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BTEX Removal from Natural Gas Final Report · PDF file 1 Executive Summary BTEX (benzene,...

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  • BTEX Removal from Natural Gas Streams

    Chad Duncan, Armando Diaz and Miguel Bagajewicz*

    Department of Chemical, Biological and Materials Engineering

    The University of Oklahoma

    100 E. Boyd, Room T-335, Norman, OK 73019-0628

    (*) Corresponding author

  • 1

    Executive Summary BTEX (benzene, toluene, ethylbenzene, and xylene) is present in natural gas streams and is being picked up in amine and glycol dehydration units, being present in the exit CO2 and Water streams. As a result, incineration temperatures need to be increased and hence the cost of compliance with EPA emission limits (25 Tons/year) is large. Specifically, in the presence of BTEX the appropriate temperature is 1500 °F, whereas when other organics (like methane) are present one can incinerate at 1350 °F. In order to cut down the cost of incineration, the removal of BTEX from various streams in the amine unit was researched. Different removal techniques such as minimizing absorption in the amine unit, removing in the amine unit, and removing prior to the amine treatment were researched. The best technique from an economic standpoint was the use of adsorbents in the acid gas stream. This was determined by comparing its cost with the savings produced by reducing the incineration temperature. Adsorbents with the largest adsorption cost to extra incineration cost ratio were silica aerogels (SAG) and macroreticular resins (ionic resins). The aerogels were able to remove 8 ppmv of BTEX in a 575 MMSCFD stream of natural gas from the acid gas stream saving $100,000 when comparing the economics of removal with that of incineration. This was achieved by reducing the buying price of SAG from $37/kg to $34/kg at 14 cycles. Similar savings were found for ionic resins used in the acid gas stream by reducing the price of the resins from $43/kg to $35/kg. Both of these reductions could be achievable with long-term contracts with Cabot and Dow respectively. If the number of cycles is larger, then savings will further increase.

  • 2

    Table of Contents  Executive Summary ........................................................................................................................ 1  Introduction ..................................................................................................................................... 3  Background ..................................................................................................................................... 3  Ability of Simulators to Make Predictions in Amine Units ............................................................ 8  Ability of Simulators to Make Predictions in Glycol Units .......................................................... 20  BTEX Removal Solutions............................................................................................................. 22  CONCLUSIONS........................................................................................................................... 42  References ..................................................................................................................................... 44 

  • 3

    Introduction BTEX components are listed by the EPA in the Clean Air Act of 1990 as some of the 188 hazardous air pollutants. The EPA sets a standard of 25 tons per year for total aromatic compounds emitted in any given plant. There also exists 10 tons per year limit on each individual aromatic compound emitted. The reason for the restrictions are because benzene is a human carcinogen (promotes leukemia), toluene exposure can lead to reproduction or developmental effects, ethylbenzene affects the blood, kidneys, and liver and finally, xylene exposure can affect the central nervous system leading to respiratory and cardiovascular problems. All gas companies must handle the emission of BTEX (benzene, ethylbenzene, toluene, and xylene) and C5+ which are absorbed in both the amine and dehydration units and released to the atmosphere if not incinerated properly. In order to reduce the emission of such compounds, one must incinerate these compounds at elevated temperatures. This report evaluates more economical ways to remove BTEX other than incineration.

    Background We first briefly review how amine units work, then discuss the solubility of BTEX in amines and its estimation, the emission limits of BTEX, and the current cost of incinerating the BTEX emissions from amine unit. In the next section we discuss means of capturing the BTEX instead of incinerating it. Amine Treating Units: Typical natural gas has the compositions of Table 1.

    Table 1: Typical Composition of Natural Gas Compound Composition Methane CH4 70-90% Ethane C2H6

    0-20% Propane C3H8 Butane C4H10 Carbon Dioxide CO2 0-8% Hydrogen Sulfide H2S 0-5% Nitrogen N2 0-5% Oxygen O2 0-0.2% Rare gases A, He, Ne, Xe trace

    In order to achieve pipeline “dry” gas quality from natural gas off the wellhead, the compounds must be separated from the methane. This is done by processing the gas through a series of processing plants that separate (when needed) the carbon dioxide and hydrogen sulfide, the water, the nitrogen, and finally, natural gas liquids (C2+). Carbon dioxide is removed from natural gas to increase the BTU value of the gas as well as to avoid the formation of carbonic acid, which will corrode pipelines while transporting the natural gas. The standard value for

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