspects of the LNG facility. Detailed cost estimatesconfirm that LNG production from an offshore facility in the range of two to three milliontonnes per year is competitive with larger land-based LNG facilities on a cost per tonne ofLNG basis. The cLNGTM process is ready to use for LNG base-load applications in orderto commercialise remote marginal gas fields.

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ACKNOWLEDGMENTS

The authors, BHP, and Linde AG would like to recognise the contributions of othergroups involved in the development of this facility including Aker Maritime, Fluor Daniel,Clough Offshore, John Holland, the Australian Institute of Marine Science, the AustralianMaritime College, Det Norske Veritas, IHI, Jardine and Associates, Marin, MSCN,Obayashi, Osaka Gas, and many others.

REFERENCES CITED

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2. “Offshore Liquefaction of Associated Gas - A Suitable Process for the North Sea”,Alan J. Kennett, David I. Limb and B.A Czarnecki, Petrocarbon Developments Ltd.,13th Annual OTC, May 1981.

3. “Techno-Economic Case for Offshore LNG”, R.H. Buchanan and A.V. Drew,Foster Wheeler, 21st Annual OTC, May 1981.

4. “Offshore Producton of LNG from Associated Gas”, B. Borgass and D. Eimer,Ninth International Conference on LNG, 1989.

5. “Design Advanced for Large-Scale Economic Floating LNG Plant”, M. Naklie, Oiland Gas Journal, 30 June, 1997.

6. “Big Bank Shoals of the Timor Sea, An Environmental Resource Atlas”, A.Heyward, and L. Smith (Australian Institute of Marine Science), and E. Pinceratto(BHP Petroleum), 1997.

7. “Critical Aspects of Safety and Loss Prevention”, T.A. Kletz, Butterworths, 1990.

8. “Loss Prevention in the Process Industries”, F.P. Lees, Butterworth & Heineman,1980.

9. “Reliability of Base-Load LNG Delivery”, W.A. Smith and W.W. Bodle, SixthInternational Conference on LNG, 1980.

10. “Availability and Efficiency Improvement of Badak LNG Plant”, H. Mahfud, NinthInternational Conference on LNG, 1989.

11. “Availability and Capacity Improvement of the Arun LNG Plant”, J. Soeryanto, A.Triyatno, Tenth International Conference on LNG, 1992.

12. “Plant Reliability Analysis in LNG Plants”, F. de la Vega, et al, EleventhInternational Conference on LNG, 1995.