FLNG

IPTC 14548 FLNG Development: Strategic Approaches to New Growth Challenges Maneenapang Bunnag, Nunthachai Amarutanon, Saranee Nitayaphan, Manit Aimcharoenchaiyakul, PTT Exploration and Production Plc.

Copyright 2011, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Bangkok, Thailand, 15  –17  –17 November 2011. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an a bstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce 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 where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax +1-972-952-9435

Abstract Underneath the ground, the world still left a quarter of its natural gas reserve (approximately 2 billion TCF) undeveloped or “Stranded” in offshore. Many gas fields were discovered in many decades ago, but reserve of those fields could not commercially be justified for the development so they were classified as marginal fields. One of the most promising solutions known as “Floating Liquefied Natural Gas or FLNG” is lately growing and foreseen as potential technical to monetize this marginal gas. We are well aware of the potential in FLNG technology and consider it as the one of the most important initiatives to lead our organization into target growth strategy. Many challenges developing FLNG, however, have been found from major players in the past decade. Although land-based LNG and offshore FPSOs are each successfully proven in operations, combining the two technologies into a FLNG is complicated and face various technical challenges e.g. safety, ship motion, topside processing, hull & containment, offloading, integration, and operation. Critical aspects of a FLNG are the space constraints, which is very limited and required fully attention in order to deliver an inherently safe and a fit for purpose installation.  Altogether,  Altogether, FLNG concept shall shall fulfill a good balance balance between between efficiency efficiency and simplicity simplicity to safeguard the reliability reliability of the facility. Moreover, commercial aspect of FLNG is also highly challenging. With costly investment, FLNG project shall be carefully ensured if it is economic viable in every step of the project. The sensitivity of market, LNG price, and demand & supply shall be reviewed and taken into consideration prior to making the Final Investment Decision (FID). Certainly, FLNG initiative still has a lot of queries. However, after years of study and development in all aspects of floating liquefaction, it finally lead into the key conclusion that today there are no technical issues “show stoppers” for FLNG; whereas economic is also promisingly attractive. We believe that we have started off in the right track and in the right sequence as well as adopting a risk management deciding a FLNG at the right size and the right technology.

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1. INTRODUCTION Floating liquefaction solutions are receiving growing interest lately as they are seen as potential enablers to un-lock and monetize offshore gas reserves that are currently considered stranded. More than 20 years development work has been done on FLNG (Floating Liquefied Natural Gas) or also often referred to as “LNG FPSO” (F loating Production, Storage and Offloading units for Liquefied Natural Gas) starting from Super Major Oil Companies to a wide variety of companies i.e. E&P companies, FPSO operating companies, engineering companies, and LNG shipping companies. However, there are apparently challenges that have prevented the realization of such a project. Both the organization of the project and the actual design of an FLNG are considerably more complicated than those of an Oil FPSO. Although Onshore LNG liquefaction facilities and Offshore Oil&Gas FPSOs are each successfully proven in operation, combining the two technologies into a FLNG poses new technical, organizational, execution and economical challenges to the industry that have to be properly addressed to be able to successfully implement a first of a kind concept. Important considerations in that perspective are listed below: Safety Aspect on Space Constraints How to achieve high level of safety for complex operation with limit space on vessel. o Cryogenic spilling and handling. o Overall process integration. o High potential of unforeseen weight growth and increasing space requirement during design. o Technology Risk/Uncertainty New challenge for not only adopting onshore LNG process to fit with limited space on ship, but also o achieving effectiveness, efficiency and high safety level as per standard and design. Ship Motions Mechanical fatigue on structures especially column and cold box. o Dynamic impact on liquid motions in topside processing including sloshing effect in containment. o How to design covering ship motion effect on equipment performance. o Offshore LNG Offloading LNG offloading in offshore environment with either conventional LNG loading arms or new technology o of cryogenic hoses. Hull How to accommodate heavy load of topside processing which is higher degree that that of FPSO. o Consideration of hull design for operation and maintenance on filed location, as unit will be on site for o 20+ years. Redeployment for future re-location. o Cargo Containment System selection to suit the Offshore Application as well as partial filling limitation o together with sloshing impact solution. Commercial How to predict LNG demand, marketing, and negotiative price. o Because of these above issues, the FLNG concept does not being operational to date yet. Being technically quite complex and capital intensive, it is essential to have a well-balanced, reputable, strong and experienced team to develop and execute a project. Since there are many options to be made during selection, such a good team should have a capability enough to explore and select the best choice for their FLNG. Table 1 below lists the main system of a FLNG where options have to be made and carefully selected.

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Table 1 - FLNG Main System

System Inlet Facilities Gas Treatment NGL Separation Liquefaction Process Storage Tank Type Offloading to Carriers Power Generation Fuel Gas System Heating / Cooling Media Turret and Mooring system

Component Slug Catcher, Hydrate Inhibitor, Water-, Condensate Treatment CO2, H2S, H2O, Hg, Dust Removal Separation of Natural Gas Liquids (NGL’s: C3, C4, C5+): Produces LPG (if required) LNG Liquefaction (may include N 2-Removal) Type of cryogenic storage tanks for LNG and LPG (if any), Condensate storage tank Offloading method of products: LNG, LPG (if any), and Condensate Power for liquefaction compressors and all other duties Fuel for the power generation system Compressor Discharge Cooling, Distillation Reboilers External or internal turret configuration, permanent mooring under cyclonic condition

 Anyhow, FLNG is not without any precedence, with the Department of Sustainability, Environment, Water, Population and Communities (SEWPAC) of Australia recently approving the Shell Prelude FLNG facility (EPBC reference: 2008/4146). Additionally, the concept of FLNG is somewhat similar to that of Floating Production, Storage and Offloading (FPSO) facilities operating worldwide. So, it is strongly believe that the successful of FLNG development is not that unachievable for any longer if we start off in the right track by doing this development in the right sequence and being developed the vessel in the right size and with the right technology.

2.

PROJECT STRUCTURE

PTT Exploration and Production Plc. (PTTEP), a subsidiary of PTT Plc. (PTT), has started developing the FLNG concept since year 2009. The conceptual study phase was performed during late 2009 and completed in early 2010 in conjunction with Golar LNG. Preliminary Front End Engineering and Design (Pre-FEED) study was done during Jul 2010-Mar 2011 with GL Noble Denton was engaged as an engineering consultant.  At April 2010, PTTEP and PTT International (PTTI) jointly established PTT FLNG Limited (PTT FLNG) to be responsible for midstream FLNG development. SBM Offshore (SBM) and Linde Group’s Engineering Division (Linde) have been selected as the technical partners to jointly own and operate the FLNG vessel and a partnership agreement has been signed in February 2011. Project structure is illustrated below (Figure 1):

Figure 1 - Project Structure

Detailed Pre-FEED study has started in March 2011. Linde’s Engineering Division performed a design for the topsides of the FLNG including gas processing and natural gas liquefaction based on Linde's proprietary natural gas liquefaction technology. SBM Offshore, based in the Netherlands, is a market leader in the field of Floating Production, Storage and Offloading units (FPSO) for the oil industry, so they will contribute their mooring system technology, marine expertise and also be involved in the gas processing on FLNG topsides.

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 Assumed that the gas resources being f ound meet expectations, the project will enter into front-end engineering and design (FEED) studies by the end of 2011. The final investment decision (FID) is targeted for the end of 2012, and first commercial operations for the end of 2016 to early 2017.

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CASH/MAPLE FLNG DEVELOPMENT

Three gas resources from three groups of fields within three permit areas in the eastern region of the Territory of  Ashmore and Cartier Islands Offshore Australia have been considered as potential feedstock to the FLNG production system; 1. 2. 3.

Cash-Maple field (located within Petroleum Retention Lease AC/RL7); Southern group of fields (located within Petroleum Production Licence AC/L7) comprising Padthaway, Bilyara, Tahbilk and Montara fields; and Oliver field (located within Petroleum Exploration Licence AC/P33).

The location of these fields is shown below (Figure 2).

Figure 2 - Targeted Gas Fields for FLNG Development

The facility will be located approximately 680 kilometers west of Darwin, Australia, and 200 kilometers southeast of the Indonesian coastline. The plant will have the capacity to produce approximately 2.3 million tons of LNG per annum.The water depth at Cash / Maple is approximately 130 metres, 305 metres for Oliver, and 80 metres for Montara. The development concept has been compared between pipeline to land-based LNG vs. offshore FLNG. Those three fields are well-suited to a stranded gas fi eld concept i.e. they are not financially viable using traditional production measures, such as an offshore platform, an export pipeline and onshore liquefaction plant. It is therefore, according to feasibility study, the most attractive development option is FLNG.

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KEY PARAMETER

For an offshore facility the interdependence of the options is much stronger than onshore because of the limited plot area. Each key parameter has been investigated to address all risks carefully as per oil and gas business approaching. On top of that, the integration of all systems to find out any showstoppers has been performed stepby-step. Key parameters that to be considered for offshore LNG are explained in the following sections:

4.1 Field Development Two possible options were considered for development of those three fields. The illustrate of each option is shown in Figure 3 and 4 respectively; 1.

Relocation from each field from time to time. If this option is preferred, each field will be developed independently and the FLNG facility will relocate to each group of fields as required at the end of field life.

2.

Pipeline gas from the fields to a central location which allows more flexibility in terms of blending the gas and daily operating flexibility. If this option is preferred, the FLNG facility will be located at a central point (i.e., at the Cash-Maple field) with approximately 63 km of pipeline required to connect it to the Oliver field and 88 km of pipeline to connect it to the Southern group of fields. During operations, regular pigging of the lines or injection of chemical or Naphtha may be required if wax formation is predicted. Regular pigging would require dual flowlines or a subsea pig launcher at the field location.

Figure 3  – Field Development Option  –  Relocation

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Figure 4  – Field Development Option - Pipeline

The relocation option results in simpler topsides facilities and lower ov erall CAPEX. However, relocation option has lower economically recoverable reserves and the optimum point to move the vessel from one field to the next will result in gas being left in the ground. This needs to be balanced against the higher pressure losses for the pipeline options, which could result in lower recoveries for the remote fields. The gas delivery profile gives short plateau periods for relocation option, followed by decline and then no production when the vessel is moved from one field to the next. This profile is not ideal for long term LNG sales agreements and may result in a lower LNG sales price.

4.2 Gas Field and Market The required LNG specification dominates FLNG topside complexity. The Higher Heating Value (HHV) specification for the LNG together with the hydrocarbon part of the feed gas composition determines the NGLSeparation (NGL’s: C3, C4, C5+). A very rich gas (high C2, C3, C4’s, and C5+ -content) with a market that requires lean LNG will require a pre-treatment process that also produces LPG and condensate. The leaner the LNG Spec, the more NGLs have to be separated. Therefore, when the feed gas composition is so lean that the LPG (C3 + C4’s) can remain in the LNG, or if the market accepts a rich LNG, this is strongly preferred, as without LPG production and storage, the topsides are much simpler and safer. The LNG markets require various LNG specifications depends on local facilities of that country. For UK, the lean LNG specification is required while rich LNG specification is allowed for Japan market. LPG and Ethane management are the key parameters for design consideration in order to meet LNG specification. For Cash/Maple FLNG, the LNG specification has not reached the conclusion yet. It is subjected to continue discussion with PTT, who is considered as a potential LNG offtaker.

4.3 Design Approach & Capacity The design of the FLNG starts with Field Specific then extends to Generic. Redeployment is the major attractiveness of FLNG. Hence, first to start, the design consideration is focused on prospect field specific (s), then extend its gas envelops such as maximum CO2 & N2 content, rich gas, and lean gas well fluid to cover either regional or worldwide stranded gas fields (s). With Generic design, however, higher investment is expected. The

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balancing between Generic design approach and investment shall be addressed based upon economic point of view and business strategy of developer. The FLNG production capacity follows from the field reserves size, normal field production period, and market requirement. For Cash/Maple FLNG development, 2.3 Mtpa LNG product has been set as base case according to potential recoverable resources and economic results with supporting from marketing point of view. 4.4 Topside Processing Design FLNG shall be designed as a fully stand-alone system for offshore operation, making it independent from any infrastructure and eliminating the need for new pipelines, platforms, etc. The topsides facilities have been designed for the extreme cases of the design condition envelope, which implies that the overall dimensions of modules, equipment, pipe sizes, weights, utilities, and power consumption are all based on these “conservative” conditions. Hydrocarbon fluid from wells will be separated into 3 phases i.e. gas, liquid and water. Hydrocarbon gas is processing further to condense into liquid phase at atmospheric pressure. Cryogenic process is applied with operating temperature -161 C. With extremely low temperature, any of substances that become solid at low temperature shall be removed in Gas Treatment system prior to cryogenic system.  A high level indicative block diagram highlighting the main process systems is provided in Figure 5. In summary, FLNG topside processing will be comprised of:  A. Gas Treatment: To remove any of substances that become solid at liquefaction condition (i.e. CO2, Water, and Hg). Because of the robust specification of inlet gas to liquefaction process, gas treatment has stringent duty to remove any contaminants about 500-4600 times compare to pipeline specification. B. Liquefaction: To liquefy hydrocarbon gas to be liquid at atmospheric pressure by means of cryogenic processing. C. Condensate Treatment: To treat condensate prior to sending to storage D. Water Treatment: To treat water prior to overboard E. CO2 Re-injection vs. Venting: If desired from an environmental point of view, the unit can sequestrate and re-inject CO2 and water.

Figure 5 - FLNG Topside Processing System

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A. Pre-Treatment The inlet separation facilities are designed to separate the bulk liquids in the feed gas stream, such as hydrocarbon condensate and any free water, including slugs, which are determined by water depth and temperature. Subsea design and flow assurance calculations will give the size of the slug catcher and determine the requirement of a continuous hydrate inhibitor injection. Provision should be made for a MEG injection & regeneration system, which is required for possible pipeline tie-backs from remote fields and also for t he feed gas compression will be installed in late field life after pressure decline phase. The non-hydrocarbon parts of the reservoir fluid composition determine the “Gas Treatment” part. Removal of CO2 and H2S is normally done by one of the well-known amine absorption processes (formulated MDEA). However, appreciable concentrations of H2S will give safety and disposal problems. Gas downstream of gas sweetening will be routed to a gas dehydration system consisting of two to three molecular sieve vessels in a duty/regeneration type arrangement. Mercury removal is fixed bed adsorption; mercury guard bed. Inerts, like nitrogen, will carry to liquefaction system and flash as End flash gas which to be further used as a fuel gas. This step is even increase the energy consumption of liquefaction, but it is much simpler and cheaper than that of installing Nitrogen rejection system upstream of liquefaction.  After some works on technology screening, there were two potential removal systems taking into consideration i.e. 1) Amine only and 2) Hybrid (Membrane then following by Amine system). Results from the study shown that the Hybrid system requires more space and weight, and then Amine only option was selected as base case for design.  Anyhow, keep bearing in mind that the results with different design basis may resulted on different result.

B. Liquefaction Process The most important independent choice for an FLNG is the selection of the liquefaction process which was driven by the following criteria: •

 

• • • • • • •

   

Safety Track record in onshore LNG service Relative simplicity and ease of start-up & operation Offshore operability and maintainability Balance between (economical reasons) and (technical-complexity reasons) Adjustable to variations in gas composition Reliability Efficiency

The main choice is between two fundamentally different processes; liquid refrigerants and expander. Expander processes (Figure 6 and 7) use gaseous nitrogen (Nitrogen expander) or feed gas (Niche Process) as refrigerant.  All large (baseload) plants use liquid refrigerants, either as single or dual mixed refrigerant (Figure 8 and 9). Most developers for small scale FLNG (less than 2 Mtpa) prefer expander processes, however, liquid refrigerant is better choice for bigger capacity. Many studies shown that the most suitable liquefaction process for the range capacity of 2-3 Mtpa is Single Mixed Refrigerant (SMR), while Dual Mixed Refrigerant (DMR) are selected for a large scale FLNG (> 3Mtpa). For a small scale FLNG (less than 2 Mtpa), the expander processes would be preferable in that:  Liquid refrigerant processes require higher hydrocarbon inventory, while expander processes using nitrogen or feed gas as refrigerant, which is also only in the gas phase in the expander loop. This is highly important in safety aspect especially offshore operation.  The liquid refrigerant processes have a higher equipment count since the refrigerant is required to produced and stored separately onboard FLNG. Moreover, the nature of their two-phase process requires liquid-gas separation in several stages.  Expander processes are not sensitiv e to motion and have no maldistribution problems as they are only in the gas phase.  Expander processes can retain the refrigerants (gases) on shutdown in the process at settle-out condition resulted in faster re-starting-up.

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Figure 6 - Dual Nitrogen Expander Processes

Figure 8 - Single Mixed Refrigerant Processes

Figure 7 - Niche LNG Processes

Figure 9 - Dual Mixed Refrigerant Processes

Single Mixed Refrigerant (SMR), on the other hand, is considered to be a good selection for a medium scale FLNG (2-3 Mtpa) by the reason of:  Higher efficiency than expander processes.  Lower overall equipment count for medium scale FLNG (2-3 Mtpa) than expander processes. This is due to limitation of expander processes in capacity per train, so duplication of train is required for higher capacity.  Lower rotating machinery (compressor-expander), so expected lower downtime for shutdown and maintenance.

It seems that the grey area is around at 2 Mtpa in which both technologies, Expander (N2 or Niche) and SMR are feasible. Comparison among candidate technologies for 2 Mtpa is shown in Table 3. Overall technical complexity and safety studies have to be done along with life cycle economic analysis in order to judge the most suitable liquefaction process in each case by case.

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Table 2 - Main Liquefaction Processes for around 2 Mtpa

C. Condensate Treatment The condensate is extracted from inlet facilities and is stabilized in a stabiliser column to achieve the specification; RVP 10 psia (as Australia’s specification). Liquid condensate is subsequently sent to the storages. The overhead product of the stabilization is re-compressed and route back to the inlet system. D. Water Treatment Produced water is being treated in conventional system to achieve specification (30 ppm of oil in water). The system consists of hydrocyclone vessels and a degassing tank. Oil in water content is measured before being routed overboard. If the water is off-spec, it can alternatively be routed to a slop tank, where it will settle and further separate and eventually be pumped overboard when acceptable specification. E. CO2 Re-Injection vs. Venting From economical point of view, even venting case has to pay along with some amount of CO2 tax, the project value is much better than CO2 sequestration via reinjection which require high CAPEX for CO2 compression and pipeline system. It is therefore recommended that CO2 venting should be carried forward as the base case.

4.5 Utilities (Topside and Marine) A. Power Generation and Driver Selection The main power consumers of any LNG plant are the large compressors. The power plant will be an order of magnitude greater than for oil FPSO. There are actually two choices: direct or indirect (electrical) drive and the choice of the prime driver. Steam turbine and gas turbine drivers are screened options for further evaluation of liquefaction compressor driver. While the potenti al options for power generation system are steam turbi ne generator, gas turbine generator, and Dual Fuel Diesel Engines (DFDE). Pros and Cons of each type are described herewith: 1.

Steam Turbine driver and generator are a very robust system, high availability, reliability, safely, and can handle high N2 content in f uel gas. Anyway, very large steam plant is required (large boilers, large stream pipes) with high sea water demand and large condensers located at deck level.

2.

Gas Turbines, especially modern aeroderivatives, have very good efficiencies but they have a limitation in flame size and expected low availability. Moreover, the system is also sensitive to the fluctuations of fuel gas quality / heating value.

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Dual Fuel Diesel Engines requires very lean fuel gas and can put in hull to safe deck space. But limitation to only small size resulted in the utilization of several machines to achieve power requirement.

Evaluation and selection of the power generation system will include equipment, installation and life cycle cost, footprint, possibility to install in the hull, heat available from exhaust WHRUs, etc. Optimization of the power generation system must be done in parallel with evaluation and selection of the liquefaction compressor driver and optimization of the heating medium system.

B. Other Utilities For a gas turbine driven power plant, the choice of heating medium is between hot oil, steam or hot water. The selection of heating medium is interdependent with power generation and liquefaction driver selection. The final answer is differing from case by case. For example, if gas turbine is selected, a closed hot water system might be a good solution for a FLNG comparing to a steam system because it has less equipment, much simpler in operation, and does not require a continuous supply of fresh water and treatment chemicals. Hot water might be competitive compared to hot oil as piping and heat exchangers are smaller because of the higher heat capacity and lower viscosity of water. Also in view of safety, water would be preferred over hot oil. On the other hands, if steam turbine is selected, design heating medium by using steam is practical solution. The main heat exchangers in LNG processes are coolers or condensers in the discharge of the compressors. These high duty heat exchangers will, on a FLNG, not be air-coolers because of the required large plot area, high weight (high design pressure), and impair the FLNG stability. For cooling water, there is a difficult choice between direct seawater cooling and an indirect closed fresh water loop. An indirect cooling water system gives the possibility to control the inlet and outlet temperatures of the heat exchangers and so stabilize the processes that depend on cooling and reduce fouling problems. Further the intercoolers can simply be spared for maintenance and cleaning. End Flash Gas, Boil off Gas (BOG) and vapor return from the LNG carriers during offloading will be either compressed to the fuel gas system or to the inlet of the cold box when the amount of gas exceeds the fuel gas requirement. Boil off gas compressors used onshore are usually of the reciprocating type. Because of their large size and weight, it is on an FLNG advantageous to use centrifugal compressors for BOG. Fuel gas will be a mixture of Boil off gas, End flash gas (from flashing the LNG to storage pressure), possibly gas from the NGL Separation and raw feed gas. Gas fields with high nitrogen content aggravate this problem as the nitrogen is significantly enriched in the Boil off gas. The fuel gas system usually i ncludes a mixing drum to dampen the changes in fuel gas quality, and it might even require a nitrogen removal unit to avoid flaring of lean BOG gas.  All relief valves from hull and topsides have to be connected to central relief systems. For safety and environmental reason they should be flared, not vented. The height of the flare is determined by the maximum allowable radiation and gas dispersion in case of relief.

4.6 Hull, Storage and Offloading A. Hull  Although the key benefits of the conversion are lower CAPEX and faster schedule, but it has been l imited to 1.0 Mtpa capacity due to limited storage capacity and challenges regarding available deck space and limits of safety. Moreover, at 1.0 Mtpa production capacity the conversion concept has lower value than the higher capacity new build vessels across the range of reserves considered and cannot capture the significant value of reserves upside. The OPEX for conversion i.e. maintenance & repair is high and more time than new build. Therefore, the new build options should be carried forward as the base case. The new-build FLNG is of the complete double hull. A range of topside weights and configurations have been assessed obtain maximum motions and accelerations for hull, containment system and topsides. Design life of the

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hull is 25-30 years and special attention is given to hull & tank design in terms of strength, fatigue, and coatings. A sizeable width is advantageous, as this will reduce the roll and thus gives a greater operating window. B. Storage (Containment) Three main types are well-known and applicable for FLNG containment system (Figure 10). With the FLNG being permanently moored at one location f or possibly up to 20+ years without dry-docking, it is v ital that the containment system is robust, reliable and repairable, without having to cease production and leave the site. Containment tanks for a FLNG will be either Self-Supporting Prismatic tanks (SPB) that are not sensitive to sloshing during partial filling but are expensive and potential to structural fatigue, or strengthened Double-Rows Membrane tanks that will withstand sloshing up to a certain sea state, while Spherical Moss-type that leaves less deck-space for the topsides is only suitable for very small scale FLNG. The selection of FLNG containment will be also limited by heavy weight of topside as the containment is required to support the load weight from topside. With limitation of deck space, even extension in length or width, Moss spherical is considered not justify for moderate size FLNG and has been ruled out from further study. Only flat deck SPB or Double-Membrane is recommended to be further studied in Pre-FEED stage. The total volume of the LNG storage capacity should be also carefully considered. It shall be a larger than the volume of the designed LNG carrier with available space for continue production if delay or bad weather prevents offloading.

Figure 10 - LNG Containment System

C. Offloading and LNG Carrier The production capacity of the FLNG and the distance to the market (the regasification terminal) determines the required number and size of LNG carriers. Metocean data of the location will determine the hull movements of both FLNG and carrier. From these follows the choice of offloading method. Offloading can be done by marine side-byside loading arms up to a significant wave height of 2.5 m which is proven solution and has been used in industry practice.  Although side-by-side LNG offloading is assumed the base case, provisions will nevertheless be made for a tandem LNG offloading system. As such, the system can be tested and proven in operation, providing comfort that such a system can successfully be applied on a FLNG in harsher environmental condition where tandem LNG offloading would be the only means of offloading.

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4.7 Turret and Mooring The selection of the mooring system is very dependent on the local environmental conditions (either the water depth or the extreme design conditions) and purpose of using. The internal turret will be considered as high safety but less of hull space for turret compartment. The external turret will be given the optimum of hull space for cargo containment. The permanent mooring is mainly selected in benign water, and the disconnectable mooring is applicable for harsh water and relocation purpose. The FLNG will be turret with weather  –vaning mooring system to enable freely moving around turret (by swivel) and applicable for side by side or tandem offloading. Spread moored will only be possible in very sheltered waters but limit the offloading operation. The choice between disconnectable and permanent turret depends on metocean data in which areas where there is a possibility of hurricanes or icebergs occur, it might be required to select a disconnectable turret. When disconnect, the FLNG will be freely sailed as ship powered by thrusters. Moreover, thrusters are also used for heading control during offloading operation 4.8 FLNG Layout and 3D Schematic  As abovementioned, FLNG development has faced a challenging on design to adopt onshore LNG to offshore operation within a very limited space. The major issue that FLNG development team has to be addressed and solving is how to fit complex system on ship, but also maintain high level of safe operation. To sort out the key showstoppers, the back-and-forth thinking is applied. At early of project development, topside system requirement on space is estimated then put into ship space with preliminary layout. Next step, brainstorming of interdiscipline was conducted to investigate the risks and record for requirement of design changing. Several cycle of working were performed to establish robust deck space requirement with proper mitigation of all risks. The layout has been developed based on maximizing inherent safety without compromising concept. With limitation of deck space, gray area for layout arrangement is still located in some cases. There is consequently affect to increase risk of adjacent area which is unavoidable. If there is any risk remaining, the properly safety device shall be put in place to mitigate all risk to an acceptable level. Here below briefly explain the Basis of FLNG Layout (Figure 11):

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-

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Layout basis is started on internal turret, which is the weathervaning position of the vessel. The accommodation shall be located at the bow in order to retain accommodation upwind of any gas leaks on the topsides deck and riser for most of the time. Process utilities without gas (instrument air and nitrogen storage, cooling water, heating medium) and power generation are placed between living quarters and turret to enhance as a safety gap from high potential ignition source and the personnel living area. From turret to the aft side, it started with inlet facilities, gas pre-treatment, NGL extraction, and then liquefaction. The emergency flare stack is located aft of the vessel and is of a sufficient height and incline to avoid excessive radiation on the deck or at the LNG carrier bridge. For safety reasons, the flare stack has to be as far as possible apart f rom the accommodation, and preferably downwind of it, to avoid gas emissions to process area and accommodation.

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Figure 11 - PTTEP FLNG  – Layout

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CONCEPTUAL STUDY

 A conceptual study phase was performed during late 2009 and completed in early 2010. This work was conducted in conjunction with Golar LNG. The prime objective of this study was to carry out a preliminary assessment of the overall economic viability of the project and to narrow down the number of options to be taken into the next stage of development. The work has focused on making four key decisions regarding the configuration of the offshore development and in particular: 1. 2. 3. 4.

To establish the optimum production capacity recognizing uncertainty in the gas resources volumes. To evaluate the benefits of relocation of the FLNG vessel to each field in turn or pipelining the gas to a single FLNG location. To evaluate the merits of conversion of an existing LNG tanker or new built hull. To determine the benefits of CO2 sequestration or venting to atmosphere.

The study options and results from the conceptual study are summarized in Table 3: Table 3 - Study Options for FLNG Conceptual Study

FLNG Vessel Design Capacity Field Development CO2 Disposal CO2 Removal Process LNG Containment Type

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Study Option New build vs. Conversion 1.0 / 1.5 / 2.0 Mtpa Pipeline vs. Relocation to each field Venting vs. Re-Injection Amine only vs. Hybrid (Membrane + Amine) Moss vs. SPB vs. 2‐row Membrane

Pre-FEED

Cash/Maple FLNG Pre-FEED stage has been started carrying out with main objectives to more refine the options and identify the key design requirements to deliver an inherently safe and a fit for purpose installation. The selected base case will be finally developed as completed design and sizing of all systems with ± 25% cost estimation. The topsides facilities will be designed to cover all worst cases of the design condition envelope. The key given parameters have been carried out from conceptual study as described above. The main study options are summarized below in Table 4:

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Table 4 - Study Options for FLNG Pre-FEE D

Liquefaction LPG Removal Driver Selection Power Generation Selection LNG Storage Turret Mooring Field Development Condensate stabilisation Mercury removal  Acid Gas Removal Molecular Sieve (Gas Dehydration) Heating Medium

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Study Option Dual N2 Expander vs. SMR Onboard FLNG vs. Onshore Steam Turbine vs. Gas Turbine Steam Generator vs. Gas Turbine Generator SPB vs. Double‐Row Membrane Internal turret vs. External turret Disconnectable vs. Permanent Re‐Visit Pipeline vs. FLNG Relocation Flash column vs. Stabilizer Upstream vs. Downstream of CO2 removal Single vs. two stages configuration Optimum number of Drier Hot oil vs. Steam vs. Hot water

CONCLUSION

With a few years of studies from both brainstorming in-house and numerous learning and exchange idea with other FLNG developers, Cash/Maple FLNG is now become more robust in both terms of technical and commercial aspects. No more remaining technical issues “show stoppers” are foreseen to date. One of the most important from now on is the sequence of execution in which such large development does not allow for any short cuts. It is strongly believes that we have started off in the right track by doing this development in the right sequence and being develop the vessel in the right size and with the right technology in order to get not only to successful of the FLNG but also secure the energy demand to support Thailand country.