CO2 removal from natural gas by employing amine absorption and membrane technology—A technical and economical analysis

doi:10.1016/j.cej.2011.07.007

Chemical Engineering Journal

Volume 172, Issues 2–3, 15 August 2011, Pages 952-960

https://doi.org/10.1016/j.cej.2011.07.007 Get rights and content

Abstract

A technical and economic analysis of gas sweetening processes for natural gas with amine absorption and membrane technology has been conducted. Amine absorption is still considered a state of the art technology for gas sweetening but membranes have shown a great potential in this area, if the flux and selectivity for CO₂ is high enough. The PVAm/PVA (polyvinyl amine and polyvinyl alcohol) membrane, developed at NTNU shows such qualities. For two different feed gas cases a simulation analysis with Aspen Hysys for amine absorption and a membrane model interfaced within Aspen Hysys was performed. Further, an economical analysis was also conducted to evaluate the total capital investment and gas processing cost for both technologies.

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]: ${CO}_{2} + 2 R_{1} R_{2}$

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.

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View full text

CO2 removal from natural gas by employing amine absorption and membrane technology—A technical and economical analysis

Abstract

Highlights

Introduction

Section snippets

General chemistry

General

Conclusions

Acknowledgment

Journal of Membrane Science

Journal of Membrane Science

Separation and Purification Technology

Chemical Engineering Science

Journal of Membrane Science

Journal of Membrane Science

Journal of Membrane Science

Journal of Membrane Science

Natural gas processing with membranes: an overview

Industrial & Engineering Chemistry Research

Gas Purification

Selecting amines for sweetening units

Performance of gas purification systems utilizing DEA solutions

CO₂ removal from natural gas by employing amine absorption and membrane technology—A technical and economical analysis