CO2 removal

Before discussing CO2 removal it is worthwhile to speak of the problem of COS formation when removing H2S from gas where CO2 is present COS is formed by a first order reaction, taking place in the sorbed phase, wherein  

The degree to which molecular sieves promote this reaction varies widely and UOP can offer a range of technical solutions to either drive or severely inhibit this reaction. 

As with the sweetening application our most common need for CO2 removal is from natural gas prior to liquefaction. In this application we are often faced with amounts of oxygen in the feed that may range up to several hundred ppm by volume. The process is often limited to adsorption at a total pressure of about 3 5 bar. In this application however the feed gas is most often pipeline natural gas which gas will have been pre-dried to pipeline standards or about seven pounds (1 lb = 0.45 kg) of water per MMSCF of gas. In some cases the gas source may be other than pipeline and the water load needs to be estimated based on a given mole fraction. The liquefaction process, which runs at -260°F (127°C), demands very low levels of water in the product as well as trace levels of CO2 so that the heat exchangers in the downstream process remain clean. 

As with sweetening the design process for removal of CO2 is very similar to that of dehydration. Special consideration is given to the presence of O2 in the feed and in some cases it is found necessary to catalytically remove the oxygen. 

Separation of CO2 from gas streams is required in four areas (1) purification of natural gas (gas sweetening), (2) separation of CO2 from enhanced oil recovery (FOR) gas streams, (3) removal of CO2 from flue gas, and (4) removal of CO2 from biogas. A fifth area vital for the space age should be mentioned removal of CO2 from life support systems onboard space ships, and also in submarines. All these applications have different specifications for the purified gas or for the recovered CO2, and future membrane applications will most likely be based on tailor-made materials. 

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Urea is produced from liquid NH and gaseous CO2 at high, pressure and temperature both reactants are obtained from an ammonia-synthesis plant. The latter is a by-product stream, vented from the CO2 removal section of the ammonia-synthesis plant. The two feed components are deUvered to the high pressure urea reactor, usually at a mol ratio >2.5 1. Depending on the feed mol ratio, more or less carbamate is converted to urea and water per pass through the reactor. 

A Na+ Naj2[(A102)j2(Si02)j2] obstmcted 8-ring 0.38 desiccant CO2 removal air separation (N2)... 

Other Separations. Other TSA appHcations range from CO2 removal to hydrocarbon separations, and include removal of air poUutants and odors, and purification of streams containing HCl and boron compounds. Because of their high selectivity for CO2 and their abiHty to dry concurrently,... 

A, 5A, and 13X zeoHtes are the predorninant adsorbents for CO2 removal by temperature-swing processes. The air fed to an air separation plant must be H2O- and C02-ftee to prevent fouling of heat exchangers at cryogenic temperatures 13X is typically used here. Another appHcation for 4A-type zeoHte is for CO2 removal from baseload and peak-shaving natural gas Hquefaction faciHties. 

Fig. 1. Hydrogen production flow sheet, showing steam reforming, shift, hot potassium carbonate CO2 removal, and methanation.

The second CO2 removal is conducted using the same solvent employed in the first step. This allows a common regeneration stripper to be used for the two absorbers. The gases leaving the second absorption step stiU contain some 0.25—0.4% CO and 0.01—0.1% CO2 and so must be methanated as discussed earlier. The CO, CO2, and possibly small amounts of CH, N2, and Ar can also be removed by pressure-swing adsorption if desired. 

The impurities usually found in raw hydrogen are CO2, CO, N2, H2O, CH, and higher hydrocarbons. Removal of these impurities by shift catalysis, H2S and CO2 removal, and the pressure-swing adsorption (PSA) process have been described (vide supra). Traces of oxygen in electrolytic hydrogen are usually removed on a palladium or platinum catalyst at room temperature. 

Fresh reducing gas is generated by reforming natural gas with steam. The natural gas is heated in a recuperator, desulfurized to less than 1 ppm sulfur, mixed with superheated steam, further preheated to 620°C in another recuperator, then reformed in alloy tubes filled with nickel-based catalyst at a temperature of 830°C. The reformed gas is quenched to remove water vapor, mixed with clean recycled top gas from the shaft furnace, reheated to 925°C in an indirect fired heater, and injected into the shaft furnace. For high (above 92%) metallization a CO2 removal unit is added in the top gas recycle line in order to upgrade the quaUty of the recycled top gas and reducing gas. 

Carbon Dioxide Removal. The effluent gases from the shift converters contain about 17—19 vol % (dry) carbon dioxide (qv) which is ultimately reduced to a few ppm by bulk CO2 removal, followed by a final purification step. Commercial CO2 removal systems can be broadly classified as... 

A.lkanolamine Process. Carbon dioxide is an acidic gas that reacts reversibly with aqueous alkaline solution to form a carbonate adduct. This adduct decomposes upon the addition of low level heat faciUtating CO2 removal. An aqueous solution of 15—20 wt % monoethanolamine (MEA) was the standard method for removing CO2 in early ammonia plants. 

Activated tertiary amines such as triethanolamine (TEA) and methyl diethanolamine (MDEA) have gained wide acceptance for CO2 removal. These materials require very low regeneration energy because of weak CO2 amine adduct formation, and do not form carbamates or other corrosive compounds (53). Hybrid CO2 removal systems, such as MDEA —sulfolane—water and DIPA—sulfolane—water, where DIPA is diisopropylamine, are aqueous alkaline solutions in a nonaqueous solvent, and are normally used in tandem with other systems for residual clean-up. Extensive data on the solubiUty of acid gases in amine solutions are available (55,56). 

The choice of a specific CO2 removal system depends on the overall ammonia plant design and process integration. Important considerations include CO2 sHp required, CO2 partial pressure in the synthesis gas, presence or lack of sulfur, process energy demands, investment cost, availabiUty of solvent, and CO2 recovery requirements. Carbon dioxide is normally recovered for use in the manufacture of urea, in the carbonated beverage industry, or for enhanced oil recovery by miscible flooding. 

Pressure Swing Adsorption. Carbon dioxide can be removed by pressure adsorption on molecular sieves. However, the molecular sieves are not selective to CO2, and the gases must be further processed to achieve the high purity required for "over the fence" use as in the urea process. Use of pressure swing adsorption for CO2 removal appears most appHcable to small, stand-alone plants (29). 

Most commercial methanator catalysts contain nickel, supported on alumina, kaolin, or calcium aluminate cement. Sulfur and arsenic are poisons to the catalyst, which can also be fouled by carry-over of solvent from the CO2 removal system. 

In practice, most of the appHcations have come where a small part (<5%) of the feed is removed. Examples include H2S /CO2 removal and gas drying with a glycol (see Distillation, AZEOTHOPic and exthactive). 

Other gas-treating processes involving sulfolane are (/) hydrogen selenide removal from gasification of coal, shale, or tar sands (qv) (108) (2) olefin removal from alkanes (109) (J) nitrogen, helium, and argon removal from natural gas (110) (4) atmospheric CO2 removal in nuclear submarines (5) ammonia and H2S removal from waste streams (6) H2S, HCl, N2O, and CO2 removal from various streams (111—120) and (7) H2S and SO2 removal from... 

Lower alkalinity, raw water, silica, and CO2 removal required... 

Methanol. Methanol is produced by stoichiometric reaction of CO and H2. The syngas produced by coal gasification contains insufficient hydrogen for complete conversion to methanol, and partial CO shifting is required to obtain the desired concentrations of H2, CO, and CO2. These concentrations are expressed in terms of a stoichiometric number, ((H2 — CO)/(H2 + CO2), which has a desired value of 2. In some cases CO2 removal is required to achieve the stoichiometric number target. CO and H2 are then reacted to form methanol in a catalytic methanol synthesis reactor. 

Power Recovery in Other Systems. Steam is by far the biggest opportunity for power recovery from pressure letdown, but others such as tailgas expanders in nitric acid plants (Fig. 1) and on catalytic crackers, also exist. An example of power recovery in Hquid systems, is the letdown of the high pressure, rich absorbent used for H2S/CO2 removal in NH plants. Letdown can occur in a turbine directiy coupled to the pump used to boost the lean absorbent back to the absorber pressure. 

Figure 3 shows a simple schematic diagram of an oxygen-based process. Ethylene, oxygen, and the recycle gas stream are combined before entering the tubular reactors. The basic equipment for the reaction system is identical to that described for the air-based process, with one exception the purge reactor system is absent and a carbon dioxide removal unit is incorporated. The CO2 removal scheme illustrated is based on a patent by Shell Oil Co. (127), and minimises the loss of valuable ethylene in the process. 

Mol sieve processes can be developed to do almost anything desired remove H2S, sweeten and dehydrate at the same time, remove CO2. remove mercaptans, etc. Regeneration is done by switching beds and sending hot... 

Burchell, T.D. and Judkins, R.R. Passive CO2 removal using a carbon fiber composite molecular sieve. Energy Convers. Mgmt, 1996, 37(6-8), 947 954... 

These cycles allow sequestration and disposal of CO2 as a liquid, rather than allowing it to enter the atmosphere. They involve the introduction of additional equipment for the CO2 removal but little or no modification of the basic CBT or CBTX plant itself. 

Description Type Special features Fuel/oxidant CO2 removal Comment... 

A1 "End of pipe CO2 removal Open/CCGT - Natural ga.s/air LP (chemical) Simple CO2 removal, but large CO2 plant... 

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