Recovery process, hydrogen-hydrocarbon

Steam Reforming Processes. In the steam reforming process, light hydrocarbon feedstocks (qv), such as natural gas, Hquefied petroleum gas, and naphtha, or in some cases heavier distillate oils are purified of sulfur compounds (see Sulfurremoval and recovery). These then react with steam in the presence of a nickel-containing catalyst to produce a mixture of hydrogen, methane, and carbon oxides. Essentially total decomposition of compounds containing more than one carbon atom per molecule is obtained (see Ammonia Hydrogen Petroleum). 

A disadvantage of the hydrocarbon—sulfur process is the formation of one mole of hydrogen sulfide by-product for every two atoms of hydrogen in the hydrocarbon. Technology for efficient recovery of sulfur values in hydrogen sulfide became commercially available at about the same time that the methane—sulfur process was developed. With an efficient Claus sulfur recovery unit, the hydrocarbon—sulfur process is economically attractive. 

Figure 3. Hydrogen-hydrocarbon recovery process with stripping column...

Reactor effluent is cooled in a series of exchangers (3) to recover waste heat and to condense (4) the hydrocarbons and steam. Uncondensed offgas—primarily hydrogen—is compressed (5) and then directed to an absorber system (6) for recovery of trace aromatics. Following aromatics recovery, the hydrogen-rich offgas is consumed as fuel by process heaters. Condensed hydrocarbons and crude styrene are sent to the distillation section, while process condensate is stripped (7) to remove dissolved aromatics and gases. The clean process condensate is returned as boiler feedwater to offsite steam boilers. 

Natural gas typically contains a range of hydrocarbon compounds, as well as carbon dioxide and hydrogen sulfide. Ethane, propane, and butane are often recovered from natural gas for use as petrochemical feed stocks. Typical recovery processes are described in U.S. 4,157,904, assigned to Ortloff Corp. Estimate the cost of recovering ethane and producing a natural gas product that meets pipeline specifications for a plant that processes 150 MMscfd of natural gas with the feed composition given in Example 3 of the patent. Assume the feed also contains 480 ppm of H2S, 14 ppm of COS, and 31 ppm of methyl mercaptan. 

In the past, the available membranes lost a significant fraction of their selectivity when operated at these high temperatures. They also became plasticized by absorbed heavy hydrocarbons in the feed gas. As a consequence, a number of early hydrogen-separation plants installed in refineries had reliability problems. The development of newer polyimide and polyaramide membranes that can safely operate at high temperatures has solved most of these problems and the market for membrane-based hydrogen-recovery processes in refineries is growing. 

Membranes compete with cryogenic, catalytic and pressure swing adsorption processes in the hydrogen recovery process [6], Carbon membranes can be apphed to recover a valnable chemical (H2) from a waste gas, or can be used for the recovery of hydrogen from gasification gas without further compression of the feed gas, while rejecting a snbstantial portion of the hydrocarbons [24], Conventional/poly-meric membranes incur additional recompression costs because H, as a fast gas, exits the unit at the lower pressure side [5, 6],... 

Sweet wells do not contain hydrogen sulfide, whereas sour wells do. The source of CO2 can be mineral dissolution or a by-product of the petroleum-forming process. The source of H2S can be dissolution of mineral deposits in the rocks, a by-product of the petroleum-forming process, or bacterial action at any time in the history of the petroleum deposit. Oxygen always originates from air and can only come in contact with petroleum fluids after the recovery process begins. It does not exist in the undisturbed hydrocarbon deposit. 

Recovery of heavy hydrocarbons or liquefied petroleum gas (LPG) from refinery purge or fuel gas is significantly more profitable than using these components as waste fuel. If the gas contains hydrogen, it can also be recovered. This application is a long-standing area of research pilot plants for the process are installed. This could become a significant market. 

Natural gas is processed mainly for the recovery of liquid hydrocarbons useful in gasoline, pure hydrocarbons as butane, propane, ethane, or mixtures of them, hydrogen sulfide (and sulfur or sulfuric acid), and carbon black but significant amounts of gas are also converted into ammonia, synthesized by the Fischer-Tropsch reaction, or oxidized into chemical products such as formaldehyde. Conventional operations, however, consist of mainly two operations, viz., recovery of liquids (absorption, etc.), and purification of the liquid. 

A derivative of the Claus process is the Recycle Selectox process, developed by Parsons and Unocal and Hcensed through UOP. Once-Thm Selectox is suitable for very lean acid gas streams (1—5 mol % hydrogen sulfide), which cannot be effectively processed in a Claus unit. As shown in Figure 9, the process is similar to a standard Claus plant, except that the thermal combustor and waste heat boiler have been replaced with a catalytic reactor. The Selectox catalyst promotes the selective oxidation of hydrogen sulfide to sulfur dioxide, ie, hydrocarbons in the feed are not oxidized. These plants typically employ two Claus catalytic stages downstream of the Selectox reactor, to achieve an overall sulfur recovery of 90—95%. 

---