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BTEX Removal From Natural Gas

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BTEX Removal from Natural Gas StreamsChad 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

Executive SummaryBTEX (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.

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Table of ContentsExecutive 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

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IntroductionBTEX 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.

BackgroundWe 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 GasCompound Methane CH4 Ethane C2H6 Propane C3H8 Butane C4H10 Carbon Dioxide CO2 Hydrogen Sulfide H2S Nitrogen N2 Oxygen O2 Rare gases A, He, Ne, Xe Composition 70-90% 0-20% 0-8% 0-5% 0-5% 0-0.2% 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 3

dioxide in tre eated gas is 2% by volu ume, unless it is transpo orted in LNG form, in w G which carbon d case the value is a lot lower. In turn, hyd drogen sulfi is remov to prev ide ved vent corrosio in on pipelines and reduce health risk s, ks. We foc mostly o amine un and we touch briefl on cus on nits fly glycol un where similar solutio can be im nits ons mplemented. Amine tr reating plants are the m most popular processes used to rem r move the car rbon dioxide and e hydrogen sulfide. Th process of amine trea n he ating is show in Figure 1: wn

Figure 1: Amine Tr reating Unit (Bullin (20 004)) Gas with CO2 and hy h ydrogen sulf contents above 5.7 m per cubic foot of nat fide s mg tural gas is c called sour gas It enters the amine u contactor where is exposed to a lean amin s. unit ne-water mix xture, which is virtually CO2 and H2S free. Thi amine-wa mixture absorbs ma C is ater ajority of ca arbon dioxide a hydroge sulfide. The natura gas leaves the contac and en al ctor as swe gas, fre of eet ee hydrogen sulfide and with low C n d CO2 contents while the rich (in C and H2S amine sol s, CO2 S) lution is sent to a regenerati unit. ion The rich amine is first flashed at a lower pressure se h d r eparate the v vapor. The liquid mixtu is ure then sent the regener t rator where i is heated to high tempe it o erature to re emove the co ontaminants. The liquid am mine is then sent back to the contact while the CO2 and H rich va o tor e H2S apors are rele eased from the regenerator as acid gas. This acid g is then se to an incinerator whe it is burn to gas ent ere ned remove v volatile orga anics and eve entually harm contam mful minants such as BTEX or it can be se to r ent a Claus u to recover the sulfur unit r. The type of amines are used in industry are monoethan es e nolamine (M MEA), diethan nolamine (D DEA), di-isopro opanolamine (DIPA), d diglycolamin (DGA), and methy diethanola ne yl amine (MD DEA). These am mines react with carbon d w dioxide and hydrogen su ulfide as show in Figure 2 wn e

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Figure 2: Amine R Reactions (Sh hiveler, (200 05)) On top o the above mentioned reactions, a of e d amines also participate in some sid reactions with de other com mponents (C Sulfur c CO, compounds, Strong acid present in the gas) (A ds n Abdi) and le to ead the degr radation of amines. T f Thermal deg gradation h happens as a result o high reb of boiler temperatu ures. Finally reactions with carbon monoxide a sulfur ca form form compoun y, n and an myl nds The react tion with str rong acids, w which enter t through inlet stream (Ab t bdi), cause h stable sa to heat alts form. T These salts can remain i the system and inter c in m rrupt the abs sorption pro ocess. An a amine reaction w strong acids is show in Figure 3: with wn e

3: w acids Figure 3 Reaction with strong a

Incinerat tion: Incine eration invo olves the com mbustion of the acid gas and fuel. The oxidiz is f . zer shown in Figure 4. This gas is then contacted with a flame at the appropriat temperatu to n s te ure fully com mbust the gas. These ox xidizers run a temperatu from 100 at ures 00F up to 1 1500F for h highly toxic VO OCs. The cl lean exhaus gas contai mostly C 2 and H2O with some r st ins CO residual CO.

Figure 4 Example of Thermal O 4: o Oxidizer *(T Thermal Oxid dizer Review w) 5

Combustion is a sequence of exothermic reactions between fuel and oxygen, usually in the form of air. These reactions break down the fuel into carbon dioxide and water releasing mass amounts of heat. This same type of combustion happens in acid gas incineration in amine plants. The reactions that take place are the following:CH4

+ 2 O 2 CO 2 + 2 H 2 O

C 2 H 6 + 3 . 5 O 2 2 CO 2 + 3 H 2 O C 3 H 8 + 5 O 2 3 CO 2 + 4 H 2 O C 4 H 10 + 6 . 5 O 2 4 CO 2 + 5 H 2 O C 5 H 12 + 8 O 2 5 CO 2 + 6 H 2 O C 6 H 14 + 9 . 5 O 2 6 CO 2 + 7 H 2 O C 7 H 16 + 11 O 2 7 CO 2 + 8 H 2 O C 6 H 6 + 7 . 5 O 2 6 CO 2 + 3 H 2 O C 7 H 8 + 9 O 2 7 CO 2 + 4 H 2 O C 8 H 10 + 10 . 5 O 2 8 CO 2 + 5 H 2 O

Figure 5: Reactions in oxidizer In order for VOC to combust, certain temperatures must be reached. These temperatures are given in Table 2: Table 2: Auto ignition temperatures Compound Benzene Toluene Xylene Methane Ethane Propane Butane I-Pentane N-Hexane AIT (F) 1097 997 924 997 859 842 788 788 437

Ethylbenzene 870

N-Heptane 419 * (Lewandowski, 2000) In order to combust at these auto ignition temperatures (AIT), long residences times must be used in the flame. In or

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