sulfa treat rev -do_v2a

SulfaTreat-DO: Direct Oxidation for Hydrogen Sulfide Removal

Samir Jategaonkar, Brian Kay and Thomas BragaSulfaTreat, A Business Unit of M-I L.L.C.

17998 Chesterfield Airport Road, Suite 215, Chesterfield, MO 63005, USA

Girish Srinivas and Steven GebhardTDA Research, Inc.

12345 W. 52nd Avenue, Wheat Ridge, CO 80033, USA

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)

H2S Direct Oxidation Chemistry

• SulfaTreat-DO converts hydrogen sulfide in various gas streams into elemental sulfur and water by catalytic oxidation with air.

• SulfaTreat-DO treats the gas directly; no pre-separation of H2S 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 SO2 formed.

• 90% conversion of H2S into elemental sulfur is obtained in a single pass .

)g(2)g(8CatalystTDA

)g(2)g(2 OHS81O5.0SH + →+

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• H2S 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.• O2/H2S ratio typically stoichiometric (i.e. 0.5)

SulfaTreat-DO Process Flow

• SulfaTreat-DO is very simple: 1) knockout drum, 2) gas preheater, 3) catalytic reactor and 4) sulfur condenser

Air

Sour Gas In

To Sulfur Storage

Direct Oxidation Reactor

Sulfur condenser

Liquidknockout

Liquids

Gas preheat

Desulfurized gas

265F

sat

ste

am

wat

er

Air-fin cooler

Liquid Knockout

SOUR GAS FROM

WHITING

Liquid knockout

Sour liquids

SOUR GAS FROM

WHITING

Liquid knockout

Sour liquids

• A liquid knockout drum is located upstream of the direct oxidation reactor to minimize exposure of the catalyst to hydrocarbons.

• The knockout is equipped with standard level controls, automatic drainage and a flare bypass.

Catalytic Reactor

• Carbon steel• Refractory lined• Operated adiabatically

• Adiabatic operation limits H2S to 3-4% maximum (because of temperature rise)

• 1700 - 2000 lb catalyst charge• Typically 1/8 in x ¼ in pellets

H2S Concentration Determines Catalyst Operating Temperature

Direct oxidation is done in the vapor phaseMinimum catalyst temperature depends on sulfur dew pointSulfur dew point depends on H2S concentration and system pressure

100 150 200 250 300 350 400 450 5000.0

0.5

1.0

1.5

2.0

2.5

3.0

lf i iC

Tem

S

S2(g)

S8(g) S6(g)S5(g) S3(g)S7(g)

• Equilibrium calculation between liquid sulfur and different vapor phase sulfur species for 3% sulfur (100% conversion of 3% H2S) 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)

Sulfur dew point

Sulfur Condenser• 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 Tsat = 256°F

• Want to keep sulfur temperature above 240°F (melting point) and below 315°F (high viscosity region).

Sulfurcondenser

Desulfurized gas

Air fin cooler

265F

sat

ste

am

wat

er

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% H2S (8000 ppm)• 20% methane• 15% ethane• 10% propane• Balance CO2 (ca 55%)• > 2300 ppm BTEX• ~ 100 ppm mercaptans

Photograph of the Pilot Plant

Close Up of Sulfur Condenser Area

Pilot Test Data – Feed Gas

Inlet H2S concentration stabilized at about 8000 ppmFeed gas flowrate varied between 275 and 150 SCFM

5000

6000

7000

8000

9000

0 200 400 600 800 1000 1200Time on stream (hours)

H2S

inle

t con

cent

ratio

n (p

pm)

0

50

100

150

200

250

300

Sour

gas

flow

rat

e (C

FM)

H2S inlet (ppm) Sour gas flow CFM

Pilot Plant Feed and Product Gas Analysis

88+ % removal of H2S• 80% removal of mercaptans• Negligible change in hydrocarbon content (i.e. no

significant hydrocarbon oxidation)

Component Mol% (inlet) Mol% (outlet) Component Mol% (inlet) Mol% (outlet) H2S 0.8000 0.095 cyclohexane 0.17 0.14

N2 1.6 2.9 n-heptane 0.09 0.07 CH4 17.7 17.8 methylcyclohexane 0.05 0.04 CO2 58.6 58.7 toluene 0.02 0.01

Ethane 8.7 8.6 n-octane 0.005 0.003 Propane 6.5 6.3 ethyl benzene 0.003 0.002

isobutane 0.98 0.92 p and m xylene 0.003 0.003 n-butane 2.38 2.32 o-xylene 0.0007 0.0004

isopentane 0.74 0.71 n-nonane 0.0022 n-pentane 0.77 0.75

cyclopentane 0.01 0.01 Mercaptans (ppm) 101.00 20 2-methylpentane 0.15 0.14 3-methylpentane 0.13 0.12 Specific gravity

(air =1 )0.45

n-hexane 0.27 0.24 Gross BTU/CF dry 731.00 methylcyclopentane 0.14 0.12 Gross BTU/CF wet 718.00

benzene 0.21 0.17

Pilot Test Data – H2S conversion

• Average H2S conversion approximately 90%• Over 1000 hours of operation with no catalyst deactivation

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%


H2S

con

vers

ion

0

2.5

5

7.5

10

Air

flow

(cfm

)

H2S conversion AIR FLOW (cfm)

Pilot Test Data – Catalyst Selectivity

• Selectivity to sulfur > 99%• Never more than 80 ppm of SO2 formed during the 1000 hour test• SO2 selectivity can be controlled by increasing the temperature or

increasing the air flow rate.

0

25

50

75

100


SO2

outle

t (pp

m)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

Air

Flow

(CFM

)

SO2 outlet (ppm) AIR FLOW (cfm)

Laboratory Test of Fresh and Used Pilot Plant Catalyst

65

70

75

80

85

90

95

0.8 0.9 1.0O2 Concentration (Percentage of Stoichiometric)

Perc

ent C

onve

rsio

n

Used Catalyst Fresh Catalyst

T = 180oCP = 1 atm8000ppm H2S3200-4400ppm O2

Bal N2

No SO2 Detected

• Laboratory testing of fresh catalyst, and catalyst removed from the pilot plant after the 1000 hour test, gave identical performance under carefully controlled conditions

Pilot Test - Summary

• Results from 1000+ hour test indicate an average removal of 89% of the H2S with 99+% selectivity for elemental sulfur

Field Test Case No Sulfur Recovery CaseAverage sour gas flow rate (SCFM) 228 228

Average air inlet flow rate (SCFM) 3.5 0 Average H2S inlet (ppm) 7341 7341

Average H2S outlet (ppm) 790 0 Selectivity to elemental sulfur 100% N/A

Average sulfur yield 89% 0 Total sulfur inlet (lbs) 7953 7953

Total sulfur inlet (tons) 3.9 3.9 Total sulfur recovered (lbs) 7097 0

Total sulfur recovered (tons) 3.6 0 Total sulfur flared as SO2 (tons) 0.86 7.95

Landfill Gas Bench Scale Test

Test conditions for bench-scale landfill gas experiment Inlet gas flow 200 sccm Inlet air flow Varied to maintain O2/H2S= 0.5

Reaction temperature (°C) 210 ± 5 GHSV (cm3

gas/cm3catalyst/hour) 750

Pressure (psig) 24.7 psig H2S concentration (vol%) 1.0 - 2.5

• Small laboratory scale test• Landfill gas• Contaminated with 1-1.2% H2S• Low pressure

Landfill Gas Test – Apparatus

AIR

INLET GAS

SULFUR CONDENSER& COLLECTOR

CONTROL VALVE

ELECTRONIC MASS FLOW CONTROLLERS

SWEET OUTLET GAS TO

ANALYSIS (Dräger Tubes)

DO REACTOR IN TUBE FURNACE

REACTOR BYPASS FOR SAMPLING

INLET GAS

AIR

INLET GAS

SULFUR CONDENSER& COLLECTOR

CONTROL VALVE

ELECTRONIC MASS FLOW CONTROLLERS

SWEET OUTLET GAS TO

ANALYSIS (Dräger Tubes)

DO REACTOR IN TUBE FURNACE

REACTOR BYPASS FOR SAMPLING

INLET GAS

Landfill Gas Results

Initial catalyst stabilization period (ca. 15 hr)Average H2S conversion = 92 ± 5% Average selectivity to elemental sulfur = 99 ± 1%

0

20

40

60

80

100

0 10 20 30 40 50 60 70 80Time on Stream (hours)

H2S

Con

vers

ion

(%)

H2S conversion Selectivity to sulfur

SulfaTreat-DO is a simple, cost effective process for removing up to 3-4% H2S from natural gas, associated gas and landfill gas streams.SulfaTreat-DO converts 90% of the H2S into elemental sulfur and water in a single pass with ≥ 99% selectivity to elemental sulfurSulfaTreat-DO produces less than 100 ppm of SO2 under normal operating conditions.

Summary and Conclusions - 1


A pilot plant test was successfully completed that demonstrates the reliability of SulfaTreat-DO

Average flow : 228 MscfdAverage H2S: 7300 ppmv Average H2S removal: 89%Typical SO2 concentration (ca 10 – 15 ppmv)1000+ hours operation with no catalyst deactivation


A field bench test on landfill gas was successfully completed that demonstrates that SulfaTreat-DO can process a wide variety of gas streams

Average H2S conversion = 90%Average selectivity = 99+%No catalyst deactivationOver 99% of the H2S can be removed when the tail gas from SulfaTreat-DO unit is treated with SulfaTreat’s H2S scavenger.Adding SulfaTreat’s H2S scavenger greatly increases the versatility of SulfaTreat-DO.

sulfa treat rev -do_v2a

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