(403c) On Improvement of Solvent Quality In a Natural Gas Sweetening Plant

Binay K Dutta

Chemical Engineering Department

The Petroleum Institute, Abu Dhabi,  UAE

Sweetening of natural gas is mostly done by absorption in an aqueous amine, single or mixed.  Mono-ethanolamine (MEA), diethanolamine (DEA), methyl-diethanolamine (MDEA), di-iso-propanolamine (DIPA) and 2-amino-2-methyl-1-propanol (AMP) are commonly used for this purpose depending on the composition of the raw gas and the process requirements.  Solvent degradation and foaming are the most severe operating problems of the gas sweetening process.  These two problems are, in fact, interrelated since the amine degradation products are the greatest contributors to the foaming problem.  It is well known that foaming in an absorption column creates flooding as well as loss of separation efficiency.  Corrosion by the dissolved acid gases   at the high operating pressure in the absorption column and the moderately high temperature of the regeneration column adds substantially to the foaming problem.  Another class of partially identified compounds, called heat-stable salts (HSS), are formed from the degradation products and the contaminants in the process water mixed with the amine.

A significant volume of literature exists on solvent degradation, identification of degradation products, foaming, formation heat-stable salts and corrosion in gas sweetening and solvent regeneration columns.   The available literature may be classified into three categories – (i) identification of degradation products and mechanism of degradation;  (ii)  measurement of foaming tendency;  and (iii) suppression of foaming.  However, the majority of these literature pertain to the conditions of post-combustion carbon dioxide capture where the presence of oxygen in the flue gases creates an environment which is radically different from that of sour gas treatment where the environment is anoxic but characterized by the presence of a significant level of hydrogen sulfide.  Chakma and Meisen (1988) reported one of the early studies on identification of the degradation products of MDEA using GC and GC-MS and listed a number of acids, alcohols and amines in the samples.   Kadner and Rieder (1995) listed the anions (such as chloride, nitrate, sulfate, thiosulfate, formate, oxalate and acetate, phosphate and fluoride ) associated with HSS that appear mainly from the dilution water and keep on accumulating.  Reza and Trejo (2006) conducted experimental studies on degradation of a few amines (DEA, MDEA and APM) up to 90 h at a maximum temperature of 200^oC.    Degradation was marginal in the absence of acid gases, particularly H₂S, confirming the need to run experiments at conditions nearing those in the actual sweetening plants in order to get realistic and representative results.

Foaming in amine solutions occur principally because of certain contaminants such as amine degradation products including heat-stable salts (HSS), corrosion inhibitors added to the solution, iron sulfide particles that get dislodged from the corroded pipe/vessel surface, carboxylic acids, alcohols and hydrocarbons (Pauley, 1991).   Measurements have been reported on the foaming tendencies of a number of amines (single and mixtures) such as DEA and MDEA at pressure up to about 5 bar and temperature up to 85^oC using N₂, CH₄ and C₂H₆ as the bubbling gas.    The foam break time was also measured.    Behaviors of DEA and MDEA were found to be similar in respect of foaming.  Higher fatty acids (C₅ and above) positively contribute to foaming.    Foaming behavior in the carbon dioxide absorption process has been reported in the literature.   Surface tension of single and mixed amine solutions, that play a major role in foaming,  as well as the foaming behavior were also measured by Aguila-Hernandez et al. (2007) in nitrogen atmosphere.  Only a few reports are available on inhibition of degradation, particularly in the context of flue gas decarbonization in an oxygen environment (Bedell, 2010).  However, degradation studies and remedial measures for foam suppression under actual industrial operating conditions such as CO₂ and H₂S environment and modeling of the phenomena are practically more important.  

The present work aims at addressing different aspects of the issues related to solvent degradation in a natural gas processing plant.  The nature of the problems will be analyzed based on  the experiences and data from a real life natural gas processing plant.  Available plant data will be analyzed using the available literature information qualitatively as well as through modeling of the foaming and solvent degradation problems.  The intensity of foaming will be related to the concentrations of heat stable corrosion and degradation products as well as dissolved hydrocarbons.  The concentration of the hydrocarbon under actual plant operating conditions will be calculated by available thermodynamic models on solubility and its effect of surface tension of the solution will be analyzed in the context of foam generation. 

References

Aguila-Hernandez, J., Trejo, A., and Garcia-Florec, B. E., Surface tension and foam behavior of aqueous solutions of blends of three alkanolamines as a function of temperature, Colloids and Surfaces, Physico-chem. Engg Aspects, 308 (2007) 33-46.

Bedell, S.:  Amine autoxidation in flye gas CO2 capture – mechanistic lessons learned from other gas treating processes, Intern. J. Greenhouse Gas Control, 2010, doi:10:1016/j.ijggt.2010.01.007.

Chakma, A., and Miesen, A: Identification of methyl-diethanol-amine degradation products by gas chromatography and gas chromatography-mass spectrometry, J. Chromatography, 457 (1988) 287-297.

Kadnar, R., and Rieder, J.: Determination of anions in amine solutions for sour gas treatment, J. Chromatography A, 706 (1995) 339-343.

Pauley, C. R.:  Face the facts about amine foaming, Chem Eng Progr., July 1991, 33-38.

Reza, J., and Trejo, A.: Degradation of aqueous solutions of alkanolamine blends at high temperature under pressure of CO₂ and H₂S, Chem Eng Commun., 193 (2006) 129-138.