4th May 2017
A previous GCA Focus article looked at the costs and cost drivers of Floating LNG (FLNG) projects, based on GCA’s database of public domain FLNG scope and cost information. This article uses the same dataset to look at the factors that drive the sizing of current FLNG projects, offers a simple “rule of thumb” first pass sizing approach, and looks at the reasons that sometimes drive project proponents to pursue an alternative sizing. Finally, we’ll have a look at field production rates and (F)LNG production capacities. Although only five FLNG projects have reached a Final Investment Decision (FID) so far (and only one is currently operating), over 25 projects have been proposed and discussed over the past five years - often in multiple configurations - providing a reasonable starting point for this analysis.
You may also be interested in other papers and articles from our Gas and LNG team:
Single Vessel FLNG: Resource Base and Capacity
The FLNG projects considered range from small capacity, inshore, barge-mounted units supplied by pipeline-specification gas, up to mega-scale, deep offshore vessels with full reservoir fluid processing and gas conditioning on board. The project gas supply ranges from dry, biogenic gas of 99.7% methane and zero Condensate/Gas Ratio (CGR) to rich gas with a CGR over 50 barrels per million standard cubic feet (Bbl/MMscf) and a range of inert components and contaminants. Proposed single-vessel capacities range from 0.5 million tonnes per annum (MTPA) LNG up to 7.5 MTPA. Figure 1 shows the average annual LNG production capacity (in MTPA) against the quoted field gas resources (in trillion cubic feet (Tcf)) for each of the project configurations in this study.
Figure 1: Single Vessel FLNG Capacity vs. Field Gas Resources
Figure 1 shows that although there is an evident trend, that there is no “right answer” to FLNG project sizing. There are a multitude of commercial, technical, and other considerations that drive scatter around the implied trend line. LNG market demand, gas composition, CGR, inerts content, well deliverability, and relative costs can all impact the targeted LNG offtake rate. However, excluding the “outliers” (more on them later), a linear best-fit trend line provides a quick first pass sizing approach. For ease of recall, we can express the line as “Capacity in MTPA = Resources (Tcf)/2 plus 1 MTPA”. GCA has developed a screening-level sizing (and costing) approach that allows for these considerations.
Onshore foundation (Phase 1) LNG projects, as a comparison, are unlikely to be sanctioned with field resources below 6 Tcf, but have plant layout space provided to allow for additional trains (sharing common utilities) such that the plants can ultimately develop tens of Tcf of field or play resources. These Phase 1 foundation projects, however, tend to be sized for a higher LNG production capacity (typically 2 MTPA higher than an FLNG sizing) for a given resource base than that suggested by the FLNG trend line in Figure 1.
FLNG project capacity is limited at the high end by the single-vessel liquefaction capacity which lies somewhere between 5 and 7.5 MTPA depending on gas composition. For larger fields, operators have considered multiple (phased) FLNG vessels, or have re-examined the fundamental onshore/offshore development concept. There is also a cluster of points around the 2 MTPA level and below, suggesting an emerging sweet spot where operator/supplier capability and development opportunities become financeable- leading to a large number of proposed projects.
That bothersome cloud of points off the Capacity/Resources trend line remains - the outliers. A closer look at the outliers highlights the flexibility and innovation in the FLNG concept.
What Drives the Outliers?
The outliers circled in Figure 1 are not an indication of “undersized” projects or cautious decision-making. Each of these projects had a good reason to be sized at the capacity shown at the time it was reported. Let’s look, in general terms, at the influences that these projects were responding to.
At the upper capacity limit are those projects where the field reserves have simply outgrown a single-vessel FLNG approach as field appraisal progressed. Given the gas quality and location of these fields, it would be challenging to put more liquefaction capacity on a single vessel and have it remain constructible. It may be possible to split the process and install greater liquefaction capacity on a single hull, however this would require that all gas gathering, preprocessing, and condensate stabilization be located on a second vessel, which would erode the benefits of FLNG over an onshore liquefaction plant.
A second category of outlier are the projects where the Phase 1 FLNG vessel is part of an overall risk management strategy. The first vessel unlocks the development and establishes cash flow. Early production information de-risks the reservoir. Follow-on phases benefit from reduced subsurface risks and (in theory anyway) reduced development costs of an identical second vessel. This approach also has an appeal where the scale of an LNG development may currently be market limited, rather than limited by the available field resources.
There are a couple of examples where the use of FLNG is in response to host government concerns or constraints. Small and mid-sized FLNG projects are faster to construct than an optimized full-scale onshore LNG project. A host government with urgent need of domestic gas production, or a need to generate early revenue from their natural resources, may prefer the quicker solution. There are also examples where the host government’s risk appetite differs from that of the project proponent. The government may wish to pursue development based on a modified “Proved” resource base, while the operator may be comfortable with a “Proved + Probable” base at FID. The deployment (and re-deployment) flexibility provided by FLNG can offer a way forward.
The Floating Storage and Regasification (FSRU) market has seen the emergence of vessel suppliers who are willing to construct an FSRU on spec, in order to be able to offer a shorter delivery schedule to charterers. Other suppliers are willing to acquire the conversion tanker hull on spec, and offer rapid customization to the charterer’s needs. The FLNG industry is seeing a similar strategy, with one supplier currently offering FLNG conversions to their own Moss-type LNG carriers. These units are sized at around 2 MTPA but are also being considered for use at lower capacities. The relatively quick availability, and ease of financing of this solution has prompted commercial innovation around the concept. Project proponents are taking advantage of leasing these FLNG units to propose quick cycle projects with low capital requirements.
Production and Capacity
What annual average field production rate is needed to deliver the required MTPA of LNG delivery? Figure 2 shows field production rate vs. FLNG capacity, with a best fit trend line of 150 MMscfd per MTPA indicated. The scatter around the trend line in Figure 2 is driven by both non-technical considerations and technical aspects such as gas composition and process efficiency.
Figure 2: Field Production Rate and LNG Capacity
Some care is needed when using “capacity” data without a clear understanding of what the quoted capacity refers to. Are the capacities quoted annual averages, or peak design rates? Does the “LNG Production Capacity” refer to only the LNG production, or also include other sales streams such as LPG’s or condensates? Do the field production rates include only hydrocarbon gas, or also non-hydrocarbon components such as CO2 and Nitrogen? Figure 3 illustrates these issues, showing the wide range of values that can legitimately be termed as “capacity”. The data used in Figure 2 (as far as it is possible to verify from the public domain sources) are based on annual average LNG production capacity, and annual average field flowrate (including non-hydrocarbon components).
Figure 3: Capacity Considerations
Non-technical considerations affecting public domain information release could include commercial positioning or engineering caution. Design maturity can play a role, too, as early field production rate estimates are gradually refined and improved as the project progresses through front-end design. With projects of this scale (and innovation) project proponents tend to exercise strict control on information release - with a view to ensure that actual project performance meets or exceeds publically released targets.
Fields with higher inerts composition, rich gas, or high CGR would be expected to require a greater field production rate to deliver a given LNG rate. FLNG projects that process pre-treated, compressed, pipeline specification feed gas would be expected to consume less fuelgas than projects with greater pre-treatment requirements and so have lower processing losses. The various liquefaction processes themselves vary in efficiency, with a clear trade-off between process complexity (and topsides weight) and efficiency - again affecting the ratio of supply gas to LNG production.
Despite the limited number of FLNG projects that have progressed to Final Investment Decision (FID), the wide range of FLNG projects considered over the past years begins to provide an understanding of the drivers and limits to FLNG sizing.
Real life operational experience will be require to validate these front-end assumptions and demonstrate that the projects will meet or exceed their investment basis.
 Usual practice for public domain information is to quote Proved + Probable (2P or 2C) resources, however GCA cannot verify this and has not reviewed these resource numbers.
 Named after the company that designed them, the Norwegian company Moss Maritime, the Spherical IMO type B LNG tanks are spherical in shape. Most Moss type vessels have 4 or 5 tanks - Wikipedia.
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