Gas Processing and Treatment CHET 3011 Fall 2024 - Week 9 PDF

Gas Processing & Treatment CHET 3011 Fall 2024 Chapter 5 Gas Treating (Removal of Acid Gases) 1  Acid Gases Acid Gases Gas treating involves reduction of the “aci...

Gas Processing & Treatment CHET 3011 Fall 2024 Chapter 5 Gas Treating (Removal of Acid Gases) 1  Acid Gases Acid Gases Gas treating involves reduction of the “acid gases” carbon dioxide (CO2) and hydrogen sulfide (H2S), along with other sulfur species, to sufficiently low levels to meet contractual specifications or permit additional processing in the plant without corrosion and plugging problems. In a survey of U.S. gas resources, Meyer (2000) defined subquality gas as that containing: CO2 > 2% Or H2S > 4ppmv. 2 Required Purification Levels 3  Selecting A Suitable Treatment Process The following items should be considered during the selection and the design of the acid gas removal processes. Type of impurities (ex: Presence of COS, CS2, & mercaptans RSH affect liq. absorbent selection) Operating temperature and pressure Volumetric flow rate of the gas Required specifications Selectivity of acid gas removal Capital & Operating cost Environmental impact (ex: air pollution and hazardous byproducts) 4 Selecting A Suitable Treatment Process 5  Solvent Absorption Operating Principle In absorption, the feed is a gas introduced at the bottom of the column, and the solvent is fed to the top, as a liquid; the absorbed gas and solvent leave at the bottom, and the unabsorbed components leave as gas from the top. When two phases are brought into contact, they eventually reach equilibrium. In absorption gas molecules are diffusing into the liquid, with negligible transfer in the reverse direction. In many instances the absorption is accompanied by the evolution of heat, and it is therefore necessary to fit coolers to the equipment to keep the temperature sufficiently low for an adequate degree of absorption to be obtained. 6  Solvent Absorption Column Equipment: Trayed Columns Packed Columns At higher liquid rates in absorption, packed columns are much more commonly used. Types of Solvents Used Chemical Solvents (Absorption is accompanied by chemical reaction ex: Amine process and Alkali salt process) Physical Solvents (Absorption occurs without chemical reactions ex: Selexol) 7 Chemical Absorption (1) Amine Process 8  Amine Process Amines Amines are compounds formed from ammonia (NH3) by replacing one or more of the hydrogen atoms with another hydrocarbon group. Replacement of a single hydrogen produces a primary amine, replacement of two hydrogen atoms produces a secondary amine, and replacement of all three of the hydrogen atoms produces a tertiary amine. Primary amines are the most reactive, followed by the secondary and tertiary amines. Amine Solutions used for Acid Gas Removal The amines are alkanol amines in water solutions in concentrations ranging from approximately 10 to 65 wt% amines. Alkanol amine is an amine with a hydroxyl (OH-) group to reduce its volatility. 9 Molecular Structures of Commonly Used Amines 10  Reactions during Amine Process Amines are bases, and the important reaction in gas processing as the ability of the amine to form salts with the weak acids formed by H2S and CO2 in an aqueous H2O solution. When a gas stream that contains acid gases (H2S, CO2), or both, is contacted by an amine solution, the acid gases react to form a soluble acid-base complex (a salt), in the treating solution. The reaction between the amine and both H2S and CO2 is highly exothermic. Therefore the amine regeneration step is endothermic (requires heating in a stripper) Example: The reaction between a tertiary amine with H2S forms amine hydrosulfide according to: 11  Monoethanolamine (MEA) Monoethanolamine (MEA) is the most basic of the amines used in acid treating and thus the most reactive for acid gas removal. Advantages High solution capacity at moderate concentrations Used for gas streams with moderate levels of CO2 and H2S when complete removal of both impurities is required. Disadvantages Relatively high vapor pressure leading to high vaporization losses. Formation of irreversible reaction products with CO and S2 High heat of reaction with the acid gases that results in high energy requirements in regeneration. Inability to selectively remove H2S in the presence of CO2 Higher corrosion rates than most other amines if the MEA concentration exceeds 20% at high levels of acid gas loading 12  Diglycolamine (DGA) Compared with MEA, low vapor pressure allows Diglycolamine (DGA) to be used in relatively high concentrations (50 to 70%), which results in lower circulation rates. About Stable salts A slow production of “heat stable salts” form in all alkanol amine solutions, primarily from reaction with CO2. Oxygen enhances the formation of the salts. In addition to fouling regenerator reboilers, high concentrations of salts can carry over to the contactor and cause foaming, which degrades contactor efficiency. One “advantage” of MEA (and DGA) over other amines is that “reclaimers” are installed in-line for intermittently removing these salts. 13  Diethanolamine (DEA) Diethanolamine (DEA), a secondary amine, is less basic and reactive than MEA. Advantages DEA has a lower vapor pressure than MEA and thus, lower evaporation losses; It can operate at higher acid gas loadings than MEA, typically 0.35 to 0.8 mole acid gas/mole of amine for DEA versus 0.3 to 0.4 mole acid-gas/mole for MEA Lower energy requirement for reactivation than MEA.. Disadvantages It undergoes irreversible side reactions with CO2 and forming corrosive degradation products; thus, it may not be the best choice for high CO2 gases. Removal of these degradation products along with the O2-heat stable salts must be done by use of either vacuum distillation or ion exchange. The reclaiming may be done offsite or in portable equipment brought onsite. 14  Methyldiethanolamine (MDEA) Methyldiethanolamine (MDEA), a tertiary amine, selectively removes H2S to pipe H2S liine specifications while “slipping” some of the CO2 because the reaction of MDEA with H2S is much faster than that with CO2. Advantages Short contact times in the absorber are used to obtain the H2S selectivity. MDEA has a low vapor pressure and thus, can be used at concentrations up to 60 wt% without appreciable vaporization losses which makes it able to remove large amounts of CO2 if enough contact time is provided. Disadvantages Not reclaimable by conventional methods (not easily reclaimed) 15  Mixed Amines The selectivity of MDEA can be reduced by addition of MEA, DEA, or proprietary additives. Thus, it can be tailored to meet the desired amount of CO2 slippage and still have lower energy requirements than do primary and secondary amines. 16 Process Flow Diagram for Amine (MEA) 17  Process Flow Description for Amine (MEA) The sour gas feed enters the bottom of the contactor at pressures up to 1,000 psi (70 bar) and temperatures in the range of 90°F (30°C). The sour gas flows upward, countercurrent to the lean amine solution (amine solution without acid gases), which flows down from the top. The lean amine inlet temperature is maintained 5°F (3°C) or more above the inlet gas temperature to prevent condensation of heavier hydrocarbon liquids. Intimate contact between the gas and amine solution is achieved by use of either trays or packing in the contactor. The contactor operates above ambient temperature because of the combined exothermic heat of absorption and reaction. 18  Process Flow Description for Amine (MEA) The maximum temperature is generally in the lower portion of the tower because the majority of the absorption and reaction occurs near the bottom (can reach 180°F (80°C)). The treated gas leaves the top of the tower water saturated (humid) and at a temperature controlled by the temperature of the lean amine that enters, usually around 100°F (38°C). The maximum temperature reached in the contactor and the shape of the temperature profile are functions of several parameters, including feed gas temperature, amine type, relative amount of CO2 and H2S in the feed gas, relative feed gas and amine rates, reaction kinetics, and contactor mass transfer. 19  Process Flow Description for Amine (MEA) The rich amine (amine containing absorbed acid gases) leaves the absorber bottom at temperatures near 140°F (60°C). The rich amine pressure is reduced to 75–100 psig (5–7 barg) to remove dissolved hydrocarbons & acid gases in a flash tank. The rich amine then passes through a heat exchanger and enters the solvent regenerator (stripper) at temperatures in the range of 180°F– 200°F (80°C–100°C). The regenerator reboiler commonly uses hot oil as the heating medium to prevent high skin temperatures or hot spots, which can degrade the amine. Sometimes low-pressure steam generated by hot oil is used. 20  Process Flow Description for Amine (MEA) The vapor generated at the bottom flows upward through either trays or packing, where it contacts the rich amine and strips the acid gases from the liquid that flows down. The regenerator overhead vapor, which consists mostly of acid gases and water vapor, passes through a condenser to recover water and amine and is often processed for sulfur recovery. The lean amine exits the bottom of the regenerator at about 260°F (130°C) and is pumped to the contactor operating pressure. The lean amine exchanges heat with the rich amine stream and is further cooled before it enters the top of the contactor. 21  Process Flow Description for Amine (MEA) The regenerator reboiler commonly uses hot oil as the heating medium to prevent high skin temperatures or hot spots, which can degrade the amine. Sometimes low-pressure steam generated by hot oil is used. The vapor generated at the bottom flows upward through either trays or packing, where it contacts the rich amine and strips the acid gases from the liquid that flows down. The regenerator overhead vapor, which consists mostly of acid gases and water vapor, passes through a condenser to recover water and amine and is often processed for sulfur recovery. The lean amine exits the bottom of the regenerator at about 260°F (130°C) and is pumped to the contactor operating pressure. The lean amine exchanges heat with the rich amine stream and is further cooled before it enters the top of the contactor. Both the treated gas leaving the gas contactor and the acid gas from the regenerator are water saturated. 22 23 Chemical Absorption (2) Alkali Salts 24  Alkali Salts Process In the “Alkali Salts” absorption process, hot potassium carbonate is used as the absorbent for removal of CO2 and H2S. The process is very similar in concept to the amine process, in that after physical absorption into the liquid, the CO2 and H2S react chemically with the solution. The chemistry is relatively complex, but the overall reactions are represented by: 25 Alkali Salts Process 26  Physical Solvents Physical Absorption In the amine and alkali salt processes, the acid gases are removed in two steps: physical absorption followed by chemical reaction. In processes such as Selexol or Rectisol , no chemical reaction occurs, and acid gas removal depends entirely on physical absorption. Physical Absorption is characterized by: Less energy requirements for regeneration with respect to amines. Solvents can be chosen for selective removal of sulfur compounds, which allows CO2 to be slipped into the residue gas stream and reduce separation costs. Partial dehydration occurs (unlike amines that result in treated gas that is saturated with water vapor). Absorption can occur near ambient conditions. Remove substantial quantities of heavy hydrocarbons, a feature that can be either positive or negative, depending on the composition of the gas being processed and the desired products. Unlike the amine systems, no irreversible products are generated in the process, which thus eliminates the need for reclaiming. 27 Chemical Solvents vs Physical Solvents 28  Hybrid Process To take advantage of the strengths of each type, a number of hybrid processes commercially used, and under development, combine physical solvents solvent- with amines. Depending upon the amine combination, nearly complete removal of H2S, CO2, and COS is possible. Other hybrid systems provide high H2S and COS removal while slipping CO2. Sulfinol is one of the more commonly used processes. The process uses a combination of a physical solvent (sulfolane) with DIPA or MDEA. Like the physical solvent processes, the hybrid systems may absorb more hydrocarbons, including BTEX, but that property can be adjusted by varying water content. 29