Chemical Engineering January 2015 - 46

Feature Report
Technology choice in pracTice
T
his case study illustrates many of the points discussed in the main text, by outlining
how a technical solution was chosen to meet a more complex set of requirements.
The plant in question specializes in large-scale production of carbon monoxide for
the chemicals industry [toluene diisocyanate (TDI) and diphenylmethane diisocyanate
(MDI)]. At the same time, the operator wishes to generate hydrogen as an additional
source to feed an existing pipeline network, for over-the-fence gas supply to several
customers. The required product ratio of CO to H2 is 2.5:1, and a variety of natural
gas sources are available as feed and fuel. As the plant serves multiple customers
with fluctuating requirements, a decision is made to implement a flexible system that
allows the ratio of H2 to CO in the syngas to vary between three and six. In addition,
co-produced superheated steam at 53 barg can be exported as required at almost
steam fuel value.
The technologies implemented along the process chain are as follows: pre-reforming,
steam methane reforming, and amine wash CO2 removal - with a downstream serial
arrangement of a methane-wash cold box, pressure swing adsorption, and CO2 and
methane recycle compression. For this system design and the given product ratio, it is
not necessary to operate a parallel CO shift train downstream of the reforming unit.
In the PSA unit, the purity of the H2-rich gas from the cold box is increased from 97.8
to 99.99%. The H2 is compressed from 23 barg to the specified product pressure of
44 barg. And by deploying a feed ejector driven by process steam, feed compression
can be avoided. The remaining H2-rich tailgas from the PSA stage is used as fuel in
the reformer. Moreover, the plant design can facilitate the import of CO2, should a
suitable source become available in the future - providing scope to reduce natural
gas consumption.
The solution is implemented using a tailor-made combination of proven, standardized
technology units, and the construction of the plant is based on pre-fabricated modules.
As a result, it is possible to not only overcome the challenge of selecting the right methane
reforming technology, but also to combine the technologies and adjust the parameters of
each individual unit in such a ways as to maximize overall plant performance. ❏
process pressure is high, as is the
case in GasPOX plants, for example.
Where the aim is to achieve as
pure a H2 stream as possible, PSA
is the separation method of choice
- enabling H2 recovery of up to
90%. Recently, a new technology
has been launched that compresses
the remaining tailgas from the
PSA process, removes CO2 using
cryogenic technology, and recycles
the hydrogen back to the PSA via
membranes. In addition to lowering
CO2-capture costs, this method can
increase H2 recovery to over 98%. If
using partial oxidation, it can be advantageous
to perform conventional
CO2 removal followed by methanation
to achieve a H2 recovery close
to one. This can be the case in instances
where the H2 product-quality
specification allows for it and
the upstream reforming technology
requires a syngas cleaning unit for
H2S and CO2 anyway.
A note on CO2 emissions
When generating H2, every carbon
atom in the feed will be converted
into CO2. As such, the more natural
gas consumed, the larger the volume
of CO2 produced. Any calculation of
total CO2 emissions, however, must
also take into account the indirect
emissions from power production or
air separation.
If CO2 removal has been integrated
into the technology chain,
the capture rate of CO2 from syngas
will be higher for those technologies
that consume less carbon-containing
fuel. Where opportunities
exist to recycle CO2 - as in the CO
process chain - it is also possible
to reduce CO2 emissions. The fuel
for the SMR or fired heater will,
in this case, primarily comprise H2
extracted from the syngas during
product separation.
Cost considerations
Needless to say the cost factor will
loom large when making decisions
on which syngas technology to
choose. A number of aspects are of
relevance: thermal efficiency, the
potential for economies of scale, reliability
of the equipment chosen,
and plant design.
Thermal efficiency. For all methane-reforming
technologies, thermal
efficiency is determined by the
limitations that exist on the use of
low-temperature heat in flue and
process gas. Losses can be minimized
by optimizing process parameters
to reduce fluegas flow and by
maximizing the use of internal process
heat, for instance, by deploying
a pre-reformer or heat exchange
reformer. Moreover, technologies
designed to use low-temperature
heat in reforming plants are becoming
more attractive, as they have
become more advanced and less expensive
in recent years.
The point at which improvements
in thermal efficiency outweigh the
advantages of higher hydrogen conversion
will depend on utility cost
factors, particularly steam value
and the ratio of feed to fuel cost.
This can be calculated by means of
an overall utility cost assessment.
To take an example, minimizing the
steam-to-carbon ratio and lowering
methane conversion will not be an
attractive option if feed is more expensive
than fuel.
In contrast to coal gasification,
where high up-front expenditure
(capex) is required, the bulk of the
total cost breakdown for gas-reforming
plants is for operating expenses
(opex) - attributable to feed, fuel,
oxygen, steam, power and other utilities.
This is particularly true of large
gas reforming plants, where economies
of scale can shift the opex-tocapex
ratio to as high as 80:20.
For the four technologies discussed
here, it should be noted that
they differ in terms of the economies
of scale that can be achieved. In the
case of steam methane reforming,
for example, the relationship of cost
to capacity for the system's tubes
and burners is almost linear. However,
the SMR furnace and header
system scales at a rate of less than
one. For ATR and GasPOX reactors,
the overall cost-scaling exponent is
also below one. This is one of the
main reasons why ATR and combined
reforming are often chosen
for large-scale methanol and synfuel
production.
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