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GL Noble Denton: Moving LNG offshore

12th August 2013

Principal LNG consultant at GL Noble Denton David Haynes talks exclusively to Oil & Gas Technology about the main drivers behind the global move towards FLNG, the technical and environmental obstacles when moving LNG from onshore to offshore and the future of this promising industry

Moving LNG offshore
David Haynes has been involved in 20-30 LNG projects, both liquefaction and importation onshore and, more recently, liquefaction and importation offshore

David Haynes is a chemical engineer and has been working in that area for the past 27 years, 17 of which in the LNG sector. He has been involved in 20-30 LNG projects, both liquefaction and importation onshore and, more recently, liquefaction and importation offshore.


Hayne’s role within GL Noble Denton is to be the company’s expert on LNG technology. The company’s offerings include concept visibility design, hazard and risk assessment, naval architecture, due diligence and any other basic services which the LNG industry requires.  


OGT: Could you please start by telling us which industry factors are driving the feasibility of upcoming FLNG projects?


David Haynes: In some ways the first of these is almost a negative driver. Onshore projects are becoming too difficult and too expensive to implement.


A lot of the projects are in extremely remote locations. Therefore, the idea of doing a floating LNG project in a shipyard in South Korea, for example, is very attractive as it gets companies around political issues, giving them more control over the project.


Another driver is where we’re actually finding the gas reserves. These are further and further offshore in deeper and deeper waters and this is starting to challenge the ability to tie that back into onshore infrastructure.


The oil and gas industry’s offshore sector, and in particular the FPSO market, has also been an essential building block to take FLNG off the ground. We have seen over the last 5-10 years some very large and complex oil and gas FPSOs that have huge topsides and are very similar to what we are looking at on an FLNG project.


I suppose that the final factor is related to the geopolitics of floating LNG. If something did go wrong you could actually tow it away, which would make going into some of the less politically attractive areas out there more of an option.


OGT: From a downstream point of view, what are the main challenges which global oil and gas companies in the FLNG business are facing?


DH: I think that the main challenge for FLNG is actually getting rid of the LNG, so the offloading process is where the main issues are going to be.


However, virtually all the floating, storage and regasification (FSRUs) units in the world are operating in very benign environments. It will only be when we see something like the offshore LNG Toscana project in Italy come on or when Prelude comes along that we will know a little bit more about transferring LNG into deepwater environments.


OGT: What factors come into play when downstream technology is moved from a static onshore environment to an unstable, rocking and motion-based offshore setting?


DH: Marinisation of equipment is reasonably understood because we do it on most oil and gas FPSOs. What we’re primarily concerned about is vapour-liquid interfaces, as we’re normally looking at some form of level control and when everything is moving around it’s very hard for us to get that running smoothly.


We’ve been looking at level control and oil and gas vapour-liquid separation on the front of the boat: primary separation; condensate stabilisation; gas processing – all of these have some form of vapour-liquid interface.


If we move into the liquefaction process, there are some processes, mostly those based on nitrogen but also something like the niche process, which is nitrogen-methane, that only use vapour phase refrigerants to avoid that problem, and this makes them more robust.


OGT: In terms of liquefaction, what are the most reliable refrigerants being considered for offshore projects?


DH: Nitrogen is obviously the ultimate thing since it’s not flammable or explosive; methane is not a desperately good refrigerant, but then again it is very hard to get it to explode; in some ways it’s actually better to opt for ethane, which is half-way between methane and propane. When analysing  inherent safety in an offshore process, we’re trying to avoid propane.


If we look at Prelude, Shell has opted for what is called the jewel-mixed refrigerant process, so it’s basically an MRMR rather than, say, a propane-based C3MR, which is the workhorse of the onshore LNG industry. They replace the C3 with another mixed refrigerant loop to lower the hazard potential of the first stage.


OGT: What challenges arise when laying out an LNG topside for a floating offshore facility?


DH: The first thing you need to consider is what is actually controlling the size of the vessel. Is that the LNG/LPG condensation storage that you have in the hull? Or is it the physical dimensions of the topside? That is going to limit you on what you can physically get on the boat, and we need to space things out as much as possible as we would do onshore to improve the survivability of the vessel should something go wrong.


The LNG industry has an extremely good safety record and usually things don’t go wrong. However, when we move from on to offshore, with limited space being a prevailing factor, for the crew there is no way to run away to. So we have to keep safety very much in the front of our minds when looking at the layout offshore and how much space we can afford to run the modules.


OGT: Some FLNG projects are set to operate for more than 20 years without dry docking, which makes reliable and long-life service equipment absolutely crucial. How will the industry work to overcome low maintenance requirements and such damaging barriers raised by the marine environment as salt and humidity?


DH: We are surely going to need maintenance but the procedures we’re looking at in terms of quality for FLNG are going to be very much similar to what we do onshore. Our issue is getting access because we can’t bring in a nice crane and have people moving around, it’s all got to be done in a marine environment, so there will be floating cranes, etc.


Insulation will be absolutely key to this and it should include such things as vapour barriers to stop humidity from getting into the system and damaging the outside of the pipework.


OGT: With FLNG putting a limit on the maximum distance between bits of kit on a given facility compared to onshore projects, will this not compromise the integrity of the facility in that if one part of it suffers an explosion, for instance, it will consequently endanger the entire structure? How can this be prevented?


DH: A lot of experimental work has been done, starting of course with the Piper Alpha disaster in the North Sea in 1988, looking at how big the separation distances need to be and how much congestion and complexity can be allowed in a module.


What we are worried about is the flame speed accelerating to such a level that it causes a type of explosion. Flames accelerate by going through congested areas, places with a lot of pipe work and equipment and cabling, so ideally what we want to do is space everything out, but obviously you can’t do that.


Therefore, the issues that we are looking at have a lot more to do with fire protection (e.g. insulation of structures) because what we don’t want to happen is for a structure to fail because then the module within that module might collapse.


The other thing that is being considered a lot more is water deluge. Water curtains have been shown to limit the impact of fire and explosions on other structures, but the problem with water curtains is that they have to be an active system, and therefore a back-up or second safety barrier to ever present passive systems.


OGT: Moving back to a global industry overview, which markets do you see as the most promising for this young industry?


DH: All of the projects at the moment are around Southeast Asia and this region is going to be key. Australia certainly is going to be very active purely because the cost of building onshore is so high. There we’ve got a whole range of projects, including Prelude, Bonaparte and Cash Maple, to name a few.


Africa will potentially also have a say in the dynamics of the FLNG industry as a lot of people are looking at smaller projects around the continent.


In the US, we’re ultimately looking at different ways of going through a permitting system as well as speed-to-market and cost-to-market.


Offshore West Africa or offshore the eastern coast of South America – the Campos Basin, for instance – provide another option for FLNG.


Overall, though, anywhere that has deepwater potential will likely lure the industry.


OGT: How do you see this young industry developing over the next decade?


DH: I think the industry is almost at a turning point. We can see the big majors and big projects moving forward, but that will probably remain fairly niche.



The issue is: will there be small FLNG? Will there be a lot more Petronas and Exmar units out there? Can they be done for a sensible price? If we can make that work and make it financeable, and most companies would like to do this on a lease basis like we do on the simpler oil and gas FPSOs, then the industry will grow dramatically. We are almost starting to see that with FSRUs.