CO2 removal from natural gas by employing amine absorption and membrane technology—A technical and economical analysis
Highlights
• CO2 capture. • Comparing amine absorption and membrane separation technologies. • Technical and economical comparison. • Facilitated transport membrane.
Introduction
Natural gas sweetening is a very important issue for many reasons; the acid gas concentration in natural gas can cause pipeline corrosion problems during transport [1]. The removal of acid gases reduces the gas volume to be transported and increases the calorific value of sold gas stream [2].
The captured acid gases can be pumped back in the reservoir; which reduces the atmospheric pollution by impurities like H2S, and the emission of greenhouse gases as CO2 [1]. The pressure and composition of crude natural gas varies from well to well. The pressure range mostly lies between 20 and 70 bar [4] but can be even higher for some wells. Table 1.1 demonstrates the wide range of compositions in crude natural gas. Processing of natural gas is so far the largest gas separation application worldwide. Almost all crude natural gas streams require treatment to remove impurities and reduce higher hydrocarbons to match with tightly controlled pipeline specifications (typical values are given in Table 1.2). CO2 usually has to be lower than 2 vol.% in sale (natural) gas [5], a requirement that generally makes CO2 removal necessary.
The scope of this study is to investigate the removal of CO2 from natural gas with amine absorption and membrane plants. Removal of CO2 from crude natural gas by amine absorption is a well known and implemented industrial process [3], [5], [6] and is still considered a state of the art technology. Likewise, there are quite a few membrane plants installed around the world, but these membranes do not have optimum performance with respect to flux and selectivity, and therefore require fairly large membrane areas. Current research in this area is focused on optimizing the membrane separation performance thus reducing both membrane area and CH4 loss. Membrane processes are considered as a promising alternative for offshore production processes. Since there will always be a little loss of amine solution to the atmosphere during the process, membrane processes also offer an environment friendly alternative.
Two different feed gas streams are considered in this study. For each stream a technical and economical analysis will be done to assess the optimal process conditions, required capital investment and the resulting gas processing cost for amine absorption and different membrane configurations, respectively. Aspen Hysys has been used to simulate the amine absorption and membrane separation process. Hysys is a powerful process simulation tool, which provides the opportunity to estimate physical properties, liquid vapor phase equilibrium, material and heat balances.
Membrane operations are not standard units in Hysys, but it is possible to include user defined unit operation. Therefore a membrane model (ChemBrane) developed at NTNU has been implemented in this analysis. This model enables three different membrane configurations (co-current, perfectly mixed and counter current flow) to estimate realistic process conditions. ChemBrane can handle vacuum and sweep operations [7]. Table 1.3 summarizes the different cases for feed gas conditions. For amine absorption process and membrane application the property packages of Amine and Peng-Robinson are used, respectively. For amine absorption, a CO2 concentration of less than 0.5 vol.% in the sweet gas and a concentration above 90% CO2 in the acid gas stream were assumed. For single stage membrane processes the aim was to match the pipeline conditions, and to minimize the loss of CH4 in the permeate stream. In multi-stage membrane processes a similar goal for CO2 purity and recovery was set as in amine absorption; less than 2% CO2 in the product stream and a CO2 concentration around 90% within the permeate stream.
Section snippets
General chemistry
Treatment of natural gas with aqueous diethanolamine solution has a long history and is state of the art technology. Diethanolamine (DEA) is a secondary amine and therefore less reactive with CO2 and H2S than primary amines like monoethanolamine (MEA). Hence it has lower energy requirements for the regeneration [1], which is a key factor for estimating gas processing cost. The absorption of acid gases into aqueous amine solution is described by the following chemical reactions [6], [8]:
General
The second part of this work is focused on the removal of CO2 from natural gas with membrane technology. The most common membranes for gas sweetening processes are cellulose acetate (CA) membranes [5], [17], [18]. Recently, fixed site carrier membranes showed a great potential for removal of CO2 [20], [21]. Membrane based gas separation process depends on the gas components, membrane material and the process conditions. The solution-diffusion model is widely accepted as the transport model for
Conclusions
During this work a technical and economic analysis for gas sweetening with amine absorption and membrane technology was conducted. For 2 different feed gas compositions a technical analysis was done with a membrane model “ChemBrane” interfaced within Aspen Hysys. For both technologies, an optimization was done to minimize total capital investment and gas processing cost. With both technologies it was possible to reach the given simulation goals. For amine absorption <0.5% CO2 within the sweet
Acknowledgment
We hereby thank Dr. Taek-Joong Kim for the excellent experimental work.
References (28)
Hybrid process for the removal of acid gases from natural gas
Journal of Membrane Science
(1998)- et al.
Optimization of membrane unit for removing carbon dioxide from natural gas
Journal of Membrane Science
(2006) - et al.
Optimization-based design of spiral-wound membrane systems for CO2/CH4 separations
Separation and Purification Technology
(1998) A study on the reaction between CO2 and alkanolamines in aqueous solutions
Chemical Engineering Science
(1984)Upgrading low-quality natural gas with H2S- and CO2-selective polymer membranes. Part II. Process Design, economics, and sensitivity study of membrane stages with recycle streams
Journal of Membrane Science
(2008)Facilitated transport of CO2 in novel PVAm/PVA blend membrane
Journal of Membrane Science
(2009)Upgrading low-quality natural gas with H2S- and CO2-selective polymer membranes. Part I. Process design and economics of membrane stages without recycle streams
Journal of Membrane Science
(2002)Membrane processes for the removal of acid gases from natural gas. I. Process configurations and optimizing of operating conditions
Journal of Membrane Science
(1993)- W.R. Parrish, A.J. Ridnay, Fundamentals of Natural Gas Processing, CRC Press Taylor & Francis Group,...
Natural gas processing with membranes: an overview
Industrial & Engineering Chemistry Research
(2008)
Gas Purification
Selecting amines for sweetening units
Performance of gas purification systems utilizing DEA solutions
Cited by (221)
Ionic liquid-ethanol mixed solvent design exemplified for the decarbonization of shale gas and biogas
2024, Chemical Engineering ScienceIntroduction to natural gas sweetening methods and technologies
2024, Advances in Natural Gas: Formation, Processing, and Applications. Volume 2: Natural Gas SweeteningApplication of electrochemical membranes for natural gas sweetening
2024, Advances in Natural Gas: Formation, Processing, and Applications. Volume 2: Natural Gas SweeteningAbsorption processes for CO<inf>2</inf> removal from CO<inf>2</inf>-rich natural gas
2024, Advances in Natural Gas: Formation, Processing, and Applications. Volume 2: Natural Gas Sweetening