Qualitative comparison of the efficiency and complexity of gas liquefaction process technologies proposed for offshore deployment.

Liquefied natural gas floating production, storage, and offloading (LNG FPSO) has been the focus of R&D since the 1980s, but in 2008 took a step toward deployment with the commitment by FLEX LNG Ltd. to construct vessels for service offshore Nigeria and Papua New Guinea.

Breaking new ground

Samsung Heavy Industries Co. is the main engineering contractor for the LNG Producer vessels. The first vessel, LNGP 1, is under construction in South Korea, and long-lead compression equipment for the 1.7 million tons per annum (mtpa) LNG FPSO topsides plant is on order. Norway’s Kanfa Aragon was contracted in January 2009 to provide the topsides based around optimized dual nitrogen liquefaction process technology. The vessel, to be deployed offshore Nigeria, is scheduled for operations in 2012.

In mid-2008, Japan’s Inpex Corp. submitted a development plan to Indonesian authorities that included a 4.5 mtpa LNG FPSO option to develop its 10 Tcf Abadi field in the Masela block close to the border with Australia. Negotiations continue regarding a potentially costly Abadi LNG FPSO project, with the potentially less-expensive alternative of piping gas to a land-based liquefaction plant in Australia that is not acceptable to Indonesian authorities.

In April 2009, Norway’s Höegh LNG announced completion of its LNG FPSO front end engineering and design (FEED) project conducted in collaboration with CB&I Lummus for the topsides design and the liquefaction technology (i.e., the NicheLNG liquefaction process, which in February 2005 received American Bureau of Shipping approval in principle for use on an FPSO) and Daewoo Shipbuilding & Marine Engineering for the hull design. That nine-month FEED project followed a six-month pre-FEED completed by Höegh LNG in conjunction with Aker Yards and Lummus in March 2008 based around a Q-Flex size vessel. Annual production capacity for the FPSO was focused on 1.6 and 2.0 mtpa of LNG costed in the pre-FEED at between US $700 and $1,000 per metric ton of capacity along with 400,000 metric tons of natural gas liquids. Final investment decision for Hoegh LNG FPSO is pending, but a specific field development project has yet to be announced. Earliest deployment could be 2012.

In response to such developments, Shell, the company that has been most associated with evaluating potential LNG FPSO projects in the past 20 years, reaffirmed in 2008 its continued pursuit of LNG FPSO opportunities.

Shell is considering projects offshore Egypt, Iraq, and Australia for facilities in the 2- to 6-mtpa capacity range. In July, the company announced a tender for FEED and engineering procurement and construction contracts for a 3.5 mtpa capacity LNG FPSO, with a deck area of 1,476 ft by 246 ft (450 m by 75 m) to contain its proprietary liquefaction process technology.

With this renewed impetus, LNG FPSO technology and development issues are receiving attention from companies and governments holding stranded non-associated gas assets or wrestling with handling large volumes of associated gas in remote oilfield developments.

Risks, rewards

Challenges to LNG FPSO deployment include construction and operating costs, unexpected downtime, volatile LNG prices & demand, politics, and extreme weather, not to mention persuading investors that LNG FPSOs offer the best development alternative for stranded gas assets.

The difficult hurdles now are not likely to be only technical. Historically, there has been skepticism about the long-term value of facilities that sit over the horizon and can be removed at short notice. Many prefer land-based liquefaction plants and the greater contributions these can make to their broader industrial and social economies.

However, remote and dispersed gas assets are unlikely to justify the financial and environmental burdens that large, land-based liquefaction plants involve.

The closest vessel to an LNG FPSO in operation is the Sanha liquefied petroleum gas (LPG) FPSO operated by SBM Offshore for Chevron as part of a gas condensate field development offshore Angola. Commissioned in 2005 and built in Japan by IHI Ltd., it consists of six self-supporting prismatic-shaped tanks of low-temperature steel providing 135,000 cu m LPG storage. Process equipment includes depropanizer, liquefaction, and reliquefaction units integrated with the LPG process plant. An external turret moors the vessel and connects a flexible riser to the seabed.

The LPG offloading system includes both side-by-side and tandem alternatives. An aft thruster minimizes wave-induced vessel motion. LNG FPSOs will need to incorporate most of these features.

A different breed

Offshore natural gas liquefaction has different process requirements from LPG or traditional on-land, base-load liquefaction plants. Thermodynamic efficiency is the key technical process selection criterion for large onshore natural gas liquefiers. Hence, high-efficiency, pre-cooled mixed refrigerant (C3/MR) and optimized cascade (multiple refrigerant cycle) plants dominate onshore base-load liquefaction facilities. However, these technologies only make commercial sense for large-capacity (> 3 mtpa) LNG FPSOs and in many cases do not best satisfy key requirements of remote offshore environments. Three generic technology options are being progressed, including dual-mixed refrigerant (DMR), nitrogen single- and dual-expanders, and single-mixed refrigerant.

Russia’s first land-based LNG plant, Sakhalin II, delivered its first LNG in February 2009. The plant uses Shell’s DMR process, focused on efficiency over a wide range of local temperatures 86°F to -22°F (30°C to -30°C).

Increasing the proportion of propane creates a heavier refrigerant mix for the first cycle in summer, which cools gas to -40°F (-40°C), while adding ethane yields a lighter mix for winter, cooling gas to -85°F (-65°C). Traditional C3/MR pre-cooling cannot be adjusted this way and is best suited to large-scale plants in equatorial conditions.

Shell compacted its DMR technology, called Shell automated cool-down (SACD) to enable medium- to large-scale offshore operations. It involves refrigerant mixes lighter than propane, used to reduce the risk of liquid pools forming. SACD technology makes the cool-down process more efficient, placing less stress on the main cryogenic heat exchangers.

Unlike large-scale liquefaction processes that use either a mixed-refrigerant or pure-component cascaded refrigeration cycle, expander-cycle technologies use all gas (or mostly gas) refrigerants. Although less efficient, the expanders offer many benefits for small- to medium-scale offshore liquefaction. The working fluid in the expander refrigeration system is typically nitrogen.

Several technology providers have variations on single expander technology that improve efficiency by using two expanders (some with hydrocarbon gas, usually methane, in one expander), adding a pre-cooling cycle, or expanding a saturated LNG product in controlled stages. These are generally used in < 0.5 mtpa applications.

To achieve more than 1 mtpa capacity, most expander technologies require more than one train, which adds to the rotating equipment count.

FLEX LNG uses Kanfa Aragon’s dual nitrogen turbo-expander liquefaction technology for LNGP 1. NicheLNG replaces one nitrogen loop with a methane (process gas) loop, resulting in higher efficiency. Regardless of the refrigerant used, all dual-loop liquefaction technologies use dual expanders and multistage compressors and can achieve 89% to 92% energy efficiency, compared to the 80% to 85% efficiency of single nitrogen loops.

Single-mixed refrigerant (SMR) provides an intermediate solution. A single cycle offers a tradeoff between efficiency and simplicity, including use of tried and tested technology. SBM/Linde offers for 2013 delivery an LNG FPSO with SMR process technology, 2.5 mtpa production capacity, and 230,000 cu m storage capacity, consisting of 180,000 cu m LNG, 25,000 cu m LPG, and 25,000 cu m condensate. SBM/Linde completed a full FEED study of the LNG FPSO concept in September 2008, which suggested 15% to 25% efficiency gains on dual- and single-nitrogen expander plants. That leaves SMR technology nearly 5% less efficient than dual-cycle mixed-refrigerant plants. However, its single-train design offers substantial savings in terms of rotating equipment count and costs.

Feasibility, the future

Significant competition is expected among the LNG process technology providers over the next few years. The onus is very much on them to justify the comparative efficiencies, reliabilities, and advantages of their offerings.