The 2015 United Nations COP21 meeting in Paris saw world leaders finally commit to measures to limit global warming. Part of the solution, as an interim measure pending greater proliferation of renewable energy, is the increased use of natural gas as an alternative to coal and oil, in order to mitigate the ever-increasing atmospheric CO2 levels that are a major contributor to global warming.
Use of gas instead of coal for power generation, as an example, reduces CO2 emissions by 60%. This in part arises from the chemical characteristics of the fuels (a higher carbon content in coal) and in part from the significantly higher energy efficiency achieved by combined cycle gas turbine power generators when compared to their coal equivalents.
As well as carbon, there are other environmental drivers at play, including sulfur, nitrogen oxides and particulate emissions. By any environmental measure gas is superior to all other fossil fuels, which has led to increasing interest in its use as a transportation fuel for marine, trucking and railroad applications.
LNG Supply and Demand Growth
The world has approximately 6,600 Tcf of conventional gas reserves, adequate for a little over 50 years supply at the current global gas demand of 123 Tcf per year. Whilst pipeline transmission of gas is the norm, approximately 10% of global gas consumption is supplied by liquefied natural gas (LNG), which is transported to market at minus 161°C in specially designed ships. The liquefaction route, which reduces the gas volume by a factor of 600, is necessary for remote gas reserves where pipeline costs are prohibitive, or where geopolitical issues preclude security of pipeline supply.
A 2013 report from the US Geological Survey estimated that about 40% (2,611 Tcf) of the world’s proven reserves was effectively stranded, implying that monetization of those reserves would be through LNG. Of the total stranded gas, some 1,529 Tcf are located onshore and 1,082 Tcf offshore.
The offshore reserves have initiated a move to ship-based liquefaction plants (floating LNG, or FLNG), such as Shell’s giant floating liquefied natural gas facility, 'Prelude', the largest floating structure in the world.
LNG sales volumes have progressively risen to meet increasing demand for gas and LNG is forecast to meet the bulk of future increases in demand. Growth projections prompted a major commitment to new LNG plants; the period 2011 to 2015 saw final investment decisions on over 100 million tonnes per year (MMt/y) of new LNG capacity. Such is the level of new construction that excess LNG capacity is forecast until the early part of the next decade. Furthermore, the new builds have been characterized by increasing complexity, higher plant capacities, and high energy efficiency and co-product value realization.
These factors and project cost over-runs have seen new build costs escalate from $200 per annual tonne of capacity to more than $1,200 per tonne over the past decade.
Recent LNG plants have capital costs upwards of $30 billion, massive investments by any measure and representing high financial risk even for the biggest corporations.
The Energy Price Impact
The fall in the oil price has put the LNG industry under financial pressure, the more so when considering the high capital cost of recent new builds and the projected overhang in liquefaction capacity. LNG prices have fallen to 50% of pre-oil price crash levels, severely impacting project returns.
Current energy prices have cast doubts over the viability of future LNG facilities to the point it is likely that there will be a paradigm shift in criteria used to structure new projects. Potentially these will become smaller and more capex driven, possibly with phased project development to mitigate financial risk. Innovative design and project execution strategies will also be required to meet the challenging investment return hurdles of the current era. Given buyers’ procurement leverage in an over-supplied market, LNG suppliers will also have to cope with shorter duration and more flexible off-take contracts and wider use of the spot market.
Recent base load LNG schemes have deployed large trains (typically multiple 5 MMt/y), built onshore, with multi-refrigerant liquefaction systems. The dominant technology suppliers have been Air Products, Shell and ConocoPhillips, all using liquid hydrocarbon refrigerants, typically extracted from the feed gas, which requires additional plant and equipment beyond the refrigeration and liquefaction plant itself. A further factor impacting the traditional base load designs is that they need very large gas fields to provide an adequate reserve life to recover the high capital costs. As an example, a 2 x 5 MMt/y train LNG plant would exhaust a 5 Tcf reserve in only ten years. This, together with the capital cost and pricing pressures, is a driver to finding a solution suited to lower capacity plants and the more than 1,000 gas fields with reserves in the range 0.3–5.0 Tcf. These smaller reserves in themselves are not financially trivial: a 1 Tcf field brought to market, even at today’s depressed energy prices, is worth $7.5 billion.
Smaller scale industrial liquefaction technologies have been suggested for the new era. A simpler variant of the base load multi-refrigerant processes, the single mixed refrigerant (SMR) process, has been proposed. However, this technology is less efficient than the multi-refrigerant processes and like multi-refrigerants also suffers a safety drawback for the emerging FLNG market, because some operators consider liquid hydrocarbon refrigerants unsuitable for FLNG with its limited personnel exit opportunities in the event of a fire or explosion.
Nitrogen expander processes have also been proposed for the smaller scale market. Although proven and safer than SMR they suffer from very poor efficiency and require at least 40% more power than base load facilities. Nitrogen schemes have thus traditionally only been deployed at the lower capacity end of the market.
Technology for the Future
FLNG is being widely considered as a solution to cost pressures in the industry. Petronas commissioned its first such facility in early 2017. FLNG eliminates the need for a pipeline to shore for offshore fields. It also reduces some of the regulatory hurdles associated with plants constructed on land. Further, modularized construction and assembly at the shipyard where the hull is built allows fabrication under higher levels of productivity and quality control than prevail at remote locations, saving substantial cost. An additional benefit is that after exhausting one remote field an FLNG facility can be moved to another stranded gas opportunity, producing further revenues.
FLNG schemes will by nature be lower capacity than current base load plants as they are deck space constrained. Multi-train plants with total capacities up to 4 MMt/y are envisaged. Special design considerations will apply – there is a need for compact layouts, lower weight and smaller footprint to minimize the size and cost of the host hull.
New liquefaction cycles also have a role to play in addressing current cost pressures. An alternative to the use of nitrogen or mixed hydrocarbon refrigerants is to use the feed natural gas as the refrigerant medium. The use of natural gas refrigerant is an excellent fit with FLNG and a number of companies, including Air Products, the market leader in liquefaction technology, have now developed methane cycle schemes.
Low Cost Process
Gasconsult Limited first developed its liquefaction technology in the mid 2000s when oil prices ranged from $30–50 per barrel, a challenging scenario comparable to today’s circumstances. The objective was to develop a simple low cost process suitable for mid-scale FLNG application. This resulted in the patented ZR-LNG methane cycle process, which uses the natural gas feed as the refrigerant medium in an optimized system of expanders. Compared to mixed refrigerant cycles this eliminates refrigerant storage and transfer systems and the process equipment used to extract refrigerant components from the feed gas.
Refrigeration is effected in two expander circuits. The expanders are configured as companders and operate in series with the recycle gas compressor, recovering approximately 35% of the power required to run the system.
ZR-LNG is similar in concept to nitrogen schemes, but it enjoys a fundamental advantage as methane has a higher specific heat than nitrogen. This significantly reduces circulating flows, which in turn reduces power consumption and pipe sizes.
A patented and innovative feature of ZR-LNG is that a partial liquefaction takes place in the low temperature expander CX2 – this very efficiently converts latent heat directly into mechanical energy and also permits a reduction in heat transfer area and cost of the main heat exchanger HX1. An optional liquid turbine TU1 in the LNG run down line also improves efficiency by providing a significant chilling effect.
These features, together with the optimized distribution of flows, temperatures and pressures in the expander circuits, makes for a highly efficient system, around 280 kWh/tonne of LNG in temperate climates. This is equivalent or better than SMR and 30% lower than dual nitrogen expander schemes. In terms of efficiency ZR-LNG is best in class of the methane cycle schemes and can achieve single train capacities of up to 2 MMt/y of LNG.
In addition to low power demand and reduced equipment count there are a number of other advantages to the methane cycle concept.
For example, there are no refrigerant logistics issues in remote or offshore locations. Importing hydrocarbons and segregated storage to facilitate blending a mixed refrigerant are not required, and absolute security of refrigerant supply is assured. The process is well suited to lean feed gases as no liquid hydrocarbon feed gas components are required for the refrigerant, and no propane or other liquid hydrocarbon refrigerants are used – a major safety plus relative to mixed refrigerant schemes, particularly for FLNG as mentioned previously.
Single phase refrigerant makes the system motion tolerant and well suited to FLNG, as does the reduced cost, weight and footprint resulting from the absence of refrigerant extraction equipment and infrastructure. Unused space on the FLNG vessel could be used to install additional productive liquefaction capacity.
Costs are reduced, since the make-up refrigerant is low cost natural gas as opposed to purchased or extracted hydrocarbons or nitrogen, plus there is a shorter start-up time and reduced flaring.
The Way Ahead
Gas will play a major role in meeting the challenge of global warming and in providing a more benign atmospheric environment. More gas is needed to achieve this and increasingly this will be supplied as LNG. At today’s challenging energy prices and with the incentive to monetize smaller discovered reserves the LNG industry needs new solutions. FLNG with its ability to process multiple smaller stranded reserves will be part of the equation. Methane expander cycles offer an efficiency very close to traditional base load schemes but with an inherent simplicity that reflects in lower capital costs. They are an excellent fit with FLNG and offer an intrinsically safer operating environment than mixed refrigerant schemes.