SulfaTreat-DO: Direct Oxidation for Hydrogen Sulfide Removal

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2 SulfaTreat-DO: Direct Oxidation for Hydrogen Sulfide Removal Samir Jategaonkar, Brian Kay and Thomas Braga SulfaTreat, A Business Unit of M-I L.L.C Chesterfield Airport Road, Suite 215, Chesterfield, MO 63005, USA Girish Srinivas and Steven Gebhard TDA Research, Inc W. 52nd Avenue, Wheat Ridge, CO 80033, USA

3 SulfaTreat-DO Partners SulfaTreat-DO uses a proprietary, patented, mixed-metal-oxide catalyst that was developed by TDA Research, Inc. (Wheat Ridge, CO) Engineering and fabrication of plants is done in collaboration with Westfield Engineering (Houston, TX)

4 H 2 S Direct Oxidation Chemistry SulfaTreat-DO converts hydrogen sulfide in various gas streams into elemental sulfur and water by catalytic oxidation with air. 1 H + 8 TDA Catalyst 2S(g) + 0.5O2(g) S8(g) H2O(g) SulfaTreat-DO treats the gas directly; no pre-separation of H 2 S is required (i.e. no amine unit is needed). The selectivity of the process is better than 99% for sulfur with little (< 50 ppm) or no SO 2 formed. 90% conversion of H 2 S into elemental sulfur is obtained in a single pass.

5 SulfaTreat-DO Catalyst Development The commercial catalyst has been tested and proven at the: Laboratory scale Few grams of catalyst and milliliter/min flowrates Field bench scale Pounds of catalyst and flowrates of several liters/min Pilot plant scale 1700 lb of catalyst and a flowrate of 300,000 SCFD H 2 S concentrations from a few hundred ppm to 3-4% can be processed Humidity can be from sat. at 100 F to 10% water Catalyst temperatures range from 350 F to 570 F depending on the sulfur dew point. O 2 /H 2 S ratio typically stoichiometric (i.e. 0.5)

6 SulfaTreat-DO Process Flow Air Gas preheat Air-fin cooler Sour Gas In Liquid knockout Direct Oxidation Reactor 265F sat steam water Desulfurized gas Sulfur condenser Liquids To Sulfur Storage SulfaTreat-DO is very simple: 1) knockout drum, 2) gas preheater, 3) catalytic reactor and 4) sulfur condenser

7 Liquid Knockout A liquid knockout drum is located upstream of the direct oxidation reactor to minimize exposure of the catalyst to hydrocarbons. SOUR GAS FROM WHITING Liquid knockout Sour liquids The knockout is equipped with standard level controls, automatic drainage and a flare bypass.

8 Catalytic Reactor Carbon steel Refractory lined Operated adiabatically Adiabatic operation limits H 2 S to 3-4% maximum (because of temperature rise) lb catalyst charge Typically 1/8 in x ¼ in pellets

9 H 2 S Concentration Determines Catalyst Operating Temperature S Sulfur dew point S2(g) 0.5 S8(g) S6(g) S7(g) S5(g) S3(g) lf i i Tem C Equilibrium calculation between liquid sulfur and different vapor phase sulfur species for 3% sulfur (100% conversion of 3% H 2 S) at 1 atm pressure Dew point is temperature where liquid sulfur concentration S goes to zero Dew point in this example is about 210 C (410 F) Direct oxidation is done in the vapor phase Minimum catalyst temperature depends on sulfur dew point Sulfur dew point depends on H 2 S concentration and system pressure

10 Sulfur Condenser 265F sat steam Sulfur condenser water Air fin cooler Desulfurized gas Sulfur condenser operates at constant temperature by boiling water in the shell Sulfur vapor condenses tubeside Controlling steam pressure controls condenser temperature 33 psia saturated steam gives T sat = 256 F Want to keep sulfur temperature above 240 F (melting point) and below 315 F (high viscosity region).

11 Pilot Plant Test of SulfaTreat-DO Demonstrated in West Texas (near Plains) Whiting Petroleum gas plant Associated gas (0.3 MMSCFD from an oil field) 0.8% H 2 S (8000 ppm) 20% methane 15% ethane 10% propane Balance CO 2 (ca 55%) > 2300 ppm BTEX ~ 100 ppm mercaptans

12 Photograph of the Pilot Plant

13 Close Up of Sulfur Condenser Area

14 Pilot Test Data Feed Gas H2S inlet concentration (ppm) Sour gas flow rate (CFM) Time on stream (hours) 0 H2S inlet (ppm) Sour gas flow CFM Inlet H 2 S concentration stabilized at about 8000 ppm Feed gas flowrate varied between 275 and 150 SCFM

15 Pilot Plant Feed and Product Gas Analysis Component Mol% (inlet) Mol% (outlet) Component Mol% (inlet) Mol% (outlet) H 2 S cyclohexane N n-heptane CH methylcyclohexane CO toluene Ethane n-octane Propane ethyl benzene isobutane p and m xylene n-butane o-xylene isopentane n-nonane n-pentane cyclopentane Mercaptans (ppm) methylpentane methylpentane Specific gravity (air =1 ) 88+ % removal of H 2 S 80% removal of mercaptans Negligible change in hydrocarbon content (i.e. no significant hydrocarbon oxidation) 0.45 n-hexane Gross BTU/CF dry methylcyclopentane Gross BTU/CF wet benzene

16 Pilot Test Data H 2 S conversion 100% 10 H 2 S conversion 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Time on stream (hours) Air flow (cfm) H2S conversion AIR FLOW (cfm) Average H 2 S conversion approximately 90% Over 1000 hours of operation with no catalyst deactivation

17 Pilot Test Data Catalyst Selectivity SO2 outlet (ppm) Air Flow (CFM) Time on stream (hours) 0.0 SO2 outlet (ppm) AIR FLOW (cfm) Selectivity to sulfur > 99% Never more than 80 ppm of SO 2 formed during the 1000 hour test SO 2 selectivity can be controlled by increasing the temperature or increasing the air flow rate.

18 Laboratory Test of Fresh and Used T = 180 o C P = 1 atm 8000ppm H 2S ppm O 2 Bal N 2 Pilot Plant Catalyst No SO2 Detected Percent Conversion Used Catalyst Fresh Catalyst O 2 Concentration (Percentage of Stoichiometric) Laboratory testing of fresh catalyst, and catalyst removed from the pilot plant after the 1000 hour test, gave identical performance under carefully controlled conditions

19 Pilot Test - Summary Field Test Case No Sulfur Recovery Case Average sour gas flow rate (SCFM) Average air inlet flow rate (SCFM) Average H 2 S inlet (ppm) Average H 2 S outlet (ppm) Selectivity to elemental sulfur 100% N/A Average sulfur yield 89% 0 Total sulfur inlet (lbs) Total sulfur inlet (tons) Total sulfur recovered (lbs) Total sulfur recovered (tons) Total sulfur flared as SO 2 (tons) Results from hour test indicate an average removal of 89% of the H 2 S with 99+% selectivity for elemental sulfur

20 Landfill Gas Bench Scale Test Test conditions for bench-scale landfill gas experiment Inlet gas flow 200 sccm Inlet air flow Varied to maintain O 2 /H 2 S= 0.5 Reaction temperature ( C) 210 ± 5 GHSV (cm 3 gas/cm 3 catalyst/hour) 750 Pressure (psig) 24.7 psig H 2 S concentration (vol%) Small laboratory scale test Landfill gas Contaminated with 1-1.2% H 2 S Low pressure

21 Landfill Gas Test Apparatus AIR INLET GAS ELECTRONIC MASS FLOW CONTROLLERS DO REACTOR IN TUBE FURNACE REACTOR BYPASS FOR SAMPLING INLET GAS SULFUR CONDENSER & COLLECTOR CONTROL VALVE SWEET OUTLET GAS TO ANALYSIS (Dräger Tubes)

22 Landfill Gas Results 100 H2S Conversion (%) Time on Stream (hours) H2S conversion Selectivity to sulfur Initial catalyst stabilization period (ca. 15 hr) Average H 2 S conversion = 92 ± 5% Average selectivity to elemental sulfur = 99 ± 1%

23 Summary and Conclusions - 1 SulfaTreat-DO is a simple, cost effective process for removing up to 3-4% H 2 S from natural gas, associated gas and landfill gas streams. SulfaTreat-DO converts 90% of the H 2 S into elemental sulfur and water in a single pass with 99% selectivity to elemental sulfur SulfaTreat-DO produces less than 100 ppm of SO 2 under normal operating conditions.

24 Summary and Conclusions - 2 A pilot plant test was successfully completed that demonstrates the reliability of SulfaTreat-DO Average flow : 228 Mscfd Average H 2 S: 7300 ppmv Average H 2 S removal: 89% Typical SO 2 concentration (ca ppmv) hours operation with no catalyst deactivation

25 Summary and Conclusions - 3 A field bench test on landfill gas was successfully completed that demonstrates that SulfaTreat-DO can process a wide variety of gas streams Average H 2 S conversion = 90% Average selectivity = 99+% No catalyst deactivation Over 99% of the H 2 S can be removed when the tail gas from SulfaTreat-DO unit is treated with SulfaTreat s H 2 S scavenger. Adding SulfaTreat s H 2 S scavenger greatly increases the versatility of SulfaTreat-DO.