Besides using natural gas directly as a motor fuel in the form of CNG, several technical options are available to synthesise liquid products that have the advantage of easier transportation and, for some, to be usable in mixture with conventional fuels. These processes rely on either steam reforming or partial oxidation of natural gas to produce syngas which is then used as a feedstock to a synthesis process. The most prominent options are:
o Synthetic hydrocarbons via the Fischer-Tropsch route, o DME,
o Methanol.
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The conversion plants can conceivably be located either near the gas production area or near the markets. For liquid fuels, the first option is far more likely to be implemented as it then becomes an alternative to LNG or very long-distance pipelines for remote gas sources. For hydrogen, plants near markets appear to be more logical as long-distance transport of natural gas would normally be preferred over that of hydrogen. Large scale electricity production needs of course to be near the consuming centres. The processes and installations involved are, however, conceptually the same.
The first step, common to all such processes, is the conversion of natural gas to “synthetic gas” (or syngas i.e. a mixture of mainly carbon monoxide and hydrogen) by partial oxidation or steam reforming.
Synthetic diesel fuel (Fischer-Tropsch)
Production of liquid hydrocarbons from syngas via the Fischer-Tropsch (FT) process has been known for many years and the subject of many variations and improvements. The first commercial plant was the Shell Middle Distillate Synthesis (SMDS) plant in Malaysia. A much larger plant has recently been completed in Qatar. When operating at full capacity (anticipated in mid 2013) this will be capable of producing 140,000 bpd of GTL products. In this study we assume the synthetic fuels to be saturated i.e. the process scheme to include a hydrocracker to cut and hydrogenate the long chains to the desired fuel type. In earlier versions of this study, the assumed FT plant was based on SMDS with an overall efficiency (including syngas generation from natural gas) in the range of 61 to 65%. This excludes any potential synergy with upstream or adjacent complexes which could add a few percent points. The theoretical efficiency is about 78% and, with the considerable R&D effort going into these processes at the moment, it is reasonable to believe that higher efficiencies could be achieved in the future. A lot can be achieved through improved heat integration, particularly in the syngas production step and, with rising energy cost, the extra capital investment required is likely to be easier to justify.
To reflect these developments, the mean efficiency figure for future plants in this study has been retained at the slightly higher figure of 65%, with a range of 63-67%.
These plants can produce a complete range of products from LPG to base oils for lubricants and small amounts of specialty products such as waxes. Some plants, particularly early ones, may be designed to produce significant quantities of high value products such as base oils. However the market for such products is limited and naphtha kerosene and diesel fuel will eventually represent the bulk of the output. Yields can be adjusted over a fairly wide range. The maximum practically achievable diesel fuel yield (including the kerosene cut) is around 75% of the total product, the balance being mainly naphtha and some LPG.
The process scheme is essentially the same for all products that can be therefore considered as “co-products”. There is no technical basis for arguing that more or less energy and emissions are associated to specific products so that, in this case, allocation on the basis of energy content is justified (i.e. that all products are produced with the same energy efficiency). We have taken this view which led us to consider that all products and their fate are independent of each other and so simply compare the energy and GHG emissions of GTL production with the marginal figures for fossil diesel.
The alternative would be to consider diesel as the main product supporting all production energy and emissions and other streams as “co-products”. In this case the fate of the co-products would have to be considered in order to calculate a credit or debit to be applied to refinery diesel. The most likely disposal route for GTL naphtha and LPG would be to substitute the equivalent petroleum products in Europe or other world markets. This would result in an energy and GHG debit for the GTL diesel, since conventional naphtha and LPG production pathways are less energy intensive than the GTL process.
Two studies by PriceWaterhouseCoopers [PWC 2001] and one study by Nexant [Nexant 2003] have taken a different approach to this question. They consider functionally equivalent hydrocarbon processing systems with and without GTL products, and calculate the energy and GHG balances for a portfolio of fuel products meeting the market demand. Their calculations confirm the debits for naphtha and LPG mentioned above. However, their calculations assume that availability of GTL can lead to less crude oil processing. In this situation, if lower availability of heavy fuel oil (HFO) were to result in a switch to natural gas in industrial heating and power generation, this would result in lower GHG emissions. The studies show that, by accounting for the HFO in the refinery system, GHG emissions from the complete system could become broadly equivalent for the scenarios with and without GTL fuels.
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The key assumption made in the PWC and Nexant studies is that availability of GTL would slow investment in crude oil capacity. This may well be applicable in rapidly developing markets (such as China) where a clear choice would need to be made between additional crude oil processing capacity and new capacity for making synthetic diesel via a Fischer-Tropsch (or other) route. However the assumption is less obviously applicable for Europe which has an established refining industry with no foreseeable major expansion. Substitution of HFO by natural gas is already happening to some extent and the trend may be expected to continue for reasons which are not linked to the road fuels market.
Our study does not consider that linking GTL diesel availability to HFO production and making the further assumption that a reduction of HFO production would be made up by natural gas, are appropriate in a European context. This is the key reason for the differences between the WTW results for GTL quoted in this study, as compared to the studies conducted by PWC and Nexant.
GTL plants produce a large amount of low temperature heat that could be of use in certain locations for e.g. seawater distillation or district heating. Such arrangements are highly location-specific and also require complex partnerships that cannot always be realised. As a result they are unlikely to apply to every project. We therefore considered the potential benefits should not be included in a generic pathway, although it is recognized that the Qatar location chosen by a number of parties (see below) would most likely be able to utilize the low grade heat (for sea water distillation).
In the GTL process CO2 is produced and separated from the syngas upstream of the Fischer-Tropsch synthesis. This provides an opportunity for CCS (see section 4.6.2).
DME
Di-methyl ether or DME has attractive characteristics as a fuel for diesel vehicles. However, it is volatile and must be kept under moderate pressure (similar to LPG) so would require specially adapted vehicles. There is, however, no commercial experience with its direct production from natural gas (via synthesis gas). Present commercial manufacture of DME is via methanol and not for fuel purposes. There have been various reports of large plants planned for Iran and particularly China, mainly for domestic fuel. We have used data available from Haldor Topsoe, scaled to a notional plant with the same gas intake as its methanol equivalent. As mentioned for synthetic diesel, development of such processes at a large scale would likely lead to process improvements and higher energy efficiency in the long run.
In the DME synthesis process CO2 is produced and separated from the syngas upstream of the synthesis step. This provides an opportunity for CCS (see section 4.6.3).
Methanol
Methanol synthesis from methane is a well-established process. We have assumed a state-of-the-art plant of 600 MW (in terms of methanol, equivalent to about 100 t/h), fully self-contained (i.e. with natural gas as only energy source and no energy export) and with an efficiency in the range of 67 to 69%.
NG to hydrogen via methanol
Methanol synthesised from remote natural gas could potentially be used as an energy vector instead of compressed or liquefied gas. Distributed into Europe it could be reformed locally to hydrogen.
MTBE
Methyl-Tertiary-Butyl Ether or MTBE is a high octane blending component for gasoline. It was originally used for its ability to reduce emissions by bringing oxygen into the fuel and was widely used in US gasoline until water contamination issues led to a partial ban. In Europe MTBE was introduced as one of the measures to recover octane after phasing out of lead in gasoline.
MTBE is synthesised by reacting isobutene with methanol. Some isobutene is produced by refineries and petrochemical plants as by-product of cracking processes. Large MTBE plants include, however, isobutene manufacture via isomerisation and dehydrogenation of normal butane often from gas fields, near which the plants are often located. The entire process is fairly energy-intensive. In that sense MTBE is a fuel derived from natural gas. Marginal MTBE available to Europe is from that source and this is the pathway that we have investigated.
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Production and Pipelines in EU NG grid + CNG GMCG1
conditioning on-site compression
NG grid
Reforming Compression CH2 GMCH1
(on-site)
Natural gas (piped)
Production and Pipeline into EU NG grid (LP/MP)+ CNG GPCG1a/b
conditioning a) 7000 km On-site compression
b) 4000 km
NG grid
Reforming (on-site) Compression CH2 GPCH1a/b
Reforming (central) Pipeline, 50 km CH2 GPCH2a/b/2bC
(+CCS option) Compression
Reforming (central) Road, 50 km CH2 GPCH3b
Compression
Reforming (central) Road, 300 km + CH2 GPLCHb
+ H2 Liquifaction vaporisation/compression
Reforming (central) Road, 300 km LH2 GPLH1a/b
+ H2 Liquifaction
GTL plant As for refinery fuels Syn diesel GPSD1a/b
Methanol/DME Mixed land transport Methanol GPME1b have endeavoured to select those pathways that appear the most relevant and plausible.
Figure 3.2.7: Natural gas pathways
Version 4, July 2013 Figure 3.2.7: Natural gas pathways (cont’d)
Energy
Production and Liquefaction Shipping (LNG) Vapourisation NG grid + CNG GRCG1/1C
conditioning (+CCS option) on-site compression
Reforming (central) Pipeline, 50 km C H2 GRCH2
+ compression
Methanol Shipping + Reforming (on-site) Compression C H2 GRCH3
Synthesis Road 500 km
Reforming Shipping (LH2) Road, 500 km L H2 GRLH2
H2 liquefaction
GTL plant Shipping As for refinery fuels or Syn diesel GRSD1/1C
(+CCS option) Mixed land transport, 500 km
MeOH/DME syn Shipping Mixed land transport Methanol GRME1
(+CCS option) 500 km DME GRDE1/1C
NG (remote) Production and Isobutene
conditioning Shipping As for refinery fuels GRMB1
MTBE Field butane Production and Methanol
conditioning
Natural gas (shale)
Shale gas Production and NG grid (LP/MP)+ CNG SGCG1
conditioning On-site compression
3.2.8 LPG
LPG (Liquefied Petroleum Gas) is the generic acronym for C3 and C4 hydrocarbons that are gaseous under ambient conditions but can be stored and transported in liquid form at relatively mild pressures (up to about 2.5 MPa for propane). LPG is widely used for heating and cooking as well as petrochemicals. It is also a suitable fuel for spark ignition engines with a good octane rating. LPG is available as a road fuel in a number of European countries.
LPG is produced in oil refineries as a by-product of virtually all treating and conversion processes.
This resource is, however, limited and already completely accounted for. Indeed Europe imports a significant proportion of its LPG consumption. Accordingly the marginal LPG consumed in Europe originates from oil or gas fields where it is produced in association with either crude oil or natural gas.
We have represented the case of natural gas fields.
Energy is required to produce the LPG and also for subsequent treatment and separation into C3 and C4 hydrocarbons (which tend to have different markets) and C5+ components. The pathway is represented below.
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Energy
LPG (remote) Production and Shipping (LPG) Road, 500 km LPG LRLP1
conditioning ETBE