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FLNG—DETERMINING THE TECHNICAL AND COMMERCIAL BOUNDARIES

Christopher Caswell Technology Manager – LNG and FLNG Technology

Charles Durr LNG and FLNG Technology

Mark Kilcran Senior Project Manager

KBR Houston, Texas, USA

chris.caswell@kbr.com

ABSTRACT

As the floating liquefied natural gas (FLNG) industry develops from its infancy, there are numerous examples of projects and prospects that are enduring the growing pains involved in being technically, economically, and operationally successful. Technical papers address the challenges or ease of FLNG technologies, while commercial papers address potential market advantages; but how are these challenges viewed by the owners, developers, and contractors?

FLNG opportunities should be analyzed from a risk viewpoint to determine the technical and commercial viability of the project. In particular, what are the individual limits or boundaries of each specific issue? Is the design extrapolation from an FPSO (floating production, storage, and offloading) or onshore LNG project a slight deviation from current practice or a completely new application? Awareness of these limitations will more or less define the issues that need to be addressed during the conceptual and FEED phases for a specific project or opportunity.

The purpose of this paper is to review the elements and risks of an FLNG project with the purpose of defining the limits that should not be exceeded from technical and commercial viewpoints. By understanding these limits, we can assure ourselves of success for the very early projects. The LNG industry has faced such challenges in the past, and it will again rise to the challenge for FLNG.

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INTRODUCTION

There are many definitions and interpretations of the word risk. Risk is commonly used as a noun (n): the exposure to the chance of injury or loss [1]. This definition is familiar to owners, developers, and contractors that classify and rank technical and commercial issues within a risk register to analyze a specific project or opportunity. One of the more interesting definitions of risk is when used as a verb (v): to venture upon or take the chance of [1]. Although all industrial projects have technical and commercial risks (n), first of a kind projects take on the active (v) form of the word; FLNG is akin to a venture into a new arena, where the final outcome is not completely certain.

As an LNG and floating production storage and offloading (FPSO) contractor, our risk register is populated with the issues that are new for FLNG as well as the technical and commercial issues that must be addressed for every FPSO or LNG project. Primary contractor risks are bundled in areas such as technical viability, execution and fabrication capability, safety performance, and overall delivery and operation. FLNG owner risks include an additional layer of issues such as contractor qualification/competence, effective use of capital, overall rate of return, and long term safety and asset security. As a result, there are significant risk profiles (with major differences) among asset owners, developers, and contractors who strive to deliver the early FLNG projects.

In 2010, there are many seemingly viable FLNG opportunities of various size, scale, and configuration. Of these known opportunities, all have a different perspective on the necessary development of front end engineering design or FEED. As addressed in many publications, insufficient front-end definition will result in increased execution risk [2]. For onshore projects, the potential losses from excessive technical and execution risk can be significant, but are rarely catastrophic. For offshore projects, excessive technical and execution risks can affect the solvency of a project or even a contractor.

The term “crying uncle” is a phrase used by combatants of all ages to allow for mercy in a battle of strength or wits. Crying uncle is similar to the resignation of one’s king in chess, the “tap out” in wrestling or mixed martial arts, or waving the white flag in war. Crying uncle concedes defeat in the face of grave risk to physical or psychological pressure, while allowing the combatant to remain intact to fight another day. Alternately, crying uncle allows you to elastically bend without breaking in order to avoid a catastrophic loss or permanent deformation.

While a contractor or technology provider cannot simply “cry uncle” while executing a multi-billion dollar infrastructure project, the analogy of “bending without breaking” is a useful way of looking at issues and risks for a first of a kind project. Catastrophic loss is not an acceptable outcome based on well managed risk; therefore, how can we apply new technologies and commercial strategies in a way to encourage innovation without an unacceptable risk of failure? To implement FLNG, technical and commercial advancements should come from logical progressions of proven technologies along with corresponding increases in size and scale. This strategy is similar to how the LNG and FPSO industries developed over time [2]. These progressions should allow technologies to bend without breaking and without adding an unacceptable level of risk.

Only a limited number of technical and commercial risks can be addressed in a single paper, but each opportunity to identify and mitigate these risks will push FLNG closer to a comfortable reality. The purpose of this paper is to review some of the “bending without breaking” issues that

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face every FLNG configuration. As an FLNG project develops through conceptual design and FEED, a contractor or a technology provider might only be allowed to cry uncle a limited number of times before the project reaches its final investment decision (FID) and faces the looming prospect of EPC.

FLNG—AN INFINITE MATRIX OF OPPORTUNITY

In order to begin to discuss the boundaries of some of the FLNG technical and commercial issues, we must visualize the types of projects that will encompass this future market. Projects of varying size and scale will have issues that will be more important for one opportunity than another. Those new to the concept of FLNG may ask: what does FLNG look like? Valid answers to this question may take on many forms. FLNG will not be based on a single concept or design, to be manufactured by multiple suppliers; FLNG will take on whatever form is best suited for the asset, location, operation, and market. As a result, FLNG cannot be based on a rigid pre-determined design. Based on recent experience in developing FLNG concepts and designs, let’s review a key concept from the histories of onshore LNG and FPSO projects.

An often misunderstood concept for onshore LNG projects is the concept of NALPACE, or “not all LNG plants are created equal” [3]. The principle of NALPACE is that the design, execution, and cost of an LNG project is a function of many site-specific parameters such as feed gas composition, train size, ambient conditions, site labor, soil conditions, etc. Due to the impact of site-specific criteria, it is difficult to compare an array of LNG projects solely on the basis of capital cost per unit capacity.

Similar to onshore LNG, site specific concepts heavily influence the design and operation of oil and gas FPSOs. For some observers, it may be easily understood that basic offshore data such as wind, wave, and temperature are not standardized or predictable. These site-specific criteria heavily influence the design of large FPSOs that separate and stabilize oil, water, and natural gas. Similar to onshore LNG, it is difficult to compare the merits of FPSO project execution solely on the basis of a capital cost metric (e.g. cost versus topsides weight or cost per barrel of storage). For FLNG, while project execution planning may be extrapolated from the experience from FPSOs, overall success is primarily based on the long-term reliable operation of an LNG plant. In order to elevate awareness of this concept offshore, let’s create a new acronym – FANG: “FPSOs are not generic”.

Regardless of the type of project, the entire slate of site specific issues affect the project evaluation criteria from concept development through FEED. Since every industrial project is unique, trying to reduce the analysis to a series of simplifications leads to a generic solution that appears to fit all but actually fits none [4]. In order to advance a project to FID, the project must meet the technical and commercial evaluation criteria which differ for every asset owner or developer. If generic or standard plants were the best method of execution, why are contractor design competitions still viable for onshore LNG and FPSOs?

FLNG solutions encompass a multi-dimensional matrix of site-specific and capacity metrics just as one could envision for any hydrocarbon project. In a simplistic example, a three dimensional solution matrix may span the criteria of methane composition, overall production capacity, and topsides availability as shown in Figure 1.

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Figure 1. Simplified Comparison of Influence and Variability – a Matrix of Solutions

From experience in LNG and FPSO projects, changes or uncertainty in reservoir data, capacity, or availability will have significant effects on the equipment and/or and hull design. Adjustments to any of the design criteria will create an overall shift in the entire configuration resulting in a unique solution (represented by a new coordinate in the matrix). For established industries like oil FPSOs and onshore LNG, changes in design criteria produce results that are predictable and well understood. Although an infinite number of solutions still exist, this predictability allows customization during design competitions or FEED. For FLNG prospects, changes to the design criteria produce results with high variability and low predictability due to limited available project and estimating data and experience. The range of solutions for FLNG may be an exponential step change from either traditional industry; when technical complexity increases, commercial uncertainty may also increase.

Although FLNG is a vast matrix of opportunity with no standard technical or commercial basis, there will be common elements, issues, and technologies that must “bend without breaking.” In order to prepare for the future, let’s create one last acronym – FICAS: “FLNG is customized and site-specific”. The principles behind NALPACE, FANG, and FICAS promote the merging of site specific criteria, appropriate technology, and design experience.

FLNG ISSUES, BOUNDARIES, AND DISCUSSION

In order to discuss FLNG technical and commercial issues and limitations, we must make some basic assumptions about an example opportunity. Even though site specific issues (FICAS) apply, we’ll assume our potential FLNG opportunity has passed the following evaluation criteria:

• FLNG preferred versus an onshore LNG plant and subsea pipeline

• Fixed reservoir data (composition and volume) for intended design life

• Preferred economics compared to another investment or asset

FLNG is one of many infrastructure solutions in a gas monetization portfolio. FLNG may be environmentally preferred over a comparable onshore project or may be part of a relocation strategy to monetize multiple fields. FLNG may be one of many ways to monetize, utilize, or dispose of offshore natural gas. For the purpose of this paper, FLNG is the intended gas monetization solution.

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As previously illustrated in Figure 1, the individual reservoir characteristics have a distinct effect on the optimal FLNG solution. As with any onshore LNG project, a high confidence feed gas composition will lead to well defined equipment for the range of parameters expected over the field life. While FLNG can be proposed for multiple reservoirs or locations, the basis for this paper is that the field characteristics are well known to allow for the proper selection of technologies and execution methods for the design life.

There is great debate about the economics of FLNG versus a comparable onshore LNG project. Although this paper will not address the economic details of FLNG versus other gas monetization options, there is an assumption that the consideration of FLNG takes precedence over investments in other opportunities. The economic evaluation of the FLNG value chain versus the onshore LNG value chain is a topic for a separate publication.

Lastly, this discussion assumes the reader is familiar with the general configuration, purpose, and components of an FLNG vessel. Background information on LNG or FLNG is available in the References Cited (e.g. [2] or [3]) or numerous publications from conferences and trade journals.

Technical Risks and Boundaries

Technical risks involve any engineering issue that can affect overall plant reliability, availability, and maintainability. Familiar LNG risks involve process design decisions and equipment selection; however, these design decisions will have an impact on overall topsides layout, modularization strategy as well as the required hull configuration and resulting performance. Of the myriad of issues and risks for a first of a kind project like FLNG, this section will address issues such as liquefaction process technology, suitability of equipment for FLNG, cryogenic liquid transfer, overall size and scale, layout and modularization philosophy, and allowable hull motions.

Liquefaction Process Technology. In the evolution of FLNG, there has been a lively debate regarding the optimal liquefaction process technologies (i.e. refrigeration cycles) which are best suited for use offshore. Often, this debate has two distinct sides; one view favors a specific process technology often in a generic application, while another view supports process selection from a range of technologies in order to find the optimal fit for each prospect [5]. Process technology selection is a key issue during conceptual design; therefore, determining the limitations (if any) of cycle selection for FLNG is of great importance.

Each refrigeration cycle has its pros and cons, although every cycle faces a functional limit of thermodynamic and operational efficiency. This efficiency is based on the number of refrigerants, the number of cooling stages for each refrigerant, and the equipment used in the process train (compressors, drivers, and heat exchangers). Since FLNG is a potential opportunity for new technologies and service providers, it is believed that all process cycles are now potentially suitable for use offshore.

Although there are many cycles to choose from, most of the worldwide baseload onshore LNG experience resides with only a few technologies and technology providers. It is expected that the decision to use a cycle outside of this range of experience is based on an atypical or site-specific issue such as refrigerant sourcing, licensing or patent issues, CAPEX/OPEX cost, or implied safety. However, since FLNG has yet to be commercialized, there is no definitive proof that a non-traditional or open art cycle has a distinct advantage over a well proven option.

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When comparing licensor flow sheets and process flow diagrams, none of these technologies will “break” under evaluation for FLNG. The key issue in process selection is the effect of site-specific criteria along with offshore optimization; how does each cycle affect capacity, equipment type, availability, layout, thermodynamics, cost, and safety? The best way to mitigate the risks associated with liquefaction technology is to perform a thorough process technology selection study for each FLNG opportunity. In this type of study, each cycle can compete on its merits and functionality during the early definition stages of a project – well before FEED.

As a result, all process technologies are open for FLNG, and omitting the process technology selection study is not recommended for any onshore or offshore LNG project. No single cycle is a best fit for the infinite matrix of offshore FLNG opportunities, but the academic evaluation of multiple options will allow for competition among technology providers and design contractors. Lastly, why allow the premature selection of process technology, the anchor point for topsides design, to be an issue that imposes limitations on design, execution, or operation?

Suitability of Equipment Types for FLNG. In parallel with conducting the liquefaction process technology selection study, there is a review of the suitability of major equipment for offshore operation. Although there is vast experience with certain equipment and systems for FPSOs (e.g. electric power generators, oil/water separation drums, heat exchangers, and gas compressors), the additional building blocks required for LNG (acid gas removal unit [AGRU], dehydration, fractionation, refrigeration, liquefaction and cryogenic storage) involves equipment of a size and scale that has not been implemented offshore. Although LNG equipment selection is touched upon in many publications, some of the equipment requiring offshore suitability review includes the refrigerant compressor drivers, distillation and absorption columns, and the main cryogenic heat exchanger (MCHE). Within each of these equipment sub-sections, there are a many decisions concerning equipment type, size, or some other specialized technology or feature.

The refrigerant compressor drivers will often receive immediate attention during process technology selection. The available choices for these drivers are industrial gas turbines, aeroderivative gas turbines, steam turbines, and electric motors. Steam turbines were used as refrigerant drivers during the early days, while industrial gas turbines have been the most commonly used driver over the last twenty years. Recent onshore LNG plants have used aeroderivative drivers (Darwin LNG), while electric motors have been used in increasingly larger scale (most often in starter/helper service); but does this recent experience allow for the application of this equipment for offshore LNG?

Although an entire paper could be written about the selection of refrigerant compressor drivers, it is clear that there are technical limitations in using either the largest powered drivers (due to size, weight, power, and speed) or equipment with limited experience (electric motors above 35MW) for the first offshore LNG projects. Most industrial and aeroderivative gas turbines are well suited for offshore LNG, but the largest models of these drivers require extensive evaluation for the long term operation and maintenance required for offshore operation. Although well suited to match refrigeration power demand, steam turbines require auxiliary steam generation equipment which would require valuable topsides plot space; as a result, steam turbines may be best suited for small scale FLNG with less restrictions on available topside space. An example of extending the boundaries of familiar onshore experience is the application of large aeroderivative turbines as compressor drivers (e.g. a GE LM6000) for FLNG.

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Distillation and absorption column performance is affected by the combination of column size and hull motion. These columns are located in the AGRU (absorber and regenerator) and in the fractionation (distillation) units, where stringent vapor and liquid specifications have to be met. Trayed columns are well suited for onshore applications, where the liquid level remains constant over the tray span; but when the vessel oscillates in any direction, the liquid level will vary across the tray leading to ineffective vapor/liquid mixing resulting in off-spec products or loss of process control. Distillation columns designed with structured or random packing can be implemented for offshore operation (e.g. Belanak and Sanha LPG FPSOs); however, even packed columns have design limitations that become boundaries with increasing motions. These limitations are addressed in the section on allowable limits on the movements of an FLNG hull.

In technical publications and conference forums, one of the most widely debated issues of FLNG equipment suitability involves the MCHE. At the heart of the LNG plant, the performance and reliability of the MCHE is critical to the plant stability and availability. In addition, plant reliability is a major factor in the LNG shipping logistics for multiple carriers traveling to multiple destinations. As discussed in publications and LNG training courses [6], the MCHE is either a spiral wound heat exchanger (SWHE) or a plate fin heat exchanger (PFHE). Although both equipment types are well proven for onshore LNG plants, each have potential limitations for high reliability offshore.

A set of PFHEs is commonly used in a cascade (e.g. classical cascade or ConocoPhillips Optimized Cascade) or a nitrogen-based (multiple commercial offerings) refrigerant process. These PFHEs are part of a system of cryogenic equipment and piping contained within a self-supporting insulated cold box that is effectively used in LNG, LPG, and ethylene projects. The benefit of using a PFHE is the ability to design a compact sized heat exchanger (often balancing multiple streams) for narrow temperature approaches by a close coupling of the flow paths. Due to the thermal balancing of the flow paths, the PFHE is a thermally effective heat exchanger for steady state operation. The potential limitations of using this equipment lie in number of startups/shutdowns or transient conditions often seen in offshore operations. Due to the unknown long-term FLNG train operating scenarios, PFHEs may be subject to many more thermal cycles than for onshore plants. Excessive thermal cycling or an unbalanced cooldown or warmup of a PFHE may cause thermal stresses resulting in refrigerant or hydrocarbon leaks. Since this equipment is contained within an enclosed cold box, accessibility for in-place repairs is relatively difficult. Although the steady state operation of the PHFE is well suited for LNG plants, the long term reliability of this equipment requires further analysis in order to reduce the overall process risk. This issue is compounded by the need for multiple cores and multiple cold boxes in order to build up LNG capacity. The potential limitations in selecting PFHEs are absolute: is a PFHE design reliable for long-term operation and can the equipment be maintained or replaced to meet the overall availability criteria?

With proven thermal performance in onshore operations, the suitability of selecting a SWHE is primarily based on its long-term structural performance under hull motions. The external profile of a SWHE is similar to a vertical pressure vessel; the helically wound bundles are supported inside the shell with the tube side flow upward and the shell side flow downward. Although thermally robust, the SWHE is subjected to the structural loads seen for similar large vertical vessels such as fractionation columns. In some scenarios, the service for the MCHE could be provided by two SWHEs in order to reduce the structural loads on the exchanger; this philosophy is used for all equipment that may reach size or scale limits. Under these conditions, structural analysis is required for the SWHE internals as well as the external loads transferred to module

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structural steel and subsequently to the hull in order to reduce the long term operational risks from the process train.

Even with project development concerns regarding process technology, module design, hull fabrication, topsides integration, and capital cost, one must always remember that the end result of an offshore hydrocarbon project is a fully functional plant with predictable reliability, availability, and maintainability. The suitability of equipment for LNG plants is a primary issue even after 40 years of onshore liquefaction experience; the greatest technical optimizations are made by selecting the right equipment that will perform with the expected reliability and maintainability for the intended service. The transition of this design philosophy and experience to an offshore environment is paramount to assuring success after mechanical completion.

Liquid Transfer Technologies. One of the most functionally critical systems for FLNG is the operation and reliability of a liquid transfer system. Even if the process topsides equipment functions with 100% availability and reliability, the reliable transfer of cryogenic liquid products (LNG and LPG) is crucial to maintain the overall availability when shipping these products to multiple destinations. Proposed FLNG cryogenic transfer systems involve either traditional equipment (e.g. mechanical loading arms in side by side [SBS] configuration) or new technologies (e.g. cryogenic aerial or floating hoses in tandem configuration). For most schemes, condensate loading is conducted in a tandem arrangement in a similar manner as for oil FPSOs. In addition to overall availability, key issues for cryogenic transfer include mechanical integrity over repetitive use, overall safety during operation, reliable ship to ship connectivity, and the provision for emergency release systems and protection between loading operations.

A mechanical loading arm (e.g. manufactured by FMC, SVT, and others) is a common piece of equipment used in onshore liquefaction plants and receiving terminals to transfer LNG and LPG to standard carriers. Mechanical loading arms function with high reliability where the onshore connection is stationary while the offshore vessel is subject to limited motion, even when being shielded from excessive wave action via breakwaters or natural harbors. In this benign environment, mechanical loading arms have operated successfully for many decades in wave heights of 2-3 meters; however, traditional loading arm technology meets limitations in less benign environments. With increased relative motion, the limiting issues are establishing the initial connection and the magnitude of motion once the vessels are connected. Of these issues, establishing the initial connection is most limiting in all but the most benign seas. In an optimal environment, traditional loading arms have been proposed for FLNG and have been installed as one of the loading options for the Sanha LPG FPSO [7].

In extending the functionality of well-proven technology, loading arm manufacturers such as FMC have developed connection assisting systems (CAS) as a means to synchronize the relative motions between vessels [8]. As an example, the FMC CAS allows for 4-5 meters of motion in all directions, which is an improvement from the onshore limits of operation. In certain sea states, “bending” this technology is a low risk way of utilizing proven equipment, maintaining comparable liquid loading rates (commonly 12,000 m3/hr onshore) without requiring modification to the shuttle carriers or tankers. Although mechanical loading arms can be successfully used in benign conditions, the FLNG vessel and LNG carrier are moving in close proximity with a narrow limit on the mechanical connection.

For the potential of additional motion flexibility, cryogenic aerial (e.g. from an FLNG boom to an LNG carrier) or floating hose technology will enable offloading capability in the most challenging of sea states. Hose technology provides greater flexibility in the distances between

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the offloading and receiving vessel; as a result, hose technologies can accommodate both SBS and tandem loading. An adaptation from FPSO oil transfer, flexible hoses must withstand cryogenic temperatures, mitigate heat leak into the fluid, and withstand the fatigue associated with batch operation. An example of a 16” flexible cryogenic hose is shown in Figure 2. In order to provide maximum operational integrity and reliability, hose configurations would be manufactured for the specific application (either SBS or tandem loading) and the number of bolted flange connections would be kept to a practical minimum. Aerial configurations would require the modification of existing LNG carriers to provide for the connections and manifolds required for bow mounted LNG transfer.

Figure 2. Manufacture and Testing of 16” Aerial Cryogenic Hose Technology Image Courtesy of Bluewater Energy Services BV

Although cryogenic hoses have been proposed as a viable solution for many years [9],

companies such as Bluewater, SBM, Technip, and Nexans are obtaining design qualification and certification of flexible hose technologies for use for FLNG. As of 2009, there have been several successful SBS LNG transfers using flexible hoses, albeit with 8” diameter hose, at lower liquid flows, resulting in longer offloading durations. In addition, data regarding vapor handling and boil off generation is not available from these exercises. However, cryogenic hose technology appears to be commercially viable in large scale for tandem operation, while a floating hose may require a longer qualification period.

For cryogenic hose manufacturers, proven qualification, certification, and testing is necessary to ensure the key mechanical and reliability risks are mitigated over the design life of the FLNG project. Even though cryogenic hoses are an extension of oil FPSO technology, this new adaptation is not a simple effort. Testing and qualification is necessary to assure that this technology is one that will bend without breaking as there is little use for FLNG without reliable cargo transfer. Current progress with the certification of 16” cryogenic hoses is a comfortable limit of extending this technology to meet the comparable loading requirements seen onshore. The key enabler for cryogenic hoses is opportunity; as more FLNG opportunities progress through FEED, the will be more opportunity for cryogenic hose technology to be tested and commercialized.

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Overall Size and Scale. Separate from equipment limitations, the FLNG hull will have overall size and scale boundaries that impose design considerations during project development. Most FLNG concepts are based on a converted carrier or customized monohull (single hull often with barge-like dimensions), but alternate hull shapes and unique concepts can be considered. Like most complex issues, the overall size and scale limitations are a function of both technical and commercial considerations.

For a steel monohull, practical size limits are set by what can be efficiently fabricated at an established shipyard such as Hyundai (HHI), Samsung (SHI), and Daewoo (DSME). Although it may seem advantageous to size the hull to the dimensions of a comparable onshore LNG train, a steel monohull cannot be technically or commercially manufactured at such a scale. As a result, an FLNG hull must conform to today’s practical limits without undue impact to the shipyards commercial strategy and backlog. Based on shipyards used to building barges, containerships, oil tankers, and LNG carriers, hull dimensions of 475m x 90m are representative of about the maximum practical size that can be fabricated today. In order to provide some flexibility in selecting the fabrication locations, the adopted hull dimensions are likely to be smaller than the absolute maximum. For a single floating hull, additional width could be obtained by a concrete hull design or using an alternate hull form.

Concrete hulls are built in unique graving docks that are customized for the actual hull dimensions. Alternate hull forms allow for more flexibility in size and scale, but these types of hulls may not be the most efficient or cost-effective design for fabrication in today’s market. Alternate hull forms may include extrapolations of existing technology, new concepts, or previously patented designs that have yet to be fabricated. Future extrapolation of existing technology includes adaptations of the largest semi-submersible hull designs for small to mid scale FLNG (e.g. GVA 40000 for Thunderhorse [10], GVA 27000 for Atlantis, or other competitive designs) or non-ship shaped hulls such as those proposed by Sevan Marine [11]. Examples of patented designs allow for a unique arrangement of hulls to obtain the desired topsides deck area and cryogenic storage [12]; other designs can encompass any shape imaginable to offer either a technical or execution benefit over a monohull. For new designs and configurations, a more stringent risk analysis of suitable equipment, process technology, and execution strategies will apply.

Figure 3. A Potential Extension of Semi-Submersible Technology and Experience Image Courtesy of GVA Consultants AB

Layout and Modularization Philosophy. Even a perfectly engineered set of process flow

diagrams (PFDs), piping and instrumentation diagrams (PIDs), technical specifications and equipment data sheets is only a theoretical representation of a reliable process plant. Through the

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integration of process and equipment design, a proper topsides layout and modularization philosophy allows for the entire facility to be designed for purchase, fabrication, integration, and operation. Although there are many paths and strategies in developing a layout and modularization philosophy to reduce project execution risk, there are sensible technical limits and boundaries to what is suitable for FLNG projects.

The layout and modularization philosophy is an integral part of the project execution plan, as it is senseless to design the topsides in a way that cannot be efficiently fabricated or integrated. Generally the ‘average’ FLNG topsides will be significantly more complex and heavier than the ‘average’ Oil and Gas FPSO and the nature of the processes introduce additional risk factors not found on a conventional FPSO. Based on the total FLNG production capacity (size and scale of LNG, LPG, and condensate processing), one can select a large or small scale module strategy to suit a particular opportunity. Layout and modularization of the FLNG topsides is not simply chopping up a conventional LNG train plot plan to fixed subsections for outsourced fabrication. This process requires applying proven FPSO topsides engineering philosophies to produce an arrangement of equipment and systems that optimize the number and complexity of interfaces during fabrication and integration of the facility. Embedded in this process is the recognition that LNG systems require different safety risk analysis and operational requirements than conventional FPSOs. It is worth noting that similar layout and modularization philosophies are being developed and utilized for onshore LNG projects (e.g. Gorgon, Inpex, etc.) where site specific constraints provide the opportunity to benefit from making use of “offshore” design and construction practices.

A module can be conceptualized in many different forms on a sliding scale of complexity and weight: from a skid mounted piece of equipment, to a pre-assembled module weighing from several hundred to several thousand tonnes (te), to a complete process plant with all supporting utilities within an integrated structure weighing in excess of ten thousand tonnes. Based on historical experience in the construction of offshore facilities, there is a trade-off between module weight, engineering workhours, and system complexity versus the inter-module hook-up and commissioning workhours saved from the ability to pre-commission entire systems at the fabrication yard. For FPSO facilities, there are the additional considerations of available lifting equipment needed to install the prefabricated modules onto the FPSO hull at the integration yard. These considerations are equally applicable to FLNG topsides and the limitations on the size and weight of individual FLNG modules is a function of the fabrication capacity of the module yard and the lifting capability to install the module on the FLNG hull.

For FLNG, the largest system that could be designed within one module is the liquefaction unit, which includes the equipment for the refrigeration system. For small train sizes (e.g. 1 Mt/a and below), this unit is easily modularized based on the total weight and equipment size; with a small scale modularization philosophy, multiple trains can be designed to meet the desired capacity. To take advantage of potential economies of scale, larger trains in larger modules can be considered. Adopting larger modules will eventually face a significant obstacle: the limits on the size and weight of a module that can be installed on the FLNG hull at the integration yard. Currently, the lifting capacity of individual floating sheerlegs (i.e. cranes) that are readily available to major fabricators is about 2,500te. Modules weighing more that 2,500te can be installed by using two sheerlegs in tandem, or by mobilizing larger, less readily available and more costly floating cranes with practicable lifting capacities of up to 10,000 – 12,000te. Alternatively, jacking and skidding techniques, which do not use traditional cranes, can be used to install topsides modules. For each FLNG opportunity, the relative cost and schedule benefits of adopting small or

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large module philosophies and the compromises involved in splitting the liquefaction system among multiple modules will need to be assessed on a case by case basis for FLNG..

In addition to the topsides modularization issues, there are other execution issues and risks regarding fabrication and integration expertise. These issues include not only the technical capabilities of design and fabrication companies, but the risks associated with building consortia or joint ventures to cover the entire FLNG scope of supply. While the challenges and opportunities in building an FLNG EPC execution strategy is the subject of a future paper, the issue of contractor and fabricator competence is addressed in the commercial section. In summary, while a modularization strategy can be developed to design FLNG topsides of any capacity, there are technical and commercial limits in turning a plan into reality.

Allowable Limits on the Movements of an FLNG Hull. A key consideration in the specification and design of any of the equipment described in this technical section is the motion characteristics of the hull. Hull motions will affect the results of the process technology selection study as well as the refrigerant compressor drivers, LNG storage tanks, cargo offloading systems, module structural steel, and nearly every single piece of topsides equipment. However, determining the required performance of the hull is an iterative process involving the equipment (process and structural) design and hull configuration design; within this process, the hull is “tuned” to optimize its responses to the operating environment and to best suit any operational limitations of process systems and equipment. For a variety of FLNG configurations, can we determine such limits of allowable motion of the hull?

Absorption and distillation column performance is significantly affected by static tilt and roll. The AGRU contains absorber and regenerator columns and the fractionation unit could contain several distillation columns depending on the feed gas composition, refrigerant requirements, and the required level of product separation and purity. In the AGRU, the feed gas is treated to remove CO2 to a specified maximum of 50 ppm as high concentrations of CO2 can freeze at cryogenic temperatures leading to plugging of equipment such as the MCHE. This condition results in a reduced production rate and eventually requires a shutdown and thawing of the cold box or other cryogenic equipment [13]. Although the technology for deep CO2 removal is easily achieved onshore, CO2 spikes or breakthrough can occur with maldistribution of gas and liquid based on hull motions. Since the AGRU is not designed to recycle off-spec gas, meeting the strict 50 ppm specification is critical to the reliability of the LNG train.

Due to the gravitational nature of vapor/liquid mixing in columns, static tilt has a more significant effect on the process performance than an equal degree of roll or pitch motion. Static tilt allows the opportunity for vapor bypass and the maldistribution of liquid. Due to an unequal distribution of liquid and the limitations on column height, this effect is compounded with increasing static tilt. A process column could be analyzed for operation under varying degrees of permanent or dynamic inclination (e.g. from 0 to 90 degrees), but limitations of the human equilibrium would govern long before operations during excessive pitch and roll. Although pitch and roll motion also affect the column functionality, the periodic nature of the motion has a potential cancellation effect and some studies support that slight periodic roll may improve the mixing in packed columns. Designing a column for multiple beds of limited depth and the design of specialized liquid distributors and outlet collectors are mitigation measures for combating the effects of motion. Similar to the AGRU equipment, the fractionation columns will experience the same operational conditions, although the products can be recycled in order to meet the design specifications. Knowing the potential effect of tilt and roll on process columns, what can be done with the hull?

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Theoretically, if a hull shape was excessively large in each dimension (length, width, and depth), the hull would have the stiffness to mitigate the cumulative effects of wind, wave, and current. With the known dimensional limitations of monohulls, this stiffness has a practical limit and the hull will respond based on the metocean data at the intended location. A key issue in determining hull motions is the design iteration among the equipment, structural steel, and hull. This iterative process involves definition of equipment distribution and layout, definition of topsides mass distribution, and hull design and analysis. If the hull motions analysis results are initially found to be excessive for the selected equipment, then the design process is recycled to achieve the desired results based on changing the equipment, weight distribution, or hull dimensions, details, or form. Each hull will respond differently based on the actual static and dynamic forces: model tests are used to verify hull designs when subjected to expected wind and wave patterns. As a result, the notion of allowable limits on hull motions are grounded in the familiar issues of equipment selection and performance, balanced with other factors such as the human equilibrium and personnel safety in the accommodation area or while working within the LNG train.

Contrary to other defined boundaries or limitations of technology, there is not a fixed limit on the allowable movement of the hull because the key issue is the operation of the process and utility equipment at the intended location. Maximum roll and pitch motions of 2 degrees may be expected for an opportunity such as the Belanak FPSO [14] while motions of 6 degrees or more may be required for another location to meet overall availability targets. Predictable but infrequent events such as hurricanes and cyclones must be considered to protect the asset, but should not be considered an operational condition or part of an unrealistic process availability target. Overall unit availability is a function of what can be mitigated by design and controls as the FLNG is designed for the expected conditions for a specified design life. While motion limits and criteria such as those for personnel safety or even seasickness can be determined, the key for FLNG is to design the hull response to allow for a high process and equipment availability and a realistic overall availability based on the long term operational requirements and the safety of the personnel on board.

Summary – Technical Risks. This section has addressed only a few of the technical risks that have limitations or boundaries that must be viewed differently for FLNG than for onshore LNG or FPSO projects. Issues like flexible cryogenic transfer, partially loaded LNG tanks, MCHE operation and maintenance, and stringent gas processing specifications are some of the many technical risks for offshore LNG. Regardless of the technical issue, each risk can be evaluated on a scale to assess if the element will bend without breaking for the intended service.

Commercial Risks and Boundaries

Commercial risks can be issues that are either truly economic in nature or those that are entwined with technical or execution elements. Since a thorough FLNG economic evaluation is beyond the scope of this paper, this section will address a subset of the commercial issues that influence project execution or the FLNG opportunity development cycle. These issues include contractor and fabricator competence, project execution strategies, and comparisons of FLNG with onshore LNG.

Contractor and Fabricator Competence. Apart from developing a site-specific technical solution, one of the most interesting aspects of FLNG is assembling a plan to integrate the elements of design, procurement, delivery, fabrication, integration, installation, commissioning, and operations. Central to this theme of technical and commercial integration is to assemble a

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team of contractors, suppliers, and fabricators that bring the technology, experience, and management to deliver the expected results. In the market to develop the early FLNG projects, there appears to be a large number of companies that offer technologies for offshore liquefaction; since a relatively limited number of companies are involved in onshore LNG projects, assembling the right team of companies requires an evaluation of contractor and fabricator competence. Accurately assessing this competence is a key to limiting execution risk.

There is little doubt that experienced companies that design and construct FPSOs and/or onshore LNG projects have the potential to support FLNG. However, there isn’t a single company that has the capability to develop the entire solution without entering partnerships, alliances, or subcontracts to account for the total scope of work. As a result, a practical limitation may exist when assembling the number of consortium members that are required to fully develop an FLNG project. Execution risk will increase with the introduction of new players – those who have not worked on LNG plants or those who don’t bring exceptional technology or project management to the table. Conversely, companies that have experience with both offshore projects and onshore liquefaction have an advantage over consortia that must develop or acquire similar experience.

Apart from historical experience, current onshore LNG project experience has resulted in developing the know-how to design and fabricate modular liquefaction. Although not subject to the layout and operational constraints for offshore operation, the design contractor and module fabricator experience from remote onshore projects such as NWS, Pluto, Gorgon, and Inpex LNG will benefit the development of the early FLNG projects. All of the companies that supply services for these projects will earn valuable experience that apply to FLNG. In addition to the companies involved in these modular projects, it is important to continually review the contractors, suppliers, and technology providers that have supported the LNG industry over its entire lifespan.

Although it is important to manage the design, construction, and commissioning phases of an offshore project, the operation of the LNG train is the most important issue after final installation. Supplier inexperience (especially offshore or cryogenic) will result in additional technical and execution risk affecting the cost of delivery, schedule adherence, or long term operation. Areas of importance include hull and mooring design, turrets, compressors and drivers, liquefaction process technology, module fabrication and integration, LNG commissioning experience, and riser design and installation. While alliances, consortiums, or subcontracts are a necessary part of large scale project execution, assembling the right team of contractors, technology providers, fabricators, and shipbuilders is critical to reducing execution risk and assuring long term operational success.

Project Execution Strategies. The successes in offshore engineering (not just FPSOs) are based on combining successful leadership and technical experience with individuals who have a passion for challenging projects. These types of projects require superior execution planning, formulated early in the project development phase, in order to assure successful fabrication, integration, and operation. When reviewing the lessons learned from successful FPSO projects, interface management and technical oversight are identified as key elements of a successful project execution strategy [2].

Interface management is required for projects where multiple designers, contractors, and fabricators execute interconnecting scopes of work for an overall integrated project. Interfaces can be technical (information shared across scope boundaries) or physical (e.g. turret to hull connectivity), but the management of these interfaces is crucial to maintain a technically sound project while limiting workhour escalation or schedule creep. Although an experienced design and

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engineering contractor could manage an extraordinary number of interfaces, limiting the number of designers, subcontractors, fabricators, and suppliers can reduce the potential number of interface issues.

Technical oversight is a natural complement to a high quality interface management program. For unique challenges such as FLNG, the overall design is composed of many subsystems and components designed by different parties such as main the EPC contractor, technology and equipment providers, fabricators, shipbuilders, etc. Independent of the interfaces among the systems and physical points of contact, the technical integrity of the overall FLNG must be maintained during execution in multiple locations and time zones. Under a technical integrity program, individual owners are assigned to be responsible for a single subsystem and its components with a keen understanding of the interfaces within their technical scope. The limits of such a technical integrity program are a function of the size and scale of project as well as the number of subsystems, contractors, technology, and equipment providers, and subcontractors that are part of the execution plan.

In summary, proper division of the scope of work and the optimal use of contractors, technology and equipment providers, and subcontractors will limit the number of unnecessary interfaces and allow for a better opportunity to manage the overall technical integrity. For example, it is advantageous to minimize the number of module fabrication yards in order to minimize physical interface risk. Consequently, subdividing the topsides scope among many fabricators, while using an independent integration yard, would increase the overall execution risk.

Commercial Comparisons of FLNG vs. Onshore LNG. Similar to a desire to compare the economics of one LNG project versus another (i.e. misunderstanding of NALPACE), it is a natural compulsion to compare the estimated CAPEX of FLNG versus historical onshore LNG costs using US$ per ton per year of LNG. Accepting that there are limitations in the data available to make such a comparison (no operating FLNG projects, differences in FLNG configurations, and variance among site-specific onshore LNG costs), there is a fundamental misunderstanding of the ability to compare the cost of liquefaction offshore versus onshore.

In our focus to develop technically feasible designs for FLNG, one must remember that liquefaction is only one element of the offshore LNG value chain [15]. The true cost is the entire cost along the natural gas supply chain of turning a natural gas asset into a usable commodity for a distant market. While there are similar elements in both the onshore and offshore LNG value chains, one cannot compare the cost of a FLNG vessel to an existing onshore LNG plant with unique site-specific economic drivers.

The cost of the FLNG value chain must include all subsea and riser costs (e.g. from the pipeline end manifold [PLEM] to the FLNG turret) as well as the modified transportation, regasification (either onshore or offshore), and end user tie-in costs. As a result, the only fair cost comparison is to compare the floating LNG value chain with a comparable LNG value chain utilizing the nearest viable onshore location. The comparison for onshore LNG would include pipeline costs from the PLEM to an onshore facility, the onshore LNG plant, the marine facilities, and the transportation and regasification to the same tie-in location. In an extreme example, one could determine that the economics of an extremely remote field in ultra deep water would favor FLNG simply due to the cost of a subsea pipeline to the nearest point of land. Therefore, the economics of the FLNG vessel should not be compared to the cost of an onshore LNG train, but

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as one element in a comprehensive analysis to determine the best monetization plan for the reservoir.

Figure 4. The Traditional Onshore LNG Value Chain

Figure 5. The Offshore LNG Value Chain

An interesting economic scenario exists with offshore reservoirs that yield multiple products (oil, gas, and natural gas liquids [NGLs]). In this scenario, the reservoir could be serviced by more than one offshore facility (e.g. an FPSO exporting stabilized crude oil and an FLNG facility treating and liquefying associated gas to export LNG). Such scenarios add to the complexity of commercial evaluation and cost comparisons. FLNG could be viewed as a proposition to properly utilize associated gas that would otherwise be reinjected while supporting highly profitable oil production. With additional NGLs, FLNG economics could be driven by the sale of LPG and condensate, which demands a higher price per BTU than LNG; LNG sales would recover the cost of the development and NGLs would make the profits. Lastly, there are cases where FLNG may be the only means of monetizing a reservoir that would otherwise remain undeveloped. In all cases, comparing offshore versus onshore liquefaction requires looking at the entire chain from the asset to the customers.

Other Commercial Risks. The overall availability of FLNG is one of the most difficult parameters to analyze. Overall availability covers more than simply the process plant, but would include the operation of every system on the vessel that could affect the liquefaction and offloading by carrier. Onshore LNG plants, once in steady state operation, are highly reliable; can this high reliability translate to offshore operation?

The biggest influence on the overall availability is the metocean conditions at a particular location. The topsides and hull designers utilize metocean data in the design and selection of the process systems and equipment as well as in the design of the FLNG topsides and hull. The topsides, utilities, and offloading system will each have an “availability” based on the calculated operational window based on this site specific data. Practically, you may not be able to “design around” site specific extreme weather events by adding additional equipment because safety considerations for personnel and equipment will dictate the plant shutdown and duration. Consequently, the overall availability must be consistent with the design philosophy for FLNG of bending without breaking.

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In the early years of considering FLNG, it was perceived that one could attain the availability of comparable onshore plants (e.g. above 92%). Results from onshore LNG projects were a function of issues that were mostly under the control of the design contractor and plant operators. As a result, onshore plant availability was primarily a function of the reliability of feed gas supply, process machinery and controls, and scheduled maintenance.

For FLNG, the biggest risk to availability is unreliable weather, which is under no ones control. Regardless of the severity of “typical” ocean conditions, the hull and topsides systems and equipment will be designed to project specific motion criteria (heave, roll, and pitch) in an iterative way. A high availability target will tend to make such motion criteria more onerous for the design of systems and equipment or will impose greater challenges for the hull designer in providing a low response hull configuration. Since availability is mathematically determined based on the system design and metocean data, the stakeholders should share the availability risk based on a realistic balance of expected hull motion and topsides availability. In addition, extreme and unpredictable weather events such as cyclones and hurricanes should be considered for asset integrity and process startup/shutdown only.

Summary – Commercial Risks. The evaluation of the commercial risks of FLNG and the entire offshore LNG value chain is a challenging task. The LNG industry was developed based on contracted long term supply from reliable plants to meet a predictable demand. Extrapolating this model for offshore LNG adds additional commercial risks that must be factored into an overall evaluation.

CONCLUSION

The design and execution issues for a first of a kind project are new; as a result, there is more technical and execution risk for FLNG than for well established concepts. Even for well established businesses, we have learned the lessons that all projects have site specific elements that make them unique. To highlight this experience, we’re reminded of the following principles:

• NALPACE – Not all LNG plants are created equal;

• FANG – FPSOs are not generic; and

• FICAS – FLNG is customized and site-specific

Reflecting back on history, the development of the FLNG business is similar to the experience during the tumultuous 1970s where project execution required the engagement of multiple parties and new technologies in order to assemble a workable solution. When history is written about FLNG projects, will the story appear to sound familiar or will we interpret the path to be truly unique?

In some ways, it seems as if we are “back to the future” or back to the development of the FPSO and LNG businesses of the 1970s. Presently, we feel that we understand the issues to make FLNG work, but we must apply our experience in a new way and through a different embodiment to create successful FLNG projects. In a different interpretation, it seems that “everything has changed” in this new arena, which would require breaking down a complex solution such as FLNG into a “top-down” versus “bottom-up” way of thinking. From the “top-down” perspective, we look at new configurations, technologies, risk management strategies, and execution scenarios in order to develop first-of-a-kind projects. From the “bottom-up” perspective,

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we look at all our previous experience, technical details, lessons learned (LNG and FPSO), and execution interfaces that must be managed to make a new concept work.

The “top-down vs. bottom-up” process has been followed in both LNG and FPSO markets with great success. A key success factor during project development is the evaluation of risk, which includes the evaluation of technologies that will “bend without breaking”. With due diligence, these successes can be repeated via a proper and intelligent understanding of the limits and boundaries of FLNG technical and commercial issues.

REFERENCES CITED

1. Risk definitions from Merriam-Webster online, Cambridge Dictionaries Online, and www.dictionary.com.

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3. H. Kotzot, C. Durr, D. Coyle, C. Caswell, KBR, LNG Liquefaction – Not All Plants Are Created Equal, LNG 15, 24-27 April, 2007.

4. C. Mole, WorleyParsons Outlines Modular Path to FLNG Project Planning and Execution, LNG Journal, November/December 2009.

5. M. Roberts, J. Brofenbrenner, D. Graham, W. Kennington, Air Products and Chemicals, Inc., Process Design Solutions for Offshore Liquefaction, GasTech 2009, 25-28 May, 2009.

6. Design and Construction of Liquefaction Plants, Fundamentals of Baseload LNG: Markets, Technology, Economics, sponsored by the Gas Technology Institute, 16-20 November, 2009.

7. W. de Ruyter, S. Pellegrino, and H. Cariou, The Sanha LPG FPSO, 2005 Offshore Technology Conference, 2-5 May, 2005.

8. R. Le Devehat, FMC Technologies SA, Safety Technologies in Offshore LNG Offloading, FLNG 2008 Conference, 20-21 February 2008 and brochure: Connection Assist (Targeting) System for Use with Marine Loading Arms, by FMC Energy Systems, August 2004.

9. J.B. Stone, M.E. Ehrhardt, A.B. Johnston, P. Rischmüller, and S. Nusser, ExxonMobil, Offshore LNG Loading Problem Solved, GasTech2000, 14-17 November, 2000.

10. Online brochures from GVA Consultants, Gothenburg, Sweden: www.gvac.se

11. K. Syvertsen, Sevan Marine, Significant Benefits with a Cylindrical Hull for FLNG Applications, FLNG 2008 Conference, 20-21 February 2008.

12. US Patent 6,125,780, J. Sweetman, G. Gu, and D. Garrett, Mobil Oil Corporation, Floating Barge-Platform and Method of Assembly, 03 October, 2000.

13. T. Katz, G. Modes, and V Giesen, Seasick? How Many Times Can You Afford to Clean Up the Cold Box? by BASF SE, presented for GPA Europe Offshore Processing and Knowledge Session, 19 February 2009.

14. I. Ramshaw and M. Wilkes, ConocoPhillips, The Layout Challenges of Large Scale Floating LNG, GasTech 2009, 25-28 May, 2009.

15. C. Durr, C. Caswell, and H. Kotzot, KBR, LNG Technology for the Commercially Minded – The Next Chapter, GasTech 2008, 10-13 March, 2008.