Breaking the offshore LNG stalemate
Growing demand may push the solution of remaining technical obstacles to offshore liquefaction.
LNGBreaking the offshore LNG stalemateMost technical obstacles to offshore liquefaction have already been overcome. Growing LNG demand may push industry and governments to conquer the remaining hurdles.Saeid Mokhatab, Contributing Editor, LNG, World Oil; and David Wood, David Wood & Associates, Lincoln, UK LNG on a floating production vessel has yet to be deployed, despite several studies and technology development demonstrating its technical feasibility. High costs and perceived risks, combined with a lack of enthusiasm from governments and operators, have inhibited its exploitation, even as increasing global demand for natural gas is supporting the rapid growth and diversification of worldwide LNG. Major international oil companies conducted most of the early research, development and feasibility studies, which consequently focused on deploying large-scale facilities to develop very large gas reserves. There are, however, very few appropriately sized gas fields in remote offshore regions available to the majors for such deployments. Companies only drill for gas close enough to shore that a pipeline is feasible. If a very large gas field (> 6 Tcf) were found farther from shore, the operator could never afford to float enough real estate to make the prospect economical, or, conversely, the field would take many decades to exploit�far exceeding the economic lifetime of the floater. Thus, just the right size of field (perhaps 1�3 Tcf) must be discovered as far away from shore and from markets as feasible, to compete with a pipeline-to-shore LNG facility. However, increasingly stringent no-flaring rules being introduced in many countries (e.g., Nigeria and Angola) may prompt some existing offshore producers of giant volatile oil and wet gas fields to aggregate gas from several such fields, and develop large-scale (i.e., with capacity greater than 4 million metric tons per year) floating liquefaction as an alternative to building and operating expensive gas re-injection facilities. Offshore gas liquefaction has moved closer to commercial viability as the value of LNG has increased during the past few years. This has increased interest in both onshore and offshore liquefaction. The realization of large, barge-mounted FPSO facilities for oil production and LPG production indicates that large, complex facilities for handling gas offshore can be deployed on a commercial and safe basis. Floating LNG regasification is on the scene already, in Energy Bridge and numerous gravity-based and floating storage and regasification units (FSRUs) planned for deployment in the Gulf of Mexico and offshore Italy. While regasification is a simpler technology, some of this technology will be transferable to offshore liquefaction. However, some hurdles must still be overcome, not all of which are technical. Geopolitics represents another formidable stumbling block. Countries that stand to gain the most from floating liquefaction plants, like Nigeria, often insist upon substantial local content in their manufacture, which is almost impossible to accommodate on a commercial basis. Most governments also prefer the guarantees of long-term deployment, local direct and indirect employment that an onshore facility provides. Conversely, in some regions, placing LNG production (or, in the case of the US, receiving) facilities a significant distance from shore could remove actual or perceived public safety risks compared with the onshore alternative. Similarly, environmental impacts become less onerous for offshore facilities. TECHNICAL CHALLENGES Feasibility studies for floating liquefaction facilities conducted by the major international companies date back to the late 1980s, with paper studies going back to the 1970s. David Wood was involved in evaluating late-1980s feasibility studies conducted by Mobil for deployment in the Persian Gulf and offshore Papua New Guinea. Shell also invested heavily in research and technical designs during the early and mid-1990s. None of these projects materialized because of unfavorable economics (high break-even LNG sales price) and high technical risk. The key technical challenges that a floating gas liquefaction facility will have to combat have been known for some time:1
Clearly, offshore gas liquefaction has different process requirements than traditional onshore baseload plants. While thermodynamic efficiency is the key process selection criterion for large onshore liquefiers, the high-efficiency mixed-refrigerant and optimized cascade plants that dominate onshore LNG installations are unlikely to meet the technical and safety needs of offshore facilities. The requirements of process simplicity, low weight and small footprint have drawn offshore liquefaction technology developers toward established onshore peak-shaving technology. Considering that all process technologies deal with the thermodynamic constraints imposed by natural gas compositions, technologies that best fit tested machinery are those most likely to succeed commercially. Key criteria that influence process selection and plant optimization for offshore liquefaction lead unavoidably to trade-offs. HISTORICAL PROGRESS Substantial work, backed up by experimental testing of offshore liquefaction designs, was first performed in the mid-1990s. Shell, with its Floating LNG (FLNG) and Floating Oil and Natural Gas (FONG) concepts for processing gas and associated gas, respectively, was one of the pioneering operators to invest in testing of the concept. 2 Foster Wheeler was one of the earliest facilities contractors involved in detailed feasibility studies, and one of the first to demonstrate a willingness to engineer such projects. 3 Onshore liquefaction is focused on high-capacity plants in the range of 4�8 million metric tons per year (mtpy). Such plants require a processing footprint well beyond what is achievable offshore. Realistic offshore process capacities are in the range of 1�3 Tcf, which is of less interest to large companies. 4 Some key issues were identified in the early studies. For one thing, the nature of an LNG process is such that significant power is required (about 50MW per million mtpy) to drive the compressors. The cryogenic processing conditions make severe demands on piping layouts in a more congested offshore processing configuration. LNG storage requires specialized containment systems with the tanks operating at continuously changing degrees of fill. Finally, LNG transfer from the FPSO to the shuttle carrier requires specialized loading equipment. BHP Billiton carried out an early study for potential deployment in the Bayu-Undan gas condensate field in the Timor Sea. 5 The envisioned GBS would have incorporated a conventional, cylindrical LNG storage tank of 170,000 m 3 alongside a 1.5-million-mtpy, improved nitrogen-cycle liquefaction train. The Bayu-Undan field was ultimately tied instead into the onshore Darwin, Australia, LNG facility operated by ConocoPhillips in 2005. A joint project by Chevron and other companies focused on the exploitation of marginal gas fields and showed that a compact plant could be developed using one of several liquefaction technologies. 6 It also demonstrated that LNG storage in the hull could use either a membrane system or a self-supporting design. In the late 1990s, Mobil developed a floating liquefaction plant design involving a large, square, concrete structure with a moon pool. Widely known as �the doughnut,� the design had inherent desirable stability and safety characteristics. 7 Black and Veitch and ABB Randall, in contemporaneous studies, identified a simplified liquefaction process appropriate for small-scale production. 8 In 2000, a European consortium of mainly French contractors led by Bouygues Offshore completed the Azure R&D project. The project focused on analytical and experimental work to demonstrate the integrity of the membrane containment system in its partially filled mode, when �sloshing� of the liquid contents places major forces upon the membrane structure. It sought to prove aspects of the control of an LNG transfer system, as well as develop the design for a novel concrete hull. In additional, steel hull designs for LNG FPSOs were developed, and topsides were laid out to meet safety and operability requirements. The work focused on small-scale and mid-scale design concepts for liquefaction plants. It also addressed issues relating to offshore FSRU reception terminals. 9 The objective was to demonstrate that a fully floating LNG chain, from well to distribution network, is a safe and viable proposal. For the liquefaction barge, two different scenarios were developed: 1. In Southeast Asia, a stand-alone gas field with a capacity of 3 million mtpy, based on a dual mixed-refrigerant process cycle 2. In West Africa, a single processing train with capacity of 1 million mtpy, based on a nitrogen expander cycle for the liquefaction of the associated gas from a deep-sea oil field. Fincantieri designed the floating receiving terminal located in southern Europe. The SN Technigaz regasification process was based on submerged combustion vaporizers with LNG storage capacity of 200,000 m3. Ship-to-ship transfers of LNG are now taking place in sheltered areas and are likely to become more routine. For example, as part of the commissioning of the Teeside GasPort facility in the UK in February 2007, a cargo was transferred from a conventional LNG carrier to an EnergyBridge regasification vessel in a parallel configuration within the sheltered area of Scapa Flow, Fig. 1.
Los Alamos National Laboratory has demonstrated the application of thermoacoustic refrigeration to small-scale gas liquefaction plants. The concept involves converting heat into sound wave energy, which is applied to highly pressurized helium contained in a network of welded steel pipes to refrigerate natural gas without any moving parts. A 1/40-scale prototype, with a projected liquefaction capacity of 500 gpd, has been built and tested in collaboration with Praxair, Inc. 10 The power source is a natural gas burner. Los Alamos continues to seek partners to assist with the final stage of development, which may be suitable for offshore deployment. In 2001, Shell developed several offshore LNG concepts. The most advanced was the Sunrise project offshore Northern Australia, which involved a 5-million-mtpy-capacity facility using Shell's dual-mixed refrigerant (DMR) liquefaction process to be deployed on a large barge (400 m x 70 m) with about 240,000 m3 (8.48 MMcf) of LNG storage and 85,000 m3 (3.00 MMcf) of condensate storage. Shell claimed the concept cost 40% less than a similar land-based project, mainly due to savings in the offshore facilities and the avoidance of a pipeline. The Australian government, some of the field partners�including ConocoPhillips�and potential customers, however, preferred a low-risk, land-based facility, and the offshore option was shelved. East Timor is now also pushing for the gas from the Greater Sunrise gas field to feed an onshore liquefaction plant in the country, following two agreements settled in February 2007. Under those agreements, Australia and East Timor will split the royalties from the field 50/50 and delay negotiations on a permanent maritime boundary for 50 years. There is still scope for an offshore solution to be justified on economic grounds, but politics seem likely to favor an onshore location. Shell evaluated the same concept as Sunrise for the Kudu field offshore Namibia, but did not follow through due to an appraisal well that downgraded the field's gas reserves. Further feasibility work was carried out by Statoil and Shell in the Gulf of Guinea, where there are several stranded wet gas fields, including the Statoil-operated Nnwa field and adjacent Shell-operated Doro field. The study, completed in late 2003, resulted in a basic FLNG plant design, but partners found development costs to be higher than anticipated and shelved the project. Moored in 1,300 m (4,265 ft) of water, the plant would have liquefied 600�1,300 MMcfd from Nnwa/Doro and other nearby fields. The concept would have also produced LPG and condensate. It featured a novel riser tower using cold water from ocean depths to pre-cool the gas before it reached the plant. Schedule for design and construction would have been four years. Statoil, in conjunction with Linde and Aker Kvaerner, has designed a liquefaction concept based on the mixed-fluid-cascade (MFC) process chosen for the Snøhvit facility, which is due to be commissioned in late 2007. Snøhvit was designed to be assembled on a barge in Spain for transport to Melkøya in northern Norway, so many �marinization� issues had to be addressed even though the project was not an offshore development. Statoil believes the MFC process can be used successfully for offshore gas liquefaction. Progress with an offshore liquefaction project in Nigeria is slow for a number of reasons, not least of which are political and security-related. The Nigerian government's strategy is to back onshore facilities that ensure a longer commitment with a facility ultimately ending up in state control and more local involvement in construction. ABB Lummus Global started working in 2003 to evolve a smaller scale of floating liquefaction plant that is economically viable with lower volumes, such as the associated gas at a large remote offshore oil development. Its system is viable for stranded gas volumes between 0.3 and 3 Tcf, and it estimated the total cost of a phase-one (dry gas only) liquefaction FPSO ready for operation at about $400 million. This includes three liquefaction trains, processing 225 MMcfd between them with storage for 135,000 m3 (4.77 MMcf) of LNG. The lowest feasible feed-gas supply rate for such a small vessel is about 50 MMcfd. ABB's �LNG alone� system has a dry weight of less than 6,000 t and would be about 100 m long. The size of the hull is determined by the storage capacity needed. The liquefaction process is based on the �dual turbo-expander cycle� developed and patented by ABB's Randall Gas Technologies division. Other recent studies have favored small offshore liquefaction operations in the range of 1�3 million mtpy, using a nitrogen cycle.11 However, by early 2007, no investment had yet been committed to developing an offshore liquefaction project. Nevertheless, this vast body of work suggests that there are few if any outstanding technical issues to prevent developments. Moreover, prevailing LNG prices worldwide above US $5/MMBtu make the break-even price for potential offshore developments more attractive than it has ever been. Despite capital costs now estimated to be comparable to onshore projects�which may appear misleadingly optimistic on an unrisked basis, especially for the �first of a kind� project�no developers have stepped forward. PROCESS TECHNOLOGIES Lifecycle assessment for offshore liquefaction includes the same process design issues as a land-based plant, with safety being paramount. Some recent design studies have considered mixed-refrigerant cycle technology including a propane pre-cooled cycle (C3MR)�the most common process used for baseload, onshore liquefaction plants�and a single-stage refrigeration cycle. 12 However, as previously discussed, for offshore liquefaction the technology selection criteria differ substantially from those for onshore facilities. Capital for the processing facilities is only a fraction of total project cost, so technology selection and process design must be considered in the context of full-cycle project economics. If process and plant design is based on location on an FPSO, this constrains the choice of liquefaction technology. REFRIGERATION CYCLES Three generic types of refrigeration cycle have been used for natural gas liquefaction: cascade, mixed-refrigerant and expander. Comparison is instructive both for development of the optimal process concept and in customizing specific designs. Optimized cascade. In this cycle, natural gas is cooled, condensed and sub-cooled in heat exchange with propane, ethylene (or ethane) and finally methane in three discrete stages. Each refrigerant circuit normally has three or four refrigerant expansion-compression stages. After compression, propane is condensed with cooling water or air, ethylene is condensed with evaporating propane, and methane is condensed with evaporating ethylene. Phillips' optimized cascade process (Fig. 2) is a modified and updated version of the simple process used in a pioneering Alaskan plant built in the 1960s. It has been used for the Atlantic LNG plant in Trinidad and for recently completed baseload plants in Egypt and Darwin, Australia, and is being applied in a plant under development in Equatorial Guinea. Train capacities up to 3.6 million t/yr have been constructed.
The cascade cycle requires less power than any other liquefaction cycle, mainly because the refrigerant flow is lower. It is also flexible in operation as each refrigerant circuit can be controlled separately. Specific power is low, but the plant is complex. Each refrigerant requires its own storage, which would need to be imported or a separate support vessel. The cascade cycle's main disadvantage is the high capital cost due to each refrigeration circuit's need for its own compressor�with associated suction drums and interstage coolers�and refrigerant storage. The large number of equipment items and the large plot space mean that this cycle is neither technically nor economically viable for offshore applications. Mixed refrigerant. The MR cycle employs a single mixed refrigerant composed of nitrogen and hydrocarbons in place of the cascade cycle's series of pure refrigerants. Various forms of MR have been used in baseload plants and in smaller-scale plants. The machinery configuration is simple, and the power requirement is usually only slightly higher than for a cascade cycle. The refrigerant composition is specified so that it evaporates over a temperature range similar to that of the natural gas being liquefied. This provides close matching of composite cooling and warming curves for the process gas and the refrigerant, which results in a more efficient thermodynamic process requiring less power and smaller machinery. Even so, a typical MR system usually has a lower efficiency than a cascade cycle because refrigerant flow is high, with associated high thermodynamic losses. Furthermore, MR is more susceptible to changes in feed gas conditions, which may necessitate large design margins, further reducing efficiency. Mixed-refrigerant technology has been assessed for offshore liquefaction based on both single mixed-refrigerant and dual mixed-refrigerant (DMR) cycles.13 The latter consumes less power but is more complex. Shell concluded that single mixed refrigerant is suitable for smaller LNG production capacities of about 2 million mtpy, while the DMR cycle is suitable for capacities up to 5 million mtpy. 14 A DMR process forms part of Shell's onshore Sakhalin Island liquefaction project with a capacity of 4.8 million t/yr per train. Process configuration is similar to the propane pre-cooled stage in the cascade process, with the pre-cooling conducted by a mixed refrigerant (mostly ethane and propane) rather than pure propane, Fig. 3.
The DMR cycle minimizes hydrocarbon inventories compared with either the single mixed-refrigerant cycle or the C3MR cycle most commonly used onshore. It also gives lower flaring rates in the event of compressor trip and refrigerant blowoff. However, all MR cycles require storage of flammable hydrocarbons. This presents the significant challenge of maintaining an offshore safety case and requires significant deck space. Any cryogenic plant needs good distribution of two-phase streams into heat exchangers, particularly MR cycles. Failure to do so can reduce production capacity. Vessel movement can make good distribution difficult, which may limit MR applications to calm seas.15 Mixed refrigerant cycle plants are sensitive to changes in feed gas conditions, as they rely on small temperature differences between the composite cooling and warming streams to give reasonable process efficiencies. Onshore, long plant run times are normal and operators have time to optimize plant performance. Offshore, the opposite may be true. Refrigerant compositions need to be adapted for different feed-gas conditions, which can make performance optimization difficult. Dual mixed-refrigerant technology gives improved operability over single mixed-refrigerant cycles but is expensive for all but the largest facilities. Mixed refrigerant plants inevitably take longer to start up and stabilize than plants using other refrigerant cycles because of the need to blend the refrigerant mix precisely. This is a significant consideration in an environment where frequent startup and shutdown are to be expected. Turbo-expander. Turbo-expander refrigeration cycles are proven for cryogenic liquefaction including LNG peak-shaving and large-scale industrial gas liquefiers. Compression and work-expansion of a suitable fluid, typically nitrogen, generate refrigeration. The cycle gas is boosted in the brake end of the expander. While this process has been used to liquefy natural gas, it has low efficiency because a gas with uniform flowrate through the cycle cannot closely match the process gas' cooling requirements. Several variations on a single expander, reverse-Brayton cycle may improve efficiency significantly. 16 If only one stage of work expansion is used, power consumption is too high to justify except for small plants. Despite their low efficiency, expander cycles may have benefits that make them uniquely suited for offshore liquefaction. Initial offshore liquefaction designs considered pre-cooling by freon, but subsequent work has concentrated on the use of a second expander, Fig. 4. 17 Both expanders operate over the same pressure ratio but at different temperatures, or alternatively the �cold end� expander operates over a much larger pressure ratio. The two expanders are mounted on a common skid. They help the natural gas cool and condense at small temperature differences, so heat exchanger size increases but specific power decreases.
Mechanical refrigeration in a pre-cooling cycle, based on propane or other refrigerant, can reduce power consumption by cooling the feed gas and also chilling the cooling water, reducing the cycle compressor discharge temperature. However, increased plant complexity, reduced overall reliability and need for refrigerant storage are crucial disadvantages of pre-cooling offshore. A major benefit of nitrogen as the cycle fluid is that it is inherently safe. Storage of hazardous hydrocarbons is avoided, and there is no need for major hydrocarbon flaring if the refrigerant compressor trips. 18 Also, since there is no large storage and management system for flammable refrigerants, an expander cycle using N2 as the refrigerant can be extremely compact and flexible in terms of equipment positioning. 19 The expander cycle's smaller plot requirements facilitate the design of conformal cold boxes and modularized plant layout. Heat exchanger cores can be arranged as needed. Note that although the refrigerant circulation rate and main heat exchanger duty are significantly reduced in expander cycles, the required heat transfer surface area may not decrease because the refrigerant heat transfer coefficient is also much lower. Expanders are highly reliable on N2 consumption, and maintenance requirements are minimal. Nitrogen is maintained in the gaseous phase at all points of the refrigeration cycle, so distribution in the heat exchangers is not a concern, unlike other refrigeration cycles. As a result, plant performance is much less sensitive to vessel movement. The N2 expander design is flexible to changes in feed gas conditions and requires minimal operator intervention. Control of specific temperatures is not as important as with mixed refrigerant cycles, and the process is inherently more stable and robust. An important attribute is the ability to easily and quickly shut down in a safe and controlled manner and to start up quickly; a plant can be started from cold condition in less than 1 hr, unlike a mixed-refrigerant plant, which may require many hours to reach stable performance. Clearly, the double N2 expander cycle outperforms the C3MR, DMR and optimized cascade cycles for offshore deployment on the following key criteria:
Cold production in a turbo-expander process is largely independent of the process gas. The double N2 expander cycle does require more power than the more complex and thermodynamically efficient cycles, but the simplicity of the process and other critical factors still make it cheaper and safer. Power consumption of less than 0.5 kW-hr/kg is attainable, which translates, with a margin, to a requirement of about 200 MW for a 3-million-mtpy plant. This could be achieved by gas turbines that would consume about 12% of the feed gas as fuel. 20 The N2 cycle compressors account for most of the power requirement, which is the limiting factor on this option's plant capacity. BROADER CHALLENGES Several technical challenges face operators wishing to deploy floating gas liquefaction. LNG storage. Transport of LNG in marine carriers is well established, but partial fill conditions in an FLNG facility are the prevailing status, as the LNG is processed before offtake. This may result in sloshing, which is of particular concern in membrane tanks. Loss of containment must also be addressed when considering hull fabrication. A concrete hull provides benefits in the storage of cryogenic fluids, as it retains its structural integrity in contact with the LNG, but traditional steel ships are cheaper to build. A catastrophic tank failure could cause large-scale discharge of LNG into the sea. This would be followed by a rapid phase transition, which could cause serious structural damage to the offshore facility, including stability loss. Prevention of such an occurrence is a key safety requirement of offshore designs. Marine offloading of LNG cargoes. Offloading LNG in a marine environment requires bulk LNG carriers to approach and berth alongside a floating facility. This is routinely achieved for crude oil cargoes in various FPSO designs worldwide, but constitutes a major collision hazard for the offshore option. Also, the offloading dynamics must be designed to cope with relative motions between the floating structure and the ship in excess of those expected between the ship and a shore-based jetty. For offloading with a typical spread-moored configuration�such as might be found offshore West Africa�side-by-side offloading could be considered. The benefit of this is that LNG carriers typically load at midships, providing more flexibility. However, in less benign seas, weather vaning and tandem offloading are more appropriate. To facilitate this, some suppliers have designed flexible loading arms for LNG transfer between the production vessel and the tanker, such as SBM's soft-yoke mooring and offloading (SYMO) system. 21 Operation and maintenance. Operating and maintaining an offshore gas production and liquefaction facility of any design would require a substantial workforce. In some cases, offshore crews could reach 250 people. Accommodating, supplying and providing adequate emergency evacuation protection for such a large offshore population is a challenge and a major operating cost. Equipment densities. Some offshore liquefaction concepts have much higher equipment densities than those typically associated with onshore liquefaction plants. This substantially increases the potential for explosions in the event of an ignited gas release, as well as the potential severity of an explosion, which could escalate to total facility loss. Feed gas compositions. Designing FLNG facilities intended to receive feed gas from multiple fields would require additional gas conditioning facilities when field gas compositions differ. Gas processing equipment capable of handing well fluids with varying natural gas liquids (NGLs), carbon dioxide, water or hydrogen sulphide compositions will add to facility cost, equipment density and operational complexity. CONCLUSIONS The LNG industry must continue to protect its excellent safety record as existing plants age and novel processes and production schemes are commercialized. DMR and optimized cascade processes have large flammable refrigerant inventories, high refrigerant circulation rates through process lines and extensive overpressure potential and flare requirements. This makes these processes inherently less safe than N2 turbo-expander processes, whose refrigerant is inert. Therefore, turbo-expander cycles are better suited to offshore liquefaction facilities than the traditional processes. Turbo-expander processes also satisfy most of the critical technical selection criteria for offshore deployment. The only serious disadvantage of turbo-expander processes is their low efficiency compared with C3MR and optimized cascade cycles. The high efficiency of C3MR cycles is the result of 30 years of operation and refinement. For example, trains 1 and 2 of Oman LNG, operational since 2000, have a power requirement of 12.2 kW-day/t.22 In contrast, small-scale (i.e., about 125-t-capacity), single N2 turbo-expander cycles in operation have unit power requirements of about 20�40 kW-day/t, requiring in some cases more than three times the power of a baseload plant like Oman LNG. This lower efficiency limits turbo-expander processes' capacity to about 3 million mtpy, but it does not outweigh the option's advantages. Furthermore, expander-based processes are steadily improving with advances in plate-fin heat exchangers, turbo-machinery and process configuration. Expander cycles shift the key efficiency-determining element from the LNG heat exchanger to the expander. Dual expander processes for gas liquefaction (e.g., ABB Randall) are expected to achieve unit power requirements of about 15�20 kW-day/t. 23 For reasons of maximum project size and materiality, it will not be the major companies and large existing liquefaction operators that deploy FLNG first. Most of them are skeptical that it can deliver baseload-scale (4 million mtpy) plants on a commercial basis. Most of the non-process technical issues associated with offshore liquefaction (e.g., storage, offloading, reliability, uptime and safety) have now been satisfactorily solved. Political and governmental hurdles still remain. Many governments prefer a liquefaction plant to be built onshore to guarantee local employment and community benefits and long-term commitment. For specific projects, operators' challenge is to convince governments that FLNG may be the only way to develop stranded gas in the foreseeable future. Hydraulic design of the liquefaction process should consider the special constraints created by the marine environment and motion impacts on equipment. 24 Achieving low capital and operating costs over the full FLNG project cycle is the key factor now confronting investment decision makers. Current gas and LNG prices are high, and break-even costs for the latest offshore liquefaction designs are well below them and comparable with onshore plants of similar capacity. Time, technology and economics are therefore ripe for this innovative technical solution to stranded offshore gas to finally move off the drawing board.
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