Amine Gas Treating Unit - Best Practices - Troubleshooting Guide

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AMINES GAS TREATING Best Practices Guide

Contents

Process Capabilities for gas treating process Typical Amine Treating Typical Amine System Improvements Primary Equipment Overview Inlet Gas Knockout Absorber Three Phase Flash Tank Lean/Rich Heat Exchanger Regenerator Filtration Amine Reclaimer WWW.GBHENTERPRISES.COM

Contents

Operating Difficulties Overview Foaming Failure to Meet Gas Specification Solvent Losses Corrosion Typical Amine System Improvements Degradation of Amines and Alkanolamines during Sour Gas Treating APPENDIX Best Practices - Troubleshooting Guide

Amines: Gas Treating

Wastes Types Generated in Different CO2 Removal Process units

Typical Amines Treating

Sour gas sweetening process

Typical Amine System Primary Equipment Overview

Typical Amine System

Primary Equipment Overview

Inlet Gas Knockout

Absorber

Three Phase Flash Tank

Lean/Rich Heat Exchanger

Regenerator

Filtration

Amine Reclaimer

Before entering the absorber, the gas is passed through an inlet separator where entrained droplets or slugs of liquid are removed from the gas stream by impaction devices (to the right >>>>>)

Inlet Gas Knockout

Baffles remove a portion of the liquids. Mist eliminator pads, located near the gas outlet of the tank, trap the rest. Typical contaminants in natural gas streams may be liquid hydrocarbons, salt water, sands, well treating compounds, pipeline treating chemicals, and compressor oils.

The sour gas, freed of entrained liquids by the inlet separator, enters the bottom of the absorber. Usually the absorber is a tray column; although packed columns are also used. In either case, the objective is to provide intimate contact between the gas and the amine solvent so that the H2S and C02 molecules can transfer from the gas phase to the solvent liquid phase. In tray columns, a liquid level is maintained on each tray by a weir usually 2 or 3 inches high (Figure >>>>>).

Tray Tower Absorber

Typical Amine System Three Phase Flash Tank

In many units the rich amine solution is sent from the absorber to a flash skimmer tank to recover hydrocarbons that may have dissolved or condensed in the amine solution in the absorber. The pressure of the solution is dropped as it enters the tank, allowing the lightest of the hydrocarbons to flash. The heavier hydrocarbons remain as a liquid, but separate from the aqueous amine, forming a separate liquid layer.

Typical Amine System Lean/Rich Heat Exchanger

The rich solvent is preheated before entering the stripper. Because the lean amine exiting the reboiler must be cooled before entering the absorber, there is an opportunity to exchange heat from the lean to the rich stream, thereby reducing the heat load on the reboiler. This is usually done in a shell and tube lean/rich heat exchanger with the rich solvent passed through the tubes, which are usually made of stainless steel.

Note: Recommended maximum velocity to minimize corrosion in the tubes is 3 or 3.5 feet/sec.

Typical Amine System Regenerator

Like the absorber, the stripper is either a tray or packed column with approximately 20 trays or the equivalent height in packing. To minimize amine vaporization loss, there may be a water wash section at the top of the column with an additional four to six trays. The preheated rich amine enters near the top of the column and flows down countercurrent to a gas stream of steam, H2S, and C02. The steam is generated in the reboiler, lowering the partial pressure of H2S and C02 in the gas stream, enhancing driving force of the acid gases from the amine solution.

Typical Amine System Filtration

A filtration scheme of mechanical and activated carbon filters is important in maintaining good solution control. Mechanical filters such as, cartridge filters or precoat filters remove particulate material while call filters remove chemical contaminants such as entrained hydrocarbons and surface-active compounds.

Filters are located in the rich line in some plants, and in the line in others. One manufacturer recommends filters in both rich and lean lines. Locating the filters in the rich line upstream of the lean rich heat exchanger will protect both the heat exchanger and the stripper from plugging, and reduce the erosion/corrosion rate in the heat exchanger.

A 10 to 20 micron mechanical filter should be adequate for particulate removal. If cotton filters are used, the cotton should be virgin cot ton rather than recycled. Recycled cottons may contain fibers with coatings which may be the source of amine solution foaming problems.

Circulation rates through mechanical filters range from 5% of the circulating system to full fl depending on the degree of contamination. Recommendations for flow to carbon filters range from less than I percent to 5 to 10 percent and some units have been built with full flow.

Criteria In determining when a carbon bed should be changed The following can be used as a guide: 1) a high pressure drop across the bed, caused by solids plugging the voids;

2) a color comparison between a sample taken from the outlet of the filter and a plant sample run through fresh carbon in the lab. Active carbon will remove color; 3) an increase in foaming tendency in the plant, or the start of a foaming problem.

Typical Amine System Amine Reclaimer

Operating Difficulties Amine gas sweetening plants can experience operating difficulties including foaming, failure to meet sweet gas specification, high solvent losses, corrosion, fouling of equipment, and contamination of the amine solution. Often one operating difficulty is the cause of another. Not all plants experience the same problems to the same degree, and what may be a continual problem in one plant may occur only rarely in another.

Operating Difficulties

Foaming Failure to Meet Gas Specification Solvent Losses Corrosion

Symptoms of Foaming

Operating Difficulties: Foaming I

Pure aqueous amine solutions do not foam. It is only in the presence of contaminants such as condensed hydrocarbons, small suspended particulate matter, or other surface active agents such as some pipeline corrosion inhibitors or compressor oils, that a foaming problem may develop. Foaming usually occurs in the absorber or the stripping tower, and is accompanied by a sudden noticeable increase in the differential pressure across the column. Other indications of a foaming condition may be a high solvent carryover, a drop in liquid levels, and the detection of off-specification gas.

Operating Difficulties: Foaming II

An immediate method to control a foaming problem is the addition of an antifoam at a location just upstream of the foam. Effective foam inhibitors for amine sweetening systems are silicone antifoams and polyalkylene glycols. Also widely used are high-boiling alcohols such as oleyl aIcohol and octylphenoxyethanol. It is advisable to test the antifoam on a plant sample in the laboratory before applying it in the field to verify that it will break the foam. In the event that one antifoam is ineffective, switching to another antifoam may solve the problem.

Operating Difficulties: Foaming III

The silicone antifoams have proven to be quick and effective in controlling foaming problems in the gas treating industry. When using a silicone antifoam, the antifoam should be added downstream of the carbon filters because carbon filters will adsorb the silicone. Care should be exercised with respect to the amount of silicone antifoam added to a system. The silicone antifoams should be used only in small quantities, as recommended by the manufacturer. It is important to be aware that silicone antifoams used in excessive quantities have the potential to promote the formation of foam.

Operating Difficulties: Foaming IV

The use of an antifoam may only be a temporary solution to a continuing problem. The objective in controlling foaming should be to minimize the level of contaminants in the amine solution. Of critical importance is the prevention of entrained contaminants in the feed gas from entering the amine system. The inlet separator, equipped with a demister pad and possibly filters, is instrumental in trapping most contaminants, and should be monitored to insure that it is operating efficiently and not being overloaded. Mechanical and carbon filters are necessary in maintaining a clean solution. In order to prevent hydrocarbons from condensing in the absorber, the lean amine feed temperature should be held between 10'F and 20'F above the temperature of the feed gas.

Causes of Failure to Meet Specifications

Failure to Meet Gas Specification I

Difficulty in meeting the sweet gas specification may be the result of poor contact between the gas and the amine solvent, which may in turn be caused by foaming or mechanical problems in the contacting equipment. In the case of foaming, the gas remains trapped in bubbles, unable to contact the rest of the solvent, resulting in poor mass transfer of acid gas from the gas to the amine solution. In terms of mechanical damage, if trays are broken or have fallen, there may not be enough contact zones (trays) for adequate sweetening. If the trays are plugged, there is less contact between the gas and liquid on each tray, resulting in poorer sweetening.

Failure to Meet Gas Specification II

Other explanations for off-specification gas may be related to the amine solution:

The circulation rate may be too low, The amine concentration too low, The lean solution temperature may be too high, The acid gas loading in the lean solution may be too high.

Monoethanolamine systems usually run with solution concentrations between 10 and 20 weight percent MEA, and a lean loading of 0.1 moles acid gas/mole of MEA.

Failure to Meet Gas Specification III

Diethanolamine systems are between 20 and 30 weight percent DEA, with lean loadings of 0.02 to 0.05 moles acid gas/mole DEA. In order to reach these lean loadings, regeneration resulting in a steam-to-acid gas ratio ranging from 1:1 to 3:1 (moles steam: moles acid gas) in the stripper overhead gas is usually required (1). In some cases, even higher ratios may be necessary to bring the loading down, as in low-pressure treating applications.

Failure to Meet Gas Specification IV

One way to estimate the overhead steam-to-acid gas ratio, knowing the stripper overhead temperature and pressure, is to use steam table data and Raoult's law: PP H2O = x H2O psat where: PP H2O = partial pressure of water in the overhead gas; X H2O = mole fraction of water in the amine solvent; psat = vapor pressure of pure water at the temperature of the overhead gas.

Failure to Meet Gas Specification V

Approximating the overhead gas as an ideal gas containing water, H2S and C02, the partial pressure of the acid gases can be obtained by subtracting the partial pressure of water, calculated from Raoult's law, from the stripper overhead pressure: PPacid gas = Poverhead – PP H2O The ratio of water partial pressure to acid gas partial pressure is equal to the mole ratio of steam to acid gas.

Failure to Meet Gas Specification VI

As an example calculation of the steam-to-acid gas ratio, a stripper with an overhead temperature and pressure of 200'F and 20 psia, carrying a 27 weight percent (6 mole percent) DEA solvent, has a corresponding water vapor pressure of 11.5 psia as obtained from the steam tables. From Raoult's law, the partial pressure of water is 10.8 psia: PPH2 0 = (0.94) (11.5) = 10.8 psia The partial pressure of acid gas would be 20 psia less 10.3 psia or 9.19 psia, and the overhead steam-to-acid gas ratio would be 1.2 moles steam/mole acid gas (10.8 -t 9.19).

Solvent Losses

Amine losses are largely through entrainment, caused by foaming or excessive gas velocities, and by leakage due to spills or corrosion. In MEA units the reclaimer bottoms disposal significantly adds to the makeup requirement. On a much smaller scale are vaporization losses from the absorber, the overhead condenser, and the flash tank, and degradation losses by chemical and thermal degradation

Factors in Corrosion

Corrosion I

Corrosion is a problem experienced by many alkanolamine gas sweetening plants. When loaded with C02 and H2S, aqueous amine solutions can become corrosive to carbon steel. Corrosion rates are increased by high amine concentration, high acid gas loading, high temperatures, degradation products, and foaming. Also corrosive are acid gases flashed from solution.

Corrosion II

Monoethanolamine is more reactive than diethanolamine and similarly more corrosive. As a result, the concentration of MEA is restricted to 10 to 20 weight percent, while DEA strengths range from 20 to 30 weight percent. Rich solution loadings are normally limited to the range of 0.25 to 0.45 moles acid gas/mole MEA, while in DEA systems loadings may range from 0.5 to 0.6 moles acid gas/mole DEA. The corrosiveness of a loaded amine solution is strongly influenced by the relative proportion Of C02 to H2S in the feed gas. C02 is more corrosive to carbon steel than is H2S in aqueous systems.

Corrosion III

Thus, for gases containing a higher ratio Of C02 to H2S, the rich acid gas loading should be maintained at the lower end of the recommended loading range. In cases where the feed gas is predominantly H2S, loadings at the higher end of the loading range may be acceptable. In terms of design, a number of measures can be taken to minimize corrosion. Solution velocities should not exceed 3 or 3.5 ft/sec.

Corrosion IV

The rich solution should be on the tube side of the lean/rich heat exchanger, and pressure should be maintained on the exchanger to prevent acid gases from flashing, creating an erosion/corrosion cycle. A low temperature heating medium should be used in the reboiler, thereby preventing accelerated corrosion rates and thermal degradation of the amine. All equipment should be stress relieved.

Corrosion V

There are certain areas of amine sweetening plants which are more susceptible to corrosion than others, and, as a result, are often constructed of corrosion-resistant materials such as Type 304 stainless steel. These areas include: 1) the lean/rich heat exchanger tube bundle, 2) the reboiler tube bundle, 3) the stripping column, particularly the upper section and overhead gas line, 4) the reflux condenser, and 5) the rich solvent let-down valve and subsequent piping to the stripper.

Several Key Operating Parameters that can Help maintain good Operation (Click here for full size Table)

Typical Amine System Improvements

Degradation of Amines and Alkanolamines

during Sour Gas Sweetening

Contents Degradation of Amines and Alkanolamines

during Sour Gas Treating Figure 1. Sour gas sweetening process Figure 2. Causes of amine degradation Figure 3. Problems irreversible degradation reaction Figure 4. Foam formations in the interior of the stripper by degradation products Figure 5. Foam formations by degradation products Figure 6. Crevice corrosion in the junction of pipelines Figure 7. Pitting corrosion occurring at the end of the pipe junction Figure 8. Fouling effect in the pipe line of gas sweetening plant Figure 9. CO2 induced degradation of MEA Figure 10. Reaction responsible for the degradation of DEA by C02 Figure 11. CO2 induced degradation of PZ and MDEA

Contents

Degradation of Amines and Alkanolamines during Sour Gas Treating Table 1. Degradation products of MEA induced by CO2 Table 2. Degradation products of MEA induced by CO2 and O2 Table 3. Degradation products of DEA induced by CS2

Simplified amine gas sweetening PFD

CAUSES OF AMINE DEGRADATION

EFFECT OF DEGRADATION PRODUCTS

Amines Gas Treating

Foam formations in the interior of the stripper by degradation products

Amines Gas Treating

Foam formations by degradation products

Crevice corrosion in the junction of pipelines

Pitting corrosion occurring at the end of the pipe junction

Fouling effect in the pipe line of gas sweetening plant

CO2 Induced Degradation of MEA

Degradation through irreversible side reactions With CO2, H2S and O2 leads to numerous problems with the process: solvent loss foaming fouling increased viscosity corrosion

Major problems associated with chemical absorption using alkanolamines

CO2 induced degradation of MEA

Degradation products of MEA induced by CO2

Degradation products of MEA induced by CO2 and O2

Degradation of DEA and its blends

Degradation products of DEA and DEA blend DEA is a secondary alkanolamine, it has a reduced affinity to reaction with H2S and CO2.

Reaction responsible for the degradation of DEA by C02

Degradation products of DEA induced by CS2

Table 3.

CO2 induced degradation of PZ and MDEA

Figure 11.

APPENDIX

Best Practices - Troubleshooting Guide

Amines: Gas Sweetening

Refinery Process Stream Purification Refinery Process Catalysts Troubleshooting Refinery Process Catalyst Start-Up / Shutdown Activation Reduction In-situ Ex-situ Sulfiding Specializing in Refinery Process Catalyst Performance Evaluation Heat & Mass Balance Analysis Catalyst Remaining Life Determination Catalyst Deactivation Assessment Catalyst Performance Characterization Refining & Gas Processing & Petrochemical Industries Catalysts / Process Technology - Hydrogen Catalysts / Process Technology - Ammonia Catalyst / Process Technology - Methanol Catalysts / process Technology – Petrochemicals Specializing in the Development & Commercialization of New Technology in the Refining & Petrochemical Industries

Web Site: www.GBHEnterprises.com

Reference List

1. Nexant Inc. Task 1: Acid Gas Removal Technology Survey and Screening for Thermochemical Ethanol Synthesis. Subcontract Report NREL/KAFT-8-882786-01. March 2009.

2. Phillips, S., Aden, A., Jechura, J., Dayton, D., and Eggeman, T., “Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass,” NREL Report No. TP-510-41168, April 2007. 3. Kohl, A. L., and Nielsen, R. B., Gas Purification, 5th ed., Gulf Publishing, Houston, TX, 1997. 4. Bishnoi, S. and G. T. Rochelle, "Absorption of Carbon Dioxide in Aqueous Piperazine/Methyldiethanolamine," AIChE Journal, Vol. 48, No. 12, December 2002, pp. 2788 - 2799.

Reference List

5. Phillips, S., Aden, A., Jechura, J., Dayton, D., and Eggeman, T., “Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass,” NREL Report No. TP-510-41168, April 2007. 6. Kohl, A. L., and Nielsen, R. B., Gas Purification, 5th ed., Gulf Publishing, Houston, TX, 1997. 7. Nexant Database. 8. Kidnay, A. J., and Parrish, W. R., Fundamentals of Natural Gas Processing, Taylor & Francis Group, Boca Raton, FL, 2006. 9. Engineering Data Book, 10th ed., Section 21, Hydrocarbon Treating, Gas Processors Supply Association, 1987.

Reference List

10. Kubek, D. J., Polla, E., and Wilcher, F. P., “Purification and Recovery for Gasification,” Gasification Technologies Conference, October 1996, San Francisco, CA. 11. Ranke, G., “Advantages of the Rectisol-Wash Process in Selective H2S Removal from Gas Mixtures,” Linde Reports on Science and Technology, Vol. 18, 1973. 12. UOP Gas Treating information, available at http://uop.com/gasprocessing/6010.html 13. Catalyst information from Johnson Matthey Group, “Absorbent for Sulphur Polishing,” available at http://www.synetix.com/refineries/pdfs/manuals/669w.pdf

Reference List 14. Watson, J., Jones, K., “Removing H2S from Syngas Using Proven Technology in Japanese Waste Gasification Facility,” available at http://www.gtp-merichem.com/ support/technical_papers 15. Douglas L. Heguy, Gary J. Nagl, “The State of Iron Redox Sulfur Plant Technology New Developments to an Established Technology,” available at http://www.gtp-merichem.com/support/technical_papers 16. Dortmundt, D., Doshi, K., “Recent Developments in CO2 Removal Membrane Technology,” 1999. 17. Edwards, M.S., “H2S Removal Processes for Low-Btu Coal Gas,” prepared by Oak Ridge National Laboratory, Oak Ridge, Tennessee, for the Department of Energy/Fossil Energy Office of Program Planning and Analysis, Contract No. W-7405-eng-26, January 1979. 18. Tennyson & Schaaf, “Guidelines Can Help Choose Proper Process for Gas Treating Plants,” Oil and Gas Journal, January 1977. 19. W. Breckenridge, A. Holiday, J. Ong and C. Sharp “Use of SELEXOL Process in Coke Gasification to Ammonia Project” Laurance Reid Gas Conditioning Conference, February 17, 2000.

Reference List

20. Degradation studies of amines and alkanolamines during sour gas treatment process M. S. Islam, R. Yusoff, B. S. Ali1*, M. N. Islam and M. H. Chakrabarti Department of Chemical Engineering, Faculty of Engineering, University of Malaya, 50603 Kuala Lumpur, Malaysia. Department of Chemistry, Faculty of Engineering, Bangladesh University of Engineering and Technology (BUET), Dhaka-1000, Bangladesh. 21. DOW Technical Article : Gas Sweetening Reprint: Printed 1998 Gas Sweetening 22. Amine Best Practices Group

Amine Gas Treating Unit - Best Practices - Troubleshooting Guide

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