DESIGN GUIDELINES FOR AMINE PLANTS
ABSTRACT Amine plant design should consider the following: Selecting the most suitable amine. The process requirements and product specifications. All applicable code requirements. Optimizing the balance between capital and operating costs. Safety and environmental requirements. Keeping the design and operation simple. This paper describes how HCI Coastal Chemical Chemical addresses these criteria. The scope is limited to graphs and hand calculations that can be easily accomplished accomplished in the field. The paper is not a substitute for computer simulations. It is, however, a guide for examining plant performance performance – both proce process ss and and equipmen equipmentt – and troubl troubleshoo eshooting. ting. It is also also helpful helpful when when procuri procuring ng an amine amine plant or prepar preparing ing equipme equipment nt specific specification ations. s. Dow Chemical Company’s Company’s GAS/SPEC solvents are reviewed. reviewed. These are proprietary amine solutions formulated for specific applications. applications. The performance is superior to to what can be obtained with generic alkanolamines.
William Manning, P.E.
Ray Veldman, P.E.
HCI Coastal Chemical Co., L.L.C.
5300 Memorial Drive, 11th Floor, Houston, TX 77007 PH: 713-865-8787 FAX: 713-865-8788
April 2000
INTRODUCTION
Sweetening natural gas with aqueous amine solutions started in the 1930’s using triethanolamine, TEA. TEA use was soon discontinued discontinued due to low reactivity for CO2 and foaming. Then monoethanolamine, monoethanolami ne, MEA, dominated the market. Low amine concentrations, concentration s, low acid gas pickups, pickups, high circula circulation tion rates rates and high reboiler reboiler duties duties were were needed needed to avoid avoid unacc unaccepta eptable ble corrosion rates. In the 1960’s diethanolamine, diethanolamin e, DEA, became the preferred solvent. There were improvements in the solution strengths, acid gas loadings, circulation rates, energy usage and especially corrosion rates. Diglycolamine, DGA, and diisopropanolamine, DIPA, were also used. Mercaptan, RSH, RSH, removal was accomplished accomplished by adding a physical solvent, solvent, e.g. sulfolane, to the amine. amine. And methyldiethanolamine, methyldiethanolamine, MDEA, was found to be selective, i.e. absorbing H 2S while slipping CO2. Processing natural and refinery gases with amines was expanding rapidly. During the last 20 years, MDEA solutions have been protonated and promoted to formulate specialty solvents with enhanced enhanced performance. Protonated refers to adding an inorganic acid to lower the alkalinity alkalinity of the amine solution (10). (10). This reduces the CO2 absorption and improves the regeneration, i.e. lower H 2S concentrations in the lean lean amine. The result is higher selectivity selectivity and lower H2S contents in the sweetened gas. Promoted refers to mixing MDEA with another amine that has a greater affinity for CO 2 (12). The ratio of the amines controls the extent of the CO 2 removal. For example, example, Dow Chemical’s Chemical’s GAS/SPEC solvents can slip nearly all, part, or very little of the CO 2 while removing the H2S to the standard 4 ppm pipeline specification. ALKANOLAMINES
The alkanolamines are derivatives of ammonia where one or two or all three of the hydrogen atoms attached to the central central nitrogen atom have been replaced with alkanol alkanol groups. Amines are referred to as primary, secondary and tertiary depending on how many of the hydrogen atoms have been replaced. Primary Amines:
Monoethanolamine, Monoethanolamin e, MEA
Diglycolamine, DGA
H-N-C2H4OH
H-N-C2H4OC2H4OH
H
H
Secondary Amines:
Diethanolamine, Diethanolamine, DEA
Diisopropanolamine,DIPA
H-N-C2H4OH
H-N-C3H5OH
C2H4OH
C3H5OH
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Tertiary Amines:
Triethanolamine, TEA
Methyldiethanolamine, MDEA
HOC2H4-N-C2H4OH
HOC2H4-N-C2H4OH
C2H4OH
CH3
Amines are bases and they react with acid gases, e.g. H 2S and CO2 to form salts. In the following equations R denotes an alkanol group, e.g. ethanol, -C 2H4OH. Hydrogen Sulfide: first RNH2 + H2S = RNH3SH then RNH2 + RNH3SH = (RNH3)2S
(bisulfide) (sulfide)
Carbon Dioxide: first RNH2 + CO2 + H2O = RNH3HCO3 then RNH2 + RNH3HCO3 = (RNH3)2CO3
(bicarbonate) (carbonate)
Primary and secondary (but not tertiary) amines also react with CO 2 to form carbamates. The reaction to carbamic acid is faster than the bicarbonate reaction. These amines can be used to promote MDEA. first then
RNH2 + CO2 = RHNCOOH RNH2 + RHNCOOH = RHNCOO-RNH3
(carbamic acid) (carbamate)
The first steps of the above reactions – bisulfide, bicarbonate and carbamic acid – may be viewed as intermediates. These are more reactive than the respective salts (sulfide, carbonate and carbamate) and the formation involves the transfer of protons (hydrogen atom cations). Protons can penetrate steel walls at the grain boundaries and accelerate the electochemical reactions that cause corrosion. Consequently, it is advantageous to minimize the concentrations of intermediates in the amine solution. Intermediates are present in the amine solution during absorption when the acid gas, AG, loading in the rich amine is high. They are also present during regeneration when the reactions that form the salts are reversed. They can remain in the lean amine when the regeneration is inadequate, e.g. low reboiler temperature and/or insufficient steam. To minimize this corrosive environment, the lean and rich loadings should be maintained at the appropriate levels. The reactivity of the amines can be assessed by the heats of reaction with H 2S and CO2 , refer to Table I. Generally, a higher heat of reaction makes an amine more reactive with H 2S and CO2. Also the ability to form carbamate compounds increases the reactivity. A more reactive amine has more reactive intermediates and is more corrosive. APPLICATION ANALYSIS
Because no two gas sweetening applications are identical, the gas properties and the process requirements must be examined. Sometimes, an existing design and equipment from inventory
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can be used. But most of the time the design has to be tailored to the application. In all cases, an application analysis – the extent and detail vary considerably – is needed to select the most suitable process and equipment. The following information is required. Technical Data:
Gas Flow Rate Gas Pressure and Temperature Gas Composition H2S Content CO2 Content RSH and Other S Compounds Treated Gas Specifications
MMscfd psig and F mol %, mol %, ppm, gr/100 scf mol %, ppm ppm, gr/100 scf H2S, CO2, RSH, S Contents
The data for liquid treating is similar – bbl/day, API gravity or mol wt, wt %, etc. Plant Requirements:
• • • • • • •
Budget Allocation. Time Limitations – Design and Construction. Use new equipment or retrofit existing equipment. Ancillaries – Utilities, Makeup water. Site Elevation. Soil Properties. Ambient Temperatures – Summer and Winter. PROCESS SELECTION
Is this a good application for an amine plant? The answer to this valid question is: only if the amine process fulfills the process requirements better than the alternatives. Figure 1 is a guide for selecting the gas sweetening process (8). Amines are usually chosen to meet the 4 ppm H 2S specification unless the sulfur removal is less than 50 pounds per day. Table I compares the properties of the following amines: MEA. The high reactivity results in low CO2 concentrations in the sweet gas. It is suitable for low gas pressures where the partial pressures of the H 2S and CO2 are low. The typical concentration of 15 to 20 % limits hydrocarbon solution and absorption when treating liquids. These advantages must be weighed against the higher operating cost and likelihood of corrosion. DEA is still the most widely used amine particularly when the capacity of the plant is adequate, e.g. when the gas flow is less than the design rate. It is the most economical approach for many applications. Unlike MEA there is no need for a reclaimer and corrosion is usually not a serious problem. DGA is suitable for cold climates. A 60% concentration freezes at -40 °F. It is a primary amine and needs a reclaimer. When treating gas that contains only CO 2, DGA solutions become corrosive.
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Generic MDEA provides selective H 2S removal. As a tertiary amine it is suitable for bulk CO2 removal. The operation is economical and there is little corrosion. Sulfinol is a mixture of DIPA or MDEA and sulfolane, which is a physical solvent. Typical concentrations are 30 to 50% amine, 20 to 35% sulfolane and at least 25% water. It absorbs mercaptans and other organic sulfur compounds. The low water content increases hydrocarbon absorption and the tendency to foam. An agreement with Dow Chemical Corp. allows Coastal Chemical to offer the GAS/SPEC solvents. These MDEA based solvents have all of the advantages of tertiary amines. The formulations are tailored for different applications. GAS/SPEC SS and GAS/SPEC SS-3 remove H 2S and slip the desired amount of CO2. The SS-3 is suitable for treating high temperature gas. GAS/SPEC TG-10 has a very high affinity for H2S and can selectively treat low pressure tail gas to 10 ppm. GAS/SPEC CS-Plus and CS-2000 provide the maximum CO 2 removal to below 50 ppm required in ethane recovery and hydrogen or ammonia plants. GAS/SPEC CS-1 removes CO2 from liquid hydrocarbons. GAS/SPEC CS-3 treats natural gas to inert gas specifications of 2 to 3% CO 2. PROCESS DESIGN
Figure 2 shows a typical amine flow sheet. The gas sweetening occurs in the absorber at high pressure and low temperature. The amine regeneration in the still and reboiler is at low pressure and high temperature. The rest of the equipment circulates the amine and makes the plant function efficiently. Computer Programs
Because of the complexity, process designs are best done using a computer. Several programs are available: AMSIM, HYSIM, ProTreat, T Sweet, etc. Detailed simulations on the proprietary amine formulations are available from the manufacturers, e.g. Dow’s GAS/SPEC Technology Group. The better programs use physical properties that include corrections for the acid gas loadings (3, 12). These programs require considerable input, e.g.:
• • • • • • • • • •
Process flowsheet and equipment configuration Inlet gas flow rate, composition or gravity, AG contents, pressure and temperature. Amine composition and concentration Physical properties for the amine solution and the gas. (These are often in the data base of the program) The AG loading in the lean amine and either the circulation rate or the rich AG loading The absorber diameter, tray geometry, number of trays and weir height Still diameter, number of trays and rich amine feed temperature Tray efficiencies in the absorber and stripper Reboiler duty, the pressures in the reboiler, top tray in the still, and reflux drum Flash tank pressure
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Sometimes the input data must be estimated. The data in Table I can be used as long as the sour gas pressure is over 400 psig and the temperature is below 120 °F (8). For applications out of this range use the partial pressures of the acid gases to estimate the loadings (6). The design is iterative. The input data may have to be revised to meet the process and product requirements. The result is a detailed mass and heat balance with stream compositions, pressures and temperatures. The program sizes the equipment using specified parameters, e.g. heat flux in the reboiler, heat exchanger design and retention time in the flash tank. The programs allow the user to compare different amine solutions – formulation and concentration – quickly. The suitability of towers and vessels in inventory can be established. Properties of the amine stream at any location in the system are obtainable. The goal is to optimize the design, e.g. minimum amine flow rate, low energy requirement, minimum tower diameter, etc. Note that the more the design is tweaked the more susceptible the system is to upsets. It is advisable to add 15% to the capacity when specifying the equipment, e.g. heat exchangers. Hand Calculations
Several rules of thumb are available for estimating the requirements of amine plants. The circulation rates when using MEA, DEA, DGA and MDEA can be obtained from the gas flow and the acid gas removal. Amine flow, gpm = K (Gas flow, MMscfd) (Mol % AG removed)
*
Amine
Conc. wt%
MEA DEA DGA MDEA
20 35 55 50
Lean* Loading 0.08 0.03 0.07 0.01
Rich* Loading 0.43 0.45 0.43 0.45
Pickup* Rich-Lean 0.35 0.42 0.36 0.44
K 1.90 1.55 1.14 1.16
Units are mol AG/mol amine.
K is inversely proportional to both the amine concentration and the pickup. The above K values are for inlet gas pressures above 400 psig and gas temperatures from 70 ° to 110°F. Exceeding the above amine concentrations and AG pickups is inadvisable. The GPSA pickups are too high (4). For some GAS/SPEC designs K can be as low as 1. Designs with K less than unity are not recommended. Another consideration is the heat transfer in the absorber. When the AG content in the inlet gas is low, e.g. 1%, most of the reaction heat is transferred to the gas rather than the amine. To avoid excessive sweet gas temperatures, the above rich loadings (and pickups) may have to be reduced to one half or even one third. The absorber diameter can be estimated from Figure 3 using the gas and amine flow rates (4). The liquid flow rate is the amine circulation, gpm. The gas flow rate at the actual pressure and temperature in the absorber can be estimated from: Gas flow, acfs = 0.327 Z (Gas flow, MMscfd) (Temp, R) / (Pres, psia)
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where Z is the compressibility factor . For 0.6 gravity gas Z can be estimated from the following table: Temperature
Compressibility Factor
200 psia
F
75 100
0.97 0.98
400 psia
600 psia
800 psia
1000 psia
0.93 0.95
0.91 0.95
0.88 0.90
0.85 0.87
Load velocity, cu. ft/sec. = (Gas flow, acfs) [ ρv / (ρL – ρv)]0.5 where ρv and ρL are the gas and liquid densities respectively, lb/cu. ft. The gas density,
ρv = 2.71 (Pres, psia) (Gas gravity) / Z (Temp, R).
Figure 3 can also be used to size the still. The liquid flow rate is the amine circulation rate. The vapor flow is obtained from the reboiler duty. Assume that all of the heat forms steam with a specific volume of 13.8 cu. ft/lb. Use 945 Btu/lb. for the heat of vaporization, and 0.0339 for 0.5 [ρv / (ρL - ρv)] . Many designers derate the capacities of the absorber and still by 20% to allow for foaming (4). The heat duties and transfer areas can be estimated from the amine circulation rate (5).
Reboiler Rich/Lean HX Aerial cooler Reflux Condenser
Duty, Btu/hr
Area, sq. ft.
Flux, Btu/hr sq. ft.
72,000 (gpm) 45,000 (gpm) 15,000 (gpm) 30,000 (gpm)
11.30 (gpm) 11.25 (gpm) 10.20 (gpm) 5.20 (gpm)
6,000 4,000 1,500 6,000
The motor sizes of the pumps can be estimated from the amine circulation rate (5). Motor
Horsepower
High Pressure Circulation Pumps Low Pressure (Booster) Pumps Reflux Pumps Aerial Cooler
(gpm) (psig) (0.00065) (gpm) (0.06) (gpm) (0.06) (gpm) (0.36) EQUIPMENT DESIGN
Equipment selection, design and fabrication play a large part in the steady and efficient operation of an amine plant. Choosing new equipment has significant advantages: there are no existing restrictions on the design, size, construction materials, etc. Assembly is also easier, e.g. equipment location and hydrostatic heads. Using used equipment requires compromise between the existing design and what could be obtained. Check the condition of the vessels and consider replacing the valves and controls. When price alone governs the procurement decision, the savings never cover the expense of lost production (downtime) and higher operating costs (efficiency and upsets).
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All equipment should be cleaned before use to remove welding slag, rust, residual contamination, etc. Poor cleaning and/or inadequate rinsing also cause problems. It is often advisable to rinse the unit with a dilute solutions– 5 to 10 percent of the design concentration – of the selected amine. Inlet Gas Separator
This vessel separates condensed hydrocarbons, produced water, corrosion inhibitors, well-treating chemicals and pipeline solids from the inlet sour gas stream. It should be located as close as possible to the amine contactor. It can be complemented, but not replaced, by an integral scrubber in the contact tower. A filter-separator design with an inlet gas baffle, filters, impingement vanes and a mist pad is recommended. There should be a separate chamber for the liquids to collect. A high liquid level shutdown is needed to guard against slugs of produced water or hydrocarbon liquids entering the absorber and ruining the amine. A troublesome problem occurs when the contaminants are aerosols, i.e. very fine (below one micron) suspensions of solids or liquids that pass through the filters. Aerosols are formed by the shearing action in well chokes, valves and compressors. They are surprisingly stable and may require washing the gas with water (1). This is an additional processing step to be used only when the filter-separator is inadequate. Absorber
A typical sour gas contactor consists of an inlet section, a contact section with 20 valve trays, and a mist pad at the top. Valve trays are preferred because the gas is treated with a significant quantity of liquid. Tray spacings of 24 inches and a 48 inch disengaging space between the top tray and the mist pad are typical. As shown in Figure 3, when the diameter exceeds 8 feet a two pass tray where the amine flow is divided should be considered. Amine carry-over can be reduced by adding a water wash tray (makeup water) above the amine feed. The inlet section transports the rich amine past the inlet gas to the bottom where a level control allows a two minute retention time to release any entrained gas. A baffle at the inlet gas nozzle deflects and distributes the gas horizontally across the tower. Leave 24 inches between the bottom tray and the inlet gas nozzle and another 24 inches between the gas nozzle and the amine level. Some smaller towers have an integral scrubber with an inlet baffle, centrifugal vanes to collect drops and a mist pad. Then a chimney tray feeds the gas to the contacting section. Include thermowells on every other tray to measure the temperature profile in the absorber. Use a differential pressure gauge connected between the inlet gas chamber and just above the mist pad to detect amine foaming or entrainment. The exothermic reactions in the absorber increase both the amine temperature (rich typically 20 ° to 40°F hotter than the lean) and the gas temperature (sweet about 10 ° to 20°F above the sour). The gas picks up water from the amine solution and remains essentially saturated. This evaporation creates most of the need for makeup water. A typical sour liquid hydrocarbons, LPG, contactor consists of two 10 ft packed sections. An open packing like Pall rings with high contact area is desirable. The amine solution is usually the continuous phase. The LPG/amine interface should be 5 ft above the amine feed point. Proper
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distribution of the sour LPG and redistribution between the packed sections are required. The drop size is important – too large impedes the treating and too small affects the phase separation. Use distribution velocities of 1 to 2 ft/sec. for the amine feed nozzles and 3 to 4 feet/sec. for the LPG nozzles. The liquid superficial velocities in the contactor are low, 0.5 to 1.5 ft/sec. for the LPG and 0.3 to 0.5 ft/sec. for the amine. The combined stream flow rates are 10 to 15 gpm/sq. ft. of cross sectional area (11). The operating pressure has to be high enough to prevent LPG vaporization. Keep the amine temperature above 100°F so that the viscosity is about 2 cp. This assures good phase separation and low entrainment of LPG and amine. Provision to control the process temperatures is recommended (9, 11). When the LPG flow rate is less than the amine flow rate, the treating works better with the LPG as the continuous phase. The LPG/amine interface needs to be below the packing and 5 ft above the amine exit line. Connections for level control are needed at both the bottom and top of the tower so the LPG/amine interface can be controlled at either location. Watch for amine and /or LPG carry-over. Drops up to 5,000 microns can be entrained in either stream. Amine losses in the LPG are more troublesome because of the effects on downstream equipment. Use a horizontal coalescer with a L/D of 2/1 and a 30 minute retention time to accomplish the phase separation needed and recover the amine carry-over (1). Structured packing is an advancement that can significantly increase the through-put of the absorber. The design and installation are best left to the supplier: Koch, Glitch or Nutter. For gases the increase in flow can be as high as 75%. For liquids the combined flow approaches 40 gpm/sq. ft. cross sectional area. However, amine and LPG carry-over can increase. The retention time in both the amine and LPG coalescers should be 30 minutes (11). Outlet Gas Separator
This vessel collects any amine solution entrained with the sweet gas from the contactor and protects downstream equipment from contamination. Include a gauge glass to indicate carryover. Foaming of the amine is the principal cause of liquid carry-over from the contactor. Feed any collected liquids to the flash tank. (When sweetening LPG consider the LPG coalescer as the outlet separator). Failure to include an outlet separator is false economy. Flash Tank
The amine solution absorbs hydrocarbons as well as acid gases in the contact tower. These flash out when the pressure is reduced – Henry’s law: gas solubility is proportional to the pressure. The horizontal flash tank provides the time for degassing – mostly methane and ethane – the rich amine solution. Removing dissolved gases from the amine solution reduces the gas flow in the still and makes amine carry-over to the reflux condenser less likely. The recommended pressure for two phase (gas and amine) separators is 50 to 75 psig. Use a retention time of 10 minutes. A two phase flash tank usually suffices when the gas gravity is less than 0.62. Heavier gravity gas and refinery systems require three phase (gas, amine and hydrocarbon) vessels. Increase the retention time to 20 minutes. Reduce the pressure to 5 to 25 psig and install a centrifugal pump to transport the amine through the lean/rich heat exchanger to the still.
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Keep the gas/amine interface in two phase tanks at the 60% full mark. For three phase tanks, use interfaces at the 40% and 60% levels. These levels provide a balance between vapor volume, disengaging area and retention time. When the flash gas contains H 2S and is used for fuel, treat it with the lean amine in a small packed tower (the reabsorber) installed on top of the flash tank. Lean/Rich Heat Exchanger
The lean amine from the reboiler supplies about 60% of the heat needed to raise the rich amine stream to the reboiler temperature. A high rich amine temperature limits the heat exchange. The design can be either shell and tube or plate and frame. Shell and tube exchangers with the rich amine tubeside and the lean amine shellside do not leak and are more rugged, but they are bulkier and cost more. In systems prone to fouling, e.g. refineries, plate and frame exchangers are not recommended. The temperature changes in the rich and lean amine streams result in a temperature cross, i.e. the exit rich amine stream, typically 180 ° to 200°F, is hotter than the exit lean amine stream, 140 ° to 160°F. Using two or more exchangers in series to overcome the cross is common practice. The pipe carrying the rich amine from the exchanger to the still should be stainless steel and a size larger than the inlet rich amine pipe. Install thermowells to measure the inlet and outlet temperatures of both streams. These temperatures monitor the amount of heat exchanged and can also be used to detect fouling of the surfaces. Sample ports on the inlet and outlet of the lean amine stream provide the means to detect leaking of the rich amine into the lean. Keep adequate pressure on the rich amine stream to reduce flashing of the acid gas and the corrosion/erosion that occurs with two phase flow. In many systems the pressure on the rich amine is maintained by installing the liquid level control valve for the flash tank next to the amine feed nozzle at the top of the still column. Filters
Solid particles enter the amine from the inlet gas, through amine degradation and from reactions between the H2S and CO2 on the steel walls – iron sulfide and carbonate. There are also soluble contaminants – dissolved hydrocarbons and other amine degradation products. Removal requires both solids filtration and adsorption of the soluble contaminants using activated carbon. If economical, include a full flow, cartridge, particulate filter in the rich amine line to remove 95% of all solid particles 5 microns and larger. For very large units with high circulation rates, a slip stream may be more practical. As a minimum, flow a 10% sidestream through a granular carbon bed to remove the soluble contaminants. For rich gas streams or when treating liquids, increase the sidestream to 20% and consider installing a second carbon bed in the lean amine stream. Both the particulate filter and carbon bed are more effective in keeping solids and hydrocarbons out of the still column when installed in the rich amine stream. However, when the rich amine has a high H 2S loading changing the filter cartridges becomes hazardous. Then safety considerations make it advisable to move the filters to the lean amine stream. The carbon filter should be installed downstream of the solids filter. (A small particulate filter can be installed after the carbon filter to collect fines). Temperature is a factor – the cooler the better and especially for the carbon adsorption. The preferred locations are after the flash tank on the rich side and after the aerial cooler on the lean side.
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A 3 inch diameter by 36 inch long solids filter cartridge can handle 2 to 3 gpm of amine and withstand a 20 psig pressure drop. A bulk carbon bed is preferred over cartridges. Size using a superficial flow rate of 0.5 to 0.8 ft/min. or 3 to 5 gal/min. sq. ft. of cross sectional area. Include equipment to collect the amine solution in the filters and any rinse water. These can be returned to the system. Still
The standard still design consists of a carbon steel tower with a bottom surge (lean amine collection) section, a stripping section with 20 stainless steel valve trays and 48 inches of disengaging space above the top tray. The tower is erected close to the reboiler. th
th
The rich amine is fed to the 18 tray and the reflux stream to the top or 20 tray. The makeup water is added to the reflux. Steam from the reboiler enters the still below the bottom tray. The stripped amine on the bottom tray flows either directly into the surge section or through the reboiler to the surge section. Nearly all of the amine regeneration occurs in the still. The vapor flow stays fairly constant – the steam condensation is offset by the release of acid gases. Measure the temperature and pressure in the still above the top tray. The overhead temperature is used to control the heat to the reboiler. The temperature and pressure are used to estimate the reflux ratio. Connections to install a differential pressure gauge across the still are recommended. Reflux Condenser
The effluent vapors from the still at 195 ° to 215°F are cooled to 110 ° to 140°F to condense and separate most of the water from the acid gases. Condensing the water also reduces the amine content of the acid gases. The condensate is returned to the still. Use an air-cooled forced-draft heat exchanger equipped with automatic louvers for temperature control. Add provisions to re-circulate the cooling air when ambient temperatures below 15 °F are expected. On small units the reflux condenser and the lean amine cooler are housed on the same skid to use the same fan. Reflux Accumulator
This vessel separates the reflux water from the water-saturated acid gases. Pump the water back to the still, together with the makeup water. The acid gases are flared or sent to a sulfur recovery unit. The reflux ratio is defined as the ratio of the mols of water condensed and returned to the still to the mols of acid gases leaving the still. Figure 4 shows how the reflux ratio can be estimated from the overhead pressure and temperature (3). Reboiler
The reboiler supplies the steam for the regeneration. The designs have progressed from large firetube heaters to kettles, once-throughs and thermosyphons. Figure 5 shows schematics for kettle, forced circulation, vertical and horizontal once-through and vertical and horizontal thermosyphon designs (7). Use a kettle or forced circulation unit for large reboilers, e.g. over 4 MMBtu/hr with 600 sq. ft. heat transfer area even though the equipment cost is higher.
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The once-throughs have short retention times, can handle over 12% vaporization of the amine stream and tend to foul less than the thermosyphons. Only part of the amine stream flows through the thermosyphon reboilers. Accordingly, they do not provide one full theoretical tray like the other designs.(7) The vertical once-through is becoming more popular, and is often recommended for smaller applications. Today, the heat source is usually steam or a heat transfer fluid. Saturated steam at 50 psig (296°F) or a heat transfer fluid below 330 °F keep the amine film temperature in the reboilers below the amine degradation range, i.e. a maximum film temperature of 300 °F. The heat flux should be 6,000 to 8,000 Btu/hr. sq. ft.. Equip firetube reboilers with a natural-draft burner. If the burner is forced-draft, install an inconel or hasteloy liner in the fired section to reduce the heat flux. Excluding heat losses, the reboiler duty divides typically as 60% sensible heat, 30% decomposing the amine-acid gas salts and 10% reflux. The estimate of 1,200 Btu/gal. of circulation includes the additional heat needed during startup. Good control and accurate measurement of the heat input is critical. Lean Amine Cooler
This is an air-cooled exchanger similar to the reflux condenser. It cools the lean amine from the lean/rich heat exchanger to 100 ° to 130°F. Within limits, cooler amine results in better acid gas absorption provided that the amine is at least 10 °F hotter than the inlet gas. When the aerial cooler cannot cool the lean amine sufficiently, consider adding a water trim cooler. Low Pressure Circulation Pumps
A pump is needed for the reflux and another (booster) to transport the lean amine to the high pressure circulation pump. Sometimes another pump is needed on the discharge of the flash tank. These are centrifugal pumps, preferably in-line or horizontal, with TEFC electric motors. Install 100% standby capacity. If possible do not locate a pump in the lean amine line before the lean/rich heat exchanger. This avoids flashing and pump cavitation. When the pump has to be located before the lean/rich exchanger, elevate the reboiler so that the hydrostatic head provides the necessary pump NPSH. Pumps work better at temperatures below 200 °F. High Pressure Circulation Pumps
Pump selection depends on the contactor pressure and the amine circulation rate. Include 50% or 100% standby capacity. For most cases, use a reciprocating pump with a pulsation damper. Use a centrifugal pump for pressures below 200 psig and a multi-stage horizontal centrifugal pump for high circulation rates. The flow rate is controlled with a bypass line to the pump suction. Change the pump speed when the bypass flow approaches 50%. Surge Tank
Many plants have surge capacity in the lean amine line in addition to that in the kettle or bottom of the still. This is needed to collect the amine in case of upsets or shutdowns when the absorber and still towers drain – valve trays do not retain a liquid level. Consider making the surge tank large enough to store most of the amine when the system is shut down for repair.
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Piping
Size all amine piping for low velocities, e.g., 2 to 5 ft/sec. Eliminate potential rich amine traps or legs. Use only welded and flanged piping. Avoid using threaded pipe, slip-on flanges and other fabrication techniques that provide cavities where the amine solution can collect and stagnate. Use seal welds to fill in gaps, e.g., tray support rings. Include provisions to drain the entire system. Alarm and Shutdown Panel
As a minimum, the following variables should be monitored. Failure to correct an alarm shuts down the plant.
• • • • • • • • • • • •
Emergency Manual Shutdown Inlet scrubber – High Level Absorber – High Pressure Flash tank – High and Low Level Still surge – High and Low Level Reflux condenser – High Temperature Reflux accumulator – High and Low Level, High Pressure Amine cooler – High and Low Temperature Amine reboiler (Still Surge) – Low Level Amine reboiler –High Pressure, High Temperature Heat medium (Steam, Oil) – High Temperature Aerial coolers – Excessive Vibration
Construction Materials
Table II lists the recommended steels (3). Use low carbon steel, e.g. SA 283 and SA 106B, for vessels and piping, and stainless 304 or 316 where acid gases pose the greatest threat of corrosion. A Rockwell hardness below 22 is often specified for carbon steel in H2S service (NACE). All vessels and piping should be stress relieved. Remember, welding on an ASME code vessel invalidates the certification. Pressure vessels and equipment built to ASME Section VIII Code requires a .0625 inch corrosion allowance; allow 0.05 inch for piping. There is no corrosion allowance for stainless steel. The ability to monitor corrosion with coupons and/or probes is most desirable. Do not use nonferrous materials – copper, brass and other copper alloys, aluminum – and series 400 stainless steels. Note that using the preferred steels does not eliminate the threat of corrosion. It is important to operate within the recommended amine concentrations, AG loadings, temperatures, and solution velocities. Winterization
Amine plants need additional protection in cold climates. Many operators prefer to erect a building over the equipment (towers excepted). Then only the unprotected piping, valves, level gauges, etc. require extra insulation and heat tracing.
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REFERENCES
1.
Ball, H.T. “Design and Operation of Amine Plants”, Coastal Chemical’s Petroenergy Conference, Houston, TX, 1994.
2.
Ballard, D. “How to Operate and Amine Plant”, Hydrocarbon Processing 45:137, April, 1966.
3.
Dow Chemical Co. GAS/SPEC Technology Group.
4.
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5.
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6.
Kent, R. L. and B. Eisenberg,“Better Data for Amine Treating”, Hydrocarbon Processing 64:87, February, 1976.
7.
Love, D. L. “No Hassle Reboiler Selection”, Hydrocarbon Processing 80:41, October, 1992.
8.
Manning, F. S. and R. E. Thompson, “Oilfield Processing of Petroleum”, Vol. 1 Natural Gas, PennWell Publishing Co., 1991.
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Nielson, R. B. “Principles of LPG Amine Treater Design”, Gas Con. Conf., Norman, OK, 1995.
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Smith, K. A., J. H. Meldon and C. K. Colton, “Gas Absorption”, U. S. Patent 4, 080,423, 1978.
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ACKNOWLEDGEMENT
The authors thank Mike DuPart, Peter Rooney and Erik Stewart, Dow GAS/SPEC; Vicki McClenny and Dave Pharis, T. H. Russell; and Bill Harell, Pro-Quip; for their helpful information and comments.
13
TABE I COMPARISON OF AMINE SOLUTIONS AMINE
Reactivity Stability HC Absorption Vaporization Losses H2S Selectivity Organic S Removal Corrosivity Foaming Tendency
MEA
DEA
DGA
MDEA
SULFINOL
GAS/SPEC
High Fair Low High No Low High Low
Moderate Good Moderate Moderate No Low Moderate Low
Moderate Fair High Moderate No Some Moderate Moderate
Moderate Good High Low Yes Low Moderate High
Moderate Good High Low No High Moderate High
High Good Moderate Low Yes Low Low Moderate
750 825
510 650
675 850
445 475
550 650
445 475-550
Heat of Reaction Btu/lb. AG
H2S CO2
Solvent Conc. Reboiler Temp.
wt. % F
15-20 235-250
25-35 240-255
40-60 240-260
40-50 245-255
60-75 250-260
40-55 245-260
AG Loading mol AG/ mol Amine
Lean Rich
0.07-0.10 0.35-0.45
0.03-0.05 0.40-0.55
0.07-0.10 0.35-0.45
0.01-0.03 0.40-0.55
0.03-0.05 0.35-0.45
0.004-0.02 0.40-0.55
Steam Rate
lb/gal.
1.0-1.2
0.9-1.1
1.1-1.3
0.9-1.2
0.7-1.3
0.9-1.1
1.5-3.0
1.2-2.0
1.4-2.8
0.9-1.5
1.1-2.0
0.9-1.2
Reflux Ratio mol H2O/mol AG
TABLE II CONSTRUCTION MATERIALS (3) H2S/CO2
CO2 ONLY
Carbon Steel Carbon Steel or 304SS
Carbon Steel 304SS or316SS
Carbon Steel or 304SS Carbon Steel
304SS or 316SS Carbon Steel
Carbon Steel Carbon Steel
Carbon Steel Carbon Steel
Shell Internals
Carbon Steel 304SS
Carbon Steel 304SS or 316SS
Shell Internals
Carbon Steel Carbon Steel or 304SS
Carbon Steel 304SS or 316SS
Carbon Steel or 304SS Carbon Steel Carbon Steel Carbon Steel Carbon Steel
304SS or 316SS Carbon Steel Carbon Steel Carbon Steel Carbon Steel
Carbon Steel or 304SS Carbon Steel
304SS or 316SS Carbon Steel
Carbon Steel
Carbon Steel
ABSORBER
Shell Internals LEAN/RICH EXCHANGER
Tubes Shell LEAN AMINE COOLER
Tubes Shell CARBON BED
STILL
REBOILER
Tubes Shell Tube Sheet Steam Side Channels Piping REFLUX CONDENSER
Tubes Shell REFLUX ACCUMULATOR PUMPS
Case Impellers
Carbon Steel Carbon Steel or 304SS
Carbon Steel or Cast Iron 304SS or 316SS
Rich Amine Lean Amine Stripper OH Cold Reflux
Carbon Steel or 304SS Carbon Steel 304SS or 316SS Carbon Steel
304SS or 316SS 304SS 304SS or 316SS Carbon Steel
PIPING
• •
The preferred metallurgy is underlined. Stainless steel (304 or 316) packing should be solution annealed to improve the corrosion resistance.
