Liquefied gas: the offshore challenge


William S. Wayne, General Manager, Society of International Gas Tanker and Terminal Operators Ltd. (SIGTTO), London, UK




As General Manager of the Society of International Gas Tanker and Terminal Operators, (SIGTTO) the reader may wonder why I have been invited to pen this article. The answer is that, as a technical society representing the interests of its members, the Secretariat needs to understand the business of its members and to keep abreast with developments in the industry. Our position does give us rather a unique view of the industry and this article arises out of the response to a question often asked of the Secretariat ‘what is the next major technology challenge for the LPG/LNG industry?’

The ‘drivers’

Before addressing the issues and challenges of taking the LPG and LNG industry into the offshore environment, it is worth spending a little time understanding the drivers of why consider offshore, particularly as the drivers affecting import terminals are different from those for production plants.

For import terminals, the dr iver often comes down to permitting. This may range from a situation where it is not practically achievable – characterised by extreme local opposition, possibly coupled with an over-politicised permitting processes, to a position where, whilst probably achievable, the time (and cost) to do so is so uncertain as to render the project unattractive. Other reasons may be more fundamental, e.g. the availability of a suitable site.

For production plants, there are two distinct strands to the discussion – monetising of stranded gas reserves and development of far offshore reserves.

By ‘stranded gas’ I refer to reserves which, while they may be significant, are not deemed large enough to develop in a conventional manner, i.e. with a pipeline to a conventional onshore LNG plant and export facility. The issue for far offshore fields is the length, and hence cost, of the sub-sea pipeline back to shore to a suitable site for the plant. At some distance offshore, the cost of this comes to a level where it is more economic to do everything offshore. One only needs to look to the oil industry over the last few years where barely a month passes without reports of new record for depth of water in which drilling and offshore production takes place. There is one twist in this far-offshore production case. Conventional shore-based LNG plants are usually sited on a plot far larger than their initial requirement. They may initially start up with, say, two production trains, and later, a third or fourth train added. These additional trains may not need additional utilities provision or infrastructure (storage and export facilities) and hence come in at a significantly lower unit cost. For the floating plant offshore, this option for incremental expansion does not exist – major expansion has to be by way of a complete new floating plant.

Design considerations

From a process technology point of view, the offshore case starts from a point of re-packaging existing shore-based equipment for offshore use. The main considerations are that the equipment has to operate in a moving environment and be mounted on, what is effectively, a flexible foundation and work in a corrosive atmosphere. Such issues are familiar to those who have been involved in the development of floating offshore oil production facilities, but may come as bit of a surprise to those whose experience lies in building large liquefaction plants on massive concrete foundations.

This leads to one of the pre-requisites for successful offshore development, and that is a recognition of, and marriage between, the two key areas of expertise, the offshore oil industry and the liquefied gas processing industry.

The main hull dimensions are driven by two key factors. The first is the deck area requirements of the process, and the second is the storage requirements for product. For the offshore production case, the storage requirements may include LNG, Propane and Butane, with possibly some small storage space for refrigerant make-up, plus condensate and possibly for liquids needed to support well flow assurance. Additionally, there will be requirements for storage of fuel for black start and diesel fire pumps, water storage requirements etc.

Clearly, from these requirements, the hull for an offshore production facility is likely to tend towards the largest hull that can be built. Indeed, the final dimensions may well be limited to those which can be built in existing facilities without having to join hull sections in-water.

This has a knock-on effect on the design of the mooring system for the floating unit. Assuming a turret type scheme for these large units, the mechanical aspects will be an extrapolation of existing designs. There is a proven track record for high pressure gas swivel units, so that should not be an issue. There will be a debate regarding the relative merits of external versus internal turrets, but this issue is not unique to the liquefied gas developments. The consideration for the import floating facility is somewhat different; the basic factors to assess are the capacity of the vessel supplying the unit with LNG plus a reserve. The tricky bit is evaluating the reserve level. This needs to be considered against the likely probability and duration of interruption of supply of LNG due (a) to weather delays en route and (b) the case of the supply vessel arriving on schedule but being unable to berth because of bad weather. The consequences of an interruption of send-out also need to be factored into the discussion.

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