Propane stripper

Fig. 18.23. Alkylation—Technology Solutions Division of ConocoPhillips. Include combination reactor/settler (1), main fractionator (2), and small propane stripper (3). (Source Hydrocarbon Processing, 2004 Refining Process Handbook. CD-ROM. September 2004 copyright 2004 by Gulf Publishing Co., all rights reserved.)...

Specific areas where corrosion is likely to occur include the bottom of the acid rerun tower, the depropanizer tower, the overhead condensers of these towers, the reboiler of the propane stripper, and piping around the acid rerun tower. 

Sketch a control scheme for the coogenic stripper shown below that is used for removing smaU amounts of propane from natural gas. 

It is fed to an absorber where 75% of the propane is recovered. The total amount absorbed is 50 mol/hr. The absorber has four theoretical plates and operates at 135psig and 100°F. All of the absorbed material is recovered in a steam stripper that has a large number of plates and operates at 25 psig and 230°F. 

Operating conditions for the absorption and stripping towers are important design parameters for the process. Due to vapor pressure and entrainment, propane will be present in the effluent gas streams from both the absorber and stripper. Usually this quantity of propane is not recovered and is considered an economic loss. The amount of propane in the gas phase is mainly dependent on the operating temperature and pressure of the towers. 

Figure 1 shows the vapor pressure of some of the relevant compounds as a function of temperature. At -230.8°F and -184°F, the vapor pressure of propane is about 0.1 mm Hg and 1 mm Hg respectively. Absorption/stripping process is a conventionally practical process so it is decided to evaluate the separation of methane from hydrogen and carbon monoxide by this process. Since the operating pressures of the absorber and stripper are about 500 psia and 487 psia respectively, the mole fractions of propane in the outlet gas streams of the absorber and stripper are about 6.75 x 10 6 and 1 x 10 4 at -230.8°F and -184°F respectively. 

When the absorber operates at higher temperature as shown in Table II, propane losses increase. When the absorber and stripper operate at -230.8°F and -184°F respectively, the propane loss is equivalent to about 0.0850% and 3.28% respectively of the cost of methane assuming the cost of methane and propane is the same. 

This low percentage of propane loss was considered acceptable. Hence it was determined to operate the absorber at -230.8°F and the stripper at -184°F. 

Table II. Propane Losses at Different Absorber Temperatures (Stripper Temperature -184°F)...

This effluent then goes to a condenser where aldehydes and by-products drop out this mixture is removed in a separator. The liquid stream from the separator contains appreciable amounts of dissolved gases, mainly propylene and propane. A product stripping column distills these out. The liquid stream from this stripper goes through two distillation columns in series that remove iso- and n-butyraldehyde as overhead products, respectively. A small stream that contains heavy by-products formed in the reactor leaves the bottom of the second column. This stream can be combined with the heavy ends stream from the n-butanol column and valuable aldehydes and alcohols recovered for recycle. The iso-butyraldehyde overhead product from the first aldehyde column may be hydrogenated and sold as a low cost solvent, cracked to synthesis gas and recycled to the oxo reactors, or burned as fuel. 

As shown in Fig. 18.23, dry liquid feed containing olefins and isobutane is charged to a combined reactor-settler. In this example, the reactor uses the principle of a differential gravity head to circulate through a cooler before contacting a highly dispersed hydrocarbon feed in the reactor pipe. The hydrocarbon phase, generated in the settler, is sent to a fractionator, which separates LPG-quality propane, isobutane recycle, n-butane, and alkylate products. A small amount of dissolved catalyst is also removed from the propane product by a small stripper tower. 

The scrubbing oil absorbs none of the CH4 or N2, much of the ethane, and all of the propane and higher hydrocarbons in the gas stream. The oil stream is then sent to a stripping column, which separates the oil from the absorbed hydrocarbons. The overhead from the stripper is termed natural gasoline, while the bottoms from the stripper is called lean oil. The lean-oil stream is cooled and returned to the absorption column. Assume that there are no leaks in the system. Gas from the wells is fed to the absorption column at the rate of 52,000 lb moles/day and the flow rate of the rich oil going to the stripper is 1230 Ib/min (MW = 140). Calculate ... 

The process concept involves the extraction of light hydrocarbon oils from asphaltic petroleum supercritical solvents followed by a subsequent fractionation and separation of the oil from the solvent. It is stated that the metal compounds which are present in the asphaltic petroleum do not dissolve in the solvent under the conditions of operation. The primary difference claimed for this new process relative to the old processes is that the solvent is at or above the critical temperature rather than below the critical temperature as is described in prior art. The operation is explained in the patent with the aid of a simple distillation-like extraction vessel. Asphaltic feedstock is heated and introduced into the extraction vessel. The solvent is also heated and introduced into the vessel and the two streams are mixed. The temperature is maintained at or above the critical temperature of the solvent. In the extractor, the non-soluble components of the feed setde and are removed and sent to a stripper to recover and recycle the solvent. Several examples give quantitative information when an asphaltic feedstock containing 28 ppm Ni, 220 ppm V is used. The oil yield and metal content results are given below for two cases where the solvent is catalytic cracker gasoline and propane, resf>ectively. 

A reboiled stripper in a natural gas plant is to be used to remove mainly propane and lighter components from the feed shown below. Determine by the group method the compositions of the vapor and liquid products. 

Dqnxipanizer overhead went to an HF strapper. Strqiper bottoms was the propane product, while stripper overhead was recycled to the depropanizer overhead. When ethane entered the depropanizer due to an upstream imit upset, it entnqtped in the overhead system and could not get out. Dqtrqnnizer pressure climbed and excessive venting was needed. 

The stripper hottom temperature was reduced temporarily to allow ethane into the propane product Within two shifts the tr rped ethane was cleared. 

Some of the chemicals frequently used in huffing along with their common sources given in parentheses are as follows acetone (solvent—paint or hardware store), butane (disposable cigar and cigarette lighters), propane (outdoor grill fuel, spray paint propellent), toluene (solvent—paint or hardware store), methylene chloride (paint stripper— paint or hardware store). Freon (propellent—compressed gas duster), and xylene (solvent—paint or hardware store). 

Wax and propane and oil and propane are sent from the filters to their respective recovery sections. High pressure flash, low pressure flash, stripper and drier vessels are used to recover propane from the product. 

The process flow of an HF alkylation unit Is somewhat similar. The inlet charge Is intimately mixed with the HF catalyst and then goes to a settler. The acid phase is recycled to the reactor occasionally, a small portion is regenerated. The settler overhead product is freed of isobutane and lighter components in the isostrlp-per, the bottom product of which is a motor blending alkylate. A portion of the isostripper overhead vapors is depropanized, and the propane is freed of acid in the HF stripper. The deposits will be iron fluorides and, very infrequently, iron oxides (the fluid usually is too acidic for oxides to form). Dilute HCI is generally used to clean these units. The addition of boric acid will sometimes aid the treatment. The... 

The bottoms liquid from the deethanizer serves as the principal feed to the depropanizer. A second feed stream to this column consists of the bottoms liquid from the condensate stripper for the fourth and fifth compression stages. The primary function of this column is propylene and propane recovery from these two feeds. The column operating pressure typically will be 240 to 340 psia, which is sufficient to condense the over-... 

The descriptive term reboiied absorber is somewhat misleading in describing the function, although it is the name most commonly used. Another descriptive name and the one most often used in the hydrocarbon processing industries is rich oil demethanizer where high ethane recovery is attained or rich oil deethanizer when propane recovery is practiced in either case, the abbreviation ROD is often used. The most accurately descriptive name but, unfortunately, the one least used now is stripper-reabsorber. 

The UCBSRP process is claimed to have significantly lower capital and operating costs than the combination of an ethanolamine absorber/stripper unit plus a Claus plant plus a SCOT tail gas unit. Most of the energy consumed by the process is connected with the recovery and fractionation of propane and heavier hydrocarbons. Approximately 92% of the electrical power usage and 89% of the cooling requirements are associated with hydrocarbon recovery and separation (Sciamanna et al., 1988). The heat generated by the sulfur furnace more than offsets the heat demand required by the desulfurization of the natural gas stream. 

The additive recovery column is basically a stripper to remove hydrogen sulfide and light hydrocarbons, primarily ethane and propane, from the circulating additive stream. Excess C4+ hydrocarbons that accumulate in the stripped additive are removed as net product, which can be combined with the overhead product as indicated in the flow diagram or handled separately. When the plant feed contains hydrogen sulfide, this will appear in the overhead of the additive recovery column and may be removed from this stream by amine treating (not shown on the diagram). 

A measure of 100 kgmol/h of feed gas at 17 atm and 100°C, containing 3% ethane, 20% propane, 37% n-butane, 35% n-pentane, 5% n-hexane, is to be separated such that 100% ethane, 95% propane, and 1.35% M-butane of the feed stream are to be recovered in the overhead stream. Use stripper to find the molar flow rates and compositions of the bottom stream. 

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