CO2 removal and methanation

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

This H2 + CO synthesis gas can be processed for sulfur-removal (Sulfinol), CO-shift (HTS/LTS), CO2-removal, and methanation to produce a high purity (>98% vol H2) hydrogen. 

These are considerably simplifted in comparison with those for the production of high purity hydrogen or thesis gas for ammonia. This is because CO conversion, CO2 removal and methanation are eliminated. However, an auxiliary compressor is necessary in this case. 

The hydrogen PSA system offers two main advantages over the conventional process incorporating shift reactors CO2 removal and methanation. The first advantage is that the equipment is less expensive and the second is that the PSA system can deliver a hydrogen purity of 99.95%. 

The second step after secondary reforming is removing carbon monoxide, which poisons the catalyst used for ammonia synthesis. This is done in three further steps, shift conversion, carbon dioxide removal, and methanation of the remaining CO and CO2. 

Assuming the feedstock is methane, which is the major component of natural gas, the theoretical feed requirement would be equivalent to one-fourth of the potential hydrogen production or 16,713 SCF CH /ST NH3(15.2 MM BTU/ST). However, the actual process consumes on the order of 22,420 SCF CHi+/ST NH3 or about 20.4 MM BTU/ST NH3 (LHV). The required quantity of feed depends on the process design criteria chosen for the methane conversion in the reforming section, the efficiency of CO conversion, degree of CO2 removal and the inerts (CHi+ + Ar) level maintained in the ammonia synthesis loop. Thus, the potential hydrogen conversion efficiency of the feedstock in the steam reforming process is about 75%. Table 3 shows where the balance of the feed is consumed or lost from the process. 

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. 

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. 

At a pressure of 30 bar and with excess steam the fractional conversion of methane in the reformer is reasonably satisfactory. The high pressure of 30 bar will favour the removal of carbon dioxide, following the shift reaction CO + H2O CO2 + H2, and reduce the cost of compressing the purified hydrogen to a value, typically in the range 50-200 bar, required for ammonia synthesis. 

A C02-CH4 methane process gas stream, similar to a typical high CO2 natural gas has been under test by SEPAREX for CO2 removal in a 2-in. diameter element pilot plant since September 1981. The feed gas contains 30% CO2 and is delivered to the membrane test unit at 250-450 psig under ambient temperature conditions. The objective of the system is to reduce the CO2 level of the methane to less than 3.5%. The membrane system consists of 5 pressure tubes in series, each tube containing three 40-in. long elements. The gas is conditioned to maintain it at a minimum of 20°F above the dewpoint. The system was operated at a variety of flow rates, pressures, recoveries and temperatures. Selected data are presented in Figures 6 through 8. 

In a steam reforming process that includes CO shift conversion and CO2 removal, the synthesis gas still contains 0.1% to 0.2 mole % CO and 100 to 1000 ppmv of CO2. The simplest method for eliminating these small concentrations of oxygen compounds is shown by the reactions in Eqs. (5.13) and (5.17) (that are the reverse of the methane reforming process). The methane that is formed does not cause any problems in the downstream ammonia process. The methane simply acts as an inert diluent70. 

Concentrate the CO2 using membrane technology. Distill the retentate to remove the methane. Take the bottoms from the demethanizer and perform an azeotropic distillation to separate CO2 from C2 using a C4 extraction fluid. Treat theazaotrope overhead with a membrane distillation hybrid to remove the CO2. Now combine the various streams as shown in Fig. P-23b. 

The product gas of the methanation section contains mainly CHi, Hj, HjO, and CO2. Removing H1O from this stream results in SNG as the final product, which leaves the system at high pressure. The heat released from the hydrogasifier product gas, and the heat generated in the methanation reactors, are used to generate superheated steam (40 bar and 540°C), which enters a steam turbine. A fraction of partly expanded steam is used to dry the biomass, while the remaining part of the steam is used for power generation. 

Solvent-drying. After annealing at lOO C, the absorbed water inside the membranes was removed by a proprietary procedure. Its effect on gas permeation is given in Table VI. No effect is observed on the.helium and carbon dioxide permeability rates. But the permeability rates of nitrogen and methane are considerably lowered so that the separations of both systems, helium/nltrogen and carbon dloxlde/methane, are enhanced. With a value of 44.1 for helium/ nitrogen, the ideal separation factor of the external reference membrane is slightly exceeded, whereas the separation factor for CO2/CK of more than 2500 is Improved by a factor of 600. 

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