Membrane Gas Separation

(a) One-stage Membrane Separation Process
(B) Two-stage Membrane Separation Process
Air
21% O
2
Air
21% O
2
Oxygen-enriched air
30-60% O
2
Oxygen-depleted air
10-15% O
2
Oxygen-depleted air
10-15% O
2
Nitrogen vent
Pure O
2
Figure 14.5 Membrane process fl ow schematics for the production of (a) oxygen -
 enriched air and (b) pure oxygen. Reprinted with permission from Industrial & Engineering 
Chemistry Research, Future directions of membrane gas separation technology, by R. W. 
Baker, 41, 1393 – 1404, Copyright (2002) American Chemical Society

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292
Membrane Gas Separation
are focused on new membrane materials exhibiting both high selectivity and high fl uxes 
in order to develop the production of pure oxygen in only one stage.
Promising results have been obtained with the facilitated transport membranes in which 
an oxygen - complexing carrier compound acts like a shuttle to transport the oxygen selec-
tively through the membrane [44] . 
Currently, dense inorganic membranes (ion transport membranes, ITM), able to be 
permeated only by oxygen (typically above 700 ° C) are being developed [45,46] . A high -
temperature air separation process could be integrated with power generation systems. 
Commercial - scale ion transport membrane oxygen modules have been fabricated by Air 
Products (0.5 ton/day of oxygen); this technology requires 35% less capital (much simpler 
fl ow sheet) and 35 – 60% less energy (less compression energy associated with oxygen 
separation) than cryogenic air separation [47] .
14.3.4
Natural Gas Treatment 
Raw natural gas composition changes depending on the source. In general, the CH 
4
content is in the range of 75 – 90%, the rest being signifi cant amounts of ethane, propane 
and butane, carbon dioxide and other impurities such as nitrogen and hydrogen sulfi de. 
In order to meet the composition specifi cations for natural gas domestic use imposed by 
each country, natural gas requires some treatment before being delivered in the pipeline. 
The main treatments are related to the carbon dioxide, natural gas liquids, water and 
nitrogen removal. 
Removal of carbon dioxide (natural gas sweetening) increases the calorifi c value and 
transportability of the natural gas stream. Carbon dioxide content in the natural gas 
obtained from the gas or oil well can vary from 4 to 50%. It has to be reduced down to 
ca. 2 
– 
5%. This goal is typically achieved by means of absorption with an aqueous 
alkanolamine solution. Amine treatment is a widely commercialized technology in which 
the hydrocarbon loss is almost negligible. However, this process has a tendency to corrode 
equipment and, over a short period of time, the amine solution loses viability through 
amine degradation and loss. However, the capital and operating cost shoots up very 
rapidly as the concentration of carbon dioxide in feed gas increases [48] . Membrane GS 
systems represent an alternative technology for separation of carbon dioxide from the 
natural gas, particularly for offshore applications [49] . 
Membrane systems can also be integrated with traditional units. The design of a hybrid 
membrane separation system depends on several aspects, such as membrane permeance 
and selectivity, CO 
2
concentration of the inlet gas and the target required, the gas value 
(per ca. 30 Nm 
3
, the price of gas in 2007 was $6 – $7 in the United States, whereas in 
Nigeria, which is far from being as well - developed a gas market, it may be as low as 
$0.50 if the gas can be used at all) and the location of the plant (on an offshore platform, 
the weight, footprint, and simplicity of operation are critical; onshore, total cost is more 
signifi cant) [51] . 
Figure
14.6 
reports the block diagrams of two typical carbon dioxide membrane 
systems that treat natural gas with low CO 
2
concentration, as proposed by Baker [51] . 
Both systems are designed to treat a feed stream with 10% of carbon dioxide. One - stage 
systems are preferred for very small gas fl ows. In such plants, methane loss to the perme-
ate is often 10 – 15%. If there is no fuel use for this gas, it must be fl ared, which represents 

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Membrane Engineering: Progress and Potentialities in Gas Separations
293
a signifi cant revenue loss. As the fl ow rate of the natural gas stream increases, the methane 
loss increases, therefore, usually, the permeate gas is recompressed and passed through 
a second membrane stage which reduces the methane loss to a few percent.
During the years 1980 – 1985, the fi rst membrane plants using cellulose acetate mem-
branes were installed [32] . Currently, several membrane systems are installed for small 
size applications (less than 6000 Nm 
3
/h), since amine processes are too complicated for 
small productions. Membrane and amine systems become competitive with respect to the 
traditional operations (PSA and cryogenic distillation) for size of 6000 – 50 000 Nm 
3
/h, 
while bigger plants are installed for offshore platforms or for enhanced oil recovery. 
Cellulose acetate is still the most widely used and tested material for natural gas sweeten-
ing as in UOP ’ s membrane systems [50,51] (Figure 14.7 ). Recently, in an offshore plat-
form located in the Gulf of Thailand (830 000 Nm 
3
/h) Cynara - NATCO [52] provided the 
biggest membrane system with 16 - inch hollow fi bre modules based on cellulose triacetate 
membranes for natural gas sweetening [53] . Polyimide membranes, originally developed 
for hydrogen separation, have been recently commercialized also for CO 
2
separation.
Raw natural gas generally contain low concentrations of light hydrocarbon vapours. 
Their condensation must be prevented in order to avoid damages in the pipeline. So 
removal of these vapours is performed by glycol absorption and refrigeration at
−
20 ° C 
in a propane atmosphere. Membrane use can make the process cheaper, drastically reduc-
ing the energy consumption due to refrigeration; however, it is still at an early commercial 
stage with only one demonstration plant installed in Pascagoula (USA), in 2002 [54] . 
1800 m
2
2000 m
2
300 m
2