Acid Gas Treating 161 structure of the solids provides a very porous solid material with all the pores exactly the same size. Within the pores the crystal structure creates a large number of localized polar charges called active sites. Polar gas molecules, such as H 2 S and water, that enter the pores form weak ionic bonds at the active sites. Nonpolar molecules such as paraffin hydrocar- bons will not bond to the active sites. Thus, molecular sieve units will "dehydrate" the gas (remove water vapor) as well as sweeten it. Molecular sieves are available with a variety of pore sizes. A molecu- lar sieve should be selected with a pore size that will admit H 2 S and water while preventing heavy hydrocarbons and aromatic compounds from entering the pores. However, carbon dioxide molecules are about the same size as H 2 S molecules and present problems. Even though the CO 2 is non-polar and will not bond to the active sites, the CO 2 will enter the pores. Small quantities of CO2 will become trapped in the pores. In this way small portions of CO 2 are removed. More importantly, CO 2 will obstruct the access of H 2 S and water to active sites and decrease the effectiveness of the pores. Beds must be sized to remove all water and to provide for interference from other molecules in order to remove all H 2 S. The absorption process usually occurs at moderate pressure. Ionic bonds tend to achieve an optimum performance near 450 psig, but the process can be used for a wide range of pressures. The molecular sieve bed is regenerated by flowing hot sweet gas through the bed. Typical regeneration temperatures are in the range of 300-40()°F. Molecular sieve beds do not suffer any chemical degradation and can be regenerated indefinitely. Care should be taken to minimize mechanical damage to the solid crystals as this may decrease the bed's effectiveness. The main causes of mechanical damage are sudden pressure and/or tem- perature changes when switching from absorption to regeneration cycles. Molecular sieves for acid gas treatment are generally limited to small gas streams operating at moderate pressures. Due to these operating limi- tations, molecular sieve units have seen limited use for gas sweetening operations. They are generally used for polishing applications following one of the other processes and for dehydration of sweet gas streams where very low water vapor concentrations are required. Techniques for sizing molecular sieve units are discussed in Chapter 8. Chemical Solvents Chemical solvent processes use an aqueous solution of a weak base to chemically react with and absorb the acid gases in the natural gas stream. 162 Design of GAS-HANDLING Systems and Facilities The absorption occurs as a result of the driving force of the partial pres- sure from the gas to the liquid. The reactions involved are reversible by changing the system temperature or pressure, or both. Therefore, the aqueous base solution can be regenerated and thus circulated in a contin- uous cycle. The majority of chemical solvent processes use either an atnine or carbonate solution. Amine Processes Several processes are available that use the basic action of various amines. These amines can be categorized as primary, secondary, or ter- tiary according to the number of organic groups bonded to the central nitrogen atom. Primary amines are stronger bases than secondary amines, which are stronger than tertiary amines. Amines with stronger base properties will be more reactive toward CO2 and H 2 S gases and will form stronger chemical bonds. A typical amine system is shown in Figure 7-4. The sour gas enters the system through an inlet separator to remove any entrained water or hydrocarbon liquids. Then the gas enters the bottom of the amine absorber and flows counter-current to the amine solution. The absorber can be either a trayed or packed tower. Conventional packing is usually used for 20-in. or smaller diameter towers, and trays or structured pack- ing for larger towers. An optional outlet separator may be included to recover entrained amines from the sweet gas. The amine solution leaves the bottom of the absorber carrying with it the acid gases. This solution containing the CC>2 and IH^S is referred to as the rich amine. From the absorber the rich amine is flashed to a flash tank to remove almost all the dissolved hydrocarbon gases and entrained hydrocarbon condensates. A small percentage of the acid gases will also flash to the vapor phase in this vessel. From the flash tank the rich amine proceeds to the rich/lean amine exchanger. This exchanger recovers some of the sensible heat from the lean amine stream to decrease the heat duty on the amine reboiler. The heated rich amine then enters the amine strip- ping tower where heat from the reboiler breaks the bonds between the amines and acid gases. The acid gases are removed overhead and lean amine is removed from the bottom of the stripper. The hot lean amine proceeds to the rich/lean amine exchanger and then to additional coolers to lower its temperature to no less than LO°F above the inlet gas temperature. This prevents hydrocarbons from con- Acid Gas Treating 163 Figure 7-4. Amine system for gas sweetening. densing in the amine solution when the amine contacts the sour gas. The cooled lean amine is then pumped up to the absorber pressure and enters the top of the absorber. As the amine solution flows down the absorber it absorbs the acid gases. The rich amine is then removed at the bottom of the tower and the cycle is repeated. Of the following amine systems that are discussed, diethanol amine (DBA) is the most common. Even though a DBA system may not be as efficient as some of the other chemical solvents, it may be less expensive to install because standard packaged systems are readily available. In addition, it may be less expensive to operate and maintain because field personnel are likely to be more familiar with it. Monoethanolamine Systems. Monoethanolarnine (MBA) is a primary amine that can meet nominal pipeline specifications for removing both H 2 S and CO 2 . MBA is a stable compound and in the absence of other chemicals suffers no degradation or decomposition at temperatures up to its normal boiling point. ME A reacts with CC>2 and H 2 S as follows: 164 Design of GAS-HANDLING Systems and Facilities These reactions are reversible by changing the system temperature. MEA also reacts with carbonyl sulflde (COS) and carbon disulfide (CS 2 ) to form heat-stable salts that cannot be regenerated. At temperateres above 245 °F a side reaction with CO 2 exists that produces oxazolidone-2, a heat-stable salt, and consumes MEA from the process. The reactions with CO 2 and H 2 S shown are reversed in the stripping column by heating the rich MEA to approximately 245°F at 10 psig. The acid gases evolve into the vapor and are removed from the still overhead. Thus, the MEA is regenerated, The normal regeneration temperature in the still will not regenerate heat-stable salts or oxazolidone-2. Therefore, a reclaimer is usually included to remove these contaminants. A side stream of from 1 to 3% of the MEA circulation is drawn from the bottom of the stripping column. This stream is then heated to boil the water and MEA overhead while the heat-stable salts and oxazolidone-2 are retained in the reclaimer. The reclaimer is periodically shut in and the collected contaminants are cleaned out and removed from the system. However, any MEA bonded to them is also lost. MEA is usually circulated in a solution of 15-20% MEA by weight in water. From operating experience the solution loading should be between 0.3-0.4 moles of acid gas removed per mole of MEA. Both the solution strength and the solution loading are limited to avoid excessive corro- sion. The higher the concentration of H 2 S relative to CO 2 , the higher the amine concentration and allowable loading. This is due to the reaction of H 2 S and iron (Fe) to form iron sulfide (Fe 2 S 3 ), which forms a protective barrier on the steel surface. The acid gases in the rich amine are extremely corrosive. The corro- sion commonly shows up on areas of carbon steel that have been Acid Gas Treating 165 stressed, such as heat-affected zones near welds, in areas of high acid-gas concentration, or at a hot gas-liquid interface. Therefore, stress-relieving all equipment after manufacturing is necessary to reduce corrosion, and special metallurgy in specific areas such as the still overhead or the reboiler tubes may be required. MEA systems foam rather easily resulting in excessive amine carry- over from the absorber. Foaming can be caused by a number of foreign materials such as condensed hydrocarbons, degradation products, solids such as carbon or iron sulfide, excess corrosion inhibitor, valve grease, etc. Solids can be removed with cartridge filters. Hydrocarbon liquids are usually removed in the flash tank. Degradation products are removed in a reclaimer as previously described. Storage tanks and surge vessels for MEA must have inert blanket-gas systems. Sweet natural gas or nitrogen can be used as the blanket gas. This is required because MEA will oxidize when exposed to the oxygen in air. As the smallest of the ethanolamine compounds, MEA has a relatively high vapor pressure. Thus, MEA losses of 1 to 3 Ib/MMscf are common. In summation, MEA systems can efficiently sweeten sour gas to pipeline specifications; however, great care in designing the system is required to limit equipment corrosion and MEA losses, Diethanolamine Systems. Diethanolamine (DBA) is a secondary arnine that has in recent years replaced MEA as the most common chemi- cal solvent. As a secondary amine, DEA is a weaker base than MEA, and therefore DEA systems do not typically suffer the same corrosion prob- lems, In addition, DEA has lower vapor loss, requires less heat for regen- eration per mole of acid gas removed, and does not require a reclaimer, DEA reacts with H 2 S and CO 2 as follows: 166 Design of GAS-HANDLING Systems and Facilities These reactions are reversible. DBA reacts with carbonyl sulfide (COS) and carbon disulfide (CS 2 ) to form compounds that can be regenerated in the stripping column. Therefore, COS and CS 2 are removed without a loss of DEA. Typically, DBA systems include a carbon filter but do not include a reclaimer. The stoichiometry of the reactions of DEA and MEA with CO 2 and H 2 S is the same. The molecular weight of DEA is 105, compared to 61 for MEA, The combination of molecular weights and reaction stoichiometry means that approximately 1.7 Ib of DEA must be circulated to react with the same amount of acid gas as 1.0 Ib of MEA. However, because of its lower corrosivity, the solution strength of DEA ranges up to 35% by weight compared to only 20% for MEA. Loadings for DEA systems range to 0.65 mole of acid gas per mole of DEA compared to a maximum of 0.4 mole of acid gas per mole of MEA. The result of this is that the circulation rate of a DEA solution is slightly less than for a comparable MEA system. The vapor pressure of DEA is approximately l/30th of the vapor pres- sure of MEA; therefore, amine losses as low as { A- { A Ib/MMscf can be expected. Diglycolamine Systems. The Fluor Econamine® process uses diglyco- lamine (DGA) to sweeten natural gas. The active DGA reagent is 2-(2- amino-ethoxy) ethanol, which is a primary amine. The reactions of DGA with acid gases are the same as for MEA. Degradation products from reactions with COS and CS 2 can be regenerated in a reclaimer. DGA systems typically circulate a solution of 50-70% DGA by weight in water. At these solution strengths and a loading of up to 0.3 mole of acid gas per mole of DGA, corrosion in DGA systems is slightly less than in MEA systems, and the advantages of a DGA system are that the low vapor pressure decreases amine losses, and the high solution strength decreases circulation rates and heat required. Diisopropanolamine Systems. Diisopropanolamine (DIPA) is a sec- ondary amine used in the Shell ADIP® process to sweeten natural gas. DIPA systems are similar to MEA systems but offer the following advan- tages: carbonyl sulfide (COS) can be removed and regenerated easily and the system is generally noncorrosive and requires less heat input. One feature of this process is that at low pressures DIPA will preferen- tially remove H 2 S. As pressure increases the selectivity of the process decreases. The DIPA removes increasing amounts of CO 2 as well as the H 2 S. Therefore, this system can be used either selectively to remove H 2 S or to remove both CO 2 and H 2 S. Acid Gas Treating 167 Hot Potassium Carbonate Process The hot potassium carbonate (K 2 CO 3 ) process uses hot potassium car- bonate to remove both CO 2 and H 2 S. It works best on a gas with CO 2 partial pressures in the range of 30-90 psi. The main reactions involved in this process are: It can be seen from Equation 7-12 that H 2 S alone cannot be removed unless there is sufficient CO 2 present to provide KHCO 3 , which is need- ed to regenerate potassium carbonate. Since these equations are driven by partial pressures, it is difficult to treat H 2 S to the very low require- ments usually demanded (J4 grain per 100 scf). Thus, final polishing to H 2 S treatment may be required. The reactions are reversible based on the partial pressures of the acid gases. Potassium carbonate also reacts reversibly with COS and CS 2 . Figure 7-5 shows a typical hot carbonate system for gas sweetening. The sour gas enters the bottom of the absorber and flows counter-current to the potassium carbonate. The sweet gas then exits the top of the absorber. The absorber is typically operated at 230°F; therefore, a sour/ sweet gas exchanger may be included to recover sensible heat and decrease the system heat requirements. The acid-rich potassium carbonate solution from the bottom of the absorber is flashed to a flash drum, where much of the acid gas is removed. The solution then proceeds to the stripping column, which operates at approximately 245°F and near-atmospheric pressure. The low pressure, combined with a small amount of heat input, drives off the remaining acid gases. The lean potassium carbonate from the stripper is pumped back to the absorber. The lean solution may or may not be cooled slightly before entering the absorber. The heat of reaction from the absorption of the acid gases causes a slight temperature rise in the absorber. The solution concentration for a potassium carbonate system is limited by the solubility of the potassium bicarbonate (KHCO 3 ) in the rich 168 Design of GAS-HANDLING Systems and Facilities Figure 7-5. Hot carbonate system for gas sweetening. stream. The high temperature of the system increases the solubility of KHCC>3, but the reaction with CO 2 produces two moles of KHCO3 per mole of K 2 CO 3 reacted. For this reason the KHCO3 in the rich stream limits the lean solution K 2 CO 3 concentration to 20-35% by weight. The entire system is operated at high temperatures to increase the solu- bility of potassium carbonate. Therefore, the designer must be careful to avoid dead spots in the system where the solution could cool and precipi- tate solids. If solids do precipitate, the system may suffer from plugging, erosion, or foaming. The hot potassium carbonate solutions are extremely corrosive. All carbon steel must be stress-relieved to limit corrosion. A variety of corro- sion inhibitors are available to decrease corrosion. Proprietary Carbonate Systems 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 Acid Gas Treating 169 decrease corrosion in the system. The following are some of the propri- etary processes for hot potassium carbonate: Benfield: Several activators Girdler: Alkanolamine activators Catacarb; Alkanolamine and/or borate activators Giammarco-Vetrocoke: Arsenic and other activators Physical Solvent Processes These processes are based on the solubility of the H 2 S and/or CO 2 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 H 2 S and CO 2 in the solvent and thus decrease the acid-gas components. Various organic solvents are used to absorb the acid gases. Regenera- tion of the solvent is accomplished by flashing to lower pressures and/or stripping with solvent vapor or inert gas. Some solvents can be regenerat- ed 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 hydrocar- bons, if the natural gas stream is rich in C 3+ hydrocarbons, then the use of a physical solvent process may result in a significant loss of the heav- ier molecular weight hydrocarbons. These hydrocarbons are lost because they are released from the solvent with the acid gases and cannot be eco- nomically 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 H 2 S removal is required. A physical solvent process is shown in Figure 7-6. The sour gas con- tacts the solvent using counter-current flow in the absorber. Rich solvent from the absorber bottom is flashed in stages to a pressure near atmos- 170 Design of GAS-HANDLING Systems and Facilities pherie. This causes the acid-gas partial pressures to decrease; the acid gases evolve to the vapor phase and are removed. The regenerated sol- vent 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. Fluor Solvent Process® This process uses propylene carbonate as a physical solvent to remove CO 2 and H 2 S. Propylene carbonate also removes C 2 + hydrocarbons, COS, SO 2 , CS 2 , and H 2 O 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 CO 2 and is not used to treat to less than 3% CO 2 , 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 economical- ly applicable for these outlet requirements. Figure 7-6. Physical solvent process. [...]... the partial pressure of the acid gas components where PPj = partial pressure of component i, psia Pt = systems pressure, psia Xj = mole fraction of component i 1 SO Df>.\i&n ofGAfi-HANDUNCi Systems and Facilities Figure 7 -11 H2S removal, no CQ& Next, determine if one of the four following situations is required and use the appropriate guide: Removal of H2S with no CO2 present (Figure 7 -11 ) Removal of. .. 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 sys- 17 2 Design of GAS-HANDLING Systems and. .. line should also have a pressure tap and sample test tap The vessel is generally constructed of carbon steel that has been heat treated Control of metal hardness is required because of the potential of sulfide-stress cracking The iron-sponge vessel is either internally coated or clad with stainless steel  18 2 Design of GAS-HANDLING Systems and Facilities Figure 7 -13 CO2 removal, no h^S The superficial... retained on 16 mesh, 80 % between 30 and 60 mesh, and 10 0% retained on 325 mesh It is purchased with a moisture content of 20% by weight and buffering to meet a flood pH of 10 Because it is necessary to maintain a moist alkaline condition, provisions should be included in the design to add water and caustic DESIGN PROCEDURES FOR AMINE SYSTEMS The types of equipment and the methods for designing the equipment... dissipation of Acid Gas Treating 18 3 Figure 7 -14 Selective removal of H2S in presence of CO2 the heat of reaction This requirement also establishes a minimum required diameter, which is given by: where dmin = minimum required vessel diameter, in Qg = gas flow rate, MMscfd MF = mole fraction of H2S The larger of the diameters calculated by Equation 7 - 18 or 7 -19 will set the minimum vessel diameter Any choice of. .. The volume of gas to be treated and temperature and pressure at which the gas is available 4 The feasibility of recovering sulfur 5 The desirability of selectively removing one or more of the contaminants without removing the others 6 The presence and amount of heavy hydrocarbons and aromati.cs in the gas, Figures 7 -11 to 7 -14 can be used as screening tools to make an initial selection of potential... (less than 2 ft/min) channeling of the gas through the bed may occur Thus, it is preferred to limit the vessel diameter to: 18 4 Design of GAS-HANDLING Systems and Facilities where dmax = maximum recommended vessel diameter, in A contact time of 60 seconds is considered a minimum in choosing a bed volume A larger volume may be considered, as it will extend the bed liie and thus extend the cycle time... arnine-aldehyde condensates process is best suited for wet gas streams of 0.5 -15 MMscfd containing less than 10 0 ppm H2S 1 78 Design of GAS-HANDLING Systems and Facilities The advantages of amine-aldehyde condensates are water (or oil) soluble reaction products, lower operating temperatures, low corrosiveness to steel, and no reactivity with hydrocarbons, Distillation The Ryan-Holmes distillation process uses cryogenic... Two-stage Claus process plant 17 4 Design of GAS-HANDLING Systems and Facilities to sulfur by burning the acid-gas stream with air in the reaction furnace, This stage provides SO2 for the next catalytic phase of the reaction Multiple catalytic stages are provided to achieve a more complete conversion of the H2S Condensors are provided after each stage to condense the sulfur vapor and separate it from the... high concentrations of H2S The chemistry of the units involves partial oxidation of hydrogen sulfide to sulfur dioxide and the catalyticaily promoted reaction of H2S and SO2 to produce elemental sulfur The reactions are staged and are as follows: Figure 7-7 shows a simplified process flow diagram of the Claus® process The first stage of the process converts H2S to sulfur dioxide and Figure 7-7 Two-stage . potassium carbonate system is limited by the solubility of the potassium bicarbonate (KHCO 3 ) in the rich 16 8 Design of GAS-HANDLING Systems and Facilities Figure 7-5. Hot carbonate . a simplified process diagram of the process. 17 6 Design of GAS-HANDLING Systems and Facilities Figure 7-9. Strefford® process. Oxidized solution is delivered from the pumping tank . regen- eration per mole of acid gas removed, and does not require a reclaimer, DEA reacts with H 2 S and CO 2 as follows: 16 6 Design of GAS-HANDLING Systems and Facilities These