Developed by Allied Chemical Company, this process is selective toward removing sulfur compounds. Levels of CO2 can be reduced by approximately 85%. This process may be used economically when there are high acid-gas partial pressures and the absence of heavy ends in the gas, but it will not normally meet pipeline gas requirements. This process also removes water to less than 1 Ib/MMscf. DIPA can be added to the solution to remove CO2 down to pipeline specifications. This system then functions much like the Sulfinol® process discussed earlier. The addition of DIPA will increase the stripper heat duty; however, this duty is relatively low.
Several proprietary processes have been developed based on the hot carbonate system with an activator or catalyst. These activators increase the performance of the hot PC system by increasing the reaction rates both in the absorber and the stripper. In general, these processes also decrease corrosion in the system. The following are some of the proprietary processes for hot potassium carbonate:
Benfield: Several activators
Girdler: Alkanolamine activators
Catacarb; Alkanolamine and/or borate activators
Giammarco-Vetrocoke: Arsenic and other activators
Licensed by Shell the Sulfinol® process combines the properties of a physical and a chemical solvent. The Sulfinol solution consists of a mixture of sulfolane (tetrahydrothiophene 1-1 dioxide), which is a physical solvent, diisopropanolamine (DIPA), and water. DIPA is a chemical solvent that was discussed under the amines.
The physical solvent sulfolane provides the system with bulk removal capacity. Sulfolane is an excellent solvent of sulfur compounds such as H2S, COS, and CS2. Aromatic and heavy hydrocarbons and CO2 are soluble in sulfolane to a lesser degree. The relative amounts of DIPA and sulfolane are adjusted for each gas stream to custom fit each application. Sulfinol® is usually used for streams with an H2S to CO2 ratio greater than 1:1 or where it is not necessary to remove the CO2 to the same levels as is required for H2S removal. The physical solvent allows much greater solution loadings of acid gas than for pure amine-based systems. Typically, a Sulfinol® solution of 40% sulfolane, 40% DIPA and 20% water can remove 1.5 moles of acid gas per mole of Sulfinol® solution.
The chemical solvent DIPA acts as secondary treatment to remove H2S and CO2. The DIPA allows pipeline quality residual levels of acid gas to be achieved easily. A stripper is required to reverse the reactions of the DIPA with CO2 and H2S. This adds to the cost and complexity of the systern compared to other physical solvents, but the heat requirements are much lower than for amine systems, A reclaimer is also required to remove oxazolidones produced in a side reaction of DIPA and CO2.
These processes are based on the solubility of the H2S and/or CO2 within the solvent, instead of on chemical reactions between the acid gas and the solvent. Solubility depends first and foremost on partial pressure and secondarily on temperature. Higher acid-gas partial pressures and lower temperatures increase the solubility of H2S and CO2 in the solvent and thus decrease the acid-gas components.
Various organic solvents are used to absorb the acid gases. Regeneration of the solvent is accomplished by flashing to lower pressures and/or stripping with solvent vapor or inert gas. Some solvents can be regenerated by flashing only and require no heat. Other solvents require stripping and some heat, but typically the heat requirements are small compared to chemical solvents.
Physical solvent processes have a high affinity for heavy hydrocarbons, if the natural gas stream is rich in C3+ hydrocarbons, then the use of a physical solvent process may result in a significant loss of the heavier molecular weight hydrocarbons. These hydrocarbons are lost because they are released from the solvent with the acid gases and cannot be economically recovered.
Under the following circumstances physical solvent processes should be considered for gas sweetening:
1. The partial pressure of the acid gases in the feed is 50 psi or higher.
2. The concentration of heavy hydrocarbons in the feed is low. That is,
the gas stream is lean in propane-plus.
3. Only bulk removal of acid gases is required.
4. Selective H2S removal is required.
A physical solvent process is shown in Figure 7-6. The sour gas contacts the solvent using counter-current flow in the absorber. Rich solvent from the absorber bottom is flashed in stages to a pressure near atmospherie. This causes the acid-gas partial pressures to decrease; the acid gases evolve to the vapor phase and are removed. The regenerated solvent is then pumped back to the absorber.
The example in Figure 7-6 is a simple one in that flashing is sufficient to regenerate the solvent. Some solvents require a stripping column just prior to the circulation pump.
Most physical solvent processes are proprietary and are licensed by the company that developed the process.
This process uses propylene carbonate as a physical solvent to remove CO2 and H2S. Propylene carbonate also removes C2+ hydrocarbons, COS, SO2, CS2, and H2O from the natural gas stream. Thus, in one step the natural gas can be sweetened and dehydrated to pipeline quality. In general, this process is used for bulk removal of CO2 and is not used to treat to less than 3% CO2, as may be required for pipeline quality gas, The system requires special design features, larger absorbers, and higher circulation rates to obtain pipeline quality and usually is not economically applicable for these outlet requirements.
Propylene carbonate has the following characteristics, which make it suitable as a solvent for acid gas treating:
1. High degree of solubility for CO2 and other gases.
2. Low heat of solution for CO2.
3. Low vapor pressure at operating temperature.
4. Low solubility for light hydrocarbons (Cl5 C2).
5. Chemically nonreactive toward all natural gas components.
6. Low viscosity.
7. Noncorrosive toward common metals.
These characteristics combine to yield a system that has low heat and pumping requirements, is relatively noncorrosive, and suffers only minimal solvent losses (less than 1 Ib/MMscf). Solvent temperatures below ambient are usually used to increase the solubility of acid gas components and therefore decrease circulation rates.
The German Lurgi Company and Linde A. G. developed the Rectisol® process to use methanol to sweeten natural gas. Due to the high vapor pressure of methanol this process is usually operated at temperatures of -30 to ~100°F. It has been applied to the purification of gas for LNG plants and in coal gasification plants, but is not used commonly to treat natural gas streams.
A bed of random packing typically consists of a bed support (typically a gas injection support plate) upon which pieces of packing material are randomly arranged (they are usually poured or dumped onto this support plate). Bed limiters, or hold-downs, are sometimes set above random beds to prevent the pieces of packing from migrating or entraining upward. Random packing comes in a variety of shapes and sizes. For a given shape (design) of packing, small sizes have higher efficiencies and lower capacities than large sizes.
Figure 6-8 shows a variety of random packing designs. An early design is known as a Raschig ring. Raschig rings are short sections of tubing and are low-capacity, low-efficiency, high-pressure drop devices. Today’s industry standard is the slotted metal (Pall) ring. A packed bed made of 1-in. slotted metal rings will have a higher mass transfer efficiency and a higher capacity than will a bed of 1-in. Raschig rings. The HETP for a 2-in, slotted metal ring in a condensate stabilizer is about 36 in. This is slightly more than a typical tray design, which would require 34 in. (1.4 trays x 24-in. tray spacing) for one theoretical plate or stage.
A bed of structured packing consists of a bed support upon which elements of structured packing are placed. Beds of structured packing typically have lower pressure drops than beds of random packing of comparable mass transfer efficiency. Structured packing elements are composed of grids (metal or plastic) or woven mesh (metal or plastic) or of thin vertical crimped sheets (metal, plastic, or ceramic) stacked parallel to each other. Figure 6-9 shows examples of the vertical crimped sheet style of
The grid types of structured packing have very high capacities and very low efficiencies, and are typically used for heat transfer or for vapor scrubbing. The wire mesh and the crimped sheet types of structured packing typically have lower capacities and higher efficiencies than the grid type.
For distillation services, as in condensate stabilization, tray design is well understood, and many engineers are more comfortable with trays than with packing. In the past, bubble cap trays were the standard. However, they are not commonly used in this service anymore. Sieve trays are inexpensive but offer a very narrow operating range when compared with valve trays. Although valve trays offer a wider operating range than sieve trays, they have moving parts and so may require more maintenance.
High capacity/high efficiency trays can be more expensive than standard valve trays. However, high capacity/high efficiency trays require smaller diameter towers, so they can offer significant savings in the overall cost of the distillation tower. The high capacity/high efficiency tray can also be an ideal candidate for tower retrofits in which increased throughputs are required for existing towers.
Random packing has traditionally been used in small diameter (<20 in.) towers. This is because it is easier and less expensive to pack these small diameter towers. However, random packed beds are prone to channeling and have poor turndown characteristics when compared with trays. For these reasons, trays were preferred for tower diameters greater than 20 in. In recent years an improved understanding of the impact of high pressure on packing performance has been gained. Improved vapor and liquid distributor designs and modified bed heights have made the application of packing to large-diameter, high-pressure distillation towers more common. A properly designed packed bed system (packing, liquid distributors, vapor distributors) can be an excellent choice for debottlenecking existing distillation towers.
For stripping service, as in a glycol or amine contactor , bubble cap trays are the most common. In recent years, there has been a growing movement toward crimped sheet structured packing. Improved vapor and liquid distributor design in conjunction with structured packing can lead to smaller-diameter and shorter stripping towers than can be obtained with trays.