GAS-TO-LIQUIDS TECHNOLOGY: Shell floating LNG plant, technology ready for project development

Alan Bliault
Shell International Exploration and Production

Thirty years after the concept was first mooted, the offshore industry is still waiting for its first offshore processing plant for LNG (liquefied natural gas). Advances in technology and changes in market conditions are now combining to create a compelling case for the floating LNG plant. The arguments in favor of the floating LNG (FLNG) plant are growing ever stronger as technical hurdles are surmounted and the economic climate swings to its advantage.

Environmental constraints - and the need to conserve future energy stocks - make offshore flaring and gas re-injection increasingly less attractive, while growth in the number of smaller, more remote offshore fields makes the laying of subsea pipelines a prohibitively expensive route to onshore processing.

At the same time, LNG has become the fastest growing sector of the world's gas market, particularly in the Far East, where Japan accounts for 60% of global LNG consumption, and increasingly in the US, where deregulation in the power generation industry is creating a gas supply deficit.

LNG projects have long been characterized by a strong interdependence between the prospect of medium-to-long-term sales prospects and the availability of an economically robust production concept. The idea of moving gas processing from onshore to offshore adds an exciting and highly flexible new dimension to this equation and also brings potential savings of up to 30% in the cost of developing some offshore projects.

Shell and others (notably Mobil, Woodside, BHP, Statoil, and Chevron/Texaco ) have been examining the options for an FLNG plant since the mid-1990s, while Japan's national oil company undertook earlier studies into the feasibility of this approach for offshore gas. Shared advantages of the various schemes have included:

Lower capital costs, compared to an LNG scheme based on offshore gas platforms, pipeline to shore, and an onshore plant with jetty facilities
Faster time to market due to the elimination of site preparation and concurrent construction of the hull and topsides modules, rather than having to wait for civil engineering and structural steelwork to be completed.

Ultimate prize

Throughout these studies, the ultimate prize has been not only a significant enhancement in the profitability of large gas fields, but also the "unlocking" of the many smaller and more marginal ones that have hitherto lacked an economic route to market.

At the same time, there have been common obstacles to overcome to maintain safe physical separation between parts of the gas processing train - particularly where large inventories of hydrocarbon refrigerants are involved - and the general issues of operating a complex process on what is essentially a moving platform, subject to the vagaries of wave and weather.

Offshore loading was also an issue in rougher environments, due to the lack of any proven cryogenic technology for allowing this to take place at very low temperatures (-162°C) involved. Shell's approach so far has been to focus on offshore gas fields in calmer environments, allowing the opportunity for LNG carriers to berth alongside and load from marinized LNG loading arms. Once the technology has been proven at such sites, extension to fields in more extreme conditions will be a realistic stepout.

Right from the start, Shell's investigation into the feasibility of a floating LNG plant has been driven by E&P considerations, with offshore associated gas being the original focus and the desire to minimize or eliminate offshore flaring, adding further impetus. The concept has subsequently been extended to include non-associated gas fields, particularly where an FLNG plant would provide a shorter line of supply to customers.

Refrigerant change

A major breakthrough came with the development of Shell's proprietary mixed refrigerant processes, which combine a low hydrocarbon inventory and equipment count with excellent efficiency. Here was a new approach that depended on neither potentially hazardous high-purity propane or lower efficiency nitrogen for the liquefaction process and was adaptable both for a small onshore package plant (for which it was originally intended) and for FLNG applications.

Two versions of this process have been examined and found suitable by the multi-disciplinary team developing Shell's FLNG proposition: a single mixed refrigerant (SMR) process, which is optimized for throughputs of around 2 million tons/yr, and a dual mixed refrigerant (DMR) alternative, which provides improved liquefaction efficiency and is suited to capacities up to - and potentially above - 4 million tons per yr.

Both variants share the same advantage of not requiring the initial fill and subsequent replenishment of relatively high-cost refrigerants to be produced onshore and shipped to the floating plant. By contrast, Shell processes are self-contained and generate their own refrigerants on the FLNG plant itself.

These two processing solutions are now at the heart of the Shell FLNG concept, which draws on a combination of extensive in-house expertise, not only in floating production, storage, and offloading systems (FPSOs), but also in LNG manufacturing and transport. The DMR liquefaction process itself is currently being engineered for construction through its selection for an onshore packaged LNG plant on the Sakhalin II development in Russia's Far East.

Asset needed now

Spurred by a request from one of Shell's operating units for a floating asset with which to develop a large offshore gas field, the project team developed a radical solution based on a rectangular barge. This barge is free to weathervane around an external turret mooring at the bow, which is also the entry point for the flexible risers.

The rectangular shape was chosen because it would be cheaper to manufacture, and because it was inherently better suited to enabling larger separation to be maintained between safe areas (such as accommodation) and the more hazardous areas such as fractionation and high-pressure risers.

The configuration of the topsides has been carefully designed to maximize safety by separating the accommodations at the stern from the process plant by placing the power generation facilities, which consist of gas turbine generators, in between. The LNG storage in prismatic tanks inside the barge is physically screened from the plant above by the heavily reinforced barge deck.

The flow sequence from the bow begins with the removal of condensates, followed by carbon dioxide, hydrogen sulfide, water, and mercury stripping. In the center of the barge, the liquefaction plant and fractionation columns, in which the refrigerant "cocktail" is produced, are physically separated to maximize safety, and also best-placed to avoid wave-induced movement of the barge. The processes have been shown to operate efficiently in roll motions of up to 2.5 degrees - conditions likely to be experienced for 99% of the time in those seas where the first FLNGs are most likely to be deployed.

Steel hull facility

While initial designs were based on a concrete structure, the project team has since proved the viability of a more conventional steel hull with similarly effective separation of processing and storage facilities. The choice of steel holds a number of intrinsic advantages in that it is both cheaper and easier to construct, and it is also the material most shipyards are already familiar with.

In overall size, the Shell FLNG barge is 70 meters wide, 30 meters deep, and between 300 meters and 390 meters in length - as big as a supertanker. It will be equipped with thrusters to enable the barge to face the prevailing wind and waves to minimize processing downtime during rough weather and maximize availability of the offloading berth.

LNG carriers are loaded while the carriers are moored alongside, which permits the use of conventional LNG loading arms. In practice, the barge orients itself to create a "safe haven" for an LNG carrier during approach and remains on station throughout the loading procedure.

Testing of concept

This approach was developed during three years of consultation with Shell International Trading and Shipping Company, and proven during a comprehensive series of computer simulations and a model test program in the Netherlands.

Other aspects of the FLNG concept were subjected to similarly rigorous testing against HSE standards and assessed against Shell's own risk assessment and project approval criteria. Three dimensional computer aided design models were used to assess the reliability, availability, and maintainability of the process equipment and utilities. Experts involved with Shell's research in the propagation of explosions and LNG spills were directly engaged in project development to ensure built-in safety at little additional cost.

Just where and when the launch of the world's first FLNG plant will take place depends on a number of factors, but it is most likely to be in an area of the world where proximity to an existing market with established import terminal facilities is combined with a less extreme offshore environment.

West Africa, the Caribbean, the Far East, and Australia all share similarly promising conditions for the first FLNG plant in terms of their mean wave heights. In the sea off the coast of Nigeria, for example, a 100-year storm would be expected to produce waves no higher than three and a half meters. Compare this to the North Sea, where the significant wave height is several magnitudes greater at 11-12 meters, and could be as high as 20 meters under storm conditions.

With an average design life of more than 20 years, and the ability to tow an FLNG barge from field to field, the economics of the LNG floater has already shown to be as good as those of an average oil project. The real potential for FLNG is to enable development of offshore gas fields in deeper water or remote locations.

Shell's gas reserves in the Atlantic basin could produce between 12-20 million tons of LNG a year from several locations, for individual project durations of 20 years. Much of this potential has been effectively marooned offshore until recently through lack of an established customer base. By contrast, an FLNG in the Timor Sea, for example, would have the large markets of Korea and Japan within reach and compete effectively against alternative supplies.

There are other options for FLNG off the Nigerian and Australian coasts, and Shell - in common with other producers - is exploring opportunities for developing the US market for LNG.

From 'if' to 'when'

At the present state of development, the technical barriers to FLNG deployment have been conquered, and the economic drivers are already in place: the whole concept has moved from "if" to "when." The answer to that question is likely to be revealed within the next 5-6 years, when we would hope to have the first FLNG in place. From that point on, further FLNG barges could be deployed in more rapid succession as construction moves into a production line status similar to that already seen with crude oil FPSOs.

In the meantime, development work continues to explore the potential for deploying an FLNG plant in deeper waters and harsher environments, and for further refinements to the basic concept in terms of alternative loading methods and higher processing throughputs.

The next challenge is to move through to execution of the first FLNG project, and preparations are already being laid for this by providing development studies to Shell operating units.